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Wellbore name
History
NPDID wellbore
Date updated
Date sync NPD
1/2-1
<p><b>General</b></p>

<p>Well 1/2-1 is located in the Central
Graben, about 200 m from the UK border in the North Sea. The main objective was
Paleocene sands of the Rogaland Group. The secondary target was the chalk
formations, although these were possibly not enough fractured to represent a
reservoir. </p>

<p><b>Operations and results</b></p>

<p>Wildcat well 1/2-1 was spudded with the
semi-submersible installation Ross Isle on 20 March 1989 and drilled to TD at 3574 m in the Late Cretaceous Tor Formation. While cutting of core no 7, the
elevators accidentally opened and dropped the string. Two attempts were made to
recover the string with no success. The hole was sidetracked from 3078.5 m and
core no 8 was cut. The well was drilled with seawater down to 645 m, with native
mud (water mixed with clays from the borehole itself) from 645 m to1525 m, and
with seawater from 1525 m to TD. No shallow gas was detected in the hole.</p>

<p>The Forties Formation came in at 3121 m.
The formation was hydrocarbon bearing down to 3142.5 m as confirmed by both
electric logs and the RFT pressure gradient. The reservoir sandstones of the
Forties Formation showed good to excellent reservoir properties. Average core porosity
was 18.5% and test permeability was measured to 49 mD. </p>

<p>Shows on cores were recorded down to core
# 8 where they gradually decreased to zero at 3166 m. From the RFT data two
water gradients were identified below the oil zone. A shift of 8 psi between
them suggested the existence of an impermeable barrier around 3160.2 and 3162 m.
Core saturations and fluorescence indicated the potential existence of a thin (4
m) oil zone below this barrier. This zone was not identified from the logs and
was not evaluated for a test due to lack of data at that point. </p>

<p>The Ekofisk formation was encountered at
3407 m, and the Tor formation at 3514 m. Both formations were water bearing.</p>

<p>A total of 8 cores were cut in the
Forties Formation, seven in the first hole and the eighth in the sidetrack. No wire
line fluid samples were taken. </p>

<p>The well was permanently abandoned on 4 June 1989 as an oil/gas discovery.</p>

<p><b>Testing</b></p>

<p>Two intervals were perforated and tested with
the intention to first test the oil zone and then open up a deeper zone to
produce and sample formation water. The perforated intervals were 3122 - 3137 m
in the oil zone and 3145.5 - 3157.7 m in the water zone. The oil test produced up
to 859 Sm3 oil and 57200 Sm3 gas/day on a 64/64&quot; choke. The GOR was 67
Sm3/Sm3 and the oil gravity was 42.5 deg API. The maximum temperature recorded
during the test was 133.8 deg C. Analysis of the final co-mingled oil + water
test confirmed that the lower perforation interval produced only water. This
confirmed the contact at 3142.5 m to be an OWC.</p>
1382
7/6/2016 12:00:00 AM
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1/2-2

<p>The 1/2-2 well was drilled to evaluate the prospect named
Hummer, located in the Central Graben in the North Sea ca 4.5 km east of the UK
border. The prospect was a relatively simple four-way dip closure structure,
with the primary target being the Palaeocene Forties Sandstone Member of the
Sele Formation. There was a secondary target in the underlying Mey Sandstone
Member of the Lista Formation. The Hummer prospect was located between several
proven hydrocarbon accumulations in the Forties Sandstone, including the Blane
oil discovery in PL 143BS, approximately 11 km to the south, the 7/11-3 gas
condensate discovery on the flank of the Cod Field, 5 km to the North, and the
Olselvar gas condensate discovery 12 km to the east in Block 1/3.</p>

<p><b>Operations and results</b></p>

<p>Well 1/2-2 was spudded with the jack-up installation Mærsk
Giant on 14 December 2005 and drilled to TD at 3434 m in the Paleocene Ekofisk
Formation. There were no serious technical problems in the operations, but due
mainly to hole problems and WOW the well was completed ca 15 days after
schedule. The well was drilled with seawater and pre-hydrated bentonite sweeps
down to703 m, with Performadrill KCl mud from 703 m to 1507 m, and with
Enviromul oil based mud from 1507 m to TD.</p>

<p>A Forties reservoir was penetrated at
3135 m, +3m low from the prognosis. No hydrocarbons were encountered, but oil
shows were recorded in the upper part of the Forties Formation and in a
sandstone stringer further down in the Lista Formation.</p>

<p>A 46 m core (4&quot;) was cut in the
Forties sandstone Member, from 3141.5 m to 3187.5 m. The core recovery was 98%
(44.9 m). Wire line logging was according to dry hole case with no wire line
fluid samples taken.</p>

<p>The well was permanently abandoned on 2
February 2006 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>













































5192
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1/3-1


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 was drilled on the crest of a
salt-induced anticline on the Hidra High in the North Sea. The purpose of the
well was to investigate Tertiary and Mesozoic sequences down to top salt.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well is Type Well for the Våle, Hidra,
Hod, and Tor Formations, and Reference Well for the Vidar, Ekofisk and Blodøks Formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 was spudded with the four leg
jack-up installation Orion on 6 July 1968 and drilled to TD at 4877 m in the
Permian Zechstein Group. From the deviation survey it is seen that the well
starts to deviate significantly at 4037 m (8 deg deviation), and at TD the
deviation is 18 deg. This will correspond to a TVD RKB that is ca 25 m less
than MD RKB.</span><span lang=EN-GB>Several drilling
problems occurred during the drilling operations of well 1/3-1. While drilling
the 17 1/2&quot; hole for the 20&quot; casing, circulation losses started at
220 m (720') and became total at 238 m (781'). While drilling on with sea
water, without returns, the pipe stuck. The lost circulation zone eventually
had to be sealed off with a cement plug. In the Tertiary plastic clays the
problems included tight hole conditions, bit balling, and difficulties in
lowering the logging tools. The mud weight had to be raised from 10.8 ppg to 13.6
ppg to stabilize the hole. At 4131 m (13554') the bit twisted off, but was
retrieved on the second fishing run. A hydrocarbon bearing zone was encountered
at 4567 m (14984'). The mud became gas cut. At 4592 m (15064') the degasser was
overloaded and the circulation lost, probably higher in the hole. A cement plug
was needed to combat the lost circulation problems. It was then decided to set
a 7&quot; casing. Circulation was lost while running the casing, which had to
be cemented in two stages. Drilling continued with a 5 7/8&quot; bit. Around
4677 m (15346'), when drilling into salt, the penetration rate increased from
10 to 50 ft/hr. Further deepening to TD went without problems. The well was
drilled water based.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-1 found no sand of any
significance in the Tertiary section. An unexpectedly thick Danian/Late Cretaceous
chalk section (Shetland Group) was penetrated from 3258 m to 4441 m. The
underlying Cromer Knoll Group was found resting directly on Permian salt at 4671
m. Minor gas was confirmed by testing in the Tor Formation. No source rock
section was identified in the well. Shows were reported in the interval from
2999 m to 3423 m as follows: direct and cut &quot;faint&quot; fluorescence were
reported on sidewall cores from the interval 2999 to 3002 m; weak cut fluorescence
was recorded on cuttings from 3039 m; strong cuttings fluorescence and moderate
cut was recorded at 3357 m; &quot;fair&quot; - &quot;soaked w/oil, giving
yellowish-grn flu, but no cut&quot; on the conventional core at 3405 to 3423 m</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 11165 to 11232 ft
(3403.1 to 3423.5 m). No wire line fluid samples were taken. A sea bed core (0
- 46 m from seabed) was taken for geotechnical purposes at the 1/3-1 location.
Samples from this core are available at the NPD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11
November 1968 as a minor gas discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.
They produced some fluids at very low rates:</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 4583.6 - 4601.0
m in the Cromer Knoll Group and recovered a total of 0.74 bbl gas cut mud in 45
minutes, corresponding to a standard rate of 40 bbl (1133 Sm3) gas/day. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4563.5 - 4581.8
m in the Cromer knoll Group and recovered a total of 18 bbl of gas cut mud with
traces of condensate and slugs of gas in 140 minutes. This corresponds to a
standard rate of 234 bbl (6626 Sm3) gas/day. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 3355.2 - 3359.8
m in the Tor Formation and recovered a total of 30 bbl of gas cut mud and slugs
of gas in 45 minutes. This corresponds to a standard rate of 1000 bbl (28317 Sm3)
gas/day. </span></p>



154
5/19/2016 12:00:00 AM
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1/3-10
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-10 is located on the Hidra High,
ca 20 km south-south west of the Ula Field in the North Sea. It was drilled to
appraise the oil and gas bearing Late Paleocene Forties Sandstone in the
Oselvar structure, first discovered by the 1/3-6 well drilled by Elf Aquitaine
Norway A/S in 1991. The main goal of the well was to acquire sufficient
reservoir data to make a decision on future development of the Oselvar
discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/3-10 was spudded with
the jack-up installation Mærsk Guardian on 25 October 2007 and drilled to TD at
3288 m in the Paleocene Lista Formation. The well was drilled and tested
without significant technical problems. It was drilled with seawater / PHB down
to 816 m, with KCl/Polymer mud from 816 to 1300 m, and with Carbo SEA OBM from 1300
to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the Hordaland Group came in
deep (19 m) compared to prognosis, as did the Balder and Sele Formations of the
Rogaland Group (12 m and 5 m deep respectively). More significantly, a thicker
than prognosed Sele Formation resulted in the target reservoir Forties
sandstone coming in at 3153 m, 24 m deep compared to prognosis. The thickness
of the Forties Sandstone however, was 52 m, which is only one meter thinner
than prognosed. Of this thickness 32 m was designated as net reservoir using a porosity
cut-off value of 10%. The average porosity was 17.7 % and the water saturation was
44.9%. The Forties Formation contained light oil with a free water level for
the area estimated at 3245 m. Shows were only recorded in the target Forties
Formation sandstones.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Forties Formation Sandstone was cored
from 3159 to 3232 m with 99.8% recovery. An RCI log was run for pressure and
fluid sampling.</span><span lang=EN-GB>Four light oil
gradients with increasing density downwards could be identified from these data.
Light oil fluid samples were taken in Run 2A at two depths, 3162.2 m and 3186.3
m. Run 2D samples were taken at 3203.3 m (approximately 70% water and 30% oil),
and at 3196.5 m (about 80% light oil and 20% water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back for
sidetracking on 7 January 2008 as an oil and gas appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Forties Formation was tested by an
open hole (&quot;barefoot&quot;) DST in the 8 1/2&quot; section from 3158 to TD.
The test produced 457 Sm3 oil and 212453 m3 gas /day through a 48/64&quot;
choke in the main flow period. The GOR was 465 m3/m3, the oil density was 0.791
g/cm3, and the gas gravity was 0.855 (air = 1), with 5 ppm H2S and 2.5 % CO2.</span></p>



5614
4/11/2017 12:00:00 AM
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1/3-10 A







<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-10 A is located on the Hidra
High, ca 20 km south-south west of the Ula Field in the North Sea. It was
drilled to further appraise the Forties Formation Sandstone in the Oselvar
structure, after the primary well 1/3-10 had confirmed oil and gas in the
structure. The main goal of the sidetrack well was to penetrate the water leg for
water sampling and establish the free water level in the structure. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Oselvar 1/3-10 A appraisal sidetrack
kicked off in the claystones of the Hordaland Group at 2276 m on 7 January
2008. It was drilled with the jack-up installation Mærsk Guardian to final TD
at 3632 m in the lower part of the Sele Formation below the target Forties
Sandstone. The well was drilled without significant technical problems. It was
drilled with Carbo SEA OBM from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well track penetrated the remaining
Hordaland claystone, and the claystones, tuffaceous claystones and sandstones
of the Rogaland Group (Paleocene-Eocene), which included the Balder Formation,
the Sele Formation, and the target Forties Sandstone Member. The top of the
Balder Formation came in only 1 m TVD shallow compared to prognosis, the Sele
Formation came in deep (10 m TVD) compared to prognosis. The Forties Sandstone
came in at 3516 m (3257 m TVD RKB), 11 m TVD compared to prognosis. The log
data confirmed that the well had penetrated the water leg of the reservoir as
expected, and indicated 64 m MD (43 m TVD) gross reservoir and a net reservoir of
37 m MD (25 m TVD), giving a Net/Gross of 0.58. The net reservoir, all of which
is considered to be non-pay, has an average porosity of 18 % and mobilities in
the range 1-13 mD/cP. Pressure measurements indicated a free water level at
3245 m TVD RKB.</span></p>

<p class=MsoBodyText><span lang=EN-GB>From petrophysical evaluation the water
bearing reservoir was found to contain residual hydrocarbons. The only oil show
in the well was a weak oil stain at 3525 m (3263 m TVD RKB) in the Forties
Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in 1/3-10 A. An RCI log
was run for pressure and fluid sampling.</span><span
lang=EN-US>Water</span><span lang=EN-GB> samples were taken at 3556 m, 3572 m,
and 3536.75 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
January 2008 as an oil and gas appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No DST was carried out</span></p>



5779
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1/3-11






<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 1/3-11 Ipswich well was drilled in
the Central Graben of the North Sea about 9 km south of the 1/3-10 Oselvar well,
which confirmed oil in a similar geological setting to that of the Ipswich
prospect. The primary objective of the 1/3-11 well was to determine the
presence and nature of recoverable hydrocarbons in the Forties Formation Sandstone
reservoir expected to exist along the western flank of the Ipswich salt dome.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-11 was spudded with the jack-up
installation Mærsk Galant on 28 May 2008 and drilled to 3289 m in the Paleocene
Våle Formation. The well path was drilled with a slight S shape after the
originally planned surface location was moved to avoid potential shallow gas.
Due to unexpected lithology the original hole penetrated most of an
hydrocarbon-bearing reservoir sand in the well without cores being taken.
Therefore it was decided to make a technical coring side-track, in which also
fluid samples would be obtained. The sidetrack was denoted technical (1/3-11
T2) as coring was the main objective. It was kicked off at 1330 m and drilled
to final TD at 3595 m in the Paleocene Ekofisk Formation. The well was drilled
with seawater and pre-hydrated bentonite down to 825 m, with KCl/polymer mud
from 825 m to 1306 m, and with Carbo SEA oil based mud from 1306 m to TD,
including the technical sidetrack.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated the clays and
claystones (with sand interbeds) of the Nordland Group, the claystones of the
Hordaland Group, and the claystones, tuffaceous claystones and sandstones of
the Rogaland Group. The latter contained the Balder Formation, the Sele
Formation (which was expected to contain the target Forties Formation sandstone),
the Lista Formation and the Våle Formation. The well did not penetrate sands at
the stratigraphic equivalent of the target Forties Formation sandstone. Instead, a
de-sanded Forties equivalent was penetrated consisting of claystone interbedded
with siltstone and dolomitic limestone. However, hydrocarbon bearing sands were
encountered at 3176 m within the underlying Lista formation, and these were
interpreted as possible lateral equivalents of the &quot;Mey Sandstone Member&quot;
(Andrew Formation). </span></p>

<p class=MsoBodyText><span lang=EN-GB>Based on initial analysis of the LWD logs
and wire line formation pressure measurements, it was decided to drill the
coring sidetrack down dip in order to investigate also the thickness of the
hydrocarbon column, lateral variation in reservoir quality and thickness, the
presence of the Forties Formation sandstone down dip in addition to the Andrew Formation penetrated in the main well, in addition to the coring and
sampling objectives. The Ipswich 1/3-11 T2 sidetrack kicked off in the
claystones of the Nordland Group and penetrated the claystone of the Hordaland
Group and claystones, tuffaceous claystones and sandstones of the Rogaland
Group. The sandstones of the Rogaland Group included 37 m of Forties Formation which,
unlike in the main well, was present in the sidetrack as a sandstone, in
addition to 116 m of the Andrew Formation. In
1/3-11 T2 the Forties Sandstone was found hydrocarbon bearing, while the Andrew Formation was poorer and water filled. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No definite hydrocarbon contact levels were
seen in the wells.</span></p>

<p class=MsoBodyText><span lang=EN-GB>In the primary well oil shows were
recorded throughout the Andrew Formation, else no shows above background
OBM was observed. In the sidetrack a show (very weak, if any) was recorded in
the Vade Formation sandstone at 2594 to 2600 m, in a thin sandstone at 3215 m within the
Sele Formation, and in the Forties Formation. In the sidetrack no shows above
background OBM level was observed in the Andrew Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>At total of 93.63 m core was recovered in
three cores from the interval 3288 m to 3355.7 m in the Forties and Sele
Formations and 2 cores from the interval 3398.9 m to 3429.1 m in the Andrew Formation. All cores were cut in the sidetrack. No fluid samples were taken in
the primary well. In the sidetrack fluid sampling resulted in the recovery of
three water samples at 3415.1 m in the Andrew Formation and five oil
samples at 3294.5 m in the Forties Formation Sandstone. All oil samples were
heavily contaminated by oil based mud filtrate.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30
August as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<

5806
4/11/2017 12:00:00 AM
29.01.2023
1/3-12 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-12 S was drilled in the
Breiflabb Basin of the southern North Sea, about half-way between the
Albuskjell Field and the 1/3-11 discovery. The principal objective of the well
was to penetrate the Mandarin East pod and evaluate a prognosed un-faulted
section of Triassic (Skagerrak Formation) within which there was a strong amplitude
event that was interpreted pre</span><span lang=EN-GB style='font-family:"Cambria Math","serif"'>&#8208;</span><span
lang=EN-GB>drilling as being the Top Julius mudstone, with a Joanne Sandstone
section above and the Judy Sandstone beneath. Both of these were prognosed to
contain hydrocarbons. The secondary objective was to evaluate the hydrocarbon
potential of the Late Jurassic Sandstones, if any were present.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-12 S was spudded with the jack-up
installation Rowan Gorilla VI on 1 December 2009 and drilled to TD at 5931 m
(5868 m TVD) in the Late Triassic Skagerrak Formation. At final TD the pipe
became stuck and after some time working to free the pipe it parted just below
the rotary table. A complex 12 day fishing operation then commenced, eventually
recovering the fish from 5590 m upwards, but leaving the BHA across the Judy
Sandstones. This made wire line logging operations impossible. Following
recovery of the fish a further 32 days were spent plugging and abandoning the
well before the rig moved off location. The well was drilled with seawater and
pre-hydrated bentonite down to 1150 m, with Carbosea oil based mud from 1150 m
to 5412 m, and with Magma-Teq oil based mud from 5412 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The stratigraphic sequence was different
to that expected, with a thicker Late Jurassic, and the unexpected presence of Middle
Jurassic claystones and sandstones eroding down into the Triassic sequence. The
Joanne sandstones was not encountered and the well went directly into what was
believed to be the Judy Sandstones at 5817.5 m. When the well had gone deep
enough to ensure that Julius Mudstone was not present, a core was taken for
evaluation of reservoir quality. The LWD GR and resistivity logs clearly showed
the Middle Jurassic and Skagerrak Sandstones to be water bearing. There were no
oil shows above OBM seen on cuttings from the Jurassic and Triassic sandstones.
No shows were seen on the core.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 5876 m to 5903 m in
the Skagerrak Formation, Judy Member. Only 8.43 m (32.6%) was recovered. It was
not possible to obtain wire line log data, pressures, and fluid samples over
the Middle Jurassic and Skagerrak Sandstones due to the BHA becoming stuck at
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22
July 2010 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



6260
4/11/2017 12:00:00 AM
29.01.2023
1/3-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-2 was drilled on the crest of a
salt-induced anticline on the Hidra High in the North Sea.</span><span lang=EN-GB>The main objective was possible L. Tertiary
sands, well developed and productive in Phillips 7/11-1. Secondary objective
was the Late Cretaceous chalky limestone, which had given shows in 1/3-1.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-2 was spudded with the
semi-submersible installation Sedneth I on 14 May 1969 and drilled to TD at
4297 m in the Early Cretaceous Sola Formation. When drilling out of the
20&quot; casing shoe, circulation was lost immediately, and the lost
circulation zone had to be cemented off. The plastic clays caused continuous
troubles, such as bit balling and plugged shaker screens, and the hole had to
be reamed and washed several times. Below 3378 m diamond bits were used, and
the drilling was interrupted frequently because of leaking bumper subs. The
well was drilled water based with a 1 - 4 % addition of diesel through most of
the well bore.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Tertiary sands were not developed, and
whilst thick Late Cretaceous chalky limestone was found as predicted, there
were no hydrocarbon bearing intervals in it, and reservoir qualities were poor.
No source rock intervals were encountered, and only very minor traces of higher
hydrocarbons were detected in the Late Paleocene-Early Eocene section, and in
the interval 3761 to 3901 m in the Hod Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A small core recovered by junk basket was
taken at 3589.02 - 3589.5 m. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27
July 1969 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



165
5/19/2016 12:00:00 AM
29.01.2023
1/3-3


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-3 is located on the Cod Terrace
in the North Sea. It was drilled to evaluate the hydrocarbon potential of both
the Late Jurassic and the Triassic sandstone formations. Main target was the Late
Jurassic Ula Formation found oil bearing in the Ula field, 17 km to the NW, and
in the well 2/1-3. Secondary target was the Triassic sandstone found oil
bearing in the well 7/12-6 in the Ula field. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-3 was spudded with the
semi-submersible installation Borgsten Dolphin on 22 August 1982 and drilled to
TD at 4876 m logger's depth (4867 m driller's depth). The well was drilled
using water based mud. Two drilling breaks occurred, one at 4127 m and one at
4180 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Thin layers of sandstone were found in
the Palaeocene. The Chalk Group was 686 m thick. Less than 10 m of sandstones
scattered in several thin layers were encountered and partially cored in the
Farsund Formation, they were found tight. The Late Jurassic Ula Sandstones,
which were the main objective, were found at 4178 m and they were oil bearing
down to an OWC at 4221 m, but with only ca 5 m pay zone. The upper half with
the best reservoir qualities was cored (cores 2 to 6). The coaly Bryne
Formation is assigned at 4527 m, top Triassic Smith Bank Formation at 4620 m,
and the Zechstein evaporitic rocks, anhydrite (26 m) and halite was penetrated
from 4820 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Residual hydrocarbon saturation based on
electric logs were seen in the Paleocene at 3068 to 3093 m and in top Triassic
at 4622 to 4637 m. Shows were reported as follows: Direct yellow fluorescence
on cuttings at 2955 m; Weak direct fluorescence and poor streaming yellow cut fluorescence
on cuttings at 3075 - 3145 m; Yellowish green direct fluorescence and dull
bright yellow cut fluorescence on cores at 4186 - 4219 m; Weak direct
fluorescence and pale cut fluorescence on cuttings at 4527 - 4542 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 4129 m to 4147 m in
the Farsund Formation and five more from 4181 m to 4284 m in the upper half of
the Ula Formation (core depths = log depths + 7 m for core 1 and + 6.4 m for
cores 2 to 6). RFT wire line fluid samples were taken at 4212 m (2 l gas and
3.5 l light brown water with yellow green oil film), 4244 m (3.5 l water), 4214
m (3.5 l water with strong petroleum odour), and 4436 m (4.2 l fluid).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24
March 1983 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Three DST's were performed in this well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the intervals 4528.5 -
4533.8 m + 4535.3 - 4538.3 m + 4546 -4552 m. It produced mud filtrate and
formation water at a rate of 2.63 m3/day. The maximum temperature recorded in
the test was 160.9 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4233 - 4240 m.
It produced formation water at a rate of 170 m3/day. The maximum temperature
recorded in the test was 160.0 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3A tested the interval 4202 - 4208 m.
It produced mud filtrate and formation water at a rate of 0.6 m3/day. The
maximum temperature recorded in the test was 158.3 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3B tested the intervals 4202 - 4208 +
4211 - 4214 m. It produced 143 Sm3 oil and 28000 Sm3 gas/day. The GOR was 196
Sm3/Sm3, the oil density was 0.829 g/cm3, and the gas gravity was 0.820 (air =
1). The maximum temperature recorded in the test was 165.6 deg C. </span></p>



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1/3-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-4 was drilled on the
northern part of the Hidra High in the North Sea. The objective was to test the
hydrocarbon potential of the Danian and late Cretaceous Chalk, on a domal structure
induced by halokinesis.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-4 was spudded with the
semi-submersible installation Dyvi Alpha on 15 February 1983 and drilled to TD
at 3198 m in the Late Permian Zechstein Group. While drilling through Middle
Miocene claystones, the average background gas increased rapidly from 5% to 80%
between 1580 m and 1595 m and, at this depth, the mud weight had to be
increased gradually from 1.37 to 1.50 - 1.53 to lower the gas content. Furthermore,
to stop the gas leakage and to isolate the weak zone, it was decided to set the
13 3/8&quot; casing. Logs were run (ISF/BHC and LDT/CNL) and the casing was set
with shoe at 1557 m. While circulating after the logging a gain of 1 m3 with
gas and more than 100 litres of oil occurred. To stabilize the well, 2 cement
plugs and 4 barite plugs were set, in order to stop the gas leaking from the
formation. In total, twenty days were spent on circulating, logging (ISF/BHC
and LDT/CNL), setting the 13 3/8&quot; casing, and plugging before drilling of
the 12 1/4&quot; section commenced. While drilling the 12 1/4&quot; hole, the
background gas varied between 32 and 84% down to 1695 m where the mud-weight
was raised to 1.60. The background gas then decreased between 10 and 25% and
drilling continued normally. Logs performed at the end of the 12 1/4&quot;
phase and covering the zone of interest are strongly affected by large cavings
and by barite squeezed into the formation. Side wall core recovery was very
poor from the caved zone. The well was drilled water based.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The first evidence of hydrocarbons in the
well was the gas and oil kick at 1595 m in the base of the Middle Miocene, The
oil in the mud was a 34 deg API gravity oil and geochemical analysis suggested that
the organic matter rich Mandal Formation of Late Jurassic age was the source
rock. However, according to the lithology and log information, there was no
evidence of a reservoir at this level. The oil was probably trapped in a fault
that acted as a drain. The Ekofisk Formation (Danian limestone) was encountered
at 2754 m, and the Tor Formation (Maastrichtian) at 2797 m. Most of RFT
measurements and core analysis showed that both formations were virtually tight
and water bearing, but some residual hydrocarbons (60 - 80% water saturation) was
seen on Cyberlook computation 2754 to 2780 in the upper Ekofisk Formation. Shows
on cuttings and cores were as follows: Bright yellow direct fluorescence at1580
- 1600 m; direct bright yellow fluorescence with pale yellow cut on sand grains
at 2244 m; direct yellow fluorescence in limestones with whitish to pale yellow
cut at 2678 - 2687 m; pale yellow direct fluorescence on a few particles at 2753
- 2765 m; a gain of 8m3 of salt water (85 g/1) with trace of hydrocarbons was observed
at 2884 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Chalk. </span><span
lang=EN-US>Core 1 was cut at 2780 - 2789 m</span><span lang=EN-GB> with 95% recovery,
and core 2 at 2817 - 2830 m with 8% recovery. Due to tight formation no fluid
samples were taken on the RFT, but oil samples were taken from the oil in the mud
at 1595 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8
May 1983 as a dry well with strong oil shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



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1/3-5
<p><b>General</b></p>

<p>Well 1/3-5 was drilled on a NW-SE
oriented fault block tilted towards the NW. The structure is located in the
northern Permian basin, on the east side of Central Graben, extending into
blocks 116, 211, and 2/4. The purpose of the well was to evaluate the
hydrocarbon potential of the Rotliegendes Group sandstones.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 1/3-5 was spudded with the
3-leg jack up installation Neddrill Trigon on 1 October 1984 and drilled to TD
at 4850 m in the Permian Rotliegendes Group. After setting the 30&quot;
conductor a 14 3/4&quot; pilot hole was drilled to 1195 m, before opening the
hole to 26&quot;. Drilling to 2470 m the mud weight was raised from 1.33 g/cm3
to 1.70 g/cm3 due to high formation pressure. This resulted in tight hole
during wiper trips, and high weight strain on the drill string, and also caused
the 13 3/8&quot; casing to be set somewhat higher than prognosed. Through the
chalk sequence the hole seemed to be tight, and while tripping at 3523 m, the
drill string got stuck with the bit at 3515 m. It was assumed that the tight
interval was caused by one of the stabilizers between 3247 and 3267 m. The
string was freed by pumping acid. A high pressure sand sequence in the interval
4363-4395 m, with pore pressure close to the last leak-off Test, resulted in
the 7&quot; liner being set 520 m higher than prognosed. The well was drilled
with spud mud down to 1195 m, with KCl/polymer mud from 1195 m to 3000 m, from
3000 m the mud was lightly treated with lignosulphonate. Fifty bbl of pipelax
with a mud/diesel ratio of 1:1 was added to the mud to free the stuck pipe at
3515 m. From 4122 m to TD the well was drilled with a polymer/sulphonated resin
mud.</p>

<p>Traces of yellow direct fluorescence,
mainly on fractures, with a moderate milky-white cut fluorescence were observed
at the top of the Tor Formation and at several levels deeper down in the
formation. Also near the base of the Hod Formation, a very weak and slow pale
yellowish cut fluorescence was occasionally observed. Direct fluorescence was
not detected. Petrophysical analysis supported that some zones in the lower Hod
Formation (4369 m to 4448 m) could be marginally hydrocarbon bearing. The
objective Rotliegendes sand came in at 4769 m. Results from permeability
measurements indicated that the sand was water bearing and tight, although
porosity readings from the core from this sand were surprisingly high. A
water-bearing formation was supported also by low background gas readings and
lack of shows while drilling through the interval. </p>

<p>One core was cut in the Rotliegendes
Group sandstones from 4805 m - 4814 m. An FMT sample taken at 4387 m (Lower Hod
Formation) recovered mud filtrate only. An FMT sample taken at 4770 m near the
top of the Rotliegendes Group recovered mud filtrate, with no indications of
hydrocarbons.</p>

<p>The well was permanently abandoned on 11
February 1985 as a dry well with shows.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed in the
well.</p>

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1/3-6
<p><b>General</b></p>

<p>Well 1/3-6 is located between the Gyda,
Ula, and Blane fields in the Central Graben of the Norwegian North Sea.</p>

<p>The primary objective was Late Jurassic
Ula sands deposited as a rim syncline linked to salt diapirism. The Ula sands had
been found hydrocarbon bearing in several wells in the surrounding blocks. Secondary
objective was Late Paleocene &quot;Cod sands&quot; (Forties Formation), which could
be present in the 1/3-6 area and could pinch out towards the diapir. The prognosed
TD was 5030 m below MSL. The &quot;Cod sands&quot; were considered a
low-probability target.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 1/3-6 was spudded with the
semi-submersible installation Dyvi Stena on 11 March 1991. Drilling performance went on without significant problems but the primary target of the well was
not reached. The discovery of a significant hydrocarbon-bearing reservoir in
the Paleocene activated the contingency measures of the programme (to set an
extra 11 3/4&quot; liner). For safety and technical reasons, and to allow for a
proper test of the Paleocene, the well was stopped at 3586 m in the Late
Cretaceous Hod Formation. No shallow gas was encountered while drilling. The
well was drilled with a KCl polymer mud.</p>

<p>The well encountered 85 m of hydrocarbon
bearing Forties sands at 2913.5 m. The pay zone was 44 m thick with a
hydrocarbon saturation of 56 %. No hydrocarbon-water contact was found. Apart
from the hydrocarbons in the Forties sands oil shows were also recorded from
3519 to 3530 m in the Tor Formation.</p>

<p>One conventional core was cut at 2921 m
to 2928.5 m in the Forties sands. Segregated fluid samples were taken at three
depths: 2923 m (filtrate and gas), 2937 m (filtrate and gas), and two samples
at 2973.5 m (filtrate and gas in one and filtrate only in the other).</p>

<p>The well was permanently abandoned on 22 June 1991 as a gas-condensate discovery.</p>

<p><b>Testing</b></p>

<p>Three DST tests were performed. DST 1A
and DST 1B both tested the interval 2960.5 - 2977 m. Due to packer failure</p>

<p>during DST 1A this test was abnormally
terminated and the re-test DST 1B was performed. DST 1B produced 78 Sm3 oil and
93300 Sm3 gas /day through a 44/64&quot; choke in the final flow period. The
GOR was 1196 Sm3/Sm3. The bottom hole temperature in this flow was 107.2 deg C.</p>

<p>DST 2 tested the intervals 2913 - 2924 m
+ 2929 - 2953 m. The final flow in DST 2 was 153 Sm3 oil and 172500 Sm3 gas
/day through a 48/64&quot; choke. The GOR was 1131 Sm3/Sm3 and the condensate
gravity was measured to 50.47 deg API. The pressure drawdown in this flow was
290 bar and the bottom hole temperature was 112.2 deg C. The maximum
temperature in DST 2 was 123.1 deg C and was recorded in the flow with the
lowest rates and lowest drawdown. It was believed to be closer to the true
formation temperature than the one recorded in DST 1B. </p>
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1/3-7

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-7 is located on the Hidra High
in the North Sea. It was drilled to appraise the 1/3-6 Oselvar condensate
discovery made in Paleocene Forties Formation sandstones. The well was placed
down-flanks on the structure relative to the discovery well in order to
penetrate the hydrocarbon-water contact and further appraise reservoir
properties and production rates. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/3-7 was spudded with the
3 leg jack-up installation West Epsilon on 13 February 1995 and drilled to TD
at 3345 m in the Paleocene Våle Formation. A gas kick was taken at 1740 m in
the top of the Hordaland Group, later it was found that the gas probably
originated from a limestone less than one meter thick. The hole packed off, the
string had to be cut off at 1564 m, and the hole was plugged back. A technical
sidetrack (1/3-7 T2) was made from 1204 m. This sidetrack failed as the bit
fell back into the original hole during a wiper trip. A new and successful
technical sidetrack (1/3-7 T3) was made from 1202 m. A second gas kick occurred
in the T3 sidetrack when reaching 1741 m. This kick was controlled by the driller's
method without significant problems or extra rig time. The extra activity
caused by the first kick prolonged the rig time with 23 days. Due to poor hole
conditions no open hole logging was performed in the 12 1/4&quot; section. As
the West Epsilon was available only up to 28 May open hole logging at final TD
was also abandoned in order to secure time for the well test. The reservoir was
logged through casing. The well was drilled with sea water down to 207 m and
with gelled mud from 207 m to 1204 m. From 3103 m to TD it was drilled with a
salt polymer.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Forties Formation was encountered at
3175 m. The Forties reservoir sandstones was encountered at 3183.5 m and proved
to be oil bearing down to an oil-water contact at 3225 m. The logs indicated
hydrocarbons down to 3229.4 m (3182.3 m MSL) and oil shows (direct and cut
fluorescence) were reported down to 3232 m. This lower zone was considered to
be only a residual oil zone, which was indicated also by the change in
geochemical composition. No oil shows were reported above the Forties reservoir
or below 3232 m, only background gas. The up-flanks 1/3-6 reservoir contains
condensate. Hence, the 1/3-7 well suggests a ca 490 m hydrocarbon column with a
gas/oil contact somewhere between the two wells. However, the depth of a GOC
could not be determined, nor could it be deduced with any certainty that there
is pressure communication between the reservoir sections penetrated in the two
wells.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 74.5 m core was cut and
retrieved in 4 cores in the interval from 3164 to 3251 m. No wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25
May 1995 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Two tests were performed on the
reservoir.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1A tested the interval 3183.5 to
3215.5 m. It produced 49 Sm3 oil and 16783 Sm3 gas /day through a 1/2&quot;
choke. The GOR was 333 with a well head flowing pressure (WHFP) of 15.4 bara. The
density of the oil was 0.797 g/cm3.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3183.5 to 3215.5
m and 3220 to 3224.5 m. It produced 136.8 Sm3 oil and 37762 Sm3 gas /day through
a 1/2&quot; choke. The GOR was 280.9 Sm3/Sm3, with a well head flowing pressure
of 35 bara. The formation temperature was measured in the tests to be 131.6 deg
C. The formation temperature was taken as the highest flowing temperature just
after opening the well for DST 1A. This is due to the temperature reducing with
time because of the thermal expansion effect of gas (BHFP &lt;&lt; Bubble point
pressure).</span></p>



2505
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1/3-8


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-8 is located on the Hidra High
in the North Sea. The primary objective was to test the Jurassic Upper Ula sand
package within the Kamskjell prospect. The secondary objective was a sand
package at the base of the Jurassic. Planned TD was tagging the Triassic or
reaching 5085 meters TVD SS.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/3-8 was spudded with the 3
legs jack-up installation Transocean Nordic on 12 December 1996 and drilled to
TD at 5199 m in the Triassic Smith Bank Formation. Two major unscheduled events
occurred in the 12 1/4&quot; section. First, the mud line hanger failed. A
total of 16 days was required to repair this before drilling could be resumed.
Secondly, and more serious, a 3.5 bbl kick was taken at 4529 m while drilling a
limestone interval in the Early Cretaceous Cromer Knoll Group. Based on the
worst case scenario interpretation of the kick, there could be a large volume
of hydrocarbons (estimated at up to 300 bbls) in the annulus between the kick
and thief zones. For this reason it was decided to rig up flare booms to
increase the rig safety should it become necessary to by-pass the MGS whilst
circulating out the influx. The well was opened up, and the influx circulated
out at 3.3 bpm. Initially returns were taken through the MGS. After pumping
1464 bbls returns were switched from the MGS to the boom. This decision was
taken as gas levels in the pit room were rising, and the seal leg pressure was
dropping steadily (from 11.5 to 6.4 psi) indicating the onset of possible
blow-down. The flare lit immediately with the clear burn characteristic of
condensate. A total of 420 bbls was flared before mud was at surface and the
flare extinguished. A total of 15 days were spent stabilising the well to
permit running casing and continue drilling the next section. The well was
drilled with seawater down to 303 m, with pre-hydrated gel mud down to 1105 m,
with KCl/polymer/glycol mud from 1105 m to 3445 m, and with Ancovert oil based
mud from 3445 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The only live hydrocarbons found in the
well was the condensate kick at 4529 m in the Cromer Knoll Group, believed to
originate from a fracture in the Sola Formation limestone. The target Upper Ula
Formation was not found in the well. Poorly developed and generally tight Basal
Jurassic sands were encountered at 5005 m with a pooled thickness of ca 22 m. Poor
oil shows were recorded in the interval 5007 to 5024 m in these sands. Thin
sands were present also in the Triassic, but no shows were recorded in these. </span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut in the interval 5024 to
5041 m with 15.07 m recovery. One FMT fluid sample was taken at 5006.3 m,
recovering muddy water with 190000 ppm of chloride.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27
May 1997 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>























































2829
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1/3-9 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S is located on the Tambar
Field on the Cod Terrace in the North Sea. The objective was to appraise the
possibility of commercial quantities of hydrocarbons in the Ula Formation sandstones
of the JU8 prospect (the Ula Formation is sometimes referred to as the &quot;Gyda
Sandstone Member&quot; in this part of the North Sea). The well was planned deviated
to avoid shallow gas anomalies and to fully appraise the target sand.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S was spudded with the semi-submersible
installation Mærsk Jutlander on 8 May 1998 and drilled to 3100 m where hole
problems led to plug-back and a sidetrack (1/3-9 S T2) with kick-off at 1836 m.
Final TD of the well was set at 4516 m in the Late Jurassic Ula Formation. The
well was drilled with seawater and hi-vis pills down to 1050 m, with Barasilc
WBM from 1050 m to 3185 m, and with Enviromul OBM from 3185 m to TD. Total
Non-Productive time for the well was 40%, most of which was due to
contamination of the mud system, the side-track of the well and the TD logging
performance. The 12 1/4&quot; Section was notably different from plan, after an
unexpected water kick was taken at 2535 m. This not only reduced the mud
systems ability to accept contaminants, with a required MW increase up to
1.7sg, but also severely reduced the ROP, due to high overbalance drilling,
later in the section. This also resulted in setting the 9 5/8&quot; casing
high, leaving reactive shales open whilst drilling the 8 1/2&quot; section. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Palaeocene Forties sands of the 1/3-6
and 1/3-7 wells were not encountered.</span><span
lang=EN-GB>The target Ula Formation sandstone was encountered at 4266.3 m, 33.7
m high to prognosis. It was oil-bearing with an estimated OWC at ca 4375 m. Oil
shows, both fluorescence in cuttings samples and drilled gas with the
compositional range of C1 - C5, were observed through the interval 4273 - 4377 m,
within this unit. No other shows were recorded in the well. Analysis of MDT
pressure revealed a 550 psi difference compared to well 1/3-3 and Gyda well
2/1-6. This is interpreted as being a result of depletion from Gyda oil
production, and suggests there is significant communication through the aquifer
between the JU8 structure and the Gyda Field.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 105 m of core was cut in two
cores in the Ula Formation. A total recovery of 99.7% was obtained,
representing the two longest core recoveries in the area. MDT oil samples were
taken at 4279.5 m, 4304.98 m, and at 4346.49 m. Following extensive logging of
the well, a 7&quot; liner was run in preparation for future development. The
well was temporarily suspended on 31 July 1998, with a combined trawl guard and
corrosion cap left on top. In June 2001 it was re-entered and reclassified to
development well on the Tambar and Tambar Øst Fields.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/3-9 S is classified as an appraisal
of the 1/3-3 Tambar Discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


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1/5-1



<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Flyndre (1/5-1) well was drilled on a
structural high situated in the Feda Graben of the North Sea close to the UK
border.  At the commencement of the well the principle objective horizons were
the Paleocene and Jurassic sand sections which had produced oil in the UK 30/13-2
well and the NO 2/7-3 wells respectively.  It was estimated that at Paleocene
depth the structure was an irregular dome about 4 miles in diameter, with 12 square
miles of closure and 290 ft (88.4 m) of vertical relief while at Jurassic depth
the structure was a NW-SE trending anticline 4.5 miles by 3.5 miles with 12
square miles of closure at 190 ft (57.9 m) of vertical relief. Planned TD was
15000 ft (4572 m), Triassic sands, or the Zechstein Group, whichever came
first.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/5-1 was spudded with the
semi-submersible installation Ocean Viking on 12 October 1973. The well was
drilled to 491 m in the Nordland Formation. When running 20&quot; casing the
casing got stuck. After an unsuccessful fishing operation the well was permanently
abandoned on 19 October 1973 as a junk well. No cores were cut and no wire line
fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Replacement well 1/5-2 was spudded 15 m
away in a 320 deg true direction.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>






















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1/5-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Flyndre well (1/5-2) was drilled on a
structural high situated in the Feda Graben of the North Sea close to the UK
border. The principle objective horizons were the Paleocene and Jurassic sand
sections which had produced oil in the UK 30/13-2 well and the NO 2/7-3 wells. It
was estimated that at Paleocene depth the structure was an irregular dome about
4 miles in diameter, with 12 square miles of closure and 290 ft (88.4 m) of
vertical relief while at Jurassic depth the structure was a NW-SE trending
anticline 4.5 miles by 3.5 miles with 12 square miles of closure at 190 ft (57.9
m) of vertical relief. Planned TD was 15000 ft (4572 m), Triassic sands, or the
Zechstein Group, whichever came first. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><a name="OLE_LINK2"></a><a name="OLE_LINK1"><span
lang=EN-GB>Well 1/5-2 </span></a><span lang=EN-GB>was spudded on 19 October
1973, 15 m away from the original Flyndre well 1/5-1, which was junked at 491 m
for technical reasons. Well 1/5-2 was drilled with the semi-submersible
installation Ocean Viking. Total depth was set at 4287 m in Late Permian Zechstein
salt. The well was drilled with seawater and hi-vis pills down to 494 m. The
rest of the well was drilled with lignosulphonate mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well had shows throughout the
Paleocene and Late Cretaceous sections and four drill-stem tests were carried
out.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top sand in Paleocene at 2832 m (Forties
Formation sand) produced oil upon testing. Mud log shows were present in the
Danian, but testing proved the section to be tight and unproductive. A thick Late
Cretaceous section was encountered with oil shows at the top of the Maastrichtian
(Tor Formation) and in the Campanian (Lower Tor and Hod Formation) sections. Drill-stem
tests were carried out in these zones and the Maastrichtian zone produced oil
from fractured limestone at 3151.6 - 3174.2 m while the lower zone from 3337.6
- 3363.2 m was tight with only minor amounts of oil being recovered. The Early
Cretaceous section, 281 m thick, consisted of sediments of Albian/Aptian and
Barremian age. There were no shows in this section. The Jurassic, section was encountered
at 4203 m but contained only 24 m of Kimmeridgian shale. The Kimmeridgian
rested directly upon the Zechstein Group at 4228 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15
April October 1974 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Four intervals were perforated and
tested.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST I tested the interval 3337.6 - 3363.2
m in the lower Hod and upper Tor Formations produced a total of 5.6 Sm3 oil and
17.5 m3 of water. The oil gravity was 35 deg API.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST II tested the interval 3151.6 - 3174.2
m in the Tor Formation produced 501 Sm3 oil, 180661 Sm3 gas, and 49 m3 water
/day through a 54/64&quot; choke. The GOR was 361 Sm3/Sm3 and the oil gravity
was 42 deg API. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST III tested the interval 3076.7 -
3102.9 m in the Ekofisk Formation produced total 30- 40 m3 water with 6 -
20% oil.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST IV tested the interval <a
name="OLE_LINK4"></a><a name="OLE_LINK3">2831.6 - 2841.3 m </a>in the Forties
Formation. It produced 37 sm3 oil, 16707 Sm3 gas, and 24 m3 water /day. The GOR
was 456 Sm3/Sm3 and the oil gravity was 42.6 deg API.</span></p>


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1/5-3 S
<p><b>General</b></p>

<p>Block 1/5 is situated in the Norwegian
Central Trough at the transition of the Feda Graben and the Breiflabb Basin.
Well 1/5-3 S was planned as an exploration well with TD at 2910 m in the Tor
Chalk Formation. The well was positioned in a seismically defined &quot;gas
chimney&quot; on the crest of a salt induced diapir and was the first well
drilled on this diapir. Similar cases have been drilled successfully by STATOIL
on the Tommeliten Discovery 1/9-2 and 1/9-3 wells. The primary objective of
well 1/5-3 S was to test the presence of moveable hydrocarbons in fractured,
reservoir quality chalk of the Ekofisk and Tor formations along the
southwestern flank of the diapir. A secondary potential objective was in the
Paleocene Rogaland Group. A total depth of 1566 m was reached in the 12
1/4&quot; hole section on June 29, 1998 before deciding to permanently abandon
the well due to increasing pore pressure, without fulfilling any of the well
objectives.</p>

<p><b>Operations and results</b></p>

<p>Exploration 1/5-3 S well was spudded with
the semi-submersible &quot;Byford Dolphin&quot; on 10 June 1998 and drilled to
TD at 1566 m in rocks of Late Miocene age (undifferentiated Nordland Group).
The well was drilled with seawater and hi-vis pills down to 792 m and with
Baroid &quot;BARASILC&quot; silicate / KCl glycol enhanced (&quot;GEM GP&quot;)
mud from 792 m to TD. Due to possible shallow gas hazard at 466 m, a 9
7/8&quot; pilot hole was drilled below the 30&quot; conductor to 780 m. The 9
7/8&quot; hole was opened up to 26&quot; at 792 m prior to setting 20&quot;
casing at 785 m. No shallow gas was observed from the MWD resistivity in this
hole section.</p>

<p>Record setting overpressures were
experienced in the 17 1/2&quot; hole section in well 1/5-3 S. Abnormal pressures
were indicated first at 700 - 800 m. Pore pressures built quickly to 1.4 g/cc
due to gas just below 1000 m in. Having passed that depth, the hole drilled
without problems until below 1200 m where it again became gassy. Mud weight was
increased to 1.52 g/cc, thus reducing 30% gas to 5-10%. This weight was
sufficient until below 1400 m when gas again increased. By 1450 m, the DXC was
beginning to show signs of increasing pore pressure, as was the MWD
resistivity. Below 1500 m, gas went off scale and an oil kick to 1.70 BMW was
taken at 1544 m. Pressures of this magnitude were not forecast at all. Lost
circulation was experienced during well control operations, which eventually
lead to cementing of the BHA, and plugging back to sidetrack around the fish.
The 17 l/2&quot; hole was re-drilled as 1/5-3 S T2 from 1246 m to a revised 13
3/8&quot; casing point at 1412 m. Although re-drilled with 1.60 g/cc mud weight
versus the original 1.52 g/cc mud, the hole drilled nearly as gassy as the
original hole. Following the 13 3/8&quot; casing, an excellent leak-off was
tested to nearly overburden gradient at 1.98 BMW. </p>

<p>The 12 1/4&quot; drilling was done with
Statoil's Tommeliten method which emphasized ignoring gas in favour of other
pressure parameters while minimizing mud weight builds but this proved to be
unsuccessful for 1/5-3S. After drilling out with 1.76 g/cc mud weight, the hole
became so gassy (up to 50%) from limestone stringers oozing oil that it had to
be circulated clean at 1494 m, and 1.80 g/cc mud was circulated around. This
should have balanced the 1.7 BMW kick zone coming up at 1544 m, as well as
leading to increased confidence, as gas and cuttings size would diminish.
Although the cuttings remained small until growing to 7 cm splinters near TD,
gas was again off scale. By 1566 m, only 22 m beyond the second kick zone, the
well was shut-in. 1.86 g/cc mud weight was required to balance the formation,
and 1.90 g/cc mud weight was eventually circulated around on a dead well. Well
1/5-3 S T2 had transitioned from a pore pressure of 1.7 EMW at 1544 m to 1.86
EMW at 1566 m in only 22m of new hole. At this point the decision was taken to
plug and abandon the well.</p>

<p>Three kicks taken were regional records
for both overpressure magnitude and shallowness of depth. Statoil's Tommeliten
Field in block 1/9 did not see anywhere near the overpressure magnitude and shallow
onset; mud weight was able to control mud gas far more successfully on
Tommeliten and multiple hydrocarbon kicks were not experienced. Conoco's 1/6-5
crestal diapir well also exhibited a lesser overpressure profile. In hindsight
the most important methods to monitor the pressure during drilling were the MWD
resistivity and the cuttings shape and size. Gas in the mud was carefully
monitored and plotted in units of percent methane in air. Gas was commonly 5%
in the claystones, some of which showed bleeding gas at the surface, and ran
30-50% and higher in the carbonate stringers, which bled oil at the surface.
The gas chimney section drilled with high gas background all the way from the
top of overpressure to the terminal kicks below 1500 m. While the mud gas gave
a general indication of overpressure, the high background levels actually
obscured both of the final two kicks. </p>

<p>Good trace of crude oil in the mud was
observed from 1498m. At 1544 m, a kick was taken which resulted in crude oil
being circulated up to the rig. Circulating gas varied between 40-100%, with
peaks way above 100% caused by large amount of hydrocarbons. The crude oil
collected at surface was dark yellowish brown and had a density of 0.84 g/cc
(37 API) measured with a pressurised mud balance. Later laboratory analysis
onshore gave a density of 0.80 g/cc (35.1 API).</p>

<p>No conventional or sidewall cores were
taken in this well. The well was permanently abandoned as a junked well with minor oil on 6
August 1998.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


3257
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1/5-4 S

<p><b>General</b></p>

<p>The primary objective of the 1/5-4 S well
was to test the hydrocarbon bearing potential of a Chalk prospect close to the
crestal position on the NE side of a salt diapir. The well path was also
planned to penetrate the edge of a mapped Palaeocene fan system. Hydrocarbon
bearing Forties sandstone were targeted and treated as a secondary objective.
Thicker and better quality sandstones were expected to be present down flank of
the structure. </p>

<p>The overburden was known to contain charged
feature, as experienced by the Conoco well 1/5-3 S. In order to avoid these
fractures and the associated well bore instability problems, a delineated well
path using Oil Based Mud was planned from the 12.25&quot; hole section to
TD.</p>

<p><b>Operations</b></p>

<p>Exploration well 1/5-4 S was spudded with
the semi-submersible installation Deepsea Bergen on 17 April 2002 and drilled
deviated to TD at 3090 m in rocks of Permian age. Drilling went very well and
closely followed the plan. The well was drilled with seawater and gel sweeps
down to 928 m and with KCl/Glycol mud from 928 m to 1646 m, and with oil based
mud from 1646 m to TD. </p>

<p>Top Palaeocene was encountered 55 m
higher than prognosis. Two thin sandstone beds were drilled, both within the
Lista formation (Andrew Formation sandstones). The lower stringer was tight but
contained some shows. The upper stringer had better reservoir properties
however. Forties sandstone were absent. The primary objective, the Chalk, was
118 m higher than forecast, and 49 m thick, which was 80 m thinner than
expected. The chalk was found to be water saturated with a maximum porosity of
25 %, and in pressure communication with the thin Palaeocene Andrews sand
stringer. Minor shows were reported in the chalk. No sidewall or conventional
cores were cut. An FMT sample was taken at 2945 m. It recovered only water. The
well was permanently abandoned as a dry well with shows on 24 may 2002</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


4521
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1/5-5
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/5-5 was
drilled to test the Solaris prospect in the Central Graben, about 40 km
North-West of the Ekofisk field, close to the border between UK and Norway.
The primary target was to prove reservoir and hydrocarbon presence in Late Jurassic
reservoir sands of the Ula Formation. Secondary target was the Triassic
Skagerrak Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/5-5 was spudded with the jack-up
installation Mærsk Gallant on 24 February 2016 and drilled to TD at 5942 m in
the Middle - Late Vestland Group. A pilot hole was drilled from 210 to 1140 m
to check for shallow gas, but no gas was seen and the opening up and
continuation of the well could be carried out. The well is a deep high
temperature-high pressure well. Thirty-nine days were counted as NPT. The
single main cause of NPT (11 days) was main rig maintenance and changing the
drilling line after installing BOP at 1140 m. Otherwise operations proceeded
without significant problems. The well was drilled with seawater and hi-vis
pills down to 1140 m, with NABM oil based mud from 1140 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The primary target Ula Formation
sandstone was encountered at 5831 m. The Ula Formation was 80 m thick and
consisted mainly of sandstones and a few siltstones. The reservoir showed
traces of gas and wireline logging was carried out for further classification.
The logging proved the reservoir tight, of moderate to poor quality, and dry.
There were no shows above the oil-based mud. As the primary reservoir was found
dry, it was decided not to continue to the secondary, Triassic target.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
September 2016 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>






















































































7874
3/16/2018 12:00:00 AM
29.01.2023
1/6-1
<p><b>General</b></p>

<p>Wildcat well 1/6-1 is located ca 15 km
northwest of the Ekofisk Field in the southern Norwegian North Sea. It was
drilled in a crestal position on a large chalk structure shared between Norske
Shell's block l/6 and Phillips' block 2/4, the Ekofisk block. Phillips
participated in drilling this well on a 50/50 basis. The primary objective was
to investigate Danian and Maastrichtian chalk prospects. Secondary objective
was to evaluate possible sand developments in the Paleocene and the Lower
Cretaceous or older units. Planned total depth was 4572 m (1500 ft).</p>

<p><b>Operations and results</b></p>

<p>Well 1/6-1 was spudded with the jack-up
installation Zapata Nordic on 10 July 1972 and drilled to TD at 4822 m in the
Late Permian Zechstein Group. No major technical problems were encountered in
the operations and the drilling of this deep well was within the prognosed time
schedule. The drill string stuck at 228 m. After working the string and
spotting pipe-free/diesel the string came loose. Some highly porous limestone
intervals (1 - 8 m thick) resulted in lost circulation problems. The pipe stuck
at 3456 m, but was freed after spotting with pipe-free/diesel. The well was
drilled with seawater down to 448 m, with seawater/lignosulphonate and a shale
inhibitor (shalock) from 448 m to 1586 m, and with
seawater/lignosulphonate/ligcon (caustisized lignite) from 1586 m to TD.</p>

<p>Reservoir development was encountered
only in the Chalk Formations, with hydrocarbon-bearing intervals being
developed in both the Danian and Late Cretaceous. Four hydrocarbon-bearing
intervals were encountered and tested within the Chalk, but only one zone in
the Maastrichtian (Tor Formation), yielded commercial flows of gas and
condensate. Reservoir developments in the Danian (Ekofisk Formation) and
earlier Maastrichtian (Hod Formation) were found to be considerably less
favourable in l/6-l than in the adjacent Ekofisk and West Ekofisk field. The
Early Cretaceous (Valanginian) was found resting directly on Late Permian
Zechstein evaporite at 4800 m.</p>

<p>Two cores were cut in the intervals
3177.5 to 3189.7 m and 4604.6 to 4610.7 m. No fluid samples were taken on wire
line.</p>

<p>The well was permanently abandoned on 26
November as a gas/condensate discovery.</p>

<p><b>Testing</b></p>

<p>Based on results from logging four zones
were perforated and tested. </p>

<p>Zone 1 was perforated from 3821 to 3833 m
in the (DST 1, Hod Formation). The test produced only a small quantity of gas
and traces of light crude/acid emulsion. </p>

<p>Zone 2 was perforated in the intervals
3653.6 - 3650.6 m, 3646.0 - 3647.5 m, and 3621 - 3632.2 m (DST 2, Hod
Formation). The test produced ca 65 Sm3 fluid (50% oil) /day. </p>

<p>Zone 3 was perforated from 3270.5 m to
3279.6 m (DST 3,Tor Formation). The test produced at maximum 451 Sm3 oil and
480400 Sm3 gas /day. The rates decreased during the test and the GOR changed
accordingly from 1070 to 1330 Sm3/Sm3. Oil gravity was 46.8 deg API. Maximum
down hole temperature was 135 deg C. </p>

<p>Zone 4 was perforated from 3152.9 m to
3158.9 m (DST 4, Ekofisk Formation). After acidization the test produced 24 Sm3
oil, 52000 Sm3 gas, and 29 Sm3 water / day. Oil gravity was 46.3 deg API, gas
gravity was 0.745 (air = 1), and GOR was 2180 Sm3/Sm3. </p>

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1/6-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/6-2 was drilled between the
Albuskjell and Flyndre Fields in the Feda Graben of the North Sea. The primary
objective was to evaluate the Danian and Maastrichtian Chalk prospects (Ekofisk
and Tor Formations) of a prominent diapiric domal structure. The well was
placed on the flank of the structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-2 was spudded with the jack-up
installation Zapata Nordic on 28 November 1972 and drilled to TD at 3383 m in
the Late Cretaceous Hod Formation. Some downtime recorded in the top hole was
due to a defect 20&quot; casing shoe and bad weather, otherwise operations went
forth without significant problems. The maximum deviation down to 3226.6 m was
3.5 deg. The well was drilled with Sea water and viscous mud down to 460 m,
with Shaletrol mud from 460 m to 2445 m, and with Unical mud from 2445 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>In the Tertiary shale sequence potential
reservoirs were limited to a few very thin (0.5 m or less) limestone or
dolomite streaks. Top of the Chalk was encountered at 3024 m. The reservoir
development in the Chalk was rather poor throughout, with the exception of a
zone of ca 12 m in the Danian Ekofisk Formation having a porosity of about 26%.
The Chalk formations were entirely water bearing as seen on the logs. However,
weak hydrocarbon indications were observed in the Chalk (namely weak
fluorescence and occasional slight oil staining), and relatively more abundant
indications of oil staining and dead oil traces were recorded in the overlying Tertiary
shales and interbedded carbonate layers.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 3226.6 m to 3241.5
m in the Tor Formation. The core confirmed the generally dense nature of the
Chalk in this section. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
January 1973 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



240
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1/6-3
<p><b>General</b></p>

<p>Well 1/6-3 is located on the Albuskjell
Field in the southern Norwegian North Sea. The primary objective was appraisal
of reservoir development in the western part of the Albuskjell field. A Danian
- Maastrichtian gas condensate field had previously been confirmed by two wells
(A/S Norske Shell l/6-l and Phillips 2/4-9) drilled farther east along the WNW
- ESE trending structure. Secondary objectives were to investigate Danian Chalk
prospect and possible deeper prospects. </p>

<p><b>Operations and results</b></p>

<p>Appraisal well 1/6-3 was spudded with the
jack-up installation Zapata Nordic on 12 April 1974. Three sidetracks had
finally to be drilled, of which the second and deepest reached 3343 m in the
Late Cretaceous Tor Formation. The first sidetrack was kicked off at 314 m
after unsuccessful fishing (lost hole opener). The second sidetrack was kicked
off at 3022 m when it was realised that a core point had been missed so that a
Danian porous zone and 37 m of Maastrichtian had not been cored. Lost circulation
and stuck pipe led to the third side track, which was kicked off at 2995 m.
Further lost circulation problems and the discovery that there was a break in
the casing at 3140 m finally led to abandonment of the well without
investigating the deeper prospects. The well was drilled with seawater down to
417 m, with shale-trol/lignosulphonate from 417 m to 1221 m, with
shale-trol/lignosulphonate and lime from 1221 m to 2500 m, and with
lignosulphonate and lime from 2500 m to TD. A diesel/pipe lax pill was spotted
at 314 m.</p>

<p>As prognosed, gas was encountered both in
the Danian and Late Maastrichtian Chalk. Hydrocarbons were present from Top
Ekofisk at 3110 m down to an OWC at 3289.7 m in the Tor Formation. The net
thicknesses were respectively 91 and 45 m. The great thickness of the Danian
reservoir was in contrast to the findings from wells l/6-l and 2/4-9, where
only a thin hydrocarbon-bearing zone was present in an otherwise tight Danian. </p>

<p>Eleven conventional cores were cut over
the interval 3123.3 to 3343.0 m. Of these, the first core was cut from 3123.3
to 3141.5 m in the first sidetrack, cores 2 to 9 were cut from 3162.3 to 3343 m
in the second sidetrack, and cores 10 and 11 were cut from 3136.4 to 3163.8 m
in the third sidetrack. No fluid samples were taken on wire line.</p>

<p>The well was permanently abandoned on 11
September 1974 as a gas/condensate appraisal.</p>

<p><b>Testing</b></p>

<p>Two thin zones in the Maastrichtian chalk
(Tor Formation) were Drill Stem Tested to obtain water samples. DST 1 tested
the interval 3298 to 3299.5 m and started to produce gas, which had flown down
the 7&quot; / 8 l/2&quot; annulus in preference to water from the formation
opposite the perforations. The well was killed immediately for safety reasons.
DST 2 was then attempted from the interval 3302.5 to 3304 m after a cement
squeeze to shut of the annulus gas stream. The Formation proved tight and only
gas cut mud was obtained. No water sample was obtained.</p>

<p>The hydrocarbon bearing zones were
Production Tested in two intervals: PT 1 from 3227.8 to 3265.9 m in the
Maastrichtian chalk (Tor Formation) and PT 2 from 3125.7 to 3166.9 m in the
Danian chalk (Ekofisk Formation). PT 1 produced after acid treatment on a
28/64&quot; choke 541000 Sm3 gas and 409 Sm3 oil /day The GOR was 1325 Sm3/Sm3,
the oil gravity was 47 deg API, and the gas gravity was 0.67 (air = 1). Maximum
reservoir temperature (from build up period between 1.and 2. flow period) was
137.2 deg C. Unfortunately, no successful test was made of the Danian reservoir
in Test 2, from the interval 3125.7 to 3166.9 m. This was due to plugging by
formation and lost circulation material from the tested interval. In this zone,
the Danian consisted of very friable, fractured chalk. The well slugged badly
and gave unstable measurements. Average rates were 325000 Sm3 gas and 318Sm3
oil /day, with similar fluid characteristics as in Test 1.</p>


241
4/26/2022 12:00:00 AM
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1/6-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/6-4 was drilled in the southernmost
part of the Breiflabb Basin in the North Sea. The objective was to evaluate a
large low relief base Tertiary - Late Cretaceous structure with potential
reservoirs both in the Danian - Late Cretaceous Chalk and in the Paleocene
Sands. The primary target was the Chalk (Ekofisk and Tor formations).</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-4 was spudded with the
semi-submersible installation Chris Chenery on 29 December 1975 and drilled to
TD at 3810 m in the Late Cretaceous Tor Formation. The drilling of 1/6-4 was
beset with rig mechanical problems, most notably failures in the mooring system
induced by adverse North Sea weather. All in all 34 days (ca 33%) of the total
rig time on the well was counted as down time. The well was drilled with bentonite/seawater
spud mud down to 437 m and with lime/Drispac/seawater mud from 437 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Rogaland Group, Balder Formation,
came in at 3110 m. A Paleocene sandstone, Andrew Formation was penetrated from
3197 to 3253 m. Top Shetland Group, Ekofisk Formation, came in at 3374 m. The Balder
Formation (Tuff marker) had some residual hydrocarbons up to 30%. This was
substantiated by gas readings and some shows of fluorescence in ditch cuttings.
The underlying Andrew Formation sandstones were found 100% water-bearing. Both the
Danian and Maastrichtian were fully water bearing based on petrophysical
analyses. This was in agreement with the lack of oil/gas shows while drilling
in this section.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9
April 1978 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



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1/6-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/6-5 is located in the Feda Graben
between the Flyndre and Tommeliten Gamma discovery in the North Sea. The well
was drilled on the crest of a major salt diapir. The objective of the well was
to test the existence of a chalk raft and the presence of reservoired
hydrocarbons.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-5 was spudded with the
semi-submersible installation Dyvi Stena on 20 July 1990 and drilled to TD at 1854
in Late Permian salt of the Zechstein Group. An 8 1/2&quot; pilot hole was
drilled from 156m to 600m. The hole was control drilled at 30m/hr maximum ROP
as a precaution for encountering shallow gas. No shallow gas was encountered. Pore
pressure prediction while drilling in the 1/6-5 well was difficult as the only
pore pressure detection parameters that appeared to work were gas measurements,
resistivity and sonic log measurements. Other parameters such as shale cuttings
density, Electric log density, D-exponent and rate of penetration were not
successful in determining high pore pressure zones. However, despite the
abnormally high pressures and temperatures encountered drilling went forth
without major incidents. A minor salt water flow accompanied by a 37.1 % gas
peak occurred during a trip at core point at 1725 m. The mud weight was
increased from 15 ppg to 15.3 ppg and finally 15.5 ppg as a result of this flow.
In the following coring 119 bbls of mud was lost to the formation, but this was
cured by setting an LCM pill. The well was drilled with seawater and viscous pre-hydrated
bentonite sweeps down to 600 m and with fresh water polymer mud/Duponol WBS 200
wellbore stabilizer from 600 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>From 864 m gas readings showed all
components from C1 to C4. Gas peaks from the formation were experienced all the
way down to the Ekofisk Formation, some of which originated from thin sandstone
beds. Oil shows were first observed at 1434 and 1585 m, both in thin limestone
beds of Oligocene age. On reaching the top Ekofisk Formation at 1721 m,
limestone with oil stain and bright yellow fluorescence was observed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from
1725 to 1742.5 m in the Tor and Hod Formations. Only 22% was recovered and most
of it was rubble, indicating a highly fractured limestone. Core 2 was cut from
1742.5 to 1751.5 m in the salt. Ten RFT pressure tests were taken in the Shetland
Group of which 6 were classified as valid tests. They indicated a formation
pressure in the range of 4520 to 4540 psi, being equivalent to 15.6 ppg
equivalent mud weight. No obvious pressure gradient could be derived from these
6 points.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2
September 1990 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One drill stem test was performed from
perforations in the Shetland Group from 1722 to 1740.9 m. The well flowed only
salt water at a rate of 231 m3/day on a 24/64&quot; choke. There was no trace
of oil and the gas content was too low to be measured. The shut-in pressure after
final build-up was 4531 psia. The maximum bottom hole temperature recorded in
the test was 98.3 deg C. This corresponds to a mean gradient of 56 deg C/km,
assuming 6 deg C at the sea floor. This is an exceptionally high temperature
gradient for the Norwegian North Sea.</span></p>



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1/6-6

<p><b>General</b></p>

<p>Well 1/6-6 is located ca 2 km south of
the Albuskjell Field in the southern Norwegian North Sea. The principal
objective was to test the hydrocarbon potential of Middle and Late Jurassic
sandstones on the southern flank of a faulted dip closure, partially underlying
the Albuskjell Chalk Field. It was proposed to drill to a total depth of 5355 m
or 200 m below the interpreted Base Late Jurassic.</p>

<p><b>Operations and results</b></p>

<p>Well 1/6-6 was spudded with the
semi-submersible installation Dyvi Stena on 10 February 1992 and drilled to
final TD at 5565 m (5562 m TVD), some 100 m into Triassic siltstone. The well
achieved its objective, which entailed drilling 210 m deeper than plan, to a
new Norwegian depth record of 5565 m RKB. Maximum pore pressure in the well was
estimated to have been 2.24 sg, higher than the worst-case scenario defined by
the well proposal. BHT was 190 deg C. Both pore pressure and BHT were the
highest yet encountered in Norway. The well was production tested under these stringent
conditions. </p>

<p>Including additional time, the planned
work scope for the well was 179.5 days. It eventually took 395 days. Of these,
only 204.5 days (51.8%) was considered productive time. Five incidents
accounted for 75% of lost time. These were: dropped 10-3/4&quot; casing, failed
wellhead, well control incident, failure of the HPC tieback packer and waiting
on weather. The problems involved two sidetracks. The dropped 10-3/4&quot;
casing with TD at 4467 m led to the first sidetrack, which was made from kick-off
at 2560 m. Then, after drilling to 3284 m and tripping out, a second sidetrack
was accidentally made from 2522 m.</p>

<p>The well was drilled with seawater and
viscous sweeps to 1127 m and with gypsum / polymer mud from 1127 m to 4466 m in
the first hole. The first sidetrack was drilled with gypsum/polymer mud from
kick-off to TD. The second and final sidetrack was drilled with VISPLEX for
sidetracking, then with HF PLUS (glycol) down to 4478 m, and with HITEMP
polymer mud from 4478 m to TD. </p>

<p>Top Paleocene was encountered at 3108 m.
Weak shows were recorded in the Lista Formation. The Shetland Chalk Group was
encountered at 3306 m and was 1345 m thick. The Late Jurassic Tyne Group was
penetrated at 4876 m, and a &quot;basal sand&quot; of Early Kimmeridgian - Late
Oxfordian age at 5396 m. The gross thickness of the sandstone was 61 m. There
were indications of hydrocarbons in this sand, but a DST produced only water.
No Middle Jurassic rocks were penetrated. Age at TD is not confirmed by
biostratigraphic evidence as samples and core was barren of fossils.</p>

<p>One ten-metre core was cut at TD in the
well. During several FMT runs over the interval 5075 - 5450 m a total of 32
pressure settings were attempted, of which some 10 pressure points were
considered useful. Two segregated samples were taken at 5432 and 5398 m. Both
recovered only mud filtrate.</p>

<p>The well was plugged and permanently
abandoned on 8 March 1993 as a dry hole with shows.</p>

<p><b>Testing</b></p>

<p>The well was tested in the interval 5396
- 5407 m. The test flowed 900 Sm3 salt-saturated formation water and 4300 Sm3
gas /day through a 32/64&quot; choke</p>



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1/6-7


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/6-7 is located in the Feda Graben
of the North Sea, approximately mid-way between the Albuskjell and Tommeliten
Gamma fields. It was drilled on the flank of a salt diapir. The primary
objective of the well was to test the hydrocarbon potential of Late Jurassic
sandstones. Two secondary objectives were identified; to test for hydrocarbons
in the Cretaceous Chalk and to test for the development and the hydrocarbon
potential of Paleocene sands.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/6-7 was spudded with the
semi-submersible installation West Vanguard on 16 March 1992 and drilled to TD
at 4995 m (5001 m logger's depth / 4925 m TVD). A 9 7/8&quot; pilot hole was
drilled from 170 to 1007m prior to the 26&quot; section to check for possible shallow
gas at 311, 351, and 397 m. No shallow gas was seen. MWD check-shots inside the
20&quot; casing (azimuth unreliable) proved that the well had sidetracked in
the 26&quot; hole. In the 12 1/4&quot; hole a steerable assembly was run in
hole to correct the course. This twisted off, leaving a fish at 3740 m. The
well was plugged back to 3550 m and the well was sidetracked from 3650 m. After
the sidetrack the azimuth stayed fairly constant in a northwest direction. The
inclination, though, increased. In the 12 1/4&quot; hole from 3515 m to 4329 m
the angle built from 3.73deg to 13.52deg. The angle kept building in the 8
1/2&quot; hole until a maximum MWD survey of 31.40deg at 4701m. At this depth
the bit was pulled out of the hole for an intermediate logging run and to
change the BHA to an angle dropping assembly. This assembly dropped the
inclination to 24.7deg by TD. At 4878 m, in the top of Sandstone Unit II, a
salt water kick was taken. The well was drilled with seawater with viscous
pre-hydrated bentonite sweeps down to 1007 m, with inhibitive polymer mud
system utilizing WBS-200 wellbore stabilizer to from 1007 m to 1400 m, with
PHPA inhibitive polymer mud from 1400 m to 3273 m, and with high temperature
polymer system mud from 3273 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Weak to fair shows in the claystone and
limestone were seen in several intervals from 2680 to 2950 m (Hordaland Group),
and free tarry oil in the mud was observed from 2912 - 2945 m (claystone with
stringers of limestone and dolomite). The tarry oil was described as dark brown
to black, with a resinous lustre, orange to yellow direct fluorescence,
moderate to fast streaming yellowish cut and had a dark brown residue. The
Chalk objective was drilled outside of structural closure and top Ekofisk
Formation was penetrated at 3278 m (3275 m TVD). Moderate shows were described here
in a zone from 3288 to 3293 m with weaker shows continuing down into core #1,
and on cuttings further down to 3420 m. The electrical logs indicate an average
porosity of 17.5% in this zone. BCU (top Mandal Formation) was penetrated at
4402.5 m (4388.6 m TVD). Two sandstone units of Oxfordian age, Sandstone Unit II
(4750 - 4788 m / 4706.4 - 4739.7 m TVD) and Unit I (4879 - 4977 m / 4820 -
4907.5 m TVD) were penetrated. Average porosities of the Units were 16.1 and 21.5
% respectively.</span><span lang=EN-GB> </span><span lang=EN-GB>Shows in
Sandstone Unit II (4750-4788m, Core #2 and #3) were described as very weak to
no direct fluorescence, slow even bluish white crush cut, and faint creamy
residue fluorescence. Shows in Sandstone Unit I (4879 - 4977 m) appeared with
no fluorescence, no cut, minor traces of slow even bluish white crush cut and
traces of creamy residue fluorescence. The cuttings in this unit had a good gas
odour.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut with 100, 94.7, and
98.5% recovery, respectively. The first core was cut in the upper part of the
Ekofisk Formation (3295 m - 3313.9, m) and the next two in the Haugesund
Formation (4754 - 4773 m and 4773 - 4800.57 m respectively) in Sandstone Unit
II and into the underlying shale. In order to match the gamma ray log cores #1,
#2, and #3 has to be shifted + 1.2 m, +6.5 m, and +5.5 m, respectively. A total
of 10 FMT pressure tests and one fluid sample were taken in Sandstone Unit I.
Calculated pressure gradient in this sandstone is 0.52 psi/ft (0.12 Bar/m). The
fluid sample, at 4884 m, contained water and mud filtrate only.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
July 1992 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



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1/9-1




<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-1 was drilled on a salt diapir
structure located in the Feda Graben in the southern North Sea. The primary objective
was to test hydrocarbon accumulations in the Danian and Late Cretaceous chalk. A
secondary objective was to test the Jurassic and Triassic sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/9-1 was spudded with the
semi-submersible installation Ross Rig on 14 October 1976 and drilled to TD at
3706 m in Cenomanian age limestone (Hidra Formation). The Jurassic was not
reached. The anchor chain broke on three occasions. The third breakdown occurred
during the last DST. The decision was then made to suspend the well for later
re-entry. The well was drilled with seawater and gel slugs down to 433 m, and
with seawater-lime-lignosulphonate from 433 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Danian chalk (Ekofisk Formation) was
reached at 3043.5 m just below a marl section. It consisted of two hydrocarbon
bearing zones. Zone 1 from 3043.5 m to 3071.5 m and a tighter zone 2 from 3071.5
m to 3103.5 m. Maastrichtian (Tor Formation) starts at about 3103.5 m and is
also hydrocarbon bearing with water saturations below 50% down to 3141.5 m. A
transition zone with gradually increasing water content is seen from 3134.0 m
down to 3182.5 m. Apart from in the oil bearing reservoirs weak oil shows on minor
sandstones were recorded in the interval 2947 to 2958 m; weak to good oil shows
were seen on limestone in the interval 3300 m to 3500 m; and finally weak oil
shows were seen occasionally from 3645 m to 3675 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The chalk section was cored in 11 cores from
3048 m to 3235.5 m (Ekofisk and Tor formations) and one core (core no 12) from
3327.2 m to 3336.7 m (Hod Formation). Total core recovery was nearly 100%. No
wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 17 February
1977 as a gas/condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing </span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Eight drill stem tests were performed in
the Late Cretaceous and Danian chalk sections. The tests indicated an oil
reservoir with a retrograde gas cap. However PVT analyses indicated that the
hydrocarbon system was close to its critical point and therefore difficult to interpret.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3298 - 3302 and
3306 - 3312 m (Tor Formation). After acidizing the test produced water with
less than 1% oil emulsion at a rate of 48 - 51 m3 /day on a 48/64&quot; choke.
Maximum recorded temperature was 120 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2A tested the interval 3210 - 3220 m
(Tor Formation). The test produced water at a rate of 53 m3 /day on a
48/64&quot; choke. Maximum recorded temperature was 116 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 3174 - 3182 m
(Tor Formation). The test produced water at a rate of 13 m3 /day on a
48/64&quot; choke. Maximum recorded temperature was 117 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 4 tested the interval 3148 - 3157 m
(Tor Formation). After acidizing the test produced 253 - 420 Sm3 oil, 152910
Sm3 gas and 108 - 180 m3 water /day on a 24/64&quot; choke. The GOR was 365 -
606 Sm3/Sm3, oil density was 0.849 g/cm3 and gas gravity was 0.699 (air = 1).
Maximum recorded temperature was 120 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 5 tested the interval 3120 - 3133 m
(Tor Formation). After acidizing the test produced 405 - 461 Sm3 oil, 242000
-251000 Sm3 gas /day on a 24/64&quot; choke. The GOR was 534 - 618 Sm3/Sm3, oil
density was 0.818 g/cm3 and gas gravity was 0.680 (air = 1). Maximum recorded
temperature was 120 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 5A tested the interval 3129 - 3133 m
(Tor Formation). The test produced 71 - 98 Sm3 oil with 1% water, 34000 - 45000
Sm3 gas /day on a 12/64&quot; choke. The GOR was 409 - 640 Sm3/Sm3, oil density
was 0.836 g/cm3 and gas gravity was 0.710 (air = 1). Maximum recorded
temperature was 121 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 6 tested the interval 3105 -3108.5 m
(Tor Formation). The test produced 111 - 127 Sm3 oil with 1% water, 125000 -
130000 Sm3 gas /day on a 22/64&quot; choke. The GOR was 989 - 1201 Sm3/Sm3, oil
density was 0.796 g/cm3 and gas gravity was 0.708 (air = 1). Maximum recorded
temperature was 118 deg C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 7 tested the interval 3082 - 3088 m (Ekofisk
Formation). The test gave no flow.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 8 tested the interval 3055 - 3068 m
(Ekofisk Formation). The test produced 79 - 90 Sm3 oil with 0.5% water, 198000
- 218000 Sm3 gas /day on a 12/64&quot; choke. The GOR was 2330 - 2740 Sm3/Sm3,
oil density was 0.760 g/cm3 and gas gravity was 0.691 (air = 1). Maximum
recorded temperature was 116 deg C. Attempts to test this interval with acid
(DST 8A and 8B) failed as a consequence of the problems with the anchor chains.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


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1/9-1 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-1 R is a re-entry of well 1/9-1
on a salt diapir structure located in the Feda Graben in the southern North
Sea. The purpose of the re-entry was permanent abandonment.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The suspended well 1/9-1 was re-entered
(1/9-1 R) with the semi-submersible installation Ross Isle on 8 May 1987. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently
abandoned on 17 May 1987.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



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1/9-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-2 was drilled on a salt diapir
structure located in the Feda Graben in the southern North Sea. It was drilled
to confirm and further evaluate the proven hydrocarbons found on this seismic
structure by the 1/9-1 well.<b> </b></span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-2 was spudded with the
semi-submersible installation Ross Rig on 1 June 1977 and drilled to TD at 3459
m in the Late Cretaceous Hod Formation. No significant problems were
encountered in the operations. The well was drilled with spud mud down to 439 m
and water based with lime/Drispac/lignosulphonate mud systems from 438 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Good oil show was observed in a thin
sandstone stringer at 1632 m in the Hordaland Group. Oil in cuttings was
recorded also at 1710 m and 2858 m in claystones. The Ekofisk Formation was
encountered at 3120 m with shows and tested small amounts of oil. The Tor Formation
came in at 3195 m with shows and tested small amounts of oil. Below 3213.5 m
only rare and weak fluorescence was observed on limestone.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The interval 3135-3215 in the Ekofisk and
Tor formations was cored with nearly 100% recovery. RFT pressure readings were attempted
in the Tor and Ekofisk formations, but all were unsuccessful due to tight
formation. No fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
August 1977. The poor results from DST are classified as shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were carried out. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the Maastrichtian Tor
Formation (3197 - 3209 m) and flowed approximately 6 - 10 m3/day of acidwater
after stimulation, slugging badly. 2-10% of oil was measured in samples. The
oil gravity was 34.0 deg API.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 &amp; 2A tested the Danian Ekofisk
Formation (3130 - 3154 m). The flow stabilized at approximately 13 - 15 m3/day
of acidwater after the retest effort. Clean samples of formation fluids were
not obtained, but this interval produced long enough to approach clean-up.
2-17% of oil was measured on samples taken during flow and reversing sequences
with the smaller value probably being more representative. Oil gravity was 35.2
- 35.7 deg API.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



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1/9-3


<p><b>General</b></p>

<p>Well 1/9-3 is located in the Feda Graben,
close to the UK border southwest in the Norwegian North Sea. The primary
objective of the well was to evaluate the Jurassic sandstones. The secondary
objective was to appraise and test the hydrocarbon bearing zones of Danian and
Maastrichtian age (Shetland Group) encountered in 1/9-1. The well was drilled
in two phases, of which Phase I is well bore 1/9-3 and Phase II is well bore
1/9-3 R. This procedure was a requirement from the Norwegian Petroleum
Directorate since Dyvi Gamma came directly from the yard and had therefore not
accumulated the experience needed to drill the high pressure Jurassic well to a
planned TD of 5000 m. Phase II was to be drilled with the rig Dyvi Beta.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well was spudded with the
semi-submersible installation Dyvi Gamma on 13 August 1977 and drilled to TD at
27871 m in the Hordaland Group. The progress of the drilling was very much
delayed due to technical problems on Dyvi Gamma. As a result, also hole
problems were increased due to very long exposure in open hole condition. Due
to these problems the well bore was terminated after setting the 13 3/8&quot;
casing instead of the plan, which was to drill down to the 9 5/8&quot; casing
point. The well was drilled with seawater and gel all through. </p>

<p>Several thin sand beds were penetrated in
the Hordaland Group between 1610 m and 1737 m. Oil shows were recorded in the
uppermost of these, from 1610 m to 1625 m.</p>

<p>No cores were cut and no wire line fluid
samples taken in the well bore.</p>

<p>The well was suspended as dry on 27
November 1977. </p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



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1/9-3 R


<p><b>General</b></p>

<p>Well 1/9-3 is located in the Feda Graben,
close to the UK border southwest in the Norwegian North Sea. The primary
objective of the well was to evaluate the Jurassic sandstones. The secondary
objective was to appraise and test the hydrocarbon bearing zones of Danian and
Maastrichtian age (Shetland Group) encountered in 1/9-1. The well was drilled
in two phases, of which Phase I is named 1/9-3 and Phase II is named 1/9-3 R.
This procedure was a requirement from the Norwegian Petroleum Directorate since
Dyvi Gamma came directly from the yard and had therefore not accumulated the
experience needed to drill the high pressure Jurassic well to a planned TD of
5000 m. The re-entry 1/9-3 R was to be drilled with the rig Dyvi Beta.</p>

<p><b>Operations and results</b></p>

<p>Well 1/9-3 was re-entered (1/9-3 R) with
the semi-submersible installation Dyvi Beta on 27 May 1978 and drilled to TD at
4570 m in the Late Jurassic Haugesund Formation. When running the 9 5/8&quot;
casing problems occurred with stuck pipe. This resulted in severe delays, but
the casing was landed at planned depth. In the 8 1/2&quot; hole the progress
was delayed due to hole problems with high pressure and mud weight combined
with lost returns. Tight hole and stuck pipe occurred on several occasions. Max
mud weight was 2.04 g/cm. The well was drilled water based, but with several
additions of diesel from 9 5/8&quot; casing depth and downwards, resulting in 1
- 12 % diesel in the mud at all times below 3835 m.</p>

<p>Several problems arose during the logging
operations, which in the end resulted in a poor suit of logs over the
reservoir.</p>

<p>In summary the problems were due to
uncontrolled stretch in the logging cable, generally poor log quality,
especially for FDC/CNL logs, and difficult hole conditions with high pressure/temperature
and excessive sticking. Logs that normally are run in combination had to be run
separately. This made petrophysical evaluation difficult, and several logs had
to be disregarded due to the poor quality.</p>

<p>The well penetrated a typical stratigraphy
for the area with a 2754 m thick Tertiary sequence down to top Rogaland Group
(the 1/9-3 well bore), a 215 m thick Rogaland Group, a 709 m thick Shetland
Group, and a 475 m thick Early Cretaceous Cromer Knoll Group. The well was
terminated 305 m into the Late Jurassic Tyne Group. The Tyne Group contained a
sand/shale sequence (Eldfisk Formation), but the sand beds were water bearing
without shows. </p>

<p>Live hydrocarbons were encountered and
proved by testing in the Ekofisk and Tor Formations, but only the Ekofisk
Formation had good reservoir properties. Petrophysical evaluation showed 36 m
net pay in the upper part of the Ekofisk Formation and only 1.75 m net pay in
the Tor Formation.</p>

<p>A total of 100 m core was recovered in
eight conventional cores in the interval from 3053 m in the Early Paleocene
Maureen Formation to 3234 m in the Late Cretaceous Tor Formation. No fluid
samples were taken on wire line.</p>

<p>The well was permanently abandoned on 30 September 1978 as a gas/condensate appraisal.</p>

<p><b>Testing</b></p>

<p>Four drill stem tests were conducted in
the Shetland Group chalks. DST 1 from 3205 m to 3214 m in the Tor Formation
produced only water. Maximum temperature recorded at the end of the 12 hours
main flow was 124.8 deg C. DST 2 from 3157 m to 3180 m in the Tor Formation
produced 7175 m3 water together with 7.9 Sm3 oil and 4800 Sm3 gas per day
through a 9.5 mm choke. Maximum temperature recorded at the end of the 10 hours
main flow was 122.6 deg C. DST 3 from 3126 m to 3135 m in the Ekofisk Formation
produced only 3 m3/day water with traces of oil and gas. DST 4 from 3094 m to
3112 m in the Ekofisk Formation was a good producer with a maximum flow of 397
Sm3 oil and 648400 Sm3 gas per day on a 19 mm choke. The gravity of the oil was
50 deg API. The maximum temperature recorded in this test was 120.1 deg C.</p>


246
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1/9-4


<p><b>General</b></p>

<p>Well 1/9-4 was drilled on a salt diapir
structure in the Central Graben in the neighbourhood of the Norwegian - UK
median line. The primary purpose was to test the Ekofisk and Tor formations of
Danian and Maastrichtian age. Lower possible porous zones in chalk and Jurassic
sands, if present, were secondary objectives.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 1/9-4 was spudded with the
semi-submersible installation Ross Rig on 13 August 1977 and drilled to TD at 3710
m in Late Permian Zechstein salt. There were no serious drilling problems down
to a depth of 3100 m. At 3100 m the bit-junksub assembly was lost in the hole. The
hole was cemented back and sidetracked after the fishing attempts proved
unsuccessful. After one unsuccessful sidetrack attempt the hole was sidetracked
again from 3041 m and drilled on to core point at 3122 m. When cutting core no 10
the bottom hole assembly got stuck and a long section of the BHA had to be left
in the hole. After some unsuccessful attempts on jarring, the hole was cemented
and sidetracked again, from 3059 m in the first sidetrack hole. This second sidetracked
hole was drilled to a measured depth of 3353 m. At this point 7&quot; liner was
run. 6&quot; hole was drilled to a total measured depth of 3710 m with only
minor problems and top of the salt was found at 3650 m. The 6&quot; hole was
logged and plugged back. It was found necessary to perform a squeeze job around
the 7&quot; liner shoe, but when attempting to pull out after this operation,
the BHA stuck just above the cementing stinger. Jarring did not free the pipe,
and a cement plug was set above the fish. The well was drilled with high
viscosity spud mud of pre-hydrated bentonite, lime, and caustic soda down to
437 m and with Drispac/lime mud from 437 m to 2580 m. From 2580 m the lime was
phased out and the remaining well to TD was drilled with a
lignite/lignosulphonate gel mud. During abandonment an anchor chain broke in
severe weather. The well was plugged back while a supply boat pulled on the
anchor chain. A cap was installed on the well head and the well was suspended. </p>

<p>No significant reservoir rock was
penetrated above Danian level. The Early Cretaceous Valhall Formation was found
resting directly on the salt. No Jurassic sediments were penetrated by the
well. Hydrocarbons were encountered and tested in the Ekofisk and Tor
Formations from 3114 m down to top Hod Formation at 3312 m. Above the reservoir
shows in the form of cut and fluorescence was recorded on occasional
shale/limestone/silty cuttings was seen from 1990 to 2733 m. More continuous
shows were seen on limestone/shale cuttings in the interval 2808 to 2991 m in the
Lower Hordaland Group, through the Balder Formation and into the Sele Formation.
</p>

<p>Nine cores were cut from - 3123 m to -
3273 m with close to 100% recovery. No RFT surveys were run and no wire line
fluid samples were taken.</p>

<p>The well was suspended on12 January 1978
as a dry well.</p>

<p><b>Testing</b></p>

<p>Four drill stem tests to evaluate
productivity and fluid composition were carried out. Hydrocarbons were produced
during all the tests. Weather conditions and operational problems interfered
with the designed test program.</p>

<p>DST 1 tested the Tor Formation in from
interval 3292 to 3296 m. The second flow produced 30582 Sm3 of gas and in the
range of 16 Sm3 oil /day. There was no water production. The oil produced had a
gravity of 46 deg API and the gas gravity (air = 1) was 0.68. GOR varied in the
range 890 to 14000 Sm3/Sm3. Maximum recorded down hole temperature was 136 deg
C but the temperature readings were not stable.</p>

<p>DST 2 tested the Tor Formation from the
interval 3235 to 3255 m. After acid stimulation the well flowed 673940 Sm3 of
gas and 592 Sm3 oil /day on a 48/64&quot; choke. The oil gravity was 48-49 deg
API at separator conditions and the gas gravity (air = 1) was 0.67 with 2 - 3 %
CO2. The GOR was in the range 890 to 1160 Sm3/Sm3. No representative
temperature reading is available from this test.</p>

<p>DST 3 tested the Ekofisk Formation from
the interval 3176 to 3198 m. After acid stimulation the well flowed 32000 Sm3
of gas and 17 Sm3 oil /day with a bottom hole flowing pressure 750 psig at
depth 3154 m. This test also produced some emulsion and water. The gas and oil
gravities were 0.81 (air = 1) and 45 deg API at separator conditions,
respectively. 3% CO2 was measured in the gas. The GOR varied in the range 1070
to 2140 Sm3/Sm3. Due probably to gas expansion and cooling in the borehole it
is assumed that the maximum recorded temperature of 122.2 deg C was not
representative for the formation.</p>

<p>DST 4 tested the Ekofisk Formation in the
intervals 3127 to 3137 and 3120 to 3123 m. After acid treatment the well flowed
498380 Sm3 of gas and 223 Sm3 oil /day on a 48/64&quot; choke. The gas and oil
gravities were 0.688 (air = 1) and 50 - 51 deg API at separator conditions,
respectively. 2-3% CO2 was measured in the gas. The GOR varied in the range 960
- 2850 Sm3/Sm3. The maximum temperature recorded, and the one assumed to be the
most representative for the Formation in all four tests, was 134.2 deg C. </p>



247
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1/9-4 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-4 R is a re-entry of well 1/9-4
in the Central Graben of the North Sea. The purpose of the re-entry was
permanent abandonment. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well was entered with the
semi-submersible installation Ross Rig on 21 April 1991. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well head was removed from the sea
floor.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26
April.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



























1727
7/6/2016 12:00:00 AM
29.01.2023
1/9-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-5 was drilled in the Feda Graben
in the southern North Sea, in the saddle between the Tommeliten Gamma-structure
and the intrusive salt plug forming the Tommeliten Delta structure. The purpose
of the well was to appraise the Tommeliten Gamma discovery made by 1/9-4 and to
test the hydrocarbon potential and reservoir quality of the Ekofisk and Tor
formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-5 was spudded with the
jack-up installation Dyvi Beta on 3 October 1978 and drilled to TD at 3450 m in
the Late Cretaceous Hod Formation. The pipe got stuck at 3426 m during a
clean-up trip. When trying to come loose the hook broke and the drill string
dropped in the hole. This event caused material damage and rig shut-down for
three days, but nobody was injured. When fishing the drill string it came loose
above the jar but the rest of the BHA (approximately 260 m) was left in the
hole. The well was drilled with spud mud down to 435 m, with a lime/&quot;Morex&quot;
mud system from 435 m to 1377 m, with lime/&quot;Morex&quot;/Drispac mud from
1377 m to 2725 m, and with lignosulphonate/lignite mud from 2725 m to TD. A lot
of hole problems occurred in the 17 1/2&quot; and 12 1/4&quot; sections and
this was attributed to the lime/&quot;Morex&quot; mud system. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Ekofisk Formation came in at 3207 m
and the Tor Formation at 3282 m. No significant hydrocarbon shows were
encountered in any section of the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 3215.5 to 3 233.5 m,
proving a dry carbonate section. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
December 1978 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



248
7/6/2016 12:00:00 AM
29.01.2023
1/9-6 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 S was drilled on the
north-west flank of the Tommeliten Gamma structure in the Feda Graben in the
southern North Sea. The main objective was to appraise the Tommeliten Field.
The well was drilled deviated due to the planned use of this well as a
production well. The main targets were the Ekofisk and Tor formations. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 1/9-6 was spudded with the
semi-submersible installation Sedco 703 on 21 March 1982. Drilling of the
36&quot; and 26&quot; holes went without incident. There was some difficulty in
getting logging tools in the 17 1/2&quot; hole. Gumbo problems occurred while
drilling the 12 1/4&quot; hole and both open hole and cased hole logging runs
were plagued with tool failures. Differential sticking also occurred while
drilling the bottom part of the 8 1/2&quot; hole. TD was set 3880 m, 99 m into
the Late Cretaceous Hod Formation. After retrieving the RFT the well began
flowing and sloughing large amounts of shale below the 9 5/8&quot; shoe. While
circulating and reaming to TD, the pipe became stuck many times due to shale
sloughing above the bit. A bit and bit sub were left in the hole during these
hole problems, and were never recovered. The well was drilled with
&quot;native&quot; mud/seawater down to 1471 m and with polymer/dispersed
solids/lignosulphonate/seawater from 1471 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Ekofisk Formation was penetrated at
3411 m (3110 m TVD) and top Tor Formation at 3516 m (3199 m TVD). Both
formations were gas/condensate bearing. No other permeable section in the well had
indications of hydrocarbons.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 14 cores were cut in the interval
3415.7 - 3619 m in the Ekofisk and Tor formations. Problems with jamming and
differential sticking occurred while coring. The overall recovery was 90%. One
run with the RFT tool on wire line was conducted, taking 14 good pressure
points, but no fluid sample due to tight formation and stuck tool. </span></p>

<p class=MsoBodyText><span lang=EN-GB>After testing the well was suspended on 1
December as a possible future producer. It is classified as a gas/condensate
appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four DST's were performed in this well. Technical
and operational problems plagued all tests. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3771.6 - 3776.8
m (3424.0 - 3428.6 m TVD) in the water zone at base Tor Formation. A few m3
water was produced in each of several flow periods. The temperature recorded in
DST 1, at measurement depth 3750.4 m varied between 130.7 deg C and 133.0 deg C
for different periods and gauges, with 131.7 deg C taken as a representative
temperature. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2, 2A, and 2B tested the interval 3636.3
- 3654.6 m (3301.0 - 3316.7 m TVD) in the lower Tor Formation. The first test,
DST 2, was aborted due to technical problems. Maximum rate achieved from DST 2A
was 536604 Sm3 /day of gas and 477 Sm3 /day of condensate on 32/64&quot; choke.
GOR was 1125 Sm3/Sm3, oil density was 0.810, and gas gravity was 0.689 (air =
1). H2S was measured to be 4-6 ppm and the CO2 content was measured to be 3%.
This test was aborted when the tester valve cut the wire line, and the zone was
retested as DST 2B. The maximum flow rates were then close to 700 x 10 Sm3 /day
of gas and 500 - 550 Sm3 /day of condensate on a 28/64&quot;. The maximum temperature
in different flows from this interval, measured at 3652 m, varied between 121.8
and 122.4 deg C</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3 tested the intervals 3587.5 - 3578.4
m, 3569.2 - 3560.1 m and 3550.9 - 3523.5 m in the Tor Formation. It flowed 243808
Sm3 gas and 231 Sm3 condensate/day on a 16/64&quot; choke after acidizing. GOR
was 1054 Sm3/Sm3, condensate density was 0.823 g/cm3 and gas gravity was 0.680
(air = 1). Final build-up period was terminated mid-way due to technical
problems. Same interval was tested in DST3A without further acidizing. This
test produced 241259 Sm3 gas and 202 Sm3 condensate/day on a 20/64&quot; choke.
The GOR was 1196 Sm3/Sm3, the oil density was 0.791 g/cm3 and gas gravity was
0.684 (air = 1). The temperature measured at 3522.6 m was 131.1 deg C</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 4 was perforated in two intervals,
the upper zone from 3416.8 - 3426.0 m (3114.8 - 3122.7 m TVD) and the second
from 3444.2 - 3459.4 m (3138.2 - 3151.3 m TVD), both in the Ekofisk formation.
It produced gas and condensate after stimulation. The maximum rates from these
intervals were 834213 Sm3 gas and approximately 559 Sm3 condensate/day of
condensate on a 56/64&quot; choke. The GOR was 1491 Sm3/Sm3 on this choke. A GOR
of 2800 Sm3/Sm3 was measured before acidization, with a low flowing pressure. </span></p>


44
5/19/2016 12:00:00 AM
29.01.2023
1/9-6 SR


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 SR is a re-entry of well 1/9-6
S on the north-west flank of the Tommeliten Gamma structure in the Feda Graben
in the southern North Sea. Well 1/9-6 S was suspended in December 1984 as a
possible producer for the Tommeliten Gamma. The objective of the re-entry was
plugging.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-6 S was re-entered with the
semi-submersible installation Ross Rig on 6 April 1991. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently
abandoned on 20 April 1991.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



1558
7/6/2016 12:00:00 AM
29.01.2023
1/9-7
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 1/9-7 was drilled on the Tommeliten
Alpha structure on the south-western side of the Feda Graben of the North Sea,
ca 1.5 km from the UK border. The main objective of well 1/9-7 was to explore
the hydrocarbon potential of the Tommeliten Alpha prospect in the Jurassic
level. Secondary objective was to appraise the Tommeliten Alpha Chalk discovery
made by well 1/9-1 in 1976.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 1/9-7 was spudded with the
jack-up installation Mærsk Giant on 22 March 2003. The well was drilled to the
TD of the 17 1/2&quot; section at 3040 m by 21 April. Problems with losses at
the 20&quot; shoe at 1039 m were remediated by spotting cement at the shoe. The
well was inadvertently sidetracked as 1/9-7 T2 while drilling out the cement on
27 April. Unable to re-enter the original borehole after drilling to 1215 m,
the 1/9- 7 T2 sidetrack was cemented back to the 20&quot; shoe. The well was
then deliberately and successfully sidetracked from 1039 m as 1/9-7 T3 on 4 May
2003. The 17 1/2&quot; hole was re-drilled to a TD of 3058 m and 14&quot;
casing set. From there the well was drilled without further significant
problems to TD at 4986 m (4965 m TVD) in the Triassic Smith Bank Formation. The
well was drilled with seawater/bentonite/CMC down to 1047 m, with Versavert OBM
in from 1047 to 3058 m (Versavert was used also in the primary well track and
the failed sidetrack), and with Versatherm HTHP mud, a mineral oil based mud,
from 3058 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Chalk of the Ekofisk Formation was
encountered at 3093 m and top Tor Formation was encountered at 3159 m.
Reservoir quality sands were not encountered at any level below the Base
Cretaceous Unconformity, although an interval containing very fine sand and silt
equivalent to the Oxfordian J50 Sand Unit in the UK well 30/19a-5, 8 km to the
WNW, was encountered. The only significant hydrocarbons encountered were in the
Ekofisk and Tor Formations in the upper portion of the Chalk Group where oil
shows were observed. MDT sampling in Ekofisk proved a gas/condensate. Logs
indicated hydrocarbon saturation down to ca 3195 m but no definite hydrocarbon
contact was found.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Petrophysical analyses indicated some
hydrocarbon saturation in a thin Miocene Sand Unit at 1675 m (1/9-7 depth) and
a thin Andrew Formation sand in the Paleocene from 2989 m to 2992.5 m (1/9-7 T3
depth). None of these had oil shows. Shales in the Mandal Formation at 4315 -
4350 m had definite shows (hydrocarbon odour). However, the oil-based drilling
fluids made shows identification difficult below 1047 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut with 100% recovery
from 3104 to 3153 m in the Ekofisk Formation. During MDT operations across the
Chalk Group, 5 down hole samples were retrieved from 3112 m in the Ekofisk
Formation with an MDT dual-packer tool. Upon examination at surface, it was
concluded that the samples contained what appeared to be single-phase
retrograde gas condensate. From PVT studies it was concluded that the samples
are 12-16 wt% contaminated with base-oil drilling mud, geochemical analyses by
GC show that apart from the contamination in the range C12 - C20 the 1/9-7 MDT
oil is very similar to the oil sampled from 1/9-1 side of the Tommeliten Alpha
discovery.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2
August 2003. The well is classified as dry in the main Jurassic exploration
target and is also a positive appraisal of the 1/9-1 Tommeliten Alpha
Ekofisk/Tor Formation discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>





































































4652
2/21/2020 12:00:00 AM
29.01.2023
10/4-1
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 10/4.-1 was drilled to test the Zeppelin
prospect ca 35 km southeast of the Yme Field in the North Sea. The primary
objective was to evaluate the presence of hydrocarbons in sandstones of the Jurassic
Sandnes and Bryne formations. Secondary target were the Zechstein Group
limestones of Late Permian age.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 10/4-1 was spudded with the semi-submersible
installation Borgland Dolphin on 20 June 2015 and drilled to TD at 2415 m in
the Permian Zechstein Group. No significant problem was encountered in the
operations. The well was drilled with seawater and hi-vis pills down to 640 m
and with Innovert oil based mud from 640 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Sandnes Formation was encountered at
2274 m and top Bryne Formation at 2311 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Both formation had sandstones with very
good reservoir quality. The Sandnes reservoir has an average porosity of 21.5
%, and the Bryne Formation 17.4 %, using a cut off value of 10%. The gross
thickness for the Sandnes Formation is 21 m with a net thickness of 19.15 m. The
well encountered the Bryne reservoir with a gross thickness of 53 m and net
thickness of 38.75 m. The water saturation is 100 % in both encountered
reservoirs. The expected Permian age limestone reservoir was not present at this
well location. All reservoirs were water-wet. The well also encountered sandstone
of undifferentiated Triassic age with good quality. The sandstone of 16 m gross
and 15.95 m net thickness had an average porosity of 23.7 %. It is water-wet. No
shows were observed in the well</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
July 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7724
5/23/2017 12:00:00 AM
29.01.2023
10/5-1



<p><b>General</b></p>

<p>Well 10/5-1 was designed to test a tilted
fault block with an overlying pinch out trap in the eastern part of the
Norwegian-Danish basin. The primary objective was Rotliegendes sands. A
probable 460 m gross thickness was anticipated. A secondary objective was
Middle Jurassic sandstones with an estimated gross thickness of 61 metres.
Other possible objectives were the Early Cretaceous sandstones and Basal
Zechstein carbonates.</p>

<p>The well is Illustration Well for the
Børglum Unit of the BoknFjord Group.</p>

<p><b>Operations and results</b></p>

<p>Exploration well 10/5-1 was spudded with
the semi-submersible installation Norjarl on 31 May 1976 and drilled to TD at
1843 m in crystalline granite dated by the potassium-argon method to apparently
689 ± 21 My (Late Precambrian). After drilling the 36&quot; section to 189 m
the hole had washed out under the temporary guide base. The guide base sank 26
feet below the mud line and the 30&quot; casing could not be stabbed through
the guide base. The rig was moved 38 m and the hole was respudded. The well was
drilled with seawater / gel down to 501 m, with Inpac polymer mud from 501 m to
1768.2 m, and with lignosulphonate mud from 1768.2 m to TD. </p>

<p>The well penetrated a gross thickness of
67 metres of Middle Jurassic (Sandnes Formation) sandstones from 1472 m to 1539
m. Porosity was good, but there were no hydrocarbon indications while drilling,
and subsequent log analysis confirmed that the objective horizons were water
wet. Triassic sandstones were also encountered, but these were extremely
shaley, and had no clean sandstone sections. Rotliegendes sandstones were not
present at the 10/5-1 location. The base of the Zechstein interval was
represented by a clear, white, light brown, hard, very angular sandstone,
cemented with siliceous cement and extremely tight. Organic geochemical
analyses found fair to rich TOC (1 - 5%) in the Early Cretaceous and Late
Jurassic and possibly in some Permian shales. The Permian TOC could be caved
Late Jurassic material. Rock-Eval pyrolysis of the high-TOC samples gave low S2
yields, so the kerogen has low hydrocarbon potential and is most likely gas
prone. The entire well was found to be immature. Minor amounts of migrant
hydrocarbons were detected by the geochemical analyses in the late Jurassic and
the Cretaceous.</p>

<p>A junk basket core was recovered from
533.4 m to 534.3 m. No conventional core was cut. Thirty sidewall cores were
attempted over the interval 1250 m to 1812 m. Eighteen of these were recovered.
No fluid samples were taken.</p>

<p>The well was permanently abandoned on 26
June 1976 as a dry hole. </p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



306
7/6/2016 12:00:00 AM
29.01.2023
10/7-1



<p><b>General</b></p>

<p>Well 10/7-1 is located at the
southeastern end of the Egersund Basin in the North Sea. The objective of the
well was to test the Tott prospect, a faulted anticline over a salt wall. The
Middle Jurassic Bryne formation was the primary objective. A thin Sandnes
formation sandstone overlying the Bryne was interpreted to be possible at the
drilled location.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 10/7-1 was spudded with the
semi-submersible installation Sonat Arcade Frontier on 28 June 1992 and drilled
to TD at 1890 m in the Late Permian Zechstein Group. The well was drilled with
seawater and gel down to 793 m and with KCl/polymer mud from 793 m to TD. </p>

<p>Good reservoir quality sandstones were
encountered in both the Sandnes and Bryne formations of the Vestland group. The
top of the Sandnes formation was penetrated at 1539 m; top of the Bryne at 1632
m. Total thickness of the Vestland group is 297 m. From drill cuttings, fair to
good visible porosity was observed in fine to coarse-grained sandstones
throughout the Vestland group. Reservoir quality is good, with a net sand/gross
thickness ratio of 54.5% using a 12% porosity cut-off. Using the same cut-off
value the average porosity of the reservoir sandstones in the Vestland group is
23.3%. Bathonian age sediments (Bryne Formation) rested directly on Late
Permian Zechstein salt at 1836 m. Occasional, spotty shows were observed in
cuttings from the Sandnes and Bryne Formations. These marginal shows were
interpreted to be sourced from in-situ carbonaceous material and not as
migrated hydrocarbons. Analysis of the wire line logs and wire line pressure
data clearly indicated that the sandstones of the Vestland group were water
bearing. Organic geochemical analyses showed Total Organic Carbon (TOC) from
1.0 to 3.19 % and Hydrogen Index (HI) from 79 to 224 mg HC/g TOC in the Late
Jurassic shales, which was classified as a poor oil and gas source. Associated
with coals in the Vestland group were gas prone sediments with TOC values
ranging from 1.64 - 6.14% and HI values of 118 to 223. The well was found
immature for oil and gas generation; maximum vitrinite reflectance, recorded
near TD, was 0.45 %Ro. Extractable organic matter contained low to modest
amounts of immature hydrocarbons associated with local shales and coals,
consistent with the trace shows recorded during drilling.</p>

<p>One conventional core was cut in the
Sandnes formation, from 1561 to 1566.5 m, where the core jammed. The recovered
core (3.95 m) consisted of sandstone with a thin claystone/shale bed at the
base. Shows were not observed in the core. Core analysis indicated generally
fair to good porosity and permeability. FMT pressures also indicated fair to
good permeability throughout the Vestland group. No fluid sample was taken.</p>

<p>The well was permanently abandoned on 30
July 1992 as a dry hole.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



1972
7/6/2016 12:00:00 AM
29.01.2023
10/8-1


<p><b>General</b></p>

<p>The 10/8-1 well is situated close to the
Lista Nose in the eastern part of the Norwegian-Danish Basin. It was drilled on
a salt induced anticlinal structure related to a salt pillow. The structure is
well defined from the Permian salt up to the upper cretaceous chalk. It has a
vertical closure of 300 m for a closed area of 80 km2 at a seismic horizon
assumed to be the Jurassic sandstone. A fault cuts the unconformably underlying
horizons attributed to Triassic. The specific objective of the 10/8-1 well was
to test the hydrocarbon potential of the Jurassic sandstone section, estimated
to be 60 m thick, with additional reservoir being furnished by the Triassic
sandstones immediately below. </p>

<p>The well is Type Well for the Skagerrak
Formation and Reference Well for the Smith Bank Formation</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 10/8-1 was spudded with the
semi-submersible installation Pentagone 81 and drilled to TD at 2861 m in the
Late Permian Zechstein salt deposits. The well was completed in 37 days without
reported problems. The well was drilled with seawater with returns on the sea
floor down to 510 m, and with a LFC/sea water mud system from 510 m to TD. </p>

<p>One thousand three hundred meter of
continental deposits of Triassic age is present. On top of this is the Gassum
Formation. The Early to Middle Jurassic was not encountered in the well. One
hundred and fifty meter Late Jurassic sand and shale is directly overlying the
Gassum Formation. Around 200 m of shale was deposited during the Early
Cretaceous while the Late Cretaceous is represented by 425 m of lime mudstones.
The lower 200 m of the Tertiary was developed in mostly sandy facies. All
Formations penetrated by the well were found water wet. The only show recorded
was traces of gas (C1 and C2) from 1010 m to 1050 m. Organic geochemical
screening analyses show TOC in range 0.1 - 1.5 % with the highest values in the
Late Jurassic and Cretaceous sequences. The Triassic sequence appears very lean
with less than 1% TOC. The upper 500 m of the well were not sampled. No
conventional cores were cut and no fluid samples were taken. </p>

<p>The well was permanently abandoned on 17
January 1971 as a dry hole. </p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



175
5/19/2016 12:00:00 AM
29.01.2023
11/10-1

<p><b>General</b></p>

<p>Wildcat well 11/10-1 was drilled in the eastern
part of the Danish Norwegian Basin close to the borderline between the
Norwegian and the Danish sectors. The well is situated close to the Kreps fault
zone on the western flank of the Horns Graben. The main objectives of the
11/10-1 well were to test the hydrocarbon potential of the Tertiary and the
Mesozoic formations. Well 11/10-1 is the first well in quadrant 11 and one of
the few wells drilled in the southeastern part of the Norwegian continental
shelf so long.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 11/10-1 was spudded with the
semi-submersible rig "Ocean Viking" on 2 August 1969 and completed 19 August
the same year. The well was drilled at 63 m water depth and bottomed at a total
depth of 2430 m in a Triassic sand section without having encountered
hydrocarbons in any of the targets.</p>

<p>Three casing strings were set in the
well. Sea water was used for the initial drilling down to 253 m. From this
depth down to 1023 m a sea water gel mud was used and from 1023 down to TD a
sea water Q-Broxin mud system was the drilling fluid. No significant drilling
problems occurred during the drilling of this well.</p>

<p>No samples are available from the sea
floor down to 305 m. From 305 to 430 m the sampled sequence consists of medium
to coarse grained, subangular to subrounded, glauconitic sand and sandstone
with scattered rock fragments. The sand is generally unconsolidated and mostly
clear quartz and is relatively well sorted. Carbonaceous material, plant
remains and shell fragments occur throughout. Dolomitic limestone are also
present, increasing towards the bottom of the unit where the dolomite forms the
cement of the sand. The underlying shales are dated Late Oligocene, the age of
the sandy section is questionable as the upper 300m of the well has not been
sampled.</p>

<p>No sandstones are developed in the
Rogaland Group which is much reduced in this well. The Upper Cretaceous chalk
formations penetrated below 1048 m are approximately 400 m thick. 200 m of marls
and shales containing limestone stringers constitute the Cromer Knoll Group
below 1493m. The Upper Jurassic section is 200 m thick and consists of mainly
shale with only stringers of sandstone. The Lower and Middle Jurassic section
is missing in this well. The interval from 1860 to 1900 is considered to belong
to the Triassic Gassum formation. At the top of this sequence there is a bed of
light grey lime mudstone. Most of the interval, however, consists of loose,
clear quartz sand, coarse to very coarse and a fine grained white to light grey
sandstone with calcareous cement. From 1900 to 2430 m (TD) interbedded reddish
and brownish sandstones and shales of the Skagerrak Formation are present. Visual
porosity is good throughout this unit. No shows were observed when drilling
through almost 600 m of Triassic section.</p>

<p>Neither fluid samples nor pressure point
were taken in this well.</p>

<p>No cores were taken in this well.</p>

<p><b>Test</b><b>ing</b></p>

<p>No drill stem test was performed.</p>

170
5/19/2016 12:00:00 AM
29.01.2023
11/5-1

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 11/5-1 was drilled to test the
Loshavn prospect, a 3-way dip closure situated on the southern flank of the Farsund
Basin. The primary objectives were to test the hydrocarbon potential in shallow
marine sandstones of the Late to Middle Jurassic Sandnes and Bryne Formations.
Secondary objectives were to test the source rock potential of the Late
Jurassic Tau Formation; and to test the reservoir and hydrocarbon potential of
the Permian Rotliegendes sandstones. The TD criterion was to drill 600 m below
Top Rotliegendes.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 11/5-1 was spudded with the
semi-submersible installation Polar Pioneer on 7 August 2007 and drilled to TD
at 1950 m into Silurian basement. The well was spudded
twice, with the second spud ca 30 m north-west of the original spud position. The
well was drilled without much technical problems, but a significant deviation
from vertical started below 1375 m. The deviation persisted down to TD, with
maximum deviation of 17.3 deg at 1837 m, resulting in a TVD at TD that was 15 m
short compared to measured TD. The well was drilled with sea water down to 415
m and with Formate polymer mud from 415 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Late Jurassic Sandnes formation was
drilled from 1276 m to 1322m. No Middle Jurassic (Bryne Formation) was present
at the well location and the Permian Rotliegendes Sands were drilled from 1321 m
to 1920 m. From 1920 m to TD biostratigraphic analyses indicate rocks of Silurian age. The Sandnes Formation was found to be an overall heterolithic
transgressive unit of 45 m at the well location. It consisted of a lower shaly
part with lower porosity, and an upper more sandy and porous. The upper part
was slightly thicker than the lower. The Rotliegendes Group is a more than 500
m thick unit, very heterolithic, mainly composed of interbedded claystones,
sandstones, conglomerates and siltstones with traces of limestones. Porosities
were very low and wire line pressure tests proved them to be tight. An
additional sandstone interval was drilled at the base of Cromer Knoll Group,
from 1073 m to 1088 m, the ?Sauda Sandstone Unit?. All reservoir sections were
water bearing. No shows were recorded in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
September 2007 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


5596
4/11/2017 12:00:00 AM
29.01.2023
11/9-1


<p><b>General</b></p>

<p>Well 11/9-1 is located in the Horn Graben
far to the east in the North Sea towards the Skagerrak Sea, ca 15 km from the
Danish border. It was located near the top of a saliferous structure in order
to explore the whole Triassic series in the most favourable structural
position. The structure is potentially large, but since all horizons above the
Jurassic level were expected to crop out on the seabed the objective horizon
was Lower Middle Triassic carbonaceous shales. These shales were seen both as
source rock and seal for hydrocarbons in underlying sandstones (basal Triassic
Brockelschiefer). No other objectives were defined for this well. </p>

<p><b>Operations and results</b></p>

<p>Wildcat well 11/9-1 was spudded with the
semi-submersible installation Deepsea Driller on 16 January 1976 and drilled to
TD at 1972 m, 42 m into Late Permian Zechstein salt. The well was drilled water
based with spud mud down to 660 m and with ferrochrom lignosulphonate mud (FCL)
from 660 m to TD. </p>

<p>Drilling was without returns to 145 m.
From there red sandstones and variegated shales made up a very thick Triassic
interval (1785 m). The Triassic contained reservoirs as usual but no obvious
sealing intervals were seen. Moreover, no potential source rocks were
encountered. No shows of gas or oil were recorded during drilling and the
different reservoirs were water bearing from the logs. No conventional core was
cut and no fluid sample taken. Forty sidewall cores were retrieved in two runs
in the interval 737 m to 1962 m. </p>

<p>The well was permanently abandoned on 28
February 1976 as a dry hole.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



307
7/6/2016 12:00:00 AM
29.01.2023
15/12-1
<p><b>General</b></p>

<p>Well 15/12-1 was drilled in order to
evaluate the Paleocene and Jurassic formations on a closed structure 5 km
northeast of the Maureen Field which is located just across the UK-Norwegian
median line in UK territory. The principle objectives of the 15/12-1 test were
the Paleocene and Dogger (Hugin Formation) sandstones where oil accumulations
had been proven in the Maureen field 5 km to the southwest on British sector.</p>

<p>The well is Reference Well for the
Sleipner Formation.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/12-1 was spudded with the
semi-submersible installation Ross Rig on 7 July 1975 and drilled to a total
depth of 3269 m in Triassic fine-grained sandstone with green and red-brown
shale of the Skagerrak Formation. The well was drilled with a lignosulphonate
type of mud.</p>

<p>The Paleocene sandstone at 2633 m to 2643
m in 15/12-1 was encountered 6 m lower than in the Maureen no. 2 well. The
sandstone is medium to coarse grained with good porosity (26%), but water wet.
The Hugin sandstone was encountered some 50 m higher than in the Maureen no. 2
well. Oil shows were encountered on the cores from the Hugin Formation, but log
analysis and FIT proved the sandstone to be water bearing. The logs also
indicated shows of hydrocarbon in the Late Cretaceous limestone at 2925 - 2955
m, but log porosity was calculated from 0 to 6%, too tight to obtain a sample.
The Late Triassic has good sand development that could be adequate for
accumulation of hydrocarbons. During the drilling of the Triassic section, the
background gas in mud and cuttings was near zero.</p>

<p>Eight cores were cut in the well.
Paleocene sands (Lista and Maureen Formations) were cored from 2612.1 m to
2651.1 m. One core was cut in the Heather Formation from 3067 m to 3073.3 m;
one core was cut from the Hugin Formation into the Sleipner Formation from
3125.7 m to 3143.7 m. The Sleipner Formation was further cored in three cores
down to 3183 m. On the basis of log analysis, two points for FIT tests were
picked: one point at 3142.5 m (Ï = 23%, SW = 66%) and one point at 3126.5 m (Ï
= 11.2%, SW = 31%). Test l at 3142.5 m produced 0.3 litres mud and 9.9 l water
with a light skim of oil. The oil skim probably came from the FIT tools
hydraulics. Based on the chloride content the water in the sample probably
contained a large proportion of mud filtrate. The other sample was a failure
due to tight formation. The well was permanently abandoned as a dry well with
shows on 6 September 1975.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


94
5/19/2016 12:00:00 AM
29.01.2023
15/12-10 S



<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The well is positioned on the western
flank of the northern segment of the Varg Field, on a horst mapped at Top
Sleipner level. Thick Intra Heather sandstones present in the southern and
eastern segments of Varg were expected also in the northern segment. Over the
horst, Draupne/Heather shales were assumed eroded so that Intra Heather
sandstones were present between BCU and Top Sleipner. These two horizons could
be mapped seismically, but the extent of sandstones could not be mapped. The
well was drilled to determine the extent and thickness of the Intra Heather
sandstone reservoir over the northern segment of Varg and, if oil was
encountered, to determine fluid characteristics and depth to the OWC. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-10 S was drilled
from the S4 slot on the Varg subsea template using the semi-submersible
installation Deepsea Bergen. It was spudded on 2 October 1996 and drilled
deviated to TD at 3550 m in the Triassic Skagerrak Formation. The deviation started
at 250 m, building angle to 35 deg at 960 m and was then kept between 28 deg
and 38 deg down to TD. No significant problems were encountered in the
operations. The well was drilled with seawater down to 207 m, with
seawater/PAC/CMC from 207 m to 1396 m, and with Ancovert oil based mud from
1396 m to TD. No shallow gas was predicted and no shallow gas was found in the
well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Down to Top Shetland, the well was within
prognosis, and penetrated the expected lithology. Below this level, the
Shetland limestone was thicker than expected, and Top Cromer Knoll and Base
Cretaceous was penetrated considerably deeper than prognosed (55 and 58 metres,
respectively). Below BCU, the well encountered Late Jurassic shales and
siltstones, and only 13 metres TVD of poor quality Intra Heather Sandstone was
penetrated at 3372 - 3388 m (2924 - 2937 m TVD MSL) in the lower part of the
Late Jurassic section. This was considerably less than prognosed, and the poor
reservoir quality seen in the well also proved a rapid facies variation between
15/12-6 S and -10 S, probably controlled by faulting. The Intra Heather
Sandstone was oil bearing, but had poor reservoir characteristics. MDT fluid
samples from the top of the unit were contaminated with oil from the oil-based
drilling mud, but analyses showed that the oil was of the same type as the oil
found in well 15/12-6 S. The Intra Heather Sandstone section was deeper than
the anticipated OWC for this part of the field (2920 m TVD MSL), and the base
of the interval represented an ODT, indicating that sandstones in this area
contain oil down to a deeper level than previously assumed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Sleipner and Top Triassic were
penetrated close to prognosis, and a core taken in the Triassic was in parts
heavily tectonized. The borehole imager (UBI) indicated faulting at the top of
the Intra Heather Sandstone, and in the Sleipner formation. </span></p>

<p class=MsoBodyText><span lang=EN-GB>One conventional core was cut from 3427 -
3448 m in the Triassic Skagerrak Formation. An MDT sampling run collected fluid
in two sample chambers at 3372.15 m (2947.04 m TVD RKB).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was re-classed to
cuttings-injector 15/12-A-4 on 4. November 1996.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed</span></p>



2285
7/6/2016 12:00:00 AM
29.01.2023
15/12-11 S

<p><b>General</b></p>

<p>Exploration well 15/12-11 S was a joint
operation of Production Licence 038 and 116. It was drilled in the northwestern
area of block 15/12 and north of the Varg Field. Well 15/12-1 nearby to the
northwest had shows in the Middle Jurassic Hugin Formation, but this was
inconclusive with respect to moveable hydrocarbons. Block 15/12 is structurally
located in the junction between the Jµren High to the southeast, the Ling
Depression to the east, the Sleipner Terrace towards the north and the Witch
Ground Graben to the west. The prospect was defined as a multi-target
structure, situated on a rotated fault block. Primary targets were Tertiary
sandstones of the Heimdal Formation in a genuine closure, in addition to
sandstones of the Middle Jurassic Hugin Formation. Secondary high-risk targets
were sandstones of Eocene, Late Jurassic and Triassic age. </p>

<p><b>Operations and results</b></p>

<p>Exploration well 15/12-11 S was spudded
with the semi-submersible drilling installation &quot;Deepsea Bergen&quot; on
10 April 1997 and drilled to TD at 3597 m (3464 m TVD RKB) in sandstones of the
Triassic Skagerrak Formation. The well was drilled with seawater and hi-vis
pills down to 407 m and with KCl / polymer / Glycol (ANCO 208) mud from 407 m
to TD. </p>

<p>Sandstone was encountered in all of the
possible prospective levels except in the Late Jurassic. The two primary
targets however, were more silt/shale dominated than expected. The upper part
of the Heimdal Formation, penetrated at 2680 m had a lower reservoir quality
than expected. These distal parts of the formation were relatively shaly/silty.
More massive and porous sand of the Heimdal Formation was penetrated deeper,
but too deep with respect to a Maureen Field oil spill. The lower reservoir,
the Hugin Formation was penetrated at 3395 m, and was slightly thicker than
prognosed. The only indications of hydrocarbons observed during drilling of
15/12-11 S were weak shows in the Hegre and Vestland Groups and a very weak cut
fluorescence on the core from the Heimdal Formation. The gas values stayed
constantly low during drilling through the reservoirs. Some gas peaks were
measured while drilling the Hugin Formation, but these were associated closely
to coal layers. Both the Heimdal and Hugin Formations were proved water bearing
through wire line logging.</p>

<p>A total of two cores were cut. The first
coring recovered only 0.5 m from the Heimdal Formation (2724 m to 2724.5 m).
The second coring recovered 18.6 m from the Hugin Formation (3399.4 m to 3418.0
m). </p>

<p>Pressure tests were carried out in the
Middle Jurassic Hugin and Sleipner formations and in the Triassic Skagerrak
Formation. No fluid sample was taken.</p>

<p>The well was permanently abandoned as a
dry well with weak shows on 19 May 1997. </p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


3074
7/6/2016 12:00:00 AM
29.01.2023
15/12-12


<p><b>General</b></p>

<p>The objective for well 15/12-12 was to
test the hydrocarbon potential of the Rev structure in PL 038 approximately 5
km south-east of the Varg Field (Varg A Platform). The target level was
Oxfordian Intra Heather Sands of the Viking Group.</p>

<p><b>Operations and results</b></p>

<p>Well 15/12-12 was spudded with the
semi-submersible installation Scarabeo 6 on 25 December 2000 and drilled to TD
at 3085 m in the Triassic Skagerrak Formation. At ca 2700 m the well starts to
build angle up to a deviation of ca 25 deg at ca 2830 m. This deviation is kept
down to TD where it leads to a difference between measured and vertical depth
of ca 30 m. The well was drilled with seawater and hi-vis pills through to the
base of the 17 1/2&quot; section at 1384 m and with Glydrill KCL Polymer from
1384 m to TD. </p>

<p>A total of 121 m (2856 - 2977 m) gross
Late Jurassic, Intra Heather reservoir sequence was penetrated in well 15/12-12
on the Rev Structure. The reservoir is interpreted as shallow marine sand
bodies and is dated Oxfordian of age. On top of the reservoir lie 6 m sand
dated Earliest Kimmeridgian of age. This sand was not considered as part of the
net reservoir. The massive Intra Heather sands had very good reservoir quality.
The cored interval of the reservoir had good hydrocarbon shows. Pressure data
showed a clear gas gradient with a distinct GOC at 2954 m (2912 m TVD MSL) and
an oil gradient down to base of reservoir (Top Triassic) at 2977 m (2932.5 m
TVD MSL). MDT samples of the oil leg indicated an oil-down-to (ODT) situation.
The pressure data also showed approximately 40 bars of depletion, caused by the
production on the Varg Field (Southern Segment). </p>

<p>The interval between 2864 - 3000 m was
cored in six cores, nearly the complete reservoir section and the upper part of
Triassic. MDT fluid samples were taken throughout the reservoir at 2867.5 m,
2895 m, 2961 m, 2964.2 m, and 2972.5 m. Samples from the two deepest levels
recovered variable proportions of water and oil, reflecting the lack of a clear
oil-water contact (OWC) in the reservoir. This is interpreted as an effect of
the pressure depletion due to the production on Varg. Apart from the sampled
water, which was heavily mud contaminated, sampled fluids were considered
representative for the reservoir. </p>

<p>The well was permanently abandoned on 9
February 2001 as an oil and gas discovery.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


3391
7/6/2016 12:00:00 AM
29.01.2023
15/12-13

<p><b>General</b></p>

<p>Well 15/12-13 is located approximately
0.8 km northwest of the 15/12-12 (Varg South) Discovery well. The primary
objective was to appraise the Varg South discovery: to define the oil/water
contact, measure current reservoir pressure and fluid gradients, confirm
reservoir quality and geometry, and confirm geophysical model in terms of depth
to top and base reservoir. Potential Kimmeridgian Sandstone immediately above
the main Oxfordian reservoir was seen as a secondary objective.</p>

<p><b>Operations and results</b></p>

<p>Appraisal well 15/12-13 was spudded with
the semi-submersible installation West Alpha on 23 April 2003 and drilled to TD
at 3047 m in Middle Jurassic Hugin Formation sandstone. The well is classified
as vertical, but due to high deviation the difference between measured depth
and vertical depth is 17 m at TD. The well was drilled with seawater and hi-vis
sweeps down to 1321 m, and with Sodium silicate (Barasil CX) mud from 1321 m to
TD.</p>

<p>Well 15/12-13
penetrated the target Oxfordian sandstone (Intra Heather Formation sandstone)
at 3013 m (2966 m TVDSS), which was 105 m deeper than prognosed. This was below
OWC, and the sand was water-wet. The overlying Draupne and Heather formations
were thicker the than prognoses, and the target area proved to be down faulted.
The sand encountered was, based on biostratigraphy, the same as in well
15/12-12. As the objectives were not achieved by this well, it was decided to
drill a geological sidetrack.</p>

<p>Well bore 15/12-3 was
logged by LWD in two runs; no wire line logs were run. No pressure or fluid
sampling tools were run. No cores were cut.</p>

<p>The well bore was plugged back to 1279 m
and permanently abandoned on 11 May 2003 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


4733
7/6/2016 12:00:00 AM
29.01.2023
15/12-13 A

<p><b>General</b></p>

<p>Well 15/12-13 is located ca 0.8 km
northwest of the 15/12-12 (Varg South) Discovery well. The primary objective
was to appraise the Varg South discovery: to define the oil/water contact,
measure current reservoir pressure and fluid gradients, confirm reservoir
quality and geometry, and confirm geophysical model in terms of depth to top
and base reservoir. Potential Kimmeridgian Sandstone immediately above the main
Oxfordian reservoir was seen as a secondary objective. The well bore 15/12-13
encountered the Oxfordian sandstones (Intra Heather Formation sandstone)  105 m
deeper than the prognosed reservoir, and below the OWC. Since the objectiv of
this well was not met well 15/12-13 A was drilled as a geological sidetrack to
15/12-13. The geological target was the same as in the primary well bore, but
ca 300 m southwest of the discovery well 15/12-12.</p>

<p><b>Operations and results</b></p>

<p>Appraisal sidetrack well 15/12-13 A was
spudded with the semi-submersible installation West Alpha on 11 May 2003.
Kick-off was at 1350 m. The well was drilled to 2530 m, when the BHA became
stuck repeatedly due to poor hole cleaning and the fact that the formation was
reacting with the mud. The well bore was drilled with Sodium silicate (Barasil
CX)/KCl/glycol mud. The well bore was logged with LWD only. No wire line logs were run, no pressure or fluid samples were
taken, and no cores were cut.</p>

<p>The sidetrack was abandoned in favor of a
lower angle sidetrack along a different azimuth. It was permanently abandoned
on 17 May as a junked well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


4754
7/6/2016 12:00:00 AM
29.01.2023
15/12-13 B

<p><b>General</b></p>

<p>Well 15/12-13 is located ca 0.8 km
northwest of the 15/12-12 (Varg South) Discovery well. The primary objective
was to appraise this discovery: to define the oil/water contact, measure
current reservoir pressure and fluid gradients, confirm reservoir quality and
geometry, and confirm geophysical model in terms of depth to top and base
reservoir. Potential Kimmeridgian Sandstone immediately above the main
Oxfordian reservoir was seen as secondary objective. The well bore 15/12-13 encountered
the Oxfordian sandstones (Intra Heather Formation sandstone) 105 m deeper than
the prognosed reservoir, and below the OWC. Since the objective of this well
was not met well 15/12-13 A was drilled as a geological sidetrack to 15/12-13. Well 15/12-13 was abandoned in the Rogaland
Group due to hole instability problems, and it was decided to drill a second
sidetrack. This sidetrack had target approximately 350 m to the northwest of
15/12-12. </p>

<p><b>Operations and results</b></p>

<p>Appraisal sidetrack well 15/12-13 B was
spudded with the semi-submersible installation West Alpha on 17 May 2003.
Kick-off was at 1345 m in 15/12-13. It was drilled to TD at 3151 m in the
Triassic Sleipner Formation. The well bore was drilled with Sodium silicate
(Barasil CX)/KCl/glycol mud.</p>

<p>A total of 134 m MD
(128 m TVD) of Kimmeridgian to Late Oxfordian reservoir (2958 m to 3092 m MD)
was penetrated in well 15/12-13 B. The oil/water contact was established at
3061.3 m (2964 m TVDSS), and the gas/oil contact at 3027.5 m (2931 m TVDSS). The
reservoir was found to be pressure depleted, most likely due to production from
the Varg Field, and the gas/oil contact had moved downwards from 2912 m TVDSS
in well 15/12-12 (drilled in 2001). </p>

<p>No conventional core
was cut. The MDT tool was run for pressure measurements and fluid sampling. Gas
was sampled at 3010 m, 3017 m, 3021 m, and 3024 m. Oil was sampled at 3028.5 m.
After completion of the logging program, the well was permanently abandoned on 11 June 2003 as an oil and gas appraisal.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


</html>

4759
7/6/2016 12:00:00 AM
29.01.2023
15/12-14
<p><b>General</b></p>

<p>Well 15/12-14 was drilled as an appraisal
well in the Varg West segment. The well was sidetracked from the existing well
15/12-A-12. The objectives were to prove hydrocarbons in the Varg West segment,
complete as an oil producer, and maximize the Varg oil production.</p>

<p><b>Operations and results</b></p>

<p>Appraisal well 15/12-14 was drilled as a
sidetrack from 15/12-A-12 on the Varg field below the 13 3/8&quot; casing shoe.
The operations started on 8 December 2003 with re-entry of well 15/12-A-12. All
operations were performed with the jack-up 3 legs installation Mærsk Giant. The
well bore was kicked off on 14 December at 1348 m and was drilled to TD at 3305
m in the Middle Jurassic Hugin Formation. Maximum deviation in the well is
36.95 degrees towards the base of the reservoir, decreasing to 34.4 degrees at
TD. Apart from a VSP_GR run and a CST-GR run all log data in the well originate
from LWD. The well was drilled using oil-based mud (ENVIRON) from kick-off to
TD. </p>

<p>Well 15/12-14 penetrated oil filled Late
Oxfordian sandstone, Hugin Formation, at 3104.9 m (2867.6 m TVD MSL). A total
of 105 m MD (3105 ? 3210 m), 84 m TVD (2868 ? 2952 m TVD MSL), was penetrated
in the well. No oil/water contact was found in the well, the oil-down-to is
placed at 2956 m TVD MSL (3214.5 m MD). Shows were recorded down to 3236 m. The
reservoir consisted of fine to medium grained sandstone with some coarser
grained beds in between. The average estimated porosity in the reservoir
section was 21 % with a N/G of 0.7. The reservoir was found to be pressure
depleted compared to the initial pressure observed in the Varg Field. Varg W is
interpreted to be in communication with Varg N3 (15/12-A-5 T2). The results
from the well thus confirmed the presence of hydrocarbon bearing reservoir in
the Varg W segment, and increased the reserves in the field. </p>

<p>No conventional core was cut in the well.
Formation pressure sampling was performed while drilling, utilizing the GeoTap
tool from Halliburton. No fluid sample was taken.</p>

<p>The well was completed with a perforated
liner and set in production with an initial production rate of 2000 Sm3/d. The
well was classified as appraisal and was renamed to 15/12-A-12 A after
completion. </p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>









































































































4845
4/11/2017 12:00:00 AM
29.01.2023
15/12-15


<p><b>General</b></p>

<p>Wildcat well 15/12-15 was drilled on the
Maureen Terrace, ca 3 km west of the Varg and 15/12-12 Rev Discoveries. The
main object of the well was to drill to Middle Jurassic/Triassic strata with
the aim to explore the hydrocarbon bearing potential of Oxfordian age
sandstones analogues to the Varg West. Secondary objective was the hydrocarbon
potential of Kimmeridge age sandstone immediately above the main Oxfordian
reservoir. The well should measure reservoir pressure and fluid gradients,
assess the reservoir quality of the Late Jurassic target reservoir, assess
reservoir geometry, and confirm geophysical model in terms of depth to top and
base reservoir. </p>

<p><b>Operations and results</b></p>

<p>Well 15/12-15 was spudded with the
semi-submersible installation Deepsea Trym on 19 November 2004 and drilled to
TD at 3300 m in the Middle Jurassic Sleipner Formation. Apart from some very
slow drilling in the interval from 2454 m to 2492 m no significant problems
were encountered in the operations. The well was drilled with seawater and
hi-vis sweeps down to 1370 m, and with a salt saturated /polymer mud system
(Performadril) from 1370 m to TD.</p>

<p>Well 15/12-15 penetrated the Oxfordian
sandstone at 3140.5 m. The sand was encountered 92 m TVDSS deeper than expected,
and was water-wet. The overlying Kimmeridgian sands within the Heather
Formation were approximately 96 metres thicker than prognosed and were also
water-wet. Weak possible fluorescence was reported from cuttings within the
Kimmeridgian reservoir but post-well geochemical analyses revealed no evidence
for hydrocarbons of any kind. MDT pressure measurements found the reservoir to
be pressure depleted. </p>

<p>No cores were cut and no wire line fluid
samples taken in the well.</p>

<p>The well was permanently abandoned on 21
December 2004 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>





5017
4/11/2017 12:00:00 AM
29.01.2023
15/12-16 S


<p>Well <a name="OLE_LINK2"></a><a
name="OLE_LINK1">15/12-16 S </a>was drilled to appraise the Varg Field in the
Southern Viking Graben area of the North Sea. Three wells had been drilled on
the field, 15/12-12 and 15/12-13 B (gas condensate) and one dry well 15/12-13. Well
15/12-13 A failed while in the Rogaland Formation. These 3 wells delineate the
Western Flank of the field, while 15/12-16 S should seek to add proven reserves
in the central panel. </span></p>

<p>The primary objective for the well was to
produce gas condensate from the Oxfordian reservoir in the central panel and to
determine by DST whether surrounding faults form barriers to production.
Secondary objectives were to acquire reservoir pressure data, formation depths,
cuttings, log and drill data for reservoir description and reservoir
performance prediction.</p>

<p><b>Operations and results</b></p>

<p>Well 15/12-16 S was spudded with the jack-up
installation Mærsk Giant on 6 February 2006 and drilled to TD at 2961 m, 47 m
into the Triassic Skagerrak Formation. No major drilling problems or incidents
occurred during the drilling of the well. The 8 ½&quot; section was drilled in
one bit run. The well was drilled with seawater and KCl/polymer down to 1319 m,
with Performadril WBM from 1319 m to 2835 m, and with Baradril-N WBM from 2835
m to TD.</p>

<p>The well encountered the top reservoir
Oxfordian sandstone at 2836 m (2787 m TVD RKB), 70 m high to prognosis and
encountered a reservoir section thinner than predicted (83 m MD vs. 130 m).
Preliminary interpretation indicated that the top of the reservoir section was
faulted out and that RZ2 is very condensed. Reservoir quality was slightly poorer
than was predicted with low porosities in the lower part but is still good. Logs
and MDT pressure data showed the reservoir was gas filled but no definite
gas-water contact was defined.</p>

<p>Dull yellow/gold mineral fluorescence,
poor slow white cuts and poor crush cuts were noted on the cuttings in top of
the Tor Formation. In the gas filled Oxfordian sandstone dull blue white slow
cloudy cut fluorescence was observed, no direct fluorescence. Otherwise there
were no shows reported from the well.</p>

<p>No cores were cut and no wire line fluid
samples were taken.</p>

<p>The well was suspended on 31 March 2006 as
a Varg South gas producer.</p>

<p><b>Testing</b></p>

<p>The well was completed with a 7&quot;
liner across the reservoir and perforated at intervals 2850 m to 2884 m for
testing. An extended testing program was carried out, with the main flow period
flowing at a steady rate of 1190000 Sm3 gas/day through a 72/64&quot; choke.
The average condensate-gas ratio was 49.7 bbl/MMSCF corresponding to a GOR of
ca 3600 Sm3/Sm3. Sampling results gave a condensate gravity of 52.3 deg API, a
gas gravity of 0.692 with 2ppm H2S and 2 % CO2.</p>



5271
4/11/2017 12:00:00 AM
29.01.2023
15/12-17 A


<p><b>General</b></p>

<p>Well <a name="OLE_LINK2"></a><a
name="OLE_LINK1">15/12-17 A </a>was drilled as a geological sidetrack of the
15/12-17 S, down dip into a separate down faulted compartment. The objective
was to find the GOC and OWC which were not seen in the 15/12-17 S well.</span></p>

<p><b>Operations and results</b></p>

<p>Well 15/12-17 A was drilled with the jack-up
installation Mærsk Giant. The well was kicked of from 3030 m in 15/12-17 S on 4
February 2007 and drilled to TD at 3620 m (2655 m TVD RKB) in the Triassic
Skagerrak Formation. The well was drilled with Carbo SEA oil based mud from
kick-off to TD.</p>

<p>The top of late Jurassic sands was picked
at 3360 m (2813 m TVD RKB). The base of the reservoir (top Skagerrak Formation)
was picked at 3550 m (2916m TVD RKB) and gives a reservoir thickness of 107 m TVD.
The well found gas in the Late Jurassic sands and the Skagerrak formation, but
did not find any GOC or OWC.</p>

<p>No cores were cut and no fluid samples
were collected.</p>

<p>The well was suspended on 23 March 2007 for
future use as a gas producer.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


5484
4/11/2017 12:00:00 AM
29.01.2023
15/12-17 S


<p><b>General</b></p>

<p>Well <a name="OLE_LINK2"></a><a
name="OLE_LINK1">15/12-17 S </a>was drilled to explore an un-drilled part of
the East flank of the Rev structure. Four previous wells on the structure had
proved good quality Late Jurassic shallow marine reservoir sandstone containing
gas-condensate and a thin oil leg around a salt structure at about 3000 metres
depth. Pressure measurements have shown that the reservoir is in communication
with the Varg field to the north. Seismic data indicated that the reservoir
thins and possibly pinches-out up dip towards the crest of the salt wall.</span></p>

<p><b>Operations and results</b></p>

<p>Well 15/12-17 S was spudded with the jack-up
installation Mærsk Giant on 23 December 2006 and drilled to TD at 3371 m in the
Late Permian Zechstein Group. The well surface position was on the west flank
of the salt structure. A vertical 9 7/8&quot; pilot hole was drilled in one bit
run down to 810 m to ensure no shallow gas in potential zones. No gas was
observed. The pilot hole was then opened up to 17 1/2&quot; down to 810 m. From
there the 17 1/2&quot; section was drilled deviated in a single bit run down to
1313 m. The well continued in an east-southeast direction with TD at a location
east of the crest of the salt structure. The well was drilled with sea water
and hi-vis sweeps down to 810 m, with sea water and KCl/polymer from 810 m to
1313 m and with Carbo SEA oil based mud from 1313 m to TD. The well took a 15
m3 gas kick at 3258 m (2871 m TVD RKB). It is clear from the kick that the
reservoir pressures were higher than both the anticipated depleted values and
the previously measured virgin pressures in the Varg/Rev area.</p>

<p>The Late Jurassic reservoir sands were
penetrated at 3246 m (2773 m TVD RKB) and were found to be gas/condensate
filled. No gas/water or gas/oil contact was penetrated. Apart from the oil
bearing Late Jurassic reservoir section, fluorescence, mostly mineral
fluorescence, was recorded only in limestone of the Tor Formation.</p>

<p>No cores were cut. MDT pressure samples
were acquired in the Late Jurassic sandstones together with an MDT fluid gas/condensate
sample at 3288 m. The pressure data obtained showed that the reservoir
penetrated by the well was in a separate pressure cell that did not seem to
have been affected by production from Varg. </p>

<p>Following wire line logging and pressure
and fluid sampling, the well was plugged back for a geological. The purpose of
the sidetrack was to establish the hydrocarbon/water contacts. </p>

<p>The well was plugged back to 3156 m on 4
February 2007.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


5442
4/11/2017 12:00:00 AM
29.01.2023
15/12-18 A




<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 A is located between the
Sleipner Øst and Varg fields in the North Sea. It was drilled to appraise the
Paleocene oil discovery made in 15/12-18 S. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 A was kicked off from below
the 13 3/8&quot; casing shoe at 1170 m in well 15/12-18 S on 8 November 2007. Inclination
was built to 41 degrees, which was achieved at 1733 m. Final TD was reached at
3036 m in the Late Cretaceous Tor Formation. The well was drilled with the
jack-up installation Mærsk Giant. It was impossible to run wire line logs past
the kick off area and therefore only LWD logs were obtained from 15/12-18 A.
Otherwise no significant problem was encountered in the operations. The well
was drilled with Enviromul oil based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was drilled into Top Heimdal
reservoir at 2884 m where hydrocarbons were encountered in two 2 m thick sands.
The targeted Ty Formation was encountered 10 m thick at 2952 m (2613 m TVD). The
sand was, however, found below the OWC established in 15/12-18 S and was water bearing.
Apart from the Heimdal Formation reservoir shows were observed only on
claystones in the interval 2600 - 2690 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken in this well bore.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11
December 2009 as a discovery well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5608
4/11/2017 12:00:00 AM
29.01.2023
15/12-18 S




<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 S is located between the
Sleipner Øst and Varg fields in the North Sea. The well was designed to test
three prospects in different stratigraphic intervals, referred to as Grid
(Eocene), Storskrymten (Paleocene) and Grytkollen (Triassic Hugin/Skagerrak
Formation). The Storskrymten reservoir was the primary objective of the three.
If hydrocarbons were discovered bore, a sidetrack would be evaluated to prove
the vertical extension of the column. All prospects were based on up doming
effects along the main migration routes from the Maureen area. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-18 S was spudded with the jack-up
installation Mærsk Giant on 5 September 2007 and drilled to TD at 3520 m (3310
m TVD) in the Late Permian Zechstein Group. It was drilled vertical down to
1700 m, building angle up to ca 35 deg at ca 2550 m. The deviation was kept within
36 to 24 deg for the remaining well path down to TD. The drilling operation was
executed with several down-hole problems. Major delays were due to logging problems
and lost circulation in the Cretaceous. The well was drilled with seawater down
to 474 m, with KCl/polymer mud from 474 m to 1173 m, with mineral oil -based
mud (Carbo-Sea) from 1173 m to 2773 m, and with Enviromul oil based mud from
2773 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Twenty-two m of Grid sandstones were
found water bearing. The Paleocene Ty Formation at 2670 m (2589 m TVD) was
found hydrocarbon bearing. The OWC was from pressure data set to 2687.5 m (2602.5
m TVD). From the resistivity logs, however, the OWC would be set at 2691 m (2605.8
m TVD). This gives a vertical oil column of 16.8 m. Shows were recorded down to
2722 m. After evaluation of the Ty Formation reservoir, drilling continued into
Hugin Formation at 3420 m (3219 m TVD), where 9 m of sandstone was encountered,
but with no hydrocarbons. Shows were recorded on limestone at 2960 to 2970 m,
in marl/claystone in the interval 3053 to 3175 m, and in shales of the Draupne
and Heather Formations from 3270 to 3320 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No core was cut. Oil was sampled during
the MDT runs at depths of 2671.9 m and 2683.6 m. Water was sampled at 2705 m. A
mini-DST was attempted but aborted due to packer problems.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was completed on 7 November 2007
as an oil discovery. A side track (15/12-18 A) was initiated to appraise the
discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5607
4/11/2017 12:00:00 AM
29.01.2023
15/12-19
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Pi North well 15/12-19 was drilled on
the northern lobe of the Maureen Terrace in the North Sea. The prospect is
adjacent to the UK Armada complex of Fields (Fleming, Drake and Hawkins) and
the Seymour Fields to the West and the Varg and Rev Fields to the North. The
main objective of the well was to test the hydrocarbon potential in
Sleipner/Skagerrak sandstone formations in the Pi North structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well was spudded with the jack-up
installation Mærsk Guardian on18 February 2008 and drilled to TD at 3212 m in
Triassic rocks of the Skagerrak Formation. A 9 7/8&quot; shallow gas pilot hole
was drilled from TD in the 36&quot; section at 203.5 m to 672 m. No shallow gas
was seen. No significant problem was encountered in the operations. The well
was drilled with sea water and pre-hydrated bentonite down to 672 m, with
Aquadrill mud from 672 m to 1364 m, and with Carbo SEA oil based mud from 1364
m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Jurassic was encountered at 2969 m
and consisted of only 4 m Draupne Formation directly overlying the Triassic
Skagerrak Formation. No sediments of the Jurassic Sleipner Formation were
encountered. The Skagerrak Formation was hydrocarbon bearing. The sandstones
had an average porosity of 17% net when using an 11.8% cut off in the oil case
and 8.1% in the gas case. The reservoir system was complex with an upper
reservoir with gas down to 2986.8 m (13.8 m TVD gross gas column, 9.21m net
pay) and an underlying oil column of 35.7 m TVD gross (13.11m net pay). A lower
reservoir with a 16.5 m TVD gross oil-leg (3.81 m net pay) was encountered at
3044.5 m. The two oil zones were separated by a 22 m thick zone of movable
water (confirmed by RCI water samples). Pressure data in the different
reservoir zones indicated different pressure regimes and varying pressure
depletion caused by production from neighbouring fields. No oil shows were
observed in the well other than in the Skagerrak reservoir sections.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores totalling 156.69 m were cut
with 100% core recovery from 2975.0 to 3131.7 m in the Skagerrak Formation. </span></p>

<p class=MsoBodyText><span lang=EN-GB>RCI wire line fluid samples were taken at
2973.5 m (gas), 2983 m (gas), 2994.5 (oil), 3023.5 m (water/oil mix), 3056.2 m
(oil), 3030.1 m (water), 3015 m (oil), and 3117.5 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
May as an oil and gas discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three drill stem test were conducted in
the Skagerrak Formation. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1A tested the interval 3088 - 3102 m.
It produced 318 Sm3 oil and 29450 Sm3 gas /day through a 28/64&quot; choke in
the main flow. The GOR was 93 Sm3/Sm3. The bottom hole temperature was 130.8
deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1B tested the intervals 3088 - 3102 m
and 3036.5 - 3064 m. It produced 657 Sm3 oil and 156620 Sm3 gas /day through a
44/64&quot; choke in the main flow. The GOR was 239 Sm3/Sm3. The bottom hole
temperature was 130.0 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1C tested the interval 3088 - 3102 m,
3036.5 - 3064 m, and 3023 - 3029 m. It produced 396 Sm3 oil and 831297 Sm3 gas
/day through a 56/64&quot; choke in the main flow. The GOR was 2102 Sm3/Sm3.
The bottom hole temperature was 127.8 deg C.</span></p>






































































5705
2/21/2020 12:00:00 AM
29.01.2023
15/12-2
<p><b>General</b></p>

<p>Well 15/12-2 was drilled in order to
evaluate Jurassic formations on a seismic structure located in the eastern part
of block 15/12. The principal objective of the 15/12-2 well was to test the
Dogger (Hugin Formation) sandstone, where oil shows had been encountered in the
15/12-1 well. A secondary object was a possible sand in the Paleocene. </p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/12-2 was spudded with the
semi-submersible installation Ross Rig on 7 January 1976 and drilled to TD at
2924 m in Late Permian Zechstein anhydrite. The well was drilled with a
lignosulphonate mud system. </p>

<p>No sand was found in the Paleocene. The
Hugin Formation sandstone was found 304 meters higher than in the 15/12-1 well.
The sandstone proved to have very good reservoir qualities, but was completely
water bearing. There were sandstone stringers in the lower part of the Heather
Formation. The Hugin Formation sand was cored from 2823 m to 2835.4 m, with no
show. No fluid sampling was attempted in the well.</p>

<p>The well was permanently abandoned as a
dry well on 27 February 1976.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>

331
9/16/2019 12:00:00 AM
29.01.2023
15/12-20 S






<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-20 S was drilled from the Varg
Field production Platform in the southern Viking Graben in the North Sea. The
primary objective of the well was to explore a potential undrained compartment
in Triassic sands. A secondary objective was potential Late Jurassic sands that
could exist above the Triassic sands. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-20 S was drilled with
the jack-up installation Mærsk Giant, as a sidetrack from development well
15/12-A-7 on the Varg Field. It was kicked off 28 May 2008 from 1306 m, just
above the 13 3/8&quot; casing in the 15/12-A-7 development well, and drilled to
TD at 4192 m (3142 m TVD) in the Late Triassic Skagerrak Formation. Significant
operational problems were not encountered although 21% of the rig time was
counted as non-productive. The main contributor to non-productive time was failure
to mill the window in the 13 3/8&quot; casing during kick-off. The well was
drilled with Carbo-Sea oil based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Oxfordian Sandstone that makes up the
reservoir over Varg Field was absent as forecast. A discovery was made in Middle
Jurassic Sleipner Formation sandstone. This sand, encountered at 3808 m, was
not prognosed. It contained oil down to a lithological contact at ca 3842 m (2878
m TVD SS). The underlying Triassic was encountered at 3874 m and was dry. Good
shows on sandstones were reported in cuttings at 3810 and all through to the
end of the cores at 3875 m. Formation Gas peaks up to a maximum of 4% were seen
in the Sleipner formation. Resistivity was initially high, 15 ? 30 ohm/m from
3812 m (after the coal) and dropped off at 3835m MD to 0.3 - 0.8 ohm/m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were taken (26.26 m and 54.85 m)
from the Sleipner Formation and ca 25 m into the Triassic. Reservoir pressures
were taken using TesTrak and an oil gradient of 0.935 SG was obtained although
a water gradient was not established. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Exploration well 15/12-20 S is classified
as an oil discovery. On 1 July 2008 7&quot; liner was run to 4191 m and the
well was reclassified to development well 15/12-A-7-A.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


5824
4/11/2017 12:00:00 AM
29.01.2023
15/12-21


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 15/12-21 Grevling well is located on
the south-western margin of the Hidra High, approximately 18 km north of the
Varg field in the southernmost part of the Viking Graben. The primary objective
was to test the Middle Jurassic Hugin and Sleipner formations in a crestal
position on the structure. The Triassic Skagerrak Formation was a secondary
objective.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A 12 1/4&quot; pilot hole was drilled to
1195 m to check for shallow gas. No shallow gas was encountered. Well 15/12-21
was spudded with the jack-up installation Mærsk Guardian on 15 March 2009 and
drilled to TD at 3310 m in the Late Triassic Skagerrak Formation. The well was
drilled with Seawater and sweeps down to 221 m, with a water based KCl mud from
221 m to 1193 m, and with Carbosea oil based mud from 1193 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the Hugin reservoir was
encountered at 3031 m, 15m deeper than prognosis. The Sleipner Formation
reservoir came in 21m shallow, at 3059 m, and top the Triassic 11 m shallow, at
3122 m. The Hugin, Sleipner and upper Skagerrak formations all proved to be oil
bearing with a total pay of 67 m. No oil water contacts were encountered within
the well. However, two vertical pressure barriers were interpreted; a top Sleipner
coal at 3059 m (3017 m TVDSS), which separates the Hugin and Sleipner oil-bearing
sandstones, and an intra-Triassic shale at 3164 m (3122 m TVDSS), which
separates oil bearing Skagerrak sandstones above from water bearing Skagerrak
sandstones below. No oil shows were recorded above reservoir level in the well.
In the Triassic oil shows were seen down to 3179 m, 15 m below the oil-down to
contact in the Skagerrak Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores of a total of 88.26 m were cut.
Core 1 was cut from 3047.50 m to 3081.70 m in the Hugin and Sleipner
formations, and core 2 was cut from 3106.50 m to 3160.56 m in the Sleipner and
Triassic Skagerrak formations. The Cores need to be depth shifted up 6.5 meters
to match log data. RCI wire line fluid samples were taken in the Hugin
Formation at 3034.5 m (oil), the Sleipner Formation at 3074.4 m (oil), and in
the Skagerrak Formation at 3152 m (oil), 3186.8 m (water), and 3222 m (water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21
May 2009 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>In DST 1 the Sleipner/Skagerrak
Formations were perforated in the interval 3099.6 to 3158.17 m. DST1 produced
124 Sm3 oil and 3617 Sm3 gas /day through a 20/64&quot; choke in the main flow.
The oil density was 0.861 g/cm3 and the GOR was 29 Sm3/Sm3. The gas gravity was
1.121 (air = 1) with 11 ppm H2S and 5.5% CO2. The bottom hole temperature
recorded in DST1 was 120 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>In DST 2 the Hugin Formation was
perforated in the interval 3030.24 to 3059.04 m. DST2 produced 75 Sm3 oil and
3563 Sm3 gas /day through a 20/64&quot; choke in the main flow. The oil density
was 0.861 g/cm3 and the GOR was 47 Sm3/Sm3.The gas gravity was 1.121 (air = 1)
with 10 ppm H2S, and 9.0 % CO2. The bottom hole temperature recorded in DST2
was 117 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No water was produced in the tests.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6047
4/11/2017 12:00:00 AM
29.01.2023
15/12-21 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 15/12-21 A is a sidetrack to the
15/12-21 Grevling well, which discovered oil in Hugin, Sleipner, and Skagerrak
Formations sandstones. No oil-water contacts were seen in 15/12-21. The
sidetrack well was drilled to appraise the discovery down flanks and to the
east on the structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-21A was kicked off
from 2162 m in well 15/12-21 on 21 May 2009. It was drilled with the jack-up
installation Mærsk Guardian to TD at 3702 m (3348 m TVD) in the Late Triassic
Skagerrak Formation. The well was drilled with Carbosea oil based mud from kick-off
to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was encountered at
3378 m (3118 m TVD), the Sleipner Formation at 3412 m (3141 m TVD), and the
Triassic Skagerrak Formation at 3493 m (3198 m TVD). All three formations proved
to be oil bearing as in the main well, with total pay of 36 m MD. No oil shows
were noted above reservoir level. Patchy oil shows were recorded down to 3570m
and the higher gas components had died away by 3586m. Show description was compromised
due to the fact that the sandstone cuttings were often altered to an amorphous rock
flour. The shows were described as poor direct pale white fluorescence, slow
white crush cut fluorescence, very pale tea colour residue.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in this well. RCI wire
line fluid samples were taken at 3394.5 m in the Hugin Formation (oil), 3411.7
m in the Hugin Formation (oil), 3519.4 m in the Skagerrak Formation (oil), and
at 3646 m in the Skagerrak Formation (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
June 2009 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6139
4/11/2017 12:00:00 AM
29.01.2023
15/12-22


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The15/12-22 Storkollen well was drilled
south of the Sleipner East Field in the south Viking Graben of the North Sea.
The objective was test the hydrocarbon and reservoir potential of the Storkollen
prospect. Primary target was Oxfordian &quot;Varg Equivalent sandstone&quot;
(Hugin Formation) of the Vestland Group, while the Early Tertiary Heimdal/Ty Formations
was a secondary target.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-22 was spudded with
the semi-submersible installation Bredford Dolphin on 17 April 2010 and drilled
to TD at 3035 m in the Late Triassic Skagerrak Formation.  A shallow gas influx
occurred at 697-700 m while waiting on weather (low wind) after having drilled
the 9 7/8&quot; pilot hole to 744 m. The interval had an intermediate shallow
gas warning. The gas influx was killed with 1.25 GS mud, and the pilot hole was
plugged back for setting the contingent 20&quot; casing with the shoe at 622 m.
The well was drilled with seawater/bentonite and hi-vis sweeps down to 622 m,
with KCl/polymer/GEM mud from 622 m to 1550 m, and with XP-07 oil based mud
from 1550 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Tertiary sands were penetrated in the Utsira
and Skade formations, while the Frigg Formation sandstones were not encountered
at the Storkollen location. The secondary target, the Paleocene Heimdal/Ty
Formations was not present, and Top Shetland chalks were penetrated at 2320 m,
which was 16 m shallower than prognosed. The primary reservoir target, the Hugin
Formation of the Vestland Group, was penetrated at 2831 m, which was 22 m
shallower than prognosed. The sandstone unit was 154 m thick and had excellent
quality with a N/G ratio of 96% and an average porosity of 25%.  It was water bearing.
GeoTap pressure measurements within the Hugin Formation detected an
overpressure of only 42 bars, compared to normal hydrostatic pressure. The low overpressures
may indicate compartmentalisation, thus explaining failed migration into the
Storkollen 4-way closure. Apart from the shallow gas influx no oil or gas shows
are reported from the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. The well was logged on
MWD/LWD and no wire line logs were run. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
May 2010 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



6326
4/11/2017 12:00:00 AM
29.01.2023
15/12-23


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 was drilled to appraise the
Grevling Discovery in the Southern Viking Graben in the North Sea. The
objective was to seek a deeper oil reservoir, or an oil water contact, within
the Sleipner Formation, while addressing reservoir distribution and quality
along with oil type and to prove up additional reserves in the Grevling
discovery in the Hugin, Sleipner and Skagerrak formations sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-23 was spudded with
the semi-submersible installation Transocean Winner on 1 April 2010 and drilled
to TD at 3485 m in the Late Triassic Skagerrak Formation. No significant
problem was encountered in the operations. The well was drilled with Hi-Vis
Bentonite Sweeps down to 176 m, with KCl/GEM mud from 176 m to 1200 m, and with
ENVIROMUL oil based mud from 1200 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The prognosed top reservoir Hugin
Formation was absent. Instead a silty Intra Heather Formation Sandstone was
found directly on the Sleipner Formation. The Sleipner Formation came in at
3164 m and proved to be the main reservoir with coals and massive sandstones interbedded
with siltstone. The top of the Sleipner was picked on the log response of coals
present at the top of the Formation, and coals seen in the samples. Top reservoir
sandstones came in at 3179 m only 1 m deep to prognosis. The reservoir
comprises the Sleipner and Skagerrak Formations at this well location. The
Skagerrak Formation came in at 3192 m 56 m shallower than the prognosis. Top
Skagerrak was picked 54 m shallower from core biostratigraphy than from seismic
and petrophysical logs. An OWC, possibly ODT, was picked at 3251 m in the
Skagerrak Formation. Shows were observed on cuttings in the Sleipner sandstones
and varied from no show to very good show in clean sands before pulling out to
cut core at 3187 m. Shows from top cored interval in the Sleipner Formation at
3187 m continued into the Skagerrak Formation and down to 3230m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut, core 1 from 3187 m to
3241.5 m and core 2 from 3241.5 m to 3296 m, giving a total of 109 m of core. Cores
must be depth shifted down 4.6 meter to match the logs. The MDT was run and 18
good pressure points were obtained. Fluid samples were taken at 3191 (oil), 3232
m (oil), 3264 (water), 3285 (water), and 3336 (water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
May 2012 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One drill stem test was performed from
the interval 3181.5 - 3233 m in the Sleipner and Skagerrak Formations. The test
produced at maximum 103 Sm3 oil/day through a 16/64&quot; choke in the main
flow. The gas measuring equipment did not work properly. In the succeeding sampling
flow the well produced 84 Sm3 oil and 4159 Sm3 gas/day through a 12/64&quot;
choke. The GOR was 50 Sm3/Sm3. </span></p>
l>

6327
4/11/2017 12:00:00 AM
29.01.2023
15/12-23 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 A is a geological sidetrack
to well 15/12-23, which proved oil in the Middle Jurassic Sleipner Formation
and the Late Triassic Skagerrak Formation. It was drilled to appraise the
Jurassic and Triassic potential in the western flank of the Grevling prospect in
the Southern Viking Graben in the North Sea. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-23 A was drilled with the
semi-submersible installation Transocean Winner. It was kicked off at 1191 m, below
the 13 3/8&quot; casing shoe in 15/12-23, and drilled to TD at 4772 m (3327 m)
in the Middle Jurassic Sleipner Formation. The well was drilled with ENVIROMUL
oil based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was encountered at
4603 m (3220 m TVD). It had very good reservoir conditions and oil shows, but was
water filled. The Sleipner Formation was encountered at 4632 m (3242 m TVD) and
the upper section down to 4699 m consisted dominantly of coal beds and
interbedded sandstones, which were difficult to interpret from logs. Some
interbedded sandstones had shows and some had no shows. From 4699 m the
Sleipner Formation was oil-bearing down to a probable OWC around 4725 m (3315 m
TVD). Shows were recorded down to 4735 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut, core 1 from 4612 to
4664 m, core 2 from 4664 to 4701 m and core 3 from 4701.2 to 4741 m, giving a
total of 129 m of core.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No wire line logs were run hence no
down-hole fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 18
July 2010 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6404
4/11/2017 12:00:00 AM
29.01.2023
15/12-24 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-24 S was drilled to test the Snømus
prospect in the Ling depression adjacent to the Varg Field in the North Sea.
The primary objective was to test the hydrocarbon potential in syn-rift
Ula-Sandnes formations and pre-rift Hugin - Sleipner formations. Sands in the
Triassic Skagerrak Formation was secondary objective.  </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/12-24 S was spudded with
the jack-up installation Mærsk Giant on 10 April 2015 and drilled to TD at 3181
m in the Late Triassic Skagerrak Formation. A pilot hole was drilled from 178 m
to 1355 m to check for shallow gas. Minor gas peaks associated with thin sand
layers were recorded at 757 and 768 m, and potentially also at 488 and 505 m. No
significant problem was encountered in the operations. The well was drilled
with seawater and hi-vis sweeps down to 178 m, with KCl/polymer/GEM mud from
178 m to 1365 m, and with Innovert oil based mud from 1365 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Ula sand was encountered at 2903 m,
10.7 m deeper than prognosed. A total of 194 m MD of Ula and Sandnes sand with
mostly good quality, were drilled. Top Skagerrak Formation was picked at 3097 m,
6 meters shallower than prognosed. A total of 84 m MD of Skagerrak Formation
was drilled, however only poor quality reservoir sands encountered. All target
reservoirs were water-wet. Only weak shows above the OBM were described in the
Vestland Group and Skagerrak Formation, else no shows were recorded in the
well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. Due to dry well, only
VSP was run on wireline. No fluid sample was taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
May 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>




























































































































































































7661
4/18/2017 12:00:00 AM
29.01.2023
15/12-3


<p>Well 15/12-3 is located in the South
Viking Graben in the North Sea, south of the Sleipner Øst Field. The primary objective
of the well was to test possible hydrocarbons in late Jurassic sand. This sand
was proven in 15/12-2. Secondary objectives were Danian and Rotliegendes sands.
Minor Danian sand beds were proved in 15/12-1, and further west on the UK side oil was produced from Palaeocene sands on the Maureen Field. The well should be
drilled through ca 1100 m of prognosed salt and 100 m into the Rotliegendes or
to a total depth of 4900 m. </p>

<p><b>Operations and results</b></p>

<p>Well 15/12-3 was spudded with the
semi-submersible installation Nordraug on 21 June 1980 and drilled to TD at
4450 m in Early Permian Rotliegendes sandstone. After setting the 13 3/8&quot;
casing the rig crew went on strike from 20 July to 14 August. While drilling 12
1/4&quot; hole with salt saturated mud the bottom hole assembly got stuck at
2715 m when pulling out of the hole. Eleven days were spent working on the fish
before the hole was eventually sidetracked from 2488 m. The well was drilled
with seawater/bentonite/lignosulphonate mud down to 2185 m, with salt saturated
polymer mud from 2185 m to 3361 m, and with oil based mud (Oilfaze) from 3361 m
to TD.</p>

<p>The primary objective, Jurassic sandstone,
was only a few meter thick. The sand was found deeper and was thinner than
expected. The well proved no sand in Palaeocene. The other secondary objective,
Rotliegendes sandstone, was highly interbedded with shale. None of the sands had
shows of hydrocarbons. </p>

<p>One core was cut from 3256 to 3263 m in
the Zechstein Group above the salt. A second core was cut near final TD in the
Rotliegendes Group from 4424 to 4433 m. No wire line fluid samples were taken.</p>

<p>The well was permanently abandoned on 22
December 1980 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



199
5/19/2016 12:00:00 AM
29.01.2023
15/12-4


<p>Wildcat well 15/12-4 is located on the
Maureen Terrace in the South Viking Graben in the North Sea. The primary
objectives were the Palaeocene Heimdal Formation and sandstones of Jurassic and
Triassic age. Secondary objectives were the Frigg Formation and fractured limestone
in the Cretaceous. </p>

<p><b>Operations and results</b></p>

<p>Well 15/12-4 was spudded with the
semi-submersible installation Deepsea Bergen on 13 September 1984 and drilled
to TD at 3157 m, 17 m into the Triassic Group. Operations were completed
within the time schedule and with very few problems. The well was drilled with
seawater and gel down to 505 m, with gypsum polymer from 505 m to 2680 m, and
with lignosulphonate from 2680 m to TD.</p>

<p>No Heimdal or Frigg sands were encountered
in the well. From logs and cores hydrocarbons were seen in the uppermost part
of the Cretaceous chalk in the interval 2490 ? 2515 m. Core analysis and log
analysis indicated very poor reservoir properties in this chalk. The water
saturation was high (60 - 80 %) and the permeability was extremely low (0.01 -
0.5 mD). A 1.5 meter oil column was seen in the Jurassic sandstone, from 2911.5
to 2913 m with a transition zone down to 2915.5. Apart from these two intervals
there were no shows or other hydrocarbon indications in the well.</p>

<p>Four cores were cut, one in the Palaeocene,
two in the Late Cretaceous and one in the Late Jurassic sequence. One FMT run
was made in the Cretaceous. Here, no pressure points out of 19 attempts were
successful due to seal failure and very low permeability in the formation. One
attempt to get sample at 2439.5 m failed due to tight formation. In the
Jurassic a segregated FMT sample was taken at 2912 m (5.8 l oil with a density
of 0.847 g/cm3 in the 2 3/4 gallon chamber) and a second segregated sample at
2913.5 m (0.5 l oil and 9 l water/mud filtrate in the 2 3/4 gallon chamber).</p>

<p>The well was permanently abandoned on 31
October 1984 as an oil discovery.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


438
7/6/2016 12:00:00 AM
29.01.2023
15/12-5
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-5 was drilled on the Beta
Central structure ca 3.3 km north-east of the 15/12-4 Varg discovery well in
the North Sea. Primary objective was the Jurassic sandstones. Secondary
objective was the Frigg Formation sand and fractured limestone of Cretaceous
age. Seismic anomalies indicated shallow gas. Prognosed TD was 3100 m RKB in
sandstone of Triassic age.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-5 was spudded with the
semi-submersible installation Ross Isle on 12 March 1986 and drilled to TD at
3150 m in the Late Triassic Skagerrak Formation. No shallow gas was
encountered. Drilling proceeded without significant problems. The well was
drilled with Spud mud down to 217 m, with gel/seawater/XC-polymer from 217 m to
619 m, with gypsum/polymer mud from 619 m to 2889 m, and with
gel/lignosulphonate/lignite from 2889 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Cretaceous came in at 2457 m, and top
Jurassic at 2841 m. Top of the reservoir, an Oxfordian sandstone, was
encountered at 2918 m with good shows. The OWC was found at 2942 m, 28 m below
that of well 15/12-4. This is probably due to a flow barrier caused by the
fault system with a maximum throw of ca 100 m that separates the Beta West and
Beta Central structures. Due to FMT pressure measurements and fluid samples,
Statoil decided to go for &quot;sole risk&quot; testing, since Esso denied
participating in the testing program.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 2892
m to 2967 m with 100% recovery. The core-log depth shifts were small, in the
range 0.0 to -0.5 m for all three cores. FMT fluid samples were taken at 2919.3
m (oil), 2923.5 m, 2937.0 m (oil), and at 2941.5 m (water mud filtrate and a
little oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4
May 1986 as an oil appraisal of the Varg Field.<b> </b></span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One DST test was performed in the
interval 2926 m to 2936 m. The test produced 520 Sm3 oil and 42000 Sm3 gas /day
through a 40/64” choke. The GOR was 81 Sm3/Sm3, oil gravity was 0,909 g/cm3,
and the gas gravity was 0.795 (air = 1). The test temperature was 127 °C.</span></p>
















































113
2/21/2020 12:00:00 AM
29.01.2023
15/12-6 S


<p>Block 15/12 is situated between the Jæren
High to the south, Central Graben to the south-southwest, Andrew Ridge to the
west, Ling Graben to the north and Viking Graben to the north-northwest. Well
15/12-6 S was the third well within the license area. It was drilled ca 3 km
north of the 15/12-4 Varg Discovery well, which found 1.5 oil column in
Jurassic sandstone. The main objective of 15/12-6 S was to test the hydrocarbon
potential in Oxfordian sandstone in the north-western segment of the Beta west
structure. Secondary objectives were Palaeocene sandstones (Maureen formation)
and Triassic sandstones. Due to possible shallow gas problems, the well was
moved 100 south to avoid this problem.</p>

<p><b>Operations and results</b></p>

<p>Well 15/12-6 S was spudded 19 August 1990
with the semi-submersible rig Deepsea Bergen and drilled to 3050 m in the
Triassic Skagerrak Formation. While drilling the 12 1/4&quot; hole the penetration
stopped at 2560 m. The BHA was pulled out and it was found that the MWD tool had
been twisted off. The hole was cemented back and sidetracked from 2495 m with
increased mud weight. Ran 7&quot; liner to 3046 m, and cemented inside the
liner to 2960 m. No shallow gas was encountered. The well was drilled with
bentonite spud mud and CMC/seawater down to 615 m, with gypsum/polymer mud from
615 m to 2757 m, and with gel/lignosulphonate mud from 2757 m to TD.</p>

<p>Logs and shows indicated presence of
hydrocarbons in the interval from 2428 to 2473 m in the late Cretaceous chalk
but tests were not performed here due to tight formation. The Late Jurassic
Oxfordian sandstone (Hugin Formation) came in at 2871 m, 80.5 m deeper than
prognosed. It contained oil and from logs the OWC was found to be at 2943 m.
There were no shows or other hydrocarbon indications below this depth.</p>

<p>A total of seven cores were cut, six in
the interval 2838 to 2966 m and the seventh from 2980 to 2988.5 m. An FMT run
in Oxfordian sandstone gave 12 pressure readings out of 27 attempts. One sample
was taken at 2935.5 m. The sample contained a mixture of mud filtrate and
formation water with traces of hydrocarbons.</p>

<p>The well was suspended on 4 November 1990
as an oil appraisal well, and was converted to development well (15/12-A-2).</p>

<p><b>Testing</b></p>

<p>Two DST tests were performed in this
well:</p>

<p>DST 1 from 2922 - 2930 m produced 153.8
Sm3/d oil and 11.683 Sm3/d gas through a 12.7 mm choke. The GOR was 76 Sm3/Sm3.
A breakthrough, possibly through a fault, occurred at the end of the cleanup
flow in this test, and this totally changed well productivity and also altered
the flowing temperature. Before the breakthrough the temperature was 127 deg C
and still increasing. After breakthrough the temperature sunk to 123 deg C.</p>

<p>DST 2 from 2875 - 2895 m produced 866 Sm3/d
oil and 52530 Sm3/d gas through a 15.9 mm choke. The GOR was 61 Sm3/Sm3, the
oil density was 0.843 g/cm3 and the gas gravity was 0.740 (air = 1). The
reservoir temperature was measured to 127.5 deg C.</p>



1524
7/6/2016 12:00:00 AM
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15/12-7 S

<p><b>General</b></p>

<p>Well 15/12-7 S was designed to drill in
Late Jurassic Oxfordian sandstones on the Theta North prospect in the
southeastern part of the PL 116 licence area. The structure is a rotated fault
block dipping southeast and bound to the west and north by faults. Based on
mapping and inversion studies of the 15/12-5 well and the Beta-east structure
it was likely that an Oxfordian sequence was present at the Theta structure.
However, it could not be excluded that the Oxfordian reservoir had been eroded
from top of the structure. The main objective of well 15/12-7 S was to test the
potential for hydrocarbons in the Oxfordian sandstones. A secondary objective
was to test possible Triassic sandstones. Seismic anomalies at 441 m and 792 m
strongly suggested shallow gas. Because of this the spud location was set
outside of the planned location.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/12-7 S was spudded with
the semi-submersible installation Deepsea Bergen on 6 November 1990 and drilled
to TD at 3529 m in the Triassic Smith Bank Formation. Problems
were encountered in building and dropping angle in deviated well section (13
3/8&quot; to 9 5/8&quot;). Pipe stuck at 2703 m and 2720m but came free. Stuck
again with FMT-tool at 3425m. The tool was left in the hole. The well was drilled with seawater and bentonite pills down to 173
m, with seawater and CMC EHV from 173 m to 620 m, with gypsum/PAC from 620 m to
3027 m, and with gel/polymer/lignosulphonate from 3027 m to TD. No shallow gas
was encountered at 441 m, but from MWD gas was encountered at 775 m. Several
misruns while logging were experienced. </p>

<p>The Oxfordian reservoir sandstone (Intra
Heather Sandstone) came in at 3025 m, 25.5 m shallower than prognosed. No
hydrocarbons were encountered. One 27 m conventional core was cut from 3028 m
to 3055 m in the reservoir unit with 94.4 % recovery. A total of 100 sidewall
cores were attempted of which 93 were recovered. No sidewall cores were
attempted in the 17 1/2&quot; section (620 m to 1820 m) due to hole problems.
No fluid samples were taken in the well.</p>

<p>The well was permanently abandoned on 7
January 1991 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



1680
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15/12-8
<p><b>General</b></p>

<p>Wildcat well 15/12-8 was drilled ca 3.5
km east of the 15/12-4 well, which made the Varg oil discovery in Jurassic and
Triassic sandstones. The main objective of the well was to test the potential
for hydrocarbons in sandstones of Oxfordian and Triassic age. Seismic anomalies
at 437, 467, 479 and 803 m indicated possibility for shallow gas. Planned TD
for the well was 3260 m.</p>

<p><b>Operations and results</b></p>

<p>Well 15/12-8 was spudded with the
semi-submersible installation Deepsea Bergen on 5 June 1991 and drilled to TD at 3054 m in the Triassic Skagerrak Formation. No significant problems occurred
during operations. The well was drilled with seawater / hi-vis pills / CMC down
to 615 m, with KCl/polymer mud from 615 m to 2855 m, and with Ancotemp/bentonite
mud from 2855 m to TD. No shallow gas was encountered.</p>

<p>Jurassic Vestland Group sandstone was
encountered hydrocarbon-bearing at 2838 m. The hydrocarbon column extended 23 m
into Triassic sandstone of the Skagerrak Formation. The gas/water contact was
estimated to 2877 m, confirmed by FMT pressure gradients and wire line logs. The
well was tested, and since no core was cut through the reservoir, the well was
sidetracked at 2623 m with TD at 2940 m. The sidetrack was drilled with
Ancotemp/bentonite mud. Three conventional cores were cut in the interval 2841
- 2902 m. The sidetrack was formally named 15/12-8 A.</p>

<p>The FMT tool was run in well 15/12-8 and
15/12-8A. One segregated sample was taken at 2863 m in 15/12-8 (gas, condensate
and mud filtrate) and another in the water zone at 2888 m in well 15/12-8 A (recovered
mud only due to seal failure). </p>

<p>Well 15/12-8 was permanently abandoned on
14 July 1991 as a gas/condensate discovery. The 15/12-8 A sidetrack was
permanently abandoned on 29 July as a gas/condensate appraisal well.</p>

<p><b>Testing</b></p>

<p>One DST test was performed in 15/12-8 in
the interval 2838 - 2869 m. The well produced gas-condensate with a dew point
of 230 bar at the measured reservoir temperature, which was 123 deg C. The rates
were 550 000 Sm3 gas and 420 Sm3 condensate /day through a 15.9 mm choke. The
condensate/gas ratio was 1308 Sm3/Sm3, the condensate gravity was 61 deg API,
and the gas gravity was 0.817 (air = 1).</p>

1778
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15/12-8 A
<p><b>General</b></p>

<p>Wildcat well 15/12-8 was drilled ca 3.5
km east of the 15/12-4 well, which made the Varg oil discovery in Jurassic and
Triassic sandstones. The main objective of the well was to test the potential
for hydrocarbons in sandstones of Oxfordian and Triassic age. Seismic anomalies
at 437, 467, 479 and 803 m indicated possibility for shallow gas. Planned TD
for the well was 3260 m.</p>

<p><b>Operations and results</b></p>

<p>Well 15/12-8 was spudded with the
semi-submersible installation Deepsea Bergen on 5 June 1991 and drilled to TD at 3054 m in the Triassic Skagerrak Formation. No significant problems occurred
during operations. The well was drilled with seawater / hi-vis pills / CMC down
to 615 m, with KCl/polymer mud from 615 m to 2855 m, and with Ancotemp/bentonite
mud from 2855 m to TD. No shallow gas was encountered.</p>

<p>Jurassic Vestland Group sandstone was
encountered hydrocarbon-bearing at 2838 m. The hydrocarbon column extended 23 m
into Triassic sandstone of the Skagerrak Formation. The gas/water contact was
estimated to 2877 m, confirmed by FMT pressure gradients and wire line logs. The
well was tested, and since no core was cut through the reservoir, the well was
sidetracked at 2623 m with TD at 2940 m. The sidetrack was drilled with
Ancotemp/bentonite mud. Three conventional cores were cut in the interval 2841
- 2902 m. The sidetrack was formally named 15/12-8 A.</p>

<p>The FMT tool was run in well 15/12-8 and
15/12-8A. One segregated sample was taken at 2863 m in 15/12-8 (gas, condensate
and mud filtrate) and another in the water zone at 2888 m in well 15/12-8 A (recovered
mud only due to seal failure). </p>

<p>Well 15/12-8 was permanently abandoned on
14 July 1991 as a gas/condensate discovery. The 15/12-8 A sidetrack was
permanently abandoned on 29 July as a gas/condensate appraisal well.</p>

<p><b>Testing</b></p>

<p>One DST test was performed in 15/12-8 in
the interval 2838 - 2869 m. The well produced gas-condensate with a dew point
of 230 bar at the measured reservoir temperature, which was 123 deg C. The rates
were 550 000 Sm3 gas and 420 Sm3 condensate /day through a 15.9 mm choke. The
condensate/gas ratio was 1308 Sm3/Sm3, the condensate gravity was 61 deg API,
and the gas gravity was 0.817 (air = 1).</p>


1835
7/6/2016 12:00:00 AM
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15/12-9 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/12-9 S was drilled on the Varg
Field in the North Sea. The Varg Field reservoir is in Upper Jurassic sandstones
at a depth of approximately 2700 metres. The Varg Field is segmented and
includes several isolated compartments with varying reservoir properties. The
well was drilled from a location near to the Varg A and Petrojarl A production
installations and targeted a southern compartment in the Varg structure. The
objective for the well was to prove hydrocarbons in Late Oxfordian sandstone
and to reduce the uncertainty in the reserve estimate for this part of the Varg
Field.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/12-9 S was spudded with
the semi-submersible installation Deepsea Bergen on 17 July 1992 and drilled to
TD at 3848 m (3213 m TVD) in the Triassic Skagerrak Formation. The well was
drilled deviated from 623 m with a sail angle of ca 56 ° and then vertical
again from ca 2400 m TVD through the target reservoir to TD. The well was
drilled with seawater down to 620 m, with KCl/polymer mud from 620 mto 3226 m,
and with Ancotemp/bentonite mud from 3226 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated top reservoir, the
Oxfordian sandstones, at 3385 m (2750 m TVD). The reservoir was oil-bearing
down to a well-defined OWC at 3501.5 m (2867.0 m TVD). Seven cores were cut with 100% recovery. Core 1
to 6 were cut in the interval 3689 m to 3555 m and core 7 was cut from 3649.5 m
to 3668.0 m. The core to log depth shift was -2.45 m for core 7; for the other
cores the core depth was equal to the logger’s depth. Two segregated FMT oil samples were taken at 3498 m. Oil shows continued down to 3545m
</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well is classified an oil appraisal
well. It was suspended on 8 October 1992 and was later re-classified to oil
production well 15/12-A-11 on the Varg Field.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed in
the Oxfordian sandstones.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the water zone from 3545 m
to 3552 m (2910 – 2917 m). The test produced water at a rate of 890 m3/day
through a 48/64” choke. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the oil zone from 3385 m to
3443 m (2750 – 2809 m). The test produced on average 132200 Sm3 gas and 1520
Sm3 oil /day through a 40/64” choke. The GOR was 87 Sm3/Sm3, the oil density
was 0.852 g/cm3 and the gas gravity was 0.751 (air = 1) with 1.5% CO2 and 4%
H2S. Maximum flowing temperature was 124.6 °C. </span></p>



1978
4/25/2019 12:00:00 AM
29.01.2023
15/2-1


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/2-1 was drilled in the Vilje
sub-basin in the Viking Graben in the North Sea, ca 1.5 km from the UK border.</span><span lang=EN-GB>The objective of the well 15/2-1 was to
test the Upper Jurassic, Middle Jurassic, and Triassic sandstone reservoirs
northwest of and down dip of the salt diapir encountered in the well 15/5-3. The
well was planned to be drilled ca 200 m into the Triassic with a total depth of
ca 4525 m.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/2-1 was spudded with the
semi-submersible installation Nortrym on 26 September 1981 and drilled to TD at
4600 m in the Late Permian Zechstein Group. No significant problems were
encountered in the operations. The well was drilled with seawater and hi-vis
pills down to 665 m and with Shaletrol polymer mud system from 665 m to 2750 m.
At 2750 m the mud was converted to a dispersed mud system by adding
lignosulphonate and this was used for the remaining well bore down to TD. There
was 0 - 3% oil in the mud below 1168 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated a number of sandstone
Formations in the Tertiary (Skade, Grid, Intra Balder sandstone, Heimdal, and
Ty Formations). All these were entirely water wet. The Hugin Formation (4356 - 4493
m) consisted of massive very fine grained sandstones with beds of coal on top. The
Sleipner Formation (4493 - 4554.5 m) had a 10 m thick coal layer on top
underlain by siltstones grading occasionally to very fine sandstones, interbeds
of sandstones, and stringers of coal. The well did not penetrate any Early
Jurassic or Triassic rocks, but encountered evaporites of Permian age at 4554.5
m, unconformably underlying the Sleipner Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Good hydrocarbon shows were reported from
both the Hugin and Sleipner Formations. However, wire line log evaluation and
core analysis showed very poor reservoir parameters and no moveable
hydrocarbons. Fluorescence and cut were observed also on limestone and shale
cuttings in the Tor Formation at 2800 - 2835 and in the Early Cretaceous at
3815 - 3922 m</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 4365 to 4405 m
in the Hugin Formation. The RFT tool was run in the Hugin Formation. The
formation proved to be tight and no wire line fluid samples were taken. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24
February 1982 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


308
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29.01.2023
15/3-1 S
<htm

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-1 S was drilled west of the
Gudrun Terrace on the east flank of the North Sea Central Graben. The primary
objective was to test sands in the Middle Jurassic (Dogger sands). Secondary objectives
were the Early Tertiary, Danian, Early Cretaceous sands. Triassic sandstones
and Zechstein dolomites down to the &quot;economic basement&quot; were also
possible targets. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well is reference well for the Ty,
Draupne, and Heather formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-1 S was spudded with
the semi-submersible installation Deepsea Driller on 27 November 1974 and
drilled without significant problems to 4400 m. While circulating before
logging the pipe stuck and the hole started to kick. After unsuccessful efforts
to free the pipe the well was plugged back and sidetracked from 3985 m. The
sidetrack was drilled without further significant problems to final TD at 5129
m in the Middle Jurassic Hugin Formation.  </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated water-bearing Hermod,
Heimdal and Ty formation sandstones from 2215 to 2715 m. The Ty Formation from
2556 m was reported as the best of these with a main body of clean sand from
2599 to 2711 m. Top Viking Group, Draupne Formation was encountered at 3947 m.
The Draupne Formation contained many oil and gas bearing Intra-Draupne
Formation sandstones. Of these the best reservoirs were found in the intervals
4083 to 4317 m with OWC at 4218 m, and 4442.5 to 4610 m with OWC at 4486 m.
Total net pay in these two intervals together were 32 m with 22 - 19 %
porosity. Geochemical analyses indicated good source rock properties in the
shale interbeds, with a maturity ranging from early to late oil window
(vitrinite reflectance from 0.6 to 0.9 %Ro). Top Heather Formation was encountered
at 4754 m. The Heather Formation had no sandstone interbeds. Top Hugin
Formation came in at 4986 m with a 10 m net pay gas bearing sandstone reservoir
at 4986 to 5001 m. Porosity here was 12.5%. Sandstones with hydrocarbons were
penetrated below this level, but these had low permeability. No oil shows were
reported above the Viking Group.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the well; the
three first before and the fourth after sidetracking. Core 1 was cut from 3947
to 3951 m, core 2 was cut from 4083 to 4092, core 3 was cut from 4141 to 4150
m, and core 4 was cut from 4991 to 4993.3 m. FIT wire line fluid samples were
taken at 4217 m (oil and gas), 4148.8 m (oil and gas), 4089.3 m (gas), 4168.5 m
(oil and gas), 4243.5 m (water and trace filtrate), 4443.5 m (oil and gas), and
at 4479.5 m (water and filtrate)</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6
July 1975 as a gas/condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



309
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15/3-10
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-10 was drilled as an appraisal
well on the 15/3-4 Sigrun discovery on the Gudrun Terrace in the North Sea. The
target formation was located to the west and down dip of the original discovery
well 15/3-4. The main objective was to prove more resources than already proven
in the Middle Jurassic Hugin Formation in the 15/3-4 discovery well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A 9 7/8” pilot hole (15/3-U-8) was drilled
to check for shallow gas. No shallow gas was observed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-10 was spudded with
the semi-submersible installation Deepsea Bergen on 5 June 2018. The well was
drilled to 990 m but due to failed cement operation of the surface casing, the
well was abandoned. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well did not fulfil the objectives.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
June 2018 as a junk well. Replacement well 15/3-11 was initiated.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


8442
6/13/2020 12:00:00 AM
29.01.2023
15/3-11
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-11 is the replacement well for
15/3-10, which was junked for technical reasons. It was drilled to appraise the
15/3-4 Sigrun discovery on the Gudrun Terrace in the North Sea. The target formation
was located to the west and down dip of the original discovery well 15/3-4. The
main objective was to prove more resources than already proven in the Middle
Jurassic Hugin Formation in the 15/3-4 discovery well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-11 was spudded with
the semi-submersible installation Deepsea Bergen on 14 June 2018 and drilled to
TD at 4014 m in the Middle Jurassic Sleipner Formation. Operations proceeded
without significant problems. The well was drilled with seawater and hi-vis
pills down to 1000 m, with KCl/polymer/GEM mud from 1000 m to 2350 m, with
Enviromul oil-based mud from 2350 m to 3660 m, and with BaraECD oil-based mud
from 3660 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The target Hugin formation was penetrated
from 3856 to 3959 m. The reservoir consisted of interbedded sandstones and
claystone with a few thin coal layers. It was oil filled in the upper sands,
whereas the deeper sands were water-bearing. The fluids are the same volatile
oils as were encountered in 15/3-4. Like the previously drilled wells, 15/3-4
and 15/3-5, did the 15/3-11 well encounter oil-down-to (ODT) situations. <a
name="OLE_LINK1">Pressure data show a complex reservoir with two different oil
gradients</a> and three different water gradients. In the well site cuttings
descriptions shows are described in the Draupne Formation from 3744 to 3798 m
(direct and cut fluorescence but no visible oil stain). In the core description
oil shows are described in the Hugin reservoir sandstones down to 3930 (typically
direct and cut fluorescence with visible stain), and with weaker shows in a few
samples around a coal layer at 3959 m. No other zones with shows are reported.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in succession from3868
to 3975 m with 99.3% and 94% recovery, respectively. MDT fluid samples were
taken at 3857.7 m (oil), 3888.46 m (oil) and 3927.5 m (water). The oil samples
proved undersaturated volatile oil with small variations in GOR.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9
August 2018 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


8489
8/9/2020 12:00:00 AM
29.01.2023
15/3-12 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-12 A is a geological side-track
to well 15/3-12 S, which discovered oil in the Sigrun East Hugin prospect on
the Gudrun Terrace in the North Sea. Side-track 15/3-12 A was drilled to the
Sigrun East Draupne prospect located west of the primary well and south of the
Sigrun Field. The primary objective of 15/3-12 A was to verify down-flank continuation
of the Hugin Formation reservoir and find the related hydrocarbon contacts. The
secondary objective was to verify presence of Intra-Draupne Formation reservoir
and hydrocarbons in same.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-12 A was kicked off on 19
January 2020 from the main well at 2100 m in Lower Hordaland Group. It was
drilled with the semi-submersible installation West Phoenix to 3593 m (3428 m
TVD) in the Cromer Knoll Group. While POOH with 12 ¼” drilling BHA, the drill
string got stuck at 2756 m in Ty sand. The BHA could not be freed and a technical
side-track 15/3-12 A T2 was initiated with kick-off at 2215 m. Large amounts of
caved cuttings was produced during kick-off. Drilling proceeded to final TD at
4038 m (3834 m TVD) in the Middle Jurassic Sleipner Formation. Both 15/3-12 A
and 15/3-12 A T2 were drilled using Exploradrill oil-based mud from kick-off to
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin reservoir was water filled and
only cemented sand stringers were penetrated in the Draupne Formation. No oil
shows were described in the well. Combined pressure data from the 15/12-3 S and
15/12-3 A T2 well indicated the following hydrocarbon contacts in the Hugin
Formation: Free Water Level at 3614.6 m TVD in the upper reservoir unit, OWC at
3570 m TVD in the middle unit, and Free Water Level at 3605.4 m TVD in the
lower unit. The contacts are based on pressure data and oil sample densities
and are not penetrated by the wellbores.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were
taken at 3898 m in the Hugin Formation in the 15/3-12 A T2 side-track</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2
March 2020 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>
8948
10/20/2022 12:00:00 AM
29.01.2023
15/3-12 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-12 S was drilled to test the Sigrun
East Hugin prospect on the Gudrun Terrace in the North Sea. The primary and
secondary exploration targets for wildcat well 15/3-12 S were to prove
petroleum in Middle Jurassic Hugin Formation reservoir rocks.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-12 S was spudded with
the semi-submersible installation West Phoenix on 3 December 2019 and drilled
to TD at 3810 m (3691 m TVD) m in the Middle Jurassic Sleipner Formation. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 1010 m, with Glydril mud from 1010 m to 2374 m, and with Exploradrill
oil-based mud from 2374 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well encountered three separate
oil-filled reservoir zones from 3647 to 3660 m, 3680 to 3683 m, and 3703 to
3733 m  in the Hugin Formation. The three zones lie on different pressure gradients.
The reservoir zones mainly have moderate reservoir quality. The oil/water
contacts were not penetrated in the well. Oil shows in the well were observed
only in the Hugin Formation between 3652 to 3729 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut with 100% recovery in
the Hugin and Sleipner formations. Core 1 was cut from 3652 to 3706 m and core
2 was cut from 3706 to 3760 m. The core-log depth shifts are 1.9 m for core 1
and 1.7 m for core 2. MDT fluid samples were taken at 3647.5 m (oil), 3681.1 m
(oil), 3698 m (water), and 3704.2 m (oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
January 2020 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>
8947
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15/3-2


<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was drilled in the Vilje
sub-basin structural element of the south Viking Graben of the North Sea. The
objectives of well 15/3-2 were all Jurassic sands. The well was planned in two
phases. Phase 1 (15/3-2) was to be drilled with the Polyglomar Driller down to
top Jurassic. Phase 2 (15/3-2 R) was to be drilled with the Pentagone 84, a rig
with a 15.000 psi wellhead equipment, necessary for testing of the high-pressure
Jurassic reservoirs.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was spudded with the
semi-submersible installation Polyglomar Driller on 29 October 1976 and drilled
to TD at 4258 m in the Late Jurassic Draupne Formation. When pulling out of the
hole to set the 9 5/8&quot; casing the drill string parted at 138 m, but was
fished out. Otherwise, no significant technical problem occurred in the
operations. The well was drilled with seawater and hi-vis pills down to 186 m,
with prehydrated bentonite in fresh water from 186 m to 784 m, with LFC/Dextrid
mud from 784 m to 2875 m, and with LFC+LC in seawater from 2875 m to TD. Up to
3% oil was added to the mud from 3953 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Down to 4236 m (Tertiary and Cretaceous
sections) no significant shows were observed except in Coniacian and Turonian
limestones where some brown-yellow fluorescence was observed. Electric log
analysis did not indicate any hydrocarbon-bearing reservoirs in these
limestones. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line pressure
points or fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A 9 5/8&quot; casing was set at 4248 m
and the well was suspended on 24 January 1977 for later re-entry and drilling
and testing of the Jurassic targets. The well is classified as dry.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



310
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15/3-2 R


<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 R is a re-entry of well
15/3-2 in the Vilje sub-basin structural element of the south Viking Graben of
the North Sea. The primary well 15/3-2 was drilled by &quot;Polyglomar
Driller&quot;, which was equipped with 10.000 psi WP 18 3/4&quot; BOP-stack.
This well was suspended on 24 January 1977 with 9 5/8&quot; casing set at 4248
m, in the Late Jurassic Draupne Formation. The re-entry was drilled with the
Pentagone 84, equipped with a 15000 psi WPI 11&quot; BOP stack, necessary to drill
and test high-pressure Jurassic reservoirs. The objective of well 15/3-2 R was
to test the Jurassic reservoirs, including the Dogger - Lias sections.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-2 was re-entered with the
semi-submersible installation Pentagone 84 on 26 July 1977 after some initial
problem with connecting to the wellhead on the sea floor. An 8 11/32&quot; hole
was drilled down to 4990 m when the drill string parted. In spite of an
extensive fishing operation, the fish had to be left in hole. Top fish is at
4742 m. A sidetracking operation was performed trying to bypass the fish, but
also this operation failed and 4990 became TD of the well. The well was drilled
water based with LFC-LC mud from re-entry point to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Draupne Formation extended from 4236
m down to 4352 m, making up a total of 116 m. Geochemical analyses proved TOC
from 3 to 7 %wt and vitrinite reflectance analyses indicated middle oil window
maturity (%Ro = 0.75). Four Intra Heather Formation sandstone reservoirs were
drilled in the Jurassic section, varying in gross thickness from 15 to 112 m. According
to logs the two upper ones, 112 and 64 m thick, were hydrocarbon-bearing, but
with bad characteristics (porosity destruction by silicification) and no tests
were successful. Shows during drilling were recorded throughout the Jurassic: low
levels of C1 to C4 gas in mud, and fluorescence (direct and cut) on cuttings
and cores. Gas was observed bubbling and seeping from all the cores. Because of
the premature stop the Brent to Statfjord (Dogger to Early Jurassic)
sedimentary section was not reached. As no electric logs were run below 4742 m
the lithostratigraphy is poorly defined in the bottom part of the well. However,
it is likely that TD was set in Heather Formation shale, and it is possible
that the Dogger section (Brent Group) is very close to the TD (J4 horizon was
prognosed at 5000/5100 m).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the intra Heather
Formation Sandstones: cores 1 and 2 from 4404 to 4409 m, core 3 from 4565 to
4574 m, and core 4 from 4656 to 4662 m. 26 RFTs were attempted in the three
upper sandstone bodies. All were either dry or they failed. Only two RFTs, at
4401 and 4401.4 m, were stabilized and indicated an equivalent density of 1.73.
The well was permanently abandoned on 27 November 1977 as a well with strong
shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>A 7&quot; liner was set from 4101 m to
4665 m. Three DST-runs were carried out, all misruns due to mechanical failure
of the PCT-tool.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



311
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15/3-3


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-3 was drilled west of the
Gudrun Terrace on the east flank of the North Sea Central Graben, about 4.5 km north-east
of the 15/3-1 S discovery. The main objective of the 15/3-3 well was to appraise
the complete Jurassic series up-dip of well 15/3-1 S drilled on the same
structure in 1975. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-3 is type well for the Grid
Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-3 was spudded with
the semi-submersible installation Pentagone 84 on 5 January 1979 and drilled to
TD at 5115 m in the Triassic Skagerrak Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Several water bearing sands with high
porosity were encountered in the Tertiary section including the Grid, Heimdal
and Ty formations. The Cretaceous had no reservoir sections and was drilled
without gas shows. The Late Jurassic Draupne Formation was encountered at 4017
m. The Draupne Formation was 208 m thick and consisted of shales with only a
few &lt; 1 m sandstone beds. The Heather Formation was penetrated from 4225 to
4522 m and contained a main Intra Heather Formation sandstone from 4260 to 4369
m. This sandstone was gas and condensate bearing in the upper part down to a
GOC at 4272 m. The Hugin Formation came in at 4522 m and then the Sleipner
Formation at 4545 m. The Hugin Formation contained gas filled sandstone from
4522 to 4527 m. Several thinner sandstones with gas followed down to a main gas
filled sandstone in the Sleipner Formation from 4588 to 4632 m. A second hydrocarbon
filled Sleipner Formation sandy interval was penetrated from 4679 to 4693 m.
The upper part down to 4687 m consisted of good sandstone, further down it was
cemented.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The only oil shows in the well was rare
pale yellow to greenish crush cut fluorescence on cuttings around 4100 m and on
white - yellowish fluorescence on all cores.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Six conventional cores were cut in the
Jurassic section all with full recovery. The three first were cut in the
Heather Formation from 4262 to 4307 m (4264 to 4309.9 m logger's depth). The
three last were cut in the Sleipner Formation (cored depth = loggers depth):
Core 4 from 4547 to 4562 m; core 5 from 4851 to 4860 m; and core 6 from 4995 to
5004 m. Three RFT fluid samples were taken at 4262 m (gas and condensate),
4262.5 m (mud and traces of condensate), and 4261.5 m (condensate). Four FIT
samples were taken at 5059.5 m (water), 4989.5 m (mud filtrate), 4626.5 m (gas
and mud), and 4262 m (oil and gas).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9
August 1979 as a gas/condensate appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two DSTs were performed through
perforations in the 7&quot; liner.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested 4967 - 4990 m with packer at
4957 m. It produced 4.3 m3 of salt water (125 g/1) with traces of gas in 11
hours.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested 4615 - 4632 m with packer at
4600 m. It produced 520000 m3 gas, 60 m3 41.5 deg API paraffinic condensate and
2.2 m3 water /day in 24 hours. The GOR was ca 8600 Sm3/Sm3.</span></p>


313
4/11/2017 12:00:00 AM
29.01.2023
15/3-4
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-4 was drilled on the Gudrun
Terrace, east of the 15/3-1 S Gudrun Discovery in the North Sea. The main objective
of the well was to test sandstones of the Late and Middle Jurassic, which were
found to contain gas and condensate in wells 15/3-1 S and 15/3-3. The secondary
target was the Eocene sands where oil shows were encountered in well 15/5-3. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-4 was spudded with the
semi-submersible installation Borgsten Dolphin on 3 October 1981and drilled to
TD at 4259 m in the Triassic Skagerrak Formation. After the 13 3/8&quot; casing
had been cemented drilling was interrupted for 13 days due to a combination of
bad weather and repairs on the BOP stack. When running in hole at TD the drill string
stuck leaving a fish with top at 4098 m. Hence, no logs were run between 4098 m
and TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Eocene sands from 1628 to 2025 m
(Grid Formation sands) were found water bearing. The Brent Group was
encountered with top Hugin Formation at 3786 m and top Sleipner Formation at
3856 m. Sandstones in the Brent Group contained oil and gas in four different intervals:
3786 to 3817 m, 3819.5 to 3826.5 m, 3849.9 to 3854.8 m, and 3872.2 to 3876.4 m.
The four zones were in different pressure regimes. The interval from 3819.5 to
3826.5 m had a low hydrocarbon saturation based on the logs, but the cores from
this section had good shows with a similar bulk hydrocarbon composition as in
the uppermost interval. Triassic sands below 4050 m were found water bearing. Good
oil shows were seen on all cores from the Hugin Formation, otherwise no shows
were reported from the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut in the well. Core 1
was cut in the Grid Formation from 1678 to 1694 m with 27% recovery. Coring of the
Grid sands was difficult due to their unconsolidated nature. Cores 2 - 5 were
cut in the interval 3792 to 3839 m in the Hugin Formation with recovery from
65% to 100%. RFT fluid samples were taken at 3802.5 m (water, mud and
filtrate), 3823.5 m (water, mud and filtrate), and 3850.2 m (gas and water).
FIT fluid samples were taken at 3822.5 m (water and dissolved gas), 3852.6 m
(oil, gas and water), and 3873.5 m (oil, gas and water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30
March 1982 as an oil and gas discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One DST was performed through
perforations in the interval 3789 to 3807.5 m. The test produced 615 Sm3 oil
and 245000 Sm3 Gas/day through a 40/64&quot; choke. The GOR was 400 Sm3/Sm3,
the oil density was 0.816 g/cm3, and the gas gravity was 0.803 (air = 1). The
gas contained 7.4 % CO2. Bottom hole temperature during the DST, at reference
depth 3800 m, was 127.8 deg C. </span></p>


























































314
12/6/2019 12:00:00 AM
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15/3-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-5 was drilled on the Gudrun
Terrace, east of the 15/3-1 S Gudrun Discovery in the North Sea. Well 15/3-5
was drilled in a downdip position of a structure explored by the well 15/3-4,
where oil bearing reservoirs of Middle Jurassic age were tested. The main
objectives of 15/3-5 were to find the extension of these reservoirs and to
define a hydrocarbon/water contact. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-5 was spudded with
the semi-submersible installation Byford Dolphin on 28 December 1983 and
drilled to TD at 4130 m in the Middle Jurassic Sleipner Formation. Drilling was
suspended at 195 m due to bad weather. The well was re-spudded on 6 January 25
m west of the original location. Some technical problems with the BOP occurred
after setting of the 20&quot; and 13 3/8&quot; casings. A seat protector got
stuck in the riser during drilling of the 17 1/2&quot; hole. Drilling breaks
occurred at 3943 m, 3954 m, 4018 m, 4032 m and at 4041 4043 m in the 8 1/2&quot;
hole section. The well was drilled using water based mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation was encountered at
3808 m, followed by the Heather Formation at 3881 m, and the target Middle
Jurassic Sleipner Formation at 3935 m. Several thin reservoir zones were
penetrated in the Sleipner Formation. The sands were interpreted as minor
fluvial channels (2 to 5m in thickness) deposited in two main sequences. Four
of the channels were oil-bearing with an oil gradient of 0.61 bar/10 m based on
pressure measurements. An OWC could be established at 4022.6 m. Pressure
measurements showed that the upper fluvial channel sequence is over-pressured,
and not in contact with the sands encountered in well 15/3-4. The lower fluvial
sequence could be connected between the two wells. Petrophysical evaluation of
the whole system gave a net pay of 6.7 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>In the Quaternary, Tertiary and
Cretaceous series no fluorescence due to hydrocarbons were observed. In the
Upper Jurassic sequence, a weak yellow colour in direct fluorescence light was
observed on sandstone pieces. A pale to clear yellow and orange colour in
direct fluorescence light was reported from the Middle Jurassic sequence down
to about 4060m. Below 4060 m to TD nil to very weak direct fluorescence was
observed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the Sleipner
Formation. Cores 1 and 2 were cut from 3971 to 4003 m (3973.6 to 4005.6 m
logger's depth) with 98 % and 84% recovery, respectively. Core 3 was cut from
4020 to 4029 m (4023.9 to 4032.9 m logger's depth) with 94% recovery. RFT wire
line fluid samples were taken at 3969.9 m (gas + mud filtrate), 3984 m (gas +
mud filtrate), 4022.2 m (minor gas + mud filtrate), and 4028.5 m (trace gas +
mud filtrate),</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
May 1984 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



52
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15/3-6

<p><b>General</b></p>

<p>Well 15/3-6 was drilled to test the
Paleocene Balder and Hermod sandstones of the Pinnsvin prospect, and had a
licence requirement to penetrate Cretaceous age formations. The well was
drilled within licence PL 187 (Amoco Norway, Statoil, Norsk Hydro). License PL
025 farmed into the well (Statoil, Elf, Total, Hydro) for 20% of well costs.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/3-6 was spudded 15.
December 1998 with the semi-submersible installation Mærsk Jutlander, and
drilled to TD at 2793 m in the Late Cretaceous Shetland Group. The well was
drilled with seawater and hi-vis pills down to 1018 m and oil based mud
(Versavert) from 944 m to TD.</p>

<p>The Intra Balder and Hermod sandstones
were encountered as prognosed but the well was found to be completely water wet
all through. A wire line fluid sample was taken at 2160 m in the Intra Balder
Formation Sandstone. Two cores were cut in the interval 2140 m to 2176 m in the
Balder Formation and Intra Balder Formation sandstones, and one was cut from 2278
m to 2297.7 m in the Hermod Formation Sandstone.</p>

<p>The well was plugged and abandoned as a
dry hole on 5 January 1999.</p>

<p><b>Testing </b></p>

<p>No drill stem test was performed</p>
3250
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15/3-7
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-7 was drilled to appraise the
Gudrun Discovery in the North Sea, on the east flank of the South Viking Graben
and west of the Utsira High. The main objective was to improve the data quality
related to formation pressure, fluid properties and other reservoir parameters
in the Hugin Formation in the Middle Jurassic. The secondary objectives were to
explore possible reservoir sands in the Late Jurassic and the hydrocarbon phase
of any proven hydrocarbons.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-7 was spudded with
the semi-submersible installation West Alpha on 26 April 2001and drilled to TD
at 4818 m, 211 meters into the Middle Jurassic Hugin Formation. The 8 1/2&quot;
hole was drilled in 21 bit runs, including 4 core runs. The main reason for all
the bit runs was junk in hole causing 18 days NPT. The well was drilled with
seawater and bentonite down to 945 m, with KCl/polymer/glycol from 945 m to
2740 m, and with oil based mud from 2740 m to TD. No shallow gas was observed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated several Tertiary
sandstone sequences including a 373 m thick Heimdal-Ty sequence. The Draupne
Formation was found to be 350 m thick and contained several intra-Draupne
sandstone sequences interbedded with claystone and limestone. The claystones
became darker and more organic rich with depth. A MDT sample from 4224 m in the
upper part of the Draupne Formation proved light oil. The upper part of the
Hugin Formation was found water bearing as confirmed by a water sample from the
Hugin 1 sandstone at 4610 m. No pressure gradients could be obtained from the
Hugin Formation. In the lower part of the Hugin Formation, no sample or
pressure data could be obtained. However, sandstones were gas filled based on
logs, with a likely GWC at 4787 m. Pressure gradients from the Draupne
Formation indicate no communication between the oil- and water-bearing zones. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four conventional cores were cut in the
interval 4609 m to 4670 m in the Hugin Formation, with a total of 46.4 m core
recovered.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on as
a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


















































4055
2/21/2020 12:00:00 AM
29.01.2023
15/3-8
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The Gudrun structure is situated on the
east flank of the South Viking Graben and west of the Utsira High in the North
Sea. Well 15/3-8 was drilled on the western flank of the structure,
approximately 9 km east of the UK border. New seismic data and results from
well 15/3-7 had revealed uncertainties regarding the Late Jurassic reservoir
section in the Gudrun structure. The main purpose of well 15/3-8 was to gather
the necessary information required to ascertain whether the Intra-Draupne
Formation reservoir rocks of the Gudrun Discovery could be developed
commercially. This included reservoir pressure data, petrophysical data
including taking cores, fluid sampling for fluid characteristics, and
production properties by drill stem testing.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/3-8 was spudded with
the semi-submersible installation Transocean Leader on 11 April 2006 and
drilled to TD at 4592 m in Late Jurassic Intra-Draupne Formation sandstone. No
significant technical problems were encountered in the operations and the well
was completed within planned time frame. The well was drilled with
seawater/bentonite/hi-vis pills down to 1010 m, with Glydril mud from 1010 m to
2765 m, and with Paratherm oil based mud (paraffin base) from 2765 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Viking Group was encountered at
3932.5 m and consisted of the interbedded lithologies of sandstone, claystone
and limestone, with varying thicknesses from laminas to stringers and massive
layers. The first 140 m was Draupne Formation claystone. The target reservoir
section, Intra Draupne Formation sands, was encountered at 4072.5 m, 38.9 m
deeper than expected. Three intra Draupne Formation sandstone units were
identified, SST1 from 4072.5 m to 4212.5 m, SST2 from 4212.5 m to 4346 m, and
SST3 from 4474.5 m to TD. The sand quality was significantly better than
observed in the neighbouring wells. When correlated with neighbouring wells
well 15/3-8 showed significant lateral reservoir variations over small
distances within the structure. SST1 contained a high-shrinkage volatile oil
down to a contact at 4208 m, the SST2 pressure gradient proved a water bearing
sandstone, although oil was sampled at 4332.9 m, while SST3 contained a near-critical
gas-condensate down to a contact at 4485.4 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Good shows were seen in the cores from
the reservoir section as they were recovered on deck. It was no possible to
give a reliable evaluation of the shows on cuttings during drilling due to
background fluorescence from the oil based mud. In addition, some of the most
marginal shows described from the cored section were hampered by the existence
of formation derived kerogens in the mud. Some of the cores were also bleeding
HC from very tight zones at surface and seepages from these zones might have
contaminated better sandstone sections below. From the general fluorescence
picture there seem to be a presence of heavier HC in the tight zones than in
the more porous zones. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 158 m core was recovered in 7
cores from the interval 4167 to 4505 m in various Intra-Draupne Formation
sandstone sections in the Late Jurassic. MDT fluid samples were taken at 4514.5
m (water), 4479.1 m (hydrocarbons), 4332.9 m (hydrocarbons), 4213.5 m (water),
4182.1 m (hydrocarbons), and at 4074 m (hydrocarbons). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11
April 2006 as an oil and gas appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two drill stem test was performed in
Intra-Draupne Formation sandstones. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 4141 - 4183 m.
The well was opened to flow for a total of 28 hours. The main flow duration was
14 hours with an approximate oil rate of 739 m3/day a gas rate of 346600 Sm3
gas/day and a GOR of 469 m3/m3 through a 32/64&quot; choke. This was followed
by a 96 hours build up period. Maximum bottom hole temperature recorded in the
test was 133 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 4073 - 4087 m.
The well was open to flow for a total of 26 hours. The main flow duration was
10 hours with an approximate oil rate of 650m3/day, a gas rate of 342400 Sm3
gas/day and a GOR of 500 m3/m3 through a 28/64&quot; choke. This was followed
by a 96 hours build up period. Maximum bottom hole temperature recorded in the
test was 130 deg C.</span></p>




































































































































































































5175
2/21/2020 12:00:00 AM
29.01.2023
15/3-9


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/3-9 was drilled on the Brynhild
prospect situated on the east flank of the south Viking Graben, west of the
Utsira High. The Brynhild Prospect was interpreted as the eastwards
continuation of the Gudrun Field. The main objective of the 15/3-9 well was to
prove economical hydrocarbon columns in the Late Jurassic SST1 and the Late
Jurassic SST2 of the Draupne Formation. The Hugin Formation was a secondary
objective.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/3-9 (Brynhild) was drilled
with the semi-submersible installation Transocean Leader. A pilot hole 15/3-U6
was drilled to 918 m. No shallow gas was observed by the ROV at the wellhead or
by the MWD while drilling the pilot hole. The main well was spudded 15 m off
the pilot-hole location on 19 May 2010 and drilled to the Ty Formation where
the pipe got stuc stuck. It was not possible to get it loose. A technical
sidetrack, 15/3-9 S T2 was decided. The sidetrack was kicked off from 2350 m
and the well was drilled to TD at 4654 m in the Middle Jurassic Sleipner
Formation without further significant problems. The well was drilled with
Seawater and SW/PAC sweeps down to 1001 m, with Performadril WBM from 1001 m to
2724 m (primary well and sidetrack), and with XP-07 OBM from 2724 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Late Jurassic Draupne Formation was
encountered at 3975 m with top Intra Draupne Formation SST1 sandstone at 4112
m. The SST1 was oil bearing down to an oil water contact was at 4132 m TVD. The
prognosed SST2 sandstone was encountered at 4226 m and was entirely water filled.
The Hugin Formation was encountered at 4475 m and contained both gas and oil,
each fluid type with its own down-to contact. The Draupne SST1 had a net to
gross ratio of 0.75, while the net to gross ratio in the Hugin Formation was 0.16.
Except for the petroleum bearing SST1 and Hugin reservoirs no oil shows were
reported from the well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in sidetrack 15/3-9 T2,
Core 1 in the Draupne SST1 (23 m), and Core 2 in the upper part of the Hugin
Formation (32.15 m). The cored section in the Draupne SST1 extends from 4124 to
4147 m MD, while the cored section in the Hugin Formation extends from 4482 to
4514.17 m MD. Core 1 and Core 2 are shifted against the log curves with +2.13 m
and +2.89 m, respectively. MDT fluid sampling was performed. Oil samples were
taken at 4115 m and 4128 m in the Intra Draupne Formation SST1 sandstone. In
the Hugin Formation a gas/condensate sample was taken at 4580.7 and an oil
samples was taken at 4510 m. MDT water samples were taken at 4182.5 m and at
4528.7 m in the Hugin Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
August 2010 as an oil and gas discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6354
4/11/2017 12:00:00 AM
29.01.2023
15/5-1


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-1 was drilled on the Ve
Sub-basin north of the Sleipner Vest Field in the North Sea. The main objective
of the well was to test sandstone reservoirs of Middle Jurassic age. In the
nearby Sleipner field (in block 15/6 and 15/9) gas had been found previously in
reservoirs of the same age. The well was located down flank on the structure at
the Kimmerian level. This position was chosen to penetrate reservoirs believed
to be wedging both above and below a strong seismic marker (&quot;Red
Marker&quot;).</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/5-1 was spudded with the
semi-submersible installation Treasure Seeker on 26 November 1977 and drilled
to TD at 3775 m in Late Triassic sediments belonging to the Hegre Group. This
was the first well drilled by Treasure Seeker, which was outfitted in
Stavanger. About 25% of total rig time was counted as lost time, mainly due to
wait-on-weather or equipment problems caused by rough weather in wintertime.
The well was drilled with seawater and gel down to 1225 m, with
seawater/gel/CMC/Spersene from 1225 m to 1910 m, and with a freshwater-based Spersene/gel/chrome-lignosulphonate/Drispac
mud from 1910 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The 15/5-1 well encountered gas
condensate-bearing sandstones of Late and Middle Jurassic age (Callovian and
Bathonian) from top at 3558 m down to 3614 m where a Bathonian/Bajocian deltaic
series with up to five m thick coal beds appeared. From wireline log evaluation
the sandstone section with a gross thickness of 56 m, has been subdivided into
four separate pay zones, each zone being separated by thin impermeable layers,
resulting in a net sand pay of 42.1 m. Average porosity was calculated to 14%
and the average water-saturation to 14%. Sands were water wet below the coal
beds at 3650 m. The actual oil-water contact was not seen. The strong seismic “Red
Marker was correlated to the top of the deltaic coaly sequence of Middle
Jurassic age. Oil shows were recorded on limestone in intervals from 2804 m to
2904 m (Tor Formation), from 3180 m to 3190 m (Hod Formation), and from 3365 m
to 3375 m (top of Rødby Formation). Below the hydrocarbon-bearing reservoir,
oil shows were recorded on sandstones in the intervals 3650 m to 3657 m and
3725 m to 3740 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 3561 m to 3601
m and two cores were cut from 3609 m to 3625.5 m. RFT samples were taken at
3560 m and 3611.8 m. They were found not to be representative of the formation
fluid. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
April 1977 as a condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two zones were production tested </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3610 m to 3614
m. The flow did not stabilise. On average, a production of 35720 Sm3 gas and
18.1 Sm3 oil /day through a 12/64” choke is reported. The GOR was ca 1970
Sm3/Sm3, the oil gravity was 43.0 °API and the gas gravity was 0.804 (air = 1).
The bottom hole temperature was 125.6 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3561 m to 3584
m. The test produced 660270 Sm3 gas and 474 Sm3 oil /day through a 48/64”
choke. The GOR was 1390 Sm3/Sm3, the oil gravity was 43.4 °API, and the gas gravity
was 0.778 (air = 1). The bottom hole temperature was 126.7 °C.</span></p>



315
7/6/2016 12:00:00 AM
29.01.2023
15/5-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 was drilled in the Ve Sub-basin
in the North Sea, north of the Sleipner Vest Field and 15/5-1 Gina Krog
Discovery. The main objective of the well was to test possible hydrocarbon
accumulations in Middle to Late Jurassic Bathonian/Callovian transgressive
sandstones and Middle Jurassic Bajocian deltaic sandstones. The well was
located in a purposely off-crestal position on an approximately 16 km2 large
structure some 7 km north-west of the 15/5-1 discovery.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was planned to penetrate into
the Triassic with a projected total depth of 4500 m. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/5-2 was spudded with the
semi-submersible installation Treasure Seeker on 16 August 1978 and drilled to
TD at 4322 m in the Triassic Hegre Group. At 1267 m, the string unscrewed in a
tight section, but it was fished without problems. After drilling to 2293 m,
the string stuck when pulling out of hole. This time the fish was not recovered
and a sidetrack was performed with kick-of at 1775 m. Heavy weather caused
further delays, otherwise the drilling went forth without significant problems
to TD. The well was drilled with seawater mud mixed with gel and Spersene down
to 454 m, and with a Spersene/XP-20 (lignosulphonate) mud from 454 m to TD. At
2232 m 1% Diesel was added to the mud. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two hydrocarbon bearing sandstone
intervals were penetrated by the well. In the Jurassic, only a thin Early to
Middle Bathonian sandstone development was penetrated between 4035 m and 4055 m.
Interbeds of siltstones and shales reduced the 20 m gross pay to a net pay of
7.3 m from wireline log interpretation. Average porosity and average water
saturation over the pay interval was calculated to 14.3 and 41.7% respectively.
The top of the Triassic sandstones was encountered at 4141.3 m and continued
with interbeds of varicoloured shales and siltstones to TD. From wireline log
evaluation hydrocarbon bearing sandstones were seen down to 4158.1 m. Below
this a tight cemented sandstone appears, masking the exact hydrocarbon - water
contact. Proven gross pay interval is thus 16.8 m while the net pay is 12.8 m.
Average porosity over this interval has been calculated to 14.6 % and the
average water saturation to 43 %.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Above top Jurassic weak oil shows were
observed on limestones at 2792 and 2828 m in the Tor Formation, between 3488 m
and 3517 m in the Lower Hod and Blodøks formations, and between 3707 m and 3723
m in the Rødby Formation. In the Jurassic oil shows were recorded on sandstones
from 4008 m to 4055 m. In the Triassic, no oil shows were seen despite the
hydrocarbon saturation (gas) in the sandstones shown by the logs.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Middle Jurassic
sequence. Core 1 was taken from 4013.6 m to 4020.6 m and recovered 5.1 m (72.8
%). The core was decided to be cut based on sandstone occurrence in the ditch
cuttings, but only shale and coal beds were found in the core. Core 2 was cut
from 4032.5 m to 4043.0 m and recovered 9.8 m (93.3 %). The core to log depth
shift is ca +4.5 m for both cores. RFT fluid samples were attempted at 4148.5
m, 4145 m, 4053 m, and 4157.5 m. Only mud filtrate was retrieved at all depths.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 16 December
1978 for future re-entry and testing. It is classified as a gas discovery. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

>

316
7/6/2016 12:00:00 AM
29.01.2023
15/5-2 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 R is a re-entry of well
15/5-2 in the Ve Sub-basin in the North Sea, north of the Sleipner Vest Field
and 15/5-1 Gina Krog Discovery. Well 15/5-2 found gas in Jurassic and Triassic
sandstones and was suspended without testing. The objective of the re-entry was
to conduct a production test from the Triassic reservoir. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-2 was re-entered with the
semi-submersible installation Treasure Seeker on 2 November 1979. </span></p>

<p class=MsoBodyText><span lang=EN-GB>After testing, the well was plugged and
permanently abandoned on 7 December 1979. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two FIT runs at 4150 m were attempted in
order to obtain fluid samples. Both runs failed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A production test was run in the Triassic
Hegre Group over the perforated intervals 4142 - 4146 and 4148 -4152 m. The
test produced 304120 Sm3 gas and 17.6 Sm3 liquid hydrocarbons /day through a
48/64” choke. The gas/condensate ratio was 17260 Sm3/Sm3, the condensate
gravity was 49 °API, and the gas gravity was 0.622 (air = 1). The reservoir
temperature estimated from the test is 130.6 °C (267 °F).</span></p>



1250
7/6/2016 12:00:00 AM
29.01.2023
15/5-3


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-3 was drilled in the Vilje
Sub-basin between the Enoch and the Gudrun fields in the North Sea. The primary
objective was to test possible sandstone reservoirs of Triassic age. A
secondary objective was to test the Middle Jurassic Sleipner Formation. The
well was planned to penetrate approximately 400 m into the Triassic and had a
projected total depth of 4200 m.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>After two unsuccessful spuds, wildcat
well 15/5-3 was spudded with the semi-submersible installation Nortrym on 21
August 1980 and drilled to TD at 5042 m in shale and sandstones of Late Permian
age. Hole reaming was necessary in intervals below 2250 m, otherwise the well
was drilled without significant problems or incidents. The hole was good and
vertical down to ca 3000 m. Below 3200 m the hole deviation increased to
between 3° and 8°. The well was drilled with seawater and hi-vis sweeps down to
615 m, with a seawater/Dextrid mud from 615 m to 2029 m, with
seawater/polymer/Q.Broxin mud from 2029 m to 3834 m, and with a salt-saturated
Dextrid mud from 3834 to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>None of the objective sandstone
reservoirs were found in the well. The Draupne Formation was encountered at
3665 m. After penetrating 135 m of Draupne shales, the well encountered 1050 m
of Zechstein evaporites. At this point, it was decided to deepen the well
further in order to explore the pre-salt rocks. Below these, undefined shales
and thin sandstones of Late Permian age were found. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Traces of oil in the mud was observed
during P&amp;A - see below. Poor oil shows were recorded in thin limestone
stringers at 2850 m, 2920, and in the interval 3355 to 3365 m. No shows were
recorded in the pre-Zechstein shales and sand sequence.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from
3815 to 3834.4 m with 59.9% recovery. Core 2 was cut from 5038 to 5042 at TD
with 94% recovery. No fluid samples were taken on wire line. However, while
cutting the 9 5/8&quot; casing during P&amp;A, small amounts of oil were found
floating on the drilling mud. The oil is assumed to originate from two 2-meter
thick sandstone stringers at 1474 m and 1479 m in the top of the Grid Formation.
From wire line log interpretation, these show high porosities and high
hydrocarbon saturations.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
December 2015 as a well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



207
5/19/2016 12:00:00 AM
29.01.2023
15/5-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5 4 was drilled on a structure
that straddles the border between the U.K. and the Norwegian sector of the
North Sea. Hydrocarbons were proven in the structure by three earlier wells
drilled in the UK sector (U.K. 16/13a-3, 16/13a-4, and 16/13a-5). Well 16/13a-4
penetrated a gas cap at the top of the structure and an oil column down to base
reservoir. The other two wells penetrated an oil zone and a water leg. The
objective of well 15/5-4 was to assess the extension of hydrocarbon bearing
Sele Formation sand towards the east into PL048. The well position was chosen for
possible use as a producer in the event of a positive appraisal. Prognosed
total depth was 2300 m. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-4 was spudded by the
semi submersible installation Vildkat Explorer on 6 June 1991 and drilled to TD
at 2300 m in rocks of the Paleocene Heimdal Formation. No shallow gas was
observed on the predicted sand/gas levels. Drilling proceeded without any
significant problems. The well was drilled with spud mud down to 1027 m and
with KCl/polymer mud from 1027 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Thin sands of the Sele Formation were
encountered at 2120 m and had good oil shows. The reservoir thickness was
calculated to 7.5 m. The sandstones of the Heimdal Formation were penetrated
below the oil/water contact and were totally water wet. Weak oil shows was
described on sidewall cores from claystone at 1909 m in the Frigg Formation and
sandstone at 2182 m in the Lista Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of six cores were cut from 2106 m
to 2147 m over the reservoir section. RFT fluid samples were attempted at 2125.1
m, 2125.3 m, 2125.8 m, and 2129.5 m. Sampling suffered from sand plugging and
only the samples from run 1C (2129.5 m) contained traces of oil.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3
July 1991 as a well with oil shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One DST test was performed over the
interval 2123.4 to 2135.9 m in the Sele Formation. Water was produced, but not
to surface. </span></p>



1762
7/6/2016 12:00:00 AM
29.01.2023
15/5-5
<p><b>General</b></p>

<p>Well 15/5-5 is located in the Northern North Sea, ca 15 km north of the Sleipner Field. The primary objective of the well
was to prove commercial volumes of oil in a prospect in the Late Paleocene Heimdal
Formation. The well location was chosen so as to test the prospect in a
position with as little up dip reserves as possible.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/5-5 was spudded with the
semi-submersible installation Treasure Saga on 31 August 1995 and drilled to TD at 2645 m in the Early Paleocene Ekofisk Formation. Boulders were experienced
in the interval 155 -170 m MD and some time was spent to correct the
inclination. Otherwise operations went without problems and the well was
completed well within schedule. The well was drilled with spud mud down to 1000
m and with KCl/polymer mud from 1000 m to TD.</p>

<p>The well penetrated water bearing Grid
Formation sands from 1479 m to 1807 m. The Heimdal Formation was encountered at
2154 m with 27.4 m of net pay hydrocarbon-bearing reservoir sand down to the
OWC at 2187m. The average porosity was calculated to 30.6 % and the average
horizontal core permeability was 1.9 Darcy. The OWC was based on formation
pressure measurements (MDT) and logs. The average oil saturation over the
interval was estimated to 67.4 %. The MDT data indicated a Free Water Level at
2189.2 m. Oil shows and low saturation of migrated hydrocarbons were observed
in selected intervals below the OWC down to 2191 m. The Heimdal Formation from
top to 2191 was the only interval in the well that had reported oil shows. An
82 m thick water bearing sandstones of the Ty Formation was encountered at 2501
m.</p>

<p>The interval 2157 - 2200 m was cored in 3
cores using equipment especially developed for soft sediment coring. The original
core depths are 4 m shallow relative to wire line log curves. The cores covered
most of the oil zone and extended into the water leg. MDT fluid samples were
taken at 2157.5 m (mud filtrate and oil), 2177 m (oil), 2186.5 m (oil), and at
2193.5 m (water).</p>

<p>The well was permanently abandoned on 5 October 1995 as an oil discovery.</p>

<p><b>Testing</b></p>

<p>One production test was conducted in the
Heimdal Formation over the perforated interval 2154 - 2183.5 m. The test
produced 575 Sm3 oil and 36000 Sm3 gas /day through a 60/64&quot; choke. The
GOR was 63 Sm3/Sm3, the oil density was 0.864 g/cm3, and the gas gravity was
0.868 (air = 1). The gas contained maximum 0.3% CO2 and no H2S. Maximum bottom
hole temperature in the test was 79.7 deg C.</p>
</html>

2635
7/6/2016 12:00:00 AM
29.01.2023
15/5-6

<p><b>General</b></p>

<p>Well 15/5-6 was drilled on the Glitne
field in the North Sea. The main objective was to appraise the 15/5-5 Glitne
oil discovery in the Heimdal Formation. The secondary objective was to
investigate the oil potential of a separate &quot;Intra Lista Sandstone&quot;
which had been mapped as a sequence lapping onto the main Heimdal Formation. </p>

<p><b>Operations and results</b></p>

<p>Appraisal well 15/5-6 was spudded with
the semi-submersible installation Byford Dolphin on 20 June 1997 and drilled to
TD at 2725 m in the Paleocene Ekofisk Formation. The drilling went according to
plan. However, problems due to poor hole conditions were encountered during
wire line logging at TD. The well was drilled with seawater and hi-vis pills
down to 1002 m and with KCl/polymer/glycol mud from 1002 m to TD.</p>

<p>The top of the main Heimdal reservoir was
penetrated 39 m TVD deeper than prognosed. The top corresponded seismically to
the reflector that pre-drill was interpreted as the top &quot;Intra Lista
Sandstone&quot;, so the general consensus is now that the reflector is actually
the top Heimdal Formation and that the &quot;Intra Lista Sandstone&quot;
sequence is not present.</p>

<p>The uppermost part of the Heimdal
reservoir was oil bearing, exhibiting good reservoir properties. The OWC was
found at 2185 m (2160 m TVD MSL), equivalent to the contact in well 15/5-5. No
other parts of well 15/5-6 contained hydrocarbons or shows of hydrocarbons.</p>

<p>One core was cut in the upper part of the
Heimdal Formation. No fluid sample was taken in the well.</p>

<p>The well was permanently abandoned on 16
July 1997 as an oil appraisal.</p>

<p><b>Testing</b></p>

<p>The well was not production tested due to
the limited oil column and no &quot;Intra Lista Sandstone&quot; being present.</p>



3113
7/6/2016 12:00:00 AM
29.01.2023
15/5-7






<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-7 was drilled on the Dagny
Discovery in the southern Viking Graben area of the North Sea. The primary
objective of the well was to prove an oil leg beneath the proven gas in the
Dagny structure and establish hydrocarbon contacts. Further objectives were the
hydrocarbon characteristics in the Hugin and Sleipner Formations and to test
the permeability and productivity of the reservoir. The second objective was to
collect a water sample in the Hugin Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-7 was spudded with
the semi-submersible installation Transocean Winner on 5 July 2008 and drilled
to TD at 4037m in the Triassic Skagerrak Formation. No shallow gas was observed
by the ROV at the wellhead or by the MWD while drilling the 36&quot; hole or
the 17 1/2&quot; hole. Operational problems included repairs of leakage in the
BOP in the 17 1/2&quot; section (close to 5 days NPT), directional deviation in
the 8 1/2&quot; section and loss of MDT tool in hole at final logging. The lost
MDT was pushed to bottom before plugging back. The well was drilled with spud
mud down to 1048 m and with KCl/polymer/Glycol (Glydril) mud from 1048 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary,
Tertiary, Cretaceous and Jurassic age. The well penetrated the Hugin Formation
reservoir at 3821 m (3815.3 m TVD), 59.7 m TVD shallower than prognosed. The well
proved oil down to base of the Hugin Formation and it was decided to sidetrack
the well for data acquisition in the water zone, including formation water
sampling. Based on pressure gradients recorded in 15/5-7 and in the later
sidetrack 15/5-7 A, the OWC was estimated at 3923 m TVD RKB. The sandstones of
the Hugin Formations had good oil shows, otherwise no oil shows were recorded
in the well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut. The first core was cut
in Hugin Formation, the second core covered the transition zones between the
Hugin and Sleipner Formations and the third core was cut in the Sleipner
Formation. MDT pressures were recorded in the oil bearing Hugin Formation and into
the Sleipner Formation. MDT oil samples were taken at 3828.8 m, 3830.5 m (sampled
during mini DST from 3830 - 3831 m), and at 3883 m (sampled during mini DST
from 3882.2 - 3883.2 m). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The open hole was plugged back to 3036 m
and prepared for sidetracking (15/5-7 A). The bore hole was abandoned on 7
September 2008 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5842
4/11/2017 12:00:00 AM
29.01.2023
15/5-7 A






<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/5-7 A is a sidetrack from well
15/5-7 on the Dagny Discovery in the southern Viking Graben area of the North
Sea. Well 15/5-7 proved an oil-filled Hugin Formation, a 98 m oil column. The
primary objective of the sidetrack 15/5-7 A was to obtain data from the water
zone, down-flanks on the structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/5-7 A was drilled with
the semi-submersible installation Transocean Winner. The sidetrack commenced on
8 September at 3145 m and drilled to 4130 m in the Sleipner Formation. The wire
line logging tools stuck in the first run at 3515 m and only very incomplete
logs were obtained from this bore hole. Fishing failed, the fish was pushed
down to 3715 m, and the borehole was plugged back for a second sidetrack. The
second, named technically as sidetrack 15/5-7 AT2, was kicked off from 3337 m
in well 15/5-7 on 24 September 2008 and drilled to TD at 4199 m in the Middle
Jurassic Sleipner Formation. TD logging was obtained. The sidetrack well was drilled
with an oil based mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Based on pressure gradients recorded in
15/5-7 and the sidetrack, the OWC was estimated at 3923 m TVD RKB. No oil shows
were recorded in the well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT pressures
were recorded in the water bearing Hugin Formation. MDT water samples were
taken at 3998.2 m in the technical sidetrack.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
October 2008 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5946
4/11/2017 12:00:00 AM
29.01.2023
15/6-1
<p><b>General</b></p>

<p>Well 15/6-1 is located ca 5 km north of
the Sleipner Field. The primary objective of the well was Eocene sands.</p>

<p><b>Operations and results</b></p>

<p>Well 15/6-1 was spudded with the drill
vessel Glomar Grand Isle on 7 August 1971and drilled to TD at 1679 m in Eocene
sediments of the Hordaland Group. Initial drilling from the sea floor to 384 m was
with sea water and gel. Below 384 m to a depth of 1247 m the mud system
consisted of sea water and Spersene XP-20 Salinex with drilling detergent. From
1247 m to TD a fresh water Spersene XP-20 system was used. Due to problems with
the casing seal assembly the well was abandoned without reaching its target.
The vessel vas moved approximately 335 m east and a replacement hole (15/6-2) was
drilled.</p>

<p>The only reservoir penetrated was a thick
Miocene sand section (the Utsira Formation) between 768 and 996 m. No hydrocarbon
shows were encountered.</p>

<p>No cores were cut and no wire line fluid
samples were taken.</p>

<p>The well was permanently abandoned on 8 September 1971 as a junk well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>
197
5/19/2016 12:00:00 AM
29.01.2023
15/6-10


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-10 was drilled on the Gudrun
Terrace in the South Viking Graben of the North Sea. The main objectives of the
well were to test the hydrocarbon and reservoir potential in the Hugin and
Sleipner sandstones of the Freke prospect. The main target was the Hugin Formation,
prognosed at 3495 m TVD RKB, and the secondary target was the Sleipner Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-10 was spudded with the
semi-submersible installation Bredford Dolphin on 7 February 2009 and drilled
to TD at 3700 m in the Late Triassic Skagerrak Formation. The well experienced
some deviation difficulties in the 17 1/2&quot; and 12 1/4&quot; sections. The
17 1/2&quot; section started out well but with fairly high torque and
stick-slip levels. When entering the Skade Fm the assembly started to build
angle. Despite attempts to reduce the building tendency, the angle kept
building 0.5- 0.7 degrees per stand drilled. When drilling at 1838 m, the 17 1/2&quot;
assembly twisted off in an extension sub just below the bottom stabilizer,
approximately 18 m above the bit. The fish was retrieved at first attempt. The
17 1/2&quot; were finished on a motor run to correct the well path. In 12 1/4&quot;
section, steering commenced in order to correct the well path back towards the target
centre. Initially steering proved to be relatively easy but turned impossible
once entering chalk due to very poor toolface control. The well was drilled
with spud mud down to 696 m, with KCl/GEM water based mud from 696 m to 2109 m,
and with Performadril water based mud from 2109 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated several Tertiary
sands (Utsira, Skade, and Heimdal Formations), all water-filled. The primary
target Hugin Formation was not encountered although an equivalent age Heather
Formation shale prone lithology was encountered at 3497 m. Top Sleipner
Formation was encountered at 3510 m and contained gas/condensate down to ca
3567 m (3536 m TVD SS), however the actual hydrocarbon/water contact could not
be established from any well data. The Sleipner Formation reservoir sands were
silty, with interbedded coals, claystone and thin limestones. Net/gross ratio
of the total reservoir was limited to ca 0.3. Oil shows were observed in the
Shetland Group (3260-3270 m and 3340-3370 m), in the Vestland Group (3497 -
3584 m) and in the Hegre Group (3620 - 3659 m).</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were taken because massive sands
with shows were not identified. No sidewall cores were obtained due to tool
failure. MDT hydrocarbon samples were taken at 3545.5 and 3563.8 m and an MDT
water sample was taken at 3628 m. Compositional analysis of the hydrocarbon
samples showed a condensate with ca 23 % C2+ hydrocarbons.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6
April 2009 as a gas/condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6030
4/11/2017 12:00:00 AM
29.01.2023
15/6-11 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-11 A was drilled to appraise
the 15/5-1 Dagny Discovery in the South-eastern end of the Viking Graben. The
north-eastern extension of this structure, the Ermintrude Segment, was tested
in 2007 by well 15/6-9 S and side tracks 15/6-9 A&amp;B, which proved oil and
gas in a down-to situation in the Hugin Formation, and in communication with
the Dagny Discovery. Well 15/6-11-A was drilled on the western part of the
Ermintrude structure, on the saddle point between the main Dagny segment and
the Ermintrude Segment. The main objective was thus to delimit and test the
extension of the hydrocarbon-bearings sands in Hugin Formation of the Dagny
Discovery. If hydrocarbons were confirmed a drill stem test would be conducted.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-11 A was sidetracked
from the primary well 15/6-11 S on 26 December 2010. Kick-off point was 1981 m.
The well was drilled with the semi-submersible installation Ocean Vanguard to
TD at 4305 m (3853 m TVD) in the Early Jurassic Statfjord Formation. No
significant problems were encountered in the operations. The sidetrack well was
drilled with XP-07 14A oil based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The target reservoir sandstones of the
Hugin Formation were encountered at 4121 m (3708.5 m TVD), 12.5 m deeper than
prognosis. The Hugin Formation was found to be heterolithic siltstone/sandstone
at the top but grading to better sand quality with depth. Good sandstones with
high gas values and hydrocarbon shows were encountered 4138 m. Both the core
and the logs showed presence of hydrocarbons in the Hugin Formation with OWC at
4167 m (3745 m TVD). There were shows indications also in sands in the Sleipner
Formation and in the Statfjord Formation towards TD of the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A core was cut from 4148 m to 4179 m. The
core shift relative to the logs was found to be close to + 2.3 m for the whole
core. MDT wire line fluid samples were taken at 4148 m (oil and gas), and at
2597.7 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
March 2011 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>A drill stem test was conducted from
perforations at 4137.8 m to 4158.5 m in the gas/condensate bearing zone of the
Hugin Formation. The test produced 120 Sm3 oil and 220000 Sm3 gas /day through
a 32/64&quot; choke. The GOR was 1830 Sm3/Sm3. The bottom hole temperature at
reference depth was 118 deg C. </span></p>



6526
4/11/2017 12:00:00 AM
29.01.2023
15/6-11 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-11 S was drilled on the Dougal
North prospect in the South-eastern end of the Viking Graben. The Dougal North
prospect is situated in a down-faulted block south of the Ermintrude West
Segment of the Dagny Discovery. It was believed to be a continuation of the
Dagny reservoir. The main objective was thus to delimit and test the extension
of the Hugin Formation of the Dagny Discovery. If hydrocarbons were confirmed a
drill stem test would be conducted.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-11 S was spudded with
the semi-submersible installation Ocean Vanguard on 27 October 2010 and drilled
to TD at 4042 m in the Early Jurassic Statfjord Formation. The BHA was lost at
1758 m but was retrieved. It was decided to run wire line logs at this point,
and drilling proceeded without further significant problem after that. The well
was drilled with sea water and bentonite sweeps down to 696 m, with
Performadrill WBM from 696 m to 2190 m, and with XP-07 14A OBM from 2190 m to
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation reservoir sands were
penetrated at 3868.5 m MD (3800 m TVD), which was 16 m deeper than prognosis.
The Hugin reservoir was found to be water wet. Only weak oil shows that could
be due to the OBM was observed in the Hugin Formation, otherwise no hydrocarbon
indications were reported from the well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were
taken at 3916.5 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back for
sidetracking to a second prospect, Ermintrude West. It was abandoned on 19
December 2010 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6488
4/11/2017 12:00:00 AM
29.01.2023
15/6-12


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-12 was drilled on the McHenry
prospect on the south-western tip of the Gudrun Terrace in the south Viking
Graben. The main objective was to test the Hugin Formation. The secondary objectives
were to test the Sleipner and</span></p>

<p class=MsoBodyText><span lang=EN-GB>Skagerrak formations. The Hugin Formation
was also the main reservoir in the Dagny/Ermintrude discovery wells. The deep
oil-water-contact observed in the 15/5-7 well on Dagny (3897 m TVD SS)
indicated a possible spill from the Dagny/Ermintrude structure towards McHenry.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-12 was spudded with the
semi-submersible installation on Transocean Leader on 22 December 2010 and
drilled to TD at 3930 m in the Triassic Skagerrak Formation. Shallow gas was
interpreted close to the well location and a 9 7/8&quot; pilot hole was drilled
from the 30&quot; conductor shoe to 1060 m. No shallow gas was observed.
Eighteen meter of drill string was lost in the hole prior to the logging job so
loggers TD is 3914 m. Otherwise no significant problem occurred in the
operations. The well was drilled with sea water and hi-vis pills down to 1104
m, with Performadrill WBM from 1104 m to 2768 m, and with Low-ECD XP-07 oil
based mud from 2768 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was penetrated at
3798 m. It was only 12 m thick and held a 4 m thick oil filled sandstone. The
Hugin sand was prognosed to be between 10 and 100 m thick. The pressure measured
in the Hugin Formation indicated no communication with the Dagny/Ermintrude
discoveries to the south of 15/6-12. Otherwise there were no hydrocarbon
indications apart from a 2.5 m thick limestone stringer with top at 2975 m.
This limestone showed a significant resistivity increase and a decrease in
density and gave a gas peak of 4.2 %, but no fluorescence was described. The
secondary targets, Sleipner Formation and Skagerrak Formation were water
bearing. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. An oil sample was
collected with a MDT tool at 3806.0 m. The sample was estimated to be ca 11%
contaminated with OBM.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9
February 2011 as an oil discovery. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6518
4/11/2017 12:00:00 AM
29.01.2023
15/6-13
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 was drilled to test the Gina
Krog East-3 prospect on the south end of the Gudrun Terrace in the North Sea. The
primary objective was to prove commercial hydrocarbons in the Hugin Formation</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-13 was spudded with the
semi-submersible installation Songa Trym on 11 April 2015 and drilled to TD at 3577
m in the Late Triassic Skagerrak Formation. No significant problem was
encountered in the operations. The well was drilled with Seawater down to
1033.5 m, with Glydril mud from 1033.5 m to 2247 m, and with EMS3300 oil based
mud from 2247 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two separate oil columns, 13 and 3 metres
were encountered in sandstone with moderate to good reservoir properties in the
Hugin Formation and upper part of the Sleipner Formation. No oil/water contact
was encountered. No oil shows were recorded other than in the
hydrocarbon-bearing Hugin and Sleipner formations.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two consecutive cores were cut from 3466
to 3495.3 m in the Hugin / Sleipner formations. The recovery was 100%. MDT
fluid samples were taken at 3466.7 m (oil), 3471.8 m (oil), 3486.3 m (oil),
3486.3 m (mud), and 3494.0 m (water)</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15
May 2015 as an oil discovery well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7667
4/18/2017 12:00:00 AM
29.01.2023
15/6-13 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 A is a geological sidetrack
to well 15/6-13 on the south end of the Gudrun Terrace in the North Sea. It was
drilled to delineate the Gina Krog East-3 oil discovery made by the main well. The
objective was to test the down-flank potential of the Gina Krog east-3
structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-13 A was kicked off
at 2141 m in the main wellbore on 16 May 2015. It was drilled with the semi-submersible
installation Songa Trym to TD at 3925 m (3741 m TVD) in the Late Triassic
Skagerrak Formation. No significant problem was encountered in the operations. The
well was drilled with EMS4400 oil based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 A encountered seven and nine
metres of sandstone with moderate reservoir quality in the Hugin and Sleipner
formations. Both were water bearing. They were not in pressure communication
with each other, but the Hugin Formation sandstone is presumed to be in
pressure communication with the oil zone in 15/6-13. Petrophysical interpretation
indicated hydrocarbons in the Skagerrak Formation, but no pressure data were
acquired to confirm this. No oil shows were recorded in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. MDT water samples were
taken at 3812 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30
May 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7668
4/26/2017 12:00:00 AM
29.01.2023
15/6-13 B
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-13 B is a geological sidetrack
to well 15/6-13 on the south end of the Gudrun Terrace in the North Sea. It was
drilled to delineate the Gina Krog East-3 oil discovery made by the main well. The
objective was to test the presence of a gas cap up-flank on the Gina Krog
east-3 structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-13 B was kicked off
at 2031 m in the main wellbore on 3 June 2015. It was drilled with the
semi-submersible installation Songa Trym to TD at 3773 m (3472 m TVD) m in the
Late Triassic Skagerrak Formation. No significant problem was encountered in
the operations. The well was drilled with EMS4400 oil based mud from kick-off
to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The main target (Hugin Formation) was not
present. The Sleipner and Skagerrak formations proved to be hydrocarbon bearing
(gas) with a GOC at 3710 m (3416 m TVD). No oil water contact was seen. No oil
shows are were recorded in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT fluid
samples were taken at 3665 m (gas), 3695.3 m (gas), and 3724.6 m (oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
June 2015 as a gas and oil discovery well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7718
4/26/2017 12:00:00 AM
29.01.2023
15/6-14 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-14 S was drilled on the Gina
Krog in the Ve Sub-basin in the North Sea. The objective was to prove
commercial hydrocarbon volumes in the Hugin Formation in the unproven Gina Krog
Central 3 Segment, contributing to the Gina Krog Field production.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-14 S was kicked off
from main bore 15/6-B-2 below the 13 5/8&quot; casing shoe at 3334 m on 20
December 2017. It was drilled with the jack-up installation Maersk Integrator.
It was drilled to TD at 4684 m (3916.3 m TVD) in the Middle Jurassic Sleipner
Formation. Operations proceeded without significant problems. The well was
drilled with Innovert oil-based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Twenty-nine meters of Hugin Formation
sandstone was penetrated from 4628 m (3861 m TVD) to 4657 m (3890 m TVD). The
formation did not contain mobile hydrocarbons based on log interpretation. There
were no oil shows above the OBM in the well, and gas levels in the Hugin
Formation were low. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No logs were run on
wire line and no fluid sample was taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26
December 2017 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


8293
1/28/2020 12:00:00 AM
29.01.2023
15/6-15

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-15 was drilled to test the Freke-Garm
prospect on the Gudrun Terrace in the North Sea. The primary objective was to
test the hydrocarbon potential in the Middle Jurassic Hugin and Sleipner formations.
The secondary objective was to test the Triassic Skagerrak Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>An 8 ½” pilot hole 15-6/U-5 was drilled
1390 m MD. The pilot was drilled in parallel with the main bore. No shallow gas
was observed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-15 was spudded with the
semi-submersible installation Deepsea Stavanger on 18 May 2019 and drilled to
TD at 3795 m in the Triassic Skagerrak Formation. Operations proceeded without
significant problems. The well was drilled with seawater and hi-vis pills down to
1377 m, with KCl-polymer mud from 1377 m to 3033 m and with Innovert oil-based
mud from 3033 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-15 encountered the Sleipner
Formation with a thickness of about 124 meters, of which 45 meters were
reservoir sands of good to moderate reservoir quality. The Skagerrak Formation was
encountered with a thickness of about 150 meters, of which 16 meters were
reservoir sands with poor reservoir quality. The well is dry without shows</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2
June 2019 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>
8746
5/1/2021 12:00:00 AM
29.01.2023
15/6-16 S


















<p class=MsoBodyText><span lang=EN-GB>Well 15/6-16 S was drilled to test the Hornet
prospect in the Ve sub-basin about 10 kilometres north of the Gina Krog field in
the central part of the North Sea. The primary objective was to prove petroleum
in reservoir rocks from the Middle Jurassic Hugin and Sleipner formations. The
secondary objective was to prove petroleum in reservoir rocks from the Late
Triassic Skagerrak Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>An 8 ½” pilot hole 15/6-U-4 was drilled
down to 1130 m to acquire good quality LWD log data in the shallowest section</span></p>

<p class=MsoBodyText><span lang=EN-GB>and to verify no shallow gas present at
the drilling location. The pilot hole was drilled in parallel with the 36’’
hole of the main bore. No shallow gas was seen.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-16 S was spudded with
the semi-submersible installation Deepsea Stavanger on 14 May 2019 and drilled
to TD at 4203 m (4192 m TVD) m in the Late Triassic Skagerrak Formation. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 1128 m, with water-based mud from 1128 to 3705 m, and with
oil-based mud from 3705 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation was absent in the
well. The Sleipner Formation was penetrated at 4020 m, and the Skagerrak
Formation at 4130 m. The Sleipner Formation consists of interlayered
sandstones, siltstones and coals of which a total of 23 metres was sandstone of
moderate to poor reservoir quality. The Skagerrak formation came in with a thickness
of 73 metres, with sandstone layers totalling 17 metres with poor to moderate
reservoir quality. There were no shows above OBM in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. RDT fluid samples were
taken at 4131.3 m (water and filtrate) and 4054.3 m (water and filtrate)</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28
June 2019 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>









































8747
5/1/2021 12:00:00 AM
29.01.2023
15/6-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-2 was drilled in the Ve
Sub-basin in the North Sea, ca 5 km north of the Sleipner Field. It is the
replacement well for 15/6-1, which was junked for technical reasons. The objective
was to evaluate a deep-seated structure in the Scottish-Norwegian Graben. The
target was Eocene to Paleocene sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-2 was spudded with the drill
vessel on 9 September 1971 and drilled to TD at 3131 m in the Shetland Group. No
drilling problems were encountered, however, due to deviation problems around 1311
m a planned FIT was aborted, as the tool would not go beyond this depth. Initial
drilling from the sea floor to 1330 m was with seawater and gel. Below 1330 m,
a fresh water Spersene XP-20 mud system was used. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Paleocene section contained abundant
potential sandstone reservoirs (Heimdal Formation) with thin beds of clay
becoming marly below 2390. Significant shows were encountered in the interval 2223
to 2236 m in the upper Heimdal Formation. The cuttings, sidewall and
conventional cores corroborated the shows. Weak shows were recorded also on
numerous sidewall cores between 2303 and 2604 m. However, other evidence did
not substantiate these shows and the reservoir was assumed water wet below 2236
m. The Danian (2676 to 2735 m, Våle Formation) consisted of a sequence of
thinly interbedded sandstones, clays, shales and chalky limestones. No shows
were reported in this section. The Late Cretaceous section, from 2735 m to 3106
m, was predominantly limestone with thin interbeds of shale. Thin interbeds of
sandstone were also noted. There were no shows in the Late Cretaceous.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut. Core 1 was cut from
2236 to 2242 m with 100% recovery, core 2 was cut from 2336.6 to 2343.9 m with
42% recovery, and core 3 was cut from 2695.3 to 2699.3 m with 46% recovery.  No
fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 26 October 1971
as a well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



317
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15/6-2 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-2 R is a re-entry of  well
15/6-2 in the Ve Sub-basin in the North Sea, ca 5 km north of the Sleipner
Field. The initial well 16/6-2 was drilled to 3131 m in the Shetland Group with
the drill vessel Glomar Grand Isle. The well found good shows in Paleocene
sandstones and was suspended in October 1971. The primary objective of the re-entry
was to deepen the well and test the Dogger (Middle Jurassic) deltaic sands. A
secondary objective was to test the Lias section (Early Jurassic).</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-2 re-entered on 9 May
1974. It was drilled with the semi-submersible installation Drillmaster to TD
at 4779 m in the Late Permian Zechstein Group. The pipe stuck temporarily three
times in intervals below 4602 m. Due to hole problems and tight spots no logs
were run below 4611 m The well was drilled with a seawater /lignosulphonate mud
from re-entry point to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The only hydrocarbon reservoir penetrated
was the Dogger gas-condensate sands from 3582 to 3641 m. The lower part of
Dogger section and all of the Lias section were cut out of this test by an
erosional unconformity and/or faulting. The missing interval has good potential
for additional reservoir quality sands. In addition, the Late Triassic has good
sand development that could be adequate for reservoiring hydrocarbons. During
the drilling of the Triassic and Permian section (3688 to TD), the background
gas in mud and cuttings was near zero, which probably is related to lack of
source material for hydrocarbons.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No shows were recorded except in Dogger.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut with 100% recovery in
the interval 3582.3 to 3641.1 m. A total of eight FIT fluid samples were taken:
P8 (3600.6 m, mud filtrate and poor gas), P7 (3606.4 m, gas and 2 litres condensate),
P6 (3610.4 m, gas), P1 (3615.5 m, mud and gas), P3 (3616.5 m, gas and water),
P5 (3623.5 m, gas and mud filtrate), P4 (3634.4 m, gas and 2 litres
condensate), and P2 (3675.3 m, water, mud and filtrate).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1 August 1974. It
is classified as an appraisal well for the 15/5-1 Gina Krog Discovery</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


517
7/2/2020 12:00:00 AM
29.01.2023
15/6-3


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-3 was drilled in the Ve
Sub-basin in the south Viking Graben in the North Sea. The primary objective
was to test the Dogger Sands (Middle Jurassic), which were gas bearing in
15/6-2 R, at a structurally higher position on a large north south trending
anticline.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-3 was spudded with the semi-submersible
installation Drillmaster on 5 September 1974 and drilled to TD at 3795 m in
Late Triassic sediments of the Skagerrak Formation. A lignosulphonate seawater
mud was used to drill the well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Dogger sand from top at 3488 m to 3579
m was hydrocarbon bearing. The resistivity log indicate gas down to a massive
coal layer at ca 3562 m. The true gas/water contact was not established. There was
63 m of net gas bearing sand with average porosity 21% and average water
saturation 21.%. The Triassic was not a viable reservoir. The only major shows in
the well were in the Dogger reservoir sands.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 125.8 m core was recovered
(90.7 % overall recovery) in ten cores in the interval 3512.2 to  3650.9 m. FIT
fluid samples were taken at 3505 m (gas, water, mud  and trace oil), 3553 m
(gas, water, mud and trace oil), 3557 m (gas, mud filtrate and mud), and 3575 m
(mud filtrate and mud).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19
December 1974 m as a gas/condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two production tests were run.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The first was between 3601.2 and 3604.3 m,
this failed to flow. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The second was between 3514.3 and 3520.4
m. This test flowed 974300 Sm3 gas with 165 Sm3 condensate /day through a
1.5&quot; choke. The GOR was 5910 Sm3/Sm3 and the condensate gravity was 41.5°
API. </span></p>



318
7/6/2016 12:00:00 AM
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15/6-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-4 was drilled on the southern
end of the Gudrun Terrace in the North Sea. The objective was to test the
hydrocarbon potential of Middle Jurassic (Dogger) sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/6-4 was spudded with the
semi-submersible installation Norjarl on 28 June 1976 and drilled to TD at 3505
m in the Triassic Smith Bank Formation. The well was drilled water based with
lignosulphonate/CMC/lignite below 3097 m</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation was encountered at 3157
m. The target sandstone unit was encountered at 3222 m and was found to be
water bearing.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut. Cores 1 and 2 were
cut from 3226.3 m to 3247.6 m and cores 3 and 4 were cut from 3271.5 m to 3308
m. FIT fluid samples were taken on wire line at 3312 m (small amounts of gas
and 10.2 l water) and at 3222.5 m (small amounts of gas and 10.2 l water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
August as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



319
7/6/2016 12:00:00 AM
29.01.2023
15/6-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/6-5 was drilled in the north-eastern
part of the Sleipner Field (Sleipner West). The objective was to confirm
structural and stratigraphic interpretations as well as define the hydrocarbon
content and contacts and the reservoir properties in this part of the Field.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well is reference well for the Hugin
Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/6-5 was spudded with
the semi-submersible installation Drillmaster on 10 October 1977 and drilled to
TD at 3824 m in Triassic sediments. No significant problems were encountered
during the drilling of the well. Initial drilling from the sea floor to 166.5 m
was with fresh water and lignosulphonate. Below this depth and down to 1197.5 m
a seawater gel with carboxymethyl-cellulose (CMC) mud system was used. Below
1197.5 m the above mud with lignosulphonate was used.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Hugin Formation (Upper Dogger
Sandstone) was encountered at 3627 meters. This was six meters below the lowest
gas seen in the main Sleipner reservoir to that date, 3597 m MSL in 15/9-1. The
Hugin Formation is 53 meters thick in the well and essentially 100% sandstone. Electric
log analysis and RFT pressure data show the section to be water bearing,
although the presence of residual hydrocarbons down to 3655 m was indicated by
bleeding gas and excellent liquid hydrocarbon shows in the cores. No
hydrocarbon indications were present below 3655 m. The Sleipner Formation
(Lower Dogger) came in at 3580 m with several massive coals beds. The well established
that the potential lower limit of hydrocarbons in the main Sleipner reservoir was
3627 m (3603 m MSL). </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four conventional cores were cut from
3629 m to 3683 m in the Middle Jurassic sandstones (Dogger). Five FIT wire line
fluid samples were taken between 3632.6 m and 3655.5 m. They all contained mud
filtrate.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
November 1977 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


320
7/6/2016 12:00:00 AM
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15/6-6
<p><b>General</b></p>

<p>Well 15/6-6 was drilled to appraise the north
eastern flank of Alpha structure on the 15/6-3 Sleipner Vest Discovery in the North Sea. The primary target was a gas bearing Jurassic sandstone known as the Hugin Formation.
It was drilled to provide needed structural control and to establish a
gas/water contact. </p>

<p><b>Operations and results</b></p>

<p>Appraisal well 15/6-6 was spudded with
the semi-submersible installation Glomar Biscay II on 1 April 1982 and drilled
to TD at 3760 m in Late Triassic sediments of the Skagerrak Formation. The
36&quot; hole had to be reamed several times due to ledging. This also occurred
in the top of the 26&quot; section. Forty-six bbl's (7.3 m3) of fluid were lost
to the formation during cementing of the 13 3/8&quot; casing. The mud weight in
this section was 1.68 which is lower than the previous Sleipner wells. This and
the fluid loss can possibly be related to an unconsolidated sand (Skade
Formation) interval from 1185 to 1199 m. Minor hole problems were encountered
in the 12 1/4&quot; section. The drill string was temporarily stuck at 1627 m
after making a connection. The well was drilled with seawater and gel.</p>

<p>The well proved sands in the Utsira, Grid,
Heimdal, and Sleipner Formations; all water bearing. The gas bearing Hugin
Formation was encountered at 3563 m and had a gross thickness of 58 m. The
gas/water contact was found at 3607 m, which gives a gross gas interval of 44
m. No oil shows were reported from the target reservoir or other sections in
the well.</p>

<p>Three cores were taken in the Middle
Jurassic interval in the 8 1/2&quot; section. Core 1 recovered 18.5 m sandstone
from 3591 m to 3609.5 m. Core 2 recovered 16.0 m sandstone from 3609.5 m to
3622 m. Core 3 recovered 18.9 m Sandstone, shale and coal from 3625.5 m to
3644.5 m. No wire line fluid sample was taken. </p>

<p>The well was permanently abandoned on 9 June 1982 as a gas appraisal well.</p>

<p><b>Testing</b></p>

<p>The well was tested in the interval 3568 -
3578 m in the Hugin Formation where reservoir data indicated significant
accumulations of gas and condensate. The test produced 835000 Sm3 gas and 278
Sm3 condensate /day through a 56/64&quot; choke. The GOR (gas/condensate ratio)
was 3003 Sm3/Sm3 and the condensate gravity was 47 dg API. The gas gravity was
0.762 (air = 1), the CO2 content was 5 % and the H2S content was 7.5 ppm.</p>
38
5/19/2016 12:00:00 AM
29.01.2023
15/6-7
<p><b>General</b></p>

<p>Well 15/6-7 was the first well in licence
166. The primary objective of the well was to test the hydrocarbon potential of
the Middle Jurassic, Hugin Formation of Callovian age within a seismically
defined structural trap. There were no secondary objectives for the well,
however, other potential reservoir horizons, albeit outside closure, were
anticipated within the early Tertiary succession. The well programme was
designed to maximize the evaluation of these sections as</p>

<p>required. </p>

<p><b>Operations and results</b></p>

<p>Exploration well 15/6-7 was spudded on 24
April 1993 with the semi-submersible installation &quot;Vildkat Explorer&quot;
and drilled to TD at 3540 m in the Triassic Smith Bank Formation. The well was
drilled with gel and seawater down to 505 m, with PHPA/KCl mud from 505 m to
1173 m, with PHPA/KCl/Glycol mud from 1173 m to 2788 m, and with PHPA/KCl mud
from 2788 m to TD. </p>

<p>The Quaternary and Tertiary sequence
represented by the Nordland, Hordaland and Rogaland Group is dominated by
mudstone lithologies with occasional thick sandstone developments in the
Utsira, Grid, and Heimdal Formations. Background gas values ranged from less
than 0.1% to 0.5% with rare isolated gas peaks. The Late Cretaceous succession
in the well, 493 m thick, is dominated by carbonate lithologies of the Shetland
Group; below 3150 m these become increasingly and atypically sandy. A number of
gas peaks were recorded over the interval 3025 m to 3157 m with a maximum gas
peak of 5.42% recorded at 3154 m. The Early Cretaceous, 14.5 m thick,
represented by the Cromer Knoll Group is substantially thinner than anticipated
and consists of arenaceous limestones interbedded with thin calcareous
sandstones. The Upper Jurassic Draupne Formation was penetrated at 3233 m, 36 m
low to prognosis. Intra Draupne Formation Sandstone was encountered at 3292 m.
A formation fluid influx of 3.9 m3 equivalent to a calculated pore pressure of
1.5 sg (RFT) occurred at 3327 m (3331 m loggers depth), a gas peak of 0.74% was
associated with this influx. The mud weight was increased from 1.30 sg to 1.52
sg during well control operations. The top Heather Formation was penetrated at
3352.5 m, 75.5 m deeper than anticipated. Background gas values within the
Draupne and Heather Formations gradually decreased with depth from 4% to 0.18%
at the base of the Heather Formation. The primary objective, the Hugin
Formation, was penetrated at 3390.5 m, 4.5 m shallower than anticipated. The
Hugin Formation consists of interbedded mudstones and sandstones with the
sandstone beds increasing in thickness with depth. The well failed to penetrate
any hydrocarbon bearing horizons. The primary objective Hugin Formation was
water bearing. This was confirmed by RFT and petrophysical evaluation of the
logs. </p>

<p>One conventional core was cut over the
interval 3414 m to 3432 m (15.7 m recovered) in the Triassic Skagerrak
Formation. Three RFT runs, 3/1,3/2 and 3/3, were performed in the 8.5&quot;
hole section in the Draupne, Hugin and Skagerrak Formations, over the interval
3433-3331 m. A segregated sample was taken on run 3/3. The sample recovered 5 l
of muddy water in the 6-gallon chamber. The 1-gallon chamber was plugged. </p>

<p>The well was permanently plugged and
abandoned as a dry hole on 8 June 1993.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


2084
7/6/2016 12:00:00 AM
29.01.2023
15/6-8 A

<p><b>General</b></p>

<p>Block 15/6 is situated on the eastern
flank of the southern part of the South Viking Graben, lying in a transition
zone on a system of faulted terraces between the main Viking Graben to the west
and the Utsira High to the east. The primary objective of the 15/6-8 S well was
to test the hydrocarbon potential of the Middle Jurassic Hugin Formation within
a seismically defined structural trap. A secondary objective was the Heimdal
Formation sandstone (&quot;C-Prospect&quot;) which was prognosed to be
penetrated in a down dip flank location, but within structural spill. </p>

<p>The sidetrack 15/6-8 A was designed to
test the &quot;C-prospect&quot; in a more optimal crestal location, some 1000 m
to the west of the well position. </p>

<p>Other potential reservoir horizons
existed in the Early Tertiary Skade and Grid Formations. These were not within
mapped structural closure in any of the well trajectories. The well programmes
were designed to maximise the evaluation of these sections.</p>

<p><b>Operations and results</b></p>

<p>Exploration well 15/6-8S was spudded with
the semi-submersible installation &quot;Byford Dolphin&quot; on 18 February
1997 and drilled as a vertical hole to a depth of 1538 m, before kicking off in
a NNW direction towards the Middle Jurassic primary objective. The final TD was
reached at 3225 m MD (3122.5 m TVD SS) in the Triassic Skagerrak Formation. The
well was drilled with Seawater and bentonite down to 512 m, with KCl / polymer
mud from 512 to 1650 m, and with KCl / polymer / glycol from 1650 m to TD.</p>

<p>The Quaternary and Tertiary sequence of
2550 m thickness (2493 m True Vertical Thickness, TVT) was represented by the
Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but
significant thick sandstone development was present in the Utsira, Skade, Grid,
and Heimdal Formations. </p>

<p>The Shetland Group comprised the Early
Palaeocene Ekofisk and the Late Cretaceous, Tor, Hod, Blod°ks and Svarte
Formations. This 408 m sequence (389 m TVT) was dominated by carbonate
lithologies. There were no intervals of reservoir potential. The Early
Cretaceous was primarily recognised from well site micropalaeontological
analysis of ditch cuttings as a very thin but condensed lithological sequence
(4.5 m). It is interpreted as the Åsgard Formation. The Draupne Formation was
penetrated at 3089.5 m (2988.6 m TVD SS), and the Heather Formation at 3117.5 m
(3016.2 m TVD SS). The primary objective Hugin Formation was penetrated at
3164.5 m, (3062.6 m TVD SS). It consisted of 9 m of sandstone with some minor
claystone intercalations, passing into the Triassic Skagerrak Formation at
3173.5 m (3071.4 m TVD SS). Sandstone lithology continued to 3191 m, below
which claystone with thin sandstone interbeds became the dominant lithology. </p>

<p>No hydrocarbon shows were recorded or
noted within any of the potential reservoir sections in the well. FMT and
petrophysical evaluation confirmed all zones to be water bearing with a
complete absence of hydrocarbons. </p>

<p>A total of four log runs, were
successfully completed at well TD, the first 2 on wire line, the second 2 were
pipe conveyed. A 5th run (walk away VSP) was abandoned after 2 1/2 x 6 km lines
due to loss of air pressure at the offset source. On rigging up the wire line
logging tools the logging contractor Western Atlas was unable to detect marks
on the cable and unable to determine the fault. The cable was changed out, but
the second cable was again found to be faulty. As a result of the problems,
depth matching between log runs had an error factor of at least +/-2m. The
first log in the hole, DLL/MLL/DAC/GR/CHT run 1/1, was therefore used as the
reference log giving a consistent error for all further runs. Depth mismatching
was further exacerbated by the need to run wire line pipe conveyed, and open
hole sticking with accelerometer correction required in certain instances. No
fluid sample was taken in the well. One core was cut in the Hugin and Skagerrak
Formations in the interval 3172 m to 3181.5 m (8.85m recovered). </p>

<p>Well 15/6-8 S was permanently plugged
back to the 9 5/8&quot; casing shoe and abandoned as a dry well on 5 April
1997. Well 15/6-8 A was kicked off from below the 9 5/8&quot; casing at 1525 m
and drilled to TD at 2480 m (2397 m TVD SS) in the Heimdal Formation, below the
mapped structural spill point. The sidetrack was drilled with KCl / Polymer /
Glycol mud from kick-off to TD.</p>

<p>The Quaternary and Tertiary sequence of
at least 2353 m thickness (2295 m TVT) was represented by the Nordland,
Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant
thick sandstone development was present in the Utsira, Skade, Grid and Heimdal
Formations. No hydrocarbon shows were recorded within any of the potential
reservoir horizons. The logging operations suffered similar problems as in the
primary well bore leading to similar uncertainty in depth correlation of the
logs. No fluid samples were taken. One conventional core was cut over the
interval 2438 m to 2449 m (10.2m recovered) in the Heimdal Formation. </p>

<p>Well 15/6-8 A was permanently abandoned
as a dry well on 18 April 1997.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



3077
7/6/2016 12:00:00 AM
29.01.2023
15/6-8 S

<p><b>General</b></p>

<p>Block 15/6 is situated on the eastern
flank of the southern part of the South Viking Graben, lying in a transition
zone on a system of faulted terraces between the main Viking Graben to the west
and the Utsira High to the east. The primary objective of the 15/6-8 S well was
to test the hydrocarbon potential of the Middle Jurassic Hugin Formation within
a seismically defined structural trap. A secondary objective was the Heimdal
Formation sandstone (&quot;C-Prospect&quot;) which was prognosed to be
penetrated in a down dip flank location, but within structural spill. </p>

<p>The sidetrack 15/6-8 A was designed to
test the &quot;C-prospect&quot; in a more optimal crestal location, some 1000 m
to the west of the well position. </p>

<p>Other potential reservoir horizons
existed in the Early Tertiary Skade and Grid Formations. These were not within
mapped structural closure in any of the well trajectories. The well programmes
were designed to maximise the evaluation of these sections.</p>

<p><b>Operations and results</b></p>

<p>Exploration well 15/6-8S was spudded with
the semi-submersible installation &quot;Byford Dolphin&quot; on 18 February
1997 and drilled as a vertical hole to a depth of 1538 m, before kicking off in
a NNW direction towards the Middle Jurassic primary objective. The final TD was
reached at 3225 m MD (3122.5 m TVD SS) in the Triassic Skagerrak Formation. The
well was drilled with Seawater and bentonite down to 512 m, with KCl / polymer
mud from 512 to 1650 m, and with KCl / polymer / glycol from 1650 m to TD.</p>

<p>The Quaternary and Tertiary sequence of
2550 m thickness (2493 m True Vertical Thickness, TVT) was represented by the
Nordland, Hordaland and Rogaland Groups. Mudstone lithologies dominated, but
significant thick sandstone development was present in the Utsira, Skade, Grid,
and Heimdal Formations. </p>

<p>The Shetland Group comprised the Early
Palaeocene Ekofisk and the Late Cretaceous, Tor, Hod, Blod°ks and Svarte
Formations. This 408 m sequence (389 m TVT) was dominated by carbonate
lithologies. There were no intervals of reservoir potential. The Early
Cretaceous was primarily recognised from well site micropalaeontological
analysis of ditch cuttings as a very thin but condensed lithological sequence
(4.5 m). It is interpreted as the Åsgard Formation. The Draupne Formation was
penetrated at 3089.5 m (2988.6 m TVD SS), and the Heather Formation at 3117.5 m
(3016.2 m TVD SS). The primary objective Hugin Formation was penetrated at
3164.5 m, (3062.6 m TVD SS). It consisted of 9 m of sandstone with some minor
claystone intercalations, passing into the Triassic Skagerrak Formation at
3173.5 m (3071.4 m TVD SS). Sandstone lithology continued to 3191 m, below
which claystone with thin sandstone interbeds became the dominant lithology. </p>

<p>No hydrocarbon shows were recorded or
noted within any of the potential reservoir sections in the well. FMT and
petrophysical evaluation confirmed all zones to be water bearing with a
complete absence of hydrocarbons. </p>

<p>A total of four log runs, were
successfully completed at well TD, the first 2 on wire line, the second 2 were
pipe conveyed. A 5th run (walk away VSP) was abandoned after 2 1/2 x 6 km lines
due to loss of air pressure at the offset source. On rigging up the wire line
logging tools the logging contractor Western Atlas was unable to detect marks
on the cable and unable to determine the fault. The cable was changed out, but
the second cable was again found to be faulty. As a result of the problems,
depth matching between log runs had an error factor of at least +/-2m. The
first log in the hole, DLL/MLL/DAC/GR/CHT run 1/1, was therefore used as the
reference log giving a consistent error for all further runs. Depth mismatching
was further exacerbated by the need to run wire line pipe conveyed, and open
hole sticking with accelerometer correction required in certain instances. No
fluid sample was taken in the well. One core was cut in the Hugin and Skagerrak
Formations in the interval 3172 m to 3181.5 m (8.85m recovered). </p>

<p>Well 15/6-8 S was permanently plugged
back to the 9 5/8&quot; casing shoe and abandoned as a dry well on 5 April
1997. Well 15/6-8 A was kicked off from below the 9 5/8&quot; casing at 1525 m
and drilled to TD at 2480 m (2397 m TVD SS) in the Heimdal Formation, below the
mapped structural spill point. The sidetrack was drilled with KCl / Polymer /
Glycol mud from kick-off to TD.</p>

<p>The Quaternary and Tertiary sequence of
at least 2353 m thickness (2295 m TVT) was represented by the Nordland,
Hordaland and Rogaland Groups. Mudstone lithologies dominated, but significant
thick sandstone development was present in the Utsira, Skade, Grid and Heimdal
Formations. No hydrocarbon shows were recorded within any of the potential
reservoir horizons. The logging operations suffered similar problems as in the
primary well bore leading to similar uncertainty in depth correlation of the
logs. No fluid samples were taken. One conventional core was cut over the
interval 2438 m to 2449 m (10.2m recovered) in the Heimdal Formation. </p>

<p>Well 15/6-8 A was permanently abandoned
as a dry well on 18 April 1997.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



3014
7/6/2016 12:00:00 AM
29.01.2023
15/6-9 A


<p><b>General</b></p>

<p>Well 15/6-9 A is a sidetrack to well
15/6-9 S on the Ermintrude prospect west of the Dagny discovery in the southern
Viking Graben. The main objective of the side track was to prove communication
between the Dagny discovery and the Ermintrude structure, and to prove gas up
dip of the oil leg discovered in the Hugin Formation in 15/6-9 S. </p>

<p><b>Operations and results</b></p>

<p>Well 15/6-9 A was drilled with the jack-up
installation West Epsilon. It was sidetracked from the 15/6-9 S well at 2911 m.
The well was drilled deviated to a total depth of 3690 m, 26 m into the
Triassic Skagerrak Formation. It was drilled with a KCl/Polymer/Glycol mud
system. </p>

<p>The MDT results concluded with gas
condensate in a gas-down-to situation. A plot of the MDT pressure data for
15/6-9 A and 15/6-9 S give oil and gas gradients that intersect to give a gas-oil
contact at approximately 3641 m TVD MSL.</p>

<p>No conventional cores were cut and no
sidewall cores were retrieved from the 15/6-9 A well. High quality condensate
samples were acquired at 3587.5 m in the Hugin Formation. </p>

<p>Well 15/6-9 A was plugged back to 2786 m
on 26 May 2007. It is classified as a gas condensate appraisal well. The
geologic sidetrack 15/6-9 B was kicked off on the same day in order to find the
oil-water contact.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


5566
4/11/2017 12:00:00 AM
29.01.2023
15/6-9 B


<p><b>General</b></p>

<p>Well 15/6-9 B is a sidetrack to well
15/6-9 S on the Ermintrude prospect west of the Dagny discovery in the southern
Viking Graben. It was drilled down dip on the structure compared to 15/6-9 S.
The primary objective was to prove a possible oil water contact below 3714 m
TVD MSL, and test the spill point depth of the Ermintrude and Dagny structures.</p>

<p><b>Operations and results</b></p>

<p>Well 15/6-9 B was drilled with the
jack-up installation West Epsilon. It was sidetracked from the 15/6-9 S well at
2824 m on 13 June 2007 and drilled deviated to a total depth of 4010 m
driller?s depth, 63 m into the Sleipner Formation. It was drilled with a
low-sulphate KCl/Polymer/Glycol mud system. </p>

<p>The MDT results and wire line logs proved
light oil in an oil-down-to at ca 3948 m (3805 m TVD MSL). The MDT results and
wire line logs from all three wells 15/6-9 S, 15/6-9 A and 15/6-9 B give
gas/condensate up to 3485 m TVD MSL, a GOC at approximately 3641 m, and a
minimum of 164 m TVD oil column below the gas.</p>

<p>No conventional cores were cut and only
two sidewall cores were recovered from the 15/6-9 B well. High quality oil
samples were acquired at 3935 m in the Hugin Formation.</p>

<p>Well 15/6-9 B was permanently abandoned
on 23 July 2007 as an oil appraisal well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed. </p>



5571
4/11/2017 12:00:00 AM
29.01.2023
15/6-9 S


<p><b>General</b></p>

<p>Well 15/6-9 S was drilled on the Ermintrude
prospect east of the Dagny discovery and north of the Sleipner Vest field. The
prospect is located in the South Viking Graben on the northernmost extension of
the Sleipner Terrace, with the Utsira High immediately to the east. The primary
objective was to prove hydrocarbons in the Hugin Formation and to acquire data
to understand the reservoir characteristics and fluid distribution, and how the
Ermintrude structure is connected to the Dagny discovery. Potential targets in
the Sleipner and Skagerrak Formation were also investigated by this drilling. </p>

<p><b>Operations and results</b></p>

<p>Well 15/6-9 S was spudded with the jack-up
installation West Epsilon on 29 March 2007 and drilled to TD at 3940 m in the
Late Triassic Skagerrak Formation. The well was drilled vertical down to 1050 m
and continued in a slightly deviated S-shaped trajectory towards TD. The well
was drilled with seawater and hi-vis sweeps down to 277 m, with seawater and
CMC EHV sweeps from 277 to 762 m, with a KCl/glycol/polymer mud from 762 to
2797 m, and with low-sulphate KCl/glycol/polymer mud from 2797 m to TD. No
shallow gas was observed while drilling the 36&quot; hole, 12 1/4&quot; pilot hole
or in the 24&quot; hole opening run. However, 6.3% gas (98% Methane) was
observed at top Utsira Formation, 39 m below the 20&quot; casing shoe. MDT
pressures and sampling confirmed a normally pressured gas accumulation.</p>

<p>The well penetrated rocks of Quaternary, Tertiary,
Cretaceous, Jurassic, and Triassic age. The well penetrated the Hugin reservoir
at 3741 m, slightly shallower than prognosed. Pressure points and fluid samples
were taken with the MDT and a hydrocarbon discovery was proven in the Hugin
Formation. The MDT results and wire line logs proved this to be light oil in an
oil-down-to situation at ca 3790 m (3714 m TVD MSL). There were no shows or
other hydrocarbon indications below 3790 m.</p>

<p>One conventional core was cut at 3761.3 -
3811 m in the Hugin Formation. Shows on the core verified the oil-down-to contact
at 3793 m. A total of 26 sidewall cores were drilled with the MSCT in Draupne,
Heather, Hugin, Sleipner and Skagerrak Formation. High quality oil samples were
acquired in the Hugin Formation at 3763 m and 3791 m. A water sample was taken at
3804 m in the Sleipner Formation. The quality of the water sample was low with
40% mud contamination measured at the rig site. In the Utsira Formation, gas
samples were taken by dual packer MDT at 793 m.</p>

<p>Well 15/6-9 S was plugged back to 2838 m
in the 8 1/2&quot; section on 26 May 2007. The well is classified as a gas and
oil appraisal well. The geologic sidetrack 15/6-9 A was kicked off on the same
day to prove communication with the Dagny discovery and to appraise gas above
the oil-leg in the Hugin Formation.</p>

<p> <b>Testing</b></p>

<p>No drill stem test was performed. </p>



5494
4/11/2017 12:00:00 AM
29.01.2023
15/8-1


<p><b>General</b></p>

<p>Wildcat well 15/8-1 was drilled west of
the Sleipner field, ca 2 km from the UK border. The well was designed to test
possible hydrocarbon accumulation in the sandstones of middle Jurassic age.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/8-1 was spudded with the
semi-submersible installation Glomar Biscay II on 18 July 1981 and drilled to
TD at 4300 m in the Middle Jurassic Fladen Group. Drilling operations were
performed without significant problems in the 36&quot;, 26&quot; and 17 1/2&quot;
holes. Pipe stuck in the 12 1/4&quot; hole at 2254 m and several times in the 8
1/2&quot; hole. Miscellaneous technical problems occurred while drilling the
6&quot; hole and a gas kick was at 4265 m while tripping. The well was drilled
with seawater and gel down to 500 m and with gypsum mud from 500 m to 2890 m.
Lignosulphonate was added from 1570 m, and from 2890 m to TD the gypsum mud was
gradually depleted and replaced with a gel/lignosulphonate mud.</p>

<p>The well 15/8-1 proved gas and condensate
in sandstone of Middle Jurassic age. The gas/water contact was indicated at
3698 m from the Formation Multi Tester. Oil shows were recorded from 3065 m to
3075 m in the Hod Formation. Five conventional cores were cut in the interval
3658 m to 3705.5 m in the Hugin Formation. Three samples were attempted taken
during FMT runs. Due to technical malfunctions only 1 sample (from 3668 m) was
obtained.</p>

<p>The well was permanently abandoned on 7
January 1982 as a gas/condensate discovery.</p>

<p><b>Testing</b></p>

<p>One drill stem test was performed in the
Sleipner formation and three in the Hugin Formation. The procedure of the tests
was similar; after initial flow and build up the well was flowed for
approximately 660 min. producing gas/condensate. Test no. 4 was only flowed for
480 minutes. CO2 was produced in all tests, in concentrations ranging from 4%
to 15%, and up to 8 ppm H2S was recorded in DST2. Two sets of PVT samples were
taken at the separator during all 4 tests. </p>

<p>DST1 from 4079 m to 4094 m in the
Sleipner Formation produced 427000 Sm3 gas and 316 Sm3 condensate/day on a 19.1
mm choke. The gas/condensate ratio (CGR) was 1351 m3/m3. DST2 from 3911 m to
3926 m produced 486000 Sm3 gas and 399 Sm3 condensate/day on a 16.7 mm choke,
the CGR was 1218 m3/m3. DST3 from 3688 m to 3697 m produced 657000 Sm3 gas and 408
Sm3 condensate/day on a 22.2 mm choke. The CGR was 1610 m3/m3. DST4 from 3643 m
to 3653 m produced 550000 Sm3 gas and 290 Sm3 condensate/day on a 22.2 mm
choke. The CGR was 1897 m3/m3. </p>



321
7/6/2016 12:00:00 AM
29.01.2023
15/8-2
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 15/8-2 well was drilled in the Ve
sub-basin, west of the Sleipner Field and ca 3 km from the UK border in the
North Sea. The primary objective was to prove a commercial hydrocarbon
accumulation within Upper and Lower Hugin Formation. The secondary objectives
were to test possible hydrocarbon presence within the Sleipner Formation and
leads in the Hod Formation (Goldfinger lead) and Late Jurassic.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/8-2 was spudded with the
semi-submersible installation COSLPioneer on 20 August 2011 and drilled to TD
at 4386 m in the Middle Jurassic Sleipner Formation. Before spud, a shallow gas
class 1 warning was given. A 9 7/8&quot; pilot hole was drilled from 208.5 to
1100 m. However, no shallow gas was observed by the ROV at the wellhead or by
the MWD during drilling. No significant problem was encountered in the
operations. The well was drilled with Seawater and bentonite hi-vis sweeps down
to 1133 m, with Glydril mud from 1133 m to 2419 m, and with Versatec OBM from
2419 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary,
Tertiary, Cretaceous, and Jurassic age. No hydrocarbon indications were observed
in the Hod Formation (Goldfinger) and only thin sandstone stringers were
observed in the Late Jurassic. The main target Upper Hugin Formation was
encountered at 3881.5 m, 31 m higher than prognosed, and the Lower Hugin Formation
came in at 4065 m, 1 m shallower than prognosed. The secondary target Sleipner
Formation was encountered at 4238 m, i.e. 61 m deeper than prognosed. No
movable hydrocarbons were proven in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Shows: Bright yellowish direct
fluorescence, and a slow streaming cloudy bluish white cut fluorescence was
recorded in siltstones in the Draupne Formation in the interval from 3812 m to
3818 m and Heather Formation from 3845 m to 3857 m. In the Hugin Formation
sandstones questionable shows (oil-based mud?) were recorded in the intervals
from 3881 m to 3911 m and 4013m to 4120m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. The MDT tool was run
for pressure and fluid sampling. Four water samples were taken at 4011 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21
October 2011 as a dry well.<b> </b></span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>
























































6681
2/21/2020 12:00:00 AM
29.01.2023
15/9-1


<p><b>General</b></p>

<p>Well 15/9-1 is located in the Sleipner
Field. It was drilled on a seismic structure in order to evaluate the Dogger
sandstone (Hugin and Sleipner Formations) of Middle Jurassic age.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/9-1 was spudded with the
semi-submersible installation Ross Rig on 24 February 1977 and drilled to TD at
3734 m in the Late Triassic Skagerrak Formation. Severe weather occurred on 31
March, at 3539 m, when the drill string was hung off in the wellhead and the lower
marine package disconnected. Drilling commenced on 2 April. When
washing/reaming back to TD at 3675 m with a bit to open up the rat hole the
pipe stuck at 3647m. Jarring/fishing action was unsuccessful and the string was
backed off at 3507 m. The hole was then plugged back, sidetracked and drilled
to TD. The well was drilled with seawater and hi-vis pills to 415.5 m and with
a seawater/conditioned bentonite/spersene mud system from 415.5 m to TD.</p>

<p>Top of the Dogger sandstone (Hugin
Formation) was encountered at 3530 m. Log evaluation gave a net productive pay
of 56 m, of which 38 m was gas bearing and 18 m was oil bearing. Lowest
producible hydrocarbon depth was top of coal bed at 3672 m. Good shows were
recorded on cuttings in the interval 3633 m to 3687 m, and in porous sandstones
on cores from 3545 m to 3667 m. The Jurassic sandstone was cored in nine cores
between 3521 m and 3675.5 m. RFT fluid samples were taken at 9 depths in the
interval 3525.5 m to 3701 m. Most of them recovered traces of condensate or oil
together with mud filtrate and gas. Only three samples recovered measurable
quantities of fluid hydrocarbons: 3528.8 m (5 - 15 ml condensate), 3596.5 m
(500 ml condensate), and 3621 m (5 - 15 ml oil). </p>

<p>The well was permanently abandoned on 30
May 1977 as an oil and gas appraisal.</p>

<p><b>Testing</b></p>

<p>Two DST's were performed. </p>

<p>DST 1 perforated the interval 3660 m to
3655 m and flowed 1330 STBOPD (211.5 Sm3 oil /day) and 1420000 SCF/D (40210 Sm3
gas/day). This gives a GOR of 1070 SCF/STB (191 Sm3/Sm3). The gas gravity was
0.738 (air = 1), and oil gravity was 26 °API. Foam problems made it difficult
to get reliable separator data: oil rates are probably maximum rates and GOR
could thus be substantially higher. </p>

<p>DST 2 perforated 3602 m to 3607 m and
flowed 812 STBOPD (129.1 Sm3 oil/day) and 26000000 SCF/D (7362400 Sm3 gas/day).
This gives a GOR of 32000 SCF/STB (5700 Sm3/Sm3). The gas gravity was 0.704
(air = 1) and oil gravity was 45.5 °API.</p>



322
7/6/2016 12:00:00 AM
29.01.2023
15/9-10


<p><b>General</b></p>

<p>Wildcat well is located between the
Sleipner Vest and Sleipner Øst Fields. The well was designed to test possible
hydrocarbon accumulations in the Upper Middle Jurassic sands and secondary test
Heimdal Formation Sand of Paleocene age.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 15/9-10 was spudded with the
semi-submersible installation Neptuno Nordraug on 15 September 1981 and drilled
to TD at 3289 m in the Triassic Smith Bank Formation. Drilling the 26&quot;
hole section complete loss of returns occurred at 186 m and a cement plug was
set. Drilling out of the cement returns were again lost, at 178 m, requiring a
further cement plug. Total losses due to this loss zone were well in excess of
10 000 bbls. After this operations went without significant problems. The well
was drilled with seawater and hi-vis pills down to 172 m. The next section, the
26&quot; section, was drilled down to 472 m with seawater/bentonite and
quantities of Mica Fine, Nutplug, Kwikseal, and other additives. From 472 m to
TD m the well was drilled with polymer/Drispac.</p>

<p>The well encountered Tertiary sands in
the Utsira Formation at 884 - 1102 m, Grid Formation at 2049 - 2079 m, Heimdal
and Ty Formations at 2547 m to 2667 m. An RFT run in the Heimdal sand indicated
a water gradient, 1.02 g/cm3. The primary target Jurassic sandstones was
encountered at 3070 m in the Hugin and Sleipner Formations. Some shows were
recorded in the Hugin Formation, but from the logs the formations were all
water-wet. Possible source rocks were encountered in a comparatively thick and
marly Blodøks Formation from 2871 m to 2924 m, and in the Late Jurassic Draupne
and Heather Formations from 3004 m to 3070 m. Four conventional cores were cut.
Core 1 was cut from 3061 m to 3062.4 m in the Heather Formation, core 2 was cut
from 3082 m to 3100 m in the Hugin Formation, and cores 3 and 4 were cut from
3137 m to 3171 m in the Sleipner Formation. No fluid sample was taken.</p>

<p>The well was permanently abandoned as dry
with minor shows on 7 November 1981.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



69
5/19/2016 12:00:00 AM
29.01.2023
15/9-11


<p><b>General</b></p>

<p>Well 15/11-9 was drilled to appraise the
15/9-9 Sleipner Øst discovery in the south Viking Graben area of the North Sea.</p>

<p>The primary objective was to delineate
the hydrocarbon accumulation found in the Heimdal Formation of the 15/9-Gamma
structure. The secondary objective was to test for possible hydrocarbons in
Triassic sandstones.</p>

<p>The well is Reference well for the Lista Formation,
the Meile Member, and the Heimdal Formation</p>

<p><b>Operations and results</b></p>

<p>Appraisal well 15/9-11 was spudded with
the semi-submersible installation Ross Rig on 18 September 1981 and drilled to
TD at 2950 m in the Triassic Hegre Group. A total of 99 days including a strike
was spent on this well. Apart from the strike, which amounted to 22 days of
lost operation, there were no severe problems during drilling and testing
operations. The well was drilled with sea water and bentonite down to 585 m and
with gel/lignosulphonate/seawater mud from 585 m to TD.</p>

<p>The well proved gas and condensate in
Heimdal formation and verified thereby the results from the 15/9-9 well. The
gas- water contact was found at 2442 m. Hydrocarbons were found also in the Jurassic
Hugin Formation sandstones with a gas-water contact at 2825 m. The TD for the
well was then extended from 2650 to 2950 m. No hydrocarbons were found in
Triassic sandstones </p>

<p>Eleven cores were cut in the well. Cores
1 and 2 were cut from 2364 to 2379 m in the Lista Formation. Cores 3 to 11 were
cut from 2395 to 2514 m in the Heimdal Formation. The RFT tool was run on wire
line and the pressure data supported communication with the 15/9-9 discovery
well within the Heimdal Formation, while the Hugin Formation was in a separate
pressure regime. Segregated fluid samples were taken at 2387.5 m, in the
Heimdal Formation, and at 2812 and 2825.8to 2826.5 m in the Hugin Formation.</p>

<p>The well was permanently abandoned on 23
December 1981 as a gas/condensate appraisal well.</p>

<p><b>Testing</b></p>

<p>Three DST was performed. DST 1 tested the
Hugin Formation sandstone from 2789.5 - 2830 m. It produced 566000 Sm3 gas and
243 Sm3 condensate / day through a 15.9 mm choke. The condensate density was
0.75 g/cm3 and the gas gravity was 0.74 (air = 1) with 0.5 - 1% CO2. The
maximum down hole temperature measured in the test was 103.9 deg C.</p>

<p>DST 2 tested the Heimdal Formation
sandstone in the interval 2432 - 2440 m. It produced 233785 Sm3 gas, 104 Sm3
condensate and 1085 m3 water/ day through a 12.7 mm choke. The oil density was
0.75 g/cm3 and the gas gravity was 0.72 (air = 1) with 0.1 - 0.5% CO2. The
maximum down hole temperature measured in the test was 93.3 deg C.</p>

<p>DST 3 tested the Heimdal Formation
sandstone in the interval 2395 - 2415 m. It produced 570867 Sm3 gas and 266 Sm3
condensate / day through a 19.1 mm choke. The oil density was 0.75 g/cm3 and
the gas gravity was 0.734 (air = 1) with 0.1 - 0.5% CO2. The maximum down hole
temperature measured in the test was 92.2 deg C.</p>


329
7/6/2016 12:00:00 AM
29.01.2023
15/9-12


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 was drilled as an appraisal
well on the saddle area between the Alpha and Beta structures on the Sleipner
Vest field in the North Sea. The main objective was to test the Middle Jurassic
sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>After setting anchors on 8 November 1981
the spud was delayed two weeks due to strike by the maritime and drilling crews.
</span></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-12 was spudded with
the semi-submersible installation Nordraug on 22 November 1981 and drilled to
TD at 3740 m in the Middle Jurassic Sleipner Formation. The 36&quot; hole was
drilled to 195 m but due to bad weather the hole was lost and the well was re-spudded
on 26 November. Drilling of the 26&quot; and 17 1/2&quot; holes went forth
without significant problems other than tight spots in the lower part of the 17
1/2&quot; hole. When setting the 9 the 5/8&quot; casing shoe at 2755 m 64 m3 mud
was lost to the formation. The well was drilled with seawater and gel slugs
down to 501 m, with gel-lignosulphonate mud from 501 m to 1135 m, with lignosulphonate/gypsum/CMC
mud from 1135 m to 2771 m, and with gel-lignosulphonate mud from 2771 to 3740
m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A 251 m thick Heimdal Formation was
penetrated from 2374 m to 2625 m. The Heimdal Formation was water bearing
without shows. The primary target reservoir Hugin Formation was penetrated at
3510 m and proved to contain gas-condensate with a gas-water contact at 3654
according to RFT pressure gradients. Weak shows continued on the cores down to
3665 m. The underlying Sleipner Formation was dry without shows. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 168.8 m core was cut from top
to base of the Hugin Formation. The depth for cores 1 - 9 should be shifted
down ca 7 m to fit with the loggers' depth. Cores 10 - 11 should be shifted 8
and 9 m down, respectively. Seven RFT runs were conducted for pressure points
and sampling. Segregated fluid samples were taken at 3653 m, 3592.5 m, 3512 m,
and 3647 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 27 February
1982 as a gas-condensate appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Testing was planned, but failed due to
problems with the test string. For this reason Nordraug was taken to the
shipyard and testing would be done in a re-entry.</span></p>


330
7/6/2016 12:00:00 AM
29.01.2023
15/9-12 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 R is a re-entry of well
15/9-12, which was drilled as an appraisal well on the saddle area between the
Alpha and Beta structures on the Sleipner Vest field in the North Sea. Due to
technical problems with the rig the final testing was not done in the primary
well. The purpose of the re-entry was testing and plugging. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-12 was re-entered on 29 March
1982 with the semi-submersible installation Deepsea Saga. </span></p>

<p class=MsoBodyText><span lang=EN-GB> After testing the well was permanently
abandoned on 27 April 1982 as a gas-condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.
DST 1A tested the interval 3585 m 3595 m. This test was aborted due to bad
weather after flowing the well for 150 minutes. The interval was retested a few
days later in DST 1B. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1B flowed 252 Sm3 condensate and
771600 Sm3 gas /day through a 64/64&quot; choke. The condensate/gas ratio (CGR)
was 3056 Sm3/Sm3, the condensate density was 0.793 g/cm3, and the gas gravity
was 0.772 (air = 1) with ca 8% CO2. The DST temperature was 121 deg C at gauge
depth 3561.8 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 3512 m to 3522
m. It flowed 231 Sm3 condensate and 808500 Sm3 gas /day through a 64/64&quot;
choke. The CGR was 3495 Sm3/Sm3, the condensate density was 0.793 g/cm3, and
the gas gravity was 0.765 (air = 1) with ca 7% CO2. The DST temperature was 119
deg C at gauge depth 3499 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Eight gas samples and six condensate
samples were taken at the separator during DST 1. Eight gas and eight
condensate samples were taken at the separator during DST 2. Neither test
experienced sand production nor was H2S detected. </span></p>



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15/9-13


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-13 was drilled on the Sleipner
East Field in the Viking Graben in the North Sea. The objective was to
delineate the hydrocarbon accumulation found in the Heimdal Formation of the
15/9 Gamma structure. Secondary objectives were to test possible hydrocarbons
in sandstones of Jurassic - Triassic age. The well is reference well for the
Utsira and Skade formations. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-13 was spudded with
the semi-submersible installation Ross Rig on 21 March 1982 and drilled to TD
at 3280 m in the Permian Zechstein Group. <span style='color:black'>No
significant problem was encountered in the operations.</span> The well was
drilled with seawater and hi-vis slugs down to 518 m, with gel/lignosulphonate
mud from 518 m to 1165 m, gypsum/lignosulphonate mud from 1165 m to 2642 m, and
gel/lignosulphonate mud from 2642 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB style='color:black'>The well proved gas
and condensate in the Heimdal Formation. Shows on cores indicate that all
sandstones in the Heimdal Formation are gas filled to a probable down-to contact
in top Shetland Group at 2440 m. Gas and condensate were also encountered in a
Jurassic sandstone from 2763 to a probable down-to contact at 2791 m. No
hydrocarbons were found in Triassic sandstones. No shows were recorded outside
of the hydrocarbon-bearing sections in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. Cores 1 - 3 were
cut from 2404 m in the Heimdal Formation to 2453.5 m in the Tor Formation with
84 to 100% recovery. Cores 4 - 7 were cut from 2763 m to 2801.6 m in the Hugin
Formation with 90 to 100% recovery. Segregated RFT fluid samples were taken at
2400 m, 2437 m, 2765.8 m, and 2766.5 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27
May 1984 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two DST's were performed on this well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested gas and condensate from 2765
to 2769 m in the Jurassic sand through the 7&quot; liner. During the main flow
on a 64/64” choke, the test produced on average 804500 Sm3 gas and 388 Sm3
condensate /day. The GOR was 2073 Sm3/Sm3, the condensate density was 0.783
g/cm3 and the gas gravity was 0.742 (air = 1). The gas contained 0.8 ppm H2S
and 1.0 % CO2. The gauge temperature at final build-up was 98.3 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested gas and condensate from 2422
to 2427 m in the Heimdal sand through the 9 5/8&quot; casing. During the
clean-up period on a 64/64” choke, the test produced on average 758600 Sm3 gas
and 401 Sm3 condensate /day. The GOR was 1891 Sm3/Sm3, the condensate density
was 0.76 g/cm3 and the gas gravity was 0.702 (air=1). The gas contained 0.4 ppm
H2S and 0.3 % CO2. The gauge temperature at final build-up was 90.3 °C.</span></p>



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15/9-14


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-14 is located ca 7 km south of
the Sleipner Vest Field in the south Viking Graben of the North Sea. The main
objectives of the well were sandstones of Late to middle Jurassic age. The
secondary objective was the Triassic. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-14 was spudded with the
semi-submersible installation Deepsea Saga on 1 May 1982 and drilled to TD at 3563
m in Triassic Smith Bank Formation. Operations were conducted without incident
except some problems with tight hole and stuck pipe in the 12 1/4&quot;
section. The well was drilled with spud mud down to 561 m, with seawater/gel/ lignosulphonate
from 561 m to 1371 m, with seawater/gypsum/ lignosulphonate from 1371 m to 3016
m, and with lignite/lignosulphonate from 3016 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>All objectives proved water bearing
according to logs and RFT measurements. The RFT data also showed that the
predicted pore pressures had been on the low side. The well was shut in two
times due to flow, but there was no pressure build-up. Grains of siltstone and
sandstone in cuttings the interval 1220 to 1260 had weak shows (fluorescence,
no cut). Fluorescence and cut were observed on sandstones from 3220 to 3290 m
in the Vestland Group. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the Vestland Group.
Core no 1 was cut from 3228 to 3243 m (recovered interval 3228.4 - 3636.6 m
corrected to loggers depth) and core no 2 was cut from 3267 to 3285.9 (recovered
interval 3267 m to 3285.9 m) corrected to loggers depth). One RFT run was
performed in the Middle Jurassic - Triassic Formations. Eleven pre-test samples
were obtained out of 19 sampling points. No wire line fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27
June 1982 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


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15/9-15


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-15 was drilled south of the
Sleipner Øst Field in the Viking Graben of the North Sea. The objectives were
to test possible hydrocarbon accumulations in Paleocene and Mesozoic sandstones
in the 15/9 My structure. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-15 was spudded with the
semi-submersible installation Ross Rig on 28 May 1982 and drilled to TD at 3200
m in the Triassic Skagerrak Formation. During drilling the 12 1/4&quot; section,
a significant volume of mud was lost at 2200 m. The thief zone was most
probably in the Frigg sand. 3 days were spent locating the zone and pumping LCM
pills. Otherwise no significant problem was encountered in the operations,
which proceeded with little downtime. The well was drilled with spud mud down
to 515 m and with gypsum/lignosulphonate mud from 515 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Paleocene sandstones were missing in
this well. The Mesozoic sandstones were encountered at 2806. The upper part
consisted of  tight Melke Formation sandstones without shows. From 2821 m (top
Skagerrak Formation) they were gas bearing down to a true gas/water contact at
2923 m. No oil shows were recorded outside of the hydrocarbon-bearing reservoir
in this well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut across the reservoir
from 2805 m in the Heather Formation to 2878.2 m in the Skagerrak Formation.
The core-to-log depth shift was 2.8 m for all four cores. RFT fluid samples
were taken at 282.5 m (gas, condensate and mud filtrate), 2838.5 m (gas,
condensate and mud filtrate), and at 2907 m (gas, condensate and mud filtrate)
fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
August 1982 as a gas and condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two Drill Stem Tests were performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2880 m to 2890
m. It produced 298000 Sm3 gas and 155 Sm3 condensate through a 32/64” choke.
The GOR was 1922 Sm3/Sm3, the condensate density was 0.760 g/cm3, and the gas
gravity was 0.718 with 0.2% CO2. The maximum temperature was 106.8 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2830 m to 2850
m. It produced 293900 Sm3 gas and 124 Sm3 condensate through a 28/64” choke.
The GOR was 2478 Sm3/Sm3, the condensate density was 0.757 g/cm3, and the gas
gravity was 0.710 with 0.5% CO2. The maximum temperature was 105.7 °C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Both Drill Stem Tests included a flow period
with a three-step multirate drawdown test. Check the well completion report and
well test report for further details, such as flow parameters for other
choke sizes. </span></p>


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15/9-16


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-16 was drilled on the Sleipner
Øst discovery in the southern Viking Graben of the North Sea. The primary
objective was to delineate the hydrocarbon accumulations in the Heimdal
Formation on the gamma structure. Sandstones of Jurassic/Triassic age were
secondary objectives. It was the fourth well drilled on this structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-16 was spudded with
the semi-submersible installation Deepsea Saga on 28 June 1982 and drilled to
TD at 3120 m, 52 m into the Permian Rotliegendes Group. The 9 5/8&quot; casing
had a leak at 522 m. It was squeezed twice with cement before it held a reduced
pressure. Otherwise, no significant problem was encountered in the operations.
The well was drilled with gel/seawater spud mud down to 515 m, with
gypsum/lignosulphonate mud from 515 m to 2652 m, and with a
seawater/lignite/lignosulphonate mud from 2652 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Heimdal was encountered at 2378 m. It
contained gas and condensate, but was thinner than expected. Pressure data
indicated a gas/water contact at 2434 m. The logs showed a sharp increase in
water saturation at 2428 m. Weak oil shows were recorded on cores between 2418
m and 2427.5 m. The prognosed sandstones of Jurassic/Triassic age were not
present at this location. Fair shows were recorded on cuttings in evaporites at
3014 m, at top Zechstein Group level. No shows were recorded on sidewall cores
from the same level.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 113.5 m of core (98% recovery)
was cut in seven cores in the interval 2382 to 2498 m. cores were cut and no
wire line logs were run in the well. An RFT fluid sample was taken at 2380 m
(good recovery), while attempts to sample at 2411m, 2413 m, and 2426 m gave
poor recovery.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24
August 1982 on as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



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15/9-17


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 was drilled on the Sleipner
Terrace in the Viking Graben of the North Sea. The primary objectives were to
test possible hydrocarbon accumulations in the Paleocene Heimdal Formation and
in Jurassic/Triassic sandstones. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-17 was spudded with the
semi-submersible installation West Vanguard and drilled to 3120 m in the
Triassic Smith Bank Formation. A 12 1/4&quot; pilot hole was drilled down to
519 m, but no indications of shallow gas was found. Bad weather caused some
delay. Bad weather and repeated BOP problems caused some down time. The well
was drilled with spud mud down to 500 m, with gypsum/polymer mud from 519 m to
2616 m, with Lignosulphonate/Drispac mud from 2616 m to 2950 m, and with
Drispac from 2950 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Both the Heimdal Formation and the
Mesozoic sandstones contained gas and were tested. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The log evaluation indicated top of the
hydrocarbon column in the Heimdal Formation at 2377.5 m. The logs indicated the
gas/water contact at 2418.5 m, while pressure data gave a gas/water contact a
bit shallower, at 2413 m. Weak and spotted shows were recorded on cored
sandstones in the Heimdal Formation below the contact down to 2425 m, and from
2442 to 2450 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the hydrocarbon column in the
Mesozoic sandstones was at 2715 m (top Vestland Group). The column extended
down into the Triassic. No definite gas/water contact was found but could be as
deep as 2848 m. Shows were recorded on cored sandstones throughout this
reservoir, getting weaker with depth. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No shows were seen outside of the
hydrocarbon bearing sections in the well</span></p>

<p class=MsoBodyText><span lang=EN-GB>Ten cores were cut. Cores 1 to 5 were cut
from 2382 to 2460 m. The recovery was 100% except for core 4, which had only
46% recovery. No core-log depth shift was required for these cores. Cores 6 to
9 were cut from 2714 to 2775.4 m with 100% recovery. The core-log shift was
from 1.1 m to 0.45 m. Core 10 was cut from 2810 to 2828.9 m with 100% recovery.
The core-log shift was 1.0 m. wire line logs were run in the well. RFT fluid
samples were taken at 2308.3 m (mud filtrate), 2729.3 m (gas, condensate and
mud filtrate), 2802.7 m (gas, condensate and mud filtrate), and 2844.8 m (gas,
condensate and mud filtrate).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 30 March 1983 as
a gas and condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2802 to 2814.5
m. It produced 590000 Sm3 gas and 210 Sm3 condensate /day through a 19.05”
choke. The GOR was 2800 Sm3/Sm3. Traces of sand and water were produced. Dräger
measurements indicated 0.5 - 1.0% of CO2 and no H2S. The downhole temperature
was 100 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2726.5 to
2741.5 m. It produced 570000 Sm3 gas and 205 Sm3 condensate /day through a
19.05” choke. The GOR was 2780 Sm3/Sm3. An average BSW of 0.5% was produced
throughout the test. Dräger measurements indicated 0.5% of CO2 and no H2S.The
downhole temperature was 97.8 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 2381.5 to 2414
m. It produced 525000 Sm3 gas and 280 Sm3 condensate /day through a 19.05”
choke. The GOR was 1875 Sm3/Sm3. Between 0.4 - 0.9% BSW was measured during the
final flow. No. CO2 and H2S was measured. The downhole temperature was 90 °C.</span></p>



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15/9-17 R


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 R is a re-entry of well
15/9-17 on the Sleipner Terrace in the Viking Graben of the North Sea. The purpose
of the re-entry was plugging and permanent abandonment.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-17 was re-entered with the semi-submersible
installation Ross Rig on 28 April 1991.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No significant problem was encountered in
the operations. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged and permanently
abandoned on 4 May 1991.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



1768
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15/9-18


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-18 is located between the
Sleipner Øst and Sleipner Vest Fields in the South Viking Graben in the North
Sea.</span></p>

<p class=MsoBodyText><span lang=EN-GB>It was designed primarily to test
hydrocarbon accumulations in the Middle Jurassic Hugin Formation. Secondary objectives
were Paleocene sandstones in the Heimdal and Sleipner Formations, and
sandstones of Triassic age. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-18 was spudded with the
semi-submersible installation Deepsea Bergen on 16 December 1983 and drilled to
TD at 3622 m in the Triassic Smith Bank Fm. No major problems occurred while
drilling this well, but some tight hole problems were experienced in the 12
1/4&quot; hole section. The well was drilled with seawater gel down to 520 m
and with gypsum/lignosulphonate mud from 520 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Tertiary sands were penetrated at 866 m
(Utsira Formation), 1254 m, and at 2071 m (&quot;Frigg Fm Equivalent&quot;). The
Draupne Formation was encountered 105 m thick at 3108 m. The Hugin Formation
was encountered at 3237 m. It was found hydrocarbon bearing in a 7.5 m interval
from 3237.5 m and down to a coal layer at 3245.0 m but the hydrocarbons were
immovable. The well did not encounter other hydrocarbon bearing intervals. Shows
were however recorded further down in the Hugin Formation in the interval 3275
m to 3325 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut, two in the Paleocene
and two in the Middle Jurassic sequence. Segregated FMT fluid samples were
taken in the hydrocarbon bearing interval in the Hugin Formation at 3238.3 m,
3239 m, and 3240 m. All samples were reported to recover mud filtrate only, but
the samples from 3240 m were analysed to contain 0.2 g petroleum hydrocarbons.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 2
March 1984 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>








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15/9-19 A



<p><b>General</b></p>

<p>The well 15/9-19 SR on the Theta Vest
structure North of the Sleipner East Field proved oil in the Hugin Formation in
1993. The objective for the well 15/9-19 A, a side-track from this well, was to
confirm a minimum economic hydrocarbon volume in the Hugin Formation and map
the extension of the oil-bearing formation. </p>
<p><b>General</b></p>

<p>The well 15/9-19 SR on the Theta Vest structure North of
the Sleipner East Field proved oil in the Hugin Formation in 1993. The
objective for the well 15/9-19 A, a side-track from this well, was to confirm a
minimum economic hydrocarbon volume in the Hugin Formation and map the
extension of the oil-bearing formation. </p>

<p><b>Operations and results</b></p>

<p>Well 15/9-19 A was kicked off from 2178 m
in well bore 15/9-19 SR on 25 July 1997, using the semi-submersible
installation Byford Dolphin. The well was drilled through the Skagerrak
Formation and terminated approximately 30 m TVD into the Triassic Smith Bank
Formation at 4131 m (3318.5 m TVD RKB). The final acquisition programme
immediately after reaching the total depth of the well was strongly affected by
a labour conflict, which delayed the well operations for 32.5 days. The
originally planned open hole electric logging program had to be terminated and
the 7&quot; casing run to TD in order to secure the well. The later cased hole
logging failed due to tool problems. The well was drilled oil based with the
Ultidril mud system (oil base consists of synthetic olefins) from kick-off to
TD.</p>

<p>Top of the Hugin Formation was penetrated
at 3796.5 m (3015.5 m TVD RKB) approximately 60 m TVD deeper than prognosed. It
was 153 m thick (TVD) and oil-bearing. The total oil column in the well was 80
m, but no clear oil-water contact was observed. The base of the reservoir was
at 3919 m (-3126.5 m TVD RKB). Seven cores were cut in the interval 3838 m to
4017 m in the Hugin and Skagerrak Formations, with a total recovery of 177.6 m.
One attempt was made to run FMT on PCL for pressure points and fluid sampling.
The run failed for technical reasons and no further attempts were made due to
the labour conflct.</p>

<p>The well was permanently abandoned on 9 November 1997 as an oil appraisal.</p>

<p><b>Testing</b></p>

<p>Three tests were performed in order to evaluate the well,
one in the water zone and two in the oil zone.</p>

<p>Test 1 at 3952 - 3958 m (3159.8 - 3165.5 m TVD RKB), was
in the water zone to obtain water samples due to MDT failure during wire line
logging. Four good samples were obtained, indicating similar formation water as
in other wells in the Sleipner area. Maximum recorded temperature in this test
was 112.7 deg C. </p>

<p>Test 2A at 3885.5 - 3888.5 m (3100 - 3102.5 m TVD RKB)
flowed 300 Sm3 oil and 27000 Sm3 gas /day through a 38/64&quot; choke during
the cleanup flow. The corresponding GOR was 90 Sm3/Sm3, the oil density was
0.892 g/cm3, and the gas gravity was 0.738 (air = 1) with 2.5 ppm H2S and 3% CO2.
The temperature recorded in this flow period was 112.3 deg C.</p>

<p>Test 2B at 3885.5 - 3888.5 m + 3826 -3865 m (3100 - 3102.5
m + 3046.2 - 3081.3 m TVD RKB flowed 528 Sm3 oil and 38107 Sm3 gas /day through
a 34/64&quot; choke during the main flow. The corresponding GOR was 72 Sm3/Sm3,
the average oil density was 0.902 g/cm3, and the average gas gravity was 0.730
(air = 1) with 2.8 ppm H2S and 3.5% CO2. The temperature recorded in this flow
period was 110.8 deg C.</p>
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15/9-19 B


<p><b>General</b></p>

<p>Well 15/9-19 B was drilled back-to-back
with 15/9-19 A. The -19 A well proved an 80 m oil column in the Hugin
Formation, and no OWC was found. Also, top Hugin Formation was found 62.5 m
deeper than prognosed in the former well. The overall well objective of 15/9-19
B was to obtain a better definition of the resource estimate of the Theta Vest
structure by identifying the oil-water contact, establish the pore pressure
east of the -19 A well, and to improve the seismic tie. </p>

<p><b>Operations and results</b></p>

<p>Sidetrack well 15/9-19 B was kicked off
from 2200 m in well bore 15/9-19 A on 9 November 1997, using the
semi-submersible installation Byford Dolphin. Well 15/9-19 A in turn, was
drilled as a sidetrack of well 15/9-19 SR drilled in 1993. The well 15/9-19 B
was drilled as an 8 1/2&quot; hole from the kick-off point to 3272 m. Due to
stuck pipe the string was severed and the well plugged back. A technical
sidetrack (15/9-19 BT2), was then made from 2911 m and drilled as 8 1/2&quot;
hole to 3220 m. A 7&quot; liner was set at 3198 m, and 6&quot; hole drilled to
well TD at 4250 m / 3360.5 m TVD RKB, approximately 30 m TVD into the Triassic
Smith Bank Formation. The originally planned open hole electric logging program
was performed in the 6&quot; hole section due to setting of 7&quot; liner. All
planned logs were run, and data obtained had generally good quality. Due to
casing-ringing data from the MAC log in 7&quot; liner is of poorer quality. The
well was drilled with the oil based Ultidril mud system from kick-off to TD.</p>

<p>The top of the Vestland Group, Hugin
Formation was penetrated at 4036 m (3174 m TVD RKB) approximately 100 m TVD
deeper than prognosed and 47.5 m deeper than the oil down-to contact in the -19
A well. The mismatch with the prognosis was due to wrong pick on the seismic.
Both the Hugin and the Sleipner Formations were present with a total thickness
of 156 m, of which the Hugin Formation was 126 m (TVD). The well is classified
as dry. However, in the Hugin Formation weak to fair shows from 4036 m and over
the cored intervals were reported.</p>

<p>Four conventional cores were cut in the
interval 4037 m to 4109 m in the Hugin Formation. The FMT measurements
confirmed a water gradient (0.1069 bar/m) in the Hugin sandstones, with a
pressure of approximately 1.09 g/cc equivalent mud weight. No formation fluid
samples were collected in the well.</p>

<p>The well was permanently abandoned on 2
February 1998 as a dry well with shows.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


3251
7/6/2016 12:00:00 AM
29.01.2023
15/9-19 S

<p><b>General</b></p>

<p>Wildcat well 15/9-19 S was the first well
to be drilled into the Theta Vest Structure north of the Sleipner East Field.
It was designed to test gas from the Heimdal reservoir, and to provide
geological and reservoir data enabling optimal reservoir management. The
secondary target was the Hugin/Skagerrak Sands, which were to be fully
evaluated if hydrocarbon bearing.</p>

<p><b>Operations and results</b></p>

<p>Well 15/9- 19 S was spudded with the
semi-submersible installation Treasure Prospect on 18 November 1992, from Slot
3 of the Loke Discovery template. The well was deviated, penetrating the top of
the Theta Vest structure approximately 2290 m west northwest of the Loke
Template, and reached the target Top Heimdal Formation at 3622.5 m (2427.0 m TVD
RKB). The 12 1/4&quot; section from 1482 m to 3580 m was drilled with
significant problems. Trips out of the hole at 2018 m, 3016 m and 3353 m were
performed to change the bits, due to low penetration rate. The hole packed of
several times when tripping out. Problems with lost returns and stuck BHA
finally led to plugging back and sidetracking from 1493 m. Attempts to
orientate the well became progressively more difficult, especially after
penetrating 3308.5 m in the Balder Formation. The Lista Formation was encountered
at 3483 m, and final TD was set at 3580 m, at the edge of the Heimdal Formation
target. The well was drilled with bentonite mud down to 531 m, and with
KCL/POLYMER (Phpa/pac) mud from 531 m to TD in the first hole. After
sidetracking oil based mud (Petrofree) was used.</p>

<p>The well penetrated 150 m TVD of Tertiary
sands between 1313 m and top Balder Formation at 3302 m. </p>

<p>It was temporarily suspended on 31
January 1993 after setting 9 5/8&quot; casing at 3569.0 m (2394.0 m TVD RKB),
immediately above the Heimdal sands. No cores were cut and no fluid samples
taken in this well bore. It is classified as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



2043
7/6/2016 12:00:00 AM
29.01.2023
15/9-19 SR




<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The re-entry 15/9-19 SR is a continuation
of wildcat well 15/9-19 S, which was temporarily suspended at 3569.0 m (2394.0
m TVD RKB), immediately above the Heimdal sands. The target of the well was the
Theta Vest Structure north of the Sleipner East Field. The primary objective
was to test gas from the Heimdal reservoir, and to provide geological and
reservoir data enabling optimal reservoir management. The secondary target was
the Hugin/Skagerrak Sands, which were to be fully evaluated if hydrocarbon
bearing. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9- 19 S was re-entered (15/9-19
SR) with the semi-submersible installation Treasure Prospect on 17 February
1993, from Slot 3 of the Loke Discovery template. The well was drilled to TD at
4641 m (3132.3 m TVD RKB) in the Triassic Skagerrak Formation. No significant
technical problems were encountered in this well bore. The well bore was
drilled with oil-based mud (Petrofree).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Heimdal sandstone was penetrated at
3623 m (2427 m TVD RKB), 50 m low to prognosis. This Formation was the main
target in the well. No hydrocarbons were encountered. The Hugin Formation was
penetrated at 4317 m (2886 m TVD RKB), 2 m low to prognosis. The entire Hugin
Formation was oil filled (18 m TVD). The core from this formation was filled
with H2S (650 ppm). Sandstones of the Skagerrak Formation were water wet. No
shows were recorded due to invasion of petrofree mud. </span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 3643 m to 3648 m in
the Heimdal Formation, and two cores were cut from 4328 m to 4383 m in the
Hugin and Skagerrak Formations.No fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 29 March 1993
as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>One Drill Stem Test from the interval
4316 to 4338 m in the Hugin Formation was performed. The test produced 680 Sm3
oil /day through a 12.7 mm choke. The GOR was 98 Sm3/Sm3, the oil density was
0.870 g/cm3, and the gas gravity was 0.740 (air =1)</span></p>











































2105
7/6/2016 12:00:00 AM
29.01.2023
15/9-19 SR2


<p><b>General</b></p>

<p>The re-entry 15/9-19 SR2 is a Re-entry of
well 15/9-19 SR, which was suspended in 1993 without testing, after having
discovered oil in the Middle Jurassic Hugin Formation. The objective of the
re-entry was plug back before sidetracking (15/9-19 A) for evaluation of the
Hugin discovery.</p>

<p><b>Operations and results</b></p>

<p>Well 15/9-19 SR was re-entered (15/9-19
SR2) on 18 July 1997 with the semi-submersible installation Byford Dolphin
through slot 3 on the Loke template. </p>

<p>The well bore was plugged back and
permanently abandoned on 25 July 1997.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



3180
7/6/2016 12:00:00 AM
29.01.2023
15/9-2
<html>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-2 was drilled on the Sleipner
Vest Field in the North Sea. The primary objective was to test the &quot;beta
closure&quot; on the 15/6-3 Sleipner Vest discovery. The target was Middle
Jurassic sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-2 was spudded with the semi-submersible
installation Ross Rig on 12 April 1978 and drilled to TD at 3764 m in Late
Triassic sediments in the Skagerrak Formation. The main problem in operations
was the discovery of a washout in the well head 18 3/4&quot; ax seal area after
setting 9 5/8&quot; casing. This was repaired so that drilling could proceed,
but it was decided not to do the planned DST due to possible leak. Otherwise,
operations proceeded without significant problem. The well was drilled with seawater
and gel down to 644 m and with gel and lignosulphonate from 644 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Vestland Group, Hugin Formation was
encountered at 3483 m. The Hugin Formation contained gas/condensate down to the
OWC between 3652 and 3654 m based on logs and pressure gradients. Weak shows
continued down to 3659 m, 2 meters into top Sleipner Formation. Two spots of
dead oil and fluorescence on limestone/siltstone cuttings at 2788 and 2812 m in
the upper Shetland Group were the only other shows described in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 186.3 m core was recovered in
11 cores from the interval 3498 m to 3692 m. RFT fluid samples were taken at
3490 m ((gas, condensate, water), 3535,7 m (gas and condensate), 3601.6 m (gas,
condensate, water), 3640.4 m (gas, condensate, water), 3641 m (gas, condensate,
water), 3641.5 m (gas, condensate, water), 3644 m (gas, condensate, water),
3652 m (gas, condensate, water), and 3654 m (water). The condensate gravity in
the samples varied from 50.3 °API in the shallowest sample to 45.5 °API in the
sample just above the OWC.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17
June 1978 as a gas/condensate well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



323
7/6/2016 12:00:00 AM
29.01.2023
15/9-20 S


<p><b>General</b></p>

<p>Wildcat well 15/9-20 S was drilled from
the Sleipner A platform on the Sleipner øst Field. It started off as
development well 15/9-A-22, which was designed to provide gas production from
the Heimdal reservoir in the central part of the Sleipner Øst Field, and to
contribute with geological and reservoir technical data for optimal reservoir
management in this area. Due to unexpected geology in the deeper part of the
well the Cretaceous and below was reclassified to exploration well 15/9-20 S.</p>

<p><b>Operations and results</b></p>

<p>Well 15/9-20 S was spudded from the fixed
installation Sleipner A on 16 February 1994 and drilled deviated to TD at 3624
m in the Triassic Smith Bank Formation. No significant problems were reported
from the operations. The well was drilled with seawater/PAC mud from below
26&quot; conductor to 506 m, with KCl/PHPA/PAC mud from 506 m to 1735 m, with
KCl/PHPA/PAC/Glycol mud from 1735 m to 2928 m, and with ester mud from 2928 m
to TD. No shallow gas was encountered.</p>

<p>The well penetrated the Heimdal Formation
target at 2931 m (2279.6 m TVD MSL), 11.6 m TVD deeper than prognosis. The
Heimdal Formation was 104 m thick (71.2 m TVD) and proved to be gas filled as
expected. Under the Heimdal Formation the well drilled 204 m Late Cretaceous
limestone overlying 8 m Blodøks Formation. At 3247 m (2490.2 m TVD MSL) the
well drilled unexpected into Jurassic/Triassic sandy sediments, which proved to
have a 30 - 50 m TVD hydrocarbon leg.</p>

<p>Five conventional cores were cut from
2940 - 3043 m in the Heimdal and into the top of the Tor Formation. A sixth
core was cut from 3216 - 3244 m, from base Hod Formation and into the Blodøks
Formation. One RFT segregated sample was taken at 3272.6 m in the Skagerrak
Formation.</p>

<p>Well bore 15/9-20 S was plugged back and
permanently abandoned on 1 June 1994 as a gas discovery.</p>

<p><b>Testing</b></p>

<p>The well was perforated on wire line over
the interval 3229 - 3238 m in the base of the Hod Formation and stimulated with
acid, but the result was negative and the interval was plugged. Two drill stem
tests were performed in the Heimdal Formation sandstone. DST 1 tested the
interval 2942 - 2956 m and DST 2 tested the interval 2933 - 2942 m.</p>



2319
7/6/2016 12:00:00 AM
29.01.2023
15/9-21 S


<p><b>General</b></p>

<p>Well 15/9-21 S was drilled from the
Sleipner Vest wellhead facility. The well was designed deviated to appraise the
oil potential of the Hugin Formation east of the main Sleipner Vest Field.
Another objective was to further appraise the Hugin Formation oil in the
Sleipner Vest area, which had been discovered in well 15/9-B-4 T2.</p>

<p><b>Operations and results</b></p>

<p>The 24&quot; section of well 15/9-21 S
was spudded from the batch-set 32&quot; conductor on 23 March 1998. Using the
jack up installation West Epsilon the well was drilled to TD at 5126 m in the
Middle Jurassic Sleipner Formation. No significant problems were reported from
the operations. The well was drilled with PAC/seawater down to 506 m, with
Aquadril KCl/glycol mud from 506 m to 3457 m, and with oil based mud from 3457
m to TD.</p>

<p>The target was penetrated approximately
2670 m east of the platform centre, at a depth of 4736.5 m (3592.0 m SS), 19.6
m deep to prognosis. The first 30 m of the target sandstone drilled was Intra
Heather Sandstone. The Hugin Formation was penetrated at 4767 m. Only minor
hydrocarbons were found. Oil shows, partly masked by the oil based mud, was
observed on the cores from the Hugin Formation. The strongest shows were seen
in the interval 4784 to 4798 m where oil slowly seeped from the core. </p>

<p>Four cores were cut from 4747 m in the
Intra Heather Formation Sandstone to 4843 m in the Hugin Formation. No wire
line fluid samples were taken.</p>

<p>The well was permanently abandoned on 23
May 1998 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


3334
7/6/2016 12:00:00 AM
29.01.2023
15/9-22


<p>Well 15/9-22 is located just south of the
Sleipner Vest field in the South Viking Graben of the North Sea. The primary
objective of the well was to test the hydrocarbon potential of the Wishbone NE
prospect, which was a stratigraphic pinch out trap. The key risks for the
prospect were reservoir adequacy (Hugin Formation) and lateral seal. The
primary reservoir target was the Upper Hugin Formation (Middle Jurassic
Vestland Group), with Middle Jurassic Lower Hugin Formation, Sleipner Formation
and Triassic as secondary targets. The anticipated hydrocarbon type was gas
with condensate.</p>

<p><b>Operations and results</b></p>

<p>Well 15/9-22 was spudded with the
semi-submersible installation Ocean Vanguard on 1 January 2006 and drilled to
TD at 3915 m (3923 m logger?s depth), 167 m into the Triassic Skagerrak
Formation. A 36&quot; hole was drilled and 30&quot; conductor was successfully
run and cemented at 201 m. Due to the probability of shallow gas, a 26&quot;
hole was drilled to 508 m and a 20&quot;x18 5/8&quot; casing string set at 204 m.
The BOP and riser were run and tested after considerable delays for repairs and
waiting on weather. The 17 1/2&quot; hole was drilled to 1531 m, and no shallow
gas was seen. The 13 5/8&quot; surface casing was run and became stuck at a
depth of 953 m. The casing was cut and fished out of hole from 601 m and a
kick-off plug set from 592 m to inside of the 18 5/8&quot; casing at 410 m. The
hole was sidetracked (15/9-22 T2) at 522 m on Jan 31 2006, and the new hole was
drilled to TD without further significant problems. The well was drilled with
seawater down to 508 m and with Glydril KCl mud from 508 m to TD. </p>

<p>The lithostratigraphic tops below 410 m,
as given on this fact page, are from the sidetrack. The Hugin Formation was
encountered at 3572 m. It was 141 m thick, of which 40 m had average porosity
of 18.1%. From wire line interpretation possible residual hydrocarbon
saturation was reported in the uppermost porosity intervals in the Hugin
Formation, but otherwise the only hydrocarbon indication in the well was a
strong hydrocarbon odour from a cuttings sample from 3408 m in the Draupne
Formation. MDT pressures were taken. A dry hole case logging program was performed.
No conventional cores or sidewall cores were taken.</p>

<p>The well was permanently abandoned on 13
March 2006 as a dry well.</p>



5174
4/11/2017 12:00:00 AM
29.01.2023
15/9-23


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-23 was drilled in the southern
Viking Graben, south of the Sleipner East Field in the North Sea. The primary
objective was to test the Middle Jurassic Hugin and Sleipner formations and the
Triassic Skagerrak formation within the Skardkollen prospect. The Early
Paleocene Ty Formation was secondary objective.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-23 was spudded with the
semi-submersible installation Bredford Dolphin on 18 November 2009 and drilled
to TD at 3225 m in late Triassic sediments of the Skagerrak Formation. A 9
7/8&quot; pilot hole was drilled from the 36&quot; section to 714 m and a
shallow gas zone was encountered at 674 to 678 m. The hole was opened to
26&quot; down to 556 m, and 20&quot; casing was set at 550 m. The well was drilled
with seawater and hi-vis sweeps down to 556 m, with KCl/Glycol mud from 556 to
1520 m, and with XP-07oil based mud from 1520 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the first Frigg Formation sand
was penetrated at 2092 m. The secondary target, the Ty Formation of the lowermost
Rogaland Group was penetrated at 2524 m. The Ty Formation constituted excellent
reservoir sandstones with a gross thickness of 24 m. GeoTap pressure
measurements detected a pore pressure depletion of 105 bar compared to a normal
hydrostatic gradient, most likely related to production at the nearby Sleipner
East Field within the same stratigraphical unit. The primary reservoir target,
the Middle-Jurassic Vestland Group, was penetrated at 3087.5 m, 45.5m deeper
than anticipated. The Hugin Formation was absent, and the top of the Vestland
Group consisted of the coal-bearing Sleipner Formation. Firm identification of
red-brown Triassic mudstones of the Skagerrak Formation was penetrated at 3169 m,
5.5m shallower than prognosed. GeoTap pressure measurements through the Sleipner-
and Skagerrak Formations also detected higher overpressures (65-73-89 bar) than
measured in the nearby, analogue wells. The high and vertically varying
overpressures, in combination with the low N/G and inferred poor/non-effective
sand-to-sand connectivity, may explain the failure of hydrocarbons migrating
into the Skardkollen structure. </span></p>

<p class=MsoBodyText><span lang=EN-GB>All reservoirs were water-wet. The only
show recorded in the well was a very weak show on cuttings in the Sleipner
Formation. Lack of supportive from logs and gas levels suggested that the show
could be caused by the drilling fluid.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No logs were run on
wire line, all logs are from LWD. No fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3
January 2010 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



6186
4/11/2017 12:00:00 AM
29.01.2023
15/9-24


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-24 was drilled just south of
the Sleipner Terrace in the southern Viking Graben of the North Sea. The main
objective was to test the hydrocarbon potential of the Storkinn prospect. The
main reservoir target was the Paleocene Heimdal-/Ty formations, south-east and
up dip to the Sleipner Øst Field. The prognosed top of the Heimdal / Ty formations
was at 2310 m.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-2 was spudded with the
semi-submersible installation Bredford Dolphin on 18 May 2010 and drilled to TD
at 2400 in the Late Cretaceous Tor Formation. The 26&quot; section was drilled
first as a 9 7/8&quot; pilot hole in case of shallow gas. Due to low wind
speeds at the moment 10 hours were spent WOW before the pilot could commence.
No shallow gas was observed, and the drilling operations went forth without
significant problems. The well was drilled with Seawater and Hi-Vis Sweeps down
to 627 m, with KCL/GEM Glycol Mud from 627 to 1496 m, and with XP-07 Oil Based
Mud from 1496 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Heimdal-/Ty Formation sandstones were
not observed in the well. No hydrocarbon shows were observed in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. The well was logged
with MWD/LWD; no wire line logs were run. No fluid samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 10
June 2010 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



6381
4/11/2017 12:00:00 AM
29.01.2023
15/9-3


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well was drilled on the northwestern part
of the Sleipner Vest structure in the Viking Graben of the North Sea. The
objective was to test hydrocarbons in the “Alpha structure” of the Sleipner
field. The target was Middle Jurassic sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-3 was spudded with
the semi-submersible installation Ross Rig on 17 December 1978 and drilled to
TD at 3796 m in the Triassic Skagerrak Formation. Many problems were
encountered in the operations. When drilling the 26&quot; interval, the
circulation was lost several times. Pumping lost circulation material pills and
cement into the formation solved this. The main problem arose when drilling the
8 1/2” interval.  At 3375 m on top of Upper Jurassic, an abnormally pressured
impermeable zone was penetrated. Due to a series of technical problems that
followed this incident, the well was finally plugged back and sidetracked from
1213 m. Furthermore, the well was drilled in the wintertime and the cold was
quite severe. Because of this, the hydraulic control system for the BOP stack
froze on one occasion. Functional problems with the BOP pods were experienced,
consequently, the time and cost estimates, were seriously exceeded. The well
was drilled with spud mud down to 402 m, with gel/lignosulphonate from 402 m to
2680 m and with gel/lignosulphonate/lignite mud from 2680 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Middle Jurassic Vestland Group, top
Hugin Formation, was encountered at 3498 m. Well 15/9-3 proved very poor
reservoir qualities in these strata and the well was hence not production
tested. A cluster of RFT pressure data points suggested a light hydrocarbon gradient
of 0.11 - 0.25 psi/ft. between 3600 m and 3612 m. Between 3650 m and 3682 m a good
&quot;heavier&quot; hydrocarbon gradient of 0.35 psi/ft. was established. This
indicates a hydrocarbon/water contact approximately at 3682 m. Very weak
spotted shows were described over this section and down to 3709 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut from the interval
3511 to 3580 m in the Hugin Formation. RFT fluid-sampling chambers recovered six
samples, all containing mud filtrate with minor amounts of gas. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3
April 1981 and was classified as dry with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


324
7/6/2016 12:00:00 AM
29.01.2023
15/9-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-4 was drilled on in the southeastern
part of the Sleipner Vest area in the Viking Graben of the North Sea. Previously
four wells had been drilled on the Sleipner Alpha structure in the north. Two
of these showed significant gas-condensate accumulations (15/6-3 and 15/9-1) in
the middle Jurassic while in the western part of the Alpha structure the sand
had shaled out (15/9-3). In the northeast, the sand was penetrated below the
hydrocarbon/water contact (15/6-5). The first well drilled on the Beta prospect
(15/9-2) showed a significant gas-condensate column in the middle Jurassic
sand. The primary objective for well 15/9-4 was to test possible hydrocarbons
in Middle Jurassic sandstones in the southeast extending Delta structure.   </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-4 was spudded with the semi-submersible
installation Ross Rig on 4 April 1979 and drilled to TD at 3716 m in the
Triassic Skagerrak Formation. Very few problems were encountered during
drilling of this well, with the exception of lost circulation in the 26&quot;
interval. This problem was solved by pumping cement into the formation. The
main problem arose only after drilling the 8 1/2” interval. The 7&quot; liner
was run and cemented sucessfully. When pressure was applied in order to test
the liner lap, the 9 5/8&quot; casing burst. The well was drilled with spud mud
down to 415 m and with gel/lignosulphonate mud from 402 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top of the Middle Jurassic Vestland
Group, Hugin Formation was penetrated at 3441 m. The section contained
sandstones with good reservoir properties interbedded with some thin shale
beds. The sandstones were hydrocarbon bearing with a gas-water contact at ca
3570 m, 7 m into the Sleipner Formation. Weak oil shows were described
throughout the hydrocarbon-bearing reservoir down to 3582 m. Shows were not
described in any other section of the well. The Triassic Skagerrak Formation
was encountered at 3629 m with some small water bearing sand intervals.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Nine cores were cut in the interval 3457
to 3594.8 m in the Hugin and Sleipner formations. The core-log depth shift is
reported as -2.5 m for all cores. Overall recovery was 132.1 m core (98.2%). An
RFT fluid sample was taken at 3481 m. It contained gas, condensate, mud and
water.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
June 1979 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was not production tested, due
to technical problems.</span></p>



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15/9-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-5 was drilled in the Sleipner
Vest area in the Central Graben of the North Sea. The objective was to test
hydrocarbons in Middle Jurassic sandstones in the Beta structure of Sleipner
Vest. The well is Reference Well for the Heimdal and Våle formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-5 was spudded with
the semi-submersible installation Norskald on 19 November 1979 and drilled to
TD at 3946 m in the Triassic Skagerrak Formation. Operations met with many
problems, but the well objectives were fulfilled in the end. Excessive drag
when pulling core barrel out of reservoir was a severe problem, and
consequently frequent reaming and circulating trips was needed. Having finished
logging in the 8 1/2” section, and just started testing the BOP stack, one of
the riser tension sheaves broke and fell down. Also several problems with the
hydraulic BOP control system and the ball joint made nearly 12 days rig repair
necessary. After this delay the hole required extensive reaming before the 7”
liner could be ran and the final 6” section could be drilled. Testing
operations were hampered and delayed by bad weather and test equipment
breakdown. The well was drilled with spud mud down to 426 m and with
seawater/lignosulphonate mud from 426 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well proved gas in sandstones of Middle
Jurassic age from top Hugin Formation at 3526 m down to a true gas/water
contact at 3662 m, based on logs and RFT samples. The Sleipner Formation was
encountered at 3693 m. Logs and RFT pressure gradient proved Sleipner water
filled, and ca 3 bar overpressured compared to the Hugin Formation. Shows were
described on cores all through the hydrocarbon bearing reservoir. Abundant
spots of fluorescence described on cuttings below ca 2000 m are described as
“no shows”. According to other comments in the cuttings descriptions the
fluorescence may be related to diesel addition to the mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Nine cores were cut in the interval 3525
to 3663.6 m. A total of 133 m core (96.8%) was recovered. A FIT fluid sample at
3536 m recovered gas, condensate and mud. An RFT fluid sample was taken at 3540
m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 11
April 1980 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three Drill Stem Tests were conducted.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3642 m to 3646.6
m. The final flow was controlled by using two variable chokes mounted in
parallel. On the smallest choke size, 2x25/64”, the well produced 583000 Sm3
gas and 181 Sm3 condensate /day. The GOR was ca 3200 Sm3/Sm3, the oil density
was 45.3 °API, and the gas gravity was 0.774 (air = 1).</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3605 to 3610 m
plus 3613 to 3618 m. The final flow was controlled by using two variable chokes
mounted in parallel. On the smallest choke size, 2x28.75/64”, the well produced
699400 Sm3 gas and 189 Sm3 condensate /day. The GOR was ca 3700 Sm3/Sm3, the
oil density was 45.4°API, and the gas gravity was 0.773 (air = 1). The CO2
content was 9.2%. Maximum temperature during this test was 122.8 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST3 tested the interval 3536 to 3546 m.
The final flow was controlled by using two variable chokes mounted in parallel.
The choke size was kept at 2x45.5/64” throughout the whole flow. The well
produced 815500 Sm3 gas and 212 Sm3 condensate /day. The GOR was ca 3850
Sm3/Sm3, the oil density was 40 °API, and the gas gravity was 0.771 (air = 1). The
CO2 content was 7.7 %.  Maximum temperature during this test was 117.8 °C. </span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



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15/9-6


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-6 was drilled in the Sleipner
Vest area in the Viking Graben of the North Sea. The objective of the well was
to test possible hydrocarbons in Middle Jurassic sandstones on the northern
flank of the 15/9-Beta structure, and to get more information about the sand
distribution in this area.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-6 was spudded with
the semi-submersible installation Nordskald on 7 May 1980 and drilled to TD at
3946 m in the Triassic Skagerrak Formation. No significant problem was
encountered in the operations. The well was drilled with seawater and
pre-hydrated gel down to 465 m, with sweater/gel and SSP lubricant (a vegetable
oil) from 465 m to 1140 m, and with gel lignosulphonate/SSP lubricant from 140
m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top of the target reservoir sandstones (Callovian
age Hugin Formation) was found at 3762 m. This was deeper than expected and below
the field gas-water contact. The sandstones were also thinner than expected. Isolated
spots of shows on sandstones were described on cuttings and cores from the Hugin
and Sleipner formations and the Upper part of the Skagerrak Formation. One
cuttings sample from 3346 m in the Blodøks Formation was described with good
show on sandstone.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from
3768.5 m to 3781.4 m in the Hugin Formation (75% recovery) and core 2 was cut
from 3810 m to 3814.5 m in the Sleipner Formation (37% recovery). An RFT fluid
sample was taken at 3774 m in the Hugin Formation. Laboratory analysis
indicated the content to be a mixture of formation water, mud, and fresh water
from the water cushion in the sampler. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
September 1980 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



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15/9-7
<html>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-7 was drilled as an appraisal
well on the south part of the Sleipner Vest Field in the North Sea. The primary
objective was to test for hydrocarbons in Callovian age sandstones in the
Epsilon structure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-7 was spudded with
the semi-submersible installation Nordraug on 26 December 1980 and drilled to
TD at 3776 m in the Middle Jurassic Sleipner Formation. A total of 20 days was
spent on waiting on weather. The phase of running BOP after cemented 20&quot;
casing took 15 days due to several broken guide wires combined with bad
weather. The well was drilled with spud mud down to 465 m, with gypsum/polymer
mud from 465 m to 2823 m, and with gel/lignosulphonate/Drispac mud from 2823 m
to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The primary target Hugin Formation was
penetrated at 3519 m and proved to hold gas and condensate down to a true gas/water
contact at 3673 m based on RFT gas gradients. The gross reservoir thickness was
185 m (3519 to 3704 m) with a net pay of 83 m with 18% porosity and 12 % water
saturation. There were no oil shows above top Hugin reservoir level. Oil shows
were described on the cores from the reservoir and on cuttings down to 3677 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 156 m core was recovered in 12
cores from the interval 3516 to 3671 m. The core-log depth shift was
significant for all cores: from +6.0 to +9.1 meter, the largest shifts are for
the deepest cores. Segregated RFT fluid samples were taken at 3560 m (gas, mud
filtrate and condensate), 3603 m (gas, mud filtrate and condensate), 3658.5 m
(gas, mud filtrate and condensate +dark oil emulsion), 3687 m (mud filtrate,
formation water and minor gas), and 3672.2 m (mud filtrate and water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
April 1981 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three drill stem tests were performed in
the Hugin Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST1 tested the interval 3671 to 3674.5
m. It produced 194100 Sm3 gas and 38 Sm3 condensate /day through a 24/64&quot;
choke. The GOR was 5107 Sm3/Sm3, the condensate density was 0.797 g/cm3 and the
gas gravity was 0.78 (air = 1). The gas contained 7-8% CO2. The maximum
temperature in the test was 127.8 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST2 tested the interval 3637 to 3638.5 m.
It produced 322500 Sm3 gas and 93.2 Sm3 condensate /day through a 24/64&quot;
choke. The GOR was 3461 Sm3/Sm3, the condensate density was 0.790 g/cm3 and the
gas gravity was 0.775 (air = 1). The gas contained 7-8% CO2. The maximum
temperature in the test was 121.1 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST3 tested the interval 3555 to 3565 m.
It produced 912900 Sm3 gas and 242.8 Sm3 condensate /day through a 64/64&quot;
choke. The GOR was 3760 Sm3/Sm3, the condensate density was 0.792 g/cm3 and the
gas gravity was 0.775 (air = 1). The gas contained 8-9% CO2. The maximum
temperature in the test was 118.3 °C.</span></p>


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15/9-8


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-8 was drilled on the Delta
structure in the southeastern part of the Sleipner West Field in the North Sea.
 The primary objective was to delineate the hydrocarbon accumulation
encountered in the 15/9-4 well on the same structure, and to get further
information about the sand distribution in the area. The primary target was Callovian
sandstones. Paleocene sandstone was the secondary target.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 15/9-8 was spudded with
the semi-submersible installation Nortrym on 5 March 1981 and drilled to TD at
3730 m in the Triassic Smith Bank Formation. Operations proceeded without
significant problems. The well was drilled with seawater and hi-vis pills down to
495 m, with gypsum/polymer mud from 495 m to 2845 m, and with a
gel/lignosulphonate mud from m 2845 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The sandstones in Paleocene were water
bearing. Top of the Callovian sandstone, Hugin Formation, was encountered at
3446 m, while top Sleipner Formation was encountered at 3493 m. Bothe formations
proved to be gas/condensate bearing with a gas-water contact at 3564 m based on
pressure gradients and well logs. No shows were recorded outside of the
hydrocarbon bearing Hugin and Sleipner Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 46.5 m core was recovered in
four cores from the interval 3448 to 3499 m. Segregated RFT fluid samples were
taken at 3460 m (gas, condensate and mud filtrate), 3561.5 m (gas, condensate
and mud filtrate), and 3566.5 m (mud filtrate and a smaller quantity of gas).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25
May 1981 as a gas/condensate appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One Drill Stem Test was performed from
the interval 3450 to 3460.2 m in the Hugin Formation. The test produced 255 Sm3
condensate and 820000 Sm3 gas /day through a 91/64&quot; choke. The gas/condensate
ratio was 3200 Sm3/Sm3, the condensate gravity was 0.78 g/cm3, and the gas
gravity was 0.74 (air = 1). The CO2 content was 6-7%. The DST temperature was
121 °C. </span></p>



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15/9-9


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 15/9-9, was drilled on the Sleipner
Terrace in the North Sea. The primary objective was to test possible hydrocarbons
in Jurassic sandstones on the 15/9-Gamma structure and to get more information
about the sand distribution in the area.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 15/9-9 was spudded with the semi-submersible
installation Nordraug on 4 May 1981 and drilled to TD at 3044 m in the Early-Middle
Permian Rotliegendes Group. No significant problems were experienced in operation,
logging or testing of the well. The well was drilled with seawater and pre-hydrated
gel down to 501 m, with gel/lignosulphonate from 501 to 1155 m, with
gypsum/polymer mud from 1155 m to 2540 m, and with gel/lignosulphonate from 2540
m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The primary objective, the Jurassic, was
thinner than expected and consisted of Late Jurassic Viking Group shales only.
The well, however, proved gas and condensate in the Heimdal Formation. The
Heimdal Formation was reached at 2322 m. It consisted of sand of fairly good
reservoir properties interbedded with some thin shale beds. The whole sand
interval was hydrocarbon bearing and no water contact was located. In addition,
the well proved residual hydrocarbons over the interval 2648 to 2738 m on cores
from the Triassic Skagerrak Formation. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. The interval 2648
to 2756 m was cored in six cores with 98 - 100% recovery. A seventh core was
cut from 3032 to 3043.5 m with 96% recovery at TD. RFT segregated samples were
taken at 2323 m (condensate and mud filtrate) and 2648 m (water and mud
filtrate, no gas or condensate). Repeated attempts to sample in the interval
2401 to 2414 all failed due to plugging of probe by unconsolidated sand.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
July as a gas/condensate discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three drill stem tests were performed. </span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 2414 to 2421 m.
This test gave no flow to surface and it was aborted due to malfunctioning
downhole valves. The maximum downhole temperature measured by the gauges was 85.6
°C</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 2386 to 2392 m.
This test produced 286 Sm3 condensate and 586200 Sm3 gas /day through a
1.0&quot; choke (max flow).  No H2S and only traces of CO2 was measured. The
GOR was 2050 Sm3/Sm3, the condensate gravity was 57.7 °API and the gas gravity
was 0.734. The bottom hole temperature measured by the Flopetrol gauge was 87.8
°C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 3 tested the interval 2323 to 2333 m.
This test produced 272 Sm3 condensate and 587000 Sm3 gas /day through a
1.0&quot; choke (max flow).  No H2S and only traces of CO2 was measured. The
GOR was 2160 Sm3/Sm3, the condensate gravity was 60.7 °API and the gas gravity
was 0.740. The maximum down hole temperature measured by the gauges was 93.9
°C.</span></p>


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16/10-1


<p><b>General</b></p>

<p>Well 16/10-1 was the first well drilled
in block 16/10 operated by Norsk Agip. Among the various structures defined
within block 16/10, the one called &quot;Alpha&quot;, located in the
southwestern area, was selected as the first one to be drill. Main reason for
this choice was the presence of a deep basin (Witch Ground Graben) to the south
west of the block, where the Viking Group shales was believed to have generated
hydrocarbons since Cretaceous time. The tectonic evolution of the structure is
probably of pre-Cretaceous age, well before hydrocarbon generation started.</p>

<p>The purpose of the well was to explore
all main reservoirs down to Triassic. The primary targets were the Jurassic and
Triassic sandstone units, expected at 2850 m and 2980 m, respectively.
Prognosed TD was at 3175 m.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/10-1 was spudded 25 May
1986 by Dyvi Offshore A/S semi-submersible rig Dyvi Stena and drilled to TD at
3151 m in the Late Permian Zechstein Group. The well was drilled with Seawater
and hi-vis pills down to 514 m, with KCl/Polymer mud from 524 m to 2565 m, and
with lignosulphonate mud from 2565 m t TD. Drilling proceeded without any
significant problems. Electrical logs were run already in the 26&quot; section
from 195 m. No shallow gas was encountered. </p>

<p>The Quaternary/Tertiary sequence, 2280.5
m thick, is represented by Nordland, Hordaland and Rogaland groups and is
predominantly constituted by marine claystones. A 513.5 m Cretaceous section
represented by the limestones of the Chalk Group and by the reddish marl and
calcareous shales of the Cromer Knoll Group was penetrated. It was nearly a
complete sequence except for two possible hiatus: the first in the Late
Santonian and the second between the Cenomanian and the Aptian-Albian. The base
Cretaceous Unconformity overlies the Late Jurassic shales of the Viking Group
(top at 2794 m), which proved to have a thickness of 211 m. The top of the
Jurassic sandstones of the Vestland Group was encountered at 3005 m. The
&quot;Oxfordian Sandstone Unit&quot; (Hugin Formation) was 33m thick with very
good reservoir properties. Below this was a 15 m thick &quot;coal unit&quot; of
the Sleipner Formation, containing a major coal sequence with interbedded
carbonaceous claystone/shale. Below the Mid Kimmerian Unconformity, a 58 m
thick sequence of arenaceous sediments of the Triassic Skagerrak Formation was
drilled. The interval was a monotonous sequence of clastics, with the typical
continental red iron colour. At 3116 m the top of the Permian evaporites of the
Zechstein Group was touched and penetrated until the depth of 3151 m (TD). Two
cores were cut in the Heather Formation, the first from 2855 m to 2873 m, and
the second from 2925 m to 2934 m. No fluid samples were taken. The well was
permanently abandoned on 14 July 1986 as a dry hole.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



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16/10-2

<p><b>General</b></p>

<p>Block 16/10 is located in a structurally
complex area between the Viking Graben, the Central Graben, the Witch Ground
Graben and the Ling Graben.  Well 16/10-2 is the second well drilled in block
16/10 PL 101 operated by Norsk Agip; the first one 16/10-1 was drilled May-July
1986. The purpose of the well was to test the hydrocarbon potential of the
&quot;Delta&quot; structure located in the west part of 16/10 block. This
structure is a tilted fault block elongated north-south bounded to the west by
a north-south trending normal fault, and dip-closing to the north, east and
south. It was interpreted as the largest structure in block 16/10 in terms of
possible oil reserves. The structure is not salt-induced and being one of the
oldest in this area it was also considered prospective for possible early
migration. The Upper Jurassic and the Lower Cretaceous shales constituted the
seal rocks for the geological model. The main and the secondary targets were
respectively the &quot;Oxfordian Sandstones&quot; (Upper Jurassic) and the
Triassic sandstones of the Skagerrak Formation that had been found hydrocarbon
bearing in the nearby blocks in wells 6/3-1, 15/12-5, 15/12-4, 15/12-8, 15/12-6
and 16/7-4.</p>

<p><b>Operations and results</b></p>

<p>Exploration well 16/10-2 was spudded with
the semi-submersible installation Byford Dolphin on 20 June 1991 and drilled to
a total depth of 3150 m in the Triassic sandstones of the Skagerrak Formation.
The well was drilled with seawater and gel down to 417 m, with Seawater and
gypsum polymer from 417 m to 2798 m and with Bentonite/Anco Temp mud from 2798
m to TD.</p>

<p>The Quaternary/Tertiary sequence
constituted predominantly marine claystones of the Nordland, Hordaland and
Rogaland Groups. The Cretaceous sequence was mainly represented by limestones of
the Chalk Group and by the reddish claystones and calcareous marls of the
Cromer Knoll Group that overlay the Base Cretaceous Unconformity found at 2818
m. The Upper Jurassic sequence consisted of 35 m darkish/brown shales belonging
to the Draupne Formation overlying 70 m of the &quot;Oxfordian Sandstones&quot;
(Hugin Formation).  This reservoir showed a larger sand development than in
16/10-1 well where only 33 m sand was encountered. The top of the
&quot;Oxfordian Sandstones&quot; was encountered at 2853 m. Below the sand,
from 2923 m to TD, Triassic continental sandstones of the Skagerrak Formation
were encountered. The geological results of 16/10-2 well were in good agreement
with the structural and stratigraphic models expected. The targets (i.e.
Oxfordian Sandstone and Skagerrak Fm.) were found water bearing and no
hydrocarbon bearing level or relevant shows were encountered in the well.
Conventional cores were not taken. A RFT segregated sample at 2876 m recovered
only water and mud filtrate.</p>

<p>The well was permanently abandoned as a
dry well on 1 August 1991.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>







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16/10-3
<b>
General
</b>
<p>
Well 16/10-3 was drilled as an exploration well on the "Tyr Central prospect" located near the block boundary in the northeast part of the Block in Production License 101. The licence was awarded in 1985, after the 9th concession round.
</p>
<p>
The purpose of drilling well 16/10-3 was to test the hydrocarbon potential of the Middle Jurassic/Triassic reservoir (Hugin and Skagerrak Formations) in the Tyr structure. The tested structure consisted in several culminations with a common dip closure. The well location was set on the largest of these, called "Tyr Central". The well was drilled by Norsk Agip as operator and was a joint well with the licence holders of PL 072.
</p>
<b>
Operations and results
</b>
<p>
Exploration well 16/10-3 was spudded with the jack-up installation "Transocean Nordic" on 22 October 1996 and drilled to a total depth of 2850 m in the Triassic Smith Bank Formation shales. The well was drilled/cased/logged and abandoned in 40 days but due to WOW (wait on weather) the rig was not released from its contract and moved off location until the 6 December 1996 after a total of almost 51 days. The well was drilled with spud mud down to 196 m, with Seawater and PAC hi-vis sweeps from 196 m to 431, and with KCl / PAC glycol mud from 431 m to TD.
</p>
<p>
All the expected formations were encountered. The Jurassic/Triassic sands were found with fair reservoir quality. The expected reservoir was encountered at 2521 m, 31 m deeper than prognosis. The Hugin-Skagerrak sands were found water bearing and no hydrocarbon shows were detected. No relevant gas amounts were recorded in the well and no hydrocarbon shows were identified on cuttings in the reservoir section. Two FMT fluid samples were collected at two different depths: the recovery was mud filtrate in the first sample at 2522 m and mud in the second one at 2544.3 m. No conventional cores were cut in this well. The well was permanently abandoned as a dry well on 1 December 1996.
</p>
<b>
Testing
</b>
<p>
No drill stem test was performed.
</p>
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16/10-4
<b>
General
</b>
<p>
Well 16/10-4 was drilled on the Trond prospect located in the northeast part of PL 101, which is southeast of the existing Sleipner field. The prospect was a north-south elongated salt-induced structure with dip closure in all directions. The main purpose was to test the hydrocarbon potential within the upper Jurassic (Hugin) formation in the prospect and to obtain representative cores of that sand package.
</p>
<b>
Operations and results
</b>
<p>
The jack up installation "Transocean Nordic" arrived on location on June 25 1998. Spud was significantly delayed due to insufficient leg penetration. Gravel boats had to be employed to dump gravel around the spud cans. This operation took 141 hours. With the gravel dumping completed, the weather became rough and the spud cans could not be lifted according to the plan. It took 162 hours before the weather was sufficiently calm to proceed with the pre-loading. Exploration well 16/10-4 was finally spudded on July 11 1998 and drilled to a total depth of 2580 m in Permian Zechstein anhydrites. The well was drilled with seawater and bentonite sweeps down to 380 m, with KCl / PAC mud from 380 m to 1230 m, and with KCl /PAC / glycol mud from 1230 m to TD.
</p>
<p>
All the formations encountered from top Balder were found above prognosis due to anomalous velocities in the gas chimney drilled by this well. The reservoir target (Hugin Formation) was encountered at 2474 m. (80 m below prognosis). The petrophysical properties of the reservoir were found to be good. The only interval with some gas shows was the Rogaland Group (1792-1888 m) where the total gas was between 2.6 and 4.4 % Ci-nC4, but no reservoir was encountered at this level. No direct shows were observed in the Hugin Formation and the total gas was below 0.1%. From FMT measurements, log analysis and all the information collected during the drilling phase, the reservoir was found to be water bearing. However, onshore geochemical analysis by Eni central laboratories in Milan reported significant traces of migrated hydrocarbons in core samples from 2478 to 2496 m and high levels of phenols with possible traces of altered oil in the FMT water sample.
</p>
<p>
One core was cut from 2477 to 2504 m in the soft, unconsolidated Hugin Formation (Previous wells in the area suffered no core recovery). The median porosity of the core was 25% and the median permeability was 260 m. Eight FMT pre tests and one segregated sample were taken from the Hugin reservoir. All pressure tests were good and gave a clear water gradient of 0,102 bar/m in the reservoir. The sample recovered was a mixture of mud filtrate and formation water.
</p>
<p>
The 16/10-4 well was permanently abandoned on 10 August as a dry well.
</p>
<b>
Testing
</b>
<p>
No drill stem test was performed.
</p>
3531
7/6/2016 12:00:00 AM
29.01.2023
16/10-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/10-5 was drilled on the Isbjørn
prospect in the northern end of the Jæren High in the North Sea. The Isbjørn
Prospect was mapped as a four-way dip-closure structure. The primary objective
of the well was to test the hydrocarbon potential in the Late Jurassic Ula
Formation sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/10-5 was spudded with the jack-up
installation Mærsk Giant on 6 October 2012 and drilled to TD at 3034 m in the
Middle Jurassic Bryne Formation. A 12 1/2” pilot hole was drilled from below
the 30” conductor to 1057 m to check for shallow gas. No shallow gas was seen. Drilling
of the 8-1/2” section was troubled with junk in the hole ending up with two
additional clean-out runs; else, operations proceeded without significant
problem. The well was drilled with seawater and sweeps down to 180 m, with
KCl/GEM/Polymer mud from 180 m to 1057 m, and with Enviromul oil based mud from
1057 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated 98 m of radioactive
Mandal Formation shales directly overlying the Ula Formation. The Ula formation
came in at 2929 m, which was 65 m shallower than the prognosis. One hundred and
six m of good quality sand was penetrated but it was water filled without shows
and gas values were low. RCI pressure data points indicate a common formation
water gradient, with no likely internal pressure barriers, for both Ula and
Bryne Formations.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No conventional or sidewall cores were taken.
The RCI tool was run for pressure points, but no fluid samples were taken. Maximum
static temperatures was measured in the reservoir on wireline RCI run was 124
ºC at 3039 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 27
November 2012 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7021
4/11/2017 12:00:00 AM
29.01.2023
16/1-1

<p><b>General</b></p>

<p>Well 16/1-1 is located roughly midway
between the Gudrun Discovery and the Balder Field in the North Sea. This early wildcat
well had the general objective to: &quot; -test the hydrocarbon potential and
investigate the lithology in this portion of the North Sea basin&quot;.</p>

<p>The well is Type Well for the Utsira
Formation.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/1-1 was spudded with the
semi-submersible installation Ocean Traveler on 26 September 1967 and drilled
to TD at 3203 m in the Late Cretaceous Hod Formation. No significant problems
were reported from the operations. Initial drilling from the sea floor to 392 m
was with seawater and gel without casing. Returns were to the sea floor. Below
392 m to total depth, a seawater slurry with Bentonite, Zeogel, Spersene,
XP-20, Caustic Soda, and 0-12% diesel oil was used.</p>

<p>Porous sandstone was observed in the
Miocene, Oligocene, and Eocene. There were also Paleocene sands in the well.
Traces of possible residual oil stain were encountered in cuttings and cores
from the Oligocene and Eocene. In addition, questionable shows (non-fluorescent
dead oil) were reported on cores from the Paleocene. However, neither the hot
wire gas indicator nor chromatograph suggested the presence of hydrocarbons. </p>

<p>A total of 18 cores were cut from the
different formations within the Hordaland, Rogaland, and Shetland Groups,
recovering a total of 171 m core. The depth for core 2 is probably incorrect,
possibly be five meter shallow due to malfunction of the bumper subs. FIT wire
line fluid samples were taken in potential hydrocarbon-yielding beds at 1878.5
m, 2532.9 m, and at 2592.3 m. Only water and mud were recovered. </p>

<p>The well was permanently abandoned on 10
December 1967 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


147
5/19/2016 12:00:00 AM
29.01.2023
16/1-10



<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-10 was drilled on the eastern
margin of the South Viking Graben on the south-western part of the Utsira High
in the North Sea. It was drilled to confirm the northern extent of the Luno oil
discovery in Early Jurassic conglomerates made by well 16/1-8. The oil-water
contact at 1965 m TVD RKB should be confirmed and a production test of the
clean sand facies and conglomeratic facies should be conducted.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-10 was spudded with
the semi-submersible installation 16/1-10 on 13 November 2008 and drilled to TD
at 2151 m in conglomeratic sandstones of Early Jurassic age. As the site survey
revealed a number of possible shallow gas zones the well started with a 9
7/8&quot; pilot hole to check for shallow gas down to 400 m, TD of planned
26&quot; section. No gas was seen in this interval. Due to a leak in the
20&quot; casing the casing programme was significantly revised, with 13
3/8&quot; casing set at 589 m, above a potential shallow gas zone at 634 m, and
the 12 1/4&quot; hole was drilled down into top Shetland Group. This
slimmer-than-planned hole turned out to give easier drilling than in the
previous well on the prospect (16/8-1). The amount of down time was however
comparatively large, due mainly to wait-on-weather. Additional coring also
added to a longer than planned time for this well. The well was drilled with seawater
and hi-vis bentonite sweeps down to 411 m, with KCl/glycol enhanced mud from
411 m to 1860 m, and with Performadril water based mud with 5% glycol from 1860
m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Utsira, Skade and Grid sandstone
formations were penetrated by the well, all water bearing. The top of the
Jurassic reservoir sequence was encountered at 1898 m (1872.9 m TVD MSL), 11.4
m TVD deeper than prognosed. The reservoir sequence was composed of oil bearing
sandstones and conglomerates with an OWC at 1965 m. No gas cap was observed on
the logs or could be inferred from the production testing. The first
hydrocarbon shows in well 16/1-10 were observed in the core chips collected in
the Shetland Group limestones that overlie the reservoir. Generally good
hydrocarbon shows were observed in the reservoir from 1898 m down to 1911 m. From
1911 to 1928 m the hydrocarbon shows became more patchy due to widespread
argillaceous infilling of the pore spaces within the sandstone matrix. More
consistent shows were present in the interval from 1929 to 1940 m but below
this depth only intermittent shows were observed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 7 cores were cut from 1868 to
1987.5 m. The first two cores were cut entirely within the Shetland Group. The
third core penetrated top reservoir at 1898 m. The entire hydrocarbon bearing
part of the reservoir interval was cored with the last core penetrating the
oil-water contact. Four wire line logging runs were made including one MDT run
for samples and pressures. Oil samples were taken at 1899.6 m and 1933.1 m and
a water sample was taken at 2024.9 m. Fluid gradients were established for both
water and oil zones, indicating an oil-water contact at 1965 m TVD, confirming
the contact extrapolated in well 16/1-8. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 5
February as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two Jurassic intervals were production
tested. DST 1A was performed in the interval 1919.92 to 1958.11 m in the conglomeratic
sandstone facies.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1B was performed in the interval
1897.00 to 1909.79 m in addition to 1919.92 to 1958.11 .The test rate was 338 Sm3
oil per day and 35500 Sm3 gas per day through a 12,7 mm choke.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Maximum temperature recorded in the tests
was 82.1 deg C.</span></p>


5879
4/11/2017 12:00:00 AM
29.01.2023
16/1-11


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 was drilled to appraise the 16/1-9
discovery on the Gudrun Terrace just west of the Utsira High in the North Sea. The
discovery well 16/1-9 was completed in April 2008 and revealed oil shows in the
Middle Jurassic Vestland Group, but neither coring or logging was completed
according to programme due to hole problems. The extent and reservoir quality
of the Sleipner Formation in the Vestland Group was a primary objective in the
data acquisition programme for 16/1-11 and an extensive wire line logging suite
was planned in order to get as much information as possible regarding the
oil-water contact, depth conversion, reservoir thickness, facies, fluids, well
productivity and possible barriers in the reservoir. The Sleipner Formation
reservoir was prognosed to be 75 m thick and coring of the hydrocarbon bearing
part of the reservoir was decided prior drilling. Planned TD was TD at 2579 m,
approximately 100 metres below prognosed base of the Sleipner Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 was spudded with the
semi-submersible installation Songa Delta on 23 February 2010. The 8 1/2&quot;
section in was drilled to TD at 2625 m in the Skagerrak Formation. After logging
problems with setting and cementing the 7&quot; liner made it necessary to make
a sidetrack, 16/1-11T2, in order to do a drill stem test. The 8 1/2&quot;
sidetrack was kicked off from 2193 m and drilled to 2532 m (2523 m TVD). The
sidetrack was drilled deviated with up to 20 deg deviation at its TD. The well
was drilled with seawater down to 603.5 m, with Aqua-drill mud with 6% glycol
from 603.5 to 1770 m, and with Carbo-Sea oil based mud from 1770 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Hydrocarbons were proven in the Sleipner and
Skagerrak formations. Top Sleipner Formation came in at 2380.5 m. It consisted
of 20 m coarse fining upward sandstones and contained gas. Analysis of core and
log data showed good reservoir quality with calculated average effective
porosity of about 19% and an average gas saturation of 31%. The Net Pay/Gross was
nearly 1.0. The Skagerrak Formation came in at 2400.5 m. The core and log
analysis proved a much lower reservoir quality than in the Sleipner Formation,
mainly due to carbonate cementation. No contacts could be interpreted from the
logs but pressure data gave a gas/oil contact at 2377.8 m TVD MSL. The log and
pressure evaluation showed oil down to 2438 m (2409 m TVD MSL) and water up to
2445 m (2416 TVD MSL) in the Skagerrak formation. There were no pressure
barriers between the Sleipner and Skagerrak formations. The deepest oil
staining and fluorescence was recorded at 2502.8 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Five 90 ft cores were cut in the interval
2385.5 m to 2522 m with practically 100 % recovery. Fluid samples were taken
with the RCI tool. Gas samples were taken at 2396 m and 2406 m while oil samples
were taken at 2408.8 m and 2437.8. A water sample was taken at 2454.1 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back for a
geological sidetrack on 26 April as an oil and gas appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One DST was performed in the sidetrack.
It was perforated from 2415 - 2425 m, underbalanced with TCP. It flowed 177 Sm3
oil /day through a 28/64&quot; choke. The oil density was 0.835 g/cm3 and GOR was
127 Sm3/Sm. Initial formation pressure was 244.75 bar at reference depth 2377.8
m TVD MSL. Initial formation temperature at this depth (DST temperature) was 98
deg C.</span></p>



6157
4/11/2017 12:00:00 AM
29.01.2023
16/1-11 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 and the subsequent 16/1-11 A
sidetrack was drilled to appraise the 16/1-9 discovery on the Gudrun Terrace
just west of the Utsira High in the North Sea. The discovery well 16/1-9 was
completed in April 2008 and revealed oil shows in the Middle Jurassic Vestland
Group, but neither coring or logging was completed according to programme due
to hole problems. In well 16/1-11, the Sleipner Formation proved to be
hydrocarbon bearing with a gas cap of approximately 25 m thickness and a
gas-oil contact interpreted at approximately 2407 m in the Skagerrak Formation.
However, acquisition of pressure data and sampling in the water zone in the
Skagerrak Formation proved to be difficult due to very low porosity and
permeability. Thus, no reliable water gradient could be established from the
RCI sampling programme. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The 16/1-11 A geological sidetrack was
drilled down flank on the structure. The main objectives were to obtain
pressure samples in order to delineate the oil/water contact and to obtain
water samples from the Skagerrak Formation in order to establish reservoir
properties. A sidetrack would also give useful facies and thickness variation
input. Another objective was to acquire sidewall cores to pin down the expected
hiatus on top of the Sleipner Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-11 A was drilled with the
semi-submersible installation Songa Delta. It was kicked off on 26 April 2010,
with kick-off point at 1744 m in the parent well. It was drilled to TD at 2595
m (2528 m TVD), 94 m MD into the Late Triassic Skagerrak Formation. The well
was drilled with Carbotech oil based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The reservoir of the Sleipner Formation
was penetrated at 2476 m (2393.2 TVD MSL) approximately 300 m down flank
westward relative to the parent well, with an inclination of 27.6 degrees. Pressure
data proved an oil gradient throughout. Top Skagerrak formation was penetrated at
2500.5 m (2414.9 m TVD MSL). Gas and oil shows were present through the
reservoir interval and a possible OWC at 2526.1 m (2433.6 m TVD MSL) in the
Skagerrak Formation was defined by pressure points and fluid samples. Oil shows
above the OBM was recorded down to 2533 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The planned wire line logging program
including pressure points, fluid samples, mini-DST and sidewall cores was
performed. No conventional cores were cut. RCI oil samples were collected at
2478.02 m and 2510.52 m. Contamination from oil base in these samples was
estimated to be between 2.5% and 8.5% by weight. Draw-down was 1.6 to 4.0 bar. RCI
samples with both oil and water was collected at 2521.13 m. In these samples
the mud contamination was estimated to be ca 76% by weight and the draw-down
was 66 - 70 bar. Water samples were collected at 2522.1 m during a mini-DST
with the MRCH-JAR-TTRm-GR-Straddle packer-Observation probe.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 9
May 2010 as an oil and gas appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6364
4/11/2017 12:00:00 AM
29.01.2023
16/11-1 S


<p>Well 16/11-1 S is located in the Danish
Norwegian Basin. The objective of the well was to test the hydrocarbon
potential of the Tertiary, Mesozoic and Permian sediments. Specifically,
Tertiary sandstones, Cretaceous sandstones and limestones, Jurassic and
Triassic sandstones, Permian carbonates and Permian Rotligendes sandstone were
considered to be prospective.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/11-1 S was spudded with
the semi-submersible installation Ocean Viking on 17 July 1967 and drilled to
TD at 3050 m (ca 3020 m TVD RKB) in the Late Permian Zechstein Group. The well
is classified as deviated, but was not meant to be. During reaming operation at
about 1463 m the hole was accidentally sidetracked. This was not discovered until
13 3/8&quot; casing was set and the cement plug drilled through. Hole deviation
was then determined to be 16 deg at the casing shoe. In order to prevent a
dogleg the deviation was gradually decreased to 12.5 deg at about 2322 m and
stabilized at an average of 12 deg to TD. The dip meter log indicates that the
hole drifted in a N 45 deg E direction. While drilling at 2952 m the drill
string stuck and a fish was left in the hole. A cement plug was set and the
fish was bypassed by sidetracking with jet action from the bit. Upon reaching
2952 m, the pipe stuck a second time, which resulted in leaving a new fish. A
second cement plug was set and the hole sidetracked using a Neyrpic turbine
drill. The pipe stuck a third time at 2954 m and another fish was left. The
hole was again sidetracked and mud weight increased to about 16 ppg. Drilling
then continued to TD, before 9 5/8&quot; casing was set. Circulation was lost
immediately after drilling through the 9 5/8&quot; casing shoe at 2957 m. Five
Diaseal &quot;M&quot; squeezes and five DOC squeezes were performed in an
attempt to regain circulation with a 16.0 ppg mud, but all attempts were
unsuccessful. A Drispac/Flosal/Desco mud system was used to a depth of 2326 m.
At this depth the system was converted to a Sodium Chloride -saturated
Drispac/Flosal/Sodium Sulphate system. The salt-saturated mud system was used
to total depth.</p>

<p>The Tertiary section consisted mainly of
clays and shales. Fairly high methane percentages were recorded by the
chromatograph in the shaley lower part of this section as the section was
drilled. Two zones within the Mesozoic were encountered which could be
prospective reservoirs in other areas. These zones were the middle part of the
Late Cretaceous chalk and the sandstones of the Early Jurassic. No shows were observed
in either zone, but permeability was indicated in the Late Cretaceous chalk by
a small salt-water inflow. Electric log calculations of the Early Jurassic
sandstones indicated an average porosity of 23 percent and 100 percent water
saturation. No sidewall or conventional cores were taken and no fluid samples
collected.</p>

<p>The well was permanently abandoned on 31
October 1967 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>




















































112
5/19/2016 12:00:00 AM
29.01.2023
16/1-12


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-12 was drilled south of the
Luno Discovery on the south-western part of the Utsira High. The Luno Discovery
sits in an inlier basin where well 16/1-8 Luno Discovery well proved a 275 m
thick Late Triassic to Jurassic sequence, overlain by a 25 m thick Late
Cretaceous chalk sequence. The purpose of the well is to prove oil-filled
sediments of Late - Middle Jurassic fluvial/marine and pre-Jurassic sediments
south of the established Luno sediment basin. The potential reservoir was
expected from the top of the Jurassic conglomeratic sandstones to the base of
the Triassic sandstones and conglomerates (TD). </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well was spudded with the
semi-submersible installation Songa Dee on 29 July 2009 and drilled to TD at
2055 m in pre-Devonian Basement rock. The well was drilled with seawater and
sweeps down to 603 m and with Glydril mud from 603 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-12 proved oil in weathered and
faulted/fractured granitic basement beneath a thin, 20 - 30 cm, Early Cretaceous
conglomerate. An oil/water contact was established at approximately 1954 m. An
extensive data acquisition program was undertaken and the oil column was
confirmed by oil sampling, pressure measurements and observations in both cores
and sidewall cores. The weathered and fractured basement showed moderate
reservoir characteristics with an average porosity of 9% and an average permeability
of 1 mD. As fractured basement plays are rare on the Norwegian continental
shelf, a large uncertainty applied to both reservoir properties and the lateral
outline of the discovery. The latter being due to seismic image quality and to
difficulties mapping the fracture/fault density. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The first oil shows in well 16/1-12 were
observed in Core 4 at 1912 m after penetrating the thin, Cretaceous age,
conglomerate layer below the Cromer Knoll marls. Moderate oil shows continued
throughout the remainder of the cored interval, which consisted of fractured
basement rocks. In cuttings from the subsequent drilling below the cored interval
oil shows were more difficult to detect, however, poor shows were reported down
to 1956 m. Oil was present in both the fractures and in secondary pore spaces.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 8 conventional cores were
taken in well 16/1-12. As planned, coring operations commenced at 1864 m in the
Shetland Group limestones in order to core the transition into the reservoir. Mini
DSTs were performed at 1922.5 m, 1946.8 m, and 1956.6 m. Test interpretation indicated
permeability ranges of 2-30 mD, 5-100 mD, and approximately 700 mD
respectively, for the three tests. Oil samples were obtained from the first two
DSTs and water from the last.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8
September 2009 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


6166
4/11/2017 12:00:00 AM
29.01.2023
16/11-2
<p><b>General</b></p>

<p>The Anchovy (16/11-2) well was drilled on
a semi-domal structure, about 5 miles long and 4 miles wide situated in the
Danish-Norwegian Basin. It was estimated that at Paleocene depth there would be
12 square miles of closure with 150 m vertical relief and at Jurassic depth, 9
square miles of closure with 370 m vertical relief. The principal objective
horizons were the Jurassic and Paleocene sands.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/11-2 was spudded with the
semi-submersible installation Ocean Viking and drilled to TD at 2378 m in Late
Permian Zechstein salt. </p>

<p>No Paleocene sands were encountered. As
expected the Danian Chalk section was missing in the well. The Upper Cretaceous
Limestone was tight with no shows. The Jurassic sand top was encountered at
2202 m with the main sand development beginning at 2207 m. The net sand
thickness was 35 m, but on testing was found to be tight and unproductive. The
total Jurassic section was about 244 m thinner than anticipated. The Triassic was
missing. An 11.5 m Dolomite section was developed from 2250 m to 2261.5 m at
the top of the Permian succession. This was also tested, but found to be tight
and unproductive. Thus the well was terminated in the Zechstein higher than
planned. Except for the reduced Jurassic sequence and absence of Triassic
sediments causing the higher position of the Zechstein, the structure and
stratigraphy were as predicted in the prognosis. Geochemical analyses of shales
from the Late Jurassic Tau Formation proved excellent source potential, but the
kerogen is immature to marginally mature in the well location. No cores were
cut. The well was permanently abandoned as a dry well on 23 July 1973.</p>

<p><b>Testing</b></p>

<p>Two intervals in the Sandnes Formation
were perforated and tested, 2261 m to 2251 m and 2242 m to 2231 m. Both
intervals were found tight and unproductive and no hydrocarbons were produced
during the tests.</p>


336
7/6/2016 12:00:00 AM
29.01.2023
16/1-13


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-13 was drilled to appraise the
Luno Discovery on the southern part of the Utsira High in the North Sea. The
Luno discovery was made after drilling the 16/1-8 well in 2007 and confirmed by
the appraisal well, 16/1-10. The objectives of well 16/1-13 were to confirm the
resource estimates for the Luno Discovery, prove the presence of Jurassic
sediments with good reservoir properties, and to improve understanding of the
reservoir facies distribution.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-13 was spudded with
the semi-submersible installation Transocean Winner on 30 November 2009 and
drilled to TD at 2303 m in the Late Triassic Hegre Group. A precautionary 9
7/8&quot; pilot hole was drilled from seabed to a depth of 606 m MD RKB. MWD
logs in the pilot hole confirmed that all permeable formations were water
bearing and shallow gas was not present. Minor gas sands were observed in the
main bore at 631 and 726 m, but no gas flow occurred. The well was drilled with
Seawater and hi-vis pills down to 606 m and with Glydril mud with 4 - 6 %
glycol from 606 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-13 proved a 50 m oil column in
Jurassic / Triassic sandstones with excellent reservoir characteristics. The
pressure at the top of the reservoir was measured at 193.2 bar (equivalent to a
gradient of 1.028 g/cc). Pressure measurements and samples established an oil
gradient of 0.069 bar/m with an oil-water contact at 1966.5 m (1939 m TVD MSL).
A water gradient of 0.101 bar/m was established below the OWC. The water zone lithology
consisted of sandstones and conglomerates, the latter of relatively poor
reservoir quality. The first oil shows in well 16/1-13 were observed in the
shale at the top of core number 2 at 1918 m. From 1967.4 m (1965.4 m TVD) in
core number 4 the sandstones became thickly interbedded with tightly cemented conglomerates.
The latter did not contain any visible hydrocarbon shows; however shows were
present within the sandstone layers down to 1972.7 m (1970.7 m TVD). Below this
depth and above reservoir level no oil shows were seen.</span></p>

<p class=MsoBodyText><span lang=EN-GB>An extensive data acquisition program was
undertaken. In total five cores were cut from 1917.0 to 2001.1 m with 97 %
total recovery. Four cores covered the complete oil column and one core was
taken in the water zone. MDT fluid samples were taken at 1924.5 m (oil), 1965 m
(oil), 1967.2 m (water and trace oil), and 1973 m (water and trace oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21
January 2010 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



6232
4/11/2017 12:00:00 AM
29.01.2023
16/1-14


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-14 was drilled to explore the
Jurassic Apollo Prospect situated south of the Draupne Discovery and down flank
of the Luno Discovery. The well is located on the eastern margin of the South
Viking Graben in the North Sea. The structure is situated between eastern part
of the Gudrun Terrace and the western flank of the Utsira High.</span><span
lang=EN-GB> </span><span lang=EN-GB>The primary objective was to test the
Vestland Group, Hugin Formation sands and to verify communication with the
16/1-9 Draupne Discovery. A thickening and improving reservoir quality in the
Hugin Formation, when compared to well 16/1-9 was expected towards the Apollo. Prospect.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-14 was drilled with the
semi-submersible installation Transocean Winner. First a 9 7/8&quot; pilot hole
was drilled to 606 m. This hole was abandoned due to shallow gas and it was
named 16/1-U-6.  Wildcat well 16/1-14 was spudded ca 15 m west of 16/1-U-6 on
26 September 2010 and drilled to TD at 2550 m in Late Triassic sediments of the
Skagerrak Formation. As the Cretaceous to Eocene hydrocarbon bearing reservoirs
were insufficiently logged and cored a sidetrack was decided. The 16/1-14 T2
sidetrack was made through a window in the 9 5/8&quot; casing at 1800 m. The
sidetrack was drilled to TD at 2295 m (2293.4 m TVD) in the Late Jurassic Draupne
Formation. The well was drilled with seawater and hi-vis sweeps down to 378 m
and with Glydril mud from 378 m to TD in both well tracks. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The primary objective of the well was not
realised because the Hugin Formation was found to be dry. However, well 16/1-14
encountered oil in three levels, the Balder Formation, the Heimdal Formation and
one in the Lower Cretaceous (Berriasian to Valangian) Åsgard Formation. Free water
levels were estimated to be at 2004 m (1978 m TVD MSL) in the Paleocene
(Balder-Heimdal) discovery and at 2181 m (2155 m TVD MSL) in the Lower
Cretaceous Åsgard discovery. In well 16/1-14 several thin sands were encountered
in the Lista Formation. The sands were oil-filled and displayed moderate properties
from log analysis. However, no fluid gradients could be acquired from
pressure-points. In the sidetrack, 16/1-14 T2, the corresponding sand intervals
were found to be missing or to be thinner. In the Heimdal Formation 6.5 to 7 m
net sand of good quality was interpreted from the logs. Oil was confirmed by
sampling. In the Åsgard Formation, a 9 m interval of very good sand was oil
filled. Mobilities derived from the MDT results showed up to 3500 mD/cp. A
water filled Intra Draupne Formation sandstone was found 16 m thick in the
primary well bore, but was only 4 m thick in the sidetrack, indicating a
pinch-out of this sand towards the south-west. The primary target Hugin
Formation came in at 2472 m; deeper than prognosed and water bearing. However,
oil shows were recorded from 2472 m to 2495 m. Weak oil shows were also
recorded in intervals in siltstones and claystones of the Draupne and Heather formations.
</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut in the
main wellbore from 2373 m to 2454.6 m, and four additional cores were cut in
the sidetrack from 2052 m to 2101 m and from 2167 m to 2221.46 m. In 16/1-14 fluid
scanning (LFA) confirmed oil at 2063.3 m, and at 2098.1 m, where 3 oil
samples were acquired. A further MDT water sample was acquired at 2491.5 m. In
the sidetrack MDT oil samples were acquired at 1998 m (Balder Formation), 2002.8 m (Balder Formation),
2102.2 m (Heimdal Member) and 2174 and 2178.8 m (Åsgard Formation). MDT water
samples were acquired in the sidetrack at 2106 m (Heimdal Member) and 2188 m
(Åsgard Formation).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30
November 2010 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6399
4/11/2017 12:00:00 AM
29.01.2023
16/1-15


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-15 was drilled on the western
side of the Utsira High in the North Sea. The objective was to test Jurassic/Triassic
sandstones prognosed at 1925 in the Tellus prospect north of the Luno Discovery.
The Luno Discovery has later been officially named the Edvard Grieg Field. The
Tellus prospect was separated from Luno by a fault zone trending NW SE.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-15 was spudded with the
semi-submersible installation Bredford Dolphin on 22 January 2011 and drilled
to TD at 2150 m, 230 m into pre-Devonian basement rock. Due to possible shallow
gas sands a precautionary 9 7/8&quot; pilot hole was drilled down to 585 m.
Only water filled sands were seen. Several incidents interrupted the progress
where the most serious was a failed 20&quot; casing cement job. The other
incidents were related to the BOP and a stuck wire line string. The well was
drilled with seawater and sweeps down to 585 m, and with Performadril mud from
585 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well proved an oil column of 48
metres in a thin, Intra Åsgard Formation Sandstone directly overlying weathered
and porous / fractured basement. Top of fractured basement was at 1920 m. No
Triassic or Jurassic sediments were identified in the well. The Intra Åsgard
Formation Sandstone is a chalk arenite, 2.7m thick, with excellent reservoir
properties. An oil/water contact was established at approximately 1965 m (1940
m TVD MSL). The acquired pressure, geochemistry and PVT data supports communication
between the Luno and Tellus Discoveries, making the Tellus area a northern
extension of the Luno Discovery.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Intermittent oil shows were described on core
1 immediately above the reservoir in a thin Hod Formation limestone. Below OWC
shows were described on cores down to 1976 m. Further weak shows were described
on cuttings down to 1997 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 61 meter core was recovered in
four cores from 1915 to 1976 m (all core depths 2.15 m deeper than logger's
depth) in the Hod Formation, Intra Åsgard Formation Sandstones and Basement.
The overall recovery rate was 85.2%. Fluid sampling, water and oil, was
performed using an extra-large diameter MDT-probe and dual packer. Samples were
taken in the oil bearing zone at 1918.99 m, 1921.47 m, 1923.81 m, 1932.96
m,1937.23 m, 1952.43 m, 1959.62 m, and 1967.04 m. A water sample was taken at
2030.52 m. The oil samples show an under saturated light oil similar to the oil
found in the Luno Field. The typical GOR from the MDT samples was 125 Sm3/Sm3,
the oil density was 0.72 g/cm3 and the gas gravity was 0.95 (air=1).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back to the 20&quot;
casing shoe on 5 April 2011 and a sidetrack 16/1-15 A was prepared. Well
16/1-15 is classified as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two drill stem tests were performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 1926 to 1960 m in
the basement. After a slow initial production, the perforations were cleaned up
and the well produced with a continuous flow to surface with an oil-rate of 105
sm3/d on a 40/64&quot; choke and a bottom-hole pressure of 56.6 bar. No water
was produced. This was the first successful full-scale production test of a
reservoir consisting of cracked and porous bedrock on the Norwegian Continental
Shelf.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 1917 to 1920 m
in the Intra Åsgard Formation Sandstone. The main flow produced 470 sm3/d on a 36/64&quot;
choke with a bottom-hole pressure of 179.7 bar. No water was produced. The
average GOR was 90 Sm3/Sm3. The maximum temperature at reference depth 1916.9 m
was 84.5 deg C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6517
4/11/2017 12:00:00 AM
29.01.2023
16/1-15 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-15A is a sidetrack to Well
16/1-15, drilled on the western side of the Utsira High in the North Sea. The
primary well proved Tellus to be a continuation of the Luno Discovery, now
officially named the Edvard Grieg Field. The objectives of the geological
sidetrack, 16/1-15 AT2, were to prove thicker, high productivity sandstone
sequences to add to the Luno reserves, and to provide seismic calibration of
complex stratigraphy.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-15 A was kicked off
at 599 m in well 16/1-15 on 6 April 2011. It was drilled with the
semi-submersible installation Bredford Dolphin. The 12 1/4&quot; hole was
drilled to TD at 2041 m. When running 9 5/8&quot; casing it got differentially
stuck forcing a new sidetrack. It is believed that the casing stuck in Grid
Formation sandstone. The 16/1-15 A well bore was thus plugged back to the
20&quot; casing and the technical sidetrack 16/1-15 AT2 was kicked off from 584
m and drilled to final TD at 2175 m (2011 m TVD) in Basement rocks. The
sidetrack was drilled with Performadril mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-15 AT2 proved 1 meter thick
Intra Åsgard Formation Sandstone at 2067 m, overlying fractured basement. The
sandstone was oil bearing and the basement had shows, but in this well bore the
basement was found to be cemented and was considered unproductive. Oil shows
were first recorded on the cores in the Intra Åsgard Formation Sandstone. They
continued on the cores into the underlying basement where they were generally
restricted to fractures. Below the cored interval sporadic shows were seen on
cuttings down to a depth of 2124 m (1967.6 m TVD).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four short cores were cut from 2066 to
2076.26 m, across the Intra Åsgard Formation Sandstone and into the Basement. The
recovery was 100% and the core-log depth shifts were less than 0.5 m. MDT fluid
samples were taken at 2067.83 m (oil), 2070.61 m (oil), and 2051.05 m (water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
May 2011 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6593
4/11/2017 12:00:00 AM
29.01.2023
16/1-16


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 was drilled on the east side
of the Gudrun Terrace towards the Utsira High in the North Sea. The main
objectives were to test the hydrocarbon potential in Late Jurassic/Early
Cretaceous sands (the Noor prospect), and to appraise the extension of the Ivar
Aasen Field of Middle Jurassic/Triassic age into PL457 area (Asha prospect). A
possible secondary target at Paleocene level is the Heimdal sand pinchout. The
well was planned to drill into Zechstein carbonates that may act as reservoir
in this area.<b> </b></span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 was spudded with the semi-submersible
installation Bredford Dolphin on 23 October 2012 and drilled to TD at 2722 m in
the Permian Rotliegend Group. A 9 7/8” pilot hole was first drilled to 600 m to
check for shallow gas. No shallow gas was observed. Operations proceeded
without significant problems. The well was drilled with </span></p>

<p class=MsoBodyText><span lang=EN-GB>No significant problem was encountered in
the operations. The well was drilled with seawater and hi-vis sweeps down to
592 m and with water based Performadril mud from 592 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The interpreted Heimdal Formation sand
reservoir was absent. The Lista Formation consists predominantly of Claystone
with Limestone stringers. </span></p>

<p class=MsoBodyText><span lang=EN-GB>In the first main exploration target
(Noor prospect), the well penetrated approximately 90 m gross sandstones altogether,
but there were no hydrocarbon shows or anomalous gas values seen. The Early Cretaceous
Åsgard Formation is a Limestone/Chalk - sandstone sequence, with a
predominantly limestone/chalk in the top 50 m and sandstone from 2120 m and
towards the base. The Draupne Formation was found as a primarily siltstone
sequence with abundant thin sandstones and limestone streaks throughout. </span></p>

<p class=MsoBodyText><span lang=EN-GB>In the other main target (Asha prospect),
the 16/1-16 well encountered a gross oil column of around 70 m in excellent reservoirs
within the Middle Jurassic Hugin  Formation, and into the Triassic Skagerrak  Formation.
Two hydrocarbon zones were found in separate pressure regime (0.6 bars
difference). The first oil zone has an ODT at ca. 2435 m in the Hugin Formation.
The deeper oil zone has an ODT at ca. 2454.2 m in the Skagerrak Formation.  No
oil/water contact was encountered. The oil found in 16/1-16 is of different
type (heavier) than the oil previously proven in the Ivar Aasen field to the
West. Moreover, unlike in Ivar Aasen, no gas cap is present in the Asha
Discovery. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The 29 m thick Zechstein Group was found
water wet. It is composed of dolomites and limestone and has relatively poor reservoir
properties</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three consecutive cores were cut from
2385 m in the Hugin Formation to 2441 m in the Skagerrak Formation. MDT fluid
samples were taken at 2163.28 m (water), 2385.2 m (oil), 2399.9 m (oil), 2424 m
(oil), 2452.7 m (oil), 2458 m (water), and 2498.2 m (water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back and completed
for sidetracking on 7 December 2012. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


6823
4/11/2017 12:00:00 AM
29.01.2023
16/1-16 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 A is a geological sidetrack
to well 16/1-16 on the east side of the Gudrun Terrace towards the Utsira High
in the North Sea. The primary well bore 16/1-16 found oil in two slightly
differently pressured compartments in the Middle Jurassic Hugin Formation and
the Triassic Skagerrak Formation (Asha prospect). Both pressure compartments
were penetrated in oil-down-to settings. The objective of the 16/1-16 A
sidetrack was to find the true Asha OWC by drilling down flank on the structure
to the south.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-16 A was kicked off at 2047 m
in main bore 16/1-16 on 7 December 2012. It was drilled with the semi-submersible
installation Bredford Dolphin to TD at 2897 m (2663 m TVD) in the Triassic
Skagerrak Formation. No significant problem was encountered in the operations.
The well was drilled with water based Performadril mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well encountered more than 30 m gross
oil in a Hugin Formation of very good quality and which is much thicker than in
16/1-16. Top Hugin was at 2527 m. The oil/water contact was encountered at
2592.8 m (2465 m TVD), 6 metres TVD deeper than the OWC found in the western
part of the Ivar Aasen Field. The Lower oil zone in a Skagerrak sand with a
separate pressure regime was not present or very little developed in 16/1-16 A
compared to16/1-16.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in the well. MDT fluid
samples were taken at 2573 m (oil) and at 2610.5 m (water)</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
January 2013 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7095
4/11/2017 12:00:00 AM
29.01.2023
16/1-17


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-17 was drilled on the Jorvik
Prospect on the Utsira High, about 5 km east of 16/1-8, the discovery well on
the Edvard Grieg field. The objective of the well was to prove petroleum in
Pre-Jurassic sandstone and conglomerate rocks.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-17 was spudded with the
semi-submersible installation Transocean Winner on 9 January 2013 and drilled
to TD at 2070 m in granitic Basement rock. Due to shallow gas warnings, a 9
7/8&quot; pilot hole was drilled to 610 m. No shallow gas was observed. Operations
proceeded without significant problems. The well was drilled with seawater and
high viscosity pills down to 615 m and with Glydril water based mud from 615 m
to TD. Geochemical analyses of cuttings and cores show traces of diesel-like
hydrocarbons in the mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A conglomeratic/sandy section was
penetrated from 1869 m to top basement at 1987 m. Poor dating suggest the
section to belong to either the Triassic Hegre Group, or the Permian Rotliegend
Group. The cores show oil in the conglomeratic part of this section between
1882 m and 1952 m. The shows correspond to increased gas readings on the logs. Moveable
oil was sampled here, at high drawdown in tight formation, but no fluid
gradients were established. The uppermost part of the basement, 1987.45 to
1993.5 m core was covered by core #5. This is an extremely weathered felsic
basement. No granitic wash or regolith was observed in core at the top of the
interval. Pressure measurements in the water filled fractured basement indicate
a pressure regime analogous to the Edvard Grieg field and the 16/1-12
discovery. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut covering the interval
from 1856 m in the Early Cretaceous, throughout the conglomeratic/sandy unit,
to 1993 m; six meter into the basement. The total recovery was 100%. MDT fluid
samples were taken in the conglomeratic section at 1915.8 m (oil and water), and
1944.6 m (oil and water), and at 1944.61 m (oil and water), and in the basement
at 2017.71 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19
March 2013 as a dry well with shows</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7113
4/11/2017 12:00:00 AM
29.01.2023
16/1-18
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-18 was drilled to appraise the
Edvard Grieg Field on the Utsira High in the North Sea. The objective of the
well was to delineate the southeastern part of the Edvard Grieg Field in order
to optimise the drainage strategy and to determine the best possible location
of production wells in this area. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A 9 7/8&quot; pilot hole was drilled from
seabed to 620 m to check for shallow gas. No shallow gas was seen. Appraisal
well 16/1-18 was spudded with the semi-submersible installation Island
Innovator on 24 February 2014 and drilled to TD at 2391 m in granitic basement
rock. No significant problem was encountered in the operations. The well was
drilled with spud mud down to 613 m and Aqua-Drill mud from 613 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No Jurassic sediments were penetrated in
the well. BCU / Top Triassic, Hegre Group was encountered at 1894 m. A 62-metre
gross oil column was found in conglomerate sandstone of the Hegre Group, where
the top 43 metres have very good reservoir properties and the lower 19 metres
have good reservoir quality. The oil/water contact was not encountered.
Pressure points proved an oil gradient with the same density oil as in the rest
of the Edvard Grieg Field, with an ODT at 1956 m. Oil shows were described on
cores down to 1986 m. There were no shows above top reservoir level.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 95.6 m core was recovered in
eight cores from the interval 1886 to 1986 m. MDT fluid samples were taken at
1894.9 m (oil), 1921.4 m (oil), 1954.5 m (oil), and 967.4 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
May 2014 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One DST was conducted in a 13-metre
interval from 1938.9 to 1959.6 m in the lower part of the oil column in
reservoir of good quality. The main flow in the test produced 135 Sm3 oil and
12000 Sm3 gas /day through a 28/64&quot; choke and showed good flow properties
from the entire oil zone. The GOR was 88 Sm3/Sm3, the oil gravity was 0.83 g/cm3,
and the gas gravity was 0.66 (air = 1). The temperature profile for the test
extrapolated to an initial top reservoir temperature of 80.1 °C at 1938.9 m.</span></p>
7314
4/11/2017 12:00:00 AM
29.01.2023
16/1-19 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-19 S was drilled on the Amol
prospect about two and a half kilometres east of appraisal wells 16/1-16 and
16/1-16 A at the Ivar Aasen field, and about three kilometres north of the
Edvard Grieg field in the central part of the North Sea. The primary objective
was to prove petroleum in Early Cretaceous reservoir rocks (the Åsgard
formation) in the western part of the Utsira High. The secondary target was to
prove petroleum in fractured and/or weathered basement rocks.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-19 S was spudded with
the semi-submersible installation Borgland Dolphin on 13 August 2013 and
drilled to TD at 1995 in the Basement rock. A 9 7/8&quot; pilot hole was
drilled to 604 m without any indication of shallow gas. Operations were
suspended twice to accommodate sidetrack operations on the Asha East prospect.
Operations proceeded without significant problems. The well was drilled with seawater
and hi-vis pills down to 604 m, with Carbo-Sea oil based mud from 604 m to 1862
m, and with Aquadril mud from 1862 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Åsgard Formation was encountered at
1878 m and proved to contain only half a metre of tight sandstone/clay stone.
The fractured basement was encountered at 1891 m with oil in the fractures.
Live oil was sampled from the fractures, but the reservoir quality was poorer
than expected. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1865
to 1910 m with 100% recovery. RCI oil samples were taken at 1929.5 m. The
samples proved a GOR in the range 106 to 135 Sm3/Sm3, an oil density of ca
0.857 g/cm3, and a gas gravity of ca 0.97 (air = 1).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 25
October 2013 as a well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7255
4/11/2017 12:00:00 AM
29.01.2023
16/1-2


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-2 is located on the eastern
side of the Gudrun Terrace, towards the Utsira High in the North Sea. The well
was designed to test all potential reservoirs through the Permian on a closure
on a large, rotated fault-block. Primary objectives were Jurassic sandstones
and secondary objectives were Paleocene sandstones.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-2 was spudded with the
semi-submersible installation Ross Rig on 4 July 1976 and drilled to TD at 2919
m in granite basement. Loss of circulation in high-porosity Zechstein
carbonates was the only significant problem encountered during the drilling of
16/1-2. Initial drilling from the sea floor to 1286 meters was with sea water
and gel. Below this depth a fresh water and lignosulphonate mud system was
used.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated several sands in the Tertiary
including the Utsira, Skade, and Grid formations. The Heimdal Formation was
encountered at 2098 m with a 10 m zone of strong oil shows. The zone was
however judged by log analysis to be water-productive and the shows not of
sufficient quality to warrant testing. Triassic sandstones were originally interpreted to be water-filled. Later reinterpretation have confirmed the presence of oil in the Triassic interval. There were no shows from either the Zechstein or the Rotliegendes
sandstone.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid samples
were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
August 1976 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>





332
7/6/2016 12:00:00 AM
29.01.2023
16/1-20 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-20 A was drilled on the Asha
East prospect about two and a half kilometres east of appraisal wells 16/1-16
and 16/1-16 A on the Ivar Aasen field, and about three kilometres north of the
Edvard Grieg field in the central part of the North Sea. The well is an appraisal
well to the 16/1-16 Asha Discovery and the primary objective was to investigate
if the hydrocarbon accumulation in the Hugin found in the Asha well spilled
eastwards into the fault bound dip closure against the Utsira High Fault.
Secondary target were younger sands of Late Jurassic and Early Cretaceous age.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-20 A was drilled with
the semi-submersible installation Borgland Dolphin. It was drilled in tandem
with the 16/1-19 S Amol well. After drilling the 16/1-19 S Amol well to 604 m
and set 13 3/8&quot; casing at 597 m, the Amol well was suspended in order to
drill 16/1-20 A Asha East 12 1/4&quot; section. Drilling operations on Asha
East were severely hampered by hole stability problems in the 12 1/4&quot; hole
section. Two attempts to drill the Asha East well were conducted from 20 August
to 4 September 2013 without success. The Asha East well was then suspended and
plugged back in order to continue with Amol well. The remaining 12 1/4&quot;
and 8 1/2&quot; sections of the Amol well was drilled from 4 to 25 September
2014, then plugged back to kick off the 16/1-20 A T3 Asha East well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>In the Cromer Knoll Group a sandy section
with a log response unlike the Åsgard Formation was penetrated from 2427 m to
2753.5 m. Below this section the well penetrated Intra-Draupne Formation
sandstone down to the target Hugin Formation sandstones at 2977 m. All
sandstones were devoid of any hydrocarbons. Post well depth conversion showed the
spill point to the east from the Asha/Ivar Aasen structure to be below the OWC.
In addition, the Heather Formation shale acting as top seal in the Asha well
was not present in the Asha East.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 55 meter of 4&quot; core was
cut and 55 meter recovered over a single core run at 2967 to 3022 m. RCX fluid
samples were taken at 2995.5 m. The maximum temperature from the RCX run was
99.9 °C at 3040.6 m, giving a temperature gradient of 4.2 °C/100 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Operations on Asha East ended with
permanent abandonment on 22 October 2013. The well is classified as a dry
appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7256
4/11/2017 12:00:00 AM
29.01.2023
16/1-21 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-21 A is a geological sidetrack
to well 16/1-21 S. It was drilled to appraise the 16/1-9 Ivar Aasen discovery
on the Gungne Terrace in the North Sea. The objective was to obtain key depth
and reservoir information for field development in the eastern part of the Ivar
Aasen Discovery. The targets were reservoirs in the Hugin/Sleipner and
Skagerrak Formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-21 A was kicked off on
3 March 2015, from the main well 16/1-21 S with an open hole kick off below the
13 3/8&quot; casing shoe at 1317 m. The well was drilled with the jack-up
installation Mærsk Innovator to TD at 3313 m (2517 m TVD) in the Triassic Hegre
Group. Due to severe losses when drilling the 12 1/4&quot; section at 2951 m a
cement plug was set and the 9 5/8&quot; liner was run with shoe depth at 2796 m.
The well was drilled with Versatec oil based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated a 6.3 m net sand in
the Sleipner Formation above the Skagerrak formation. The reservoir quality in
the sand is very good with an average porosity in the net sand of 24 percent.
The sand contains gas-condensate and oil. A gas oil contact is interpreted to
be at 3192.0 m (2408.0 m TVD).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The underlying Skagerrak reservoir is oil
filled and the net sand interval above the Alluvial Fan is 20.3 meters. The
average porosity in the net intervals is 23 percent in Skagerrak 2 and 21 percent
in Skagerrak 1. The formation pressures in 16/1-21 A indicated a contact at 3273.9
m (2481.6 m TVD) in Skagerrak Alluvial Fan. However, the pressures in this very
calcite cemented part of Skagerrak Formation is about 0.6 bar higher than in
the oil-filled Skagerrak above, and the actual contact is not resolved. The
deepest oil sample is from 3221.1 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Oil shows were recorded on cores from
3183 m, in the Sleipner Formation. Shows were visible throughout the cored sections
with a weakening trend towards the lowermost part of core 3 in the Skagerrak Formation.
No shows are described below base of core 3 at 3234 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 3174 m in the
Heather Formation, through the Sleipner Formation and down to 3235.8 m in the
Triassic Skagerrak Formation. The core recovery varied from 92.7% to 99.0 %.
The core to log shift is reported to vary between +2.0 m to +3.0 m in different
sections of the cores. MDT fluid samples were taken at 3191.03 m (gas-condensate),
3193.44 m (oil), 3195.53 m (oil), 3208.93 m (oil), and 3221.1 m (oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
April 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7530
4/18/2017 12:00:00 AM
29.01.2023
16/1-21 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-21 S was drilled to appraise
the 16/1-9 Ivar Aasen discovery on the Gungne Terrace in the North Sea. The objective
was to obtain key depth and reservoir information for field development in the north-eastern
part of the Ivar Aasen Discovery. The targets were reservoirs in the Heimdal,
Hugin/Sleipner and Skagerrak Formations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-21 S was spudded with
the jack-up installation Mærsk Interceptor on 21 January 2015 and drilled to TD
at 2630 m (2584 m TVD) m in the Triassic Hegre Group. A 9 7/8&quot; pilot hole
was drilled from the 30&quot; conductor shoe to 376 m. No shallow gas was
encountered. The well was drilled with seawater and hi-vis pills down to 373 m,
with Glydril mud from 373 m to 1304 m, and with Versatec oil based mud from
1304 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Heimdal Formation was encountered water
filled at 2176 m (2138.7 m TVD). Reservoir properties were excellent with 26.5
m net sand with 30% average porosity. The distribution of the Jurassic versus
the Triassic sequence was different from the expected. Triassic reservoir was thicker
than predicted, while the Jurassic had no reservoir at all. However, the total
actual reservoir quality and hydrocarbon pore volume height was in agreement
with the predicted, since the Triassic proved better than expected combined
with a deeper hydrocarbon contact. The Triassic reservoir (Skagerrak Formation)
was penetrated at 2491 m (2446.6 m TVD) and it was hydrocarbon bearing with
20.3 m net pay with 20% average porosity. The hydrocarbon type was
undersaturated oil, as in well 16/1-16. No gas cap was present and an oil down-to
situation was established at ca 2535 m (2490 m TVD). Hydrocarbon shows were
first evident in the lowermost part of core #1, from 2489 m in the Skagerrak Formation.
Good hydrocarbon shows continued in the sandy sections in the cores. No shows
were recorded below 2554 m, in the lowermost part of the Skagerrak Formation. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in succession from
2499 m in the Heather Formation to 2586.2 m in the Skagerrak Formation. Core
recovery was 100%. The core to log shift is +1.85 m for all three cores. Fluid
samples were taken at 2178.25 m (water), 2497.71 m (oil), 2514.7 m (oil), 2525.25
m (oil), 2533.61 m (oil), and 2538.92 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back and abandoned
on 3 March 2015 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7529
4/11/2017 12:00:00 AM
29.01.2023
16/1-22 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 A is a geological sidetrack
to well 16/1-22 S on the Ivar Aasen Field on the Gudrun Terrace in the North
Sea. The primary objective was to test the hydrocarbon potential in the Sleipner
and Skagerrak Formations in the southwestern part of the Ivar Aasen Field, ca
950 m northeast of the main wellbore. 16/1-22 A also aimed to investigate a seismic
anomaly at reservoir level.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 A was kicked off
at 1465 m in the main wellbore on 27 May 2015. It was drilled with the jack-up
installation Mærsk Interceptor to TD at 2896 m (2522 m TVD) m in the Triassic
Skagerrak Formation. Static and dynamic mud losses occurred from 2794 m. The
losses were cured by using coarse lost circulation material. The well was
drilled with oil-based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top of the reservoir in the 16/1-22 A
well was penetrated at 2769 m (2432.4 m TVD), 17 m shallower than expected, and
with a reservoir thickness approximately half of what was predicted. No
Jurassic reservoir was present, only Triassic. A total oil column of about 55
metres was encountered in the Skagerrak formation, 30 metres of which was in
sandstone of varying reservoir quality, from moderate to very good. The
oil/water contact was not encountered. The seismic anomaly is linked to the top
of a total oil column of about 25 metres in an alluvial sandstone unit within
the Skagerrak Formation, 15 metres of which had moderate reservoir properties. Hydrocarbon
shows were recorded from top at 2769 m and throughout the Skagerrak Formation, with
a weakening downward trend towards TD. A gas peak of up to 20% total gas
indicated a gas cap in the uppermost part down to ca 2785 m. Shows were visible
throughout the reservoir to TD, </span></p>

<p class=MsoBodyText><span lang=EN-GB>No coring or wireline operations were
performed in this sidetrack. No pressure points or fluid samples were acquired
du to mud losses.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4
June as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7716
4/26/2017 12:00:00 AM
29.01.2023
16/1-22 B
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 B is a geological sidetrack
to well 16/1-22 S on the Ivar Aasen Field on the Gudrun Terrace in the North
Sea. The primary objective was to test the hydrocarbon potential in the Sleipner
and Skagerrak Formations in the southwestern part of the Ivar Aasen Field, ca 1290
m northeast of the main wellbore. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 B was kicked off
at 1470 m in the main wellbore on 4 June 2015. It was drilled with the jack-up
installation Mærsk Interceptor to TD at 3215 m (2556 m TVD) m in the Triassic
Skagerrak Formation. No significant problem was encountered in the operations.
The well was drilled with oil-based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top reservoir, Skagerrak Formation was
penetrated at 3065 m, 19 m deeper than prognosed, and with a total reservoir
thickness of 35 m, 12 m thinner than expected. Like the -S and -A wells, a
thick Viking Group was penetrated but no Jurassic reservoir. The total
reservoir quality was proven better than predicted. Well 16/1-22 B encountered
a total oil column of about 45 metres in the Skagerrak formation, 25 metres of
which was in sandstone of good to very good reservoir quality. The oil/water
contact was not encountered. Hydrocarbon shows were evident from top Skagerrak
Formation at 3065.6 m. A 10% total gas reading indicated clearly a gas cap in
the uppermost part of the reservoir. As for the two previous well tracks, shows
varied according to changing lithologies in the reservoir. No shows were
recorded below 3160 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. Attempts to record
pressure points with a stethoscope tool on the 8 1/2&quot; drilling assembly
failed. No fluid sample was taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
June 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7720
4/26/2017 12:00:00 AM
29.01.2023
16/1-22 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-22 S was drilled to appraise
the Ivar Aasen Field on the Gudrun Terrace in the North Sea. The primary
objective was to test the hydrocarbon potential in the Sleipner and Skagerrak
Formations in the southwestern part of the Ivar Aasen Field and to establish
hydrocarbon fluid contacts.  </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-22 S was spudded with
the jack-up installation Mærsk Interceptor on 24 April 2015 and drilled to TD
at 2640 m in the Late Triassic Skagerrak Formation. No significant problem was
encountered in the operations. The well was drilled with seawater and bentonite
sweeps down to 600 m, with Versatec oil based mud from 600 m to TD. Good
hydrocarbon shows were recorded in the sandy sections in the cores from 2503 to
2550 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Jurassic - Triassic sequence was different
from the expected as the Jurassic consisted of the Viking Group only, with no
Jurassic reservoir present. This was however partly compensated by a thicker
Triassic reservoir sequence with good quality sandstone in the uppermost part. Top
Skagerrak Formation was encountered at 2506 m, which was 28 m deeper than the
prognosis. The total reservoir thickness was 9 m thinner than expected. The
Skagerrak Formation had moveable oil in the top three meters down to an ODT at
2508.3 m (2486 m TVD).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in this well. Core 1
was cut from 2502.8 to 2517.66 m with 93.14% recovery, and core 2 was cut from
2517.66 to 2550 m with 100% recovery. A small depth shift relative to the logs
(-0.1 to -0.4 m) is estimated for core 1. For Core 2 there was no core-log
depth shift. MDT fluid samples were taken at 2506.15 (oil) and 2524.03 m
(water) fluid.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back for
sidetracking on 27 May 2015. It is classified as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7531
4/18/2017 12:00:00 AM
29.01.2023
16/1-23 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-23 S was drilled appraise the
Edvard Grieg Field on the Utsira High in the North Sea. The primary objective
was to investigate the hydrocarbon potential in the South Eastern part of the
Field. It was also designed to allow installation of a CaTS pressure gauge for
long term monitoring of reservoir pressure.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-23 S was spudded with
the jack-up installation Rowan Viking on 24 June 2015 and drilled to TD at 2130
m in basement rock. The well was drilled S-shaped with up to 24 ° deviation in
the interval from 630 m to 1480 m. This was to avoid a fault at the reservoir
level. Target location was approximately 43 m west of the spud location. No significant
problem was encountered in the operations. The well was drilled with seawater
and hi-vis sweeps down to 315 m, with KCl/polymer mud from 634 m to 1888 m, and
with Aquadril mud from 188 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-23 S proved a 66 metres gross
oil column in conglomerates and sandstones with medium to good reservoir
quality. The top of the reservoir, from 1953 to 1953.5 m, is a marine sandstone
unit with a basal conglomeratic transgression lag belonging to the Åsgard
Formation, the remaining reservoir is conglomerates and thin sandstone units
belonging to the Triassic Skagerrak Formation. A Free Water Level was
established from pressure gradients at ca 2020.4 m (1985.5 m TVD). The pressure
points further proved an oil gradient with the same density as in the rest of
the Edvard Grieg field. Fair to poor oil shows were recorded on cores below the
FWL down to 2054 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Eight cores were cut. Core 1 was cut from
1681 to 1690 m in Hordaland Group claystone for hole instability studies. Core
recovery was 104.1%. Cores 2 to 8 were cut from 1945.5 m in the Åsgard
Formation to 2064.4 m in the Skagerrak Formation. Recovery varied from 92.5 to
100%.  MDT fluid samples were taken at 1958.2 m (oil), 1990.0 m (oil), 1990.6 m
(oil), 2015.21 m (oil), 2024.7 m (water), 2061.4 m (water), 2061.72 m (water),
and 2030.85 m (water). Single stage separation of the oil samples gave oil
densities in the range 0.857 to 0.886 g/cm3 and GORs in the range 149 to 111
Sm3/Sm3.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The CaTS reservoir pressure monitoring
system was installed before the well was permanently abandoned on 25 August 2015 as an oil
appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7532
5/23/2017 12:00:00 AM
29.01.2023
16/1-24
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-24 was drilled to test the Gemini
prospect on the Gudrun Terrace west-south-west of the Edvard Grieg Field in the
North Sea. The primary objective was to test the hydrocarbon potential in the
Paleocene Ty Formation</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-24 was spudded with the
semi-submersible installation Island Innovator on 14 February 2015 and drilled
to TD at 2299 m in the Late Jurassic Hugin Formation. No significant problem
was encountered in the operations. The well was drilled with seawater and
hi-vis pills down to 600 m and with Aquadril mud from 600 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The target Ty Formation came in at 2116
m. The Ty Formation consisted of a 30-metre thick sandstone with an average
porosity of 26.7% and a net/gross of 0.984. </span><span lang=EN-US>The well
also encountered a ca 30-metre thick Intra Draupne Formation sandstone of very
good reservoir quality and a ca 120-metre thick sandstone-dominated interval in
the Heather formation with good to poor reservoir quality. Pressure points in
Paleocene and Late Jurassic were below hydrostatic, indicating pressure
depletion in the area. All reservoirs are water bearing. </span><span
lang=EN-GB>No oil shows were observed in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
March 2015 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

















































7616
4/18/2017 12:00:00 AM
29.01.2023
16/1-25 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-25 S was drilled on the Utsira
High in the North Sea, 2.7 km south of well 16/1-12 (Rolvsnes discovery well). The
primary objective was to prove the presence of transgressive Cretaceous and/or
Jurassic sandstones overlying the basement and to test the extension of the
16/1-12 discovery in porous basement towards south.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-25 S was spudded with
the semi-submersible installation Bredford Dolphin on 15 October 2015 and drilled
to TD at 2210 m (2121 m TVD) m in the basement rock. The section from 2010 to
602 m was drilled first as a 97/8” pilot hole to check for shallow gas and then
opened up with a 26” bit. No shallow gas was observed. The well was drilled as
a deviated well (15° through basement) in order to cross more faults and test a
wider area and in that way to get better control on variability, quality and
thickness of the weathered zones. Operations proceeded without significant
problems. The well was drilled with seawater and hi-vis sweeps down to 602 m and
with Aquadril mud from 602 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A 10 m transgressive sandstone was prognosed
at the base of the Early Cretaceous Åsgard Formation but only 10 cm was
observed directly above basement. The top basement was found at 2004.25 m (1922.7
m TVD). The well encountered an oil column of about 30 m in porous and
fractured basement rock. The OWC is set 2034.5 m MD RKB (1952 m TVD). The
pressure data shows communication with the 16/1-12 oil discovery, with
approximately the same oil/water contact. The fluid type is oil with similar
properties to the Edvard Grieg oil. Below OVC there was oil shows (direct, cut
and residual fluorescence) down to 2067 m, and weaker shows down to 2124 m.
There were no shows below this depth or above top Basement.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Six Cores were cut in succession in the
basement from 2002 to 2025.23 m with a total recovery of 97%. The core-log
shift varies between 0.07 and 0.342 m. MDT fluid samples were taken at 2012.25
m (oil), 2032.5 m (oil), and 2059.6 m (water). PVT single flash analyses of the
samples from 2012.25 m gave GOR in the range 175 to 197 Sm3/Sm3 and oil density
in the range 0.847 to 0.849 g/cm3. The samples from 2032.5 m had GOR in the
range 168 to 177 Sm3/Sm3 and oil density in the range 0.851 to 0.852 g/cm3.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 26
December 2015 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One production test (DST) was performed
in the oil zone from 2006.83 to 2029.26 m. The test produced 47 Sm3 oil and
13300 Sm3 gas per day through a 32/64“ choke. The GOR was 280 Sm3/Sm3. The DST
temperature measured at 2019.9 m (1937.8 m TVD) was 77.4°C.</span></p>
7775
5/20/2022 12:00:00 AM
29.01.2023
16/1-26 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 A is a geological sidetrack
to well 16/1-26 S, both wells being drilled from the 16/1-D-9 West Cable oil
producer well on the Ivar Aasen Platform in the North Sea. The objective for
16/1-26 A was to prove additional reserves in the southern part of the West
Cable structure, west of the Ivar Aasen Field. West Cable is a Sleipner
Formation oil discovery made by well 16/1-7 in 2004.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-26 A was kicked off
from 16/1-26 S at 2925 m (1893.1 m TVD) on the 17 April 2016. It was drilled with
the jack-up installation Mærsk Interceptor to TD at 4888 m (3102 m TVD) m in
the Middle Jurassic Sleipner Formation. The well is highly deviated with
drilled inclination dropping from ca 60° at kick-off to ca 31° at TD.  No significant
problem was encountered in the operations. The well was drilled with Versatec
oil based mud all through. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Sleipner Formation was encountered at
4710 m (2959.2 m TVD, 2901.2 m MSL), above the OWC at 2940 m MSL in 16/1-7
Cable West. The Sleipner Formation contained approximately 75 metres TVD of
sandstone with moderate to good reservoir properties, but the reservoir was
proven to be entirely water bearing. No oil shows were recorded in this well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24
April as a dry appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



















































7940
4/25/2019 12:00:00 AM
29.01.2023
16/1-26 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 S was drilled deviated from the
16/1-D-9 West Cable oil producer well on the Ivar Aasen Platform in the North
Sea. The objective was to prove additional reserves in the southern part of the
West Cable structure, west of the Ivar Aasen Field. West Cable is a Sleipner
Formation oil discovery made by well 16/1-7 in 2004.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Exploration well 16/1-26 S was drilled
from below the 13 3/8 casing shoe at 2792.5 m in producer well 16/1-D-9. Spud
date for the exploration well was 3 April 2016. The well was drilled with the jack-up
installation Mærsk Interceptor to TD at 5330 m (2979 m TVD) in the Late
Triassic Skagerrak Formation. The well is highly deviated with a deviation of
ca 63 ° all through. No significant problem was encountered in the operations. The
well was drilled with Versatec oil based mud all through. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-26 S encountered gas and oil in
two Intra-Draupne Formation Sandstone units. Top of the upper sandstone is at
4726.2 m (2713.4 m TVD).The two sands are indicated not to be in pressure
communication. The upper sand is gas-filled, while the lower, with top at 4754
m (2725 m TVD) contain oil down to a lithological contact at 4773 m (2731 m
TVD) and with a possible 1-metre gas cap on top. The underlying sandstones of
the Statfjord Group and Skagerrak Formation are water wet. No Middle Jurassic
sediments are present in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut. No fluid sample was
taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 14
April 2018 as an oil and gas discovery</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>
























































7915
3/16/2018 12:00:00 AM
29.01.2023
16/1-27
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/1-27
was drilled on the Edvard Greg Field on the Utsira High in the North Sea. It
was drilled as an appraisal well to verify top reservoir and sand content in
the western part of the field.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Appraisal
well 16/1-27 was spudded with the semi-submersible installation Island
Innovator on 1 March 2017 and drilled to TD at 2258 m in Basement rock. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 611 m and with <span class=SpellE>Aquadril</span> mud with
4% glycol from 611 m to TD.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Top
reservoir, <span class=SpellE>Åsgard</span> Formation sandstone, was
encountered at 1962 m, directly overlying Triassic Skagerrak Formation sandstone
at 1968.35 m. The reservoir contained oil from top down to the OWC at 1978 m (1948
m TVD MSL), 9 meters deeper than the established FWL at 1939 m TVD MSL in the
central Edvard Grieg area. Pressure data showed one oil gradient through the
Cretaceous to Triassic sandstones, and two water gradients below the oil: one
in communication with the oil gradient and one with 6 bar higher pressure in
the lower conglomerates of the Skagerrak Formation, below a <span class=SpellE>shaly</span>
layer around 2150 m.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Apart
from shows in the reservoir section significant oil shows were recorded above
reservoir level. First oil show in the well was described in thin Oligocene
sandstones at 1309 to 1322.5 m as fair patchy straw yellow direct fluorescence,
fast blooming to streaming bluish white cut fluorescence, medium straw to bluish
white fluorescent residue, no visible residue. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>At 1506
to 1543 m, in thin Eocene Hordaland Group sandstones, there were oil shows described
as no to weak hydrocarbon odour, no to medium brown oil stain, patchy to even
weak to dull straw yellow to orange direct fluorescence, slow blooming to
streaming bluish white cut fluorescence, weak bluish white fluorescent residue,
no visible residue.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>At 1811
to 1858 m, in Early Eocene Balder Formation and base Hordaland group Tuff and limestone,
there were oil shows described as medium brown to dark brown oil stain, weak
spotty to patchy bluish white to light yellowish brown direct fluorescence,
slowly bleeding to blooming light yellowish brown cut fluorescence, no
fluorescent or visible residue. Below the OWC only poor shows were recorded
down to 2023 m.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Three
cores were cut. Core 1 was cut from 1967 to 1993.1 m with 95.8% recovery. The core-log
shift is +0.7 m. Core 2 was cut from 1993.1 to 2002.2 m with 78.8% recovery.
The core-log shift is +0.5 m, Core 3 was cut from 2002.2 to 2023 m with 98.7%
recovery. The core-log shift is -0.25 m. <span
style='mso-spacerun:yes'> </span>MDT fluid samples were taken at 1972.3 m (oil),
1976 m (oil), and 2025 m (water). The two oil sampling stations gave similar
oils according to PVT analysis, with GOR ranging from 120.3 to 123.2 Sm3/Sm3
and stock tank oil density ranging from 0.8545 to 0.8565 g/cm3.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
permanently abandoned on 11 April 2017 as an oil appraisal<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>


8124
11/11/2019 12:00:00 AM
29.01.2023
16/1-28 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-28 S was drilled to appraise
the 16/1-12 Rolvsnes Discovery on the Utsira High in the North Sea. The objective
was to verify pressure communication within the reservoir and determine
possible depletion resulting from production from the Edvard Grieg Field. Further
objectives were to prove the drillability of a 2.5 km long horizontal well
within granitic basement, and to perform a production test to better understand
the reservoir performance.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-28 S was spudded with
the semi-submersible installation COSL Innovator on 3 April and a 36 “x 42” was
drilled to 200 m.  A 9 7/8” pilot was drilled from 200  to 780 m due to shallow
gas warnings. No shallow gas was observed. Hole instability problems were
encountered in the 12 ¼” section, from 1742 to 2186 m, and this section was
unintentionally side-tracked at 1978 m while reaming. The side-track, 16/1-28
ST2, was drilled to final TD at 4880 m (1919 m TVD) in granite basement rock. The
well was drilled vertical down to 957 m, building angle from there to ca 2410
m, from where the well was drilled horizontally. A union strike delayed the DST
operations with approximately 11 days. The well was drilled with seawater and
hi-vis pills down to 957  m, with Aquadril mud from 957 m to 1734 m, with Delta
TEQ oil-based mud from 1734 m to 2180 m, and with Performadril mud from 2180 m to
TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Basement was encountered at 2335.5 m (1908.8
m TVD) and well TD was reached at 4880 m (1919.0 m TVD). A total horizontal
section of 2500 m in basement was drilled with an average penetration rate of
9.9 m/h. 65 pressure measurements were attempted, the successful tests showed a
depletion of about 10 bars, which can be the result of production from the
Edvard Grieg Field. Good oil shows were recorded throughout the fractured
granitic reservoir from 2336.5 to 4880 m, otherwise no shows were described in
the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Due mainly to wellbore instability
issues, no cores or sidewall cores were taken in wellbore 16/1-28 ST2. This
restricted the amount of petrographic data acquired to evaluate the degree and
type of alteration of the basement rock. Fluid samples were taken during the
DST</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 23
August 2018 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was formation-tested (DST) for
ten days. The well was tested from intervals separated by swell packers over
the whole reservoir section below 2417 m and production logging was carried out.
The maximum production rate was 1100 Sm3 oil per flow day through a 52/64”
nozzle opening. The main flow period of 5 days was held with a rate of 650 Sm3 oil
per day through a 52/64” nozzle opening. The oil is undersaturated with a
gas/oil ratio of 130 Sm3/Sm3. The DST temperature at Gauge depth 1852.4 m TVD was
77.6°C. </span></p>


8357
8/23/2020 12:00:00 AM
29.01.2023
16/1-29 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-29 S was drilled to test the Lille
Prinsen prospect on the north-western part of the Utsira High in the North Sea.
The exploration objective was to test the Lille Prinsen prospect, believed to mainly
consist of Triassic sediments, with the possibility of (thin) transgressive
Jurassic sands similar to Johan Sverdrup on top. In addition, the well was
expected to penetrate Grid and Heimdal sands, which were found to contain oil
and gas in the 16/1-6 S Verdandi well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-29 S was spudded with
the semi-submersible installation Deepsea Bergen on 22 April 2018. During the
operation, the well (16/1-29 S) experienced unexpected heavy mud losses when
drilling into the reservoir section, eventually leading to well collapse and
stuck drill string. Consequently, a technical side-track (16/1-29 ST2) was
kicked off at 1225 m and this was successfully drilled through the reservoir
section. Continuous mud losses were also experienced in the reservoir section
of the technical side-track, but these were controlled by lowering the mud
weight. The well was finally drilled to planned TD at 2024 m (2010 m TVD) in Basement
rock. The well was drilled with seawater and hi-vis pills down to 550  m, with
KCl mud from 550 m to 1210 m, with Enviromul oil-based mud from 1210 m to 1863
m (mainwell and side-track) and with KCl/polymer/GEM mud from 1863 m to final TD.
</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Eocene Grid Formation and the
Paleocene Heimdal Formation were encountered at 1419 m (1416 m TVD), and 1794 m
(1785 m TVD), respectively. They both contained gas over oil. In the Grid
formation a gas-oil contact was found at 1462.6 m (1459.9 m TVD) with a free
water level at 1498.9 m (1495.8 m TVD). In the Heimdal Formation a gas-oil
contact was found at 1808.1 m (1798.4 m TVD) with a thin oil leg down-to 1809.2
m (1799.5 m TVD). The oil-leg was confirmed by PVT analyses, which  found the
fluid samples taken at 1808.5 m (1798.8 m TVD) to contain both gas-condensate
and black oil. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well did not encounter any of the
expected Jurassic/Triassic sands, but instead encountered 26.6 m of oil filled
Permian Zechstein Group Dolostone carbonates with top at 1885 m (1874 m TVD), immediately
below the Cretaceous Shetland Group. The Permian Carbonates show varying, but
good reservoir quality, with an average net/gross of 0.91 and porosity of 23%. The
core and thin sections show variations within the carbonate reservoir, with the
better zones in the upper parts, which can be associated with vuggy porosity,
low content of calcite cement and karst development.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Poor shows were described from drilled
cuttings in Grid sand at 1475 m and in Heimdal sand at 1800 m. Shows from
drilled cuttings in Zechstein were described as patchy even brown oil stain,
even yellow direct fluorescence, weak blooming cut and weak patchy yellow
residual. Oil shows (direct and cut fluorescence and spots of oil stain)
continued in basement down to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut in the technical side-track
from 1888.2 to 1907.5 m in the Permian Zechstein Group. MDT fluid samples were
taken at 1474.5 m (oil with 3% mud contamination), 1808.5 m (gas-condensate and
oil with &lt;1% mud contamination), 1892.5 m (oil, no mud contamination), and
1985.7 m (formation water and filtrate).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3
June 2018 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>










8383
6/3/2020 12:00:00 AM
29.01.2023
16/1-3

<p><b>General</b></p>

<p>Well 16/1-3 is located on the Gudrun
Terrace west of the Utsira High. The main objective of the well was to evaluate
the hydrocarbon potential of Jurassic sand reservoirs. Eocene and Paleocene
sands were secondary objectives. 16/1-3 was drilled on the flank of a
seismically defined structure. The prime crestal location could not be tested
due to the presence of a telephone cable on the sea floor. </p>

<p><b>Operations and results</b></p>

<p>Well 16/1-3 was spudded with the
semi-submersible installation Glomar Biscay II on 29 July 1982 and drilled to
TD at 3498 m in granite basement. After losing returns while drilling at 210 m,
the 30&quot; casing was re-cemented. Shallow gas was encountered between 400
and 444 meters. Tight hole, swabbing on trips and reaming were recurrent
problems in the 12 1/4&quot; hole due mainly to swelling of claystone and
siltstone. Mud was lost when drilling through a flint layer at 2638 m. The well
was drilled with seawater and bentonite down to 702 m, with a
lignosulphonate/CMC mud from 702 m to 2282 m, and with lignosulphonate/lignite
mud from 2282 m to TD.</p>

<p>Mechanical log analysis over the Jurassic
interval indicated the presence of about 60 meters of gross sand. Two thin
zones of approximately 4 meters each in thickness were interpreted to be
hydrocarbon bearing. The remaining sands were judged to be water bearing or
non-reservoir. No reservoir was believed to be present in the Triassic sand,
siltstones and shales. Minor shows, consisting of stain, fluorescence and/or
mud gas manifestations were recorded in the Pliocene-Eocene, Miocene and
Paleocene sections. In addition, oily mud was recovered in one of the MFT
samples from the Jurassic Sleipner Formation. The Zechstein formation contained
generally tight anhydritic dolomites at the top. A porous but interpreted water
bearing limestone section was found in the middle portion of the Zechstein
Group. Below the limestone a 36 m thick sandstone sequence was encountered. At
the base of the Zechstein Group 3 m of Kupferschiefer Formation was
encountered. The Kupferschiefer Formation is present in several wells in the
area. The Permian Rotliegendes formation contained poor reservoir quality
felspathic sandstones, siltstones and shales. Also the Permian reservoirs
appeared to be water bearing on wire line logs. </p>

<p>One core was cut from 2282 m to 2290.5 m
in the Lista Formation. Two Multi Formation Test (MFT) samples were taken at
2742 m and 2742.5 m in a thin sand in the Jurassic Sleipner Formation. The
first sample contained mud filtrate only. The second sample contained mud
filtrate and 75 cc of light gravity oil. The well was permanently abandoned as
a dry well with shows on 27 September 1982.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed </p>


84
5/19/2016 12:00:00 AM
29.01.2023
16/1-30 A
<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 A Lille Prinsen Outer Wedge was
drilled to appraise the 16/1-29 Lille Prinsen Discovery in</span><span
class=a1455><span lang=EN-US> the north-western part of the Utsira High in the
North Sea. The structure was first tested by wells 16/1-6S and 16/1-6 A, which made
the Verdandi Discovery in the Eocene Grid and the Paleocene Heimdal formations.
The Lille Prinsen prospect is mapped in several geographically separate segments
at Basement to Base Cretaceous level. These segments are: The Permian Main Carbonate
Discovery penetrated by 16/1-29 S, the western Outer Wedge segment, and segments
2,3 and 5 (Carbonate upsides).</span></span><span lang=EN-US> </span><span
lang=EN-GB>The primary well 16/1-30 S found oil in Intra-Draupne Formation
sandstone in the Outer Wedge segment. The objective of 16/1-30 A was to verify
lateral reservoir distribution and quality of the Outer Wedge reservoir units.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-30 A is a geological
side-track to 16/1-30 S. It was kicked off at 1307.2 m on 2. July 2019 with the
semi-submersible installation West Phoenix and drilled to TD at 2075 m (1989 m
TVD) m in Basement rock. Operations proceeded without significant problems. The
well was drilled with Versatec oil-based mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 A encountered Viking Group
sandstone and Basement Group granite reservoirs. Some shows were observed on
the core chips from the Intra-Heather reservoir. MDT pressure points showed an
oil gradient in Intra-Heather Formation sandstone down to 2031 m (1951.2 m TVD).
Good shows with fluorescence odour and stain were recorded from top Intra-Heather
Formation sandstone down to ca 2030 m. The log responses in Basement indicate
the granite is oil filled at the top and water-bearing below ca 2045 m. However,
MDT pressure logging gave no valid pressure points here (tight) and no shows
were observed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut. Core 1 was cut from
1993 to 2029 m with 92.3% recovery, capturing Shetland Group claystone and
limestone and Intra-Heather Formation reservoir sandstone. The core-log depth
shift is 2.3 m. Core 2 was cut from 2030 to 2039.46 m with 72.8% recovery,
capturing basal Heather Formation claystone and granitic basement. The core-log
depth shift is 4.5 m. MDT fluid samples were taken at 2026.5 m (oil with 6% OBM
contamination) in Intra-Heather Formation sandstone.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 19
July 2019 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>
8749
11/11/2021 12:00:00 AM
29.01.2023
16/1-30 S


<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 S Lille Prinsen Outer Wedge was
drilled to appraise the 16/1-29 Lille Prinsen Discovery o</span><span
class=a1455><span lang=EN-US>n the north-western part of the Utsira High in the
North Sea. The structure was first tested by wells 16/1-6S and 16/1-6 A, which made
the Verdandi Discovery in the Eocene Grid and Paleocene Heimdal formations. The
Lille Prinsen prospect is mapped in several geographically separate segments at
Basement to Base Cretaceous level. These segments are: The Permian Main Carbonate
Discovery penetrated by 16/1-29 S, the western Outer Wedge segment, and segments
2,3 and 5 (Carbonate upsides).</span></span><span lang=EN-US> </span><span
lang=EN-GB>The primary objective of 16/1-30 S was to appraise the Outer Wedge
segment believed to consist of Permian carbonates in  the 16/1-29 S with an
overlying package of Triassic to Early Cretaceous siliciclastics. The secondary
objective in 16/1-30 S was to appraise the oil and gas in the Grid and Heimdal
formations found in the 16/1-6 S Verdandi discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-30 S was spudded with
the semi-submersible installation West Phoenix on 27 May 2019 and drilled to TD
at 2140 m (1990 m TVD) m in basement rock. Operations proceeded without
significant problems. The well was drilled with seawater and hi-vis pills down to
572 m, with Glydril mud from 572 to 1361 m, and with Versatec oil-based mud
from 1361 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-30 S encountered poor quality
oil-filled sandstone in the Grid Formation. Shows were observed on core and
cuttings in the interval 1499 to 1421 m, including fluorescence and oil stain,
and the log responses indicated the sandstone being oil filled. MDT pressure
points was not conclusive due to poor reservoir quality, but oil was sampled at
1507.1 m and water at 1548 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Heimdal Formation was not present.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Good quality Viking Group sandstone and
Basement Group granite reservoirs were encountered in the primary target. Shows
were observed on core chips and sidewall cores in the interval 2016 to 2047 m,
including odour, oil stains, fluorescence, and oil seeping from SWC’s. MDT
pressure points confirmed an oil and a water gradient in the Viking Group. Oil
was sampled at 2023.8 m and water at 2042.7 m, and the oil and water gradients
intersect at ca 2029 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut. Core 1 was cut in
the Grid Formation from 1510.9 to 1537.9 m. Cores 2 to 4 were cut in the
interval 2023.2 to 2104.3 m in Intra-Draupne and Intra-Heather sandstones and
upper part of Basement. The core-log depth shifts are 0.9 m, 6.2 m, 0.6 m, and
2.05 m respectively for core 1, 2, 3, and 4. MDT fluid samples were taken at
1507.1 m (oil with 8 to 14% OBM contamination) and 1548 m (water) in the Grid
Formation, and at 2023.76 m (oil with 8 to 15% OBM contamination) and 2042.7 m
(water) in the Viking Group.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
July 2019 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>
8748
11/11/2021 12:00:00 AM
29.01.2023
16/1-31 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-31 A  was drilled in the northern
margin of the Edvard Grieg Field on the Utsira High in the North Sea. The
primary objective was to appraise the reservoir quality, fluid properties,
hydrocarbon potential and productivity of potential reservoir rocks on the
eastward continuation of the Edvard Grieg basement high.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-31 A was spudded with
the semi-submersible installation Leiv Eiriksson on 11 May 2019 and drilled to
TD at 2650 m (2002.6 m TVD) m in granitic basement rocks. Operations proceeded
without significant problems. The well was drilled with seawater and hi-vis
pills down to 1404 m, with Innovert oil-based mud from 1404 m to 2267 m, and
with Baradril N water-based mud from 2267 m to TD. </span></p>

<p class=MsoNormal><span lang=EN-GB style='font-family:"Times New Roman",serif;
font-weight:normal'>The Tellus East appraisal well encountered a gross oil
column of 60 metres in porous, weathered basement reservoir. Top reservoir was
encountered at 2350.1 m (1874.8 m TVD). The oil/water contact is estimated to
be between 2492 and 2497 m (1935 and 1937 m TVD). No oil shows were observed
above top reservoir. Partly continuous shows with petroleum odour, stain, cut,
and direct fluorescence were seen in basement down to 2390 m. Below this depth sporadic
shows were observed with direct and cut fluorescence, but without odour or
stain down to 2460 m.</span></p>

<p class=MsoBodyText><span lang=EN-US>Three cores were cut in succession from
2357 to 2369.05 m with 85% total recovery. MDT pressure data indicated ca 4
bars depletion relative to the 16/1-13 Edvard Grieg well. MDT fluid samples
were taken at 2351.51 m (oil), 2362.01 m (water), 2389.5 m (oil), 2410.4 m
(oil), 2452.71 m (oil), 2492.70 m (oil and water), 2497.68 m (water), 2513.91 m
(water), and 2538.0 m (water). The oil composition indicated same oil as in the
Edvard Grieg oil population.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22
June 2019 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>
8758
12/21/2021 12:00:00 AM
29.01.2023
16/1-31 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-31 S was drilled to test the
Jorvik prospect on the Utsira High, about 4 kilometres northeast of the Edvard
Grieg platform in the North Sea. The primary objective was to prove oil in
conglomerates from the Triassic Age in an extension of the Edvard Grieg basin toward
the east. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-31 S was spudded with
the semi-submersible installation Leiv Eiriksson on 10 March 2019 and drilled
to TD at 2220 m in conglomerates of indeterminate Triassic to Permian age. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 602 m and with Polymer water-based mud from 602 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated the Early Cretaceous
Åsgard Formation directly overlying top of the target reservoir at 1938 m
(1866.4 m TVD). The reservoir contained an oil column of about 30 metres in
conglomerates and conglomeratic sandstones, presumably of Triassic Age and with
generally poor reservoir quality. There was around one metre of sandstone of
good quality in the upper part of the reservoir section. The oil/water contact
was not proven. Pressure measurements showed that the area is in communication with
the Edvard Grieg field. The reservoir pressure was depleted 9-10 bar compared
to the Edvard Grieg before start of production.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Below 1968 m and down to 2028 m shows are
described on cores as: faint to moderate odour, 40% patchy weak, dark yellow
direct fluorescence, slow blooming good bluish white cut fluorescence, 30% moderately,
cream fluorescent residue. Patchy shows (cut and fluorescence) was described on
sidewall cores down to 2176.5 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1940
to 2034.5 m. Recoveries were 100%, 97.7%, and 99.3% in cores 1, 2 and 3
respectively. MDT fluid samples were taken at 1938.61 m (oil) and 1964.57 m
(oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back for side-tracking
(16/1-31 A) on 10 May 2019. The well was initially classified as a wildcat but has
been reclassified as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A drill stem test was conducted from
perforations in the interval 1945.15 to 2001.9 m. The test produced oil and gas
at relatively low rates, between 21 to 24 Sm3 oil and 4900 to 8000 Sm3 gas /day
through a 26/64” choke. The GOR was between 233 and 333 Sm3/Sm3, but this was likely
not representative due to slugging. The temperature at gauge depth 1920.9 m was
80.2°C.</span></p>
8655
12/22/2021 12:00:00 AM
29.01.2023
16/1-33 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-33 S was drilled to test the Sørvesten
prospect on the Gudrun Terrace west of the Utsira High in the North Sea. The
primary objective was to test the hydrocarbon potential in the Middle Jurassic
Sleipner Formation and the Triassic Skagerrak Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-33 S was spudded with
the semi-submersible installation Leiv Eiriksson on 10 July 2020 by tagging
seabed with the 9 7/8&quot; pilot hole BHA. The shallow gas pilot hole was
drilled to 555 m, 5 m deeper than the planned setting depth for the 20&quot;
surface casing. No shallow gas was encountered. Drilling proceeded to final TD
at 3158 m (3066.8 m TVD) m in the Late Triassic Skagerrak Formation. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 553 m and with Rheguard oil-based mud from 553 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No hydrocarbons were encountered in any
formation. Seven pressure points were taken with Stethoscope LWD tool on the
way out of hole, proving a hydrostatic pressure slightly depleted compared to
the regional pressure regime. Apart from some fluorescence in traces of sand in
the Draupne and Heather formations there were no shows in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut, no wireline runs were made,
and no fluid sample was taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6
August 2020 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

9062
12/21/2021 12:00:00 AM
29.01.2023
16/1-4
<p><b>General</b></p>
<p>The objectives of
exploration well 16/1-4 were to test Paleocene sandstones (Heimdal Formation)
in prospect C and Eocene sandstones (Grid Formation) in prospect D. Prospect C
was the main target. Oil was the prognosed hydrocarbon type. It was expected to
penetrate a pre-Cretaceous sedimentary sequence, although the well location was
not optimal for a test of the pre-Cretaceous. </p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/1-4
was spudded with the semi-submersible installation &quot;Deepsea Bergen&quot;
on 17 March 1993 and drilled to TD at 2010 m, 146 m into basement rocks. The
well was drilled with spud mud / hi-vis pills down to 324 m and with &quot;ANCO
2000&quot; mud from 324 m to TD. Well 16/1-4 penetrated sedimentary rocks of
Quaternary, Tertiary, and Cretaceous ages, in addition to basement rocks of
unknown age. No pre-Cretaceous sediments were present in the well. In the
Tertiary, reservoir quality sandstones were present in the Miocene and the
Oligocene (Utsira and Skade Formations) and in the Eocene Grid Formation. The
Grid sandstones were thinner than expected. No sandstones were developed in the
Paleocene (Rogaland Group) at the well location. The carbonates in the Shetland
Group were dated to be of Early Paleocene, Danian age. The lower Cretaceous
sediments in well 16/1-4 are 4 m thick (1860 m -1864 m) and consist of clay
stone/marls and immature sandstones with grains of igneous rocks similar to the
basement rocks below. These sediments are dated to be of Early Aptian age and
have been identified as the Sola Formation of the Cromer Knoll Group. The
basement rocks consist mainly of brecciated igneous rocks. No hydrocarbon shows were observed in the Grid Formation sandstones.
Gas-condensate was encountered in the upper part of the drilled basement section.
Cores were cut in the Eocene Grid Formation and in the Hordaland Group shales
between upper and lower Grid Formation (cores 1-3), in the Paleocene Balder-
and Sele Formations (cores 4-6), and in basement rocks (core 7).</p>

<p>The cores show
well-developed clean sandstones in the Grid Formation. The boundary between the
Balder- and the Sele Formations is present in core 4. The basement core
generally consists of a mafic plutonic rock (gabbro/diorite) with intrusions of
a felsic rock (syenite). The rocks are strongly brecciated. Petrologic analysis
indicates that the plutonic igneous rocks are hydrothermally altered. FMT
samples from1867.5 m and 1867.4 m in the Basement contained wet gas /
condensate. Onshore geochemical analyses indicated low maturity for both the
gas and the condensate components. The well was permanently abandoned as a minor gas/condensate discovery on 13 April 1993.</p>

<p>&nbsp;</p>

<p><b>Testing</b></p>

<p>No drill stem test
was performed. </p>



2072
9/10/2016 12:00:00 AM
29.01.2023
16/1-5
<b>
General
</b>
<p>
The objectives of well 16/1-5 were to prove hydrocarbon reserves in the Upper Jurassic (Oxfordian - Ryazanian) shallow marine sandstone as well as in the Middle Jurassic shallow to marginal marine sandstone. The well was also planned to provide a good stratigraphic tie to the Paleocene interval and test the possibility for Paleocene sands. A high amplitude at around 2070 ms TWT was also meant to be clarified with this well.
The objective of the 16/1-5A sidetrack was to prove hydrocarbon reserves in an Upper Jurassic shallow marine sandstone, up-dip from the hydrocarbon shows that were recorded in well 16/1-5.
</p>
<b>
Operations and results
</b>
<p>
The main well, 16/1-5, was spudded and drilled with a water based mud to a total depth of 2460 m RKB.
Both the Upper Jurassic sandstone, the Heather Formation "Sandstone Unit", and the Middle Jurassic Hugin Formation were encountered. Both sandstone sequences were water bearing, but oil shows were recorded in the upper 3 meters of the Heather Formation. A good stratigraphic tie to the Paleocene interval was established by the well, but no Paleocene sands were encountered. The high amplitude, observed on the seismic data at approximately 2070 ms TWT, most probably stems from the acoustic impedance contrast between the Heather sandstone - siltstone boundary and/or the Heather - Hugin boundary.
No Permian sediments were encountered, with a stratigraphic succession going directly from Jurassic sediments into the Basement. Well 16/1-5 was terminated 194.5 m TVD into the Basement. Three cores were cut in the interval 2023 to 2066 m RKB in the Heather Formation. An FMT sample from 2024.5 m contained formation water and filtrate. The well was classified as dry.
<br>
The sidetrack, 16/1-5 A, was kicked off at 1440 m RKB and a 8 1/2" hole section was drilled to a total depth of 2150 m with no casing strings run. Oil based mud was used from kick off to TD. The well encountered the Heather Formation "Sandstone Unit" close to prognosis. Moderate hydrocarbon shows were recorded in the thin, Cretaceous limestone sequence above the Heather Formation as well as in the upper 8 meters of the Heather Formation sandstone. The sidetrack was terminated 24 m TVD into the Heather Formation where a core was cut from 2123 m RKB to TD. No wire line logs were run and the well was permanently plugged and abandoned.
</p>
<b>
Testing
</b>
<p>
No drill stem test was performed.
</p>



3279
7/6/2016 12:00:00 AM
29.01.2023
16/1-5 A
<b>
General
</b>
<p>
The objectives of well 16/1-5 were to prove hydrocarbon reserves in the Upper Jurassic (Oxfordian - Ryazanian) shallow marine sandstone as well as in the Middle Jurassic shallow to marginal marine sandstone. The well was also planned to provide a good stratigraphic tie to the Paleocene interval and test the possibility for Paleocene sands. A high amplitude at around 2070 ms TWT was also meant to be clarified with this well.
The objective of the 16/1-5A sidetrack was to prove hydrocarbon reserves in an Upper Jurassic shallow marine sandstone, up-dip from the hydrocarbon shows that were recorded in well 16/1-5.
</p>
<b>
Operations and results
</b>
<p>
The main well, 16/1-5, was spudded and drilled with a water based mud to a total depth of 2460 m RKB.
Both the Upper Jurassic sandstone, the Heather Formation "Sandstone Unit", and the Middle Jurassic Hugin Formation were encountered. Both sandstone sequences were water bearing, but oil shows were recorded in the upper 3 meters of the Heather Formation. A good stratigraphic tie to the Paleocene interval was established by the well, but no Paleocene sands were encountered. The high amplitude, observed on the seismic data at approximately 2070 ms TWT, most probably stems from the acoustic impedance contrast between the Heather sandstone - siltstone boundary and/or the Heather - Hugin boundary.
No Permian sediments were encountered, with a stratigraphic succession going directly from Jurassic sediments into the Basement. Well 16/1-5 was terminated 194.5 m TVD into the Basement. Three cores were cut in the interval 2023 to 2066 m RKB in the Heather Formation. An FMT sample from 2024.5 m contained formation water and filtrate. The well was classified as dry.
<br>
The sidetrack, 1671-5 A, was kicked off at 1440 m RKB and a 8 1/2" hole section was drilled to a total depth of 2150 m with no casing strings run. Oil based mud was used from kick off to TD. The well encountered the Heather Formation "Sandstone Unit" close to prognosis. Moderate hydrocarbon shows were recorded in the thin, Cretaceous limestone sequence above the Heather Formation as well as in the upper 8 meters of the Heather Formation sandstone. The sidetrack was terminated 24 m TVD into the Heather Formation where a core was cut from 2123 m RKB to TD. No wire line logs were run and the well was permanently plugged and abandoned.
</p>
<b>
Testing
</b>
<p>
No drill stem test was performed.
</p>



3626
7/6/2016 12:00:00 AM
29.01.2023
16/1-6 A

<p><b>General</b></p>

<p>Well 16/1-6 A is a sidetrack to the
16/1-6 S discovery on the Utsira High in the North Sea. The objective of well
16/1-6A was to penetrate the Heimdal Formation down flank, where a flat event
had been mapped, in order to appraise the extent of the gas discovery and
possibly penetrate a hydrocarbon - water contact.</p>

<p><b>Operations and results</b></p>

<p>Appraisal well 16/1-6 A was spudded with
the semi-submersible installation Borgland Dolphin on 8 June 2003. The well was
kicked off at 1215 m in 16/1-6 S and drilled to TD at 2194 m in the Late
Cretaceous Tor Formation. It was drilled with oil-based mud (Novatec) from
kick-off to TD. </p>

<p>Grid sands were penetrated from 1529.5 m
(1480.5 m TVD MSL) to 1757 m (m TVD MSL). The Heimdal Formation came in at 2006.5
m (1850.5 m TVD MSL), which was considerably deeper than expected. The Heimdal
Formation was also thinner than expected. Wire line and MWD logs showed
relatively high resistivity readings combined with high porosity within the
uppermost 2 ? 3 m of the Grid sandstone, but no conclusions regarding the
presence of hydrocarbons could be drawn from these weak indications. Weak shows
in the Heimdal Formation were considered to be residual only. From logs both
the Grid and the Heimdal sandstones were concluded to be water wet. One core
was attempted in the Grid Formation, but junk in the hole prevented the core
from entering the core barrel, hence no recovery. MWD log data were collected
from the whole well track, while the majority of the wire line logging,
including MDT and VSP, had to be abandoned due to tight, partly collapsed hole.
</p>

<p>The well was permanently abandoned on 21
June 2003 as a dry hole.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


4767
7/6/2016 12:00:00 AM
29.01.2023
16/1-6 S

<p><b>General</b></p>

<p>Wildcat well16/1-6 S is located on the
Utsira High in the North Sea. The objective was to test the hydrocarbon
potential of the Verdandi prospect on Paleocene level in a favourable position
with respect to an observed DHI, interpreted tentatively as a gas-oil contact
in a reservoir sand.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/1-6 S was spudded with
the semi-submersible installation Borgland Dolphin on 22 May 2003 and drilled
to TD at 1997 m in the Late Cretaceous Ekofisk Formation. Sidewall coring and
VSP logging could not be performed below 1762 m due to hole problems. Apart
from this no significant problems were encountered in the operations. The well
was drilled with seawater and viscous bentonite/polymer pills down to 551 m, with
KCl/polymer/glycol (Glydril) mud from 551 m to 1200 m, and with oil based mud
(Novatec pseudo oil based) from 1200 m to TD. </p>

<p>MWD logs and drill gas indicated shallow
gas in a sandstone stringer at 603 m. This gas correlate well with nearby
wells, particularly well 16/1-4. </p>

<p>Grid sandstones were encountered between
1489.5 m (1451 m TVD MSL) to 1685 m (1617.5 m TVD MSL). Top Heimdal Formation
came in at 1861.5 m (1765 m TVD MSL). It proved to be slightly deeper and
significantly thinner than expected. Hydrocarbons were proven in the Grid sands
as well as in the Heimdal sand. A distinct gas peak of 2.55 %, C1 to C4, was
recorded from 1498 m in the upper Grid Formation. Log responses indicated thin,
hydrocarbon filled stringers of sand positioned above the massive Grid
sandstone. Cuttings exhibited calcareous sand with traces of hydrocarbon stain
and with spotty to even, bright, bluish white, direct fluorescence with
instant, white cut fluorescence. MDT hydrocarbon samples confirmed the presence
of oil, with a density of 0.857 g/cm³. No shows were seen in the underlying,
massive Grid sandstone with logs confirming a water-wet sandstone. Furthermore
gas was found in the Heimdal Formation with a ?gas down to? situation. One
conventional core was cut from 1872 m to 1899 m in the Heimdal Formation.
Sidewall cores were recovered from the Grid Formation sandstones. MDT
hydrocarbon samples were collected from 1499 m in the Grid Formation and 1870.5
m in the Heimdal Formation. Oil based mud contamination was as high as 59 % in
the Heimdal sample which gave limited value for PVT analysis. The oil sample
collected in the Grid sandstone was of good quality with contamination
calculated to 16 %. </p>

<p>The well was permanently abandoned on 7
June as an oil and gas discovery.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>


4711
7/6/2016 12:00:00 AM
29.01.2023
16/1-7


<p><b>General</b></p>

<p>The primary objective of well 16/1-7 was
to test the hydrocarbon potential of the West Cable prospect. The prospect was
located on the eastern margin of the South Viking Graben southwest of the
Utsira High in the North Sea, approximately 35 km southwest of the Balder
Field. The main objective of the well was to test the hydrocarbon potential of
the Sleipner Formation coastal plain sandstone reservoir of Callovian and
Bathonian age. The hydrocarbon potential of the Late Jurassic Heather and
Draupne Formations, and the Tertiary Lista and Våle Formations were considered
as secondary objectives. The anticipated hydrocarbon type was light oil.
Planned TD was 50 m into Triassic sediments.</p>

<p><b>Operations and results</b></p>

<p>Well 16/1-7 was spudded with the
semi-submersible installation Deepsea Delta on 29 April 2004 and drilled to TD
at 3186 m 103 m into in the Late Triassic Skagerrak Formation. No significant
problems were reported from the operations. The well was drilled with seawater
+ high viscosity polymer sweeps down to 1286 m and with Versavert oil based mud
from 1286 m to TD. No shallow gas was observed.</p>

<p>A 73 m thick Heimdal Formation (Meile
Member) was encountered at 2327 m. The Formation was water wet with no shows.
No sands were developed in the Late Jurassic. The well discovered a 14.0 m
(11.0 m net) oil bearing sand between 2955.5 and 2969.4 m (logging depth) in
the Sleipner Formation. The RCI tool was used to take pressures and samples. The
reservoir was normally pressured. Four 840 cc and two 4 litre samples were
taken in the oil zone at 2965 m, 2964.1 m and two 840 cc samples were taken in
the water zone at 2977.5 m, 2976.5 m. The interpreted Free Water Level was at
2969.9 m. No conventional coring was performed in the well.</p>

<p>The well was permanently abandoned on 28
May 2004 as an oil Discovery.</p>

<p><b>Testing</b></p>

<p>The discovery was tested using RCI
straddle packer assembly (also called mini drill stem tests) at 2975 m, 2964.5
m and 2959.5 m (logging depth). </p>



4928
4/11/2017 12:00:00 AM
29.01.2023
16/1-8




<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 was drilled on the Luno
Prospect on the eastern margin of the South Viking Graben on the south-western
part of the Utsira High in the North Sea. The Luno prospect is situated between
well 16/1-5 with oil shows in Late Jurassic and 16/1-4 with gas/condensate
discovery in fractured basement rocks and up dip from the 16/1-7 Jurassic
discovery. The primary objective of well 16/1-8 was to test the hydrocarbon
potential in Late Jurassic sandstones of the Viking Group. Secondary objectives
were to assess the quality of the Eocene Grid Formation and Permo-Triassic
sandstones. Total depth was planned in basement at 2173 +/- 50 m.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 was spudded with the
semi-submersible installation Bredford Dolphin on 8 September 2007 and drilled
to TD at 2200 m in undefined Triassic formations consisting of conglomerates,
sandstones and claystone. A shallow gas zone was warned and encountered in a
thin sand from 634 - 638 m. Downtime (NPT) for the operations was as much as
33% of total rig time. Forty-four per cent of the total NPT was due to WOW
before anchor handling. Another 14 % of NPT was caused by problems with
cementing the 13 3/8&quot; casing. In addition formation characteristics in the
reservoir made operations challenging, and combined with increased formation
evaluation scope; time spent on coring, logging and drilling to TD drastically
increased compared to plan. The well was drilled with seawater and hi-vis pills
down to 400 m, with KCl/glycol enhanced mud (GEM) from 400 to 1196 m, and with
Performadril mud from 1196 m to TD. Performadril may contain up to 5%
polyakylene glycols.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Eocene sandstones of the Grid
Formation at 1556 m were found water bearing with normal pressure gradient. Top
Jurassic was encountered at 1925 m and contained sandstones and conglomerates
with hydrocarbon shows. A 2 m thick and questionable Late Jurassic sequence was
seen on top. Palynoflora at 1930.7 m suggested a Middle to Early Jurassic age. Hydrocarbons
were encountered from 1925 m down to an OWC based on MDT pressure data at ca 1965
m, which gives an oil column of ca 40 m. Shows on cores continued down to
1966.3 m. No shows were recorded below this depth or above 1925 m. The
reservoir was not easily characterized by log data as these were affected by
feldspar rich conglomerates and other electrically conductive materials.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut. The
first two were taken in the hydrocarbon bearing interval and the third in the
water bearing interval. MDT pressure and fluid sampling was carried out and the
fluid gradients were determined (oil and water). The fluid samples were taken
at 1933.6 m, 1939.4 m, 1952.8 m, and 1956.4 m (oil), and at 1982 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The plan was to permanently abandon the
well, but due to the characteristics of the discovery, a decision was made to
temporary abandon the well with the purpose of re-entering to perform a DST at
a later stage. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was suspended on 13 November
2007 as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5612
4/11/2017 12:00:00 AM
29.01.2023
16/1-8 R











<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/1-8 R is a re-entry of well
16/1-8, which made the Luno discover in Jurassic sandstone and conglomerate.
The purpose of the re-entry was testing and plugging of the bore hole.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/1-8 R was re-entered
with the semi-submersible installation Transocean Winner on 2 October 2009. </span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut and no wire line fluid
samples were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>After testing the well was permanently
abandoned on 10 October.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was perforated and tested in two
intervals with flow rate up to approximately 3547 barrels of oil per day (564
Sm3/day) through a one inch (40/64&quot;) choke.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>






















6226
4/2/2020 12:00:00 AM
29.01.2023
16/1-9


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 16/1-9 Draupne prospect is located on
the eastern margin of the South Viking Graben in the North Sea. The structure is
situated in the eastern part of the Gudrun Terrace and the western flank of the
Utsira High. The primary target was a faulted anticline trap within Hugin/Sleipner
reservoir sandstones of Middle Jurassic Bajocian - Callovian age. A secondary
target was mapped on a four way dip closure within the Paleocene top Heimdal
level, the Gugne prospect. Well 16/1-9 was planned as a vertical well with TD ca
50 m into the Hugin/Sleipner Formation if water bearing, or ca 50 m into the
Triassic Skagerrak Formation in case of a discovery. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/1-9 was spudded with the
semi-submersible installation Bredford Dolphin on 19 February 2008 and drilled
to TD at 2544 m in the Late Triassic Skagerrak Formation. A pilot hole was
drilled prior to the 36&quot; section. No signs of shallow gas were observed or
seen on MWD logs. Significant downtime resulted from a shallow water flow
beside the well (5.2 days), wait on weather (4.3 days), BOP acoustic failure
(3.5 days), poor hole conditions (2.9 days) and stuck wire line (2.2 days). The
well was drilled with Seawater and sweeps down to 600 m, with KCl/GEM mud from
600 m to 1281 m, and with Performadril mud from 1281 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The secondary target Heimdal Formation
was entered at 2126.0 m (2123.2 m TVD), approximately 100 meters deeper than
the prognosed depth, and it was dry. The Sleipner Formation sandstone was encountered
at 2399.0 m (2393.2 m TVD), 167 TVD meters deeper than prognosed. The Skagerrak Formation was encountered at 2411 m (2405 m TVD), 23 TVD meters shallower than prognosed. The wire line
logs proved a thin gas cap from 2399 m (2368 m TVD MSL) to about 2407.5 m
(2376.5 m TVD MSL), oil down to 2442.5 m (2411 m TVD MSL) and oil shows on
cuttings down to 2448 m. There was no indication of an oil-water contact from
the logs. The reservoir quality is variable with good reservoir sands disrupted
by shale layers and cemented zones (carbonate nodules/clasts).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Apart from shows in the Sleipner and Skagerrak formations
reservoir zone oil shows were observed also in thin Hordaland Group sandstones
from 1510 to 1540 meters.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut at 2417.5 to 2426.9 m in
the Skagerrak Formation with 100% recovery. The MDT tool was run on wire line. One
gas and one oil sample were taken at 2405.0 and 2419.5 m respectively. During the
MDT run the wire line cable got stuck and further wire line operations were
terminated.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 22
April 2008 as an oil discovery</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>


5773
4/11/2017 12:00:00 AM
29.01.2023
16/2-1
<p><b>General</b></p>

<p>Well 16/2-1 is located on the very
western part of the Utsira High in the central part of the Vestland Arch. The
Utsira High is a large, flat, fault bounded basement feature. The objective of
this early well in the North Sea was: &quot;To test the hydrocarbon potential
of the sedimentary section; investigate the lithology and sequence in this
portion of the North Sea basin; and to partially fulfil Esso's drilling
obligation to the Norwegian Government incurred on behalf of the Licences.&quot;
</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/2-1 was spudded with the
semi-submersible installation Ocean Traveler on 11 July 1967 and drilled to TD
at 1906 m, 33 m into basement rock. There were no noteworthy drilling problems
encountered while drilling. Initial drilling from the sea floor to 381 m was
with seawater and gel without casing. Returns were to the sea floor. Below 381
m to total depth of 1906 m, a seawater slurry with gel, CMC, Spersene, XP-20,
Caustic Soda, Barite, and 0-10% diesel oil was used.</p>

<p>Oil shows were seen on cores in tight
Cretaceous carbonate rocks in the Tor Formation. The shows were strong and
continuous from top Tor Formation down to 1776 m, and then became patchy. These
rocks were too impermeable to justify further tests in this well. Weak shows
were seen also in a thin Oligocene sand from 1256 m to 1263 m and in Eocene
mudstones from 1631 m to 1637 m, Balder Formation. Dead oil/tar was observed in
fractures in the basement rock. </p>

<p>Five cores were cut from 1739.5 m to
1821.8 m in the Tor Formation chalk and two more cores were cut from 1879.1 m
to 1883.7 m in the basement. Four Formation Interval Tests (FIT) were performed
at 1748.9 m, 1733.4 m, 1642.6 m, and at 1738.2 m. The tests, one in Early
Tertiary shales and three in Late Cretaceous carbonates, did not show any
hydrocarbons.</p>

<p>The well was permanently abandoned on 9
August 1967 as a well with shows.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>

144
5/19/2016 12:00:00 AM
29.01.2023
16/2-10


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-10 was drilled on the Utsira
High in the North Sea to appraise the northern part of the Aldous Major
Discovery in a segment called Espevær. The main objective was to investigate
the hydrocarbon potential and the</span></p>

<p class=MsoBodyText><span lang=EN-GB>reservoir quality and lateral sand
distribution in Late Jurassic sandstones in the Draupne Formation of the Viking
Group, and the Hugin and Sleipner Formations of the Vestland Group. The
secondary well objective was to explore the reservoir properties in the Triassic
age Skagerrak Formation. The third objective was to investigate the hydrocarbon
potential in the Cretaceous chalk of the Shetland Group.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A 9 7/8&quot; pilot hole 16/2-U-6 was
drilled to check for shallow gas down to setting depth for the 20&quot; casing.
No sign of shallow gas or shallow water flow was seen on the logs nor observed
by the ROV. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-10 was spudded with
the semi-submersible installation Transocean Leader on 27 September 2011 and
drilled to TD at 2090 m in the Late Triassic Skagerrak Formation. No
significant problem was encountered in the operations. The well was drilled
with sea water down to 463 m and with water based Performadril mud with 3-4%
glycol from 463 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-10 penetrated sediments of Cenozoic,
Cretaceous, Jurassic and Triassic age. Top of the Intra Draupne Formation
sandstones, came in at 1892 m. An oil column of 66 meters was found in these sandstones
and the underlying sandstones of the Middle Jurassic Hugin Formation. The free
water level was established at 1957.7 m (1934.2 m TVD MSL) as confirmed by
logs, cores, pressure data and fluid samples. This is deeper than in the 16/2-8
discovery well, where the free water level was found at 1920.7 m. The Triassic
Skagerrak Formation was water wet. There were no sign of hydrocarbons in the
Shetland Group. Oil shows were recorded from 1890 m to 1953 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut from 1889.5 m in the Åsgard
Formation to base Hugin Formation at 1962 m. Reservoir fluid samples were
obtained in 3 MDT runs at 7 depths: 1893.5 m (oil), 1927.0 m (oil), 1935.5 m
(oil), 1935.7 m (oil), 1955 m (oil and some water), 1961 m (water), and 1966 m
(water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28
October 2011 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


6715
4/11/2017 12:00:00 AM
29.01.2023
16/2-11


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-11 was drilled to appraise the
western part of the Johan Sverdrup (formerly Avaldsnes) discovery on the Utsira
High in the North Sea. The primary objective was to prove a 50 to 60 m oil
column in Middle - Late Jurassic sandstones. The well would also serve as
calibration for seismic interpretation and depth conversion and it would give
information about any lateral variation in facies and thickness of the Johan
Sverdrup reservoir.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-11 was spudded with
the semisubmersible installation Bredford Dolphin to 2126 m in the Triassic
Skagerrak Formation. A 9 7/8&quot; pilot hole was drilled to 756 m to check for
shallow gas. No indication of shallow gas was observed. No significant problem
was encountered in the operations. The well was drilled with sea water and
hi-vis pills down to 756 m and with Performadril Water Based Mud from 756 m to
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top reservoir, Intra-Draupne Formation
sandstone, was encountered at 1890 m and Middle Jurassic sandstones, Vestland
Group, was encountered at 1910 m. The reservoir was encountered at the
prognosed depth and 54 m oil column in an oil-down-to situation was proven. The
well also confirmed good reservoir properties, in line with the earlier Johan
Sverdrup wells where the Late Jurassic reservoir was also of excellent quality
with a high net to gross ratio. A peak of high gamma ray between 1889.3 m and
1890 m, indicated a 0.7 m thick Draupne shale on top of the reservoir, but this
could not be confirmed by cuttings samples and adjacent sidewall cores. Oil
shows were restricted to the Middle-Late Jurassic reservoir section.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 1891.6 m, just
below the possible Draupne shale, to 1957.78 m, ca 12 m into the Skagerrak
Formation. Overall good recovery was obtained. MDT fluid samples were taken at
1895.61 m (oil), 1918.41 m (oil), 1937.02 m (oil), 1941.75 m (oil), 1951.38 m
(water), and at 2059.09 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
March 2012 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>A production test (DST) was run over the
interval 1934.5 m to 1943.3 m in the previously untested Middle Jurassic reservoir
section to investigate its flow properties. The main flow gave 476 Sm3 oil and
14500 Sm3 gas per day through a restricted 40/64 choke, with good reservoir
properties indicating a laterally continuous reservoir. The GOR was 30 Sm3/Sm3,
the oil density was 0.89 g/cm3, and the gas gravity was 0.768 (air = 1). The
flowing temperature, recorded at depth 1908.2 m, was 79.7 deg C. </span></p>



6742
4/11/2017 12:00:00 AM
29.01.2023
16/2-11 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-11 A is a sidetrack to well
16/2-11. It was drilled to appraise the western part of the Johan Sverdrup
(formerly Avaldsnes) discovery on the Utsira High in the North Sea. The primary
objectives of 16/2-11 A was to verify the system pressure and oil-water contact
in the 16/2-11 area and to get a representative water sample from the central
part of the Johan Sverdrup field. The well would also give information about
variations in lateral thickness and facies in the Johan Sverdrup Field for
better understanding of geology and field drainage strategy.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-11 A was kicked off
from 770 m in the main well bore on 29 March 2012. It was drilled with the
semi-submersible installation Bredford Dolphin to TD at 2365 m (2073 m TVD) in
the Triassic Skagerrak Formation. The sidetrack deviation was up to 45 degrees
and it penetrated BCU ca 950 m to the north-east of the main well location. No
significant problem was encountered in the operations. The well was drilled
with Performadril Water Based Mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated a 4 m thick Draupne
Formation from 2180 m to 2184 m. The Draupne Formation consisted of decimetre
scale Spiculites and fine grained sandstones interbedded with centimetre scale laminated
mudstones typical of the Draupne shales. It was dated Late Volgian to Late
Ryazanian. Top Intra-Draupne Formation Sandstone was penetrated at 2184 m (1915
m TVD). The Vestland Group was encountered at 2206 m (1934 m TVD) with a section
of claystone and silstone on top down to 2215 m (1942 m TVD) and heterolithic
sandstone from there down to top Skagerrak Formation at 2239 m (1963 m TVD). The
oil water contact was established at 2221 m (1947 m TVD). This is in line with
other wells in the License. The well also confirmed the good reservoir
properties encountered in the well 16/2-11. Minor oil shows were reported in
one sample of tuff from the Balder Formation at 1600 m, otherwise oil shows
were restricted to the Middle to Late Jurassic reservoir section.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 2169 m to 2243 m
with 98-100% recovery in all cores. The cores covered the entire section from
base Åsgard Formation, across the BCU, through the Late to Middle Jurassic
reservoir, and into the upper Skagerrak Formation. MDT fluid samples were taken
at 2186.1 m (oil), 2202 m (oil), 2223.5 m (oil), 2225.1 m (water), and 2233.4 m
(water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 4
May 2012 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6849
4/11/2017 12:00:00 AM
29.01.2023
16/2-12


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-12 was drilled on the Geitungen
Prospect on the Utsira High in the North Sea. The prospect is situated on a
basement terrace north-west of the Johan Sverdrup Field. The main objectives
were to investigate the hydrocarbon potential, reservoir quality, and lateral
distribution of Intra-Draupne Formation sandstones, and the underlying
sandstones of the Hugin and Sleipner Formations. The secondary objectives were
to explore the hydrocarbon potential and reservoir properties in the fractured
granitic Basement.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-12 was spudded with the
semi-submersible installation Ocean Vanguard on 25 July 2012 and drilled to TD
at 2067 m in granite Basement. There was a pre-drill shallow gas warning at 707
m, ca 100 m below 20” casing shoe, but no gas was observed when drilling. The
well was drilled with seawater down to 211 m and with PerformaDril water based
mud from 211 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary,
Neogene, Paleogene, Cretaceous and Jurassic age. No indication of hydrocarbons
were recorded above top Intra Draupne Formation sandstone, which was picked at
1894 m, 12 m deeper than prognosed. The reservoir had excellent reservoir
properties and contained oil. The top of the Basement was picked at 1938 m, 5 m
deeper than prognosed. The fractures in the uppermost part of Basement were
oil-filled. The oil/water contact was not encountered, but pressure
measurements indicate a connection between this segment and the rest of the
Johan Sverdrup discovery. Extensive data acquisition and sampling was carried
out. The gas/oil ratio is 51.8 Sm3/Sm3 and the oil density is estimated at 0.81
g/cm3 in the Intra-Draupne reservoir. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut in the interval 1893
m to 1951.7 m, covering the whole Jurassic interval and 13.7 m of the Basement.
The difference between the cores depth and wireline logs depth is less than 50 cm.
Core 1 was dripping with oil and had excellent shows. The same type of shows
continued on core 2 down to 1930 m. From 1930 – 1940 m, the shows disappeared.
From 1940 m, oil was observed in fractures in the granitic Basement. Due to
less fractures in core 4 shows disappeared. The deepest indication of weak
shows were seen at 1950 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Reservoir fluid samples were obtained at four
depths, with three MDT runs in the well. Large diameter probe was used on MDT
wireline runs 5 and 7, and dual straddle packer was used on MDT wireline Run 8.
In Run 5, samples were taken in Intra-Draupne Formation sandstone at 1901.3 m
(oil) and in the Basement at 1940.0 m (oil with water and filtrate). In Run 7
samples were taken in Intra-Draupne Formation sandstone at 1928.3 m (oil), In
Run 8 samples were taken in the Basement at 1940.1 m (oil with water and
filtrate) and at 1945 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 6
September 2010. It was planned and drilled as a wildcat well. However, after
performing data acquisition, and acquiring formation pressure testing data in
the reservoir section, the well was reclassified as an appraisal of the Johan
Sverdrup field. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Formation tests (mini-DST) were conducted
in the bedrock, revealing stable flow rates of both oil and water in different
levels in the fractured and weathered bedrocks. </span></p>


6952
4/11/2017 12:00:00 AM
29.01.2023
16/2-13 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 A is a geological side track
to well 16/2-13 S on the Johan Sverdrup discovery on the Utsira High in the
North Sea, 6.7 km northeast of well 16/2-8 and 2.4 km north-east of well
16/2-6. The objective of the side track was to calibrate the depth model in a
position far enough away from 16/2-13 S to provide significant information for
depth conversion; to investigate if FWL in 16/2-10 is present in area across
the fault close to 16/2-13 S and; to map lateral thickness and quality
variations in the Jurassic sequence.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 A was kicked off at 735 m in
16/2-13 S on 30 August 2012. The semi-submersible installation Transocean
drilled the well to TD at 2776 m (2101.7 m TVD) in indeterminate pre-Rotliegend
Group rock. The sidetrack was drilled with Enviromul OBM.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The reservoir was encountered at 2596.06
(1926 m TVD) about 1250 metres north of well 16/2-13 S and slightly shallower
than prognosis. It consisted of a 26.5 m thick Intra-Draupne, Intra-Heather and
Hugin sandstone package, similar as in 16/2-13 S. The oil column in the
sidetrack was 12 m and the oil water contact was established at 1949 m TVD (1925
m TVD MSL). </span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut from 2587.3 m in
Draupne Formation shales to 2669.0 m in Pre-Rotliegendes rock. The core to log
shift for all four cores is -1.5 m. The core recovery was 100%. RCX wire line
fluid samples were taken at 2596.7 m (oil), 2607.5 m (oil), 2608.5 m (oil and
water), 2610.7 m (water), and 2615.0 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
September 2012 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7028
4/11/2017 12:00:00 AM
29.01.2023
16/2-13 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-13 S was drilled on the Johan
Sverdrup discovery on the Utsira High in the North Sea, 6.7 km northeast of
well 16/2-8 and 2.4 km north-east of well 16/2-6. The main objectives were to
confirm an oil saturated Upper Jurassic Draupne sand thickness of approximately
30 meter in the northeastern part of Johan Sverdrup; to establish the Johan
Sverdrup pressure system and oil-water-contact in this area; and to improve the
understanding of Draupne sand facies changes and lateral Draupne shale
thickness variations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 16/2</span><span lang=EN-GB
style='font-family:"Cambria Math",serif'>&#8208;</span><span lang=EN-GB>13
(later renamed as 16/2</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>&#8208;</span><span
lang=EN-GB>U</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>&#8208;</span><span
lang=EN-GB>13) well was drilled according to the well design with the
semi-submersible installation Transocean Arctic. A 9 7/8” pilot hole was
drilled from the seabed and encountered shallow gas at 382 m. The hole was then
plugged back with gas tight cement and the rig was moved 45 m SW. The appraisal
well 16/2</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>&#8208;</span><span
lang=EN-GB>13 S was then re</span><span lang=EN-GB style='font-family:"Cambria Math",serif'>&#8208;</span><span
lang=EN-GB>spudded on 24 July 2012 and a new 9 7/8” pilot hole was drilled to
725 m without seeing shallow gas.  Drilling continued with 36”, 26”, 12 ¼” and
8 ½” hole sections and reached TD at 2090 m (2085.7 m TVD) in Pre-Permian
fractured granite and quartzite rock. Seawater and high viscosity pill was used
as drilling fluid on the riserless sections down to 725 m, while Performadril
water based mud was used from 725 m To TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Draupne Formation shale was encountered
at 1914.5 m (1910.2 m TVD) and was 10 m thick. Intra Draupne Formation
sandstone was drilled from 1924.4 m to 1939.9 m (1920.1 m to 1935.6 m TVD). A
25 m oil column was confirmed in these sandstones and down through sandstones in
the underlying Heather Formation (1 m thick) and Hugin Formation (8 m thick) to
top Skagerrak Formation at 1949.3 m (1945 m TVD). The reservoir was oil filled
to the base with an oil-down-to contact at top Skagerrak Formation. The upper
Intra Draupne Formation sandstone had very good reservoir properties. No shows
were recorded above top Jurassic or below the oil-bearing reservoir. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut across the reservoir
from 1918 m in Draupne Formation shale to 1971.8 m in the Rotliegend Group. The
core to log depth shift is -1.6 m for both cores. The core recovery was 100%. RCX
oil samples were collected at, 1925.0 m, 1940.7 m and 1948.7 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 30
August as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



6888
4/11/2017 12:00:00 AM
29.01.2023
16/2-14


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-14 was drilled on the Espeværhøgda
prospect on the Johan Sverdrup Field on the Utsira High. The main objective was
to investigate the reservoir thickness, quality and facies near the crest of
the whole Johan Sverdrup structure. The secondary objective was to acquire data
in the overburden for field development decisions and planning of future
production and injection wells at Johan Sverdrup Field. A third objective was
to investigate reservoir presence in the Triassic section (Hegre Group). The
fourth objective was to investigate the reservoir quality of the Shetland Group
chalk (Ekofisk/Tor Formation).</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A pilot hole 16/2-U-14 was drilled 30 m south
of the main wellbore location to aid in picking core points in the overburden.
Appraisal well 16/2-14 was spudded with the semi-submersible installation Ocean
Vanguard on 14 September 2012 and drilled to 1210 m where a fish was lost in
hole. The hole was cemented back and it was decided to set the 13 3/8 casing
shoe. Well 16/2-14 T2 was sidetracked from 16/2-14 below the 13 3/8&quot; casing
shoe at 1171 m and drilled to TD at 1982 m in the Triassic Skagerrak Formation.
The well was drilled with Seawater down to 608 m and with oil based XP-07 mud
from 608 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Good oil shows were recorded at top
Ekofisk level from 1565 to 1570 m. Weak shows (from OBM?) were recorded in the
Ekofisk chalk from 1570 to 1733 m. The well encountered the target Late
Jurassic reservoir sand 18 m deep to prognosis, at 1856 m. The reservoir showed
good reservoir properties and contained oil. Top Triassic, the tertiary
objective, came in at 1886 m, 11 m deeper than prognosed. There were no shows on
the core from the Triassic section (core 7).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Seven cores were cut. Core 1 was cut from
811 to 820 m in Utsira Formation sandstone, core 2 was cut from 987 to 996 m in
Skade Formation sandstone, and core 3 was cut from 1067 to 1076 m in
undifferentiated Hordaland Group sandstone and core 4 was cut from 1539 to 1548
m in the Lista Formation mudstone.  Cores 5 to 7 were cut in succession from 1836
to 1904.5 m, covering the interval from lowermost Cretaceous, through the whole
reservoir section, and 16 m into the Triassic. MDT water samples were taken at
820.05 m, 820.53 m and 820.98 m in the Utsira Formation and at 1116.53 m in
undifferentiated sandstone in the Hordaland Group. Oil samples were taken at
1858 m in the Late Jurassic reservoir sandstone. Fifteen percent contamination
of the sampled fluid was estimated.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17
November 2012 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Injection tests were performed in the
plug and abandon phase.</span></p>



6898
4/11/2017 12:00:00 AM
29.01.2023
16/2-15


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 16/2-15 Kvitsøy Basin well was
drilled as an appraisal well for the Aldous Major South discovery in PL265 that
together with Avaldsnes discovery in PL501 was to be called the Johan Sverdrup
Field. The objective of 16/2-15 was to investigate the reservoir thickness,
quality and facies in the southwestern part of the Johan Sverdrup Field. A
specific objective was to obtain good water samples from the reservoir.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-15 was spudded with
the semi-submersible installation Ocean Vanguard on 21 November 2012 and
drilled to TD at 2006 in the Triassic Skagerrak Formation. A 9 7/8” pilot hole
was drilled to 511 m to check for shallow gas. No shallow gas was observed. No
significant problem was encountered in the operations. The well was drilled
with seawater down to 736 m, with Performadril water based mud from 736 m to
1159 m, and with XP07 oil based mud from 1159 m to TD. The oil-based mud was
chosen to avoid drill water contamination in the water samples from the
reservoir.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The target reservoir, Intra Draupne Formation
sandstones, was encountered at 1913 m. The reservoir was oil filled down to top
Statfjord Group at 1945 m. Pressure data and logs indicate a true OWC at this
depth. Oil shows on cores continued down to 1958 m. Oil shows were not observed
above top reservoir or below 1958 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut from 1895 m in the
Åsgard Formation and down through the entire reservoir section to 1990.7 m in
the Skagerrak Formation. MDT fluid samples were taken at 1913.8 m (oil), 1916.6
m (oil), 1926.9 m (oil), 1946.5 m (water), and at 1957.1 m (water). Water
samples of good quality was obtained.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
January 2013 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



6979
4/11/2017 12:00:00 AM
29.01.2023
16/2-16


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 was drilled on the northeastern
part of the Johan Sverdrup Field on the Utsira High. The main objective was to
acquire information about the Jurassic reservoir properties and hydrocarbon
column in this part of the field.  Secondary objectives were to investigate the
reservoir properties of the Zechstein Group, and to determine whether
oil-bearing Paleocene sandstones (Heimdal and Hermod formations) were present.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 was spudded with the semi-submersible
installation Transocean Winner on 11 November 2012 and drilled to TD at 2214 m
in the Permian Rotliegend Group. A 9 7/8” pilot hole was drilled to a total
depth of 706 m to check for shallow gas before opening up the pilot hole to
36&quot; and 26&quot; sections. No shallow gas was observed. No significant
problem was encountered in the operations. The well was drilled with seawater and
bentonite mud down to 695 m and with Glydril mud from 695 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No Paleocene sands were present in the
well. In total 15 m of net sandstone was found within a 60 m Jurassic sequence.
The top of the reservoir was penetrated at 1950 m as prognosed. The oil/water
contact was identified at 1952 m just above the good reservoir sand. This is the
same level as observed in well 16/2-13 A and 3 m deeper than found in
previously drilled wells in PL 501. The 6 m thick Intra Draupne Formation
sandstone below the contact sand had good shows. A 3 m thick sandstone in the
Vestland Group had similar, but weaker shows; otherwise, no shows were reported
from the well. The Zechstein Group consisted of water-wet sandstones,
limestones and siltstones with a water gradient in line with the above Jurassic
sandstones.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two successive cores were cut from 1947 m
in the lower Draupne Formation and down to 1986.8 m in the Statfjord Group. Oil
and water samples were collected using MDT. Water was sampled at 1952.1 and
1966.0 m. At 1951.6 m, formation water, mud filtrate and oil were sampled with
68 bars drawdown.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back and completed
for sidetracking on 12 December 2012. It is classified as an oil appraisal
well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7047
4/11/2017 12:00:00 AM
29.01.2023
16/2-16 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 A is a sidetrack to well
25/2-16 on the northeastern part of the Johan Sverdrup Field on the Utsira
High. The primary well bore found the oil/water contact at 1952 m, in line with
the other wells in PL501. The main objective was to investigate lateral
thickness and facies variations within the Viking Group and the Vestland Group
in the area 1000 m to the west of the main wellbore. Further, to provide input
to the Johan Sverdrup water injection strategy, and to investigate lateral
pressure and free water level variations.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-16 A was kicked off from 693 m
in main well bore 16/2-16 on 13 December 2012. It was drilled with the
semi-submersible installation Transocean Winner to 2274 where the string stuck.
Attempts to free the string failed and in the end, a 434 m fish was left in the
hole. The hole was cemented back and a technical sidetrack, 16/2-16 A T2, was
kicked off from 1600 m. Drilling continued to final TD at 2503 m (2085 m TVD)
in the Triassic Skagerrak Formation. The well was drilled with Versatec oil
based mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well encountered a gross oil column
of approximately 30 m within a Jurassic sequence with largely excellent
reservoir quality. No firm FWL could be established. A range for the FWL from a
clean oil sample at 2361.9 m (1960.7 m TVD) to approximately 2368 m (1966 m TVD)
from water gradient/oil gradient intersection was suggested. This is the
deepest contact so far observed in the Johan Sverdrup area. Very weak shows
(trace blue-white fluorescent cut) were recorded below the FWL, and a good spot
of oil show (stain, odour, yellow-brown fluorescence) was described at 2382.5 m
in the Eirikson Formation. No shows were recorded in the Skagerrak Formation.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut in succession in the
16/2-16 A T2 sidetrack from 2324 m in the Draupne Formation to 2420 m in the
Skagerrak Formation. MDT fluid samples were taken at 2327.3 m (oil), 2355.0 m (oil),
2361.9 m (oil), and at 2379.9 m (water)</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 12
December 2012 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7107
4/11/2017 12:00:00 AM
29.01.2023
16/2-17 B
<html>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-17 B is a geological sidetrack
to well 16/2-17 S. The sidetrack targeted the Cliffhanger South prospect on the
western side of the main western bounding fault on the Johan Sverdrup
Discovery. The primary objective of 16/2-17 B was to investigate whether the Intra-Draupne
Formation sandstone is present west of the main bounding fault. A secondary
objective was to investigate the hydrocarbon potential of the Basement, which
is expected to be directly beneath the Jurassic reservoir. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal sidetrack well 16/2-17 B was drilled
with the semi-submersible installation Ocean Vanguard. It was kicked off from
600 m in the primary well bore on 20 May 2013 and drilled to TD at 2200 m (1937
m TVD) in pre-Devonian granitic basement. No significant problem was
encountered in the operations. The well was drilled with XP-07 oil based mud.</span></p>

<p class=MsoBodyText><span lang=EN-GB>This well did not encounter any Jurassic
strata, nor any sands with potential reservoir properties. The top of the
Basement was encountered at 2133 m, which was 23 m TVD deeper than prognosed. The
granitic Basement contained hydrocabons; however, the fractured top was disappointing
concerning reservoir properties. Apart from the shows in top of the granitic basement,
no oil shows above the oil-based mud were recorded in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut through the target
prospect, from 2087 in the Rødby Formation to 2144.5 m in the Basement. The
basement core recovered 70.5% (including ca 7.6 m of the basement); the two
others had 100% recovery. MDT pressure evaluation was attempted at four depths
in the top of the basement without success due to tight rock. No fluid samples
were taken.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 16
May 2013 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7175
4/11/2017 12:00:00 AM
29.01.2023
16/2-17 S
<html>>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-17 S was drilled on the western
flank of the Johan Sverdrup Discovery. The main objectives were to investigate
the reservoir thickness, quality and facies along the western bounding fault of
the Johan Sverdrup Field. The main bounding fault separates the basin to the
east where Intra-Draupne Formation sandstone is present in all the wells, and
the main Utsira High to west where Intra-Draupne Formation sandstone has not
been encountered in the wells nearby.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A pilot hole 16/2-U-17 was drilled 25m
South-East of the main wellbore to investigate for shallow gas. No gas or
shallow water flow were encountered. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-17 S was spudded with
the semi-submersible installation Ocean Vanguard on 24 March 2013 and drilled
to TD at 2052 m (2039 m TVD) in the Triassic Skagerrak Formation. No
significant problem was encountered in the operations. The well was drilled
with seawater down to 905 m and with Performadril water based mud from 905 m to
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the main reservoir, Draupne
Formation, was picked at 1873 m (1859.7 m TVD), 18.3m deeper than prognosed.
The reservoir showed excellent reservoir properties and held an 82 m thick oil column
down to the oil-water contact in the Statfjord Group at 1957 m (1922 m TVD MSL).
A formation gas peak with C2+ hydrocarbons was recorded in the top of the
Shetalnad Group, and at 1873 m good oil shows were recorded. Gas generally
dropped off down in the Shetland Group. Below the OWC oil shows were described down
to 1965 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 164 m core were recovered from
seven coring runs covering the Jurassic interval and 21 m TVD into the Triassic
Skagerrak Formation. Core recoveries varied between 98.8 and 105.3%. The high
recoveries are due to core expansion. MDT fluid samples were taken at 1884.8 m
(oil), 1934.5 m (oil), and 1959.7 m (water). </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
May 2013 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two Drill Stem Tests were performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 1 tested the interval 1929 to 1937 m
in the Statfjord Formation reservoir section. It produced 422 Sm3 oil and 14200
Sm3 gas /day through a 40/64&quot; choke. The DST temperature was 77.7 °C.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST 2 tested the interval 1875.5 to
1914.5 m, nearly the whole Intra Draupne Formation sandstone section of the
reservoir. It produced 910 Sm3 oil and 24300 Sm3 gas /day through a 48/64&quot;
choke. The DST temperature was 75.5 °C.</span></p>

7085
4/11/2017 12:00:00 AM
29.01.2023
16/2-18 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-18 S was drilled on the Cliffhanger
North prospect west of the Johan Sverdrup Field on the Utsira High in the North
Sea. The main objective was to prove hydrocarbons in the Late Jurassic
intra-Draupne Formation sandstones and to verify the reservoir quality, fluid
property, lateral extension and possible communication with the Johan Sverdrup
discovery. The secondary objective of the well was to explore the hydrocarbon
potential and reservoir properties in fractured and weathered granitic
Basement.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-18 S was spudded with
the semi-submersible installation Ocean Vanguard on 5 July 2013 and drilled to
TD at 1970 m in fractured granitic basement rock. The well was drilled with a
slightly deviated well path with the purpose of avoiding a prognosed shallow
gas anomaly. A 9 7/8&quot; pilot hole was drilled from 201 m to 455 m to check
for shallow gas. No shallow gas was seen. No significant problem was
encountered in the operations. The well was drilled with seawater and hi-vis sweeps
down to 855 m and with KCl/Polymer/Glycol mud from 855 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The Intra-Draupne Formation sandstone
reservoir was not present at the well location; hence the primary objective of
the well was not met. The secondary objective, however, was met by proving oil
in weathered and fractured granitic Basement, which was encountered at 1864 m.
An oil column of ca 15 m was estimated but no oil/water contact was
established. Pressure data showed the discovery to be 2.6 bar higher and with a
different oil gradient than in the Johan Sverdrup Field, and thus not in
communication. However pressure and sampling data from the 16/2-4 Ragnarrok
basement discovery has shown that the 16/2-18 S basement discovery is in
communication, making 16/2-18 S well an appraisal of the Ragnarrok discovery.
From the combined pressure data for these two wells the gas oil contact for the
Ragnarrok discovery is found to be at ca 1862 m (1840 m MSL).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Shows were observed in the upper part of
the Shetland Group and in the Basement. The uppermost Shetland Group (Ekofisk
Formation) also had high gas readings.</span></p>

<p class=MsoBodyText><span lang=EN-GB>An extensive sample and data acquisition
programme was conducted in the upper part of the Basement. Four cores were
drilled, but the first core was lost in the hole. Cores 2 - 4 recovered 19.9 m between
1855.5 m in the Åsgard Formation and 1876 m in the Basement. Three dual packer mini-DST’s
were performed showing limited production properties. Fluid samples were taken
at 1866.2 m (gas, oil, and mud) and 1875.1 m (oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8
August 2013 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



7220
4/11/2017 12:00:00 AM
29.01.2023
16/2-19
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>The 16/2-19 Geitungen well was drilled on
the northern part of the Johan Sverdrup Field on the Utsira High in the North
Sea. The primary objectives were to investigate the reservoir distribution,
facies and quality in a more distal and down flank position and different
seismic response than the Geitungen discovery well 16/2-12. The well was
targeting possible Intra Draupne Formation sandstones to find the oil-water
contact and to take water samples to aid the design of Johan Sverdrup
production facilities.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-19 was spudded with
the semi-submersible installation Ocean Vanguard on 1 March 2014 and drilled to
TD at 2023 m in the granitic basement rock. The well was drilled and cored
without any major problems. The well was drilled with spud mud down to 902 m
and with XP-07 oil based mud from 902 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Intra Draupne sandstone was not
encountered in the well. Top Statfjord Group sandstone came in at 1945 m and
the upper 5 m was oil filled. Shows were observed from the well site
description in the Draupne Formation above the Statfjord reservoir and in the
Skagerrak Formation below the OWC, but no shows are observed in the Basement. Gas
readings were generally low through the entire well. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut with a total of
68.38 m recovery, starting from lower part of Cromer Knoll Group, through
Viking Group, Statfjord Group, Hegre Group and down into the Basement. MDT
samples were taken at 1945.13 m (oil with ca 4% OBM contamination), 1949.03 m
(oil with ca 18% OBM contamination), and 1951.21 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Since no Intra Draupne Formation
sandstone was encountered in the well, it was decided to drill a sidetrack,
16/2-19 A.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well bore 16/2-19 was plugged back and
prepared for sidetracking on 3 March 2016. It is classified as an oil appraisal
well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7403
4/11/2017 12:00:00 AM
29.01.2023
16/2-19 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-19 A is a geological sidetrack
to the 16/2-19 Geitungen well. The well is drilled on the northern part of the
Johan Sverdrup Field on the Utsira High in the North Sea.  The sidetrack
16/2-19 A targeted Intra Draupne Formation Sandstones in an assumed depocentre
in a more distal position than the 16/2-12 but in a more proximal position than
16/2-19. The objectives were to investigate the reservoir distribution, facies
and quality of the Draupne sandstone, and to find the oil-water contact.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-19 A was kicked off
through 13 3/8&quot; casing at 625.5 m in the primary well on 3 April 2014. It
was drilled with the semi-submersible installation Ocean Vanguard to TD at 2347
m (1979 m TVD) in granitic basement rock. No significant problem was
encountered in the operations. The well was drilled with XP-07 oil based mud from
kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Draupne Formation claystone was
penetrated at 2265 m, while Intra Draupne Formation Sandstone came in at 2271
m. A 13 m gross oil column was encountered in Intra Draupne Formation sandstone
and Triassic Skagerrak Formation sandstone, the upper 3 m of which were in
sandstone with very good reservoir quality. An oil-down-to situation was
encountered. Oil shows described in in the reservoir section from 2270 m to
2289 m; otherwise, no shows are reported from the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut across the reservoir
section. Core 1 was cut from 2256.5 m in the Åsgard Formation, through Draupne
formation claystone and Intra Draupne Formation Sandstone to 2283.2 m in the
uppermost Hegre Group with 100% recovery.  Core 2 was cut from 2283.2 m to
2305.1 m in the Skagerrak Formation with 99% recovery.  MDT fluid samples were
taken at 2281.04 m (oil with trace OBM contamination) and 2291.74 m (oil with
ca 30% OBM contamination).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 3
May 2014 as an oil appraisal well. A CATS system was installed for long term
monitoring of pressure and temperature.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7456
4/11/2017 12:00:00 AM
29.01.2023
16/2-2
<p><b>General</b></p>

<p>Well 16/2-2 is
located on the Skuld prospect located just to the south of the proven
Balder/Grane oil province. There are four main prospective sandstones in the
area: the Ty, the Lower Heimdal, the Middle/Upper Heimdal, and the Hermod
Formations. All four sandstones were believed to be present in the prospect.
The objectives of the well were to prove commercial volumes of hydrocarbons and
to test the stratigraphic trap and the structural closure.</p>

<p><b>Operations and results</b></p>

<p>Exploration well
16/2-2 was spudded with the semi-submersible installation &quot;Byford
Dolphin&quot; and drilled to TD at 1880 m in the Early Cretaceous Rødby
Formation. The well was drilled with seawater and bentonite hi-vis pills down
to 1312 m and with oil based &quot;NOVATEC&quot; mud from 1312 m to TD.</p>

<p>No shallow gas was
encountered. Only minor amounts of gas were recorded in the well with maximum
0.17% formation gas recorded at 1697 m in Tertiary, predominantly claystone
lithology. Otherwise there were no indications of hydrocarbons throughout the
well. No reservoir rock was developed in the Paleocene section. The Paleocene
sequence is composed of claystones with only occasional traces of coarser
clastics (siltstone and rarely sandstone). No cores were cut in the well and no
fluid samples were taken.</p>

<p>The well was
permanently plugged and abandoned as a dry well on 4 October 2000.</p>

<p><b>Testing</b></p>

<p>No drill stem test
was performed.</p>

4408
7/6/2016 12:00:00 AM
29.01.2023
16/2-20 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 A is a geologic sidetrack to
well 16/2-20 S. Both well tracks were drilled to test the Torvastad prospect
north of the Johan Sverdrup Field on the Utsira High in the North Sea. The
primary objective was to investigate the Jurassic - Early Cretaceous sequence
with respect to reservoir facies, hydrocarbons, free water level, pressure
communication with the Johan Sverdrup Field, and seismic interpretations and
depth conversion. Well 16/2-20 A was drilled 800 meters towards west to
investigate the presence of oil filled Jurassic reservoir at shallower depth
than the S well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-20 A was drilled with
the semi-submersible installation Island Innovator. Operations started on 21
November 2013 but due to problems with the lower marine riser package (LMRP)
and bad weather, actual kick-off was not performed until 12 December 2013. The
kick-off point was at 732 m in the primary S well. Equipment failure, mainly related
to the LMRP, caused 551 hours no production time for this well, while bad
weather caused 725 hours WOW. Only 41% of total rig time was counted as
productive. The well was drilled to TD at 2215 m in Granitic basement rock
using Aquadril mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 A found a late Jurassic Draupne
</span><span lang=EN-US>spiculitic sandstone/siltstone</span><span lang=EN-US> </span><span
lang=EN-GB>sequence of similar extent and facies as found in well 16/2-20 S,
despite indications of a thinning of this sequence interpreted from seismic
data. The Statfjord Group sequence is not present and the spiculite rests
unconformable on a 57 m Triassic Hegre and Skagerrak Group sequence. Good shows
were observed in the sandstones of the Draupne and Skagerrak formations.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 2090
to 2139 m, recovering a total of 45.7 m (93.3% total recovery). The core to log
depth shifts are +0.31 m, -2.28 m, and -2.67 m for cores 1, 2, and 3,
respectively.  RCX fluid samples were taken at 2125.19 m and 2129.52 m. Water
with a fraction of oil was obtained from both depths.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 17
February as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7316
4/11/2017 12:00:00 AM
29.01.2023
16/2-20 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-20 S was drilled on the Torvastad
prospect north of the Johan Sverdrup Field on the Utsira High in the North Sea.
The primary objective was to investigate the Jurassic - Early Cretaceous
sequence with respect to reservoir facies, hydrocarbons, free water level,
pressure communication with the Johan Sverdrup Field, and seismic
interpretations and depth conversion.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-20 S was spudded with
the semi-submersible installation Island Innovator on 30 September 2013 and
drilled to TD at 2150 m (2098 m TVD) m, 36 m into granitic basement. A 9
7/8&quot; pilot hole was drilled from </span></p>

<p class=MsoBodyText><span lang=EN-GB>seabed to 720 m RKB to check for shallow
gas. No shallow gas was observed. The well was drilled deviated due to a ridge
on the seafloor that could cause instability for the wellhead and BOP. The well
path is vertical down to ca 730 m, deviated with a sail angel of ca 23 ° from
730 to 1900 m, and vertical from 1900 m to TD. The well was drilled with seawater
and hi-vis sweeps down to 720 m and with Aquadril mud from 720 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>An unusual, 21 m thick age-equivalent to
the Draupne Formation (Volgian to Ryazanian age) was encountered at 2006.3 m
(1954.6 m TVD). It consists of a condensed section at base, a thin shale
section, and a 16.6 m thick spiculitic sandstone/siltstone on top. The porosity
of these sediments is relatively high, but permeability is very low. Underlying
this sequence, at 2027 m (1975.5 m TVD) the well penetrated a 10 m sequence of
sandstones belonging to the Statfjord Group, a 77 m sequence of sandstones,
limestone and mudstones belonging to the Skagerrak Formation and a 20 m thick
Smith Bank Formation resting on the granitic basement. Good oil shows were described
in the Statfjord Group. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 52.5 m core was recovered in
four cores from the interval 2001 to 2055 m. The core to log depth shifts are -2.34
m, -2.12 m, -1.3 m, and -1.3 m for cores 1 to 4, respectively. RCX fluid
samples were taken at 2012.5 m (water), 2026.7 m (one sample with water and one
with water and a fraction of oil), and at 2031.3 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 21
November 2013 as a dry well with shows.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7181
4/11/2017 12:00:00 AM
29.01.2023
16/2-21
<html>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-21 was drilled to appraise the
central part of the Johan Sverdrup discovery on the Utsira high in the North
Seas. The hydrocarbon column height was predicted to be 14 m in the well
location. The main objectives of the well were to investigate the reservoir
sequence, facies and thickness in the central part of the discovery and to find
the free water level (FWL).</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-21  was spudded with
the semi-submersible installation Bredford Dolphin on 5 May 2013 and drilled to
TD at 2070 m in the Late Triassic Skagerrak Formation. A  9  7/8&quot; pilot
hole  was  drilled  from  the  seabed  to  706  m  due to slight shallow gas
warnings. No shallow gas was seen. Drilling was efficient with little NPT. The
NPT was caused mostly by mud losses in the Skagerrak Formation reservoir
section. The well was drilled with seawater and hi-vis pills down to 706 m and
with Performadril water based mud from 76 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the reservoir came in as
prognosed at 1935 m, overlain by a 4 m thick Draupne Formation shale. An oil
column of 12 meter entirely within the late Jurassic Intra-Draupne sandstones
was proven. The well proved excellent development of these sandstones in the
central part of the Johan Sverdrup discovery. The total thickness of the Intra-Draupne
Formation sandstone was 12 m. No sediments of middle Jurassic age were found,
but 17 m of water filled early Jurassic Eriksson Formation was encountered
below the Draupne Formation. The well results show an oil water contact at 1947
m, but with residual oil saturations of 20-30% down to ca 1955 m. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Above the reservoir, increasing amounts
and wetness of mud gas down through the lowermost part of the Cromer Knoll
Group suggested the possibility of leakage from the reservoir. However, no oil
shows were observed in the Cromer Knoll Group; the only oil shows in the well were
recorded on the cores from 1935 to 1945 m, and 1953 to 1955 m, within the
Intra-Draupne and Eriksson Formation sandstones.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the interval 1907
m in the Cromer Knoll Group to 1976.6 m in the Skagerrak Formation with close
to 100% total recovery. MDT fluid samples were taken at 1937.02 m (oil),
1946.62 m (oil), 1947.11 m (oil), 1947.71 m (water), 1953.79 m (water), and 1975.55
m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
June 2013 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7169
4/11/2017 12:00:00 AM
29.01.2023
16/2-22 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-22 S was drilled to appraise
the Northern outline of the Johan Sverdrup Field on the Utsira High in the
North Sea. The Johan Sverdrup reservoir range from Late Triassic to Early
Cretaceous in age, with Intra Draupne Formation sandstone as the main unit. The
primary objective was to test The Intra-Draupne Formation sandstone and
investigate pressure communication.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-22 S was spudded with
the semi-submersible installation Deepsea Atlantic on 16 January 2017 and
drilled to TD at 1993 m (1982 m TVD) m in granitic basement. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 1214 m and with Carbosea oil-based mud from 1214 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Intra Draupne Formation reservoir was
penetrated from 1934.5 to 1950 m. The Formation consists of muddy spiculites
and is directly overlying basement. It is oil bearing from top to base. No shows
were observed in the well outside of the oil-bearing reservoir. Pressure data over
the reservoir proved an oil gradient that match the one in surrounding wells.
The reservoir pressure is about 0.4 bar lower pressure compared to previously
drilled well 16/2-12. This difference is in line with the rate of pressure
depletion in the area.</span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 1937 to 1953 m in
the Intra Draupne Formation sandstone and Basement with 100% recovery. Two RCX
fluid samples were taken. Oil was sampled at 1943.4 m (1933.4 m TVD) and water
at 1950 m (1939.9 m TVD).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 28
January 2017 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>







































8083
11/12/2019 12:00:00 AM
29.01.2023
16/2-3


<p><b>General</b></p>

<p>Well 16/2-3 was drilled on the Ragnarrock
prospect in the North Sea.The
Ragnarrock prospect is situated on the top of the Utsira High, southeast of the
Verdandi discovery in PL 167 and east of the Gudrun field in PL 025. The main
objective was to prove presence of hydrocarbons in the Tor Formation of
Maastrichtian age and to test its permeability and its productivity. The
secondary target was to check the presence of hydrocarbon in the Basement and
to test its permeability and its productivity.</p>

<p><b>Operations and results</b></p>

<p>Well 16/2-3 was spudded with the jack-up
installation West Epsilon on 1 August 2007 and drilled to TD at 1905 m, 9 m
into basement rock. No significant problem was encountered during drilling, but
an incident with a falling object during P&amp;A caused several days stand
still for investigation before the well could be abandoned. No shallow gas was
observed by the ROV at the well head or by the MWD while drilling the 36&quot;
hole and the 12 1/4&quot; pilot hole. The well was drilled with spud mud down
to 640 m and with KCl/polymer/glycol mud from 640 m to TD.</p>

<p>The well encountered the Tor reservoir
section at 1716 m, 6 m shallower than prognosed. A HC discovery was proven in
the Tor Formation but the results from the MDT suggested the formation to be
tight and tightening with depth. The basement was penetrated at 1894 m, 22 m
deeper than prognosed. Only occasional dead oil stain was found in the upper 7
m of the basement so no further formation evaluation was performed here. No oil
shows were recorded above top Tor Formation.</p>

<p>Three cores were cut from 1715.7 to
1852.5 m. The first core covered the transition zone between the Lista and Tor
Formations. Cores 2 and 3 were cut in the Tor and Hod Formations. Two mini-DST
runs were performed for pressure points and fluid sampling in the Tor
Formation.Sampling was
performed at depths 1716.8 m (gas), 1720.5 m (oil) and
1742.6 m (oil), 1769.9 m, and 1781.1. Only the samples at 1720.5 m were found
to be representative of reservoir fluid.PVT analyses of these samples gave a single stage GOR around 140
Sm3/Sm3 and an oil density of 0.861 /cm3. Sample
bottles from depth 1716.8 m, 1742.6 m, 1769.9 m and 1781.1 contained mainly
water</p>

<p>The well was permanently abandoned on 28
September 2007 as an oil discovery.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed.</p>



5551
4/11/2017 12:00:00 AM
29.01.2023
16/2-4




<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well <a name="OLE_LINK2"></a><a
name="OLE_LINK1">16/2-4 </a>is located on the Utsira High in the North Sea. The
objective of drilling 16/2-4 was to delineate the Tor Formation oil discovery made
in 16/2-3 and to test the permeability and productivity of the chalk. The
secondary objective was to check the presence of hydrocarbon in the basement
and to test the permeability and productivity of the basement rock.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-4 was spudded with the jack-up
installation West Epsilon on 8 October 2007 and drilled to TD at 2000 m, 121 m
into basement rock. No major problem was encountered in the operations. The
well was drilled with spud mud down to 640 m and with KCl/polymer/glycol mud
from 640 m to TD. No shallow gas was observed by the ROV at the wellhead or by the
MWD while drilling the 36&quot; hole or the 17 1/2&quot; hole. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Tor Formation reservoir section was
encountered with hydrocarbons at 1709.5 m, 12.5 m shallower than prognosed. A
clear hydrocarbon contact was not seen. The best indication of an OWC was seen on
cores as a disappearance of shows below 1775. The well showed that the size of
the 16/2-3 discovery is likely to be in the range 5 - 10 million Sm3
recoverable oil. A series of small-scale formation tests were carried out,
showing promising flow properties. Smaller amounts of oil and gas were found also
in basement, but small-scale tests in the basement showed limited flow
properties. Apart from the oil and gas bearing reservoirs, no significant shows were
seen in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five cores were cut. The first core was cut
in the Lista Formation, the second core covered the transition zones between
the Lista, Våle and Ekofisk Formation, the third core was in the Tor Formation,
the fourth core was in the Tor and Hod Formation, and the fifth core was in
Basement. Four mini-DST runs were performed in the Tor Formation and in the
Basement for pressure points and fluid sampling. Oil and water were sampled
from the Tor Formation. Gas, oil and water were sampled from the Basement. The
following depths were sampled (hydrocarbon type is verified only from
chromatographic analyses of the oil phase): 1939 m (water), 1930 m, 1904 m
(oil), 1898,1 m (oil), 1896.1 m, 1886.1 m (gas/condensate), 1727.5 m (oil), and
1710 m (water). Due to high draw-down during pumping with the wire line tools,
most of the hydrocarbon samples are flashed and not representative for PVT
analysis. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 15
December as a gas/minor oil discovery and an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>



5625
4/11/2017 12:00:00 AM
29.01.2023
16/2-5


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-5 was drilled on the Ragnarock III
prospect on the Utsira High in the North Sea. The primary objective of the well
was to prove the presence of hydrocarbons in the pre-BCU interval and establish
the composition and age of the sediments. The secondary target was the chalk in
the Ekofisk and Tor Formations of Late Cretaceous age. The presence of
hydrocarbons in these formations at the well location was possible, but not
expected.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-5 was spudded with the jack-up
installation West Epsilon on 22 February 2009 and drilled to TD at 2373 m in
pre-Devonian Basement. After drilling the 36&quot; hole to 288 m a 9 7/8&quot;
pilot hole was drilled to 513 m to check for shallow gas. No shallow gas or
shallow water flow was observed. The well was drilled with spud mud down to 519
m, with KCl/polymer/glycol mud from 519 m to 1747 m, and with
KCl/polymer/glycol low-sulphate mud from 1747 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated rocks of Quaternary,
Tertiary and Cretaceous age, it then penetrated Graben Fill before TD in
Basement. Base Cretaceous/top Graben Fill was encountered at 1884 m. A total
thickness of 458 m of Graben Fill consisting of coarse, clastic sediments was
penetrated and 3 cores were cut from 1894 to 1994 m. Due to lack of fossils no
reliable dating was obtained for the Graben Fill. The Graben Fill was gas/condensate
filled from top of the reservoir and down to 1902 m. High quality gas
condensate samples were acquired by use of wire line sampling tools. A water
sample was acquired at 1935 m and oil was scanned at 1916 m MD. An interval with
oil was confirmed also by sampling at 1921.5 m, but due to poor pressure
measurements in this interval the OWC was only tentatively set at 1917 m based
on logs and geochemistry. No oil shows were observed above reservoir level. In
the reservoir oil shows were seen down to 1981 m and no shows were seen below
this level.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 13
May 2009 as a gas discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>A full scale DST was performed in the
interval 1885 - 1902 m. The perforated interval was placed in the gas zone with
the lowermost interval close to the interpreted GOC. The gas rate for the main
flow was 110 000 Sm3/d with a 40/64&quot; choke size. A maximum gas rate of 120
000 Sm3/day was achieved on a 60/64&quot; choke size. The total test production
of associated condensate with the gas was about 6 Sm3 mixed with some oil, no
water was produced during testing. At top reservoir the formation pressure was
191.8 bar at 1885 m. The bottom hole temperature recorded in the test was 71
deg C.</span></p>



6042
4/11/2017 12:00:00 AM
29.01.2023
16/2-6


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-6 was drilled on the Avaldsnes
prospect on the Utsira High in the North Sea. The primary objective was to prove
oil in Jurassic and pre-Jurassic sandstone in the Karmsund Graben. The
secondary objective was to prove oil in the Paleocene Ty Formation Sandstone. Planned
TD was 50 m into solid basement rock.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-6 was spudded with the
semi-submersible installation Transocean Winner on 20 July 2010 and drilled to
TD at 2131 m. The well encountered severe loss problems in the Zechstein Group
and a technical sidetrack was drilled (well 16/2-6 T2) through the reservoir. The
sidetrack was kicked off from 1830 m and drilled to 2131 m where severe losses
again were experienced and the well was completed without reaching its planned
TD. All wire line logging and a DST were performed in the sidetrack. The well
was drilled with seawater and hi-vis pills down to 748 m and with Glydril WBM
(3- 5% glycol) from 748 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No Ty Formation sand was seen in the
well. Top Viking Group, Draupne Formation was encountered at 1925.5 m (1927.5 m
in sidetrack) and top of the Draupne reservoir sand came in at 1931 m (1931 m
in sidetrack). The top of the reservoir consists of an 8 m thick, coarse to very
coarse, sand. Underlying this is finer grained sand laminated with shale. A
reworked calcareous formation lies on top of the Triassic. Pressure points, MDT
sampling and DST results confirmed the presence of oil in the reservoir with an
oil-water contact at 1948.6 m. Residual oil was found down to 1966 m. In
addition to the main reservoir section, oil was sampled in calcareous slumps
with vuggy porosity between the Jurassic sandstone and the Triassic. Apart from
this there were no shows of hydrocarbons reported elsewhere in the well bores.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three conventional cores were cut from 5
m into the Draupne sandstone, through the Middle Jurassic Vestland Group
down to 1961.5 m in the Late Triassic Skagerrak Formation. MDT fluid
samples were taken at 1933.2 m (oil), 1936.0 m (oil), 1945.2 m (oil), 1948 m
(oil and water), 1953 m (water), and at 1962.5 m (water and oil).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 20
September 2010 on as an oil discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>A drill stem test was performed from the
interval 1931.8 m to 1938.1 m. The test flowed 786 Sm3 oil and 18700 Sm3
through a 52/64&quot; choke. At single stage separation The GOR was 39.6
Sm3/Sm3, the oil density was 0.891 g/cm3, and the gas gravity was 1.012 (air =
1). The maximum DST temperature was 82.7 deg C. The interpretation of the DST
indicated a continuous reservoir without barriers in a radius of 2-3 km with
extremely good flow characteristics.</span></p>



6374
4/11/2017 12:00:00 AM
29.01.2023
16/2-7


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-7 was drilled about 5.5
kilometres southeast of the discovery well for the oil discovery 16/2-6
(Avaldsnes) on the Utsira High in the North Sea. The 16/2-6 Avaldsnes discovery
was proven in September 2010 in Middle-Late Jurassic reservoir rocks. The
primary exploration target for 16/2-7 was to delineate the presence of hydrocarbons
in Middle-Late Jurassic sandstones above the 1922 m MSL oil-water contact
established in well 16/2-6. The well?s secondary objective was to determine the
reservoir properties of the Rotliegendes Formation.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-7 was spudded with
the semi-submersible installation Bredford Dolphin on 19 July 2011and drilled
to TD at 2500 m in Early Permian Rotliegendes Group rock. A 9 7/8&quot; pilot
hole was drilled from the seabed to 710 m to check for shallow gas. Some sand
was found at the pre-warned level, but without shallow gas. No significant
technical problem was encountered in the operations. The well was drilled with
seawater and hi-vis pills down to 710 m and with Performadril WBM from 710 m to
TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>BCU/top Draupne Formation was encountered
at 1936 m</span><span lang=EN-GB> </span><span lang=EN-GB>approximately 15 m
deeper than prognosis. This was due to a small fault that was originally not
accounted for in the seismic interpretation. The well proved oil in Intra
Draupne Formation sandstone from top at 1939 m and down to the OWC at 1947.5 m
(1922.5 m TVD MSL), confirming the OWC found in 16/2-6. Reservoir quality was good
to very good and the reservoir continued through base of the Intra Draupne
Formation sandstone at 1964 m and into the underlying Sleipner with base at
1984 m. Total net reservoir was 35 m. The Permian Zechstein and Rotliegendes
Groups were encountered within the depth prognosis uncertainty. Reservoir properties
were not found in these sequences. The first oil show was observed in the
Draupne Formation at 1937 m. Good oil shows were recorded down through the
reservoir to 1948 m. Below 1948 m the oil shows became progressively weaker
with no further shows observed below 1957 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Five conventional cores were cut in the
well. The three first were cut from 1924 m to 1973.5 m across BCU, Draupne
Formation shales and sandstone and into the underlying Sleipner Formation. Core
no 4 was cut from 2198 m to 2217 m in the Zechstein Group, and core no 5 was
cut from 2283 m to 2310 m in the Rotliegendes Group. MDT wire line fluid
samples were taken in the Intra Draupne Formation sandstone at 1941.62 m (oil),
1945.54 m (oil), 1963.51 m (water, and 1963.52 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
September 2011 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6561
4/11/2017 12:00:00 AM
29.01.2023
16/2-7 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-7 A is a geologic sidetrack to
well 16/2-7 drilled about 5.5 kilometres southeast of the discovery well for
the oil discovery 16/2-6 (Avaldsnes) on the Utsira High in the North Sea. Well
16/2-7 confirmed the Avaldsnes Discovery OWC at 1922 m TVD MSL</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/2-7 A was drilled with
the semi-submersible installation on Bredford Dolphin. It was kicked off from
below the 20&quot; shoe at 708 m in primary wellbore 16/2-7 on 2 September 2011
and drilled to a total depth of 2100 m (2010 m TVD) in the Triassic Skagerrak
Formation. The sidetrack well was drilled conventionally with 12 1/4&quot; and
8 1/2&quot; sections using Performadril water based mud all through. No
significant problem was encountered in the operations.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The geological sidetrack penetrated the
BCU and top Intra Draupne Formation sandstone reservoir according to prognosis
at 2014 m (1931 m TVD). The Draupne sandstone rested unconformable on a 14 m
TVD thick Sleipner Formation sandstone with top at 2024 m (1940 m TVD). The Draupne
sandstone thickness variation going from 25 m TVD in 16/2-7 to 9 m TVD in
16/2-7 A is attributed to Late Jurassic faulting. As in 16/2-7 Pressure points
and MDT sampling results confirmed the presence of oil in the reservoir with a
free water level at approximately 2032 m (1947.5 m TVD). </span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 2012 to 2054 m
across the Draupne and Hugin formations. MDT wire line fluid samples were taken
at 2015.8 m (oil), 2031.29 m (oil), 2035.19 m (water), and 2036.95 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 29
September 2011 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



6711
4/11/2017 12:00:00 AM
29.01.2023
16/2-8


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Statoil well 16/2-8 (Aldous Major South) was
drilled about 4.2 kilometres west of the Lundin oil discovery well 16/2-6
(Avaldsnes) on the Utsira High in the North Sea. The 16/2-6 Avaldsnes discovery
was proven in September 2010 in Middle-Late Jurassic reservoir rocks. The main
objective of well 16/2-8 was to investigate the hydrocarbon potential in Late
Jurassic sandstones in the Draupne Formation and the Middle Jurassic
Hugin/Sleipner Formations. The secondary and third objectives were to explore
the hydrocarbon potential in the Triassic Skagerrak Formation and in Chalks of
the Late Cretaceous Shetland Group, respectively.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-8 was spudded with the
semi-submersible installation Transocean Leader on 17 July 2011 and drilled to
TD at 2140 m in the Triassic Skagerrak Formation. Neither shallow gas nor
shallow water flow was observed and the well was drilled without significant problems.
The well was drilled with seawater and bentonite sweeps down to 213 m, with
seawater and bentonite/PAC RE sweeps from 213 m to 945 m, with Performadril WBM
spec 6a from 945 m to 1573 m, and with Performadril Low sulphate WBM from 1573
m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The top of the main reservoir, in the
Draupne Formation, was picked at 1877 m. The reservoir (Draupne and Hugin
Formations) showed excellent reservoir properties and contained oil. An oil column
of 67.5 m was present down to 1944.5 m (1921 m TVD MSL), close to the contact
level seen in the 16/2-6 Avaldsnes well. Pressure data showed that the 16/2-8
Aldous Major South and the 16/2-6 Avaldsnes discoveries are in the same
pressure regime and thus in communication. The secondary objective, Skagerrak
Formation was water wet. The third objective, the Shetland Group chalk had moderate
to poor oil shows in the very top, from 1573 to 1622 m, with a pronounced wet
gas peak from 1573 to 1601 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Six cores were cut in the well. Cores 1
to 4 were cut from 1880.5 m to 1953.21 m in the Rødby Formation, across Draupne
and Hugin formations and into the Sleipner Formation. Cores no 5 and 6 were cut
from 1995 m to 2048.8 m in the Statfjord and Skagerrak formations. MDT wire
line fluid samples were taken at 1882.1 m (oil), 1931.2 m (oil), 1945.0 m
(water), 1945.4 m (water), and at 1947.2 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-8 proved communication between
the Aldous Major South discovery in PL265 and the Avaldsnes discovery in PL501
made by Well 16/2-6 in august 2010. The two discoveries will be developed
together under the name Johan Sverdrup Field. Well 16/2-8 was permanently
abandoned on 19 August 2011 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6562
4/11/2017 12:00:00 AM
29.01.2023
16/2-9 S


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/2-9 S was drilled on the Aldous
Major North prospect on the Utsira High in the North Sea. The prospect is
separated from the Aldous Major South/Avaldsnes discovery by a North-East
trending fault, but was considered as a possible extension of the Aldous Major
South. The main objective of the well was to investigate the hydrocarbon
potential, reservoir quality and lateral sand distribution in the Late Jurassic
Viking Group. The secondary objective of well 16/2-9 S was to explore the
hydrocarbon potential in the fractured granitic basement. The third objective
of well 16/2-9 S was to investigate the hydrocarbon potential in the Cretaceous
age Shetland Chalk Vindballen lead. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/2-9 S was spudded with
the semi-submersible installation Transocean Leader on 21 August 2011and
drilled to TD at 2082 m (2070.6 m TVD) into Basement rocks. Neither shallow gas
nor shallow water flow was observed, and operations went forth without
significant problems. The well was drilled with sea water and hi-vis bentonite
pills down to 343 m, with KCl/Polymer/GEM Spec 3 mud from 343 m to 1066 m, with
Performadril WBM spec 6a mud from 1066 m to 1725 m, and with Low sulphate
Performadril WBM mud from 1725 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top expected main reservoir, the Draupne
Formation, was picked at 1933.5 m. The intra-Draupne reservoir was unusual and consisted
of spiculites. It contained oil. The reservoir proved to be considerably
thinner and with much poorer reservoir quality than expected and the oil water
contact could not be established exactly. However, based on the saturation
profile and results from fluid sampling, the OWC was set at 1941.5 m (1930.1 m
TVD / 1906.6 m TVD MSL) with the Free Water Level a few meters further down. The
secondary and third objectives, the fractured granitic basement and the
Shetland chalk respectively, were dry. There were no oil shows observed in the
well apart from in the hydrocarbon bearing reservoir section.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were taken in the Skagerrak
Formation and into the basement at core depths 1952 - 1975.5 m, 1975.5 - 1987 m
and 1987.1 - 1991.5 m. The core shifts relative to the logs were 1, 2, and 3 m
respectively, for the three cored intervals. MDT wire line fluid samples were
taken at 1935.17 m (oil), 1938.2 m (oil), 1941.0 m (water/oil), and at 1941.7 m
(oil/water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 24
September 2011. It is classified as an oil appraisal to the Aldous Major South
discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6615
4/11/2017 12:00:00 AM
29.01.2023
16/2-U-18
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-18
was drilled on the Johan Sverdrup Field on the Utsira High in the North Sea. The
well objective was to reduce the geological uncertainty in the <span
class=SpellE>Espevær</span> North structure in order to place the planned
injectors from the E-template in a robust location with regards to sand
thickness and FWL.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>well 16/2-U-18
was spudded with the semi-submersible installation Deepsea Atlantic on 5 November
2016 and drilled to TD at 2143 m (2139 m TVD) m in the Triassic Skagerrak
Formation. Operations proceeded without significant problems. The well was
drilled with Seawater and hi-vis pills down to 951 m, with Aquadrill mud from
951 to 1748 m, and with Carbosea oil-based mud from 1748 m to TD. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The
Draupne Formation was encountered at 1947 m (1943 m TVD) and constitutes <span
class=GramE>of <span style='mso-spacerun:yes'> </span>muddy</span> spiculites.
Intra-Draupne Formation sandstone was penetrated from 1954 m (1950 m TVD) to
1978 m (1974 m TVD). A thin Hugin Formation sandstone is between the Viking Group
and the Statfjord Group and is in communication with the Viking Group. Shales in
the top of the Eiriksson Formation constitutes a pressure barrier. Hence, the
pressure gradient in the water in the Intra-Draupne and Hugin sandstones is 0.4
bar higher than in the homogeneous thick sand of the Eiriksson Formation below
the shale. These sands have better reservoir properties than the Intra-Draupne Formation
sandstone. The Eiriksson Formation sandstone is 1 bar depleted compared to well
16/2-10 reservoir sandstone. This is as expected based on the regional pressure
depletion in the area. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Fluid
contacts are not conclusive in the well. The deepest possible water up to depth
is 1956.5 m where a clean formation water sample was taken. A free water level
is weakly indicated by the logs in the homogeneous sand at 1954.6 m, but this cannot
be confirmed by pressure data. A paleo-OWC can be interpreted down to 1967 m,
but again this is uncertain due to partially missing core at this level. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Shows
were present in sandstones in the interval 1988 to 2028 m in the Statfjord
Group. They were typically described as poor to moderate to strong hydrocarbon
odour, no to even stain, poor streaming cloudy cut fluorescence white stain,
yellowish gold occasionally bluish gold even bright direct fluorescence,
moderately streaming becoming strongly cloudy cut fluorescence, spotted
residual fluorescent ring, brown patchy residual ring.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The
interval from 1937 to 2077 m was cored in seven cores with variable recovery
from 29.71% in core 3 to 100% in cores 5 and 7. Water samples were taken with
the RCX tool at 1956.5 m, 2020.5 m and 2046.5 m.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
permanently abandoned on 28 November 2016.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>




















































8052
11/14/2019 12:00:00 AM
29.01.2023
16/2-U-19
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-19
was drilled on the Johan Sverdrup Field on the Utsira High in the North Sea. The
primary objective was to reduce the depth, thickness and quality uncertainty of
the Draupne reservoir for future producers. The secondary objective of the well
was to gather geological information regarding the Draupne sand distribution in
the Geitungen area of the Johan Sverdrup Field.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/2-U-19
was spudded with the semi-submersible installation Deepsea Atlantic on 29 November
2016 and drilled to TD at 2017 m (2009.6 m TVD) in Basement rock. Operations
proceeded without significant problems. The well was drilled with seawater and
hi-vis pills down to 1180 m and with Carbosea oil-based mud from 1180 m to TD. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Intra-Draupne
Formation sandstone was encountered at 1907 m (1900 m TVD) and was directly
overlying basement rock at 1943 m (1936 m TVD). The Intra Draupne Formation
sandstone had excellent reservoir properties and was oil filled all through. The
pressure level in the reservoir is about 1 bar under the pressure observed in
August 2012 in 16/2-12, in line with the general rate of pressure depletion in
the area. There were no shows in the well outside of the oil-bearing reservoir.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Two cores
were cut from1896 in the Åsgard Formation to 1945 in the granitic basement.
Recovery was 99.6% in core 1 and 96.6% in core 2. The depth shift from logger’s
depth is 1.1 m for core 1 and 1.15 m for core 2. <span
style='mso-spacerun:yes'> </span>No fluid sample was taken.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
permanently abandoned on 12 December 2016.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>










































8063
11/14/2019 12:00:00 AM
29.01.2023
16/3-1

<p><b>General</b></p>

<p>Well 16/3-1 was drilled on the Utsira
High in the North Sea. The objectives were to investigate Paleocene sand pinch
out, the weathered top of the Cretaceous chalk and Jurassic sandstone.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/3-1 was spudded with the
semi-submersible installation Polyglomar Driller on 31 January 1976 and drilled
to TD at 453 m in Pliocene sediments. The well was drilled with seawater and
gel. </p>

<p>Due to progressive tilting of the BOP
stack the well was junked and abandoned 10 days later, on 10 February 1976.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


451
7/6/2016 12:00:00 AM
29.01.2023
16/3-2


<p><b>General</b></p>

<p>Well 16/3-2 was drilled 40 m east of
16/3-1 on the Utsira High in the North Sea. The objectives were to investigate
Paleocene sand pinch out, the weathered top of the Cretaceous chalk and
Jurassic sandstone. The 16/3-2 well is a replacement for well 16/3-1, which was
junked for technical reasons. </p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/3-1 was spudded with the
semi-submersible installation Polyglomar Driller on 11 February 1976 and
drilled to TD at 2019 m in granite basement. No significant problems were
reported from the operations. The well was drilled with spud mud (gel and lime)
and pre-hydrated bentonite down to 440 m, and with lignosulphonate mud from 440
m to TD. Around the well there was a 3 m deep and 15 m wide crater. Gas was
observed leaking from 2 main openings and 1 minor. The gas flow from one of the
major openings was about 400 l/hour. The gas was practically pure methane
(99.98%), probably coming from layers near the surface.</p>

<p>There were no sands in Paleocene and the Cretaceous
chalk was tight. A 20 m thick immature Draupne shale was encountered at 1955 m.
The well then encountered a 31 m thick late Jurassic sandstone from 1975 m to
2006 m. Below this sandstone was a 9 m thick layer of weathered basement
overlying the solid granite. The well proved to be water wet all through, and
no shows were recorded.</p>

<p>Three cores were cut. Core 1 gave no
recovery, while core recovered 3.5 m core from the interval 1998 m to 2000.6 m
in the Late Jurassic sand. Core no 3 was cut from 2017.5 m to 2019 m in
basement rock. No fluid sample was taken in the well.</p>

<p>The well was permanently abandoned on 8
March 1976 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>



334
7/6/2016 12:00:00 AM
29.01.2023
16/3-3


<p><b>General</b></p>

<p>Well 16/3-3 is located on the eastern
margin of the Utsira High in the North Sea. The primary objective of the well
was to test the reservoir and hydrocarbon potential of the Paleocene Heimdal
sands in the Havørn Prospect. The prospect sands pinches out to the east and
south combined with a structural dip to the northwest. The source kitchen was
expected to be the Late Jurassic Draupne Formation in the Southern Viking
Graben. Top seal for the sands were prognosed to be the Late Paleocene- and the
Eocene marine shales.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/3-3 was spudded with the
semi-submersible installation Vildkat Explorer on 24 July 1989 and drilled to
TD at 1566 m in the Late Cretaceous Tor Formation. No significant problems occurred
during the operations. The well was drilled with seawater down to 445 m and
with lignosulphonate/seawater and gel from 445 m to TD.</p>

<p>Late Cretaceous rocks were encountered at
1488 m, underlying 1341 meters of Cenozoic claystones. The Late Cretaceous
sediments (+ 78 m) consisted of white-creamy chalk. The Heimdal Formation sands
were absent. No reservoir intervals were penetrated. No shows were recorded. </p>

<p>No cores were cut and no fluid samples
taken in this well.</p>

<p>The well was permanently abandoned on 6
August 1989 as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>

1415
7/6/2016 12:00:00 AM
29.01.2023
16/3-4


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 was drilled to prove the extension
of the Avaldsnes Discovery to the north-east of the structural crest of the
Avaldsnes structure. In this area, a continuation of the Upper Jurassic, Intra-Draupne
Formation sandstone found in the discovery well 16/2-6 was expected to rest on
granitic basement.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/3-4 was spudded with the
semi-submersible installation Bredford Dolphin on 16 May 2011 and drilled to TD
at 2020 m in granitic basement. A 9 7/8&quot; pilot hole was drilled down to
planned setting depth for 20&quot; casing at 760. No shallow gas or boulders
were seen. No significant problem was encountered during drilling of the pilot
or the main well. The well was drilled with seawater and hi-vis sweeps down to
760 m and with Performadril mud from 760 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>BCU, top Draupne Formation was encountered
at 1914 m, and a 13.8 m thick Intra-Draupne Formation sandstone, Tithonian age,
was penetrated at 1926 m. The Intra-Draupne sandstone was oil-filled down to weathered
basement at 1940 m. No oil-water contact was established, however, pressure
communication between 16/3-4 and the 16/2-6 T2 Avaldsnes discovery well was
proved. There were no shows above or below the Intra Draupne Formation
sandstone reservoir.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut from 1913 to 1961 m,
covering the Draupne Formation and 21 m of the underlying Basement. Good
recovery was obtained in the first and last core (100 and 94% recovery
respectively), while the recovery in core number 2 was 43%. Extensive wire line
logging was performed including pressures (XPT/MDT) and fluid sampling. MDT
fluid samples were taken at 1929.0 m (oil), 1939.6 m (oil), and 1943 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>After completing the data acquisition
program and testing, the well was plugged back to the 20&quot; casing shoe and
sidetracked as well 16/3-4 A. The 16/3-4 well bore was permanently abandoned on
28 June as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Draupne Formation sandstone was
production tested (DST) from the interval 1923.5 to 1936.8 m. The test produced
in the main flow 18200 Sm3 gas and 885 Sm3 oil /day through a 52/64&quot;
choke. The GOR was 20 Sm3/Sm3 at separator conditions of 46 deg C and 13.6 bar.
The oil density and gas gravity at ambient conditions on-rig were 0.889 g/cm3
and 0.806 (air = 1), respectively. The maximum temperature measured at 1894.8 m
was 83.5 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>


6553
4/11/2017 12:00:00 AM
29.01.2023
16/3-4 A


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 A is a sidetrack to well
16/3-4, which was drilled to prove the extension of the Avaldsnes Discovery to
the north-east of the structural crest of the Avaldsnes structure. Well 16/3-4
proved oil in a 14 m thick Intra-Draupne Formation sandstone overlying
weathered basement rock. The oil was proven to be in pressure communication
with the 16/2-6 Avaldsnes discovery well. The 16/3-4 A sidetrack was drilled
up-flanks (south-south-west) of the main well bore. The objective was to
further appraise the Avaldsnes oil discovery and to determine the extent,
thickness, and quality of the reservoir in this part of the structure. </span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-4 A was kicked off from 790 m
in the primary well on 28 June 201. I was drilled with the semi-submersible
installation Bredford Dolphin to TD at 2128 m (1959 m TVD) in granitic basement.
No significant problem was encountered in the operations. The well was drilled
with Performadril mud from kick-off to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The geological sidetrack 16/3-4 A
encountered top Draupne Formation shales at 2065.5 m (1906.3 m TVD). At 2076.5
m (1915.6 m TVD) a 5 m vertical thickness of Intra-Draupne Formation sandstone was
penetrated. The Draupne sandstone was oil bearing down to fractured basement at
2081.6 m (1919.8 m). Slightly different fluid gradients were recorded compared
to the main wellbore, however, PVT analysis of the samples showed identical oil
to be present in both wellbores. No oil water contact was established. The
first oil shows in the sidetrack were observed in the marls of the Åsgard Formation
in a sidewall core at 2052.8 m. More extensive oil shows were seen in the
underlying Draupne sandstones. The oil shows became weaker in the fractured
basement that was recovered in the core. Oil shows were seen in cuttings and
sidewall cores below the core down to 2115.5 m; the last observed oil shows. </span></p>

<p class=MsoBodyText><span lang=EN-GB>One core was cut from 2067 m to 2082.5 m
in the Draupne Formation shales and reservoir sandstone, and into the basement.
MDT oil samples were taken at 2079.2 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 18
July 2011 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>

<p class=MsoBodyText><span lang=EN-GB>&nbsp;</span></p>



6629
4/11/2017 12:00:00 AM
29.01.2023
16/3-5
<html>

<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-5 is an appraisal well on the southeaster
part of the Sverdrup Field on the Utsira High in the North Sea. The objectives
were to determine presence and thickness of the Late Jurassic Intra-Draupne Formation
sandstone in a representative part of the Avaldsnes High (informal basement
structure), and to investigate the reservoir properties of the Permian
Rotliegend Group and Zechstein Group.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-5 was spudded with
the semi-submersible installation Bredford Dolphin on 4 January 2013 and
drilled to TD at 2050 m in the Permian Rotliegend Group. No significant problem
was encountered in the operations. The well was drilled with seawater down to 700
m and with Performadril water based mud from 700 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well encountered top Draupne
Formation shales at 1909 m and the Intra-Draupne Formation sandstone at 1918 m.
The Draupne shales are immature but has very good source rock potential with
TOC around 7-8 % and Hydrogen Index around 540 mg HC/g TOC. The Intra-Draupne
sandstone is 14 m thick and rested on Permian Zechstein Group carbonates. An
oil column of approximately 30 meters was found in the Intra Draupne Sandstone
and Permian carbonate. The well proves an excellent development of the Late
Jurassic sandstone in the southern part of the Avaldsnes High and the reservoir
level was encountered a bit shallower than predicted. The Permian carbonates,
mainly limestone, had varying reservoir quality with the best quality
principally located in open and partially cemented vugs, plus in the fractures.
The well results show an oil down-to situation and consequently no oil/water
contact was encountered. The oil bearing Zechstein limestones are in pressure
communication with the overlying Draupne sandstone.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 1912 to 1950.5 m
with ca 97% recovery in both. The cored interval includes the lower part of the
Draupne Formation shales, the whole Intra-Draupne sandstone unit, one m of
Triassic sediments, and 18.5 m of Permian limestones.  MDT oil samples were taken
at 1920.1 m, 1929.5 m, and 1943.6 m. MDT water samples were taken at 1959.4 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
March 2013 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One commingled production test from both
Draupne sandstones and Zechstein carbonates was performed in the well. DST 1A
tested only the lower zone in the Zechstein Group carbonates from 1937 to 1945
m. This zone did not produce oil to surface, but a rate of 2-3 Sm3/day was estimated
based on volumes of base oil to tank.</span></p>

<p class=MsoBodyText><span lang=EN-GB>DST1 B tested both zones: 1937 to 1945 m
in Zechstein plus 1918 to 1931.3 m in the Intra-Draupne Formation Sandstone. The
Intra-Draupne sandstone showed extremely good reservoir properties as well as
no indications of pressure barriers. This zone produced 740 Sm3 oil and 17000
Sm3 gas /day through a 40/64&quot; choke. The GOR was 17.5 Sm3/Sm3, the oil
density was 0.89 g/cm3 and the gas gravity was 0.79 (air = 1). The H2S and CO2
contents in the gas were ca 0.5 ppm and ca 0.4%, respectively. The maximum DST
temperature at the end of the Main flow was 79.9 °C.</span></p>



7046
4/11/2017 12:00:00 AM
29.01.2023
16/3-6


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-6 was drilled on the eastern part
of the Johan Sverdrup Field on the Utsira High in the North Sea. The primary
objective was to appraise the eastern part of the Johan Sverdrup Field between
wells 16/2-13 S and 16/3-4. These two wells are located 5 km apart and found
different Jurassic sequences and no oil water contact. Well 16/3-6 was drilled
to determine which Jurassic sequences were present at this position as well as
oil water contact, thickness of the sequences and depth to top reservoir.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>A 9 7/8&quot; pilot hole was drilled from
seabed 706 m to check for shallow gas. No shallow gas was seen. Appraisal well 16/3-6
was spudded with the semi-submersible installation Bredford Dolphin on 10 June
2013 and drilled to TD at 2050 m in fractured granitic basement. No significant
problem was encountered in the operations. The well was drilled with spud mud
down to 698 m and with Performadril water based mud from 698 m to TD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Top Draupne Formation/BCU was encountered
close to prognosis at 1924 m. A well-defined 15-meter thick Draupne Formation shale
was penetrated above 24 meters of excellent quality Late Jurassic Intra-Draupne
Formation sandstone. The Draupne Formation shales are of late Volgian to early
Valanginian age. The Intra-Draupne Formation sandstones were encountered at
1939 m. They are of early Kimmeridgian to ?late Kimmeridgian/early Volgian age
and rest directly on solid granitic basement rocks at 1964.5 m. No middle
Jurassic sequence was present as in the neighbouring well 16/2-13 S. The oil
water contact was established at 1951 m, 4 meters deeper than predicted. Oil
shows were described in the interval from 1925 m in the Draupne shales to 1956
m, 5 m below the oil water contact; no other shows were described in the well.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Two cores were cut from 1926 m in the
Draupne Formation shale, through the Intra-Draupne Formation sandstone
reservoir and down into the basement at 1968 m. The core recovery was close to 100%
and the core-log shift was 1.2 m. Oil and water samples were acquired using SLB
MDT tools. Oil samples were acquired at 1940.11 m, 1946.51 m and 1950.3 m.
Water samples were acquired at 1952.9 m and 1962.5 m. The oil samples proved a
GOR of ca 33 Sm3/Sm3, oil density of ca 0.892 g/cm3, and gas gravity of ca 1.06
(air = 1).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged and abandoned on 16
July 2013 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>The hole was perforated between 1952.2 m
and 1956.2 m, and two Expro Cats wireless downhole gauges were installed at
1900.7 m and 1885.2 m to monitor reservoir pressure and temperature. The gauges
have battery capacity to sample data for up to 5 years. No DST was performed.  </span></p>



7182
4/11/2017 12:00:00 AM
29.01.2023
16/3-7


<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-7 was drilled to appraise the southeast
flank of the Joan Sverdrup Field on the Utsira High in the North Sea. It is
located approximately 2.8 km southeast of the appraisal well 16/3-5 and
approximately 4.2 km south-west of the exploration well 16/3-2. The objectives
were to determine the presence and thickness of the Upper Jurassic Draupne
shale and Draupne sandstone, to calibrate the seismic interpretation and depth
conversion, and find the free-water level. The well should also investigate the
reservoir properties in the Permian.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-7 was spudded with
the semi-submersible installation Bredford Dolphin on 30 September 2013 and
drilled to TD at 2100 m, 12 m into granitic basement rock. A 9 7/8&quot; Pilot
Hole section was drilled from Seabed to 711 m. No shallow gas was observed
while drilling the pilot hole or while opening it up to 36&quot;. No
significant problem was encountered in the operations. The well was drilled
with seawater and hi-vis sweeps down to 711 m and with Aquadril glycol mud from
711 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The Draupne Formation shale section was
encountered at 1937 m and was 13 m thick. The Intra Draupne Formation Sandstone
was encountered at 1949 m, which was 12 m deep to prognosis. It was 14 m thick
and of excellent quality. Live oil was proved in the uppermost part, but the
reservoir was encountered almost completely in the water zone. Sampling
indicated that the oil-water contact is at or near 1950 m. Permian carbonates,
belonging to the Zechstein Group, were encountered at 1963 m, directly under
the Jurassic section. The 36 m thick dolomitic carbonate reservoir has moderate
to good reservoir properties. The pressure measurements confirmed the reservoir
to be in the same pressure regime as the Johan Sverdrup discovery and the well
showed a common water gradient in both the sandstone and Permian carbonates,
demonstrating good communication between the two reservoirs. The carbonate
reservoir is resting on a two meter thick Kupferschiefer, which in turn rests
on 89 m of sandstone and conglomerate belonging to the Rotliegendes Group. Oil
shows continued below the thin live oil, throughout the Intra Draupne Formation
sandstones, the Zechstein carbonates and a few meters into the Rotliegendes Group.</span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 35.7 m core was recovered in
two cores from the interval 1935.5 to 1977.5 m (85% overall recovery).The cores
captured most of the Draupne Formation shale, parts of the Intra Draupne
Formation sandstone reservoir, and 15 m of the Zechstein Group carbonate. The
core to log depth shift was +0.3 m for core 1 and -0.32 m for core 2.  RCX fluid
samples were taken at 1949.9 m (water and oil), 1950 m (water and trace oil),
1952 m (water), 1952.1 m (water), and 1967 m (water).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 8
November 2013 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>


7276
4/11/2017 12:00:00 AM
29.01.2023
16/3-8 A
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-8 A is a geological sidetrack
to well 16/3-8 S.  The well was drilled on the eastern part of the Johan
Sverdrup Field on the Utsira High in the North Sea. The primary objective was
to further investigate the reservoir sections penetrated in the primary well
bore 16/3-8 S.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-8 A was kicked off at
1716 m in the primary well bore on 18 March 2014. It was drilled with the
semi-submersible installation Bredford Dolphin to TD at 2132 m in the Permian
Rotliegend Group. No significant problem was encountered in the operations. The
well was drilled with Aquadrill mud from kick-off to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>The well penetrated 12 m of Intra Draupne
Formation sandstone at 1960 m, above a thin Triassic sequence and Permian
Zechstein carbonates. The Intra Draupne sandstone possessed excellent reservoir
properties. Petrophysical analysis show average porosity of 25 %, N/G 0.99 and
water saturation of 19 %. The resistivity data over the section is affected by
massive filtrate or whole mud invasion. Oil shows were described over the Intra
Draupne Formation sandstone reservoir and in the dolomitic limestone in the
lower part of the Zechstein Group, down to top Kupferschiefer Formation. The
oil-water contact was the same as in the main well bore, at 1950 m TVD.</span></p>

<p class=MsoBodyText><span lang=EN-GB>No cores were cut in this well bore. An
RCX fluid sample was taken at 1990 m (water and filtrate).</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
April 2014 as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed.</span></p>
7459
4/11/2017 12:00:00 AM
29.01.2023
16/3-8 S
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/3-8 S was drilled on the
Avaldsnes High, in the Eastern part of the Johan Sverdrup Field in the North
Sea. The well has a crestal position on this part of the Johan Sverdrup
structure. The primary objective was to investigate the reservoir properties of
the Zechstein Carbonates, including a designed DST for this purpose. A
secondary objective was to determine the presence, thickness and quality of the
Late Jurassic Intra Draupne Formation sandstones at this location.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/3-8 S was spudded with
the semi-submersible installation Bredford Dolphin on 1 January 2014 and
drilled to TD at 2109 m in the Permian Rotliegend Group. No significant problem
was encountered in the operations. The well was drilled with spud mud down
to 607 m and Aquadrill mud from 607 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A six-meter thick interval of tight
Draupne shale was encountered before entering the Volgian Intra Draupne
Formation sandstone reservoir at 1964 m (1897 m TVD). The reservoir section
consists of 13 meters of Draupne sandstone with excellent reservoir quality and
66 meters of Zechstein carbonates with variable reservoir quality. The
carbonate sequence consists of limestone with limited reservoir quality in the
upper part and dolomites with moderate to good reservoir quality in the lower
part. The reservoir contained a 53 m TVD oil column. The oil/water contact is interpreted
at 2021 m (1950 m TVD) based on the interception of the water gradient and the
oil gradient from pressure measurements. Oil shows are described throughout the
oil-bearing reservoir and down to a depth of 2035.6 m in the dolomitic
limestones.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Four cores were cut in succession from 1965
m in the Draupne Formation, through the Intra Draupne Formation Sandstone and
the Smith Bank Formation and down to 2035.6 m in the Zechstein Group
carbonates. Recovery was good, between 97.2 and 100%.  RCX fluid samples were
taken at 1965.6 m (oil), 1977.7 m (oil), 2019.5 m (water and oil), and 2037.8 m
(water). Single stage separation to ambient conditions gave a GOR of ca 41
Sm3/Sm3 and an oil density of ca 0.894 g/cm3 for both of the two oil samples.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was plugged back and prepared
for sidetracking on 16 March 2014. It is classified as an oil appraisal well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>One production test was performed. The
interval 1964.1 - 1979.2 m was perforated and tested. In the main flow, the
test produced 803 Sm3 oil and 18900 Sm3 gas through a 52/64&quot; choke. The
GOR was 23.5 Sm3/Sm3, the oil gravity was 0.89 g/cm3, and the gas gravity was
0.79 (air = 1). The maximum DST temperature was 82.5 °C.</span></p>

7302
4/11/2017 12:00:00 AM
29.01.2023
16/3-U-1
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1
was drilled on the south-eastern end of the Johan Sverdrup Field on the Utsira
High in the North Sea. The reservoir in this part of the field is below seismic
resolution. The primary objective was to investigate sand presence, thickness
and quality. Side-tracks were planned to further investigate horizontal well
drilling and high angle hole time-stability in Draupne shales.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1
was spudded with the semi-submersible installation Deepsea Atlantic on 13
December 2016 and drilled to TD at 2005 m (1999 m TVD) m in Basement rocks. The
well was designed with open hole below the 13 3/8” casing shoe at 1119 m in the
Hordaland Group. This allowed for reservoir logging at TD to be extended to the
overburden. Operations proceeded without significant problems. The well was
drilled with seawater and hi-vis pills down to <span
style='mso-spacerun:yes'> </span>down to 1130 m and with Carbosea oil-based mud
from 1130 m to TD. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The
Draupne Formation was encountered at 1938 m (1932 m TVD), the Intra-Draupne
Formation sandstone at 1950 m (1944 m TVD), <span
style='mso-spacerun:yes'> </span>and top Basement at 1959 m (1953 m TVD). The
Intra-Draupne Formation sandstone had excellent reservoir properties and was
oil-filled all through. No oil shows were described outside of the oil-bearing
reservoir. Pressure data show ca 0.9 bar depletion in the reservoir compared to
the pressure in well 16/3-5 in January 2013. Pressure data and logs in the
overburden show no indication of flow potential.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>One core
was cut from 1943 to 1962 m in Draupne shale, sandstone and into basement. An
RCX oil sample was taken at 1958.2 m.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
plugged back for side-tracking on 24 December 2016.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p>&nbsp;</o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p>&nbsp;</o:p></span></p>































8071
11/14/2019 12:00:00 AM
29.01.2023
16/3-U-1 A
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1
A is a geological and geo-mechanical side-track to 16/3-U-1 on the
south-eastern end of the Johan Sverdrup Field on the Utsira High in the North
Sea. The reservoir in this part of the field is below seismic resolution. <a
name="_Hlk23318253">The primary objective of the primary well and side-track was
to investigate sand presence, thickness and quality. Secondary, to investigate
horizontal well drilling and high angle hole time-stability in the Draupne
shales.<o:p></o:p></a></span></p>

<span style='mso-bookmark:_Hlk23318253'></span>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Wildcat
well 16/3-U-1 A <a name="_Hlk23319048">was kicked off below the 13 3/8” casing
at 1135 m in the primary well on 24 December 2016. It was drilled with the
semi-submersible installation Deepsea Atlantic, down-dip towards the south-east
to TD at 2882 m (1965 m TVD) in Basement rock. Operations proceeded without significant
problems. The well was drilled with Carbosea oil-based mud from kick-</a><span
class=GramE><span style='mso-bookmark:_Hlk23319048'>off <span
style='mso-spacerun:yes'> </span>to</span></span><span style='mso-bookmark:
_Hlk23319048'> TD. <o:p></o:p></span></span></p>

<span style='mso-bookmark:_Hlk23319048'></span>

<p class=MsoBodyText><a name="_Hlk23319432"><span lang=EN-GB style='mso-ansi-language:
EN-GB'>Top Draupne Formation was penetrated at 2578 m (1939 m TVD), while the
Intra Draupne Formation sandstone was encountered at 2763 m (1955 m TVD), and Basement
at 2861 m (1963 m TVD). </span></a><span lang=EN-GB style='mso-ansi-language:
EN-GB'>The Draupne sandstone had abundant cementations and was water-filled. The
hole was re-entered as planned after 48 hours from encountered TD, with liner running
parameters, in order to simulate a liner running job combined with time exposure
of the Draupne shale. The BHA was not able to pass restrictions at the top of
the Draupne shale. It was decided to re-enter with a less stiff BHA. However, a
fire broke out in a hose and led to about a week delay in operations, the well
had to be abandoned, and a side-track, 16/3-U-1 B, was prepared.<o:p></o:p></span></p>

<p class=MsoBodyText><a name="_Hlk23320912"><span lang=EN-GB style='mso-ansi-language:
EN-GB'>There are no oil show recordings from this well bore.<o:p></o:p></span></a></p>

<span style='mso-bookmark:_Hlk23320912'></span>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No cores
were cut. No fluid sample was taken.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
plugged back for side-tracking on 10 January 2017.</span><span lang=EN-GB> </span><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p>&nbsp;</o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p>&nbsp;</o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p>&nbsp;</o:p></span></p>

</div>

</body>

</html>









































8077
11/15/2019 12:00:00 AM
29.01.2023
16/3-U-1 B
<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>General</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1
B is a geological and geo-mechanical side-track to 16/3-U-1 on the
south-eastern end of the Johan Sverdrup Field on the Utsira High in the North
Sea. The reservoir in this part of the field is below seismic resolution. The
primary objective of the primary well and side-tracks was to investigate sand presence,
thickness and quality. Secondary, to investigate horizontal well drilling and high
angle hole time-stability in the Draupne shales. As part of the secondary objective
the first side-tracked bore hole 16/3-U-1 A should be left open for 48 hours
and then re-entered. After an unsuccessful re-entry well bore 16/3-U-1 A was
abandoned and side-track 16/3-U-1 B was initiated. Final TD in this side-track was
set to a location between the primary wellbore and the first side-track in order
to penetrate the field OWC.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Operations
and results</span></b><span lang=EN-GB style='mso-ansi-language:EN-GB'><o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Well 16/3-U-1
B was kicked off from 16/3-U-1 A below the 13 3/8&quot; shoe at 2115 m on 10 January
2017. It was drilled with the semi-submersible installation Deepsea Atlantic, down-dip
towards the south-east of the primary well bore to TD at 2665 m (1963 m TVD) in
Basement rock. Operations proceeded without significant problems. The well was
drilled with Carbosea oil-based mud from kick-off <span
style='mso-spacerun:yes'> </span>to TD. <o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>Top
Draupne Formation was penetrated at 2515 m (1937 m TVD), while the Intra
Draupne Formation sandstone was encountered at 2598 m (1952 m TVD), and Basement
at 2646 m (1960 m TVD). The Intra-Draupne sandstone was oil-filled down to the
OWC at<span style='mso-spacerun:yes'>  </span>2605.5 (1953 TVD).<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>In order
to check for mechanical issues, a check trip through Draupne shale was
successfully made 8-9 hours after drilling. Then a second check trip was made
after 18 hours. The BHA was unable to get down with liner running parameters,
and therefore drilling parameters were used and proved to be successful.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>There are
no oil show recordings from this well bore.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No cores
were cut. No fluid sample was taken.<o:p></o:p></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>The well was
permanently abandoned on 15 January 2017.<o:p></o:p></span></p>

<p class=MsoBodyText><b><span lang=EN-GB style='mso-ansi-language:EN-GB'>Testing</span></b><span
lang=EN-GB style='mso-ansi-language:EN-GB'> <b><o:p></o:p></b></span></p>

<p class=MsoBodyText><span lang=EN-GB style='mso-ansi-language:EN-GB'>No drill
stem test was performed. <o:p></o:p></span></p>















































8104
11/15/2019 12:00:00 AM
29.01.2023
16/4-1
<p><b>General</b></p>

<p>Well 16/4-1 is located on the Utsira
High. The primary objective of the well was to test the Paleocene Heimdal
Formation. Secondary objectives were Jurassic and Triassic sandstones,
Zechstein carbonates and Rotliegendes conglomerates. The well was planned to
reach TD at 2850 m + 100 m after having identified a seismic reflector at this
depth, interpreted to represent Top Metamorphic Basement.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/4-1 was spudded with the
semi-submersible installation Treasure Seeker on 8 September 1984 and drilled
to TD at 2909 m in crystalline/metamorphic basement of Early Paleozoic age.
Under the 30&quot; casing shoe a 17 1/2&quot; pilot hole was drilled. At 494 m
in Pleistocene sand and shale, the well started to flow up the annulus from a
small gas pocket. The well died out by itself but there were problems with lost
circulation, so a cement plug was set from 494 - 415 m. The cement was drilled
out to 480 m and the hole was underreamed to 26&quot; before landing of the
20&quot; casing. No other major problems occurred during drilling of this well.
The well was drilled with seawater and bentonite down to 494 m, with
KCl/polymer mud from 494 m to 2052 m, and with NaCl/polymer mud from 2052 m to
TD. </p>

<p>The well 16/4-1 encountered water-bearing
sandstones in the Paleocene Heimdal Formation as well as in the Triassic. The
latter is a 36 m thick sand in between the Smith Bank Formation and the
Zechstein Group. The Heimdal Formation Sandstones occur as interbedded
sand/claystone in the upper part (2100 m to 2142 m) and as a massive sandstone,
which is homogenous and very clean in the lower part (2142 m 2277 m). The
Triassic sandstones (2394 m to 2430 m) were very fine-to-fine grained with a
considerable amount of silt and mica. Log evaluations over these sands gave the
following results: The interval 2100 m to 2142 m gave a net/gross ratio of
0.095, with an average porosity of 23,06% and a shale volume of 43,58% after
cut-off. The interval 2142 m to 2277 m had a N/G of 0,89 with 26,36% average
porosity and 11,19% shale volume. The Triassic interval (2394 m to 2430 m) had
a net/gross of 0,37 with 22,88% average porosity and 18,54% shale volume. All
these values are calculated after a cut-off of 20% (1 mD). Twenty-five pressure
tests (RFT) were performed from 2083 m to 2422.4 m. These gave a water gradient
of 0,445 psi/ft (1.024 g/cc) in the Heimdal Fm sandstones. No pressure data
were obtained from the Triassic. </p>

<p>Three cores were cut in this well, the
first and second in sandstones of the Heimdal and Smith Bank formations
respectively. The third core was taken in metamorphic/crystalline basement.
Core 1 was cut from 2161 m to 2174 m in the Heimdal formation. The recovered
core of 11 m (85%) consisted of very fine to medium grained, poorly sorted sandstone
with claystone in the interval 2170-71 m. Core 2 was cut from 2404 m to 2422 m
and 17.5 m (97%) was recovered. The core was cut in the Triassic sand under the
Smith Bank Formation. It consisted of micaceous sandstones and siltstones with
subordinate clay clasts. Core 3 was cut from 2907 m to 2909 m in the Basement
and 100% was recovered. The core consisted of schist and granite. No fluid
samples were collected. The well was permanently abandoned on 18 November 1984
as a dry well.</p>

<p><b>Testing</b></p>

<p>No drill stem test was performed</p>


229
7/6/2016 12:00:00 AM
29.01.2023
16/4-10
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/4-10 was drilled to test the Fosen
prospect on the southwest part of the Utsira High in the North Sea. The primary
objective was to test the hydrocarbon potential in Late and Middle Jurassic
reservoirs. A secondary objective was to core the BCU top reservoir boundary for
facies evaluation and dating.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Wildcat well 16/4-10 was spudded with the
semi-submersible installation Island Innovator on 24 January 2016 and drilled
to TD at 2668 m in Early Triassic sediments in the Smith Bank Formation. A 9
7/8&quot; pilot hole was drilled to 520 m after installing the
30&quot;x36&quot; conductor casing to check for shallow gas. No shallow gas or
water flow was observed. No significant problem was encountered in the
operations. The well was drilled with seawater and hi-vis pills down to 529 m
and with Aquadril mud from 529 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-US>The well encountered about 160 m of water
bearing sandstones in the Late Jurassic to Middle Triassic, of which about 90 m,
mainly in the Middle Jurassic Sleipner Formation, are of good reservoir
quality. The well also encountered 75 m of reservoir rocks with very good
reservoir quality in the Paleocene Ty Formation. Trace fluorescence was
recorded in the Sleipner Formation, but could not be confirmed as migrated
petroleum in post-well organic geochemical analyses. </span></p>

<p class=MsoBodyText><span lang=EN-GB>A total of 11.7 m core was cut in four
cores from 2424.1 to 2440 m in the Åsgard Formation, thus missing the BCU
boundary. Core depths are equal to log depths for all cores. After drilling through
BCU there were no shows and no gas response and it was decided to drill ahead
without taking any more cores. MDT pressure points were acquired in the
reservoir section and water samples were taken at 2313.6 m and 2467.1 m.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 7
March 2016 as a dry well.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>

7731
5/23/2017 12:00:00 AM
29.01.2023
16/4-11
<p class=MsoBodyText><b><span lang=EN-GB>General</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Well 16/4-11 was drilled on the Luno
Discovery on the Utsira High in the North Sea. The primary objective of the
well was to delineate the southwest flank of the 16/4-6 S (Luno II) discovery,
to investigate the reservoir properties, and to investigate the type of oil and
total oil column in this part of the discovery.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Operations and results</span></b></p>

<p class=MsoBodyText><span lang=EN-GB>Appraisal well 16/4-11 was spudded with
the semi-submersible installation COSL Innovator on 7 February 2018. A 9 7/8”
pilot hole was drilled from below the 30x36” casing shoe at 195 m to 475 m. Shallow
gas was observed in the interval 469 m to 471 m. The 20” casing was therefore
set shallow at 409.5 m, above the shallow gas zone. From there the well was
drilled to TD at 2475 m in the Permian Rotliegendes Group. Operations proceeded
without significant problems. The well was drilled with seawater and hi-vis
pills down to 409.5 m, with KCl/polymer mud from 409.5 m to 1922 m, and with
Aquadrill mud from 1922 m to TD. </span></p>

<p class=MsoBodyText><span lang=EN-GB>Top of the target reservoir, Hegre Group,
was encountered at 1950 m. It was oil-bearing down to a clear oil-water contact
at 1971.5 m. Good shows were described in the oil-bearing reservoir section.
Below the OWC shows continued down to the base of the cored interval at 2004 m.
These shows are described as having no odour, 100% even weak yellowish direct
fluorescence, slightly blooming weak bluish white cut fluorescence, and 10%
moderate bluish white fluorescent residue. The conventional core and sidewall cores
from the Permian sandstone had shows that weakened with depth in the interval
2090 to 2329 m. These are typically described as having no odour, yellowish
brown direct fluorescence, no to diffuse blue-white fluorescent cut, and no to
80% blue white cream fluorescent residue.</span></p>

<p class=MsoBodyText><span lang=EN-GB>Three cores were cut in the well. Cores 1
and 2 were cut in the top of the Hegre Group reservoir from 1952 to 2004.1 m
with 100% recovery. Core 3  was cut in the Permian sandstones from 2090 to 2099
m with 94.2% recovery. MDT fluid samples were taken at 1952.1 m (oil), 1963 m
(oil), 1970.1 m (oil), 1971.61 m (water), 1978.3 m (water), 2001.72 m (water),
and 2075 m (water). Single flash of the uppermost oil sample gave a GOR of
233.4 Sm3/Sm3 and an oil density of 0.8482 g/cm3.</span></p>

<p class=MsoBodyText><span lang=EN-GB>The well was permanently abandoned on 1
April 2018 as an oil appraisal.</span></p>

<p class=MsoBodyText><b><span lang=EN-GB>Testing</span></b><span lang=EN-GB> </span></p>

<p class=MsoBodyText><span lang=EN-GB>No drill stem test was performed. </span></p>



8353
4/1/2020 12:00:00 AM
29.01.2023
16/4-2

<p><b>General</b></p>

<p>Well 16/4-2 was the second well on the
block and last commitment well for license 087. The well is located in a
central position on the structure, close to the western border of the block.
The main target was sands of Middle Eocene age supposed to be present within a
mounded seismic sequence that constitutes the eastern part of the Alpha
prospect in the Sleipner Field. The primary objective of the well was to prove
oil in the Eocene sandstones. Secondary objectives were to confirm the seismic
interpretation and the geological model for the Eocene sand; to test a possible
small closure at top Heimdal Formation level; to obtain additional information
on migration paths in the area; to confirm the seismic interpretation of the
basal Cretaceous/ Late Jurassic sequence; and to test the hydrocarbon potential
of possible Late Jurassic sand accumulations. Shallow gas could be expected at
537 m. This corresponds to the level of the blowout in well 16/4-1. A possible
shallow gas content could occur in a thin sand layer at 685 m, which was
correlated from well 16/4-1.</p>

<p><b>Operations and results</b></p>

<p>Wildcat well 16/4-2 was spudded with the
semi-submersible installation Vildkat Explorer 29 June 1990 and drilled to 3117
m in Intra Draupne Formation sandstones. No shallow gas was encountered in the
well; the gas zones were drilled with r