Shell U.K. Limited

Relinquishment Report

for

Licence P.2038

(Blocks 29/8b and 29/9a)

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Important Notice

This Relinquishment Report does not purport to be all-inclusive or to contain all of the information

that an interested party might desire. Shell has provided the information contained in this

Relinquishment Report in good faith; nevertheless Shell and the participants in the P.2038

Partnership and the affiliates, officers, directors, employees, agents, advisers and representatives of

all such entities make no representations or warranties, expressed or implied or accept any

responsibility or liability, concerning any information in this Relinquishment Report or the omission

of any information.

Reliance on the information provided in this Relinquishment Report shall not give rise to any cause

of action against Shell and the participants in the P.2038 Partnership, or the affiliates, officers,

directors, employees, agents, advisers and representatives of all such entities, including, without

prejudice to the generality of the foregoing, causes of action or claims based upon their negligence

or wilful misconduct.

This Relinquishment Report contains forward-looking information (statements that are not historical

facts and relate to future performance) concerning, among other things, a property's prospects for

production. Although Shell believes the expectations reflected in these forward-looking statements

are based on reasonable assumptions, no assurance can be given that these expectations will be

correct. No representation, warranty or undertaking, express or implied, is made by Shell and the

participants in the P.2038 Partnership, or the affiliates, officers, directors, employees, agents,

advisers and representatives of all such entities, that any projections, forecasts or opinions should or

will be achieved. In furnishing this Relinquishment Report, each such entity undertakes no obligation

to provide the recipient with access to any additional information.

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1. Licence Information

Licence Number: P.2038

Licence Round: 27th

Licencing Round 2012

Licence Type: Traditional

Block Numbers: 29/8b and 29/9a

Equity Holding: Shell U.K. Limited (50%, operator)

Esso Exploration and Production UK Limited (50%)

2. Licence Synopsis

The P.2038 licence, comprising blocks 29/8b and 29/9a, is located some 225 km east of the UK

coastline, in the UK sector of the Central North Sea (Figure 1). The licence was awarded during the

27th

Offshore Oil and Gas Licencing Round to Shell U.K Limited (100%) with a start date of 1 January

2013. Subsequently in March 2013, in keeping with a 50 year old partnership in the North Sea, Esso

Exploration and Production UK Limited backed into the licence obtaining a 50% interest with Shell

U.K. Limited remaining as operator with a 50% interest. The initial licence term expires on 31

December 2016.

Figure 1 – Location of Licence P.2038.

At the time of licence application, potential was assessed in the undeveloped Acorn North and

Beechnut East high pressure/high temperature oil discoveries in combination with additional

prospectivity at the Beechnut West exploration lead. The licence bid included both the 29/8b (Acorn

North) and 29/9a (Beechnut) blocks as any potential economic development would need the

combined resources from both blocks. Key to unlocking these stranded resources was considered to

include proving the Beechnut West volumes combined with an envisaged relatively low cost

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development concept based primarily on a subsea tie-back to an anticipated FPSO at the nearby (10

km to the north) Fram discovery. Potential synergies with the undeveloped Puffin discovery 18 km to

the northeast were also considered.

3. Work Program Summary

The work program for the initial licence term comprised obtaining 100 km2 of 3D seismic data and

drilling a well targeting Jurassic sands at Beechnut West.

A total of 293 km2 of 3D seismic was obtained within the licence area, consisting of both reprocessed

and newly acquired data, exceeding the commitment for 100 km2 of data. Licencing of 190 km

2 of

the Cornerstone 3D TomoML reprocessed data and 103 km2 of the newly acquired Cornerstone 3D

Quad 30 Phase 8 Extension data was purchased from CGG. A comparison of these data sets with the

previous 3D seismic is shown in Figure 2. An important feature of the new data is improved reflector

continuity and multiple suppression at top reservoir level (Figure 2 right panel), further enhanced by

Shell post-processing. The obtained surveys enabled coverage of the entire licence area with new

seismic data of superior quality to that available at the time of licence application (Figure 3).

Figure 2 – Comparison of 3D seismic vintages showing progressively improved imaging from left to right panels. Seismic

data courtesy of CGG Multi Client.

As a result of integrated technical studies completed utilising all available data, including the newly

obtained 3D seismic data, the remaining undrilled potential in the P.2038 licence is too immaterial to

deliver an economic discovery and therefore further drilling will only erode value to all stakeholders.

The discovered volumes at Acorn North and Beechnut East have also been reduced from pre-award

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estimates due to improved seismic imaging which indicates greater reservoir complexity. These

factors, combined with a higher cost development concept due to the Fram FPSO project no longer

proceeding, result in no viable economic project being present and the licence will be relinquished.

4. Database

The seismic and well data available for the resource assessment of licence P.2038 is summarised in

Figure 3 and presented in Tables 1 and 2.

Figure 3 – Map of seismic and well database.

Table 1 – Summary of 3D seismic data within the licence.

The newly obtained Cornerstone 3D Tomo ML data was available and interpreted over the entire

licence area. The later Cornerstone 3D Quad 30 Phase 8 Extension data which became available

3D Seismic Survey Type Year Aquired Processing Area Covered

Quad 30 Phase 4 Conventional 2004 2011 HPHT PSDM Entire P.2038 licence

Cornerstone 3D Tomo ML Conventional 2004 2014 CGG PSDM Entire P.2038 licence

Cornerstone 3D Quad 30 Phase 8 Extension Broadseis 2014 2015 CGG PSTM Central 29/8b block

Cornerstone 3D Quad 30 Phase 8 Extension Broadseis 2014 2015 CGG PSDM Central 29/8b block

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during the feasibility study is restricted to the Acorn part of the licence area (Figure 3) and was used

to assess the quality of the new seismic interpretations.

Well calibration within the licence is provided by a total of 11 exploration and appraisal wells drilled

by various operators over a period of nearly 40 years (Table 2).

Table 2 – Summary of well data within the licence.

5. Prospectivity Update

Licence P.2038 contains four undeveloped HPHT oil discoveries; Acorn North, Acorn South, Beechnut

East and Lynn North and a number of exploration leads (Figure 3). The discoveries are stranded due

to uncertainties related to in-place and recoverable volumes, HPHT technical and cost challenges

and access to a suitable host. The Acorn North and Beechnut East discoveries, as envisaged at the

time of licence application, were to provide the main economically viable opportunities for a

conceptual cluster development in combination with a successfully appraised Beechnut West, all

evacuated to the planned FPSO at Fram. Volumes at other discoveries and leads within the licence

are small and below economic development threshold. A comprehensive feasibility assessment has

been completed on the licence comprising detailed technical studies which fully utilise the newly

obtained 3D seismic data.

Regional Structure

A robust regional structural interpretation was key as a predictor of Jurassic versus Triassic reservoir

presence in the licence area. This chiefly involved the delineation of “pod” versus “interpod” areas

Well Operator Year Status Well Test

29/8b-1 Premier 1976 Abandoned, Dry n/a

29/8b-2s Union Oil 1983 Suspended, Acorn South discovery Short term well test

29/8a-3 Shell 1985 Abandoned, Acorn North discovery Short term well test

29/9b-2 Premier 1985 Suspended, Beechnut East discovery Short term well test

29/9b-3 Premier 1986 Abandoned, Dry n/a

29/8a-4 Shell 1988 Abandoned, Lynn North discovery Short term well test

29/9b-6 Premier 1989 Abandoned, Beechnut B6 appraisal Short term well test

29/8b-5 Hess 1996 Abandoned, Dry n/a

29/9b-9 Hess 2001 Abandoned, Beechnut Graben appraisal Short term well test

29/9b-9z Hess 2001 Abandoned, Beechnut North Flank appraisal None

29/8a-6 Venture 2009 Abandoned, Acorn North appraisal Extended well test

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which are the fundamental tectonic building blocks of the Permian-Jurassic structure. The major

regional surfaces, including Top Rotliegend (Figure 4), Top Zechstein (Figure 5), Base Cretaceous

Unconformity (Figure 6) and Top Cromer Knoll (Figure 7) were mapped over the full licence area.

The discoveries at Acorn and Beechnut (and Fram to the north) are underpinned by Rotliegend fault

blocks, which can have very large throws of up to 1s TWT (Figure 4). There are several overprinted

fault orientations, with the dominant extension being on the E-W striking faults. The Rotliegend

faults around Beechnut throw to the South, while the major faults underpinning Fram throw

northwards. The Acorn discoveries sit in a relay zone between these fault systems.

Overlying the Rotliegend is the Zechstein salt. The depositional geometry, depositional facies and

mechanical stratigraphy bore great influence on the present day structural configuration of the

overlying succession as the salt tectonic processes matured. Salt was deposited in the Permian

within the arid Silverpit Lake. It is likely that in the earliest stages of basin extension, brittle

deformation of the Rotliegend provided highs and discontinuities upon which salt structures could

nucleate. In some areas the salt welded in the Triassic, leaving grounded pods. Salt structures

continued to develop in the interpods as late as the Eocene leaving salt pillows, walls or diapirs

(Figure 5). Examples include the Beechnut discovery which sits on an E-W striking salt wall and Acorn

South which sits upon a salt diapir. An area of welded salt sits beneath the two, defining a Triassic

pod.

The next regional seismic marker above salt is the Base Cretaceous Unconformity (BCU). This is a

marked erosional unconformity formed during the major extension phase of the basin and the rift

fabric can be clearly seen on this surface (Figure 6). Growth of the salt wall beneath Beechnut seems

to have subsided by this point. The Acorn South and Fram salt bodies were clearly still expanding.

The situation at Acorn North is more complex with movements related to several smaller diapirs

continuing to have a subtle impact on the structure at BCU level.

The Top Cromer Knoll is near the base of the post rift sediments in the basin. Above this sediments

onlap the basin margin to the south with local inversion in the Cimmerean. There is some evidence

for inversion across Acorn South and Beechnut, but generally the post rift sediments gently drape

the two structures (Figure 7). The Fram diapir to the north was the only active salt feature in the

area post Cromer Knoll deposition.

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Figure 4 – Regional Top Rotliegend structure. Seismic data courtesy of CGG Multi Client.

Figure 5 – Regional Top Zechstein structure. Seismic data courtesy of CGG Multi Client.

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Figure 6 – Regional Base Cretaceous Unconformity structure. Seismic data courtesy of CGG Multi Client.

Figure 7 – Regional Top Cromer Knoll structure. Seismic data courtesy of CGG Multi Client.

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Acorn North

Acorn North is an HPHT oil accumulation within Skagerrak reservoir discovered by well 29/8a-3. A

high angle appraisal well, 29/8a-6, was drilled a few hundred meters north of the first well. Acorn

North is not a typical, simple Triassic pod but rather contains a number of small salt diapirs within

the pod area. There are two small diapirs within the Acorn North Field itself as well as an

underpinning salt pillow which may also affect structure. Additionally there is a significant salt diapir

present at the southern margin of the field at Acorn South. Internal faulting is typified by relatively

small normal faults which approximately follow the dominant North-South and Northeast-Southwest

trends (Figure 8). The area around the 29/8a-3 and 29/8a-6 wells at the crest of the field appears to

be more intensely faulted than other parts of the discovery.

Figure 8 – Acorn North Top Skagerrak depth map from static model. For model area see Fig. 10

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A typical seismic section is shown in Figure 9 which intersects the 29-8a-3 discovery well. The BCU is

a clear regional seismic reflector while the Top Skagerrak is a more difficult pick.

Figure 9 – Interpreted west-east seismic section over the 29/8a-3 well at Acorn North. Seismic data courtesy of CGG Multi

Client.

A detailed interpretation of the data beneath the BCU identified several distinct seismic facies

related to the variable presence of Triassic-Jurassic stratigraphy and numerous roughly circular

structural elements related to the relatively complex interaction of sediment deposition and salt

tectonics under the Acorn North field (Figure 10).

The most common seismic facies were a “Skagerrak Type” where the sub Kimmeridge reflectors had

very little character. A large part of the Acorn North Triassic section is composed of this seismic

facies, which can be tied to the 29/8A-3 and 29/8A-6 wells and is indicative of the presence of

Skagerrak reservoir. The south west fringing area had a “Jurassic Wedge” type seismic facies, with a

prominent reflector that could be tied to the Heather Fm in the 29/8A-4 well in the northwest of the

field area. A similar high amplitude facies is found in the graben to the east of the discovery well

(Figure 10). The fill of this graben has no well control but interpretation of the seismic facies suggest

that, rather than a typical Skagerrak, this graben most likely contains an expanded Heather section.

This non-reservoir feature splits the structure into the proven Acorn North discovery and an

unproven Acorn East lead (Figure 3).

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Figure 10 – Seismic facies interpretation at Acorn North showing the high amplitude non-reservoir facies in the graben area

between the Acorn North and Acorn East structures. Seismic data courtesy of CGG Multi Client.

Biostratigraphic data from 29/8a-3, although sparse, are sufficient to establish the upper part of the

Skagerrak section at Acorn North as Early Ladinian, indicating that the bulk of the penetrated section

is likely to comprise the Judy Sandstone Member. In the water-bearing basal part of the well Bunter

equivalent sandstones have been encountered. The Skagerrak reservoir at Acorn North Field is

interpreted from core and log data to have been deposited in a dryland setting within ephemeral to

intermittent streams with associated overbank splays and playa (Figure 11). In comparison with

producing Skagerrak fields to the north, the proportion of channel belt deposits is lower, upper bar

deposits are more heterolithic, and lower bar and channel thalweg deposits are finer grained. This

facies change is due to a more southerly, distal location within the Triassic depositional system and

results in the loss of a connected, higher permeability network that is critical in effectively draining

Triassic fluvial reservoirs. As a consequence the reservoir quality at Acorn North is relatively poor in

terms of both permeability and connectivity.

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Figure 11 – Geological facies in core from well 29/8a-3

History matching of the extended well test at 29/8a-6 confirmed the geological evaluation of a low

quality reservoir with relatively poor lateral and vertical connectivity. The well is located at the crest

of the field and was drilled with a 60° average deviation through the reservoir over approximately

600 ftAH. The well was perforated over the interval 13619-14239 ftAH and the test comprised a total

of nearly 10 producing days followed by a long 70 day shut-in period during which pressure build up

was measured. Analysis indicates a low productivity of 1-2 bbl/day/psi with a rapid flowing bottom

hole pressure decline from an initial 8300 psia to 5300 psia at the end of the flow period. Similarly,

oil production rates declined from an initial ca. 6000 bbl/day to ca. 5000 bbl/day after a total

production of only 52,000 bbl. At the end of the 70 day shut-in the pressure had still not returned to

the initial level with some 570 psi yet to recharge. Temperature log data shows that production did

not occur uniformly over the perforated interval but rather was confined to 3 main zones which

were found to be associated with the presence of the better quality channel sandstone facies (Figure

12). This facies represents only a small proportion of the reservoir (ca. 10%) so that the majority of

the reservoir was unproductive, at least over the time-scale of the well test.

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Figure 11 – Log plot of the 29/8a-3 well showing the flow units from the extended well test.

The analysis of the 29/8a-3 extended well test concludes that the well is directly connected to a

limited volume with slow feed from a larger, further away volume. This is consistent with the

geological interpretation of a relatively poor quality reservoir compared to analogues further north

(e.g. Heron Cluster fields) in which the channel deposits are fewer, smaller and lack the coarse

grained thalweg deposits resulting in a tortuous connectivity. Recovery factors from any production

wells are likely to be relatively low. Detailed static and reservoir simulation models were build for

Acorn North and although the discovery is estimated to contain some 89.9 MMbbl in place volumes

the evaluated recoverable resources total just 12.6 MMboe with a multi-well development required

based on the reservoir connectivity risk.

Beechnut East

Beechnut East is an HPHT oil accumulation within Fulmar reservoir discovered by well 29/9b-2. The

four subsequent appraisal wells, 29/9b-3, 29/9b-6, 29/9b-9 and 29/9b-9z, attest to the complexity of

the structure and the variability of the Fulmar in this area (Figure 12).

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Figure 12 – Fulmar depth map in the Beechnut area.

Regional seismic interpretation (Figures 4-7) shows that Beechnut East is located over a Zechstein

salt pillow complex adjacent to a major detachment. Structurally, the field is in an interpod setting

surrounded on all sides by Triassic pods so that the deposition/preservation of the Jurassic Fulmar in

the Beechnut area is limited to an area of only some 40 km2 bordered by Smithbank shales (Figure

12). Interpreted seismic sections showing these relationships are shown in Figure 13 (Beechnut East)

and Figure 14 (Beechnut West).

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Figure 13 – Interpreted south-north seismic section over the 29/9b-9 and 29/9b-2 wells at Beechnut East. Seismic data

courtesy of CGG Multi Client.

Figure 14 – Interpreted south-north seismic section over the 29/9b-3 well at Beechnut West. Seismic data courtesy of CGG

Multi Client.

The interpretation of the new seismic data shows that the Beechnut East structure is heavily faulted

and broken into numerous small blocks (Figures 12 and 13). The lack of Fulmar-to-Fulmar reservoir

juxtaposition across most of the faults suggests a high compartmentalisation risk. Pressure data from

the wells indicates that all the blocks are at different overpressures and interpretation confirms that

the faults are sealing. This is further supported by the distinct geochemical signatures of the oils

from each block. Three of the blocks contain proven hydrocarbons; a new and smaller Beechnut East

(29/9b-2), the tiny Beechnut B6 block (29/9b-6) and the downthrown Beechnut Graben (29/9b-9).

The Beechnut North block was appraised by the 29/9b-9z well which found oil shows in a mostly

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tight Fulmar section. The small Beechnut South Flank East and West blocks remain undrilled and,

given the observed compartmentalization, are classified as leads. The area contains three further

leads; the small 4-way dip closed Beechnut West and the Beechnut South and Southwest leads

which are assessed as very high risk due to a reliance on a stratigraphic trapping element. A

summary of the estimated resources in all blocks and leads is summarised in Table 3.

The upper Jurassic succession at Beechnut lies unconformably on the underlying, Middle Jurassic

Rattray Volcanics, which in turn rest variably on Zechstein halite, the Triassic Smith Bank or

Skagerrak formations. A type section based on the 29/9b-2 well is shown is Figure 13.

Figure 13 – General stratigraphic architecture of the Beechnut area based on well 29/9b-2.

A comprehensive suite of new biostratigraphic sampling of the Beechnut wells combined with

seismic quantitative interpretation has resulted in a revised Fulmar sedimentology in the Beechnut

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area. Unlike in many other areas, the Fulmar reservoir in Beechnut does not form a field-wide,

tabular sheet sandstone. Deposition is thought to have occurred as a shallow marine fringe around

former Kimmeridgian structural highs, with reservoir quality likely to be in part influenced by

available accommodation space on fault terraces, and preservation of those sands further

compromised by subsequent erosional truncation during Volgian extension. As a consequence, the

Fulmar at Beechnut is fragmented, discontinuous and of variable reservoir quality over relatively

short distances as confirmed by the well data (Figure 14).

Figure 14 – Well log correlation across the Beechnut area.

At Beechnut the Fulmar section can be informally subdivided into two distinct packages (Figure 13);

a lower package of generally fine grained, relatively clean sandstones (JU375) which is generally well

preserved as a basal sheet across basement and an upper package (JU425-475) which is more mud-

prone and truncated by the Volgian unconformity. Thickness variations in this interval are a

combination of both reduction through erosion and some apparent depositional thickening into

former depocentres. Reservoir quality also varies rapidly, even over the relatively small distances

between the appraisal wells. Reservoir quality sandstones in the JU425-475 section are found only

on the 29/9b-2 well in the Beechnut East block and rapidly shale out laterally. Although the generally

better quality JU 375 sandstones can be correlated between the 29/9b-6, 29/9b-2 and 29/9b-9 wells,

they are absent in the thick section at 29/9b-3 which comprises entirely siltstones and shales.

At Beechnut East, the combination of a poorer, discontinuous Fulmar reservoir with the structural

break up of accumulation into small blocks has resulted in a revision to much smaller discovered

volumes which do not support the possibility of discovering an economically viable development

(Table 3).

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Similarly, the Fulmar exploration leads in the licence (Figure 12) are now evaluated with smaller

volumes and higher risk. In particular the Beechnut West lead, which formed part of the licence

application assessment as a potential low risk extension of the Beechnut East discovery, is revealed

in the new seismic interpretation to comprise a very small, four-way closure up dip of the 29/9b-3

well which found no reservoir in the Jurassic section (Figure 14). The lead is estimated to contain

negligible volumes which no longer provides a viable appraisal well candidate. The remaining

undrilled potential in the licence is also considered to be immaterial (Table 3).

6. Further Technical Work Undertaken

In addition to the subsurface technical studies incorporating the newly obtained 3D seismic,

geochemical and biostratigraphical data which have provided the prospectivity update, the following

feasibility work was completed:

• Assessment of alternative host options following the demise of the Fram FPSO opportunity.

Development concepts investigated included a 10 km subsea tieback to the proposed Fram

manifold and a 43 km subsea tieback to the Shearwater Platform.

• Well studies including preliminary HPHT well designs and costs.

• Subsea studies including corrosion assessment, material selection and flow assurance

evaluations encompassing wax and asphaltene studies.

• Assessment of potential synergies with Puffin, although this option is significantly more

expensive due to additional requirements for higher specification pipeline materials and a

HIPPS system.

• Shearwater topside study based on analogues.

• Cost estimates for each of the development concepts for input into economic analyses.

This work enabled an assessment of the technical feasibility of a subsea development at Acorn and

Beechnut. For the option of a subsea tie-back to Fram, a carbon-steel with corrosion inhibition, pipe-

in-pipe solution was considered optimal. The completed wax study concluded that build-up is

anticipated to be moderate and can likely be controlled by wax inhibitor injection. The asphaltene

study confirmed that the oils are unstable with respect to asphaltene precipitation which would be

worsened by mixing with Fram condensates. Downhole injection of asphaltene inhibitor and

dispersant chemicals would likely be required for any development. A corrosion assessment found

that carbon steel would be a technically acceptable material. There would also be a requirement for

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a HIPPS system due to higher pressures than Fram. The Puffin subsea tie-back option would be

significantly more expensive than the Fram tie-back option due to the requirement for a CRA

pipeline due to high chloride levels at Puffin.

7. Resource and Risk Summary

A summary of the volumes and risks for all discoveries and exploration leads in the licence is shown

in Table 3.

Table 3 – Summary of resources within the licence.

8. Conclusions

This report details the relinquishment of the P.2038 licence following the completion of feasibility

assessments based on newly purchased 3D seismic datasets and integrated technical studies. The

evaluation has concluded that the resource is significantly lower than previously assessed and no

commercially viable development scenario can be generated. The remaining undrilled potential in

the licence is considered to be immaterial and therefore further drilling on the licence is not

considered to be in the interests of stakeholders.

Low Central High Low Central High

Acorn North D Triassic 8.0 11.8 16.4 3.1 4.5 6.3 100 12.6

Acorn South D Jurassic 1.2 2.5 4.9 0.8 1.7 3.3 100 2.8

Acorn East L Triassic 0.7 1.6 3.2 0.2 0.6 1.1 36 0.6

Acorn South West L Jurassic 0.4 1.2 3.2 0.3 0.8 2.2 18 0.2

Lynn North D Jurassic 0.6 1.6 4.0 0.4 1.1 2.7 100 1.8

Beechnut East D Jurassic 0.8 1.4 2.1 0.5 0.9 1.5 100 1.5

Beechnut B6 D Jurassic 0.0 0.0 0.0 0.0 0.0 0.0 100 0.0

Beechnut Graben D Jurassic 0.3 0.9 1.9 0.2 0.6 1.5 100 0.9

Beechnut Deep D Triassic/Jurassic 0.3 1.0 2.7 0.2 0.7 1.9 100 1.1

Beechnut West L Jurassic 0.0 0.1 0.3 0.0 0.1 0.2 21 0.0

Beechnut North Flank L Jurassic 0.1 0.7 2.1 0.1 0.5 1.5 26 0.2

Beechnut South Flank - East L Jurassic 0.1 0.1 0.2 0.0 0.1 0.2 65 0.1

Beechnut South Flank - West L Jurassic 0.1 0.2 0.4 0.0 0.1 0.3 65 0.1

Beechnut South L Jurassic 0.1 0.9 5.9 0.1 0.6 4.1 12 0.1

Beechnut South West L Jurassic 0.0 0.6 3.7 0.0 0.4 2.5 2 0.0

Resource and Risk Summary

Geological

Chance of

Success %

Risked

P50

MMboe

Prospect

Lead

Discovery

Name

P

L

D

Stratigraphic

level Oil MMbbls Gas BCF

Unrisked recoverable resources

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9. Clearance

Shell U.K. Limited confirms that the Department of Energy & Climate Change is free to publish the

contents of this report.