competent person's report: solan field solan final.pdfcompetent persons technical report: solan...

SENERGY (GB) LIMITEDBRETTENHAM HOUSE 6th FLOOR LANCASTER PLACE LONDON WC2E 7EN UNITED KINGDOM

T: +44 20 7438 4700 F: +44 20 7438 4701 E: [email protected] IN SCOTLAND SC 125513 REGISTERED OFFICE: 15 BON ACC ORD CRESCENT ABERDEEN AB11 6DE

Senergy (GB) Limited is also registered to OHSAS 18001

w w w . s e n e r g y w o r l d . c o m

SENERGY (GB) LIMITED

Senergy (GB) Limited is also registered to OHSAS 18001

w w w . s e n e r g y w o r l d . c o m

Competent Person's Report: Solan Field Conducted for

Chrysaor Updated by

Peter Aquilina, Barry Squire, Nigel Maclean, Matt Rothnie, Chris Priddis

Final

K14CHR036L

June 2014

Competent Persons Technical Report: Solan

www.senergyworld.com ii Final K14CHR036L June 2014

Senergy has made every effort to ensure that the interpretations, conclusions and recommendations presented herein are accurate and reliable in accordance with good industry practice and its own quality management procedures. Senergy does not, however, guarantee the correctness of any such interpretations and shall not be liable or responsible for any loss, costs, damages or expenses incurred or sustained by anyone resulting from any interpretation or recommendation made by any of its officers, agents or employees.

Authors

Peter Aquilina

Technical Audit

Barry Squire

Quality Audit

Jennifer Ives

Release to Client

Barry Squire

Date Released 20th June 2014 (Final Version)


www.senergyworld.com iii Final K14CHR036L June 2014

The Directors Chrysaor Limited Brettenham House, 4th Floor, Lancaster Place London WC2E 7EN

20th June 2014

Dear Sirs,

In accordance with your instructions Senergy (GB) Limited (Senergy) has reviewed the technical evaluation and the development plan prepared for the Solan field, located in Block 205/26a West of Shetlands on the UK Continental Shelf. The Solan Development was initially reported upon in the 2010 CPR (Reference 1) and revisited in 2013, together with Spanish Point and Phoenix (Reference 2). This work incorporates technical work undertaken in 2013 (essentially the results of two new wells) and updates that performed previously. Changes have not been made to the Triassic part of Solan as no new data is available.

Senergy was requested to provide an independent evaluation of the recoverable hydrocarbons expected for the asset, categorised in accordance with the 2007 Petroleum Resources Management System prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). An economic assessment was conducted and recoverable volumes are reported assuming standalone development and cessation of production once operating cash flows cease to be positive. The production rates associated with this cut-off correspond to approximately 1,000 bopd for Solan. These cut-offs are considered robust on first principles and by analogy with other fields with comparable developments.

Recoverable volumes are expressed as gross technical reserves or resources attributable. Gross reserves or resources are defined as the total estimated petroleum to be produced from the discoveries evaluated from 1st July 2014 (this is an arbitrary date prior to first hydrocarbons being produced).

In conducting this review, Senergy has utilised information supplied by Chrysaor, comprising basic engineering data and technical reports. We have reviewed the information provided and modified assumptions where we considered appropriate. Site visits were not considered necessary for the purposes of this report, other than a visit to the Bifab construction yard at Methil Fife, where the Topsides and Jacket are both in the final stage of construction. Senergy has not verified the entitlement of Chrysaor to the interests stated in this report as this is outside the remit of the evaluation.

Standard geological and engineering techniques accepted by the petroleum industry were used in estimating recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement; hence the recoverable volumes included in this evaluation are estimates only and should not be construed to be exact quantities. It should be recognised that such estimates of hydrocarbon recoverable volumes may increase or decrease in future if there are changes to the technical interpretation, economic criteria or


www.senergyworld.com iv Final K14CHR036L June 2014

regulatory requirements. As far as Senergy is aware there are no special factors that would affect the operation of the assets and which would require additional information for their proper appraisal.

The following Executive Summary contains tables giving Senergy’s estimates of the gross volumes attributable to the Solan asset.


www.senergyworld.com v Final

K14CHR036L June 2014

Executive Summary

Recoverable volumes associated with the Solan field are currently catagorised as reserves under development. The gross reserves and economic values are summarised in the following table:

Gross Reserves and Resources (MMboe)

Proved + Probable

2P 2C Best

Estimate

Reserves Contingent Resources

Prospective Resources

Assets

Solan Field 52.4

Solan Triassic

5.5

Total Hydrocarbons (MMboe) 52.4 5.5

Table E1: Gross Reserves and Resources for Solan Asset

Gross Economic Value (NPV10) in $MM

Assets Equity 1P 2P 3P

Reserves Reserves Reserves

Solan 100% 1,121.9 2,090.4 2,788.3

Total 1,121.9 2,090.4 2,788.3

Table E.2: Solan Field - Gross Economic Field Value at 10%


www.senergyworld.com vi Final K14CHR036L June 2014

Solan Area

Senergy was requested by Chrysaor to revise its previous review of the development plans and assessment of the reserves and resources attributable to Solan in the light of the results of the recent drilling campaign.

The Solan field is located West of Shetland on the UK Continental Shelf, some 35 km south of the Foinaven and Schiehallion fields, see Figure 1.1.

The original Field Development Plan (FDP) and Environmental Statement were both submitted to DECC in December 2009 but were reissued incorporating the revised platform development and associated cost estimates, and approved by DECC in April 2012 (Solan FDP – Premier Oil April 2012). The FDP is predicated on developing the field by drilling four horizontal wells, two producers and two injectors, tied-back to a new build facility comprising a storage tank and a steel jacket to support the process topsides. Oil export will be via shuttle tanker. It is intended that the facility will be Not Permanently Manned (NPM) after the first year of operation.

Development drilling and facilities installation were planned for 2013/2014 with first oil expected in the last quarter of 2014. The planned production wells require accurate placement within the reservoir but the appraisal/pilot wells, 205/26a-8z and -8y, drilled in 2009 along the line of the proposed primary producer, show that this is within the capabilities of modern geo-steering tools. The producers will be completed with dual ESPs. This is a complex completion which requires careful installation and operational practices but is not regarded as being of unduly high risk because the same approach has been implemented successfully in several fields in the North Sea. In deriving the recoverable volumes associated with the development of Solan, Senergy has accounted for a range of sub-surface uncertainties that require production performance for full quantification. Some of these uncertainties have been addressed by the drilling of the first two wells, the results of which have been incorporated into this report.

All values of hydrocarbon volumes and expenditures discussed in the text refer to 100% interest.

Reserves and associated production profiles were derived for Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) scenarios incorporating the wells and facilities defined in the operator’s plans.

Gross reserves attributable to the Solan Asset are summarised in the following table.

Gross Reserves and Economic Results for Solan Asset

Proved Proved plus Probable

Proved plus Probable plus

Possible Gross Reserves (MMstb) 36.6 52.4 68.9

Pre-Tax NPV10 ($MM) 1,121.9 2,090.4 2,788.3

Field cut-off Jul 2038 Jul 2043 Jul 2044

Table E3: Gross Reserves and NPV-Solan Asset


www.senergyworld.com vii Final K14CHR036L June 2014

Contingent Resources

Chrysaor has estimated potentially recoverable volumes from the Triassic reservoir penetrated and tested in well 205/26a-3. Senergy has reviewed the data supplied and concurs with the ranges tabulated below. Additional work has not been conducted on this reservoir since the previous report and the numbers remain unchanged.

Gross Contingent Resources 1C

MMstb 2C

MMstb 3C

MMstb Solan/Strathmore Triassic 2.3 5.5 12.7 Field cut-off Jan 2028 Jan 2036 Jan 2039

Table E4: Gross Contingent Resources for Solan Asset

Prospective Resources

Prospective resources are not addressed in this report.


www.senergyworld.com viii Final K14CHR036L June 2014

Professional Qualifications

Senergy (GB) Limited is a privately owned independent consulting company established in 1990, with offices in Aberdeen, London, Stavanger, Abu Dhabi, Perth and Kuala Lumpur. The company specialises in petroleum reservoir engineering, geology and geophysics and petroleum economics. All of these services are supplied under an accredited ISO9001 quality assurance system. Except for the provision of professional services on a fee basis, Senergy has no commercial arrangement with any person or company involved in the interests that are the subject of this report.

Dr Barry Squire is the Head of Resources Evaluation for Senergy in London, and was responsible for supervising this evaluation. He is a professional petroleum geologist with over 25 years of oil industry experience gained in major international companies and within Senergy, and has over 10 years experience in resources evaluation and auditing. He holds an Honours Degree in Geology and a Ph.D. in Sedimentary Geochemistry, and is a Fellow of the Geological Society and member of the Petroleum Exploration Society of Great Britain.

Yours faithfully,

Dr Barry James Squire

Head of Reserves and Asset Evaluation For and on behalf of Senergy


www.senergyworld.com ix Final K14CHR036L June 2014

Contents 1 Introduction .......................................................................................................................1

1.1.1 Licence Status ....................................................................................................3 1.1.2 Sub-surface Review ............................................................................................3 1.1.2.1 Geology and Petrophysics ............................................................................. 3 1.1.2.2 Structural and Seismic Interpretation ............................................................ 6 1.1.2.3 Depth Conversion and Petrel Stratigraphic Modelling ................................. 11 1.1.2.4 Hydrocarbon-Initially-in-Place Estimates ..................................................... 12 1.2 Reservoir Engineering ......................................................................................... 14 1.2.1 Reservoir Pressure and Fluid Properties ......................................................... 14 1.2.1.1 Recoverable Volumes and Profiles ............................................................. 22 1.2.1.2 Triassic Recovery ........................................................................................ 25

2 Field Development ........................................................................................................ 28 2.1 Facilities Overview ............................................................................................... 28 2.2 Facilities Contracting Arrangements .................................................................... 30 2.3 Facilities Schedule and Progress ........................................................................ 30 2.4 Transportation and Installation ............................................................................ 33 2.5 Subsea Construction ........................................................................................... 33 2.6 CapEx Costs ........................................................................................................ 35 2.7 OpEx Cost............................................................................................................ 37 2.8 Conclusions and Recommendations ................................................................... 38 2.8.1 CapEx .............................................................................................................. 38 2.8.2 OpEx ................................................................................................................ 38

3 Solan Field Economics .................................................................................................. 39 3.1.1 Economic Model Input Assumptions ............................................................... 39 3.1.2 Brent Oil Price Deck ........................................................................................ 39 3.1.3 Exchange Rate ................................................................................................ 39 3.1.4 Discount Rate .................................................................................................. 39 3.1.5 Tax and Fiscal ................................................................................................. 39 3.1.6 Solan Economic Results .................................................................................. 39 3.2 Sensitivity Analysis .............................................................................................. 39 3.2.1 Discount Rate .................................................................................................. 39 3.2.2 Oil Price ........................................................................................................... 40 3.2.3 CapEx .............................................................................................................. 40 3.2.4 OpEx ................................................................................................................ 40 3.3 Solan Area Prospectivity ...................................................................................... 40

4 References .................................................................................................................... 41 5 Nomenclature ................................................................................................................ 42


www.senergyworld.com x Final K14CHR036L June 2014

List of Tables

Table 1.1: Oil Initially In Place ................................................................................................. 14 Table 1.2: FWLs Associated with Low, Mid and High Dynamic Cases ................................... 16 Table 1.3: Solan Profiles ......................................................................................................... 24 Table 1.4: Gross Reserves at 100% Equity to Solan .............................................................. 25 Table 1.5: Contingent Resources 100% Gross ....................................................................... 27 Table 2-1 Solan Major Facilities Contracts and Suppliers....................................................... 30 Table 2-2 SOST, Jacket and Topsides Progress June 2014 .................................................. 31 Table 2-3 Solan CapEx June 2014 .......................................................................................... 36 Table 2-4 Solan OpEx June 2014 ........................................................................................... 37 Table 2-5 OpEx- Diesel ........................................................................................................... 37 Table 2-6 OpEx-Workovers ..................................................................................................... 37 Table 3.1: Attributable Reserves and NPV- Solan Asset ........................................................ 39 Table 3-2 Sensitivity- Discount Rate ....................................................................................... 40 Table 3-3 Sensitivity- Oil Price ................................................................................................ 40 Table 3-4 Sensitivity- CapEx ................................................................................................... 40 Table 3-5 Sensitivity- OpEx ..................................................................................................... 40

List of Figures

Figure 1.1a and b: Solan Location Map......................................................................................1 Figure 1.2a and b: Top Solan Depth Map With Appraisal Well Locations and Illustration of the Jurassic stratigraphic Correlation Scheme .................................................................................4 Figure 1.3: Solan Area Regional Overview ................................................................................7 Figure 1.4: Seismic Profile Across the Solan Field ....................................................................8 Figure 1.5: Relationship Between Total Jurassic Thickness and Solan Sand Thickness ..........9 Figure 1.6: Total Jurassic Thickness Map (TST) ........................................................................9 Figure 1.7: Jurassic Isochron Overlain by New Fault Interpretation ....................................... 11 Figure 1.8: Reservoir Pressure Measurements W1 Well ........................................................ 16 Figure 1.9: Reservoir Pressure Measurements ....................................................................... 17 Figure 1.10: Transmissibility Factors Vs Cumulative Production (generic illustration) ........... 18 Figure 1.11: Possible Compartment Polygons Used Previously ............................................. 18 Figure 1.12: Previously Planned Wellpaths ............................................................................. 19 Figure 1.13: Possible Compartment Polygons (Previous Interpretation) ................................ 20 Figure 1.14: Solan Horizontal Permeability Scaling ................................................................ 21 Figure 1.15: Solan Low Case Oil Production Profile (Yearly Average, bopd) ......................... 23 Figure 1.16: Solan Mid Case Oil Production Profile (Yearly Average, bopd) .......................... 23 Figure 1.17: Solan High Case Oil Production Profile (Yearly Average, bopd) ........................ 23 Figure 1.18: Solan Total Recoverable Oil Volumes ................................................................ 27 Figure 1.19: Solan Near Term 2P Oil Production Profile ......................................................... 27 Figure 2-1 Solan Facilities Layout ........................................................................................... 28 Figure 2-2 Solan Jacket Methil May 2014 ............................................................................... 32 Figure 2-3 Solan Topsides Methil May 2014 ........................................................................... 32


www.senergyworld.com 1 Final K14CHR036L June 2014

1 Introduction The Solan field is located approximately 150 km West of Shetland on the UK Continental Shelf, some 35 km south of the Foinaven and Schiehallion fields (Figures 1.1a and b) in Block 205/26a, Licence P164. The Licencees are Premier Oil UK Limited (Premier) (currently 60%) and Chrysaor Limited (Chrysaor) (currently 40%). The field lies at the south-western end of the East Solan basin in approximately 430 ft of water. See Figures 1.1a and b below.

Figure 1.1a and b: Solan Location Map



The Solan Sandstone reservoir is a good quality, turbiditic Jurassic sandstone within the Kimmeridge Clay Formation. Underlying the Solan Sandstone is a poorer quality Otter Bank Sandstone reservoir of Triassic age, consisting mainly of braided river deposits.

The Triassic oil accumulation was discovered by Amerada Hess in 1990 with exploration well 205/26a-3. Appraisal well 205/26a-4, drilled in 1991, encountered water in the Triassic but discovered the Solan oil accumulation in the overlying Jurassic. This vertical well tested dry oil at a stabilised rate of 2,070 bopd with natural lift and up to 8,346 bopd using an electrical submersible pump (ESP). A further appraisal well 205/26a-5 penetrated the Solan reservoir water leg and was sidetracked up-dip as 205/26a-5z into the oil column. The appraisal wells showed that both reservoir quality and oil quality deteriorate with depth over the total oil column height of some 800ft. (see Section 1.2.1). The 205/26a-6 well was drilled to the south-east but did not encounter Jurassic reservoir.

In 2008, Chrysaor drilled another appraisal well, 205/26a-7, and an up-dip sidetrack 205/26a-7z, in the north-west flank of the field. These were intended primarily to appraise the Solan reservoir and give a better understanding of the distribution of oil and reservoir properties. A second appraisal campaign was completed in 2009 with the 205/26a-8, -8z and -8y wells confirming reservoir continuity and quality along the western margin of the field. See Figure 1.2 for well locations (on Top Solan Depth Map). Additional information became available in 2013 during the first season of development drilling.

The Solan oil is undersaturated with properties that vary with depth; oil gravity varies from 23.8 to 27.5º API with a corresponding viscosity range of approximately 2.75 to 4.5 cP at reservoir conditions. The GOR is comparatively low, in the region of 120 to 130 scf/stb. Note that the dynamic model only represents a single, unvarying, fluid type. The errors introduced are not considered to be substantive.

The current Field Development Plan (FDP) was submitted to DECC in April 2012 (issued by the operator Premier)i and approved in April 2012. Modifications to the Environmental Statement were also accepted by DECC in April 2012. The FDP proposes a base case development of two horizontal producers and two horizontal injectors tied back sub-sea to a new build facility comprising a jacket supporting the topsides facilities connected to a storage tank on the sea bed. In an upside STOIIP case, a third horizontal producer may be desirable and facilities are designed for this eventuality. Oil export will be by a tethered hose stored on the sea bed to a dynamically positioned shuttle tanker. Any produced gas in excess of fuel requirements will be flared. After a 12 month trial period with manning, it is intended that the facility will be not be permanently manned. Access for periodic visits will be by helicopter.

Development drilling began during summer 2013 and will continue through summer 2014. Installation of the facilities is planned for summer 2014 with first oil scheduled for the last quarter of 2014 after offshore hook-up and commissioning.

At the time of writing this report, the top hole sections of all development wells had been batch drilled to their 13 3/8” shoes and the 12 ¼” sections of the water injection well W1 and Producer P1 had been drilled and successfully cased. Additionally the 12 ¼” section of the water injection well W2 had been drilled but has been temporarily abandoned after stuck pipe problems. See Figure 1.12. The dotted line shows the existing 12 ¼” well path for W1. Before becoming stuck, one pressure point was taken in well W2 in section “a”.



1.1.1 Licence Status

The Solan field is in Block 205/26a, Licence P164. Premier acquired 60% equity in 2011, with the remaining 40% share continuing to be held by Chrysaor. Under the terms of the acquisition, Premier became Operator on the basis of providing full development financing to Chrysaor. The loan and interest will be recovered from 60% of Chrysaor’s revenues (after transport costs but before Opex). Under the commercial terms of the sales agreement with Premier, Chrysaor have the option to buy back 10% working interest in the field for £1 once Premier’s IRR on Solan investments reaches 25%. Subject to necessary approvals, Operatorship will revert to Chrysaor at first oil.

The background to this CPR update is the mutually agreed wish of Premier and Chrysaor to convert this financing arrangement to a more conventional Capital Markets financing with appropriate modification of the buy-back arrangement. Ongoing commercial negotiations on the buy-back arrangement, if Premier are not to provide full length of life development financing, are likely to impact average life of field equity. For this reason, Chrysaor has requested that this technical update addresses gross field reserves and resources rather than assuming the life of field equity splits that would have been expected under the old commercial agreement to be replaced.

1.1.2 Sub-surface Review

1.1.2.1 Geology and Petrophysics

Field STOIIP has been modified since the previous CPRsii,iii in light of various studies and well results. In particular there have been changes to the Free Water Level (FWL). In the light of the recent well results it is thought that the field is less likely to be compartmentalised and field wide FWLs have been used in all cases. Although it has not been shown without doubt that the field is not compartmentalised, and some ambiguity remains in the data, it is considered by Senergy that the conclusion is warranted. A summary of the background follows (taken from previous Senergy CPRs (see references ii and iii).

Database

A review of the field by Senergy in early 2009 was based upon mapping carried out on a 3D survey acquired in 1993/1994 by Geco for Hess, covering 260 km2 at 12.5 x 12.5 m bin spacing. Subsequently, a BP/Arco 3D dataset of 1995 vintage covering 1,200 km2 and the entire East Solan Basin has become available. This dataset is of superior resolution, higher bandwidth and overall better quality than the earlier data and has helped to validate and improve the original interpretation and modelling of the field.

Seven key wells (Figure 1.2a) fall within the Solan field area of interest:-



Figure 1.2a and b: Top Solan Depth Map With Appraisal Well Locations and Illustration of the Jurassic stratigraphic Correlation Scheme

205/26a-3 Triassic reservoir discovery well did not encounter Solan Sandstone reservoir

205/26a-4 Solan field discovery well originally drilled as Triassic appraisal well

-8000

-8500

-8000

-8500

-9000

-9000

-9500

-8500

-8500

-8500

-8500

-9000

-80 0

0

-750

0

-8000

-750

0-8

000

205_26a-7z

205_26a-7

205_26a-5z

205_26a-5

205_26a-3

205_26a-4

205_26a-8205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8y

205_26a-8y

205_26a-8y

444800 445600 446400 447200 448000 448800 449600 450400

444800 445600 446400 447200 448000 448800 449600 450400X, [m]

6656

800

6657

600

6658

400

6659

200

6660

000

6660

800

66568006657600

66584006659200

66600006660800

Y, [

m]

444800 445600 446400 447200 448000 448800 449600 450400

444800 445600 446400 447200 448000 448800 449600 450400X, [m]

6656

800

6657

600

6658

400

6659

200

6660

000

6660

800

66568006657600

66584006659200

66600006660800

Y, [

m]

444800 445600 446400 447200 448000 448800 449600 450400

444800 445600 446400 447200 448000 448800 449600 450400X, [m]

6656

800

6657

600

6658

400

6659

200

6660

000

6660

800

66568006657600

66584006659200

66600006660800

Y, [

m]

444400 444800 445200 445600 446000 446400 446800 447200 447600 448000 448400 448800 449200 449600 450000 450400

444400 444800 445200 445600 446000 446400 446800 447200 447600 448000 448400 448800 449200 449600 450000 450400

6656

500

6657

000

6657

500

6658

000

6658

500

6659

000

6659

500

6660

000

6660

500

66565006657000

66575006658000

66585006659000

66595006660000

6660500

00.10.20.30.40.50.60.70.80.91

N/G

-9800-9700-9600-9500-9400-9300-9200-9100-9000-8900-8800-8700-8600-8500-8400-8300-8200-8100-8000-7900-7800-7700-7600-7500-7400-7300

DepthWell Penetrations shown at Top Solan

Top Solan Depth f t TVDSS

N 1km

Area of SolanAccumulation

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

Top JTU_1JTU Base

-40

-20

0

20

40

60

80

100

120

133

TST*1:198

0.00 250.00GR 1.95 2.95Density0.45 -0.15Neutron

140.00 40.00Sonic

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

JTU Base Top JTU_1

205_26a-7z [TST]

-40

-20

0

20

40

60

80

100

120

133

TST*1:198


140.00 40.00Sonic

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

JTU Base

Top JTU_1

205_26a-4 [TST]

-40

-20

0

20

40

60

80

100

120

133

TST*1:198


140.00 40.00Sonic

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

JTU Base Top JTU_1

205_26a-5z [TST]

-40

-20

0

20

40

60

80

100

120

133

TST*1:198


140.00 40.00Sonic

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

JTU Base

Top JTU_1

205_26a-5 [TST]

-40

-20

0

20

40

60

80

100

120

133

TST*1:198


140.00 40.00Sonic

Supra Solan Sh.

USS Top Unit 3

USS Top Unit 2

USS Top Unit 1

MSS Top Unit 2

LSS Top

LSM Top

JTU Base Top JTU_1

205_26a-7 [TST]



205/26a-5 Down-dip appraisal well drilled into the water leg

205/26-5z Up-dip sidetrack of 205/26a-5 well into oil leg

205/26a-6 Appraisal well to south-east that did not encounter Solan Sandstone reservoir

205/26a-7 Appraisal well to north-west into the oil leg

205/26a-7z Up-dip sidetrack of 205/26a-7 into the oil leg

205/26a-8z 6,000 ft horizontal appraisal well near the mapped western margin of the field, with planned penetrations of the full reservoir sequence at four separate points to confirm reservoir thickness and quality patterns; pilot well for first producer

205/26a-8y Geological sidetrack to confirm quality and thickness at the crest of the core area on the southern margin of the field

The reservoir was partially cored in 206/25a-4 and -5, completely cored in 206/25a-5z and practically so in 206/25a-7. Drill stem tests were conducted on 206/25a-4 and -5z.

Data from these wells formed the basis for Chrysaor’s correlation (Figure 1.2b) and property mapping.

Reservoir Description and Zonation

The Solan reservoir sands were deposited within the East Solan Basin, one of a number of ‘back basins’ situated between the West Shetland Platform and the Rona Ridge and Judd High. The back basins were likely initiated as half grabens during the early or middle Jurassic, with gravitational subsidence during the late Jurassic to early Cretaceous and major thermal subsidence in the Late Cretaceous.

The Solan Sandstone is present locally within the Kimmeridge Clay Formation. The sands are only encountered in the deeper areas of the East Solan Basin, although the encasing shales are present on the flanks of the basin. The Solan reservoir sands were deposited by mass flows that originated from the shelfal areas lying to the north-east, possibly on the Papa Ridge, and appear to have been deposited in a counter-slope environment where these flows were forced to decelerate.

Overall, the Solan Sands appear to onlap progressively over the basin with the uppermost units having the greatest areal extent. However, it is possible that the detailed distribution of the sands is more complex as deposition could have been influenced by minor topography on the sea bed at the time of deposition.

The Solan Sands are massive, generally homogenous and exhibit abundant de-watering structures with evidence of post-depositional remobilisation in some wells. The sands are quartzose to sub-arkosic in composition, with minor glauconite, detrital clays, plagioclase feldspar and kaolinite. The abundance of kaolinite increases with depth through the oil leg and into the aquifer suggesting that the earlier-charged part of the trap were protected from continuing diagenesis in the water leg.



A marked angular unconformity separates the Jurassic sequence from the underlying Triassic strata, and a thin transgressive sandstone, the Jurassic Transgressive Unit (JTU), was deposited on this erosional surface. This unit is not incorporated into the Solan simulation or current development plans as it is deemed to be too thin to be of consistently commercial reservoir quality. Furthermore it is blanketed by a relatively thick Lower Solan Mudstone (LSM).

Chrysaor has divided the Solan section into Upper (USS), Middle (MSS) and Lower (LSS) Units, with the first of these further sub-divided into three layers. The base of the Solan Sandstone reservoir is defined by the top of the LSM, which overlies the basal JTU. Figure 1.2b shows the Jurassic correlation scheme, and is flattened on the top USS3 pick.

Petrophysical Modelling

Data from the seven wells listed in Section 1.1.2.1 was used to populate the petrophysical model taking account of porosity (phi), net to gross (NTG) and water saturation (Sw). These parameters provided inputs for the volumetric calculations described in Section 1.1.2.4 below. While there is reasonable well coverage over much of the area, interpolation of the parameters was aided by the use of pseudo-wells in areas of sparse coverage.

These pseudo-wells were populated with porosity and permeability having a stratigraphic pattern consistent with that in drilled wells but modified for the difference in depth between the reference well and the pseudo-well. This approach provides control points for the interpolation of poroperm character with both stratigraphic position and overall depth. Parameter and consequently layer values are reasonable, and the methodology provides a sound geologically based model input rather than purely algorithm driven interpolation.

Implementation of the petrophysical modelling employed in the stochastic estimation of the Hydrocarbon-Initially-In-Place (HCIIP) is described in Section 1.1.2.4 below.

1.1.2.2 Structural and Seismic Interpretation

The East Solan Basin is a small sub-basin lying between the West Shetland Platform to the east and the Faroe-Shetland Basin to the west. The basin is bounded by the Lewisian-cored Rona Ridge to the north-west, the Triassic-cored Papa Ridge to the south-east, and the Schiehallion and Judd Transfer Zones north-east and south-west respectively (Figure 1.3).



Figure 1.3: Solan Area Regional Overview

At the Top Jurassic horizon, the basin is about 25 km long (from north-east to south-west) and 8 km at it’s widest. The basin is asymmetric, being broadly speaking a half-graben whose hinge lies along the Rona Ridge, with the trap-door opening to the south-east – with the maximum growth being along the bounding faults associated with the Papa Ridge.

The sedimentary fill is thickest to the north-east of the Solan field, and thins generally towards the south-west, where the basin is bounded by the structural offset known as the Judd Transfer Zone. A subtle structural saddle trending north-west to south-east just to the south-west of Solan is the feature that most likely limited deposition of the Upper Jurassic Solan Sands. The trap is a combination of structural and stratigraphic components; dip closure to the north-east, and reservoir pinch-out to the north-west, south-west and south-east.

The regional horizons interpreted for the study cover the area of interest and the surrounding area that may be important in delineation of upside potential.

Although a full suite of horizons has been picked over the dataset (Figure 1.4), the main horizons that influenced the interpretation of Solan are the Top and Base Jurassic, and the overlying Top Hidra Formation, as these are key to the depth conversion. Also the underlying Triassic markers (Top Otter Bank Sandstone and Top Griesbachian Shale) as these relate to tuning problems at the Base Jurassic horizon. These horizons have been interpreted primarily on the 1995 Arco 3D dataset over the field as this has higher resolution than the earlier Hess 3D.

EAST SOLAN BASIN

SOUTH SOLAN BASIN

Existing Chrysaor Licensed Acreage

10 km

Depth to Base Cretaceous Unconformity (ft TVDSS)

Solan Facilities

27th Licence Round Provisional Awards



Figure 1.4: Seismic Profile Across the Solan Field

The shape of the Top Solan Sandstone boundary is inferred as approximately equivalent to Base Jurassic on seismic scale, since the event has little or no seismic expression due to its small impedance contrast and relative thinness in comparison with seismic resolution. The various Solan Sandstone markers were created during structural modelling in Petrel using isochores from the Base Jurassic marker. The 205/26a-8z and -8y well penetrations have shown that the Solan Sand members lie more or less conformably with the Base Jurassic. The isochore method is explained in more detail in Section 1.1.2.3.

Given the lack of seismic expression of the top of the reservoir, other methods were investigated to provide information on the Solan Sand thickness and presence. Chrysaor has shown through well information that the correlation between the entire Solan Sandstone unit and the total Jurassic thickness exhibits a correlation coefficient of approximately 90% (Figure 1.5).

Area of Field

Base Cretaceous

Top Triassic

Top Hidra

Top Asgard

Calcarenite Unit

8z penetration:

Southern Horst

8y penetration:

Southern Graben

Core Area

Shetland Group



Figure 1.5: Relationship Between Total Jurassic Thickness and Solan Sand Thickness

Thus it is possible to infer the thickness of the Solan Sandstone Unit based on the time/depth thicknesses of the Jurassic package and create sand thickness maps. Similarly, within the separate Solan Sandstone packages, there are good correlations between the observed total thickness and the thickness of the individual sands. The inferred maximum extent of the Upper Solan Sand from mapping and well control is illustrated in Figure 1.6.

Figure 1.6: Total Jurassic Thickness Map (TST)

Analysis of the -8z and -8y results has allowed a more accurate interpretation of the faulting of the reservoir in that region. These wells were planned primarily to test the south-westerly

250

250250

250

250

250

250

250

250

250

250

250125

125

205_26a-7z

205_26a-7

205_26a-5z

205_26a-5

205_26a-3

205_26a-4

205_26a-8205_26a-8z

205_26a-8z205_26a-8z

205_26a-8z205_26a-8z

205_26a-8z

205_26a-8z

205_26a-8y

205_26a-8y

205_26a-6

205_26a-8y

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200X, [m]

6656

000

6657

000

6658

000

6659

000

6660

000

66560006657000

66580006659000

6660000Y

, [m

]

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200X, [m]

6656

000

6657

000

6658

000

6659

000

6660

000

66560006657000

66580006659000

6660000Y

, [m

]

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200

443200 444000 444800 445600 446400 447200 448000 448800 449600 450400 451200X, [m]

6656

000

6657

000

6658

000

6659

000

6660

000

66560006657000

66580006659000

6660000Y

, [m

]

443500 444000 444500 445000 445500 446000 446500 447000 447500 448000 448500 449000 449500 450000 450500 451000

443500 444000 444500 445000 445500 446000 446500 447000 447500 448000 448500 449000 449500 450000 450500 451000

6655

500

6656

000

6656

500

6657

000

6657

500

6658

000

6658

500

6659

000

6659

500

6660

000

6660

500

66555006656000

66565006657000

66575006658000

66585006659000

66595006660000

6660500

75100125150175200225250275300325350

TST



extent of the sand distribution but also removed much of the uncertainty in fault placement, particularly to the south of the -4 well. In addition, the -8z well proved a lack of sand in the previously named “Southern Horst”, which was viewed as potential upside to the field. The -8y borehole proved hydrocarbon bearing sands in the “Southern Graben”.

The Jurassic sequence isopach map has been used by Chrysaor as a key indicator of Solan Sand development, with the unit not expected to be present where the total Jurassic thickness is 175 ft or less and not expected to include net reservoir where it is below about 250 ft (Figures 1.5, 1.6). Where the Jurassic sequence is thicker, Solan Unit thickness is expected to increase proportionately, potentially exceeding 100 ft where the total sequence thickness is approximately 360 ft. The thicknesses of the overall Solan Sand units and subunits were modelled by co-kriging well data with total Jurassic thickness from seismic after correcting this for the small areas of Top Jurassic erosion at the crests of some fault blocks.

A large basement structure, trending north to south, may have some ultimate control on the depositional architecture of the Jurassic sequence. Figure 1.6 shows a base map of total Jurassic thickness. This shows thicker Jurassic to the east in the area of the Solan field. The Jurassic thins to the west, ultimately falling below the thickness where Solan Sand would be expected to have been deposited. Reservoir quality Solan Sand has not been found in any well penetration where the vertical thickness of the Jurassic section as a whole was less than 250 ft but is seen in the Solan area wherever this threshold is exceeded.

The north-western limit of the Jurassic sequence (and by inference the Solan Sand) is well defined owing to the sharp depositional boundary against the Rona Ridge. Likewise to the south-west and south, the gradual Jurassic pinch-out governs sand distribution. Limits on sand distribution and hydrocarbon charge have also been taken into account through using the 205/26a-3, -5, -6 and -8z penetrations (with the 26a-5 well providing a key data point in the water leg down-dip, and -8y providing an up-dip limit to the sand deposition).

Further confidence can be placed in the field delineation to the south-west through the recent re-interpretation of the key structural fabrics in the field, particularly through the combination of re-interpretation of the Arco 1995 dataset with the accurate x/y fault cut information from the -8, -8z and -8y boreholes. Furthermore, these wells provided information on erosion at the Top Jurassic (Base Cretaceous) at the leading edge of the main core field area. This erosional thinning has been taken into account during the Petrel modelling process so as not to unfairly thin the Solan Sand sequence in this area. Basement structure also appears to conform well to depositional “thicks” although this has not been explicitly incorporated in the current model.

In the model, post depositional faulting affects the upside potential for the field (e.g. to the south-west of the 205/26a-4 well in the Graben area) Figure 1.7. However, the effect of these faults may have led to overly conservative estimates of base case volumes by Chrysaor. Interpretation of the Arco 1995 and Hess PSDM data has resolved ambiguity from the original mapping, indicating that the Southern Graben section (proven by the -8y well) is not completely offset by faulting but displaces in a “trap-door” style. The “Graben” has little or no offset to the east, while in the west there is offset of up to 200 ft.



Figure 1.7: Jurassic Isochron Overlain by New Fault Interpretation

Structural dip over the core Solan area is towards the north-east at around 8 to 10º in the region between the 205/26a-4 and -5 wells. In contrast, the effect of the faulting style described above is to reduce dip angles to between 0 and 2º down to the east within the Southern Graben area proven by 205/26a-8y.

1.1.2.3 Depth Conversion and Petrel Stratigraphic Modelling

As discussed, Solan Sand thickness is highly dependent upon total Jurassic thickness. This makes the depth conversion of Top and Base Jurassic particularly important in the derivation of the Solan Sand sequence. The multi-layer depth conversion was created using the seismic time picks and depths from wells to create time-depth relationships. Top and Base Jurassic depth grids were created for input into the stratigraphic model in Petrel.

The seabed was depth converted using a constant velocity of 4,975 ft/sec. For subsequent layers, a pseudo interval velocity was created using seismic times from the interpretation, and depths from the well information. The overburden velocity (particularly in the Shetland Group) is extremely consistent, meaning that error from surface to Top Hidra (and down to reservoir level) is small. Top Hidra is used as a proxy for the division between Upper and Lower Cretaceous due to its unambiguous reflectivity signature, although in reality the stratigraphic boundary is at the base of the Hidra. A “lower Cretaceous” package is therefore demarcated by the Top Hidra – Top Jurassic.



Top Jurassic and Top Triassic have both been depth converted using the same pseudo-Vint method and these surfaces provide the Total Jurassic package within which the Solan Sandstone horizons have been created.

As there are no direct seismic picks for the various Solan Sand layers, they have been created through a three-stage process of isochore generation from the well information and multi-layer stacking of the resultant horizons:

1. First-order isochores and stacking for Top Upper Solan Sand and Base Lower Solan Mudstone

2. Second-order isochores and stacking to create both Top and Base Middle Solan Sands (thus creating 3 layers, Top, Middle and Lower)

3. Third Order isochores and stacking to create the intra-Sand layers

Use of the total Jurassic thickness as a guide to sand presence will incur a certain risk as the sand is not mapped directly. However, considering the evidence available including the correlation between Jurassic thickness and Solan Sand presence/thickness, the reasonable spread of well penetrations and the structural model, this risk should be well constrained.

Each of the depth surfaces was input into the Petrel model for volumetric calculation and upscaling to the dynamic model. Depth surfaces for the Top Asgard limestone and the Top Calcarenite Unit were also used as they provide additional information to help in understanding the structure, fault throw, and possible timing of fault movements, and are of use for future well planning, as the section through the Lower Cretaceous limestones is arguably the most problematic for drilling.

1.1.2.4 Hydrocarbon-Initially-in-Place Estimates

Volumetric estimates were made by Chrysaor in Petrel. The best technical estimate model from Petrel had a STOIIP of 140 MMstb, assuming a FWL of 8,750 ft tvdss. The depth of the FWL remains the largest of the uncertainties affecting volumes; STOIIP reduces to 110 MMstb with FWL at 8,600 ft tvdss, and increases to 179 MMstb at the deepest expected FWL of 8,900 ft tvdss consistent with the 205/26a-3 well ODT in the Triassic.

The Solan partnership made a series of estimates of STOIIP volumes as a basis for the FDP. The last set of STOIIP volumes included interpretations of FWL variations across the field and modest pore volume multipliers to reduce the STOIIP of potential compartments. Uncertainties in the individual elements used to describe variations in the Gross Rock Volume, net to gross and petrophysical parameters have been comprehensively and rigorously combined in this treatment.

Inputs to these analyses have been reviewed by Senergy and are described briefly below. The latest FWL estimates have also been reviewed and are considered robust. Where appropriate any variations in the latest update (post W2 and W1 wells) are mentioned.

Gross Rock Volume

Gross Rock Volume (GRV) is governed by the thickness of the Solan unit, its lateral extent, the depth structure and the field FWL.



The lateral extent of the reservoir was fixed at the most likely extent of Solan net sand predicted from the relationship developed between net sand thickness in appraisal wells and the true vertical thickness of the Total Jurassic (see Section 1.1.2.2 above). Reservoir quality Solan Sand is likely to be restricted to those parts of the basin where Total Jurassic thickness exceeds 250 ft tvt. Variation in the amount of sand was estimated stochastically by the average oil leg net to gross ratio and deterministically by truncation of the model in areas distant from well control and use of varying net to gross multipliers.

Estimates of GRV are subject to various uncertainties including seismic interpretation of the total Jurassic interval and, most significantly, depth of the FWL. The current best estimate for FWL based on MDT gradients is at 8,780 ft tvdss (Chrysaor P50 case) and extremes of interpretation give rise to a range from 8,670 (Chrysaor P90 case) to 8,865 ft tvdss (Chrysaor P10 case). For comparison, in the FDP models, maximum field FWL was set conservatively at 8,720 ft tvdss.

As discussed in Section 1.2.1 below, there is uncertainty regarding interpretation of pressure data and the consequent impact on compartmentalisation and position of the FWLs throughout the field, in particular in the area defined by the 205/26-7 well pressure data. The results from wells W1 and W2 have reduced the risk of reservoir compartmentalisation, although compartmentalisation cannot be completely ruled out.iv

Net to Gross Ratio

Variation in the average Solan Unit NTG ratio is fairly limited within the field ranging from 59% in the 205/26a-4 well (where both MSS and LSS are shaled out) through 72 to 75% in 205/26a-5z and -7z (where the MSS unit only is shaled out) to 94% in the basinal 205/26a-5 well and 100% in 205/26a-7 on the northern margin of the basin. The 205/26a-8z and -8y wells show that there is likely to be a zone around 500 m or so wide and 1 to 2 km2 in area in this western flank where NTG progressively declines from around 60 to 30% or less, just within the 250 ft total Jurassic thickness contour.

Field average NTG for the total Solan Sand interval has been estimated as 73% in the best technical estimate reservoir model and this is considered the most likely value for probabilistic analysis. A normal distribution does not adequately capture uncertainty in NTG and so the distribution was truncated at minimum value of 0.25 and a maximum value of 0.92 which had similar levels of probability.

Average Net Porosity

Average porosity in net pay varies relatively little between control wells in the core of the field declining predictably with depth from 27% in the thin crestal sands of 205/26a-4 well to around 23% down-dip in the 205/26a-5z well. Porosity deteriorates along the western pinch-out of the field where, during deposition, sand-depleted flows were arrested by the relief.

Average net sand porosity in the oil leg in the best technical estimate reservoir model is 21.6%, which reflects the impact of modelling both the decline in porosity towards the western margin of the field and the decline in porosity with depth.

Potential errors fall into two areas, namely where there is no core calibration and the possibility of variation away from well control entirely. For probabilistic volumetrics the



uncertainty in average reservoir porosity was taken as +/- 1.5% and a normal distribution was adopted, which is regarded as appropriate.

Although the Chysaor P50 case uses porosity and net to gross properties updated by Premier in September 2013, there is negligible difference to those from the FDP. When both models are initialised with a single FWL at 8,720 ft (now updated to 8,780), STOIIP values are within 0.05% of each other (102.63 – FDP vs 102.68 MMstb – Premier Sep13 prop update)

Formation Volume Factor

The Formation Volume Factor was modelled as a low range, normally distributed probability density function with a most likely value of 1.105. This value is based on good quality down-hole samples in the 205/26a-4 well near the crest of the structure and in 205/26a-7 some 250 ft down-dip. The P90 to P10 range of +/- 0.025 is based on potential variation due to experimental error and the impact of lower GOR further down-dip.

Oil Initially In-Place

Hydrocarbons-initially-in-place for the reservoir scenarios modelled dynamically (as provided to and agreed by Senergy) for the Solan field in this report are summarised as follows:

P90 (MMstb)

P50 (MMstb)

P10 (MMstb)

79.7 116.5 154.5 Table 1.1: Oil Initially In Place

The P50 number is below that in the Chrysaor best technical estimate reservoir model for the same FWL assumption. This reflects continued use of the same pore volume multipliers as the FDP model to account for the overall impact of uncertainties in reservoir thickness and properties away from well control.

1.2 Reservoir Engineering

1.2.1 Reservoir Pressure and Fluid Properties

The properties of the Solan oil vary with depth, oil gravity increases from 27.5º API in 205/26a-4 to 23.8º API in 205/26a-5z, with a corresponding increase in oil viscosity at reservoir conditions from 2.75 to 4.5 cp. The GOR is comparatively low with an average of 124 scf/bbl. PVT data obtained from 205/26a-7 were generally consistent with the data from 205/26a-4 though levels of some trace components like Vanadium and Nickel were intermediate to 205/26a-5z. This suggests that density and viscosity do not deteriorate gradually with depth but undergo a more rapid transition at some depth between the oil-down-to in 205/26a-7 and the oil-up-to in 205/26a-5z, probably in the region of 8,400 ft tvdss. This assumption is consistent with the intersection between the oil gradients through the 205/26a-4 and 205/26a-5z pressure data (after correcting the latter for the apparent depletion discussed below), which occurs just below the oil-down-to observed in 205/26a-7.

It is possible that this effect could also be caused by a lateral barrier created by a sealing fault or stratigraphic pinch-out between the up-dip and down-dip wells. However, the former is not consistent with the interpretation of the seismic data and the latter is not consistent with the most likely stratigraphic correlation or the normal pattern of mass-flow sand deposition expected in this basin.



Previous technical work on the field has speculated about the possible presence of a thin layer of high viscosity oil at the base of the column (somewhat misleadingly referred to as a “tar mat”), which might have occurred if the oil viscosity continued to increase exponentially with depth. However, the 12 ¼” section of the W1 development well drilled in 2013 down the reservoir from 8,500 ft tvdss in the oil leg down to 8,825 ft tvdss in the water leg found reservoir fluids remained mobile throughout, ruling out the presence of an impermeable “tar mat” on the northern side of the field. Moreover, previous sensitivity studies suggest that the effect of a thin high viscosity layer at the base of the oil column would only provide a “baffle” to initial pressure maintenance and would have little impact on ultimate recovery. The Solan dynamic model represents a single fluid only. It is considered that this does not substantively affect the results. Taken with the other modelling assumptions (compartmentalisation and water contact) it is possible that the reserves are very slightly overstated, although not by a significant amount. Taking the worst case scenario of each uncertainty would lead to an unduly pessimistic view of the reserves and so this has not been done.

In order to identify the fluid contact in the field, available data including but not limited to log data, pressure data and recent MDT data on drilled appraisal/development wells were reviewed thoroughly. Prior to the start of development drilling, reservoir pressures were only obtained from wells 205/26a-4, 205/26a-5, 205/26a-5z and 205/26a-7. Drill stem tests both with and without an ESP were conducted on well 205/26a-4. Well 205/26a-5z was also tested, approximately three months later.

The historical pressure data have been interpreted in several previous studies, which led to a number of different estimates of FWL. A definitive interpretation is not possible because of the small difference between the oil and water pressure gradients, the potential variation in oil gradient with depth or PVT properties, the widely differing depths of the Jurassic wells, the relatively poor quality of some of the pressure measurements and potential for depletion of the reservoir as a result of extended testing or recharged from the aquifer in the time since well test. As a result, pre-development pressure data do not demonstrate consistent fluid contact across the whole field, with additional contradictions on the log-calculated water saturations and fluids gradient from pressure data.

The interpretation adopted for the FDP was to assume a common FWL for most of the field but a much higher FWL in the 205/26a-7 area on the northern side of the field in the P90 and P50 cases. This hypothesis was tested during the drilling of the 12¼” section for the W1 injector well in 2013 (205/26a-7Y). W1 was drilled downdip within the Solan reservoir from 8,500 ft tvdss in the oil leg to 8,825 ft tvdss in the lower transition zone or upper water leg with multiple pressure measurements made prior to casing (Figure 1.8).



Figure 1.8: Reservoir Pressure Measurements W1 Well

The new data have allowed a refined interpretation of the oil-water contact in the northern part of the Solan field, together with additional data from the Solan in the other water injector W2. Senergy has reviewed results from these wells which are consistent and adopted the following field-wide FWLs.

Case FWL (ft TVDSS) STOIIP (MMstb)

P90 8670 79.70

P50 8780 116.50

P10 8865 154.50

Table 1.2: FWLs Associated with Low, Mid and High Dynamic Cases

There is no entirely satisfactory explanation for the pressure observations made. Having reviewed the various interpretations, Senergy notes that the apparent depletion observed at 205/26a-5z in 1992 immediately after the extended production test of the Upper Solan Sand in 205/26a-4 results in a material balance estimate of approximately 100 MMstb, which is consistent with the volumetric assessments for the Upper Solan Sand. However it also concurs that 205/26a-7 may lie in a slightly separate pressure compartment within the oil leg. Reviewing available data demonstrated the P50 estimate of FWL is consistent with pressure data and the P10 estimate of the hydrocarbons-in-place reflects a common FWL for the whole field, which assumes that the difference in pressures can be attributed to gauge errors. Considering pressure data from well 205/26a-7, the P90 estimate of FWL is at the depth of 8,670 ft tvdss is an acceptable interpretation of the FWL. Although it could be argued that it should be 20 ft shallower (Figures 1.8 and 1.9), this would have little impact on overall volumetrics v.



Figure 1.9: Reservoir Pressure Measurements

Dynamic Modelling

Chrysaor and Premier conducted extensive reservoir modelling studies as part of the preparation of the FDP for Solan, which built on work conducted over several years. In addition to the Jurassic reservoir, the work has also examined the potential of the Triassic reservoir that underlies it and extends westwards to 205/26a-3. This Triassic reservoir is not part of the Solan FDP but remains a potential upside for the development. Contingent resources are included in this report, lifted directly from previous Senergy reports.

A reservoir simulation model was constructed using the gridding and properties from the geo-cellular model. A “best technical estimate” base case model was constructed and used to conduct sensitivity analysis on key parameters. The final models chosen for the FDP had a number of changes incorporated, including additional barriers, isolation of the 205/26a-7 area with its own FWL, pore volume modifiers for the South Graben, exclusion of the minor STOIIP in the unappraised south-east area of the field, changes to the saturation tables, restriction of PVT properties to 205/26a-4, and well controls in line with the discussion on development wells in Section 1.2.3.2. Since then the following modifications to the model have been made by Chrysaorvi:-

• P10 case has no PV multipliers

• P90 (previously sealing) compartment boundaries were changed to baffles having a transmissibility factor of 0.01 (in effect fully open – see Figure 1.10 for a generic illustration of the effects of transmissibility on production (based on the Chrysaor P90 model and changing fault transmissibilities) and Figure 1.11 for the location of the compartments introduced into previous models).



Figure 1.10: Transmissibility Factors Vs Cumulative Production (generic illustration)

Figure 1.11: Possible Compartment Polygons Used Previously

• Options to perforate the heel of well P1EE and section “a” of W2abc, which would have mitigated any downside due to fault seal around possible pressure compartments considered at the time of the FDP, have been removed (see Figure 1.12 which highlights the zones now to be completed relative to the compartments considered possible at the time of the FDP in 2012). The decision to remove the mitigation options was based on a cost benefit analysis performed by the Operator, Premier, after collection of additional Solan pressure data in W1 and W2 during 2013. In line with Premier and Chrysaor, Senergy does not see any convincing evidence for compartmentalisation as was modelled previously, however the P90 case (compartmentalisation with minor baffling) has been accepted as one of a number of

10

15

20

25

30

35

40

45

0.000001 0.00001 0.0001 0.001 0.01 0.1 1

Cum

ulat

ive

Prod

uctio

n (M

Mst

b)

Fault / Baffle Transmissibility Factor

Transmissibility Factors Vs Cumulative Production



likely scenarios. Should compartmentalisation be evident after production starts, mitigation is still possible at a later date but would involve unplanned expense (a well)vii.

Figure 1.12: Previously Planned Wellpaths

• P90 and P50 a small compartment around well-7 was introduced and acts as a baffle, although Senergy see no firm evidence for the size or location of the compartment.

• P90, P50, P10 FWLs adjusted as shown in Table 1.1.

• P90, P50, P10 – downdip permeability reduction: A review of FDP modelled permeability compared to measured estimates from core and well test data and mobility data from formation pressure measurements confirmed that permeability was being over estimated in the model deeper than 8,300 ft tvdss. Correcting the modelled permeability from the dashed purple line to the solid as shown in Figure 1.14 improved the match of modelled permeability to actual dataviii.

• Relative permeability description remains unchanged from that of FDP for P50 and P90 cases. The FDP P10 case used a more optimistic relative permeability description with residual oil saturation of 0.15 instead of 0.2. However, current modelling uses the same relative permeability description in the P10 case as the P50 case.

• P90, P50, P10 - For the first year while the wells come onstream at different times reflecting different drilling/completion/tieback timing assumptions. The following constraints were changed from those applied in FDP

o P1 and P2 maximum liquid rate constraint of 15,000 b/d

o W1 and W2 maximum water injection rate constraint of 17,500 b/d

o Total maximum water injection rate constraint of 30,500 b/d until both producers come onstream



o From 1/10/15, prediction control reverts to voidage replacement and constraints revert to those used in the FDP prediction runs

o With the reduced downdip permeability, W1 injection potential is lower than in the FDP description resulting in potential for unequal injection if run on group control. An additional well level control (max water injection rate = 17,500 b/d) has therefore been introduced for W2 - throughout life of field - to ensure injection is distributed equally between the two injectors and sweep is optimised.

• In all cases modified VLP curves were used. These new VLP curves (generated by the Operator Premier based on the latest well designs) cause warnings within Eclipse as they need to be extrapolated. The results are not considered to be effected adversely but the curves should be modified to avoid extrapolation.

The FDP models were previously reviewed and no major concerns were identified but the following observations were made, which are still relevant.

• In the FDP P90 case, Area 5, or the South Graben (Figure 1.13) was eliminated from the volumetrics. This appears still to be the case. In the P50 case, the South Graben has been included, but with a greatly reduced pore volume (again as in the FDP). For all cases, a small part of the STOIIP mapped in Area 6 in the unappraised area of the field also remains excluded (as in the FDP model).

Figure 1.13: Possible Compartment Polygons (Previous Interpretation)



Figure 1.14: Solan Horizontal Permeability Scaling

• In the FDP P10 case, a common FWL was assumed for the whole field and the South Graben was included with no reduction in pore volumes. However, the modelled FDP P10 FWL was no deeper than the modelled FDP P50 case FWL over most of the field and substantially shallower than the deepest FWL that can be interpreted from RFT data. This anomalous conservatism has been corrected in the latest modelling following the new pressure data obtained in the W1 and W2 wells in 2013.

• The P90 and P50 FDP cases used a constant value of residual oil saturation of 20%, while the FDP P10 case used a residual oil saturation value of 15%. Irreducible water saturation varies within a narrow range, from 13 to 23% depending on porosity. The residual oil saturations are slightly below the Koederitz database for this range of irreducible water saturation but are in line with end point SCAL work on Solan core. The current reservoir models use the same residual oil value of 20% at all risk levels.

• The rock quality of the formation decreases into the aquifer and the depositional model predicts that the aquifer will be of limited extent. Because of this and the fact that a horizontal injector will be located immediately below the oil leg, the aquifer will not have a significant impact on the performance of the development wells.

• The base case development scenario includes two horizontal production wells and two horizontal injection wells. The P90, P50 and P10 FDP cases used the same number of development wells. In the extreme upside STOIIP scenarios, a third producer may be desirable to improve recovery from the south-eastern horn of the field and the facilities have been designed to cope with this contingency.

• The production well completions were modelled with ESPs located above the Calcarenite Member in the Lower Cretaceous, which is considered to be the best location to balance electrical power losses, pump efficiency and ease of placement.



1.2.1.1 Recoverable Volumes and Profiles

Compartmentalisation

In assessing the volumes that can be attributed to reserves, Senergy, in previous reports placed weight on the apparent pressure depletion observed during the appraisal of the field and the implication that there may be compartmentalisation in the oil leg. In the absence of further oil pressure data or oil saturation observations below 8,600 ft tvdss to confirm OWC in the northern of the field, it was felt prudent to adopt a more conservative assessment for reserves definition. However, following the results of wells W1 and W2, Chrysaor and Premier believe that the potential for major static compartmentalisation with a much higher OWC in the northern part of the field than the south is no longer realistic. Senergy do not see any convincing evidence for compartmentalisation, although the pressure data is still ambiguous (possibly complicated by changing fluid gradients with depth). See Figure 1.9.

Overall Senergy considers the data to be slightly ambiguous but with no firm basis for applying compartmentalisation within the model. The exception is potentially around the 7 well where MDT pressure measurements appear to suggest the well is in a different pressure regime than others in the field. However, there is no clear seismic evidence for the existence of a pressure barrier around this well.

As described earlier, the -7 well has been assumed to be a separate compartment with marginally different initial pressure to the rest of the field in the current Chrysaor modelling, and a slight amount of baffling has been applied to historical compartment polygons. Senergy see no firm evidence for any compartments or for their size or location.

1P, 2P and 3P Cases

In deriving the Proved reserves case, it was assumed that the connected volume in the core area of the field was defined by an interpretation of depletion constrained by the minimum oil volume estimated within the area defined by well control, i.e. very little compartmentalisation overall, however, the P90 model provided by Chrysaor was deemed suitable for use and the results from that model were used without modification.

Senergy’s Proved plus Probable case was based on the view that that the P50 model provided by Chrysaor was suitable for use without modification. This was based on a review of all the data made available and of the model itself.

The Proved plus Probable plus Possible case incorporates the upside STOIIP identified by the operator’s revised interpretation of the field and the assumption that there are no compartments. Proved plus Probable plus Possible reserves are stated using the base case development of two horizontal producers and two horizontal injectors. However, if development drilling finds a deeper FWL or successfully appraises the south-eastern segment, there is likely to be upside recovery if a third producer is drilled. Again, Senergy believes it is appropriate to use Chrysaor’s model (P10) without modification.

For all cases it was assumed that sufficient investment will be provided to maintain ESPs throughout field life. The associated production profiles (start dates: low - 15/01/14, mid -01/12/14 and high - 15/10/14 are given in Table 1.3 below and Figures 1.15 to 1.17.



Figure 1.15: Solan Low Case Oil Production Profile (Yearly Average, bopd)

Figure 1.16: Solan Mid Case Oil Production Profile (Yearly Average, bopd)

Figure 1.17: Solan High Case Oil Production Profile (Yearly Average, bopd)

-

5,000

10,000

15,000

20,000

25,000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

Solan 1P Profile

-

5,000

10,000

15,000

20,000

25,000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040

Solan 2P Profile

-

5,000

10,000

15,000

20,000

25,000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044

Solan 3P Profile



Table 1.3: Solan Profiles



The gross (100% equity) recoverable volumes attributed to the development of Solan are summarised below.

Gross Reserves stated at 100% Equity

Proved MMstb

Proved plus Probable MMstb

Proved plus Probable plus Possible MMstb

36.57 52.44 68.86

Table 1.4: Gross Reserves at 100% Equity to Solan

1.2.1.2 Triassic Recovery

As no new information has become available on the Triassic accumulation under Solan, this section remains unchanged from the previous CPR (Reference iii).

Evaluation of the Triassic reservoir is still at an early stage, but this represents potential upside for the Solan development. HCIIP has been modelled by Chrysaor using Crystal Ball with a range of 77 / 166 / 264 MMstb. Senergy has reviewed these estimates and they are reasonable, if slightly conservative. Approximately 60% of the HCIIP lies on 205/26a, with the remainder on Hurricane’s neighbouring Block 204/30. The key issue for recovery, however, is demonstrating productivity and to a lesser extent reservoir connectivity.

Triassic data are available from wells 204/30a-2, 204/30a-3, 205/26a-3, -4, -5 and -5z, -6, -7 and -7z, with 205/26a-3 and -4 above the FWL at approximately 8,900 ft tvdss. Triassic cores are from wells 204/30a-2, 205/26a-3 and -4. Core permeability ranges from less than 0.1 mD to several 100 mD, uncorrected for overburden which may be significant. Also permeability at reservoir conditions may be affected by clay minerals which can react with drilling mud.

Well 205/26a-3 was tested in the Triassic. After acid stimulation, the maximum rate with coiled tubing injection of nitrogen was 960 or 240 bopd without nitrogen assistance during DST1a, giving a PI of 0.4 bopd/psi. The initial estimate of permeability-thickness interpreted from DST1a was 2,030 mD-ft, with total thicknesses being applied to derive a permeability of just 7 mD. It is more likely that the flow during DST1a came from a few “sweet-spots”, with a higher permeability. Commercial rates from the Triassic are likely only to be achieved with artificial fracturing, horizontal drilling, or a combination of both. Connectivity of these higher permeability zones (beyond the fractured zone) will be crucial in long-term productivity and response to water-flooding.

A fracture model has been set up using derived stresses from 205/26a-3 log data, which has demonstrated an initial rate of 4,500 bopd may be achieved from an artificially-fractured vertical well. The associated PI is 1.8 bopd/psi, i.e. an increase of over four from the tested PI. The rates also assume the well can be drawn down by over 2,500 psi with no adverse consequences. Potential recovery of 3 MMstb is estimated over five years with no pressure support.

Current plans are to drill a sub-horizontal Triassic producer stimulated with several propped hydraulic fractures and carry out an EWT beginning two years after the start of Jurassic production. The location of this well would lie within the Field Determination Area for Solan, which is based on the outline of the Jurassic accumulation but is not limited by formation or depth. Full Field Development is subject to being verified by a successful EWT



demonstrating long term productivity, and is, therefore, classed as Contingent Resources, which should recognise a range of success of the fracture model. Following the test period, the well could remain on production at a low rate, or be incorporated into a Triassic development. In the former scenario, it is likely that the well would recover several MMstb in pure depletion even if no decision is made to progress to a larger full field development. Extended development of the Triassic reservoir will require agreement with the 204/30 partnership to the west.

Chrysaor has modelled full development of the Triassic based on three fractured producers plus one horizontal injector with a range of recovery from 8 / 20 / 38 MMstb or 5 / 13 / 24 MMstb attributable to 205/26a licencees, based on recovery factors of 8 / 12 / 18% of the entire Triassic structure. Recovery factors over 8% assume a successful water-flood. Full connectivity of the Triassic reservoir would, therefore, add another contingency. Water flooding the Triassic would require additional water injection facilities, or divert water injection from the Solan Jurassic field.

Senergy has reviewed the Crystal Ball estimate of full-field recovery factors, and endorses a range of depletion recovery factors of 3 / 5.5 / 8%. The maximum recovery factor for depletion is 8% based on supplied documents (8% given as the upside case in “ES vintage Trias 2Producer P10 Case 08_09_Triassic_SEN_7_16_rev15b” and “GRV and RE inputs to QL Strathmore Probabilistic Model”). The minimum depletion recovery factor of 3% was based on aquifer supported depletion together with low connectivity with the bulk of the Triassic STOIIP. This is in line with the latter supplied documents cited above. The mid case depletion recovery factor of 5.5% was chosen as mid-way between the low and high recovery factors. These recovery factors were applied deterministically to the low, mid and high STOIIP estimates of 77 / 100 / 159 attributable to 205/26a, being the total Triassic STOIIP estimates supplied by Chrysaor (reviewed against internal estimates) multiplied by 100% (no full field development so 205/26a only) to form the 1C case and 60% for the 2C and 3C cases.

Recovery factors for depletion were based on connectivity not having been established for the Triassic, and hence the ability to water-flood still being in doubt. Information about connectivity will be one of the benefits of carrying out an EWT. Waterflood recovery factors range from less than 10% to over 25%. The most likely recovery factor with waterflood has been assessed as 10%. The cost of water injection is likely to be high and the injectors would also need to be hydraulically fractured in order to increase injectivity, so no additional benefit due to cold water should be assumed. The injector well count would range from 1 for the 1C case to 3 for the 3C case. Triassic production would need to occur in the same time period as Jurassic production, and while the installed injection facilities are being fully utilised for the Jurassic. Additional water injection facilities would need to be added, and the platform weight limits would need to be verified. For these reasons, waterflood recovery factors are not the basis for Senergy’s Triassic resources.

Applying these depletion case recovery factors to the STOIIPs attributable to 205/26a licensees of 46 / 100 / 159 MMstb results in a contingent recovery of 2.3 / 5.5 / 12.7 MMstb attributable to 205/26a licensees.



Contingent Resources (Gross, 100%) Number of Producers 1 2 3

1C MMstb

2C MMstb

3C MMstb

EWT 2.3 3.0 5.0 Full-Field Development Attributable to 205/26a Licensees - Incremental 0 2.5 7.7

Total 2.3 5.5 12.7 Table 1.5: Contingent Resources 100% Gross

1.2.1.3 Jurassic / Triassic Combined Recoverable Volume and Profiles

Total combined gross recoverable volumes for the Solan Jurassic and Triassic are summarised in Figure 1.18 below.

Figure 1.18: Solan Total Recoverable Oil Volumes

Figure 1.19 shows the combined near term production profiles for the Solan Jurassic and Triassic Reservoirs.

Figure 1.19: Solan Near Term 2P Oil Production Profile

0

10

20

30

40

50

60

70

80

90

1P (+1C) 2P (+2C) 3P (+3C)

Tota

l Re

cove

rab

le V

olu

me

s (M

Mst

b)

Total Recoverable Volumes

Triassic Resources

Solan Reserves

0

5,000

10,000

15,000

20,000

25,000

2014 2015 2016 2019 2018 2019

Oil

Rat

e (

bo

pd

)

Solan Near Term 2P Oil Production Profile

Triassic Resources

Solan Reserves



2 Field Development

2.1 Facilities Overview

Figure 2-1 Solan Facilities Layout

The Solan field development was formally sanctioned by Chrysaor, Premier and DECC in April 2012, with First Oil currently targeted for 1st December 2014.

Solan is a subsea well development West of Shetland using two producer & injector pairs (four wells). The subsea wells will be tied back using subsea flowlines to the fixed Solan facilities consisting of a jacket structure complete with topsides facilities, subsea oil storage tank (SOST) and an oil offloading system. Shuttle tankers will be chartered as and when required to offload the SOST for onward transportation and sale of the Solan crude. The required offloading rate is ca. 240,000 bopd, the capacity of the SOST is 300,000 stb and the time to ramp up, offload and ramp down should take approximately 36 hours without any disconnection.

The jacket structure consists of a four leg design with bracing and stiffening necessary for the harsh West of Shetland environment where it will be installed. The jacket design has been completed by the same company (Mustang) who delivered the BP Clair jacket in the nearby area. The jacket incorporates connections for the risers, caissons and J-tubes, from the base of the jacket to the top of the deck stab-in points. The topsides facilities consist of well controls, separation, gas treatment to fuel gas quality, water (produced and sea) injection, utilities, and power generation for topsides and production well electrical submersible pumps (ESP). Power will be generated by dual-fuel turbines and a diesel generator. Initially the turbines will be fuelled by fuel gas taken from associated gas with any excess gas being flared. When the field becomes fuel-gas deficient the turbines will be fuelled by imported diesel. The topside facility includes a helideck as the primary access point and permanent accommodation for 30 with temporary accommodation for a further 10 personnel.

The production facility has been designed as a Not Permanently Manned Installation (NPMI). However, during the hook-up and commissioning phase, plus the first year of operation the



platform shall be permanently manned. Following this period, the installation will be unmanned and shall be operated remotely from an onshore control room in Dyce, Aberdeen by the Duty Holder contractor (Aker Solutions). The installation will always remain capable of operating as a manned installation and shall be for 7 to 10 days per month to enable routine maintenance and inspection tasks to be performed. The design of the topsides facilities has taken into account of the desire to become an NMPI with aspects such as material specifications being high to reduce the need for frequent inspection and later life fabric maintenance. Where critical topsides equipment is concerned, such as in power generation and cranes, the vendors selected to supply would be considered premium in many cases showing good operational consideration in the project from early stages. Early investment in materials and equipment is intended to pay dividends in operational life with increased availability and reduced maintenance.

The facilities have also been designed with the capability to add up to 1,000 tonnes of topsides load which will enable future third party business to be accommodated, or indeed, the tying back of any successful near field exploration success.

Under the terms of the Sale and Purchase Agreement between Chrysaor and Premier, Premier have assumed the role of Operator for the development and commissioning phase of Solan. Subject to certain conditions, operatorship will revert to Chrysaor within the first three months of operation. Throughout this period Aker Solutions remains the Duty Holder service provider and are responsible for all operations within the 500m zone of the operated facilities.



2.2 Facilities Contracting Arrangements

The main contracts for the design, fabrication, installation and commissioning of the Solan facilities have now been placed, each on the basis of competitive tendering. The key contracts in place are shown in the table below:

Contract Description Supplier Topsides Engineer Procure and Construction BiFab with ODE

Jacket Design Mustang Jacket Construction BiFab

SOST Design Atkins

SOST Construction Dubai Drydocks World

Integrated Control System Emerson Transportation & Installation of SOST, Jacket and

Topsides Heerema Marine

Contractors Offshore Tanker Loading System APL

Subsea Design Pegasus Subsea Controls RRC

24” Subsea Loading Pipeline Construct and Install Allseas Hook Up & Commissioning Aker Solutions Duty Holder and Operations Aker Solutions

Subsea Installation Bibby Offshore Flexible Flowlines Wellstream Subsea Umbilicals Oceaneering SOST Transport Cosco

Table 2-1 Solan Major Facilities Contracts and Suppliers

The only significant contract still to be officially awarded is that for the Shuttle Tanker. Senergy has been informed by Chrysaor that final stage negotiations for this are underway between Teekay Shipping and the Solan partnership.

2.3 Facilities Schedule and Progress

The overall Solan project schedule has been reviewed by the Solan project management team following several material events which have taken place. These include a delay on the jacket fabrication, a delay in the SOST fabrication, a delay in the topsides construction and the challenging 2013 drilling campaign. Schedule impact for a project of this size and complexity is not uncommon as extremely large scopes of work are executed on a global basis with harsh weather conditions such as is the case for Solan. Currently, the facilities project schedule's critical path is the fabrication and load-out of the jacket structure. Without the jacket, the heavy lifting contractor cannot install the topsides and the opportunity to install the SOST as a campaign is also lost. Additionally, as the jacket nears completion the contractual window for the heavy lift campaign is also starting to close during June and July 2014.

According to the figures from 20th June 2014, combining the overall progress for the three key components of the topsides, jacket and SOST was:



Planned Progress to Date Actual Progress to Date 99.0% 97.1%

Table 2-2 SOST, Jacket and Topsides Progress June 2014

Of the 97.1% actual progress this is made up of an average of the actual completion of the SOST at 99.9%, jacket at 96.0% and topsides at 96.2% showing all three aspects very close to target completion levels.

Slippage has been reported in all areas of fabrication for a variety of understood reasons. These issues were mainly around technical design aspects primarily in the SOST (acceptable for a new design) and productivity levels falling short of expectation at the BiFab construction facility in Scotland.

Atkins designed the subsea storage tank and provided an ongoing design service to support various changes throughout the construction in Dubai. The changes were influenced by aspects such as the seabed floor having obstructions and the increasing understanding of the sea conditions and subsequent loadings on the tank. The tank required a material increase in fabrication to deal with these issues and Atkins supported this throughout. The Dubai based construction contractor Dry Docks World (DDW) has completed the extra scope (albeit with delay). The original planned progress for the SOST was re-base-lined in mid-2013 following a greater understanding of the SOST complexity by the original designer (Atkins) which impacted the overall project progress as fabrication scope increased at DDW. The Bifab commercial arrangements were reviewed in late 2013 and in early 2014 the productivity levels increased to a sufficient level to show at least delivery of the critical path jacket assembly. Chrysaor and Premier are working with the fabricators DDW and BiFab with input from Atkins and ODE to ensure that any outstanding issues are suitably addressed and that all testing and certification is completed in time for the planned sail away dates of June 2014 for the SOST, mid July 2014 for the jacket and late July 2014 for the topsides.

The SOST, jacket and topsides appear to be reaching suitable levels of technical close out in all three cases. The technical support available to all three components is in place for the project to allow full concentration on the final scopes of work to enable the items to be installed. The jacket and SOST must be fully complete with no post yard scope and this appears to be on schedule. However, the topsides can have post yard scope and although not desirable it can be completed once on location with the necessary logistics in place.



Figure 2-2 Solan Jacket Methil May 2014

The Solan project team are making preparations for offshore topsides construction scope in anticipation that the topsides will leave the yard with outstanding unplanned construction scope. The main focus is to establish and prioritise the minimum system requirements to allow manpower to reside on the facility within UK Health and Safety at Work legislation up front of an approved Safety Case from the Health and Safety Executive. However, the Solan project team have looked to use the heavy lift facility in the short term and the ongoing drilling rig on the Solan location until October 2014 to provide a local hotel provision.

Figure 2-3 Solan Topsides Methil May 2014



2.4 Transportation and Installation

The single most significant milestone event in the facilities side of the Solan project appears to be the coming together of the SOST, topsides and jacket at the Solan location for the heavy lift facility to install in a single campaign. The jacket and topsides will depart from BiFab in Fife and the SOST will depart from Shetland. All transportation and lifting at the Solan location depends on suitable weather conditions (mainly a sea state less than 2 m significant wave height). It is not planned for the SOST, jacket or topside to leave their local locations until that is the case.

The SOST will be dry transported by Cosco from Dubai to Shetland where it will be floated and prepared for tow out. The jacket will be loaded out onto a barge and sea fasted by the heavy lift contractor (Heerema) along with the topsides and transported to the Solan location directly. The SOST will be submerged at the Solan location under a controlled lift by the heavy lift facility and the lift and installation of the jacket and topsides will follow respectively.

A contract with Heerema has been agreed where they will provide a window for the lifts to start, then as the window approaches, Heerema shall reduce the size of the window from an initial 5 weeks to 21 days to 15 days and finally a 7 day window. The date of the actual lifts starting shall be notified 7 days prior. At present there is a 7 day window in place with the earliest start being 20th July and the latest start being 27th July. The weather conditions on the Solan location would be considered favourable at this time of year and although West of Shetland is a fast changing weather location this timing offers a reasonably reduced risk of weather delay. Heerema are themselves likely to be open to weather delay by the previous lifting project before Solan which may provide some additional time for the jacket and topsides to be worked on but this should not be relied upon. However, the arrangements and relationship between Solan and Heerema appear pragmatic and the option to procure a lifting window extension is available if required.

2.5 Subsea Construction

The Solan subsea equipment would not be considered extensive therefore the time and resources to install them would not be considered exceptionally high. However, the potential weather conditions West of Shetland have proven challenging for this type of work in the past on other local projects. There are fundamentally two subsea construction campaigns with one in the June 2014 and the second in the autumn of 2014. The Solan project has mitigated the potential impact of weather delay by again (as in the heavy lift) choosing the most favourable time in the summer period to complete the bulk of the subsea scope with a single Dive Support Vessel (DSV). However, in the second autumn campaign the Solan project has contracted two DSV’s to maximise the working time in the weather windows available.

The 24” concrete coated flowline which runs from the platform to the offloading system has already been installed. This line will be cut at the location of the SOST to split this single lay of pipe into two distinct sections. The section from the platform to the SOST shall be the displacement water line while the remaining section from the SOST to the offloading system shall be the oil export line.

With the exception of the subsea umbilicals, all remaining subsea components are completed and ready for installation, including the subsea offloading system. The delivery of the umbilicals is expected in late August 2014. First oil will be dependent on this equipment being



both delivered and installed and represents a risk in terms of the weather window being available following delivery for both installation and commissioning. However, the umbilical at 450m is not of a significant size and a relatively small weather window is required to install and commission it. There will be post first oil subsea scope to accommodate the second production and injection wells in 2015 which has been allowed for in all areas of the CAPEX forecast.



2.6 CapEx Costs

The Solan project was sanctioned in 2012 with a budgeted CapEx of $856.9 MM. A number of supplementary AFE’s have been approved since 2012 increasing the approved budgeted forecast to $1,238.1 MM in May 2014. A recent reforecast in June 2014 indicates a total expected spend of $1.453 MM which has been proposed as a new budget. This figure also includes updated contingency amongst the spend categories but with no contingency currently remaining as a standalone line item.

The cost increases have been primarily driven by the issues around fabrication of the jacket, topsides and SOST with the interrelated transportation and installation charges which follow to accommodate the delays. The Bifab commercial arrangements for the jacket and topside module were renegotiated in late 2013 to a reimbursable contract to take control of the schedule slippage which has been effective in 2014. However, the Bifab renegotiation arrangement increased the forecasted costs for the jacket and topside module to meet the installation window which is both weather and commercially sensitive. Cost increase within the transportation and installation category has increased as an individual line item due to the Solan project procuring 14 additional days to accommodate any late completion of the Jacket and a further 15 days of weather allowance. This is in addition to a base case initially agreed of 19 days to install the SOST, Jacket and topsides. Additional days of Heerema time are in the order of $1m per day over and above the current arrangements.

Chrysaor have assessed the level of risk and weather allowances contained within these supplemental AFEs and estimates that potential weather delays during the subsea installation, being performed in September through to December, and the subsea tie-in of the second producer in 2015 may still not be adequately covered.

Senergy also reviewed the drilling data provided by Premier. The observations were as follows:

The Revised Premier Authorisation For Expenditure (AFE) in February 2014 was $335 MM, which included Value of Work Done (VOWD) of $202 MM. This meant that there was a total of $133 MM of expenditure required to complete the required drilling work scope.

This work scope was subject to the following points of interest:

• In 2014, the drilling performance so far in progress is running 15 days behind AFE (estimate $8.5 MM adjustment).

• A recent event (loss of W2 12-1/4” hole section) led to a non-productive time (NPT) event and will result in a time delay of circa 30 days for re-drilling. This event has led to an estimated cost overrun of ca. $16.5 MM adjustment.

• If current performance continues then an allowance for an additional 20% contingency on the cost to complete the project (20% of $133 MM = $26 MM)

Based on the above points, the forecast to complete the drilling program in the Solan field would be $386 MM.

See figure 2.3 below for the operator forecasts and the corresponding Senergy adjustments.



Item Total Proposed

Budget June 2014 (US$MM)

Senergy Adjustment (US$MM)

Total (US$MM)

Topsides 246.51 0.00 246.51 Jacket 181.91 0.20 182.11 Tank 112.25 0.00 112.25

Transportation & Installation 147.45 14.00 161.45 Hook-up & Commissioning 43.03 0.00 43.03

Subsea 146.64 5.00 151.64 Pre-ops 21.72 6.00 27.72

Project Management 92.35 5.00 97.35 Insurance 13.20 1.30 14.50

Drilling 448.11 (62.11) 386.00 Unallocated contingency 0.00 30.61 30.61

Total 1,453.17 0.00 1,453.17

Table 2-3 Solan CapEx June 2014



2.7 OpEx Cost

The OpEx fixed costs budget used by Chrysaor has been developed jointly by Chrysaor and Aker Solutions but is materially the same as the current Premier forecast is shown in the table below. It covers one month’s production in 2014, and is based on achieving NPMI status 12 months after First Oil. A full review of Operating costs is currently in progress by Premier for the 2015 budget submission.

Operating Costs per annum (in US$MM) 2014 2015 2016 2017 2018

Personnel 1.00 11.45 5.63 5.63 5.63

Materials 0.57 6.61 4.46 4.46 4.46 Services 0.78 9.06 5.82 5.82 5.82 Support 1.42 16.54 10.70 10.25 5.30 Head Office G&A 0.41 4.73 2.19 2.19 2.19 Insurance 0.33 3.90 2.8 2.8 2.8 Total 4.51 52.29 31.59 31.14 26.10

Table 2-4 Solan OpEx June 2014

Production related operating costs not included in the table above consist of diesel payments, CO2 emissions, and transportation.

Diesel is expected to be required towards the end of field life for power generation as the gas production declines. It is assumed that a generator would use 15 tonnes/day, with 1 generator running on diesel when the gas rate is less than 0.9 MMscf/d and 2 generators when gas rate is less than 0.4 MMscf/d. Diesel per tonne was assumed to be priced at a factor of 8.5 to oil price. CO2 emission cost was assumed at $10/tonne. See table below:

Item Value Unit GOR 124 scf/bbl 2 generators gas requirement 0.90 mmscfd 1 generator gas requirement 0.40 mmscfd Generator diesel usage 15 T/day/generator Diesel cost factor 8.5 Dump flood mode 19 from year

Table 2-5 OpEx- Diesel

Transportation costs via shuttle tankers are calculated at approximately $2.1/bbl.

One well workover to replace ESP’s is assumed every 2.5 years to end of field life on average (with the producers alternating). This continues until the remaining cashflow is insufficient to justify the workovers. See table below:

Item Value Unit Days 25.0 Days Rig Rate 280.0 $MM/day Spread Rate 169.9 £MM/Day Tangibles 1.2 T/day/generator Total 9.8 £MM/Day

Table 2-6 OpEx-Workovers



2.8 Conclusions and Recommendations

2.8.1 CapEx

There are no material value risks with respect to the overall budget present in the Solan project which have not been addressed in some way by the project management and the partners. However, factors such as weather delay West of Shetland, no contingency for offshore completion of the topsides once offshore using an accommodation barge and extended costs for the pre ops team stand out as the likely events which could add to the overall CapEx forecast.

The drilling budget and schedule from Premier is overly pessimistic and Senergy agrees with Chrysaor that it is more prudent to reallocate the additional sums against other line items and create an overall unallocated contingency for potential delays and cost overruns.

2.8.2 OpEx

The low Solan OpEx depends on up-front investment in the design to reduce breakdowns and integrity work in the operational phase and also a reliance on reaching NPMI status after one years of manned status. However it is possible that it may take longer until NPMI is reached and that the lower falling OpEx estimated thereafter may not be achieved.

Finally it should also be noted that the Forecast numbers are based on a GBP/USD rate of 1.6 and a EUR/USD rate of 1.24. Whilst FX fluctuations largely balanced over the early months of the project current exchange rates will now be putting further pressure on the cost estimates.



3 Solan Field Economics Senergy has calculated project pre- tax cash flows attributable to the whole Solan field, based on the revenue stream from petroleum production and deducting related operating and capital expenses. To this extent, Senergy reviewed the economic model provided by Chrysaor and made adjustments as it deemed necessary.

The resulting cashflows have been used to determine the Net Present Value (NPV) of the Reserves of the whole Solan Field as of 1st July 2014.

3.1.1 Economic Model Input Assumptions

3.1.2 Brent Oil Price Deck

The price of Brent has been taken as $100/bbl with no cost inflation.

These values have also had a discount applied of c.2.4% in the expectation that Solan crude will trade at a small discount to Brent.

3.1.3 Exchange Rate This has been taken as a 1.6USD:1GBP.

3.1.4 Discount Rate This has been taken as 10% in line with PRMS standards.

3.1.5 Tax and Fiscal For the sake of this CPR, the economic calculations have been done pre-tax to give a representation of the Solan Field as a whole, excluding any company specific tax arrangements.

3.1.6 Solan Economic Results

The outcomes of the analysis, using the economic model and inputs as described above are provided in the table below. The NPV is calculated as of July 2014.

Solan Field 1P 2P 3P Attributable Reserves (MMstb) 36.57 52.44 68.86 Pre-Tax NPV10 ($MM) 1,121.9 2,090.4 2,788.3 Field cut-off Jul 2038 Jul 2043 Jul 2044

Table 3.1: Attributable Reserves and NPV- Solan Asset

3.2 Sensitivity Analysis

Sensitivity analysis was done with respect to the oil price, capex and opex.

3.2.1 Discount Rate

The variation of discount rate was varied between 8% and 12% producing the following NPV for the 2P case:



8% 10% 12% Pre-Tax NPV10 ($MM) 2,260.9 2,090.4 1,938.2

Table 3-2 Sensitivity- Discount Rate

3.2.2 Oil Price

The Variation of Oil Price by +/-10%producing the following NPV for the 2P case:

$90/bbl $100/bbl $110/bbl Pre-Tax NPV10 ($MM) 1,787.8 2,090.4 2,392.1

Table 3-3 Sensitivity- Oil Price

3.2.3 CapEx

The Variation of CapEx by +/-20%producing the following NPV for the 2P case:

+20% 2P case -20% Pre-Tax NPV10 ($MM) 1,882.1 2,090.4 2,298.7

Table 3-4 Sensitivity- CapEx

3.2.4 OpEx

The Variation of OpEx by +/-20%producing the following NPV for the 2P case:

+20% 2P case -20% Pre-Tax NPV10 ($MM) 2,033.5 2,090.4 2,136,3

Table 3-5 Sensitivity- OpEx

3.3 Solan Area Prospectivity

Blocks 205/26c and 205/27 were awarded to Chrysaor (100%) in the UK 27th Round under a Traditional Licence. The blocks lie in the East Solan Basin, northeast of the Solan field (Figure 1.14). Chrysaor has identified two Jurassic prospects and one Triassic prospect which represent potential tie-back candidates to Solan.

Chrysaor were also awarded Blocks 202/4, 202/5 and 203/1 (part) in the 27th Round on a 100% basis under a 6-year Frontier Licence. The blocks cover the whole of the South Solan Basin, immediately south and southeast of Solan. Chrysaor has identified a number of Cretaceous, Jurassic and Triassic leads on the existing 2D seismic data.

Please refer to the previous CPR for further details of any prospectivity in the area.



4 References i “Solan Field Development Plan” – Premier Oil April 2012 ii “Solan CPR” – Senergy 2010 iii Solan, Spanish Point, Phoenix and Adjacent Exploration Acreage CPR” – Senergy 2013 iv “Slides 15Jan14 Rev1.ppt” Premier presentation slides January 2014 v 2Interpretation of LWD Density Images from 205/26a-7Y(W1y)” – Lind Energy Services August 2011 vi “Solan Jurassic Dynamic Model Update April 2014 – Changes Compared with FDP Model” – Chrysaor technical

note to Senergy vii “Solan Subsurface and Wells SCM 6Feb14 latest.pdf” Premier presentation 2104 viii “‘Update of Solan Permeability Modelling 2014_RP170214.pdf” – Chrysaor 2014



5 Nomenclature

Variable Meaning Units

AAPG American Association of Petroleum Geologists API American Petroleum Institute bbls/d Barrels per day bopd Barrels of oil per day cp Centipoise CO2 Carbon dioxide CPI Computer-processed interpretation DST Drill stem test ESP Electrical submersible pump º F / º C Degrees Fahrenheit / Centigrade FDP Field Development Plan ftss Feet subsea FWL Free water level GOR Gas Oil Ratio GRV Gross Rock Volume GWC Gas-water contact HCIIP Hydrocarbon-Initially-In-Place JTU Jurassic Transgressive Unit LSM Lower Solan Mudstone LSS Lower Solan Sand MD Measured depth ft or m mD Millidarcies MDRKB Measured depth rotary Kelly Bushing ft or m MDT Moduler Dynamic Tester MDBRT Measured depth below rotary table ft or m MMscf/d Million standard cubic feet per day MMstb Million Stock Tank Barrels MSS Middle Solan Sand NPM Not Permanently Manned NTG Net to Gross OBM Oil based mud ODT Oil down to OWC Oil water contact phi Porosity ppg pounds per gallon PVT Pressure volume temperature RFT Repeat formation tester Scf SOST

Standard cubic foot Subsea Oil Storage Tank

SCAL Special core analysis SPE Society of Petroleum Engineers



SPEE Society of Petroleum Evaluation Engineers stb/d Stock tank barrels per day STOIIP Stock tank oil initially in place Sw Water saturation ratio TD Total depth ft or m TVDBRT True vertical depth below rotary table ft or m tvdss True vertical depth sub sea ft or m tvt True vertical Time USS Upper Solan Sand WPC World Petroleum Council

competent person's report: solan field solan final.pdfcompetent persons technical report: solan...

Documents