UKCS-23rd-round-Anergy_text

Anergy Ltd – Application 23rd Offshore Round UKCS

23rd Concession Round Page 1 of 75 Geological and Technological Evaluation

23rd Offshore Concession Round UKCS

JUNE 2005



List of content 1 EXECUTIVE SUMMARY........................................................................................................................ 7

1.1 GENERAL INFORMATION ................................................................................................................... 7 1.2 BLOCKS APPLIED FOR........................................................................................................................ 8 1.3 BLOCK SUMMARIES........................................................................................................................... 8

1.3.1 211/19b and 211/24c ..........................................................................................8 1.3.2 Block 211/11B ................................................................................................12

1.4 WORK PROGRAMME FRAMEWORK ................................................................................................... 14 1.5 COMMENTS TO APPLICATION .......................................................................................................... 14

1.5.1 Blocks 211/19b and 211/24c.......................................................................14 1.5.2 Block 211/11b .................................................................................................15

2 INTRODUCTION................................................................................................................................... 16 2.1 REPORT ORGANISATION .................................................................................................................. 16 2.2 WORK PROCESSES AND METHODOLOGY........................................................................................... 16

2.2.1 Data Management .........................................................................................16 2.2.2 Software ..........................................................................................................17 2.2.3 Development scenarios ................................................................................17

3 EVALUATION OF BLOCKS 211/19b and 211/24c ............................................................................... 18 3.1 REGIONAL GEOLOGICAL OF NORTHERN TAMPEN SPUR PROVINCE .................................................... 18

3.1.1 Tectonostratigraphic development ..............................................................18 3.1.2 Exploration opportunities ..............................................................................20

3.2 DATABASE...................................................................................................................................... 21 3.2.1 Seismic data ...................................................................................................21 3.2.2 Well data..........................................................................................................22

3.3 PETROLEUM GEOLOGICAL ANALYSIS ............................................................................................... 22 3.3.1 Well ties and seismic interpretation ............................................................22 3.3.2 Depth conversion ...........................................................................................24 3.3.3 Attribute mapping ...........................................................................................25 3.3.4 Structural and stratigraphic framework.......................................................26

3.4 IDENTIFIED EXPLORATION OPPORTUNITIES....................................................................................... 28 3.4.1 Introduction .....................................................................................................28 3.4.2 Prospect Aladdin ............................................................................................30 3.4.3 Lead Ali ............................................................................................................33 3.4.4 Prospect Jasmine ..........................................................................................34 3.4.5 Leads Lago, Lago South and Abu...............................................................37 3.4.6 Leads Jafar and Sultan .................................................................................39 3.4.7 Lead Genie......................................................................................................41

3.5 TIME CRITICAL DEVELOPMENT OF RESOURCES IN 211/19B AND 24C BLOCK AREA............................. 42 3.5.1 Introduction .....................................................................................................42 3.5.2 Pressure development in Tampen Spur.....................................................42 3.5.3 Consequence of Statfjord Field pressure depletion .................................45 3.5.4 Summary .........................................................................................................46

3.6 RESERVOIR TECHNOLOGY ............................................................................................................... 46 3.7 TECHNOLOGICAL ASSUMPTIONS ...................................................................................................... 48 3.8 PLAN FOR EXPLORATION ................................................................................................................. 50

4 EVALUATION OF BLOCK 211/11B..................................................................................................... 51 4.1.1 Exploration opportunities ..............................................................................52

4.2 DATABASE...................................................................................................................................... 52 4.2.1 Seismic data ...................................................................................................52



4.2.2 Well data..........................................................................................................52 4.3 IDENTIFIED EXPLORATION OPPORTUNITIES..................................................................................... 54 4.4 RESERVOIR TECHNOLOGY AND TECHNOLOGICAL ASSUMPTIONS .................................................... 72 4.5 PLAN FOR EXPLORATION ................................................................................................................ 72

5 REFERENCES........................................................................................................................................ 73



List of Figures Figure 1.3-1 Prospect and leads in block 211/24c Figure 1.3-2 Prospect and leads in block 211/19b Figure 1.3-3 Prospect and leads in blocks 211/11b Figure 3.1-1 Location and Tectonic Elements Map, Block 211/24c Figure 3.1-2 General Stratigraphy of the Northern Viking Graben Figure 3.1-3 Middle Jurassic Palaeogeography, North Sea Figure 3.1-4 Early Late Jurassic Palaeogeography, North Sea Figure 3.1-5 Lithostratigraphy Upper Jurassic Sequence Figure 3.1-6 J40 Palaeogeography, Northern North Sea Figure 3.1-7 J50 Palaeogeography, Northern North Sea Figure 3.1-8 J60 Palaeogeography, Northern North Sea Figure 3.1-9 Geological Cross Section Northern North Sea Figure 3.1-10 Lithostratigraphy North Sea Figure 3.1-11 Borg Field Location map Figure 3.1-12 Borg Field - Seismic line Upper Jurassic section Figure 3.1-13 Borg Field - Seismic line Upper Jurassic section Figure 3.1-14 Borg Field - Sand distribution Figure 3.1-15 Borg Field - Paleogeographic setting Figure 3.1-16 Lithostratigraphy - Lower Cretaceous Figure 3.2-1 Seismic database, Block 211/24c Figure 3.2-2 Well database, Block 211/24c Figure 3.3-1 Synthetic Well Tie – Well 33/9-14 Figure 3.3-2 Synthetic Well Tie – Well 33/9-15 Figure 3.3-3 Synthetic Well Tie – Well 33/9-16 Figure 3.3-4 Top Lower Cretaceous Wedge, Time Structure Map, Block 211/24c Figure 3.3-5 Lower Cretaceous, Time Structure Map, Block 211/24c Figure 3.3-6 Lower Cretaceous, Isopach Map, Block 211/24c Figure 3,3-7 Lower Cretaceous Wedge, Isopach Map, Block 211/24c Figure 3.3-8 Base Cretaceous Unconformity, Time Structure Map, Block 211/24c Figure 3.3-9 Intra Kimmeridgian Fm Unit 2, Time Structure Map, Block 211/24c Figure 3.3-10 Intra Kimmeridgian Fm Unit 2, Depth Structure Map, Block 211/24c Figure 3.3-11 Intra Kimmeridgian Fm Unit 2, Isopach Map, Block 211/24c Figure 3.3-12 Intra Kimmeridgian Fm Unit 1, Time Structure Map, Block 211/24c Figure 3.3-13 Intra Kimmeridgian Fm Unit 1, Isopach Map, Block 211/24c Figure 3.3-14 Top Brent Group, Time Structure Map, Block 211/24c Figure 3.3-15 Top Brent Group, Depth Structure Map, Block 211/24c Figure 3.3-16 BCU level, Amplitude extraction 20 msec TWT below BCU Figure 3.3-17 Amplitude interval BCU to 55 msec below BCU Figure 3.3-18 Seismic line illustrating interval performed amplitude extraction on Figure 3.3-19 Amplitude extraction of BCU + 15 msec TWT



Figure 3.4-1 Prospect Jasmine, Seismic section Figure 3.4-2 Prospect Jasmine, Top Brent Gp Depth Structure Map Figure 3.4-3 Prospect Jasmine, Geoseismic section Figure 3.4-4 Leads Lago and Lago South, Seismic section Figure 3.4-5 Leads Lago and Lago South, Top Brent Depth Structure Map Figure 3.4-6 Leads Lago and Lago South, Geoseismic section Figure 3.4-7 Lead Abu, Seismic Section Figure 3.4-8 Lead Abu, Top Brent Gp Time Structure Map Figure 3.4-9 Lead Abu, Top Brent Gp Time Structure Map Figure 3.4-10 Prospect Aladdin, Seismic section Figure 3.4-11 Prospect Aladdin, Seismic section Figure 3.4-12 Prospect Aladdin, Top Intra Kimmeridge Fm sst unit Time Structure Map Figure 3.4-13 Prospect Aladdin, Top Intra Kimmeridge Fm sst unit Depth Structure Map Figure 3.4-14 Prospect Aladdin, Intra Kimmeridge Fm sst unit Isopach Map Figure 3.4-15 Prospect Aladdin, Attribute Map, 15 msec twt below BCU Arithmetic Amplitude Figure 3.4-16 Prospect Aladdin, Geoseismic section Figure 3.4-17 Seismic Well Correlation - wells 33/9-15 and 16 Figure 3.4-18 Well Log Correlation - wells 33/9-15 and 16 Figure 3.4-19 Lead Jafar, Seismic section Figure 3.4-20 Lead Jafar, Top Lower Cretaceous Wedge Unit Time Structure Map Figure 3.4-21 Lead Jafar, Lower Cretaceous Sandstone Unit Isopach Map Figure 3.4-22 Lead Jafar, Geoseismic section Figure 3.4-23 Lead Jafar, Attribute RMS interval Lower Cretaceous Wedge Figure 3.4-24 Lead Sultan, Seismic section Figure 3.4-25 Lead Sultan, Top Lower Cretaceous Wedge Unit Time Structure Map Figure 3.4-26 Lead Sultan, Lower Cretaceous Sandstone Unit Isopach Map Figure 3.4-27 Lead Genie, Seismic section



List of Tables Table 1.2-1 Blocks applied for Table 1.3-1 Block summary 211/19b and 211/24c Table 1.3-2 Block summary 211/11b Table 3.2-1 Seismic database Table 3.2-2 Well database Table 3.3-1 Seismic markers and maps generated Table 3.4-1 Prospect summary Aladdin Table 3.4-2 Prospect summary Ali Table 3.4-3 Prospect summary Jasmine Table 3.4-4 Prospect summary Lago and Lago South Table 3.4-5 Prospect summary Abu Table 3.4-6 Prospect summary Jafar Table 3.4-7 Prospect summary Sultan Table 3.4-8 Prospect summary Genie Appendixes A Application form for Production License - Petroleum Act 1998 B Upper Jurassic Sandstone Evaluation Study C Pilot study Inversion D Analogue study UKCS E Fault seal analogue study F Company related matters G Anergy Ltd – a Company presentation



1 EXECUTIVE SUMMARY

1.1 General information Anergy was created in mid 2005 as an independent exploration company with the

focus on finding and developing new sources of energy in the North Sea.

The current business of the company is oil and gas exploration, appraisal and production and is primarily focused on the UK and Norwegian Offshore North Sea.

The directors are strong believers that small, Independent companies have a vital role to play in E&P in mature to semi-mature basins worldwide. Furthermore these companies might readily demonstrate materiality and profit where larger companies fail. Dedication, imagination, belief and commitment are important pre-requisites of the Anergy Ltd ethos. The ability to identify opportunities and to move quickly, plus the flexibility of small company mentality and relatively low overheads are also the key to our future growth.

The company puts effort into the strategy of structuring our business to be sustainable for future growth and performance in such environments. Anergy Ltd. is now established with a clear strategy, visionary management to grow and become an enduring participant committed to the upstream oil industry. Administrative Manager Stig-Arne Kristoffersen will serve as liaison to the DTI for the 23rd Concession Round application. The company address is:

17 Ensign House, Admirals Way Canary Wharf , London E14 9XQ United Kingdom Phone : + 44 (0) 207 863 2429 Fax : + 44 (0) 207 863 7510.



1.2 Blocks applied for Anergy Ltd has screened the available acreage in the 23rd Offshore License Round in mature areas of the North Sea. Important parameters in the screening process have been resource potential, probability of discovery, seawater and reservoir depth and distance to infrastructure. In addition Anergy Ltd has put emphasis on new play models in need of maturation. The most attractive blocks have been subject to a detailed evaluation and ranking procedure. The blocks applied for by Anergy Ltd are:

• Open acreage in blocks 211/19c and 211/24 (adjacent to Murchison and Statfjord Fields)

• Open acreage in block 211/11b (adjacent to Magnus Field) The blocks applied for and the participating role and interest in the round are listed in Table 1.2-1. If there is insufficient interest from other parties for the blocks applied for, Anergy is willing to enter into discussions to raise the interest level.

Priority Applied for Proposal Duration of period Proposal

Block/combination of block(s) applied

for

Participating interest

(%)

Participating role

Work obligation

Extent and time schedule for

relinquishment of acreage

211/24c 100

211/19b 100

211/11b 100

Promote License

-Complete database -Reprocess seismic -Re-evaluate all relevant data - Contingent well

2years Initial period of 2 years, after which 100 % of the held acreage will be relinquished prior to a 2 years extension if no drillable prospect is identified.

Table 1.2-1 Blocks applied for

1.3 Block summaries

1.3.1 211/19b and 211/24c Blocks 211/19b and 211/24c was awarded to Kerr Mc Gee and in turn taken over by



Statoil (UK) Ltd before relinquished. One exploration well is drilled in license acreage, a dry well. The main reason for Anergy Ltd applying for additional acreage in blocks UK211/19b and UK211/24c is to explore the remaining potential adjacent to held licenses, in particular the Upper Jurassic play model, which is already proven on Statfjord North Field and in block NO34/7 (Borg Field and the Vigdis Extension development project). Wells NO33/9-15, NO33/9-16 and NO33/9-17 penetrated good quality Upper Jurassic sandstones with oil shows, but failed to find commercial accumulations. The Anergy database in blocks 211/19b and 211/24c includes released two 3D surveys, some well information and publications. In addition Anergy has detailed knowledge of the area as company employees have previously been working for operating companies in the area. The identified exploration opportunities in the block are shown in Figures 1.3-1 and 1.3-2 and summarized in Table 1.3-1:

• Prospect Aladdin (Intra Kimmeridgian Fm sandstone) The prospect represents a stratigraphic pinch-out of the Intra Kimmeridgian Fm sandstone Unit 2 at 9860 ft TVD. The prospect is supported by seismic facies analysis and amplitude studies. The presence of good quality sandstone is proven by time equivalent reservoirs in block NO34/7 and on the Statfjord North Field and the nearby wells NO33/9-15 and NO33/9-16. The prospect is sourced from the Upper Jurassic Kimmeridgian Fm, which reaches the oil window a few kilometers to the southwest. The calculated most likely STOOIP and recoverable resources is 29,4 MBO and 13,6 MBO respectively. The probability of discovery is 22 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect.

• Lead Ali (Intra Kimmeridgian Fm sandstone) The lead represents a stratigraphic pinch-out of the Intra Kimmeridgian Fm sandstone Unit 2 at 10080 ft TVD. The lead is partially supported by seismic facies analysis and amplitude studies. The presence of good quality sandstone is proven by time equivalent reservoirs in block NO34/7 and on the Statfjord North Field and the nearby wells NO33/9-15 and NO33/9-16. The prospect is sourced from the Upper Jurassic Kimmeridgian Fm, which reaches the oil window a few kilometers to the southwest. The probability of discovery is 22 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect.



• Prospect Jasmine (Brent Gp) The prospect is located in block211/19b, west of Statfjord field in Dunlin Low area. The prospect represents a traditional rotated fault horst block, but the hanging-wall position requires the fault plane to be sealing. The depth to the structure is approximately 11970 ft TVD. The prospect is sourced from the Kimmeridgian Fm. The calculated most likely STOOIP and recoverable resources is 582 MBO and 179 MBO respectively. The probability of discovery is 19 %.The major risk for the prospect is the presence of trap at the Brent Gp reservoir level.

• Leads Lago and Lago South(Brent Gp)

The leads are located in block211/19, west of Jasmine Prospect in Dunlin Low area. The leads represent traditional rotated fault horst blocks, but the hanging-wall position requires the fault plane to be sealing. The depth to the structures is approximately 12510 and 12420 ft TVD respectively. The leads are sourced from the Kimmeridgian Fm. The probability of discovery is 22% and 19% respectively. The major risk for the leads is the presence of trap at the Brent Gp reservoir level.

• Lead Abu (Brent Gp) The lead is located in block211/19b, south of Jasmine Prospect in Dunlin Low area. The lead represents a traditional rotated fault horst block, but the hanging-wall position requires the fault plane to be sealing. The depth to the structure is approximately 11780 ft TVD. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 13 %. The major risk for the prospect is the presence of trap at the Brent Gp reservoir level.

• Lead Jafar (Lower Cretaceous) This lead is located in the northern part of block 211/19b, down-flank Statfjord west side. The reservoir section is assumed to be sandstone lobes of Valanginian or younger age, derived from the elevated Tampen Spur province. Typical mounded facies patterns are recognized on seismic lines, associated with chaotic to transparent internal seismic pattern, which may be indicative of sandstone units being present. Gas clouds are seen above the structure. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 12 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect. The depth to the structure is approximately 9050 ft TVD.

• Lead Sultan (Lower Cretaceous) This lead is located in the northern part of block 211/19, down-flank Murchison Field. The reservoir section is assumed to be sandstone lobes of Valanginian or younger age, derived from the elevated Tampen Spur province. Typical mounded facies patterns are recognized on seismic lines, associated with chaotic to transparent internal seismic pattern, which may be indicative of



sandstone units being present. Gas clouds are seen above the structure. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 7 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect. The depth to the structure is approximately 9020 ft TVD.

The proximity of the prospects and leads to the Murchison Field (4-8 km) makes this field the preferable tieback alternative. The prospects, which has total most likely recoverable oil reserves of 193 MBO, has been assumed developed with 16 oil production wells and 7 water injection wells drilled from the Murchison Platform. Wells and facilities will be designed for gaslight. The ultimate recovery is based on a 9 years economic field life. If an exploration well is drilled in 2007 and proves the prospect, the earliest possible oil production can start in 2008.

Block(s) Reservoir

211/24 Unrisked recoverable resources

Prospect/Lead Oil (106Sm3) Gas (109Sm3)

Name P/L Low Base High Low Base High

Probability of

discovery (%)

Stratigraphic level Depth to top

reservoir (ft MSL)

Aladdin P 4,1 13,6 18,0 - - - 22 Kimmeridgian Fm 9580 Ali L - - - Kimmeridgian Fm 10020

Jasmine P 80 179 372 - - - 19 Brent Gp 11240 Lago/ Lago South

L - - - Brent Gp 11960/11880

Abu L - - - Brent Gp 11660 Jafar L - - - Cromer Knoll 9000

Sultan L 6 14 26 - - - 22 Cromer Knoll 8040 Genie L - - - Kimmeridgian Fm 8040

Table 1.3-1 Block summary 211/19b and 211/24c



1.3.2 Block 211/11B The Anergy database in block211/11b includes official reports in the area, and screening of 2D data in the block. Anergy Ltd has not yet interpreted any horizons and has utilized the PGS regional maps in area as well as single articles:

• Prospects 211/11A-B (Brent Gp) All information about these prospects is derived from DTI UK Promote information document. The Prospects are located 9.7 km to the south-west of the Magnus Field. The Trap is defined by Tilted fault block trap with erosional truncation on the crest. Top seal is provided by the Upper Jurassic Heather Formation and thick Upper Cretaceous Shetland Group mudstones. The Prospects are sourced from The Kimmeridge Clay Formation (Late Jurassic to Early Cretaceous) is the principal source rock of the northern North Sea, and has charged all Brent Group oilfields in the region, as well as reservoirs at other stratigraphic levels. In Place volume range from : 116 - 161 - 210 MBO Recoverable: 44 – 64 – 85 MBO Deterministic: 83 MBO The probability of discovery is 10 %. The trap definition and migration of hydrocarbons are regarded as the major risk factors for the prospect.

• Leads 211/11C-G (Upper Jurassic)

The leads represents stratigraphic pinch-out of the Upper Jurassic sands, now designated the Magnus Sandstone Member of the Kimmeridge Clay Formation. The leads are partially supported by seismic analysis and amplitude indications. The presence of good quality sandstone is proven by time equivalent reservoirs in Magnus Field and in similar settings in the area. The lead is sourced from the Kimmeridge Formation. The calculated STOOIP and recoverable resources is 102 MBO and 41 MBO respectively. The probability of discovery is not calculated exactly, but would be around 10%. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect.

The proximity to the Magnus Field in Block 211/12A gives an opportunity for sub sea tieback of the identified prospects and leads in block 211/11B to the one steel platform and several subsea completions, which may prolong the production life of the Magnus Field. The technical solution is a straightforward sub sea development of



the 211/11A prospect and 211/11C lead and a tieback to the Magnus installation approximately 10 km to the northeast of the prospect and lead. The development requires oil-producing wells and water injectors, and it is assumed that they are located on a set of templates, each with a fixed amount of wells. With an aggressive development plan production can be initiated already in 2008.

Block Reservoir

211/11B Unrisked recoverable resources

Prospect/Lead Oil (MBO) Gas (BBO)

Name P/L Low Base High Low Base High

Probability of

discovery (%)

Stratigraphic level Depth to top

reservoir (ft MSL)

211/11A P 4 13 26 - - - 10 Brent Gp 11500 211/11C L 1 4 10 - - - 10 Kimmeridgian Fm 10000 * Assumed recoverable resources in blocks 15/11 and 15/12 Table 1.3-2 Block summary 211/11B



1.4 Work programme framework The nature of the exploration opportunities identified in the blocks applied for are classified as prospects or leads. The difference between a prospect and lead is the technical confidence in the exploration opportunity, which is controlled by the geological complexity, the available database and the variable data quality. The proposed duration of the initial period is 2 years (2005-207), defined as a promotional license:

• Geoscientific evaluation

Conduct a block specific work programme during first two years, which will mature the exploration opportunities to drillable prospect(s). If the decision is taken not to drill any well the entire block will be relinquished.

• Well before end 2008 Drill contingent well(s) to test matured prospect(s). Decide whether or not to prepare a development plan for any discovery made in Phase 2 (“Decision on Carry it Further”). If the decision is taken not to proceed the entire block will be relinquished.

1.5 Comments to application

1.5.1 Blocks 211/19b and 211/24c Anergy has performed a comprehensive evaluation of the available 23rd Concession Round acreage in the northern Tampen Spur Province; see databases in Sections 3.1 and 3.2. Although the block applied for include only blocks 211/24 and 211/24c, relevant illustrations from other parts of the Tampen Spur has been included in this report. To enable a better understanding of the seismic response of the Upper Jurassic sandstones identified in blocks 33/9, Anergy has initiated a pilot study in co-operation with NTNU, Trondheim; Seismic analysis of Upper Jurassic sands based on well log information (Stovas & Landrø, M., 2004). A summary of the pilot study is included in Section 3.3.4. The planned pressure draw-down on the Statfjord and Murchison Fields will probably effect the development of remaining resources in blocks 211/19b, 211/24c and 211/24c.



1.5.2 Block 211/11b For our evaluation of block 211/11b, we have relied upon DTI’s evaluation in UK Promote work, in addition to screening of 2D data in the area. Anergy is of the manpower knowledge from Magnus Field and Norwegian sector in the area would benefit the exploration potential development in this block acreage.



2 INTRODUCTION

2.1 Report organization The 23rd Concession Round application includes a technological and economical evaluation of the blocks applied for. In more detail the applications consists of:

• Section 1 Executive summary including basic company information and a presentation of the exploration opportunities in the blocks applied for. Tables of Prospects and Leads are enclosed in this section.

• Section 2 This section includes an Introduction to the application, including basic information facilitating the organization of the report. A database summary and a description of the work processes utilized are included.

• Section 3-5 Short descriptions of the geological provinces in which the blocks applied for are located and a detailed geological and technological evaluation of the exploration opportunities identified. Included in this section are database, petroleum geological analysis, production profiles and development scenarios.

• Section 6 References

• Attachment to Application

Company related matters and experience in technology, safety, working environment and environmental matters. Also separate reports made for Anergy Ltd is included in the report in this part.

The application is submitted as hard copy and on CD, 1 copy for the DTI.

2.2 Work processes and methodology

2.2.1 Data Management Schlumberger Information Technology Services Norway has been responsible for project data management. Schlumberger Infodata Norway provides the released well and seismic data. The NPD and DTI fact pages have been used extensively. In addition the Lead web pages together with UK Promote web pages have been used in order to compile needed information.



Robertson Information Systems has been used for UK well information packages of various types.

2.2.2 Software The Petrel suite of SIS software, including “Petrel Seismic”, “Petrel Basic Geology” and “Petrel Modeling”, has been loaded on PC workstations. The Petrel software suite has been used for:

• Seismic interpretation • Synthetic seismogram and well tie analysis • Simple depth conversion combining sonic and VSP and/or check shot data to

generate a first pass regression time-depth curve • Geological zonation and well correlation

The special software module from Central Geophysical Expedition – CGE, “INPRES”, has been used for:

• Special Processing of Seismic • Seismic Interpretation

The visualization software from RockWare, “RVS – Rock Visualization Software”, has been used for:

• Visualization of seismic and well data The “Interactive Petrophysics” (IP) software, provided by Schlumberger Information Technology Services Norway, has been used for:

• Petrophysical analysis of key wells • Generation of CPIs for key wells • Input parameters to volume calculations

2.2.3 Development scenarios A screening of the most likely potential development scenarios for the prospect has been carried out by the Real Concept Group, utilizing their software “Cost”.



3 EVALUATION OF BLOCKS 211/19B AND 211/24C

3.1 Regional geological of northern Tampen Spur Province

3.1.1 Tectonostratigraphic development Location of the area is in the East Shetland Basin, adjacent to the North Viking Graben, close to the median line with Norway. On the Norwegian side, The Tampen Spur area has been through a complex geological evolution, with deposition of sediments ranging in age from Devonian to Recent. The basin is delineated by the Northern Viking Graben to the east, the Marulk Basin to the northwest and the Shetland Platform to the west and south; see Figure 3.1-1. Several traps have been identified in the area, including traditional rotated fault blocks and stratigraphic pinch-outs; see Figures 1.3-1, 1.3-2 and 1.3-3. Below follows a short description of the geological periods evaluated in this application, Figure 3.1-2. Paleozoicum A few wells have been drilled into sediments of Devonian age, without proving any reservoir or source potential. The main geological features generated during the Caledonian Orogeny are seen to form the framework for later structural developments. The thickness and distribution of the Permian sediments are not defined on seismic and in wells. The Permian basin configuration reflects a widespread extensional rifting, with the Øygarden Fault Zone as the eastern boundary and the East Shetland Platform as the western limit. Volcanic material, frequently found over large parts of the North Sea region, has not been observed in the Tampen Spur region. During the Kazanian- Tatarian, a renewed phase of extension is indicated by the intrusion of basaltic dykes along the west coast of Norway, dated 250-260 Ma (Fossen & Dunlap, 1999). Sediments deposited during this period are thought to be fluvial and lacustrine of origin, with some eolian deposits. The Zechstein Gp sediments are not expected in its classical evaporite facies. Mesozoicum The Triassic period is characterised by multiple extensional episodes, starting with the Pfalzen/Hardegsen tectonic phase occurring during the Early Triassic and the Early Kimmerian phase during the Carnian to Norian times. The latter phase is also recorded as intrusive dykes in the west coast of Norway, dated to 230-220 Ma. The extension involved the region between the Norwegian west coast and the East Shetland Platform. Large sediment thickness is observed, ranging from a few tens to



more than 1300 m in thickness. The Triassic succession in the Northern Viking Trough is included in the Hegre Gp, which is divided into the Teist (base), Lomvi and Lunde Fms (top). The group is characterized by intercalated sandstones and shales, representing alluvial fans and a variety of fluvial systems, intercalated with lacustrine deposits. The Lunde Fm sandstones represent a major reservoir in the Snorre Field. The tectonic evolution and basin configuration during the deposition of the Late Triassic to Early Jurassic series is uncertain. The transition between Triassic and Jurassic is characterised by renewed subsidence (Early Kimmerian tectonic episode) and transition to a more humid climate. During this period fluvial, deltaic and shallow marine sediments were deposited, referred to as the Statfjord Fm. Marine connection with the East Greenland region is indicated based on faunal comparison (Surlyk, 1990), indicating a marine area to the north. The entire region was transgressed and covered with the predominantly storm dominated shales of the Dunlin Gp of late Early Jurassic (Sinemurian to Toarcian) age. The Early Jurassic succession gives a proven play over most of the Tampen Spur Area. A marked unconformity, linked to a rift phase in the North Sea Basin, initiated in the mid-Jurassic, divides the Early and Middle Jurassic series, Gabrielsen et al. (1990), Roberts et al. (1990). During this period the Viking Graben, the Central Trough and the Moray Firth Basin were individualized as distinctive structural units. The east-west extension led to reactivation of older lineaments with orientations N-S, NE-SW and NW–SE. The sediments of Middle Jurassic age range from fluvial through deltaic to shallow marine sandstones; see Figure 3.1-3. The fluvial to deltaic deposits of Aalenian-Bathonian (Callovian) age is included in the Brent Gp, consisting of the Broom (Base), Rannoch, Etive, Ness and Tarbert (top) Fms. The Brent Gp represents an attractive and proven play type in the entire Tampen Spur province. During the Callovian-Oxfordian, the northern Viking Graben was transgressed and the shales of the Viking Group, the Heather (base) and Kimmeridgian (top) Fms, were deposited. Extensive erosion over crestal highs during the latest Jurassic, created large amounts of sand deposits in down slope positions; see Figures 3.1-4 to 3.1-8. These intra Kimmeridgian Fm sandstones have been proven as good quality reservoirs in the Statfjord North and Borg Fields and in the Vigdis Extension development project. In the Vigdis and Sygna Fields the Late Jurassic sandstones may overlie directly the Brent Gp reservoirs and are therefore difficult to identify. The large amount of sand eroded off crestal highs during Late Jurassic; embedded in the Kimmeridgian Fm source rock, make them attractive exploration targets. The Lower Cretaceous, resting unconformably on the Late Jurassic, consist of shales with varying interbeds of limestone and are included in the Cromer Knoll Gp. However, erosion of the northern part of the Tampen Spur may have continued into the Lower Cretaceous allowing clastic deposits to be shed into the Marulk Basin. These deposits may form an attractive exploration target. The overlying Shetland Gp consists of shale with variable amounts of limestone covering the entire northern North Sea.

The Lower Cretaceous deep-water depositional system in parts of North Sea is



emerging as a significant economic target. It contains a broad range of sedimentary facies and architecture. In central North Sea we can observe thick sands could be deposited by high-density sediment gravity flows. Unusual banded and mixed slurried facies represent the products of processes transitional between turbidity currents and debris flows. Shale-prone units show evidence of debris flows and post-depositional down-slope movement. Geometrical architectural elements include narrow linear incised channels, broad linear sand-rich fairways, prograding sand lobes and laterally extensive sheets. Models for exploration and production are refined by core magnetic measurements, automated quantitative petrography, detailed structural analyses and biostratigraphical zonations. Key remaining challenges are refining depositional models to aid prediction of lateral facies variations, understanding trap mechanisms and geometry and improving images of sandstone units on seismic data, Figure 3.1-9

Cenozoicum During the latest Cretaceous to Eocene uplift, created by the early phases of oceanisation in the northern Atlantic Ocean, resulted in mobilization and re-deposition of older sediments into the North Sea. These deposits are generally of different mass flow types and form attractive targets for exploration in the central and southern parts of the Viking Graben. The detrittic supply to the East Shetland Basin region seems to have been restricted and only scattered occurrences of Paleocene reservoirs; northern part of the Statfjord Field and wells 34/7-18 and 34/7-21. During the Late Oligocene an uplift in the northern North Sea resulted in deposition of the shallow marine sediments of the Skade and East Shetland Basin area. By the end of the Oligocene and into the Miocene, a major transgression occurred in the North Sea. Increased relief in the hinterland, however, resulted in a large sediment supply to the region and the basin gradually filled up. Starting during the Miocene and increasing in frequency in the Pliocene and Quaternary, the influence of fluctuating ice caps (and thereby eustatic level) caused thick series of glacio-marine sediments to deposit. The rapid subsidence and possible tilting of the study area may have had an influence on the migration and conservation of hydrocarbons in the traps of the area.

3.1.2 Exploration opportunities Three major plays have been identified along with three play models:

• Tilted fault blocks with Early to Middle Jurassic sandstone reservoirs belonging to the Statfjord Fm and Brent Gp, sealed by Late Jurassic and Cretaceous shales. This play type forms the basis for most of the fields in the East Shetland Basin region. The Brent delta shales out northeastwards into Norwegian sector, but should not constitute a severe risk of efficient reservoir rocks. High reservoir pressure in the Brent Gp is also considered as a potential risk.

• Intra Kimmeridge Fm marine sandstone deposits of Late Kimmeridgian-



Volgian age, representing erosional products from the elevated parts of the Tampen Spur on the Norwegian side of the continental shelf, and individual rotated fault blocks. The deposition or reworking of these sandstones may have continued into the earliest Cretaceous (well NO34/7-8 and in the Norwegian Vigdis Field wells). The sandstones are proven oil-bearing in the region and are also proven to have stratigraphic components in the trap configuration. Two distinct depositional facies types of sandstone is proven, assigned the unofficial names “Magnus” and “Munin” Fms respectively. These sands are included in the Intra Kimmeridge Fm Unit 2 and Unit 1 respectively. Analogue fields in vicinity would be Borg Field on the Norwegian sector, see Figures 3.1-11 to 3.1-15 and Magnus Field on the UK sector. This field shows similarities to the exploration opportunities seen in Upper Jurassic in Block 211/24c.

• Early Cretaceous sandstones of assumed pre-Albian/Aptian age, see Figure

3.1-10, forming stratigraphic traps where gravity driven sandstones on lap morphological highs. This play is well developed in areas such as Moray Firth in the UK sector. The traps are assumed to be sealed the by Lower Cretaceous or younger shales, see Figure 3.1-16.

Anergy is of the opinion that stratigraphic prospects are under explored in these areas of the UKCS. In an article in the AAPG Explorer August 2004 (Durham, 2004) the title supports this statement: “Subtle traps become new prey and subtle does not mean small in the North Sea”. Anergy expect stratigraphically controlled hydrocarbon accumulations to be present in blocks 211/24 and 211/11B. The proven reservoir communication between the Brent Gp and Late Jurassic reservoirs in the Norwegian sector make the exploration of the undiscovered prospect time critical in light of the planned pressure depletion of the Statfjord and Murchison Fields. Potential consequences for nearby fields and undiscovered resources in communication with the Statfjord Field aquifer are presented in Section 3.5.

3.2 Database

3.2.1 Seismic data The seismic database includes released seismic surveys covering parts of Blocks 211/10b and 211/24c; see Figure 3.2-1. The surveys interpreted are listed in Table 3.2-1. The overall quality of the seismic is average to good. The 3D data has better resolution and good signal-noise ratio. The ties between the different surveys are made without major problems. The static shifts were 0-5 ms relative to the ST9101 used as reference survey.. The shifts were handled in the Petrel workstation.



Survey Survey name 2D 3D Type

Stacking velocities

MC3D-211-19

X Final mig -

ST9101 X Final mig - Table 3.2-1 Seismic database East Shetland Basin Province

3.2.2 Well data The available well database provided by Schlumberger Infodata Norge is included in Table 3.2-2 and Figure 3.2-2. The well control is sufficient to control the source and reservoir sections for the prospect and leads. Wells 33/9-10 and 33/9-17 suffers from incomplete database available from NPD and former operators.

Velocity data Synthetic seismogram Well Composite

log Check shot VSP

NO33/5-1 X X X NO33/5-2 X X X NO33/6-1 X X X NO33/6-2 X X NO33/9-8 X X X NO33/9-11 X X X NO33/9-14 X X X NO33/9-15 X X X NO33/9-16 X X X

NO33/9-17 *

UK211/24C- 7 *

* Scout information only

Table 3.2-2 Well database East Shetland Province

3.3 Petroleum geological analysis

3.3.1 Well ties and seismic interpretation To ensure proper well ties to seismic, synthetic seismograms have been generated for wells listed in Table 3.2-2; see Figures 3.3-1 to 3.3-3. Several seismic reflectors have been interpreted, ranging in age from seafloor to top Brent Gp; see Table 3.3-1. The listing below provides an overview of the time structure maps and associated depth - and isopach maps that have been generated.



Structure maps Seismic reflector / interval

Time (ms) Isopach (m) Depth (m) Seafloor Top Balder Fm Isochore Balder – Shetland Fm Top Lista Fm Top Shetland Fm Top Lower Certaceous Wedge X Top Cromer Knoll Gp Isopach L Cret Wedge - BCU Base Cretaceous Unconformity X X Top Intra Kimmeridgian Fm Unit 2 X X Isopach I Kimmeridgian Fm Unit 2 X Top I Kimmeridgian Fm Unit 1 X Isopach Kimmeridgian Fm Unit 1 X Top Heather Fm Top Brent Gp X X

Table 3.3-1 Seismic markers and maps generated block 211/24c The seafloor is picked on positive acoustic impedance in the mapped region and is relatively smooth and easy to map out The top Balder Fm is interpreted at the maximum negative amplitude. This marker is defined as an increase in sonic velocities as well as an increase in density, which sets up a positive impedance contrast. The quality of this reflector varies through the area, but proves to be quite easy to map. On-lapping character and high impedance contrast define the reflector. Top Lista Fm is defined as the top of a more sandy sequence. The character of the reflector is variable, reflecting the lithology of the interval above and below the reflector. The seismic facies within the Lista Fm varies from sub-parallel to mounded. Top Shetland Gp is interpreted at positive acoustic impedance. This reflector is easy to map in the whole area and is partially erosive in character. The marker is characterized by local negative impedance contrasts due to facies changes within the Jorsalfare Fm. The areas with negative impedance contrast have limited lateral extent. The marker is usually mapped on the onset of positive amplitude, however local variations do occur. Top Lower Cretaceous Wedge is marked by an increase in acoustic impedance, due to an increase in sonic over the reflector. The reflection is not a regional consistent marker in the mapped area, since it is marking the top of local Lower Cretaceous lobes. The marker is picked on negative amplitude. This unit is not penetrated by any wells in a basinal setting, see Figure 3.3-4 to 3.3-7.



Base Cretaceous Unconformity (BCU); see Figures 3.3-8, is characterized by an increase in acoustic impedance. The reflection varies somewhat throughout the area, but is in general interpreted in maximum amplitude to zero crossing in some areas. Top Intra Kimmeridgian Fm Unit 2; see Figures 3.3-9 and 3.3-10, is generally seen as a decrease in acoustic impedance. However, due to lithology variations the character of this reflector is variable. Usually the pick is made at maximum to zero crossing amplitude. Intra Kimmeridgian Fm Unit 2 isopach is constructed from the depth structure maps of top Intra Kimmeridgian Fm Unit 2 and 1; see Figure 3.3-11. The map shows an overall thickening towards the south and western part of block 211/24c. In the area between the Murchison and Statfjord Fields there is a local deposcenter into Blocks 211/19b and 211/24c. Top Intra Kimmeridgian Fm Unit 1; see Figures 3.3-12 and 3.3.-13, is marked by a slight increase in acoustic impedance. Some variations are expected in the properties of this reflector due to the same reasons as mentioned for Unit 1 above. The seismic pick is made on onset maximum amplitude to maximum amplitude. Intra Kimmeridgian Fm Unit 1 Isopach is constructed from the top Intra Kimmeridgian Fm Unit 1 and Top Heather maps; see Figure 3.3-13. The general trend for this interval is increased thickness towards the northern part of block, thinning towards the southwestern part of block 211/24c. Top Heather Fm is marked by a decrease in acoustic impedance in cases where the Kimmeridgian Fm contains sandstone units above it; elsewhere it is marked by a slight increase in acoustic impedance. The seismic pick is made on minimum amplitude and in some places zero crossing. Top Brent Gp; see Figures 3.3-14 and 3.3-15, is characterized by an increase in acoustic impedance, generated by a change in acoustic impedance over the shale/sand boundary between the Heather and Tarbert Fms. The signature of the reflector varies throughout the mapped area, probably due to thickness variations. The marker is picked on negative amplitude on seismic.

3.3.2 Depth conversion The interpreted horizons from the 3D seismic survey have been manipulated in Petrel workstation, gridded and model built. All the horizon grids are generated with an increment of 250 m in both x- and y-direction. Only the top Brent Gp surface has been gridded with closed fault polygons (without z-values). The original plan for depth conversion was to generate a 3D velocity cube from stacking velocities, but since no velocity information was available at the time of interpretation, a traditional layer-cake approach was applied using Petrel software.



The BCU was converted to depth by the formula:

Depth = time * (0.00014 * time + 0.711) Then the unadjusted surface was adjusted by the depth values in key wells. The next step in the procedure was to establish an interval velocity between top Brent Gp and the BCU. This velocity was used to depth convert the following isochores:

• BCU-Unit 2 • BCU-Unit1 • BCU-Top Brent Gp

The same procedure was repeated upwards for the horizons above BCU. The average velocity was calculated between BCU and Top Shetland Gp.

3.3.3 Attribute mapping Amplitude studies have been performed in areas with 3D seismic coverage in the blocks; see Figure 3.2-1. The main purpose for these studies has been to predict the potential of sand presence and to identify possible indicators for hydrocarbons, See Figures 3.3-16a-d. Wells drilled in the northern part of the Tampen Spur (Snorre Field) and on intra basinal highs (Gullfaks, Visund, Statfjord, Statfjord Øst, Statfjord North and Sygna Fields) show that extensive erosion has taken place during Late Jurassic-earliest Cretaceous. The accumulation of these sediments is proven in block NO34/7 and by wells drilled in basinal settings in block NO33/9 (33/9-15, 33/9-16 and 33/9-17). Anergy assume the amplitudes described above to indicate that these sands might have been deposited deeper into the basin between the Statfjord and Murchison Fields. In order to guide the Upper Jurassic sand distribution a rock physics pilot study has been performed on well logs; “Seismic analysis of Upper Jurassic sands based on well log information” (Staovas & Landrø, 2004). The merging of different seismic surveys as well as the seismic resolution, reduce the confidence in amplitude studies. However, by combining the amplitude extractions with isochore maps of the Upper Jurassic units a depositional system as described is likely to occur. A further investigation of these aspects will be addressed in the proposed work program for the license; see Section 3.8.



3.3.4 Structural and stratigraphic framework The Middle Jurassic traps identified are classically formed by Late Jurassic extensional tectonics, generating rotated fault-blocks of different scale. The blocks are normally sealed by Late Jurassic and Early Cretaceous shale. If Late Jurassic and/or lowermost Cretaceous sands occur above the reservoir, they may act as thief zones and may cause communication between structures. Sealing faults in the Middle Jurassic section are known from the Tampen Spur area, but normally faults do not seal if sandstones are juxtaposed over the fault. Down-faulted structures, closing against the hanging wall, will consequently have a major risk of failure connected to the sealing. Hydrocarbon charging of the Middle Jurassic structures is proven by a large number of fields in the region. The hydrocarbon phase is normally reflected by the maturity of the Kimmeridgian Fm source rock in the vicinity of the structure. During the Late Jurassic, the Tampen Spur was faulted into mega-blocks and uplifted due to the extensional rifting in the Viking Graben. The crests of several of the blocks were made subject to erosion. Re-deposition of clastic material occurred; see Figures 3.1.4 to 3.1-9, mostly on the dipping flank as illustrated by wells in block 211/24c; see. Some clastic material was also deposited along the fault-scarp of the blocks, mostly as conglomeratic fans with little exploration interest. An upper and a lower sandstone unit are known from the Late Jurassic of the Tampen Spur. The lower unit, called Intra Kimmeridgian sst Unit 1, is of Kimmeridgian to lowest Volgian age (“Magnus Fm equivalent”). The depositional environment of this unit is normally sub-marine gravity driven flows, overlying the Heather Fm with an unconformity on the basin flanks; see Figure 3.1-9. The unit is assumed to be widespread in the basinal areas between the eroded crests of the Jurassic mega-blocks; see Figure 3.1-4. The upper unit, called Intra Kimmeridgian sst Unit 2, is of lower Volgian age (“Munin Fm equivalent”. The depositional environment of this unit is shallow marine to shore facies. The unit rests on an unconformity, separating it from the underlying Heather or lower Kimmeridgian Fm shale or sometimes from the Intra Kimmeridgian 1 Unit. The unit is assumed to be present along a paleo-coastline along the dipping flank of the tilted mega-blocks; see Figure 3.1-9. The porosity of the Late Jurassic reservoir units is generally ranging from around 20 % at 2500 m to around 10% at 4000 m. The variation is around +/-3 %, although there are examples of lower porosities for instance in well 33/9-15 Intra Kimmeridgian Fm sst unit 2. Sparse well information makes it difficult to discriminate between the two units. The net/gross ratio normally varies unsystematically (in the wells available) between 50-100 %. The lower values probably reflect a peripheral setting with respect to proper sand development. The permeability of the reservoir units will be dependent on the shale content (also affecting the porosity) and the reservoir depth. The value for the lower unit (Unit 1) is consequently expected to vary rapidly, both vertically and laterally according to its location inside the deep marine fan, while the values for the Unit 2 is conceptually considered more stable. The aquifer of the



reservoir is mostly considered good, as the sands are thought to become thicker down flank. Intraformational barriers may, however, decrease the connectivity within the reservoir. The trapping mechanism for the Late Jurassic reservoirs will mainly be stratigraphic although a structural component is sometimes observed. Top seal is considered to be the shales of the uppermost part of the Kimmeridgian Fm and the Lower Cretaceous shale. Base seal is assumed to be the Heather Fm in the case of the lower unit and intraformational Kimmeridgian Fm shales in the case of the upper unit. It should be noted that the two reservoir units may be in contact and base and lateral seal may be questioned. Contact between the Late Jurassic reservoirs and the Brent Gp sands may also occur, possibly jeopardizing the base seal. Hydrocarbon charge of the Late Jurassic traps is considered unproblematic, as they are located within the mature source rocks of the Kimmeridgian Fm. The hydrocarbon phase will most probably reflect the local degree of maturity of the source rock. Retention of the hydrocarbons is thought to be unproblematic, as young tectonic activities are not seen to affect accumulations in the vicinity. Biodegradation is not considered a problem at this depth in this region. Massive lowermost Cretaceous sandstones are known from the Magnus Basin, presumably derived from erosion of the crests of the previously mentioned mega-blocks. Some (most) of the sands may also have been derived from the Nordfjord High, as this structural unit was lifted as a response to the extensional rifting in the West of Shetland/Møre Basin to the northwest. The sediments are of deep marine gravity flow origin, probably settling close to the basin floor at that time. No information with respect to petrophysical characteristics is available to this study. The traps for this reservoir sequence are assumed to be mostly stratigraphic, although structurally closed features may also be anticipated. The sealing of this type of trap is considered unproblematic, with Lower Cretaceous shale as top seal and lowermost Cretaceous and Kimmeridgian Fm as base seal. The hydrocarbon charging of these traps is assumed from locally mature Kimmeridgian Fm, directly underlying the trap. Retention of hydrocarbons is not considered a risk factor in this setting.



3.4 Identified exploration opportunities

3.4.1 Introduction Several exploration opportunities have been identified in the area, of which two has reached sufficient maturity to reach prospect level. The remaining is referred to as leads. Anergy has to stress that any exploration further in the Upper Jurassic and Lower Cretaceous will require a more detailed mapping of the unconformities within these intervals not only within the licensed area, but also in the surrounding areas, in order to fully understand the Upper Jurassic sand distribution and migration pathways for hydrocarbons.

• Prospect Aladdin (Intra Kimmeridgian Fm sandstone) The prospect represents a stratigraphic pinch-out of the Intra Kimmeridgian Fm sandstone Unit 2 at 9860 ft TVD. The prospect is supported by seismic facies analysis and amplitude studies. The presence of good quality sandstone is proven by time equivalent reservoirs in block NO34/7 and on the Statfjord North Field and the nearby wells NO33/9-15 and NO33/9-16. The prospect is sourced from the Upper Jurassic Kimmeridgian Fm, which reaches the oil window a few kilometers to the southwest. The calculated most likely STOOIP and recoverable resources is 29,4 MBO and 13,6 MBO respectively. The probability of discovery is 22 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect.

• Lead Ali (Intra Kimmeridgian Fm sandstone) The lead represents a stratigraphic pinch-out of the Intra Kimmeridgian Fm sandstone Unit 2 at 10080 ft TVD. The lead is partially supported by seismic facies analysis and amplitude studies. The presence of good quality sandstone is proven by time equivalent reservoirs in block NO34/7 and on the Statfjord Nord Field and the nearby wells NO33/9-15 and NO33/9-16. The prospect is sourced from the Upper Jurassic Kimmeridgian Fm, which reaches the oil window a few kilometers to the southwest. The probability of discovery is 22 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect.

• Prospect Jasmine (Brent Gp) The prospect is located in block211/19b, west of Statfjord field in Dunlin Low area. The prospect represents a traditional rotated fault horst block, but the hanging-wall position requires the fault plane to be sealing. The depth to the structure is approximately 11970 ft TVD. The prospect is sourced from the Kimmeridgian Fm. The calculated most likely STOOIP and recoverable resources is 582 MBO and 179 MBO respectively. The probability of discovery



is 19 %.The major risk for the prospect is the presence of trap at the Brent Gp reservoir level.

• Leads Lago and Lago South(Brent Gp)

The leads are located in block211/19, west of Jasmine Prospect in Dunlin Low area. The leads represents traditional rotated fault horst blocks, but the hanging-wall position requires the fault plane to be sealing. The depth to the structures are approximately 12510 and 12420 ft TVD respectively. The leads are sourced from the Kimmeridgian Fm. The probability of discovery is 22% and 19% respectively. The major risk for the leads are the presence of trap at the Brent Gp reservoir level.

• Lead Abu (Brent Gp) The lead is located in block211/19b, south of Jasmine Prospect in Dunlin Low area. The lead represents a traditional rotated fault horst block, but the hanging-wall position requires the fault plane to be sealing. The depth to the structure is approximately 11780 ft TVD. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 13 %. The major risk for the prospect is the presence of trap at the Brent Gp reservoir level.

• Lead Jafar (Lower Cretaceous) This lead is located in the northern part of block 211/19b, down-flank Statfjord west side. The reservoir section is assumed to be sandstone lobes of Valanginian or younger age, derived from the elevated Tampen Spur province. Typical mounded facies patterns are recognized on seismic lines, associated with chaotic to transparent internal seismic pattern, which may be indicative of sandstone units being present. Gas clouds are seen above the structure. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 12 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect. The depth to the structure is approximately 9050 ft TVD.

• Lead Sultan (Lower Cretaceous) This lead is located in the northern part of block 211/19, down-flank Murchison Field. The reservoir section is assumed to be sandstone lobes of Valanginian or younger age, derived from the elevated Tampen Spur province. Typical mounded facies patterns are recognized on seismic lines, associated with chaotic to transparent internal seismic pattern, which may be indicative of sandstone units being present. Gas clouds are seen above the structure. The lead is sourced from the Kimmeridgian Fm. The probability of discovery is 7 %. The presence of sand and the stratigraphic nature of the trap are regarded as the major risk factors for the prospect. The depth to the structure is approximately 9020 ft TVD.



3.4.2 Prospect Aladdin The outline of the Upper Jurassic prospect Aladdin is shown in Figure 1.3-1. Key prospect information is included in Table 3.4-1. The prospect includes the shallow/marginal marine Intra Kimmeridgian Fm Unit 2; see Figures 3.1-4. The prospect is located within Intra Kimmeridgian Fm Unit 2, which is described in wells NO33/9-15 and NO33/9-16. Based on the isopach generated for the Intra Kimmeridgian Fm Unit 2, the average thickness is assumed to be 90 ft; see Figure 3.4-3. Additional potential may also be present in the underlying Intra Kimmeridgian Fm Unit 1 sandstones. The prospect is a stratigraphic trap with sands on-lapping the underlying Unit 1; see Figures 3.4-10 to 3.4-16. The top Heather Fm is the ultimate on-lapping surface for both units, and will provide the base seal for this play. Both the Intra Kimmeridgian Fm sandstone Units 1 and 2 surfaces have a mounded character, which together with the Isopach maps indicate the presence of sand. The top of the Intra Kimmeridgian Fm Unit 2 usually lies close to the BCU, Figures 3.4-16 and -17. These sand units seen in Block 211/24c could be different sand units from what is seen in wells NO33/9-15 and 16. This since we see a sand unit just below BCU surface, partly masked by BCU reflector as well. This sand unit however does not have any stratigraphic nor structural trap definition within Block 211/24c. In well N33/9-15 it is only about 20 cm with shales between the BCU and top Intra Kimmeridgian Fm Unit 2 sandstone. The internal reflection is transparent to mounded and in parts chaotic to transparent. The prospect is sourced from Kimmeridgian Fm shales. As in the other fields in the area the prospect is expected to be oil bearing. Both Upper Jurassic Kimmeridgian Fm shale and Lower Cretaceous shale/chalk act as seal in the area. The main risk is connected to the definition of the stratigraphic trap. A Ptrap of 0.4 has been assumed. The seal is considered less problematic. Thief sands may exist in the shales above the reservoir zone, but normally the seal is regionally efficient. Biodegradation of an oil column is less likely at this depth and a Pretention of 0.9 is taken for this trap. The probability of reservoir presence is considered medium, both from well and seismic evidences. If the reservoir is present it will probably have sufficient petrophysical properties to produce it efficiently. A Preservoir of 0.6 is assumed. The probability for source rock is assumed to be one based on discovered fields in the area. The probability of discovery is 22%. The volumetric calculation is based on oil down to contact at 9860 ft MSL for all cases. This is due to the fact that a stratigraphic isolated sand body in the prospect position is assumed, which would be filled to its maximum extent. A variation in gross rock volume (+10 % to –20 %) has been applied in order to take into account the uncertainty in seismic interpretation and time to depth conversion. The uncertainty linked to sand content is described by the net/gross ratio; 55 % (45-60 %). The porosity used is 18 % (16-20 %) based on log interpretation of nearby wells. The permeability in this type of sand is normally not a constraining element. The Bo is set



to 1.30 (1.35 –1.20) from field analogies. The recovery has been assumed to be 40 % (35-50 %) due to the size of the prospect and the uncertain size of the underlying aquifer.



Block: 211/19B and 24C Prospect outline (file name):

Prospect name: Aladdin Lead name:

Structural element: East Shetland Basin Seal: Kimmeridgian Fm and Lower Cretaceous shale/chalk

Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Upper Jurassic Depth to top reservoir: 9580 ft MSL Anticipated number of development wells: 12 Lithostratigraphic level: Intra Kimmeridgian Fm sand, Unit 2 Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Stratigraphic General parameters LOW BASE HIGH Comments Area (km2) 4,4 4,4 4,4 HC-column (ft) 280 280 280 Rock volume (109 Sm3) 0,31 0,396 0,45 +10% / -20% uncertainty in seismic

interpretation and time/depth conv.

Porosity 0,16 0,18 0,20 From log interpretation Reservoir thickness (ft) 90 90 90 Net/gross ratio 0,45 0,55 0,60 + 10% / -20 % uncertainty in sand cont. Parameters OIL case LOW BASE HIGH Comments Water saturation 30 25 20 Recovery factor main phase 35 40 50 Recovery factor associated phase Oil case only Formation volume factor Bo 1,35 1,3 1,2 Gas/oil ratio Parameters GAS case LOW BASE HIGH Comments Water saturation

Recovery factor main phase

Recovery factor associated phase

Formation volume factor Bg

Gas/oil ratio Risk analysis: P1 P2 P3 P4 Pdiscovery Poil Pgas Poil and gas

0,6 0,4 1 0,9 0,22 0,22 NA 0,22 Volumes:

Uncertainty distribution

Pmin % Pbase % Pmax % MAIN PHASE ASSOCIATED PHASE

LOW BASE HIGH LOW BASE HIGH VOLUMES OIL case

OIL MBO 15,6 29,4 43,2 In place resources GAS BBO

Recoverable resources OIL MBO 4,1 13,6 18

GAS BBO VOLUMES GAS case

OIL MBO In place resources

GAS BBO Recoverable resources OIL MBO

GAS BBO

Estimated resource distribution (%) for mean volumes in blocks, existing licenses and open acreage.

Blocks: 211/19b 211/24c Norwegian

Licences: PL344

Open: 85 % 10% 5%



Table 3.4-1 Prospect summary Aladdin

3.4.3 Lead Ali Location of this lead is west of Aladdin, on the other side of Basin, See Figure 1.3-1. Hydrocarbon charging is considered unproblematic as proven by a large number of fields in the region. The hydrocarbon phase will probably be dependant on the degree of maturity of the Kimmeridgian Fm down-flank of the lead location. The lead is expected to be oil bearing. More detailed mapping to sort out trap integrity and its size is needed in order to firm up this lead. In addition there has to be acquired better seismic in area, in order to delineate the faults in the vicinity of the potential trap, as well as to validate any potential sealing faults in order to make trap function at lead location. The volumetric calculation is based on oil down to contact at 10080 ft MSL for all cases. This is due to the fact that a stratigraphic isolated sand body in the prospect position is assumed, which would be filled to its maximum extent. A variation in gross rock volume (+10 % to –20 %) has been applied in order to take into account the uncertainty in seismic interpretation and time to depth conversion. The uncertainty linked to sand content is described by the net/gross ratio; 55 % (45-60 %). The porosity used is 18 % (16-20 %) based on log interpretation of nearby wells. The permeability in this type of sand is normally not a constraining element. The Bo is set to 1.30 (1.35 –1.20) from field analogies. The recovery has been assumed to be 40 % (35-50 %) due to the size of the prospect and the uncertain size of the underlying aquifer.



Block: 211/24C Prospect outline (file name):

Lead name: Ali Lead name:


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Upper Jurassic Depth to top reservoir: 10020 ft MSL Anticipated number of development wells: 12 Lithostratigraphic level: Intra Kimmeridgian Fm sand, Unit 2 Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Stratigraphic General parameters LOW BASE HIGH Comments Area (km2) 0,23 0,23 0,23 HC-column (ft) 60 60 60 Rock volume (109 Sm3) 0,001 0,004 0,005 +10% / -20% uncertainty in seismic







0,6 0,4 1 0,9 0,22 0,22 NA 0,22

Estimate resource distribution (%) for mean volumes in blocks, existing licenses and open acreage.

Blocks: 211/24c

Licences:

Open: 100 %

Table 3.4-2 Prospect summary Ali

3.4.4 Prospect Jasmine Prospect Jasmine is located in the area around prospect Jasmine, see Figure 1.3-1. The leads are located within Brent Gp sandstones. Prospect Jasmine is presented in Figures 3.4-1, -2 and -3. All the Middle/Lower Jurassic prospects/leads are assumed to be structural traps sealed by Upper Jurassic and/or Lower Cretaceous shales. The prospect is sourced from deeply buried Kimmeridgian Fm shales. This has



proven to generate hydrocarbons in the Statfjord and Murchison Fields. As in the Statfjord Field the prospect is expected to be oil bearing. The main risk is linked to the definition of trap and presence and/ or distribution of reservoir sand at prospect location. The trap integrity is also considered a risk since faults could leak.



Block: 211/19B and 24C Prospect outline (file name):

Prospect name: Jasmine Lead name:


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Middle Jurassic Depth to top reservoir: 11240 ft MSL Anticipated number of development wells: 12 Lithostratigraphic level: Brent Gp Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Structural General parameters LOW BASE HIGH Comments Area (km2) 3 3 3 HC-column (ft) 730 730 730 Rock volume (109 Sm3) 1,12 1,4 1,54 +10% / -20% uncertainty in seismic







0,6 0,4 1 0,8 0,19 0,19 NA 0,19 Volumes:

Uncertainty distribution

Pmin % Pbase % Pmax % MAIN PHASE ASSOCIATED PHASE

LOW BASE HIGH LOW BASE HIGH VOLUMES OIL case

OIL MBO 310 582 931 In place resources

GAS BBO Recoverable resources OIL MBO 80 179 372

GAS BBO


Blocks: 211/24c Norwegian

Licences: PL344

Open: 95 % 5%

Table 3.4-3 Prospect summary Jasmine



3.4.5 Leads Lago, Lago South and Abu Three Middle Jurassic leads are identified. Leads Lago, Lago South and Abu are located in the area around prospect Jasmine; see Figure 1.3-1. The leads are located within Brent Gp. sandstones. The leads can be described as for prospect Jasmine; see Figures 3.4-4 to 3.4-9. Based on the structural depth map, the leads are expected to be located at various depths.

• Lead Lago; located at approximately 11240 – 11970 ft depth.

• Lead Lago South; located at approximately 11880 – 12420 ft depth.

• Lead Abu; located at approximately 2650-2750 m depth. No volumes are calculated on the leads, due to uncertainty in mapping at this stage, together with the limited sizes of these makes this exercise needed. However we have included the table listing up the parameters we assume will be valid for the three different leads in the acreage. These tables will indicate the GRV and parameters for reservoir together with risk parameters assumed for these leads. Block: 211/19 and 19B Prospect outline (file name):

Prospect name: Lead name: Lago


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Middle Jurassic Depth to top reservoir: 11960 ft MSL Anticipated number of development wells: Lithostratigraphic level: Brent Gp Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Structural General parameters LOW BASE HIGH Comments Area (km2) 0,38 0,38 0,38 HC-column (ft) 550 550 550 Rock volume (109 Sm3) 0,02 0,05 0,07 +10% / -20% uncertainty in seismic


Porosity 0,14 0,16 0,20 From log interpretation Reservoir thickness (ft) 90 90 90 Net/gross ratio 0,45 0,55 0,60 + 10% / -20 % uncertainty in sand cont. Parameters OIL case LOW BASE HIGH Comments Water saturation 30 25 20 Recovery factor main phase 35 40 50 Recovery factor associated phase Oil case only Formation volume factor Bo 1,35 1,3 1,2 Gas/oil ratio

P1 P2 P3 P4 Pdiscovery Poil Pgas Poil and gas

0,6 0,4 1 0,9 0,22 0,22 NA 0,22

Estimate resource distribution (%) for mean volumes in blocks, existing licences and open acreage.

Blocks: 211/19 211/19B

Licences:



Open: 60 % 40%

Table 3.4-4 Prospect summary Lago Block: 211/19 Prospect outline (file name):

Prospect name: Lead name: Lago South






0,5 0,3 1 0,9 0,13 0,13 NA 0,13


Blocks: 211/19

Licences:

Open: 100 %

South Table 3.4-4 Prospect summary Lago Block: 211/19B and 24C Prospect outline (file name):

Prospect name: Lead name: Abu








0,5 0,3 1 0,9 0,13 0,13 NA 0,13


Blocks: 211/19b 211/24c

Licences:

Open: 50 % 50%

Table 3.4-5 Prospect summary Abu The plays are sourced from deeply buried Kimmeridgian Fm shales. This has proven to generate hydrocarbons in the Statfjord and Murchison Fields. As in the Murchison and Statfjord Fields, the leads are expected to be oil bearing. The main risk is linked to the definition of trap and presence and/ or distribution of reservoir sand at lead locations, see Figures 3.4-7 to -9.

3.4.6 Leads Jafar and Sultan This leads are located in the southwestern part of block 211/19b and southeastern corner of 211/19 respectively; see Figures 1.3-1 and 3.4-19 – 3.4-27. The reservoir is expected to be sandstone lobes of Valanginian or younger age. Large amount of sandstone was eroded from the elevated parts of the Tampen Spur Province during the Early Cretaceous. Typical mounded facies patterns are recognized on seismic lines, associated with chaotic to transparent internal seismic pattern, which may be indicative of sandstone units being present. Gas clouds are seen above the structure. Very high amplitude is located around the upper part of the Shetland Fm. Other variations in amplitude are also seen around a potentially smaller structural closure, but this will probably relay on stratigraphic component. The lead is in a stratigraphic closure sealed by Lower Cretaceous shale. It is expected to have been sourced from the Kimmeridgian Fm and is expected to be oil bearing. Block: 211/19b Prospect outline (file name):

Prospect name: Lead name: Jafar


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Lower Cretaceous Depth to top reservoir: 9000 ft MSL Anticipated number of development wells: Lithostratigraphic level: Cromer Knoll Gp Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field



Trap type: Structural General parameters LOW BASE HIGH Comments Area (km2) 1,3 1,3 1,3 HC-column (ft) 50 50 50 Rock volume (109 Sm3) 0,03 0,07 0,09 +10% / -20% uncertainty in seismic


Porosity 0,16 0,18 0,24 From log interpretation Reservoir thickness (ft) 60 60 60 Net/gross ratio 0,50 0,65 0,70 + 10% / -20 % uncertainty in sand cont. Parameters OIL case LOW BASE HIGH Comments Water saturation 30 25 20 Recovery factor main phase 35 40 50 Recovery factor associated phase Oil case only Formation volume factor Bo 1,35 1,3 1,2 Gas/oil ratio Risk analysis: P1 P2 P3 P4 Pdiscovery Poil Pgas Poil and gas

0,5 0,3 1 0,8 0,12 0,12 NA 0,12 Volumes:

VOLUMES OIL case Estimate resource distribution (%) for mean volumes in blocks, existing licenses and open acreage.

Blocks: 211/19b

Licenses:

Open: 100 %

Table 3.4-6 Prospect summary Jafar Block: 211/19 Prospect outline (file name):

Prospect name: Lead name: Sultan


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Lower Cretaceous Depth to top reservoir: 8040 ft MSL Anticipated number of development wells: Lithostratigraphic level: Cromer Knoll Gp Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Structural General parameters LOW BASE HIGH Comments Area (km2) 0,35 0,35 0,35 HC-column (ft) 80 80 80 Rock volume (109 Sm3) 0 0,01 0,01 +10% / -20% uncertainty in seismic



0,3 0,3 1 0,8 0,07 0,22 NA 0,07



Volumes: VOLUMES OIL case


Blocks: 211/19

Licences:

Open: 100 %

Table 3.4-7 Prospect summary Sultan

3.4.7 Lead Genie This lead is located in the south eastern part of block 211/24c, see Figure 1.3-1. The reservoir is expected to be sandstone lobes of Valanginian or Younger age as for Leads Jafar and Ali, see Figures 3.4-28 and 3.4-29. Block: 211/24C Prospect outline (file name):

Prospect name: Lead name: Genie


Mapped by (company): Anergy Source rock, lithostrat: Kimmeridgian Fm Play: Seismic coverage: 90% 3D / 10% 2D Chronostratigraphic level: Upper Jurassic Depth to top reservoir: 8000 ft MSL Anticipated number of development wells: Lithostratigraphic level: Kimmeridge Fm Distance to existing/ planned infrastructure (km): 6-8 km Water depth: 470 ft Which infrastructure: Murchison Field Trap type: Stratigraphic General parameters LOW BASE HIGH Comments Area (km2) HC-column (ft) Rock volume (109 Sm3) +10% / -20% uncertainty in seismic



0,4 0,4 1 0,8 0,13 0,13 NA 0,13 Volumes:

VOLUMES OIL case Estimate resource distribution (%) for mean volumes in blocks, existing licences and open acreage.

Blocks: 211/24c Norwegian

Licences: PL344-NO

Open: 70 % 30%

Table 3.4-8 Prospect summary Genie



3.5 Time critical development of resources in 211/19b and 24c Block area

3.5.1 Introduction Production from the Norwegian sector of the Tampen Spur started with the Statfjord Field in 1979, the same year as production started from the Murchison Field. Since then a number of fields have been developed and are currently in production. With the present forward production profile the oldest Statfjord Field platform could be shut in before 2010. In order to extend the life of the Statfjord Field, Statoil as operator is evaluating the effect of an extensive gas production by reducing the reservoir pressure in the Statfjord Field to less than 100 bars (Rosenberg, 2003). The blow down is stipulated to begin in 2007 and continue until 2015-2020. A corresponding successful blow down has been commenced in the Brent Field in the UK sector (Coutts, 1997).

3.5.2 Pressure development in Tampen Spur Pressure measurements obtained from wells drilled prior to the start of production in the Norwegian sector of the Tampen Spur (Statfjord Field, 1979) defined a virgin regional pressure gradient (0.096 bars/m), regardless if the measurements are obtained from the intra Kimmeridgian Fm, the Brent Gp, the Statfjord Fm or the Hegre Gp, see figures below. The virgin regional pressure gradient forms the basis from which pressure depletion can be measured as response to production in the area. Pressures higher than the virgin pressure gradient do occur. Wells 34/4-3, 34/4-5 and 34/4-10R, which are drilled on a fault terrace facing the Marulk Basin, are overpressure. The high pressures in these wells can be explained by the following:

• Virgin pressure post-dating the extensive uplift of the Tampen Spur (1000-2000 m?), being preserved by an ideal cap-rock

• Pressure communication from the Marulk Basin province through the major fault bordering the Tampen Spur.

Pressure measurements obtained after the start of production from the Statfjord Field, which are below the virgin gradient, are interpreted as pressure depletion from local production. As an example the Brent Gp reservoir in the Statfjord Field experienced a rapid pressure decline from virgin pressure in 1979/1980 to 310 bars in 1986.





The immediate communication to the Statfjord East Field is illustrated here by the pressure measurements obtained from the predrilled wells on the Statfjord East Field, which are all draw-down to the level for the Brent Gp on the Statfjord Field. As demonstrated in above mentioned figures, the majority of wells drilled during 1992 shows pressure below the virgin gradient, which is a result of local production and/or communication with the Statfjord Field. Pressure depletion has been observed in both the intra Kimmeridgian Fm sandstones and the Brent Gps reservoirs, indicating good aquifer communication. The aquifer communication demonstrates the non-sealing nature of faults and/or communication through the intra Kimmeridgian Fm sandstones. Assuming that the Gullfaks Field (1988) has limited pressure influence towards the north the Statfjord Field was the only source for pressure draw-down until other fields came on stream in 1994/1995. For wells drilled after 1994/1995 the pressure draw-down represents a combination of production from the actual fields and pressure influence from the Statfjord Field. The Statfjord Field is therefore assumed to have a major influence on the pressure development in the Statfjord East Field, the Vigdis Field and the Borg Field. The ongoing Vigdis Extension development project as well as undrilled prospects/leads in communication with the intra Kimmeridgian Fm and Brent Gp common aquifer will also be influenced by future pressure development of the



Statfjord Field. The older Statfjord and Lunde Fm do not experience any pressure effect related to production from the intra Kimmeridgian Fm or Brent Gp reservoirs. The lack of communication confirms the presence of sealing faults.

3.5.3 Consequence of Statfjord Field pressure depletion Producing fields demonstrated to be in pressure communication with the Statfjord Field include the Statfjord East, Vigdis and Borg fields. Structures included in the Vigdis Extension development project are also assumed to communicate with the Statfjord Field. These fields have Brent Gp and/or intra Kimmeridgian Fm reservoirs and are characterized by under-saturated to strongly under-saturated oil, with no gas cap initially present. All fields are produced by water injection for pressure maintenance and displacement of oil towards the producers. Production is generally limited by well productivity, water cut or sand production. Assuming a comprehensive pressure depletion of the Statfjord Field, from 310 bars to less than 100 bars, the potential consequences for the fields/prospects in communication with the Statfjord Field are:

• Additional water injection requirement • Reduced well productivity, due to the decrease in the bottom hole pressure • Sand production, which will limit the well deliverability. • As pressure decreases secondary gas caps could be generated. The gas

caps will push the oil into the water zone, creating a potential loss of residual oil. Both mechanisms are important for prospects and fields early in their life cycle.

• The secondary gas cap will create a reservoir volume of 40 – 80 % of the original oil volume. If not produced, the secondary gas cap will provide pressure support by reducing the effect of the pressure depletion.

• Scaling problems so far not yet observed may occur. Pressure depletion may increase susceptibility to (halite?) scaling.

• Drilling of depleted reservoirs has a large effect on the fracture gradients, reducing the flexibility in well and completion design in light of present day safety regulations.

If communication between the Statfjord Field and the field in question is not too strong, pressure depletion can be prevented by additional injection of manageable volumes of water, requiring new injectors. With good communication, pressure depletion may be unavoidable and fields may require earlier shut-in. Several undrilled prospect and leads are identified within blocks 211/19b and 211/24c. The intra Kimmeridgian sandstones and Brent Gp prospects in aquifer communication with the Statfjord Field will be influenced by a depressurization of the Statfjord Field.



The presences of impermeable sealing faults have been demonstrated in several fields and drilled prospects in the Tampen Spur province (Nybakken, 1991). If the pressure in the Statfjord Field aquifer is reduced this will probably affect the sealing capacity of faults. When the pressure difference over a fault or fault zone exceeds a certain threshold, the seal may break and open for fluid flow. The Statfjord and Lunde Fms reservoir are so far not influenced by the Statfjord Field pressure draw down. However, if the differential pressure over a major fault is exceeded the seal may be broken and open for communication to the Statfjord and Lunde Fms reservoirs.

3.5.4 Summary To our knowledge the potential pressure draw-down on the Statfjord Field is still not decided. If the plan is initiated the remaining reserves in producing fields and resources left in undrilled prospects in aquifer communication with the Statfjord Field will be influenced by this depletion. It is therefore critically important that the remaining Prospectivity around the area of Statfjord and Murchison Fields is revealed and developed within a relatively short time span in order to avoid loss of reserves.

3.6 Reservoir technology The Aladdin prospect is approximately 4,4 km2, in which the Upper Jurassic reservoir will have a maximum thickness of 180 ft. The Statfjord North field Munin Fm reservoir has been assumed as analogue but with slightly reduced reservoir quality due to the increased reservoir depth. Reservoir pressure slightly above hydrostatic and medium density oil type with moderate GOR has been assumed. It has been assumed developed with 8 oil production wells located structurally high and 4 water injection wells located structurally low, but with the elongated geometry, the well spacing and location of the wells may be a challenge with respect to efficient reservoir drainage. Possible production limitations could arise due to limited pressure support, early water breakthrough and high water cut production. Wells and facilities should be designed for gas lift. The exploration well is assumed to be drilled in 2007. Production profiles are based on drilling of a total of 8 production wells and 4 water injection wells from the nearby Murchison field. The production start is assumed to be in 2008. The current oil reserves in the prospect are 13,6 MBO assuming a recovery factor of 40 % and maximum well production rates of 2000 Sm3/d. The ultimate recovery is based on a 9 year economic field life. The production profile for Aladdin is shown below;



OIL PRODUCTION PROGNOSIS - ALADDIN PROSPECT

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

2008 2009 2010 2011 2012 2013 2014 2015 2016

YEAR

Oil

Pro

du

ctio

n,

Sm

3/d

ay

The Jasmine prospect has put in the assumption that the exploration well is to be drilled in 2007, testing both the Upper Jurassic Aladdin and Middle Jurassic Jasmine prospects. Production profiles are based on drilling of a total of up to 16 production wells and 7 water injection wells from the nearby Murchison field. The production start is assumed to be in 2008. The current oil reserves in the prospect are 179 MBO assuming a recovery factor of 40 % and maximum well production rates of 8000 Sm3/d. The ultimate recovery is based on a 9 year economic field life. Below is the production profile for Jasmine prospect;



Oil Production Profile - Jasmine prospect

0

20000

40000

60000

80000

100000

120000

2008 2009 2010 2011 2012 2013 2014 2015 2016

Year

Oil

pro

du

ctio

n, S

m3/

day

.

3.7 Technological assumptions The proximity of the Murchison Field, (6-8 km), and available process and well capacity, makes this field the preferable tieback alternative. Another tieback alternative is Statfjord C platform, but with a distance of 8-9 km to the prospect, this development is a more expensive sub sea tieback. The Murchison development case assumes only minor topside modifications, e.g. to the inlet separator to allow for separate fiscal metering. Some removal work/demolition is assumed necessary in order to place new equipment package on the installation. For Aladdin prospect, a total of 8 production wells and 4 injection wells are assumed drilled from the Murchison Platform and a lateral distance of 6-8 km into the reservoir. Previous drilling operations in the Murchison field and other North Sea fields have proven that these types of long-reach wells are not difficult to drill. If only Jasmine prospect is to be developed, a total of 16 production wells and 7 injection wells are assumed drilled from the Murchison Platform with same distances as or Aladdin would be valid. It is expected that all other processing requirements are available from Murchison. Processing of production water and discharge/injection with other production water streams on Murchison has been assumed. The Murchison facility is designed with gas lift facilities and has export facilities for both oil and gas. The Murchison platform is old, and maintenance cost is escalating with time. The processing tariffs will therefore necessarily reflect this situation, and a maximum field life of 9 years is assumed.





3.8 Plan for exploration The framework for the duration and decision gates for the initial period of 2 years is presented in Section 1.4. The exploration programme outlined in this section explains the proposed work to be performed during the first 2 years after the award. The work will focus on the main geological uncertainties and to mature the exploration opportunities to drillable prospects. The intention is to drill a potential exploration well in the 3rd year. The proposed programme includes:

• Establish complete well and seismic database • Merge available seismic survey database covering the area • Perform a reprocessing pilot project to try to improve the Upper Jurassic

resolution • Reprocess parts of seismic database. • Seismic interpretation on existing and potential reprocessed data. • Seismic attribute identification and modeling (AVO analysis) • Rock physics modeling in order to evaluate the reservoir potential and fluid

content of the Upper Jurassic. • Perform pilot inversion study (survey wide and/or targeted) • Sequence - and seismic stratigraphy project focusing the Lower Cretaceous

and Upper Jurassic sequences • Pilot Basin modeling project to evaluate fluid distribution and pressure build-up • Evaluate slot availability on Murchison Platform and perform preliminary risk

analysis on long range drilling (6-8 km from Murchison Platform) • Prospect portfolio Management firm up.



4 EVALUATION OF BLOCK 211/11B The generally shaly Late Jurassic Viking Gp comprises the Heather and Kimmeridgian Fms. In the UK sector, thick sand-prone series of Late Kimmeridgian and Volgian age are referred to as the Brae Fm. These are alluvial fans of origin close to the East Shetland Platform boundary fault, but develop rapidly into deep marine fan systems reaching the Norwegian sector. It is also seen that local erosion of the Magnus High has provided shallow marine sediments to be deposited along the flank of the East Shetland Basin, Figure 5.1-4. The Late Jurassic sediments in the central parts of the graben continue without interruption into the Lower Cretaceous, while a marked unconformity/hiatus exists on the flanks of the graben. The Lower Cretaceous series are all referred to as the Cromer Knoll Gp and consist of shales with varying amounts of limestone. Towards the upper part of the series, a sandstone interval, the Ran Fm, may occur in relation to uplifted highs.The thickness of the Cromer Knoll Gp is determined by thermal subsidence related to the rifting of the Viking Grabens. The overlying Shetland Gp consists of shale with variable amounts of limestone, tending to become chalk towards the upper parts of the group. This section is not considered to have any exploration potential in the region. Cenozoicum During the period between the late Cretaceous and Eocene, an uplift caused by the early phases of oceanisation in the northern Atlantic Ocean, caused mobilisation and re-deposition of older deposits into the North Sea. The deposits are generally of different mass flow types and form very attractive targets for exploration in the central and southern parts of the Viking Graben. Internal sand / shale configurations within the Palaeocene series provide traps that are difficult to define without good geological and seismic control. Following the very successful exploration of the more obvious traps in these series, a second generation of discoveries are now being made in these intra-Palaeocene traps. The final stages of clastic deep marine deposition took place during the Eocene. The reservoir series of this age are geographically constrained and well defined. They are not considered to be a play in the area evaluated. By the end of the Oligocene and into the Miocene, a major transgression occurred in the North Sea. Increased relief in the hinterland, however, resulted in a large sediment supply to the region and the basin gradually filled up. Starting during the Miocene and increasing in frequency in the Pliocene and Quaternary, the influence of fluctuating ice caps (and thereby eustatic level) caused a thick series of glacio-marine sediments to deposit. The rapid subsidence and possible tilting of the study area may have had an influence on the migration and conservation of hydrocarbons in the traps of the area.



4.1.1 Exploration opportunities Three major plays are identified in these parts of East Shetland Basin area, of which one is proven to include commercial discoveries:

• Middle Jurassic sandstones (Brent Gp), sealed by Late Jurassic and Cretaceous shales and structured into tilted fault blocks by Late Jurassic extensional events, form a proven play in the region. The play is sourced from Upper Jurassic source rocks, mature in the entire graben area. This play forms an attractive target for exploration in the region.

• Late Jurassic sandstones, presently undefined as a formal stratigraphic unit,

are thought to provide a possible target for exploration along the western flank of the Mezosoic Structures. It is sealed and sourced by the Kimmeridgian Fm shales and trapping mechanisms may be combined structural and stratigraphical.

• A tentative lowermost Cretaceous play is proposed. The reservoir is believed

to have been eroded off the High and deposited in a sequence immediately overlying the Base Cretaceous Unconformity. Sealing will be by Lower Cretaceous shale and sourcing from the Kimmeridgian Fm.

4.2 Database

4.2.1 Seismic data At the moment Anergy Ltd does not have a seismic database in the area, but has screened TGS-Nopec data in this area.

4.2.2 Well data Anergy Ltd does not have access to any well data at the moment, and solely base its knowledge based on scout information available at the moment of application.





4.3 Identified exploration opportunities





































4.4 Reservoir technology and technological assumptions Since the exploration opportunities identified in the blocks are defined as leads no volumetric assessments or development scenario has been carried out. Therefore the reservoir technology and technological assumptions sections are excluded. Development of potential discoveries made in the blocks applied for will be evaluated in light of the future access capacity on the Magnus Field.

4.5 Plan for exploration The framework for the duration and decision gates for the initial period of 2 years is presented in Section 1.4. The exploration programme outlined in this section explains the proposed work to be performed during the first phase, which is the first 2 years after the award. The work will focus on the main geological uncertainties and to mature the exploration opportunities to drillable prospects. The intension is to reach a decision to drill a potential exploration well in the 3rd year. The proposed work programme include:

• Establish complete well and seismic database • Perform a reprocessing pilot project if needed • Seismic interpretation on reprocessed data set • Seismic attribute identification and modelling (AVO) • Inversion study (survey wide and/or targeted) • Rock physics project in order to evaluate the reservoir potential and fluid

content of the Early Cretaceous and Late Jurassic sequences Sequence - and seismic stratigraphy project focusing the Cretaceous and Jurassic

• Structural and reconstruction study in order to outline the accommodation space evolution during the Early Cretaceous and Late Jurassic



5 REFERENCES Aceca Geologica North sea Dynamic Facies Map Browser v 1.2a Castagna, J.P., Batzle, M. L. and Eastwood, R.L., 1985; Relationships between compressional-wave and shear-wave velocities in clastic silicate rocks, In: Geophysics, 50, pp 571-581. Coutts, S. D., 1997; Aqifer behaviour during Brent depressuration and the impact on neighbouring fields. Offshore Europe Conference, Aberdeen, Scotland, 9-12 September 1997. Deal home page; www.ukdeal.co.uk DTI home page; www.og.dti.gov.uk Durham, L. S., 2004; Subtle Traps Become New prey and subtle does not mean small in the North Sea. In: American Assiciation of Petroleum geologists Explorer, August 2004, p 14. Evans D., Graham C., Armour A. and Bathurst P., 2003; The Millennium Atlas: Petroleum Geology of the Central and Northern North Sea, The Geological Society of London. Fossen, H., 1992; The role of extensional tectonics in the Caledonides of the South Norway. Journal of Structural geology, Soc. Of London, Vol. 18, pp. 1033-1046.

Garrett S.W.1; Atherton T.2; Hurst A.3 m 2000; Lower Cretaceous deep-water sandstone reservoirs of the UK Central North Sea, Petroleum Geoscience, August 2000, vol. 6, no. 3, pp. 231-240(10)

Gabrielsen, R. H., Færseth, R. B., Steel, R. J., Idil, S. & Kløvjan, O. S., 1990; Architectural styles of the basin fill in the northern Viking Graben. In: Blundell, D. J. & Gibbs, A. D. (ed.) Tectonic Evolution of the North Sea Rifts. Oxford University Press, London, pp. 158-179.

Hanslien , S., 1987; Balder Geology of the Norwegian Oil and Gas Fields. In: A. M. Spencer et al., Graham & Trotman (Eds), pp. 193-201. Isaksen, D. & Tonstad, K. 1989; A revised Cretaceous and Tertiary lithostratigraphic nomenclature for the Norwegian North Sea. Norwegian Petroleum Directorate Bulletin, 5, 59 pp.



Landrø, M. and Strønen, L. K., 2003; 4D study of fluid effects on seismic data in the Gullfaks Field, North Sea. In: Geofluids, 3, pp 233-244. Millenium Atlas North Sea, 2003 NPD’s home page; www.npd.no Nybakken, S., 1991; Sealing fault traps, an exploration concept in a mature petroleum province; Tampen Spur northern North Sea, First Break vol. 9, no. 5, May 1991/209 Nøttvedt, A., Gabrielsen, R. H. & Steel, R. J., 1995; Tectonostratigraphy and sedimentary architecture of rift basins, with reference to the northern North Sea. Marine and Petroleum Geology, Vol. 12, No. 8, pp. 881 – 901 Roberts, A. M., Yielding, G. & Badley, M., 1990; A kinematic model for the orthogonal opening of the late Jurassic North Sea rift system, Denmark-Mid Norway. In Blundell, D. J. & Gibbs, A. D. (ed.) Tectonic Evolution of the North Sea Rifts. Oxford University Press, London, pp. 180-199. Rosenberg, Ulf-E., 2003; Statfjord can turn into a gas field, Stavanger Aftenblad, 16/12/2003 Stovas, A. and Landrø, M., 2004; Seismic analysis of Upper Jurassic sands based on well log information. An Anergy pilot study performed by NTNU, Trondheim. Sørensen, S. & Martinsen, B. B., 1987; A paleogeographic reconstruction of the Rotliegendes deposits in the Northeastern Permian Basin. In: Brooks, J. & Glennie, K. W. (ed.) Petroleum Geology of NorthWest Europe. Graham & Trotman, London, pp. 497- 509. Surlyk, F.,1990; Timing, style and sedimentary evolution of Late Paleozoic to Mesozoic extensional basins of East Greenland. In: Tectonic Events Responsible for Britain’s Oil and Gas reserves. Hardman, R.F.P. and Broks, J. (Eds.) Special Publication of the Geological Society of London, No. 55, pp. 107-126. Ursin, B., and Stovas, A., 2002; Reflection and transmission responses of a layered isotropic viscoelastic medium: In Geophysics, 67, pp307-323. Vollset, J. & Doré, A. G., 1984; A revised Triassic and Jurassic lithostratigraphic nomenclature for the Norwegian North Sea. NPD-Bulletin, 3, 53 pp.



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