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Licence Number: P.1645 commenced 12th November 2008 Licence Round: 25th Licence Type: Traditional Block Number: 9/8b Operator: EnQuest (60%) Partners: Norwegian Energy Company (Noreco) UK Ltd 40% Work Obligation: Obtain and reprocess 200km2 of 3D Seismic data.

Fig 1: Licence P1645

Introduction

Block 9/8b straddles the faulted boundary between the East Shetland Platform in the

northwest and the Beryl Embayment to the southeast. The Bruce Field is located just

a few kms to the southeast in blocks 9/8a and 9/9. The heavy oil discoveries at

Bentley, Bressay and Kraken are in Upper Palaeocene sands within 9/2&3 and are

located 5-15km north to northwest of Block 9/8b (Figure 1). A technical evaluation

of 9/8b, Licence P1645 involved seismic interpretation of a 2009 Pre-Stack Time

Migrated dataset between November 2009 and January 2010.

P1645

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Database

Seismic

Figure 2 shows the seismic datasets that were available for the interpretation. Most of

the work was carried out on the Pre-Stack Time Migrated volume processed between

May and November 2009. Over 200km2 were reprocessed to fulfil the seismic work

obligation on this licence.

Fig 2: seismic data sets over P1645 9/8b study area.

The Bruce 3D dataset provided useful well ties and the two TGS-Nopec 1988 regional

2D lines provided invaluable ties into Bentley and Kraken as well as understanding of

the Palaeocene stratigraphy. In the southwest corner Conoco Phillips 2D lines were

preferred to the Western 1984 2.5D data because of concerns about data quality and

also because field data for the Western survey has been lost and therefore could not be

reprocessed.

Considerable time and effort was expended in procurement of the PSTM dataset as it

resulted from the pre stack merge of BP’s HEB97 3D survey with the 1992 Bruce 3D

to the southeast. Some CGGVeritas spec 3D was also merged post stack to provide

coverage in the northwest corner (Figure 3).

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Fig 3: seismic data sets over P1645 9/8b study area.

The quality of the final dataset is good in the Tertiary section, less so in the Jurassic

where Pre-Stack Depth Migration is really needed to image the complex structure.

Wells

Figure 2 highlights the wells used in the technical evaluation. Approximately 25 wells

were incorporated in the study.

Geophysics - Well Ties

The synthetic tie for the Palaeocene section at well 9/8-5 shows a reasonable tie to the

final seismic stack data using a 25Hz UK ‘Normal Polarity’ zero phase wavelet

(Figure 4).

Fig 4: 25Hz UK ‘Normal Polarity’ zero phase wavelet

this, plus the character of the seafloor response suggests the data is correctly zero

phased. However, the synthetic ties are not generally of very good quality. It is

believed that many of these early (1970’s to 1980’s) wells suffer from very poor log

quality and this makes reliable synthetic ties a problem. This is illustrated in Figure 5

where the deep section of 9/8-5 gives a poor correlation value (r) mainly because of

an erratic sonic trace producing strong synthetic amplitudes in the Upper Cretaceous

which are not present in the 3D seismic data.

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Fig 5: 9/8-5 erratic sonic trace giving a poor correlation

Interpretation

Nine Eocene and Palaeocene horizons were picked to define structural and

stratigraphic traps. The correlation with regional stratigraphy is illustrated in Figure 6

which is taken from a study on the Bentley and Bressay discoveries by Underhill

(2001).

Fig 5: 9/8-5 regional correlation (Underhill 2001).

Mapping The main prospective intervals identified in the block application were the

Upper Palaeocene Dornoch (Hermod and Teal) sands and the Lower Palaeocene

(Maureen) Sands.

Dornoch Sands

Initial mapping concentrated on extending the Upper Dornoch Sand pick south from

the Bentley area into 9/8b. The east-west regional tie line (Figure 6) shows clearly the

pronounced clinoform build up at Bentley between the pink and orange picks.

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Fig 6: 9/8-5 East/West Regional Seismic Line.

The oil in Kraken (well 9/2-1) is within slightly older sands though there are minor

shows in the Upper Palaeocene Sands. The southward correlation of the Bentley sands

is shown in Figure 7.

Fig 7: 9/8-5 North/South Regional Seismic Tie Line

The clinoforms are less obvious in this orientation as the line runs across the front of

the prograding beds. The higher amplitude parallel bedded appearance of this interval

may be indicative of a transition to a deeper offshore setting at the base of the

prograding slope. The Top Dornoch TWT map (Figure 8) shows that there is little in

the way of structural closure. This is unlikely to be a southward extension of Bentley

as the OWC there occurs at c.1.150 secs.

South North

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Fig 8: Top Dornoch TWT map Line

Fig 9: 9/8-5 East/West Seismic Tie Line (See Fig 8).

However a line across the shape (Figure 9) shows very similar internal architecture to

Bentley and it seems that this is part of the same sedimentary system. Figure 9 also

illustrates a quite well developed erosive based channel as described by Underhill

from Bressay, but there is no significant compactional roll-over on the top surface.

Hermod Sands

Shows in the Hermod Sandstone at well 9/8-3 and 9/9c-16 suggest the possibility of

stratigraphic trapping in the base of slope equivalent to the Upper Dornoch Sands at

Bentley. An east west line between wells 9/8-4 and 9/9c-16 reveals a low angle

prograding wedge containing Hermod Sands in the 2 wells. A shaley interval between

the Hermod and underlying Teal sands may act as a bottom seal to any potential

stratigraphic trap as the Hermod sand pinches out updip to the north and west.

A pinchout trap might exist northwest of well 9/8-4, which is dry, but inspection of a

north south line connecting the Hermod interval with the Dornoch Sand build up

south of Bentley shows that there is very likely to be sand to sand contact across the

fault so the seal integrity is highly questionable.

Teal Sands

No internal architecture has been identified within the Teal sand section where the

amplitudes tend to be generally lower; however it seems likely that these sands would

also be in updip communication with the Bentley Dornoch system.

West East

Fig 9

Bentley Feature

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Maureen Sands

The top of the Maureen sands has been mapped in the hanging-wall of the main fault.

These Lower Palaeocene sands were not deposited on the footwall. A number of very

small closures can be seen against the main fault (Figure 10) but these are extremely

high risk as they depend on fault seal.

Fig 10: Small closures along main fault

Some strong amplitude anomalies are also seen at Top Maureen but these do not seem

to conform to structure. Furthermore the very strong trough at the Top Maureen

suggests a hard kick which is unlikely to indicate hydrocarbon presence (Figure 11).

Fig 11: Small closures along main fault

The amplitude seems to be greatest where an antithetic system of faults is best

developed, also shown in Figure 11. The most likely cause of these high amplitudes is

shown at well 9/8-4 where a series of high velocity calcite cemented sands (actually

shown as limestone on the composite logs) tie to the high amplitudes in the seismic.

This contrasts with the low amplitudes and poorly cemented Maureen Sand at well

9/9c-16. It is therefore concluded that the amplitude anomalies are the result of calcite

cementation around the antithetic faults south of the main platform fault. This is also

likely to explain the amplitudes seen in the Hermod interval which do not conform to

structure and which are in a similar position with respect to the faulting.

South North

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Lower Eocene and Balder Formation Sands

Sand sections at Lower Eocene (9/8b-12, -13 and 9/8-5) and Balder (9/8-5) offer the

possibility of stratigraphic traps as there is no significant structural closure at either

level. Unfortunately amplitude extractions do not show any depositional patterns

which could define potential sand pinchouts.

Jurassic

Fig 12: Base Cretaceous Unconformity TWT map

The Base Cretaceous Unconformity TWT map (Figure 12) shows a significant area of

closure in the hanging-wall of the main fault, just updip of well 9/8-4. The wells

closest to this fault (9/8-3, -4, 9/8b-12, -13 and 9/9c-16) contain Kimmeridgian age

sands directly below the Base Cretaceous. For this reason the pick is variable in

character; it is usually carried in a peak, but locally in a trough where the acoustic

impedance of the Jurassic exceeds that of the Cretaceous section. The mapped closure

represents the top of a potential trap with top seal provided by Upper Cretaceous

Chalk and marl and side seal provided by the fault itself. These seals are a major

element of risk on the potential accumulation as the top seal is thin and the chalk is

prone to fracture near the fault; and directly above that are the Lower Palaeocene

sands. The fault itself provides a likely leakage route as it has undergone movement at

least as recently as the Eocene, The potential for shale smear is low as both sides

contain much coarse clastic material, typically Devonian Old Red Sandstone in the

footwall and Jurassic and Palaeocene sands in the hanging-wall.

Mapping beneath the Base Cretaceous is very difficult. Radical differences in the

deep stratigraphy between wells 9/8-3 and 9/8-4 are not imaged at all well by the

seismic, which was reprocessed primarily for Tertiary targets. Even the Base

Cretaceous reflection is unclear downdip from 9/8-3.

However, a top Heather pick has been made just west of well 9/8-5 where a high

amplitude event was observed. Unfortunately this feature has minimal (<20ms)

closure to the north as shown by Figure 30. In any case the Heather section in 9/8-5 is

predominantly shale even though part of it is labelled Bruce Sandstone on the cross

section. No further intra Jurassic mapping was attempted.

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Volumetrics and Risking

This was carried out in REP using lognormal distributions for the hanging-wall

closure evident at Base Cretaceous Unconformity level. A gas case was run to reflect

the situation at Bruce where there is a very large quantity of gas with some oil

produced as condensate. As the fault plane was not explicitly mapped geometry

factors of 80% and 50% were used to subtract the GRV underneath the fault plane for

the P10 and P90 cases respectively. The Net/Gross range was centred on well 9/9c-16

which has c.30% good quality sands. The porosity range encompassed Upper Jurassic

sands at Magnus as well as those seen in the Middle Jurassic of Bruce.

Assuming constant average velocity of 2394 m/s:

Spill point 2485 m (2.075s)

Area: 5.1 x 106 m2

GRV P10 368 x 106 m3 (80% geometry factor)

P90 239 x 106 m3 (50% geometry factor)

(Geometry factors applied to estimate GRV above main

platform boundary fault plane)

N/G P10 50% - P90 10% (9/9c-16 well)

Porosity: P10 24% - P90 10% (Bruce, Magnus)

Hydrocarbon

Saturation:

P1 0.95 – P99 0.8 (Bruce)

Bg: P50 237 P90 210

Gas in place:

P90 29 bcf

P50 75 bcf

P10: 188 bcf

Mean 96 bcf

There is a very low Chance of Success (COS) mainly due to the fault seal requirement

and also the very thin topseal which comprises chalk and marl. The seal is especially

critical for a gas trap with a vertical column height of 250m. Other risks would be the

reservoir quality (sands in 9/8-4 are very silty) and source effectiveness as the

Kimmeridge clay in the immediate vicinity is immature.

Overall the modest size of the potential gas in place Figure (mean 96bcf) and the very

low COS do not make this an attractive structure.

Reservoir Presence 90% Effectiveness 60%

Trap: Presence 80% Effectiveness 10%

Source: Presence 100% Effectiveness 70%

COS: 3%

Summary and Recommendation

No viable structural or stratigraphic traps have been identified. Some areas of high

amplitude within the Tertiary section are not conformable with structure and are

believed to result from calcite cementation associated with the main platform

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boundary fault system. A possible trap has been mapped at Base Cretaceous level but

this is extremely high risk as it depends on down-faulted seal and a very thin Upper

Cretaceous chalk and marl topseal.

Clearance

EnQuest and co-venture partner give permission to DECC to publish this report.