TAQA Bratani Limited and INEOS Clipper South C Limited · TAQA Bratani Limited & INEOS Clipper South C Limited Relinquishment Report May 2016 P1634 In 4Q 2012, Fairfield and TAQA

[1]

TAQA Bratani Limited & INEOS Clipper South C Limited Relinquishment Report May 2016 P1634

TAQA Bratani Limited and INEOS Clipper South C Limited

UKCS Licence P1634

Block 211/27e

Relinquishment Report

May 2016

[2]


Table of Contents

1. Licence Information ......................................................................................................................... 3

2. Licence Synopsis ............................................................................................................................. 3

3. Work Programme Summary ........................................................................................................... 6

4. Database ........................................................................................................................................... 7

4.1 Seismic ........................................................................................................................................ 7

4.2 Wells .......................................................................................................................................... 10

4.3 Production ................................................................................................................................. 12

4.3.1 Darwin (NW Hutton) Field ................................................................................................... 12

5. Prospectivity Update ..................................................................................................................... 13

5.1 Field Description ...................................................................................................................... 13

5.2 Darwin (Static) Field Modelling .............................................................................................. 16

5.3 Darwin (Dynamic) Field Modelling ........................................................................................ 17

6.0 Further Technical Work Undertaken ......................................................................................... 18

7.0 Resource and Risk Summary .................................................................................................... 20

8.0 Conclusion .................................................................................................................................... 21

9.0 Clearance ...................................................................................................................................... 22

[3]


1. Licence Information

Licence P1634

Licence Round 25th Round

Block 211/27e All (P1634)

Licence Type Traditional

Licence Operator TAQA Bratani Limited

Licence Partners TAQA Bratani Limited (50%)

INEOS Clipper South C Limited (50%)

2. Licence Synopsis

Block 211/27e (Figure 2a), licence P1634 was considered by TAQA Bratani Limited (TAQA)

and Fairfield Cedrus Limited (Fairfield) to contain a southern extension of the North West

Hutton Field (NW Hutton) known as Darwin.

Darwin is the field name attributed to the same Brent reservoir oil accumulation that was

previously developed as NW Hutton field by Amoco and subsequently BP, (licences P184,

(Block 211/27a) and P474 (Block 211/27c)). The P184 and P474 licences were acquired by

Fairfield from BP in 2009.

Fairfield acquired licence P1634 in the 25th round on 12th February 2009. The full licence

expires on 12th February 2035. The P1634 second exploration licence term is due to expire

on 31st January 2017.

In January 2012 TAQA farmed in to all three Fairfield Darwin/NW Hutton licences, P184,

P474 and P1634 in return for a firm drilling programme, with the anticipation that 3 well

penetrations would be drilled in Q2/Q3 2012. Two additional wells (contingent upon

success/development options), were included in the carry subject to an overall cost cap.

TAQA earned 50% equity in the Darwin and NW Hutton licences as a consequence of the

farm-in, with Fairfield initially remaining as Operator and retaining the remaining 50% equity.

As part of the terms of the farm-in deal, TAQA assumed Operatorship of the Darwin and NW

Hutton licences on 1st January 2013.

In October 2015 Fairfield was sold to INEOS Clipper South C Limited (INEOS) who then

held 50% of all three licences P184, P474 and P1634.

[4]


Figure 2a: Location map showing the P1634 Licence coverage with respect to other Darwin

(NW Hutton) Licences P185 and P474.

INEOS Capital

INEOS Capital

INEOS Capital

[5]


TAQA farmed-in to the P1634 acreage on the basis that:

There were still undeveloped discoveries in the central region (Darwin North)

There were unexplored fault blocks (Darwin South) that could be oil bearing,

dependant on reservoir properties and Brent-Brent fault seal, Figure 2b.

There was still potential for production from the southern sector of NW Hutton

Figure 2b: Map showing areas considered prospective by TAQA in 2012. Both wells

211/27a-13 and 211/27a-13Z lie within Licence P1634.

Subsequent to the Farm-in TAQA/Fairfield drilled three exploration wells which revealed that

Brent-Brent fault seal does not work in Darwin South and that the Brent reservoir rock

properties (particularly the Etive permeability) were much poorer than predicted. This

combined with extensive reservoir modelling and prediction showed that despite there still

being up to 500MB oil in place across NE Hutton/Darwin, it was divided up into multiple,

very small, discreet, fault bound accumulations.

In February 2016 TAQA decided that as a result of the above studies it wished to relinquish

its share of all three Darwin/NW Hutton licences (P184, P474 and P1634). INEOS decided

to take over TAQA’s share in Licences P184 and P474. Both TAQA and INEOS agreed to

relinquish Licence P1634.

TAQA Farm-in History

• 2012 FOCUS: ‘Darwin South’ blocks: proving up potential by drilling 3 wells in previously unexplored southern fault blocks, down-dip from the former NWH Field

• Key themes:

• Brent-Brent fault seal

• Depth to top reservoir (Brent Group)

North West Hutton Field (NWH)

Undeveloped Discoveries (‘Darwin North’)

Exploration Area (‘Darwin South’)

2012 / 13 planned Exploration wells

Well Block Depth tvdss

211/27e-13 (SHE Seg 1 Block): 11300 ft

211/27e-13z (SHW Seg 3 Block): 12100 ft

211/27a-14 (A34 Nose Block): 11800 ft

[6]


3. Work Programme Summary

Licence P1634 was acquired by Fairfield in 2009 on the basis of a work programme that

included

(re)processing 37 sq kms of 3D seismic

the drilling of one commitment well to a depth of 3400m or 50m into the Lower

Jurassic Dunlin Group.

Both of these commitments have been fulfilled. Seismic was reprocessed as well as new 3D

seismic data over all three licences being purchased from PGS in 2009, Figure 3.

Two Brent exploration wells 211/27e-13 and 13z were drilled in 2013 and were plugged and

abandoned.

Figure 3: Map showing areas of reprocessed and new seismic and wells drilled to fulfil

P1634 licence obligation. Wells are marked as yellow circles.

PHASE 1

PHASE 2

PHASE 3

Fairfield

New Seismic

Esb09 area

Licence

P184

Licence

P474

Licence

P1634

Fairfield Seismic

Re-processing area

PGS esb09 Seismic SurveyAcquisition area

[7]


4. Database

This document represents a relinquishment report for the recent Darwin phase of re-

development study/appraisal work. Although the Darwin accumulation includes part of the

previously developed NW Hutton field, NW Hutton has already been fully abandoned with all

wells plugged and the platform removed (by the then operator, BP).

4.1 Seismic

As part of the P1634 licence requirement Fairfield reprocessed an area of the old 1979/1984

Amoco surveys covering block 211/27e, in 2009. However at the same time PGS were

acquiring a large non-proprietary seismic survey that covered the NW Hutton and Darwin

area which Fairfield bought in to, Figure 3. The newly acquired PGS esb09 3D survey was

processed using Pre-Stack Time Migration (PSTM). It showed a vast improvement in

seismic data quality compared to the previous reprocessed Amoco 1979/84 data, Figure

4.1a. There was clearer resolution of the reservoir section particularly over the crest, both

Top and Base Brent being interpretable, and fault imaging was significantly clearer,

particularly at depth. The 2009 PSTM seismic was used throughout the initial Fairfield/TAQA

Darwin subsurface study which commenced in 2009.

The Top Brent surface and most of the key faults were picked on the 2009 PSTM 3D seismic

volume and formed the basis of the NW Hutton/Darwin field mapping. However Fairfield

concluded that the Base Brent resolution was improved on a PSI(+50deg) pre-stack

inversion volume generated from the 2009 PSTM in 2011.

Faults were still difficult to interpret and position with a high degree of confidence. In

2013/14 the esb09 seismic data was re-processed to Pre–Stack Depth Migration (PSDM)

with the objective of better fault definition and a new interpretation was created. A pre-stack

inversion of the PSDM dataset was also generated in 2014.

In general, the reprocessed PSDM dataset shows increased quality compared to the original

PSTM dataset and allows a more consistent well to seismic tie across the Darwin Field, such

that Base Brent could be picked equally well on the reflectivity volume, Figure 4.1b. The

depth conversion method remained unchanged and it was observed that the final 2014 Top

and Base Brent depth maps were typically within 50ft of the older (PSTM) interpretation.

Also the PSDM fault pattern that emerged was very similar to the PSTM interpretation which

increased confidence in it. It was concluded that there was no need to update the structural

fault model.

[8]


Figure 4.1a NW Hutton cross-section from the 1979&1984 merged seismic compared

to the 2009 PSTM seismic. Type Line

Improved resolution of deep & steeply dipping reflectors

Possible to pick both Top and Base Brent and resolve small faults

Higher frequency content allows resolution of Brent over crest

[9]


Figure 4.1b Comparison of the 2009 PSTM processed 3D seismic data set with the

2014 PSDM re-processed 3D seismic data. Type Line.

2012 esb09 PSDM processing

2009 esb09 PSTM processing

The uplift between the PSTM and the PSDM processing at this scale is not dramatic.

However there is considerably better fault plane resolution and a better signal to noise

ratio which gives increased confidence in the structural mapping in such a faulted area.

Data supplied courtesy of PGS and TGS

[10]


4.2 Wells

In 2012/13 three new wells were drilled by TAQA/Fairfield into separate fault bound

compartments on Darwin, adding to the 17 exploration and 53 appraisal and development

wells (plus 18 sidetracks) originally drilled by BP/Amoco in support of NW Hutton, .

Figure 4.2a Darwin/NW Hutton field map showing locations of the NW Hutton

development wells, since abandoned. Of the 53 wells, 12 were water injectors

converted from earlier producers. The red dashed circle shows the maximum drilling

reach from the original, now fully abandoned NW Hutton platform. The red well

symbols were original exploration or appraisal wells. The 3 new TAQA/Fairfield wells

drilled in 2012/13 are highlighted.

211/27a-14

211/27e-13z

211/27e-13

[11]


In 4Q 2012, Fairfield and TAQA simultaneously drilled wells 211/27e-13 and 211/27a-14,

Figure 4.2a. The 13 well and its subsequent sidetrack 13z met the well requirement of the

P1634 licence commitment.

The well objectives were:

to evaluate the reservoir potential and presence of hydrocarbons in the southern

area of the Darwin field that lay beyond the NW Hutton field, Figure 2b,

to test whether Brent to Brent fault seal works in this area

to determine the OWC(s) in each fault block

The well results are summarised in Figure 4.2b and below.

Figure 4.2b Exploration well results 211/27a-14, 211/27e-13 and 211/27e-13z

Well 211/27e-13 drilled a downthrown fault block in the south east of Darwin. The

well found water bearing sands indicating that the proposed Brent to Brent fault seal

scenario had failed and that the Darwin South potential highlighted in Figure 2b only

extended into Block SHW Seg 3. The other blocks in P1634 were considered dry.

• 211/27e-13 water-bearing (fault seal

failure)

• 211/27a-14 & 211/27e-13z oil bearing in

upper parts of the Brent only (i.e. faults

blocks not full of oil, as predicted pre-drill)

• 211/27a-14 oil bearing in Upper and Lower

Ness, with separate oil columns above

and below the Mid Ness Shale (MNS),

illustrated by pressures and PVT

• 211/27a-14 and 211/27e-13z Upper Ness

oil columns in pressure communication

• Etive downgraded significantly. NB: Very

hard to distinguish oil versus water bearing

Etive, as formation so tight

Upper Ness

Etive

211/27a-14 (A34 Nose) 211/27e-13z (SHW) 211/27e-13 (SHE)

W

a

t

e

r

Oil

2

Oil

2

Oil

3

MNS

GR Den Res

MDT pressures

1

Tarbert

W

a

t

e

r

W

a

t

e

r

2012/2013 Darwin Exploration Drilling Results

[12]


211/27e-13 was sidetracked to a second downdip target fault block. The 13z well

penetrated fully oil bearing Tarbert and Upper Ness with porosities in the 14-18%

range. This was above pre-drill expectations. The Lower Ness and Etive were water

bearing and the Etive very tight. The well was plugged and abandoned.

4.3 Production

4.3.1 Darwin (NW Hutton) Field

There has been no production from the Darwin Field during the TAQA/Fairfield operating

period. The NW Hutton Field was produced by BP Amoco from 1983 to 2002, during which

time c.125 mmbbls of oil (~17% of initial oil in place) were extracted, Figure 4.3.

Figure 4.3 NW Hutton Field: summary of Production Phase

Decommissioning of NW Hutton Field started in 2003 and has been completed.

No development plan has been produced or submitted for the Darwin area.

[13]


5. Prospectivity Update

5.1 Field Description

The North West Hutton oil field lies approximately 10 km to the east of TAQA Bratani’s

Northern North Sea operated assets of Cormorant North/ South and Pelican.

The Darwin field is a channelised Brent sequence 400-450ft thick which has been

extensively faulted, Figure 5.1a. Different fault blocks have different oil water contacts.

The Tarbert is generally present as a relatively thin fine grained, silty and bioturbated

sandstone package. The Ness is a variable thick sequence of multi-stacked fluvial channels

commonly isolated from each other. The Etive below is around 40 ft thick in the north with a

fining upwards profile (fluvial channel setting) yet over 100 ft thick with a clean aggradational

profile (a more traditional shoreface setting) in the south. Hence the Etive and Ness

isochores are inverse, with thin Etive equating to thick Lower Ness, Figure 5.1b. This

resulted from period of uplift post Etive deposition causing erosion of the Etive in the crestal

area – typical ‘incised valley-fill’ topography. Etive quality varies significantly with depth and

facies type, having significantly poorer permeability and porosity over the Darwin South area,

Figure 5.1b

The Rannoch is a progradation of a linear shoreline system. There is a prominent shale

interval which cleans up into silty sandstone. The Broom is poorly sorted, with sandy and

pebbly deposits and commonly cemented. Much of the Rannoch and Broom is non-reservoir

or lies below the OWCs.

Structurally, the Brent generally deepens towards the south and west and there is a general

reduction in that direction in both porosity and permeability in all units. There is also a clear

degradation effect on permeability with depth due to the presence of illite.

[14]


NW Hutton: Large oil columns, fault seal on relatively simple NE-SW oriented faults with large offsets.

Darwin Exploration Area: Smaller oil columns, mostly downthrown fault traps with fault seal on multi-

oriented faults with relatively small fault offsets. Different oil pools in Upper and Lower Brent.

Figure 5.1a Darwin Structural Complexity

• The former NW Hutton Field is structurally complex

• All the coloured blocks illustrated right indicate separate oil

columns with different pressures. e.g. NWH West (blue),

NWH Central (yellow), NWH East (orange), QWest (dark

green)

• Oil pools are separated by faults with different offsets. Red

lines indicate full Brent offset (safe). Blue lines indicate Brent-

Brent fault juxtaposition. Fault seal can be a valid sealing

mechanism in this area. However, the presence of some dry

wells (-13) indicates this is not always the case

-13-13z

-14

NWH

DARWIN

2012 / 13 well locations

[15]


Figure 5.1b Variation in Etive thickness, permeability and porosity

Initial interest in the area to the south of the NW Hutton development was triggered by the

down-dip 211/27a-11 exploration well in licence P184, Figure 4.2b, which discovered oil in

the Tarbert and Ness. The well was not tested due to operational complications. The area

(outwith NW Hutton) was anticipated to contain over 500 mmbbls of oil. Based on analogue

studies of NW Hutton well performance it was thought possible of supporting a new, fixed

jacket development that might also access additional recovery from the abandoned NW

Hutton field.

Results from the three 2012/13 exploration wells changed this. Well 211/27e-13 was dry,

and the other two penetrations -13z and 211/27a-14 encountered only partial oil columns.

The 211/27e-13 result was interpreted as indicating that hydrocarbon trapping by Brent-on-

Brent fault seal had failed, and thus STOIIP potential of other relatively shallow fault blocks

to the south-east was severely limited; hydrocarbons would have continued migrating up-dip

to the Hutton oil field. Reservoir quality in the (thick) Etive section of all three penetrations

was also very poor, effectively limiting Darwin to an Upper Brent/ Lower Ness development

only.

Etive Reservoir Quality

Isochore map based on Etive thickness

[16]


Drilling results in 2012/13 were disappointing Figure 5.1c. Pre and post drill expectation

results for the three prospects are shown below. From an almost 200 MMbbls STOIIP

potential, the wells delivered less than 50MMbbls STOIIP (only 22MMbbls in P1634).

Failure of the shallowest target, 211/27-13 eliminated a number of other associated

prospects, with the consequence that a TAQA pre-drill target STOIIP for all Darwin blocks of

659 MMbbls fell to 209 MMbbls STOIIP post drill.

Figure 5.1c ‘Before and After’ STOIIP in the three drilled prospects. (Prospects SHE

and SHW in Licence P1634 detailed in the red box)

5.2 Darwin (Static) Field Modelling

Throughout the re-appraisal period a variety of static models were constructed to honour NW

Hutton production data, and the changing surfaces, fault patterns and geological

understanding as new data arrived. The modelling work was performed in conjunction with a

full interpretation of the (NW Hutton) open and cased hole logs (PLT’s) as well as a review of

the core data. Post drilling incorporation of the 2012/13 well results enabled this work to be

updated with both sets of results described below.

A full field Petrel™ static model covering the entire Brent sequence over NW Hutton and the

P1634 area was constructed. The STOIIP distribution across the field by sector is shown in

Figure 5.2. It should be noted that the figures quoted for the NW Hutton blocks are initial in-

place values, pre-production. There is a significant reduction in Darwin STOIIP values post

2012/13 drilling campaign.

[17]


Figure 5.2 Mid-case STOIIP distribution by sector pre and post 2012/13 drilling results.

5.3 Darwin (Dynamic) Field Modelling

Distribution of oil in place remained a principal uncertainty for Darwin/NW Hutton. Recourse

was made to a full-field Eclipse simulation model delivered to TAQA by Fairfield Energy in

2012.

Unfortunately even an optimistic scenario of a combined NW Hutton/ Darwin fixed platform

development delivering 88 mmboe oil and associated gas via 34 wells returned poor project

economics; the mid and downside cases were NPV negative. Various subsea development

schemes were also investigated, and similarly yielded poor economic returns even when

combined with development of other hydrocarbon accumulations identified in the area.

As a result, a decision was taken by TAQA in August 2013 to suspend further development

studies.

It was felt that the challenges to achieving economic development of the NW Hutton/ Darwin

areas were substantial and included:

18

13

2

8

12

9

16 17

14

15

4

3

10

1

116

15

14

13

4

3

129,12

5

5116

16,717,718,7

22

8

1

Pre-

drill

139

83

67

180

7828

3413

11

21

28

20

0

145

Post-

drill

56

61

205

2940

117

1213

139

83

67

180

78

145

1223 847

7

[18]


Relatively deep (11,500 ft TVDSS) Brent reservoir succession, resulting in generally

poorer reservoir quality, higher drilling costs and limited step-out of platform wells;

Complex structure and faulting, particularly in Darwin, leading to potential reservoir

compartmentalisation and attendant upward pressure on number and/ or completion

complexity of development wells;

Concerns related to longevity, operational efficiency, gas compression capacity (for

gas lift) and power generation capacity of potential host platforms (to a subsea

development of NW Hutton/ Darwin);

Potential formation and precipitation of barium sulphate and calcium carbonate

scales, decreasing well productivity and increasing need for preventative and/ or

remediation treatments (which could be particularly costly in subsea wells).

In 2014 Fairfield carried out a further static modelling study incorporating the latest 2014

PSDM fault pattern and facies based reservoir heterogeneity that had been significantly

understated before. It is likely that the degree of lateral connectivity is still over-estimated

however, which makes prediction of the habitat of remaining oil difficult and adds significant

uncertainty to the optimum placement and likely performance, of future NW Hutton

production and injection wells. Fairfield concluded that there remained an attractive re-

development opportunity in two key areas – the NE area of NW Hutton and the A34

(Western area), both of which lie out with the P1634 licence.

6.0 Further Technical Work Undertaken

Further subsurface technical work outside the original licence remit includes

Purchase of new non-proprietary seismic covering all three licence area (PGS 2009)

Pre-stack seismic inversion of the PSTM, (SIP 2011) and PSDM seismic volumes

(CGG 2014)

Post stack depth migration (GTX 2013/14)

Core description of NW Hutton (Ichron 2010)

Darwin Fault Study (Badley 2011)

NW Hutton (Fluid Inclusion Analyses 2011)

Integrated core description and analysis of Pelican and Darwin wells in order to

develop a methodology for modelling permeability –(Dundas 2014)

An extensive review of all NW Hutton data including well by well analysis of core,

open hole and cased hole log data, well performance data and PVT data.

[19]


Several static models built using Petrel™ (versions reworked as additional data such

as new seismic became available). These all covered the entire Darwin / NW Hutton

field area and the undeveloped area to the south.

A range of original in-place hydrocarbon volumes was computed.

Several full field and sector dynamic models were built using Eclipse™ and history

matched using the NW Hutton production, pressure and fluid data. Models were then

run in forecast mode to predict the future production potential. Inclusion of the history

phase of NW Hutton meant that account was taken of oil and gas volumes produced

during 1983 – end 2002 when the field was abandoned.

Notional field development plans were envisaged including a large platform including

Pelican Field, small subsea tie-back and FPSO.

Different export routes were considered including the Cormorant North and Dunlin

platforms. These concluded that the cost and impact of utilising these older facilities

could not be justified. Additionally, there have been several market reviews of

FPSO’s in terms of physical needs, availability and cost

A spread of production profiles were generated coupled with economic metrics in the

form of barrels of oil per well.

[20]


7.0 Resource and Risk Summary

Initial resources for NW Hutton and Darwin were re-evaluated following the drilling of the

three exploration wells in 2012/13. The post-drill STOIIP (i.e. prior to any NW Hutton

production) was significantly reduced from 1225 MMSTb to 847 MMSTb – a reduction of

over 30%, Figure 7.1.

Figure 7.1 Mid-case STOIIP distribution by sector post 2012/13 drilling results.

Further static modelling work incorporating the new seismic fault interpretation and updated

geological understating from core analysis etc. in 2014 concluded that a small focussed re-

development might be possible of two key areas. The A14/A15 area (sector 3) of the ‘old’

NW Hutton Field, and/or the ‘greater’ A34 region (sector 16-18) of Darwin, which both had

slightly better predicted recoverable volumes. However both these areas lie outside the

P1634 licence.

15

14

13

4

3

129,12

5116

16,717,718,7

22

8

1

Post-

drill

139

83

67

180

78

13

145

28

20

0

11

21

28

34

847

13

2

8

12

9

16

14

15

43

10

1

116

57

18

17

[21]


8.0 Conclusion

The greater Darwin (including NW Hutton) total BRENT sequence of reservoir horizons is

still thought to contain in excess of 500 MM bbls of oil in-place plus associated gas.

However, this accumulation is spread across multiple and hydraulically isolated vertical units

with notably differing reservoir properties (of pressure, porosity, permeability and water

saturation) coupled with a high areal density of partial and wholly pressure sealing fault

boundaries. These combine to distribute this remaining in-place oil volume into potentially

hundreds of discrete or semi-autonomous compartments in a 3 dimensional matrix.

There is insufficient natural pressure support in this reservoir system to facilitate sustained

oil production without also employing continuous water injection. Given the

compartmentalisation of this field, this tends to result in the need for a large number of

development wells (both producers and injectors) and a development scheme which is

capable of managing large produced volumes of water at a time when the oil production is

modest and declining and there will be a need to employ artificial lift system, e.g. gas lift, in

the wells.

It has not been possible to find a development design which would be economically viable to

pursue. While it is possible to identify a few well targets with modest resources of <2 MM

bbls/development well, these are insufficient to justify both the well costs and infrastructure

costs and consequently development still proves to be sub-commercial at this time.

TAQA and Fairfield concluded in 2015 that no further work on the NW Hutton/Darwin

licences can be justified. TAQA has given notice to withdraw from Licences P184 and P474

and both TAQA and INEOS wish to relinquish P1634.

[22]


9.0 Clearance

TAQA and INEOS confirm that the Oil and Gas Association is free to publish the contents of

this report and that all third party ownership rights (on any contained data and/or

interpretations) have been considered and appropriately cleared for publication purposes.

The 2009 ESB09 PSTM seismic survey lines are held under licence and are the property of

PGS and TGS.

Documents

TAQA Bratani Limited and INEOS Clipper South C Limited · TAQA Bratani Limited & INEOS Clipper South C Limited Relinquishment Report May 2016 P1634 In 4Q 2012, Fairfield and TAQA