TAQA Bratani Limited & INEOS Clipper South C Limited

Transcription

1 [1] TAQA Bratani Limited and INEOS Clipper South C Limited UKCS Licence Block 211/27e

2 [2] Table of Contents 1. Licence Information Licence Synopsis Work Programme Summary Database Seismic Wells Production Darwin (NW Hutton) Field Prospectivity Update Field Description Darwin (Static) Field Modelling Darwin (Dynamic) Field Modelling Further Technical Work Undertaken Resource and Risk Summary Conclusion Clearance... 22

3 [3] 1. Licence Information Licence Licence Round Block Licence Type Licence Operator Licence Partners 25th Round 211/27e All () Traditional TAQA Bratani Limited TAQA Bratani Limited (50%) INEOS Clipper South C Limited (50%) 2. Licence Synopsis Block 211/27e (Figure 2a), licence 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 Fairfield acquired licence in the 25 th round on 12th February The full licence expires on 12 th February The second exploration licence term is due to expire on 31 st January In January 2012 TAQA farmed in to all three Fairfield Darwin/NW Hutton licences, P184, P474 and in return for a firm drilling programme, with the anticipation that 3 well penetrations would be drilled in Q2/Q 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 1 st January In October 2015 Fairfield was sold to INEOS Clipper South C Limited (INEOS) who then held 50% of all three licences P184, P474 and.

4 [4] INEOS Capital INEOS Capital INEOS Capital Figure 2a: Location map showing the Licence coverage with respect to other Darwin (NW Hutton) Licences P185 and P474.

5 [5] TAQA farmed-in to the 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 TAQA Farm-in History North West Hutton Field (NWH) Undeveloped Discoveries ( Darwin North ) Exploration Area ( Darwin South ) 2012 / 13 planned Exploration wells 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) Well Block Depth tvdss 211/27e-13 (SHE Seg 1 Block): ft 211/27e-13z (SHW Seg 3 Block): ft 211/27a-14 (A34 Nose Block): ft Figure 2b: Map showing areas considered prospective by TAQA in Both wells 211/27a-13 and 211/27a-13Z lie within Licence. 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 ). INEOS decided to take over TAQA s share in Licences P184 and P474. Both TAQA and INEOS agreed to relinquish Licence.

6 [6] 3. Work Programme Summary Licence 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. PGS esb09 Seismic Survey Acquisition area PHASE 2 PHASE 1 Fairfield New Seismic Esb09 area Licence P184 Licence P474 Fairfield Seismic Re-processing area Licence PHASE 3 Figure 3: Map showing areas of reprocessed and new seismic and wells drilled to fulfil licence obligation. Wells are marked as yellow circles.

7 [7] 4. Database This document represents a relinquishment report for the recent Darwin phase of redevelopment 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 licence requirement Fairfield reprocessed an area of the old 1979/1984 Amoco surveys covering block 211/27e, in 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 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 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 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 [8] Possible to pick both Top and Base Brent and resolve small faults Higher frequency content allows resolution of Brent over crest Improved resolution of deep & steeply dipping reflectors Figure 4.1a NW Hutton cross-section from the 1979&1984 merged seismic compared to the 2009 PSTM seismic. Type Line

9 [9] 2009 esb09 PSTM processing Data supplied courtesy of PGS and TGS 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 esb09 PSDM processing Figure 4.1b Comparison of the 2009 PSTM processed 3D seismic data set with the 2014 PSDM re-processed 3D seismic data. Type Line.

10 [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,. 211/27a /27e /27e-13z 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.

11 Oil 3 Oil 2 Oil 2 1 [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 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. 2012/2013 Darwin Exploration Drilling Results 211/27a-14 (A34 Nose) 211/27e-13z (SHW) 211/27e-13 (SHE) Upper Ness MNS Etive GR Den Res W a t e r Tarbert MDT pressures W a t e r W a t e r 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 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 were considered dry.

12 [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 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 [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 ft 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 [14] 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 -14 NWH DARWIN -13z / 13 well locations 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 multioriented faults with relatively small fault offsets. Different oil pools in Upper and Lower Brent. Figure 5.1a Darwin Structural Complexity

15 [15] Etive Reservoir Quality Isochore map based on Etive thickness 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.

16 [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 ). 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 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 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 inplace values, pre-production. There is a significant reduction in Darwin STOIIP values post 2012/13 drilling campaign.

17 [17] Predrill Postdrill , ,7 17,7 18, 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 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 [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 redevelopment opportunity in two key areas the NE area of NW Hutton and the A34 (Western area), both of which lie out with the 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 [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 [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 17,7 18,7 1 Postdrill 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 redevelopment 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 licence.

21 [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.

22 [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.