Trap Oil Ltd. Relinquishment Report. for. Licence P Blocks 12/25a & 13/21b (Surprise & Nutmeg)

Transcription

1 Trap Oil Ltd Relinquishment Report for Licence P.1267 Blocks 12/25a & 13/21b (Surprise & Nutmeg) Relinquishment date: 21 December 2014

2 Contents 1. Header 2. Synopsis and introduction 3. Exploration activities 3.1 Seismic data 3.2 Wells 4. Prospectivity analysis 5. Preliminary FDP 5.1 Executive summary 5.2 Production forecast 5.3 Subsurface resource Geological context Structural geology Petroleum system Depositional model and reservoir description Geophysics Formation properties Reservoir fluid properties Uncertainty management Static geological model Property modelling Fluid contacts 5.4 In- place estimates 5.5 Dynamic reservoir modelling Fluid properties Rock properties DST Model controls Wellbore model 5.6 Dynamic modelling uncertainties Viscosity Water cut limit Low BHP limit Kv/Kh 5.7 Range of oil In- place recoverable volumes and factors 6. Benchmark Recovery Factors 6.1 Key issues and focus 6.2 Surprise analogues 6.3 Analogue recovery factors 6.4 Indicative recovery factors 7. Clearance 2

3 1. Header Licence number P1267 Licence round 23 rd Licence Effective date 22 nd December 2005 Licence type Traditional Block number 12/25a & 13/21b Operator Trap Oil Ltd Licensees Trap Oil Ltd 100% Work programme Firm commitments - shoot 18 sq km 3D seismic data and drill: - one well to a depth of 2700m or to the early Volgian - one well to 3300m or to the Heather Fm - one well to 2700m or to the Rotliegendes All working obligations have been fulfilled. 2. Synopsis and introduction Licence P.1267 (Blocks 12/25a & 13/21b) was awarded to Petro- Canada UK Limited and Reach Exploration (North Sea) Limited as a Seaward Production Licence in the 23rd Licensing Round with the Initial term commencing on 22 nd December In 2006 Petro- Canada farmed out 40% working interest to Samson North Sea Limited. In 2007 Reach Exploration (North Sea) Limited assigned 5% working interest to Reach Exploration (UK) Limited. Reach Exploration (North Sea) Limited subsequently farmed out its 5% working interest to First Oil Expro Limited. Well 13/21b- 7 (Surprise discovery) was drilled in The discovery is named after HMS Surprise, featured in the third historical novel in the Aubrey- Maturin series by Patrick O'Brian, first published in 1973 In 2008 Samson farmed out 5% working interest to First Oil Exploration (North Sea) Limited. Well 12/25-3 (Surprise appraisal) and well 12/25-4Z, Y (Nutmeg discovery) was drilled in In 2010 Samson North Sea Limited withdrew from the licence. Its working interest was acquired by Petro- Canada. Later that year Petro- Canada merged with Suncor Energy. In 2011 Suncor Energy UK Limited farmed out its entire equity to Dana Petroleum (E&P) Limited. Dana was acquired by KNOC. 3

4 In 2012 Trap Oil Ltd acquired Reach Exploration (UK) Limited s working interest. In 2013 Dana withdrew from the licence and Trapoil acquired its working interest. Trapoil also became operator of the block. Late in 2013 Trapoil sought and received from DECC a 12- month extension to the Second Term. This extension was granted to allow Trapoil to seek a farminee to develop the Surprise and Nutmeg discoveries. First Oil withdrew from the block in early 2014 leaving Trapoil as operator and sole licensee. Trapoil was unsuccessful in farming out the discoveries and consequently the blocks were relinquished, effective Exploration Activities 3.1 Seismic Data 3D seismic was acquired and processed by WesternGeco in 2006 as part of a Group shoot involving Petro- Canada (operator), Nexen and Ithaca. 3.2 Wells The key wells are as follows: 13/21b- 7 Surprise discovery (Petro- Canada, 2007) Oil was first discovered by Petro- Canada in well 13/21b- 7 in November The well tested a faulted 4- way dip rollover on the down thrown side of a large fault. The oil was present in two Early Cretaceous sandstone reservoirs, the Coracle and Punt. The well encountered a 186 ft column (FWL at 4,500 ft TVDSS) in the Coracle Sandstone Member reservoir, which tested partially biodegraded black oil (21.5 API, 104 scf/bbl and a viscosity of 28cp) at an average rate of 150 BOPD. The well also encountered a 72 ft oil column in the Punt Sandstone Member. Wireline samples indicated 34.5 API, 206 scf.bbl and a viscosity 1.75 cp. Well 12/25-3 Surprise appraisal (Petro- Canada, 2009) An appraisal well, 12/25-3, was drilled by Petro- Canada 1.6km to the south in August The well was to appraise the Punt reservoir in a separate culmination (Western Extension) and the Coracle reservoir on the flanks of the mapped closure. Both reservoirs were cored. The Punt horizon in well 12/25-3 was water bearing and not tested. Although the upper unit in the Coracle was oil bearing it was thin and poor in quality. The good quality Coracle sandstone was below the oil water contact. 4

5 Well 12/25-4Z, Y Nutmeg discovery (Petro- Canada, 2009) In September 2009 Petro- Canada drilled a deviated exploration well to the north of Surprise to test closures on the footwall of the main fault. This well intersected the top Coracle at 4,377 BRT (- 3,630.7 ft TVDSS) and 172 ft of gross oil column. No oil samples were recovered. The discovery was subsequently named Nutmeg. The deeper Punt reservoir in this well was wet. 4 Prospectivity Analysis A significant number of technical studies have been undertaken on the Surprise and Nutmeg discoveries. In anticipation of a successful appraisal/development well being drilled in the Nutmeg accumulation, a preliminary Field Development Plan was prepared with the assistance of OPES International Pty Ltd. The following is an extract from that document and captures the essence of the static and dynamic modelling that was undertaken. 5 Preliminary Development Plan 5.1 Executive Summary This is the development plan for the Surprise field, which is located in 90m of water in the Moray Firth Basin, Central North Sea, within Blocks 12/25a & 13/21b, in Licence P These are shown on the map to the right. This phase of the development proposes to exploit the three proven oil accumulations in the Early Cretaceous Coracle and Punt members of the Valhall Formation. They are shown in the figure to the right and detailed in the grid below, which also shows the confirmation wells. The gross likely recoverable resources are estimated at 13 MMSTB and a projected field life of some 10 years. 12/ /25-4y NUTMEG (Coracle) 13/21b-7 SURPRISE (Coracle) SURPRISE (Punt) The development is based on proven technology and standard equipment commonly used in the North Sea. The subsurface program calls for three wells equipped with electric submersible pumps and a water disposal well, which 5

6 also provides partial pressure support. Each well will be initially capable of producing more than 5,000BPD. The self- installing platform, complete with a gravity base for stability and limited storage, will be set on top of a 300,000- barrel concrete oil storage tank. This will provide flexibility for additional separation. Individual well risers connect to dry trees on the topside. The power and separation facilities consist of standard packages for 3- phase separation and be capable of 15,000 BLPD; 12,000 BOPD and 2,000 to 5,000 BPD per well. The concept is visualized by the schematic to the left. Accommodation is available for up to eight people. The platform is not intended to be normally manned except for the first year or for cargo offloading in packets of 200,000 barrels. Access for crew and materials will be by workboats via a dedicated landing deck. A helideck will be incorporated for emergency transfer only. The system is designed for additional wells and workovers, if required, and will have the capacity to accept third party oil tie back. 5.2 Production Forecast The table and plot included below are a summary of the most likely production forecast DATE BOPD BWPD MMBO 1-Jan Jan Jan Jan Jan Jan Jan Jan Jan Jan Jul

7 7

8 5.3 Subsurface Resource The Surprise/Nutmeg accumulations lie within a well- defined geological sequence close to an area with significant production history. Blocks 12/25a and 13/21b, in which the fields lie, are located in the Inner Moray Firth to the SW of the producing Captain oil field, 125 km north of Aberdeen in 90m water depth. The Inner Moray Firth is bounded to the west by the Helmsdale and Great Glen faults, to the north by the Wick Fault and to the south by the Banff Fault. It is characterised by NW dipping half grabens, controlled by SE dipping faults. The history development of the Moray Firth Basin is intimately connected with that of other major structural units in the North Sea, being the failed arm of the trilete rift system that included the Viking and Central Grabens Geological Context The reservoirs at Surprise and Nutmeg are part of the Early Cretaceous Cromer Knoll Group, Valhall Formation. The earliest is the Punt Sandstone Member, which is of Valanginian age and overlies the Kimmeridge Clay Formation (Error! Reference source not found.). The upper reservoir is the Coracle Sandstone Member, which is of Hauterivian to Barremian age. Both sandstone members are believed to be in the form of submarine fans derived from mass- flow deposits originating from the hinterland of the Scottish Highlands and Shetland Platform to the west and north- west. This is shown in the stratigraphic column below. Generalised early Cretaceous lithostratigraphy 8

9 The Coracle sandstone is oil bearing in both Surprise and Nutmeg while the Punt sandstone is hydrocarbon bearing only at Surprise. The Surprise accumulation comprises a faulted 4- way dip closure located in the hanging wall of the southern bounding fault to the western extension of the Halibut Horst while the Coracle accumulation is a dip closed, fault bounded structure in the footwall of the same fault Structural Geology The Surprise field is located in the Smith Bank Graben, which is a sub- basin in the Inner Moray Firth Basin (see below). It is a late Jurassic basin formed by extensional rifting, which produced a series of tilted fault block and horst features, including the Smith Bank High, West Bank High and West Halibut Horst, which are separated by a series of grabens. Surprise is on trend with the southern bounding fault of the West Halibut Horst, it is a small rollover feature on the downthrown side of the fault that is probably related to minor inversion. Nutmeg is on the up- thrown side of the fault and has a tilted fault block type structural configuration. Wick Fault Caithness Ridge Sinclair High Surprise & Nutmeg Area West Halibut Horst Captain Surprise Phoenix Blake Beatrice Dee Ross Banff Fault 12 km. Moray Firth structural elements Most of this extensional rifting ceased by the earliest part of the Lower Cretaceous, switching to post rift thermal subsidence, which continued into the Cenozoic. Late Tertiary uplift has produced a strong regional dip to the east, causing heavy erosion. This has resulted in the Upper Cretaceous Chalk sub- cropping the sea floor in the Surprise area, with progressively younger formations sub- cropping to the east. 9

10 5.3.3 Petroleum system The Moray Firth area is dominated by the Late Jurassic and Early Cretaceous petroleum system, sourced from the Kimmeridge Clay Formation. In addition, a Middle Jurassic play with a lacustrine Devonian hydrocarbon source is present in the Inner Moray Firth, as exemplified in the Beatrice Field. The deeper Devonian source gives rise to a more paraffinic and waxy oil than that sourced from the Kimmeridge Clay Depositional model and reservoir description The Coracle and Punt reservoirs consist of massive turbidite channel/basin floor fan deposits grading to lower energy heterolithic fan margin deposits towards the top of the units. The depositional fabric of the Coracle and Punt sands strongly controls reservoir quality. The Coracle reservoir has a high level of lithics and silts, which are more ductile and, therefore, the reservoir exhibits a relatively high degree of compaction and reservoir quality reduction. The Punt reservoir is typically cleaner and quartz grain supported. Although the Punt has a lower porosity, it has a similar average permeability to the Coracle. Both units display a high degree of secondary porosity due to feldspar dissolution, which is not fully accessible by the heavy oil yielding higher Sw values than would otherwise be expected Geophysics The seismic data over the Surprise structure is of moderate quality; the structure is adequately defined at Coracle and Punt levels. The Surprise structure is not very sensitive to depth conversion uncertainty, as it is a simple structure with a relatively uniform overburden and is constrained by two wells. Only one set of depth surfaces was used for the geocellular model Formation properties The characteristics of the two identified reservoirs are as follows:- Reservoir Level: Reservoir pressure Reservoir Temperature Reservoir Level: Reservoir pressure Reservoir Temperature Coracle (Nutmeg and Surprise) Bar (1965 psi) at 4,450ft TVDSS 55 C (131 F) Punt (Surprise) Bar (2445 psi) at 5,510ft TVDSS 63.3 C (146 F) Reservoir fluid properties The fields contain two different crudes. Crude oil properties to be used for design are as follows:- 10

11 Reservoir Level Coracle (Nutmeg and Surprise) Reservoir Depth 4, ft TVDSS (Total Vertical Depth Sub Sea) Oil Gravity (API) 21.5 Dynamic Viscosity (cp) C Wax Content 4.1% Wax Appearance Temp 28 C Reservoir Level Punt (Surprise) Reservoir Depth 5, ft TVDSS Oil Gravity (API) 34.5 Dynamic Viscosity (cp) C Wax Content 8.4% Wax Appearance Temp 34 C Hydrocarbon and Formation water compositional data is detailed in Appendix Uncertainty management No probabilistic analysis has been undertaken. Rather, a number of deterministic cases have been generated and run to test the sensitivity of resource size to a number of reservoir and fluid properties Static geological model A 3D static reservoir model was constructed to assess the volumetrics associated with the Surprise and Nutmeg discoveries. The main objectives of the modelling process were: Construct a structural framework over the area of interest (AOI), including the horizons and faults interpreted by seismic evaluation. The AOI includes the Surprise and Nutmeg discoveries Model the geometry and structure of the Coracle and Punt reservoirs over the AOI for determination of reservoir connectivity and geometry Populate the model with properties based on the petrophysical interpretation to characterise the reservoirs for volumetric assessment Property modelling From the petrophysical analysis, Volume of clay (Vcl) and effective porosity (PHIE) were populated through the grid via kriging. Seismic attributes were extracted with the aim of guiding the property distribution; however, there was no discernible relationship between the two sets of data, hence the use of kriging. With the use of 40% Vcl cut- off, a simple sand/shale facies log was generated at each well. These facies were then populated throughout the grid using sequential indicator simulation. 11

12 Using the same settings as Vcl, a net reservoir flag was also populated through the grid based on 12% porosity and 40% Vcl cut- offs. With values below 12% set as undefined, effective porosity was distributed through the model via kriging, as mentioned previously. Permeability relationships for each reservoir were derived from the core data of the 12/25-3 well, as illustrated below. From these, logs were generated before a correlation factor of 0.7 was used to populate the property through the grid via co- kriging with porosity. A kv/kh ratio of 0.1 was assumed Fluid contacts Log analysis and analysis of the RFT data indicate an OWC at 4,447 ft SS for the Coracle section in Surprise (see below). For the Punt, two different contacts are observed in the two separate accumulations intersected by the 12/25/3 and 13/21b- 7 of 5,523 and 5,513 ft SS respectively b Y WATER OIL

13 Fluid contacts At Nutmeg, oil is only present in the Coracle. A clear contact is seen at 3,803 ft SS (see below) and this is used for both zones. Saturation distribution for the model was populated by generating a single function that honours both the lab data and logs. Although this function is not asymptotic at S w =S wir and S w =1, it fits the data in the range of interest with acceptable precision. The function and the matches are shown in the figure below. 13

14 5.4 In- place estimates The resultant STOIIP from the model is 47.2 MMSTBO at Surprise (32.5 in Coracle, 14.7 in Punt) and 23.7 MMSTBO at Nutmeg (all Coracle). The majority of the oil is contained with the better quality Coracle 3 zone, as can be seen in the following breakdown of volumes: Base Case (MMSTB) SURPRISE CORACLE 32.5 NUTMEG 23.7 PUNT (13/21B- 7 Region) 9.9 PUNT (12/25-3 Region) Dynamic reservoir modelling The aforementioned static model was then exported without up scaling to allow reservoir simulation to be carried out. 14

15 5.5.1 Fluid properties PVT properties for the fluids in the model were based on samples taken from the Coracle and Punt reservoirs, via DST and MDT, respectively, at the Surprise 13/21b- 7 well. No samples were taken from the 12/25-4Y well at Nutmeg. The following table summarises the analysis of these fluids by Corelab: For Nutmeg, it was assumed the oil was similar to the Coracle at Surprise. However, based on a higher observed temperature at Nutmeg (from logs), the viscosity was reduced slightly to 25 cp. Gas properties were not required (other than a constant solution gas- ratio) because the reservoir pressure does not fall below bubble point Rock properties Core samples from the 12/25-3 well were used by Corex to perform SCAL. Relative permeability and capillary pressure data measurements were taken. The resultant curves were normalised, with consistency in the data allowing a single set of best fit curves to be generated for, and applied to, the Coracle and Punt, as illustrated below. Relative Permeability - Coracle vs Punt Kr Sw Krw - Punt Kro - Punt Krw - Coracle Kro - Coracle 15

16 OWC s were defined, as described in the Static Modelling section, with equilibrium regions incorporated to accommodate the number of different contacts. The saturations generated in the static model were imported as a SWATINIT array, with endpoint scaling switched on to allow quiescent initialisation. The layer (31) below the Coracle member was set as inactive to isolate the Coracle and Punt, which are clearly not in communication. The oil in place of the dynamic model was within a few percent of the value calculated from the static model. The grid below shows the Coracle in both Nutmeg and the Surprise. It is important to note that the transition zone in Surprise Coracle is the culprit for the exceptionally low recovery factor. Carter- Tracy analytical aquifers were attached to both the Punt and Coracle reservoirs and faults were considered to be sealing DST The DST results in 13/21b- 7 Coracle were closely matched by a model, which reflected the geological interpretation and generated a permeability of 220md and a skin of - 1. A summary of the DST interpretation is presented in Appendix 6. It is interesting to note the model permeability derived from porosity transform had to be increased by a factor of 3.5 to match the well drawdown. This, in fact, confirms the results of the DST interpretation. For this reason the factor was applied to permeability throughout, consistent with a single cap curve equation for all reservoirs, as discussed below Model controls After initial concept screening runs, a base case production forecast was generated for the following scenario: Start date of 2017 (Initial schedule at time of construction slipped now by a year) Horizontal wells (with ICD's) targeting the Surprise Coracle (SC1), Surprise Punt (SP1) and Nutmeg Coracle (NC1) 16

17 Skin factor of +3 assigned to each producer to account for likely inclusion of gravel pack or sand screen Maximum rate for each well of 10,000 BLPD Maximum field rate of 12,000 BLPD Minimum BHP of 1,000 psia for Coracle wells, 1,300 psia for Punt well Well limit of 95% WC Field limit of 90% WC Minimum field rate of 500 BOPD Produced water reinjected into the Coracle at Nutmeg Carter- Tracy aquifer of 1,500 md attached to both aquifers All faults assumed to be sealing It was assumed that all wells will be produced via ESP. No surface facilities or network pressure losses were included in the modelling. Significant improvements in recovery were obtained by utilising horizontal wells over vertical wells and by placing the injector at Nutmeg instead of one of the Surprise reservoirs. The presence of the numerical aquifer had only a minor effect on recovery Wellbore model The use of ICD's was mimicked by incorporating wellbore hydraulics and segmented wells. For this work, well diameter and internal diameter of the flowing completion string is considered to be 8½ and 4½, respectively. The absolute roughness of the completion is assumed to be ft (0.6 mm). A case was run with a higher roughness (3 mm) as sensitivity to imperfections, for which the BHP distribution is illustrated below. With virtually no difference in recovery, the former was selected for the base case. 17

18 Variable skins were used along the well segments to regulate liquid influx and prevent early water breakthrough, thereby mimicking ICD s. The minimum skin was as per the base case (S=3), with extra skin applied based on KH of the cells. The resultant change in segment inflows is illustrated below, using NC1 as an example. As can be seen, the initial horizontal well has a very high influx at the heel (left), which results in premature water- breakthrough. By adjusting the skins, a much more uniform profile is generated, as would be expected with the installation of ICD s. 18

19 The diagram above illustrates how the segmented wellbore looks in the reservoir. 5.6 Dynamic modelling uncertainties Uncertainty management focused only on the dynamic model. The following sensitivities were tested Viscosity As described previously, the base case model assumes the viscosity of the oil at Nutmeg to be similar to that of Surprise, only slightly less due to a higher recorded temperature during wireline logging. However, no fluid sample has been taken from this reservoir, leaving its true value as an uncertainty. Nearby fields were reviewed to see what range of viscosities could be expected. Using values from the Captain, West Wick and Blake fields to the east (shown below), all of which produce from the Coracle and/or the overlying Captain Formation, it was decided to test Nutmeg viscosities (at reservoir conditions) of 11 cp, 45 cp, 85 cp and 100 cp. The effect on recoveries is illustrated overleaf. The worst- case scenario is a reduction of ~20% 19

20 to 10.9 MMSTBO Water- cut limits As the model was still producing ~1,000 BOPD at the end of the run, it was decided to see what sort of boost in recovery was possible by increasing the field water- cut limit to 95%. An additional 2 MMSTBO is recovered, albeit over an extra seven years. 20

21 5.6.3 Low BHP limit Upon advice from the service company, the original BHP limit, designed to stay above bubble point so that gas breakout would not affect the ESP s, was pessimistic and the pumps would be able to handle the GOR s present in the field. Therefore, an additional run was carried out with BHP limits of 400 psia for SC1 and NC1 and 500 psia for SP1. A similar recovery was achieved, but with significant early acceleration of the oil K v /K h The k v /k h ratio was also tested as a sensitivity. Decreasing the vertical permeability actually improved the recovery of the model as it delays the water encroachment from below the wells. 21

22 5.7 Range of oil In- place, recovery volumes and factors The results of the static and dynamic modelling of Surprise and Nutmeg are as shown below: Oil In Place Ultimate Recovery Recovery Factor (MMSTB) (MMSTB) (%) SURPRISE CORACLE % Base Case NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Nutmeg Viscosity =11 cp NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Nutmeg Viscosity =45 cp NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Nutmeg Viscosity =85 cp NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Nutmeg Viscosity =100 cp NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Kz / Kx = 0.05 NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Kz / Kx = 0.01 NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Kz / Kx = NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Kz / Kx = NUTMEG % PUNT (13/21B- 7 Region) % SURPRISE CORACLE % Low BHP in Wells NUTMEG % PUNT (13/21B- 7 Region) % 22

23 6. Benchmark recovery factors The Captain oil field provides subsurface analogue for the Surprise field with regards to recovery factors. In Surprise, where the viscosity range is 1.7 to 29 cp, the recovery factors are estimated to be between 6% and 40% of the oil in place. In the Captain field, however, the relative values are 47 to 88 cp and 17 to 40 %. Clearly a significant upside potential exists in the recovery factor of Surprise. 6.1 Key issues and focus The critical factors to consider in benchmarking the Surprise recovery factor against analogue fields are: Subsurface issues such as reservoir quality and aquifer support. Development issues such as well numbers and backpressure. 6.2 Surprise analogues Surprise s main Early Cretaceous Coracle and Punt Formation sands are not dissimilar to those seen in the nearby Captain producing field. Although the latter exhibits significantly better permeability, its viscosity is also much higher. In that context the recovery should be comparable. The Captain field is located in Block 13/22a in the Western Moray Firth, in a water depth of 340 ft. The reservoirs at Surprise are part of the Early Cretaceous Cromer Knoll Group. The earliest is the Punt Sandstone Member, which is of Valanginian age and overlies the Kimmeridge Clay Formation. The upper reservoir is the Coracle Sandstone Member, which is of Hauterivian to Barremian age. Both sandstone members are believed to be in the form of submarine fans derived from mass- flow deposits originating from the hinterland of the Scottish Highlands and Shetland Platform to the west and north- west. The producing Lower Cretaceous, Upper and Lower Captain sand units within Captain field provide good analogue with recovery against varying levels of aquifer support. 6.3 Analogue recovery factors The nearby Captain oil field provides insight and context to the calculated recovery factor expected for the Surprise project. Captain field recovery factor for producing Early Cretaceous and the Late Jurassic reservoirs range from 20-40%. The principal reservoirs in the Captain field consist of turbidite sandstones of Lower Cretaceous age comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section, the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenber- corrected permeability averaging 7 Darcies and porosity in the range of 28-34%. 23

24 The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at 2,700 ft TVDss 6.4 Indicative recovery factors Field performance of producing reservoirs predominantly in the Coracle and Punt units suggests that, on the basis of early water breakthrough, a recovery range from Surprise simulation of 17-40% is strongly supported. 6.5 References 1. The Captain field, Block 13/22a, UK, North Sea, S.J Pinnock et al, p 431, Clearance Trap Oil Ltd confirms that DECC is clear to publish this relinquishment report. 24