Relinquishment Report. for. Licence P1578. Block 13/22b including Phoenix Discovery

Transcription

1 Relinquishment Report for Licence P1578 Block 13/22b including Phoenix Discovery Top Phoenix Reservoir level Depth ft TVDSS Phoenix N March 2015 Licence P.1578 Relinquishment Report - March 2015 Page 1 of 16

2 Contents 1. Licence Information 3 2. Synopsis 4 3. Exploration & Development Activities 4 4. Phoenix Resource Analysis 8 5. Analysis of Other Potential Resources Clearance 16 Page Tables Table 1 Table 2 Table 3 Table 4 Table 5 Table 6 Table 7 Details of Licence Award Phoenix Total Gas & Condensate in Place (assuming flash separation) Recoverable Sales Gas & Condensate Resources for Phoenix Development via a nearby host field and infrastructure Probabilistic Modelling Inputs and Outputs for Phoenix Deep Lead Geological Chance of Success Assessment for the Phoenix Deep Lead Probabilistic Modelling Inputs and Outputs for Ashes Lead Geological Chance of Success Assessment for the Ashes Lead Figures Figure 1 Figure 2 Figure 3 Figure 4 Figure 5 Figure 6 Figure 7 Figure 8 Figure 9 Geographic Setting of UK Block 13/22b and the Phoenix Discovery Block 13/22b Time Structure at Top Phoenix Reservoir (ms) North-South Geoseismic Section to Illustrate Structural Character of Phoenix Petrophysical Interpretation of Phoenix Discovery and Associated DST Results Phoenix Depth Structure Structural Cross-section Phoenix Geocellular Model Phoenix Reservoir Correlation Optimal Horizontal Well Design Determined for Phoenix Ashes Lead at Top Phoenix Reservoir Level Licence P.1578 Relinquishment Report - March 2015 Page 2 of 16

3 1. Licence Information Licence Number P1578 Round & Start Date 25 th Licence Type Traditional Licence Start Date 12/02/2009 Block 13/22b Equity Holding Chrysaor (CNS) Limited 100% Work Program Summary Drill or Drop Commitment Drill one well to 3625m or 150m below the top Phoenix reservoir, whichever is the shallower Relinquishment 11/12/2014 Table 1 Details of Licence Holding 13/22d 13/22b 13/22c CAPTAIN PHOENIX BEATRICE ROSS BLAKE ATLANTIC/CROMARTY St.Fergus. Figure 1 Geographic Setting of UK Block 13/22b and the Phoenix Discovery Licence P.1578 Relinquishment Report - March 2015 Page 3 of 16

4 2. Synopsis Licence P1578 was awarded to Chrysaor Limited on 16 March 2009 with a start date of 12 February The basis of the Chrysaor application for block 13/22b was the Phoenix gas condensate accumulation discovered in 1990 which Chrysaor believed to be commercially developable as a single well tieback to existing infrastructure provided it could reach satisfactory transportation, processing and tie-in agreements. The accumulation, which is well defined on 3D seismic, is considered to be adequately appraised by the existing discovery well and associated production tests. Technical studies over the course of the P1578 licence strongly supported the technical feasibility of Phoenix development as a single well tieback but it has proved impossible to reach an acceptable commercial agreement with any of the local infrastructure owners. In part this reflects the relatively high CO 2 and liquids content of the produced fluid, which is particularly challenging for a small gas accumulation. Chrysaor tried a number of different approaches to progress the development of Phoenix, and ultimately agreed to purchase a nearby field interest and associated infrastructure with the aim of redeveloping it jointly with Phoenix. This redevelopment would have had particular synergy for both fields, with P50 sales gas resources for Phoenix estimated as 32 Bscf and incremental liquids production as 3.8mmbc. After reaching agreement to acquire that nearby field, Chrysaor requested and obtained a licence extension for Phoenix and committed to drilling of the Phoenix development well to fulfil the licence conditions. Unfortunately the asset purchase was subsequently pre-empted. Chrysaor was therefore forced to relinquish the licence as there was then no commercial or technical justification for drilling a well in the absence of an export route. 3. Exploration & Development Activities Block 13/22b was applied for by Chrysaor solely on the basis of the Phoenix accumulation, a gas condensate discovery within the Banff sub-basin of the Moray Firth area. 3.1 Seismic Block 13/22b is fully covered by the PGS Megamerge 3D. There is no material structural closure within block 13/22b down to Base Cretaceous. However, small tilted fault blocks are developed within the Jurassic sequence, one of which provided structural closure for the Phoenix accumulation (Figures 2, 3). The next tilted fault block to the south and the only other closure within the licence areas was tested by dry well 13/22b-19. Another dry hole targeting the same stratigraphic level 13/22c-30 was drilled some three kilometres to the south east. The quality of the data is good and the Phoenix structure itself is small but well defined. Licence P.1578 Relinquishment Report - March 2015 Page 4 of 16

5 Hallibut Horst Southern Bounding Fault Top Phoenix Reservoir Depth Structure (ft TVDSS) Hallibut Horst Southern Bounding Fault 13/22b N Top Top Phoenix Reservoir Time Depth Structure (ms) (ft TVDSS) Figure 2 Block 13/22b Time Structure at Top Phoenix Reservoir (ms) 13/22B-4 DISCOVERY 13/22B-19 DRY HOLE Reservoir section HALIBUT HORST Line of section 13/22b Seismic Data Courtesy of PGS NORTH Hydrocarbon kitchen - Jurassic Hot Shales deeply buried. Top Phoenix Reservoir Time Structure (ms) N SOUTH Figure 3 North-South Geoseismic Section to Illustrate Structural Character of Phoenix Licence P.1578 Relinquishment Report - March 2015 Page 5 of 16

6 3.2 Wells The only well on the licence area is 13/22b-4, drilled by Kerr McGee in 1990 to a total depth of 13670ft MD within Permian subcrop. This well discovered the Phoenix accumulation trapped within deepwater sand reservoirs of Lower Volgian age towards the base of the Kimmeridge Clay (Figure 4). DST-2 11,498 11,798 ft MD Cond. Rate = 3898 stb/d Gas Rate = 17.2 MMSCFD CGR = 227 STB/MMSCF 80/64 Choke DST-1 11,895 11,826 ft MD Cond. Rate = 1146 stb/d Gas Rate = 5.2 MMSCFD CGR = 221 STB/MMSCF 64/64 Choke Figure 4 Petrophysical Interpretation of Phoenix Discovery and Associate DST Results Licence P.1578 Relinquishment Report - March 2015 Page 6 of 16

7 Average porosity within the net reservoir of the Phoenix accumulation is just under 10%, average hydrocarbon saturation relatively low at around 60% and the reservoir is normally pressured. However the well was successfully flowed at a rate 17.2mmscf/day + 3,898bcpd consistent with average DST permeability 1-2mD. Shows were also encountered within the poor quality Rhaxella Spiculite at base Jurassic but the underling Permian sands were water-wet. 3.3 Studies Seismic interpretation, petrophysical, geological and reservoir engineering studies were undertaken during 2008/2009 prior to and immediately after licence award, resulting in development of an integrated geoscience model covering the whole of the licensed acreage with detailed Petrel/Eclipse models for the Phoenix accumulation. Subsequent geotechnical work has concentrated on upgrading the Phoenix simulation model from black oil to fully compositional, refining the compositional model with improved equation of state modelling collection/understanding of performance information from producing analogues (work conducted in-house as well as on behalf of Chrysaor by Senergy, Petrophase and OPC between 2010 and 2013). The refined compositional simulation model was then used to carry out detailed development well optimisation work (Chrysaor 2013) and provide information for detail process design in different export scenarios (both in-house and through Atkins/ODE in 2013 and 2014). The most recent studies are summarized in a Competent Persons Report produced by Senergy in June Licence P.1578 Relinquishment Report - March 2015 Page 7 of 16

8 4. Phoenix Resources Analysis 4.1 Structural Definition The Phoenix field is a three way dip closure that is fault bounded to the south (Figures 5 & 6). Top Phoenix Reservoir level Depth ft TVDSS Phoenix FWL Phoenix N Figure 5 Phoenix Depth Structure Gamma Ray Signature Well 13/22b-4 North Phoenix Crest c 11050ft TVDSS in this line of section UMA MMA South 1 km LMA Phoenix FWL 11842ft TVDSS Figure 6 Structural Cross-section Phoenix Geocellular Model Licence P.1578 Relinquishment Report - March 2015 Page 8 of 16

9 Simple structuring, good quality seismic data, small size and central control well tying down the gaswater contact mean that uncertainty in Phoenix gross rock volume is low. The gas column extends significantly below the pure elevation closure, indicating that the southern bounding fault of the field is an effective gas seal. Depth conversion uncertainty at the FWL is unlikely to exceed +/- 50ft. It is possible in a downside scenario that the low throw WNW/SSE cross-faults downdip in the eastern part of the field may act as material production baffles for about 10% of GIIP. 4.2 Reservoir Architecture and Quality Major reservoir units in 13/22b-4 correlate excellently into 13/22b-19 just over 2km away, with no significant changes in reservoir quality (Figure 7). Section flattened on ASD3 Figure 7 Phoenix Reservoir Correlation Licence P.1578 Relinquishment Report - March 2015 Page 9 of 16

10 Detailed pressure data and compositional variation between DST1 and DST2 suggest that unit ADS2, the 28ft thick mudstone whose top lies at 11700ft TVDSS, is a fieldwide pressure barrier. However, most of the reservoir within closure should be connected to a single suitably planned producer. Reservoir quality is modest with well test analysis suggesting an overall permeability to hydrocarbon of 1-2mD. From a practical viewpoint development is best undertaken with a near horizontal well cutting stratigraphy close to the crest of the structure in order to minimise the risk of water influx (Figure 8). To maximise condensate recovery and total economic value (if produced through the nearby field and its infrastructure) it was also desirable to restrict Phoenix off-take rate to maximum 25mmscf/day at wellhead. Top Reservoir Structure Map H4a Well Surface Location Reservoir Entry Point Reservoir Completion Zone W H4a Short Reservoir Completion Zone E AAU UMA MMA FWL ft TVDss LMA MAD IAU 400 ft 250 m Figure 8 Optimal Horizontal Well Design Determined for Phoenix (via a nearby host field) Licence P.1578 Relinquishment Report - March 2015 Page 10 of 16

11 4.3 Hydrocarbon Quality RFT data and DST build-up data indicate the Phoenix accumulation is normally pressured with a reference pressure of 5,348psia and a temperature of 213 o C at the predicted hydrocarbon water contact of 11,842ft TVDSS. The overall pressure gradient in the hydrocarbon bearing interval of DST 2 is 0.196psi/ft. This is in line with expectations from PVT data which suggest a rich retrograde gas condensate with a dewpoint of 5,225psia, only a little below its current reservoir pressure. This notwithstanding, detailed analysis of the well test and fluid samples suggest liquid condensate in the reservoir was mobile, at least within the condensate bank adjacent to the well where flow velocities were high. Around 12% of the total well-stream composition was CO 2 which helps condensate mobility even though it is an undesirable impurity that needs to be removed from sales gas. 4.4 Resource Estimation Latest estimates of Phoenix Gas and Condensate in place are summarised below: Total Gas and Condensate Initially in Place for Phoenix (assuming flash separation) P90 P50 P10 Gas (bscf) Condensate (mmstb) Total (mmboe) Table 2 Phoenix Total Gas & Condensate in Place (assuming flash separation) Recoverable sales resource volumes estimates depend on precise development, detailed process design, fuel losses and commercial cut-off of the host facilities (as well as Phoenix itself). The balance of gas and condensate is also impacted by the desired plateau production rate and the properties of other fluids being co-processed. The resource estimates below are based on simple depletion with detailed process engineering of liquids/co 2 separation processes for co-production with host field fluids. This gives an 18% increase in condensate recovery compared to flash separation of fluids produced at wellhead, though sales gas is reduced to 77.4% of total flash gas. Recoverable Resources for Planned Phoenix Development 2014 (Host Process Separation) P90 Simulation P50 Simulation P10 Simulation Sales Spec Gas (bscf) Condensate (mmstb) Total (mmboe) Table 3 Recoverable Sales Gas & Condensate Resources for Phoenix Development via nearby host field and infrastructure Licence P.1578 Relinquishment Report - March 2015 Page 11 of 16

12 The relatively low recovery of condensate reflects the reservoir being close to dewpoint at initial conditions, with most produced early in the production profile. Gas cycling is not commercially practical for such a small low permeability accumulation with the field best developed through a single horizontal producer whose design is shown in Figure 8 (maximising spread of depletion while contacting all reservoir units directly and maintaining offset from aquifer in a single drillable well). The relatively low recovery factor for sales gas primarily reflects the low permeability of the reservoir, the impact of CO 2 removal and the impact of fuel deductions to power facilities. 4.5 Export Options Technically, with the support of suitable infrastructure owners, it would be possible to engineer a subsea development to onshore processing or to nearby facilities in the Moray Firth for offshore processing followed by gas export or fuel use. However the small size of the accumulation, combined with the challenge of processing high CO 2 condensate rich gas (even as a fuel) and a changing tax situation has limited the desire of infrastructure holders to host Phoenix facilities. Initial plans to use the Atlantic-Cromarty pipeline to export onshore for processing floundered following the tax changes of 2010/2011. Subsequent plans for processing to sales specifications offshore through a nearby host field and infrastructure floundered when other partners pre-empted sale of the asset to Chrysaor. In the absence of a commercial development option, it is not possible to justify drilling a development well on Phoenix. Nor is it possible to justify an appraisal well on Phoenix that is considered technically unnecessary or an offset exploration well where there is considered to be zero chance of commercial success. 5. Analysis of Other Potential Resources 5.1 Phoenix Deep Lead Although the Permian sands encountered by 13/22b-4 were water-wet, the crest of the Phoenix structure at Permian level lies some 500ft above this with some attic potential at this level, the Phoenix Deep Lead. Although the Phoenix Deep structure is robust, there is a significant angular unconformity between the Permian and the overlying Jurassic with the former dipping more steeply to the north and west. As a result, the Permian sand unit proven by 13/22b-4 is partially eroded at the south-eastern extremity of the structure at either the Base Triassic or the Base Jurassic unconformity. This introduces the possibility of leakage to Rhaxella Sand waste zone if the Smith Bank Shale is missing. Although the existence of some potential trapping geometry is highly likely, associated GRV is uncertain. The distribution used in probabilistic modelling is tied by a downside where sand is Licence P.1578 Relinquishment Report - March 2015 Page 12 of 16

13 restricted to the interval that was seen in 13/22b-4 while the upside assumes the Permian sub-crop is sandy right across closure. Details of the resource potential and risking are tabulated below. Property Distribution Type P90 Tie P10 Tie Low End Truncation High End Truncation Gross Rock Volume (millions of m 3 ) Lognormal Mean Volumetric Net: Gross Ratio Lognormal Mean Porosity in Net Sand (%) Uniform Mean Gas Saturation in Net Pay (%) Uniform Wellhead Dry Gas Expansion Factor (scf/rcf) Normal Condensate Gas Ratio (bc/mmscf dry gas) Normal Dry Wellhead Gas Recovery Efficiency (%) Normal Condensate Recovery Efficiency (%) Uniform Loss to Sales Gas (%) Uniform Output Prediction P90 Mode P50 Mean P10 Gas Initially in Place (bscf) Condensate Initially in Place (mmbc) Sales Gas (bscf) Sales Condensate (mmbc) Total Oil Equivalent Sales (mmboe) Table 4 Probabilistic Modelling Inputs and Outputs for Phoenix Deep Lead Risk Factor Chance of Success (%) Reservoir Effectiveness (chance of commercial reservoir thickness and deliverability) 70 Hydrocarbon Charge (chance of adequate charge to fill trap to modelled capacity) 80 Seal Effectiveness (chance of adequate lateral and vertical containment since time of migration) 30 Trap Definition (chance of minimum geometry being present) 100 POSg Overall 17 Table 5 Geological Chance of Success Assessment for the Phoenix Deep Lead Licence P.1578 Relinquishment Report - March 2015 Page 13 of 16

14 The small resource potential of the Phoenix Deep Lead combined with its low chance of success rules it out as an attractive incremental exploration target. 5.2 Ashes Lead The Ashes Lead is the potential attic volume within the fault block tested by 13/22b-19. Hallibut Horst Southern Bounding Fault Ashes Lead Key geological risk is downthrown fault seal highlighted in red Top Phoenix Reservoir Depth Structure (ft TVDSS) Figure 9 Ashes Lead at Top Phoenix Reservoir Level Trap definition is fairly robust, although the seismic image is not as good as at Phoenix. Hydrocarbon charging is considered to be low risk, as the fault block would be able to access the same hydrocarbon kitchen that sources Phoenix itself. All of the properties of the reservoir and fluids are expected to be similar to those in the Phoenix accumulation, or even slightly improved, as this culmination is at a depth of 10,500 ss, about 1,000 shallower than the Phoenix discovery. Seal effectiveness is a major risk for the Ashes Lead. The first element of this is that the overall trap relies on a downthrown-to-the-north fault at the south-western end of the feature to seal (marked in red on the map in Figure 9). This is possible but carries a high level of risk, as the fault throw is small and the juxtaposition across the fault will be Phoenix Reservoir against Phoenix Reservoir, not an ideal scenario for trapping hydrocarbons. The fault throw varies from less than 50 to perhaps 150, while the Phoenix Reservoir is about 600 thick. The crestal part of the Ashes feature is in contact with this fault. Licence P.1578 Relinquishment Report - March 2015 Page 14 of 16

15 The second element of seal effectiveness risk is on the main south-downthrown bounding fault. Although this fault provides upthrown closure, it has a maximum throw of about 250. This throw does not offset the reservoir completely, and so it is necessary to have shale smear across the fault to seal more than a 250 column. The lead itself has a vertical relief of about 600 on the structure above the penetration at the 13/22b-19 location but is very narrow giving low GRV potential. Because seal capacity is a big volumetric uncertainty, it is modelled separately as a fill proportion variable separate to conventional GRV uncertainty related to seismic picking and depth conversion. Fill proportion is modelled as between 40 and 100% on the basis that any exploration well drilled as production keeper would need be drilled at the centre of the potential accumulation and have failed geologically if it did not prove fill of at least 40% fill. Above this there is no rationale to pick a most likely fill so a uniform distribution is used. Hydrocarbon properties and dynamic performance of any accumulation are expected to be similar to those of the Phoenix Field. Property Distribution Type P90 Tie P10 Tie Low End Truncation High End Truncation Gross Rock Volume (millions of m 3 ) Lognormal Fill Proportion Uniform Mean Volumetric Net: Gross Ratio Lognormal Mean Porosity in Net Sand (%) Normal Mean Gas Saturation in Net Pay (%) Normal Wellhead Dry Gas Expansion Factor (scf/rcf) Normal Condensate Gas Ratio (bc/mmscf dry gas) Normal Dry Wellhead Gas Recovery Efficiency (%) Normal Condensate Recovery Efficiency (%) Custom (8.8) (16.3) Loss to Sales Gas (%) Normal Output Prediction P90 Mode P50 Mean P10 Gas Initially in Place (bscf) Condensate Initially in Place (mmbc) Sales Gas (bscf) Sales Condensate (mmbc) Total Oil Equivalent Sales (mmboe) Table 6 Probabilistic Modelling Inputs and Outputs for Ashes Lead Risk Factor Chance of Success (%) Reservoir Effectiveness (chance of commercial reservoir thickness and deliverability) 95 Hydrocarbon Charge (chance of adequate charge to fill trap to modelled capacity) 95 Seal Effectiveness (chance of adequate lateral and vertical containment since time of migration) 15 Trap Definition (chance of minimum geometry being present) 95 POSg Overall 13 Table 7 Geological Chance of Success Assessment for the Ashes Lead Licence P.1578 Relinquishment Report - March 2015 Page 15 of 16

16 Given its very small size, high estimated risk and requirement for a dedicated well, it is unlikely that drilling of the Ashes lead will ever be commercially attractive. 6. Clearance The Management of Chrysaor has reviewed this document and verified that DECC is free to publish it. The annotated seismic line is based on PGS Megamerge data and its inclusion has been approved by them as the data owner. No liability whatsoever is accepted by Chrysaor Holdings Limited or Chrysaor CNS Limited in respect of the contents of this relinquishment report and no representation, warranty or undertaking is or will be made regarding the information herein contained. Licence P.1578 Relinquishment Report - March 2015 Page 16 of 16