Relinquishment Report P.1120, P.1320 Ockley

Transcription

1 Relinquishment Report P.1120, P.1320 Ockley April 2017

2 Contents 1. Licence Information Licence Synopsis Work Programme Summary Database Further Technical Work Undertaken Resource and Risk Summary Conclusions ii

3 1. Licence Information The Ockley field is located in the central North Sea Quadrant 30 principally spanning two blocks and licences, P1120 and P1320 and extending eastwards into a third P098 (Figure 1.1): P.1120 Block 30/1d P.1320 Block 30/1h P098 Block 30/2a, held by BG (operator), Maersk Oil, GDF Suez and OMV The licences also cover the Oakwood discovery. This Relinquishment report covers licences P.1120 & P Blocks 30/1d and 30/1h were operated by Maersk Oil under the relevant Joint Operating Agreements. Interests in both 30/1h and 30/1d are as follows: Maersk Oil (Operator) 58% Wintershall 22.7% GDF Suez 19.3% Maersk Oil confirms that DECC / OGA is free to publish this report and that all 3 rd party ownership rights have been considered and appropriately cleared for publication purposes. Figure 1.1 Ockley Location Map 3

4 2. Licence Synopsis P.1120 (block 30/1d) originally awarded in 21 st Round in 2003 as a Promote licence to Veritas Geophysical Ltd (100%, operator), with a firm work programme of analysis of prestack seismic data for lithology and fluid indicators. Maersk Oil farmed in to this licence in 2005, this involved a firm commitment to test the Ockley gas/condensate discovery with a horizontal well. P.1120 was then operated by Maersk Oil (85%) with partner Veritas (15%). Also that year Maersk Oil (85%, operator) and Veritas (15%) were awarded P.1320 licence block 30/1h in the 23 rd Round, this was a Traditional licence with firm work programme of acquisition of 64km2 of 3D seismic data and completion of AI and AVO Inversion studies. In % equity in both licences was farmed out to Wintershall by Maersk Oil. Also in 2007, 22.3% equity in both licences was farmed out to E.On Ruhrgas by Maersk Oil. Afurther change in licence participants occurred in 2007 as GdF purchased the UKCS licence assets of Veritas Geophysical Limited. By the time the Ockley appraisal well, 30/1d-10, was drilled the partnership in both licences was Maersk Oil (40%, operator), Wintershall (22.7%), E.On Ruhrgas (22.3%) & GdF (15%). The drilling of 30/1d-10 well, completed in 2008, completed any outstanding licence work programme commitments for P In 2009, a 1 year extension was granted to licence P In 2011, E.On Ruhrgas withdrew from both licences with resulting equities as follows: Maersk Oil (operator) 58% Wintershall 22.7% GdF 19.3% The P1320 licence initial term was extended to allow drilling of the 30/1d-12 well which fulfilled all remaining work programme commitments. An extension to the Second Term for P.1120 was agreed in 2012 to the end of A further extension to the Second Term for P.1120 was agreed at the end of 2013, requiring the Ockley project to pass through Assess to Select Stage Gate by 31 st July An extension to the Second Term for P.1320 was also agreed at the same time with the same condition, requiring the Ockley project to pass through Assess to Select Stage Gate by 31 st July Both P.1120 & P.1320 licences determined effective 30 th September

5 3. Work Programme Summary The agreed work programme for the 30/1g licence was to drill one Intra-Hod horizontal well to a TD of 3950m TVD. This was planned to be a production appraisal well within the intra-chalk Ockley discovery in block 30/1d. In addition to this there was also a commitment to acquire 64km 2 of existing 3D seismic data and to carry out an AI and AVO inversion for fluid and lithology prediction over the licence area Well results summary Within the licence term the 30/1d-10 horizontal well was drilled in 2007 to meet the licence commitment. In addition two further wells, the 30/1d-12 and 30/1d-12Z were also drilled in the licence in 2012 in licence P1120. The 30/1d-12 was drilled with the main objective being to acquire key data (reservoir pressures/samples and compressional and shear sonic as well as core) over the Ockley reservoir interval. As these objectives were successfully met the well was deepened to the Upper Jurassic Oakwood exploration target. The 30/1d-12Z horizontal section was then drilled with the main objective being to prove that commercial hydrocarbon flow rates could be achieved using horizontal well stimulation and completion technology Ockley well results summary Well tests were carried out on both 30/1d-10 and 30/1d-12z. The earlier well failed to achieve stable flow, despite acid stimulation via Controlled Acid Jetting (CAJ) liner. The - 12z well test proved the hydrocarbon phase of gas condensate, formation pressure of c. 11,100psia (at 12,784 tvdss), and average formation permeability on the order of 35µD. The average petrophysical properties total porosity and water saturation for the 30/1d- 10, 30/1d-12 and 30/1d-12Z are tabulated in table 3.1. Well Zone Top Bottom Gross Sw PHIT Ft MD Ft MD Ft v/v v/v 30/01d-10 Ockley /01d-12 Ockley /01d-12Z Ockley Table 3.1 Average total porosity and water saturation over the Ockley reservoir Oakwood well results summary The Oakwood well targeted the up dip pinchout zone of a large stratigraphic wedge mapped in the Upper Jurassic Heather Formation. Reservoir sand within this dominantly shale prone succession was predicted within deep water turbidite intervals interpreted as pinching out towards the north, east and west. The principal geological risks for Oakwood were considered to be trap and reservoir presence. Trap risk was associated with the requirement for effective top, lateral and base stratigraphic sealing mechanisms. Risk associated with reservoir presence was identified in relation to the dominantly shale prone character of the Heather Formation together with the up-dip position of the well location - within the pinchout zone of the 5

6 Oakwood wedge. In a sub-regional context, Heather Formation turbidite reservoirs are developed in the East Central Graben and are present in the nearby Erskine, Shearwater and Elgin-Franklin fields and also within the Jackdaw Discovery. 30/1d-12 reached TD at 15,500 ft MDRT (14,232 ft TVDss) in the Middle Jurassic, Pentland Formation. The well encountered a 209 ft gross interval of Heather turbidites with a GDT recorded at 13,983 ft TVDss within the Heather turbidite sands. Nine logging runs were performed, however these were not all successful due to hole conditions & geometry. Two pressure and four single phase samples were successfully obtained from the Heather reservoir intervals Seismic work programme The seismic requirement was mostly focused around the geotechnical studies in addition to the licensing of 64km 2 of existing 3D seismic data. There have been several phases of seismic based studies over all or part of the Ockley discovery which are summarised in table 3.2. Name Contractor Year Facies Finder CGG 2005 Relative Acoustic Impedance (RAI) Maersk Internal 2005 Elastic Inversion Maersk Internal 2005 Absolute Acoustic Inversion (AAI) Maersk Internal 2013 Table 3.2. Summary of seismic inversions carried out over the Ockley area Of these, the subsurface work on Ockley has subsequently been focused on the RAI and AAI volumes which have been discussed in more length in section

7 4. Database An overview of the well and seismic database which was used in the analyses of Ockley and Oakwood is summarised in sections 4.1 and Ockley Well Database The log data, core data, formation pressure and well test data available over the Ockley interval in the wells that define the Ockley accumulation are presented in table 4.1 along with the data availability from 2 near Ockley offset wells that were considered in the building of the Ockley static and dynamic models. Well Interval GR Resistivity Neutron Density Dt Images Core Formation DST (Ockley) Pressures MD (Ft) 30/1c- 2A /2a /1f /1d /1d /1d- 12Z / /1c Table 4.1. Key wells used in the evaluation of the Ockley discovery. The 30/01d-12 well was cored from ft to ft MD. This interval covered the Ockley reservoir. An extensive routine and special core analysis program was carried out and results obtained despite the very tight nature of the rock Oakwood Well Database The evaluation of Oakwood was carried out using a slightly different well database which was appropriate for the stratigraphic interval. The well database used can be seen in table

8 Well GR Resistivity Neutron Density Dt Images Core Formation pressures DST 30/1d /1a /2a- 2 30/2-1 Table 4.2. Key wells used in Oakwood evaluation (Upper Jurassic Heather Interval) Seismic Database The geophysical interpretation carried out on Ockley and Oakwood was completed on the CGG Cornerstone PSTM dataset. This was due to data availability and lateral coverage of this dataset which allowed regional wells to be incorporated into the analysis. Also available over the majority of the Ockley discovery was the CGG 2006 PSDM multi-client data which was used for fault and fracture attributes on Ockley and in 2013 the Faraday PSDM dataset (re-processing of the Cornerstone acquisition). The extent of these various seismic datasets can be seen in figure 4.1 and a comparison of the CGG cornerstone PSTM data and the 2006 PSDM data across Ockley can be seen in figures 4.2 and 4.3. Figure 4.1. Map showing extent of seismic data across the Ockley/Oakwood licence. 8

9 Following receipt of the Faraday PSDM this data was used for the post-drill (30/1d-12) interpretation update for Oakwood (the data does not extend far enough to be used for the Ockley reservoir modelling work). A comparison between the pre-drill cornerstone and post-drill Faraday PSDM datasets and interpretations can be seen in figures 4.4 and 4.5. Data courtesy of CGG Figure 4.2. West-East cross-section through Ockley on the Cornerstone PSTM dataset. 9

10 Data courtesy of CGG Figure 4.3. West-East cross section through Ockley on the CGG 2006 PSDM dataset stretched back to time. Data courtesy of CGG Figure 4.4. West-East cross section through the Oakwood prospect on Cornerstone predrill reference seismic dataset. 10

11 Data courtesy of CGG Figure 4.5. West-East cross section through the Oakwood discovery on the Faraday PSDM seismic dataset with post-drill interpretation. 11

12 5. Further Technical Work Undertaken 5.1. Acoustic Impedance Inversion The Ockley discovery is characterised by an amplitude anomaly which was initially identified on reflectivity data. A Relative Acoustic Impedance (RAI) inversion was carried out in 2005 and was used to help delineate the field outline as well as identify sweet spots within the accumulation. Following the drilling of the 30/1d-12 and 30/1d-12Z wells an Absolute Acoustic Impedance (AAI) inversion was carried out in 2013 which much improved the coherency of the anomaly and reduced the noise significantly compared with the RAI. The presence of an anomaly is understood to be due to a porosity anomaly where increased porosity is causing low acoustic impedance compared to the surrounding chalk. The reference case geological model is that hydrocarbon charge has preserved porosity within the accumulation. There is no evidence from the rock physics that the hydrocarbons are detected directly from the anomaly but only by indirect associated due to the geological model that their presence has preserved the porosity. A comparison of the anomaly from the RAI and AAI inversions can be seen in figures 5.1 and 5.2. Figure 5.1. Ockley anomaly as defined on the Relative Acoustic Impedance inversion volume. 12

13 Figure 5.2. Ockley anomaly defined on the 2013 Absolute Acoustic Impedance inversion volume 5.2. Hydrocarbons Initially In Place The Ockley reservoir is an intra-unit of the Lower Cretaceous Hod Formation comprising of chalk with varying degrees of clay content from 5 to 30%. It is a very low permeability ( mD) and uniform reservoir with an average porosity of 12% in the hydrocarbon interval. There are 9 distinct successions within Ockley that correlate over large distances to the regional wells. The chalk is interpreted to be in-situ with deposition in a slope/basin setting. There is no evidence of remobilisation. A seismic anomaly exists over the Ockley field which is thought to relate to elevated porosities that have been preserved through hydrocarbon emplacement and overpressure. However paleo reconstruction work suggests that the accumulation may be greater than the extent of the anomaly. It is suggested that the hydrocarbons are trapped in a paleo high and surrounded by tighter lower porosity rock at a former structural high that is now slightly off structure. No fluid contacts have been observed. The Top Ockley is shown in figure 5.3 with the Acoustic Impedance Anomaly outline (orange). The reference case hydrocarbons are modelled to fit approximately with the anomaly. 13

14 Figure 5.3 Top Structure Ockley Following full evaluation of the 30/1d-12 and 12z well results, updated static and dynamic models have been generated. The reference case geological model, which represents the best technical case, uses the AAI response to guide the porosity model and to define the extent of the hydrocarbons in place. An uncertainty study defines the uncertainty ranges in top structure, isochores thickness, porosity, Sw model and the FWL. Using the uncertainty ranges in a stochastic workflow, a probabilistic range of volumes for the Ockely Field is defined. Presented in table 5.1 is the range of in-place gas and condensate volumes for the Ockley Field, represented by a low, mid and high case. The cases are derived from P90, P50 and P10 deterministic (modelled) estimates Hydrocarbons in Place Low Mid High GIIP (Bscf) CIIP (MM bbls) H/carbons (MMboe) Table 5.1 Ockley Hydrocarbons In Place Summary 14

15 5.3. Resources and Production Forecast Following full evaluation of the 30/1d-12 and 12z well results, updated static and dynamic models were generated. Along with the full field modelling study, significant sector modelling numerical simulation work were undertaken to understand the well, fracture & reservoir performance in appraisal well (30/1d-12z), and to help define ranges on key static/dynamic parameters to capture uncertainty surrounding future well/fracture performance and resulting resources. The reference development scenario is that the field would be developed initially by three wells drilled, stimulated and produced sequentially, followed by a number of wells 3 in the low case, 5 in the mid and high case batch drilled, then stimulated. The wells themselves would have 8,000 horizontal sections fracture stimulated with up to 13 fracs, with each frac varying between (mid case 250 ). Variability in production forecasts have been created by modelling individual wells in a dynamic simulator (sector model), with a range of key parameters (matrix permeability, relative permeability, frac half length, number of frac failures). Representative low, mid and high individual well profiles were then selected and combined in a Monte Carlo simulation. Each of the eight wells had a 30% chance of being a low case well, a 40% chance of being a mid case well, and a 30% chance of being a high case well; a Swanson s mean distribution. The resulting median run was selected as being a representative mid case profile. For the low and high case resource determination, this process was repeated with sector models with volumes representative of the high and low case geological models; however, well likelihoods were altered to 50% low / 30% mid / 20% high (in the low case) and 20% low / 30% mid / 50% high (in the high case). In the low case, only 6 wells are drilled, whereas in the mid and high case, 8 wells are drilled. Once more, the median run from each Monte Carlo simulation was taken as the representative profile for the low and high case. A number of different development scenarios (for different platform concepts, different stimulation concepts and different schedules), as well as subsurface variations (such as the distribution of natural fractures), were tested; table 5.2 gives the results for the reference development concept. Ultimate recovery Low Mid High Gas (Bscf) Condensate (MM bbls) Hydrocarbons (MMboe) Table 5.2 Ockley Ultimate Recoverable Resources Summary 15

16 5.4. Well Engineering Overview Ultimate Recovery from Ockley is strongly linked to the ability to place large numbers of propped hydraulic fractures into the reservoir in the most economic way. The low matrix permeability means that whilst there may be a high in-place volume of hydrocarbons, ultimate recovery is in the end determined by the number and quality of frac treatments. To this end it was determined that horizontal wells would be required. Well spacing studies and well length optimisation studies identified that a well spacing of some 2500 ft would be optimum and that well length would have to be maximised within constraints of drilling /liner running and cementing envelope and Coiled Tubing (CT) reach envelope. In all fracture scenarios considered, CT will be required for proppant clean up following stimulation and for potential remedial work later in well life. Geomechanics A significant amount of effort has been spent on determining the stress conditions in the Ockley reservoir. The in-situ stress magnitude and orientation has a significant impact on the ability to fracture the reservoir and on the orientation and tortuosity of resulting fractures. The results of this study effort are that the stress orientation is ambiguous and the orientation of induced fractures is impossible to predict with any accuracy. Furthermore, it is very likely that high levels of tortuosity will be encountered. As a result of the uncertain direction of maximum horizontal stress and the necessity to orient wells such that the well azimuth aligns with the direction of minimum horizontal stress (to facilitate transverse fractures for maximum UR), it was necessary to investigate different scenarios for well orientation. Trajectory design work was thus performed for a number of scenarios and found to be feasible for all. These included the two scenarios below which are also shown in figure 5.4: Scenario#1: a single wellhead platform centrally located in the field, with 8 wells drilled in a NW-SE orientation (considered as reference case), Scenario#2: dual drill centres with 8 wells drilled SW to NE Figure 5.4 Well Orientation Both orientations result in similar recoverable resources, however, scenario#2 above requires 2 drill centres. In order to maximise horizontal drilling reach, optimise the chance of running the reservoir completion to TD, and to facilitate CT reach it was 16

17 determined that geometric drilled trajectories would be used, with wells drilled at or slightly below 90 degrees. The stimulation method selected will ensure vertical connectivity with the best quality reservoir if not directly penetrated as a result of the geometric trajectory. Casing designs were performed on the basis of the designs used for the 10 and 12/12z wells and using learnings from the Culzean and Jackdaw projects. It was determined that 10 kpsi wellhead and Xmas trees would suffice for Ockley, however 15 kpsi wellheads and trees would be carried as an option which could prove beneficial when planning to fracture stimulate through the completion, removing the need for wellhead protection equipment, used in conjunction with a temporary 15k frac tree. Casing and tubing stress analysis were performed identifying no significant issues. Batch drilling and stimulation 'off the rig' have been included as a means of reducing the rig related costs for the development. Completion design and stimulation concept The completion design for Ockley wells needs to allow for the execution of 13 frac treatments per well. It was concluded early on as one of the main learnings from the 12z well stimulation, that it would be preferable to use a system based on a cemented liner as a Base Case, and only to re-visit potential application of open hole systems after significant experience was gained with cemented liner systems. The use of a proven system would be preferred over the use of novel technology, at least for the first wells on Ockley. During the last year, over a dozen different completion and stimulation systems were studied in close cooperation with colleagues from the Danish Business Unit and Corporate Well Engineering. Expertise and recent fracture stimulation experience from Ockley partners Wintershall and GdF Suez was also obtained. Systems were compared and ranked on the basis of track record, functionality and costs (both equipment and rig time needed during installation/stimulation/clean up). After thorough review of these systems a selection was made whereby as a reference case, a combination of modified PSI (for the first 3 wells) and 'plug and perf' technology (for the remaining 5 wells) would be used. The PSI system is better for dealing with screen outs due to the ability to reverse circulate and hence this system carried favour for the initial wells where stimulation learnings would be made and screen outs could be more prevalent. An opportunity to improve fracturing efficiency by incorporating cemented sleeves was also identified, as this could be implemented without compromising the base case plug and perf option. A reference case scenario was constructed which caters for the first 3 wells to be completed and stimulated from the rig using the PSI system, followed by 5 wells which will be batch drilled and stimulated from the wellhead platform using Plug & Perf methodology. Flow assurance (wax, salt) Ockley condensate has been determined to have a high Wax Appearance Temperature (WAT) of some deg C. The WAT can be somewhat depressed using inhibitor chemicals but not likely by more than 10 deg C. Thermal modelling of Ockley wells in Prosper and in Wellcat software has determined that Flowing Wellhead Temperature (FWHT) is expected to drop below WAT between 4 and 6 years after production start-up even when using inhibitors. Traditional methods to maintain FWHT include the use of insulating annulus fluids or possibly Vacuum Insulated Tubuluars (VIT). Neither of these methods were found to be suitable for Ockley conditions however. Annulus fluids were not able to raise FWHT sufficiently and VIT is not capable of dealing with the load conditions seen during stimulation. It has therefore been found necessary to turn to the use of downhole electric heat tracing of the production tubing as a means to avoid 17

18 deposition of wax inside the production tubing. Details of this technology which is in use onshore USA, are currently scarce and allowances for costs for electric power supply (estimated at some 200kW per well) and the impact on well reliability / availability are not yet well understood and require further study. 5.5 Development Concepts Based on early economic screening, it was concluded that Ockley could not be a standalone development i.e. with dedicated full processing facilities prior to export tie-in. Therefore, a tieback to a third party processing facility was assumed the base case. For the Ockley facilities, a WHP concept and a subsea concept were considered in the Assess phase. A summary of the high level assessment carried out for the subsea option is in Table 5.3; Benefits Lower Upfront Facilities CAPEX Challenges Well Integrity Monitoring Drilling Rig Selection: Semi-Sub or HDJU Proppant Production Risk (Erosion and Removal Prior to Export to Host) No WHP OPEX Higher Well Costs Table 5.3 Subsea Assessment Completion Limitations High Intervention Costs as Requires Rig; Likely to Make Interventions Cost Prohibitive. Based on this assessment, the challenges were considered to outweigh the benefits for subsea vs. dry tree. The main concerns with a subsea development are the lack of annulus management options and intervention costs are prohibitive. Both these concerns were assessed to be of high importance for the success of the Ockley development s design, operation and cost. Therefore, the subsea concept was eliminated based on technology limitations available currently i.e. these challenges may be overcome with new technology not available at present. The WHP concept (reference section 5.7.1) was further developed to provide for a range of drilling, stimulation and interventions capabilities to cater for the nature of the Ockley field. 18

19 5.6. Export and Tie-back A number of tieback/export options were identified as part of the Ockley Assess phase. See Figure 5.5. Potential hosts identified for an Ockley development tieback are as follows; - Elgin Franklin Platform (~20 km) - Shearwater Platform (~18 km) - Erskine WHP (~12 km) - Jade WHP (~10 km) - Notional Jackdaw Platform (~12 km) Of these, only the Jackdaw option was carried forward. It should be recognised that when Jackdaw was selected as the Ockley base case, the project was in the Select phase of design. However, Jackdaw is now (at the time of this report) in a state of recycle with partners currently re-evaluating the Jackdaw concept. The development or any results from the assessment have not been taken into account in this report. However, this should be considered a major risk to any Ockley development going forward. Ockley was considered as two types of tieback to Jackdaw; A Joint Venture Assumes Ockley can pre-invest as required into a joint processing facility at Jackdaw. Dedicated Ockley ullage available from day one; A Third Party Tieback Module approach. Production treated as ullage filler on a Jackdaw processing platform. A joint venture is considered as the reference case for the Ockley development. This represents the most realistic case based on the uncertainty of the export route. Not Technically Not Technically Being Considered Not Technically Technically Challenging Technically Challenging Being Considered Not Technically No Capacity Not Technically Not Technically Figure 5.5 Field Location and Nearby Hosts 19

20 5.7. Overview of Facilities Studies WHP Facilities Five development options were considered for the Ockley WHP. For all of these options studied, Oakwood facilities and equipment have not been considered other than in the provision of space for future well slots. The basic design of the WHP was developed around a 12-slot wellbay. However, in four of the options considered, additional well slots were included in the design for Ockley redrill and Oakwood appraisal/production. A summary of the options considered, describing the different drilling and intervention capabilities is in table 5.4. Option Description Slots POB A Minimal Facilities HDJU Required for all. 12 T/R Drilling/Stimulation/Intervention. A Minimal Facilities HDJU Required for all. 19 T/R Drilling/Stimulation/Intervention. B Medium Facilities HDJU Required for All Drilling and Stimulation. Capable of Light Intervention from WHP (e.g. Coil, Wireline). C Comprehensive Stimulation and Intervention Facilities HDJU Required for all Drilling. Capable of Batch Stimulation and all Interventions. All development wells drilled and completed by HDJU. D Maximum Facilities All Operations from WHP. No HDJU Required Table 5.4 WHP Options Considered All designs considered have a 10k wellhead/tree design for Ockley, and where applicable, a 15k design for Oakwood with 3 m x 3m and 3.25 m x 3.25 m (as per Culzean) well spacing respectively. This is typical of many other well-bay configurations and reflects the access requirements and restrictions imposed by the candidate drilling rigs operational envelope. The HDJU is intended to drill only from 12 slots on first visit. The additional slots are designed for a second phase of drilling. All options are based on a single vertical face jacket (lower cost that the twisted base alternative). For the WHP study report, see Reference 3. Accommodation has been considered in varying degrees for all options with the minimum being a T/R. The approach taken for each option is also outlined in Table. Key features of the WHP topsides design are as follows; Annulus management; Proppant removal; Test manifold; MPFM; Support utilities (chemical injection, drains, emergency power generator); Helideck, lifeboat(s) and life rafts; Crane (varying load capacity dependant on option) Pig launcher 20

21 WHP Option C was used as the reference case. The main reason for this conclusion was that the platform can stimulate once HDJU is removed from site and it also has the capability of interventions without HDJU in later life. This allows prolonging of field life production at minimum cost Host Facilities As stated in Section 3.5, two tieback options were considered. Maersk Oil carried out an assessment on the Joint Venture option in-house. This was based on early investment into a joint processing facility at Jackdaw. It assumes that Ockley will have its own dedicated reception facilities and ullage of the processing facility (including separation, compression and contaminants treatment) from day one of production. Aker (on behalf of the Jackdaw operators BG) carried out an assessment of the Third Party Tieback. This assumes a brownfield module onto an existing Jackdaw processing facility. The module will contain reception facilities and additional compression capacity. This option is limited to Ockley being considered an ullage filler. 21

22 6. Resource and Risk Summary The only prospectivity identified in licences P1120, P1320 is the Ockley and Oakwood discoveries. The resource summaries for these can be seen in tables 6.1 and 6.2. Resource and Risk Summary Discovery Name Stratigraphic level Unrisked recoverable resources Geological Chance of Success Risked P50 MMboe Oil, MMstb Gas, Bcf Low Central High Low Central High Ockley Ockley Fm (Hod) % 99 Table 6.1 Resource summary Ockley. Recoverable resources (mmboe) Mean P99 P90 P50 P10 P01 Pre-drill Post-drill (June 2013) Table 6.2. Resource summary Oakwood. 22

23 7. Conclusions Remaining potential on these licences is recognised in the 2 discoveries, Ockley and Oakwood. After extensive evaluation and activity, the situation in 2014 was that the Ockley development project was not able to pass from Assess stage into Select stage. There was insufficient confidence in achieving successful fracture stimulation of the Ockley reservoir due to the in-situ stress regime. No economic host was available for development and project economics were poor. The Oakwood discovery was not able to support a viable economic appraisal programme. The partnership was aligned in not moving forward with these projects. After frequent collaboration with DECC, the licences determined at end of September