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Home My WebLink About2015 Prudhoe Satellite Oil Pools1 2015 ANNUAL SURVEILLANCE REPORT AURORA PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2014 – JUNE 30, 2015 2 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8B) 3 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8C) 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8D) 4 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8E) 4 7. REVIEW OF PLAN OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8F&G) 5 LIST OF ATTACHMENTS Figure 1: Aurora Well Location Map 1 Figure 2: Aurora Cumulative Voidage Replacement by Region 10 Figure 3: Aurora Voidage History 10 Figure 4: Aurora Reservoir Pressure Map- June 30, 2015 11 Figure 5: Aurora Allocated Production History 13 Figure 6: Aurora Allocated Injection History Table 1: Aurora Monthly Production, Injection, Voidage Balance Summary 6 Table 2: Cumulative Voidage Status by Fault 7 Table 3: Valid Aurora Pressure Surveys 7 3 Prudhoe Bay Unit 2015 Aurora Oil Pool Annual Surveillance Report 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 8 of Conservation Order 457A for the Aurora Oil Pool and covers the period from July 1, 2014 to June 30, 2015. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8 A) Enhanced Recovery Projects Water injection in the Aurora Oil Pool (AOP) started in December 2001. Tertiary EOR Miscible Water Alternating Gas (MWAG) started in the North of Crest (NOC) and West blocks at Aurora in December 2003 and continues expanding to the Southeast Crest (SEC), Crest (CR) and South of Crest (SOC) blocks. Evaluation of hydrocarbon recovery mechanisms for the Aurora Oil Pool (AOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, gas cap presence, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life and will help ensure greater ultimate recovery. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the AOP where injection is justified, water-flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Water injection should maintain average reservoir pressure above 2400 psi in the flood area to ensure hydrocarbon recovery targets are achieved. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility between the reservoir fluid and the injected miscible gas. There will be higher pressure in the area around injection wells and a pressure sink around the producers, which in some cases can be below minimum miscibility pressure (MMP) of approximately 2700 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and voidage replacement ratios. Reservoir Management Strategy The objective of the Aurora reservoir management strategy is to manage reservoir development and depletion to achieve greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, producers experienced increasing gas-oil-ratios (GORs) due 4 to existence of an initial gas cap, primarily in the West side of the field, but also apparent in the CR and SEC areas. Production was restricted to conserve reservoir energy. Beginning in mid- 2001 and continuing into 2003, production from wells S-100, S-106 and S-102 was reduced to approximately half capacity, allowing injection to significantly reduce the GORs by the end of 2003. This practice continued in 2004-5 with curtailment of wells S-108, S-113B and S-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure and productivity in S-108. Pressure data and production performance in S-113B indicates the well is supported by a large gas-cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Irregular pattern waterfloods have been designed to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns are based on the current understanding of compartmentalization; however, reservoir management is a dynamic process. Patterns and producer/injector ratios will be modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring and waterflood performance monitoring to support this feedback and intervention process. Figure 1 shows Aurora well locations and the field development areas. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement by fault block is summarized in Table 2 and Figure 2. Figure 3 summarizes the voidage history of Aurora Field. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed and started in late 2006 to provide increased injection rates to low injectivity patterns. The VRR challenge for this reporting year came from downtime of the Sulzer and Ruston injection pumps at GC-2, downtime of individual injectors due to drilling proximity and pressure management concerns during drilling of offset producers. The Sulzer leaking recycle valves were replaced during the August 2015 GC2 shutdown and the Ruston downtime has been caused by control panel upgrades and exhaust system issues with repairs planned for 4Q 2015. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457B. A summary of reservoir pressure surveys is shown in Table 3. The field average reservoir pressure map is shown in Figure 4. Static BH pressures were gathered in 14 wells during the reporting period. Most producers in the AOP have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) There were no injection profiles that were run in the Aurora Field during this reporting year. There were no production profiles that were run in the Aurora Field during this reporting year. 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) 5 Since August 2002, Aurora production allocation has adhered to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Aurora production volumes at the end of each month. A minimum of one well test per month is used to check the performance curves and to verify system performance, with more frequent testing during the first three months of production in new wells and after major wellwork. Allocated daily production and injection is shown in Table 1. Graphical representation of the allocated figures is shown in Figures 5 and 6. 7. REVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8 F & G) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation and are annotated in Figure 1. Differing initial gas-oil and oil-water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area, 2) North of Crest Area (NOC), 3) South East of Crest Area (SEC), 4) Crest Area (AURCR), and 5) South of Crest Area (SOC) After establishing primary production from each area, water-flood and tertiary EOR has been implemented to provide pressure support and reduce residual oil saturations. The West and North of Crest areas began production in 2000-2001; water injection commenced in 2002 and MWAG began in December 2003. Initiation of water injection into the South East of Crest Area began with conversion of Wells S-112 and S-110 to injection in June and July 2003 and conversion to MWAG in 2006. Crest Area production began in mid-March 2003 with startup of Aurora Well S-115; Well S-117 production began in early June 2003 with a water-flood startup in August 2004 with newly drilled injection wells S-116i and S-120i that were put on MWAG in 2006. South of Crest Area production started-up on August, 2002 with the well S-113B. This area was separated from the West and Crest Area after confirming compartmentalization between both areas. In 2014 the well S-135 was drilled at SOC Area to continue expanding the reservoir development. Summarized below are significant events and accomplishments at Aurora over the past year:  The injection management strategy at Aurora targeted a voidage replacement ratio of 1.2 through WAG injection to maintain reservoir pressure and capture EOR benefits.  S-101: Injector S-101 had a RWO to repair two production casing leaks. Workover was successful and the well was POI 2/2/2015.  S-104: Injector S-104 was repaired with a patch and POI in November 2014 after being SI since mid-2013 for TxIA communication.  S-108: Producer S-108 was P&A’d after a RWO attempt in October 2014 found collapsed tubing and casing @ 2601’ MD. The bottomhole location has been replaced by the heel of new well S-42A.  S-128: WAG injector S-128 was put on MI injection in May 2015 for the first time.  S-129: A hydraulic fracture treatment was pumped on S-129 in May 2015 and the well was put online in June. During the flowback through ASRC, the peak post-frac oil rate was 2,486 bopd at a GOR of 682 scf/stbo and WC of 34.4% during a 4-hour test.  S-135: New producer S-135 was put online in October 2014, with an initial oil rate of 884 bopd at a GOR of 543 scf/stbo and a WC of 2%. 6 The Aurora owners will continue to evaluate optimal well count, well utility and well locations to maximize recovery. Table 1: Aurora Monthly Production, Injection, Voidage Balance Summary Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2014 1515 4049 3757 2.10 0 17470 8/31/2014 0 0 0 Non Injection 0 0 7 9/30/2014 2998 7495 5598 1.37 4201 17093 10/31/2014 4095 8612 9311 1.08 6958 16659 11/30/2014 3842 7160 10022 1.29 11743 16513 12/31/2014 5529 17034 16732 0.87 12785 22756 1/31/2015 5855 12772 18616 0.97 14254 22801 2/28/2015 6094 12243 20839 0.93 14023 23252 3/31/2015 6512 14201 25394 0.77 10388 24669 4/30/2015 5812 13303 22793 0.75 6125 23748 5/31/2015 4206 11390 11600 1.28 3117 29115 6/30/2015 5206 14633 14831 0.88 3199 25216 Table 2: Cumulative Voidage Status by Fault Block On 6/30/2015 AUR-CR* AUR-NOC** AUR-SEC* AUR-WEST* AUR-SOC* Total Inj Cum MRVB 13,937 36,979 8,421 61,478 8,261 Total Prod Cum MRVB 28,843 44,082 11,647 71,231 20,519 Cum I/W ratio 0.48 0.84 0.72 0.86 0.4 Bo 1.32 rb / stb oil Bg 0.843 rb / mcf gas Bw 1.02 rb / stb water Rs 0.65 mscf / stb oil * Initial gas-cap Bmi 0.62 rb / mcf gas MI ** Solution gas only Table 3 - Valid Aurora Pressure Surveys 8 6. Oil Gravity: 0.9SG/25 API 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instruction s 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut- In Time, Hours 16. Press. Surv. Type (see instruction s for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) S-03 500292069500 O 640120 6494.37-6507.08 6524.95-6537.76 8679.61-8721.40 8825.42-8888.43 5/27/2015 480 SBHP 144 6600 2690 6700 0.27 2718 S-100 500292296200 O 640120 6728.24-6762.28 6771.09-6778.88 6777.46-6769.00 6761.85-6735.69 6733.02-6731.60 6729.70 6724.55 6724.97-6731.14 6733.49-6741.26 6741.81-6746.23 5/30/2015 528 SBHP 147 6700 3001 6700 0.44 3001 S-102 500292297200 O 640120 6681.5-6687.57 6687.57-6690.45 6687.57-6693.31 6690.45-6693.31 6693.31-6696.13 6697.81-6703.09 6699.92-6685.10 6685.10-6723.26 9/7/2014 1248 PBU 141 6487 2354 6700 0.33 2424 S-102 500292297200 O 640120 6681.5-6687.57 6687.57-6690.45 6687.57-6693.31 6690.45-6693.31 6693.31-6696.13 6697.81-6703.09 6699.92-6685.10 6685.10-6723.26 6/3/2015 648 PBU 140 6487 2113 6700 0.33 2167 S-103 500292298100 O 640120 6604.11-6604.76 6604.76-6617.15 6617.15-6617.80 6623.01-6635.98 6642.45-6650.19 6657.91-6664.33 6670.73-6675.85 6740.90-6753.63 6763.83-6774.02 6779.12-6785.50 9/7/2014 1248 PBU 138 6429 2625 6700 0.33 2714 S-104 500292298800 WAG 640120 6712-6739 11/3/2014 11952 SBHP 125 6700 2749 6700 0.40 2749 S-109 500292313500 O 640120 6703.1-6703.93 6715.61-6730.61 6731.85-6740.66 6739.95-6739.55 6739.45-6738.96 6743.22-6747.09 6746.44-6754.57 6758.5-6759.75 5/30/2015 552 SBHP 144 6700 2659 6700 0.34 2659 S-112 500292309900 WI 640120 6641-6655 6672-6679 6703-6684 4/17/2015 1056 SBHP 129 6700 3824 6700 0.45 3824 S-112 500292309900 WI 640120 6641-6655 6672-6679 6703-6684 5/18/2015 1776 SBHP 130 6700 3720 6700 0.44 3720 S-113B 500292309402 O 640120 6674-6749 4/14/2015 6480 SBHP 152 6700 2730 6700 0.30 2730 S-115 500292313000 O 640120 6711.97-6743.58 8/29/2014 1008 SBHP 144 6600 2404 6700 0.33 2437 S-118 500292318800 O 640120 6617-6651 6697-6711 10/30/2014 4392 SBHP 136 6383 1765 6700 0.43 1902 S-121 500292330400 O 640120 6692-6736 6745-6756 6770-6772 6766-6759 6751-6723 6721-6724 6728-6746 6752-6762 6765-6754 6748-6744 6749-6751 6752-6754 6756-6758 6764-6779 9/4/2014 1176 PBU 140 6581 2736 6700 0.33 2775 S-125 500292336100 O 640120 6704.62-6743.94 6714.31-6775.28 6785.74-6787.66 6786.73-6782.62 6771.12-6747.05 6740.74-6732.47 6725.94-6699.15 9/4/2014 1176 PBU 147 6569 2296 6700 0.33 2339 S-135 500292350800 O 640120 6698.24-6846.95 6848.06-6833.24 6834.59-6858.32 6861.06-6865.06 6867.50-6894.98 5/18/2015 245 PBU 147 6592 2936 6700 0.33 2972 S-129 500292343300 O 640120 6724.25-6725.02 6747.41-6752.28 6751.06-6761.81 6763.27-6783.25 6782.90-6740.05 6737.26-6728.57 9/19/2014 1536 PBU 147 6554 2719 6700 0.33 2767 ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E Benson Blvd, Anchorage, AK 99519-8612 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field: Aurora Oil Pool 6700 TVDss 0.72 Printed Name Pedro A. San Blas D. Date August, 4. 2015 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Pedro A. San Blas D.Title Reservoir Engineer 9 Figure 1: Aurora Well Location Map 10 Figure 2: Aurora Cumulative Voidage Replacement by Region 11 Figure 3: Aurora Voidage History 12 Figure 4: Aurora Reservoir Pressure Map –June 30, 2015 13 Figure 5: Aurora Allocated Production History 14 Figure 6: Aurora Allocated Injection History 7/14 – 6/15 Borealis Annual Surveillance Report 1 2015 ANNUAL SURVEILLANCE REPORT BOREALIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2014 – JUNE 30, 2015 7/14 – 6/15 Borealis Annual Surveillance Report 2 CONTENTS 1. INTRODUCTION ....................................................................................................................... 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) ............................................................. 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) ..... 3 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) .......... 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) ..................................... 4 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) ............................................................................................................................................. 4 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) .................................................................................................................................... 4 LIST OF ATTACHMENTS Figure 1: Borealis Well Location Map ................................................................................................ 9 Figure 2: Borealis Allocated Production Profile ............................................................................... 10 Figure 3: Boreallis- Total Production/Injection rates (rvb/d), VRR Rate, and Cum VRR ................ 10 Figure 4: Borealis Total Injection Rates- Gas & Water.................................................................... 12 Figure 5: Borealis Reservoir Pressure Map .................................................................................... 12 Table 1: Borealis Monthly Production, Injection, Voidage Balance Summary .................................. 6 Table 2: Borealis Cumulative Production & Injection Summary ........................................................ 7 Table 3: Borealis Pressure Surveys .................................................................................................. 8 7/14 – 6/15 Borealis Annual Surveillance Report 3 Prudhoe Bay Unit 2015 Borealis Oil Pool Annual Reservoir Report 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 471 for the Borealis Oil Pool and covers the period from July 1, 2014 to June 30, 2015. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) Enhanced Recovery Projects Waterflood has been implemented in Borealis, which includes 20 injectors in full service. Enhanced Recovery Projects using Miscible Injectant (MI) are implemented in Borealis. Currently 19 of the 20 injectors can interchange between water and MI injection. Figure 1 shows Borealis well locations. Reservoir Management Summary The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery, consistent with prudent oil field engineering practices. Water injection was initiated in June 8, 2002 to restore reservoir pressure and reduce gas-oil-ratios (GORs), thereby enabling wells to be produced at their full capacity. An irregular pattern waterflood has been designed and implemented to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and GORs stabilized near solution GOR. When water injection was initiated, a VRR target greater than 1.0 was implemented in order to catch up with voidage. The current VRR target is 1.0. Injection facility limitations were identified in 2003, which limited the delivery pressure of water to be injected to the field. Booster pumps were installed at Z Pad to provide increased injection pressure and better water distribution. The increased injection pressure has allowed better management of injection at a pattern level. The Borealis waterflood strategy is progressing as planned however Borealis has experienced water breakthrough earlier than expected in many patterns. Impacts of the early breakthrough include reduced production due to unfavorable wellbore hydraulics and gas-lift supply pressure limitations. Remedies have included gas-lift redesign and optimization and prioritization of gas-lift use. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) 7/14 – 6/15 Borealis Annual Surveillance Report 4 Monthly production and injection surface volumes for July 2014 to June 2015 are summarized in Table 1, and cumulative volumes can be found in Table 2. Figures 2, 3 and 4 graphically depict this information since start-up. Subsequent to initiating and stabilizing injection, monthly reservoir voidage will be balanced with water injection, consistent with the reservoir management strategy. During the reporting period, Borealis suffered from low VRR because the Z-Pad booster pumps were offline due to electrical failure. The B-Booster was repaired in June 2015 and the A-Booster repair is planned for 4Q 2015. The VRR in Borealis should improve with the return of both boosters to full time service. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. Figure 5 is a map of reservoir pressures collected over the last reporting period. Five of the newer producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures, and reservoir connectivity on a continuous basis. Static Bottom Hole pressures were gathered in 19 wells during reporting period. Most producers in Borealis have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) There were no injection or production profiles run in the Borealis Field during this reporting year. 6. REVIEW OF POOL PRODUCTION ALLOCATION AND W ELL TEST EVALUATION (RULE 9E) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is now being applied to adjust the total Borealis production similar to IPA production allocation procedures. A minimum of one well test per month is used to check the performance curves and to verify system performance. In an effort to improve well test quality, Weatherford Generation 2 multi-phase meters (Gen 2) were installed at the L-pad and V-pad test headers. In 2012, the V-pad Gen 2 meter was accepted as the primary metric for production allocations, and the V-pad Well Pad Separator was taken out of service. The L-pad Gen 2 meter is being used to allocate the production rates for the majority of the L-pad online wellstock; the L-pad Well Pad Separator is currently still in service, but is largely used as a back-up for the Gen 2 meter. During the reporting period, improvements in Gen 2 maintenance and calibration activities were identified and we are working to implement these changes for future reporting cycles. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) Miscible gas injection and water-alternating with miscible gas injection is used to increase the economic recovery of Borealis reservoir hydrocarbons. Injection wells are completed for Enhanced Oil Recovery services. Waterflood and tertiary EOR have been implemented to provide pressure support and reduce residual oil saturations on all three Borealis Pads, L, V and Z. 7/14 – 6/15 Borealis Annual Surveillance Report 5 Injection started on June 8, 2002. Water injection manifolding and booster pumps have been installed and have been operating since January 2004. These booster pumps allow even pattern support throughout the waterflood providing optimum waterflood spacing, configuration, timing and operations. The Borealis waterflood management strategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize oil recovery. The Z-Pad expansion project was completed in 2011. The expansion facilitates the further development of Borealis. In 2014 one additional injector Z-114 was placed in service. Currently Borealis owners continue evaluating the optimal number of development wells in this area to continue reservoir development. In March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut in during their MI responses due to elevated H2S in the returned MI. The installation of Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from MI. 7/14 – 6/15 Borealis Annual Surveillance Report 6 Table 1: Borealis Monthly Production, Injection, Voidage Balance Summary Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB VRR Cum RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2014 5242 12869 13271 0.963 0.862 11922 21630 8/31/2014 0 0 0 Non inj 0.862 0 0 9/30/2014 9467 18710 25368 0.747 0.861 7418 33542 10/31/2014 12436 26458 34591 0.612 0.859 17467 32318 11/30/2014 11761 25485 29308 0.525 0.856 12769 25518 12/31/2014 10304 22315 28839 0.706 0.855 18871 30001 1/31/2015 9910 24407 29867 0.729 0.854 20120 32616 2/28/2015 9385 21558 27599 0.791 0.854 18980 32767 3/31/2015 9811 21520 25873 0.827 0.854 16860 34919 4/30/2015 9932 21679 28343 0.728 0.853 10449 35289 5/31/2015 8756 16635 24706 0.765 0.852 11403 29572 6/30/2015 8216 18164 16294 0.759 0.852 11999 23510 7/14 – 6/15 Borealis Annual Surveillance Report 7 Table 2: Borealis Cumulative Production & Injection Summary MONTH_ENDING Data units 06-30-2015 Oil Prod Cum 77817 MSTB Gas Prod Cum 109019 MMSCF Water Prod Cum 93291 MSTB Gas Inj Cum 79717 MMSCF Water Inj Cum 173468 MSTB Total Inj Cum 227895 MRVB Total Prod Cum 267138 MRVB VRR Cum 0.852 RVB/RVB Bo 1.25 rb / stb oil Bg 1.013 rb / mcf gas Bw 1.03 rb / stb water Rs 0.457 mscf / stb oil Bmi 0.62 rb / mcf gas MI 7/14 – 6/15 Borealis Annual Surveillance Report 8 Table 3: Borealis Pressure Surveys 1. Operator: BP Exploration (Alaska) Inc. 3. Unit or Lease Name:6. Oil Gravity: 7. Gas Gravity: Prudhoe Bay Unit 0.9 SG / 25° API 0.72 8. Well Name and Number: 9. API Number 50-XXX-XXXXX-XX-XX 10. Oil (O) or Gas (G) 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDss 19. Final Pressure at Tool Depth 20. Datum TVDss (input) 22. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) L-100 50-500-29228-58-01 O 640130 6562.13-6594.12 5/31/2015 552 SBHP 161 8,546 2,924.50 6,600 0.4353 2,924.50 L-101 50-500-29228-65-00 O 640130 6387.21-6413.83, 6417.78-6429.61, 6444.88-6449.32, 6449.32-6450.8, 6532.09-6551.8 9/16/2014 1440 SBHP 151 7,034 3,086.40 6,600 0.1722 3,120.83 L-102 50-500-29230-71-00 O 640130 10144 - 10170, 10170 - 10200, 10280 - 10290 5/28/2015 504 SBHP 156 10,272 3,084.00 6,600 0.4317 3,084.00 L-105 50-500-29230-75-00 WAG 640130 6213.58-6229.98 6283.69-6300.32 6475.47-6484.87 6484.87-6492.56 6484.87-6501.96 6492.56-6499.40 6499.40-6501.96 6501.96-6528.47 6554.13-6559.26 7/13/2014 792 SBHP 141 8,157 3,163.00 6,600 0.4396 3,163.20 L-106 50-500-29230-55-00 O 640130 6496.35-6560.33 5/29/2015 504 SBHP 157 6,984 3,089.00 6,600 0.4202 3,109.90 L-110 50-500-29230-28-00 O 640130 8467 - 8521 6/13/2015 864 SBHP 159 8,496 3,092.40 6,600 0.2394 3,092.30 L-117 50-500-29230-39-00 WAG 640130 6474.93-6523.23, 6535.52-6540.25 8/26/2014 936 SBHP 146 8,787 3,703.60 6,600 0.3961 2,832.23 L-118 50-500-29230-43-00 O 640130 8726 - 8776 8/26/2014 960 SBHP 152 8,743 2,840.30 6,600 0.4343 2,908.80 L-124 O 640130 6353.60-6404.21, 6401.91-6391.30, 6393.65-6404.27 10/13/2014 8976 PBU 148 8,211 2,535.10 6,600 0.33 2,647.00 V-102 50-500-29230-70-00 O 640130 6456.04-6475.81 6456.04-6495.58 6475.81-6495.58 6495.58-6525.25 6525.25-6545.02 6584.57-6604.34 8/28/2014 1008 SBHP 158 8,530 3,262.90 6,600 0.3942 3,288.50 V-106A 50-500-29230-83-01 O 640130 6560.63-6571, 6586.23-6581.69, 6574.21-6566.47, 6566.97-6571.66, 6575.64-6576.21, 6575.91-6574.93, 6542.76-6535.7, 6528.17-6526, 6520.6- 6542.85, 6586.88-6583.5, 6581.47- 6582.7, 6582.19-6599.63, 6601.31- 6602.25 10/13/2014 2088 PBU 152 8,629 3,440.00 6,600 0.33 3,480.00 V-108 50-500-29231-12-00 O 640130 6/1/2015 576 SBHP 157 9,118 2,803.00 6,600 0.4375 2,803.00 V-117 50-500-29231-56-00 O 640130 6640.9-6622.68, 6616.5-6604.36, 6598.39-6600.85, 6628.62-6633.47, 6627.57-6612.1, 6612.02-6598.3, 6596.72-6596.74, 6597.57-6608.84, 6616.21-6620.87 5/17/2015 7272 SBHP 156 10,494 3,220.29 6,600 0.4376 3,220.30 V-122 50-500-29233-28-00 O 640130 6633.07-6625.4, 6620.42-6611.13, 6606.5-6603.16, 6601.28-6596.49, 6595.92-6601.47, 6602.68-6603.59, 6605.05-6619.23, 6635.44-6631.5, 6631.34-6632.11, 6631.01-6630.72, 6632.17-6631.23, 6630.7-6635.79, 6636.1-6637.88 9/5/2014 1824 PBU 150 10,008 2,663.80 6,600 0.33 2,727.00 Z-100 50-500-29231-82-00 O 640130 6884 - 6920, 6924 - 6930 6/1/2015 600 SBHP 151 6,901 2,632.74 6,600 0.4388 2,632.70 Z-108 50-500-29232-92-00 O 640130 6555.55-6579.67 10/13/2014 14880 PBU 144 7,102 3,040.00 6,600 0.33 3,096.00 Z-112 50-500-29233-80-00 O 640130 6604-6642, 6641-6616, 6617-6644, 6644-6635, 6632-6626 5/27/2015 480 SBHP 149 7,719 2,650.32 6,600 0.3376 2,650.30 Z-113 50-500-29234-50-00 O 640130 6505, 6577, 6551, 6544, 6553, 6549 9/4/2014 1176 PBU 143 8,626 2,789.00 6,600 0.33 2,891.00 Z-115 50-500-29234-68-00 O 640130 6484-6558 9/7/2014 1248 PBU 139 10,627 2,371.00 6,600 0.33 2,504.00 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Pedro A. San Blas D.Title Reservoir Engineer Printed Name Pedro A. San Blas D.Date 6-Aug-2015 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 2. Address: P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 Prudhoe Bay Field, Borealis Oil Pool 6600 TVDss 4. Field and Pool:5. Datum Reference: 7/14 – 6/15 Borealis Annual Surveillance Report 9 Figure 1: Borealis Well Location Map 7/14 – 6/15 Borealis Annual Surveillance Report 10 Figure 2: Borealis Allocated Production Profile Figure 3: Borealis – Total production / Injection rates (rvb/d), VRR Rate, and Cumulative VRR 7/14 – 6/15 Borealis Annual Surveillance Report 11 7/14 – 6/15 Borealis Annual Surveillance Report 12 Figure 4: Borealis Total Injection Rates-Gas & Water Figure 5: Borealis Reservoir Pressure Map 7/14 – 6/15 Borealis Annual Surveillance Report 13 7/14 – 6/15 Midnight Sun Annual Reservoir Report 1 2015 ANNUAL SURVEILLANCE REPORT MIDNIGHT SUN PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2014 – JUNE 30, 2015 7/14 – 6/15 Midnight Sun Annual Reservoir Report 2 CONTENTS 1. Introduction 3 2. Progress of Enhanced Recovery Project Implementation and Reservoir Management 3 3. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) 3 4. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) 4 5. Results and Analysis of Production and Injection Logging Surveys (Rule 11 d) 4 6. Results of Well Allocation and Test Evaluation (Rule 11 e) 4 7. Future Development Plans and Review of Plan Operations and Development (Rule 11 f & g) 5 LIST OF ATTACHMENTS Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary .......................... 6 Table 2: Reservoir Pressure Surveys ............................................................................................... 7 7/14 – 6/15 Midnight Sun Annual Reservoir Report 3 Prudhoe Bay Unit 2015 Midnight Sun Annual Reservoir Report This Annual Reservoir Report for the period from July 1, 2014 through June 30, 2015 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 452 for the Midnight Sun Oil Pool. This report summarizes surveillance data and analysis and other information as required by Rule 11 of Conservation Order 452. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11 a) Production and injection volumes for the 12-month period ending June 30, 2015 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to ensure greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, both producers experienced increasing gas-oil-ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR’s to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil in-flux into the gas cap from mid-field water injection. Placement of the wells drilled in 2001 and voidage management is minimizing this risk. A VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re-saturation of oil into the gas cap. During the period covered by the report, the VRR averaged 1.28. Midnight Sun gas production has remained level during the report period as reservoir pressure has leveled off. Both oil and water production rates have remained fairly constant during the report period. Well E-101 currently produces at ~89.9% watercut, and Well E-102 produces at ~94.8% watercut. Since 2005, gas lift has been utilized to produce the Midnight Sun wells more efficiently. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) A total of six Midnight Sun wells have been drilled, with the most recent well, P1-122, drilled in 2015 from Pt. McIntyre. Midnight Sun is expected to have an oil production rate of approximately 1000 BOPD through 2015. A peak water injection rate of 20-25 MBWPD for the field has been achieved since E-103 and E-104 were converted to water injection in 2003. Monthly production and injection surface volumes for the reporting period are summarized in Table 1 along with a voidage balance of produced and injected fluids for the report period. 7/14 – 6/15 Midnight Sun Annual Reservoir Report 4 Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) Reservoir pressure monitoring is performed in accordance with Rule 8 of Conservation Order 452. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Reservoir pressures have remained stable throughout the last year. Results and Analysis of Production & Injection Logging Surveys (Rule 11 d) In July 2010, three unique tracers were injected into each of the three Midnight Sun injection wells (E-100, E-103, & E-104) with the intent to evaluate communication between the injection and production wells. Samples to check for tracers at the producers (E-101 & E-102) were initially taken every day for the first week, once a week for the next month, and remained on an every two week sample schedule until the study ended in October 2012. Starting in March 2012, tracer from injector E-104 began showing up in samples from producer E-102, but the validity of these results was questioned. Samples from E-101 and E-102 since March 2012 underwent testing to determine the extent of the tracer breakthrough from E-104. No more tracer breakthrough was observed through the duration of the study, which concluded in October 2012 with no significant results. The tracer was long overdue for a reservoir with the size and production/injection rates of Midnight Sun. A pressure fall-off test was completed July 26th 2014 for injector E-104. E-104 only operates at 5-10% of the daily injection rates of both E-100 and E-103. This rate has declined with time and the block shows evidence of increased pressure, indicating the well may not be efficiently sweeping or providing efficient pressure support. A static bottom hole pressure was taken on September 3rd 2015 for injector E-104. The SBHP will provide information on reservoir pressure behavior to confirm the observations from the pressure fall-off test. Results of Well Allocation and Test Evaluation (Rule 11 e) Midnight Sun wells are tested using the E-Pad test separator, and Midnight Sun production is processed through the GC-1 facility. Midnight Sun production allocation has been performed according to the PBU Western Satellite Production Metering Plan for the report period. Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) Development plans for the Midnight Sun Oil Pool are set forth in the Sixteenth Plan of Development for the Midnight Sun Participating Area. Well E-102, located to the south of Well E-100, was planned as an injection well that would undergo a pre-production period. Well E-102 has been utilized as a producer to date and has been converted to a permanent producer. Well E-103, located to the southwest of Well E-100, was originally drilled as an up-dip production well. Due to an apparent conduit to the overlying gas cap, Well E-103 was shut-in shortly after being placed on production due to excessive gas production. Well E-103 was converted to water injection service during 2003. Well E- 104, drilled in the northwest corner of the field, was drilled as an additional injector well. 7/14 – 6/15 Midnight Sun Annual Reservoir Report 5 P1-122, a Water-Alternating-Gas (WAG) injector was drilled in 2015 from P1 Pad (only pad with Miscible Injectant nearby) to supply MI to enhance the oil recovery. There is no other development planned for the Midnight Sun Oil Pool. 7/14 – 6/15 Midnight Sun Annual Reservoir Report 5 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = .795 rb/Mscf Date Oil Prod (stb) Water Prod (stb) Total Gas Prod (Mscf) Produced Lift Gas (Mscf) Water Inj (stb) Cum Oil (stb) Cum Gas (Mscf) Cum Gas less Prod Lift Gas (Mscf) Net Reservoir Voidage (rb) 2014/07 28,916 410,856 82,178 122,232 454,355 20,092,409 63951805 54,938,388 -9,435 2014/08 28,957 402,186 103,727 115,413 512,546 20,121,366 64055532 54,899,234 -81,533 2014/09 27,951 362,723 100,737 117,988 501,254 20,149,317 64156269 54,887,553 -110,218 2014/10 33,503 426,454 75,483 144,199 534,585 20,182,820 64231752 54,869,493 -73,616 2014/11 34,171 420,931 124,335 91,778 493,574 20,216,991 64356087 54,835,146 -2,089 2014/12 39,423 464,280 207,655 109,695 549,444 20,256,414 64563742 54,933,106 18,022 2015/01 35,784 447,833 175,458 140,844 577,550 20,292,198 64739200 54,971,129 -67,512 2015/02 29,444 367,928 125,317 134,365 320,240 20,321,642 64864517 54,987,033 89,728 2015/03 19,400 303,167 81,507 125,234 364,290 20,341,042 64946024 54,954,505 -41,651 2015/04 26,470 329,229 67,408 129,277 491,491 20,367,512 65013432 54,911,484 -138,007 2015/05 27,437 318,453 69,510 138,685 539,014 20,394,949 65082942 54,851,752 -197,290 2015/06 20,434 246,467 88,353 146,578 498,163 20,415,383 65171295 54,783,205 -237,958 2015/07 27,910 308,520 51,170 122,031 426,463 20,443,293 65222465 54,724,442 -89,867 6 7/14 – 6/15 Midnight Sun Annual Reservoir Report 6 Table 2: Reservoir Pressure Surveys 6. Oil Gravity: 25-29 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) E-100 50-029-22819-00 WI MSOP KUP 8045-8122, 8122-8136 7/26/14 96 SBHP 124 8,050 ft. 3,434 8050 0.45 3,434 3. Unit or Lease Name:4. Field and Pool: 5. Datum Reference: Marcus Charles 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Marcus CharlesSignature 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Midnight Sun Printed Name Title Date Pad Engineer August 11, 2014 8050' TVDss 0.72 ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 7 1 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT 2015 ANNUAL SURVEILLANCE REPORT ORION PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2014 – JUNE 30, 2015 2 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION ....................................................................................................................... 3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) .... 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) ......... 3 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) ........................................................................................ 6 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) ............................................... 7 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) ............................................................ 7 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) ...................................................................................................................... 8 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) .................................................... 9 LIST OF ATTACHMENTS Figure 1: Orion production and injection history .............................................................................. 11 Figure 2: Orion voidage history ........................................................................................................ 11 Figure 3: Orion pressures at datum ................................................................................................. 16 Figure 4: Orion pressures in map view ............................................................................................ 17 Table 1: Orion monthly production and injection summary .............................................................. 10 Table 2: Orion pressure survey detail .............................................................................................. 12 Table 3: Injection and production profiles ........................................................................................ 18 3 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2015 ORION OIL POOL ANNUAL SURVEILLANCE REPORT 1. INTRODUCTION This Annual Surveillance Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 505B, and covers the period from July 1, 2014 to June 30, 2015. 2. V OIDAGE B ALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,693 BOPD, 4.0 MMSCFD (FGOR 843 SCF/STB), and 3,496 BWPD (WC 43%). Water injection during this period averaged 6,973 BWIPD with 8.8 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.3. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. A NALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 505B. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates valid Orion pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed-off rates. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir 4 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT pressure from pressure build-up (PBU) or pressure fall-off (PFO) data is difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre- injection or pre-production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is becoming increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200 and is supported by injectors L-211i, L-212i, and L-218i. Measured pressures in the polygon range from 2000 psi to 2300 psi. During the reporting period, there was no production or injection due to producer L-200 being offline for sanding issues. Poylgon 1A This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-215i, L- 216i, L-217i, L-219i, and L-223i. Measured pressures in the polygon range from 1900 psi to 2000 psi. During the reporting period, producer L-203 was offline for sanding issues and L-250 was offline a majority of the time for hydrate issues. Consequently, offset injectors L-215i and L-216i were also offline to balance voidage. The operator is evaluating options to return the wells in Polygon 1A to active status. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L-213i, V-210i, V-211i, V-212i, V-213i, V-214i, V-215i, V-216i, V-217i, V-218i, V-222i, V-223i, V-225i, V- 229i. Measured pressures in the polygon range from 1300 psi to 2200 psi. The lowest pressure in the polygon was observed to be injector V-222i’s OA sand. In 2012, a matrix bypass event was identified in the OA sand between producer V-202 and injector V-222i. The OA sand in injector V-222i was subsequently isolated by replacing the waterflood regulating valve with a dummy valve, thus allowing the injector to remain online while remediation options were evaluated. The matrix bypass event was remediated in early 2014 and by all accounts the wellwork appears to be a success as a reduction in OA sand injectivity was observed. To date, no significant increase in OA pressure has been observed. . In October 2014, injector V-211i was placed on miscible gas injection which quickly broke through to offset producer V-203. Diagnostic wellwork was performed January 2015, confirming a matrix bypass event in the OA sand. Wellwork is pending to remediate the matrix bypass event in V-211. Injector V-213i was offline for a majority of the reporting period due to a previously identified matrix bypass event in both the OA and Oba sands. The matrix bypass event was remediated in October 2014 and by all accounts the wellwork appears to have been a success as a reduction in OA and Oba injectivity was observed. The well was placed back on injection in February 2015. 5 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT Polygon 2A This polygon contains producers L-201, L-204, and V-207 and is supported by injectors L-210i, L- 214Ai, L-222, V-219i, V-220i, V-221i, V-224i, and V-227i. Measured pressures in the polygon range from 1300 psi to 2400 psi. One of the lowest pressures in the polygon was observed at producer L-204. As reported previously, producer L-204 is located in an isolated fault block receiving minimal injection support from offset injectors L-214A and V-220. Due to the narrow size of the fault block, there is insufficient space to place additional injectors to provide full injection support. On two separate occassions, producer L-204 was cycled on for a month and subsequently shut-in to allow reservoir pressure to build-up. Currently, producer L-204 is offline and reservoir pressure is 1304 psi.. In addition, reduced reservoir pressures were observed in injectors L-222i and V-224i as these injectors had either been online with clogged waterflood regulating valves or offline for a period of time prior to acquiring the pressure data; offset producer remained online.  Injector L-222i was offline for the majority of the reporting period. In October / November 2013, the waterflood regulating valves set across the OA and Obd sands became clogged . Wellwork to change out the waterflood regulating valves was performed in November 2014. The well was placed back on injection and shortly afterwards all of the waterflood regulating valves became clogged and the well had to be shut-in due to low injectivity. Wellwork to change out the waterflood regulating valves and address the low injectivity is pending. As noted in prior reports, the reservoir pressure initially observed in the OA sand upon completion was ~1200 psi. After extended periods of injection into the OA sand, reservoir pressure in the OA sand has risen to 1302 psi.  Injector V-224i went offline in January 2014 to change out the waterflood regulating valves. While conducting the wellwork, one of the waterflood regulating valves was found to be flowcut. Additional diagnostics were performed and the mandrel where the flowcut waterflood regulating valve had been installed was determined to be damaged. A swell dummy valve was installed in the damaged mandrel in January 2014. Subsequent diagnostics indicate the swell dummy valve was not successful in resolving the issues with the damaged mandrel. Injector V-224i remained offline until integrity of the mandrel was restored in October 2014. In November 2014, injector V-224i was placed on miscible gas injection which quickly broke through to offset producer V-207. Diagnostic wellwork was performed January 2015, confirming a matrix bypass event in the Oba sand. The matrix bypass event was remediated in July 2015 and by all accounts the wellwork appears to have been a success as a reduction in Oba injectivity was observed. Injector V-224 is currently offline as waterflood regulating valves need to be installed. Polygon 5S This polygon contains producer L-205 and is supported by injectors L-220i and L-221i. Measured pressures in the polygon range from 2000 psi to 2300 psi. During the reporting period, there was no production or injection due to producer L-205 being offline for sanding issues. 6 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: A production log (memory mode) was run in L-201 during the reporting period. Unfortunately, production splits could not be obtained due to poor data quality resulting from a tool failure. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well Fluids Sampling: A well fluids sampling program is ongoing to gather high quality and high frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples is later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples , and improve analysis techniques to improve data value. Well Testing Improvements: In an effort to improve well test quality, Weatherford Generation 2 multi-phase meters (Gen 2) were installed at the L-pad and V-pad test headers. In 2012, the V-pad Gen 2 meter was accepted as the primary metric for production allocations, and the V-pad Well Pad Separator was taken out of service. The L-pad Gen 2 meter is being used to allocate the production rates for the majority of the L-pad online wellstock; the L-pad Well Pad Separator is currently still in service, but is largely used as a back-up for the Gen 2 meter. During the reporting period, improvements in Gen 2 maintenance and calibration activities were identified and we are working to implement these changes for future reporting cycles. 7 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT Injection Logs: No injection logs were run during the reporting period. Injection logs are used to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. 5. REVIEW OF P OOL P RODUCTION ALLOCATION (RULE 9D) Orion production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust production on a daily basis. A minimum of one well test per month is used to check the performance curves, and to verify system performance, with more frequent testing during new well start-up and after significant wellwork. 6. P ROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) Enhanced Recovery Project - Waterflood: Primary production from the Orion oil pool commenced in 2002 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 6,973 BWIPD. Cumulative injection through June 2015 was 39.2 MMSTBW , which has been injected in 36 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Project - Miscible Injectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began 8 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT later that year in the updip portion of Polygon 2. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 8.8 MMSCFD. Cumulative injection through June 2015 was 19.6 BCF, which has been injected in 23 water-alternating-gas injectors. No new water-alternating-gas injectors have been placed into service during the reporting period. However, water-alternating-gas injector V-229i was placed on miscible gas injection for the first time. Reservoir Management Strategy: The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods are managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. During the reporting period, two matrix bypass events were confirmed; injectors V-211i and V-224i. In October 2014, injector V-211i was placed on miscible gas injection which quickly broke through to offset producer V-203. Diagnostic wellwork was performed January 2015, confirming a matrix bypass event in the OA sand. Wellwork is pending to remediate the matrix bypass event in V-211. In November 2014, injector V-224i was placed on miscible gas injection which quickly broke through to offset producer V-207. Diagnostic wellwork was performed January 2015, confirming a matrix bypass event in the Oba sand. The matrix bypass event was remediated in July 2015 and by all accounts the wellwork appears to have been a success as a reduction in Oba injectivity was observed. Injector V-224 is currently offline as waterflood regulating valves need to be installed. 7. P ROGRESS OF P LANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE P OOL (RULE 9 F) New Sands: 9 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT As mentioned in previous reports, Orion includes three wells with slotted liner completions in the N-sand; L-203, L-205, and V-207. 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT B REAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, no new responses to miscible injectant were observed. To date, in the life of the field, responses to miscible injectant have been observed in the following producers: L- 201, V-202, V-203, V-204, V-205, and V-207. 10 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT TABLE 1: ORION MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-14 88,757. 57,233. 62,662. 156,975. 36,220. 30,432,720. 28,804,971. 8,248,384. 36,846,963. 46,931,102. -6,097 3,428,298 1.04 Aug-14 0.0.0.0.0.30,432,720 28,804,971 8,248,384 36,846,963 46,931,102 0 3,428,298 0.00 Sep-14 105,041. 54,311. 69,528. 175,647. 8,102. 30,537,761 28,859,282 8,317,912 37,022,610 47,113,286 14,029 3,442,327 0.93 Oct-14 209,392. 142,116. 141,182. 282,927. 86,731. 30,747,153 29,001,398 8,459,094 37,305,537 47,450,214 68,967 3,511,294 0.83 Nov-14 195,368. 128,048. 141,578. 274,610. 268,237. 30,942,521 29,129,446 8,600,672 37,580,147 47,885,830 -48,589 3,462,705 1.13 Dec-14 172,734. 133,549. 122,180. 292,027. 333,215. 31,115,255 29,262,995 8,722,852 37,872,174 48,377,374 -145,083 3,317,622 1.42 Jan-15 174,714. 153,603. 138,486. 248,187. 351,473. 31,289,969 29,416,598 8,861,338 38,120,361 48,835,412 -84,321 3,233,301 1.23 Feb-15 155,324. 153,882. 127,742. 184,395. 315,556. 31,445,293 29,570,480 8,989,080 38,304,756 49,207,829 -25,282 3,208,019 1.07 Mar-15 177,697. 187,229. 130,540. 247,555. 464,432. 31,622,990 29,757,709 9,119,620 38,552,311 49,731,874 -136,070 3,071,949 1.35 Apr-15 169,977. 181,026. 126,139. 200,374. 484,320. 31,792,967 29,938,735 9,245,759 38,752,685 50,220,001 -114,584 2,957,365 1.31 May-15 148,419. 146,564. 118,157. 241,252. 428,678. 31,941,386 30,085,299 9,363,916 38,993,937 50,716,585 -169,108 2,788,257 1.52 Jun-15 115,547. 105,937. 97,835. 241,207. 417,372. 32,056,933 30,191,236 9,461,751 39,235,144 51,206,454 -233,834 2,554,423 1.91 11 7/14 – 6/15 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY FIGURE 2: ORION VOIDAGE HISTORY 12 7/14 – 6/15 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 1/4 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) L-200 50029231910000 O 640135 OBa+OBb+OBd 4267-4147, 4312-4189, 4407-4278 6/30/2015 26304 SBHP 82 4142 1894 4400 0.40 1997 L-203 50029234160000 O 640135 Nb+OBa+OBc+ OBd 4277-4282, 4277-4284, 4457-4446, 4445-4451, 4542-4544, 4566-4589, 4591-4588, 4608-4664, 4672-4688, 4685-4699, 4632-4668, 4682-4654, 4648-4642 6/30/2015 23928 SBHP 82 4194 1903 4400 0.40 1985 L-204 50029233140000 O 640135 OA+OBa+OBb+OBc +OBd 4355-4397, 4409-4474, 4407-4482, 4509-4540, 4453-4577, 4525-4641, 4555-4567, 4574-4648, 4653-4691 9/21/2014 25988 SBHP 83 4204 1225 4400 0.40 1303 L-205 50029233880000 O 640135 OA+OBa+ OBb+OBc+OBd 4188-4183, 4173-4190, 4228-4248, 4237-4239, 4272-4285, 4394-4364, 4328-4350, 4392-4395, 4393-4393, 4385-4406 6/30/2015 25056 SBHP 57 3028 1703 4400 0.40 2252 L-250 50029232810000 O 640135 Nb 4199-4269, 4208-4281 4/27/2015 21185 SBHP 82 4123 1922 4400 0.40 2033 L-219 50029233760000 WAG 640135 OA 4413-4445 9/13/2014 1452 SBHP 84 4362 1943 4400 0.44 1960 L-219 50029233760000 WAG 640135 OBa 4480-4492 9/13/2014 1452 SBHP N/A 4470 1946 4400 0.44 1915 L-219 50029233760000 WAG 640135 OBd (oil) 4661-4665, 4669-4672, 4676-4679, 4683-4685, 4688-4690, 4691-4692, 4693-4693, 4762-4691, 4691-4690, 4689-4688, 4687-4686, 4686-4686, 4686-4687, 4689-4690, 4691-4692 9/13/2014 1452 SBHP 88 4652 2069 4400 0.44 1958 L-220 50029233870000 WAG 640135 Nb 4116-4136 6/30/2015 41496 SBHP 82 4052 1837 4400 0.44 1990 L-220 50029233870000 WAG 640135 OA 4250-4291 6/30/2015 41496 SBHP 87 4203 1885 4400 0.44 1972 L-220 50029233870000 WAG 640135 OBa 4318-4347 6/30/2015 41496 SBHP 90 4308 2023 4400 0.44 2063 L-220 50029233870000 WAG 640135 OBb+OBc 4360-4377, 4414-4431 6/30/2015 41496 SBHP 90 4362 2025 4400 0.44 2042 L-220 50029233870000 WAG 640135 OBd 4466 -4511 6/30/2015 41496 SBHP 90 4457 1997 4400 0.44 1972 L-221 50029233850000 WAG 640135 Nb 4090-4105 6/30/2015 23208 SBHP 84 4038 1835 4400 0.44 1994 L-221 50029233850000 WAG 640135 OA 4222-4258 6/30/2015 23208 SBHP 87 4176 1871 4400 0.44 1970 L-221 50029233850000 WAG 640135 OBa 4285-4316 6/30/2015 23208 SBHP 89 4276 1999 4400 0.44 2054 L-221 50029233850000 WAG 640135 OBb+OBc 4329-4343, 4382-4401 6/30/2015 23208 SBHP 90 4329 2030 4400 0.44 2061 L-221 50029233850000 WAG 640135 OBd 4433-4481 6/30/2015 23208 SBHP N/A 4426 1984 4400 0.44 1973 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 13 7/14 – 6/15 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 2/4 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) L-222 50029234200000 WAG 640135 OA 4307-4347 6/30/2015 5829 SBHP 86 4286 1252 4400 0.44 1302 L-222 50029234200000 WAG 640135 OBa 4378-4412 6/30/2015 5829 SBHP 87 4370 1595 4400 0.44 1608 L-222 50029234200000 WAG 640135 OBb+OBc 4427-4435, 4466-4482 6/30/2015 5829 SBHP 88 4433 1801 4400 0.44 1786 L-222 50029234200000 WAG 640135 OBd 4521-4571 6/30/2015 5829 SBHP 91 4514 1688 4400 0.44 1638 L-223 50029234150000 WAG 640135 Nb 4377-4396 6/30/2015 48576 SBHP 84 4339 1966 4400 0.44 1993 L-223 50029234150000 WAG 640135 OA 4502-4538 6/30/2015 48576 SBHP 88 4477 2014 4400 0.44 1980 L-223 50029234150000 WAG 640135 OBa 4567-4599 6/30/2015 48576 SBHP 90 4560 1960 4400 0.44 1890 L-223 50029234150000 WAG 640135 OBc 4667-4686 6/30/2015 48576 SBHP 92 4642 2035 4400 0.44 1929 L-223 50029234150000 WAG 640135 OBd 4717-476 5 6/30/2015 48576 SBHP 93 4714 2095 4400 0.44 1957 V-203 50029232850000 O 650135 OA+OBa+ OBb+OBc+OBd 4249-4274, 4306-4331, 4342-4365, 4397-4426, 4455-4486 9/23/2014 1658 SBHP 78 4125 1442 4400 0.40 1552 V-205 50029233380000 O 640135 OA+OBa+OBd 4395-4404, 4393-4435, 4452-4452, 4458-4470, 4498-4505, 4514-4511, 4588-4618, 4620-4617 12/20/2014 3830 SBHP 81 4269 1811 4400 0.40 1863 V-207 50029233900000 O 640135 Nb+OBa+OBb+OBd +Obe 4452-4443, 4445-4434, 4440-4431, 4646-4644, 4652-4631, 4636-4643, 4696-4684, 4681-4654, 4678-4665, 4803-4802, 4805-4793, 4779-4785, 4783-4782, 4844-4827 9/13/2014 1400 SBHP 91 4423 1311 4400 0.40 1302 V-215 50029233510000 WAG 640135 OA 4370-4404 5/8/2015 18841 SBHP 80 4347 1884 4400 0.44 1907 V-218 50029233500000 WAG 640135 OBa+OBb 4455-4550 6/30/2015 5403 SBHP 84 4515 1809 4400 0.44 1758 V-218 50029233500000 WAG 640135 OBd 4664-4703 6/30/2015 5403 SBHP N/A 4653 1867 4400 0.44 1756 V-219 50029233970000 WAG 640135 Nb 4434-4450 10/28/2014 4074 SBHP 89 4416 1362 4400 0.44 1355 V-219 50029233970000 WAG 640135 OBa 4626-4654 10/28/2014 4074 SBHP 91 4613 1898 4400 0.44 1804 V-219 50029233970000 WAG 640135 OBb 4667-4680 10/28/2014 4074 SBHP 90 4665 2099 4400 0.44 1982 V-219 50029233970000 WAG 640135 OBd+OBe 4769-4810, 4842-4866 10/28/2014 4074 SBHP 93 4752 2080 4400 0.44 1925 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 14 7/14 – 6/15 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 3/4 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) V-220 50029233830000 WAG 640135 Nb 4351-4367 9/13/2014 3139 SBHP 89 4328 1526 4400 0.44 1558 V-220 50029233830000 WAG 640135 OA 4486-4525 9/13/2014 3139 SBHP 87 4465 2389 4400 0.44 2360 V-220 50029233830000 WAG 640135 OBa 4554-4583 9/13/2014 3139 SBHP 92 4544 1654 4400 0.44 1591 V-220 50029233830000 WAG 640135 OBb+OBc 4598-4616, 4658-4678 9/13/2014 3139 SBHP 93 4597 1848 4400 0.44 1761 V-220 50029233830000 WAG 640135 OBd 4710-4748 9/13/2014 3139 SBHP 95 4703 1487 4400 0.44 1354 V-220 50029233830000 WAG 640135 OBe 4774-4793 9/13/2014 3139 SBHP 96 4775 1869 4400 0.44 1704 V-222 50029233570000 WAG 640135 OA 4326-4364 10/21/2014 2366 SBHP 83 4248 1216 4400 0.44 1283 V-222 50029233570000 WAG 640135 OBa 4393-4421 10/21/2014 2366 SBHP N/A 4376 1684 4400 0.44 1695 V-222 50029233570000 WAG 640135 OBb+OBc 4433-4450, 4485-4503 10/21/2014 2366 SBHP 95 4433 1739 4400 0.44 1724 V-222 50029233570000 WAG 640135 OBd 4448-4578 10/21/2014 2366 SBHP N/A 4532 1734 4400 0.44 1676 V-223 50029233840000 WAG 640135 OA 4419-4458 5/31/2015 36768 SBHP 84 4397 1772 4400 0.44 1773 V-223 50029233840000 WAG 640135 OBa 4485-4513 5/31/2015 36768 SBHP 85 4471 1709 4400 0.44 1678 V-223 50029233840000 WAG 640135 OBb 4528-4545 5/31/2015 36768 SBHP 87 4524 1805 4400 0.44 1750 V-223 50029233840000 WAG 640135 OBd 4632-4674 5/31/2015 36768 SBHP 90 4616 1996 4400 0.44 1901 V-224 50029234000000 WAG 640135 Nb 4466-4485 11/27/2014 7843 SBHP 91 4450 1434 4400 0.44 1412 V-224 50029234000000 WAG 640135 OBa 4674-4704 11/27/2014 7843 SBHP 92 4624 1399 4400 0.44 1300 V-224 50029234000000 WAG 640135 OBb 4718-4736 11/27/2014 7843 SBHP 95 4718 1414 4400 0.44 1274 V-224 50029234000000 WAG 640135 OBd 4832-4881 11/27/2014 7843 SBHP 95 4801 1862 4400 0.44 1686 V-224 50029234000000 WAG 640135 OBe 4903-4928 11/27/2014 7843 SBHP 96 4901 2109 4400 0.44 1889 V-225 50029234190000 WAG 640135 OA 4330-4365 10/1/2014 1910 SBHP 87 4281 1930 4400 0.44 1982 V-225 50029234190000 WAG 640135 OBa 4394-4420 10/1/2014 1910 SBHP 91 4379 2131 4400 0.44 2140 V-225 50029234190000 WAG 640135 OBd 4531-4576 10/1/2014 1910 SBHP 89 4522 1880 4400 0.44 1826 V-227 50029234170000 WI 640135 Nb 4449-4462 6/30/2015 35328 SBHP 88 4403 1912 4400 0.44 1911 V-227 50029234170000 WI 640135 OBa 4634-4662 6/30/2015 35328 SBHP 91 4596 1522 4400 0.44 1436 V-227 50029234170000 WI 640135 OBb 4677-4695 6/30/2015 35328 SBHP 92 4760 1750 4400 0.44 1592 V-227 50029234170000 WI 640135 OBd 4790-4837 6/30/2015 35328 SBHP 94 4673 1903 4400 0.44 1783 V-227 50029234170000 WI 640135 OBe 4854-4876 6/30/2015 35328 SBHP 96 4854 2081 4400 0.44 1881 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 15 7/14 – 6/15 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 4/4 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) V-229 50029234640000 WAG 640135 OA 4339-4377 9/20/2014 1621 SBHP 97 4325 1799 4400 0.44 1832 V-229 50029234640000 WAG 640135 OBA 4403-4431 9/20/2014 1621 SBHP 99 4395 1831 4400 0.44 1833 V-229 50029234640000 WAG 640135 OBb 4446-4464 9/20/2014 1621 SBHP 103 4446 2181 4400 0.44 2161 V-229 50029234640000 WAG 640135 OBd 4505-4515 9/20/2014 1621 SBHP 98 4594 2187 4400 0.44 2102 V-229 50029234640000 WAG 640135 Obd 4554-4593 9/20/2014 1621 SBHP 101 4553 1902 4400 0.44 1835 Printed Name Brenden Swensen Date July 15th, 2015 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Petroleum Engineer 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 16 7/14 – 6/15 PBU Orion Annual Reservoir Report FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 17 7/14 – 6/15 PBU Orion Annual Reservoir Report FIGURE 4: ORION PRESSURES IN MAP VIEW 1 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT 2015 ANNUAL SURVEILLANCE REPORT POLARIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2014 – JUNE 30, 2015 2 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION ............................................................................................................................. 3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ........................ 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) ............................. 3 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) ............................................................................................................... 5 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) ............................................................. 6 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) ............................................................................................ 6 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO O FFSET PRODUCERS (RULE 9F) .................................................................................................. 7 LIST OF ATTACHMENTS Figure 1: Polaris production and injection history ............................................................................. 10 Figure 2: Polaris voidage history ...................................................................................................... 10 Figure 3: Polaris pressure at datum .................................................................................................. 13 Figure 4: Polaris pressures in map view ........................................................................................... 14 Table 1: Polaris monthly production and injection summary .............................................................. 9 Table 2: Polaris pressure survey detail ............................................................................................. 11 3 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2015 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1. I NTRODUCTION This Annual Surveillance Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 484A, and covers the period from July 1, 2014 to June 30, 2015. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 3,890 BOPD, 3.2 MMSCFD (FGOR 834 SCF/STB), and 4,973 BWPD (WC 56%). Water injection during this period averaged 6,197 BWIPD with 3.0 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.0. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 484A. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates all valid Polaris pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period at the Pool datum of 5000 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light-oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed-off rates during shut-in. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build-up (PBU) pressure fall-off (PFO) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible 4 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre-production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: S-Pad North This polygon contains long term shut-in producer S-200 and low-rate jet pump producer S-201 (offline – jet pump maintenance). This is the only polygon without injection support. Pressure surveys taken over the past few years have shown little change in pressure, which is in line with minimal offtake from the polygon. The most recent pressure measurement was 2061 psi which was taken on 6/13/2015. S-Pad South This polygon contains producer S-213A and is supported by injectors S-215i, S-217i and S-218i. Measured pressures in this polygon range from 1700 psi to 2500 psi. W-Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211 and is supported by injectors W-209i, W-212i, W-213i, W-214i, W-215i, W-216i, W-217i, W-218i, W-219i, W-220i, W-221i, and W-223i. Measured pressures in this polygon range from 1700 psi to 2500 psi. In July 2013, two new matrix bypass events from the aquifer to producers W-201 and W-202 were identified. The aforementioned producers and downdip injectors W-220i and W-223i were taken offline for the second half of 2013 while remediation options were being evaluated. All of the wells were brought back online in early 2014. W-202’s matrix bypass event was successfully remediated in October 2014 by setting an isolation sleeve across the Oba lateral. Surveillance to assess the best course of action for remediating W-201’s matrix bypass event is pending. The impact to production and injection can be seen in Figure 2. During the reporting period, two matrix bypass events were confirmed. In May 2015, a matrix bypass event from injector W-212i to producer W-200 was confirmed via a red dye test. In June 2015, a matrix bypass event from injector S-215i to producer S-213A was confirmed via an open pocket step rate test. Wellwork is pending to remediate the matrix bypass events in both S-215i and W-212i. W-Pad East 5 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT This polygon contains producer W-203 and is supported by injectors W-207i and W-210i. Measured pressures in the polygon range from 2300 to 2400 psi. The pressures on the upper end of the range are typical injection-induced high pressure regions around the injector, which does not represent a polygon average pressure due to the very slow pressure fall-off. 4. RESULTS AND A NALYSIS OF PRODUCTION & INJECTION L OGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: No production logs were run during the reporting period. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples are later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Injection Logs: No injection logs were run during the reporting period. Injection logs are run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors 6 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. The current Polaris injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) Polaris production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust Polaris production on a daily basis. A minimum of one well test per month is used to check the performance curves, and to verify system performance, with more frequent testing during new well start-up and after significant wellwork. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E ) Enhanced Recovery Project - Waterflood: Primary production from the Polaris oil pool commenced in 1999 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 6,197 BWIPD. Cumulative injection through June 2015 was 21.8 MMSTBW, which has been injected into 18 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Project - Miscible Injectant: In 2005, approval to implement an enhanced oil recovery project in Polaris oil pool using Prudhoe Bay miscible injectant was granted via C.O. 484A. Injection of miscible injectant began in early 2006 in the downdip portion of W Pad North. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in S Pad South, W Pad North, and W Pad East. 7 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT During the reporting period, average injection rate was 3.0 MMSCFD. Cumulative injection through June 2015 was 4.1 BCF, which has been injected into 13 water-alternating-gas injectors. No new water-alternating-gas injectors have been placed into service during the reporting period. However, water-alternating-gas injectors W-210, W-213, and W-214 were placed on miscible gas injection for the first time. Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods will be managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. During the reporting period, two matrix bypass events were confirmed. In May 2015, a matrix bypass event from injector W-212i to producer W-200 was confirmed via a red dye test. In June 2015, a matrix bypass event from injector S-215i to producer S-213A was confirmed via an open pocket step rate test. Wellwork is pending to remediate the matrix bypass events in S-215i and W- 212i. 7. RESULTS OF M ONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, no new responses to miscible injectant were observed. To date, in the life of the field, response to miscible injectant have been observed in the following producers: S- 213A and W-204. 8 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 1: POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj Oil Prod Cum Gas Prod Cum Water Prod Cum Water Inj Cum Cum Total Inj (MI+Water) Net Res Voidage Net Voidage Cum Monthly VRR Date STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul-14 28,247. 24,943. 50,376. 82,241.0.17,312,968. 15,691,721. 5,694,041. 19,658,790. 21,682,259. -27,106 5,593,288 1.48 Aug-14 0.0.0.0.0.17,312,968 15,691,721 5,694,041 19,658,790 21,682,259 0 5,593,288 0.00 Sep-14 79,733. 55,100. 109,892. 53,694.0.17,392,701 15,746,821 5,803,933 19,712,484 21,736,490 100,780 5,694,068 0.35 Oct-14 139,018. 109,857. 259,173. 250,274. 133,874. 17,531,719 15,856,678 6,063,106 19,962,758 22,069,591 -65,377 5,628,691 1.24 Nov-14 138,255. 99,533. 172,886. 244,870. 183,049. 17,669,974 15,956,211 6,235,992 20,207,628 22,426,739 -102,194 5,526,497 1.40 Dec-14 160,511. 123,034. 193,691. 238,981. 160,997. 17,830,485 16,079,245 6,429,683 20,446,609 22,764,708 -28,650 5,497,847 1.09 Jan-15 176,330. 198,892. 204,812. 243,049. 135,089. 18,006,815 16,278,137 6,634,495 20,689,658 23,091,241 52,221 5,550,068 0.86 Feb-15 138,960. 130,464. 172,980. 206,859. 91,411. 18,145,775 16,408,601 6,807,475 20,896,517 23,355,015 21,799 5,571,867 0.92 Mar-15 150,887. 137,520. 190,036. 252,387. 203,359. 18,296,662 16,546,121 6,997,511 21,148,904 23,731,942 -68,862 5,503,005 1.22 Apr-15 141,066. 139,643. 175,526. 213,191. 103,491. 18,437,728 16,685,764 7,173,037 21,362,095 24,009,359 16,223 5,519,228 0.94 May-15 149,374. 96,466. 131,790. 288,346. 42,393. 18,587,102 16,782,230 7,304,827 21,650,441 24,326,024 -30,546 5,488,682 1.11 Jun-15 117,304. 69,001. 153,977. 188,025. 31,727. 18,704,406 16,851,231 7,458,804 21,838,466 24,534,966 89,097 5,577,779 0.70 9 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 10 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 1/2 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) S-201 50029229870000 O 64160 OA+OBa+OBb+ OBd 4984-5067, 5163-5170 6/13/2015 22776 SBHP 93 5000 2061 5000 0.45 2061 S-215 50029231070000 WAG 64160 OA 4988-5002, 5006-5016 9/16/2014 3935 SBHP 90 4975 2415 5000 0.44 2426 S-215 50029231070000 WAG 64160 OBa 5032-5059 9/16/2014 3935 SBHP N/A 5022 1746 5000 0.44 1736 S-215 50029231070000 WAG 64160 OBb+OBc 5068-5085, 5119-5133 9/16/2014 3935 SBHP 93 5067 2115 5000 0.44 2085 S-215 50029231070000 WAG 64160 OBd 5169-5196 9/16/2014 3935 SBHP N/A 5151 1910 5000 0.44 1844 S-217 50029233620000 PWI 64160 OA 4960-4989 10/27/2014 17890 SBHP 92 4921 1898 5000 0.44 1933 S-217 50029233620000 PWI 64160 OBa 5007-5023 10/27/2014 17890 SBHP 88 5001 1913 5000 0.44 1913 S-218 50029234140000 WAG 64160 OA 4997-5027 9/8/2014 3976 SBHP 93 4945 2454 5000 0.44 2478 S-218 50029234140000 WAG 64160 OBa 5050-5067 9/8/2014 3976 SBHP 89 5041 2064 5000 0.44 2046 S-218 50029234140000 WAG 64160 OBb+OBc 5086-5105, 5140-5151 9/8/2014 3976 SBHP 89 5086 2083 5000 0.44 2045 S-218 50029234140000 WAG 64160 OBd 5185-5225 9/8/2014 3976 SBHP 93 5183 2125 5000 0.44 2044 W-202 50029234340000 O 64160 OBa+OBc+Obd 4971-4989, 4988-4988, 4983-4986, 5055-5123, 5123-5134, 5135-5119, 5161-5158, 5123-5125, 5140-5180, 5180-5181 9/20/2014 1827 SBHP 94 4917 2029 5000 0.40 2062 W-204 50029233330000 O 64160 OBa+OBc+OBd 4873-4889, 4862-4866, 4901-4862, 4909-4881, 4950-4968, 4969-4940, 4992-4950, 4980-5038, 5029-4978, 5048-5019 9/13/2014 1642 SBHP 89 4840 1617 5000 0.40 1681 W-205 50029231650000 O 64160 OBa+OBc+OBd 4973-4982, 4984-5015, 5044-5051, 5052-5092, 5109-5159 9/13/2014 1668 SBHP 93 4875 2040 5000 0.40 2090 W-210 50029233390000 WAG 64160 OBa+OBb 4893-4928 2/25/2015 1915 SBHP N/A 4884 2244 5000 0.44 2295 W-210 50029233390000 WAG 64160 OBc 4971-4997 2/25/2015 1915 SBHP 84 4959 2321 5000 0.44 2339 W-210 50029233390000 WAG 64160 OBd 5025-5063 2/25/2015 1915 SBHP N/A 5010 2392 5000 0.44 2388 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 11 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 2/2 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) W-213 50029233540000 WAG 64160 OBa 4871-4894 9/14/2014 1591 SBHP N/A 4799 2350 5000 0.44 2438 W-217 50029234180000 WAG 64160 OBa 4915-5940 10/2/2014 2029 SBHP 90 4881 1757 5000 0.44 1809 W-217 50029234180000 WAG 64160 OBc 4994-5019 10/2/2014 2029 SBHP 88 4974 2239 5000 0.44 2250 W-217 50029234180000 WAG 64160 OBd 5050-5088 10/2/2014 2029 SBHP 85 5053 2001 5000 0.44 1978 W-218 50029234030000 WAG 64160 OBa 4948-4970 10/2/2014 2011 SBHP 89 4929 1958 5000 0.44 1989 W-218 50029234030000 WAG 64160 OBc 5032-5055 10/2/2014 2011 SBHP 90 5006 1993 5000 0.44 1990 W-218 50029234030000 WAG 64160 OBd 5087-5127 10/2/2014 2011 SBHP 89 5092 2021 5000 0.44 1981 W-220 50029234320000 WAG 64160 OBa 5142-5166 9/22/2014 1777 SBHP 90 5117 2358 5000 0.44 2307 W-220 50029234320000 WI 64160 OBc 5228-5251 9/22/2014 1777 SBHP 90 5199 2359 5000 0.44 2271 W-220 50029234320000 WI 64160 OBd 5278-5311 9/22/2014 1777 SBHP 88 5280 2618 5000 0.44 2495 W-223 50029234400000 WAG 64160 OBa 5035-5059 9/22/2014 1779 SBHP 91 4999 2050 5000 0.44 2050 W-223 50029234400000 WAG 64160 OBc 5112-5143 9/22/2014 1779 SBHP 89 5090 2467 5000 0.44 2427 W-223 50029234400000 WAG 64160 OBd 5169-5208 9/22/2014 1779 SBHP 87 5169 2580 5000 0.44 2506 Printed Name Eric Zoesch Date July 15th, 2015 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Petroleum Engineer 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 12 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 13 7/14 – 6/15 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 4: POLARIS PRESSURES IN MAP VIEW