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Home My WebLink About2016 Prudhoe Satellite Oil Pools1 2016 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1, 2015 – JUNE 30, 2016 2 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 3 3. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8B) 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS W ITHIN THE POOL (RULE 8C) 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8D) 5 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) 5 7. REVIEW OF PLAN OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8F&G) 5 LIST OF ATTACHMENTS Figure 1: Aurora production and injection history 9 Figure 2: Aurora voidage history 9 Figure 3: Aurora pressures in map view 4 Table 1: Aurora monthly production and injection summary 7 Table 2: Aurora cumulative voidage by fault block 8 Table 3: Aurora pressure survey detail 10 Table 4: Aurora production and injection profiles 12 Table 5: Aurora monthly average oil allocation factors 13 3 Prudhoe Bay Unit 2016 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 457B for the Aurora Oil Pool and covers the period from July 1, 2015 to June 30, 2016. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT 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 t o 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 to maximize recovery. Initial development involves a period of primary production to determine reser voir 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. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. Th e 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 2600 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 f ield 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 maximize economic recovery consistent with prudent oil field engineering 4 practices. During primary depletion, producers experienced increasing gas-oil-ratios (GORs) due to existence of an initial gas cap, primarily in the West side of the field, but also ap parent in the CR and SEC areas. Production was restricted to conserve reservoir energy. Beginning in mid - 2001 and continuing into 2003, production from w ells S-100, S-106 and S-102 w as reduced to approximately half capacity, allowing injection to signifi cantly 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. Waterflood patterns have been designed and implemented to maintain pressure 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 the reporting period, average injection rate was 24,851 BWIPD and 3.4 MMSCFD. Cumulative injection through June 2016 was 106.7 MMSTBW and 45.7 BCF. A total of 19 injectors have been on water injection and 16 injectors have been on MI. 3. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 6,303 BOPD, 14.1 MMSCFD (FGOR 2,230 SCF/STB), and 15,070 BWPD (WC 71%). Water injection during this period averaged 24,851 BWIPD with 3.4 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.9. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Cumulative production, injection, and voidage replacement ratios by fault block are sum marized in Table 2. Figures 1 and 2 graphically depict this information since field start -up. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessar y and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed at S Pad to provide increased injection pressure for low injectivity patterns. The VRR challenge for this reporting year came from do wntime of the Sulzer and Ruston injection pumps at GC-2, which includes the following: 1) Sulzer Pumps: cycle valve repair, heat manifold de-icing mechanical piping, full functional PMs, and bundle replacement and 2) Ruston Pumps: mechanical seal upgrade and full functional PMs. In addition to the injection pump downtime, individual injectors have been offline due to drilling proximity, pressure management concerns while drilling offset producers, and acquisition of static bottomhole pressures. 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 obtained during the reporting period is shown in Table 3. The field average reservoir pressure map is shown in Figure 3. Pressure measurements were gathered in 16 wells during the reporting period. Most producers in the AOP have evidence of pressure response to injection support. 5 5. RESULTS AND ANALYSIS OF SPECIAL M ONITORING (RULE 8 D) During the reporting period, no injection logs were run in the Aurora Field. During the reporting period, a production log was run in S-44A to identify areas of high watercut production in the horizontal section of the well. This information was subsequently used to decision which sliding sleeves to shift closed in order to shut -off high watercut production. A summary of the interpreted results from the production log ran during the reporting period is shown in Table 4. 6. REVI EW OF POOL PRODUCTION ALLOCATION (RULE 8 E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) Aurora 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 Aurora 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. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.90 and 1.10. Any days with allocation factors of zero were excluded. A planned TAPS shutdown was responsible for two zero allocation days on 6/25/16 and 6/26/16. The m onthly averages of daily oil production allocation factors are shown in Table 5. Electronic files containing daily allocation data and daily test dat a for a minimum of five years are being retained. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 8 F & G) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation. 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 t hat were put on MWAG in 2006. South of Crest Area production start ed-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. 6 Summarized below are significant events and accomplishments at Aurora over the past year:  S-42A: New producer replacing abandoned producer S-108 and targeting additional undrained volumes in an adjacent fault block was drilled in 3Q 2015 and was placed on production in 4Q 2015.  S-44A: New producer to the North of S-101 injector was drilled in 3Q 2015 and was placed on production in 4Q 2015.  S-112: Add lateral to support t he toe of S-42A was spudded in 2Q 2016, but could not reach the target (West side of fault) due to wellbore stability; parent well and a portion of the add lateral (East side of fault) is currently on injection.  S-135: A hydraulic fracture treatment was pumped in early January 2016 with the well being placed on production at the end of the month. The initial post -frac oil rate was 2,658 bopd at a formation gas-oil-ratio of 338 scf/stbo and watercut of 26%. The pre-frac oil rate was 248 bopd.  MI was injected into 2 water-alternating-gas injectors  In addition to the aforementioned activity, miscellaneous producer and injector wellwork was executed to minimize oil rate decline. The Aurora owners will continue to evaluate optimal well count , well utility and well locations to maximize recovery. Future development plans are discussed in the 2015 update to the Plan of Development for the Aurora Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2015, of copy of which was provided to the Co mmission. The Commission will be copied when the 2016 update of the Aurora Plan of Development is filed with the Division. 7 TABLE 1: AURORA 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 RVB RVB RVB RVB/RVB Jul-15 179,482.377,743.489,581.788,555.127,889.39,606,614.122,602,263.43,630,614.98,459,448.128,067,025.66,573 44,968,093 0.93 Aug-15 118,626.214,391.308,390.528,489.90,871.39,725,240 122,816,654 43,939,004 98,987,937 128,662,424 -8,524 44,959,569 1.01 Sep-15 177,956.388,511.409,385.612,331.91,275.39,903,196 123,205,165 44,348,389 99,600,268 129,343,592 192,056 45,151,625 0.78 Oct-15 260,508.402,331.579,092.922,531.122,692.40,163,704 123,607,496 44,927,481 100,522,799 130,360,642 113,913 45,265,539 0.90 Nov-15 271,556.498,044.571,018.867,025.92,814.40,435,260 124,105,540 45,498,499 101,389,824 131,302,553 270,034 45,535,573 0.78 Dec-15 208,240.490,512.403,278.906,346.108,333.40,643,500 124,596,052 45,901,777 102,296,170 132,294,192 -24,854 45,510,719 1.03 Jan-16 189,573.496,662.451,626.835,097.147,206.40,833,073 125,092,714 46,353,403 103,131,267 133,237,259 54,318 45,565,037 0.95 Feb-16 202,647.518,394.536,431.766,704.89,034.41,035,720 125,611,108 46,889,834 103,897,971 134,074,498 275,899 45,840,937 0.75 Mar-16 168,980.406,280.177,813.801,676.73,934.41,204,700 126,017,388 47,067,647 104,699,647 134,938,046 -226,344 45,614,593 1.36 Apr-16 171,140.433,241.580,843.714,259.138,130.41,375,840 126,450,629 47,648,490 105,413,906 135,752,231 253,433 45,868,026 0.76 May-16 196,362.498,801.505,178.754,673.160,971.41,572,202 126,949,430 48,153,668 106,168,579 136,621,800 191,959 46,059,985 0.82 Jun-16 155,696.405,789.487,768.572,841.0.41,727,898 127,355,219 48,641,436 106,741,420 137,206,098 352,724 46,412,710 0.62 8 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun-16 Aurora Aurora Aurora Aurora Aurora Crest*N of Crest**E of Crest*W of Crest*S of Crest* Total Cumulative Injection (rsvb)15,038,242 40,491,110 8,985,053 64,013,272 9,050,313 Total Cumulative Production (rsvb)30,656,407 47,454,921 12,870,068 75,335,002 22,956,849 Cumulative Voidage Replacement Ratio 0.49 0.85 0.70 0.85 0.39 * Initial Gas Cap ** Solution Gas Only Bo 1.32 rsvb/stb Bg 0.84 rsvb/mscf Bw 1.02 rsvb/stb Rs 0.65 mscf/stb Bg (MI)0.62 rsvb/mscf 9 FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY FIGURE 2: AURORA VOIDAGE HISTORY 10 TABLE 3 - AURORA PRESSURE SURVEY DETAIL 6. Oil Gravity: 0.9SG/25 API 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructio ns 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-42A 500292266201 O 640120 6714 - 6823 3/3/2016 265 SBHP 121 6648 1592 6700 0.42 1614 S-44A 500292273501 O 640120 6698 - 6708 2/17/2016 744 SBHP 142 6466 2816 6700 0.42 2914 S-44A 500292273501 O 640120 6698 - 6757 2/23/2016 120 SBHP 144 6466 3552 6700 0.44 3655 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 5/5/2016 264 SBHP 135 6487 2322 6700 0.42 2411 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 4/16/2016 1152 SBHP 139 6429 2820 6700 0.42 2934 S-106 500292299900 O 640120 6689 - 6716, 6727 - 6742 3/11/2016 460 SBHP 152 6674 2218 6700 0.59 2233 S-110B 500292303002 WAG 640120 6765 - 6794 6/22/2016 408 Other @surface 730 6700 0.41 3530 S-112 500292309900 WI 640120 6641-6655 6672-6679 6703-6684 1/4/2016 7338 SBHP 134 6700 3607 6700 0.43 3607 S-112 500292309900 WI 640120 6641-6655 6672-6679 6703-6684 3/26/2016 9295 SBHP 131 6700 3384 6700 0.43 3384 S-113B 500292309402 O 640120 6674-6749 6/21/2016 328 SBHP 154 6700 2622 6700 0.29 2622 S-114A 500292311601 WAG 640120 6658 - 6685 4/24/2016 1112 SBHP 130 6600 4023 6700 0.44 4067 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 3/21/2016 696 SBHP 142 6580 2624 6700 0.42 2674 S-122 O 640120 6675 - 6689, 6705 - 6713, 6716 - 6718, 6719 - 6718, 6717 - 6716, 6706 - 6699, 6716 - 6716, 6716 - 6716,6715 - 6717, 6717 - 6716, 6713, 6708, 6696 - 6681 5/28/2016 816 SBHP 141 6517 3277 6700 0.42 3354 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 3/3/2016 264 SBHP 146 6554 2725 6700 0.42 2786 S-134 500292341300 WAG 640120 6633 - 6692, 6777 - 6790 6/22/2016 408 Other @surface 700 6700 0.39 3319 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 8/25/2015 168 SBHP 151 6592 2883 6700 0.42 2928 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume STATE OF ALASKA 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 Ken Huber Date July 26th, 2016 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 Ken Huber Title Reservoir Engineer 11 FIGURE 3: AURORA PRESSURES IN MAP VIEW 12 TABLE 4 - AURORA PRODUCTION AND INJECTION PROFILES Well Survey Date Survey Type Zones Splits Oil / Water / Gas Service Comments S-44A 12/15/15 PPROF C3A C2E C2D C2C C2b 100%/90%/100% Producer Sliding Sleeve #3 C2E 0% / 10% / 0% Producer Sliding Sleeve #1 TABLE 5 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS 13 Oil Allocation Month Factor Jul-15 0.93 Aug-15 0.96 Sep-15 1.03 Oct-15 1.01 Nov-15 0.94 Dec-15 0.92 Jan-16 0.90 Feb-16 0.91 Mar-16 0.91 Apr-16 0.92 May-16 0.98 Jun-16 0.93 f 1 2016 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2015 – JUNE 30, 2016 2 CONTENTS 1. INTRODUCTION ........................................................................................................................ 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) .................................................................................... 3 3. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) ......... 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS W ITHIN THE POOL (RULE 9C) ................ 5 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) ......................................... 5 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTIN ALLOCATION FACTORS AND ISSUES (RULE 4G) ..... 5 7. OPERATIONS, DEVELOPM ENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) ..................................................................................................................................... 6 . LIST OF ATTACHMENTS Figure 1: Borealis production and injection history ............................................................................ 8 Figure 2: Borealis voidage history ...................................................................................................... 8 Figure 3: Borealis pressures in map view ....................................................................................... 10 Table 1: Borealis monthly production and injection summary ........................................................... 7 Table 2: Borealis pressure survey detail ............................................................................................ 9 Table 3: Borealis monthly average oil allocation factors .................................................................. 11 3 Prudhoe Bay Unit 2016 Borealis Oil Pool Annual Reservoir Report 1. INTRODUCTION This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Borealis Oil Pool in accordance with Commission regulations and Conservation Order 471. This report covers the period f rom July 1, 2015 through June 30, 2016. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT SUMMARY (RULE 9A) Enhanced Recovery Projects Water injection in the Borealis Oil Pool (BOP) started in June 2001, whereas t ertiary EOR Miscible Water Alternating Gas (MWAG) started in June 2004. Evaluation of hydrocarbon recovery mechanisms for the Borealis Oil Pool (BOP) 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, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life to maximize 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 BOP where injection is justified, waterflooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility be tween 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 2100 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 reserv oir 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 Summary The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize economic recovery consistent with prudent oil field engineering practices. 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 4 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. Waterflood patterns have been designed and implemented to maintain pressure 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. Injection f acility limit ations 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 earlier than expected water breakthrough 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. During the reporting period, average injection rate was 28,118 BWIPD and 19.7 MMSCFD. Cumulative injection through June 2016 was 181.5 MMSTBW and 86.2 BCF. A total of 22 injectors have been on water injection and 22 injectors have been on MI. 3. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) During the reporting period, field production averaged 8,517 BOPD, 16.2 MMSCFD (FGOR 1,905 SCF/STB), and 19,939 BWPD (WC 70%). Water injection during this period averaged 28,118 BWIPD with 19.7 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. 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. Booster pumps were installed at Z Pad to provide increased injection pressure for low injectivity patterns. During the reporting period, Borealis suffered from low VRR because the Z Pad booster pumps were offline due to electrical failure. The A Booster (Z-504A) was repaired and is expected to be returned to service in 3Q 2016. The B Booster (Z-504B) was repaired and was returned to service in 2Q 2016. The VRR in Borealis should improve with the return of both boosters to full time service. Production and injection for V-Pad was shut -in, isolated, and brought to a safe state in June 2016 due to piping over stress findings from an engineering study. The study was commissioned to analyze subsidence and the potential for piping stress that was visually recognized across the pad, which was confirmed by the engineering model from the study. Therefore, in order to mitigate the risk of a loss of primary containment, the pad was shut in while a plan to safely return production/injection is developed. 5 Currently, the piping is being brought back to a neutral stress state via piping modifications and support leveling. The plan is to have production/injection from the pad back online by the end of 2016. This will remain as a short term solution with periodic surveying of subsidence and preventative mitigations ongoing. The PBU operator is studying the cause of the subsidence, with the goal of developing a long term solution by 2018. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 o f Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. The field reservoir pressure map is shown in Figure 3. Five of the newer producers and one injector have been completed with perm anent bottom hole gauges, giving valuable information about the f lowing conditions, reservoir pressures, and reservoir connectivity on a continuous basis. Pressure measurements 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 M ONITORING (RULE 9D) During the reporting period, no injection or production logs were run in the Borealis Field. 6. REVIEW OF POOL PRODUCTION ALLOCATION AND W ELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine th e 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 still considered the primary metric for production allocation at L Pad. Due t o reliability issues, however, we have also been utilizing the L Pad Test Separator for production allocation. During the reporting period, the need for standardization in L and V testing was identified along with improvements in maintenance and calibration activities for both the L Pad Test Separator and the Gen 2 m eters. We are currently working to standardize the production allocation systems at L and V for use in future reporting cycles. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.90 and 1.10. Any days with allocation factors of zero were excluded. A planned TAPS shutdown was responsible for two zero allocation days on 6/25/16 and 6/26/16. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test dat a for a minimum of five years are being retained. 6 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F & G) M iscible 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 saturatio ns on all three Borealis Pads, L, V and Z. 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 waterf lood 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. 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 w ithin the allowable limit. Borealis wells continue to show benefits from MI. Summarized below are significant events and accomplishments at Borealis over the past year:  L-123: A hydraulic fracture treatment was pumped in December 2015 with the well being placed on injection in February 2016. Prior to the treatment, the injector was offline due to poor injectivity (rock quality).  L-124: A hydraulic fracture treatment was pumped in January 2016 with the well being placed on production in January 2016. The initial post -frac oil rate was 1,758 bopd at a formation gas-oil-ratio of 692 scf/stb and watercut of 5%. The pre-frac oil rate was 83 bopd.  Z-114: WAG injector was placed on MI injection in February 2016 for the first time.  Z-504A: A booster pump has been repaired and is expected to be returned to service in 3Q 2016.  Z-504B: B booster pump has been repaired and was returned to service in 2Q 2016.  MI was injected into 12 water-alternating-gas injectors  In addition to the aforementioned activity, m iscellaneous producer and injector wellwork was executed to minimize oil rate decline.  The static & dynamic models for the Borealis field have been updated, inclusive of history matching the dynamic model. The Borealis owners will continue to evaluate opt imal well count, well utility and well locations to maximize recovery. Future development plans are discussed in the 2015 update to the Plan of Development for the Borealis Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2015, of copy of which was provided to the Commission. The Commission will be copied when the 2016 update of the Borealis Plan of Development is filed with the Division. 7 TABLE 1: BOREALIS 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-15 282,392.530,941.536,335.972,879.543,775.78,098,958.109,550,130.93,827,834.172,254,130.226,743,259.-83,185 32,259,086 1.07 Aug-15 218,243.407,888.484,624.777,764.299,899.78,317,201 109,958,018 94,312,458 173,031,894 227,730,294 54,379 32,313,465 0.95 Sep-15 255,447.420,774.467,594.744,004.681,884.78,572,648 110,378,792 94,780,052 173,775,898 228,919,386 -107,903 32,205,562 1.10 Oct-15 239,900.284,972.492,597.945,914.649,581.78,812,548 110,663,764 95,272,649 174,721,812 230,296,417 -392,165 31,813,398 1.40 Nov-15 231,429.322,062.517,844.827,146.353,509.79,043,977 110,985,826 95,790,493 175,548,958 231,367,553 -31,235 31,782,162 1.03 Dec-15 285,167.442,827.635,427.966,962.447,152.79,329,144 111,428,653 96,425,920 176,515,920 232,640,758 33,930 31,816,092 0.97 Jan-16 332,625.616,474.774,697.1,077,660.294,508.79,661,769 112,045,127 97,200,617 177,593,580 233,933,343 328,582 32,144,674 0.80 Feb-16 281,875.659,946.675,914.868,425.1,117,066.79,943,644 112,705,073 97,876,531 178,462,005 235,520,402 -107,973 32,036,701 1.07 Mar-16 281,185.649,797.720,081.801,436.957,591.80,224,829 113,354,870 98,596,612 179,263,441 236,939,587 98,185 32,134,885 0.94 Apr-16 274,270.625,035.793,679.806,643.751,581.80,499,099 113,979,905 99,390,291 180,070,084 238,236,410 271,833 32,406,718 0.83 May-16 271,392.553,710.749,793.1,042,156.704,026.80,770,491 114,533,615 100,140,084 181,112,240 239,746,327 -34,501 32,372,216 1.02 Jun-16 154,757.406,750.429,128.432,013.388,247.80,925,248 114,940,365 100,569,212 181,544,253 240,432,013 213,687 32,585,903 0.76 8 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY FIGURE 2: BOREALIS VOIDAGE HISTORY 9 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL 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 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-102 50-500-29230-71-00 O 640130 10144 - 10170, 10170 - 10200, 10280 - 10290 6/17/2016 310 SBHP 156 6,602 3,016 6,600 0.43 3015 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 6/24/2016 3288 Other @surface 10 6,600 0.42 2843 L-108 50-500-29230-90-00 WAG 640130 6441 - 6496, 6505 - 6510, 6517 - 6523, 6526 - 6532 6/24/2016 480 Other @surface 600 6,600 0.42 3426 L-109 50-500-29230-46-00 WAG 640130 6584 - 6611, 6620 - 6648 6/24/2016 480 Other @surface 360 6,600 0.42 3188 L-112 50-500-29231-29-00 O 640130 6611 - 6633 6/16/2016 6170 SBHP 160 6,685 2,284 6,600 0.21 2266 L-119 50-500-29230-77-00 WAG 640130 6382 - 6384, 6473 - 6475, 6577 - 6602, 6609 - 6622 6/24/2016 480 Other @surface 700 6,600 0.42 3534 L-121A 50-500-29231-38-01 O 640130 6547 - 6586 6/18/2016 327 SBHP 157 6,563 2,412 6,600 0.33 2424 L-122 50-500-29231-47-00 O 640130 6416 - 6448, 6460 - 6470, 6552 - 6582 6/11/2016 5280 SBHP 154 6,443 2,714 6,600 0.35 2769 L-124 50-500-29232-55-00 O 640130 6353.60-6404.21, 6401.91- 6391.30, 6393.65-6404.27 5/4/2016 1512 SBHP 148 6,261 2,239 6,600 0.42 2381 V-100 50-500-29230-08-00 WAG 640130 6603 - 6648 6/22/2016 362 SBHP 113 6,600 3,694 6,600 0.19 3694 V-104 50-500-29231-03-00 WAG 640130 6503 - 6547, 6553 - 6558, 6567 - 6570, 6642 - 6668 5/28/2016 597 SBHP 145 6,600 2,975 6,600 0.44 2975 V-105 50-500-29230-97-00 WAG 640130 6555 - 6557, 6559 - 6570, 6574 - 6584, 6588 - 6598, 6604 - 6610 6/24/2016 480 Other @surface 870 6,600 0.42 3701 V-112 50-500-29233-00-00 WAG 640130 6522 - 6542, 6546 - 6554, 6560 - 6568, 6579 - 6586, 6671 - 6665, 6658 - 6652, 6649 - 6642, 6637 - 6634 6/23/2016 384 SBHP 132 6,450 3,093 6,600 0.18 3120 V-114A 50-500-29231-78-01 WI 640130 6601 - 6609, 6639 - 6645, 6661 - 6669, 6658 - 6654 6/24/2016 480 Other @surface 420 6,600 0.42 3258 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 6/30/2016 312 SBHP 151 6,408 2,624 6,600 0.42 2705 V-123 50-500-29234-22-00 WAG 640130 6612 - 6607, 6604 - 6602, 6600 - 6597, 6593 - 6577, 6574 - 6569 6/27/2016 552 SBHP 139 6,267 3,151 6,600 0.45 3301 Z-102 50-500-29233-53-00 WAG 640130 6506 - 6525, 6529 - 6538, 6514 - 6513, 6512 - 6507, 6505 - 6501 6/22/2016 432 Other @surface 540 6,600 0.42 3378 Z-103 50-500-29232-35-00 WAG 640130 6604 - 6646 6/22/2016 432 Other @surface 240 6,600 0.40 2900 Z-113 50-500-29234-50-00 O 640130 6505, 6577, 6551, 6544, 6553, 6549 8/24/2015 144 SBHP 146 6,291 2,868 6,600 0.42 2998 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission.Z-113 I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Ken Huber Title Reservoir Engineer Printed Name Ken Huber Date July 26th, 2016 *Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume 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: 10 FIGURE 3: BOREALIS PRESSURES IN MAP VIEW 11 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Oil Allocation Month Factor Jul-15 0.93 Aug-15 0.96 Sep-15 1.03 Oct-15 1.01 Nov-15 0.94 Dec-15 0.92 Jan-16 0.90 Feb-16 0.91 Mar-16 0.91 Apr-16 0.92 May-16 0.98 Jun-16 0.93 7/15 – 6/16 Midnight Sun Annual Surveillance Report 1 2016 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1, 2015 – JUNE 30, 2016 7/15 – 6/16 Midnight Sun Annual Surveillance 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) and Review of Pool Production Factors and Issues (Rule 7(d) 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 Survey Details ...................................................................................... 8 Table 3: Allocation Factors ................................................................................................................ 8 Figure 1: Midnight Sun Monthly Production and Injection History ................................................... 7 Figure 2: Midnight Sun Voidage History ........................................................................................... 7 Figure 3: Midnight Sun Voidage History ........................................................................................... 9 7/15 – 6/16 Midnight Sun Annual Surveillance Report 3 Prudhoe Bay Unit 2016 Midnight Sun Annual Reservoir Report This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Midnight Sun Oil Pool in accordance with Commission regulations and Conservation Order 452. This report covers the period from July 1, 2015 through June 30, 2016. 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, 2016 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to maximize 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 1.00. Midnight Sun production volumes have remained relatively constant for oil, water, and gas phases during the reporting period. Stabilized reservoir pressure from injection underpins the steady fluid production. Well E-101 currently produces at ~90% watercut, and Well E-102 produces at ~96% 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 2016. 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. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) 7/15 – 6/16 Midnight Sun Annual Surveillance Report 4 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 for most of the field have remained stable throughout the last year. E-104 only operates at 5-10% of the daily injection rates of both E-100 and E-103. This injection rate has declined with time and the block shows evidence of increased pressure, indicating the well may not be providing efficient sweep or efficient pressure support. A static bottom hole pressure was taken on September 3rd, 2015 for injector E-104 which provided additional evidence of reservoir compartmentalization. This surveillance data indicates pressure in the E-104 area has increased to near initial reservoir conditions which implies the injector is not providing meaningful support to the field. As a result, E-104 was shut-in for reservoir pressure management on 9/27/15. Results and Analysis of Production & Injection Logging Surveys (Rule 11 d) A tracer study was performed in 2010. Progress and results of that study were discussed in the 2014-2015 ASR. During the 2015-2016 reporting period, no significant production logging or tracer studies were completed Results of Well Allocation and Test Evaluation (Rule 11 e) and Review of Pool Production Factors and Issues (Rule 7(d) 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. Over the reporting period, the monthly average of the daily oil production allocation factors fell within the range of 0.90 and 1.10. Any days with allocation factors of zero were excluded. A GC-1 plant turnaround (TAR) is responsible for zero allocation days between 8/1/15 to 8/28/15; a planned TAPS shutdown was responsible for a zero allocation day on 6/26/16. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) 7/15 – 6/16 Midnight Sun Annual Surveillance Report 5 In 2015 P1-122, a Water-Alternating-Gas (WAG) injector, was drilled from P1 Pad (the only pad with Miscible Injectant nearby) to supply MI and implement enhanced oil recovery in the pool. Today development plans include successful management of the EOR flood and do not include imminent drilling though sidetracks to increase recovery will be evaluated as the field matures. Future development plans are discussed in the 2015 update to the Plan of Development for the Midnight Sun Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2015, of copy of which was provided to the Commission. The Commission will be copied when the 2016 update of the Midnight Sun Plan of Development is filed with the division. 7/15 – 6/16 Midnight Sun Annual Surveillance Report 6 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance 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-15 27,910 51,170 308,520 426,463 0 20,442,142 65,211,286 40,397,585 90,230,893 92,937,820 -58,158 17,182,699 1.15 Aug-15 226 1,630 2,064 2,750 0 20,442,368 65,212,916 40,399,649 90,233,643 92,940,652 776 17,183,475 0.78 Sep-15 21,832 134,988 230,922 354,221 0 20,464,200 65,347,904 40,630,571 90,587,864 93,305,500 -1,685 17,181,790 1.00 Oct-15 42,294 176,687 449,868 517,630 0 20,506,494 65,524,591 41,080,439 91,105,494 93,838,659 105,282 17,287,072 0.84 Nov-15 38,127 49,508 399,305 490,157 0 20,544,621 65,574,099 41,479,744 91,595,651 94,343,521 -23,347 17,263,725 1.05 Dec-15 38,777 35,769 429,709 513,666 0 20,583,398 65,609,868 41,909,453 92,109,317 94,872,597 -26,685 17,237,039 1.05 Jan-16 40,108 28,707 395,956 509,751 0 20,623,506 65,638,575 42,305,409 92,619,068 95,397,640 -61,981 17,175,058 1.13 Feb-16 36,355 36,789 380,036 471,738 0 20,659,861 65,675,364 42,685,445 93,090,806 95,883,530 -35,800 17,139,258 1.08 Mar-16 42,274 37,514 429,571 501,251 0 20,702,135 65,712,878 43,115,016 93,592,057 96,399,819 -9,830 17,129,428 1.02 Apr-16 44,021 81,653 438,428 376,511 0 20,746,156 65,794,531 43,553,444 93,968,568 96,787,625 164,406 17,293,834 0.70 May-16 45,140 62,546 447,007 539,870 0 20,791,296 65,857,077 44,000,451 94,508,438 97,343,691 -9,363 17,284,471 1.02 Jun-16 36,905 73,269 308,481 458,098 0 20,828,201 65,930,346 44,308,932 94,966,536 97,815,532 -65,899 17,218,572 1.16 Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = 0.798 rb/Msc 7/15 – 6/16 Midnight Sun Annual Surveillance Report 7 Figure 1: Midnight Sun Production and Injection History Figure 2: Midnight Sun Voidage History 7/15 – 6/16 Midnight Sun Annual Surveillance Report 8 Table 3: Allocation Factors Month Oil Allocation Factor Jul-15 1.0144 Aug-15 1.0233 Sep-15 1.0654 Oct-15 0.9855 Nov-15 0.9690 Dec-15 0.9188 Jan-16 0.9481 Feb-16 0.9588 Mar-16 0.9796 Apr-16 0.9260 May-16 0.9321 Jun-16 0.9512 7/15 – 6/16 Midnight Sun Annual Surveillance Report 9 Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS 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-101 500292290900 PAL MSOP KUP 8080-8098, 8116-8132 8/30/15 709 SBHP 161 8050 3459 8050 0.44 3459 E-104 500292304900 WI MSOP KUP 7857 - 7870, 7879 - 7892 8/30/15 821 SBHP 116 7885 4000 8050 0.43 4043 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Weston Smith 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. Weston SmithSignature 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Midnight Sun Printed Name Title Date Reservoir Engineer September 15, 2015 8050' TVDss 0.72 STATE OF ALASKA 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 7/15 – 6/16 Midnight Sun Annual Surveillance Report 10 Figure 3: Midnight Sun Pressure History 1 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT 2016 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1, 2015 – JUNE 30, 2016 2 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION .............................................................................................................. 3 2. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ........ 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS W ITHIN 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) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (F)) .......................... 6 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) .................................................... 8 9. FUTURE DEVELOPMENT PLANS ............................................................................................. 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: Orion production and injection profiles ............................................................... 18 Table 4: Orion monthly average oil allocation factors ....................................................... 19 3 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY U NIT 2016 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, 2015 t o June 30, 2016. 2. VOIDAGE B ALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,747 BOPD, 5.0 MMSCFD (FGOR 1,045 SCF/STB), and 4,217 BWPD (WC 47%). Water injection during this period averaged 8,275 BWIPD with 9.4 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.3. Monthly production, injection, and voidage volumes for the re porting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start -up. Production and injection for V-Pad was shut -in, isolated, and brought to a safe state in June 2016 due to piping over stress findings from an engineering study. The study was commissioned to analyze subsidence and the potential for piping stress that was visually recognized across the pad, which was confirmed by the engineering model from the study. Therefore, in order to mitigate the risk of a loss of primary containment, the pad was shut in while a plan to safely return production/injection is developed. Currently, the piping is being brought back to a neutral stress state via piping modifications and support levelling. The plan is to have production/injection from the pad back online by the end of 2016. This will remain as a short term solution with periodic surveying of subsidence and preventative mitigations ongoing. The PBU operator is studying the cause of the subsidence, with the goal of developing a long term solution by 2018. 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 bott om hole 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 report ing 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 4 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT 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 sam e wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience crossflow between laterals completed in different Schrader Bluff sands while shut -in, which can result in uneven zonal recharge. 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 t ransient analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir 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 becom ing 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 are ~2000 psi. During the reporting period, there was no production or injection due to producer L-200 being offline for sanding issues. The operator is evaluating options to return the wells in Polygon 1 to active status. 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 were cycled on and off 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 1200 psi to 2400 psi. The lowest pressure in the polygon was obser ved 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. 5 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT The OA sand in injector V-222i was subsequently isolated by replacing the waterflood regulating valve with a dum my 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 reservoir pressure has been observed. During the prior reporting period, a matrix bypass event was confirmed in V-211i. In July 2015, the matrix bypass event in V-211i’s OA sand was remediated with Crystal Seal and subsequent diagnostics indicate the remediation was successful. 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 2100 psi. One of t he 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. Producer L-204 was cycled on in April ’16 and has been online since. The most recent reservoir pressure for L- 204 is 1373 psi. During the prior reporting period, a matrix bypass event was confirmed in V-224i. In July 2015, the matrix bypass event in V-224i’s Oba sand was remediated with Crystal Seal and subsequent diagnostics indicate the remediation was successful. 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 2100 psi. During the reporting period, there was no production or injection due t o producer L-205 being offline for sanding issues. The operator is evaluating options to return the wells in Polygon 5 to active status. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL M ONITORING (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 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 6 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT 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 allocatio ns 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: During the reporting period, two injection logs were run. In May 2016, injection logs were run in V-211 and V-224 to identify if any valves (dummy valve or waterflood regulating valve) were no longer seated in the well’s gas lift madrels; troubleshooting increased injectivity. A summary of the interpreted results from the injection logs run during the reporting period is shown in Table 3. Injection logs are used to quality check waterflood regulat ing 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 POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATIO N FACTORS AND ISSUES (RULE 4, PART (F)) 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. 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 7 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT 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 still considered the primary metric for production allocation at L Pad. Due to reliability issues, however, we have also been utilizing the L Pad Test Separator for production allocation. During the reporting period, the need for standardization in L and V testing was identified along with improvements in maintenance and calibration activities for both the L Pad Test Separator and the Gen 2 meters. We are currently working to standardize the pro duction allocation systems at L and V for use in future reporting cycles. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.90 and 1.10. Any days with allocation factors of zero were exc luded. A planned TAPS shutdown was responsible for two zero allocation days on 6/25/16 and 6/26/16. The monthly averages of daily oil production allocation factors are shown in Table 4. Electronic files containing daily allocation data and daily test dat a for a minimum of five years are being retained. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT 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 an d 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 8,275 BWIPD. Cumulative injection through June 2016 was 42.3 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 - M iscible 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 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. 8 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT During the reporting period, average injection rat e was 9.4 MMSCFD. Cumulative injection through June 2016 was 23.1 BCF, which has been injected in 24 water-alternating-gas injectors. No new water-alternating-gas injectors have been placed into service during the reporting period. Reservoir Management Strategy: The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize 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 eme rgence 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 prob able 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, no new matrix bypass events were confirmed. 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) New Sands: 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 M ONITORING 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 report ing 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. 9 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT 9. FUTURE DEVELOPMENT PLANS Future development plans are discussed in the 2015 update to the Plan of Development for the Orion Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2015, of copy of which was prov ided to the Commission. The Commission will be copied when the 2016 update of the Orion Plan of Development is filed with the Division. 10 7/15 – 6/16 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-15 141,723.122,388.106,016.149,477.333,960.32,198,656.30,313,624.9,567,767.39,384,621.51,554,462.-53,836 2,144,231 1.18 Aug-15 120,067.86,256.94,843.98,200.342,867.32,318,723 30,399,880 9,662,610 39,482,821 51,855,935 -54,501 2,089,730 1.22 Sep-15 183,133.145,236.150,745.161,348.367,840.32,501,856 30,545,116 9,813,355 39,644,169 52,235,922 7,762 2,097,492 0.98 Oct-15 177,092.132,555.117,503.208,853.319,084.32,678,948 30,677,671 9,930,858 39,853,022 52,635,124 -55,626 2,041,865 1.16 Nov-15 172,162.101,729.176,570.283,793.215,922.32,851,110 30,779,400 10,107,428 40,136,815 53,049,148 -26,792 2,015,073 1.07 Dec-15 172,783.144,918.134,403.321,992.256,655.33,023,893 30,924,318 10,241,831 40,458,807 53,525,787 -115,324 1,899,749 1.32 Jan-16 133,845.73,392.121,041.258,708.321,684.33,157,738 30,997,710 10,362,872 40,717,515 53,976,876 -168,478 1,731,271 1.60 Feb-16 136,029.186,730.137,274.304,944.364,601.33,293,767 31,184,440 10,500,146 41,022,459 54,499,984 -164,019 1,567,252 1.46 Mar-16 140,213.220,330.140,900.312,866.343,574.33,433,980 31,404,770 10,641,046 41,335,325 55,018,687 -132,737 1,434,515 1.34 Apr-16 118,742.218,376.136,132.279,729.270,511.33,552,722 31,623,146 10,777,178 41,615,054 55,460,815 -79,535 1,354,980 1.22 May-16 145,977.231,998.132,601.325,204.141,060.33,698,699 31,855,144 10,909,779 41,940,258 55,872,496 -22,540 1,332,440 1.06 Jun-16 90,814.147,418.91,029.315,095.154,009.33,789,513 32,002,562 11,000,808 42,255,353 56,281,607 -156,577 1,175,863 1.62 11 7/15 – 6/16 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY FIGURE 2: ORION VOIDAGE HISTORY 12 7/15 – 6/16 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 8/26/2015 27648 SBHP 82 4142 1924 4400 0.40 2027 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 4/22/2016 31032 SBHP 82 4194 1908 4400 0.40 1990 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 1/26/2016 9216 SBHP 83 4204 1294 4400 0.40 1372 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 6/27/2016 33720 SBHP 57 3028 1541 4400 0.40 2090 L-250 50029232810000 O 640135 Nb 4199-4269, 4208-4281 3/12/2016 6240 SBHP 82 4123 1872 4400 0.40 1983 L-219 50029233760000 WAG 640135 OA 4413-4445 6/30/2016 3000 SBHP 83 4362 1962 4400 0.44 1979 L-219 50029233760000 WAG 640135 OBa 4480-4492 6/30/2016 3000 SBHP N/A 4470 1966 4400 0.44 1935 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 6/30/2016 3000 SBHP 87 4652 2086 4400 0.44 1975 L-220 50029233870000 WAG 640135 Nb 4116-4136 6/30/2016 50232 SBHP 82 4052 1832 4400 0.44 1985 L-220 50029233870000 WAG 640135 OA 4250-4291 6/30/2016 50232 SBHP 86 4203 1870 4400 0.44 1957 L-220 50029233870000 WAG 640135 OBa 4318-4347 6/30/2016 50232 SBHP 89 4308 1997 4400 0.44 2037 L-220 50029233870000 WAG 640135 OBb+OBc 4360-4377, 4414-4431 6/30/2016 50232 SBHP 90 4362 2013 4400 0.44 2030 L-220 50029233870000 WAG 640135 OBd 4466 -4511 6/30/2016 50232 SBHP 89 4457 1995 4400 0.44 1970 L-221 50029233850000 WAG 640135 Nb 4090-4105 6/30/2016 31944 SBHP 83 4038 1829 4400 0.44 1988 L-221 50029233850000 WAG 640135 OA 4222-4258 6/30/2016 31944 SBHP 87 4176 1861 4400 0.44 1960 L-221 50029233850000 WAG 640135 OBa 4285-4316 6/30/2016 31944 SBHP 89 4276 1976 4400 0.44 2031 L-221 50029233850000 WAG 640135 OBb+OBc 4329-4343, 4382-4401 6/30/2016 31944 SBHP 89 4329 2009 4400 0.44 2040 L-221 50029233850000 WAG 640135 OBd 4433-4481 6/30/2016 31944 SBHP 91 4426 1982 4400 0.44 1971 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 7/15 – 6/16 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 10/28/2015 8328 SBHP 87 4286 1248 4400 0.44 1298 L-222 50029234200000 WAG 640135 OBa 4378-4412 10/28/2015 8328 SBHP 87 4370 1564 4400 0.44 1577 L-222 50029234200000 WAG 640135 OBb+OBc 4427-4435, 4466-4482 10/28/2015 8328 SBHP 88 4433 1786 4400 0.44 1771 L-222 50029234200000 WAG 640135 OBd 4521-4571 10/28/2015 8328 SBHP 92 4514 1669 4400 0.44 1619 L-223 50029234150000 WAG 640135 Nb 4377-4396 6/30/2016 57360 SBHP 85 4339 1966 4400 0.44 1993 L-223 50029234150000 WAG 640135 OA 4502-4538 6/30/2016 57360 SBHP 88 4477 2030 4400 0.44 1996 L-223 50029234150000 WAG 640135 OBa 4567-4599 6/30/2016 57360 SBHP 90 4560 2066 4400 0.44 1996 L-223 50029234150000 WAG 640135 OBc 4667-4686 6/30/2016 57360 SBHP 92 4642 2037 4400 0.44 1931 L-223 50029234150000 WAG 640135 OBd 4717-476 5 6/30/2016 57360 SBHP 93 4714 2052 4400 0.44 1914 V-203 50029232850000 O 650135 OA+OBa+ OBb+OBc+OBd 4249-4274, 4306-4331, 4342-4365, 4397-4426, 4455-4486 8/27/2015 216 SBHP 81 4125 1249 4400 0.40 1359 V-205 50029233380000 O 640135 OA+OBa+OBd 4395-4404, 4393-4435, 4452-4452, 4458-4470, 4498-4505, 4514-4511, 4588-4618, 4620-4617 6/30/2016 312 SBHP 81 4269 1661 4400 0.40 1713 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 6/30/2016 312 SBHP 88 4407 1335 4400 0.40 1332 V-215 50029233510000 WAG 640135 OA 4370-4404 6/30/2016 9504 SBHP 80 4347 1856 4400 0.44 1879 V-217 50029233340000 WAG 640135 OBa+OBb 4416 - 4443, 4456 - 4472 8/29/2015 1392 SBHP 85 4422 1753 4400 0.44 1743 V-217 50029233340000 WAG 640135 OBd 4562-4610 8/29/2015 1392 SBHP N/A 4551 1740 4400 0.44 1674 V-218 50029233500000 WAG 640135 OBa+OBb 4455-4550 6/30/2016 14184 SBHP 84 4515 1809 4400 0.44 1758 V-218 50029233500000 WAG 640135 OBd 4664-4703 6/30/2016 14184 SBHP N/A 4653 1867 4400 0.44 1756 V-219 50029233970000 WAG 640135 Nb 4434-4450 10/24/2015 1704 SBHP 89 4416 1773 4400 0.44 1766 V-219 50029233970000 WAG 640135 OBa 4626-4654 10/24/2015 1704 SBHP 90 4613 1869 4400 0.44 1775 V-219 50029233970000 WAG 640135 OBb 4667-4680 10/24/2015 1704 SBHP 90 4665 1933 4400 0.44 1816 V-219 50029233970000 WAG 640135 OBd+OBe 4769-4810, 4842-4866 10/24/2015 1704 SBHP 91 4752 2071 4400 0.44 1916 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 7/15 – 6/16 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 1/31/2016 1056 SBHP 89 4328 1402 4400 0.44 1434 V-220 50029233830000 WAG 640135 OA 4486-4525 1/31/2016 1056 SBHP 86 4465 2149 4400 0.44 2120 V-220 50029233830000 WAG 640135 OBa 4554-4583 1/31/2016 1056 SBHP 88 4544 1573 4400 0.44 1510 V-220 50029233830000 WAG 640135 OBb+OBc 4598-4616, 4658-4678 1/31/2016 1056 SBHP 85 4597 1845 4400 0.44 1758 V-220 50029233830000 WAG 640135 OBd 4710-4748 1/31/2016 1056 SBHP 96 4703 1603 4400 0.44 1470 V-220 50029233830000 WAG 640135 OBe 4774-4793 1/31/2016 1056 SBHP 96 4775 1957 4400 0.44 1792 V-222 50029233570000 WAG 640135 OA 4326-4364 4/22/2016 1560 SBHP 82 4248 1132 4400 0.44 1199 V-222 50029233570000 WAG 640135 OBa 4393-4421 4/22/2016 1560 SBHP N/A 4376 1311 4400 0.44 1322 V-222 50029233570000 WAG 640135 OBb+OBc 4433-4450, 4485-4503 4/22/2016 1560 SBHP 80 4433 1726 4400 0.44 1711 V-222 50029233570000 WAG 640135 OBd 4448-4578 4/22/2016 1560 SBHP N/A 4532 1634 4400 0.44 1576 V-223 50029233840000 WAG 640135 OA 4419-4458 3/22/2016 6936 SBHP 84 4397 1769 4400 0.44 1770 V-223 50029233840000 WAG 640135 OBa 4485-4513 3/22/2016 6936 SBHP 85 4471 1694 4400 0.44 1663 V-223 50029233840000 WAG 640135 OBb 4528-4545 3/22/2016 6936 SBHP 87 4524 1790 4400 0.44 1735 V-223 50029233840000 WAG 640135 OBd 4632-4674 3/22/2016 6936 SBHP 90 4616 1990 4400 0.44 1895 V-224 50029234000000 WAG 640135 Nb 4466-4485 5/29/2016 408 SBHP 86 4450 1555 4400 0.44 1533 V-224 50029234000000 WAG 640135 OBa 4674-4704 5/29/2016 408 SBHP 89 4624 1409 4400 0.44 1310 V-224 50029234000000 WAG 640135 OBb 4718-4736 5/29/2016 408 SBHP 90 4718 1435 4400 0.44 1295 V-224 50029234000000 WAG 640135 OBd 4832-4881 5/29/2016 408 SBHP 91 4801 1875 4400 0.44 1699 V-224 50029234000000 WAG 640135 OBe 4903-4928 5/29/2016 408 SBHP 91 4901 2117 4400 0.44 1897 V-227 50029234170000 WI 640135 Nb 4449-4462 6/30/2016 44064 SBHP 88 4403 1887 4400 0.44 1886 V-227 50029234170000 WI 640135 OBa 4634-4662 6/30/2016 44064 SBHP 92 4596 1495 4400 0.44 1409 V-227 50029234170000 WI 640135 OBb 4677-4695 6/30/2016 44064 SBHP 92 4760 1700 4400 0.44 1542 V-227 50029234170000 WI 640135 OBd 4790-4837 6/30/2016 44064 SBHP 94 4673 1882 4400 0.44 1762 V-227 50029234170000 WI 640135 OBe 4854-4876 6/30/2016 44064 SBHP 97 4854 2058 4400 0.44 1858 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 7/15 – 6/16 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 2/16/2016 1104 SBHP 95 4325 1699 4400 0.44 1732 V-229 50029234640000 WAG 640135 OBA 4403-4431 2/16/2016 1104 SBHP 97 4395 1627 4400 0.44 1629 V-229 50029234640000 WAG 640135 OBb 4446-4464 2/16/2016 1104 SBHP 101 4446 2378 4400 0.44 2358 V-229 50029234640000 WAG 640135 Obd 4505-4515 2/16/2016 1104 SBHP 98 4594 2238 4400 0.44 2153 V-229 50029234640000 WAG 640135 Obd 4554-4593 2/16/2016 1104 SBHP 99 4553 2031 4400 0.44 1964 Printed Name Ken Huber Date July 26th, 2016 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 Ken Huber Title Reservoir 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 7/15 – 6/16 PBU Orion Annual Reservoir Report FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 17 7/15 – 6/16 PBU Orion Annual Reservoir Report FIGURE 4: ORION PRESSURES IN MAP VIEW 18 7/15 – 6/16 PBU Orion Annual Reservoir Report TABLE 3: ORION MONTHLY PRODUCTION AND INJECTION PROFILES Well Survey Date Survey Type Zones Splits Oil / Water / Gas Service Comments V -211 5/1/16 IPROF OA 0%/5%/0% Injector Water Injection Oba 0%/6%/0% Injector Water Injection Obb 0%/0%/0% Injector Water Injection Obc 0%/0%/0% Injector Water Injection Obd 0%/89%/0% Injector Water Injection V -224 5/2/16 IPROF OA 0%/46%/0% Injector Water Injection Oba/Obb 0%/1%/0% Injector Water Injection Obd 0%/40%/0% Injector Water Injection Obe 0%/13%/0% Injector Water Injection 19 7/15 – 6/16 PBU Orion Annual Reservoir Report TABLE 4: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Oil Allocation Month Factor Jul-15 0.93 Aug-15 0.96 Sep-15 1.03 Oct-15 1.01 Nov-15 0.94 Dec-15 0.92 Jan-16 0.90 Feb-16 0.91 Mar-16 0.91 Apr-16 0.92 May-16 0.98 Jun-16 0.93 1 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT 2016 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2015 – JUNE 30, 2016 2 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION ................................................................................................................ 3 2. VOIDAGE B ALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ...... 3 3. A NALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B)............. 3 4. RESULTS AND A NALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL M ONITORING (RULE 9C) .................................................................................. 5 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (D)) .......................... 6 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT SUMMARY (RULE 9E) ............................................................................ 6 7. RESULTS OF M ONITORING TO DETERMINE ENRICHED GAS INJECTANT B REAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) ................................................... 8 8. FUTURE DEVELOPMENT PLANS………………………………………………………. 8 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 Table 3: Polaris production and injection profiles.............................................................................. 15 Table 4: Polaris monthly average oil allocation factors ..................................................................... 16 3 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY U NIT 2016 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1. I NTRODUCTION This Annual Surveillance Report is submitted to the Alaska Oil and Gas Conservation Commission for the Polaris Oil Pool in accordance with Commission regulations and Conservation Order 484A. This report covers the period from July 1, 2015 t hrough June 30, 2016. 2. VOIDAGE BALANCE BY M ONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,306 BOPD, 3.6 MMSCFD (FGOR 832 SCF/STB), and 6,095 BWPD (WC 59%). Water injection during this period averaged 6,049 BWIPD with 4.1 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.9. 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 9 B) 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 stat ic bott om hole 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 report ing 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 t ransient 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 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. 4 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT 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 Nort h Th is 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 2137 psi which was taken on 02/06/2016. 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 1400 psi to 2400 psi. During the prior reporting period, a matrix bypass event was confirmed in S-215i. In August 2015, the matrix bypass event in S-215i’s Oba sand was remediated with Crystal Seal and subsequent diagnostics indicate the remediation was successful. 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 1500 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. Subsequent production logging in W -202’s Oba lateral identified the location of the matrix bypass event as well as confirmed W -201’s increased water production was coming from W -202’s Oba lateral via what is presumed to be a second matrix bypass event between the two producers. W -202’s matrix bypass event to the aquifer was remediated in October 2015 by setting a HEX plug in the Oba lateral; W -201’s matrix bypass event was remediated with the same piece of wellwork. The aforementioned remediation was initially deemed a success, but within two months watercut and water rate were once again increasing in both W -201 and W -202. The f ailure mechanism was attributed to a failed swell packer in W -202’s Oba lateral. In July 2016, the toe of W -202’s Oba lateral was cemented off and the initial results suggests the matrix bypass remediation was a success. During the prior reporting period, a matrix bypass event w as confirmed in W -212i. In October 2015, the matrix bypass event in W -212i’s Oba sand was remediated with a cement squeeze. 5 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT Subsequent diagnostics indicate the remediation was initially successful but broke down after several weeks, returning to similar injectivity and inter-well transit time of water. Alternative remediation options are currently being evaluated for W -212i. W -Pad East 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 2500 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 ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL M ONITORING (RULE 9C) Production Logs: During the reporting period, a production log was run in August 2016 in W -202. The primary goal of the logging job was to identify the location of the matrix bypass event in the Oba lateral. The logging job was successful and played a key role in designing the wellwork job to remediate the matrix bypass event. Prior production logs have frequently been adversely affected by well slugging. Fu ture 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 (MB E) 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 o n 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. 6 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT Injection Logs: During the reporting period, two injection logs were run. In December 2015, an injection log was run in W -212 to determine if the well needed to be re-perf orated after the remediation of the matrix bypass event. In March 2016, an injection log was run in W -216 to identify which zone was cycling MI as quick breakthrough was observed in offset producer W -204. A summary of the interpreted results from the injection logs run during the reporting period is shown in Table 3. Injection logs are typically 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 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) AND REVIEW OF POOL PRODUCTION ALLOCATIO N FACTORS AND ISSUES (RULE 4, PART (D)) 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 the oretical 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. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.90 and 1.10. Any days with allocation factors of zero were excluded. A planned TAPS shutdown was responsible for two zero allocation days on 6/25/16 and 6/26/16. The monthly averages of daily oil production allocat ion factors are shown in Table 4. Electronic files containing daily allocation data and daily test dat a for a minimum of five years are being retained. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR M ANAGEMENT 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 maintain reservoir pressure 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 san ds to accurately control injection rate into the vastly different sands. Injection rate into each zone is 7 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT 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 6,049 BWIPD. Cumulative injection through June 2016 was 24.0 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 s trategy 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 . During the reporting period, average injection rate was 4.1 MMSCFD . Cumulative injection through June 2016 was 5.6 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. Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage reservoir development and depletion to maximize economic 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 eme rgence 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 prob able 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, no new matrix bypass events were confirmed. 8 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT 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 report ing 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. Future Developm ent Plans Future development plans are discussed in the 2015 update to the Plan of Development for the Polaris Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2015, of copy of which was provided to the Commission. The Commission will be copied when the 2016 update of the Polaris Plan of Development is filed with the D ivision. 9 7/15 – 6/16 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-15 118,554.70,217.182,023.192,148.3,689.18,822,960.16,921,448.7,640,827.22,030,614.24,731,249.51,691 5,274,892 0.79 Aug-15 84,355.42,568.175,114.144,740.18,715.18,907,315 16,964,016 7,815,941 22,175,354 24,888,665 40,824 5,315,716 0.79 Sep-15 118,360.42,933.200,508.154,887.65,807.19,025,675 17,006,949 8,016,449 22,330,241 25,084,585 77,339 5,393,056 0.72 Oct-15 130,493.79,524.164,035.232,224.80,390.19,156,168 17,086,473 8,180,484 22,562,465 25,367,365 -8,242 5,384,814 1.03 Nov-15 118,447.86,011.146,260.200,986.111,180.19,274,615 17,172,484 8,326,744 22,763,451 25,637,069 -6,614 5,378,200 1.03 Dec-15 151,599.98,774.145,345.211,766.178,105.19,426,214 17,271,258 8,472,089 22,975,217 25,957,816 -3,850 5,374,350 1.01 Jan-16 153,114.117,572.267,145.203,275.197,535.19,579,328 17,388,830 8,739,234 23,178,492 26,281,645 12,865 5,387,215 0.96 Feb-16 157,197.153,616.207,355.170,334.193,520.19,736,525 17,542,446 8,946,589 23,348,826 26,569,794 53,719 5,440,935 0.84 Mar-16 167,009.217,136.216,183.166,420.121,822.19,903,534 17,759,582 9,162,772 23,515,246 26,810,971 154,558 5,595,493 0.61 Apr-16 103,488.129,554.152,199.190,871.107,901.20,007,022 17,889,136 9,314,971 23,706,117 27,068,492 -15,885 5,579,608 1.07 May-16 148,962.144,077.200,516.165,530.292,611.20,155,984 18,033,213 9,515,487 23,871,647 27,411,244 -21,130 5,558,478 1.07 Jun-16 120,246.125,354.167,864.174,771.109,845.20,276,230 18,158,567 9,683,351 24,046,418 27,653,669 97,612 5,656,090 0.71 10 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 11 7/15 – 6/16 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 2/6/2016 28488 SBHP 92 5000 2137 5000 0.45 2137 S-215 50029231070000 WAG 64160 OA 4988-5002, 5006-5016 4/3/2016 1536 SBHP 89 4975 2170 5000 0.44 2181 S-215 50029231070000 WAG 64160 OBa 5032-5059 4/3/2016 1536 SBHP N/A 5022 1394 5000 0.44 1384 S-215 50029231070000 WAG 64160 OBb+OBc 5068-5085, 5119-5133 4/3/2016 1536 SBHP 93 5067 2392 5000 0.44 2362 S-215 50029231070000 WAG 64160 OBd 5169-5196 4/3/2016 1536 SBHP N/A 5151 2053 5000 0.44 1987 S-217 50029233620000 PWI 64160 OA 4960-4989 4/26/2016 1224 SBHP 86 4921 2004 5000 0.44 2039 S-217 50029233620000 PWI 64160 OBa 5007-5023 4/26/2016 1224 SBHP NA 5001 1999 5000 0.44 1999 S-218 50029234140000 WAG 64160 OBa 5050-5067 7/29/2015 984 SBHP 86 5041 2176 5000 0.44 2158 S-218 50029234140000 WAG 64160 OBb+OBc 5086-5105, 5140-5151 7/29/2015 984 SBHP 88 5086 2196 5000 0.44 2158 S-218 50029234140000 WAG 64160 OBd 5185-5225 7/29/2015 984 SBHP 89 5183 2250 5000 0.44 2169 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 8/25/2015 168 SBHP 95 4917 1831 5000 0.40 1864 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 8/25/2015 168 SBHP 88 4840 1447 5000 0.40 1511 W-210 50029233390000 WAG 64160 OBa+OBb 4893-4928 8/1/2015 816 SBHP N/A 4884 2246 5000 0.44 2297 W-210 50029233390000 WAG 64160 OBc 4971-4997 8/1/2015 816 SBHP 86 4959 2434 5000 0.44 2452 W-210 50029233390000 WAG 64160 OBd 5025-5063 8/1/2015 816 SBHP N/A 5010 2280 5000 0.44 2276 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 7/15 – 6/16 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 6/30/2016 10800 SBHP N/A 4799 1854 5000 0.44 1942 W-217 50029234180000 WAG 64160 OBa 4915-5940 9/10/2015 1128 SBHP 89 4881 1906 5000 0.44 1958 W-217 50029234180000 WAG 64160 OBc 4994-5019 9/10/2015 1128 SBHP 87 4974 2182 5000 0.44 2193 W-217 50029234180000 WAG 64160 OBd 5050-5088 9/10/2015 1128 SBHP 85 5053 2100 5000 0.44 2077 W-218 50029234030000 WAG 64160 OBa 4948-4970 4/2/2016 408 SBHP 88 4929 1844 5000 0.44 1875 W-218 50029234030000 WAG 64160 OBc 5032-5055 4/2/2016 408 SBHP 89 5006 1889 5000 0.44 1886 W-218 50029234030000 WAG 64160 OBd 5087-5127 4/2/2016 408 SBHP 85 5092 1991 5000 0.44 1951 W-219 50029234290000 WAG 64160 OBd 5093 - 5137 8/26/2015 216 SBHP 84 5095 2336 5000 0.44 2294 W-220 50029234320000 WAG 64160 OBa 5142-5166 8/26/2015 264 SBHP 86 5117 2417 5000 0.44 2366 W-220 50029234320000 WAG 64160 OBc 5228-5251 8/26/2015 264 SBHP 88 5199 2423 5000 0.44 2335 W-220 50029234320000 WAG 64160 OBd 5278-5311 8/26/2015 264 SBHP 85 5280 2593 5000 0.44 2470 W-223 50029234400000 WAG 64160 OBa 5035-5059 8/26/2015 264 SBHP 88 4999 2138 5000 0.44 2138 W-223 50029234400000 WAG 64160 OBc 5112-5143 8/26/2015 264 SBHP 87 5090 2422 5000 0.44 2382 W-223 50029234400000 WAG 64160 OBd 5169-5208 8/26/2015 264 SBHP 85 5169 2498 5000 0.44 2424 Printed Name Ken Huber Date July 26th, 2016 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 Ken Huber Title Reservoir 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: 13 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 14 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 4: POLARIS PRESSURES IN MAP VIEW 15 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS PRODUCTION AND INJECTION PROFILES Well Survey Date Survey Type Zones Splits Oil / Water / Gas Service Comments W -212 12/18/15 IPROF Oba 0%/49%/0% Injector Water Injection Obc 0%/21%/0% Injector Water Injection Obd 0%/30%/0% Injector Water Injection W -216 3/13/16 IPROF Oba 0%/0%/98% Injector MI Injection Obc 0%/0%/2% Injector MI Injection Obd 0%/0%/0% Injector MI Injection 16 7/15 – 6/16 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 4: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Oil Allocation Month Factor Jul-15 0.93 Aug-15 0.96 Sep-15 1.03 Oct-15 1.01 Nov-15 0.94 Dec-15 0.92 Jan-16 0.90 Feb-16 0.91 Mar-16 0.91 Apr-16 0.92 May-16 0.98 Jun-16 0.93