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Home My WebLink About2014 Prudhoe Satellite Oil Pools 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 1 2014 ANNUAL SURVEILLANCE REPORT AURORA PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2013 – JUNE 30, 2014 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 2 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF E NHANCED RECOVERY PROJECT I MPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A)3 2.1. ENHANCED RECOVERY P ROJECTS 3 2.2. RESERVOIR MANAGEMENT STRATEGY 4 3. VOIDAGE B ALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B)4 4. A NALYSIS OF R ESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C)5 5. R ESULTS AND ANALYSIS OF S PECIAL MONITORING (RULE 8 D)5 6. R EVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E)5 7. R EVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8 F & G)5 LIST OF ATTACHMENTS Figure 1: Aurora well location map........................................................................ 9 Figure 2: Cumulative voidage replacement by region ......................................... 10 Figure 3: Aurora voidage history ......................................................................... 11 Figure 4: Aurora reservoir pressure map – July 2013 .......................................... 12 Figure 5: Aurora allocated production history ...................................................... 13 Figure 6: Aurora allocated injection history ......................................................... 14 Table 1: Aurora monthly production, injection, voidage balance summary ........... 7 Table 2: Cumulative voidage status by fault block ................................................ 7 Table 3: Aurora pressure survey detail .................................................................. 8 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 3 PRUDHOE BAY UNIT 2013 AURORA OIL POOL ANNUAL RESERVOIR REPORT 1. I NTRODUCTION This Annual Reservoir Report for the year ending June 30, 2014 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 457A for the Aurora Oil Pool. 2. PROGRESS OF E NHANCED RECOVERY PROJECT I MPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 2.1. 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 expanded to the Southeast Crest (SEC) and Crest (CR) blocks in 2006. Evaluation of hydrocarbon recovery mechanisms for the Aurora Oil Pool (AOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, gas cap presence, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field’s life and will help ensure greater ultimate recovery. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the AOP where injection is justified, water-flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Water injection should maintain average reservoir pressure above minimum miscibility pressure (MMP) of approximately 2700 psi in the flood area to ensure hydrocarbon recovery targets are achieved. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility between t he 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 MMP. 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 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 4 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. 2.2. RESERVOIR MANAGEMENT STRATEGY The objective of the Aurora reservoir management strategy is to manage reservoir development and depletion to achieve greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, producers experienced increasing gas -oil-ratios (GORs) due to existence of an initial gas cap, primarily in the West side of the field, but also apparent in the CR & SEC areas. Production was restricted to conserve reservoir energy. Beginning in mid -2001 and continuing into 2003, production from wells S-100, S-106 and S-102 were reduced to approximately half capacity, allowing injection to significantly reduce the GORs by the end of 2003. This practice continued in 2004 -5 with curtailment of wells S-108, S-113B and S-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure & productivity in S-108. Pressure data & production performance in S -113B indicates the well is supported by a large gas-cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Irregular pattern waterfloods have been designed to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns are based on the current understanding of compartmentalization; however, reservoir mana gement is a dynamic process. Patterns and producer/injector ratios will be modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring and waterflood performance monitoring to support this feedback and intervention process. Figure 1 shows Aurora well locations and the field development areas. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement by fault block is summarized in Table 2 and Figure 2. Figure 3 summarizes the voidage history of Aurora field. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed and started in late 2006 to provi de increased injection rates to low injectivity patterns. The largest VRR challenge for this reporting year came from down time of the Sulzer and Ruston injection pumps at GC-2 and downtime of the S-504 boosted water pump. Injection volumes were limited because of the pump failures and a ground fault issue on S-Pad preventing the S- 504 boosted water pump to be operated. All c hallenges have been brought to a successful resolution. 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 5 4. ANALYSIS OF R ESERVOIR PRESSURE S URVEYS WI THIN THE P OOL (RULE 8 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457B. A summary of reservoir pressure surveys is shown in Table 3. The field average reservoir pressure map is shown in Figure 4. Static BH pressures were gathered in 13 wells during the reporting period. Most producers in the AOP have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) There were no injection profiles that were run in the Aurora Field during this reporting year. There were no production profiles that were run in the Aurora Field during this reporting year. 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) Since August 2002, Aurora production allocation has adhered to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust the total Aurora production volumes at the end of each month. A minimum of one well test per month is used to check the performance curves and to verify system performance, with more frequent testing during the first three months of production in new wells and after major wellwork. Allocated daily production and injection is shown in Table 1. Graphical representation of the allocated figures is shown in Figures 5 and 6. 7. REVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8 F & G) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation and are annotated in Figure 1. Differing initial gas -oil and oil-water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area, 2) North of Crest Area (NOC), 3) South East of Crest Area (SEC), and 4) Crest Area (AURCR). 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 6 After establishing primary production from each area, water -flood and tertiary EOR has been implemented to provide pressure support and reduce residual oil saturations. The West and North of Crest areas began production in 2000-2001; water injection commenced in 2002 and MWAG began in December 2003. Initiation of water injection into the South East of Crest Area began with conversion of Wells S-112 and S-110 to injection in June and July 2003 and conversion to MWAG in 2006. Crest Area production began in mid -March 2003 with startup of Aurora Well S-115; Well S-117 production began in early June 2003 with a water-flood startup in August 2004 with newly drilled injection wells S-116i and S-120i that were put on MWAG in 2006. Summarized below are significant events and accomplishments at Aurora over the past year: The injection management strategy at Aurora will continue to target an instantaneous VRR of 1.2 through WAG injection to maintain reservoir pressure and capture EOR benefits. Various jobs related to wells (wellwork and drilling) were achieved during the reporting period: Injection well S-110A was sidetracked as S-110B to support the producing well S-109. Water injection began in April of 2014 with a response observed in well S-109 in May 2014. The production well S-118 was brought online as an intermittent producer three times during the reporting period. Due to slow recharge from the reservoir, the well was not able to maintain continuous production. Due to TXIA communication the well was classified as inoperable in April 2014. Injection well S-116A was sidetracked to support the S-129 producer and started water injection in May of 2014. A response in the producing well S-129 was observed in June 2014. S-135 was drilled and completed as a producer in March 2014. The well was tested in April 2014 and well tie-in work continued during the reporting period. The Kuparuk (Aurora) interval in the S-09 injector was abandoned to allow the well to be sidetracked for Sag injection infill target. The Aurora owners will continue to evaluate optimal well count, well utility and well locations to maximize recovery. 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 7 TABLE 1: AURORA MONTHLY PRODUCTION, INJECTION, VOIDAGE BALANCE SUMMARY Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2013 4805 7500 10940 0.779 8201 10732 8/31/2013 4221 7884 11280 0.280 435 5441 9/30/2013 5503 10250 13150 0.204 330 4967 10/31/2013 4680 6088 9636 0.871 4175 12783 11/30/2013 4837 6005 12655 0.862 10063 11239 12/31/2013 4396 5032 10695 1.073 10499 12071 1/31/2014 3501 5464 8433 1.136 4400 14462 2/28/2014 3880 11842 11265 0.420 0 10122 3/31/2014 5229 11600 14631 0.506 1868 12858 4/30/2014 4969 11467 12153 0.788 8455 14771 5/31/2014 4543 11011 10171 1.016 8603 17992 6/30/2014 5279 15915 13967 1.167 2549 35155 TABLE 2: CUMULATIVE VOIDAGE STATUS BY FAULT BLOCK On 6/30/2014 AUR-CR* AUR-NOC** AUR-SEC* AUR-WEST* Total Inj Cum MRVB 14,794 33,918 7,530 62,758 Total Prod Cum MRVB 28,347 40,889 11,329 86,673 Cum I/W ratio 0.52 0.83 0.66 0.72 Bo 1.32 rb / stb oil Bg 0.843 rb / mcf gas Bw 1.020 rb / stb water Rs 0.650 mscf / stb oil * Initial gas-cap Bmi 0.620 rb / mcf gas MI ** Solution gas only 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 8 TABLE 3: AURORA PRESSURE SURVEY DETAIL 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 9 Figure 1: Aurora well location map 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 10 Figure 2: Cumulative Voidage Replacement by Region 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 11 Figure 3: Aurora Voidage History 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 12 Figure 4: Aurora Reservoir Pressure Map – July 2013 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 13 Figure 5: Aurora allocated production history 7/13 – 6/14 AURORA ANNUAL SURVEILLANCE REPORT 14 Figure 6: Aurora allocated injection history 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 1 2014 ANNUAL SURVEILLANCE REPORT BOREALIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2013 – JUNE 30, 2014 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 2 TABLE OF CONTENTS 1.INTRODUCTION 2.P ROGRESS OF E NHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT S UMMARY (RULE 9A) 2.1.ENHANCED RECOVERY PROJECTS 2.2.RESERVOIR MANAGEMENT SUMMARY 3.V OIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) 4.ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) 5.RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) 6.REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) 7.O PERATIONS , DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) LIST OF ATTACHMENTS Figure 1: Borealis well location map ................................................................................................. 9 Figure 2: Borealis allocated production history ............................................................................... 10 Figure 3: Borealis voidage history ................................................................................................... 11 Figure 4: Borealis injection history .................................................................................................. 12 Figure 5: Borealis reservoir pressure map ...................................................................................... 13 Table 1: Borealis monthly production, injection, voidage balance summary .................................... 6 Table 2: Borealis cumulative production & injection summary ........................................................ 7 Table 3: Borealis pressure surveys ................................................................................................... 8 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 3 PRUDHOE BAY UNIT 2014 BOREALIS OIL POOL ANNUAL RESERVOIR REPORT 1. I NTRODUCTION This Annual Reservoir Report for the year ending June 30, 2014 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 471 for the Borealis Oil Pool. This report summarizes surveillance data, analysis and ot her information as required by Rule 9 of Conservation Order 471. 2. PROGRESS OF E NHANCED RECOVERY PROJECT I MPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) 2.1. ENHANCED RECOVERY P ROJECTS Waterflood has been implemented in Borealis, which includes 21 injectors in full service. Enhanced Recovery Projects using Miscible Injectant (MI) are implemented in Borealis. Currently 19 of the 21 injectors can interchange between water and MI injection. Figure 1 shows Borealis well locations. 2.2. RESERVOIR MANAGEMENT SUMMARY The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery, consistent with prudent oil field engineering practices. Water injection was initiated in June 8, 20 02 to restore reservoir pressure and reduce gas-oil-ratios (GORs), thereby enabling wells to be produced at their full capacity. An irregular pattern waterflood has been designed and implemented to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and GORs stabilized near solution GOR. When water injection was initiated, an instantaneous VRR target of greater than 1.0 was aimed for in order to catch up with voidage. The cumulative VRR target remains 1.0. 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 4 Injection facility limitations were identified in 2003, which limited the delivery pressure of water to be injected to the field. Booster pumps were installed at Z Pad to provide increased injection pressure and better water distribution. The increased injection pressure has allowed better management of injection at a pattern level. The Borealis waterflood strategy is progressing as planned however Borealis has experienced water breakthrough earlier than expected in many patterns. Impacts of the early breakthrough include reduced production due to unfavorable wellbore hydraulics and gas -lift supply pressure limitations. Remedies have included gas-lift redesign and optimization and prioritization of gas-lift use. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) Monthly production and injection surface volumes for July 2013 to June 2014 are summarized in Table 1, and cumulative volumes can be found in Table 2. Figures 2, 3 and 4 graphically depict this information since start-up. Subsequent to initiating and stabilizing injection, monthly reservoir voidage will be balanced with water injection, consistent with the reservoir management strategy. The largest VRR challenge for this reporting year came from down time of the Sulzer and Ruston water injection pumps at GC-2. Injection volumes were limited because of the pump failures. 4. ANALYSIS OF R ESERVOIR PRESSURE S URVEYS WITHIN THE P OOL (RULE 9 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. Figure 5 is a map of reservoir pressures collected over the last reporting period. Five of the newer producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressur es, and reservoir connectivity on a continuous basis. Static BH pressures were gathered in 9 wells during reporting period. Most producers in Borealis have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) During this report period, two production logs were performed on wells Z-113 and Z-116. The data quality was good, and the resulting production splits were used to shut off water and check injection conformance. Options continue to be evaluated to utilize enhanced production logging techniques in horizontal wells. 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 5 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST E VALUATION (RULE 9 E) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is now being applied to adjust the total Borealis production similar to IPA production allocation procedures. . A minimum of one well test per month is used to check the performance curves and to verify system performance. In an effort to improve well test quality, Weatherford Generation 2 multi -phase meters (Gen 2) were installed at the L-pad and V-pad test headers. In 2012, the V-pad Gen 2 meter was accepted as the primary metric for production allocations, and the V -pad Well Pad Separator was taken out of service. The L-pad Gen 2 meter is being used to allocate the production rates for the majori ty of the L-pad online wellstock; the L-pad Well Pad Separator is currently still in service. During the reporting period, field tests were conducted at L-pad with the Gen 2 in series with a portable gravity separator system (ASRC Unit 1), which was used as the reference for measurements. Compared to the ASRC Unit 1, the L-pad Gen 2 meter trends higher formation gas rates in a few L-pad wells, but still within 10% (acceptance criteria) of the ASRC Unit measurement. We are working to better understand and try to improve this tendency. 7. O PERATIONS, D EVELOPMENT & RE SERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) Miscible gas injection and water-alternating with miscible gas injection is used to increase the economic recovery of Borealis Reservoir hydrocarbons. Injection wells are completed for Enhanced Oil Recovery services. Waterflood and tertiary EOR have been implemented to provide pressure support and reduce residual oil saturations on all three Borealis Pads, L, V and Z. Injection was started in June 8, 2002. Water injection manifolding and booster pumps have been installed and have been operating since January 2004. These booster pumps enable more efficient waterflood management. The Borealis waterflood management strategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize oil recovery. The Z-Pad expansion project was completed in 2011. The expansion facilitates the further development of Borealis. During the reporting period one additional injector Z -114 was placed in service. The Borealis owners will continue to evaluate the opt imal number of development wells and their location throughout the life of the reservoir. In March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut in during their MI responses due to elevated H2S in the returned MI. The installation of Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from MI. 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 6 TABLE 1: BOREALIS MONTHLY PRODUCTION, INJECTION, VOIDAGE BALANCE SUMMARY Case 1 Date Oil Prod Rate STB/DAY Water Prod Rate STB/DAY Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB VRR Cum RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 7/31/2013 8867 23309 15649 1.000 0.842 19507 33638 8/31/2013 8037 19410 14311 0.857 0.842 15807 24359 9/30/2013 8170 18333 16079 1.265 0.845 34017 30516 10/31/2013 9241 25432 14945 1.137 0.847 25709 38082 11/30/2013 9949 27367 18369 1.161 0.849 34094 40947 12/31/2013 10620 25414 21196 1.167 0.851 41338 38446 1/31/2014 11703 29588 25483 0.908 0.852 27337 41184 2/28/2014 8773 23473 20223 1.018 0.853 25372 35627 3/31/2014 11591 24674 33894 0.715 0.851 27042 31434 4/30/2014 11647 25647 28691 0.949 0.852 45942 31824 5/31/2014 11511 25139 21177 0.847 0.852 23389 32199 6/30/2014 8928 21242 19292 1.139 0.854 23342 39421 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 7 TABLE 2: BOREALIS CUMULATIVE PRODUCTION & INJECTION SUMMARY MONTH_ENDING Data units 06-30-2014 Oil Prod Cum 74601 MSTB Gas Prod Cum 100344 MMSCF Water Prod Cum 86168 MSTB Gas Inj Cum 74201 MMSCF Water Inj Cum 161215 MSTB Total Inj Cum 212056 MRVB Total Prod Cum 248371 MRVB VRR Cum 0.854 RVB/RVB Bo 1.25 rb / stb oil Bg 1.013 rb / mcf gas Bw 1.03 rb / stb water Rs 0.457 mscf / stb oil Bmi 0.62 rb / mcf gas MI 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 8 TABLE 3: BOREALIS PRESSURE SURVEYS 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 9 FIGURE 1: BOREALIS WELL LOCATION MAP 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 10 FIGURE 2: BOREALIS ALLOCATED PRODUCTION PROFILE 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 11 FIGURE 3: BOREALIS – TOTAL PRODUCTION / INJECTION RATES (RVB/D), VRR RATE, AND CUMULATIVE VRR 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 12 FIGURE 4: BOREALIS TOTAL INJECTION RATES-GAS & WATER 7/13 – 6/14 BOREALIS ANNUAL SURVEILLANCE REPORT 13 FIGURE 5: BOREALIS RESERVOIR PRESSURE MAP 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 1 2014 ANNUAL SURVEILLANCE REPORT MIDNIGHT SUN PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2013 – JUNE 30, 2014 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 2 CONTENTS 1. INTRODUCTION ......................................................................................................................... 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 11 A) .................................................................................... 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 & INJECTION LOGGING SURVEYS (RULE 11 D) ...... 4 6. RESULTS OF WELL ALLOCATION AND TEST EVALUATION (RULE 11 E) ..................................... 4 7. FUTURE DEVELOPMENT PLANS AND REVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT (RULE 11 F & G) ........................................................................................................................ 5 LIST OF ATTACHMENTS Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary .......................... 6 Table 2: Reservoir Pressure Surveys ................................................................................................ 7 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 3 PRUDHOE BAY UNIT 2014 MIDNIGHT SUN ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report for the period from July 1, 2013 through June 30, 2014 is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Conservation Order 452 for the Midnight Sun Oil Pool. This report summarizes surveillance data and analysis and other information as required by Rule 11 of Conservation Order 452. 2. 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, 2014 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to ensure greater ultimate recovery consistent with prudent oil field engineering practices. During primary depletion, both producers experienced increasing gas-oil-ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR’s to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil in-flux into the gas cap from mid-field water injection. Placement of the wells drilled in 2001 and voidage management is minimizing this risk. A VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re-saturation of oil into the gas cap. During the period covered by the report, the VRR averaged 1.18. Midnight Sun gas production has remained level during the report period as reservoir pressure has leveled off. Both oil and water production rates have remained fairly constant during the report period. Well E-101 currently produces at ~90% watercut, and Well E-102 produces at ~95% watercut. Since 2005, gas lift has been utilized to produce the Midnight Sun wells more efficiently. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 11 B) A total of five Midnight Sun wells have been drilled, with the most recent wells drilled in 2001. A peak water injection rate of 20-25 MBWPD for the field has been achieved since E-103 and E-104 were converted to water injection in 2003. Monthly production and injection surface volumes for the reporting period are summarized in Table 1 along with a voidage balance of produced and injected fluids for the report period. 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 11 C) Reservoir pressure monitoring is performed in accordance with Rule 8 of Conservation Order 452. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. Reservoir pressures have remained stable throughout the last year. 5. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS (RULE 11 D) In July 2010, three unique tracers were injected into each of the three Midnight Sun injection wells (E-100, E-103, & E-104) with the intent to evaluate communication between the injection and production wells. Samples to check for tracers at the producers (E -101 & E-102) were initially taken every day for the first week, once a week for the next month, a nd remained on an every two week sample schedule until the study ended in October 2012. Starting in March 2012, tracer from injector E-104 began showing up in samples from producer E-102, but the validity of these results were questioned. Samples from E-101 and E-102 since March 2012 underwent testing to determine the extent of the tracer breakthrough from E-104. No more tracer breakthrough was observed through the duration of the study, which concluded in October 2012 with no significant results. The tracer was long overdue for a reservoir with the size and production/injection rates of Midnight Sun. A pressure fall-off test was completed August 6th 2014 for injector E-104. The data will be analyzed and may help explain the reason why this injector has suc h small injection capacity. E- 104 only operates at 5-10% of the daily injection rates of both E-100 and E-103. This rate has declined with time, but the block shows no evidence of significant pressure increase. The PFO test will provide information on reservoir pressure behavior and reveal any near-wellbore damage that could be reducing the injectivity index over time. 6. RESULTS OF WELL ALLOCATION AND TEST EVALUATION (RULE 11 E) Midnight Sun wells are tested using the E-Pad test separator, and Midnight Sun production is processed through the GC-1 facility. Midnight Sun production allocation has been performed according to the PBU Western Satellite Production Metering Plan for the report period. 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 5 7. FUTURE DEVELOPMENT PLANS AND REVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT (RULE 11 F & G) Development plans for the Midnight Sun Oil Pool are set forth in the Twelfth Plan of Development for the Midnight Sun Participating Area. Well E -102, located to the south of Well E- 100, was planned as an injection well that would undergo a pre-production period. Well E-102 has been utilized as a producer to date and has been converted to a permanent producer. Well E-103, located to the southwest of Well E-100, was originally drilled as an up-dip production well. Due to an apparent conduit to the overlying gas cap, Well E-103 was shut-in shortly after being placed on production due to excessive gas production. Well E-103 was converted to water injection service during 2003. Well E-104, drilled in the northwest corner of the field, was drilled as an additional injector well. A Water-Alternating-Gas (WAG) injector is being evaluated from P1 Pad (only pad with MI nearby). There is no other development planned for the Mid night Sun Oil Pool. 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 6 TABLE 1: MIDNIGHT SUN MONTHLY PRODUCTION, INJECTION, VOIDAGE BALANCE SUMMARY Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = .79 rb/Mscf Date Oil Prod (stb) Water Prod (stb) Total Gas Prod (Mscf) Produced Lift Gas (Mscf) Water Inj (stb) Cum Oil (stb) Cum Gas (Mscf) Cum Gas less Prod Lift Gas (Mscf) Net Reservoir Voidage (rb) 2013/07 15,794 227,558 98,807 62,678 464,035 19,675,600 62753258 55,417,956 -206,033 2013/08 17,784 249,306 101,464 61,116 299,635 19,693,384 62854722 55,458,304 -6,808 2013/09 34,976 375,178 115,669 153,165 490,301 19,728,360 62970391 55,476,788 -64,922 2013/10 37,348 418,129 97,992 151,573 536,731 19,765,708 63068383 55,418,158 -79,422 2013/11 39,936 392,218 118,823 144,798 474,142 19,805,644 63187206 55,366,618 -37,060 2013/12 32,849 273,131 93,988 87,506 545,501 19,838,493 63281194 55,355,046 -236,800 2014/01 40,393 404,735 123,659 101,624 538,576 19,878,886 63404853 55,369,769 -81,429 2014/02 38,846 371,858 161,296 137,368 359,682 19,917,732 63566149 55,408,865 78,676 2014/03 36,718 366,729 83,558 239,709 506,312 19,954,450 63649707 55,388,763 -101,561 2014/04 35,599 430,736 38,226 192,176 501,606 19,990,049 63687933 55,231,122 -32,185 2014/05 36,558 401,485 69,946 182,655 522,641 20,026,607 63757879 55,075,208 -82,960 2014/06 36,886 414,179 111,748 142,339 515,998 20,063,493 63869627 54,972,534 -62,173 2014/07 17,404 180,066 39,245 68,582 245,109 20,080,897 63908872 54,938,388 -47,046 7/13 – 6/14 MNS ANNUAL SURVEILLANCE REPORT 7 TABLE 2: RESERVOIR PRESSURE SURVEYS 6. Oil Gravity: 25-29 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) E-100 50-029-22819-00 WI MSOP KUP 8045-8122, 8122-8136 7/26/14 96 SBHP 124 8,050 ft.3,434 8050 0.45 3,434 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Marcus Charles 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Marcus CharlesSignature 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Midnight Sun Printed Name Title Date Pad Engineer August 11, 2014 8050' TVDss 0.72 ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 1 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT 2014 ANNUAL SURVEILLANCE REPORT ORION PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2013 – JUNE 30, 2014 2 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT CONTENTS 1. INTRODUCTION ........................................................................................................................ 3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ........ 3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) ................ 3 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) .......................................................................................... 6 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) .................................................. 7 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) ................................................................................... 7 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) .................................................................................................................................. 9 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) ........................................................ 9 LIST OF ATTACHMENTS Figure 1: Orion production and injection history .............................................................................. 11 Figure 2: Orion voidage history ........................................................................................................ 11 Figure 3: Orion pressures at datum ................................................................................................. 16 Figure 4: Orion pressures in map view ............................................................................................ 17 Table 1: Orion monthly production and injection summary ............................................................. 10 Table 2: Orion pressure survey detail............................................................................................... 12 Table 3: Injection and production profiles ........................................................................................ 18 3 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2014 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, 2013 to June 30, 2014. 2. VOIDAGE B ALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 5,483 BOPD, 4.1 MMSCFD (FGOR 747 SCF/STB), and 3,737 BWPD (WC 41%). Water injection during this period averaged 11,302 BWIPD with 0.3 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.1. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. A NALYSIS OF R ESERVOIR 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 reportin g period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates valid Orion pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in lig ht-oil reservoirs. The low mobility of viscous oil 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 experience slow falloff during shut-in due to the low mobility of the system. Most injectors now incorporate check valves in the waterflood regulat ors to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to 4 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT make the quality of pressure transient 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 problems, 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 a MDT in new producers, or via downhole gauges in injectors. Injector data is becoming increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200 and is supported by injectors L-211i, L-212i, and L-218i. Measured pressures in the polygon range from 2000 psi to 2300 psi. During the reporting period, there was no production or injection due to producer L-200 being offline for sanding issues. Poylgon 1A This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-215i, L- 216i, L-217i, L-219i, and L-223i. Measured pressures in the polygon range from 1400 psi to 2400 psi. During the reporting period, producer L-203 was offline for sanding issues and L-250 was offline for hydrate issues. Consequently, offset injectors L-215i and L-216i were also offline to balance voidage. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L-213i, V-210i, V-211i, V-212i, V-213i, V-214i, V-215i, V-216i, V-217i, V-218i, V-222i, V-223i, V-225i, V-229i. Measured pressures in the polygon range from 1300 psi to 2300 psi. The lowest pressure in the polygon was observed to be injector V-222i’s OA sand. In 2012, a matrix bypass event was identified in the OA sand between producer V -202 and injector V-222i. The OA sand in injector V-222i was subsequently isolated by replacing the waterflood regulating valve with a dummy valve, thus allowing the injector to remain online while remediation options were evaluated. The matrix bypass event was remediated in early 2014 and by all accounts the wellwork appears to be a success as a significant reduction in OA sand injectivity was observed. Now that injection into the OA sand has been restored in injector V-222i, pressure in the OA sand is expected to increase. In addition, reduced reservoir pressure was observed in injector V-211i as this injector had been offline for a period of time prior to acquiring the pressure data; offset producers remained online. Injector V-211i went offline in April 2013 due to low flow rate likely caused by clogged waterflood 5 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT regulating valves. The waterflood regulating valves were changed out in October 2013 (clogged shortly afterwards) and again in June 2014. 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 2200 psi. The lowest pressure in the polygon was observed to be 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. Currently, producer L-204 remains offline due to low reservoir pressure. During the 2014 reporting period, reservoir pressure has climbed to 1299 psi; an increase of 165 psi. In addition, reduced reservoir pressures were observed in injectors L-222i, V-219i, V-220i and V- 224i as these injectors had either been online with clogged waterflood regulating valves or offline for a period of time prior to acquiring the pressure data; offset producer remained online.  Injector L-222i was online for the majority of the reporting period. In October / November 2013, the waterflood regulating valves set across the OA and Obd sands became clogged. Wellwork to change out the waterflood regulating valves is pending. As noted in prior reports, the reservoir pressure initially observed in the OA sand upon completion was ~1200 psi. After extended periods of injection into the OA sand, reservoir pressure in the OA sand has risen to 1384 psi.  Injector V-219i was online for a majority of the reporting period with a clogged waterflood regulating valve in the Nb sand. The waterflood regulating valves were changed out in June 2014.  Injector V-220i went offline in June 2013 to change out the waterflood regulating valves. While conducting the wellwork, the job scope expanded to include fishing operations to recover parted wireline. The waterflood regulating valve change out a nd fishing operations were concluded in November 2013. After placing the well back on injection in December 2013, downhole pressure gauges confirmed several of the waterflood regulating valves were clogged. As additional waterflood regulating valves beca me clogged, the injector was taken offline. Wellwork to change out the waterflood regulating valves is pending.  Injector V-224i went offline in January 2014 to change out the waterflood regulating valves. While conducting the wellwork, one of the waterflood regulating valves was found to be flowcut. Additional diagnostics were performed and the mandrel where the flowcut waterflood regulating valve had been installed was determined to be damaged. A swell dummy valve was installed in the damaged mandrel in January 2014. Subsequent diagnostics indicate the swell dummy valve was not successful in resolving the issues with the damaged mandrel. Injector V-224i remains offline while remediation options are being evaluated. 6 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT Polygon 5S This polygon contains producer L-205 and is supported by injectors L-220i and L-221i. Measured pressures in the polygon range from 2000 psi to 2300 psi. During the reporting period, there was no production or injection due to producer L-205 being offline for sanding issues. 4. R ESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: Production logs were run in producers V-203 and V-207 during the reporting period. Prior production logs have frequently been adversely affected by well sluggin g. Future production logging candidates will be evaluated on a case by case basis. A summary of the interpreted results from the production logs run during the reporting period is shown in Table 3. Well Fluids Sampling: A well fluids sampling program is ongoing to gather high quality and high frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples is later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in s ome wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Well Testing Improvements: In an effort to improve well test quality, Weatherford Generation 2 multi-phase meters (Gen 2) were installed at the L-pad and V-pad test headers. In 2012, the V-pad Gen 2 meter was accepted as the primary metric for production allocations, and the V -pad Well Pad Separator was taken out of service. 7 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT The L-pad Gen 2 meter is being used to allocate the production rates for the majority of the L -pad online wellstock; the L-pad Well Pad Separator is currently still in service. During the reporting period, field tests were conducted at L-pad with the Gen 2 in series with a portable gravity separator system (ASRC Unit 1), which was used as the reference for measurements. Compared to the ASRC Unit 1, the L-pad Gen 2 meter trends higher for formation gas rates in a few L -pad wells, but still within 10% (acceptance criteria) of the ASRC Unit measurement. We are working to better understand and try to improve this tendency. Injection Logs: An injection log was run in injector V-217i during the reporting period. Injection logs are run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. A summary of the interpreted results from the injection logs run during the reporting period is shown in Table 3. 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 an d healing of MBE’s, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. The current Orion injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5. R EVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) Orion production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor is applied to adjust production on a daily basis. A minimum of one well test per month is used to check the performance curves, and to verify system performance, with more frequent testing during new well start-up and after significant wellwork. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND R ESERVOIR MANAGEMENT SUMMARY (RULE 9E) Enhanced Recovery Project - Waterflood: Primary production from the Orion oil pool commenced in 2002 and cont inued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is 8 7/13 – 6/14 ORION 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 11,302 BWIPD. Cumulative injection through June 2014 was 36.7 MMSTBW, which has been injected in 36 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Project - Miscible Injectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began later that year in the updip portion of Polygon 2 . The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 0.3 MMSCFD. Cumulative injection through June 2014 was 16.4 BCF, which has been injected in 22 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 ultimate recovery consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage r eplacement ratio required to keep reservoir pressure above the bubble point. Individual floods are managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude o f probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. No new matrix bypass events have been identified during the reporting period. 9 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT 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. R ESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT B REAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, no new responses to miscible injectant were observed. To date, in the life of the field, response to miscible injectant has been observed in the following producers: L-201, V-202, V-203, V-204, V-205, and V-207. 10 7/13 – 6/14 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-13 261,160.231,935.153,965.305,492.31,269.28,603,670.27,485,133.6,975,681.32,870,144.42,845,257.179,434 3,885,994 0.65 Aug-13 151,661.160,633.101,720.202,671.0.28,755,331 27,645,766 7,077,401 33,072,815 43,049,955 117,136 4,003,129 0.64 Sep-13 209,064.205,648.152,311.290,423.0.28,964,395 27,851,414 7,229,712 33,363,238 43,343,282 153,217 4,156,347 0.66 Oct-13 189,703.135,114.128,220.381,832.0.29,154,098 27,986,528 7,357,932 33,745,070 43,728,932 -15,323 4,141,024 1.04 Nov-13 163,461.116,445.110,234.380,292.0.29,317,559 28,102,973 7,468,166 34,125,362 44,113,027 -65,239 4,075,785 1.20 Dec-13 160,713.97,648.123,506.425,622.0.29,478,272 28,200,621 7,591,672 34,550,984 44,542,905 -107,150 3,968,634 1.33 Jan-14 144,274.96,227.102,366.378,281.0.29,622,546 28,296,848 7,694,038 34,929,265 44,924,969 -97,864 3,870,770 1.34 Feb-14 129,001.83,037.87,627.300,933.0.29,751,547 28,379,885 7,781,665 35,230,198 45,228,911 -54,848 3,815,923 1.22 Mar-14 149,351.98,756.93,916.356,400.0.29,900,898 28,478,641 7,875,581 35,586,598 45,588,875 -78,244 3,737,679 1.28 Apr-14 144,600.89,109.98,147.360,116.0.30,045,498 28,567,750 7,973,728 35,946,714 45,952,593 -86,003 3,651,676 1.31 May-14 169,940.101,492.122,626.387,446.29,940.30,215,438 28,669,242 8,096,354 36,334,160 46,361,578 -76,411 3,575,265 1.23 Jun-14 128,525.78,496.89,368.355,828.51,227.30,343,963 28,747,738 8,185,722 36,689,988 46,751,188 -140,869 3,434,396 1.57 11 7/13 – 6/14 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY FIGURE 2: ORION VOIDAGE HISTORY TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 1/4 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) L-200 50029231910000 O 640135 OBa+OBb+OBd 4267-4147, 4312-4189, 4407-4278 6/30/2014 17512 SBHP 82 4142 1886 4400 0.40 1989 L-202 50029232290000 O 640135 OA+OBa+OBb+OBd 4309-4337, 4341-4363, 4368-4410, 4422-4429, 4437-4479, 4414-4425, 4433-4474, 4510-4609, 4615-4653 8/21/2013 336 SBHP 84 4200 1412 4400 0.03 1418 L-203 50029234160000 O 640135 Nb+OBa+OBc+ OBd 4277-4282, 4277-4284, 4457-4446, 4445-4451, 4542-4544, 4566-4589, 4591-4588, 4608-4664, 4672-4688, 4685-4699, 4632-4668, 4682-4654, 4648-4642 6/30/2014 15128 SBHP 83 4194 1802 4400 0.41 1886 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 6/30/2014 23996 SBHP 82 4204 1213 4400 0.44 1299 L-205 50029233880000 O 640135 OA+OBa+ OBb+OBc+OBd 4188-4183, 4173-4190, 4228-4248, 4237-4239, 4272-4285, 4394-4364, 4328-4350, 4392-4395, 4393-4393, 4385-4406 6/30/2014 16248 SBHP 57 3028 1760 4400 0.41 2323 L-250 50029232810000 O 640135 Nb 4199-4269, 4208-4281 6/30/2014 13950 SBHP 81 4123 1875 4400 0.41 1989 L-211 50029231970000 WAG 640135 OA 4042-4068 2/26/2014 13948 SBHP 80 4148 2098 4400 0.44 2209 L-211 50029231970000 WAG 640135 OBa+OBb 4095-4123, 4141-4154 2/26/2014 13955 SBHP 82 4245 2134 4400 0.44 2202 L-211 50029231970000 WAG 640135 OBd 4240-4248, 4249-4257, 4262-4269, 4275-4282 2/26/2014 13955 SBHP 82 4285 1943 4400 0.44 1994 L-215 50029232740000 WAG 640135 Nb 4233-4251 12/26/2013 216 SBHP 87 4281 1931 4400 0.44 1983 L-215 50029232740000 WAG 640135 OA 4359-4392 12/26/2013 210 SBHP 89 4371 1933 4400 0.44 1946 L-215 50029232740000 WAG 640135 OBa+OBb 4424-4459, 4473-4484 12/26/2013 224 SBHP 90 4478 1859 4400 0.44 1825 L-215 50029232740000 WAG 640135 OBd 4586-4633 12/24/2013 156 SBHP 89 4516 1865 4400 0.44 1814 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: 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 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-217 50029233120000 WI 640135 OBa 4409-4458 8/4/2013 664 SBHP 90 4450 2160 4400 0.44 2138 L-217 50029233120000 WI 640135 OBb 4474-4487 7/31/2013 610 SBHP 88 4498 2451 4400 0.44 2408 L-217 50029233120000 WI 640135 OBc 4530-4554 7/25/2013 460 SBHP 90 4556 2516 4400 0.44 2447 L-217 50029233120000 WI 640135 OBd 4582-4639 8/3/2013 664 SBHP 91 4585 2168 4400 0.44 2087 L-219 50029233760000 WAG 640135 OA 4413-4445 8/27/2013 9153 SBHP 84 4362 1950 4400 0.44 1967 L-219 50029233760000 WAG 640135 OBa 4480-4492 8/27/2013 9153 SBHP N/A 4470 1954 4400 0.44 1923 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, 8/27/2013 9153 SBHP 88 4652 1907 4400 0.44 1796 L-219 50029233760000 WAG 640135 OBd (water)4756-4758 8/27/2013 9153 SBHP N/A 4695 2059 4400 0.44 1929 L-220 50029233870000 WAG 640135 Nb 4116-4136 6/30/2014 32709 SBHP 82 4052 1845 4400 0.44 1998 L-220 50029233870000 WAG 640135 OA 4250-4291 6/30/2014 32709 SBHP 87 4203 1905 4400 0.44 1992 L-220 50029233870000 WAG 640135 OBa 4318-4347 6/30/2014 32709 SBHP 90 4308 2058 4400 0.44 2098 L-220 50029233870000 WAG 640135 OBb+OBc 4360-4377, 4414-4431 6/30/2014 32709 SBHP 91 4362 2041 4400 0.44 2058 L-220 50029233870000 WAG 640135 OBd 4466 -4511 6/30/2014 32709 SBHP 90 4457 2005 4400 0.44 1980 L-221 50029233850000 WAG 640135 Nb 4090-4105 6/30/2014 14424 SBHP 84 4038 1843 4400 0.44 2002 L-221 50029233850000 WAG 640135 OA 4222-4258 6/30/2014 14424 SBHP 87 4176 1893 4400 0.44 1992 L-221 50029233850000 WAG 640135 OBa 4285-4316 6/30/2014 14424 SBHP 90 4276 2029 4400 0.44 2084 L-221 50029233850000 WAG 640135 OBb+OBc 4329-4343, 4382-4401 6/30/2014 14424 SBHP 90 4329 2056 4400 0.44 2087 L-221 50029233850000 WAG 640135 OBd 4433-4481 6/30/2014 14424 SBHP 90 4426 1986 4400 0.44 1975 L-222 50029234200000 WAG 640135 OA 4307-4347 6/30/2014 6263 SBHP 78 4286 1334 4400 0.44 1384 L-222 50029234200000 WAG 640135 OBa 4378-4412 8/16/2013 208 SBHP 90 4370 1788 4400 0.44 1801 L-222 50029234200000 WAG 640135 OBb+OBc 4427-4435, 4466-4482 8/16/2013 208 SBHP 92 4433 1893 4400 0.44 1878 L-222 50029234200000 WAG 640135 OBd 4521-4571 6/30/2014 5694 SBHP 91 4514 1801 4400 0.44 1751 L-223 50029234150000 WAG 640135 Nb 4377-4396 6/30/2014 39792 SBHP 84 4339 1963 4400 0.44 1990 L-223 50029234150000 WAG 640135 OA 4502-4538 6/30/2014 39792 SBHP 88 4477 2006 4400 0.44 1972 L-223 50029234150000 WAG 640135 OBa 4567-4599 6/30/2014 39792 SBHP 90 4560 1973 4400 0.44 1903 L-223 50029234150000 WAG 640135 OBc 4667-4686 6/30/2014 39792 SBHP 92 4642 2032 4400 0.44 1926 L-223 50029234150000 WAG 640135 OBd 4717-476 5 6/30/2014 39792 SBHP 93 4714 2126 4400 0.44 1988 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: 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 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-203 50029232850000 O 650135 OA+OBa+ OBb+OBc+OBd 4249-4274, 4306-4331, 4342-4365, 4397-4426, 4455-4486 3/21/2014 774 SBHP 80 4125 1339 4400 0.38 1443 V-205 50029233380000 O 640135 OA+OBa+OBd 4395-4404, 4393-4435, 4452-4452, 4458-4470, 4498-4505, 4514-4511, 4588-4618, 4620-4617 4/12/2014 1856 SBHP 81 4269 1601 4400 0.41 1655 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 8/15/2013 168 PBU 88 4423 1476 4400 0.41 1467 V-211 50029232320000 WAG 640135 OA 4249-4282 10/16/2013 2428 SBHP 93 4406 1431 4400 0.37 1428 V-215 50029233510000 WAG 640135 OA 4370-4404 6/30/2014 11356 SBHP 80 4347 1967 4400 0.44 1990 V-217 50029233340000 WAG 640135 OBd 4562-4610 4/12/2014 5927 SBHP N/A 4551 1674 4400 0.44 1608 V-219 50029233970000 WAG 640135 Nb 4434-4450 6/30/2014 15084 SBHP 89 4416 1356 4400 0.44 1349 V-219 50029233970000 WAG 640135 OBa 4626-4654 6/30/2014 1204 SBHP 89 4613 1973 4400 0.44 1879 V-219 50029233970000 WAG 640135 OBb 4667-4680 6/30/2014 1204 SBHP 89 4665 2291 4400 0.44 2174 V-219 50029233970000 WAG 640135 OBd+OBe 4769-4810, 4842-4866 6/30/2014 7835 SBHP 92 4752 2058 4400 0.44 1903 V-220 50029233830000 WAG 640135 Nb 4351-4367 6/30/2014 3808 SBHP 88 4328 1535 4400 0.44 1567 V-220 50029233830000 WAG 640135 OA 4486-4525 12/11/2013 4049 SBHP 89 4465 2239 4400 0.44 2210 V-220 50029233830000 WAG 640135 OBa 4554-4583 6/30/2014 8851 SBHP 92 4544 1683 4400 0.44 1620 V-220 50029233830000 WAG 640135 OBb+OBc 4598-4616, 4658-4678 6/30/2014 8851 SBHP 93 4597 1865 4400 0.44 1778 V-220 50029233830000 WAG 640135 OBd 4710-4748 6/30/2014 18495 SBHP 95 4703 1484 4400 0.44 1351 V-220 50029233830000 WAG 640135 OBe 4774-4793 6/30/2014 9965 SBHP 96 4775 1876 4400 0.44 1711 V-222 50029233570000 WAG 640135 OA 4326-4364 5/16/2014 2111 SBHP 84 4248 1229 4400 0.44 1296 V-222 50029233570000 WAG 640135 OBa 4393-4421 6/30/2014 4583 SBHP N/A 4376 1706 4400 0.44 1717 V-222 50029233570000 WAG 640135 OBb+OBc 4433-4450, 4485-4503 6/30/2014 4583 SBHP 96 4433 1758 4400 0.44 1743 V-222 50029233570000 WAG 640135 OBd 4448-4578 6/30/2014 4583 SBHP N/A 4532 1754 4400 0.44 1696 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: 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 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-223 50029233840000 WAG 640135 OA 4419-4458 6/30/2014 28748 SBHP 84 4397 1775 4400 0.44 1776 V-223 50029233840000 WAG 640135 OBa 4485-4513 6/30/2014 28748 SBHP 85 4471 1717 4400 0.44 1686 V-223 50029233840000 WAG 640135 OBb 4528-4545 6/30/2014 28748 SBHP 87 4524 1820 4400 0.44 1765 V-223 50029233840000 WAG 640135 OBd 4632-4674 6/30/2014 28748 SBHP 90 4616 1999 4400 0.44 1904 V-224 50029234000000 WAG 640135 Nb 4466-4485 6/30/2014 4225 SBHP 91 4450 1481 4400 0.44 1459 V-224 50029234000000 WAG 640135 OBa 4674-4704 6/30/2014 11186 SBHP 92 4624 1469 4400 0.44 1370 V-224 50029234000000 WAG 640135 OBb 4718-4736 6/30/2014 6793 SBHP 95 4718 1485 4400 0.44 1345 V-224 50029234000000 WAG 640135 OBd 4832-4881 6/30/2014 4225 SBHP 95 4801 1892 4400 0.44 1716 V-224 50029234000000 WAG 640135 OBe 4903-4928 6/30/2014 4225 SBHP 95 4901 2127 4400 0.44 1907 V-225 50029234190000 WAG 640135 OA 4330-4365 9/11/2013 3721 SBHP 87 4281 1833 4400 0.44 1885 V-225 50029234190000 WAG 640135 OBa 4394-4420 9/11/2013 3721 SBHP 93 4379 2016 4400 0.44 2025 V-225 50029234190000 WAG 640135 OBb 4433-4453 9/11/2013 3721 SBHP 91 4432 2319 4400 0.44 2305 V-225 50029234190000 WAG 640135 OBd 4531-4576 9/11/2013 3721 SBHP 89 4522 2064 4400 0.44 2010 V-227 50029234170000 WI 640135 Nb 4449-4462 6/30/2014 26524 SBHP 88 4403 1946 4400 0.44 1945 V-227 50029234170000 WI 640135 OBa 4634-4662 6/30/2014 26524 SBHP 91 4596 1639 4400 0.44 1553 V-227 50029234170000 WI 640135 OBb 4677-4695 6/30/2014 26524 SBHP 92 4760 1851 4400 0.44 1693 V-227 50029234170000 WI 640135 OBd 4790-4837 6/30/2014 26524 SBHP 94 4673 1909 4400 0.44 1789 V-227 50029234170000 WI 640135 OBe 4854-4876 6/30/2014 26524 SBHP 96 4854 2102 4400 0.44 1902 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: 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 Printed Name Brenden Swensen Date August 12, 2014 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Petroleum Engineer FIGURE 3: ORION AVERAGE PRESSURE AT DATUM FIGURE 4: ORION PRESSURES IN MAP VIEW TABLE 3: PRODUCTION AND INJECTION PROFILES Well Survey Date Survey Type Zones Splits Oil / Water / Gas Service Comments V-203 09/26/2013 PPROF OA 51% / 88% / 0% Producer Oba 29% / 10% / 12% Producer Obb 11% / 0% / 0% Producer Obc/Obd 9% / 2% / 88% Producer V-207 08/29/2013 PPROF Nb 13% / NA / 28% Producer Oba 84% / NA / 70% Producer Obb 3% / NA / 2% Producer Obe 0% / NA / 0% Producer V-217 07/25/2013 IPROF OA NA / 41% / NA Water Injection Oba/Obb NA / 31% / NA Water Injection Obd NA / 28% / NA Water Injection 1 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT 2014 ANNUAL SURVEILLANCE REPORT POLARIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2013 – JUNE 30, 2014 3 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2014 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1. I NTRODUCTION This Annual Surveillance Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 484A, and covers the period from July 1, 2013 to June 30, 2014. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 4,080 BOPD, 3.3 MMSCFD (FGOR 809 SCF/STB), and 4,327 BWPD (WC 51%). Water injection during this period averaged 7,628 BWIPD with 2.4 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.2. 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 R ESERVOIR PRESSURE S URVEYS WITHIN THE P OOL (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 static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates all valid Polaris pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period at the Pool datum of 5000 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. The low mobility of viscous oil 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 experience slow falloff during shut -in due to the low mobility of the system. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build-up (PBU) pressure fall-off (PFO) data is very difficult. In order to mitigate these concerns, single point pressure 4 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT 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 a MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: S-Pad North This polygon contains long term shut-in producer S-200 and low-rate jet pump producer S-201 (offline – jet pump maintenance). This is the only polygon without injection support. Pressure surveys taken over the past few years have shown little change in pressure, which is in line with minimal offtake from the polygon. The most recent pressure measurement was 1942 psi which was taken on 6/19/2014. 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 1800 psi to 2500 psi. W-Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211 and is supported by injectors W-209i, W-212i, W-213i, W-214i, W-215i, W-216i, W-217i, W-218i, W-219i, W-220i, W-221i, and W-223i. Measured pressures in this polygon range from 1700 psi to 2600 psi. In July 2013, two new matrix bypass events from the aquifer to producers W-201 and W-202 were identified. The aforementioned producers and downdip injectors W-220i and W-223i were taken offline for the second half of 2013 while remediation options were being evaluated. All of the wells were brought back online in early 2014. Remediation wellwork is pending for the matrix bypass event in W-202. The impact to production and injection can be seen in Figure 2. 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 2700 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. 5 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Logs: Production logs were run in producers W-200 and W-202 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. A summary of the interpreted results from the production logs run during the reporting period is shown in Table 3. 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 sample s 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 identifyin g 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 development s, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Injection Logs: No injection logs were run during the reporting period. Injection logs are run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors 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. 6 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) Polaris production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC -2 allocation factor is applied to adjust Polaris production on a daily basis. A minimum of one well test per month is used to check the performance curves, and to verify system performance, with more frequent testing during new well start-up and after significant wellwork. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) Enhanced Recovery Project - Waterflood: Primary production from the Polaris oil pool commenced in 1999 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the ori ginal reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves ins talled 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 7,628 BWIPD. Cumulative injection through June 2014 was 19.6 MMSTBW, which has been injected in 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 mis cible injectant began in early 2006 in the downdip portion of W Pad North. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in S Pad South and W Pad North. During the reporting period, average injection rate was 2.4 MMSCFD. Cumulative injection through June 2014 was 3.0 BCF, which has been injected in 10 water-alternating-gas injectors. No new water-alternating-gas injectors have been placed into service during the reporting period. 7 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods will be managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to c hanges in completion designs and operational strategies. In addition, the emerg ence 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 evalu ated 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 Sl ope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or “worm holes”. In July 2013, two new matrix bypass events from producers W-201 and W-202 to the aquifer were identified based on increased total fluid production and increased watercut from well tests. Chemical analysis of produced water samples confirmed the increase in water production was from the aquifer and not from an offset injector; low Boron concentration confirmed this. Both wells were put online 7. RESULTS OF M ONITORING TO DETERMINE E NRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas-oil-ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, no new responses to miscible injectant were observed. To date, in the life of the field, response to miscible injectant has been observed in the following producers: S-213A and W-204. 8 7/13 – 6/14 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-13 151,379.74,846.109,567.313,495.0.15,947,076.14,536,555.4,174,003.17,105,983.18,583,329.-76,260 6,108,741 1.32 Aug-13 53,492.31,295.32,057.134,636.0.16,000,568 14,567,850 4,206,060 17,240,619 18,719,311 -46,091 6,062,650 1.51 Sep-13 116,406.63,675.87,065.283,824.0.16,116,974 14,631,525 4,293,125 17,524,443 19,005,973 -97,198 5,965,452 1.51 Oct-13 123,549.69,611.62,436.210,108.45,375.16,240,523 14,701,136 4,355,561 17,734,551 19,245,407 -27,364 5,938,089 1.13 Nov-13 113,070.87,046.53,075.206,713.126,718.16,353,593 14,788,182 4,408,636 17,941,264 19,530,218 -85,917 5,852,172 1.43 Dec-13 100,400.82,490.128,677.219,463.133,817.16,453,993 14,870,672 4,537,313 18,160,727 19,832,166 -112,144 5,740,028 1.59 Jan-14 125,386.94,693.120,185.245,532.132,539.16,579,379 14,965,365 4,657,498 18,406,259 20,159,677 -100,373 5,639,656 1.44 Feb-14 111,531.111,095.67,055.184,968.109,644.16,690,910 15,076,460 4,724,553 18,591,227 20,412,281 -26,427 5,613,228 1.12 Mar-14 135,917.137,674.147,474.267,763.122,826.16,826,827 15,214,134 4,872,027 18,858,990 20,756,417 -63,561 5,549,667 1.23 Apr-14 154,531.175,744.264,108.208,377.82,280.16,981,358 15,389,878 5,136,135 19,067,367 21,016,246 60,749 5,610,417 0.81 May-14 157,312.134,418.266,084.238,424.98,384.17,138,670 15,524,296 5,402,219 19,305,791 21,316,085 4,254 5,614,671 0.99 Jun-14 146,051.142,482.241,446.270,758.16,076.17,284,721 15,666,778 5,643,665 19,576,549 21,599,196 5,723 5,620,394 0.98 9 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 0 2,500,000 5,000,000 7,500,000 10,000,000 12,500,000 15,000,000 17,500,000 20,000,000 22,500,000 25,000,000 Jan-99Jan-00Jan-01Jan-02Jan-03Jan-04Jan-05Jan-06Jan-07Jan-08Jan-09Jan-10Jan-11Jan-12Jan-13Jan-14VRR (RVB/RVB)Oil Prod (STB) & Water Inj / Total Inj / Net Voidage (RSVB)Oil Prod Cum Water Inj Cum Total Inj Cum (Water+MI) Net Voidage Cum Monthly VRR Lifetime Cum VRR 10 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 1/2 6. Oil Gravity: 15-23 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. B.H. Temp. 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) S-201 50029229870000 O 64160 OA+OBa+OBb+ OBd 4984-5067, 5163-5170 6/19/2014 14160 SBHP 88 4425 1752 5000 0.33 1942 S-215 50029231070000 WAG 64160 OBa 5032-5059 6/30/2014 2064 SBHP N/A 5022 1837 5000 0.44 1827 S-215 50029231070000 WAG 64160 OBb+OBc 5068-5085, 5119-5133 6/30/2014 2064 SBHP 93 5067 2217 5000 0.44 2187 S-215 50029231070000 WAG 64160 OBd 5169-5196 6/30/2014 2064 SBHP N/A 5151 1896 5000 0.44 1830 S-217 50029233620000 PWI 64160 OA 4960-4989 6/30/2014 15010 SBHP 92 4921 2091 5000 0.44 2126 S-217 50029233620000 PWI 64160 OBa 5007-5023 6/30/2014 15010 SBHP N/A 5001 1886 5000 0.44 1886 S-218 50029234140000 WAG 64160 OBa 5050-5067 6/29/2014 2278 SBHP 87 5041 2134 5000 0.44 2116 S-218 50029234140000 WAG 64160 OBb+OBc 5086-5105, 5140-5151 6/29/2014 2278 SBHP 88 5086 2154 5000 0.44 2116 S-218 50029234140000 WAG 64160 OBd 5185-5225 6/29/2014 2278 SBHP 93 5183 2266 5000 0.44 2185 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 3/26/2014 1858 SBHP 93 4917 2167 5000 0.44 2204 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 8/25/2013 455 SBHP 89 4840 1583 5000 0.44 1654 W-205 50029231650000 O 64160 OBa+OBc+OBd 4973-4982, 4984-5015, 5044-5051, 5052-5092, 5109-5159 8/27/2013 507 SBHP 94 4875 1920 5000 0.44 1975 W-210 50029233390000 WAG 64160 Nb 4697-4702 6/30/2014 62567 SBHP 84 4671 2153 5000 0.44 2298 W-210 50029233390000 WAG 64160 OBa+OBb 4893-4928 3/2/2014 365 PFO N/A 4884 2419 5000 0.44 2470 W-210 50029233390000 WAG 64160 OBc 4971-4997 3/2/2014 365 PFO 87 4959 2444 5000 0.44 2462 W-210 50029233390000 WAG 64160 OBd 5025-5063 3/2/2014 365 PFO N/A 5010 2553 5000 0.44 2549 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 11 7/13 – 6/14 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 Nb 4693-4704 6/30/2014 60864 SBHP 98 4672 2112 5000 0.44 2256 W-213 50029233540000 WAG 64160 OBa 4871-4894 8/25/2013 454 SBHP N/A 4799 2275 5000 0.44 2363 W-218 50029234030000 WAG 64160 OBa 4948-4970 10/24/2013 673 SBHP 90 4929 2241 5000 0.44 2272 W-218 50029234030000 WAG 64160 OBc 5032-5055 10/24/2013 673 SBHP 90 5006 2277 5000 0.44 2274 W-218 50029234030000 WAG 64160 OBd 5087-5127 10/24/2013 673 SBHP 89 5092 2293 5000 0.44 2253 W-220 50029234320000 WI 64160 OBc 5228-5251 3/13/2014 4186 SBHP 80 5199 2376 5000 0.44 2288 W-220 50029234320000 WI 64160 OBd 5278-5311 12/22/2013 2233 SBHP 87 5280 2498 5000 0.44 2375 W-223 50029234400000 WAG 64160 OBa 5035-5059 12/22/2013 2231 SBHP 92 4999 2192 5000 0.44 2192 W-223 50029234400000 WAG 64160 OBc 5112-5143 12/22/2013 2231 SBHP 90 5090 2256 5000 0.44 2216 W-223 50029234400000 WAG 64160 OBd 5169-5208 12/22/2013 2231 SBHP 89 5169 2429 5000 0.44 2355 Printed Name Eric Zoesch Date August 11, 2014 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title Petroleum Engineer 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference:7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Field, Polaris Oil Pool 5000 TVDss 0.7 BP Exploration (Alaska) Inc.P.O. Box 196612, 900 E. Benson Blvd., Anchorage, AK 99519-6612 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: 12 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 14 7/13 – 6/14 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: PRODUCTION AND INJECTION PROFILES Well Survey Date Survey Type Zones Splits Oil / Water / Gas Service Comments W-200 09/24/2013 PPROF Oba 8% / 86% / 29% Producer Obd 45% / 4% / 25% Producer Obf 47% / 10% / 46% Producer W-202 09/02/2013 PPROF Oba 100% / 96% / 46% Producer MBE Diagnostics Obc 0% / 0% / 0% Producer MBE Diagnostics Obd 0% / 4% / 54% Producer MBE Diagnostics