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Home My WebLink About2013 Prudhoe Satellite Oil PoolsSeptember 16, 2013 HAND DELIVERED Ms. Kathy Forester, Chair Alaska Oil and Gas Conservation Commission 333 West 7h Ave, Suite 100 Anchorage, AK 99501 Re: Prudhoe Bay Unit Satellites 2012/13 Annual Surveillance Reports Dear Chair Forester: BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 BP Exploration (Alaska) Inc. (BPXA), as operator of the Prudhoe Bay Unit, submits herewith the 2012/13 Annual Surveillance Reports for all Prudhoe Satellite Oil Pools (Aurora, Borealis, Midnight Sun, Orion, and Polaris). These Annual Surveillance Reports were prepared in accordance with the latest conservation orders for each satellite pool. We look forward to a further discussion and review of the data contained herein at the Prudhoe Bay Unit Satellite Annual Overview Presentation that we have scheduled for September 25, 2013 at 2:00 pm at the BP Building 1St Floor Conference Room A. Please call Werner Schinagl at 564-5436 or Travis Peltier at 564-4511 if you have any questions regarding the reports or the upcoming presentation. Respectfully, FoG Katrina Garner Manager Base Management, BPXA cc: Mr. Jon Schultz, ConocoPhillips Alaska, Inc. Mr. Jan Seglem, ExxonMobil Mr. Phil Ayer, Chevron USA Ms. Patricia Bettis, Division of Oil and Gas Mr. Dave Roby, Alaska Oil and Gas Conservation Commission Ms. Susan Kent, BPXA Ms. Judy Buono, BPXA 2013 ANNUAL SURVEILLANCE REPORT AURORA PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2012 -JUNE 30, 2013 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT CONTENTS 1 . INTRODUCTION.................................................................................................3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A)....................................................................3 2.1. ENHANCED RECOVERY PROJECTS............................................................3 2.2. RESERVOIR MANAGEMENT STRATEGY......................................................4 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B)..4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C)........5 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) ............................5 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) .....................................5 7. REVIEW 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 2 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2013 AURORA OIL POOL ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report for the year ending June 30, 2013 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 ENHANCED RECOVERY PROJECT IMPLEMENTATION 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 ACP where injection is justified, water -flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Water injection should maintain average reservoir pressure above 2400 psi in the flood area to ensure hydrocarbon recovery targets are achieved. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility between the reservoir fluid and the injected miscible gas. There will be higher pressure in the area around injection wells and a pressure sink around the producers, which in some cases can be below minimum miscibility pressure (MMP) of approximately 2700 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on average reservoir 3 7112 —6/13 AURORA ANNUAL SURVEILLANCE REPORT 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-1 13B 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-1 13B indicates the well is supported by a large gas -cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Irregular pattern waterfloods have been designed to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns are based on the current understanding of compartmentalization; however, reservoir management is a dynamic process. Patterns and producer/injector ratios will be modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring and waterflood performance monitoring to support this feedback and intervention process. Fi ure 1 shows Aurora well locations and the field development areas. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) Monthly production and injection surface volumes are summarized in Table 1. Voidage replacement by fault block is summarized in Table 2 and Figure 2. Figure 3 summarizes the voidage history of Aurora field. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed and started in late 2006 to provide increased injection rates to low injectivity patterns. The largest VRR challenge for this reporting year came from down time of the Sulzer and Ruston injection pumps at GC -2. Injection volumes were limited because of the pump failures. 4 7/12 — 6/13 AURORA ANNUAL SURVEILLANCE REPORT 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457B. A summary of reservoir pressure surveys is shown in Table 3. The field average reservoir pressure map is shown in Figure 4. Static BH pressures were gathered in 7 wells during the reporting period. Most producers in the ACP have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING RULE 8 D S-128 had an injection profile run in May of 2012. The log indicated all injection going to the first two heel sleeves. 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). 5 7/12 — 6/13 AURORA ANNUAL SURVEILLANCE REPORT 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 Qast vear The injection management strategy at Aurora will continue to target voidage replacement ratio of 1.2 through WAG injection to maintain reservoir pressure and capture EOR benefits. An attempt was made to establish injection into the recently drilled injector, Well S-1 10A. The decision was made to abandon the S -110A and progress a new sidetrack to support the S-109 producer. A successful frac was performed on the S-102 producer following the previously done RWO, the well was then returned to service as a producer. Pre -rig work began on Well S-101 i, in June 2013, in preparation for the upcoming RWO to repair the S-101 and return it to service as a WAG injector. Pre -rig work began on Well S-108, in June 2013, in preparation for the upcoming RWO to repair the S-108 and return it to service as a producer. BrightwaterTM treatment was pumped in S-104, in October 2012, to improve pattern conformance. S-118 was taken off the LTSi list and reclassified as a cycle well S-128 started water injection, in October 2012, following an injector conversion the previous year. Two seismic reprocessing projects for the TRIO seismic survey were progressed. One project was to investigate the potential for improved structural imaging and a second project was to attempt enhanced seismic inversion. Both projects are nearing completion as of the report date. The Aurora owners will continue to evaluate optimal well count, well utility and well locations to maximize recovery. 6 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT 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 7/31/2012 2379 4976 7608 1.038 529 13242 8/31/2012 7461 12927 24085 0.699 114 26843 9/30/2012 6021 9271 16097 0.674 2768 16610 10/31/2012 6307 11557 18780 0.888 7402 23795 11/30/2012 5904 9956 17212 0.885 9290 19702 12/31/2012 6485 13590 19363 0.781 13820 18553 1/31/2013 7031 12520 19626 0.802 15884 17678 2/28/2013 6630 12546 22074 0.827 19137 17977 3/31/2013 6104 12887 18294 0.954 19569 19231 4/30/2013 5737 12061 17580 0.941 19209 17432 5/31/2013 6042 11127 18204 0.680 9356 15222 6/30/2013 4852 6657 9317 1.140 8456 15423 TABLE 2: CUMULATIVE VOIDAGE STATUS BY FAULT BLOCK On 6/30/2013 AUR -CR* AUR-NOC** AUR -SEC* AUR -WEST* Total Inj Cum 0.843 rb / mcf gas Bw 1.020 MRVB 14,125 32,134 7,365 58,454 Total Prod Cum rb / mcf gas MI MRVB 26,204 38,756 10,897 83,110 Cum INV ratio 0.54 0.83 0.68 0.70 Bo 1.32 rb / stb oil * Initial gas -cap * Solution gas only Bg 0.843 rb / mcf gas Bw 1.020 rb / stb water Rs 0.650 mscf / stb oil Bmi 0.620 rb / mcf gas MI 7 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT TABLE 3: AURORA PRESSURE SURVEY DETAIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT I. Oparat- 2. Add-: OP! wqn N IrK. P.O 5-196612. V*C 6knw.awd NC 39519-8612 S Unit w Lean Name: L Field and Pool; 5 Datum Rderrncr. 6- Oil Gravity: 7 0a:0-ity: vrwwe Univ pr.ai.o-.E F :A-. Gl Pae! 6700TVDar 0 IWVJ25 AA1 0.72 6 wan-wrd 9API Numb« 9]. Type 11. AOGCL Id Zane 13.P"NVAd N-f6T- S-sm}. %Pass ICSH b.`"p 19.il-1 m. Dana 2Lvenror 2L Pr>-yye et Namb. ..Sar P"Codr Yatnr4 Top- D-Teme,H-, Sun,Type Tamp. T..ITVDSS Ob-md TVDSS[input) OradierK. P. Oatum(calJ NO DASHES In~.i- 5o«om TVDSS lwr Precwrew legnaeePa Teal Depth 649437-6507.08 652455-6537.76 867MI-872140 S-03 500292069500 O 640120 8625.42-686643 07!3912 34 SSHP M 6600 2748 .7.1 042 MNI 672&24-6762 20 6771.03-677888 6777.46-6763.00 676185-6735 69 6733.02-673160 6723 70 6724 55 6724 97-6731.14 6733,43.6741.26 S-100 500292296200 0 640120 674t64674623 07120f72 28 SEW 0-W 6700 3231 67y11 046 3234 6636.08-6726,63 I 6726.03.6735.23 S-101 50029M63001 WAO 640120 671600-6687,72 OM7113 4304 SaW 142 6700 3186 6700 046 3166 66615-"8757 6687.57-6690.45 6607.57-6633.31 663045-663351 6693.345696.13 6537.81-670309 S -W2 500292297260 Ol 640120 6633.92-668510 1 6685.10-6723.26 ONW13 3 SSHP 124 6nol 0.at 2135 6604.76-6517.15 6617.15-6517.50 6629.01.6635.98 664245-6650.19 6657 91-66U 33 6670.73-5675 85 S-109 50029229000 0 610120 674&30.6753.63 6763.83-677L02 ourn13 53 SEHP 199 6125 Mm 9701 045 2515 7838-7901 7 a040 8050-8170 63'-640o 6430.8540 8650-6780 0920-6150 9406 S•W9 500292313500 0 640120 IU28 0712912 665 S511P M. 6706 ml 6700 ❑40 2$79 672525-6735 02 6747.41-6752 28 b7510 6 -676t81 6763.27-6783.25 5-129 500292343300 O 640t2o 678250-6740 05 673726-672657 owwt3 6 1 SSHP 137 6750- 24115 6700 037 2466 23 A8 ten: rrpwtod harem wwo made in accordance with the applieabW rule:, rrgubtion: arM in^.eruetiore d thr Alaska Cil 0-M G- Cancerratlo, C...6 Van I hereby eert6y that the Foregoing ie aue 0-M correct to the best d my krawlodge Signature Cameron Sh:pherd Title PETROLEUM ENGINEER Pd -d Name Camaro. Shrpherd Dote August 17th, 2013 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 1: Aurora well location map .....---.-- S-111T S-119 S-102LI ................... j g: S -107-T 2 110-121T != S -122T f 8-11 i 107H S'422H I 8-.s�11A S -tai • S t 1H / S.-03 /« • S-1007 s_♦a4 "t _.. � S•11 5-113 &031KupY 8-108 3-110 • S-113AS 101T ��331 lKuPi • 5-11 A 5.16 5-1138 S-120` $-112T ■._-»„ 1ati4� 7 8-118 ] A26 S•126H 5.134 • 8.20-123 r j S•1 t&T S-1 �►'1 _1 S9 --�KupY !!!°''�------- --------- S-1 S. T k*pckw •PMducer . Ab.ftned s 7/12 — 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 2: Cumulative Voidage Replacement by Region 10 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT AURORA Cumulative VRR by Region 1.Dd 0.90 - Norfi of Crest Cum VRR West of Crest Cum VRR 0,80 —AU BORA Fieldwide Cum VRR ^' 0.70 —S East of Crest Cum VRR }, cr ?tr �xrsx rS�� rrsx•xx�- —Crest Cum VRR 0.60 o� 0.50 x 0.40 E 2 0.30 0.20 0.10 1" 0.00 Y w w w w 10 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 3: Aurora Voidaae Histo 11 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT AURORA Voidage History 70000 -- - 250 60000 4 } 2.00 50000 + E E v40000 i #� 1.60 w ` > 0 30000 h + ` O + 1.00 a 20000 0 r ;+ 1 A" 1", 1 +5y 0.60 10000 + 0 1 0 0.00 - 00 00 ON O 00V O 000 O o 0o O O O o N N N N N N N N N N N N N N > > > > > > > > > > > > > > —total injection rate —total production rate ----VRR rate —VRR cum J 11 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 4: Aurora Reservoir Pressure Map — July 2013 i i t S-1tiT &118 • S•102LI •--•------ 5-106 5-10TT 5 1111.1VT 1 • 36 3-1 22T IU i 107M t22H 5 11A S-103'0 5.1 IN A 3 5-100T A+�Ivlj ps1Q4 3 100FI nsa • 5 �OS i 3-1t3 S-034%) g•1pd 5-110 ' 5-113A S 1Q1T 1 rup] • S- 10A $" M3 S-120 1mss-11s4 5412T 0 3-1!2 s- � 10*117 S -11s S•126 • 11 134 • *_2&S-123 ■ 5-126 S•115T S -12M' % *0 F[up) S-1 S• T ._ 2W 12 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 5: Aurora allocated production histo 13 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT AURORA Allocated Production History 20,000 60000 —oil production rate 18,000 —water production rate —gas production rate 50000 16,000 A w 14.000 v 12.004 = 10,000 30000 r- 0 0 +, IL 8,000 +; o 20000 a� � 6,000 0 4,000 10000 2,000 0 Ir _0 8v O O O O C O I O QO > > > > > > > > > > > > > > 13 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT Figure 6: Aurora allocated injection history 14 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT AURORA Allocated Injection History 60.000 - • - -water ntecbm rate —Gas inlecbm Rate 60.000 w `o 40.000 M 30.000 ro 99 V 20.000 ' C i 10.000 0 A JF � -i J� 14 7/12 - 6/13 AURORA ANNUAL SURVEILLANCE REPORT 2013 ANNUAL SURVEILLANCE REPORT BOREALIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2012 -JUNE 30, 2013 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT TABLE OF CONTENTS 1 . INTRODUCTION.......................................................................................................................... 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY(RULE 9A) ................................................................................................................. 3 2.1.ENHANCED RECOVERY PROJECTS...........................................................................................3 2.2.RESERVOIR MANAGEMENT SUMMARY.................................................................................:._ 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) ......................... 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) ............................... 4 5 RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) . ......... ................ -- .......... ............ 4 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) ............... 5 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G)........ 5 LIST OF ATTACHMENTS Figure 1: Borealis well location map.............................................................................:....,........:..10 Figure 2: Borealis allocated production history...............................................................................11 Figure 3: Borealis voidage history ............................ ................,.,.....,...................................12 Figure 4: Borealis injection history ......................................... ....................13 Figure 5: Borealis reservoir pressure map.......,......................,,..................,,.........,.....,,.......................14 Table 1: Borealis monthly production, injection, voidage balance summary............................::......7 Table 2: Borealis cumulative production & injection summary ...................................,........................8 Table 3: Borealis pressure surveys...............................................................................................,...9 2 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2013 BOREALIS OIL POOL ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report for the year ending June 30, 2013 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 other information as required by Rule 9 of Conservation Order 471. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) 2.1. ENHANCED RECOVERY PROJECTS Waterflood has been implemented in Borealis, which includes 20 injectors in full service. Enhanced Recovery Projects using Miscible Injectant (MI) are implemented in Borealis. Currently 18 of the 20 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, 2002 to restore reservoir pressure and reduce gas -oil -ratios (GORs), thereby enabling wells to be produced at their full capacity. An irregular pattern waterflood has been designed and implemented to ensure pressure is maintained in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and GORs stabilized near solution GOR. When water injection was initiated, a VRR target of greater than 1.0 was set in order to catch up with voidage. The current VRR target is 1.0. 3 7/12 —6/13 BOREALIS ANNUAL SURVEILLANCE REPORT 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 2012 to June 2013 are summarized in Table 1, and cumulative volumes can be found in Table 2. Ficrures 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, Ruston, and booster injection pumps at GC -2. Injection volumes were limited because of the pump failures. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 471. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. Figure 5 is a map of reservoir pressures collected over the last reporting period. Five of the newer producers and one injector have been completed with permanent bottomhole gauges, giving valuable information about the flowing conditions, reservoir pressures, and reservoir connectivity on a continuous basis. Static BH pressures were gathered in 10 wells during the 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, one production log was performed on well V-115. The data quality was poor, and the resulting production splits were questionable. Options continue to be evaluated to utilize enhanced production logging techniques in horizontal wells. 4 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION RULE 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, multi -phase meters were installed in the test header lines at L -pad and V -Pad. During past reporting periods, tests were conducted to establish repeatability, accuracy and viability of the multiphase system. In the fall of 2012, the V pad multiphase meter was commissioned for permanent use. Troubleshooting of the L pad multiphase metering system is ongoing. Borealis allocation continues to use the established Western Satellite Production Metering Plan. 7. OPERATIONS. DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G Miscible gas injection and water -alternating with miscible gas injection is used to increase the economic recovery of Borealis Reservoir hydrocarbons. Injection wells are completed for Enhanced Oil Recovery services. Waterflood and tertiary EOR have been implemented to provide pressure support and reduce residual oil saturations on all three Borealis Pads, L, V and Z. 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 allow even pattern support throughout the waterflood providing optimum waterflood spacing, configuration, timing and operations. The Borealis waterflood management strategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize oil recovery As EOR patterns mature and watercuts increase, improving areal sweep and vertical conformance by pumping Brightwater treatments into the reservoir has been identified as a potential opportunity for improving recovery. During the reporting period one BrightwaterTM treatment was pumped in L -108i. The analysis of the potential results and benefits continue to be an ongoing process. The analysis of this and Brightwater treatments from past reporting periods will be used to determine feasibility of a larger campaign in the Borealis field. The Z -Pad expansion project was completed in 2011. The expansion facilitates the further development of Borealis. During the reporting period one additional producer Z-115 was placed in service. The Borealis owners will continue to evaluate the optimal 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 5 7/12 — 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from Ml. H. 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT TABLE 1: BOREALIS MONTHLY PRODUCTION, INJECTION, VOIDAGE BALANCE SUMMARY Case 1 Date Oil Prod Rate STB/DAY 8025 Water Prod Rate STB/DAY 19546 Gas Prod Rate MSCF/DAY VRR Rate RVB/RVB VRR Cum RVB/RVB Gas Inj Rate MSCF/DAY Water Inj Rate STB/DAY 28807 7/31/2012 19034 0.982 0.857 24445 8/31/2012 10885 25686 27260 0.679 0.856 15171 32087 9/30/2012 9361 19950 19208 0.658 0.854 11638 23203 10/31/2012 11562 23758 26562 0.723 0.853 22806 28659 11/30/2012 10893 21297 30245 0.661 0.851 19403 27468 12/31/2012 10465 26152 25206 0.639 0.850 17520 27042 1/31/2013 10574 25069 32205 0.607 0.847 25182 24115 2/28/2013 12698 23442 38170 0.587 0.845 16079 31733 3/31/2013 10338 24274 34335 0.617 0.843 12076 33375 4/30/2013 10812 21926 30689 0.539 0.840 15294 23260 5/31/2013 10113 20776 26360 0.819 0.840 19404 32798 6/30/2013 7471 21973 13763 1.066 0.841 19625 32052 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT TABLE 2: BOREALIS CUMULATIVE PRODUCTION & INJECTION SUMMARY MONTH_ENDING 06-30-2013 Data 63,784 units Oil Prod Cum 70,976 MSTB Gas Prod Cum 92,758 MMSCF Water Prod Cum 77,371 MSTB Gas Inj Cum 63,784 MMSCF Water Inj Cum 148,517 MSTB Total Inj Cum 192,519 MRVB Total Prod Cum 228,809 MRVB VRR Cum 0.841 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 7/12 — 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT TABLE 3: BOREALIS PRESSURE SURVEYS :i 1 A I L OI ALASKA ALASKA OIL AND GAS CONSE=RVATION COMMISSION RESERVOIR PRESSURE REPORT . uPweot= 1. naarorc: ❑P •�+ .a W iw P.O. D•sx 106618. 000 C. Pen.., DWJ.. Apx Uyr •. AK 00910-6412 S. Vml or Lbara rPamb: �. bald Intl Ypo1: !u Natum L2btarbnco: b, Vll Vrawty: f. Vac L:nyky: rn aLel8tb uls. rreIL- R. .Be cJi, 04 Peal 6600TVDaa 0.880 J *s- API 0.73 0 Wdl O, Nr M.Lra 10.oil (0) 11. AOGOO 1p..Z a 10. 14. fm,l 15.316c1 -111r 10. Prow. 17, DJL 10. D0TO. Tna1}i�arrr+,l 20.Dawle 22. F.-,- 2E, Mmn anA en-',: xx•x•A rx•,:- r,.r olr.] PnrJ f.nAr PrrMrnrr rl M-Prrwwu.l Tra n TI., Ilnnrt .Eller Tyres• Temrl TnnlTWnr. Tnnl flnrrb TVnx r.•-AnMar p"oer n. -(-I) N�Mr+- x x -x n Inrnrval2 (er (Inrrrir] I ep - mrlracbenc eoeeen ter eeeca I TYDCB L 134 50 038 93955 00 O 640130 6354 6404, 6M370013 8780 nou 147 6961 3358 6600 0 33 9486 6400 6381, 4304-Gdo4 V-121 5h•AF.-F. n7LPn n 4dntnn A.M•n.4P. T71drPni1 ISPs 3n11P 1'n nnnn :Inpn nnM n!e :lf p.'r Ay} -Ml V-111 -u-2'Slbl-VV V b4U1'SU b>biL-bbic2, 1Vf ul. b>UV 1Y14 bbUV U.45 %Ybb b>�Jf•b>`J 3, 6585 6556, 4950-0500, 4940-6076. weM1.laLzvs, as>s•eeoa, bbU"2-bbU f, 6607 6617 V -1D >V-V1Y-1'>lYy-W V ba Vl'SU bb'32-bbJn 'JJILLJ1U11 X11 ybm" 11. bbUV 2A.b bb11V U.I. 143Y 66:7 6635, 6025-O4aa. 4031.OG04. AA.1S-ANM1, eb>T-DlSS, bb'31•bb-1 f, Obur "U5, 66:5 6585, 101 SO 038 3 3873 00 O 640130 650 8 6638, 67V3013 87416 CBHr, 153 6600 3854 6600 0.43 0854 6711 6727 2-102 90.020-20090-00 WAG 440100 4007-6529. 2n1r2010 012 3DIIP 120 6500 8280 0000 05 0200 A---.-. AS H•A51.}• bl TS•b>U f, b>VS b>VT C-wS SO one 03-+35 Cb wnu b4u1'Su 6604 6646 fOJ3J9D10 1370 BBHr 133 6600 0703 6600 0.41 ±700 i -T0 50.020.20490-00 O 440100 4505.0577. 4251, 451d, PSS} M1Y.1 4f20fE010 744 PDU 142 0201 EOA 0000 042 2700 e -TT> y1t-V4*-mbv-w V 64V1'SV 64 tl4-0>Sif 'Sl JtSJYVI'3 WFU ✓eLV T$f .1- 1'S bV bbW V,S* 3 uu 2 i16 50 038 03455 00 WI 640100 6733 6717, 1/3010013 1114 SBHrl 145 1,600 3873 6600 0.44 9373 0714-6710 0744-4746. ATan-4TIp. M1TO.-M1T 1.1, U3, All Luta rrperted M.rem ware mode In •eep d -L mltb tb<ppl... bls mlea, -c Wliena Pntl motto-tlena et the Aloalra V4 -4 Uoa Uen.<rveben UpmmVarpn. I Irel v4y 1 Pl tiry 0-Llle f �ro V 1A..W i> L.- ..,J -.-1 w Ill. I,- �f �i iy l,lruwlodl .[10 n>rnrr .Inl rrn ncblm Tlrtr Pnrrnlrllm Pn7lnery Nia.d Haug Jlrlcmr O.Li- Date U-A.W-2010 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT FIGURE 1: BOREALIS WELL LOCATION MAP v OT .STl�7 y t�fb/ir�� 474 • t LTG .M 41. 477 L -M4 e IA- 0 L406 L tU L-102 LTI L.79f • wtes ""� L400 • V.7� VAINAT 41M `r w104 toWr v1H • 4�• Y -A V•,Y211 toa ,4t � v.tr,r •; V -101v • ______ '�' • AK,DB 4V.71711• V. w109-77eL2 Li -} • � J SRT V-11 .tt6 v nr4yF� tLt �ts - •-•-"•W vnrH V•7�Z•107 Y•77YT � j • %jig 1JT ._—_......•_� 1100 _ 7 i 2.1WN r I• PN i x. Z-l0e toe i - ,-------- ♦ lri__ • Producer Abandoned 10 7/12 — 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT FIGURE 2: BOREALIS ALLOCATED PRODUCTION PROFILE 45,000 40,006 W 35.000 m m 30,000 C 25,000 v a ` 20,000 IL 15,000 10,000 O 5.000 0 0 BOREALIS Allocated Production History 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT 50000 45000 40000 35000 300000 25000 c v 20000 a 0 15000 IZ 10000 O 5000 0 11 FIGURE 3: BOREALIS - TOTAL PRODUCTION / INJECTION RATES (RVB/D), VRR RATE, AND CUMULATIVE VRR 12 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT BOREALIS Voidage History 90wo 80000 70004 ; :+ ; 1 + I, 1 + 1 !! I + 0. 114 64041E 1.00 E $ 50000 m 1 + , i � V L+loil ��_+ • ' jr it �� O 40000 I c b 30000 � , ; ' a 030 O + Is. 20000 H 10000 0 0.00 N w w� w total injection rate total production rate ----VRR rate VRR cum 12 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT FIGURE 4: BOREALIS TOTAL INJECTION RATES -GAS & WATER 13 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT BOREALIS Injection History 70,000 . 65,000 —water injection rate —Gas Injection Rate „ 60,000 w 55,000 50,000 0 .a 45,000 40,000 35,000 = 30,000 0 25,000 d 20,000 15,0€]0 10,000 5,000 0 13 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT FIGURES: BOREALIS RESERVOIR PRESSURE MAP n 14 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT 1' i L t�iTG1 14 7/12 - 6/13 BOREALIS ANNUAL SURVEILLANCE REPORT 2013 ANNUAL SURVEILLANCE REPORT MIDNIGHT SUN PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2012 -JUNE 30, 2013 7/12 - 6/13 MNS ANNUAL SURVEILLANCE REPORT 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 2 7/12 - 6/13 MNS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2013 MIDNIGHT SUN ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report for the period from July 1, 2012 through June 30, 2013 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, 2013 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 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 .1.08. Midnight Sun gas production has remained level during the report period as reservoir pressure has leveled off. Both oil and water production rates have remained fairly constant during the report period. Well E-101 currently produces at 89.2% watercut, and Well E-102 produces at —93.5% 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. Midnight Sun is expected to have an oil production rate of approximately 1.2 MBOPD through 2013. 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 during 2003. Monthly production and injection 3 7/12 — 6/13 MNS ANNUAL SURVEILLANCE REPORT 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. 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, <50 psi change. 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, and are currently on an every two week sample schedule. Starting in March 2012, tracer from injector E-104 began showing up in samples from producer E-102, but the validity of these results was questioned. Samples from E-101 and E-102 since March 2012 underwent testing to determine the extent of the tracer breakthrough from E-104. No more tracer breakthrough was observed through the duration of the study, which concluded in October 2012 with no significant results. The tracer was long overdue for a reservoir with the size and production/injection rates of Midnight Sun. A pressure fall-off test is being planned for injector E-104 to gain information that may help explain the reason why this injector has such 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 II 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. 4 7/12 — 6/13 MNS ANNUAL SURVEILLANCE REPORT 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. At this time, no further development drilling is planned for the Midnight Sun Oil Pool. 5 7/12 — 6/13 MNS ANNUAL SURVEILLANCE REPORT TABLE 1: MIDNIGHT SUN MONTHLY PRODUCTION, INJECTION, VOIDAGE BALANCE SUMMARY 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 Voida a (rb) 7/12 19.274 254.837 96,109 78.708 452,104 19,313,547 61,195.153 55.226,967 -166,685 8/12 0 0 0 - 453,065 19,313,547 61.195,153 55,219,339 -471,188 9/12 18,053 186.258 89,963 60.258 439,365 19,331,600 61,285,116 55,249.044 -226,323 10/12 37,351 467.687 182,721 126.428 454,956 19,368,951 61,467,837 55,305.337 83,223 11/12 33.295 403.024 110,205 148,380 441,195 19,402,246 61,578,042 55,334,341 16,359 12/12 28.381 397.470 151.730 164,354 456,847 19,430,627 61.729.772 55,266,157 -28,271 1/13 35,243 463,704 132.298 166,336 457,808 19.465.870 61,862,070 55,251,584 46.927 2/13 32.037 418,060 48.665 167,643 414.330 19,497,907 61,910,735 55,214.793 40,994 3/13 36.652 466,262 194,019 116,872 459,637 19,534.559 62,104,754 55,178,669 99,614 4/13 35,250 440,437 196.997 114,504 445,725 19.569.809 62,301,751 55.261.162 83,914 5/13 33.258 406,970 121,320 115,644 461,528 19,603.067 62,423,071 55.267.614 -15,220 6/13 41.896 418.361 272,913 116.391 447,555 19,644.963 62,695,984 55,423.360 123,406 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 7/12 - 6/13 MNS ANNUAL SURVEILLANCE REPORT TABLE 2: RESERVOIR PRESSURE SURVEYS 7/12 — 6/13 MNS ANNUAL SURVEILLANCE REPORT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: BP Exploration (Alaska) Inc. P.O. Box 196612, 900 E Benson Blvd., Anchorage, AK 99519-6612 3. Unit or Lease Name: 4. Feld and Pool: 5. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Feld Mdni ht Sun 8050' TVDss 25-29 0.72 8. Well Name and 9. API Number 10. Type 11. AOGCC 12. Zone 13. Perforated 14. Final Test 15. Shut -In 16. Press. 17. B.H. 18. Depth 19. Final 20. Datum 21. Pressure 22. Pressure at Number: 50>0(XXXXXXXXXX See Pool Code Intervals Date Time, Hours Surv. Type Temp. Tool T/DSS Observed NDSS (input) Gradient, psi/ft. Datum (cal) NO DASHES Instructions Top - Bottom (see Pressure at NDSS instructions Tool Depth for codes). E-101 5002922909 O MOP KUP 8080-8098, 7/10/12 192 SBHP 161 BDSD 3203 8050 0.44 3203 8116-8132 23. AN 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 rry knowledge Signature Eric Zoesch Title Pad Ertl4ineer Printed Name Eric ZDeech Date July 24, 2013 7/12 — 6/13 MNS ANNUAL SURVEILLANCE REPORT 2013 ANNUAL SURVEILLANCE REPORT ORION PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2012 -JUNE 30, 2013 7/12 - 6/13 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).......................................................................................... 5 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) .................................................. 7 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E)................................................................................... 7 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F).................................................................................................................................. 8 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) ........................................................ 9 LIST OF ATTACHMENTS Figure 1: Orion production and injection history ...................... ...........,,10 Figure2: Orion voidage history .......................... ...... ...................... .................................................. 10 Figure 3: Orion pressures at datum...................................................................................................15 Figure 4: Orion pressures in map view............................................................................................16 Table 1: Orion monthly production and injection summary ...............:...................................................11 Table 2: Orion pressure survey detail .................................... Table 3: Injection and production profiles ................................... ....................... ,............................... 17 2 7/12 - 6/13 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2013 ORION OIL POOL ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 50513, and covers the period from July 1, 2012 to June 30, 2013. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS fRULE 9A) Monthly production and surface injection volumes from July 1, 2012 to June 30, 2013, as well as cumulative volumes and voidage are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 913) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 50513. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2 in form 10-412 format (3 pages). A shut in time of "na" is used for intervals with no prior injection or production. This data was acquired from open -hole formation tester surveys (RFT or MDT), extrapolated surface pressures (EXTR1), static bottom hole pressure surveys (SBHP), and pressures from permanent downhole gauges installed in new wells. Figure 3 illustrates valid Orion pressure data acquired since field inception, while Figure 4 shows a map of the pressures acquired during this report period interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed -off rates. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can still occur where these are not present or not holding. These phenomena combine to make the quality of pressure transient 3 7/12 — 6/13 ORION ANNUAL SURVEILLANCE REPORT analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build up (PBU) data is difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been shut-in for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build or fall-off rates of several psi per day. Whenever possible, by -zone initial pressures are being obtained with MDTs in new producers, or via downhole gauges in new or existing 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. Most Orion pressures remain in the range of — 1700 to 2200 psi, but low pressures in Orion Polygon 2 and Polygon 2A continue to be a cause of concern. Several producers in Polygon 2 and Polygon 2A remained choked over the report period to control voidage. However, cumulative Polygon 2 VRR has stabilized and static bottom -hole pressure data collected in V -214i and V-2161 have shown relatively constant or increasing reservoir pressure compared to previous pressure surveys taken within Polygon 2. In Polygon 2A and as reported previously, 1200 psi was observed in the OA sand of L -222i upon completion. Low pressure in this well is thought to be due to the influence of L-204. Due to the narrow size of the L-204 fault block, there is insufficient space to place sufficient injectors to provide full injection support. Fault bounded producer L-204 has shown low pressures around 1100 psi. As described last year, injection in the L-222 OA sand was initiated with a small waterflood regulator, with the intention of increasing water volume after a pressure "bulb" has been established. Injection was established in April 2011, but the OA sand suffered from waterflood regulator plugging in March 2012, and the remainder of the sands plugged off in June 2012. Injection resumed after the waterflood regulator valves were changed -out in January 2013. Updated OA pressures will be observed during the next shut-in period. In Polygon 1A, L-2231 was completed as an injector downdip of L-203 but injection has been delayed due to mechanical issues. These include both difficulty running waterflood regulators, and TxIA communication per the AOGCC notification of 5/22/11. Current depletion in L -223i varies from 100 psi in the OBd sand to +20 psi in the OBa sand. Offset producers L-203 and L- 250 were shut-in in September 2011 for sanding and an aquifer MBE respectively, but producer L- 202 remains at solution GOR. Producer L-200 in Polygon 1 was offline and producer L-205 in Polygon 5S was online for 33 days in this reporting period. Neither Polygon 1 or Polygon 5S show depletion from these producing periods in offset injectors with installed real-time downhole pressure gauges or the producers own commingled downhole pressure gauges. 4 7/12-6/13 ORION ANNUAL SURVEILLANCE REPORT 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Log: No production logs were run during this reporting year. Prior production profiles have frequently been adversely affected by well slugging. Future production profile candidates will be evaluated on a case by case basis. Iniection Logs: Seven injection profile logs were run during the report period, and are listed in Table 3. Profiles are run to quality check water flood regulator valve performance while in water service, or to determine the distribution of miscible injectant between zones. Red Dye Testing: A technique for diagnosing matrix bypass events (MBE's) using injection of red dye in offset injectors has been adapted for use in the Polaris and Orion reservoirs. Due to the high injector to producer ratio of these developments, it is necessary to use oilfield brines as "tracers" to determine which of several offset injectors is the source of the MBE. Because waterflood regulators limit the volume of water into any given sand, it is theoretically possible to have an MBE in a producer without going to extremely high watercut. Several red dye tests were performed during this reporting period. A red dye test was performed in July 2012 on L-203 with offset injectors L-21 5i, L-2161, L-21 7i and L-2191 to try to determine the source of high WC in L-203. No red dye was observed and no high tracer samples were analyzed. Red dye testing was performed on V-204 with V-213i, V-217i, V-2221 and V-225i. Again, no red dye was observed and no evidence of tracer samples. The last test was performed on L-201 with L- 222i. The test was intentionally run twice as the first test was done with two zones plugged and the second test was run with all zones open. When L-222i was drilled, the OBa pressure was low and remains low based on SBHP data. This test was run to check that low pressure was not a possible MBE conduit. Results indicate no MBE is present. Interference Testing: V-213i/V-204 test. A pressure response in injector V-2131 to production in V-204 was observed in September 2012. V-2131 was shut-in in July 2012, and had zonal side-pocket mandrel pressure gauges installed for three months. In September 2012, V-204 was shut-in for an interference test with injector V-2171. No response was seen in V-2171, but a rapid response was seen in V-2131. The time delay of the pressure response was less than four hours and indicates an MBE exists between the two wells. V-217i/V-204 test. In September 2012, producer V-204 was shut-in to test for a pressure response in injector V-217i, but no response was seen. 5 7/12 — 6/13 ORION ANNUAL SURVEILLANCE REPORT Interference Testing on Pre -Existing MBE's: No new interference tests were performed on pre-existing MBE's during this report period Comminaled iniector monitorina: All commingled injection wells have dummy waterflood regulator valves installed across the Schrader Bluff interval as of April 2012. There are no further plans for commingled injection due to potential MBE risk. Geochemical Finaerprintin This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Well 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 GC signatures and track returned miscible injectant (MI). Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE's, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. The current Orion injector basis of design calls for pressure gauge installation in all future injectors. Well Testing Improvements: In an effort to improve well test quality, multiphase meters were installed in the test header lines at L -pad and V -Pad in April 2010. During past reporting periods, tests were conducted to establish repeatability, accuracy and viability of the multiphase system. In the fall of 2012, the V pad multiphase meter was commissioned for permanent use. Troubleshooting of the L pad multiphase metering system is ongoing. 6 7/12 — 6/13 ORION ANNUAL SURVEILLANCE REPORT 5. REVIEW 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 monthly 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 Projects: Water flooding began in Orion in December 2003. Initial pattern development on L and V pads is essentially complete. Downhole flow regulators are being employed to balance the flood. A minimum rate of 500 BWPD has been implemented in new waterflood regulator designs to minimize trouble with well freezing. Wherever this rate might result in an excessive VRR, as is the case for injectors downdip of V-205, the injectors are cycled. Injection at low rates is underway in severely depleted zones such as the OA of L-2221, and also depleted zones where MBEs are thought to have healed. Commission approval for implementing an enhanced oil recovery project using Prudhoe Bay miscible injectant was granted on April 28, 2006 through C.O. 505A. Miscible injection started in L -213i in October, 2006, in the high quality oil of up dip Polygon 2. Initial response to large volume MI slugs in up dip producers was encouraging. Injection in late 2008 was concentrated in wells in down dip Polygon 2 to test for response in lower quality oil. However, hydrate problems were encountered in conjunction with returned MI in down dip producer V-205. The current MI strategy is to inject shorter MI slugs to improve MI efficiency, and also to inject MI in additional wells. The MI flood is currently implemented in most polygons in Orion. Reservoir Management Summary: The objective of the Orion 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 balancing voidage to maintain average reservoir pressure. One aspect of the strategy is to control the waterflood sweep primarily with the injector through the downhole regulator valves. Learnings over the last few years reveal the dramatic differences in productivity and oil mobility between sands, which have led to changes in completion designs and operational strategies. The emergence of Matrix Bypass Events (MBEs) has further highlighted the complexity of this reservoir, and the importance of maintaining a dynamic depletion strategy while incorporating changes as new data becomes available. 7 7/12 - 6/13 ORION ANNUAL SURVEILLANCE REPORT Depletion Strate The application of multi -lateral technology in Orion has provided wells with up to six individual legs ("hexa -lateral"), >27K ft of high -angle footage (27,743' drilled; 24,871' completed with slotted liner), and >17K ft of net pay (17,215' in the L-201 Quad -lateral). Good oil quality in some wells and extensive sand exposure has combined to deliver choked production capacity in excess of 7000 bopd. With this prolific production, comes the reservoir management challenge of replacing reservoir energy in Orion's fault -bounded polygons. In early 2005, the Orion depletion strategy was changed to compensate for these prolific producers. Production was choked in some new wells to 2500 bopd which could be more easily supported by injection. The drilling of infill injectors was accelerated to earlier in a pattern's life. Ongoing performance monitoring and reservoir modeling will guide future rate adjustments on producers and injectors, as well as determine the need for additional injection support. As the flood matures, surveillance and flood management become increasingly important in optimizing flood performance and recovery. Frequent pattern reviews are performed on all flood patterns to ensure effective flood management. Matrix Bypass Events (MBE): As described in prior Reservoir Reports, the phenomenon of premature water breakthrough between producer and a water source (usually an injector) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or "worm holes" due to sand production from the lower -pressured producer to the higher - pressured water source. A new MBE from producer V-204 to injector V-2131 was found as of September 2012 based on interference testing between the two wells. The interference test showed a strong connection between V-204 and V-2131, and a red -dye test was performed for confirmation. Due to insufficient sampling duration, the red -dye test was inconclusive and another test is planned for the next reporting period. 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. During the report period, V-207 plugged off, but was returned to production with a coiled tubing fill cleanout. 8 7/12 — 6/13 ORION ANNUAL SURVEILLANCE REPORT 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) During the report period, no new MI responses were observed. An MI response is indicated by an increase in GOR in conjunction with a reduction in the producing ratio of C1 (methane) to C3 (propane). To date in the life of the field, MI response has been seen in the following producers: L-201, V-202, V-203, V-204, V-205, and V-207. Recent Development Work: There has been no development drilling during the report period. Future Development Plans: Future development options for Orion will be discussed in the POD report. 7/12 — 6/13 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY FIGURE 2: ORION VOIDAGE HISTORY 5Q000,00& 45,000,000- 40,000,000. 35,000,000. 30,000,000 cc 0 m 25,000,000 N rn E 20,000,000 G7 15,000,000 10,000,()00. 5,000,000. -Oil Prod Cum -Water Int Cum -Total InI Cum (Water+Ml) Net Voldage Cum - Monthly VRR t Lifetime Cum VRR y r I I !t 100% pprpp N 25000 —�, i,,enwn Ra!g �oR 90% —Weir N;ec;im Ralu I4 I tl uit U) �1Y S()% ¢ 0 ~ t ` r 0 20000 70% ♦L 60% 15000 .1 I — � r 50% 3 � t1i 1 IL 10000 40% m 30% cc O 5000 20% di 10% 3 0 0% N N N N M M M cQQg44gg4g44g4ggg44gg444�4vg�4��6L M u'1 LL] to W 0 0 fon n r n M W m m M M 0 0 0 0 0 0 N N M M 6 �� M FIGURE 2: ORION VOIDAGE HISTORY 5Q000,00& 45,000,000- 40,000,000. 35,000,000. 30,000,000 cc 0 m 25,000,000 N rn E 20,000,000 G7 15,000,000 10,000,()00. 5,000,000. 20 18 16 14 12m 10> 08> 06 04 02 0 00 ON N N N O OW 0 0 0 0 O O � � —— N N N N M M 0 0O O0$ 0 0 0 O O O O 0 O 8 0 0 0 8 0 0 08 0 00 8 0 0 0 5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c M f0 W N M co m N M 0 O) N M t0 W N M f0 QI N M f0 W N M tD O) N M (D W N M 0 7/12-6/13 ORION ANNUAL SURVEILLANCE REPORT -Oil Prod Cum -Water Int Cum -Total InI Cum (Water+Ml) Net Voldage Cum - Monthly VRR t Lifetime Cum VRR y r I I !t I4 I tl uit 1 ! 1 ~ t ` r 20 18 16 14 12m 10> 08> 06 04 02 0 00 ON N N N O OW 0 0 0 0 O O � � —— N N N N M M 0 0O O0$ 0 0 0 O O O O 0 O 8 0 0 0 8 0 0 08 0 00 8 0 0 0 5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c c M f0 W N M co m N M 0 O) N M t0 W N M f0 QI N M f0 W N M tD O) N M (D W N M 0 7/12-6/13 ORION ANNUAL SURVEILLANCE REPORT TABLE 1: ORION MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date Oil Prod STB Gas Prod MSCF Water Prod STB Water Inj STB MI Inj MSCF Oil Prod Cum STB Gas Prod Cum MSCF Water Prod Cum STB Water Inj Cum STB Cum Total Inj (MI+Water) RB Net Res Voidage RVB Net Voidage Cum RVB Monthly VRR RVB/RVB Jul -12 209,531. 129,935. 122,711. 520,718. 39,920. 26,217,616 25,325,474 5,461,296 29,202,967 37,413,775 -166,470 4,534,247 1.43 Aug -12 154,972. 106,965. 110,698. 410,738. 78,668. 26,372,588 25,432,439 5,571,994 29,613,705 37,875,034 -153,944 4,380,303 1.50 Sep -12 107,997. 64,145. 73,042. 308,766. • 64,429. 26,480,585 25,496,584 5,645,036 29,922,471 38,224,901 0 4,380,303 1.70 Oct -12 168,028. 100,779. 112,494. 299,559. , 244,146. 26,648,613 25,597,363 5,757,530 30,222,030 38,671,502 -126,455 4,253,848 1.39 Nov -12 169,992. 128,758. 127,476. 215,234. , 355,602. 26,818,605 25,726,121 5,885,006 30,437,264 39,098,693 -79,881 4,173,968 1.23 Dec -12 175,204. 135,217. 115,714. 282,633. , 432,406. 26,993,809 25,861,338 6,000,720 30,719,897 39,639,272 -197,545 3,976,422 1.58 Jan -13 199,018. 202,207. 121,643. 309,936. , 363,076. 27,192,827 26,063,545 6,122,363 31,029,833 40,166,522 -121,946 3,854,477 1.30 Feb -13 187,071. 223,565. 116,382. 287,857. , 352,744. 27,379,898 26,287,110 6,238,745 31,317,690 40,665,377 -96,056 3,758,421 1.24 Mar -13 221,190. 245,440. 129,443. 320,275. , 303,018. 27,601,088 26,532,550 6,368,188 31,637,965 41,167,635 -45,393 3,713,028 1.10 Apr -13 211,353. 217,885. 131,765. 292,320. 321,731. 27,812,441 26,750,435 6,499,953 31,930,285 41,652,700 -50,175 3,662,853 1.12 May -13 270,612. 271,197. 180,010. 314,656. • 229,844. 28,083,053 27,021,632 6,679,963 32,244,941 42,106,110 110,237 3,773,090 0.80 Jurr13 259,457, 231.565. 141.753. 319.711, 151,259. 28.342,510 27253,198 6.821 r716 32,564,652 42,518,261 80,331 3,853,421 0.84 11 7/12 — 6/13 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 1/3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2 Address: BP Exploration (Alaska) Inc. P.O. Box 196612, 900 E Benson Blvd, Anchorage, AK 99519-6612 3. Unit or Lease Name: 4. Field and Pool: 5. Datum Reference: 6. Oil Gravity: I 7. Gas Gravity: 1 Prudhoe Bay Unit Prudhoe Bay Field, Orion Oil Pool 4400TVDss 1 07 a. Well Name and 9 API Number 10. Type 11 AOGCC 12. Zone 13. Perforated Intervals 14. Final Test 15. Shut -h 16. Press, 17. B H 18Depth 19, Final 20. Datum 21 Pressure 22. Pressure at Number: 50xxxxxxxxxxxx See Pool Code Top - Bottom TV DSS Date Time, Hours Surv, Type Temp. ToollVDSS Observed TVDSS(input) Gradient,psi/tt. Datum (cal) NO DASHES Instructions (see Pressure at instructions Tool Depth for codes) 4277-4147,4331-4189, L-200 50029231910000 0 640135 OBa+OBb+OBd 4135-4287 6/3012013 9624 1 SBHP 53 4142 1891 4400 0.40 1995 4267-4290,4444-4462, Nb+08a+OBc+ 4542-4598,4608-4664, L-203 50029234160000 0 640135 OBd 4672-4698.4630-4682 11/27/2012 936 SBHP WA 4194 1 1382 4400 041 1467 4514-4640,4555-4695. OA+OBa+OBb+O 4438-4578,4393-4539, L-204 50029233140000 0 640135 Bc+OBd 4432-4475 6/30/2013 1 10824 SBHP 1 48 4204 1105 4400 0,15 1134 4015-4038,4154-4190, N1b+OA+OBa+ 4214-4248,4267-4294, L-205 50029233880000 0 640135 OB1b+OBc+OBd 4324-4393,4383-4406 11/25/2012 2328 SBHP 30 3028 1251 4400 0.41 1 1814 4337-4353,4201-4291, L-250 50029232810000 0 640135 N1b+OA 4191-4268 6/30/2013 5208 SBHP 53 4123 1 1797 4400 0.41 1911 L-216 50029232060000 WI 640135 Nb 4217-4249 4/13/2013 8808 SBHP 85 4264 1921 4400 0.44 1981 L-216 50029232060000 WI 640135 OA 4340-4378 4/15/2013 8856 1 SBHP 91 4444 1732 4400 0.44 1752 L-216 50029232060000 WI 640135 OB1b+OBc 4403-4436,4450-4467 4/14/2013 Ba32 SBHP 89 4552 1899 4400 0.44 1966 L-216 50029232060000 WI 640135 OBd 4556-4612 4/15/2013 8856 SBHP 90 4601 1800 4400 0,44 1886 L-219 50029233760000 WAG 640135 OA 4413-4445 6/30/2013 8160 SBHP 84 4362 1958 4400 0.44 1975 L-219 50029233760000 WAG 640135 OBa 4480-4492 6/30/2013 8160 SBHP NIA 1 4470 1962 4400 0.44 1931 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, L-219 50029233760000 WAG 640135 OBd oil 4691-4692 6/30/2013 8160 SBHP 88 4652 1912 4400 1 0.44 1801 L-219 50029233760000 WAG 640135 OBd (water) 4756-4758 6/30/2013 8160 SBHP N/A 4695 2067 4400 044 1937 L-220 50029233870000 WAG 640135 Nb 4116-4136 6/30/2013 24360 SBHP 82 4052 1867 4400 0.44 2020 L-220 50029233870000 WAG 640135 OA 4250-4291 6/30/2013 24360 SBHP 87 4203 1953 4400 0.44 2040 L-220 50029233870000 WAG 640135 OBa 4318-4347 6/30/2013 24360 SBHP 90 4308 2112 4400 0.44 2152 L-220 50029233870000 WAG 640135 OBb/OBc 4360-4377.4414-4431 6/30/2013 24360 SBHP 91 4362 2066 4400 0.44 2083 L-220 50029233870000 WAG 640135 OBd 4466-4511 6/30/2013 24360 SBHP 90 4457 2010 4400 0.44 1985 L-221 50029233850000 WAG 640135 Nb 4090-4105 6/30/2013 5760 SBHP 84 4038 1903 4400 0.44 2062 L-221 50029233850000 WAG 640135 OA 4222-4258 6/30/2013 5760 SBHP 87 4176 1952 4400 0.44 2051 L-221 50029233850000 WAG 640135 OBa 4285-4316 6/30/2013 5760 SBHP 90 4276 2082 4400 0.44 2137 L-221 50029233850000 WAG 640135 OB1b+OBc 4329-4343,4382-4401 6/30/2013 5760 SBHP 90 4329 2021 4400 0.44 2052 L-221 50029233850000 1 WAG 640135 OBd 1 1 4433-4481 6/30/2013 5760 SBHP 92 4426 1988 4400 0.44 1977 12 7/12 — 6/13 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 2/3 13 7/12 - 6/13 PBU Orion Annual Reservoir Report STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: BP Ex oration Alaska Inc. 2 Address: P.O. Box 196612, 900 E Benson Blvd., Anchorage, AK 99519-6612 3, Unit or Lease Name: Prudhoe Bav Unit 4. Field and Pool: Prudhoe Bay Field. Orion Oil Pool 5. Datum Reference: 4400 TVDss 6. Oil Gravity: 15-23 7. Gas 0.7 Gravity: 8 Well Name and Number: 9. AR Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12, Zone 13. Perforated Intervals Top - Bottom NDSS 14. Final Test Date 15. Shut -h Time, Hours 16. Press. Sury Type (see instructions for codes) 17. B.H Terrp. 18. Depth Tool NDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psilft. 22. Pressure at Datum (cal) L-222 50029234200000 WI 640135 OA 4307-4347 11/25/2012 6696 SBHP 86 4266 1246 4400 044 1296 L-222 50029234200000 WI 640135 OBa 4378-4412 5/22/2013 2424 SBHP 85 4370 1644 4400 0.44 1657 L-222 50029234200000 WI 640135 OBb+OBc 4427-4435.4466-4482 5/22/2013 2424 SBHP 86 4433 1823 4400 0.44 1808 L-222 50029234200000 WI 640135 OBd 4521-4571 11/25/2012 10512 SBHP 93 4514 1792.0 4400 0.44 1742 L-223 50029234150000 WI 640135 Nb 4377-4396 6/30/2013 30624 SBHP 85 4339 1964 4400 0,44 1991 L-223 50029234150000 WI 640135 OA 4502-4538 6/30/2013 30624 SBHP 88 4477 1998.0 4400 0.44 1964 L-223 50029234150000 WI 640135 OBa 4567-4599 6/30/2013 30624 SBHP 90 4560 2008 4400 0.44 1938 L-223 50029234150000 WI 640135 OBC 4667-4686 6/30/2013 30624 SBHP 92 4642 2031 4400 0.44 1925 L-223 50029234150000 WI 640135 OBd 4717-4765 6/30/2013 30624 SBHP 93 4714 2060 4400 0.44 1922 V-203 50029232850000 O 650135 OA+OBa+ OBb+OBc+O13d 4249-4274,4306-4331, 4342-4365,4397-4426, 4455-4486 9/15/2012 168 SBHP 65 4125 1181 4400 0.38 1286 V-205 50029233800000 0 640135 OA+OBa+OBd 4392-4459,4444-4521. 4579-4623 3/14/2013 2808 SBHP WA 4269 2203 4400 0.41 2257 V-207 50029233900000 0 640135 Nb+OBa+OBb+O Bd+Obe 4428-4452,4628-4653, 4654-4695,4775-4821, 4823-4861 9/27/2012 1488 SBHP 33 4423 2029 4400 0.41 2020 V-213 50029232130000 WAG 640135 OA 6582-6627 10/1/2012 1560 SBHP 85 4436 1362 4400 0.44 1346 V-213 50029232130000 WAG 640135 OBa+013b 6667-6702,6717-6742 8x712012 200 SBHP 88 4530 1344 4400 0.44 1287 V-213 50029232130000 WAG 640135 Obd 6862-6937 10/6/2012 1632 SBHP 89 4588 1834 4400 0.44 1751 V-214 50029232750000 WAG 640135 OBa+OBb 4334-4360,4376-4393 9/5/2012 334 SBHP 102 4379 1690 4400 0.44 1699 V-214 50029232750000 WAG 640135 OBc 4431-4444 9/5/2012 331 SBHP 99 4446 1641 4400 0.44 1621 V-214 50029232750000 WAG 640135 OBd 4480-4527 9/5/2012 327 SBHP 100 4504 1832 4400 0.44 1786 V-215 50029233510000 WAG 640135 OA 4370-4404 10/21/2012 9840 SBHP 79 4347 1967 4400 0.44 1990 V-216 50029232160000 WAG 640135 OA 4350-4387 8/18/2012 315 SBHP 83 4366 1790 1 4400 0.44 1805 V-216 50029232160000 WAG 640135 OBa+OBb 4417-4441.4458-4474 8/18/2012 406 SBHP 83 4442 1489 4400 0.44 1471 V-216 50029232160000 WAG 640135 Obd 4564-4611 8/18/2012 393 SBHP 85 4504 1960 4400 0.44 1914 V-217 50029233340000 WAG 640135 OA 4349-4387 3/2112013 1728 SBHP WA 4341 1676 4400 0.44 1702 V-217 50029233340000 WAG 640135 OBa+OBb 4416-4443,4456-4472 3/21/2013 1726 SBHP 83 4422 1735 4400 0.44 1725 V-217 50029233340000 WAG 640135 OBd 4562-4610 3/21/2013 1728 SBHP WA 4551 1771 4400 0.44 1705 V-218 50029233500000 WAG 640135 OBa+OBb 4520-4550,4563-4576 11/27/2012 9360 SBHP 83 4515 1 1815 4400 0.44 1764 V-218 50029233500000 WAG 640135 OBd 1 4662-4703 11/27/2012 9360 SBHP WA 4653 1886 4400 0.44 1775 V-219 50029233970000 WAG 640135 Nb 4434-4450 6/3012013 1 259 1 SBHP 1 87 4416 1547 4400 0.44 1540 V-219 50029233970000 WAG 640135 OBa 4626-4654 6/3012013 259 SBHP 87 4613 1910 4400 0.44 1816 V-219 50029233970000 WAG 640135 OBb 4667-4680 6/30/2013 259 1 SBHP 86 4665 2262 4400 0.44 2145 V 219 50029233970000 WAG 640135 OBd+OBe 4769-4810,4842-4866 6/3012013 259 1 SBHP 91 1 4752 2255 4400 0.44 2100 13 7/12 - 6/13 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 3/3 14 7/12 - 6113 PBU Orion Annual Reservoir Report STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: BP Exploration (Alaska) Inc. 2. Address: P.O. Box 196612, 900 E Benson Blvd., Anchorage, AK 99519-6612 3. Unit or Lease Name: Prudhoe Bay Unit 4 Field and Pool: Prudhoe Bay Field, Orion Oil Pool 5. Datum Reference: 4400 T/Dss 6, Oil Gravity: 15-23 7. Gas 0.7 Gravity: 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 TV DSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) V-220 50029233830000 WAG 640135 Nb 4351-4367 9/17/2012 1728 SBHP 92 4328 1851 4400 0.44 1883 V-220 50029233830000 WAG 640135 OA 4486-4525 11/27/2012 3432 SBHP 80 4465 2353 4400 1 0.44 2324 V-220 50029233830000 WAG 640135 OBa 4554-4583 9/17/2012 1728 1 SBHP 94 4544 1948 4400 0.44 1885 V-220 50029233830000 WAG 640135 OBb + OBc 4598-4616,4658-4678 9/17/2012 1728 SBHP 93 4597 1922 4400 0.44 1835 V-220 50029233830000 WAG 640135 OBd 4710-4748 9/17/2012 2568 SBHP 95 4703 1463 4400 0,44 1330 V-220 50029233830000 WAG 640135 OBe 4774-4793 9/17/2012 2568 SBHP 96 4775 1896 4400 0.44 1731 V-221 50029232460000 WAG 640135 OBa 4616-4643 9/9/2012 327 SBHP 92 4636 2034 4400 0.44 1930 V-221 50029232460000 WAG 640135 OBb 4661-4677 9/9/2012 327 SBHP 64 4679 1642 4400 1 0.44 1519 V-221 50029232460000 WAG 640135 OBd 4770-4810 9/9/2012 327 SBHP 86 4710 2449 4400 0.44 2313 V-223 50029233840000 WAG 640135 OA 4419-4458 6/30/2013 20016 SBHP 83 4397 1770 4400 0.44 1771 V-223 50029233840000 WAG 640135 OBa 4485-4513 6/30/2013 19944 SBHP 84 1 4471 1726 4400 0.44 1695 V-223 50029233840000 WAG 640135 OBb 4528-4545 6/30/2013 18600 SBHP 86 4524 1842 4400 0.44 1787 V-223 50029233840000 WAG 640135 OBd 4632-4674 6/30/2013 35640 SBHP 90 4616 1996 4400 0.44 1901 V-225 50029234190000 WAG 640135 OA 4330-4365 6/30/2013 1992 SBHP 87 4281 1922 4400 0,44 1974 V-225 50029234190000 WAG 640135 OBa 4394-4420 6/30/2013 1992 SBHP 94 4379 2090 4400 0.44 2099 V-225 50029234190000 WAG 640135 OBb 4433-4453 6/30/2013 1992 1 SBHP 92 4432 2423 4400 0.44 2409 V-225 50029234190000 WAG 640135 OBd 4531-4576 6/30/2013 1992 SBHP 89 4522 2139 4400 0.44 2085 V-227 50029234170000 WI 640135 NB 4449-4462 6/30/2013 18096 SBHP 88 4403 1977 4400 0.44 1976 V-227 50029234170000 WI 640135 OBa 4634-4662 6/30/2013 18096 SBHP 92 4596 1831 4400 0,44 1745 V-227 50029234170000 WI 640135 1 OBb 4676-4695 6/30/2013 31488 SBHP 91 4760 1984 4400 1 0.44 1826 V-227 50029234170000 WI 640135 OBd 4790-4836 6/30/201318096 SBHP 94 4673 1871 4400 0.44 1751 V-227 50029234170000 WI 640135 OBe 4854-4876 6/30/2013 18096 SBHP 95 4854 2120 4400 0.44 1920 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas I hereby certify that the foregoing is true and correct to the best of ny knowledge. Signature Carolyn Kirchner Printed Name Carolyn Kirchner Conservation Commssion. Title Date Production August 15, Enaineer 2013 14 7/12 - 6113 PBU Orion Annual Reservoir Report FIGURE 3: ORION PRESSURES AT DATUM 2500 L-200 Y 218 2300 `-2,2 L-211 V�205 • 218 L-221 2100 `-200 217Q L.200 .225 Wp .100L-117 •Q ♦ W-20 L-21 202}@50 V 1 V-214 2i� LL --22 L L-275 L 721A18 L-216 08 73 7 'k�215 V.106200#� *5 2�4♦ 2 1900 - +276L OS d V-216 v-212 • ♦ L-200 4 7'218 V-224 L-103fln ♦♦ ♦ ♦ 22 0205 227 *2231.218 i V-204 ♦ ♦ V-203 V-223 5 v,1700 .217♦ -t05 L,203 14 V.217 : * 13%*217 L-222 CL :222 4-229 ♦ V-222 V-;�E J-205 1500 — • *- YXI W3 1300 r2D7 1100 2oa 01-01 01-02 01-03 01-04 12-04 12-05 12-06 12-07 12-08 12-09 12-10 12-11 12-12 12-13 Survey Date 15 7/12 — 6/13 PBU Orion Annual Reservoir Report FIGURE 4: ORION PRESSURES IN MAP VIEW Orion Field by Last Static Pressure 7/12 to 6/13 L-203 L-223 L-200 • Notes: L-25 6818 Fn uun" arr rnrmgw I n. , aro...... l 1 -h.k, DHA; SCHP 1IDT owl ffHYdik, rwm r L-212PIY-1- yh,fevFnf rayl{� ,A.l L-217 .-21 � -L,-216 D., I.", �._»> L -21S L-218 `ar A A leas L-219 HfY• 1811• L-202 L-222 26A L-21 0 L -214A ♦ L-201 181 0 1921 1 V-203' ., 4— (0 L-221 L-205 q-220 N 1:24000 7,\ A - 4331 { V-211. -2 - 4-21 • 105 ! V-211 V-2 V 222♦ 1♦ V-212 VZ1 V-225 V423 15 16 7/12 — 6/13 PBU Orion Annual Reservoir Report TABLE 3: INJECTION AND PRODUCTION PROFILES Well Survey Date Survey Type Zones Total Flow Splits Comments V-225 8/26/12 IPROF OA 23% Water IPROF OBa 26% OBb 22% OBc 0% OBd 29% V-224 12/2/12 IPROF Nb 33% Water IPROF OBa 27% OBb 10% OBd 30% OBe 0% V-225 2/15/13 IPROF OA 25% Water IPROF OBa 36% OBb 7% OBc 0% OBd 32% V-212 1/2/13 IPROF OA 17% MI IPROF OBa+OBb 28% OBd 55% L-210 6/30/13 IPROF OA 1 % M I IPROF OBa 64% OBb 3% OBd 32% V-211 12/30/12 IPROF OA 59% Water IPROF OBa+OBb 30% OBc 7% OBd 4% V-216 2/10/13 IPROF OA 40% MI IPROF OBa+OBb 0% OBd 60% 17 7/12 — 6/13 PBU Orion Annual Reservoir Report 2013 ANNUAL SURVEILLANCE REPORT POLARIS PARTICIPATING AREA PRUDHOE BAY UNIT JULY 1, 2012 -JUNE 30, 2013 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT CONTENTS 1 . INTRODUCTION.............................................................................................................................3 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) ............................3 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9B) ..................................3 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING(RULE 9C)................................................................................................................5 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D)................................................................6 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY(RULE 9E)....................................................................................................................6 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS(RULE 9F).................................................................................................................7 LIST OF ATTACHMENTS Figure 1: Polaris production and injection history .............................................................................10 Figure2: Polaris voidage history .......................................................................................................10 Figure 3: Polaris pressure at datum ............................ .............. ............. ,............. .................. ......... ..12 Figure 4: Polaris pressures in map view..............................................................................................13 Table 1: Polaris monthly production and injection summary .....................................................................9 Table 2: Polaris pressure survey detail.....................................................................::....................:..11 2 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2013 POLARIS OIL POOL ANNUAL RESERVOIR REPORT 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 484A, and covers the period from July 1, 2012 to June 30, 2013. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) Monthly production and surface injection volumes from July 1, 2012 to June 30, 2013, as well as cumulative volumes and voidage are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 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 from open hole formation tester surveys (MDT), static bottom hole pressure surveys (SBHP), and from permanent downhole gauges installed in new wells. Figure 3 illustrates all valid Polaris pressure data acquired since field inception, while Figure 4 shows a map of the pressures acquired during this report period at the Pool datum of 5000 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed -off rates during shut-in. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can still occur where these 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) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been 3 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT shut-in for several weeks or months to allow maximum build-up or fall-off. Even after a long shut- in time, wells show build 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, by -zone initial pressures are being obtained with MDTs 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 polyaon follows: S -Pad North This polygon contains shut-in production well, S-200, and low -rate jet pump producer, S-201. This is the only Polaris polygon without injection support. Pressure surveys taken over the past few years have shown little pressure change, which reflects minimal offtake from this area. The most recent pressure measurement was 1952 psi on 6/14/13, which is close to the surveys taken in 2009 and 2010. S -Pad South Penta -lateral producer S -213A is supported by injectors S-2151, S-2171 and S-2181 in this polygon. S -213A was put on production in 2005. S-2151 experienced a matrix bypass event (MBE) in early 2006 which created a "short circuit" to S -213A in the OBa sand, and therefore lost its utility as an injector because it was merely cycling water. The well was worked over in 2007 to install a multi - packer completion, thereby isolating each sand similar to the completions installed in new injectors. With the multi -packer completion, injection in S -215i resumed in late 2007. S-215 OBa injection resumed in November 2011 as the OBa sandface pressure continued to rise and the MBE was thought to be inactive. Injection started in new injector S-2171 in early 2008, and the pattern was completed with new injector S-21 Bi, with injection starting in January, 2010. Many injectors now have individual sandface pressure gauges which permit zonal pressure monitoring. Measured pressures are primarily in the range of 1700 psi to 2400 psi. W -Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211, and injectors W-2091, W-2121, W -213i, W -214i, W -215i, W-2161, W-2171, W -218i, W-2191, W -220i, W-221 i, and W-2231. Measured pressures in this polygon primarily range from 1850 psi to 2400 psi depending on the sand and the area. A majority of the North injectors where shut in for the 2010 - 2011 report period because of the W pad drilling campaign, causing a drop in VRR. The majority of injection was brought online in September 2011 and VRR has recovered from the 2010 - 2011 reporting period's drop, refer to figure 2. 4 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT W -Pad East W-203 is the only producer in this polygon, supported by W -207i and W-2101. The only pressure obtained in the polygon in the last year was 2637 psi in the OBc sand of W -21 0i. This is a typical injection -induced high pressure region around an injector, but does not represent a polygon average pressure due to the very slow pressure fall-off. Overall the pressure has remained constant over the years with the consistent injection into the pattern. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production & Infection Loagina No production or injection surveys were run during the report period. Geochemical Finaerprintina This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples are later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas GC signatures and track returned miscible injectant (MI). 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, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. The current Polaris injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5 7/12-6/13 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 Proiects Waterflood has been implemented in Polaris with 14 injectors at W -Pad, and 3 active injectors at S -Pad. Almost all Polaris injectors utilize waterflood regulators to control the volume of water going into each sand. This is done wherever the completions permit it. MI breakthrough is indicated by an increase in GOR in conjunction with a reduction in the producing ratio of C1 (methane) to C3 (propane). W-219 began injecting MI in November of 2012, and was swapped back to water in April 2013. No offset producer has seen an MI response from this slug. To date in the life of the field, W-204 and S -213A are the only producers to see an MI response. Reservoir Manaaement Summa The objective of the Polaris reservoir management strategy is to manage reservoir development and depletion to maximize ultimate recovery consistent with prudent oil field engineering practices. One aspect of the strategy is to control the waterflood sweep primarily through the use of downhole injection regulator valves. Learnings over the last few years have revealed dramatic differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. The emergence of MBEs has further highlighted the complexity of the Schrader Bluff reservoirs, and the importance of maintaining a dynamic depletion strategy while incorporating changes as new data becomes available. Ten producers were drilled in the S and W -Pad areas using various completion and stimulation techniques, evolving into the current multilateral well design. These wells produced on primary depletion, until waterflood was initiated in May 2003. The waterflood patterns are designed to ensure pressure is maintained above bubble point pressure, and as close to original reservoir pressure as possible. The W-200 pattern has shown a classical waterflood response over the last few years through a significant reduction in GOR and increase in oil production. Because of differences in rock and oil quality between the three main target sands, the Polaris reservoir behaves like several different reservoirs connected in the same wellbore, and requires a 6 7/12-6/13 POLARIS ANNUAL SURVEILLANCE REPORT much higher degree of control in the injectors and producers to properly manage voidage. Substantial changes have been made to producer and injector designs to address this challenge. A number of initiatives are underway to address the areas in Polaris that are suffering from ineffective waterflood support: ■ Updating the infector completion desian The completion design of PBU viscous oil injectors has evolved significantly during the last eight years to include isolation packers between sands to accurately control injection into each of the vastly different sands. Injection rate into each zone is controlled by downhole flow regulators installed in mandrels adjacent to the target sand. The new completion design also includes real-time downhole pressure gauges that read pressure adjacent to each sand for better monitoring and diagnosis of injection into each zone. In 2009, the downhole flow regulator design was updated with a check valve to prevent between zone cross -flows during shut -downs and improve valve reliability. The last flowsleeves in Polaris were replaced with waterflood regulators during the 2010 report period. • Development Areas under evaluation for near-term flood expansion and infill are described under "Future Development Plans" below. Matrix Bypass Events (MBE): There have been no new MBEs in Polaris during this report period. As described in prior Reservoir Reports, the phenomenon of premature water breakthrough between a producer and a water source (usually an injector) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or "worm holes" due to sand production from the lower -pressured producer to the higher -pressured water source. 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 90 No new MI responses were seen during this report period. MI breakthrough is indicated by an increase in GOR in conjunction with a reduction in the producing ratio of C1 (methane) to C3 (propane). Recent Development Work: No new wells were drilled during this report period. 7 7/12 -6/13 POLARIS ANNUAL SURVEILLANCE REPORT Future Development Plans: Expansion of M and S pads to access resources of the northern part of Polaris continues in the Appraise Stage. The M&S project has been integrated into the overall west end development program being managed by BP's Global Projects Organization in order to better understand the infrastructure and GC -2 fluid handling capacity requirements. Work will continue on evaluating facility requirements and options for pad expansion, heat and infrastructure. This work will aid in developing facility & drilling cost projections, and will help to understand viability of development options. 8 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 1: POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Water Inj MI Inj Oil Prod Gas Prod Water Prod Water Inj Total Inj Cum Net Res Cum Net Monthly Date Prod Cum Cum Cum Cum (Water+Ml) widage Voidage VRR STB MSCF STB STB MSCF STB MSCF STB STB RB RVB RVB RVB/RVB Jul -12 176,408 116,863 54,009 216,855 39,348 14,118,118. 13,515,755. 3,565,181. 13,932,783. 15,284,326 30,949 6,639,565 0.89 Aug -12 ' 187,591 ' 137,504 ' 54,948 ' 262,367 0 '14,305,709.'13,653,259.'3,620,129. '14,195,150. 15,549,316 28,173 6,667,738 0.90 Sep -12 ' 149,013 ' 97,476 ' 36,214 ' 194,310 0 '14,454,722.'13,750,735.'3,656,343. '14,389,460. 15,745,569 24,896 6,692,634 0.89 Oct -12 ' 181,394 ' 132,666 ' 40,732 ' 319,956 0 '14,636,116.'13,883,401.'3,697,075. '14,709,416. 16,068,725 -52,308 5,640,326 1.99 Now12 ' 145,315 ' 102,865 ' 37,266 `261,228 18,692 '14,781,431.'13,986,266.'3,734,341. '14,970,644. 16,343,780 -54,622 6,585,704 1.25 Dec -12 ' 127,679 ' 55,527 ' 46,686 `284,341 26,320 '14,909,110.'14,041,793.'3,781,027. '15,254,985. 16,646,757 -107,723 6,477,982 1.55 Jan -13 ' 142,108 ' 69,033 ' 46,629 ' 232,108 25,809 '15,051,218.'14,110,826.'3,827,656. '15,487,093. 16,896,671 -35,386 6,442,596 1.16 Feb -13 ' 152,023 ' 69,491 ' 49,232 P'269,761 27,685 '15,203,241.'14,180,317.'3,876,888. '15,756,854. 17,185,741 -61,795 6,380,801 1.27 Mar -13 ' 173,875 ' 93,559 ' 55,340 `283,514 29,538 '15,377,116.'14,273,876.'3,932,228. '16,040,368. 17,489,813 -40,053 6,340,748 1.15 Apr -13 ' 147,906 ' 85,266 ' 43,876 ' 264,156 28,741 '15,525,022.'14,359,142.'3,976,104. `16,304,524. 17,773,855 -60,648 6,280,100 7.27 May -13 ' 145,094 ' 59,340 ' 43,810 ' 250,241 0 '15,670,116.'14,418,482.'4,019,914. '16,554,765. 18,026,598 -41,544 6,238,556 1.20 Jun -13 ' 125.581 ' 43.227 ' 44,522 ' 237,723 0 '15,795,697.'14,461,709.'4,064,436. '16,792,488. 18,266,699 -53,553 6,185,004 1.29 9 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY FIGURE 2: POLARIS VOIDAGE HISTORY 20,000,000 18,000,000 16,000,000 14,000,000 12, 000, 000 m M 10,000,000 E8,000,000 6,000,000 4,000,000 2,000,000 zo 18 1.6 14 1.2 _ 10� x 0.8 0.6 0.4 0.2 0 0.0 4� 4� 4$ 4�� i > > > > > > > > > > > > > > > > z z° - 3 z g z° g - 5 z 5 z 5 z° 3 z } z° z° 3 z z Figure 2 — Polaris Voidage & Injection History 10 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT -Oil Prod Cum, STB —Total Inl Cum (Water+Ml), RVB — -Ne[ Vadage Cu., RVB Monthly VRR —lifetime cum VRR I I II II 111 II I I III Illi I III it I 1 zo 18 1.6 14 1.2 _ 10� x 0.8 0.6 0.4 0.2 0 0.0 4� 4� 4$ 4�� i > > > > > > > > > > > > > > > > z z° - 3 z g z° g - 5 z 5 z 5 z° 3 z } z° z° 3 z z Figure 2 — Polaris Voidage & Injection History 10 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 11 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: BP Exploration (Alaska) Inc. P.O. Box 196612, 900 E Benson Blvd., Anchorage, AK 99519-6612 3. Unit or Lease Nam: 4 Feld and Pool: 5. Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Prudhoe Bay Unit Prudhoe Bay Feld, Polaris Oil Pool 5000 TV Dss 15-23 0.7 S. Well Name and 9. A PI Number 10. Type 11. AOGCC 12. Zone 13. Perforated Intervals 14, Final Test 15 Shut -In 16. Press. 17. B.H. 18 Depth 19. Final 20. Datum 21. Pressure 22. Pressure at Number: 50XXXXXXXXXXXX See PoclOode Top - Bottom TV DSS Date Time, Hours Surv. Type Temp. Tool TV DSS Observed TVDSS(input) Gradient,psi/ft. Datum(caq NO DASHES Instructions (see Pressure at instructions Tool Depth for codes) S-201 50029229870000 0 64160 OA+OBa+OBb+OBd 49845067,5163-5170 6/20/2013 WA D(RT1 WA 4984 1945 5000 0.44 1952 S-215 50029231070000 WAG 64160 OA 4988-5002,5006-5016 6/15/2013 2376 SBHP 89 4975 2704 5000 0.44 2715 S-215 50029231070000 WAG 64160 OBa 5032-5059 6/15/2013 6264 SBHP WA 5022 1 1712 5000 0.44 1702 5066-5085,5119-5133 1 S-215 50029231070000 WAG 64160 OBb+Obc 6/1512013 2376 SBHP 92 5067 2349 5000 044 2320 S-215 50029231070000 WAG 64160 OBd 5169-5196 6/15/2013 4368 SBHP WA 5151 1799 5000 0.44 1733 5-217 5002923362000D WAG 64160 OA I 4950-4989 10/5/2012 1779 SBHP 91 4921 2233 5000 0.44 2268 5-217 50029233620000 WAG 64160 OBa f 5007-5023 10/5/2012 1779 SBHP WA 5001 1646 5000 0.44 1646 5047-5066,5099-5115 S-217 50029233620000 WAG 64160 OBb+OBc 10/5/2012 1779 SBHP 90 5040 1669 5000 0.44 1651 S-217 50029233620000 WAG 64160 OBd 5151-5193 10/5/2012 1779 SBHP WA 5147 1940 5000 0.44 1875 S-218 50029234140000 WAG 64160 OA 4997-5027 11/19/2012 1560 SBHP 93 4945 2215 5000 0.44 2239 S-218 50029234140000 WAG 64160 OBa 50435067 11/19/2012 1560 SBHP 69 5041 2250 5000 0.44 2232 5086-5105,5140-5151 S-218 50029234140000 WAG 64160 OBb+OBc 11/19/2012 1560 SBHP 90 5066 2269 5000 0.44 2231 S-218 50029234140000 WAG 64160 OBd 5185-5225 11/19/2012 1560 SBHP 93 5183 2311 5000 0.44 2230 4971-4989,4988-4968, 4983-4986,5055-5123, 5123-5134,5135-5119, 5161-5158,5123-5125, W-202 50029233330000 0 64160 OBa+OBc+Obd 5140-5180.5180-5181 11/6/2012 240 SBHP 94 4917 1462 5000 041 1497 4973-4982,4984-5015, 5006-5015,5044-5051, W-205 50029231650000 0 64160 Oba+OBc+OBd 5052-5092,5109-5159 1/28/2013 1248 SBHP 94 4875 1920 5000 0.41 1971 M210 50029233390000 Vul 64160 Nb 4697-4702 11/27/2012 48624 SBHP 85 4671 2153 5000 0.44 2298 W-210 50029233390000 Vvl 64160 OBc 4971-4997 5/10/2013 1194 PFO 87 4959 2619 5000 0.44 2637 W-213 50029233540000 VIA 64160 Nb 46934704 11/27/2012 46944 SBHP 101 4672 2112 5000 0.44 2256 W-223 50029234400000VN 64160 OBa 50355059 4/27/2013 4200 SBHP 80 4999 2315 5000 0.44 2315 W-223 50029234400000 Vvl 64160 OBC 5112-5143 4/27/2013 4200 SBHP 80 5090 2355 5000 0.44 2315 VV -223 50029234400000 Vvl 64160 OBd 51635208 4/27/2013 4200 SBHP 80 5169 2388 5000 0.44 2314 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 know ledge. Signature Qarolyn Kirchner Title Production Enaineer Printed Name Carolyn Kirchner Date August 15, 2013 11 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS PRESSURES AT DATUM 12 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT 2600 W-209 S-216 V1�209 ♦ ♦ W-215 ♦ 2400 zra V1N218Wg'�i10 ♦ VW8'®9 ♦ ♦♦ �2�223 5-219►♦ ?�21 fi VL V1�200 ♦ ♦ S-217 ♦ �`♦ 5-217 fVhl-205 X210 B 218 2200 VV -211 vv+�515 W-215 $_218 ♦ :212 ♦ W-205♦ �M-216 � 13 14±215 $2133A �216:�05 +217+205 X218 21 :-215 ♦ S-200 #.S ♦ S-21 � ♦ 5-200 ♦ S-116 y�218 V1F204 � 1 _ IA ♦ 5-20� 5-215 ♦ 217 ♦ 2 2000 ♦ ♦ ♦ ♦ 2D 7 S-201 21" 217 ♦ i 7 �� * W-211 $_201�Z S-201 ♦ 201 # l�4-�5 5-205 ♦ N N ♦ ♦ ♦ S-217 �Y1�205 d 205 W-201 ♦�? 0 S-215 W-205 * 1M-2 6 ♦ a` 1800 w-¢esao ♦ ♦ ♦ W-200 `zo1 W-200 S-2SQ16 W-200 1600 5-213 213A ♦ V1ti204 w-2oo W-202 :213 1400 1200 . 09-97 09-98 09-99 09-00 09-01 09-02 09-03 09-04 09-05 09-06 09-07 09-08 09-09 09-10 09-11 09-12 09-13 Survey Date 12 7/12 - 6/13 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 4: POLARIS PRESSURES IN MAP VIEW S 13A -218 \W-202 W-220 -- z Polaris Field ty W-218 Last Static Pressure W-217 7/12 to 6/13 1 l S- W-223 • V ofes W-216 A.l.rr � nrz n�.�rugw! o, ,•onrn,nrgl:rl • hr: Gulv.. T,/!Pu SBHP 191T nnJ If HT' d,,,,, I W-214Oar � P,•.•i,,,rr.,,,r,n.•,1,,, �,,,, r„ .,nrrl 5-20 W-205 W-2 219 Fal, Aq,N Yep. Jlil W 12 W-209 -200 ,,,, • W-2 1 S 13A -218 \W-202 W-220 -- � � N ice= l 1:z4oao 13 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT z W-218 W-217 l W-223 W-216 • W-201 I W-214Oar � AW -2 5 W-205 W-2 219 W 12 W-209 -200 ,,,, • W-2 1 - 2V0�I •w -210 W 3 � � N ice= l 1:z4oao 13 7/12 — 6/13 POLARIS ANNUAL SURVEILLANCE REPORT