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Home My WebLink About2017 Prudhoe Satellite Oil PoolsEs September 14, 2017 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit Satellite Pools Annual Reservoir Surveillance Reports July 1, 2016 — June 30, 2017 Dear Chair French: BP Exploration (Alaska) Inc. P. 0. Box 196612 900 East Benson Boulevard Anchorage, AK 99519-6612 RECEIVED SEP 14 2017 AOGC*�^ BP Exploration (Alaska), Inc, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports for the Satellite Oil Pools (Aurora, Borealis, Midnight Sun, Orion, and Polaris). These Annual Reservoir Surveillance Reports were prepared in accordance with the latest conservation orders for each pool. If you have any questions regarding the reports please contact Bill Bredar at 564-5348 or through email at William.bredargbi2.com. Res ectfully, Diane Richmond Performance Management Team Lead Alaska Reservoir Development, BPXA ' 564-4212 Cc: Mr. Eric Reinbold, ConocoPhillips Alaska, Inc Mr. Phil Tsunemori, ConocoPhillips Alaska, Inc Mr. Hank Jamieson, ExxonMobil Alaska, Production Inc a Mr. Gerry Smith, ExxonMobil Alaska, Production Inc y Mr. Dave White, Chevron USA Ms. Rebecca Kruse, SOA DNR -Division of Oil and Gas Mr. Dave Roby, AOGCC 1 Mr. Lewis Westwick, BPXA 2017 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1, 2016—JUNE 30, 2017 7/16 — 6/17 Midnight Sun Annual Surveillance Report 1 rrNmTCIUTC 1. Introduction 3 2. Progress of Enhanced Recovery Project Implementation and Reservoir Management (Rule 11 a) 3 3. Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) 3 IA w. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) + 5. Results and Analysis of Production and Injection Logging Surveys (Rule 11 d) 4 6. Results of Well Allocation and Test Evaluation (Rule 11 e) and Review of Pool Production Factors and Issues (Rule 7(d) 4 7. Future Development Plans and Review of Plan 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 Survey Details.....................................................................................................8 Table3: Allocation Factors..............................................................................................................................8 Figure 1: Midnight Sun Monthly Production and Injection History................................................................7 Figure 2: Midnight Sun Voidage History..........................................................................................................7 7/16 — 6/17 Midnight Sun Annual Surveillance Report 2 r I Prudhoe Bay Unit 2016 Midnight Sun Annual Reservoir Report This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Midnight Sun Oil Pool in accordance with Commission regulations F and Conservation Order 452. This report covers the period from July 1, 2016 through June 30, 2017. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11 a) i Production and injection volumes for the 12 -month period ending June 30, 2017 are summarized in Table 1. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to maximize commercial production F 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 s GOR's to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. j There is a risk of oil in -flux into the gas cap from mid -field water injection. Placement of the wells drilled in 2001 and voidage management is minimizing this risk. A VRR target of 1.0 to 1.3 is designed to increase reservoir pressure while minimizing re -saturation of oil into the gas cap. During the period covered by the report, the VRR averaged 1.11. Midnight Sun production volumes have remained relatively constant for oil, water, and gas phases during the reporting period. Stabilized reservoir pressure from injection underpins the steady fluid production. Well E-101 currently produces at —86% watercut, and Well E-102 produces at —96% watercut. Since 2005, gas lift has been utilized to i produce the Midnight Sun wells more efficiently. 9 Voidage Balance by Month of Produced and Injected Fluids (Rule 11 b) ' A total of six Midnight Sun wells have been drilled, with the most recent well, P1-122, drilled in 2015 from Pt. McIntyre. Midnight Sun is expected to have an oil production rate of approximately 1000 BOPD through 2017. A peak water injection rate of 20-25 MBWPD for the field has been achieved since E-103 and E-104 were converted to water injection in 2003. Monthly production and injection surface volumes for the reporting period are summarized in Table 1 along with a voidage balance of produced and injected fluids for the report period. 7/16 — 6/17 Midnight Sun Annual Surveillance Report 3 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. The acquisition of E -100's elevated pressure on 8/12/2016 giving a gradient of 0.52 psi/ft is being monitored to see if this trend continues and whether an adjustment to field injection should occur to meet reservoir management goals. The E-104 injection well has been shut-in since September 911, 2015. Prior to that this well's injection rate declined with time and the block showed evidence of increased pressure, indicating the well may not be providing efficient sweep or efficient pressure support to the field. A static bottom hole pressure was taken on September 3r1, 2015 for injector E-104 which provided additional evidence of reservoir compartmentalization. This surveillance data indicated pressure in the E-104 area had increased to near initial reservoir conditions which implies the injector was not providing meaningful support to the field. Results and Analysis of Production & Injection Logging Surveys (Rule 11 d) A tracer study was performed in 2010. Progress and results of that study were discussed in the 2014-2015 ASR. During the 2016-2017 reporting period, no significant production logging or tracer studies were completed, and future tracer studies are not being planned at this time because the field's interactions are satisfactorily understood. Results of Well Allocation and Test Evaluation (Rule 11 e) and Review of Pool Production Factors and Issues (Rule 7(d) Midnight Sun wells are tested using the E -Pad test separator, and Midnight Sun production is processed through the GC -1 facility. Midnight Sun production allocation has been performed according to the PBU Western Satellite Production Metering Plan for the report period. Over the reporting period, the monthly average of the daily oil production allocation factors fell within the range of 0.90 and 0.99. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 7/16 — 6/17 Midnight Sun Annual Surveillance Report 4 Q Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) In 2015 P1-122, a Water -Alternating -Gas (WAG) injector, was drilled from P1 Pad (the ' only pad with Miscible Injectant nearby) to supply MI and implement enhanced oil recovery in the pool. Today development plans include prudent management of the EOR flood. Wellwork such as well sidetracks to increase recovery will be evaluated as the field matures. Future development plans are discussed in the 2017 update to the Plan of Development { for the Midnight Sun Participating Area, which was filed with the Division of Oil and ' Gas of the Alaska Department of Natural Resources on September 30, 2016, a copy of which was provided to the Commission. The Commission will be copied when the 2018 update of the Midnight Sun Plan of Development is filed with the division. i 7/16 — 6/17 Midnight Sun Annual Surveillance Report 5 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance 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 -16 29,462 76,315 322,100 346,308 0 20,857,663 66,006,661 44,631,032 95,312,844 98,172,229 59,706 17,278,278 0.86 Aug -16 31,102 74,126 315,600 0 0 20,888,765 66,080,787 44,946,632 95,312,844 98,172,229 409,283 17,687,561 0.00 Sep -16 32,948 102,398 331,140 0 0 20,921,713 66,183,185 45,277,772 95,312,844 98,172,229 449,338 18,136,898 0.00 Oct -16 42,201 96,478 404,085 444,448 17,590 20,963,914 66,279,663 45,681,857 95,757,292 98,640,389 44,269 18,181,167 0.91 Nov -16 39,615 76,149 348,636 466,481 110,980 21,003,529 66,355,812 46,030,493 96,223,773 99,186,342 -105,040 18,076,127 124 Dec -16 32,613 62,198 300,818 464,200 179,431 21,036,142 66,418,010 46,331,311 96,687,973 99,770,333 -207,081 17,869,047 155 Jan -17 31,660 57,531 265,239 507,127 74,341 21,067,802 66,475,541 46,596,550 97,195,100 100,336,535 -229,580 17,639,467 1.68 Feb -17 24,736 67,142 192,529 444,795 13,989 21,092,538 66,542,683 46,789,079 97,639,895 100,802,927 -205,439 17,434,028 179 Mar -17 30,292 30,057 73,978 466,380 98,571 21,122,830 66,572,740 46,863,057 98,106,275 101,341,455 -416,389 17,017,639 4.41 Apr -17 23,093 32,716 396,303 465,656 79,968 21,145,923 66,605,456 47,259,360 98,571,931 101,868,262 -77,807 16,939,832 117 May -17 21,137 30,974 370,019 505,279 75,962 21,167,060 66,636,430 47,629,379 99,077,210 102,433,517 -146,177 16,793,655 1.35 Jun -17 19,904 32,663 386,586 459,702 62,562 21,186,964 66,669,093 48,015,965 99,536,912 102,943,922 -74,415 16,719,240 117 Assumptions for Production Table: Oil Formation Volume Factor = 1.29 rb/stb Water Formation Volume Factor = 1.03 rb/stb Gas Formation Volume Factor = 0.798 rb/Mscf MI Formation Volume Factor = 0.59 rb/Mscf 7/16 - 6/17 Midnight Sun Annual Surveillance Report 6 Figure 1: Midnight Sun Production and Injection History 90, 000, 000 — 85,000,000 80,000,000 m 75,000,000 0 70,000,000 65,000.000 60,000,000 Z 55,000,000 50, 000, 000 m 45,000,000 40,000,000 E'35,000,000 30,000,000 25,000.000 20,000,000 p'p 15, 000.000 H v� 10,000,000 c 5,000,000 a` 0 O -5,000,000 -10,000,000 Q R q R R Q Q R R R C C C C C C N � A � Figure 2: Midnight Sun Voidage History 30,000 G1 w 27,500 U. y 25,000 p 22,500 O i 20,000 U 17,500 m 15,000 S 2, 500 D a m 10,000 m 7,500 0 5,000 2,500 co 0 m m O N (`7 t CO r m (D O ('l a CO r � '- C C C C C C C CC C C C 7/16 — 6/17 Midnight Sun Annual Surveillance Report 7 5.0 4.8 45 43 40 3.8 35 33 30m 28¢ 25m 23¢ 20¢ 1.8> 1.5 1.3 10 08 05 0.3 00 100% 90% 80% 70% 60% 50% U 40% 30% 20% 10% 0% Table I Allocation Factors Month Oil Allocation Factor Jul -16 0.95 Aug -16 0.95 Sep -16 0.91 Oct -16 0.92 Nov -16 0.91 Dec -16 0.94 Jan -17 0.90 Feb -17 0.92 Mar -17 0.95 Apr -17 0.96 May- 17 0.99 Jun -17 0.96 7/16 — 6/17 Midnight Sun Annual Surveillance Report Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS 7/16 — 6/17 Midnight Sun Annual Surveillance Report 9 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: 7. Gas Gravity: Prudhoe Bay Unit 8. Well Name and 9. API Number Prudhoe Bay Field, Midnight Sun 8050' NDss 10. Type 11. AOGCC 12. Zone 13. Perforated 14. Final Test 15. Shut -h 16. Press. 17. B.H. 18. Depth 19. Final 25-29 20. Datum 0.72 21. Pressure Number: 50xxxxxxxxxxxx See Pbol Code Intervals Date Time, Hours Surv. Type Tertp. Tool TVDSS Observed TVDSS (input) 22. Pressure at Gradient, psitft. Datum (cal) NO DASHES Instructions Top - Bottom (see Pressure at TVDSS instructions Tool Depth for codes) E-100 500292281900 W MSOP KUP 7976-8053, 8053-8067 8/12/16 531 SBI -P 127 8050 3645 8050 0.52 3645 23. All tests reported herein w ere made in accordance w ith the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. 1 hereby certify that the foregoing is true and correct to the best of my know ledge. Signature Weston Smith Title Reservoir Engineer Printed Name Weston Smith Date July 28, 2017 7/16 — 6/17 Midnight Sun Annual Surveillance Report 9 Figure 3: Midnight Sun Pressure History Midnight Sun Pressure History (measured at 8050 ft. TVDSS datum) 7/16 — 6/17 Midnight Sun Annual Surveillance Report 10 4,100 -- —r ♦ 1 I I I ♦ 1 I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I I I I ------r , ----- I --- I I I I 1 I 1 I I I I I Waterflood commences I I I ♦ I I ♦ I I I I 1 ♦I I i�■th 3,700 -------- i---------�------r--�---------�---------�---------+---------r- I I --------+--------------------------- _ I I I I I I I I I I I I I I I I I I I I I I I I I I 1 I I ♦ I I I I I I I I I I 1♦ I I I 1 I I I I I I I I I I I I I 1 I I I I I 3,500 -------- =----------------- F-;---------T--------;---------r----- ♦-- 1-------7-------------------;--------- ♦ ♦ ♦ I I 1 I I I I I I I I I I I I ♦ I 1 1 C 1 I I I I I I I ♦ I I I♦ I I 1 I + 1 1 I I____-----I I I I I I I I I I I I I 3,300--------------------r------f-�---------r---------, I 1 I I I --I - - ---- I________ I - 1I -------- I r--------�--------- I 1 I I I I I I I ♦ 1 I I 1 I ♦ ♦ I ♦ I ; ♦ 1 ♦ I 1 1 I I I♦ I I I I I 1 1 1 I 1 I I I 1 I I (y� 3, 1^^ 1 I ♦ I I I -----___1--------- L______�_J___.______L_________J___ 1 ---------- L_._______1 1 --------- 1 L.._____.___J__ I 1 1 ♦ 1 ♦ ♦ ♦ ♦ I I I I I I ♦♦ ♦ I I 1 ♦ I I I 1 I I I I I I 1 I I 1 I I I I I I I I I I I I I I 1 I I I I I I I 1 I , I I I I I 1 1 I I ♦ I I I I I I I I I I 1 I I I I I 1 I I I I I 1 ♦ I I I 1 I I I I I 1 I I 1 1 I I 1 I 1 1 I 1 I I I I I I /y I I I I I 1 I I I I I I I I 1 I I I I I 2, 700 Jan -96 Jan -98 Jan -00 Jan -02 Jan -04 Jan -06 Jan -08 Jan -10 Jan -12 Jan -14 Jan -16 7/16 — 6/17 Midnight Sun Annual Surveillance Report 10 2017 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2016 -JUNE 30, 2017 7/16 - 6/17 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) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (D)).............................................................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 8. FUTURE DEVELOPMENT PLANS...................................................................................................... 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............................................................................................................ 1 1 Table 3: Polaris monthly average oil allocation factors................................................................................... 14 2 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2017 POLARIS OIL POOL ANNUAL SURVEILLANCE REPORT 1. INTRODUCTION This Annual Surveillance Report is submitted to the Alaska Oil and Gas Conservation Commission for the Polaris Oil Pool in accordance with Commission regulations and Conservation Order 484A. This report covers the period from July 1, 2016 through June 30, 2017. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 3,891 BOPD, 3.3 MMSCFD (FGOR 857 SCF/STB), and 7,016 BWPD (WC 64%). Water injection during this period averaged 9,809 BWIPD with 1.2 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.9. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 96) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 484A. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates all valid Polaris pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period at the Pool datum of 5000 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Polaris wells due to the physical characteristics of viscous oil, three sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience cross-flow between laterals completed in different sands and uneven zonal recharge during shut-in. Injectors also suffer from slow bleed -off rates during shut-in. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) very questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build- up (PBU) pressure fall-off (PFO) data is very difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. 3 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre- production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: S -Pad North This polygon contains long term shut-in producer S-200 and low -rate jet pump producer S-201 (offline — packer leak). This is the only polygon without injection support. Pressure surveys taken over the past few years have shown little change in pressure, which is in line with minimal offtake from the polygon. The most recent pressure measurement was 2036 psi which was taken on 11/15/16. S -Pad South This polygon contains producer S -213A and is supported by injectors S -215i, S -217i and S -218i. Measured pressures in this polygon range from 1400 psi to 2400 psi. W -Pad North This polygon contains producers W-200, W-201, W-202, W-204, W-205, and W-211 and is supported by injectors W -209i, W -212i, W -213i, W -214i, W -215i, W -216i, W-2171, W -218i, W -219i, W -220i, W -221i, and W-2231. Measured pressures in this polygon range from 1600 psi to 2600 psi. In July 2013, two new matrix bypass events from the aquifer to producers W-201 and W-202 were identified. The aforementioned producers and downdip injectors W -220i and W -223i were taken offline for the second half of 2013 while remediation options were being evaluated. Subsequent production logging in W -202's Oba lateral identified the location of the matrix bypass event as well as confirmed W -201's increased water production was coming from W -202's Oba lateral via what is presumed to be a second matrix bypass event between the two producers. W -202's matrix bypass event to the aquifer was remediated in October 2015 by setting a HEX plug in the Oba lateral; W -201's matrix bypass event was remediated with the same piece of wellwork. The aforementioned remediation was initially deemed a success, but within two months watercut and water rate were once again increasing in both W-201 and W- 202. The failure mechanism was attributed to a failed swell packer in W -202's Oba lateral. In July 2016, the toe of W -202's Oba lateral was cemented off and the initial results suggests the matrix bypass remediation was a success. However, over the course of the last 12 months, liquid rate has increased dramatically suggesting the remediation has either failed or the matrix bypass event has advanced along the lateral. Options to re -treat the matrix bypass event in the Oba lateral will be evaluated. W -Pad East This polygon contains producer W-203 and is supported by injectors W -207i and W -210i. Measured pressures in the polygon range from 2100 to 2500 psi. The pressures on the upper end of the range are typical injection -induced high pressure regions around the injector, which does not represent a polygon average pressure due to the very slow pressure fall-off. 4 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Loss: No production logs were run during the reporting period. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples are later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar prep^rtics as injected water. (3) A produced U water Supply SaiTipie is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Injection Logs: No injection logs were run during the reporting period Injection logs are typically run to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real- time data has confirmed offtake from offset producers, formation and healing of MBE's, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. The current Polaris injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (D)) Polaris production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily 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. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.86 and 0.99. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) Enhanced Recovery Prosect - Waterflood: Primary production from the Polaris oil pool commenced in 1999 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to maintain reservoir pressure above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled During the reporting period, average injection rate was 9,809 BWIPD. Cumulative injection through June 2017 was 27.6 MMSTBW, which has been injected into 18 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Prosect - Miscible Infectant: In 2005, approval to implement an enhanced oil recovery project in Polaris oil pool using Prudhoe Bay miscible injectant was granted via C.O. 484A. Injection of miscible injectant began in early 2006 in the downdip portion of W Pad North. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in S Pad South, W Pad North, and W Pad East. During the reporting period, average injection rate was 1.2 MMSCFD. MI injection rate was lower than the prior reporting period due to W Pad's MI flowline being taken out of service due to corrosion under insulation. Plans are currently in place to replace a section of the 6" MI flowline inside the W Pad road 6 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT crossing by 4Q 2017. Cumulative injection through June 2017 was 6.1 BCF, which has been injected into 13 water -alternating -gas injectors. No new water -alternating -gas injectors have been placed into service during the reporting period. Reservoir Management Strategy: The objective of the Polaris oil pool reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods will be managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or "worm holes". During the reporting period, no new matrix bypass events were confirmed. 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9F) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas -oil -ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, no new responses to miscible injectant were observed. To date, in the life of the field, response to miscible injectant have been observed in the following producers: S -213A and W-204. 8. Future Development Plans Future development plans are discussed in the 2017 update to the Plan of Development for the Polaris Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2016, a copy of which was provided to the Commission. The Commission will be copied when the 2018 update of the Polaris Plan of Development is filed with the Division. 7 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 1: POLARIS 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 -16 142,337. 152,823. 131,699. 175,718. 0. 20,418,567. 18,311,390. 9,815,050. 24,222,136. 27,831,145. 160,022 5,816,112 0.53 Aug -16 137,096. 149,574. 173,005. 218,374. 0. 20,555,663 18,460,964 9,988,055 24,440,510 28,051,702 152,556 5,968,667 0.59 Sep -16 101,141 118,561. 132,628. 190,180. 0 20,656,804 18,579,525 10,120,683 24,630,690 28,243,784 93,153 6,061,820 0.67 Oct -16 141,707. 128,440. 216,159. 312,289. 11,719. 20,798,511 18,707,965 10,336,842 24,942,979 28,566,227 85,229 6,147,049 0.79 Nov -16 111,183. 88,458, 240,908. 298,126. 67,697. 20,909,694 18,796,423 10,577,750 25,241,105 28,907,953 43,555 6,190,605 0.89 Dec -16 123,833. 97,152. 230,601. 404,864. 80,271. 21,033,527 18,893,575 10,808,351 25,645,969 29,365,028 -66,544 6,124,060 1.17 Jan -17 130,440. 106,546. 239,370, 367,825. 72,832. 21,163,967 19,000,121 11,047,721 26,013,794 29,780,231 -5,894 6,118,166 1.01 Feb -17 115,478. 87,039. 226,537. 347,840 60,122. 21,279,445 19,087,160 11,274,258 26,361,634 30,167,622 -12,877 6,105,289 1.03 Mar -17 117,967, 91,508. 253,930. 350,711. 63,112. 21,397,412 19,178,668 11,528,188 26,712,345 30,559,707 14,167 6,119,456 0.97 Apr -17 109,517. 85,315. 256,491. 319,542. 37,917. 21,506,929 19,263,983 11,784,679 27,031,887 30,905,195 52,752 6,172,208 0.87 May -17 110,333. 72,146. 265,081. 321,759 23,270. 21,617,262 19,336,129 12,049,760 27,353,646 31,244,134 64,060 6,236,268 0.84 Jun -17 79,114. 39,806. 194,297. 273,230. 25,121. 21,696,376 19,375,935 12,244,057 27,626,876 31,535,169 -2,083 6,234,186 1.01 8 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY l 5, 000 - 14, 000 N u 13,000 U 12,000 0 11,000 LL 10,000 U 9,000 m 8,000 cc 7,000 6,000 IL M 5.000 m a 4,000 O 3,000 2,000 m m 1,000 0 W O N M a If) t0 W W W9 O O2? O O O O O q C C C C C C C C C C C C C C C C C FIGURE 2: POLARIS VOIDAGE HISTORY 40, 000, 000 38,000,000 36,000.000 y 34.000,000 al 32,000,000 30,000,000 28,000,000 ? 26,000.000 'E'24,000.000 �24,000.000 22,000,000 N 20,000,000 18,000,000 y 16,000,000 14,000,000 ca 12,000,000 of 10,000,000 8,000,000 c 6,000,000 a` 4,000,000 p 2,000,000 0 a)O- N M ICI CD 1� W O N M (OCc: I� rn o o q q q 4 q 4 c c c c c c c c m m m m m 10091 901/. sol/. 701/6 60'Y 501/. 40916 301/6 20% 10% 09; 2.0 1.8 f1: 1.4 06 04 02 0.0 9 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 2: POLARIS PRESSURE SURVEY DETAIL 1/1 10 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: BP Expioration (Alaska) Inc. 2. Address. P.O. Box 196612, 900 E Benson Blvd-, Anchorage, AK 99519-6612 3. Unit or Lease Name: Prudhoe Bay Lint 4. Field and Fool: Prudhoe Bay Field, Polaris Oil Pool 5. Datum Reference 5000 TVDss . Oil Gravity 15-23 7. Gas Gravity: 0.7 8 Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Fool Code 12. Zone 13. Perforated Intervals Top - Bottom TV DSS 14 Final Test Date 15 Shut -In Time, Hours 16. Press. Surv. Type (see instructions forcodes) 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) S-201 50029229870000 O 64160 OA+OBa+OBb+ OBd 49845067,5163-5170 11/15/2016 35280 SBHP 96 5000 2135 5000 0.3750 2136 S-215 50029231070000 WAG 64160 OA 4988-5002,5006-5016 10/25/2016 3576 SBHP 88 4975 1440 5000 0.4400 1451 S-215 50029231070000 WAG 64160 Oba 5032-5059 10/25/2016 3576 SBHP 92 5022 1454 5000 0.4400 1444 S-215 50029231070000 WAG 64160 Obb +Obc 5068-5085, 5119-5133 10/25/2016 3576 SBHP "A 5067 2054 5000 0.4400 2024 S-215 50029231070000 WAG 64160 Obd 5169-5196 10/25/2016 3576 SBHP NA 5151 1982 5000 0.4400 1916 S-217 50029233620000 PM 64160 OA 4960-4989 6/30/2017 2520 SBHP 88 4921 2354 5000 0.4400 2389 S-217 50029233620000 AM 64160 Oba 5007-5023 6/30/2017 2520 SBHP NA 5001 1458 5000 0.4400 1458 W-210 50029233390000 WAG 64160 OBa+OBb 4893-4928 8/20/2016 1536 SBHP WA 4884 2088 5000 0.4400 2139 W-210 50029233390000 WAG 64160 Obc 4971-4997 8/20/2016 1536 SBHP 83 4959 2380 5000 0.4400 2398 W-210 50029233390000 WAG 64160 Obd 5025-5063 8/20/2016 1536 SBHP WA 5010 2532 5000 0.4400 2528 W-218 50029234030000 WAG 64160 Oba 4948-4970 8/20/2016 1512 SBHP 81 4929 1606 5000 0.4400 1637 W-218 50029234030000 WAG 64160 Obc 5032-5055 8/20/2016 1512 SBHP 81 5006 1650 5000 0.4400 1647 W-218 50029234030000 WAG 64160 Obd 5087-5127 8/20/2016 1512 SBHP 81 5092 1902 5000 0.4400 1862 W-220 50029234320000 WAG 64160 Oba 5142-5166 10/4/2016 648 SBHP 78 5117 2385 5000 0.4400 2334 W-220 50029234320000 WAG 64160 Obd 5278-5311 11/19/2016 2496 SBHP 88 5280 2679 5000 0.4400 2556 W-220 1 50029234320000 WAG 64160 Obc 5228-5251 2/17/2017 2784 SBHP 79 1 5199 2335 5000 0.4400 j 2247 23. All tests reported herein w ere made in accordance w ith the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Comnission. I hereby certify that the foregoing is true and correct to the best of my know ledge. Signature Ken Huber Title Printed Name Ken Huber Date Resemir Engineer July 26th, 2017 10 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 11 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT ?900 '1800 '2700 21'600 ''500 2400 • 5.2,6 • W.209 • W-209 ••W'�113 • W -2t • W-210 • • W-220 ?300 �'A • S- ,5 ♦ WiNato ♦ V�2o*22102,0 • W-210 20- 2 • 215 • • W-223 W.210.3 •2 W-219 ii • W-200 S•�Wii4f09 • S-2te •.:•� W-214 • S -2t7 NWS. ° ,��pt'� ♦ �j 2 •4yYW215 WW -2 W-213• 77 1 00 • S-200 • W-211 • W-205 • W-215 • VV -205 • W-210 ♦ S-218 S.218 • W202 W ')100* W • 205 • W-205 205 W2t8 213 W-212 W , • • • Szz18• 5.218 S -*8 W205 • S -*7 W• -205 W�218 •• yy. ,t S-215 • 8-213 • 5-215 • S 2i8 • SQO� S-201 ��//�� 1r/ • S 200 • S-200 • 5.213A • S -2t7 • S-115 • W216 w1� tp • W�204 • >�195'ZOT • W.205• • W-20 5.201 N ?(� 000 • S-201 • S-215 21 2 1 - 11 •�•2 Y7� • S-217 L W-203 .� 1 • S-217• 1! 4.217 • • ♦ dtS w205 • W218 • S-215 �- 1900 • S-201 217 ^''S? • W ♦ W-217 • • 5201. • W 213 • 5.217 • w.2• • W.218 • S-201 g • W 205 205 .2°1 • 5.201 • $. • W-218 • W-210 • W-205• 5201 • S-217 • W-202 1800 S • W 201 • W-210 • S-215 • W,2� W216 • •N -]B000 • W-20# W-200 700 • W-200 • W-201 • W-200 NW"a • 0-2102,6 • W-200 • W-204 (� 600 • • 5213 S -213A • W-204 • W-204 ♦ w-200 1500 W-202 • •.. SJ • S•2* 1400 r O 00 O 0) a) O O c1l O O r" I_r) CO rl- 00 m O r c•' I M O O O O O O O I_0 CO r - c c c c c c1 C C C C C C C C C C C (B C C C C Survey Date 11 7/16 — 6/17 POLARIS ANNUAL SURVEILLANCE REPORT FIGURE 4: POLARIS PRESSURES IN MAP VIEW 12 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT III a 1 s , �217� a `'?' m \ w -m wzMNz • � �Z179 - Yit AW219 ilt$_ t i NF�K wrl • w�ti l " s 1,10 ti - - - 2155 t Polaris Field 12 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -16 0.99 Aug -16 0.92 Sep -16 0.94 Oct -16 0.96 Nov -16 0.88 Dec -16 0.86 Jan -17 0.89 Feb -17 0.90 Mar -17 0.86 Apr -17 0.88 May -17 0.90 Jun -17 0.88 13 7/16 - 6/17 POLARIS ANNUAL SURVEILLANCE REPORT 2017 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1, 2016 -JUNE 30, 2017 7/16 - 6/17 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) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4, PART (F))...............................................................6 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY(RULE 9E)...........................................................................................................7 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) ........8 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS(RULE 9G).........................................................................................................8 9. FUTURE DEVELOPMENT PLANS............................................................................................................... 9 LIST OF ATTACHMENTS Figure 1: Orion production and injection history ................................................................11 Figure 2: Orion voidage history .......................................................................................... I 1 Figure 3: Orion pressures at datum.....................................................................................15 Figure 4: Orion pressures in map view...............................................................................16 Table l: Orion monthly production and injection summary ...............................................10 Table 2: Orion pressure survey detail.................................................................................12 Table 3: Orion monthly average oil allocation factors........................................................17 2 7/16-6/17 ORION ANNUAL SURVEILLANCE REPORT PRUDHOE BAY UNIT 2017 ORION OIL POOL ANNUAL SURVEILLANCE REPORT 1. INTRODUCTION This Annual Surveillance Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 9 of Conservation Order 505B, and covers the period from July 1, 2016 to June 30, 2017. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9 During the reporting period, field production averaged 3,469 BOPD, 3.9 MMSCFD (FGOR 1,112 SCF/STB), and 5,619 BWPD (WC 62%). Water injection during this period averaged 12,190 BWIPD with 4.2 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.4. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. Production and injection for V -Pad was shut-in, isolated, and brought to a safe state in June 2016 due to piping over stress findings from an engineering study. The study was commissioned to analyze subsidence and the potential for surface piping stress that was visually recognized across the pad, and which was confirmed by the engineering model from the study. Therefore, in order to mitigate the risk of a loss of primary containment, the pad was shut in while a plan to safely return production/injection is developed. V Pad surface repairs were completed as planned in 4Q 2016. V Pad production was ramped up starting in 40. 2016 with all of the wells back online in 1Q 2017. Surface subsidence issues are now being managed on an ongoing basis as the need arises for specific well line and wellhouse levelling/ replairs. 3. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 98) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 5056. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. Figure 3 illustrates valid Orion pressure data acquired since field inception, whereas Figure 4 shows a map of the pressures acquired during this reporting period interpolated to the Pool datum of 4400 ft TVDss (true vertical depth subsea). Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers 3 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT experience crossflow between laterals completed in different Schrader Bluff sands while shut-in, which can result in uneven zonal recharge. Injectors also suffer from slow bleed -off rates. Most injectors now incorporate check valves in the waterflood regulators to limit cross flow, but cross flow can occur where check valves are not present or not holding. These phenomena combine to make the quality of pressure transient analysis (PTA) questionable, and therefore, extrapolating a representative average reservoir pressure from pressure build-up (PBU) or pressure fall-off (PFO) data is difficult. In order to mitigate these concerns, single point pressure surveys are obtained whenever possible after a well has been offline for several weeks or months to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre -production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is becoming increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analysis of the recent pressure data by polygon follows: Polygon 1 This polygon contains producer L-200 and is supported by injectors L -211i, L -212i, and L -218i. Measured pressures in the polygon range from 2000 - 2300 psi. During the reporting period, there was no production or injection due to producer L-200 being offline for sanding issues. Poylgon 1A This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-2151, L-2161, L -217i, L -219i, and L -223i. Measured pressures in the polygon range from 1900 psi to 2200 psi. During the reporting period, producer L-203 was offline for sanding issues and L-250 was returned to production after a profile modification was performed in August '16. Consequently, offset injectors were cycled on and off to balance voidage. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L -213i, V -210i, V - 211i, V -212i, V -213i, V -214i, V -215i, V -216i, V -217i, V -218i, V -222i, V -223i, V -225i, V -229i. Measured pressures in the polygon range from 1300 psi to 2300 psi. The lowest pressure in the polygon was observed to be injector V-222i's OA sand. In 2012, a matrix bypass event was identified in the OA sand between producer V-202 and injector V -222i. The OA sand in injector V -222i was subsequently isolated by replacing the waterflood regulating valve with a dummy valve, thus allowing the injector to remain online while remediation options were evaluated. The matrix bypass event was remediated in early 2014 and by all accounts the wellwork appears to be a success as a reduction in OA sand injectivity was observed. To date, no significant increase in OA reservoir pressure has been observed. 4 7/16 - 6/17 ORION ANNUAL SURVEILLANCE REPORT During the prior reporting period, a matrix bypass event was confirmed in V-214i's OA sand in May '17. Options to remediate the matrix bypass event will be evaluated. Polygon 2A This polygon contains producers L-201, L-204, and V-207 and is supported by injectors L -210i, L-214Ai, L- 222, V -219i, V -220i, V -221i, V -224i, and V -227i. Measured pressures in the polygon range from 1100 psi to 2400 psi. One of the lowest pressures in the polygon was observed at producer L-204. As reported previously, producer L-204 is located in an isolated fault block receiving minimal injection support from offset injectors L -214A and V-220. Due to the narrow size of the fault block, there is insufficient space to place additional injectors to provide full injection support. Producer L-204 was cycled on in April '16 and remained online until March '17. The most recent reservoir pressure for L-204 is 1118 psi. Polygon 5S This polygon contains producer L-205 and is supported by injectors L -220i and L -221i. Measured pressures in the polygon range from 2000 psi to 2100 psi. During the reporting period, there was no production or injection due to producer L-205 being offline for sanding issues. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS, AND SPECIAL MONITORING (RULE 9C) Production Loas: During the reporting period, a production log was run in August 2016 in L-250. The primary goal of the logging job was to identify the location of the matrix bypass event in the OA lateral. The logging job was successful in identifying the entry point of the matric bypass event. However, remediation of the matrix bypass event was deferred as the additional water production increased the wellhead temperature, thereby reducing the well's propensity to form hydrates in the tubing. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well Fluids Sampling: A well fluids sampling program is ongoing to gather high quality and high frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples is later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). 5 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT Geochemical Fingerprinting: This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Injection Logs: No injection logs were run during the reporting period. Injection logs are used to quality check waterflood regulating valve performance while in water service or to determine the distribution of miscible injectant between zones. Real-time Downhole Pressure Gauges in Injectors: Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real-time data has confirmed offtake from offset producers, formation and healing of MBE's, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection regulators. 5. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 9D) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4. PART (F Orion production allocation is performed in accordance with the PBU Western Satellite Production Metering Plan, subject to ongoing review and approved changes. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC -2 allocation factor is applied to adjust production on a daily basis. A minimum of one well test per month is used to check the performance curves, and to verify system performance, with more frequent testing during new well start- up and after significant wellwork. In an effort to improve well test quality, Weatherford Generation 2 multi -phase meters (Gen 2) were installed at the L -pad and V -pad test headers. In 2012, the V -pad Gen 2 meter was accepted as the primary metric for production allocations, and the V -pad Well Pad Separator was taken out of service. Reliability issues with the L -Pad Gen 2 meter have led to an increased use of the Well Pad Separator for allocation on many of the wells. The disagreement between the Gen 2 meter and Well Pad Separator has led to the need for portable well tests to determine which meter is more accurate for each well. These portable tests have been used along with the routine Gen 2 and Well Pad Separator tests to allocate well production rates. A project has been initiated to solve the L & V metering reliability issues by phasing out the Gen 2 meters and upgrading/reinstating the Test Separators with modern flow measurement components that are easily maintained. Although the Gen 2 meters function well when all components are maintained and calibrated, the ongoing maintenance and reliability issues have proven to be detrimental to the overall metering 6 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT health of L & V Pads. The expertise and equipment necessary to keep the Gen 2 meters functioning have proven to be too specialized, causing lapses in calibration and maintenance. The project to replace the meters is expected to be complete in 2018. During the reporting period, tests were obtained with a portable test separator to check the accuracy of the on -pad metering and adjust allocation curves as needed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.86 and 0.99. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 6. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9E) Enhanced Recovery Proiect - Waterflood Primary production from the Orion oil pool commenced in 2002 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 12,190 BWIPD. Cumulative injection through June 2017 was 46.7 MMSTBW, which has been injected in 36 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Project - Miscible Infectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began later that year in the updip portion of Polygon 2. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 1A, Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 4.2 MMSCFD. Cumulative injection through June 2017 was 24.6 BCF, which has been injected in 25 water -alternating -gas injectors. No new water - alternating -gas injectors have been placed into service during the reporting period. However, L-217 did inject its first slug of MI starting in March '17. Reservoir Management Strate 7 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. Key to this is achieving a balanced voidage replacement ratio required to keep reservoir pressure above the bubble point. Individual floods are managed with downhole waterflood regulating valves in the injectors, as well as limited capabilities of reducing offtake in the producers by shutting in or choking laterals. Learnings over the last few years have revealed significant differences in productivity and oil mobility between Schrader Bluff sands. These learnings have led to changes in completion designs and operational strategies. In addition, the emergence of matrix bypass events has further highlighted the complexity of the Schrader Bluff sands. It is expected that the reservoir management strategy will continually be evaluated and revised as appropriate throughout the life of the field. Matrix Bypass Events: As described in prior reports, the phenomenon of premature water breakthrough between a producer and a water source (water injector or aquifer) challenges the North Slope viscous oil developments. These events appear to have a multitude of probable causes: faults, fractures, matrix short-circuit through high perm streaks, and what is believed to be the creation of tunnels or "worm holes". During the prior reporting period, a matrix bypass event was confirmed in V-214i's OA sand in May '17. Options to remediate the matrix bypass event will be evaluated. 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F) New Sands: As mentioned in previous reports, Orion includes three wells with slotted liner completions in the N -sand; L-203, L-205, and V-207. 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 9G) A response to miscible injectant is indicated by an increase in produced gas rate, an increase in formation gas -oil -ratio, and a reduction in the producing ratio of C1 (methane) to C3 (propane). During the reporting period, L -202's formation gas -oil -ratio has increased and its C1:0 ratio has decreased, which is a good indication of production response to the recent slug of miscible injectant injected into L-217. To date, in the life of the field, responses to miscible injectant have been observed in the following producers: L-201, L-202, V-202, V-203, V-204, V-205, and V-207. 8 7/16 - 6/17 ORION ANNUAL SURVEILLANCE REPORT 9. FUTURE DEVELOPMENT PLANS Future development plans are discussed in the 2017 update to the Plan of Development for the Orion Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2016, a copy of which was provided to the Commission. The Commission will be copied when the 2018 update of the Orion Plan of Development is filed with the Division. 7/16 — 6/17 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 -16 58,683, 42,517 60,306. 313,316 0 33,848,196. 32,045,079 11,061,114 42,568,669 56,598,056 -181,521 994,341 2.35 Aug -16 63,992. 55,999. 64,203. 283,651. 20,207. 33,912,188 32,101,078 11,125,317 42,852,320 56,896,466 -148,650 845,691 1.99 Sep -16 56,071, 57,191. 97,949. 169,370. 77,096. 33,968,259 32,158,269 11,223,266 43,021,690 57,113,016 -38,425 807,265 1.22 Oct -16 88,417. 80,068, 151,974. 176,071. 86,985. 34,056,676 32,238,337 11,375,240 43,197,761 57,342,169 43,256 850,521 0.84 Nov -16 135,723. 190,987. 167,305. 277,461. 120,649. 34,192,399 32,429,324 11,542,545 43,475,222 57,693,588 40,265 890,786 0.90 Dec -16 140,447. 232,975. 250,739. 479,920. 82,379. 34,332,846 32,662,299 11,793,284 43,955,142 58,226,911 -28,769 862,018 1.06 Jan -17 139,581. 229,071. 252,512. 442,101. 128,676. 34,472,427 32,891,370 12,045,796 44,397,243 58,749,352 -19,101 842,917 1.04 Feb -17 120,573. 107,658. 176,359. 336,485. 175,055. 34,593,000 32,999,028 12,222,155 44,733,728 59,192,484 -103,750 739,167 1.31 Mar -17 116,540. 111,633. 193,960. 537,937. 129,588. 34,709,540 33,110,661 12,416,115 45,271,665 59,812,257 -263,538 475,629 1.74 Apr -17 113,655. 86,941 220,031, 517,514. 168,908. 34,823,195 33,197,602 12,636,146 45,789,179 60,434,602 -255,107 220,522 169 May -17 139,246. 119,300. 245,522. 464,179. 297,611, 34,962,441 33,316,902 12,881,668 46,253,358 61,079,013 -213,168 7,354 149 Jun -17 93,392. 93,646. 170,155. 451,397. 254,476. 35,055,833 33,410,548 13,051,823 46,704,755 61,685,065 -303,236 -295,882 200 10 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 25.000 m w -2,500 LL U y 20,000 m O 17,500 LL U 15000 m 12,500 10,000 CL m m 7,500 m m O 5,000 `m 2.500 R 0 9 O 9O 9 9 9 9 _O N 2 <_ <2 t2 1� C C C E C C C C E C C C C C E FIGURE 2: ORION VOIDAGE HISTORY 60, 000, 000 m U) 55,000,000 cl m 50, 000, 000 m j 45, 000, 000 d Z 40,000,000 35, 000.000 M 30,000,000 G m 25, 000.000 m 3: 20, 000.000 a'! m 15, 000, 000 F 10, 000, 000 0 d 5,000,000 O 0 R o 4 R 9 9 q c? co m m m m m m m m m 100% 90% 80% 70% 60% 50% U 3 40% 30% 20% 10% 0% 3.0 2.8 2.5 23 20 7/16 — 6/17 ORION ANNUAL SURVEILLANCE REPORT 0.8 05 03 00 11 TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 1/3 12 7/16 — 6/17 PBU Orion Annual Reservoir Report STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1 Operator 2 Address BP Exploration (Alaska) Inc I PO 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 7 Gas Gravity Prudhoe Bay Und Prudhoe Bay Field, Orion Oil Pool 4400 TVDss 1523 0.7 8 Well Name and 9 AR Number 10. Type 11. AOGCC 12. Zone 13 Perforated Intervals 14 Rnal Test 15. Shut -In 16 Press 17 BH 18 Depth 19 Final 20 Datum 21 Pressure 22 Pressure at Number 50xxxxxxxxxxxx See Pool Code Top - Bottom TVDSS Date Time, Hours Sury Type Temp Tool TV CSS Observed TV DSS (input) Gradient, PsiMt. Datum (cal) NO DASHES Instructions (see Pressure at instructions Tool Depth for codes) L-200 50029231910000 O 640135 OBa+OBb+OBd 4267-4147,4312-4189, 8/212016 36288 SBHP 82 4142 2218 4400 0.4000 2321 4407-4278 43554397, 4409-4474, OA 4407-4482,4509-4540, L-204 50029233140000 O 640135 4453-4577,4525-4641, 6/302017 2496 SBHP 83 4204 1040 4400 0.4000 1118 +OBd 45554567,4574-4648, 4653-4691 4188-4183,4173-4190, 0A+OBa+ 42284248, 4237-4239, L-205 50029233880000 0 640135 4272-4285,4394-4364, 10212016 36504 SBHP WA 3028 1552 4400 0.4000 2101 OBb+OBc+OBd 43284350, 4392-4395, 4393-4393,4385-4406 L-211 50029231970000 WAG 640135 Obd 4240-4248 4249-4257 9/162016 36336 SBHP WA ® surface 28 4400 0.4240 1926 4262 - 4269 4274 - 4282 L-219 50029233760000 WAG 640135 OA 4413-4445 6/302017 11784 SBHP 83 4362 1 1878 4400 0.4400 1895 L-219 50029233780000 WAG 640135 Doe 4480-4492 6/302017 11784 SBHP 87 4470 1880 4400 0.4400 1849 4661-4665,4669-4672, 4676-4679,4683-4685, 46884690, 4691-4692, L-219 50029233760000 WAG 640135 Obd (oil) 4693-4693, 4762-4691, 6/302017 11784 SBF_P WA 4652 2000 4400 04400 1889 4691-4690,4689-4688, 4687-4686,4686-4686, 46884687, 4689-4690, 4691-4692 L-220 50029233870000 WAG 640135 Nb 4116-4136 8232016 51528 SBHP 82 4052 1832 4400 0.4397 1985 L-220 50029233870000 WAG 640135 OA 4250-4291 8232016 51528 SBHP 86 4203 1868 4400 04416 1955 L-220 50029233870000 WAG 640135 Oba 4318-4347 8232016 51528 SBHP 89 4308 1994 4400 0.4348 2034 L-220 50029233870000 WAG 640135 Obb+Obc 4360-4377,4414-4431 8232016 51528 SBHP 90 4362 2012 4400 0.4474 2029 L-220 50029233870000 WAG 640135 Obd 4466-4511 8232016 51528 SBHP 89 4457 1994 4400 04386 1969 L-220 50029233870000 WAG 640135 Nb 4116-4136 2/92017 3648 SBHP 82 4052 1830 4400 04397 1983 L-220 50029233870000 WAG 640135 OA 4250-4291 2/92017 3648 SBHP 87 4203 1892 4400 0.4416 1979 L-220 50029233870000 WAG 640135 Oba 4318-4347 2/92017 3648 SBHP 90 4308 2007 4400 0.4348 2047 L-220 50029233870000 WAG 640135 Obb+Obc 4360-4377,4414-4431 2/92017 3648 SBHP 90 4362 2015 4400 0.4474 2032 L-220 50029233870000 WAG 640135 Obd 4466-4511 2/92017 3648 SBHP 89 4457 1999 4400 04386 1974 L-221 50029233850000 WAG 640135 Nb 4090-4105 7242016 32544 SBFP 83 4038 1829 4400 04392 1988 L-221 50029233850000 WAG 640135 OA 4222-4258 7242016 32544 SBFIP 86 4176 1860 4400 04375 1958 L-221 50029233850000 WAG 640135 Oba 4285-4316 7242016 32544 SBHP 88 4276 1975 4400 0.4435 2030 L-221 50029233850000 WAG 640135 Obb+Obc 4329-4343,4382-4401 7242016 32544 SBHP 89 4329 1 2008 4400 1 04366 2039 L-221 50029233850000 WAG 640135 Obd 4433-4481 7242016 32544 SBFP 91 4426 1982 4400 04231 1971 L-221 50029233850000 WAG 640135 Nb 4090-4105 292017 4656 SBHP 83 4038 1826 4400 0.4392 1987 L-221 50029233850000 WAG 640135 OA 4222-4258 292017 4656 SBHP 86 4176 1877 4400 0.4375 1975 L-221 50029233850000 WAG 640135 Oba 4285-4316 292017 4656 SBHP 88 4276 1977 4400 0.4435 2032 L-221 50029233850000 WAG 640135 Obb+Obc 4329-4343,4382-4401 2912017 4656 SBHP 89 4329 2002 4400 0.4366 2033 L-221 50029233850000 WAG 640135 Obd 1 4433-4481 292017 4656 SBHP 91 4426 1986 4400 0.4231 1975 12 7/16 — 6/17 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 2/3 13 7/16 — 6/17 PBU Orion Annual Reservoir Report STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT . 1Operator 2. Address: BP Exploration(Alaska) Inc UL 3. Unit or Lea Name: P.O. Box 196612, 900 E Benson Blvd., Anchorage, AK 99519-6612 Prudhoe Bay !.hit 4. Feb and Pool: 5. Datum Reference. 6. Oil Gravity: 7. Gas Gravity: 8. Well Name and 9. AR Number 10. Type 11. AOGCC 12. Zone 13. Perforated Intervals 14 Final Test Prudhoe Bay Field, Orion Oil Pool 15. Shut 16. Press. 4400 TVDss 1523 0.7 Number 50XXXXXXXXXXXX See Pool Code -In 17. B.H. 18. Depth 19. Final 20. Datum 21. Pressure 22. Pressure at NO DASFES Instructions .p Bottom Date Time, Hours Sury.Type Temp. Tool TVDSS Observed TVDSS(input) Gradient,psilft- Datum (cal) (see Pressure at instructions Tool Depth L-222 50029234200000 WAG 640135 Oba 4378-4412 2/142017 1080 for codes) SBHP 103 4370 2069 4400 0.4400 L-222 50029234200000 WAG 640135 Obb+Obc 4427-4435,4466-4482 2/142017 1080 SBFp 103 4433 2040 4400 2062 L-222 50029234200000 WAG 640135 Obd 4521-4571 2/142017 1080 SBHP 103 4514 2078 4400 0.4400 0.4400 2025 L-222 50029234200000 WAG 640135 OA 4307-4347 2272017 1392 SBHP 102 4286 1371 4400 0.4400 2028 1421 L-223 50029234150000WAG 640135 Nb 4377-4396 2222017 64200 SBHP 84 4339 1965 4400 0.4400 1992 L-223 50029234150000 WAG 640135 pA 4502-4538 2222017 64200 SBHP 89 4477 2028 4400 0.4400 1994 L-223 50029234150000 WAG 640135 Oba 4567-4599 2222017 64200 SBHP 91 4560 2062 4400 0.4400 1992 L-223 50029234150000 WAG 64 0135 Obc 4667-4686 2222017 64200 SBHP 92 4642 2037 4400 0.4400 1931 L-223 50029234150000 WAG 640135 Obd 4717-4765 2222017 64200 SBFp 93 4714 2020 4400 0.4400 1882 L-250 50029232810000 O 640135 Nb 4199-4269,4208-4281 8/182016 10032 SBFP 99 4123 2050 4400 0.4000 2161 V-202 50029231530000 O 640135 O4+Oba+Obd 4320-4350 4380-4437 10262016 3144 SBFP 75 4250 4543-4579 1287 4400 0.0199 1290 V-202 50029231530000 O 640135 pA+Oba+Obd 4320-4350 4380-4437 1172017 1032 SBHP 69 4250 4543-4579 1288 4400 -0.0239 1285 OA+OBa+ 4249-4274,4306-4331, V-203 50029232650000 O 640135 OBb+OBc+O� 4342-4365,4397-4426, 8272016 216 SBHP 81 4125 1249 4400 0.4000 1359 44554486 V-204 50029232170000 O 640135 OA+Oba+Obb+Obd 4315-4424 4388-4490 10272016 3192 SBHP 81 4250 1521 4400 4442 - 4522 4558 - 4619 0.2069 1552 4395-4404,4393-4435, V-205 50029233380000 O 640135 OA+OBa+OBd1 4452-4452,4458-4470, 3252017 2568 SBHP 81 4269 1850 4400 4498-4505, 4514-4511, 0.4000 1902 4588-4618, 462G 4617 4452-4443,4445-4434, 4440-4431,4646.4644, V-207 50029233900000 O 640135 Nb+OBa+06b+OBd 4652-4631,4636-4643, +Obe 4696-4684,4681-4654, 8/132016 1368 SBHP 90 4407 1238 4400 0.4000 1235 4678-4665,4803-4802, 4805-4793,4779-4785, 47834782,4844-4827 V-215 50029233510000 WAG 640135 OA 4370-4404 6/302017 1 18264 SBHP 81 4347 1833 1 4400 0.4400 1856 V-217 50029233340000 WAG 640135 Oba+Obb 74416-4443,4456-4472 11/302016 3936 SBHP 81 4422 1679 4400 0.4400 1669 V-219 50029233970000 WAG 640135 Nb 4434-4450 10252016 3120 SBFP 89 4416 1683 4400 0.4400 1676 V-219 50029233970000 WAG 640135 Oba 4626-4654 10252016 3120 SBHP 89 4613 1761 4400 0.4400 1667 V-219 50029233970000 WAG 840135 Obb 4667-4680 1025x2016 3120 SBFp 90 4665 1815 4400 0.4400 1698 V-219 50029233970000 WAG 640135 Obd+Obe 4769-4810,4842-4866 10252016 3120 SBHP 82 4752 1965 4400 0.4400 1810 V-220 50029233830000 WAG 640135 Nb 4351-4367 11/152016 1536 SBHP 95 4328 1836 4400 0.4400 1868 V-220 50029233830000 WAG 640135 O4 4486-4525 11/152016 1536 SBFP 90 4465 2425 4400 0.4400 2396 V-220 50029233830000 WAG 640135 Oba 4554-4563 11/152016 1536 SBHP 97 4544 1926 4400 0.4400 1863 V-220 50029233830000 WAG 640135 Obb+Obc 4598-4616,4658-4678 11/1512016 1536 SBFp 97 4597 2023 4400 0.44 1936 V-220 50029233830000 WAG 640135 Obe 4774-4793 6262017 4672 $BHP 97 4775 2014 4400 0.4400 1849 V-22050029233830000 WAG 640135 Obd 4710-4748 6272017 19560 SBHP 97 4703 1554 4400 0.4400 1421 13 7/16 — 6/17 PBU Orion Annual Reservoir Report TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 3/3 23 All tests reported herein w ere made in accordance w ith the applicable rules, regulations and instructions of the Alaska OI and Gas Conservation Commsson. I hereby candy that the foregoing is true and correct to the best of my know ledge Signature Ken Huber Title Resenair Engineer Printed Name Ken Huber Date July 26th, 2017 14 7/16 — 6/17 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 Lind 4 Field and Pool Prudhoe Say Field, Orion Oil Pool 5. Datum Reference. 4400 Noss 6. 09 Gravity. 15-23 7 Gas Gravity. 0.7 8 Well Nacre and Number 9. AR Number 5oxxxxxxxxxxxx NO DASHES 10 Type See Instructions 11- AOGCC Pool Code 12. Zone 13 Perforated Intervals Top - Bottom NDSS 14. Final Test Date 15 Shut -In Time, Hours 16. Press Sury Type (see instructions for codes) 17 B.H. Tenp 18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum NOSS (input) 21 Pressure Gradient, psdf t. 22. Pressure at Datum (cal) V-222 50029233570000 WAG 640135 OA 4326-4364 10/172016 2904 SBHP 82 4248 1226 4400 0.3355 1277 V-222 50029233570000 WAG 640135 Oba 4393-4421 10/172016 2904 SBHP WA 4376 1450 4400 0.4583 1461 V-222 50029233570000 WAG 640135 Ob1b+Obc 4433-4450,4485-4503 10/172016 2904 SBHP 84 4433 1729 4400 0.4545 1714 V-222 50029233570000 WAG 640135 Obd 4448-4578 10/172016 2904 SBHP WA 4532 1758 4400 0.4394 1700 V-223 50029233840000 WAG 640135 GA 4419-4458 10242016 3072 SBHP 179 4397 1835 4400 0.4400 1836 V-223 50029233840000 WAG 640135 Oba 4485-4513 10242016 3072 SBHP 1 80 4471 1825 4400 0.4400 1794 V-223 50029233840000 WAG 640135 Obd 4632-4674 10242016 3072 SBIHP 86 4616 1795 4400 0.4400 1700 V-224 50029234000000 WAG 640135 fob 4466-4485 2232017 3912 SBHP 90 4450 1550 4400 04400 1528 V-224 50029234000000 WAG 640135 Oba 4674-4704 2232017 3912 SBHP 91 4624 1425 4400 0.4400 1326 V-224 50029234000000 WAG 640135 Obb 4718-4736 2232017 3912 SBHP 91 4718 1552 4400 04400 1412 V-224 50029234000000 WAG 640135 Obd 4832-4881 2232017 3912 SBHP 91 4801 1810 4400 04400 1634 V-224 50029234000000 WAG 640135 Doe 4903-4928 2232017 3912 SBHP 91 4901 2094 4400 0.4400 1874 V-225 50029234190000 WAG 640135 O4 4330-4365 10242016 3072 SBHP 94 4281 1983 4400 0.4400 2035 V-225 50029234190000 WAG 640135 Oba 4394-4420 10242016 3072 SBHP 95 4379 2310 4400 04400 2319 V-225 50029234190000 WAG 640135 Obd 4531-4576 10242016 3072 SBFP 93 4522 1872 4400 04400 1818 V-227 50029234170000 VIA 640135 Nb 4449-4462 6/302017 52624 SBHP 88 4403 1871 4400 0.4400 1870 V-227 50029234170000 W 640135 Oba 4634-4662 6/302017 52824 SBHP 91 4596 1527 4400 0.4400 1441 V-227 50029234170000 W 640135 Obd 4790-4837 6/302017 52824 SBHP 94 4673 1868 4400 0.4400 1748 V-227 50029234170000 VVI 640135 Obb 4677-4695 6/302017 52824 SBHP 93 4760 1684 4400 0.4400 1526 V-227 50029234170000 Vv1 640135 Obe 4854-4876 6/302017 52824 SBHP 97 4854 2042 4400 0.4400 1842 V-229 50029234640000 WAG 640135 OA 4339-4377 9292016 2496 SSFP Be 4325 1406 4400 0.4400 1439 V-229 50029234640000 WAG 640135 Oba 4403-4431 9292016 2496 SBHP 92 4395 1361 4400 0,4000 1363 V-229 50029234640000 WAG 640135 Obb 4446-4464 9292016 2496 SBHP 92 4446 1828 4400 0.4348 1808 V-229 50029234640000 WAG 640135 Obc 4505-4515 9/2 16 2496 SBHP 95 4499 1921 4400 0.4444 1877 V-229 50029234640000 WAG 640135 Obd 4505-4515 9292016 2496 SBHP 92 4594 1 1857 1 4400 0.3454 1790 23 All tests reported herein w ere made in accordance w ith the applicable rules, regulations and instructions of the Alaska OI and Gas Conservation Commsson. I hereby candy that the foregoing is true and correct to the best of my know ledge Signature Ken Huber Title Resenair Engineer Printed Name Ken Huber Date July 26th, 2017 14 7/16 — 6/17 PBU Orion Annual Reservoir Report FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 2700 - -- -- - - --- - 2600 2500 • V.21b 24004200 . v-218 2300 • 4212 . L205 • L-200 2200 • L-211 • L206 ♦ 4218♦ 4221 2100 ♦ L-217 L-22 1 0 • V22' 4211 ♦ L-250 222t9 •:w Y, • 4200 • L-200 • V -219F ♦ *206-205 . �-28Q125 • V-225 0-2000 ♦ V100 ♦ L. 17 1 • L-221 t: 7 5 -200 '2�g �1� `,- V-'' ♦L 2zv3-zo7 � 4220 � �L. 2a� Lwy�� 2 07 V.'ZR31 V.214 LIyS�_O`4216& L122� L-218 M U204 L_'25 • •20@1'.21* *2*j�2�23 t: pry�ys�� • 2b87q L i 1900 _2) + Wo ♦1000 �21�21b♦ • L-213 L-204 AL •-$.' QO V•274223 • L-223 ♦#-2C-27�• L223 23VO 4223 i VIlID@ ♦ V.2�3 ♦ 4218 .•V'29hl • 4211 V Z1♦6 �� ♦ 4217 L ♦ V.218 ♦ L-205 ~ ~ Z00 ♦ R.- Q ♦ V 216 ��ryry55 v2w 2� V.2 � �L.2 4 N 18 0 0 ♦ V.212 * L� V 22#V� V♦18 V -22q X20 ♦ V-227 ♦ V21. V-2 420 `-'L 206 • V-210 5 ,,AA Y/ • V-210 ♦ 11204 4200 ♦ V-203 • � . V-223 ♦ 1122314 Vk-2� 11.223 ` V223 ♦ 4222 •• t` V -21B 4-2$218 i 1700 • V-217 ♦ V1ee V-214 ♦ V-225 V217 20. V'?,-' ♦ L203 ♦ V-2� . �L�gl . V2t7 22 .205'-21G 2 ♦ �21y1p11 4$ Vq� • M20V j27 V-2 7 1600 05 . L♦13V-217 ♦ V2,W •••V la • L-222 ♦ V-2 0 �J��2 ♦ V-228 ~ V-227# ♦ V-222 22 �.,�y • L-206 • •' 2;4203 L 22' 1#241?l£ 224 1 500 • V-22,* V-218 ♦ V-224 V-213 V-214 •. V.b*3• V.20 . 11222 14 0 0 V 203 ••LMS 11 • �03L2� !{� f0 1 300 • V-220707 ♦ 11207 •41k'2"m ♦ V-203 •♦V'2n02 1200 ♦ K207 1 1 0 0 ♦ 4204 • L- 4 �— N M C9 r` 00 (3i d N M Lr) Cfl f� O O O I i 1 O O O I I O O O c— .— I I I I 1 I 1 1 1 I 1 1 cB M M m cu cB cv M cv cv M Survey Date 15 7/16 — 6/17 PBU Orion Annual Reservoir Report FIGURE 4: ORION PRESSURES IN MAP VIEW Mi4Ct-0t 1711 �Lstia �� -ris y_y-201L1 low �1� GS *212 ) ism �� yS Im \ ' t71• SS w2t7 1 �� 'arh13S Won Field MAP 1 16 7/16 — 6/17 PBU Orion Annual Reservoir Report TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -16 0.99 Aug -16 0.92 Sep -16 0.94 Oct -16 0.96 NOVA 6 0.88 Dec -16 0.86 Jan -17 0.89 Feb -17 0.90 Mar -17 0.86 Apr -17 0.88 May -17 0.90 Jun -17 0.88 17 7/16 — 6/17 PBU Orion Annual Reservoir Report 2017 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2016 -JUNE 30, 2017 1. INTRODUCTION........................................................................................................................................3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY(RULE 9A)................................................................................................................................3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) ..................................4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) ..........................................5 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D)................................................................5 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTIN ALLOCATION FACTORS AND ISSUES (RULE 4G) .....................................................5 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F AND 9G) ..................6 LIST OF ATTACHMENTS Figure 1: Borealis production and injection history..........................................................................................8 Figure 2: Borealis voidage history.....................................................................................................................8 Figure 3: Borealis pressures in map view........................................................................................................10 Table 1: Borealis monthly production and injection summary.........................................................................7 Table 2: Borealis pressure survey detail............................................................................................................9 Table 3: Borealis monthly average oil allocation factors................................................................................11 E Prudhoe Bay Unit 2017 Borealis Oil Pool Annual Reservoir Report 1. INTRODUCTION This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Borealis Oil Pool in accordance with Commission regulations and Conservation Order 471. This report covers the period from July 1, 2016 through June 30, 2017. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9A) Enhanced Recovery Projects Water injection in the Borealis Oil Pool (BOP) started in June 2001, whereas tertiary EOR Miscible Water Alternating Gas (MWAG) started in June 2004. Evaluation of hydrocarbon recovery mechanisms for the Borealis Oil Pool (BOP) has been a continual process. A phased development program has been deemed appropriate due to the technical characteristics of considerable faulting, low initial oil rates, and thin oil columns. This development approach employs three reservoir mechanisms throughout the field's life to maximize commercial production. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the BOP where injection is justified, waterflooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Tertiary EOR MWAG provides additional oil recovery by further reducing residual oil saturation. The miscible gas injection project is operated to maintain miscibility 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 2100 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and voidage replacement ratios. Reservoir Management Summary The objective of the Borealis reservoir management strategy is to manage reservoir development and depletion to maximize commercial production consistent with prudent oil field engineering practices. During primary depletion, a number of producers experienced increasing GORs. Production was restricted in several wells in 2002 to conserve reservoir energy. As more injection patterns were implemented in 2003, the rising GOR trend was reversed and GORs stabilized near solution GOR. When 3 water injection was initiated, a VRR target greater than 1.0 was implemented in order to catch up with voidage. The current VRR target is 1.0. Waterflood patterns have been designed and implemented to maintain pressure in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. Injection 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 earlier than expected water breakthrough in many patterns. Impacts of the early breakthrough include reduced production due to unfavorable wellbore hydraulics and gas -lift supply pressure limitations. Remedies have included gas -lift redesign and optimization and prioritization of gas -lift use. During the reporting period, average injection rate was 25,987 BWIPD and 15.2 MMSCFD. Cumulative injection through June 2017 was 191.0 MMSTBW and 91.8 BCF. A total of 22 injectors have been on water injection and 22 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B During the reporting period, field production averaged 6,040 BOPD, 12.7 MMSCFD (FGOR 2,105 SCF/STB), and 17,961 BWPD (WC 75%). Water injection during this period averaged 25,987 BWIPD with 15.2 MMSCFD of miscible gas injection. The average voidage replacement ratio was 1.1. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Figures 1 and 2 graphically depict this information since field start-up. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. Booster pumps were installed at Z Pad to provide increased injection pressure for low injectivity patterns. The A Booster (Z -504A) suffered multiple electrical failures during the reporting period. The A Booster (Z - 504A) was repaired and returned to service in 1Q 2017. The B Booster (Z -504B) ran reliably for the entire duration of the reporting period, following the 2Q 2016 repair. Production and injection for V -Pad was shut-in, isolated, and brought to a safe state in June 2016 due to piping over stress findings from an engineering study. The study was commissioned to analyze subsidence and the potential for surface piping stress that was visually recognized across the pad, which was confirmed by the engineering model from the study. Therefore, in order to mitigate the risk of a loss of primary containment, the pad was shut in while a plan to safely return production/injection is developed. V Pad surface repairs were completed as planned in 4Q 2016. V Pad production was ramped up starting in 4Q 2016 with all of the wells online in 1Q 2017. Surface subsidence issues are now being managed on an ongoing basis as the need arises for specific well line and wellhouse leveling / repairs. 4 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 2. The field reservoir pressure map is shown in Figure 3. 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. Pressure measurements were gathered in 22 wells during reporting period for a total of 22 statics. Most producers in Borealis have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 9D) During the reporting period, no injection or production logs were run in the Borealis Field. 6. REVIEW OF POOL PRODUCTION ALLOCATION AND WELL TEST EVALUATION (RULE 9E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4G) Borealis production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC -2 allocation factor is now being applied to adjust the total Borealis production similar to IPA production allocation procedures. A minimum of one well test per month is used to check the performance curves and to verify system performance. In an effort to improve well test quality, Weatherford Generation 2 multi -phase meters (Gen 2) were installed at the L -pad and V -pad test headers. In 2012, the V -pad Gen 2 meter was accepted as the primary metric for production allocations, and the V -pad Well Pad Separator was taken out of service. Reliability issues with the L -Pad Gen 2 meter have led to an increased use of the Well Pad Separator for allocation on many of the wells. The disagreement between the Gen 2 meter and Well Pad Separator has led to the need for portable well tests to determine which meter is more accurate for each well. These portable tests have been used along with the routine Gen 2 and Well Pad Separator tests to allocate well production rates. A project has been initiated to solve the L & V metering reliability issues by phasing out the Gen 2 meters and upgrading/reinstating the Test Separators with modern flow measurement components that are easily maintained. Although the Gen 2 meters function well when all components are maintained and calibrated, the ongoing maintenance and reliability issues have proven to be detrimental to the overall metering health of L & V Pads. The expertise and equipment necessary to keep the Gen 2 meters functioning have proven to be too specialized, causing lapses in calibration and maintenance. The project to replace the meters is expected to be complete in 1Q 2018. During the reporting period, tests were obtained with a portable test separator to check the accuracy of the on -pad metering and adjust allocation curves as needed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.86 and 0.99. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 3. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 9F & G) 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 started on June 8, 2002. Water injection manifolding and booster pumps have been installed and have been operating since January 2004. These booster pumps allow even pattern support throughout the waterflood providing optimum waterflood spacing, configuration, timing and operations. The Borealis waterflood management strategy targets a voidage replacement ratio of 1.0 through MI WAG injection to maintain reservoir pressure and to maximize commercial oil production. In March 2010, GC2 reached its permit limit for H2S production. Several Borealis wells were shut in during their MI responses due to elevated H2S in the returned MI. The installation of Metal Triazine injection continues to help maintain H2S production within the allowable limit. Borealis wells continue to show benefits from MI. Summarized below are significant events and accomplishments at Borealis over the past year: • Z -504A: A booster pump was repaired and put back into service in 1Q 2017 • Z -504B: B booster pump ran reliably for the entirety of the reporting period • MI was injected into 7 water -alternating -gas injectors • In addition to the aforementioned activity, miscellaneous producer and injector wellwork was executed to minimize oil rate decline. The Borealis owners will continue to evaluate optimal well count, well utility, wellwork and well locations to maximize commercial production. Future development plans are discussed in the 2017 update to the Plan of Development for the Borealis Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2016, a copy of which was provided to the Commission. The Commission will be copied when the 2018 update of the Borealis Plan of Development is filed with the Division. LV u TABLE 1: BOREALIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date Oil Prod STB Gas Prod MSCF Water Prod STB Water Inj STB MI Ing 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 Monthy VRR RVB/RVB Jul -16 102,520. 270,517. 247,223. 468,318. 0. 81,027,768. 115,210,882. 100,816,435. 182,012,571. 240,914,381. 75,920 32,661,823 0.86 Aug -16 126,577. 255,300. 367,614. 606,009. 184,839. 81,154,345 115,466,182 101,184,049 182,618,580 241,653,170 -34,037 32,627,786 1.05 Sep -16 96,719. 225,624. 259,870. 383,500, 501,092. 81,251,064 115,691,806 101,443,919 183,002,080 242,358,852 -169,893 32,457,893 1.32 Oct -16 122,373, 244,920. 338,263. 666,578. 449,461. 81,373,437 115,936,726 101,782,182 183,668,658 243,324,093 -302,730 32,155,163 1.46 Nov -16 162,704. 310,525. 456,155. 918,210. 386,469. 81,536,141 116,247,251 102,238,337 184,586,868 244,509,460 -307,279 31,847,884 1.35 Dec -16 148,373. 308,369. 429,058. 739,288. 407,896, 81,684,514 116,555,620 102,667,395 185,326,156 245,523,823 -184,522 31,663,362 1.22 Jan -17 242,715. 545,315. 867,061, 759,804. 439,165. 81,927,229 117,100,935 103,534,456 186,085,960 246,578,703 498,094 32,161,456 0.68 Feb -17 216,732. 418,857. 645,984. 770,598. 553,441. 82,143,961 117,519,792 104,180,440 186,856,558 247,715,552 75,562 32,237,019 0.94 Mar -17 251,292. 523,226. 801,265. 1,013,726. 507,380. 82,395,253 118,043,018 104,981,705 187,870,284 249,074,266 124,168 32,361,187 0.92 Apr -17 265,985. 576,398. 816,421, 984,534. 700,000 82,661,238 118,619,416 105,798,126 188,854,818 250,522,336 102,870 32,464,057 0.93 May -17 266,674. 553,151. 737,810. 1,107,339. 781,370. 82,927,912 119,172,567 106,535,936 189,962,157 252,147,344 -168,538 32,295,519 1.12 Jun -17 201,829. 408,229. 589,102. 1,067,486. 652,961. 83,129,741 119,580,796 107,125,038 191,029,643 253,651,691 -376,872 31,918,647 1.33 7 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY 100,000 GO 90,000 U. U 80,000 O 70.000 u- U 60.000 d 50,000 40, 000 CL m m 30.000 Q 2 p 20.000 m 10.000 m 0 0 c c� c� o - w n m m o r a2 0 o q o 0 0 0 0 c c c c c c c c cc c c c c FIGURE 2: BOREALIS VOIDAGE HISTORY 300.000, 000 m tg275,000, 000 9250,000,000 m a 0225, 000, 000 m Z 200, 000, 000 175, 000, 000 m 150, 000, 000 —12 5, 000, 000 m w 100, 000, 000 m 75,000,000 H y 0 50,000,000 0 a 25,000,000 O 0 m m O N (2 In CO n q q o 4 q q q q q C C c C C C C C C C C c C C C W N N A N t0 N N m 100% 90% 80% 70% 60% 50% 3 40% 30% 20% 10% 0% 300 2.75 250 2 25 200 1 75; 5 1 50 j 125C, 1 00 075 0 50 025 000 TABLE 2: BOREALIS PRESSURE SURVEY DETAIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION DCCCCVAro ooCccs 4foc ncn�rsT 'Other Static pressure for water injectors were calculated Wasp tubing Il,d level shots and ureter g196ent balm known freeze protect salume L BPFapbralnn (Agsb) we 2 Add-. a ma«t...a. wr. -.. PO. Boa taea12.900 E Bens.. awe.. AmMrs4s. AK BB519 WI2 .. Fak and Por snwm wlea... sac..ev 7. c.a cr..4v. 8 W.1 aay lM4 8 Weil Nama and 9. /WI Number 10. Oil (0) 11 AOGCC 12 Zone 13. Perblalee Intends Tap- 14. Final Test Dale 15 Shut -d- Bay F.1d,.-sa aPool 16 Press 6608 w01s 0950125 -AH 0n Number 50-AAK)000(K-)OF%A or Gas (G) Pool Code Bosom TWSS -In Time, Hou. Sury Type 17 SH Temp 18 Depth Tool Turas 19 Final Pressure al Tool 20. Datum TWsa (,,put) 22. Pressure Gradlenl, psuit 22. Re -re at Darum (cal) (aee Depth ,net rucaona L-106 50500-29230.55-00 O 640130 8496 - 6560 7/27/2016 504 mr.oma) 58HP 155 6561 27976600 0.4198 2813 L-109 5050029230-0800 WAG 40 6730 6584-6811,6620-6848 6272017 312 gher surface 840 6600 0.4228 3661 L-111 50500-2923043&00 WAG 640130 8541 - 6564 6573 - 6578 72312016 408 SBHP 120 6596 - 6603 8549 2954 6600 0.4320 2976 L-117 5050029230-39.00 WAG 640130 6475-6523 6536-6540 65BB-6603 8272017 372 Other @surtece 40 6800 0.4230 2870 L-110 50500292301300 O 8401306426-6475 9/112016 5232 SBHP 150 6439 2875 6600 0 1900 29W L-119 50-500.29230.77-00 WAG 640130 6382 - 63B4, 6473 - 6475, 6577 - 6/272017 8802, 8809 - 6822 312 Other surface 370 8600 0.4229 3195 L-120 50.500-29230$1-00 0 840130 8477 - 8511 8521 -8527 11272018 380 SBHP 148 6500 3091 8800 0.7897 3710 L-724 50500-29232-56-00 O 840130 6353 91308404.21, 6401.91- 8397.36 6393.856104.27 101&2016 336 SBHP 148 6261 1856 6600 0.4000 1992 V-107 50500-2923074-00 O 640730 BSOB-8580 10272018 3168 SBHP 155 6600 3039 6800 0.4394 3039 V-103 50500-29231-17-00 O 640130 6561 - 8800 6608 -6615 10272018 3168 SBHP 156 6621-6628 6574 3097 6600 04360 3108 8561 -8571 6586 - 6582 6574 -0586 6567-6572 6576-6576 6576-6575 V -106A 50.500-29230-83-01 O 640130 6543 - 6536 6528 - 6526 12/3V1016 4728 SBHP 152 6480 3152 6600 04000 3200 6521 -6543 6587 . 6584 6581-8583 6582-8600 6601.6802 V-107 5050029231-08-00 O 640130 6521-65586609-6628 70272018 3168 SBHP 156 6600 2796 6600 04406 2795 V-109 50 500.29231-2000 O gg0730 6582 -8600 6800 - 6589 1027!1016 3188 SBHP 156 6600 6589-6623 2528 6800 0.4243 2528 6568-8582 8898-8598 559-6588 6585 - 6558 6559-6588 V-111 5050029231431-00 O 640130 6588-6576 6589-8595 1027/2016 3192 SBHP 146 6500 2951 6800 0.3168 2951 6595-6602 6603-8807 6607-6617 V-173 60500-29231-25-00 O 640130 6472-6524 6580-6588 10282016 3192 SBHP 134 6596 2523 66W 0.1929 2524 6718 6620 6632-5827 V-115 5050029231-95-00 O 640130 6625- W30 6631.8634 10282016 3192 SBHP 149 6600 2690 BB00 0.3098 2690 6637 6637 6634-6828 W63 6888 6672 -6678 V-121 50-500-2923348-00 WAG 640130 6682-66896689-6702 6272017 312 Other ®surface 400 6600 0.4248 3226 6707-6714 6720-6729 6633 0743625 4, 6820.4243611 13, 66065-6603 .16, 8807 288596 49, 6595.928801 47, 6602.68 V-122 5050029233-2800 O 840130 660359. 66M 05M19 23. 10/212076 3024 SBHP 6635 448631 5, 6631 3486 11, .32 149 8408 2768 6800 0.4000 2845 6631 0143630 72, 6632.17- 6631 23, 6630 78835 79, 68361- 8361- 663788 663788 V-123 50-500-29234-22-00 WAG 640130 BB12 - 6607, 13604 - 6602, 6600 - 12220 616 4896 SBHP 139 6267 2788 6600 6597, 6593 - 6577, 6574 - 9 856 0.4400 2935 Z-102 50-500.29233-5380 WAG 640130 5506 - 6525. 6529 - 6536,6514 - 6513, 6512 - 6507, 6505 - 6507 8/182017 336 Other @ au W. 450 6800 0.4234 3279 Z-108 50-500.29232.92.00 O 840730 6556-8580 I 10/52018 1 32160 SBHP 142 6430 3715 8600 0.4000 3183 Z-114 50500-29234-9080 WAG 640130 8112 - 6434 6434 - 8436 6282077 1 336 Other 100 6600 6436-6458 @ surface 0.4221 2929 M Ar gala reperlotl lar.. were mos in acwranca w M Va appecsbq ruga, .pugwu ane nstruclgna.r the A...... Gas Cor Z-113 1 M.by 11110V tnat the Nra9oaiq o Irua aM wrracl to iM heal r na Ww Meas Signature Ken Huber Title Resemir Engineer Printed Name Ken Huber Date July 26th, 2017 'Other Static pressure for water injectors were calculated Wasp tubing Il,d level shots and ureter g196ent balm known freeze protect salume L FIGURE 3: BOREALIS PRESSURES IN MAP VIEW 10 L7 L-123 L- fid L41 , L t ntc W t- kvs Luj 4N* - L406 Wg 03** L IRS 'tea #1221;tl t , z Z- Z-rQ Z - Borealis Field 16 1.0 6�1' 0 10 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -16 0.99 Aug -16 0.92 Sep -16 0.94 Oct -16 0.96 Nov -16 0.88 Dec -16 0.86 Jan -17 0.89 Feb -17 0.90 Mar -17 0.86 Apr -17 0.88 May -17 0.90 Jun -17 0.88 11 2017 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1, 2016 -JUNE 30, 2017 CONTENTS 1. INTRODUCTION 3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8A) 3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8B) 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8C) 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8D) 5 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) 5 7. REVIEW OF PLAN OPERATIONS AND DEVELOPMENT AND RESERVOIR DEPLETION PLANS (RULE 8F&G)5 LIST OF ATTACHMENTS Figure 1: Aurora production and injection history 9 Figure 2: Aurora voidage history 9 Figure 3: Aurora pressures in map view 11 Table 1: Aurora monthly production and injection summary 7 Table 2: Aurora cumulative voidage by fault block 8 Table 3: Aurora pressure survey detail 10 Table 4: Aurora monthly average oil allocation factors 12 K Prudhoe Bay Unit 2017 Aurora Oil Pool Annual Surveillance Report 1. INTRODUCTION This Annual Reservoir Report is being submitted to the Alaska Oil and Gas Conservation Commission in accordance with Rule 8 of Conservation Order 457B for the Aurora Oil Pool and covers the period from July 1, 2016 to June 30, 2017. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 8 A) Enhanced Recovery Projects Water injection in the Aurora Oil Pool (AOP) started in 2001. Tertiary EOR Miscible Water Alternating Gas (MWAG) started in the North of Crest (NOC) and West blocks at Aurora in 2003, Southeast Crest (SEC) in 2004, and Crest (CR) & South of Crest (SOC) 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 to maximize commercial production. Initial development involves a period of primary production to determine reservoir performance and connectivity of drainage areas. Primary production under solution gas and aquifer influx drive, from both floodable and non-waterflood pay intervals, provides information, including production pressure data to evaluate compartmentalization and conformance, that is used to improve the depletion plan. This drilling and surveillance data influences subsequent steps in reservoir development, including proper water injection pattern layout. In areas of the AOP where injection is justified, water -flooding is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. 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 2600 psi. With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even when producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR are based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, and voidage replacement ratios. Reservoir Management Strategy The objective of the Aurora reservoir management strategy is to manage reservoir development and depletion to maximize commercial production 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 and SEC areas. 3 Production was restricted to conserve reservoir energy. Beginning in mid -2001 and continuing into 2003, production from wells S-100, S-106 and S-102 was reduced to approximately half capacity, allowing injection to significantly reduce the GORs by the end of 2003. This practice continued in 2004-5 with curtailment of wells S-108, S -113B and S-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure and productivity in S-108. Pressure data and production performance in S -113B indicates the well is supported by a large gas -cap, so it was returned to full-time production in 2006 to capture benefits of MI injection in the area. Waterflood patterns have been designed and implemented to maintain pressure in individual reservoir compartments and areal sweep is maximized. Initial patterns were based on the understanding at the time of reservoir compartmentalization. Patterns and producer/injector ratios are being modified as development wells and surveillance data provide new information. The surveillance program emphasizes pressure monitoring, injection tracers in select patterns, and waterflood performance monitoring to support this feedback and intervention process. During the reporting period, average injection rate was 22,196 BWIPD and 1.5 MMSCFD. Cumulative injection through June 2017 was 114.8 MMSTBW and 46.2 BCF. A total of 19 injectors have been on water injection and 17 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 8 B) During the reporting period, field production averaged 4,696 BOPD, 8.0 MMSCFD (FGOR 1,697 SCF/STB), and 14,379 BWPD (WC 75%). Water injection during this period averaged 22,196 BWIPD with 1.5 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.9. Monthly production, injection, and voidage volumes for the reporting period are summarized in Table 1. Cumulative production, injection, and voidage replacement ratios by fault block are summarized in Table 2. Figures 1 and 2 graphically depict this information since field start-up. Plans to achieve injection withdrawal ratios consistent with the reservoir management strategy include drilling and stimulation of injection wells as necessary and increasing water injection supply pressure to enhance injection rates where needed. A booster pump was installed at S Pad to provide increased injection pressure for low injectivity patterns. The variability in monthly VRR during this reporting period was due to periodic downtime of the Sulzer and Ruston water injection pumps at GC -2. In addition to the injection pump downtime, individual injectors have been offline periodically due to drilling proximity, pressure management concerns while drilling offset producers, the V Pad shutdown, and acquisition of static bottomhole pressures. 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 8 C) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 457B. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 3. The field average reservoir pressure map is shown in Figure 3. Pressure measurements were gathered in 13 wells during the reporting period for a total of 18 statics. Most producers in the ACP have evidence of pressure response to injection support. 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) During the reporting period, no production or injection logs were run in the Aurora Field. 4 6. REVIEW OF POOL PRODUCTION ALLOCATION (RULE 8 E) AND REVIEW OF POOL PRODUCTION ALLOCATION FACTORS AND ISSUES (RULE 4E) Aurora production allocation is performed according to the PBU Western Satellite Production Metering Plan. Allocation relies on performance curves to determine the daily theoretical production from each well. The GC -2 allocation factor is now being applied to adjust the total Aurora production similar to IPA production allocation procedures. A minimum of one well test per month is used to check the performance curves and to verify system performance. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.86 and 0.99. Any days with allocation factors of zero were excluded. The monthly averages of daily oil production allocation factors are shown in Table 4. Electronic files containing daily allocation data and daily test data for a minimum of five years are being retained. 7. OPERATIONS, DEVELOPMENT & RESERVOIR DEPLETION PLANS REVIEW (RULE 8 F & G) Field development areas for the ACP have been defined by geological and reservoir performance data interpretation. Differing initial gas -oil and oil -water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area, 2) North of Crest Area (NOC), 3) South East of Crest Area (SEC), 4) Crest Area (AURCR), and 5) South of Crest Area (SOC) After establishing primary production from each area, water -flood and tertiary EOR has been implemented to provide pressure support and reduce residual oil saturations. The West and North of Crest areas began production in 2000-2001; water injection commenced in 2002 and MWAG began in December 2003. Initiation of water injection into the South East of Crest Area began with conversion of Wells S-112 and S-110 to injection in June and July 2003 and conversion to MWAG in 2006. Crest Area production began in mid-March 2003 with startup of Aurora Well S-115; Well S-117 production began in early June 2003 with a water -flood startup in August 2004 with newly drilled injection wells S -116i and S - 120i that were put on MWAG in 2006. South of Crest Area production started -up on August, 2002 with the well S-11313. This area was separated from the West and Crest Area after confirming compartmentalization between both areas. In 2014 the well S-135 was drilled at SOC Area to continue expanding the reservoir development. Summarized below are significant events and accomplishments at Aurora over the past year: • S-113BL1: Drilled a sidetrack lateral targeting an area to the Southwest of the parent well in3Q 2016 and placed on production in 4Q 2016. • MI was injected into 4 water -alternating -gas injectors • In addition to the aforementioned activity, miscellaneous producer and injector wellwork was executed to minimize oil rate decline. The Aurora owners will continue to evaluate optimal well count, well utility, wellwork and well locations to maximize commercial production. 5 Future development plans are discussed in the 2017 update to the Plan of Development for the Aurora Participating Area, which was filed with the Division of Oil and Gas of the Alaska Department of Natural Resources on September 30, 2016, a copy of which was provided to the Commission The Commission will be copied when the 2018 update of the Aurora Plan of Development is filed with the Division. R TABLE 1: AURORA MONTHLY PRODUCTION AND INJECTION SUMMARY Report Date Oil Prod STB Gas Prod MSCF Water Prod STB Water Inj STB MI lnj MSCF Oil Prod Cum STB Gas Prod Cum MSCF Water Prod Cum STB Water Inj Cum STB Cum Total Inj (MI+Water) RVB Net Res Voidage RVB Net Voidage Cum RVB MontNy VRR RVB/RVB Jul -16 218,716. 351,208. 609,652, 787,869. 0. 41,946,614. 127,706,427. 49,251,088. 107,529,289. 138,009,724. 283,147 46,695,856 0.74 Aug -16 196,786. 301,784. 417,010. 850,093. 0. 42,143,400 128,008,211 49,668,098 108,379,382 138,876,819 -35,412 46,660,444 1.04 Sep -16 107,816. 157,995. 218,943. 408,738. 0. 42,251,216 128,166,206 49,887,041 108,788,120 139,293,732 22,838 46,683,282 0.95 Oct -16 169,666. 324,962. 287,321. 597,821 0. 42,420,882 128,491,168 50,174,362 109,385,941 139,903,509 88,224 46,771,506 0.87 Nov -16 101,195. 151,676. 162,460. 622,981. 11,856. 42,522,077 128,642,844 50,336,822 110,008,922 140,546,300 -271,092 46,500,414 1.73 Dec -16 134,528. 231,381. 340,988. 799,852. 23,359. 42,656,605 128,874,225 50,677,810 110,808,774 141,376,632 -183,607 46,316,807 1.28 Jan -17 152,964. 286,731. 479,231. 813,794. 184,012. 42,809,569 129,160,956 51,157,041 111,622,568 142,320,789 -95,532 46,221,275 1.11 Feb -17 134,310. 247,781. 556,929, 809,192, 50,381. 42,943,879 129,408,737 51,713,970 112,431,760 143,177,401 24,029 46,245,304 0.97 Mar -17 160,070. 299,158. 721,018. 801,702. 61,757, 43,103,949 129,707,895 52,434,988 113,233,462 144,033,427 255,185 46,500,489 0.77 Apr -17 149,453. 269,037. 718,710. 743,070. 54,359. 43,253,402 129,976,932 53,153,698 113,976,532 144,825,061 283,634 46,784,123 0.74 May -17 138,247. 214,339. 553,190. 700,069. 68,922. 43,391,649 130,191,271 53,706,888 114,676,601 145,581,863 94,873 46,878,996 0.89 Jun -17 50,407. 72,689. 183,040. 166,314. 88,157. 43,442,056 130,263,960 53,889,928 114,842,915 145,806,160 62,597 46,941,593 0.78 19 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun -17 Aurora Aurora Aurora Aurora Aurora Crest" N of Crest" E of Crest* W of Crest* S of Crest* Total Cumulative Injection (rsvb) 16,756,306 43,993,290 10,050,098 65,577,385 9,800,974 Total Cumulative Production (rsvb) 32,036,833 50,579,507 13,342,355 76,819,570 24,787,212 Cumulative Voidage Replacement Ratio 0.52 0.87 0.75 0.85 0.40 Initial Gas Cap Solution Gas Only Bo 1.32 rs\,b/stb Bg 0.84 rsvb/mscf Bw 1.02 rsvb/stb Rs 0.65 mscf/stb Bg (MI) 0.62 rs\/b/mscf Aurora 146,178,052 197, 565,478 0.74 Eij FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY 50,000 m y 45.000 LL U 40,000 O a 35,000 LL U 30,000 d 25,000 G 20, 000 a m m 15,000 a+ mc O 10,000 d! d 5,000 m 0 4 R o m V 4 4 q M M o N M c c c c c c c_ c c c c c c c m m m m m m m l m m m c m FIGURE 2: AURORA VOIDAGE HISTORY 150,000,000 m >140,000,000 y 130, 000, 000 m '120,000,000 > 110, 000, 000 m z 100,000,000 5 90, 000, 000 80,000,000 70,000,000 d 60,000,000 cc s 50,000,000 Go 40,000,000 N � 30,000,000 M Q 20,000,000 CL O 10, 000, 000 0 O N M a In O n O o 4 4 R 4 4 4 R 4 c c c c c c c c c c C c C C C C � t0 (0 � N m 10 N (O fV l0 10 N 10 N f0 t0 100% 90% 80% 70% 60% 50% 3 40% 30% 20% 10% 0% 3.0 2.8 25 2.3 20 08 0.5 0.3 0.0 TABLE 3 - AURORA PRESSURE SURVEY DETAIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1 OpxNor 2 Atltlnn 8P Ex orNim Alaeka) Inc P O B.. 196812, 900E 8—BIW, A— e, AK 995198612 3. 7A a laeae Nem. 4 Fw1d Mtl Pool 5 Did— Refs— 6 09 Gravity 7 Gim G—ty Pkdhw�unit _ _ Pr.—Be Fib A -09P 6700 TVD" 096G25API 072_ __ 8 Well 9 API Number 10. Typerl(�— 12 Zone 13Perforated ytlervak Top -Bottom 14 FInN Tesl Date 15 ShN- 16 Press17BH18 Depth 19 Final 20 Datum 21 Pressure ___ 22Name and 50X)VVXV) = NO See CTVDSS In Time, Sury Temp Tool TVDSS Observdl TVDSS (Input) Cxadlen( Pressure at Number DASHES ImBuct.Code Hours Type (see Pressure P"' Datum (cal) rr instruction at Tool 6 for Depth codes) 6681 58687 57 6687 57-6®0.45 S-102 500292297200 O 640120 6597578893.31 63MA5.6683.31 6893 31-60116 W97 81.6703 09 2/252p17 696 SBHP 140 6487 2283 6700 04 2368 - - 13 6609 22-6695 10 W05 106723.26- 6904 11-6604.76 BBOT 766617 is - - - - — - - - a6t71sfifin eo e62:t.o1-6635 ae 5103 500292298100 O 640120 654245665019665791-666433 11/14/2016 1272 SBHP 139 6429 28 88 6700 04 2996 M70.738675 85 6740.9016753.63 6763.836774 02_6779 12-6765.50 6B3111 -660M1 M 6601 766617 15 6617 15861780662301-663598 S-103 500292298100 O 640120 6642452565019665791-666433 6/3012017 456 SBHP 140 6429 2705 6700 04 2813 6670.736675.85 6740 90-6753.63 - --500292313500 - - - 6763.836774 02 6779 12 -BM 50 O 140 8599 2731 _ 04 5-109 640120 6703-6704 8716-67316737-fi7H 8743-6747 6746-6755 6759 6760 12272016 216 SBHP 6704 - 2771 S-1138 500292309402 _0 WAG 64012066740749 640120 -- -- 121.16 _ - 914/2016 744 4296 SBHP_ Other 149 6564 2705 6700 6700 _ 04 0.3542-- 2759 -3648 S -114A _ 500292311601 6Yie-9685 ------------ 130 surface 1260 S-118 500292138800 O 640120 6617-6851 6607-6711 42211017 26112 SBHP 129 6349 1979 6700 0.3459 2100 6882-8736 67458756 67108772 67668759 6751-6723 67218724 5-121500292330400 O 640120 672687466752.6 127272016 1440 SBHP 141 6581 3072 6700 04 3120 67636754 67484744 674%751 6752{754 67566758 67646779 68926736 67456755 67108772 67668759 8751 6723 6721-6724 S-121 500292330400 O 640120 6728874667524762 6[3012017 456 SBHP 141 6581 2784 6700 04 2832 6765-6754 674867M 67496751 67524754 67566758 6764-6779 8675-6688. 6705-8713, 6716 � 6718. 6719-6718, 5-122 0 O 640120 6717 6716 6706 - 6604, 6716 - 6716, 6716 - 6716.6715 6717,6717-6716 6713, 6708, 6696 6/30/2017 456 SBHP 141 6517 2919 6700 04 2992 Seal S-125 500292336100 O 640120 6705/6175 6786-6788 5787.6783 6771 -6747 6741-67M 6726 -6699 11/2212016 576 SBHP 146 6567 2076 6700 04 2129 S-125 500292336100 O 640120 6705.6747 6741 - 6732 6726 - 6804 6775 67W-6788 6787-6783 6 771 - 6130/1017 456 SBHP 146 6567 1938 6700 04 1991 S-126 500292313500 WAG 640120 sm 6649 s652 66513 6662-6668 6674 � 6681 66M - 661at 6706 67119282016 1104 1 Other 753 ®wince 1490 6700 0.4473 4387 6724.258725.02 6747 414752.28 S-129 500292343300 O 640120 6751066781 B1 6763 27-678325 W172016 336 SBHP 147 6554 2568 6700 04 2626 16 M26737 26672557 6714.256725.02 6747 418752.29 S-129 500292343300 O 640120 67510667618/6763.274783.25 6r30r2017 456 SBHP 140 6554 2460 6700 04 2518 6782.906740.05 6731 266728 57 S -42A 500292288201 O 640120 b7u-6123 522/2017 4920 SBHP 6478 1616 6700 04_ 1705 S -44A 500292273501 - - O - 640120 - - 6898-9706 -- - —- ---- -- _ 11252016 672 SOHP 144 6478 _ 2484--- _-6700 - 04 2573 S -44A 500292273501 O 1 640120 16WO - 6708 61[302017 480 SBHP 144 6478 2896 6700 04 2985 23. All Ion np—d herein were madam ecco1i— with tri eppl¢a5M rul.4. rpWabaa antl Imirucllorr N iM Ahab Oil eM Gu C4nurlNion Commue,n I hereby —fy tfal the baparlp le true and correct to 1M Met N my knoMMJV S0prvlure Ken Huber TBI. Rs—Erg— P -m! Name Kan HWM DNa July 26th, 2017 'an. SIN, rv— b water igmKton wen c,WJNed Maed IW n, Sud Iwl endo and rater yrad— two. kwon hexa pmts ct u1- 10 FIGURE 3: AURORA PRESSURES IN MAP VIEW 11 t i � r t 1 • i s. 3-af \ a ts� • � I i -- ---LI >ro-df Ltt4 d t �Itl ,. 12f[3+ I $-it" - �-- • � sea 21Pf 3 Z-%, r, l Lt1] '•.y •LiN `l- 1[ {-Wt 2384` 9 ,Liwi� 1721 spm s1Bd� L•21 t tM L .� L-t]a - _ s-tzs'Zs. \•L �ti I $421- 't •LISS � Aurora Field _ .-_.._...�,..., i.i4t �SfUi ikRSSFi'E • .,.,� .w ln.nc�• {Tr,MAP 1 11 TABLE 4 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -16 0.99 Aug -16 0.92 Sep -16 0.94 Oct -16 0.96 Nov -16 0.88 Dec -16 0.86 Jan -17 0.89 Feb -17 0.90 Mar -17 0.86 Apr -17 0.88 May -17 0.90 Jun -17 0.88 12