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Home My WebLink About2019 Prudhoe Satellite Oil Poolsbp 0 BP Exploration (Alaska) Inc 900 East Benson Boulevard P O Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 September 12, 2019 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 RE: Prudhoe Bay Unit Satellite Pools Annual Reservoir Surveillance and Annual Reservoir Properties Reports July 1, 2018 — June 30, 2019 Dear Commissioners: BP Exploration (Alaska), Inc, as operator of the Prudhoe Bay Unit, submits the enclosed Annual Reservoir Surveillance Reports and the Annual Reservoir Property Report for the Satellite Oil Pools (Aurora, Borealis, Midnight Sun, Orion, and Polaris). The Annual Reservoir Surveillance Reports were prepared in accordance with the latest conservation orders for each pool. In addition, as required by 20 AAC 25.270(e), BPXA is simultaneously electronically filing the Annual Reservoir Properties Reports (ARPs, form 10-428) to aogcc.reporting@alaska.gov. If you have any questions regarding the reports please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Respectfully, Katrina Garner West Area Manager/Reservoir Management, Prudhoe Bay Unit Alaska Reservoir Development, BPXA Cc: Eric Reinbold, ConocoPhillips Alaska, Inc Greg Keith, ConocoPhillips Alaska, Inc Doug Sturgis, ExxonMobil Alaska, Production Inc Jeff Farr, ExxonMobil Alaska, Production Inc Dave White, Chevron USA Justin Black, SOA DNR -Division of Oil and Gas Mr. Dave Roby, AOGCC 2019 ANNUAL SURVEILLANCE REPORT AURORA OIL POOL PRUDHOE BAY UNIT JULY 1, 2018 -JUNE 30, 2019 lYl1UTCAITc 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 813) 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 T OF ATTACHMENTS Figure 1: Aurora production and injection history 9 Figure 2: Aurora voidage history 9 Figure 3: Aurora pressures in map view 12 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 13 4 Prudhoe Bay Unit 2019 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, 2018 to June 30, 2019. 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. Consequently, 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 Managgment Strateev 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 5-100, 5-106 and 5-102 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 5-108, S -113B and 5-118. By 2006, these wells were returned to production with a notable increase in reservoir pressure and productivity in 5-108. Pressure data and production performance in 5-113B 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 14,769 BWIPD and 4.6 MMSCFD. S Pad MI was down from 3Q 2018 to 1Q 2019 for planned maintenance (mapegaz valve replacement). Cumulative injection through June 2019 was 128.4 MMSTBW and 49.9 BCF. A total of 19 injectors have been on water injection and 18 injectors have been on MI. 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 89 During the reporting period, field production averaged 5,291 BOPD, 11.2 MMSCFD (FGOR 2,118 SCF/STB), and 17,384 BWPD (WC 77 %). Water injection during this period averaged 14,769 BWIPD with 4.6 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.58 . 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 S Pad booster pump was offline from Sept 2018 to Nov 2018 for electrical issues (feeder ground fault). 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 22 wells during the reporting period for a total of 29 statics. Most producers in the ACP have evidence of pressure response to injection support. For the period of July 1", 2019 to June 30`h, 2020, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of five pressure surveys will be taken. 4 5. RESULTS AND ANALYSIS OF SPECIAL MONITORING (RULE 8 D) During the reporting period, two production logs were run in the Aurora Field. On November 9th, 2018 and March 30th, 2019, a PNL log was run in S-113BL1 to determine where hydraulic fractures (gadolinium tagged proppant) had initiated, as S-113131-1 has an uncemented completion. During the reporting period, no injection logs were run in the Aurora Field. 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 0.82 and 1.02. 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 (RULES F &G) Field development areas for the AOP have been defined by geological and reservoir performance data interpretation. Differing initial gas -oil and oil -water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area, 2) North of Crest Area (NOC), 3) South East of Crest Area (SEC), 4) Crest Area (AURCR), and 5) South of Crest Area (SOC) After establishing primary production from each area, water -flood and tertiary EOR has been implemented to provide pressure support and reduce residual oil saturations. The West and North of Crest areas began production in 2000-2001; water injection commenced in 2002 and MWAG began in December 2003. Initiation of water injection into the South East of Crest Area began with conversion of Wells S-112 and S-110 to injection in June and July 2003 and conversion to MWAG in 2006. Crest Area production began in mid-March 2003 with startup of Aurora Well S-115; Well S-117 production began in early June 2003 with a water -flood startup in August 2004 with newly drilled injection wells S-1161 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 -105A: was sidetracked and placed on production in 2Q 2019 ■ S-109: had concentric liner installed November '18 and was hydraulically fractured in December '18 5 • S-26: attempted fill cleanout in December '18 (coil tubing got stuck 4 fish left in the well) ■ S-113BL1: had perforations added in March '19 ■ 5-129: had perforations added in June'19 (obstruction in liner 4 damage from frac) • S-2213: approved RWO to add Kuparuk injection; scheduled for 4Q 2019 • MI was injected into 6 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. Future development plans are discussed in the 2019 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 25th, 2018, a copy of which was provided to the Commission. The Commission will be copied when the 2020 update of the Aurora Plan of Development is filed with the Division. 0 TABLE 1: AURORA MONTHLY PRODUCTION AND INJECTION SUMMARY rteport Date Uil Prod STB _ Gas Prod MSCF Water Prod STB Water Inj STB M1 Inj MSCF Oil Prod Cum STB Gas Prod Cum MSCF Water Prod Cum STB Water Ing Cum STB Cum Total Inj (MI+Water) RVB No Res Voidage RVB Net Voidage Cum RVB Monthly VRR RVBlRVB Jul -18 96,315 150,512- 307,695 419,995 604,933 45,220,596 133,074,120 60,112,193. 123,390,496. 156,148,883 -288,363 -288,363 156 Aug -18 158,574. 186,249 477,946. 340,998 148,260. 45,379,170 133,260,369 60,590,139 123,731,494 156,588,622 327,201 327,201 057 Sep -18 172,619. 244,085 577,016 233,177 0 , 45,551,789 133,504,454 61,167,155 123,964,671 156,826,463 689,750 689,750 026 Oct -18 184,590. 281,940 517,565 96,876 0 45,736,379 133,786,394 61,684,720 124,061,547 156,925,277 809,291 809,291 011 Nov -18 164,490. 307,420 489,687 204,398 0 45,900,869 134,093,814 62,174,407 124,265,945 157,133,763 677,144 677,144 024 Dec -18 162,163 372,965 529,481 542,771 0 ' 46,063,032 134,466,779 62,703,888 124,808,716 157,687,389 413,397 413,397 057 Jan -19 161,645. 336,804. 573,579 525,475 56,359. 46,224,677 134,803,583 63,277,467 125,334,191 158,258,316 418,031 418,031 0.58 Feb -19 154,310. 403,923. 552,048 538,596. 142,450 46,378,987 135,207,506 63,829,515 125,872,787 158,896,003 362,071 362,071 0.64 Mar -19 167,092 383,818. 584,558 663,327. 171,868 46,546,079 135,591,324 64,414,073 126,536,114 159,679,155 252,728 252,728 076 Apr -19 168,912. 360,567 545,855 536,931 r 234,313 46,714,991 135,951,891 64,959,928 127,073,045 160,372,098 291,240 291,240 0.70 May -19 180,752. 554,208. 615,635 655,257 206,411 46,895,743 136,506,099 65,575,563 127,728,302 161,168,435 393,369 393,369 067 JUn- 19 159.588 507-734 574 180- 6322 895 97,524- 47,055,431 137.013.833 66149,743 128.361 197 161.8T4.453 387.168 387 168 065 TABLE 2: AURORA CUMULATIVE VOIDAGE BY FAULT BLOCK On Jun -19 Aurora Aurora Aurora Aurora Aurora Crest* N of Crest** E of Crest* W of Crest* S of Crest* Total Cumulative Injection (rsvb) 19,063,713 49,136,829 11,454,530 71,008,934 11,582,339 Total Cumulative Production (rsvb) 35,290,058 57,226,159 14,194,180 83,432,036 27,568,226 Cumulative Voidage Replacement Ratio 0.54 0.86 0.81 0.85 0.42 * Initial Gas Cap " Solution Gas Only Bo 1.32 rs,,b/stb Bg 0.84 rsvb/mscf Bw 1.02 rs%b/stb Rs 065 mscf/stb Bg (MI) 0.62 rsvb/mscf Aurora 162,246,345 217,710,659 0.75 0 FIGURE 1: AURORA PRODUCTION AND INJECTION HISTORY 50,000 m W 45,000 u V) G40,000 0 w 35,000 30,000 25,000 0 d in if 20,000 A cc b 15,000 as `u � 10,000 3 5,000 0= C C C C C C C C C C C L C m m m A m FIGURE 2: AURORA VOIDAGE HISTORY 200,000,000 j 190,000,000 —oil Prod Cum yt -Waterinj Cum 180,000,000 —TatalImC..lwat—Mp w 011 170,000,000 ---'Net Vaidage Cum '—O 160,000,000 —Monthly VRR > ---• Lifetime Cum VRR w 150,000,000 - — — — z 140,000,000 130,000,000 - c 120,000,000 F 110,000,000 100,000,000 i 90,000,000 - 3 80,000,000 70,000,000 m 60,000,000 c 50,000,000 - a 40,000,000 G 30,000,000 A J 20,000,000 10,000,000 0 i 8 0 o q 0 8 0 C C C C C C C C C C C C C C C C C C C C m m N m m m N m N m N m N N 100% 90% 80% 70% 60% 50% v 3 40% 30% 20% 10% 0% 4.0 3.8 3.6 3.4 3.2 3.0 2.8 2.6 2.4 m 2.2 2.0 C 1.8 1.6 j 1.4 1.2 1.0 0.8 0.6 0.4 0.2 0.0 J TABLE 3 - AURORA PRESSURE SURVEY DETAIL 1/2 10 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1" Ope ata 2 Address: BP Exploration IAleska) Inc. P 0. Box 196612, 900 E Benson Bled, Anchorage, AK 99519.8612 3. Unit or Lease Name: 4 Field and Pool: 5. Datum Reference: 6, Oil GraWy: 7. Gas Graeity: Prudhoe Bay Unit Prudhoe Bay Field: Aurora Oil Pot 6700 TVDss 0.9SG/25 AP 0 72 a. Wolf Nemo anis I. API N nrw 19 Type 11 AO ,( 18 -Zone 13 P9rfWated yltm+eall Top. BollomT DS.'. 14. Fugal Telt 15 Snut-in 16 FTess. 17. B H. 18 Depth 19 Rnal Zuu Datum 2i Pressure 22 Pressure Nunber: 50)COCXX)O(XX)= See Fool Code at Date Tine, Eburs Sury Type YP Te rrp. Tool DSS N Observed N DSS (input) Gradient, psVFt Datum (cal) NO DASHES instructions (see Pressure at instructions Tool Depth for codes) 5741 500297296890 TAG 649120 6696 - 6735, 6687 - 6716 6/9/16 1480 OTHER -64 11170 r 6700 043 4050 s10d 500292296600 WAG 64012-0 6693 - 6742, 6719 - 6738 6/9/16 480 e7- tHere -65 650 6700 0 43 3592 6105 500292297700 O 640120 6712 - 6759, 6768 - 6777 8/17/18 690 SBHH 147 6700 2940 S /uu 0 44 2939 SA 05A 500292297701 O 640120 6777 - 6788, 6787 - 6792 5/6/19 SCHF' 143 6701 3020 15700 0 51 3019 6703 - 6704 6716-6731 6732-6741 S-109 500292313500 O 640120 6743-6747 6746-6755 6759-6760 8/24/18 5455 SBHP 136 6700 3684 6700 0"34 3684 51108 50CM3030Q2 WAC; 640120 6/65-5794 811718 3552 OTHER -83 1040 8700 0.42 3920 S -110B 500292303002 vVAG 640120 57165-5794 1Lbn8 5666 SBHP 132 6700 3746 6700 0.47 3746 5-1108 500292303002 VVP.G 640120 676$-6794 1131%19 1-944OTHER -83 88u 6700 0.42 3690 e r /l - 6 /80, 6777 - 6782, 6794 - 6801 6815 - 6823, 6834 - 6833, 6832 - 6832 6860 - 6861, 6799 - 3801, 6805 - 6812 S-111 500292325700 1 WAG 640120 6823 - 6829, 6869 - 6870, 6864 - 6830 8/9/18 480 OTHER -64 880 6700 0.43 3763 6641-6655 6672-6679 5-112 500292309900 VVI 640120 6703-6684 819/18 504 OTHER -70 1300 6700 0.43 4206 6641-6655 6672-6679 S-112 500292309900 VVI 640120 6703-6684 10/10/18 720 OTHER -70 1060 6700 0.43 3966 S-1 14A s002923IMI WAG b`auliu 6658-6685 8/9/18 480 0 -1nen -70 1060 6700 0.43 3964 S -116A 500292318301 WAG 540120 6776-6749 8/9/18 504 0-114M -64 80 fi700 0.43 3962 5-116A 5QQ29231a301 WAG 840120 6776-6749 t9lmis 73u OIHER -64 950 8700 0.43 3852 5-123 500292321900 WAG 640120 6646 - 6675, 6681 . 6693 10/14118 6569 SBHP F 119 8885 4061 67-00 0.43 4073 5133 WU392321900 WAG 640120 6646 - 6675, a681 - 6693 1161/19 %944 OTHER - 00 1369 6700 0.42 4175 6608 - 6816, 6825 - 6835, 6837 - 6854 5-124 500292332300 WAG 640120 6864 - 6873, 6881 - 6868 12/20/18 3175 SBHP 133 1 6700 3222 6700 1 0,18 3222 6808 - 6816, 6825 - 6835, 6837 - 6854 5-124 500292332300 WAG 640120 6864-6873,6881 - 6888 3/30/19 1224 OTHER -63 480 6700 0,42 3321 6633 - 6649 6652 - 6658 6662 - 6668 5-126 500292313500 WAG 640120 6674 - 6681 6686 - 6694 61. - .711 8/3/18 336 OTHER -67 1500 6700 0.43 4403 s126 500292343600 VAG 840120 6795, 6753, 6719, 6857, 6816, 6796 6/3/16 336 OTHER -r Seo 67011 0.43 3483 S -42A 500297256201 O b4U72U 8714-6623 6/11/18 1056 SBHP 131 647-8 1184 6700 039 1670 18.42A 500292268201 O 640120 6714-6823 8/17/18 1056 S& i 44 6660 1270 6700 0.39 1886 10 TABLE 4 - AURORA PRESSURE SURVEY DETAIL 2/2 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1 Operator 2. Address BP Exploration (Alaska) Inc P 0 Box 1915612, 900 E Benson Blvd, Anchorage, AK 99519-8612 3 Unit or Lease Name- 4 Field and Pool: 5 Datum Rebie oe 6 Oil Grady 7 Gas Gravity: Prudhoe Bay Unit PnxR= Bay Field: Aurora Oil Poe 0700lVDss 0 9SGf25 All 0.72 6, Wal Noes and 9. AR Nemec 10. Type 11 AOGCC 12. 2ono 13. Fhd orateo lrte ale Top - 5ou*m TVCSS; 14 Final Test 16 Stiuhln 16- Bess. 17 S.K 18. Depth 19. Final ZD. Daum 21, Ressurlr 22 Pressure at Number: 50xxxxxxxxx)o(x See Pool Code Date Time, Fours Sury Type Terp Tool TVDSS Observed TVDSS(input) Gradient, psi/fl Datum(cap NO DASHES Instructions (see Pressure at instructions Tool Depth for rode&) 6685 5615&7-576567.51.8690.45 6687 57-6693 31 6690-45-6693.31 6693 31-6696 13 6697.81-6703 09 S-102 500292297200 O 640120 6699 92-6665 10 6685 10-6723 26 01108119 3000 SBHP 141 6487 2596 6700 040 2681 66&7.5.6667.516867.57.6690.45 6687 57-6693 31 6690.45-6693 31 6693 31-669613 6697 81-6703 09 5-103 500292297200 O 640120 6699 92-6685 10 6685.10-6723 26 08/04/18 384 SBHP 6429 2764 6700 0.40 2872 8692.6796 6745-8756 6770-6772 6766-6759 6751-6723 6721-6724 6728-6746 6752-6762 6765-6754 6748-6744 6749-6751 6752-6754 S-121 500292330400 O 640120 6756-67586764-6779 08/04/18 360 SBHP 6581 2816 6700 0.40 2864 6575- 6689. 6705.6713.67115. 6718, 6719 -6713,6717. 713,6717- STIS. STIS. 6706 - 6699, 6716 - 6716, 6716 - 6716,6715 - 6717, 6717 - S-122 500292326500 O 640120 6716,6713,6708,6696-6681 08/25/19 13920 SBHP 6517 3072 6700 040 3145 6705.6775 6716.673& 6787 • 67W 5-125 500292336100 O 640120 6771-6747 6741-6732 6726-6699 09/03/18 336 SBHP 6568 2126 6700 0.40 2179 6724.2' 6725.026747-41-SM28 6751 06-6761 81 6763 27-6783 25 S-129 500292343300 O 640120 6782 90-6740 05 6737.26-6728 57 02/24/19 4056 SBHP 144 6554 3401 6700 040 3459 6516. 6541, 8543 -6577 5-120 500292318600 WAG 640120 6629. 6540, 6713 - 6725 1 10/09/18 720 OTHER -64 990 6700 043 3909 23. All tests reported herein w ere made in accordance w th the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Comrission. I hereby certify that the foregoing is true and correct to the best of my know ledga Signature Ken Huber Title Reservoir Engineer Printed Nacre Ken Huber Date July 24th, 2019 'Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume 11 FIGURE 3: AURORA PRESSURES IN MAP VIEW �A71 • 3713 t � �•k2a j !3321 145 Mata 28fi7 s•lasn s53z • t Pl� [.t a 4a5o. uv3 ijelrs � °�:' JKI"a s-�ioe X1870 •tioa also s•jw f -I tt ` t -+ }l 1■ 0 3sss ssa4 drr5a•tn--. ow o nn lam. ml- CoaNMb tam: FND f9I! �N�6FIP8 5000 Rglcf00: Trmfutlse AOrrC'aeer prWm: NUT Nnerksi t9:"1 as Mow..: vsimam� r1 s 12 Aurora Field Last 8ta& Pressure 7178 to 8,19 �'i! Pressures are averaged of i5gied �A71 • 3713 t � �•k2a j !3321 145 Mata 28fi7 s•lasn s53z • t Pl� [.t a 4a5o. uv3 ijelrs � °�:' JKI"a s-�ioe X1870 •tioa also s•jw f -I tt ` t -+ }l 1■ 0 3sss ssa4 drr5a•tn--. ow o nn lam. ml- CoaNMb tam: FND f9I! �N�6FIP8 5000 Rglcf00: Trmfutlse AOrrC'aeer prWm: NUT Nnerksi t9:"1 as Mow..: vsimam� r1 s 12 TABLE 4 - AURORA MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -18 0.82 Aug -18 1.02 Sep -18 0.87 Oct -18 0.88 Nov -18 0.83 Dec -18 0.84 Jan -19 0.84 Feb -19 0.87 Mar -19 0.85 Apr -19 0.85 May -19 0.85 Jun -19 0.84 13 2019 ANNUAL SURVEILLANCE REPORT BOREALIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2018 -JUNE 30, 2019 CONTENTS 1. INTRODUCTION........................................................................................................................................3 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY(RULE 9A)................................................................................................. ............. ..3 3. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9B) ...... ............................4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 9C) ...... ................:...................4 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) ..................5 LIST OF ATTACHMENTS Figure 1: Borealis production and injection history.................:.............................:...........................................8 Figure2: 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 2 Prudhoe Bay Unit 2019 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, 2018 through June 30, 2019. 2. PROGRESS OF ENHANCED RECOVERY PROJECT IMPLEMENTATION AND RESERVOIR MANAGEMENT SUMMARY (RULE 9AA 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 30,591 BWIPD and 21.0 MMSCFD. Cumulative injection through June 2019 was 217.3 MMSTBW and 103.3 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 5,905 BOPD, 17.0 MMSCFD (FGOR 2,885 SCF/STB), and 26,544 BWPD (WC 82 %). Water injection during this period averaged 30,591 BWIPD with 21.0 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.97. 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. Booster pump Z -504A ran reliably for the entire reporting period. Booster pump Z -504B had a motor failure in 3Q 2018 and returned to service in 3Q 2019. 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 19 wells during reporting period for a total of 20 statics. Most producers in Borealis have evidence of pressure response to injection support. 4 For the period of July 1", 2019 to June 30`h, 2020, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of six pressure surveys will be taken. 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 AN❑ 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. A project was initiated to improve the L & V pad 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. The upgrades on L Pad included installation of a MicroMotion meter and Phase Dynamics meter, as the L Pad test separator was already in service. The upgrades on V Pad included returning the test separator to service as well as installation of a MicroMotion meter and Phase Dynamics meter. The L & V pad test separator upgrades were completed in January 2019. The meter prove -up and rate verification was completed with the portable testers in 1Ct 2019. Overall, improvements in both well test quality and accuracy have been observed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.82 and 1.02 . 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. 5 Summarized below are significant events and accomplishments at Borealis over the past year: • L-1181-1: was an add lateral drilled in 1Q 2018, with first production in 3Q 2018 • Z-113: had a fill cleanout and profile modification performed in October '18 • L-119: had an OA down squeeze performed in November '18 • L-1181-1: had perforations added in March '19 • Z-20: approved RWO to recomplete as Kuparuk producer; scheduled for 3Q 2019 ■ Z-25: approved RWO to add Kuparuk injection; scheduled for 4Q 2019 • L -119A: approved coil tubing sidetrack; scheduled for 4Q 2019 • MI was injected into 9 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 2019 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 25th, 2018, a copy of which was provided to the Commission. The Commission will be copied when the 2020 update of the Borealis Plan of Development is filed with the Division. L TABLE 1: BOREALIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Date STB Gas Proc Water Prod Water Inj MSCF STB STB 1vu n g vii riuu %.un] vas rruu vvawr rroo vvater ink Gum iotas int Net Res Net Voldage Monthly VRR Cum Cum Cum (MI+Water) Voidage Cum Jul -18 121,173. 412,652 605,907 713,141 530,939. , 86,139,611 127,119,706 118,488,594. 206,808,754 272,643,624. -23,130 33,295,973 1.02 Aug -18 138,706. 279,021 650,482 1,074,757 470,875. , 86,278,317 127,398,727 119,139,076 207,883,511 274,042,566 -372,048 32,923,925 136 Sep -18 165,110. 356,315 714,033 1,380,370 640,133. , 86,443,427 127,755,042 119,853,109 209,263,881 275,861,230 -643,381 32,280,544 155 Oct -18 149,030 312,397 570,398 1,363,280 659,047. , 86,592,457 128,067,439 120,423,507 210,627,161 277,674,017 -833,998 31,446,546 1.85 Nov -18 239,242 493,736 847,476 887,484 722,759. , 86,831,699 128,561,175 121,270,983 211,514,645 279,036,236 133,999 31,580,545 091 Dec -18 245,222 470,078 879,940 813,032 622,263. , 87,076,921 129,031,253 122,150,923 212,327,677 280,259,462 299,691 31,880,236 080 Jan -19 223,197 520,941 1,108,834. 850,282. 537,252. , 87,300,118 129,552,194 123,259,757 213,177,959 281,468,349 552,124 32,432,360 069 Feb -19 181,391. 505,543. 956,619 722,831 567,839 , 87,481,509 130,057,737 124,216,376 213,900,790 282,564,925 442,678 32,875,038 0.71 Mar -19 204,081 764,966. 933,841 962,096 780,738 , 87,685,590 130,822,703 125,150,217 214,862,886 284,039,942 231,702 33,106,740 0.86 Apr -19 160,628 651,578 756,014 836,277 649,321 , 87,846,218 131,474,281 125,906,231 215,699,163 285,303,886 131,699 33,238,439 0.91 May -19 161,575 672,928. 737,123 833,715. 816,149 88,007,793 132,147,209 126,643,354 216,532,878 286,668,625 25,939 33,264,378 0.98 Jun -19 165.874 777.457 927.749 728,514, 658,208. 88,173,667 132,924,666 127,571,103 217.261.392 287.827.083 499072 33.763.451 0.70 7 FIGURE 1: BOREALIS PRODUCTION & INJECTION HISTORY 100,000 �Oil -MI Injection Rate 90,000 U -GOR "•• -Water Injection Rale 80,000 0 "--WC% u 70,000 _ ,.n t : i ,� , :� •'I, y. 60,000 = 1 �t' ..iii 50,000 s 40,000 t� �I II p 30,000 1 A 20,000 1 � 10,000 i 1 1 0- c c c c c c c c R N N N FIGURE 2: BOREALIS VOIDAGE HISTORY 300,000,000 m 275,000,000 to m � 250,000,000 3 w 225,000,000 2 200,000,000 F 175,000,000 150,000,000 `w m ?� 125,000,000 cd m 100,000,000 H c 75,000,000 CL` p 50,000,000 25,000,000 0 C C C C C C C C C C C C C C C N A A N q A A A N N N N 100% 90% 80% 70% 60% 50% u 3 a0% 30% 20% 10% 0% 3.00 2.75 2.50 2.25 2.00 1.75 � 1100 0.75 0.50 0.25 m TABLE 2: BOREALIS PRESSURE SURVEY DETAIL STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPc)RT 1 Operator: 2 Address: BP Expbraten (Anglo) Inc PO. Box 196612. 900 E Benson Blvd , Anchorage. AK 99519-6612 3 Unit or Lease Name: 4 Field and Fool:5 Datum Reference: 6. Oil Gravity: 7. Gas Gravity: Prudhoe Say Unit 6. ftl Name and I. AS NATOW 19 Type 11 AOGCC 12. Zone 13. Perforated nrorvals Top - Bottom 1VM 14 Final Test 15. Shut in Prudhoe Bay Fuld, Borealis 15 prose. 17 B.H Oil Pool 18- Depth 6600 TVDss 1S, FWW 20. Daum 0 9 SG / 25° AFI 072 Nunber: 50%XXXXXXXXXXX See Pool Code 21 Pressure 22. Prnsure at Date Ttmu, Hours Surv. Type Tenp Tool TVDSS Observed TVDSS (input) Gradient, psi/ft Datum (cal) NO DASHES Instructions (see Pressure at instructions Tool Depth for Codec) 6387.6414, 6418 - 64M, 6405 -6449 L-101 500292286500 O 640130 6449.6451, 6532 - 6552 06/13/19 1345 SBHP 153 6400 1 2522 6600 0.44 1 2610 4302 500292307100 O 640139 10144. 10770. 10170. 10200- to=- 70290 912119 969 SSFP F 155 66m 2852 6600 0.44 2852 6394 . frM5 L-103 500292310100 WAG 640130 08/09/18 480 Other 522 220 6600 0.43 2839 6541.6564 8573.6578 L-111 500292306900 WAG 640130 6596-6603 06/18/19 456 Other -76 230 6600 0.41 2993 L-115 500292303500 WAG 640170 6397. 6430. 6d40-6409-8456-&166 9B/O9na 480 C4har -76 740 6600 0:43 3603 L-119 50029ZW77W WAG 640730 6382 - 6384-6473. 6475.6577. 6602, 6809. 6622 07= is 552 SM -P 1 121 6601 4716 5600 052 4115 L-119 500292307700 WAG 640130 6382 • 6384, 6473 - 6475- 6577 - 6602. 6809 - 6622 0611&19 4344 Other -78 220 6640 0,42 2993 L-120 500292306400 1 O 640130 6477.6511 6571.6527 06 W9 2892 SBFP F 146 8500 2959 6600 pA4 W43 V-104 500292310300 WAG rADIW 6603 • 6547, 6559. 8556-6567 • 6570, 6542-8688 08/03118 336 Other .172 200 69W-7-043 am V-105 500292309700 WAG 640130 6555 - 6557. 6559 - 5576, 6574 - 6584, 6588 - 6598, 6604 - 6610 08/O6/16 1008 Other -82 1030 6600 042 3867 6522 • 6.542. 6546. 65.56- 8560. 6568, 6579 • 6586, 6671 - V-112 500292330000 WAG 640130 6685, 6658.8652, 8649. 6642- 6637. 6634 08/01/18 1 1176 Other -82 630 6600 039 3202 6 -6688 6672. 6678 663 6662 - 6689 6689 - 6702 V-121 500292334800 WAG 640130 6707-6714 6720-6729 08/03/18 336 Other 2200 270 6800 043 2239 Z-100 5002Bp378200 O 640130 6884.6920, 6924.5930 06711r18 538 SBHP ids 6600 2742 6607 0,43 2742 Z-102 500292335300 WAG 640130 6506.SUS. 6529. 6535- 6514 - 6513- 6512 - 6507, 6505 - 6501 08/07/18 432 Other -81 1730 6600 0.42 4558 Z-103 SOD2923236W WAG 640130 6804. SIM 0843718 336 Other •83 470 6600 0.44 3t46 6664 • 664$, 6641 - WIS. 6617 • 6644 Z-112 500292338000 O 640130 6644 - 6635, 6632 - 6626 08/11118 554 SBHP 146 6600 2827 6600 0.34 2827 L-124 500292325500 0 640t30 6353.60-640431.6 W7.91$391,30, 6393,650404 MWIS 1296 SBHP 6261 24776600 0.40 2513 8561 - 6571 6585 -6582 6574-6566 6567-6572 6576-6576 6576-6575 6543-6536 6528-6526 6521 -6543 6587-6584 6581-6583 6582-6600 V -106A 500292308301 O 640130 6601-6602 08/06/18 432 SBHP 6480 1 3024 1 6600 1 0.40 1 3072 6633.07.6825.4.6820.456671.13, 66% 5.6603-76, 860125- 6596.49, 6595 92-6601.47, 6602-68-6603.59, 6605.05-6619 23, 6635.44-6631-5, 6631.34-6632.11, 6631.01-6630-72, 6632 17- V-122 500292332800 O 640130 663123, 6630 7-6635 79, 6636.1-6637.88 08/01/18 312 SBHP 151 6408 2384 6600 040 2461 Z-108 500292329200 0 640130 6556 - 65M Ofi130119 58160 --a F 142 6431 2592 6800 CAD 3650 23 All tests reported herein w ere made in accordance w 4h the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Conrrission I hereby certify that the foregoing is true and correct to the best of my know ledge. Signature Ken Huber Title Reservoir Engineer Printed Name Ken Huber Date July 24th, 2019 `Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume FIGURE 3: BOREALIS PRESSURES IN MAP VIEW 10 lia •L.124 2T1 L•I1� rll L•tl r 294 I- L-1 302, _ L -tot l/7II L-112 1 7 C e zs1C� 3043 ' _ ,} za■■3s u1- L • } L-10a� T TM ' Y-7ej L � Y-190 1 V- Y•TBiA l -fel Im rip all a Y238M -171 ' L•�ip v-1 0 V.1 ,36671 v1 3 S6 L•I�Sd V-1 I 1 DI V•19e V-TI514 41=1 V•�x y -77].l � Y•II f 2 V-117 T �et z-117 a 17 'Y•Tte 7 1 ( I •� 0 IraT j YT zin i x•lae Borealis Field MfaN O��4u. ®Mln !Np 1914 eM2Ptlrle NeYu 4 FF9 IDt .•r"' P1aKclon: Tr�nsrvx 1l�r gym: rI9T Nnatm 1921 Last Static Prm5 7?18 to 6119 D11, sw: l><r MAP 1 10 TABLE 3: BOREALIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -18 0.82 Aug -18 1.02 Sep -18 0.87 Oct -18 0.88 NOVA 8 0.83 Dec -18 0.84 Jan -19 0.84 Feb -19 0.87 Mar -19 0.85 Apr -19 0.85 May -19 0.85 Jun -19 0.84 11 2019 ANNUAL RESERVOIR SURVEILLANCE REPORT MIDNIGHT SUN OIL POOL PRUDHOE BAY UNIT JULY 1, 2018 -JUNE 30, 2019 rn nlrl` nlrc 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) 4 4. ANALYSIS OF RESERVOIR PRESSURE SURVEYS WITHIN THE POOL (RULE 11 C) 4 5. RESULTS AND ANALYSIS OF PRODUCTION AND INJECTION LOGGING SURVEYS (RULE 11 D) 5 6. RESULTS OF WELL ALLOCATION AND TEST EVALUATION (RULE 11 E) AND REVIEW OF POOL PRODUCTION FACTORS AND ISSUES (RULE 7(D) 5 7. FUTURE DEVELOPMENT PLANS AND REVIEW OF PLAN OF OPERATIONS AND DEVELOPMENT (RULE 11 F & G) LIST OF ATTACHMENTS 5 Figure 1: Midnight Sun Monthly Production and Injection History............................:...................................5 Figure 2: Midnight Sun Voidage History.....................................................................................................7 Figure 3: Midnight Sun Pressure History............................................................................................... 8 Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary ....................................... 9 Table 2: Midnight Sun Pressure Survey Details.............................................................................................10 Table3: Allocation Factors............................................................................................................................11 2 Prudhoe Bay Unit 2019 Midnight Sun Annual Reservoir Report 1. Introduction This Annual Reservoir Report is submitted to the Alaska Oil and Gas Conservation Commission for the Midnight Sun Oil Pool in accordance with Commission regulations and Conservation Order 452. This report covers the period from July 1, 2018 through June 30, 2019. 2. Progress of Enhanced Recovery Project Implementation and Reservoir Management Summary (Rule 11 a) Production and injection volumes for the 12 -month period ending June 30, 2019 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 consistent with prudent oil field engineering practices. During primary depletion, both the E-101 and the E-102 producers experienced increasing gas -oil -ratios (GORs). Consequently, production was restricted to conserve reservoir energy. Produced water injection into the Midnight Sun reservoir commenced in October 2000 and continues to provide pressure support to Midnight Sun. The objective of water injection is to increase reservoir pressure, reduce GOR's to enable wells to be produced at their full capacity, and maximize areal sweep efficiency. There is a risk of oil in -flux into the gas cap from mid -field water injection. Placement of the wells drilled in 2001 and voidage management is minimizing this risk. A historical 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 0.39, primarily due to E-1031 being shut-in in May 2018. Midnight Sun oil production volume increased during the reporting period. E-1031 ceased injection in May 2018 following a low flow condition and inability to pig the water injection line after work began to convert E-100 to production service for the Sambuca development. Subsequent pressure surveys in E-103 showed significant reservoir pressure decline which led to the shut-in of E-102, which also had an uncompetitive watercut and had not seen MI response from P1-122. Stabilized reservoir pressure from injection underpins the steady fluid production observed in individual producers. Well E-101 currently produces at a stable fluid rate of 7000 bfpd with —87 % watercut. Since 2005, gas lift has been utilized to produce the Midnight Sun wells more efficiently. 3 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. With the drilling of the PI -122 well MI WAG has become possible for the first time for this pool. During the plan period, P1-122 injected MI until November. On November 29th 2019 P1-122 was swapped to produced water injection. Development plans include prudent management of the EOR flood. Wellwork such as well sidetracks to increase recovery will be evaluated as the field matures. Additionally, the subsurface management team plans to update the MNS simulation model to facilitate development opportunities. 3. 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, P 1-122, drilled in 2015 from Pt. McIntyre. Midnight Sun produced at an average rate of 1,394 bopd, 12,948 bwpd, 11.4 mmscfpd and injected 6,432 bwpd and 2.8 mmscfpd of MI for the report period resulting in a total VRR of 0.39 for the period. 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. E-1031 ceased injection in May 2018 following a low flow condition and inability to pig the water injection line after work began to convert E-100 to production service for the Sambuca development. Subsequent pressure surveys in E-103 showed significant reservoir pressure decline which led to the shut-in of E-102, which also had an uncompetitive watercut and had not seen MI response from P 1-122. 4. Analysis of Reservoir Pressure Surveys within the Pool (Rule 11 c) Reservoir pressure monitoring is performed in accordance with Rule 8 of Conservation Order 452. A summary of reservoir pressure surveys obtained during the reporting period is shown in Table 2. For the report period three reservoir pressures were acquired: E-103 (3736 psi, 0.42psi/ft, 10/30/2018), E-100 (3095 psi, .42psi/ft, 02/24/2019), and E-103 (3486 psi, 0.42psi/ft, 03/15/2019). The E-104 injection well has been shut-in since September 9th, 2015 and remains shut-in. 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 3rd, 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. A high pressure break down was successfully completed in PI -122 in November 2017 to increase MI injection rates. The E-103 injection well has been shut-in since May 3rd, 2018 due to a low flow condition and inability to pig the water injection line. E-103 was also SI to manage the water cut of the E-102 producer well and facilitate better MI interaction between PI -122 and E-102. The E-102 producer has been shut-in since May 7th, 2019. This 4 well has not responded to MI injection and has remained at an uncompetitive watercut. The well was shut-in to manage voidage following reservoir pressure measurements in the E - 103i well. 5. 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 2018-2019 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. EOR oil response and returned MI response from P1-122 MI injection also serves as a tracer. Results thus far indicate good communication and response between P 1-122 and E-101 but poor communication between P1-122 and E-102. 6. 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 0.93-0.99. 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. Future Development Plans and Review of Plan of Operations and Development (Rule 11 f & g) Future development plans are discussed in the 2019 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 25, 2018, a copy of which was provided to the Commission. The Commission will be copied when the 2019 update of the Midnight Sun Plan of Development is filed with the division. 5 Figure 1: Midnight Sun Production and Injection History 30,000 - 100% m I.— 27,500 — Ml lnjectian Rate , '►y —GOR n vr�+%, ' t A 90% U her i t 25,000 i►'+_ .i n� �. • rr it 'r -Water Injection Race ----WC% F , r Yi Q 8096 22,500 Ir LL i; 70% 20,000 Y i ► J ;� 11 r , v K 17,500 i; 6096 AAAG 15,000 �+ r,, 50% 3 I 00 12,500 ` ' 40% � 10,000 v 30% 03 7,500 r r 1 ; 20% 3 5,000 2,500 10% � r D 0% m m m 0 '. ry m v ,n kO n m m Q1 O1 4 4 4 4 4 4 R 4 4 4 I" c c c c c c c c c c c c c c c c c c c c c p u Figure 2: Midnight Sun Voidage History 110,000,000 105,000,000 100,000,000 ID 95,000,000 90,000,000 0 > 85,000,000 z 80,000,000 75,000,000 'c 70,000,000 c 65,000,000 H 60,000,000 5 55,000,000 50,000,000 3 45,000,000 ca 40,000,000 m 35,000,000 H :;; 30,000,000 0 25,000,000 a 20,000,000 O 15,000,000 10,000,000 5,000,000 0 00 Q1 O N N M Ln Ql Ol O O O p p O O O O Q Q � N m-1 r�-1 Ln -t to rn-I 00 ,Cl) .� C C C C C C C C C C C C C C C C C C C C C C 5.0 4.8 4.5 4.3 4.1 3.9 3.6 3.4 3.2 3.0 �p 2.7 2.5 j 2.3 2.0 1.8 1.6 1.4 1.1 0.9 0.7 0.5 0.2 0.0 II Figure 3: Midnight Sun Pressure History Midnight Sun Pressure History (measured at 8850 ft. TVDss datum) 4,100 _ �! I 3,900 r waterflood commences 3,700 ! I 3,500 3,300 i r , 3,100 + 2,900 I � I + 2,700 r Jarf96 Jan -98 Jan -00 Jan -02 Jan -04 Jan -06 Jan -M Jan -10 Jan, -12 Jarw14 1am16 Jan -18 Jarr20 C•] Table 1: Midnight Sun Monthly Production, Injection, Voidage Balance Summary Report Date STS Gas Prod MSCF Water Prod STB Nater IN STB MI IN MSCF Oil Prod Cum STB - .. tASCF Water Prod Cum STB Water IN Cum STB Cum Total Int (MI+Water) RB Net Res Voidage RVB Net Voidage Cum RV9 MonthlyVRR RVBrRVB Jul -18 39,794 174,389 391,838 0 102,218 21,649,416 67,781,247 53,033,022 102,299,195 107,293,289 483,231 18,624,262 0.11 Aug -18 45,891 196,958 501,123 0 221,655 21,695,307 67,978,205 53,534,145 102,299,195 107,424,065 544,321 19,168,582 0.19 Sep -18 45,364 541,026 581,339 0 260,446 21,740,671 68,519,231 54,115,484 102,299,195 107,577,729 806,566 19,975,148 0.16 Oct -18 44,103 360,089 602,265 0 250,902 21,784,774 68,879,320 54,717,749 102,299,195 107,725,761 725,823 20,700,971 0.17 Nov -18 42,958 261,092 386,023 8,663 194,965 21,827,732 69,140,412 55,103,772 102,307,858 107,849,713 467,700 21,168,671 0.21 Dec -18 40,078 297,582 367,292 292,554 0 21,867,810 69437,994 55,471,064 102,600,412 108,151,044 289,875 21,458,546 0.51 Jan -19 43,055 293,830 309,017 295,220 0 21,910,865 69,731,824 55,780,081 102,895,632 108,455,120 227,665 21,686,211 0.57 Feb -19 41,585 343,180 305,208 308,000 0 21,952,450 70,075,004 56,085,289 103,203,632 108,772,360 238,326 21,924,537 0.57 Mar -19 47,133 587,612 466,974 360,418 0 21,999,583 70,662616 56,552,263 103,564,050 109,143,591 500,335 22,424,872 0.43 Apr -19 48,386 517,811 398,779 348,733 0 22,047,969 71,180,427 56,951,042 103,912,783 109,502,786 402,114 22,826,986 047 May -19 42,174 382,940 239,657 395,737 0 22,090,143 71,563,367 57,190,699 104,308,520 109,910,395 104,446 22,931,432 080 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 601 Table 2: MIDNIGHT SUN PRESSURE SURVEY DETAILS co .m iesrs reuurieu nerem were mane in accoroance wlm me applicable rules, regulations and instructions ofthe Alaska Oil and Gas Conservation Commission. I hereby certifythat the foregoing is true and cbrrectto the best of my knowledge Signature Keith Robertson Printed Name Keith Robertson Title Reservoir Engineer Date August 20, 2019 10 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 BIW, A AK 99519612 3 Unit or Lease Name. 4. Field 8W Pod! 5. Datum Ralerence: 8. Oil Gravity, 7. Gas Grdvty- Prudhoe" Unit Prudhoe Bay Feld, MkWtight Sun WW TVDss 25-29 API 0 72 a (Also Pat.. e and 9, AR Pairrber 19., Type 11 AOGM 12 Zone 13 Pbfwatae n[emals Top - SoNomIVLBS 14-Foial Taft 15 Shut-in18 Press 17 BH 18 Depth 19 Final 20 Datum 2i Pressure 22 Pressure at IWnber: 5oxxxxxxxxxxxx See Pool Code Date Tirre, Ho— Sury Type Tenp. TooINDSS Observed NDSS(input) Gradient, psi/ft Datum (cal) NO DASHES Instructions (see pressure at instructions Tool Depth for codes) E-103 500292304500 VN 640158 1 806139-8063 35 03/152019 4776 1 Fl- -64 80 6050 42 3486 E-103 500292304500 W 640158 8061 39-8063 35 10/302018 408 FL .4 330 8050 42 3736 7976.67-8052 94 , 8052 948066 96, 9052.65-9083.29,9052 65-909911, E-100 500292281900 W 640158 9083 23909911,9229 96-9234 65-9234 659244 03 02242019 7080 SBHP 131 8051 3095 8050 42 3095 co .m iesrs reuurieu nerem were mane in accoroance wlm me applicable rules, regulations and instructions ofthe Alaska Oil and Gas Conservation Commission. I hereby certifythat the foregoing is true and cbrrectto the best of my knowledge Signature Keith Robertson Printed Name Keith Robertson Title Reservoir Engineer Date August 20, 2019 10 Table 3: Allocation Factors Month Oil Allocation Factor Jul -18 Aug -18 0.95 0.94 Sep -18 0.93 Oct -18 0.94 Nov -18 0.94 Dec -18 0.95 Jan -19 0.98 Feb -19 0.96 Mar -19 0.95 Apr -19 0.99 May -19 0.97 Jun -19 0.99 11 2019 ANNUAL SURVEILLANCE REPORT ORION OIL POOL PRUDHOE BAY UNIT JULY 1, 2018 -JUNE 30, 2019 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) ........5 8. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS(RULE 9G).........................................................................................................5 9. FUTURE DEVELOPMENT PLANS............................................................................................................... S LIST OF ATTACHMENTS Figure 1: Orion production and injection history................................................................10 Figure 2: Orion voidage history..........................................................................................10 Figure 3: Orion pressures at datum.....................................................................................13 Figure 4: Orion pressures in map view...............................................................................14 Table 1: Orion monthly production and injection summary.................................................9 Table 2: Orion pressure survey detail.................................................................................11 Table 3: Orion monthly average oil allocation factors........................................................15 2 PRUDHOE BAY UNIT 2019 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, 2018 to June 30, 2019. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS RULE 9A During the reporting period, field production averaged 4,955 BOPD, 8.3 MMSCFD (FGOR 1,672 SCF/STB), and 11,042 BWPD (WC 69 %). Water injection during this period averaged 11,848 BWIPD with 12.9 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.98 . 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 913) Reservoir pressure monitoring is performed in accordance with Rule 5 of Conservation Order 505B. A summary of valid pressure surveys obtained during the reporting period is shown in Table 2. This data was acquired using static bottomhole pressure surveys (SBHP) and permanent downhole gauges installed in injectors. A total of 49 statics in 18 wells were acquired over the plan year. 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). For the period of July 15L, 2019 to June 30`h, 2020, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of five pressure surveys will be taken. Acquiring representative regional average pressures continues to be a challenge in Orion wells due to the physical characteristics of viscous oil, multiple sand targets, and multilateral producer wellbores which present a paradigm shift from typical data acquisition in light -oil reservoirs. Pressure gradients around producers and injectors are very shallow due to the low mobility of viscous oil, which results in very slow build-up and fall-off of pressures. Obtaining representative reservoir pressures is further complicated by significant differences in rock and oil properties between sands in the same wellbore, and as a result, productivity (and average sand pressure) varies dramatically between sands. Multilateral producers experience 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 3 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: PoIyE n 1 This polygon contains producer L-200 and is supported by injectors L-2111, L -212i, and L -218i. During the reporting period, no new pressures were acquired, as there was no production or injection from the polygon. "Ion-IAPo This polygon contains producers L-202, L-203, and L-250 and is supported by injectors L-2151, L -216i, L -217i, L -219i, and L -223i. Measured pressures in the polygon range from 1690 psi to 1981 psi. During the reporting period, producer L-203 was offline for sanding issues, L-250 remained online, and L-202 was returned to production after isolating the lateral responsible for increased water production. Consequently, offset injectors were cycled on and off to balance voidage. During the reporting period, it was determined (via production logging) that the Oba lateral in L-202 had a matrix bypass event to the aquifer in January '18. In order to return the well to production, the Oba lateral was isolated. Long term options to remediate the matrix bypass event within the Oba lateral are being evaluated. Polygon 2 This polygon contains producers V-202, V-203, V-204, V-205 and is supported by injectors L-2131, V-2101, V - 211i, V -212i, V -213i, V-2141, V -215i, V -216i, V-2171, V -218i, V -222i, V -223i, V -225i, V -229i. Measured pressures in the polygon range from 1081 psi to 2056 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 matrix bypass event was remediated in early 2014. An additional matrix bypass event was confirmed in the OA sand between producer V-204 and V -222i in October 2018. 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 are being evaluated. To date, no significant increase in OA reservoir pressure has been observed. �1 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 1144 psi to 1871 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 online for most of the reporting period. The most recent reservoir pressure for L-204 is 1144 psi. Polygon 55 This polygon contains producer L -205A and is supported by injectors L -220i and L -221i. Measured pressures in the polygon range from 2007 psi to 2212 psi. Producer L -205A was offline for most of the reporting period due flow assurance issues caused by low flow rates. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS AND SPECIAL MOWTORING (RULE 9C) Production Logs; During the reporting period, production logs were run in L-202 and L -205A. On September 22, 2018, a production log was run in L-202 to identify which lateral was responsible for the increased watercut (aquifer MBE). The derived splits from the production log suggested the Oba lateral was responsible for the increased watercut (81% of the water production). A subsequent logging run in the Oba lateral suggests 65% of the water production is coming from the last —1100' of slotted liner. On August 27th, 2018, a production log was run in L -205A to determine the production splits for the various sands. The derived oil splits from the production log are as follows: Nb 1%, OA 33%, Oba 11%, Obb 9%, Obc 10%, Obd 36%. 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 5 on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining snapshot relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. Infection 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. A project was initiated to improve the L & V pad 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. The upgrades on L Pad included installation of a MicroMotion meter and Phase Dynamics meter, as the L Pad test separator was already in service. The upgrades on V Pad included returning the test separator to service, as well as installation of a MicroMotion meter and Phase Dynamics meter. The L & V pad test separator upgrades were completed in January 2019. The meter prove -up and rate verification was completed with the portable testers in 1Q 2019. Overall, improvements in both well test quality and accuracy have been observed. Over the reporting period, the monthly average of daily oil production allocation factors fell within the range of 0.82 and 1.02 . Any days with allocation factors of zero were excluded. The monthly averages of A 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 Project - Waterflood: Primary production from the Orion oil pool commenced in 2002 and continued until waterflood was initiated in 2003. The waterflood patterns are designed to ensure reservoir pressure is maintained above the bubble point pressure and as close to the original reservoir pressure as possible. Because of differences in rock and oil quality, the various sands behave like different reservoirs connected in the same wellbore, thereby requiring a much higher degree of control in the injectors to manage voidage. The basis of design for water injectors has evolved to include isolation packers between sands to accurately control injection rate into the vastly different sands. Injection rate into each zone is controlled by downhole waterflood regulating valves installed in mandrels adjacent to the target sand. To prevent freezing, a minimum injection rate of 500 BWIPD is being used for all new waterflood regulating valve designs. In patterns where the minimum injection rate results in a high voidage replacement ratio, injectors in the pattern are cycled. During the reporting period, average injection rate was 11,848 BWIPD. Cumulative injection through June 2019 was 55.5 MMSTBW, which has been injected in 36 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Proiect - Miscible Injectant: In 2006, approval to implement an enhanced oil recovery project in the Orion oil pool using Prudhoe Bay miscible injectant was granted via C.O. 505A. Injection of miscible injectant began later that year in the updip portion of Polygon 2. The current MI strategy is to inject smaller slugs of miscible injectant to improve the efficiency of the flood. To date, miscible injectant has been injected in Polygon 1A, Polygon 2, Polygon 2A, and Polygon 5. During the reporting period, average injection rate was 12.9 MMSCFD. Cumulative injection through June 2019 was 31.6 BCF, which has been injected in 26 water -alternating -gas injectors. No new water - alternating -gas injectors have been placed into service during the reporting period. Reservoir Management Strategy: The objective of the Orion oil pool reservoir management strategy is to manage reservoir development and depletion to maximize 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 rA 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, matrix bypass events between V -212i and V-204 (OA and Oba sands) and V - 222i and V-204 (OA sand) were confirmed via separate red dye tests. Options to remediate the matrix bypass events are being evaluated. 7. PROGRESS OF PLANS AND TESTS TO EXPAND THE PRODUCTIVE LIMITS OF THE POOL (RULE 9F N -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). 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. 9. FUTURE DEVELOPMENT PLAN Future development plans are discussed in the 2019 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 25th, 2018, a copy of which was provided to the Commission. The Commission will be copied when the 2020 update of the Orion Plan of Development is filed with the Division. 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 -18 65,585 77,549 130,826. 204,655 293,608 , 36,544,739 34,680,344 16,009,694. 51,355,158 67,889,991 -148,876 -1,518,573 1.64 Aug -18 96,910. 136,439 163,464 219,902 394,381 , 36,641,649 34,816,783 16,173,158 51,575,060 68,344,777 -130,629 -1,649,202 1.40 Sep -18 169,806. 277,418 384,003. 244,663 319,191 , 36,811,455 35,094,201 16,557,161 51,819,723 68,780,209 253,740 -1,395,462 063 Oct -18 189,073. 299,298 507,957 291,951 231,295 , 37,000,528 35,393,499 17,065,118 52,111,674 69,211,544 411,559 -983,903 0.51 Nov -18 165,992. 276,336 416,394 374,366 282,185. , 37,166,520 35,669,835 17,481,512 52,486,040 69,756,142 173,558 -810,345 076 Dec -18 171,548. 294,679 681,483 376,170 433,757 , 37,338,068 35,964,514 18,162,995 52,862,210 70,391,991 365,375 -444,971 0.64 Jan -19 145,631 261,392 311,775 394,343 467,489 , 37,483,699 36,225,906 18,474,770 53,256,553 71,066,096 -86,936 -531,907 1.15 Feb -19 142,120 268,038 272,420 355,299 502,170 , 37,625,819 36,493,944 18,747,190 53,611,852 71,721,228 -106,637 -638,543 1.19 Mar -19 171,554 293,020 292,006 397,688 612,904 , 37,797,373 36,786,964 19,039,196 54,009,540 72,484,506 -156,401 -794,944 1.26 Apr -19 170,083 281,960 293,781 448,874 488,848 , 37,967,456 37,068,924 19,332,977 54,458,414 73,226,289 -140,831 -935,775 1.23 May -19 170,859 290,952. 317.767 515,301 412,585 , 38,138,315 37,359,876 19,650,744 54,973,715 73,990,168 -132,767 -1,068,542 1.21 Jun -19 149-414. 265,985. 258,471. 501,457. 287 244 38.287,729 37,625,861 19.909,215 55,475 172 74.666.114 -136 ,837 -1-205.379 1.25 �61 FIGURE 1: ORION PRODUCTION AND INJECTION HISTORY 25,000 m F 22,500 u G 20,000 0 N 17,500 w 15,000 n m �I oll —Mllnjeclion Rate —GOR Water I*dl— Rate p 7,500 `w � 5,000 3 2,500 0 4 4 C C C C Ic C C C N R T A i0 A N q A N FIGURE 2: ORION VOIDAGE HISTORY 100,000,000 > 95,000,000 90,000,000 Iv m 85,000,000 v 'p 80,000,000 75,000,000 z 70,000,000 E 65,000,000 10 60,000,000 H � 55,000,000 50,000,000 45,000,000 3 40,000,000 ± 35,000,000 m 30,000,000 3 25,000,000 a 20,000,000 0 15,000,000 10,000,000 5,000,000 0 1. 0 o g o o ", w C C C C C C C C C C C C C C C C C C 100% 90% 90% 70% 60% 50% 3 40% 30% 20% 10% 0% 4.0 3.8 3,6 3.0 - 2.8 2.6 2.4 m -2,2> 2.0 j a -- 1.8 1.6 j - 1-4 1-2 1.0 0-8 - 0.6 04 0.2 - 0.0 10 TABLE 2: ORION PRESSURE SURVEY DETAIL- PART 1/2 11 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT I. Operator: 2. Address BP Fxpiorelan (ALuka) Inc P.O Box 196812. 900 E IlBe Blvd, Aacaorage, AK 99519-6612 3 Unit or Lease fine: 4 Feld and PD01 5 Datum Reference: 6 Oil Gravity: 7. Gas Gravity: Prudhoe Bay Lind Prudhoe Bay Feld, Orion Oil Pool 4400 TVDss 15-23 0.7 a Y*1 Name and 9.AHNrlrher 10, Typo 11 AOGCC 12-Za06 13 Purfor4lcd Intervals Top. Bottom TVDSS 14. Finaf Test 15. S1Wr.11 18. PME& 17. WK la. 0OPM 19. Fn l 2D. Dalum 21 pm * 22-Prnssure art h1u ber: 50XXXXXXXXX)D(X See Pool Code Dale Time Hours Sury Type Terrp. ToolTVDSS Observed TVDSS(input) Gradient,psi/fl Datum (cal) NO DASHES Instructions (see Pressure at instructions Tool Depth for codes) 435, ZU44. 4655.1470, 4499-d 505. 4514 43954404, 43934 52 V-205 50029=380000 O 640135 CA4000-075d 4511, 456"16, 4620-4617 08/10/18 528 SBFP 4250 1385 4400 .43 1450 277-41M 47n,42M. 4457.4446, 44454451, 4512-4544, 4 Nb+OBa+OBc _ OBd 4589,4591-4588,4608-4664,4672-4688,4685-4699,4632- L-203 50029234160000 O 640135 4668,468246.54,4648-4642 06/27/19 1047432 SBFP 82 4194 1899 4400 040 1981 OA+01B4.0W 4355.4397, 4409.4474, 44074482, 45094540.4459-4577, 48 L-204 50029233140000 O 640135 +OBC+OBd 4861.4555-4567,4574.4645,4653-4691 08/06/18 432 SBFP 4204 11766 44110 040 1144 40234022,4163-4165, 4227-4229, 4277-4279, 4333-4334, 4 L -205A 50029233880100 O 640135 OBb+ObOB d+Obe 4396,4448-4453 12/08118 1200 SBI -P 3989 1834 4400 0.40 2007 L-219 5OM233760000 VWG &101135 OA 4419-M45 DEM119 29258 .331-P E3 4%2 1532 4400 OA4 1x 49 L-219 50029233760000 MAG 6 60135 COs -. _,04492 )5wI9 22256 S9l-11, 4479 1721 4400 D-44 1690 4881.4865, 4889.4872, 6876.4679, 4653.4685, 4688-4890, 4891 Obd (o6 4692, 4693-4693, 4762-4691, 4691-4690, 46894688, 4687- L-219 50029233760000 WAG 640135 4M 46864688.,4686-4687.46594690.4691-4692 06131VN9 29256 SBFP 87 4652 1824 4400 044 1713 L-220 5DQ2923387DW0 YaAG 640135 NU 4116;136 wKirvi6 406 SBI -P SL 4052 1902 4400 044 2065 4-M 59429233670000 WAG 640135 OA 4250.4291 M"ti 4G8 SBP 86 4293 1s53 4100 D44 2070 L-220 50029233870000 Mr 840135 Oho 4318-4347 Da705118 408 3" 91 4396 2157 4400 0.44 2197 L-220 5W2 923 3 611=1 MIS 660135 O6 7 438(h4377-4414.4431 D6R19na 408 SSFP 93 4362 2135 4400 0-84 2152 L•220 50029233570000 WAG 640435 Ohd 4468.4571 98A5118 405 SM -11' 91 4457 2166 4400 044 2141 L-221 5DUM3650wo VAG 060135 M 4090-4105 05!11119 24338 S" 53 4036 1985 4400 DAA 2114 L-221 50929237850000 V G 640135 OA 4222.425a 05911119 243W SBFP 58 4176 2114 4400 0-44 2212 L-221 50029233850000 WAG 640135 Oho 42854316 W11119 243W 38FP 85 4276 2113 4400 9-44 2188 L-221 sa14a993A4oryln VAG 616135 OtRrOaC .49!2-4401 DSrltn9 243M SSW 59 4329 2114 4400 064 2145 L-221 59029233850000 VAG 840135 O00 44594451 05!11119 24938 S81 -P 90 4426 2215 4400 044 2204 L-722 54029234200000 VAG 640135 OA 43474367 050=18 6405 SBHP 4296 1335 4400 0-a4 1365 L-2.22 5002823429000E WAG e40t38 Oba 47784412 OSR18r19 6408 GBhP 4370 1728 4400 0.44 1739 L-222 50029234200400 WAG 640135 Ohd 4521-571 05r06n9 6605 GWFP 4514 1751 4400 0.64 17171 OA+OBe+ OBb+OBc+OB 42494274, 4306-4331, 4342-4365, 4397-4426, 4455-4486 V•2f13 50029232850000 O 640135 0 08/05/18 408 SBFP 4125 1291 4400 OAG 1401 11b+OBa+OBb 44, 4852-631, M52 -4H3, 4445.4434, 44434131, 464584 + + 4643,4696-4684,4681-4654,4678-4665,4803-4802,4805- V-207 50029233900000 O 640135 4793, 4779.4885, 475-3.47U,4844-4827 omma 456 SBFP 88 4407 1461 4400 040 1458 V•21S 50029233516000 VAG 640135 OA 437G4404 11 x2211a 30450 SBef 89 4347 1837 4400 0-44 1880 V-210 50029233970000 MG 6401135 tip - 11AWIa 1725 SBFP 90 4616 1$78 4400 044 1271 V-210 50028233970000 WAG 640135 Ota 4826-4656 11MU 1725 SBFP 92 4613 1618r 4400 044 1324 V-219 50029233427WM WAG 040135 Ohb 486 -Mill 114ena 1728 SOW 93 1 4685 1960 4400 044 1843 V-210 50029233970000 YAG 640138 13G41+CM 4709.4810,484$4868 1110an6 !TIB Saw 93 1 4752 me 4400 0,44 1871 11 TABLE 2: ORION PRESSURE SURVEY DETAIL - PART 2/2 'Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect wlume 12 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: BP ExpWiaw (ABs* Irr- 2 Address: P.O. Box 196612, 900 E Benson BW., Anchorage, AK 99519-6612 S. 4km or Leese N m Prudhoe Bay Und 4 Fed and Pool: Prudhoe Bay Fed, Orion W Pool 5 Datum Reference: 4400 TVDss 6 Oil Gravity: 15-23 7 Gas Gravity: 0.7 6. Wel Na m. and Wrrber: 9. An Nurrber 50� NO DASHES 10 Type See Instructions 11 AOGOC Pool Code 12. Zone 13. Ferioratea Intervals Top - Bottom TVDSS 14 rinai Test i 5. Shut-in Date Tine, Hours 16 Press Sury Type (see instructions for codes) 17 B H Tenp 18. Depth Tool TVDSS 19. F1nai Observed Pressure at Tool Depth 20- Datum TVDSS (input) 21 Pressure 22. Pressure at Gradient, psi/ft Datum (cal) V-772 50ui92336Tu000 1AIAG 540135 OA 4326-4364 10/06/16 936 SBHP 81 4248 1014 4400 0-44 1061 V-222 50029233Si000a WAG640135 Oba 4393-4421 10A81ts 938 SOW 4T76 2045 4400 OA4 2056 V.= 50029253570000 WAG 640135 OBb+OBc 44.9}4430.4{654503 OaR2ffd 376 Saw 4433 1825 4400 0.44 1810 V-222 50029233570000 WAG 640135 CW 4448-4578 MOWS y36 SBFP 4532 1744 4400 044 168E V-223 5002._... . 50029233640000 WAG 640135 CM 4419-4456 06YdN19 ii544 5BiP 84 4397 1824 4400 0.44 1825 V-223 50029233840000 WAG &10175 Oda 4485-4513 08!30119 11544 SSFP 4471 1810 4400 044 1119 V-224 50029234000000 WAG $40135 W 4466-4485 IWMT8 935 5131i3 90 4450 1581 M00 0.44 1559 V-224 5x029234000000 WAG 640135 Obs 4574-4704 1012811E y36 SHFP 92 4624 1660 4400 044 1561 V-224 50029234000000 WAG 640135 071313 4718-4736 10rzili18 936 5BFP 94 4718 1690 4400 0-44 1550 V-224 50024234690000 MG 840135 OW 4832-4881 11/01/18 5880 SBHP 94 4801 law 4400 0 44 1630 V-224 50029234000000 WAG &10135 Obe 4903-4926 1110111$. 5880 513HP 95 4901 2082 4400 0.44 1862 V-225 50029234190000 WAG 840136 (.m 4571-4576 mrsaN9 )188 SBFP 93 4522 1909 4400 044 1655 V-227 50029234170000 W 640135 hG 4449-4462 ue/3'u/i9 70344 Saw 68 4403 1859 6400 0.44 1555 V-227 50029234170000 W 640135 ODa 4534-4662 08!30119 70344 SSFP 92 1 4596 1543 4480 044 1457 V-227 50029234110000 WI 840M Oob 4677-4695 ovili11g 70344 SBHP 93 4673 1692 4400 044 1572 V-227 50029234170000 WI 640135 Obd 4790-4837 3630119 70344 Saw 94 4760 1845 4400 0-44 1587 V-227 591279234170000 11M 640135 Gbe 4854-4876 Writing 70344 SBHP 97 4854 2032 4400 0.44 1832 V-228 6=923464=0 NB1G 1 640135 OA 4339-4377 0//13118 1488 SBFP 90 4325 1384 4480 044 1417 V-229 50049234840000 'VV,vO'; 8001 a5Oba 4403-4431 01/13/18 1488 WHIP 93 4395 180 4400 044 1771 V-229 uu29z3 S4640000 iivAG 640135 Obb 4446-4464 07/13/16 1486 SBHP 94 4446 i9s9 4400 044 1919 V-229 Suuz9234ti40000 WAG 540135 Ohc 4605-4515 07/13/18 1466 SBFP 95 4x99 20>'I 4400 0-44 2013 V-2"29 50029234640000 WAG 640135 0`]btl 4553-4593 1 07113/18 1488 SE -1w 92 4594 1733 4400 044 1648 23 All tests reported herein w ere made in accordance w ith the applicable rules, regulations and I hereby certify that the foregoing is true and correct to the best of ny know ledge Signature Ken Huber Printed Name Ken Huber instructions of the Alaska Oil and Gas conservation Conrrission Tile Reserwir Engineer Date July 24th, 2019 'Other: Static pressure for water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect wlume 12 FIGURE 3: ORION AVERAGE PRESSURE AT DATUM 13 2700 -- - 2600 2500 2400 2300 2200 20 2100 2000 1900 IA 1800 a 1700 1600 1500 1400 1300 1200 1100 0 I m ♦ V-215 ♦ V-219 ♦ L-200 L-a1z ♦ L-205 ♦ L-200 ♦ ♦ L-211 ♦ 1*20k-21 i ♦ L-205 ♦ � _' * U -,2T ♦ L' ♦ L' ♦ LOO so -a ♦ L,22S V"L+� L-i0D V-104 +y�yyy,. '` ��yy�� ♦ V.i76 �. mMT ' 00♦ ♦n Y * L�20!AL ♦ I ♦ 1 S j*R)W A V•21+ ; LW L -* Lys; L-278 « 4LSil8 LL �33 + V•aYs '�- 444wgtwa ♦ *21-223 L�.S�j L -2 ♦� `-" L-•na ` ♦ L,2.. V' ♦•,CSW �_yx�' _2 L-23a� ♦ l -_� ♦ L-2'e*Ass' 4.. ♦ L•7:5 ♦ V �6 ♦ Y.2+i« V-232 ♦ 0,ti 1lv•=y ♦ Y--72: ♦ Y•219 ♦ V-2Segg ++ ..��__�� ,+� ♦ L.2M V-204 'f.;03 1 .n.E Y•:277 • L-2 _� Y ,i ��f ♦ V.21T ♦ V.1� ti. ♦ �•.� ♦ V"*1 Y-]1' ♦ Y I V• 1 ` ♦ L 204 4�S�P �* * t. ♦:06214 YvY' a ♦ 1227 •, Vti3C * 10- ♦ V'2f V-216 + V-22. • V-'&14 �►L v Y.2y V40a V4➢3 V�3 ♦ V-207 C C 0 r -i 0 ♦ L-204 I � 0 0 0 0 � I I I 1 � 1 c c c c c c c m m m m m m m m m m m m Survey Date ♦ 0 r -i 0 ♦ L-204 I � � cc �o c m m m Survey Date ♦ ♦ L-204 ♦ L-204 ni m 1*1 Ln �o oo rn c c c c I c c c m m m m m m m m 14 FIGURE 4: ORION PRESSURES IN MAP VIEW I L7W4�-0! J. L!e L477 L-2aoL1Y 1 •20QL2 l LL--7W)5k, r�h4�j y •l L -21i LAf5 L-7MI • 19i� ' L4wu �iah' �a1 AL -IM e L4YXL7 Lav7Lr L -2m L. • L�L•>!P! •'ter u^ ` L•tet i fl L .m1if Am K203^k V- 2 7L • Y• r I L 721Av-2WL2 Y 591 L20 •• • V-114 Y4 L,te *2123 vxa v- Lt L•20 LQG617 rLL-72a V-211 ar Yp 4 a 16320 • t83d•-, 4n! 1858 v -les 1498 �i66 ya17 \ r62 i Y 11 8nx r�S R e I uaexe o.a o as ' • ats...a.w.e......vr.r...xnpr�o-�.aa..� ®rare r.n e,.h... L�I ria �. �m eaerae.6 eraM: Orion Field — giisd.�R...e wo,snaaeeven.veraarwaaor Last Static Pressure emxn: rrue� w.encm rsn NS to Wig A 611 Pressures are averaged win or wmirgw 10 MAP 1 15 TABLE 3: ORION MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -18 0.82 Aug -18 1.02 Sep -18 0.87 Oct -18 0.88 Nov -18 0.83 Dec -18 0.84 Jan -19 0.84 Feb -19 0.87 Mar -19 0.85 Apr -19 0.85 May -19 0.85 Jun -19 0.84 iv. 2019 ANNUAL SURVEILLANCE REPORT POLARIS OIL POOL PRUDHOE BAY UNIT JULY 1, 2018 -JUNE 30, 2019 r r1AITFKITC 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 S. FUTURE DEVELOPMENT PLANS....................................................................................................... 8 LIST OF ATTACHMENTS Figure 1: Polaris production and injection history........................................................................................... 10 Figure2: Polaris voidage history...................................................................................................................... 10 Figure 3: Polaris pressure at datum................................................................................................................. 12 Figure 4: Polaris pressures in map view.. .... ................................. .................................. ........ -- .................. 13 Table 1: Polaris monthly production and injection summary............................................................................ 9 Table 2: Polaris pressure survey detail........ 11 Table 3: Polaris monthly average oil allocation factors................................................................................... 14 V, PRUDHOE BAY UNIT 2019 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, 2018 through June 30, 2019. 2. VOIDAGE BALANCE BY MONTH OF PRODUCED AND INJECTED FLUIDS (RULE 9A) During the reporting period, field production averaged 3,969 BOPD, 3.5 MMSCFD (FGOR 879 SCF/STB), and 5,935 BWPD (WC 60 %). Water injection during this period averaged 7,178 BWIPD with 4.5 MMSCFD of miscible gas injection. The average voidage replacement ratio was 0.82 . 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 913) 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. A total of 22 statics in 12 wells were acquired over the plan year. 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). For the period of July 15L, 2019 to June 30`h, 2020, a minimum of one pressure survey will be taken in each of the active representative areas that contain active wells. If all active representative areas contain active wells, a minimum of four pressure surveys will be taken. 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 3 to allow maximum build-up or fall-off. Even after a long shut-in time, wells show build-up or fall-off rates of several psi per day. In light of these challenges, significant effort is being made to obtain high-quality initial pre-injection or pre- production pressure surveys relatively unaffected by pressure gradients applied to the wellbore. Whenever possible, initial pressures by zone are being obtained with an MDT in new producers, or via downhole gauges in injectors. Injector data is expected to become increasingly important as the flood matures. Once development is completed, this becomes the only practical way to collect pressure data on a zonal basis. An analvsis of the recent ❑ressure data by oolveon follows. S -Pad North This polygon contains low -rate jet pump producer 5-201 (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. During the reporting period, no new pressures were acquired, as there was no production from the polygon. S -Pad South This polygon contains producer 5-213A and is supported by injectors 5-215i, 5-217i and 5-218i. Measured pressures in this polygon range from 1034 to 2303 psi. The lowest pressure in the polygon was observed to be injector 5-215i's OA sand. In 2017, a matrix bypass event was confirmed in the OA sand between producer S -213A and injector 5-2151. The OA sand in injector 5-215i was subsequently isolated by replacing the waterflood regulating valve with a dummy valve, thus allowing the injector to remain online while remediation options are being evaluated. 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-2121, W -213i, W -214i, W-2151, W -216i, W-2171, W -218i, W -219i, W -220i, W -221i, and W-2231. Measured pressures in this polygon range from 1494 to 2489 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-2231 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. In July 2017, the Oba lateral in W-202 was isolated via an isolation sleeve to minimize offtake from the aquifer MBE. Options to re -treat the matrix bypass event in the Oba lateral of W-202 are being evaluated. 4 W -Pad East This polygon contains producer W-203 and is supported by injectors W -207i and W -210i. Measured pressure in the polygon for the Oba sand was 2327 psi. The pressures on the upper end of the range are typical injection -induced high pressure regions around the injector, which does not represent a polygon average pressure due to the very slow pressure fall-off. 4. RESULTS AND ANALYSIS OF PRODUCTION & INJECTION LOGGING SURVEYS AND SPECIAL MONITORING (RULE 9C) Production Logs: No production logs were run during the reporting period. Prior production logs have frequently been adversely affected by well slugging. Future production logging candidates will be evaluated on a case by case basis. Well fluids sampling A well fluids sampling program is ongoing to gather high quality and frequency surveillance data: (1) Uncontaminated wellhead samples are obtained monthly to quarterly on each producer, and tested for API, viscosity, WC, and sand quantity. This data helps track changes in production from different sands, waterflood or MI response, and sanding tendencies. A portion of these samples are later used for geochemical production allocation analysis. (2) Wellhead samples are analyzed quarterly for water properties to identify changes between formation water production and waterflood breakthrough. This data is also useful for identifying matrix bypass events (MBE) because produced water will have similar properties as injected water. (3) A produced water supply sample is analyzed quarterly to serve as a baseline for analysis of well production samples. (4) Gas sampling is done monthly or quarterly depending on WAG activity in the polygon to establish gas chromatography signatures and track returned miscible injectant (MI). Geochemical Fingerprinting This technique has been in use since 1999 in the North Slope viscous oil developments, and has shown promise in obtaining a snapshot or relative oil flow splits from individual sands. This data is useful in gauging zonal well performance, identifying problem laterals, and providing a basis by which to optimize offset injection. Wellhead oil samples are taken on roughly a quarterly basis, or as well performance changes. Results to date are mixed with reasonable allocations in some wells, but questionable data in others. Work is ongoing to gather additional baseline oil samples, and improve analysis techniques to improve data value. In'ectiJ o During the reporting period, injection logs were run in W-207 and W-212. 5 On August 13th, 2018, an injection log was run in W-212 to determine the injection splits for the various sands. The derived splits from the injection log are as follows: Oba 64%, Obc 21%, Obd 15%. On September 30th, 2018, an injection log was run in W-207 to determine the injection splits for the various sands. The derived splits from the injection log are as follows: Oba 100%, Obc 0%, Obd 0%. 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 Iniectors Monitoring of individual zonal pressures is continuing on all injectors with downhole gauges installed. Real- time data has confirmed offtake from offset producers, formation and healing of MBE's, pressure transmission across the OWC, and helped tremendously in identifying underperforming injection zones. The current Polaris injector basis of design calls for individual zonal pressure gauge installation in all future injectors. 5. REVIEW OF POOL PRODUCTION ALLOCATION RULE 9D AND REVIEW OF POOL PRODUCTION 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 0.82 and 1.02 . 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 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 7,178 BWIPD. Cumulative injection through June 2019 was 33.6 MMSTBW, which has been injected into 18 water injectors. No new water injectors have been placed into service during the reporting period. Enhanced Recovery Proiect - 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 4.5 MMSCFD. S Pad MI was down from 3Q 2018 to 1Q 2019 for planned maintenance (mapegaz valve replacement). Cumulative injection through June 2019 was 8.2 BCF, which has been injected into 14 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 identified. 7. RESULTS OF MONITORING TO DETERMINE ENRICHED GAS INJECTANT BREAKTHROUGH TO OFFSET PRODUCERS (RULE 90 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). 7 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: 5-213A and W-204. 8. Future Development Plans Future development plans are discussed in the 2019 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 25th, 2018, a copy of which was provided to the Commission. The Commission will be copied when the 2020 update of the Polaris Plan of Development is filed with the Division. TABLE 1: POLARIS MONTHLY PRODUCTION AND INJECTION SUMMARY Report Oil Prod Gas Prod Water Prod Water Inj MI Inj _Date STB MSCF STB STB Net Res MSCF Jul -18 73,201. 49,745 120,786. 178,144. (MI+Water) 163,240. Aug -18 114,993. 78,813. 153,556. 139,090. STB 54,101. Sep -18 120,987. 62,673. 162,813. 183,465. , 248,952. Oct -18 150,934 99,928. 222,576 204,801. , 259,410 Nov -18 134,763. 102,781. 166,575 243,085 23,523,334 189,160. Dec -18 115,703. 71,021. 182,813 225,653 , 211,715. Jan -19 137,182. 105,041. 238,183. 241,177. , 137,187. Feb -19 124,060. 123,750 155,059. 199,446. , 164,723. Mar -19 134,417. 150,261 167,794 236,473. 37,094,995 72,922. Apr -19 122,269. 169,523. 207,412. 225,519. , 34,093. May -19 113,768. 133,815. 192,294. 273,325 16,279,523 56,158. Jun -1 9 106.473. 125.749. 196,480. 269.853. 21,162,071 64.843. Oil Prod Cum Gas Prod Water Prod Water Inj Cum Total Inj Net Res Net Voidage Monthly VRR Cum Cum Cum (MI+Water) Voidage Cum STB MSCF STB STB RB RVB RVB RVBIRVB 23,287,354. 20,367,803. 14,997,948 31,166,305. 35,510,938 -65,458 6,972,968 1.31 23,402,347 20,446,616 15,151,504 31,305,395 35,683,879 124,429 7,097,397 0.58 23,523,334 20,509,289 15,314,317 31,488,860 36,018,550 -27,802 7,069,596 1.09 23,674,268 20,609,217 15,536,893 31,693,661 36,381,045 47,792 7,117,388 0.88 23,809,031 20,711,998 15,703,468 31,936,746 36,740,057 -20,292 7,097,096 1.06 23,924,734 20,783,019 15,886,281 32,162,399 37,094,995 -30,111 7,066,984 1.09 24,061,916 20,888,060 16,124,464 32,403,576 37,420,896 88,352 7,155,336 0.79 24,185,976 21,011,810 16,279,523 32,603,022 37,721,171 28,890 7,184,226 0.91 24,320,393 21,162,071 16,447,317 32,839,495 38,003,762 83,549 7,267,775 0.77 24,442,662 21,331,594 16,654,729 33,065,014 38,251,992 159,855 7,427,630 0.61 24,556,430 21,465,409 16,847,023 33,338,339 38,561,745 54,902 7,482,532 0.85 24,662,903 21.591,158 17,D43,593 33,608,192 38,873202 45,806 7.529,338 0.87 0 FIGURE 1: POLARIS PRODUCTION AND INJECTION HISTORY 15,000 F 14,000 u 13,000 y 0 12,000 l7 11,000 u 10,000 a 9,000 is 8,000 a 7,000 m y 6,000 m C 5,000 O od 4,000 `w � 3,000 3 2,000 1,000 0 8 0 0 0 o 0 0 c c c c c c c c c c c c 9 A 9 FIGURE 2: POLARIS VOIDAGE HISTORY 40.OW.000 j 38,000,000 N ^ 36.000,000 ^ x 34,000,000 •• 32.000,000 30.000,000 29.000.000 26,000.000 c 24,000,000 22.000,000 e 10.000,000 r 18,000.000 w 3 16,000.000 14.000.000 m 12.000,000 10.o00.ow a 8.000.000 b 6,000,000 4.000.000 2,000,000 0 100% 90% 80% 70% 60% 50% 3 40% 30% 20% 10% 0% 20 I 18 16 14 1 11 m lo o< os % 06 04 O2 00 10 TABLE 2: POLARIS PRESSURE SURVEY DETAIL 1/1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator: 2. Address: SPExO1antKYS (AWmkii) 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 $ WelNwmnber: and 9 AFtiwrtOer Type Prudhoe Bay Field, Polaris Oil Pool 5000 NDss 1523 0 7 10 11 12 [one 13 Perforated Intervals Top -Bottom NDSS 14. Final Test i5 Shut-in 16 Press. 17,B -ti 18 -Depth i9. Fina% 20 Datum 21 Pressure 22 Pressure at Number: SOX'.J00{XXXXXXX See Pool Code lCode Date Time, Hours Surv. Type Tenp TooINDSS Observetl NDSS(input) Gradient,psVrt Datum (cal) NO DASHES instructions (see Pressure at instructions Tool Depth codes) Ylifor 59024230870000 O w160 pBa•pBc,pl3d 4975.5125.5050-5125. 511x-5175 0ti/08118 480 SSFP 9.4 4398 1725 W- W205 50029231650000 O 64160 OBa+OBc+OBd 4y1;i4962, 49845015, 50445051, 5052-5092, 5109-5159 06/06/18 456 jBHP 90 4921 1793 -14W 5000 044 1770 W-211 50029230800000 O 64160 Oh7eOW-OCe 4982-4991,5042-5071,5106-5135,5173-5178 09AW1113 458 SBHP 87 4470 1333 044 1828 5215 50029231070000 WAG 64160 OA 493&500$, 5006.5315 12727/18 M1fi SBHP 89 4475 71123 5000 044 1 1562 5215 5002923iu/0000 WAG 64160 Oba 5032-5059 12/27/18 4416 SBHP 5022 1190 5000 5000 0.44 044 303e 5215 50029231070000 WAG 64160 Obb+Obc 506&5085,51135133 12/27/18 4416 SBHP 95 5067 2259 3000 1180 S-215 50029231070000 WAU 64160 Obd 51635196 t2J2//iti 044 2229 5-217 VfYI &1160 OA 4960-4989 04/21!19 4416 840 SBHP samP 81 5151 4921 1546 1869 5000 5000 044 044 i5N0 1904 5217 5UU29233620000 WI 64160 Goa 5007-5023 04/21/19 840 SEHP 5001 1334 Suuu 0.44 1334 -5-218 50029234140000 WAG 64130 081 5050-5067 0426!18 499 SBHP 66 5041 0321 5600 044 2303 S-218 50029234140000 WAG 64160 0Bb+OBc bUM-5105, 5140-5151 09/e6lt8 406 SBHP 88 5ui16 2341 5000 044 2303 S21$ 50029234i40000WAG 64160 Oed 51855225 0425118 408 SBHP 92 5109 2383 5000 0.44 2302 4971-4969, 4988-4988, 4983-4986, 50555123, 51235134, 5135 W-202 50029234340000 O 64160 OBa+OBc+Obd 5119,5161-5158,5123-5125,5140-5180,5180-5181 08/03/18 360 SBHP 95 4917 1809 5000 0.40 1842 4W73-4889, 4852-4866, 4901-4852,4909-4881, 4950-4968, 4969 W-204 50029233330000 O 64160 OBa+OBc+OBd 4940,4992-4950,4980-5036,5029-4978,5048-5019 08/06/18 408 SBHP 88 4840 1430 5000 040 W-210 50045233390000 WAU b4iti0 OBa+OBb 4893-4928 08/09/18 4au SBHP 4884 2259 5000 044 1494 2310 W-21350029233540000 WAG 64160 OBa 46%1-4894 10S/u5719 3288 SBHP 4799 [139 3000 044 2327 W-217 50029234180000 WAG fia16II OBa 4915-5940 'U9lU1/i8 1032 SBHP 08 4881 1527 5000 044 i679 W-217 50029234160000 WAG 64160 Dec 49945019 09%01/18 1032 SSFP 86 4974 2041 5000 Oqd 20.52 tiv-Lli 50029234160000 WAG 641 eu oua 5050-5088 09/01/18 1032 JIiHF' 82 5053 2002 5000 Dad 1979 W216 50029234030000 WAu tiaiti0 Oba 4948-4970 08/13/18 575 SBHP 89 4929 2440 5000 044 2471 w -21a 50029234030000 WAG 64160 Obc 5032-5055 utl%1 J/tti Sib SBHP 89 SODS 24//4 5000 044 2471 1iv-2iti 50024234030000 WAG 64160 OW 508 -5127 0&04116 3$0 1 SSFP 66 5092 2529 5000 O.e4 2489 23 All tests reported herein w ere made in accordance w ah the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission I hereby certify that the foregoing is true and correct to the best of my know ledge Signature Ken Huber Tale Reservoir Engineer Printed Name Ken Huber Late ,July 24th, 2019 'Other: Static pressure Tor water injectors were calculated based tubing fluid level shots and water gradient below known freeze protect volume 11 FIGURE 3: POLARIS AVERAGE PRESSURE AT DATUM 12 3000 2900 2800 2700 -� 2600 2500 - ♦ W-210 ♦ W-289 ♦ ♦T16b-218 ♦ S,216♦ w-zos i♦'"�uP1a 2400 ♦ w-Tt5 ♦ W-218 + �•� ♦ W-220 'W-218 /R •N 2300 ♦ �5'1�"£'10 «w�s� 5-215 ♦ ♦ � y��.0♦ ♦ n'v'13'� ♦ � S Ci CL ♦ W-2118 ♦ 5215 ♦ 5216 �� W.2'; # R'�L,. ♦ 3•2.7 Yiy� "T ♦ P:•2TJ � YILlE 2200♦♦ri15 _ ♦ W2•Q ♦ 215 � W'�`- W -21T 0 VMSW- S•iid ♦ W-282 A, L♦ ♦ S-200♦ ♦ X♦TJ'&-* x -2:O ♦ n.Tt. 13 ♦ t� 5218 '�' y 2100 '♦�34 wa75 i s: w.?AR Yw2:d w'�1 �13aT! ♦ ♦ s-2S"f� ♦ sial N# ♦ SaOD ♦ 5217 ♦ W � M• z!"f S-Ao♦ S11B L- 2000 • s•:vt ♦ + ?7 s••2i11♦7 �i ri ♦ W-203 ♦ RF 0!"18 5-215w ♦♦w ♦ szQr ♦ w♦.a ♦ 1} 52 1 5217+W1900 11sdap:4lt�• ♦ 94D5 . af�"•t ♦ W.a1Q +� ♦ w 9.7Qi i wa1Q ♦ &at! W21p ♦ W-282 ♦ k�T. # 1800 ♦ w,20 ♦ ♦*max= ♦ WDA W anD ♦ �21�-203 1700 ♦ W-200 ♦ W-200 ♦ W-201 «Wgi 5 ♦ X288216 ♦ W.20A ♦ W-aaa i w•xD. 1600 * =s • 8-21S ♦ W ♦ a< ♦ v, -2o0 ♦ W,2ti 1500 + ♦ S2T3 ♦ Y zO6 ♦ 5215�¢ ♦ 4k.^, -i• ♦ W-204 1400 n oo rn o -1 r*4 m Ln Lo n oo rn o -1 rq m C Ln (D n oo rn rn rn rn o 0 0 0 0 0 0 0 0 0 1-1 C C !` C C C C C C C C C C C C C C C C C C C C Survey Date 12 FIGURE 4: POLARIS PRESSURES IN MAP VIEW 13 I aao+ e t a•2oa � � I �a ISO ��-`— ails sa1�1s>I e•211� �� i ua, *2303 :-212at2 � i W -2I0 W204LZ A .34 hw-204 AW -210 xerr■ w.xan2� W-217 W223 ■ 1 A f ■!6701 1 1 ll 'k-IIG • W201 r � ` +' ! ■ w•7/SO w-215 � yj �W210 VYS0542 •rp0 . A 1494 W{21e Wd W-2 � 2377 � W200r laza N.9 ■1770 -� +657�w „ ■ 7310 i w -I 7 ■ A W l 331.1-W20JL2 1 Polaris Field M.e.n pa��wMln . • •• .9I, eme<vwne N.,.. s Fss seo� P14�[tan: hsia.efe Nertlir Lal StatlicPmwm A +� ------•-T°�'e.w..: 7,10 m6M9 `-.d^ by P,eswm are auaaged w comrged ._ _ a .46+rR. MAP 7 _ 13 TABLE 3: POLARIS MONTHLY AVERAGE OIL ALLOCATION FACTORS Month Oil Jul -18 0.82 Aug -18 1.02 Sep -18 0.87 Oct -18 0.88 NOVA 8 0.83 Dec -18 0.84 Jan -19 0.84 Feb -19 0.87 Mar -19 0.85 Apr -19 0.85 May -19 0.85 Jun -19 0.84 14