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Home My WebLink About2017 Endicott Oil PoolHilcorp Alaska, LLC April 5th, 2018 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8377 Fax: 907/777-8580 ckanyer@hilcorp.com Hollis French, ChairmannF Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 APIA 0 6 20-13 RE: DUCK ISLAND UNIT, ENDICOTT FIELD, ENDICOTT OIL POOL, STATE OF ALASKA,AOG CC 2017 ANNUAL RESERVOIR REVIEW Dear Commissioner French: In accordance with Conservation Order No. 462, Hilcorp Alaska, LLC ("Hilcorp"), as Operator, hereby submits for your review the following Annual Reservoir Review for the Endicott Field. This is the Annual Reservoir Review and corresponds to events during the 2017 calendar year. The Endicott Field has been on production since October 1987. A. Progress of Enhanced Recovery Project and Reservoir Management Summary During 2017, one new well was sidetracked in the Duck Island Unit. The bottomhole location of the Duck Island Unit well 3-23A changed to the North of the original wellbore location, penetrating through the Kekiktuk K3A, 1<213, and K2A sands. Production and injection statistics are summarized in Table 1. Average daily oil production from the Endicott Oil Pool was 7,240 bopd and average daily gas injection was 332.3mmscfpd. During 2017, injected fluid was calculated to be 27,462 thousand -reservoir barrels (MRB) less than reservoir voidage. At year end, the reservoir overall cumulative voidage replacement ratio was 0.93. The average reservoir pressure varies between zones. The average of surveys run in 2017 was 4,435psia. Hilcorp became the official Operator of the Endicott Field effective November 18, 2014. As a result, the historic reservoir simulation model developed by the previous operator will no longer will be utilized in the enhanced recovery or reservoir management. Hilcorp will continue to identify and improve waterflood pattern efficiency by allocating existing water injection volumes and adding perforations in active injection wells. Table 1: ENDICOTT FIELD 2017 OVERVIEW STATISTICAL SUMMARY WELL STATISTICS Total As of 12/31/2017 Full year (1) As of Dec -16 (2) Injection, Producers 58 55 Voidage, Year Cum since Injectors 26 26 Free Gas, RB NOTES: MRB Cum, MRB start-up, MRE Jan -2017 (1) Well count data reflects ONLY those wells which contributed to production/injection during the respective year (2) Active w ells as of December 2017 6,701,243 14, 205,158 14, 205,158 4 253,02243! PRODUCTION/INJECTION STATISTICS 318,188 6,845,265 6,018,110 Cumulative Start - Mar -2017. 346,927 Up through Production 2017 12/31/17 Oil (BBL) 2,642,615 474,345,646 Gas (MCF) 121,304,733 3,411,638,211 Water (1313L) 74,172,417 1,668,845,772 Injection 271,350 6,695,973 Water (1313L) 74,989,289 2,012,539,194 Gas (MCF) 83,135,919 3,011,174,529 Balance Aug -2017 249,753 Cum Production (MRB) 159,257,783 4,398,075,063 Cum Injection (MRB) 131,796,063 4,069,327,289 Over/Under(MRB) -27,461,720 -328,747,774 DAILY AVERAGE RATE DATA 2017 7, 643, 393. 6,796,228 Production Nov -2017 291,933 Oil, BOPD 7,240 14, 720, 640 144, 329, 399 4,383,146,6& Gas, MCF/D 332,342 7,602,509 Water, BWPD 203,212 Injection Water, BWPD 205,450 Gas, MCFPD 227,770 AVERAGE RESERVOIR PRESSURE Average of surveys obtained in 2017 4,435 psia B. Voidage Balance by Month of Produced Fluid and Infected Fluids- 2017 Produced Fluids 3,570,173 81,515,193 74,172,417 159,257,783 Page 2 Fluids Total Total Water, Injection, Year Cum since Water, Voidage, Year Cum since Month Oil, RB Free Gas, RB MRB MRB Cum, MRB start-up, MRE Jan -2017 352,900 7,151, 015 6,701,243 14, 205,158 14, 205,158 4 253,02243! Feb -2017 318,188 6,845,265 6,018,110 13,181, 564 27, 386, 722 4, 266, 204, 0a Mar -2017. 346,927 7,532,988 6,841,699 14, 721, 614 42,108, 336 4, 280, 925, 611 Apr -2017 313,620 6,478,435 5,949,879 12, 741, 934 54, 850, 270 4, 293, 667, 55 May -2017. 342,607 7,382,968 6,836,121 14, 561, 696 69, 411, 966 4, 306, 229, 241 Jun -2017 271,350 6,695,973 6,228,057 13,195, 380 82, 607, 346 4,321,424,62; Jul -2017 272,187 5,819,923 5,431,236 11, 523, 346 94,130, 692 4,332,947,97; Aug -2017 249,753 5,753, 524 5,279,969 11, 283, 247 105, 413, 938 4, 344, 231, 21! Sep -2017 211,903 5,176, 907 4,063,225 9,452,035 114, 865, 973 4, 353, 683, 25. Oct -2017 303,165 7, 643, 393. 6,796,228 14, 742, 786 129, 608, 759 4, 368, 426, 04l Nov -2017 291,933 7,432,292 6,996,414 14, 720, 640 144, 329, 399 4,383,146,6& Dec -2017 295,639 7,602,509 7,030,236 14, 928, 384 159, 257, 783 4, 398, 075, 06, 3,570,173 81,515,193 74,172,417 159,257,783 Page 2 Fluids 56,806,773 74,989,289 (Injection -Production) Net Cum since Injection, Year start-up, MRB Cum, MRB MRB -2,378,037 -2,378,037 .303.173.062 -2,390,601 -4,768,638 -305,563.663 -2,651,576 -7,420,214 -308,215,239 -2,269,324 -9,689,537 -310,484,563 -2,675,396 -12,364,933 -313,159,959 -2,413,072 -14,776,005 -315,573,031 -2,122,233 -16,900,238 -317,695,264 -1,738,730 -18,638,968 -319.433,994 -1,615,233 -20,254,201 -321.049.227 -2,427,274 -22,681,476 -323,476,501 -2,328,240 -25,009,716 -325,804,741 -2,452,005 -27,461,720 -328, 256, 746 -27,461,720 Total Formation Water, Injection, Year Cum since Gas, MRB MRB MRB Cum, MRB start-up, MRB 5,033,728 6,793,393 11, 827,122 11, 827,122 3, 949, 849, 377 4,702.223 6,088,740 10, 790, 963 22, 618, 084 3, 960, 640, 339 5,152, 218 6,917,820 12, 070, 038 34, 688,122 3, 972, 710, 377 4,450,329 6,022,282 10, 472, 611 45,160, 733 3.983.182, 988 5,011,777 6,874,524 11, 886, 300 57, 047, 033 3, 995, 069.288 4,537,869 6,244,439 10,782,308 67,829,341 4,005,851,596 3,900,550 5,500,563 9,401,113 77, 230, 454 4, 015, 252, 709 4,060,355 5,484,162 9,544,517 86, 774, 970 4, 024, 797, 226 3,601,784 4,235,018 7,836,801 94, 611, 772 4, 032, 634,027 5,536,338, 6,779,174 12,315,512 106,927,284 4,044,949,539 5,390,693 7,001,707 12,392,400 119,319,683 4,057,341,939 5,428,910 7,047,469 12,476,379 131,796,063 4,069,818,318 56,806,773 74,989,289 (Injection -Production) Net Cum since Injection, Year start-up, MRB Cum, MRB MRB -2,378,037 -2,378,037 .303.173.062 -2,390,601 -4,768,638 -305,563.663 -2,651,576 -7,420,214 -308,215,239 -2,269,324 -9,689,537 -310,484,563 -2,675,396 -12,364,933 -313,159,959 -2,413,072 -14,776,005 -315,573,031 -2,122,233 -16,900,238 -317,695,264 -1,738,730 -18,638,968 -319.433,994 -1,615,233 -20,254,201 -321.049.227 -2,427,274 -22,681,476 -323,476,501 -2,328,240 -25,009,716 -325,804,741 -2,452,005 -27,461,720 -328, 256, 746 -27,461,720 C. Summary and Analysis of reservoir pressure surveys within the pool The following key wells in the Endicott Pool were proposed in 2017; 2017 Key Well Program 1-01 K2A, K2B 2-70 K313, K3C 4-04A 1<313, K3C 1-29 K2B 3-01 K2A 4-08 K2B, K3A 2-14 K2B 3-05 K3B 4-26 K3A 2-22 K3A, K3B, K3C 3-23 K2B, K3A, K3B 4-34 K3A 2-40 K3B, K3C 3-37 K3A 1-11 Ivishak 2-50 K3B, K3C 3-47 K3B, K3C 2-30B Sag River - Minke 2-60 K3C 3-49A K3B, K3C 2-56A Sag River - Eider Endicott Oil Pool Datum: -10,000 ssTVD Minke Tract Datum: -9,800 ssTVD Eider Oil Pool Datum: -9,700 ssTVD Static bottomhole pressures collected in 2017 are summarized and submitted quarterly on the form 10-412 form below. Well 2-70 survey was not possible due to wellbore conditions preventing timely plug removal, and was deferred to 2018. Page 3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Cytrae HizraHxsFa. LLC Z Ad*- MXC . WWx D: S+cxe zecc. 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Pre9ax'a 3t a*= Kffi 1-01 00500292180100 O 220100 K2A 10,085-10.154' 10/111017 83,297 SBHP 212 10,000 4,125 10,000 041 4,125 1-11 50028221070000 O 220150 Nr" 10.028'-10,114' 107$2017 64,500 SSW 1964. 9,974 3,582 10,000 0.43 3.593 1.29 50029216696360 O 220100 KZA 10.205-10.230' 30d2O17 48.830 SSW 213.3 9,983 4,097 10 Wo OA3 4,105 1-65A 5W29225Z7010 0 220100 K28 9,9979.5.98' 411012017 104 SBHP 199.3 10,000 4,079 10:000 0.44 4,079 1-65A 150029226270100 O 22010 K2B 907-9,99a 91832017 331 SBHP 199.8 9,901 4,09 10,E 0.41 4,049 2-14 50029216396700 O 2201CO K2A, KM 13,169•-10,21T 2fJ.2017 494 SBHP 204 10,00 4,134 1%00-0 0.12 4,134 2-22 50029219310000 1M 226100 K3A.Ki81csC 9,13:'-10,333 431812077 297 SBHP 184 10,001 5,301 10.0@1 0.44 51301 2-22 500292!9310060 V71 220100 {A,+c6K'+C 9,x85'-1G.3:i3` 9f102637 372 SBHP 183.1 1G,007 5.186 10,000 0.41 5,1& 2-306 50029212280200 O 220170 Sag River 9.771'-9,833' 4&,2017 153 SBHP 203.5 9,855 1,742 9,300 048 VW 2-308 50029122280200 O 220!70 Sag Ricer 9,771'-1,533' 9x 17 358 SJP 202.8 9,859 1,891 9.800 Mos 1,887 2-40 5002922,5270000 0 220100 K36, K30 la$35-11,034' 312172017 3,300 S200 10,00 4,109 19,000 0.41 4,109 2.50 5002922367MW 0 220100 K3C 10,00-10,2175 N15,�2{117 28,935 $201 9,96' 3,422 10,000 0.45 3,440 2-56A 50029228630100 0 2207165 Sag River 9.434'-9,SM' 9R4�2017 1,021 $185 9,2299 1,198 9,700 O.M 1,211 250 50029223750000 O 220100 K3C 10,071'-10,156 1@39%1017 12.640 S205.4 10,000 4.301 10,000 0.39 4,301 3-01 50029216780000 , VANJ 220100 K2A 9,757-10278' 9,2672317 734 S188 i 70.00 4,546 10.00 0.45 4,846 3-05 3029216240000 0 720100 K3B 9,MV-9,&a 3Y&2017 49,048 S209 9,890 4,391 1044 0.43 4,438 3-23 50029216450600 O 220100 Im ic6kiae 9,854'-10.180' 3!13,21317 84,016 S 214 11,00 4,498 10.00 0.42 4,498 3-35 50029217010000 0 220163 K3A 9.917'-10,048' 5±22017 654 S 192 10,000 4,569 13,00 0.44 4,� 3-35 5029217010000 O 22MOO K3A 9,917-13,048' 10f72017 899 S 194 10,000 4,709 10,000 0.44 4.,709 3.37 5002822554000 O 720100 K3A 9.933'4,915 3714+'2017 Z SS 200 9,899 4,265 16.03 0.43 4,309 3-41 50029218780000 Mn 220100 K7A K2B 10,023'-16,365- 971772017 544 S167 ( 10,003 5,743 10,000 0.44 5,742 3-17 50029215640600 VW 220100 K36, K3C 9.93? -10,37 3.'15,2017 43,618 SS200 10,000 4,252 10,00 0.43 4,252 349A 50029217350100 VA 220100 K36, K3C 9,557.13,157 122212017 573 S192 10,000 4,335 10,!300 0.45 4.335 4,04A 50029219680160 O 2'20100 Kia K3C 8988'-10,212 37512017 16,139 S211 10.000 4,907 !0,000 OA3 4,907 4� 50079216920000 1271 220100 KZB, K3A 9,913-10,195 12712617 99.585 S201 10,02 4,822 1{1,000 0.45 4,821 4-28 5029218350006 O 220100 K3A 9,893-10.1^09' 3`1712427 $9,265 SB211 10,001 3,742 10,000 0-33 3,742 434 5002922765000 Ma 22MOD K3A 9,914'-10.106' 3117/2017 15,424 S210 9,990 4,171 10,000 0.32 4,203 Cammer4Y: 23. A2 tesde rePnte4 hc>!r: wee 1+aae:r a�fa+ce w1e 1712 �� rales. repfaTamad;:s a1'1ke A1utn Cd x1tl Ga Cn+serAGr Caevaas;sa. � MetsOy aen4y#cf ale 4repeng k ace a+6 aY. reGmCce bea o1m/ 70Kki7e11g4.. Sq:aMit... fes„ PemayHa�na Cm's Kager To. cat Resa:va°TErgea AP"A 2.289& Well 2-70 survey was not possible due to wellbore conditions preventing timely plug removal, and was deferred to 2018. Page 3 The following key wells in the Endicott Pool will have static bottomhole pressure measurements captured in 2018; 2018 Key Well Program 1-09A K2A, K2B 2-70 K3B, K3C 4-42 K3C 1-17A K3A 3-23A 1<213, K3A K3B, K3C K2A, K2B 1-11 Ivishak 2-22 K3A, K3B, K3C 3-47 2-56A Sag River - Eider 2-64 K3C 4-38 3-258 Endicott Oil Pool Datum: -10,000 ssTVD Eider Oil Pool Datum: -9,700 ssTVD D. Summary and Analysis of Gas -Oil Contact or Gas MonitorinI4 Surveillance Plan. The following table summarizes the results of the logs run in 2017 for gas monitoring. END 2017 GOC Monitoring Program Well Location Log Type log Description Date log Results Notes 2-14 MPI Gas Saturaion Log CCL/GR/Press/Temp/Sigma 2/21/2017 GCC at 10,295'MD(-9,871'ssTVD)" well was logged in fluid 3-23A SDI Gas Saturation Log CCL/GR/Press/Tem S" ma 10/1/2017 No GOC observed in all Kekilduk reservoirs Well was logged in fluid 3-258 SDI Gas Saturation Log CCL/GR/Press/Tem /S" ma 2/22/2017 GOC at 13,97&MD-9,987'ssTVD " Well was logged in fluid 4-50 SDI Gas Saturation Log CCL/GR/Press/Tvrnp/Sigma 2/21/2017 No GOC observed in all Kekiktuk reservoirs Well was bgged in fluid using the [u1 i xs r rog results ana some onservarnons1rom me Zu1 / proaucaon, me Current MH RZ5 (AX is estimated at-9,91371sTVD. A field wide current GOC is not likely to be identified as the Kekiktuk sands have several subzones that are vertically separated and have different permeability. In addition, faulting in the reservoir may lead to hydraulic isolation or partial pressure communication within a sub zone. Using only the 2017 RST log results and some production observations, the current GOC can be as deep as-10,077'ssTVD. E. The Following Year Gas -Oil Contact or Gas Monitoring Surveillance Plan. In 2018, we will run at least one cased hole pulsed neutron logs. Planned well is the 1-29 production well to monitor GOC and any potential remaining oil zones following a planned rig workover. Additional candidates may be identified and logged to continue GOC surveillance of the Endicott Oil Pool. F. Results and Analysis of Production and Injection log surveys, tracer surveys, observation well surveys and any other special monitoring The following table summarizes the results of the production logs run in 2017. END 2017 Production Logging Program Well location Log Type log Description Date log Results Notes 3-23A SDI Production Profile Spin/Temp/Press/GR/CCL 10/21J2017 Majority water production below 12,580' to12,610'MD Perfect intervals 12/192'-12 551'MD -9,890'to-9,906'sSTVD 3-15 SDI Production Profile Spin/Temp/Press/Deft/GR/CCL 11/27/2017 Majority water production below Perfedintervals 12,620'-12,688'MD 12,678'MD (-9,890'ssTVD) 3-09A SDI Production Profile Spin/Tem 11J28J2017 Majority water production belowpJPress/DeftJGRJCCL Perfect intervals 13 974'-14A82'MD 12 678'MD-9,890'ss7VD Spin/Temp JGhost) K2B: Minorfiulo entry above 12,586'MD Intervals K2B: 12,548'-12,586'MD, 3-31 SDI Production Profile GR/CCL GR/CCLL 11/30/2017 (-9,853'ssTVD); K2A Majority gas production K2A:12,614'-12,638'MD, & K1: below 12,614'MD(-9,881'ssTVD) 12,868'-12,958'MD Page 4 Sampling from the previous waterflood tracer program has been discontinued. No current tracer program is in place. G. Future Development Plans & Review of Annual Plan of Operations and Development In 2017, Hilcorp increased unit production through well intervention projects, and other optimization opportunities, that included the evaluation of shut-in wells for potential return to service. A full field study of the Duck Island Unit is ongoing. The re -mapping of all productive horizons, review of well histories, analyzed production and injection data, and geophysical work is ongoing. Some additional wellwork was initiated due to data provided by surveillance activities, summarized in above sections D & F. Projects completed during the 2017 calendar year: • Add Perfs in existing production wells including: o SDI 3-25B (PROD) Perf K2A & S3A2 • Failed WSO SDI 3-29 (Prod) by dumping cement on existing plug to shut off K2B. Water/gas flood maintenance work o Run several static BHP surveys or IPROF logs to identify unhealthy water flood patterns o SDI 4-42 (PROD) well bore failed MIT -IA prior to conversion to water injection. o SDI 4-04A (PROD) converted to injection to improve pattern support to well MPI 4-18 (Prod). o MPI 5-03 (WINJ) Coil tubing cleanout to improved injectivity in Ivishak - Sag Delta North Oil Pool o MPI 2-22 (WINJ) Perf UPSZ FV to support existing MPI 2-26 (Prod) o MPI 1-67 (WINJ) Perf UPSZ FV to support existing MPI 1-55 (Prod) o MPI 1-41 (WINJ) Perf S3A2 to support existing SDI 4-10A (Prod). MPI 2-60 (PROD) Failed to perform surface casing repair. MPI 2-14 (PROD) Successfully repaired surface casing leak — added Kekiktuk S3A3/S3A2 perfs o Excavate, repair surface casing, add perfs, and returned to production. SDI 3-23A (Prod) Sidetrack -- Endicott Oil Pool - Kekiktuk S3A3/S3A2/K2B/K2M o Sidetracked LTSI well to bypassed traditional oil pay targets. o Well was redrilled twice after stuck BHA. o Remediation of poor cement quality across the Kekiktuk reservoirs in progress. Projects postponed during the 2017 calendar year: Rig workovers delayed until 2018 due to barge season window/rig availability. The sidetrack of the 3-23A well took priority and used entire rig barging window. o MPI 2-50 (PROD) RWO - Endicott PA- Kekiktuk UPSZ o MPI 1-29 (PROD) RWO/GSO -Endicott Oil Pool - Kekiktuk o MPI 1-11 (WINJ) RWO -Sag Delta North PA- Ivishak o SDI 4-42 (PROD) WINJ conversion delayed due to failed MIT -IA. ■ RWOs planned to be completed Q2 -Q4 2018 In 2018, Hilcorp will pursue increased unit production through additional well intervention projects, any necessary infrastructure and facility repairs, and other optimization opportunities as they arise. Workover and drilling activities are tentatively planned at Endicott for Q2 -Q4 2018 calendar year. This schedule is governed by the planned mobilization of a workover/drilling rigs to the Endicott field. The workover rig season is planned April thru May 2018. The drilling rig barge season is July thru October 2018. Both of these dates are subject to change. Projects planned for the 2018 calendar year: Page 5 Add Perfs in existing production wells o Add perf in bypassed or laminated pay in Endicott Oil Pool. o Identify additional oil pay with gas saturation logging Perform WSO/GSO o SDI 3-09A (Prod) isolate/water shut off lower K2B water. o SDI 3-15 (Prod) isolate/water shut off lower K2B water. o SDI 4-38 (Prod) isolate/gas shut off upper K2A gas. o Identify excessive water or gas production with PPROF/RST logging o Perform water/gas shut off using wireline/coil. Perform water/gas flood maintenance work o Run several static BHP surveys or IPROF logs to identify unhealthy water flood patterns o SDI 4-42 (PROD) RWO - Endicott Oil Pool - Kekiktuk UPSZ. ■ Conversion to WINJ to support active SDI 4-14A (PROD) ■ Pull/replace tubing, and begin water injection. o MPI 2-50 (PROD) RWO -Endicott Oil Pool - Kekiktuk UPSZ ■ Conversion to WINJ to support active MPI 2-58 (PROD) & MPI 2-46B (PROD) ■ Patch casing, replace tubing, and begin water injection. o MPI 1-11 (WINJ) RWO -Sag Delta North Oil Pool - Ivishak ■ Repair WINJ to support active MPI 2-32 (PROD) & MPI 2-38 (PROD) ■ Patch casing, replace tubing, and begin water injection. o Other production well conversions to injection under assessment. o Reallocate water injection in existing injectors. MPI 1-29 (PROD) RWO - Endicott Oil Pool - Kekiktuk o Pull completion, patch liner - GSO, run completion, and return to production. SDI 4-26A (Prod) Sidetrack - Endicott Oil Pool - Kekiktuk K213 o Sidetrack LTSI well to bypassed attic oil pay targets. MPI & SDI Sidetrack - possible additional sidetrack(s) opportunities will be evaluated, and possibly drilled. Hilcorp will continue to update the field study of the Duck Island Unit. This may include re -mapping potentially productive horizons, updating well histories, reviewing all production and injection data, material balance calculations, and reviewing results of recent well intervention projects. Sincerely, Chris Kanyer Reservoir Engineer - Endicott Page 6