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Home My WebLink About2020 Oooguruk-Kuparuk Oil Pool Annual Reservoir Surveillance Report Oooguruk-Kuparuk Oil Pool (OKOP) Oooguruk Field April 1, 2021 Eni Petroleum - Alaska Development Table of Contents SUBJECT PAGE 1.0 Progress of the Enhanced Recovery Project ................................................................................ 1 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool ........................................... 2 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring ................................................................................ 3 4.0 Review of Pool Production Allocation Factors and Issues Over the Year ..................................... 3 5.0 Reservoir Management Summary .............................................................................................. 4 ATTACHMENTS ATTACHMENT A: OKOP Well Location Map ............................................................................................ 5 ATTACHMENT B: 2020 OKOP Voidage Balance by Month ...................................................................... 7 ATTACHMENT C: OKOP Pressure Report, Form 10-412 ........................................................................... 8 ATTACHMENT D: OKOP Reservoir Pressure Map – December, 2020 ...................................................... 9 ATTACHMENT E: OKOP Annual Reservoir Properties Report, Form 10-428 .......................................... 10 Eni Petroleum-Alaska Development Page 1 1.0 Progress of the Enhanced Recovery Project The Oooguruk Field (OF) is one of two Eni US Operating Co. Inc. (Eni) offshore-operated fields in Alaska. Three oil pools, the Torok, Kuparuk and Nuiqsut are currently under development within the OF. The development consists of an offshore man-made gravel island, the Oooguruk Drillsite (ODS), located just east of the Colville River Delta in Harrison Bay. ODS production is delivered to the Oooguruk Tie-in Pad (OTP) via a buried subsea flowline bundle and onshore flowlines, metered, then transferred to Kuparuk River Unit (KRU) facilities, operated by ConocoPhillips Alaska, Inc. (CPAI), for final processing and transportation to the sales line. During 2020 low crude oil prices, lack of demand for oil, and the logistical interference of the COVID-19 pandemic resulted in budget cuts, production curtailments and project deferrals. The Oooguruk-Kuparuk Oil Pool (OKOP) development includes eight wells: ODSK-13i, ODSK-14, ODSN-29 Kuparuk, ODSK-33, ODSK-35Ai, ODSK-38i, ODSN-40i Kuparuk, and ODSK-41. The locations of the OKOP, the OKOP wells, the current OU, and Oooguruk Kuparuk Participating Area (OKPA) are shown in Attachment A. Currently three producers, ODSK-14, ODSK-41 and ODSN-29 Kuparuk, and one injector, ODSK-38i, are active. The ODSK-33 well is inactive due to high water cut, ODSK-13i remains shut-in for long term pressure fall-off monitoring, ODSK-35Ai is shut-in and secured due to multiple tubing leaks, and the ODSN-40i Kuparuk is shut-in due to limited injection capacity. The Oooguruk project originally envisioned producing wells would ultimately utilize ESP completions in order to maximize drawdown and minimize gas lift and the associated KRU and hydraulic back-out effects. However, currently all producing wells, except one cycled pre- produced injector, ODSN-10, require gas lift to produce. Gas lift capacity is limited to approximately 15 MMSCFPD. The high gas lift rate coupled with approximately 10 MMSCFPD in combined OF formation gas increases the flowline pressure, reducing overall flowrates, and generates significant back-out cost at KRU, which is primarily constrained by gas compression capacity. These constraints result in backing out KRU fluid production when high total gas oil ratio (TGOR, includes formation and lift gas) OF fluids enter the system. Because of the hydraulic effects and KRU back-out all OF wells cannot be produced concurrently using gas lift. In 2020, on average, twelve of the 23 producing OF wells were on-line with TGOR ranking typically used to determine which wells to produce. Consequently, due to a non-competitive TGORs, using back- up gas lift, ODSK-14 was limited to four days of production and ODSK-41 was not produced during 2020. ODSN-29 Kuparuk sustained production was considered a priority due to adverse effects (reduced oil rates with high watercut and high GOR) when shut-in despite its high TGOR ranking; the well accounted for 99% of OKOP production in 2020. In 2019 and early 2020 Eni initiated rig repairs, maintenance and material purchases in preparation for planned OF workover and drilling programs. However, due to low crude oil prices, the reduced demand for oil, and the logistical interference of the COVID-19 pandemic no rig workovers nor new drilling were conducted at the OF in 2020. Future ESP recompletions, including the OKOP wells, have been planned but have not been approved. A Partial Gas Processing (PGP) study has been initiated to determine the feasibility of installing on-site gas Eni Petroleum-Alaska Development Page 2 processing and compression equipment at OTP to mitigate gas processing constraints and reduce associated costs from CPF-3. During 2020 OKOP oil production was impacted by the Alyeska Pipeline (Alyeska) prorations due to high inventories, low crude oil prices, and reduced gas handling capacity at KRU facilities associated with their North Slope production curtailment. Annual average daily OKOP production for 2020 was 552 BOPD. Total oil production during 2020 was 201,987 barrels for a total 9,887,648 barrels since field start-up. The 2020 annual average producing gas oil ratio and watercut were 3,147 SCF/STBO and 64%, respectively. The new 5-mile 12-inch seawater flowline from the KRU 30-inch low pressure seawater flowline to OTP, and the Seawater Injection System (SWIS) pump upgrade project at OTP and ODS were commissioned in 2020. The system started up in May 2020 allowing higher pressure and higher rate water injection at ODS. ODSK-38i injection was restarted in May upon commission of SWIS. Average annual daily water injection from May thru December 2020 was 1,115 BWPD with daily rates ranging from 0 bpd to 9,658 bpd. Total water injection in 2020 was 273,079 barrels and 15,649,628 barrels since the start of injection in 2009. 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Eight pressure surveys were reported from seven OKOP wells; the pressure survey results are presented in the OKOP Pressure Report, Form 10-412 (See Attachment C). Overall, the pressures in the Kalubik fault block continue to indicate pressure stabilization due to historical voidage replacement, excluding the ODSK-41 area, which, despite being shut-in since October, 2018 due to a failed ESP, continues to show limited communication to offset wells. Pressures from the ODSK-13i injection and fall off test show the western Ivik block has relatively low transmissibility and is not in hydraulic communication with the main Kalubik block development area. Kuparuk pressures measured in the ODSN-29 Kuparuk eastern Ivik well confirmed communication with the main Kalubik fault block but not to ODSK-13i in the western Ivik fault block. The OKOP Reservoir Pressure Map, Attachment D, depicts the OKOP average pressures for December, 2020 including shut-in and producing wells. The December 2020 OKOP pressure at 6,050 ft. TVDss is estimated at 2,500 psi. The average annual producing GOR was 3,147 SCF/STBO and in December, 2020 the GOR averaged 2,113 SCF/STBO (refer to Attachment E, Kuparuk Annual Reservoir Properties Report Form 10-428). Eni Petroleum-Alaska Development Page 3 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring A chemical tracer program was initiated in May 2012 and completed in 2014. Tracers were injected into ODSK-35Ai and ODSK-38i. Within 20 months of initial injection tracer concentrations were observed in ODSK-33 and ODSK-14 from ODSK-35Ai. To date, ODSK-38i tracer has only been seen in minor amounts in ODSK-33. Produced water samples for ODSN-29 Kuparuk have not shown signs of either tracer. No additional surveillance logging or surveys were conducted in 2020. 4.0 Review of Pool Production Allocation Factors and Issues Over the Year Production from the Oooguruk-Torok Oil Pool (OTOP), Oooguruk-Kuparuk Oil Pool (OKOP) and Oooguruk-Nuiqsut Oil Pool (ONOP) is commingled at the surface into a common production line. Allocation between the pools is based on the ratio of total production for a pool to the total production for the Oooguruk Unit. The pool allocation factors for 2020 are: ONOP: 92.7% OKOP: 7.1% OTOP: 0.2% Theoretical production for individual wells for all pools is calculated on a daily basis. During 2020 wells were produced with chokes at 100% most of the time due to the capacity of the production line. Daily theoretical production for a well was calculated using the data from the most current well test and the amount of time a well was on production for a given day: oductionlDailyTheoreticaBOPDxDailyRate dayMinutes Minutes Welltest produced Pr)( 1440  The daily allocation factor for the unit is calculated by dividing the actual total production for the day by the sum of the theoretical daily production for each individual well. Daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average daily allocation factor for 2020 was 0.9947. Eni Petroleum-Alaska Development Page 4 5.0 Reservoir Management Summary The AOGCC issued pool rules under Conservation Orders No. 645A, 596 and 597 for the OTOP, OKOP and the ONOP, respectively. While there is no subsurface commingling, unitized substances produced from the three oil pools are commingled on the surface. Area injection orders (AIOs) authorizing the injection of fluids for enhanced oil recovery in the OTOP, OKOP, and ONOP reservoirs were issued by the AOGCC as AIO No. 37A, 33 and 34, respectively. Injection commenced into the OKOP in 2009. The OKOP reservoir management targets maximizing oil production, managing producing gas oil ratios (GOR) and maximizing long term reservoir performance and value through enhanced recovery while minimizing the project risks and maintaining the highest environmental and safety standards. Flood throughput and reliable water supply are critical to long-term OKOP recovery. The main recovery mechanism for all three OF reservoirs is waterflood. During 2018 and 2019 KRU seawater supply to the OF was very limited and then shut-off completely on July 4, 2019. Consequently, Eni constructed an alternate seawater injection supply (SWIS) enhancement project. Water for injection was not available from July 2019 thru April 2020 due to construction of SWIS infrastructure. Start-up was delayed due to logistical interference associated with the COVID-19 pandemic. The SWIS project, commissioned in May 2020, supplies ODS with up to 25,000 bpd of seawater, increase water injection reliability, and avoid the detrimental alternative of KRU produced water injection. Additionally, water injection supply pressures will be boosted from 2,800 psi to 3,700 psi, which will significantly increase injectivity and flood throughput in targeted low injectivity wells. The AOGCC has approved increasing the pressure limit to 3,700 psi from 2,800 psi for both the Nuiqsut and Kuparuk pools; the Torok limit currently remains at 2,800 psi consistent with Rule 4 of AIO 37A; a request for the AOGCC to modify AIO 37A to increase the Torok limit to 3,700 psi is in progress. Typically higher injection pressures are not needed for Kuparuk reservoir injection; however, one well ODSN-40 with limited injectivity may benefit. OKOP 2020 production was primarily associated with the ODSN-29 Kuparuk in the eastern Ivik fault block. Performance to-date suggests a significant associated pore volume with support from the Kalubik fault block injection wells, ODSK-35A and ODSK-38, but not with the ODSK-13 well in the western Ivik fault block (refer to Attachments C and D). Since initiating Kuparuk production from ODSN-29 in 2017 there has been no change in the fall-off trend in the ODSK-13 well. Future development plans of the expanded area are contingent on the longer term performance from the well and evaluation of alternatives to further develop this area of the OKOP. Kuparuk production from the ODSN-29 wellbore has temporarily shut-in Nuiqsut production from the wellbore; however, the long-term plan, which requires AOGCC approval, is to commingle production from the two pools or alternate production from each zone. The Kuparuk is much more prolific and is currently at a higher pressure than the underlying Nuiqsut in the area. Because the main Kalubik fault block OKOP development area is a very mature flood, in a dual porosity system, with highly variable matrix permeability and open fracture networks, voidage replacement has been purposely reduced to minimize waterflood by-pass while stabilizing the Eni Petroleum-Alaska Development Page 5 reservoir pressure and GOR. As a result, the producing Kuparuk water oil ratio and oil production have remained stable and ultimate recovery is projected to exceed expectations. However, during the extended 2019-2020 water injection shutdown, the OKOP producing GOR increased from 3,200 SCF/STBO to 4,800 SCF/STBO. Following the production shut-in and restart of injection in May, 2020 significant water breakthrough occurred between ODSK-38i and ODSN-29 Kuparuk. The watercut increased to 85% with the oil rate dropping to 204 BOPD. Subsequently, injection and offtake have been managed and December oil production averaged 705 BOPD and the watercut and GOR have declined to 62% and 2,113 SCF/STBO, respectively. In 2020 the ODSK- 35Ai injection well was diagnosed with multiple tubing leaks and has been shut-in and secured pending remediation. At the end of 2020 OKOP cumulative voidage replacement was at 63%, refer to Attachment B. Eni Petroleum - Alaska Development Page 5 ATTACHMENT A. OKOP Well Location Map Eni Petroleum - Alaska Development Page 6 ATTACHMENT B 2020 OKOP Voidage Balance by Month Month Oil, MRB Free Gas, MRB Water, MRB Total Voidage, MRB Year Cum, MRB Cum since start-up, MRB Gas, MRB Water. MRB Total Injection, MRB Year Cum, MRB Cum. since start-up, MRB Net Injection, MRB Year Cum, MRB Cum since start-up, MRB Cum Since Start-Up thru 2019 >>24,412 Cum Since Start-Up thru 2019 >>15,377 -9,035 Jan-20 32 98 25 155 155 24,566 0 0 0 0 15,377 -155 -155 -9,190 Feb-20 31 115 27 173 327 24,739 0 0 0 0 15,377 -173 -327 -9,362 Mar-20 32 122 27 181 509 24,920 0 0 0 0 15,377 -181 -509 -9,543 Apr-20 20 81 21 122 630 25,042 0 0 0 0 15,377 -122 -630 -9,665 May-20 0 0 0 0 630 25,042 0 50 50 50 15,427 50 -580 -9,615 Jun-20 19 52 37 108 738 25,149 0 127 127 177 15,553 19 -561 -9,596 Jul-20 8 39 37 84 822 25,233 0 32 32 209 15,586 -51 -613 -9,648 Aug-20 14 45 41 101 922 25,334 0 22 22 231 15,608 -79 -691 -9,726 Sep-20 21 50 39 110 1,032 25,444 0 13 13 244 15,621 -97 -788 -9,823 Oct-20 23 58 33 114 1,146 25,558 0 9 9 253 15,630 -105 -893 -9,928 Nov-20 26 55 33 114 1,260 25,671 0 7 7 261 15,637 -106 -999 -10,034 Dec-20 27 50 36 113 1,373 25,784 0 12 12 273 15,650 -101 -1,100 -10,135 2020 Totals 252 764 357 1,373 0 273 273 -1100 Produced Fluids Injected Fluids Net Injection (Injection - Production) Eni Petroleum-Alaska Development Page 8 ATTACHMENT C OKOP Pressure Report, Form 10-412 6. Oil Gravity: 21 - 26 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Intervals Top - Bottom TVDSS 14. Final Test Date 15. Shut-In Time, Hours 16. Press. Surv. Type (see instructions for codes) 17. Temp.18. Depth Tool TVDSS 19. Final Observed Pressure at Tool Depth 20. Datum TVDSS (input) 21. Pressure Gradient, psi/ft. 22. Pressure at Datum (cal) ODSK-41 50703205850000 O 576100 Kuparuk 5980 - 6034 1/18/20 10,984 SBHP 151 5,664 1,549 6,050 0.36 1,688 ODSK-38 50703205840000 WI 576100 Kuparuk 6013 - 6041 5/13/20 7,512 PFO 146 5,839 2,429 6,050 0.44 2,523 ODSN-29 50703206610000 O 576100 Kuparuk 6083 - 6121 6/2/2020 815 PBU 158 5,936 2,298 6,050 0.44 2,348 ODSK-13 50703206070000 WI 576100 Kuparuk 6117 - 6195 12/15/2020 61,276 PFO 163 6,102 3,717 6,050 0.45 3,695 ODSK-14 50703206100000 O 576100 Kuparuk 6123 - 6163 12/15/2020 6,969 SBHP 48 -13.5 1,638 6,050 0.19 2,800 ODSK-33 50703205620000 O 576100 Kuparuk 5990 - 6043 12/15/2020 60,172 PBU 65 -13.5 398 6,050 0.35 2,520 ODSK-35A 50703205600100 WI 576100 Kuparuk 6085 - 6126 12/15/2020 7,776 PFO 62 -13.5 592 6,050 0.38 2,925 ODSK-41 50703205850000 O 576100 Kuparuk 5980 - 6034 12/15/20 18,936 PBU 49 -13.5 1,066 6,050 0.13 1,841 23. All tests reported herein were made in accordance with the applicable rules, regulations and instructions of the Alaska Oil and Gas Conservation Commission. I hereby certify that the foregoing is true and correct to the best of my knowledge. Oooguruk Oooguruk-Kuparuk 6050 0.7 3. Unit or Lease Name:4. Field and Pool:5. Datum Reference: Production Engineer April 1, 2021 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RESERVOIR PRESSURE REPORT 1. Operator:2. Address: Eni US Operating Company Inc. (Eni US)3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 7. Gas Gravity: Keith Lopez Signature Printed Name Title Date Eni Petroleum - Alaska Development Page 9 ATTACHMENT D OKOP Reservoir Pressure Map – December, 2020 Eni Petroleum-Alaska Development Page 10 ATTACHMENT E OKOP Annual Reservoir Properties Report, Form 10-428 3. Field and Pool Code: 4. Pool Name 5. Reference Datum (ft TVDSS) 6. Temperature (°F) 7. Porosity (%) 8. Permeability (md) 9. Swi (%)10. Oil Viscosity @ Original Pressure (cp) 11. Oil Viscosity @ Saturation Pressure (cp) 12. Original Pressure (psi) 13. Bubble Point or Dew Point Pressure (psi) 14. Current Reservoir Pressure (psi) 15. Oil Gravity (°API) 16. Gas Specific Gravity (Air = 1.0) 17. Gross Pay (ft) 18. Net Pay (ft)19. Original Formation Volume Factor (RB/STB) 20. Bubble Point Formation Volume Factor (RB/STB) 21. Gas Compressibility Factor (Z) 22. Original GOR (SCF/STB) 23. Current GOR (SCF/STB) 576100 Kuparuk 6050 160 13 - 32 50 - 100 30 2 - 4 2 - 4 3150 2600 2500 21 - 26 0.7 3 - 50 1 - 40 1.26 1.24 0.7 450 2113 Keith Lopez STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator:2. Address: Eni US Operating Company Inc. (Eni US)3700 Centerpoint Drive, Suite 500, Anchorage AK 99503 Date Production Engineer I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Title 4/1/2021Printed Name