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Home My WebLink About2021 Oooguruk-Nuiqsut Oil Pool2rnn� us operat�nng Annual Reservoir Surveillance Report Oooguruk-Nuigsut Oil Pool (ONOP) Oooguruk Field April 1, 2022 Table of Contents SUBJECT E 1.0 Progress of the Enhanced Recovery Project................................................................................ 1 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool...........................................4 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring........................................................................ 4 4.0 Review of Pool Production Allocation Factors and Issues Over the Year ..................................... 5 5.0 Reservoir Management Summary.............................................................................................. 6 ATTACHMENTS ATTACHMENT A: ONOP Well Location Map............................................................................................8 ATTACHMENT B: 2021 ONOP Voidage Balance by Month......................................................................9 ATTACHMENT C: ONOP Pressure Report, Form 10-412.........................................................................10 ATTACHMENT D: ONOP Reservoir Pressure Map — December, 2021....................................................12 ATTACHMENT E: ONOP Annual Reservoir Properties Report, Form 10-428..........................................13 Eni Petroleum —Alaska Development 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 Drill site (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. At the end of 2021, there were 28 active Oooguruk-Nuiqsut Oil Pool (ONOP) development wells, including 18 producer and ten injection wells. One producing well, ODSN-29 Nuiqsut, remains shut-in as it is isolated in the ODSN-29 wellbore to allow production of the Kuparuk interval. Commingling is not currently allowed nor functional at this time. The locations of the ONOP, the existing and planned ONOP wells, the current OU, and Oooguruk Nuiqsut Participating Area (ONPA) are shown in Attachment A. During 2021, OF engineering and operational efforts were focused on optimizing and debottlenecking existing equipment, including separator control system performance, proportional fluid sampling maintenance and upgrades to both the daily and monthly production fluid samplers, and improving measurement system accuracy. Operations included general maintenance and replacement of critical oil, water, and gas piping and valves. Additional field - wide maintenance was also performed, including mechanical integrity inspections of piping and other safety systems. Routine maintenance was performed on the three power generation turbines and two gas injection compressors at the OTP, with one of the power generation turbines receiving a complete overhaul replacement. Compressors A and B were inspected to identify potential design flaws and asset integrity improvements. In addition, cathodic protection inspections were completed on the sub -sea production flowline from ODS to OTP to ensure mechanical integrity of the pipelines. Mandatory DOT hydrotesting was successfully performed on the 2-inch diesel flowline from OTP to ODS. A detailed monitoring plan for seawater injection system microbes was established with three biocide treatments conducted during 2021. Minor capital projects included design studies to relocate the ODS and OTP control rooms, with ODS control room in process to be relocated, enhancing the ODS polar bear camera system, seawater injection line pig trap upgrades and adding a corrosion coupon to the ODS subsea diesel flowline. Several corrosion coupons were pulled at OTP and ODS for the monitoring plan. A conversion from the existing Siemens PCS7 Distributed Control System (DCS) to Emerson DeltaV has been approved with detailed engineering scheduled for 2022. Major capital projects included finalizing the commissioning and startup of the Seawater Injection System (SWIS) booster pump upgrade at ODS. SWIS started up in May 2020 allowing higher pressure, increased from 2,800 psi to 3,300 psi, and sustained higher seawater injection rates at ODS. The SWIS project was trigged by the conversion of the KRU CPF-3 HAMI line supply to produced water in 2019. SWIS was implemented to avoid life cycle production and reserve Eni Petroleum —Alaska Development Page 1 loss associated with injection of KRU produced water and to improve reliability. Since implementation, seawater supply has been consistently available at required volumes for reservoir management. Once fully implemented the ODS booster pump will further increase injection pressures, where needed and approved, up to 3,700 psi. The Oooguruk development originally envisioned producing wells would ultimately utilize electrical submersible pump (ESP) completions in orderto maximize drawdown and minimize gas lift and the associated KRU and hydraulic back -out effects. However, currently all OF producing wells require gas lift to produce. Gas lift capacity is limited to approximately 20 MMSCFPD. The high gas lift rate coupled with approximately 4 to 12 MMSCFPD in combined OF formation gas significantly increases the flowline pressure, reducing overall flowrates, and generates significant back -out cost at KRU, which is also primarily constrained by gas processing 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 2021, on average, twelve of the 22 available producing OF wells were on-line with TGOR ranking typically used to determine which wells to produce. An engineering study was completed and approved to construct a 20 MMSCFD on site Partial Gas Processing (PGP) at OTP to mitigate gas processing constraints, reduce associated costs from KRU CPF-3, and unburden the CPF-3 gas treating and compression system. Detailed engineering began in June 2021 and startup is forecast for late 2023. In addition, an Electrical Power Sharing (EPS) feasibility study was also completed and approved to interconnect the Oooguruk and Nikaitchuq power generation systems to allow a more robust and efficient power system sharing between the two development projects. EPS startup is forecast in 2024. 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 2021. Subsequently, rig mobilization, recommissioning of the Rig Support Complex (RSC) and workover planning have been reinitiated. OF rig activity is planned to start in mid-2022. Timing of the ONOP workovers is dependent on equipment availability and execution of other priority rig interventions and drilling activities. Currently, the near -term plan is to restore production from ODSN-31, which has been shut-in since March 22, 2021 due to a failed SSSV, recomplete ODSN-25 with a new ESP (limited drawdown using back-up gas lift and non-competitive high TGOR), and evaluate several additional OTOP workovers to improve lift efficiency as water rates increase and GORs decline associated with sustained injection. Additionally, ODSN-06 will be recompleted with a selective single completion to access additional Kuparuk resources while maintaining future access to the Nuiqsut in the well, similar to the ODSN-29 recompletion in 2017. There are no plans to commingle production in the well. Detailed engineering and planning for the drilling of eight new wells is also in progress (refer to Attachment A for locations). Eni Petroleum —Alaska Development Page 2 In 2021 Eni conducted fifteen rigless well interventions in ten wells as summarized in Table 1 below. Well Name Well Type Activity Start Date End Date Scope of Work ODSN-02 Producer E-Line/Slickline 12-Mar-21 12-Mar-21 TRSV Brush and Flush ODSN-31 Producer E-Line/Slickline 18-1un-21 12-Jul-21 TRSV Brush and Flush ODSN-17 Producer E-Line/Slickline 20-Jun-21 25-Jun-21 OV Replacement ODSN-48 Injector E-Line/Slickline 18-Jul-21 19-Jul-21 WRSSV Replacement ODSN-04 Producer E-Line/Slickline 19-Jul-21 01-Aug-21 OV Replacement ODSN-02 Producer E-Line/Slickline 02-Aug-21 10-Aug-21 TRSV Brush and Flush ODSN-06 Producer E-Line/Slickline 03-Aug-21 07-Aug-21 OV Replacement ODSN-19 Injector Coil Tubing 15-Sep-21 26-Sep-21 Hydrate removal ODSN-31 Producer Coil Tubing 17-Sep-21 22-Sep-21 TRSV Chem soak ODSN-31 Producer Coil Tubing 17-Sep-21 28-Oct-21 TRSV Lockout ODSN-02 Producer Coil Tubing 21-Sep-21 29-Sep-21 TRSV Chem soak, Fluff &Stuff, Scale Inhibition Treatment ODSN-03 Injector E-Line/Slickline 26-Sep-21 27-Sep-21 Swab pressure test ODSN-24 Producer Coil Tubing 27-Sep-21 09-Oct-21 Fluff & Stuff, Scale Inhibition Treatment ODSN-01A Producer Coil Tubing 29-Sep-21 03-Oct-21 Fluff&Stuff ODSN-01A Producer Coil Tubing 19-Dec-21 21-Jan-21 Fluff & Stuff, incomplete due to weather delay and equipment issues Table 1: 2021 ONOP Rigless Well Interventions Annual average daily ONOP oil production for 2021 was 5,731 BOPD. Total oil production during 2021 was 2,091,715 barrels for a cumulative 33,949,609 barrels since field start-up in 2008. The 2021 annual average producing gas oil ratio (GOR) and watercut were 1,147 SCF/STBO and 19%, respectively. The December 2021 average GOR was 871 SCF/STBO and the watercut was 28%. Average annual daily water injection for 2021 was 13,169 bpd. Total water injection in 2021 was 4,806,820 barrels for a cumulative 30,548,750 barrels since the start of injection in 2009. The December 2021 average injection rate was 15,306 bpd. Gas injection was limited in 2021 due to a shutdown of one of the two OTP compressors since February 2020 preventing gas injection until it was repaired in April 2021. Additionally, in order to maximize OF gas lift volumes, gas injection was gradually reduced with no injection in November and December 2021. Total gas injection in the ONOP during 2021 was 463 MMscf and 12,617 MMscf since the start of the project. The annual voidage replacement averaged 95% for the year, and in December 2021 was at 142%. The cumulative voidage replacement ratio is at 53%. Attachment B details the 2021 voidage balance for the ONOP. Eni Petroleum —Alaska Development Page 3 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Twenty pressure surveys recorded in 2021 were reported from twelve wells. The pressure survey results are summarized in the ONOP Pressure Report, Form 10-412 (See Attachment C). The ONOP Reservoir Pressure Map, Attachment D, depicts the estimated ONOP average pressures for December 2021 including all wells, both shut-in and on-line. The estimated average ONOP December 2021 reservoir pressure is 2,500 psi at 6,350 ft. TVDss. The 2021 average annual producing GOR was 1,147 SCF/STBO and in December 2021 the GOR averaged 871 SCF/STBO consistent with sustained and increasing water injection voidage replacement (refer to Attachment E, Nuigsut Annual Reservoir Properties Report Form 10-428). 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring Reservoir surveillance is routinely conducted to monitor wells and reservoir performance and to recommend changes in operating conditions, perform rate allocations, propose optimization actions, address, and solve general issues. Historically well surveillance equipment was placed in the liners of seventeen Nuiqsut wells during the initial completions. The systems are in -place to assess production profiles and continuity along the lateral via target fluid tracers, which were monitored and analyzed by collecting surface fluid samples during restarts and over time. The tracers have been used to assess hydraulic connectivity along the laterals to evaluate the need for coil tubing interventions to clear any sand or debris blocking the flow path. For all wells the oil tracer components are no longer active. However, if a significant water breakthrough event occurs sampling to assess the water tracer response is planned. During unplanned 2021 well interventions pressure surveys were collected in the ODSN-19 and ODSN-24 wells, and gamma ray logs were recorded in ODSN-01A, ODSN-02 and ODSN-24. The gamma ray logs reveal elevated counts in areas of water breakthrough associated with barium sulfate scale deposition which can be helpful in diagnosing connections with offset injectors (the data is currently under review). Eni Petroleum —Alaska Development Page 4 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 2021 are: ONOP: 91.0% OKOP: 8.8% OTOP: 0.2% Theoretical production for individual wells for all pools is calculated daily. During 2021 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: Minutes produced 1440 Minutes day xDailyRate(BOPD) we,,,,, = TheoreticalDaily Production 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 2021 was 0.9281. Eni Petroleum —Alaska Development Page 5 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 A10 No. 37A, 33 and 34, respectively. Injection commenced into the ONOP in 2009. During 2021 the ONOP Under -Saturated Water -Alternating -Gas (US -WAG) reservoir management included maximizing voidage replacement and managing producing gas oil ratios by cycling producing wells on and off production where possible operationally. The current cumulative voidage replacement ratio is at 53%, which is consistent with ratio of injection wells to producing wells (18 producer and ten injection wells) and the overall ONOP pattern layout. Attachment B details the 2021 annual and cumulative voidage balance for the ONOP. In general, producing wells in the more mature flood areas have seen GOR stabilization, stabilized or increased oil production, and some water breakthrough as expected, and via unexpected connections which are being evaluated and monitored. With the consistent water injection and ample supply due to implementation of SWIS, ONOP flood throughput has increased reducing the overall GOR and increasing area pressures. Following the July 2019 water injection shut-in the ONOP average monthly GOR peaked in September 2020 at 1,435 SCF/STBO from a low of 675 SCF/STBO in October 2019 and has since declined to 871 SCF/STBO in December 2021. Similarly, ONOP average monthly watercut decreased from 20% in August 2019 to 10% in January 2021 and has since increased to 28% in December 2021. Overall ONOP pressures have stabilized and are increasing. The central Kalubik fault block (Kalubik) currently has 11 wells, seven producer and four injection wells. Three producers, ODSN-01A, ODSN-37, and ODSN-42B were produced consistently during 2021 with uptime greater than 80%. Production from three wells ODSN-24 (21% uptime), ODSN- 25 (67% uptime), and ODSN-36 (40% uptime) was limited due to facility constraints and to manage voidage replacement and producing GORs. The ODSN-31 well had limited production (24% uptime) due to a failed SSSV in March. Kalubik 2021 average daily production was 1,715 BOPD with 459 BWPD (21% water cut) at a 923 SCF/STBO GOR. Water injection was sustained throughout 2021 in both ODSN-32 and ODSN-34, with each at 91% uptime. ODSN-26 was also on injection consistently in 2021 with 88% uptime; gas was injected in the well from May through October. ODSN-19 injection was shut-in from May through September due to a hydrate plug in the tubing which required coiled tubing to clear. The Kalubik 2021 annual average daily water injection rate was 2,814 BPD and the gas injection rate was 1.27 MMSCFPD. Eni Petroleum —Alaska Development Page 6 The southern Colville Delta fault block (Colville Delta) currently has nine wells, six producer and three injection wells. One producer, ODSN-16 produced consistently during 2021 with 99% uptime. Offtake from two producers, ODSN-22 (54% uptime) and ODSN-43 (65% uptime), were purposely restricted to manage pattern pressures, voidage replacement and the pattern producing GORs by alternating production cycles from the wells. Additionally, production from the ODSN-10 well, a pre -produced up -dip injector, was cycled on for 30 days and shut-in for 60 days (29% uptime) to manage area pressures and GORs. Due to non-competitive TGORs on gas lift and periodic gas lift valve plugging, production from both ODSN-17 and ODSN-18 was limited during 2021 to 31% and 45% uptime, respectively. Colville Delta 2021 average daily production was 2,170 BOPD with 318 BWPD (13% watercut) at a 934 SCF/STBO GOR. Water injection was sustained throughout 2021 in ODSN-15 (uptime 91%), ODSN-23 (uptime 91%), and ODSN-48 (uptime 83%). The Colville Delta 2021 annual average daily water injection rate was 4,489 BPD; gas was not injected in the Colville Delta injectors during 2021. The Ivik fault block (Ivik) currently has eight wells, five producer and three injection wells. Two producers, ODSN-02 and ODSN-28 were produced consistently during 2021 with 95% and 98% uptime, respectively. Production from two wells ODSN-04 and ODSN-06 was limited to 68% and 69% uptime, respectively, due to non-competitive TGORs on gas lift, facility constraints and to manage voidage replacement and producing GORs. One producing well, ODSN-29 Nuigsut, remained shut-in during 2021 as it is isolated in the ODSN-29 wellbore, to allow production of the Kuparuk interval. Commingling is not currently allowed nor functional at this time. Plans in 2022 include closing off Kuparuk production in the ODSN-29 well and restarting ONOP production. Kuparuk offtake will be moved more distal to the ODSN-06 wellbore which will improve recovery from both pools. Ivik 2021 average daily oil production was 1,846 BOPD with 607 BWPD (25% watercut) at a 1,605 SCF/STBO GOR. Water injection was sustained throughout 2021 in ODSN-07i (91% uptime) and ODSN-27i (91% uptime). Injection into ODSN-03i was purposely delayed until June (48% uptime) to assist in evaluating flow path connections in the northern area of the Ivik. The Ivik 2021 annual average daily water injection rate was 5,866 BPD. Due to well integrity issues on gas injection in the three Ivik injection wells no gas was injected in the block. Individual well and pattern surveillance data will continue to be collected to monitor performance and improve recovery. A simulation model has been maintained and updated to assist in reservoir development and flood management decisions in the ONOP. 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