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Home My WebLink About2022 Schrader Bluff Oil PoolFrom:Roby, David S (OGC) To:Carlisle, Samantha J (OGC); Guhl, Meredith D (OGC); AOGCC Reporting (CED sponsored) Subject:FW: Eni"s 2022 Oooguruk Reservoir Surveillance Reports Date:Monday, April 17, 2023 3:23:18 PM Eni has dropped the confidentiality request. Please add a copy of this email chain to the PDFs of the reports. Dave Roby (907)793-1232 From: Province Robert <Robert.Province@eni.com> Sent: Monday, April 17, 2023 2:55 PM To: Roby, David S (OGC) <dave.roby@alaska.gov> Subject: Eni's 2022 Oooguruk Reservoir Surveillance Reports Dave, Regarding Eni’s recently submitted 2022 Reservoir Surveillance Reports for both Nikaitchuq and Oooguruk Units, please disregard Eni’s request for confidentiality stated in our transmittal letter dated March 31, 2023. If you need an amended transmittal letter for the record, let me know. Please accept our apologies for this oversight. Thanks, Robert A. Province Manager – Land & Public Relations Eni US Operating Co. Inc (907) 865-3350- Office (907) 947-3793 – Cell Email: robert.province@eni.com From: Roby, David S (OGC) <dave.roby@alaska.gov> Sent: Thursday, April 13, 2023 1:16 PM To: Province Robert <Robert.Province@eni.com> Subject: RE: [EXTERNAL] RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Hi Robert, No worries. Because you made a claim of confidentiality, one that we disagree with, we’re not going to make the documents available to the public until we resolve the issue. Waiting until early next week is no big deal but if it drags on too long we may take other steps, like scheduling a hearing on the matter. Regards, Dave Roby (907)793-1232 From: Province Robert <Robert.Province@eni.com> Sent: Thursday, April 13, 2023 12:53 PM To: Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Dave, Thank you for the helpful information below. I am suspecting early next week, to revoke Eni’s request for the RSRs be held Confidential. I will contact you as soon as I hear back from HQs. Again, thank you in advance for your patience in this regard. Robert A. Province Manager – Land & Public Relations Eni US Operating Co. Inc (907) 865-3350- Office (907) 947-3793 – Cell Email: robert.province@eni.com From: Roby, David S (OGC) <dave.roby@alaska.gov> Sent: Wednesday, April 12, 2023 3:49 PM To: Province Robert <Robert.Province@eni.com> Subject: RE: [EXTERNAL] RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Hi Robert, Yes, but it’s a little convoluted. 20 AAC 25.517 requires and initial reservoir development plan and then annual updates to said plan, so submitting an annual plan is a regulatory requirement. However, that requirement is usually superseded, as it is in the case of Eni’s operations, when pool rules are issued that prescribe slightly different requirements for a reservoir surveillance report (for example, Rule 12 of CO 631 prescribes the rules for Nikaitchuq’s report). The pool rules are issued in accordance with 20 AAC 25.520 and thus the rules in the orders have the same effect (i.e. it is a requirement the operator has to follow and the AOGCC could take an enforcement action against an operator if they do not abide by the conditions of the rule) as if they were written directly in the regulations themselves. In reference to why we’re saying these reports should be public information, 20 AAC 25.537(a) states: The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: …(3) all reports and information required by this chapter [this refers to 20 AAC 25] for development and service wells,… So, since the reports are required by an order issued under the chapter it’s our position the reports should be public. Hope this helps. Regards, Dave Roby (907)793-1232 From: Province Robert <Robert.Province@eni.com> Sent: Wednesday, April 12, 2023 2:48 PM To: Roby, David S (OGC) <dave.roby@alaska.gov> Subject: RE: [EXTERNAL] RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Dave, I probably won’t be able to get a final response to you until next week. Also, Headquarters had asked how AOGCC makes the request for these reports. It’s a regulatory requirement, correct? I am attempting to convince Headquarters to remove their confidentiality request. Eni has never requested confidentiality status on the RSRs. Robert A. Province Manager – Land & Public Relations Eni US Operating Co. Inc (907) 865-3350- Office (907) 947-3793 – Cell Email: robert.province@eni.com From: Roby, David S (OGC) <dave.roby@alaska.gov> Sent: Monday, April 10, 2023 2:13 PM Security Warning: This email originated from outside of the organization. Do not click links or open attachments unless you have verified the sender’s email address and know the content is safe. To: Province Robert <Robert.Province@eni.com> Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov>; Brooks, James S (OGC) <james.brooks@alaska.gov> Subject: [EXTERNAL] RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Hi Robert, I haven’t heard anything back on the confidentiality issue. Have you had a chance to think about this? Regards, Dave Roby (907)793-1232 From: Roby, David S (OGC) Sent: Monday, April 3, 2023 2:47 PM To: Province Robert <Robert.Province@eni.com> Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov>; Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov>; Brooks, James S (OGC) <james.brooks@alaska.gov> Subject: RE: Eni's 2022 Oooguruk Reservoir Surveillance Reports Hi Robert, I understand there’s been some back and forth this morning about additional submittals. What we need are Excel spreadsheet versions of the 10-412 reports that are attachment C in the ARSs and the 10-428 that is Attachment E in the reports to facilitate loading this information into our database. Attached is your submittal of the 412s from last year for reference. Also, on the Annual surveillance reports and the Polymer Injection project report on the cover letters you request that the reports be held confidential. Many moons ago you submitted ARSs marked as confidential and at that time you said that was done in error and Eni wasn’t seeking to have the reports held confidential (see attached email). Has Eni’s position on this matter changed? If so you will need to provide justification for the AOGCC to consider for why these documents should be held confidential. Generally speaking, information that the AOGCC requires to be submitted, as is the case for the ARSs and the polymer injection report since those were required by orders issued by the AOGCC, is considered public information unless it is entitled to confidentiality under some other provision of state or federal law. In which case the specific information that is entitled to confidentiality can be redacted from the report but the bulk of the report will be made available to the public. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Regards, Dave Roby (907)793-1232 From: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Sent: Monday, April 3, 2023 12:08 PM To: Roby, David S (OGC) <dave.roby@alaska.gov>; Brooks, James S (OGC) <james.brooks@alaska.gov> Cc: Guhl, Meredith D (OGC) <meredith.guhl@alaska.gov> Subject: FW: Eni's 2022 Oooguruk Reservoir Surveillance Reports From: Province Robert <Robert.Province@eni.com> Sent: Monday, April 3, 2023 12:05 PM To: Carlisle, Samantha J (OGC) <samantha.carlisle@alaska.gov> Cc: Zuber Joshua <Joshua.Zuber@eni.com> Subject: Eni's 2022 Oooguruk Reservoir Surveillance Reports Sam, Attached please find the subject reports (digital copies) that I dropped off at AOGCC on Friday March 31st. Remainder of reports to follow in next email. Robert A. Province Manager – Land & Public Relations Eni US Operating Co. Inc (907) 865-3350- Office (907) 947-3793 – Cell Email: robert.province@eni.com ------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------- Message for the recipient only, if received in error, please notify the sender and read http://www.eni.com/disclaimer/ 2�n1� us apera[inng 2022 Annual Reservoir Surveillance Report Nikaitchuq Schrader Bluff Oil Pool (NSBOP) Nikaitchuq Field April 1, 2023 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..........................................5 3.0 Results and Analysis of Production and Injection Log Surveys, Tracer Surveys, Observation Well Surveys and Any Other Special Monitoring.......................................................................................6 4.0 Review of Pool Production Allocation Factors and Issues Over the Year .................................... 8 5.0 Reservoir Management Summary..........................................................................................9 ATTACHMENT A NSBOP Well Location Map.......................................................................11 ATTACHMENT B 2022 NSBOP Voidage Balance by Month................................................12 ATTACHMENT C NSBOP Pressure Report, Form 10-412...................................................13 ATTACHMENT D NSBOP Reservoir Pressure December 2022...........................................14 ATTACHMENT E NSBOP Annual Reservoir Properties Report, Form 10-428.....................15 ATTACHMENT F NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) ......16 ATTACHMENT G NSBOP Polymer Project Location Map....................................................17 Eni Petroleum —Alaska Development 1.0 Progress of the Enhanced Recovery Project The Nikaitchuq Field (NF) is one of two Eni US Operating Co. Inc. (Eni) offshore -operated fields in Alaska. It is located offshore in East Harrison Bay, near the Colville River Delta in the Beaufort Sea. The Nikaitchuq Schrader Bluff Oil Pool (NSBOP) development utilizes an onshore gravel pad located at the Oliktok Point Pad (OPP) and the offshore Spy Island Drill site (SID). The onshore development contains standalone multiphase processing facilities. SID is a drilling location from which offshore production is imported via a flowline bundle to OPP. Processed oil sales are exported through a dedicated pipeline tied into the Kuparuk River Unit (KRU) facilities, operated by ConocoPhillips Alaska, Inc. (CPAI), which exports the oil to the Trans -Alaska Pipeline System (TAPS). The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under Conservation Order No. 639 (CO 639) and Area Injection Order 36 (A1O 36) authorizing the injection of fluids for pressure maintenance and enhanced oil recovery in the NSBOP. At the end of 2022, there were 54 active NSBOP development wells, including 31 production (11 OPP, 20 SID) and 23 injection (8 OPP, 15 SID) wells. Dual lateral wellbores have been completed in 22 of the production wellbores (8 OPP, 14 SID). These wells target the OA sand of the NSBOP. One inactive development well, OP19-T1N, was drilled and completed to test the potential of the N sand development. Additionally, two disposal wells (1 OPP, 1 SID) and three Ivishak source water wells (3 OPP) are active in supporting operations. Future development plans include drilling one additional OA wells (SP42-NE4) in 2023, adding a 2"d lateral to SP05-FN7 (2024) and an injector producer pair (2024) to assess the N sand development potential. Under the current economic environment, this scenario will be completed in 2024 but is subject to change. The existing and planned NSBOP wells are shown in Attachment A. In 2022, Eni continued rig and rigless (RLWO) activities at OPP and SID. In total, 24 rig activities (6 OPP, 18 SID), including 10 workovers (6 OPP, 4 SID) and 14 SID drilling and completion operations, were conducted in 14 wells (5 OPP, 9 SID). Eighteen RLWO operations (14 OPP, 4 SID) were performed on ten wells (6 OPP, 4 SID). Both types of activities are summarized in Table 1 below. Eni Petroleum —Alaska Development Page 1 Action # Well Name Well type Location Reservoir Action Type Objectives/Description Completion Date 1 SP09-E2 L1 OP SID CASand Drilling Grassroots dual lateral production well 1/10/2022 2 SP09-E2 OP SID OASand Completion Run ESP and Upper Completion 1/13/2022 3 OP26-DSP02 DSP OPP Torok RLWO Tubing integrity failure, installed patch 1/24/2022 4 OP21-WW01 WW OPP Ivishak RLWO Brush & flush SSSV 2/5/2022 5 OP10-09 OP OPP OASand RWO ESP replacement 2/11/2022 6 SI07-SE4 WI SID CASand RLWO Tubing integrity failure, installed patch 2/15/2022 8 OP23-WW02 WW OPP Ivishak RLWO Brush & flush 2/18/2022 7 SI15-El WI SID CASand Drilling New injection well 2/19/2022 9 OP05-06 OP OPP OASand RWO ESP replacement 2/22/2022 10 SI15-El WI SID OASand Completion New injection well 2/22/2022 11 OPO4-07 OP OPP OASand RWO ESP replacement 3/5/2022 12 SP31-W7 OP SID OASand RWO ESP replacement 3/8/2022 13 OP23-WW02 WW OPP Ivishak RLWO Passport Test 3/9/2022 14 OP21-WW01 WW OPP Ivishak RLWO Passport Test 3/17/2022 15 SP03-NE2 L2 OP SID OASand RWO Pull ESP and Completion to drill lateral 3/22/2022 16 0115-S4 WI OPP CA Sand RWO Pull and Replace Tubing 3/31/2022 17 SP03-NE2 L2 OP SID OASand Drilling Drill L2 lateral 4/24/2022 18 OP26-DSP02 DSP OPP Torok RLWO Pull and Replace Tubing 4/30/2022 19 SP03-NE2 L2 OP SID CA Sand Completion Run ESP and Upper Completion 5/5/2022 20 OP14-S3 OP OPP OASand RWO ESP replacement 5/9/2022 21 0107-04 WI OPP OASand RLWO Tubing integrity failure, installed patch 5/20/2022 22 OP21-WW01 WW OPP Ivishak RLWO Brush & flush SSSV 6/18/2022 23 OP22-WW03 WW OPP Ivishak RLWO Brush & flush SSSV 6/20/2022 24 OP23-WW02 WW OPP Ivishak RLWO Brush &flush SSV 6/23/2022 25 SP40-E4 OP SID OASand Drilling New production well 6/27/2022 26 0120-07 WI OPP CASand RLWO Tubing integrity failure, installed patch 7/5/2022 27 SP40-E4 L1 OP SID OASand Drilling New production well 7/13/2022 28 SP40-E4 OP SID OASand Completion Run ESP and Upper Completion 7/19/2022 29 SI114N6 WI SID CA Sand RLWO Tubing integrity failure, installed patch 7/22/2022 30 0107-04 WI OPP OASand RLWO Tubing integrity failure, diagnostics 8/16/2022 31 SP41-E3 OP SID CASand Drilling Initially drilled as new injector, changed to producer 8/25/2022 32 SP41-E3 Ll OP SID OASand Drilling Lateral 9/9/2022 33 SP41-E3 OP SID OASand Completion Run ESP and Upper Completion 9/13/2022 34 OP22-WW03 WW OPP Ivishak RLWO Brush&flush 10/12/2022 35 SP31-W7 OP SID CASand RWO Cleanout, ESP replacement with middle completion 10/13/2022 36 OP23-WW02 WW OPP Ivishak RLWO Passport Test 10/24/2022 37 SP03-NE2 OP SID CASand RLWO Rigless Through Tubing ESP Pull and Replace 11/6/2022 38 S143-NE3 WI SID OASand Drilling New injection well 11/21/2022 39 S143-NE3 WI SID CA Sand Completion New injection well 12/1/2022 40 SD37-DSP01 DSP SID Torok RLWO Integrity Testing 12/15/2022 41 SP03 NE2 OP SID OASand RWO Cleanout, ESP replacement with middle completion 12/17/2022 42 OP10-09 10P OPP CASand IRWO I ESP replacement, Casing Repair 2/1/2023 * Action 1&2 were initiated in 2021 and completed in January 2022. Table 1: 2022 Nikaitchuq Field Drilling Rig Activity Eni Petroleum —Alaska Development Page 2 The primary causes for well shut-ins and workovers are electrical submersible pump (ESP) failures, solids plugging and tubing corrosion. All workovers since 2019 have incorporated coated tubing to mitigate the corrosion risk and have not experienced any integrity issues. At the end of 2022, two producing wells (OP10-09 and SDP40-E4) and one injection well (0115-54) are shut in pending rig interventions. The planned well interventions for 2023 are OP10-09 (ESP replacement, clear solids), 0106-07 (tubing replacement), 0107-04 (tubing replacement), O1303-1305 (ESP replacement), 0120-07 (tubing replacement), SP21-NE1 (ESP replacement, clear solids), and SP36 (ESP replacement, clear solids). Other well interventions will be on a need basis during 2023. On October 22, 2019, pursuant to NO 36.002, polymer injection was initiated in the Oliktok Point 1-2 (OP-12) well for a one-year test to determine the effectiveness of polymer injection for improving recovery from the NSBOP. The test was cut short after 154 days due to logistical issues resulting from the COVID-19 pandemic and the shortened test period resulted in inconclusive test results. Eni resumed the polymer injection test in 2021 and has received Administrative Approval under NO 36.003 to extend the test through December 31, 2022. During 2022, OF engineering performed an internal operations and maintenance assessment to ensure compliance with corporate requirements. Additionally, Eni's corporate operations team performed a cold -eye review of the Oooguruk plant to identify bottlenecks, efficiencies and production improvement opportunities. An internal corporate assessment was also performed to ensure compliance with internal procedures on safety and environmental critical elements. Engineering work commenced on an integrated model to connect the reservoir, wells and surface production equipment to facilitate production optimization. An engineering study for revamping the 2-phase separator also started. A modelling analyses was also started with the Multiphase pumps at SID (MPP) in order to optimize their operation. Routine maintenance was performed on the four power generation turbines and two gas compressors at the Oliktok Production Pad (OPP), with one of the power generation turbines receiving a complete overhaul replacement and all receiving exhaust stack inspections and associated repairs. Maintenance was performed on Train 2 Inlet and Low Pressure Separators. They were cleaned, inspected and partially recoated in order to be API inspected and certified. Train 1 Low Pressure Separator Vessel was cleaned and Inspected during 2022 as well. In addition, cathodic protection inspections were completed on the sub -sea production flowline from the offshore Spy Island Drill Site (SID) to OPP to ensure the mechanical integrity of the flowline bundle. 10" Sale Oil Pipeline was internally inspected with a High Resolution Pig. The Electrical Power Sharing project to interconnect the Oooguruk and Nikaitchuq fields continued with design and procurement, with startup scheduled for 2025. Through additional drilling, well interventions, and consistent injection the NSBOP observed field oil production and water cut align with Eni's reservoir model expectations. The annual average daily NSBOP production during 2022 was 17,400 BOPD. Total oil production from the NSBOP during 2022 was 6,351,050 barrels and is 74,873,728 barrels since field start-up thru 2022. The annual average producing GOR and watercut were 161 SCF/STBO and 74%, respectively. Eni Petroleum —Alaska Development Page 3 The annual average daily NSBOP water injection during 2022 was 79,611 BWPD. Cumulative water injection in the NSBOP during 2022 was 29,058,044 barrels and 178,906,703 barrels since the start of the project. The 2022 annual and cumulative voidage replacement ratios were 1.13 and 1.02, respectively. Attachment B details the 2022 voidage balance for the NSBOP. Pursuant to AlO 36 Rule 8, Attachment F summarizes the mechanical integrity testing results and plans for the NSBOP injection wells. Eni Petroleum —Alaska Development Page 4 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Thirteen pressure surveys recorded in 2022 were reported from twelve wells. There were eight pressure surveys from worked -over wells. Four were grassroots wells with initial pressures reported. The pressure survey results are summarized in the NSBOP Pressure Report, Form 10-412 (refer to Attachment C). The NSBOP Reservoir Pressure Map, Attachment D, depicts the estimated NSBOP average pressures for December 2022, including shut-in and producing wells. The estimated average NSBOP reservoir pressure is currently 1,700 psi at -3,760 ft. TVDss (datum). 2022 average annual producing GOR was 161 SCF/STBO; in December 2022, the GOR averaged 150 SCF/STBO (refer to Attachment E, NSBOP Annual Reservoir Properties Report Form 10-428). Reservoir management utilizes continuous pressure monitoring in both producers and injectors. In addition to surface gauges measuring tubing pressures, Nikaitchuq oil producers are equipped with downhole ESP gauges, providing both pump intake pressures (PIP) and discharge pressures, which allow real-time bottom -hole pressure (BHP) monitoring. The data are used to optimize production while monitoring for signs of sand production, rising water cuts (WC), increasing gas - oil ratios (GOR) and balancing voidage. During extended shut-ins, the BHP data provides valuable surveillance and model input. Additionally, downhole gauges have been installed in ten injection wells to assist in monitoring and calibration; seven systems are currently functional (0106-05, 0107-04, S102-SE6, S106-NE1, S115-El, S125-N2, S143-NE3). Three systems no longer transmit accurate data, 0111-01, S114-N6, and S120-N4. OP-12 had a temporary memory gauge installation for the polymer test. The gauge was removed in early 2023 and was found to have stopped recording data on November 14, 2022. Water injection targets maximizing voidage replacement and throughput to maximize production and reserves. Consequently, injection pressures target the maximum pressure not to exceed the fracture gradient, which can lead to early breakthrough events and poor flood conformance; injection wellhead pressures, and if available BHPs, are continuously monitored and injection rates adjusted accordingly. The operational target injection pressure limits are significantly lower than the sandface limit of 2,400 psi prescribed by A10 36, Rule 4 so that injected fluids do not fracture the arresting or confining intervals or migrate out of the approved injection strata. Maps of the field pressures, including shut-in and active wells, refer to Attachment D, are used for monitoring performance, reservoir management and modeling. In December 2022, the datum referenced average NSBOP producing well pressure was 678 psi (range: 395 psi to 1,475 psi), the average injection well pressure was 2,042 psi (range: 761 psi to 2,317 psi), and areas outside the influence of the development are at the initial pressure of 1,700 psi. Eni Petroleum —Alaska Development Page 5 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 well and reservoir performance, recommend operating condition changes, perform rate allocations, propose optimization actions, and address and solve general issues. Production allocations have been performed continuously using well models calibrated with the most recent well tests. Reservoir surveillance and monitoring activities in 2022 for the NSBOP included: • Downhole and wellhead pressure and real-time temperature measurements, • ESP main performance parameter monitoring (e.g., current, voltage, motor temperature), • Distributed Temperature Systems (DTS, fiber optics) monitoring lateral conformance (fiber optics) in three wells: 0107-04, S114-N6, and S120-N4, • Corrosion monitoring, • Well performance indicative of tubing leaks or failing ESPs, • Hydrocarbon and produced water surface sampling, • Tracer sampling and interpretation in the OP-12 polymer pilot area, • Well production tests, • Continuation of the polymer flood testing pilot phase at the OP-12 well Initially, three OPP injectors (0106-05, 0107-04, 0111-01) and two SID injectors (S114-N6, S120-N4) were equipped with DTS fiber optics to quantify the conformance along the horizontal injection intervals and monitor it over time. The DTS on 0111-01 and 0106-05 have been taken out of commission. During 2022, no DTS fall -off testing or analyses were performed. Eni has concluded an FOR pilot project focused on using polymer injection to enhance the overall recovery of the field. The pilot was planned in three phases: • Phase 1: Short-term Injectivity test (completed in May 2019), • Phase 2: One-year pilot injection test (initiated in late 2019, shut down in March 2020 due toCOVID-199), and • Phase 3: Full -Field Application (dependent on Phase 2 results and further review) During 2022 Phase 3 of the polymer injection pilot test for the OA sands reservoir was carried out in the OP-12 well. Those results have been quantified in terms of oil rate & water cut rates observed on the neighboring producer wells OP12-01 and OP17-02. The study aimed to evaluate polymer injection's effects in the Nikaitchuq field's OA sand. The pilot project was conducted on the OP-12 well (See Attachment G). Polymer injection started on October 22, 2019, and was suspended on March 24th, 2020, due to Covid-19 related issues. The project resumed operations on March 19th, 2021 and polymer injection stopped on December 16th, 2022 with the project concluding on December 31, 2022. Eni Petroleum —Alaska Development Page 6 The successful execution of this pilot test allowed Eni to gather important information about the effectiveness of polymer injection into the Schrader Bluff OA sands in the Nikaitchuq field. Key results of the study included the effects of polymer injection on the neighboring production wells, indications about polymer injectivity over time and tracer arrival times. These findings provided valuable expertise in developing a case to support a future full -field polymer injection project. Results quantification was done using dynamic modeling and decline curve analysis (DCA). At the end of June 2022, the estimated additional oil recovered associated with the polymer injection was approximately 54,000 stb, corresponding to an average of +120 bopd for the period considered. Further analysis and interpretation are ongoing. Eni Petroleum —Alaska Development Page 7 4.0 Review of Pool Production Allocation Factors and Issues Over the Year Production from all wells producing from the NSBOP is commingled at the surface into a common production line. Theoretical production for individual wells from the pool is calculated daily using well test allocations consistent with CO 639, Rule 8. Wells are tested at least twice per month using Schlumberger Vx multiphase meters. Daily theoretical production per well is calculated based on the last valid well test and the amount of time that the well was on production for a given day: Minutesproduced 1440 Minutes day xDailyRate(BOPD) wen�eSr = TheoreticalDaily Production The daily oil allocation factor for the field is calculated by dividing the actual total LACT meter production for the day by the sum of the theoretical daily production for each well. Subsequently, daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average 2022 NSBOP oil allocation factor was 0.9754 as detailed in Table 2 below. Month Average Daily Allocation Factor January 0.9632 February 0.9854 March 0.9808 April 0.9756 May 0.9803 June 0.9617 July 0.9552 August 0.9720 September 0.9549 October 0.9950 November 1.0017 December 0.9787 2022 Average 0.9754 Table 2: Average Daily Field Allocation Factors for 2022 Eni Petroleum —Alaska Development Page 8 5.0 Reservoir Management Summary The Alaska Oil and Gas Conservation Commission (AOGCC) issued pool rules under Conservation Order No. 639 (CO 639) and Area Injection Order 36 (AIO 36) authorizing the injection of fluids for pressure maintenance and enhanced oil recovery in the NSBOP. Consistent with the orders, the overall reservoir management objective is to maximize economic recovery and minimize project risks while maintaining the highest environmental and safety standards. The primary recovery mechanism for the field is waterflooding. Producers and injectors have been drilled in pairs, located side by side and completed with horizontal drains in the OA sands. Oil producer and water injector targets are defined based on historical producer -injector waterflood responses, pressure trends, ESP constraints and well integrity limits. Water injection targets maximizing voidage replacement and throughput to maximize production and reserves. Injection pressures target the maximum pressure not to exceed the fracture gradient, which can lead to early breakthrough events and poor flood conformance. The hydrocarbon present in the Schrader Bluff is viscous and has low expansion energy and little potential for gas expansion. Production and recovery are a result of waterflood displacement. Artificial lifting is crucial for well productivity; thus, ESP failures represent one of the most significant risks to NSBOP production. Other significant risks are tubing, manifold and pipeline leaks due to corrosion. Studies to understand and mitigate these risks are ongoing. This integrity issue continues to negatively affect production, is costly to diagnose and is remediated through the tubing and ESP replacements. Well constraints for injectors and producers are based on historical analog field and well performance, ESP capacity, pressure trends, waterflood pattern behavior, well integrity conditions and ongoing operations. Individual well, pattern and field performance are routinely reviewed and discussed with the Anchorage, Houston and Milan teams; pump intake targets and injection well rate targets and pressure limits are defined and communicated to the lead field operators along with guidelines to implement changes. The typical minimum pump intake pressure targets 400 to 500 psi at the sandface, but is occasionally higher due to pump capacity limits, gas locking at low pressures, sand production or other performance concerns. The maximum injection pressure limit for all well's targets stays below the formation fracture pressure and is continuously monitored by surface wellhead pressures; occasionally, lower injection limits are implemented for diagnostic or operational purposes. Reservoir management activities will continue in the NSBOP with the objective to: • Maximize daily volumes and value by optimizing hydrocarbon production; • Minimize risk exposure to key producing wells and maintain well integrity; • Continue the Polymer Injection Pilot at OPP through 2022; • Proactively define and develop mitigation plans related to water production; • Proactively acquire reservoir performance data critical to reservoir management and overall recoverable volumes determination; • Ensure timely execution of reservoir surveillance plans, workovers, re -completions, and infill drilling; Eni Petroleum —Alaska Development Page 9 • Update current reservoir simulations and studies to reproduce the field behavior; • Find cost-effective solutions to optimize production. 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 reservoir development and flood management decisions in the NSBOP. Eni Petroleum —Alaska Development Page 10 ATTACHMENT A NSBOP Well Location Map A F.da.1 State Nikaitchuq Unit Boundary Spy stand Sg Ei �, I ,r __ gg LEGEND cm O,Iikt.k Point IN,kaftchuq Field Development Map ZZ" 11.11102J I Alaska G., Team e Ile �C—s Eni Petroleum — Alaska Development Page 11 CO G` m Z cv CW m G � 2 � U H o 1— > as co) ''V, Z N N O N ai u C O_ :3 m CC O Ln LO r-i M M It 'It ri Ln r-i O Ln N lD ri It Ln LD r-I O E � 2 N Ln 0) `� 'ct 00 O M n r-i lD o0 �--1 r-I e-I N N f V N N' m M m C V O ++ u O1 r`0 m 00 Ln N Ol M Ln O Ln O'T O N Ln .-i M Ln Ln r-i 0) Ln M •C a) Of r-1 ct Ln lD oo Ol m Ln l0 n 00 N l0 O mr-I } V -i a-i r-i r-i N N m ro Y N Z C v° CO 00 00 W r- LD O LOM rn-zt LD Ln m Z N ri m N N M Ln M LO ri o r-i m r-i r-i r-i r,N M -It m -zt M N rn O1 u C Q m d' m ri N O m 'zt O 1.0 d' N Ln LO m N m M N M Ol M It O o O t' K 00 m N m f O m O N LO m m m m m E cT r\ cr N' l0 00 r-1 r6 LD 00 U Ln E r-i Ln LD O 00 O ri Ln 00 Lr-I r^-1 N lD' rLr)-I Ol L1i r-1-I (.00Ln L6 01 LL Lp N r� Ql ri ri ri ri r-I' N Ct N N (V � N } N lu a O m L Q LO LO r, 00 Ln r-' -t LO -i 'ct Ln LO o r\ m Dl r, LD in cr cn O oo Ln c d ri Ln Ln Ln 't N m m m Ln Ln a o f T N' f,' fV' f T fV' N' fV' N' N N N N C m L% C V o m c LD LD r, 00 3 u) -1 t LD ri -Zt Ln LD o N m 0) r, LO m 'Gt m OLn o0 m u Ln N c-I In ifl "It M M M Vl to O >> E N' N' N N' N' N N' N' r i N' N N N C 7 u p_ m n w 'cY r-I m O O N -i Ln m N v m M m M M a-1 O M oo M M M 0 m E u Of in M m m r, o ri m LO LO r, m o 7 U C • cc C m -im Lij r-:'O l0 N' �• lD l6 lD 06 l0 O n N Lil i� V1 (O Nr-i cY L!'1 ci lf') ci Ll'1 ri Lit ri ci lD ri ci ri ri c-I f� ri a -I to co 00 t\ LnN O c-I r1 00 N LD m N 7 -�Q � O W N n^'7 LO 000000 N M Ln n } U •0 N lY7 lD 00 O1 rN-I r�-I r^-I r-i N N fV 00 m r- 00 00 ri O r, 't m 0) rn cn m � 8 � r-i Ln 0) -t m Lnr-I -It O Ln N -p O C N -1 N a--1 N N O CAi0- N r-I N N N N' N N' N' N' N' N N .7 > LL 1 J ri oo N N m oo LO r\ oo Ln r-1 O1 m 'a aJ m l0 Lf) Ln N N 00 r\ Ol M N r-I K O y m It M LO to to V Ln Ln C Li) L11 Ln N 7 >� GC rl r-I r1 r1' r-I' .--1' r-I' r-1' r-I'r-I' > O -p n i a LL m V O 00 00 W N 0) 00 O lD Lr) N l0 D1 N N LO 00 C) 00 00 0) 0) 0) r-00 r, r, O O i rl a. L Y O fl CO ri N Ol r-i LO r-i oo m Lit Ln LD z N O N oo � � r-m �t cF Dl N r-I N L» ru Y Ln v Ln Ln Ln Ln Ln Ln rt Ln Ln Ln L Ln L Y _C N ry N N N N N N N N N N ry N N N N N N N N N N +�' O N L- Q c ry ' m Q Y> uow u ~ Cc G 7 - LL c- c Q cm c '�'+ Q Ln O Z 0 N U N N bL rD tl N T— d' O E 0 U- O ^^CL` ^W W L V/ CD a a m cn d� J� P O f0 P O P N P t0 (O N 0 w v E N P o m n m m m P co N o � M o o Q om O N O T j 41 j w P Q P P P P Q Q P P P Q OI Q n Cl rn m " E a W O N C] n n n n n A n r n n c N o. O O C C _ � L tp 41 N m O1 N (O O Q (O (O O J 2 u C> v o O Vl N 10 P t0 C'1 � n P w � C O�- `ooi � m O '- r N M M Q Q Q P Q 0 w � J m ^ m V N n Z w ❑ o d N�o U a m m a m a m a m a m a m a m a m a m a m a m a m 4 � Q � v N o m y y fn f7 fn Ul V) N (n N In S Q � g. r�✓/ W co m 0 m P m Q Q tmV co CO C¢ J a l0 N< C 0 C 0 z 00 V ^ Q Q 1..� IL ❑ N N N N ry N o N N N o co a f0 O N M Z O v Q n c 0 m Qo o ' o i> V/ 7 N co w W N m a m a m a m v m o m a m a m a m a m a m a m a N w oC L N �j C N N N t0 to N N l0 fn N N t0 N N 1. (n l0 /n t0 fn lV t (/1 l0 L fQ t` L N N Y U n Y o o 0 0 0 0 0 0 0 o 0 0 0 0 0 0 o 0 0 0 0 o n N v CQ U vO1 Z y c o u 7 O O O O O O O 1 m cm 0 0 0 0 0 0 0 0 0 0 0 0 a Z Q t7 Nl CQ'J m tP_l m A M N N M tn+l C W Z S ❑ Q � � N N m N O O N m N O O N rn N O O N rn N O O N rn N O O N rn N t0 O N m N t0 O N rn N t0 O N m N N O N rn N N O N m N �O O N m N N O - � .� W L J a i0 ✓OI 0 o Ot. UI t O Fj. M 3 a m O O O O O W � tq m m to w ¢ � of N ATTACHMENT D NSBOP Reservoir Pressure December 2022 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 o' 0 m 0 m Federal State 0 c SP n S SP S _ WUT-Haa'as SP o SI o" m SP o SI 0 SP O ' O ' O snC O O e QO o. 0 ✓ 125 02- o " t0 - o SP36- .W6 p 0 N S -W 2 6 o: m_ o! E o' m- o m 0 y O " O ' O ' o O t0 oGeneral o ! 23oB - o zzoo zloo " z000 1800 o noB Oliktok Point 1100 \ i300 \ o0 100 o0 g N - Boo \ O 600 l00 � B00 500 / 100 / 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 Nikaitchuk Development Gate Signalise 0 2000 4000 6000 BOOOftUS 01/17/2023 Alaska Dev. Team 1:25000 Eni Petroleum — Alaska Development Page 14 co N O E L O U- 0 Q CD N Q. O L- a. '0 0 0 c� a m z 80 U U mmN Q P O O U U N A N s N dp � LL pe V S o a LL 4) S P 8 U LL � LL a m� O E 47. �� z0 ow � 5 a mo,ga z �Qa a <0 a om8� O o �, 8 S v mE_ F U) > < 2 a_ o� zw�d Q d 6.q o W < f;N Q Q o.o a o;o�� i Q = Z Z a y _ w E N Y Paz s' � m n 8 N E 8 i b G s V N 6 5� Q1 txo ra d ATTACHMENT F NSBOP Injection Well Mechanical Integrity Testing (AIO 36, Rule 8) Well PTD # Status Date of Last Test Result Frequency (Years) Due Date Injecting since MIT due date? OP-12 (inj) 206-144 WINJ 3/21/2021 P 4 3/21/2025 Yes 0106-05 210-165 WINJ 6/27/2021 P 2(AA) 6/27/2023 Yes 0107-04 210-153 WINJ 6/19/2022 P 2(AA) 6/19/2024 Yes 0111-01 210-106 WINJ 3/21/2021 P 4 3/21/2025 Yes 0113-03 211-100 WINJ 5/6/2021 P 4 5/6/2025 Yes 0115-54 211-141 WINJ 6/3/2021 P 2(AA) 6/3/2023 Yes 0120-07 211-140 WINJ 6/4/2021 P 2(AA) 6/29/2024 Yes 0124-08 211-130 WINJ 3/23/2021 P 4 3/23/2025 Yes S102-SE6 220-019 WINJ 12/15/2021 P 4 12/15/2025 Yes S106-N E1 219-165 WINJ 5/1/2021 P 4 5/1/2025 Yes S107-SE4 214-100 WINJ 2/26/2022 P 4 2/26/2026 Yes S111-FN 6 213-128 WINJ 8/3/2022 P 4 8/3/2026 Yes S113-FN 4 212-156 WINJ 4/30/2021 P 4 4/30/2025 Yes S114-N 6 213-194 WINJ 4/30/2021 P 4 4/30/2025 Yes S115-FN2 221-111 WINJ 3/13/2022 P 4 3/13/2026 Yes S117-SE2 214-041 WINJ 4/30/2021 P 4 4/30/2025 Yes S119-FN 2 213-043 WINJ 4/30/2021 P 4 4/30/2025 Yes S120-N 4 212-029 WINJ 4/30/2021 P 4 4/30/2025 Yes S125-N 2 212-090 WINJ 4/30/2021 P 4 4/30/2025 Yes S126-N W2 214-157 WINJ 8/14/2021 P 4 8/14/2025 Yes S129-S2 212-006 WINJ 6/26/2021 P 4 6/26/2025 Yes S132-W2 213-013 WIND 4/30/2021 P 4 4/30/2025 Yes S134-W6 215-016 WINJ 5/16/2021 P 2 (AA) 4/16/2023 Yes S135-W4 213-101 WINJ 4/30/2021 P 4 4/30/2025 Yes S143-NE3 222-115 1 WINJ 1/1/2023 P 4 1/1/2027 Yes Eni Petroleum —Alaska Development Page 16 ATTACHMENT G NSBOP Polymer Project Location Map 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 m a Federal m m 0 m State p SP - E4 S E3\ N m SP E2 �\ WUT.4160'SS S - El SP -FN Q SI -FN SP -FN SI -FN \ SP -FN \ I -FN1 SP40-E4 � m SP21-NWf SON . £2'FNi SP41 E P0 SP28-NW3 SI15{ S 08-N S114.N6 m P SP18-N S120-N4 SP23-N3 SP30•W SQS•N2 snawi \ SP27-Nf m g�gSP33-W3 SP36-WS-W4 SO4.WS SPY I61 d f 7 OP09 51 \ SP31.W 2-sl 6 04SE5 \ P74S3 7SE4 ' 0115-S4 01134. - 12-SE OP104 75E2 OPOS46 o m o OPO4-0 Z4SEOID"5 \` 007.0 ,-0\� �� 9-52 OPO7-Pas OP18B8 ` \^ 0 POa OP78- 4111-01 OQ0S7 Producer Malnbore ♦♦ a ♦ ♦♦♦ - - Producer Ll 1. Injector Oliktok Point I 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 Nikaitchuk Development Late &9-1we 0 2000 4000 6000 6000RUS 02/062023 Alaska Dev, Team 1:25000 Eni Petroleum —Alaska Development Page 17