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Home My WebLink About2019 Schrader Bluff Oil Pool Annual Reservoir Surveillance Report Schrader Bluff Oil Pool Nikaitchuq Field May 15th, 2020 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 ........................................ 5 3.0 Pool Allocation Factor Year 2019 .........................................................................................11 4.0 Reservoir Surveillance and Management Summary ..............................................................12 4.1 2019 NSBOP Voidage Balance by Month ..........................................................................17 5.0 NSBOP Injection Well Mechanical Integrity Testing ...............................................................18 ATTACHMENT A NSBOP Pressure Report, Form 10-412 ...............................................................19 ATTACHMENT B NSBOP Annual Reservoir Properties Report, Form 10-428 ...................................20 Eni Petroleum – Alaska Development Page 1 1.0 Progress of the Enhanced Recovery Project In 2019, Eni reactivated the drilling and completion of the Nikaitchuq Schrader Bluff Oil Pool (NSBOP) development well plan from the Spy Island Drill Site (SID) with the addition of production well, SP03-NE2, and three dual lateral wellbores, SP33-W3 L1, SP30-W1 L1, SP03-NE2 L1. Eni also conducted twelve well interventions and rig workovers (RWO) at SID and Oliktok Point Pad Drill Site (OPP) on eleven wells as summarized in Table 1 below. Table 1. 2019 Nikaitchuq Field Drilling and Well Intervention Activity The SP03-NE2 drilling scope of operations included drilling a pilot-hole, SP03-NE2 PH, to the northwest with the objective to refine the structural interpretation in order to evaluate the potential for additional development. The pilot-hole results were positive, with the structure coming in higher than previously mapped. As a result, current conceptual development plans target six additional wells for the area. The Nikaitchuq Development Pattern, Figure 1 below, shows the completed and planned development wells in the NSBOP OA sand through December 2019. WELL NAME WELL TYPE DRILL SITE ACTIVITY DESCRIPTION COMPLETION DATE OP08-07 Oil Producer Olitok Point RWO Tubing Hole 3/21/2019 SP18-N5 Oil Producer Spy Island E-line Tubing Patch Tubing Hole 4/2/2019 OP16-03 Oil Producer Olitok Point RWO Corrosion / Electrical failure 4/3/2019 SP36-W5 Oil Producer Spy Island RWO Electrical failure 4/26/2019 OP04-07 Oil Producer Olitok Point RWO Casing erosion 5/5/2019 SP12-SE3 Oil Producer Spy Island RWO Sand Issue 5/12/2019 OP10-09 Oil Producer Olitok Point RWO Tubing Hole 5/16/2019 OP17-02 Oil Producer Olitok Point RWO Tubing Hole 5/24/2019 OP03-05 Oil Producer Olitok Point ESP Restarted Shut-in since Jan. 2018 5/29/2019 SP33-W3 L1 Oil Producer Spy Island New Dual Lateral 6/20/2019 SP30-W1 L1 Oil Producer Spy Island New Dual Lateral 7/20/2019 SP24-SE1 Oil Producer Spy Island RWO Tubing Hole 8/7/2019 SP03-NE2 Oil Producer Spy Island New Producer 10/9/2019 SP03-NE2 L1 Oil Producer Spy Island New Dual Lateral 10/31/2019 SP12-SE3 Oil Producer Spy Island RWO Electrical failure 11/10/2019 SD37-DSP01 Disposal Spy Island RWO Tubing issue 11/20/2019 Eni Petroleum – Alaska Development Page 2 SI11-FN6 SI13-FN4 SI14-N6 SI17-SE2 SI19-FN2 SI20-N4 SI25-N2 SI26-NW2 SI29-S2 SI32-W2 SI34-W6 SI35-W4 SP05-FN7 SP08-N7 SP10-FN5 SP12-SE3 SP16-FN3 SP18-N5 SP21-NW1 SP22-FN1 SP23-N3 SP24-SE1 SP27-N1 SP30-W1 SP31-W7 SP33-W3 SP36-W5 OI06-05 OI07-04 OI11-01 OI13-03 OI15-S4 OI20-07 SI07-SE4 OI24-08 OP-I2 OP03-P05 OP04-07 OP05-06 OP08-04 OP10-09 OP12-01 OP14-S3 OP16-03 OP17-02 OP18-08 OP19-T1N OP09-S1 SP04-SE5 SP01-SE7 SP28-NW3 SP03-NE2 SP03-NE2 PH SI02-SE6 (p5) SI06-NE1 (P5) 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 488000 492000 496000 500000 504000 508000 512000 516000 520000 5240006028000603200060360006040000604400060480006052000605600060600006064000606800060720006076000 6028000603200060360006040000604400060480006052000605600060600006064000606800060720006076000Nikaitchuq Development Pattern Nikaitchuk Development Date 04/27/2020 Signature Alaska Dev. Team 0 2000 4000 6000 8000ftUS 1:25000 -4300 -4200 -4100 -4000 -3900 -3800 -3700 -3600 -3500 -3400 -3300 -3200 -3100 Elevation depth [ft] Spy Island Federal State Oliktok Point Figure 1: Nikaitchuq Development Map. Green = Producer, Blue = Injector, Yellow = Dual lateral producer, Purple = N Sand Appraisal well, dashed lines (- - - -) planned development wellbores. Eni Petroleum – Alaska Development Page 3 The total well count at the end of 2019 was 57 wells excluding the dual lateral wellbores. Table 2, below, provides a summary of the development well count. Activity up to date (Dec, 2019) Wells to be drill OPP SID Total OPP SID Total Project Well Type Injector 8/8 13/15 21/23 0 2 23 Producer 11/11 19/19 30/30 0 0 30 Disposal 1/1 1/1 2/2 0 0 2 Water Source 3/3 0 3/3 0 0 3 Total 23/23 34/35 56/58 0 2 58 Dual Lateral Well Paths 8 13 21 0 6 27 OPP = Oliktok Point Pad Drill Site (onshore) SID = Spy Island Development Drill Site (offshore) Table 2: Total Well Count for Nikaitchuq Development thru 2019 The NSBOP utilizes water injection to enhance recovery and maintain reservoir pressure. Production well artificial lift employs electrical submersible pumps (ESPs) which are susceptible to various failure mechanisms as summarized in Table 1 above. However, through additional drilling, well interventions, and consistent injection NSBOP oil production is performing very well as shown in Figure 2, below. The observed field oil production and water cut are in line with Eni’s reservoir model expectations. Annual average daily NSBOP production during 2019 was 18,556 BOPD. Total oil production from the NSBOP during 2019 was 6,772,787 barrels and is 56,026,544 barrels since field start-up thru 2019. The aforementioned well activities conducted in 2019 contributed approximately 2.26 MMBO or 6,200 BOPD to NSBOP gross production during the year. The annual average producing GOR and watercut were 111 SCF/STBO and 66%, respectively. Annual average daily NSBOP injection during 2019 was 57,771 BWPD. Cumulative water injection in the NSBOP during 2019 was 21,086,416 barrels and 99,903,392 barrels since the start of the project. Eni Petroleum – Alaska Development Page 4 Figure 2: Nikaitchuq Field Production and Events Summary 2017-2019 (upper section: workover events in yellow, new production wells in red) Eni Petroleum – Alaska Development Page 5 2.0 Results and Analysis of Reservoir Pressure Surveys within the Pool Twenty shut-in or initial pressure surveys recorded between December 2018 and March 2020 are reported from 19 wells in Attachment A, NSBOP Pressure Report, Form 10-412. The estimated average NSBOP reservoir pressure is currently 1,600 psi at -3,760 feet TVDSS (refer to Attachment B, NSBOP Annual Reservoir Properties Report, Form 10-428). NSBOP 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, pump intake pressures (PIP), which allow real-time bottom- hole pressure (BHP) monitoring. For producing wells, the continuous reservoir pressure data is monitored as shown in Figures 2a and 2b, below, for OPP and SID, respectively. The plots illustrate how the pump intake pressures (PIP) are gradually reduced to maximize production while also monitoring for signs of sand production, rising water cuts (WC), increasing gas-oil ratios (GOR) and balancing voidage across all sectors in the field. Additionally, during extended shut-ins the BHP data also provides valuable surveillance and model input. For the OPP active wells the PIPs have been stable in 2019, ranging from 300 psi to 800 psi, with the exceptions due to failed ESPs/tubing leaks in the wells before being worked over or restarted (See Figure 2a). An example is well OP03, which had been shut-in since January 2018 due to a failed ESP, was successfully restarted in May 2019. The PIPs for producing SID wells have ranged between 300 psi to 1200 psi. Well SP12-SE3 had multiple shut-ins and was worked over twice in 2019. (See Figure 2b) Monthly and cumulative voidage replacement ratios (VRRs) are monitored along with pattern area pressures to optimize flood performance and recovery (refer to Section 4.1 2019 NSBOP Voidage Balance by Month, below, for details). Maps of dynamic pressures, refer to Figure 3, are used for monitoring performance, reservoir management and modeling. In December 2019 the datum referenced average NSBOP producing well PIP was 640 psi, the average injection well bottomhole pressure was 2,030 psi, and areas outside the influence of the development are at the initial pressure of 1,700 psi. The estimated average December 2019 NSBOP reservoir pressure was 1,600 psi. Eni Petroleum – Alaska Development Page 6 Figure 2a: Intake BHP measurements during year 2019 for active wells at OPP Eni Petroleum – Alaska Development Page 7 Figure 2b: Intake BHP measurements during year 2019 for active wells at SID NSBOP injection targets a cumulative VRR of 1.0 while also avoiding fracturing the reservoir and potentially causing a by-pass breakthrough event. Maximum injection wellhead pressure limits are set based on an individual well reservoir depths and a gradient of 0.60 psi/ft to preserve well formation integrity; pressures are continuously monitored and adjusted, if necessary (Figures 2c and 2d). Downhole gauges are installed and functional in six injection wells: OP-I2 (temporary installation for polymer test, from Sep 2019), OI06-05, OI07-04, OI11-01, SI14-N6 and SI20-N4 to assist in monitoring and calibration. Eni Petroleum – Alaska Development Page 8 Figure 2c: Tubing head pressure (THP) measurements during 2019 for injectors at OPP OPP Injection Well Tubing Head Pressure Trends for 2019 Eni Petroleum – Alaska Development Page 9 Figure 2d: Tubing Head Pressure (THP) measurements during 2019 for injectors at SID OPP Injection Well Tubing Head Pressure (THP) Trends for 2019 Eni Petroleum – Alaska Development Page 10 SI11-FN6 SI13-FN4 SI14-N6 SI17-SE2 SI19-FN2 SI20-N4 SI25-N2 SI26-NW2 SI29-S2 SI32-W2 SI34-W6 SI35-W4 SP05-FN7 SP08-N7 SP10-FN5 SP12-SE3 SP16-FN3 SP18-N5 SP21-NW1 SP22-FN1 SP23-N3 SP24-SE1 SP27-N1 SP30-W1 SP31-W7 SP33-W3 SP36-W5 OI06-05 OI07-04 OI11-01 OI13-03 OI15-S4 OI20-07 OI24-08 OP03-P05 OP04-07 OP05-06 OP08-04 OP10-09 OP12-01 OP14-S3 OP16-03 OP17-02 OP18-08 SI07-SE4 OP09-S1 OP-I2 SP04-SE5 SP01-SE7 SP28-NW3 SI06-NE1 SP03-NE2 1500 1500 1500 1500 1500 2048 2048 2048 2048 2048 2144 2144 2144 2144 2144 2068 2068 2068 2068 2068 1821 1821 1821 1821 2147 2147 2147 2147 2147 2126 2126 2126 2126 2126 1881 1881 1881 1881 2132 2132 2132 2070 2070 2070 2070 2070 2091 2091 2091 2091 2091 2091 2054 2054 2054 2054 2054 21012101 2101 2101 2101 2101 2036 2036 2036 2036 2036 571 571 571 571 571 724 724 724 724 724 504 504 504 504 504 557 557 557 557 557 727 727 727 727 783 783 783 783 783 1307 1307 1307 1307 1307 455 455 455 455 455 762 762 762 762505 505 505 505 505 489 489 489 489 489 489 597 597 597 597 472 472 472 472 472 472 854 854 854 854 537 537 537 537 537 550 550 550 550 550 545545 545 545 545 585 585 585 585 585 1083 1083 1083 1083 1083 2117 2117 2117 2117 2117 2028 2028 2028 2028 2003 2003 2003 2084 2084 2084 2084 2084 1984 1984 1984 1984 1984 2012 2012 2012 2012 2086 2086 2086 2086 2086 2086 2080 2080 2080 2080 908 908 908 908 474 474 877 877 877 877 877 574 574 574 574 411 411 411 411 411 492 492 492 492 492 662 662 662 662 430 430 430 430 430 430 430 607 607 607 607 607 590 590 590 590 590 590 538 538 538 538 488000 492000 496000 500000 504000 508000 512000 516000 520000 524000 488000 492000 496000 500000 504000 508000 512000 516000 520000 5240006036000604000060440006048000605200060560006060000606400060680006072000 60360006040000604400060480006052000605600060600006064000606800060720000 2000 4000 6000 8000ftUS 1:25000 Nikaitchuq Average Pressure Dec 2019 Nikaitchuk Development Date 03/30/2020 Signature Alaska Dev. Team 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 Elevation depth [ft] Datum: -3,760' TVDss Figure 3: NSBOP Reservoir Pressure Map – December 2019 Eni Petroleum – Alaska Development Page 11 3.0 Pool Allocation Factor Year 2019 Production from all wells producing from the Schrader Bluff pool is commingled at the surface into a common production line. Theoretical production for individual wells from the pool is calculated on a daily basis by using well test allocation. Wells are tested, at least twice per month for a minimum of 24 times per year per well. For the year 2019, 878 well tests were performed. Measurements were performed on a multiphase meter. 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. For example, if there is a valid well test on the first of the month and another on the fifth of the month, the allocation factor for that well would be calculated on the first through the fourth of the month using the first of the month test results. Subsequently, the allocation factor will be recalculated on the fifth of the month using the new valid test measured on the fifth. Looking at the monthly level data, our AVOCET Manager Production software sums up the allocated volumes from each time period between valid well tests. (Minutes on production/1440 minutes/day)*Daily Rate (stb/d) well test=Theoretical Daily Production) The daily allocation factor for the field is calculated by dividing the actual total production for the day by the sum of the theoretical daily production for each individual well. Subsequently, daily allocated production is assigned to each well by multiplying its theoretical daily production by the daily allocation factor. The average allocation factor for 2019 has been 1.1255 Month Daily Alloc Factor January 1.1887 February 1.1568 March 1.1520 April 1.1940 May 1.1796 June 1.1638 July 1.1969 August 1.1887 September 1.1381 October 1.0092 November 0.9465 December 0.9912 Figure 4: Average field allocation factor trend for 2019 Eni Petroleum – Alaska Development Page 12 4.0 Reservoir Surveillance and Management Summary The NSBOP utilizes waterfloood for enhanced oil recovery consistent with Area Injection Order No. 36 (AIO). Horizontal producers and injectors have been drilled in pairs currently targeting the OA sands. Producer and injector targets are defined based on pattern waterflood response, pressure trends, ESPs constraints and well integrity limits. Individual well, pattern and field performance are routinely reviewed and discussed with the integrated Eni development team in Anchorage, Houston and Milan. Pump intake targets and injection well rate targets and pressure limits are defined and communicated to the lead field operators along with guidelines to handle changes. The minimum pump intake pressure targets 500 psi at the sandface but is often higher due to pump capacity limits, gas locking at low pressures, sand production or other performance concerns. The maximum injection pressure limit for all wells targets staying below the formation fracture pressure and is monitored by surface wellhead pressures; occasionally, other, lower injection limits are implemented. Reservoir surveillance is conducted to monitor well and reservoir performance and to recommend changes in operating conditions, perform rate allocations, propose optimization actions and address and solve general issues. Production allocations have been performed continuously using well models that are calibrated with the most recent well tests. In 2019 reservoir surveillance and monitoring activities for the NSBOP included:  Downhole and wellhead pressure and temperature real time measurements,  ESP main performance parameter monitoring (e.g. current, voltage, motor temperature),  Distributed Temperature Systems (fiber optics) monitoring lateral conformance (fiber optics),  Corrosion monitoring,  Hydrocarbon and produced water surface sampling,  Tracer sampling and interpretation,  Well production tests,  Polymer injectivity testing, and  Planning and designing a test of the N sand in OP19 using a jet pump for lift. Eight injector wells: four in Spy Island (SI11-FN6, SI19-FN2, SI13-FN4, SI25-N2) and four in Oliktok Point (OI11-01, OP-I2, OI13-03, OI24-08) have been treated with unique Tracerco tracers in 2015 in order to evaluate the water flow patterns, the breakthrough time and the sweep efficiency of the water injection. The tracer data showed a clear and consistent tracer arrival in the well producers. However, in three producers, SP05-FN7, SP27-N1 and SP10-FN5, the tracer arrival time was very small compared to other areas in the field; no geological features (faults, fractures) have been identified to justify the behavior. In August 2018, tracer was injected in OI15-S4 to evaluate a suspect case of matrix bypass event occurring with the neighboring producers OP10- 09, OP14-S3 and OP08-04. One sample per day was collected for each well for four weeks. The analyses indicated no tracers were detected from any of the samples, showing no sign of direct communication. Eni Petroleum – Alaska Development Page 13 Resman oil and water tracers were installed in SP03-NE2 after dual lateral completion on November 2019. A restart profile is planned to be conducted in 2020. Resman tracer system pairs (oil and water tracers) were previously deployed in two OPP producers (OP17-02 & OP05- 06) and six Spy Island producers (SID) (SP10-FN5, SP16-FN3, SP21-NW1, SP31-W7, SP33-W3, SP36-W5), to help assess oil flow distribution along the wellbores and determine locations of water production. However, only two of those wells SP21-NW1 and SP31-W7 retain useful tracer life. Initially three OPP injectors (OI06-05, OI07-04 & OI11-01) and two SID injectors (SI14-N6 & SI20- N4) were equipped with DTS fiber optics, to determine the level of injectivity along the horizontal injection intervals. The DTS on the OI11-01 & OI06-05 were taken out of commission. Figure 5 below, shows the Nikaitchuq field map with Resman, Tracerco tracers and the wells injector with DTS fiber optic. Refer to Figure 5 below. Eni Petroleum – Alaska Development Page 14 Figure 5: Nikaitchuq map showing wells with Resman, Tracerco tracers and DTS Fiber systems Eni Petroleum – Alaska Development Page 15 Eni is currently performing an EOR pilot project focused on the use of polymer injection to enhance overall recovery of the field. The first phase of the activity was carried out in Milan headquarters and ended in 2017 with final selection of the polymer for the test. The field application, which is in progress, is planned in three phases as follows:  Phase 1: Short-term Injectivity test (completed in May 2019),  Phase 2: One year pilot injection test (initiated in late 2019, shutdown due to COVID19), and  Phase 3: Full-Field Application (dependent on Phase 2 results and further review) The first phase focused on assessing the feasibility of the activity by monitoring injection well performance during polymer injection. For this stage, a 60 day injectivity test was performed in the southern part of the field (refer to Figure 6 below), with four wells each tested for two weeks with continuous polymer injection (March 26, 2019 and ended on Friday, May 24, 2019). The wells tested were OI06-05, OI07-04, OP-I2 and OI24. Figure 6: NSBOP location map of wells selected for injectivity test around OPP well path Eni Petroleum – Alaska Development Page 16 For each well a range of viscosities were tested, resulting in no detrimental impact seen on any of the wells. All downhole pressures limits were honored. The primary conclusion of the Phase 1 test is that the polymer selected for this study can be safely and effectively injected into the Nikaitchuq reservoir. This conclusion clears the way for a long-term polymer injection pilot that will evaluate the benefit of polymer injection on reservoir production. For Phase 2, the OP-I2 injection well, already tested in Phase 1, has been selected as the long term pilot test candidate well. The planned duration of the test is 12 months. Targets for polymer injection rates, and concentrations were determined from a simulation study conducted by the Eni Milan EOR team. The pilot was initiated on October 22, 2019 with injection of tracers early in the test phase with continuous sampling of offset production wells planned at least through 2020. A downhole gauge was run in OP-I2 and periodic falloffs are conducted to assist in modeling the performance. Unfortunately, due to the COVID-19 pandemic operational disruption the polymer injection pilot was shutdown on March 23, 2020. Water injection continues along with bi-monthly offset producing well sampling for tracer studies. Current plans are to restart Phase 2 in 2021. Then, depending on the outcome of Phase 2, a full field polymer injection multidisciplinary feasibility study will be carried out, in order to evaluate the full field application and the required surface modifications to the existing facility network. To further enhance SID NSBOP production and provide operational flexibility a multi-phase pump (MPP) system was installed and commissioned at SID in late 2019. The three phase pump reduces the SID flowline back pressure to 100 psi providing additional drawdown capacity for wells with ESPs at maximum speeds. Eni Petroleum – Alaska Development Page 17 4.1 2019 NSBOP Voidage Balance by Month For the year 2019, the NSBOP management activities have successfully supported the objective to replenish reservoir energy by replacing the voidage created with water injection and optimizing the field production performance through workover activities. During 2019, NSBOP produced approximately 6.8 million barrels of oil at an average daily rate of 18,556 BOPD. Injected volumes of water during this time were 21 million barrels at an average daily rate of 57,771 BWPD. The 2019 annual average voidage replacement ratio (VRR) was 1.04. Table 5 below summarizes the 2019 voidage replacement for the NSBOP. Table 5: 2019 Nikaitchuq Field Monthly Production/Injection Volumes and Voidage Replacement Ratio Graph Injection Monthly Oil Water Gas Water VRR BBL BBL MCF BBL BBL Jan-19 569,618 977,975 72,294 1,693,251 1.05 Feb-19 482,838 822,543 56,311 1,577,496 1.17 Mar-19 512,343 878,369 56,316 1,642,598 1.15 Apr-19 506,318 966,049 54,826 1,591,814 1.05 May-19 515,832 1,044,222 56,933 1,564,492 0.98 Jun-19 581,810 1,148,490 63,236 1,733,011 0.98 Jul-19 625,423 1,198,108 64,845 1,879,252 1.01 Aug-19 546,004 1,043,785 58,789 1,684,052 1.03 Sep-19 619,550 1,281,345 68,510 1,865,926 0.96 Oct-19 618,322 1,178,701 70,643 2,012,930 1.09 Nov-19 557,258 1,143,459 61,138 1,878,297 1.08 Dec-19 637,469 1,236,946 69,531 1,963,297 1.02 Total 6,772,785 12,919,992 753,372 21,086,416 1.04 Production 0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 Eni Petroleum – Alaska Development Page 18 5.0 NSBOP Injection Well Mechanical Integrity Testing Pursuant Area Injection Order No. 36 Rule 8, Table 6 provides a summary of the mechanical integrity testing results and plans for the NSBOP injection wells. Table 6: NSBOP Injection Well MIT Results and Plans Well PTD # Status Date of Last Test Result Frequency (Years) Due Date Injecting since MIT due date? OP-I2 206-144 WINJ 12/06/16 P 4 12/05/20 Yes OI6-05 210-165 WINJ 12/06/16 P 4 12/05/20 Yes OI7-04 210-153 WINJ 12/06/16 P 4 12/05/20 Yes OI11-01 210-106 WINJ 12/06/16 P 4 12/05/20 Yes OI13-03 211-100 WINJ 12/06/16 P 4 12/05/20 Yes OI15-S4 211-141 WINJ 12/06/16 P 4 12/05/20 Yes OI20-07 211-140 WINJ 12/06/16 P 4 12/05/20 Yes OI24-08 211-130 WINJ 12/06/16 P 4 12/05/20 Yes SI06-NE1 219-165 WINJ 02/27/20 P 4 02/26/24 Yes SI07-SE4 214-100 WINJ 12/10/16 P 4 12/09/20 Yes SI11-FN6 213-128 WINJ 12/10/16 P 4 12/09/20 Yes SI13-FN4 212-156 WINJ 12/10/16 P 4 12/09/20 Yes SI14-N6 213-194 WINJ 12/10/16 P 4 12/09/20 Yes SI17-SE2 214-041 WINJ 12/10/16 P 4 12/09/20 Yes SI19-FN2 213-043 WINJ 12/10/16 P 4 12/09/20 Yes SI20-N4 212-029 WINJ 12/10/16 P 4 12/09/20 Yes SI25-N2 212-090 WINJ 12/10/16 P 4 12/09/20 Yes SI26-NW2 214-157 WINJ 12/10/16 P 4 12/09/20 Yes SI29-S2 212-006 WINJ 12/10/16 P 4 12/09/20 Yes SI32-W2 213-013 WINJ 12/10/16 P 4 12/09/20 Yes SI34-W6 215-016 WINJ 09/27/17 P 4 09/26/21 Yes SI35-W4 213-101 WINJ 09/27/17 P 4 09/26/21 Yes Eni Petroleum – Alaska Development Page 19 ATTACHMENT A NSBOP Pressure Report, Form 10-412 6. Oil Gravity: 13-19 8. Well Name and Number: 9. API Number 50XXXXXXXXXXXX NO DASHES 10. Type See Instructions 11. AOGCC Pool Code 12. Zone 13. Perforated Interval Top 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) OI07-04 50029234350000 WI 561100 Schrader Bluff 3,624 3/20/2019 320 PFO 105 3,595 1,635 3,760 0.44 1,708 OP03-P05 50029233960000 O 561100 Schrader Bluff 3,633 5/24/2019 11,687 SBHP 70 3,454 1,657 3,760 0.44 1,792 OP04-07 50029234090000 O 561100 Schrader Bluff 3,785 5/4/2019 1,951 SBHP 74 3,524 1,635 3,760 0.51 1,757 OP08-04 50029234240000 O 561100 Schrader Bluff 3,473 3/21/2019 2,217 SBHP 67 3,349 1,424 3,760 0.47 1,616 OP10-09 50029234390000 O 561100 Schrader Bluff 3,625 5/18/2019 615 SBHP 64 3,528 1,029 3,760 0.48 1,141 OP16-03 50029234420000 O 561100 Schrader Bluff 3,187 4/4/2019 1,293 SBHP 67 3,202 1,083 3,760 0.48 1,353 OP17-02 50029234310000 O 561100 Schrader Bluff 3,504 5/26/2019 797 SBHP 72 3,466 1,060 3,760 0.47 1,198 SI06-NE1 50629236580000 WI 561100 Schrader Bluff 3,934 3/13/2020 Initial PFO 83 3,925 1,500 3,760 0.44 1,427 SP03-NE2 50629236390000 O 561100 Schrader Bluff 4,089 12/5/2019 Initial SBHP 87 4,026 1,651 3,760 0.48 1,524 SP05-FN7 50629234810000 O 561100 Schrader Bluff 3,943 12/30/2018 12,112 SBHP 75 3,614 1,587 3,760 0.50 1,660 SP08-N7 50629235010000 O 561100 Schrader Bluff 3,967 12/29/2018 2,710 SBHP 74 3,898 1,446 3,760 0.48 1,379 SP10-FN5 50629234730000 O 561100 Schrader Bluff 3,878 12/27/2018 1,382 PBU 80 3,679 1,433 3,760 0.41 1,466 SP12-SE3 50629235130000 O 561100 Schrader Bluff 3,943 5/18/2019 17,130 PBU 75 3,761 1,895 3,760 0.55 1,895 SP12-SE3 50629235130000 O 561100 Schrader Bluff 3,943 11/28/2019 1,493 PBU 76 3,761 1,832 3,760 0.55 1,832 SP18-N5 50629234530000 O 561100 Schrader Bluff 3,945 4/2/2019 3,687 PBU 82 3,929 1,910 3,760 0.41 1,840 SP21-NW1 50629235200000 O 561100 Schrader Bluff 3,441 12/29/2018 3,524 SBHP 65 3,278 1,158 3,760 0.48 1,391 SP24-SE1 50629235100000 O 561100 Schrader Bluff 3,850 8/7/2019 959 SBHP 78 3,738 673 3,760 0.47 683 SP30-W1 50629234760000 O 561100 Schrader Bluff 3,630 7/21/2019 733 SBHP 78 3,543 1,574 3,760 0.47 1,676 SP33-W3 50629534680000 O 561100 Schrader Bluff 3,572 6/21/2019 1,000 SBHP 77 3,494 1,603 3,760 0.47 1,727 SP36-W5 50629234920000 O 561100 Schrader Bluff 3,412 4/27/2019 604 SBHP 69 3,153 1,321 3,760 0.51 1,630 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. Production Engineer May 15, 2020 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 NIKAITCHUQ NIKAITCHUQ-SCHRADER BLUFF OIL 3760 0.6 3. Unit or Lease Name: 4. Field and Pool: 5. Datum Reference: Eni Petroleum – Alaska Development Page 20 ATTACHMENT B NSBOP 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) 561100 Schrader Bluff 3760 70 -90 15 -35 50 - 1000 13 - 45 90 - 200 70 - 180 1700 600-1200 1600 13 -19 0.6 30 - 40 25 - 40 1.045 1.05 0.7 - 0.8 80 - 140 111 Production Engineer STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT 1. Operator: 2. Address: I hereby certify that the foregoing is true and correct to the best of my knowledge. Signature Eni Petroleum 3800 Centerpoint Drive , Suite 300. Anchorage, Alaska 99503 Printed Name Title Date 15-May-20Keith Lopez