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Home My WebLink About2018 Prudhoe Oil and Put River Oil Pools ANNUAL RESERVOIR SURVEILLANCE REPORT WATER AND MISCIBLE GAS FLOODS PRUDHOE OIL POOL AND PUT RIVER OIL POOL & ANNUAL RESERVOIR PROPERTIES REPORT PRUDHOE AND PUT RIVER OIL POOLS JANUARY THROUGH DECEMBER 2018 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 2 CONTENTS SECTION PAGE 1.0 INTRODUCTION 4 2.0 OVERVIEW 5 3.0 PRESSURE UPDATE 7 3.1 Pressure Monitoring 7 3.2 Pressure Plan 7 4.0 PROJECT SUMMARIES 8 4.1 Flow Station Two Water / MI Flood Project 8 4.2 Eastern Peripheral Wedge Zone Water / MI Project 9 4.3 Western Peripheral Wedge Zone Water / MI Project 10 4.4 Northwest Fault Block Water / MI Project 11 4.5 Eileen West End Waterflood Project 12 4.6 Gas Cap Water Injection Project 13 4.6.1 Observation Well RST Surveys and Zonal Conformance 13 4.6.2 2019 Surveillance Plans 14 4.6.3 Plans for Change in Project Operation 14 4.7 Put River Pool 15 5.0 GAS MOVEMENT SURVEILLANCE 17 5.1 Gas Movement Summary 17 6.0 REVIEW OF POOL PRODUCTION ALLOCATION FACTORS 18 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 3 LIST OF EXHIBITS 1-A Prudhoe Bay Unit Field Schematic 1-B PBU Well Statistics 1-C PBU Production / Injection Statistics 1-D PBU Pressure Map 1-E Areally Weighted Average Pressure Plot 1-F Areally Weighted Pressure Data 1-G Average Monthly CGF MI Rates and Compositions 2 Fieldwide Reservoir Balance 3-A FS-2 Base Flood Map 3-B FS-2 Reservoir Balance 3-C FS-2 Areal Average Reservoir Pressure 3-D FS-2 Daily Average RMI 4-A EPWZ Base Flood Map 4-B EPWZ Reservoir Balance 4-C EPWZ Areal Average Reservoir Pressure 4-D EPWZ Daily Average RMI 5-A WPWZ Water / MI Flood Base Map 5-B WPWZ Reservoir Balance 5-C WPWZ Areal Average Reservoir Pressure 5-D WPWZ Daily Average RMI 6-A NWFB Base Flood Map 6-B NWFB Reservoir Balance 6-C NWFB Areal Average Reservoir Pressure 6-D NWFB Daily Average RMI 7-A EWE Base Flood Map 7-B EWE Reservoir Balance 7-C EWE Areal Average Reservoir Pressure 7-D EWE Daily Average RMI 8 Wells Surveyed for Gas Movement 9 Pressure Surveys (Form 10-412) 10-A GCWI Surveillance and Extent 2018 10-B GCWI 2018 Extent: Southwest – Northeast Section 10-C GCWI 2018 Extent: North – South Cross Section 11-A Annual Reservoir Properties Report-Prudhoe and Put River Oil Pools (AK 20 AAC 25.270) 12 Put River Sandstone Distribution 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 4 1.0 INTRODUCTION As required by Conservation Order (CO) 341G and CO 559A, this report provides a consolidated waterflood and gas oil contact report summary of the surveillance activities for the Waterflood Project, Miscible Gas and Gas Cap injection projects, and the Gravity Drainage Area within the Prudhoe Oil Pool plus a section for the Put River Pool. The time period covered is January through December of 2018. In keeping with the requirements of the Conservation Orders, the report format provides information for each of the five major flood projects and the gravity drainage project in the field, where applicable, as follows: • Analysis of reservoir pressure surveys and trends • Progress of the enhanced recovery projects, including the gas cap water injection project • Voidage balance by month of produced and injected fluids • Data on Minimum Miscibility Pressure (MMP) of injected miscible gas • Summary of Returned Miscible Injectant (RMI) volumes • Results of gas movement and gas-oil contact surveillance efforts • Results of pressure monitoring efforts The Annual Reservoir Properties Report-Prudhoe and Put River Oil Pools is being submitted under cover of this report as Exhibit 11-1. (AK 20 AAC 25.270). The Excel version is also being submitted electronically to aogcc.reporting@alaska.gov. A report of completed development or service wells that have been shut-in for 365 days or longer as of January 1, 2019, will be separately filed with the Commission by March 31, 2019, in accordance with 20 AAC 25.115. Separate sections are provided for the five major flood areas: Flow Station 2 (FS-2), Eastern Peripheral Wedge Zone (EPWZ), Western Peripheral Wedge Zone (WPWZ), North West Fault Block (NWFB), and Eileen West End (EWE) along with information on the GCWI in the Gravity Drainage region and the Put River Oil Pool. Water and miscible gas floods are described in each section. A separate section has been provided with detailed information on gas-oil contact surveillance. As agreed in 2004 with the Commission, the discussion of Gas Production Mechanisms was not included in the report. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 5 2.0 OVERVIEW Exhibit 1A identifies the five flood areas and gravity drainage areas in the Prudhoe Oil Pool as follows: FS-2, EPWZ, WPWZ, NWFB, EWE, and GD. The Waterflood Project encompasses all five flood areas. The Prudhoe Bay Miscible Gas Project (PBMGP) is currently active throughout the waterflood areas. The Eileen West End waterflood pilot concluded in March 1999, after successfully establishing EWE injection potential. EWE information since waterflood startup in September 2001 is included in this report. Exhibits 1-B and 1-C provide well, production, and injection statistics for the major project areas included in this report. As in last year’s report, wells do not share project boundaries, but belong to a single project area. The well counts therefore reflect the total number of wells actually contributing to production and injection. Similar to last year, only wells that actually produced or injected during the year are included. During the report period of January through December 2018, field production averaged 174.2 MBOD, 7050.6 MMSCFD (GOR 40483 SCF/STB), and 892.6 MBWD (water-cut 83.67%). Overall Waterflood injection during this period averaged 1281 MBWD with 158.7 MMSCFD of miscible gas injection. Cumulative water injection in the five major projects from waterflood startup through December 2018 was 13301 MMSTB, while cumulative MI injection was 3318 BCF. Cumulative production in these same areas (not including Gravity Drainage) since waterflood startup was 3051 MMSTB oil, 14824 BCF gas, and 9674 MMSTB water. As of December 31, 2018, cumulative production exceeded injection by -10020 MMRB compared to -9113 MMRB at the end of 2017. Similar to last year, production and injection values have been calculated based upon the waterflood start- up dates for the project areas rather than for each injection pattern. Exhibit 1-D provides analysis of pressure static, buildup, and falloff data that was collected from 2016 through 2018 at a datum of 8,800 ft, subsea for the Ivishak Formation. Using the three-year rolling technique improves the statistical validity of the pressure distribution since it roughly triples the number of data points employed versus only using the current year static pressures. As in the past, abnormal pressures, such as pressures taken in fault compartments and in the Sag River Formation have been removed. As shown in Exhibit 1E, the historic pressure decline appears to have stabilized due to gas-cap water injection. For 2018, average pressure in the PBMGP project areas using three years of pressure static measurements was calculated to be 3,360 psia by areal weighting, as compared to 3345 psia in 2017 (Exhibit 1F). The GD area pressure was stable decreasing just 6 psi from 3292 psia in 2017 to 3286 psia in 2018. This subtle pressure decrease is within the expected statistical variation with a different annual pressure sampling data sets. Interpreted MI breakthrough has occurred in 78 wells during the reporting period. The previous year showed interpreted MI breakthrough in 101 wells, but with further evaluation probably included some wells that were reflecting naturally occurring rich gas. RMI production is an indicator of EOR pattern performance and the presence of RMI is best determined by primarily gas sample analyses that show a separator gas composition richer in intermediate range hydrocarbon components but also proximity to WAG injectors in known MI patterns. MI breakthrough in a WAG pattern well is considered to have occurred when the average RMI rate 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 6 over the number of producing days in a well exceeds 200 MCF/D. Exhibit 1-G shows that more MI was injected in 2018 than 2017. Relating to condition 5 of CO 547.004 (as amended by CO 547.006), during the reporting period there were two Gen 2 (VSRD) meters utilized in the Prudhoe Oil Pool, at L Pad and V Pad. Production from L and V Pads comes from the Prudhoe Pool (Ivishak Formation), Borealis Pool (Kuparuk), and Orion Pool (Schrader Bluff), and presents a wide range in fluid types and composition involving a challenge for metering. The Gen 2 (VSRD) meters at both pads, when calibrated by independent means such as the ASRC test separator, have had close matches with total fluids, and formation gas, but have struggled to match water cut. The Gen 2 meters at L and V Pads are known as VSRD meter kits, and are composed of four components: a Venturi meter, Sonar flow meter, Red-eye water cut meter, and gamma Densitometer. When one of the four components of the Gen 2 VSRD meter kits is non- operational, the others are also down. Maintenance of the Gen 2 VSRD is challenged because it requires specialized skills that are only available from the vendor. L pad has both a pad test separator and a Gen 2 VSRD metering kit. The pad test separator is thought to be more accurate for the one active Ivishak well and the one active Sag well on the pad, so allocations were typically done using the pad test separator well tests. At V pad the pad test separator was taken out of service in 2012. The Gen 2 VSRD metering kit is used to test and allocate the five active Ivishak producers. A calibration test was done in 2016 with a portable test separator. There was a wider error band than expected for the Ivishak wells. To mitigate the allocation uncertainty in 2018, a portable test separator was brought to V pad in March to test online wells. The results were used to improve production allocation. Well head temperatures and gas lift pressures were also monitored to identify changes in well performance. A study to determine if the Gen 2 VSRD meters can be better calibrated for Ivishak wells or if the pad test separator should be reinstated was completed. The decision was made to go back to well pad separators at L&V Pads, and to decommission the VSRD meters. The VSRD decommissioning work was completed in late 2018, while V and L pad separator upgrades were nearly completed by year end. Exhibit 2 provides monthly and annual fieldwide reservoir balance figures. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 7 3.0 PRESSURE UPDATE 3.1 Pressure Monitoring Exhibit 9 (Form 10-412) provides pressure, buildup, and falloff data collected in 2018 at a datum of 8,800 ft, subsea used for the Ivishak Formation. During 2018, per CO 341G, as modified by the Commission on July 20, 2016, use of calculated BHP’s from surface data in injectors are permitted. All of these new data are listed in Exhibit 9 as “FL”. Inclusion of the reasonable surface calculated data, based on consistency of the results, confirms an elevated pressure area in the Gas Cap associated with the GCWI project. For this report, as in the past, pressures taken in fault compartments, the Sag River Formation, and in Zone 1 of the G-Pad LPA (Low Pressure Area), which don’t appear to be in good communication with the rest of the reservoir, have been excluded from Exhibit 1-D. Also excluded were wells shut-in less than a week that had not stabilized as compared to offsetting statics. Other wells completed in Zone 1 and Zone 4B, which are in poor communication with the rest of the reservoir and therefore have lower pressures, were still included in the map and calculations if their shut-in times were deemed long enough. The excluded pressure measurements are listed separately in Exhibit 9. Unless otherwise noted, all pressure calculations are areally weighted, bound by the main field original 50' LOC contour, and are referenced to a pressure datum of 8,800' SS. It was agreed with the commission that the polygon pressures would be calculated differently starting with the 2005 than it had in past reports due to the advent of pressure response to gas-cap water injection. That methodology consisted of utilizing only the pressure gathered during the reporting period. Starting with the 2009 report, since the field pressure has stabilized, pressure points from a rolling three year period were used to construct the pressure map so as to reduce the statistical variation induced by changing year-to-year well sets. Exhibit 1-D illustrates the 2018 pressure map using 2016 through 2018 data points. 3.2 Pressure Plan Per CO 341G Rule 6a, the following pressure surveillance plan information is provided. Prudhoe Bay reservoir depletion strategies are defined, and the goal of the pressure program is to optimize areal coverage and provide sufficient data for well safety and reservoir management. The plan for 2019 calls for collection of a minimum of 40 pressure surveys fieldwide. In accordance with the rule (5% clause), a minimum of 2 pressure surveys will be collected in each of the seven development areas: Gas Cap, Gravity Drainage, Flow Station 2 Water/MI Flood (MWAG) Project, Eastern Peripheral Wedge Zone MWAG Project, Western Peripheral Wedge Zone MWAG Project, Eileen West End Waterflood Project, and the Northwest Fault Block MWAG Project. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 8 4.0 PROJECT SUMMARIES 4.1 Flow Station Two Water / MI Flood Project The Flow Station Two area (FS-2), which comprises the eastern third of the Eastern Operating Area, is shown in Exhibit 3-A. The locations of production and injection wells are shown with the EOR injection patterns identified. There were 100 producing wells and 58 injection wells that contributed to production/injection during 2018 within the FS-2 flood area. Production/injection data was calculated with the polygon boundaries as in last year’s report. The FS-2 waterflood area oil production averaged 28.1 MBOD for 2018 compared to 28.6 MBOD in 2017. Cumulative production since waterflood start-up through the end of 2018 is 1121 MMSTB of oil, 6701 BCF of gas, and 4851 MMSTB of water. Injection rates averaged 343.9 MBWD and 81.4 MMSCFD in 2018. Since 12/31/17, the waterflood imbalance has increased from a cumulative under injection of 3515 MMRB to 3747 MMRB under injected. During the report period, production exceeded injection by 232 MMRB. Under-injection is related to production of free gas influxing from the gravity drainage region which should not be replaced so as to maintain a steady declining gas contact. Waterflood strategy is to replace voidage on a zonal basis after accounting for the free gas influx. Cumulative water and MI injection since waterflood start-up, through the end of 2018, is 6962 MMSTB and 1132 BCF respectively. The flood area's GOR increased from an average of 26083 SCF/STB in 2017 (corrected number from 2017 ASR Report) to an average of 27990 SCF/STB in 2018. Gas influx continues along the FS-2/GD GDWFI area, and in the high permeability conglomerates in the Updip Victor area. Water-cut was 92%. A breakdown of the production and injection data is provided in Exhibit 3-B for the report period. See Exhibit 1-C for a comparison of the cumulative figures with last year’s AOGCC report. Exhibit 3-C presents the FS-2 areal average waterflood pressure change over time. The pressure in the FS-2 area was 3,396 psia in 2018. This is a decrease of 2 psi under the 2017 pressure. Exhibit 3-D is a presentation of 2018 average returned MI (RMI) rates. Miscible gas return has been confirmed in 28 wells by gas compositional analysis (RMI>200 MSCFD). 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 9 4.2 Eastern Peripheral Wedge Zone Water / MI Flood Project The Eastern Peripheral Wedge Zone (EPWZ) water and miscible gas (MI) flood area is shown in Exhibit 4-A. In 2018, oil production averaged 14.9 MBOD, as compared to 16.8 MBOD in 2017, with an average 93% water cut and 19531 SCF/STB Gas Oil Ratio. Injection averaged 159 MBWD and 0 MMSCFD of miscible injectant (MI). There is a total of 71 producers and 26 injectors in the flood area that contributed to production/injection during 2018. Of the 26 injectors, none injected miscible gas at some point throughout the year, all wells injected water only. Production and injection values have been calculated using polygon boundaries the same as last year’s report. Two waterflood start-up dates have been used, 12/30/82 for the DS13 flood and 8/20/84 for the down-dip sections, rather than the start-up dates of each injection pattern. A cumulative total of 664 MMSTB of oil, 3778 BSCF of gas, and 1963 MMSTB of water have been produced with 2418 MMSTB of water and 691 BSCF of miscible gas injected. Exhibit 4-B shows the monthly injected and produced volumes on a reservoir barrel basis during 2018 and provides cumulative volumes since injection began. During the report period, production exceeded injection by 107 MMRB. Exhibit 4-C shows the trend of reservoir pressure change in the EPWZ flood area with time. The area receives pressure support from pattern injection, some aquifer influx, and GCWI. Faulting and out of conformance injection can impair flood performance in some areas. Areas of low pressure are being addressed by flood management strategies designed to increase voidage replacement. The EPWZ pressure was 3,328 psia in 2018. This is an increase of 24 psi as compared to 2017. Exhibit 4-D shows the 2018 average of estimated RMI rates in producers, as calculated from well tests and from numerous produced gas sample analyses. Miscible gas returns have been confirmed in 6 wells (RMI >200 MSCFD). 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 10 4.3 Western Peripheral Wedge Zone Water / MI Flood Project Exhibit 5-A is a map of the Western Peripheral Wedge Zone (WPWZ) water and miscible gas (MI) flood areas. During the report period oil production averaged 14.7 MBOD compared with 16.3 MBOD in 2017, with a gas/oil ratio of 20704 SCF/STB and a watercut of 89%. Injection averaged 126 MBWD of water and 24.84 MMSCFD of miscible injectant. For the WPWZ project, 38 injectors (3 WAG injectors and 31 water injectors, 4 gas injectors), and 98 producers contributed to the production and injection during 2018. The well counts reflect only the active wells for the year. The waterflood startup date for the WPWZ project area was September 1985, corresponding to the start of injection in the Main Pattern Area (MPA). The production and injection data for the project reflect this startup date. Consistent with last year, production and injection data are calculated on the single area basis. Cumulative water injection from waterflood start-up through December 2017 was 1943 MMSTB while cumulative MI injection was 666 BSCF. Cumulative production since waterflood start-up is 556 MMSTB oil, 2445 BSCF gas, and 1531 MMSTB water. As of December 31, 2018 cumulative production exceeded injection by -1735 MMRB. Exhibit 5-B provides the monthly injection and production data from 01/18 through 12/18. During the report period, production exceeded injection by 92 MMRB. The reservoir balance in Exhibit 5-B doesn’t identify support from the aquifer, thereby understating voidage replacement nor does it capture the production of gas-cap-gas which needs not be replaced. During 2006 a produced water tie-line was installed connecting two GC-1 slug catchers to GC-3 produced water tanks. This allowed up-dip Zone 4 waterflood expansion and should allow ideal voidage replacement in the eastern half of the WPWZ area. Exhibit 5-C shows that the pressure in the WPWZ was 3,320 psia in 2018. This is an increase of 5 psi over the pressure reported in 2017. Exhibit 5-D indicates wells with MI breakthrough and the 12-month averaged returned MI rates. Miscible gas breakthrough has been confirmed in 22 wells by gas compositional analysis. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 11 4.4 Northwest Fault Block Water / MI Flood Project Exhibit 6-A is a map of the Northwest Fault Block (NWFB) water and miscible gas (MI) flood areas. During the report period, oil production averaged 9 MBOD, as compared to 9.2 MBOD in 2017, with a gas/oil ratio of 9521.4 SCF/STB and a watercut of 87%. Injection averaged 73.7 MBWD and 33.4 MMSCFD of miscible injectant. For the NWFB project, 29 injectors (2 WAG injectors, 22 water injectors, and 5 gas injector), and 58 producers contributed to the production and injection during 2018. The well counts reflect the number of wells actually contributing to production/injection during the reporting period. Production and injection values have been calculated based upon the start-up date for the project area, 8/13/84. Consistent with last year, production and injection data are calculated on the single area basis. Cumulative water injection from waterflood start-up in August 1984 through December 2018 was 1736 MMSTB while cumulative MI injection was 711 BCF as detailed in Exhibit 1-C. Cumulative production since waterflood start-up was 613 MMSTB oil, 1511 BSCF gas, and 1102 MMSTB water. As of December 31, 2018 cumulative production exceeded injection by 681 MMRB. Exhibit 6-B provides the monthly injection and production data from 01/18 through 12/18. During the report period, production exceeded injection by 16 MMRB. However, this does not include support obtained from aquifer influx or gas cap expansion. The areally weighted pressure in the NWFB area was 3,380 psia in 2018. This is an increase of 53 psi over last year. The historical pressure trend can be seen in exhibit 6-C. The increase in 2004 was largely due to the fact that these polygon’s boundaries were expanded to the northwest with the presence of aquifer area affecting the overall pressure of the northwest fault block Exhibit 6-D indicates wells with MI breakthrough and the 12-month average returned MI rates. Miscible gas breakthrough has been confirmed in 15 wells by gas compositional analysis. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 12 4.5 Eileen West End Waterflood Project Exhibit 7-A is a map of the Eileen West End (EWE) waterflood area and miscible gas (MI) flood area. During the report period, oil production averaged 8.7 MBOD, as compared to 12.8 MBOD in 2017, with a gas/oil ratio of 3998 SCF/STB and water cut of 83%. Injection averaged 49.9 MBWD and 14 MMSCFD of miscible gas injectant. For the EWE project, 18 injectors (4 WAG injectors, 12 water injectors. 2 gas injectors), and 67 producers contributed to the production and injection during 2018. The well counts reflect only the active wells for the year. Cumulative water injection from waterflood start-up in September 2001 through December 2018 was 242 MMSTB and cumulative MI injection was 118 BCF. Cumulative production since waterflood start-up was 97 MMSTB oil, 389 BCF gas, and 227 MMSTB water. As of December 31, 2018 cumulative production exceeded injection by 317 MMRB. Exhibit 7-B provides the monthly injection and production data from January 1, 2018 through December 31, 2018. During the report period, production exceeded injection by 6 MMRB. The averaged EWE pressure was 3,619 psia in 2018, representing a pressure increase of 2 psi from 2017. The historical pressure trend can be seen in exhibit 7-C. Exhibit 7-D indicates wells with MI breakthrough and the 12-month average returned MI rates. Miscible gas breakthrough has been confirmed in 6 wells by gas compositional analysis. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 13 4.6 Gas Cap Water Injection Project Details of the volume of water injected into the Gas Cap during 2018 are shown below; units in thousands of barrels of seawater injected per month (MBWPM): PSI-01 PSI-05 PSI-06 PSI-07 PSI-08 PSI-09 PSI-10 Total 1/1/2018 1,620 1,518 1,030 1,692 1,650 1,659 750 9,920 2/1/2018 1,559 1,362 995 1,676 1,503 1,427 720 9,243 3/1/2018 1,583 1,584 1,062 1,846 1,510 1,737 869 10,190 4/1/2018 1,500 1,433 998 1,806 1,582 1,579 948 9,846 5/1/2018 1,816 1,724 0 2,011 1,883 1,696 1,123 10,253 6/1/2018 1,912 1,759 0 1,904 1,612 1,696 1,094 9,978 7/1/2018 1,848 1,859 0 2,221 1,713 1,829 1,114 10,584 8/1/2018 908 939 0 1,044 883 854 822 5,450 9/1/2018 562 501 0 643 542 521 239 3,008 10/1/2018 1,404 1,496 0 1,444 1,387 1,389 922 8,043 11/1/2018 1,432 1,404 1,329 1,468 1,352 1,407 1,366 9,758 12/1/2018 1,953 1,903 1,273 1,943 651 376 561 8,660 The 2018 volume of sea water injected in the PSI wells was 104.9 million barrels. The cumulative volume injected at the end of 2018 was 2.6 billion barrels of sea water since the project startup in 2002. 4.6.1 Observation Casedhole Saturation Logs and Zonal Conformance Pulsed neutron logs (RPM, RMT, etc) run in offset producers continue to be the primary method of monitoring water movement from the Gas Cap Water Injection project. Many of these wells have had several repeat logs since injection began. By comparing the latest neutron logs with the baseline and previous logs, the presence of injected water can be readily observed. This procedure has provided a very clear picture of water in the Ivishak Formation and allows the monitoring of vertical and lateral movement of the waterfront. Exhibit 10-A is the locator map for the GCWI area and shows the PSI injectors along with the observation wells. The blue polygon indicates the interpreted current GCWI waterfront, which has very minimal change since 2017. Well 02-38A, south of the mid-field graben, started producing water in late 2017, and chemistry analysis suggests it is likely GCWI. It was this datapoint in 2017 that resulted in the slight extension of the polygon across the mid field graben. The information from the neutron logs was also used to develop the updated northwest-southeast and north-south cross sections (Exhibit 10-B) showing the interpretation of the surveillance data for the current time period. The most recent round of neutron log surveillance included the following wells: 05-02A, 11-23B, 11-27, 11-29, 11-35, 15-07D, 15-32C, 18-06B, 18-29C, L1-09, L1-13, L2-14C and L2-33. As the areal and vertical extent of the water mass becomes larger, the rate of incremental advancement both laterally and vertically has become noticeably slower. At this point, the changes in the waterfront have followed a relatively predictable pattern established in recent 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 14 surveillance, where the largest extent of incremental waterfront coverage appeared in Zone 2C, owing to significant lateral continuity of the 24N shale. Surveillance wells for 2018 saturation monitoring were chosen for sufficient coverage to monitor GCW extent, as well as better refine understanding of the water movement into the producing zones 1A and 1B. Several wells, notably 18-35 which was completed in late 2015, have logged GCW from Z3 down to bottom of Z1B. Multiple wells in the DS18 area are producing GCW. Understanding the water pathway to Zone 1, which is the oil bearing interval in this far upstructure area of the field, is a focus for future logging and analysis. Integrating production evidence with log evidence is an important part of the analysis. Future surveillance will continue to include repeat neutron logs for monitoring the maximum lateral extent of the flood front, monitoring water movement within each zone, and specifically in the producing Zone 1. 4.6.2 2019 Surveillance Plans GCWI Injectors Injection pressures, rates, and temperatures are recorded for each well every day. Pressure-rate plots will be routinely monitored for changes in injectivity of the wells. Observation Well Casedhole Saturation Logs This program will continue as it has in the past by running casedhole saturation logs every year with the final timing and locations determined based on the results to date. Gravity Survey A gravity survey is not planned for 2019. 4.6.3 Plans for Change in Project Operation No changes to the Gas Cap Water Injection operation are planned for 2019. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 15 4.7 Put River Oil Pool On November 22, 2005 the AOGCC ruled in Conservation Order 559 that the Western, Central and Southern Lobes of hydrocarbon bearing Put River sands would be defined as the Put River Pool and that the Northern Lobe would be included in the Prudhoe Oil Pool. Exhibit 12 displays all four lobes which are in pressure isolation from each other. Additional technical information was previously supplied with the application which led to Conservation Order 559. 2018 Production and Injection For the year 2018, over 99% of the production, and all of the injection, occurred in the Southern lobe, with less than 1% of production from the Western lobe. Production from the Put River Oil Pool in 2018 averaged 250 BOPD for the days the reservoir was on production and 179 BOPD averaged across calendar days. The total 2018 production of the Put River Pool comes from three Put River producers: wells 02-23A, 02-27A, and 15-41B. Injection in the Southern Lobe of the Put River averaged 3,585 BWPD for the days the injector was online and 2,563 BWPD averaged across calendar days. Cumulative Put River water injection is 12.9 MMBW, of which 936 MBW was injected in 2018. The 2018 cumulative production for the Put River Oil Pool was 65 MBO, 615 MBW and approximately 682 MMSCF formation gas. The full life cumulative production for the Put River Oil Pool through December 31, 2018 was 4.09 MMBO, 8.07 MMBW, and approximately 5.96 BSCF formation gas. (Note that these cumulative volumes include a technical estimate, based on material balance calculations, of Southern lobe production from a casing leak in 02-27 between 1994-1997. The cumulative gas volume reported in this report is reflective of the best technical estimate of the formation gas production from the PROP; the volume reported in previous ASR may differ due to accounting for the estimated casing leak volumes and gas lift volumes.) For this report (and also for last years 2017 ASR), the reservoir properties in Exhibit 11 for the PROP pertain to the Southern lobe only. Southern lobe properties are reflective of over 99% of production in 2018. 2018 Pressures Put River pressures taken during 2018 are listed in Exhibit 9. The Southern Lobe pressure obtained in 02-23A producer in June 2018 measured 4,533 PSI at 8,100’ SSTVD. The Southern Lobe pressure obtained in 02-27A producer in June 2018 measured 4,061 PSI at 8,100’ SSTVD. The increased pressure was a result of a voidage replacement ratio of greater than 1 on average for the year. The Western Lobe pressure obtained in 15-41B producer in September 2018 measured 4,127 PSI at 8,100’ SSTVD. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 16 2019 Surveillance Plan Southern Lobe – An increasing pressure trend has been observed in 2018 as a result of injection, in line with the injection management strategy of 2018. In 2019, the strategy is to manage at VRR of 1 or slightly lower. A static bottom hole pressure survey is planned in Q1 2019 in producer 02-23A. Western Lobe - 2019 production and surveillance plan will be dependent on the outcome of the application for commingled production from the Put River Oil Pool and the Prudhoe Oil Pool. Central Lobe - No 2019 production or surveillance is currently planned. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 17 5.0 GAS MOVEMENT SURVEILLANCE The report on gas movement surveillance activities and interpretations provides an overall summary of gas influx movement and summarizes the 2018 gas-monitoring logging program. 5.1 Gas Movement Summary Fieldwide GOC surveillance continues with collection of open-hole and cased-hole logs and monitoring of well performance. In order to monitor gas movement in the reservoir, GOC estimates are made across the field and are based upon the ongoing monitoring program and historical well performance. The central portion of the field, the gravity drainage area (GD) exhibits in some areas almost total influx of the LOC (Light Oil Column). In many areas of the GD a distinct GOC no longer exists. Rather the data suggest that there is a continuous gradation of gas saturation throughout this part of the reservoir. Gas influx is essentially absent in the southern peripheral regions as a result of water and WAG injection in the waterflood areas. There are areas downdip of the GDWFI area that are affected by gas. It has become difficult in most parts of the field to define a single current GOC as the surface is commonly broken into a series of oil lenses and gas underruns beneath the shales. The reservoir is better characterized by a description of remaining oil targets. The targets within the GD occur within three general regions; the basal Romeo (Zones 1 & 2A) sands, the inter-underrun sands, and oil lenses within the expanded GOC. Production from the Romeo (Zones 1 & 2A) sands has historically been low compared to the more prolific upper zones. This interval has a lower net to gross, lower permeability and more limited sand connectivity than the rest of the reservoir. These factors impede gas expansion into the Romeo. Underruns beneath shales within the Romeo sands are likely to be local. The inter-underrun sands occur throughout the GD and are characterized by one or more underruns or solution gas pockets segmenting the remaining oil pad. Gas underruns are observed beneath the top of the Sadlerochit reservoir, under Zone 4 shales, and the most regional persistent underruns have developed under the mappable floodplain shales of Tango or Zone 2B. Oil within the expanded GOC occurs in lenses above regionally continuous shales. Such lenses have been identified from neutron logs. Many lenses continue to exhibit oil drainage over time, while others appear isolated. Exhibit 8 lists the open and cased-hole neutron logs, as well as RST logs, run in the Prudhoe Bay Unit during the gas-influx reporting period from January 2018 through December 2018. A total of 53 gas-monitoring logs were run in the PBU of which 49 were cased-hole. On July 20, 2016 the Commission modified the neutron log requirements in CO 341F Rule 7 (341F.002 (Corrected)) to provide that either cased or open hole neutron logs are useable to fulfill the minimum requirements of 40 neutron log surveys to be run annually. On January 9, 2018 the commission further modified the neutron log requirements in CO 341F (.007) Rule 7 to have the Annual Reservoir Surveillance Report contain the number and approximate locations of neutron log surveys anticipated for the next calendar year. The 2017 ASR committed to a minimum of 30 neutron saturation logs. For plan year January 1, 2019 until December 31, 2019, a minimum of 30 neutron saturation logs will be obtained with the following approximate distribution (minimums): Gas Cap – 0, as there is no expectation of a GOC there, Gravity Drainage-6, Gravity Drainage Waterflood Interaction-15, Downdip Areas Affected by Gas-9. 2018 ANNUAL RESERVOIR SURVEILLANCE REPORT PRUDHOE BAY AND PUT RIVER OIL POOLS Page 18 6.0 REVIEW OF POOL PRODUCTION ALLOCATION FACTORS Prudhoe Oil Pool (POP) and Put River Oil Pools Monthly Average Oil Allocation Factors: 2018 Jan 0.90 Feb 0.90 Mar 0.89 Apr 0.92 May 0.93 Jun 0.98 Jul 0.94 Aug 0.94 Sep 0.91 Oct 0.92 Nov 0.91 Dec 0.91 The table contains monthly averages of oil allocation factors from the 7 facilities that receive production from these two pools: GC-1 (POP only), GC-2 (POP only), GC-3 (POP only), FS-2 (POP & PUT), FS-2 (POP only), FS-3 (POP only) LPC (POP only). Any days of allocation factors of zero were excluded. These allocation factors range from 0.89 to 0.98. Daily allocation data and daily test data are being retained. Exhibit 1-A Prudhoe Bay Unit Field Schematic Exhibit 1-B WPWZ NWFB FS2 EPWZ EWE GD 2017 AOGCC Report Producers 101 64 108 74 69 444 Injectors 41 30 59 26 18 54 -WAG 4 3 2 1 2 0 -Water Only 34 23 51 24 16 23 -Gas 3 4 6 1 0 31 2018 Producers 98 58 100 71 67 440 Injectors 38 29 58 26 18 57 -WAG 3 2 0 0 4 2 -Water Only 31 22 49 26 12 24 -Gas 4 5 9 0 2 31 Production Well Status in 2018 -Newly Drilled 0 0 2 0 0 0 -Sidetracked or Redrilled 0 0 4 0 0 4 Gas Injection Well Status in 2018 -Newly Drilled 0 0 0 0 0 0 -Sidetracked or Redrilled 0 0 0 0 0 0 WAG Injection Well Status in 2018 -Newly Drilled 0 0 0 0 0 0 -Sidetrcaked or Redrilled 0 0 0 0 0 0 Water Injection Well Status -Newly Drilled 0 0 0 0 0 0 -Sidetracked or Redrilled 0 0 0 0 0 0 NOTES: (1) Well count data reflects ONLY those wells which contributed to production/injection during the respective year. (2) Project boundaries were simplified in 1998. Wells no longer share project boundaries, but belong to a single project area. (3) EOA GD and WOA GD have been combined. Exhibit 1-CWPWZNWFBFS2EPWZEWETOTAL556 613 1121 664 97 30512445 1511 6701 3778 389 148241531 1102 4851 1963 227 96741943 1736 6962 2418 242 13301666 711 1132 691 118 33184017 2778 11132 5830 595 243532374 2113 7617 2857 278 15240-1643 -665 -3515 -2973 -317 -91134164 2831 11516 5997 624 259092428 2150 7768 2917 301 15889-1735 -681 -3747 -3080 -323 -1002023 15 28 6 6 7814.7 9.0 28.1 14.9 8.7 75.5305.1 85.9 787.1 290.8 34.8 1503.7119.0 60.3 335.6 184.9 41.5 741.2125.6 73.7 343.9 158.8 49.9 751.924.8 33.4 81.4 14.0 153.6GDWPWZNWFBFS-2EPWZEWEPBMGP3292 3315 3327 3398 3304 3617 33453286 3320 3380 3396 3328 3619 3360-6 5 53 -2 24 2 151CWaterflood Project AreaCumulative Production from WF Start-Up thru 2018Oil (MMSTB)Gas (BCF)Water (MMSTB)MI (BCF)Cumulative Injection from WF Start-Up thru 2018Water (MMSTB)Cumulative Balance from WF Start-Up thru 2017Cum Production (MMRB)Cumulative Balance from WF Start-Up thru 2018Cum Injection (MMRB)Over/Under (MMRB)Cum Production (MMRB)Cum Injection (MMRB)MI Breakthrough in Producing Wells> 200 mcfdOver/Under (MMRB)AVERAGE RATE DATA 2018Gas (MMSCFD)Water (MBD)ProductionOil (MBD)Current report period:Estimated Annual Change (psi/yr)InjectionWater (MBD)Gas (MMSCFD)AVERAGE RESERVOIR PRESSURE (psia)Previous report period: 8 8 ii! 8 8 il! 8 8 ~ --------·-·----·--... ---, 2018 Reservior Pressure at 8800" SS Datum 3,050 -3 ,150 psi 3,150 -3,225 psi 3,225 -3 ,300 psi 3,300 -3 .420 psi 3,420 -3 ,550 psi 3,550 -3.6BO psi 3,680 -3 ,790 psi 3,790 -3 .890 psi 3,890 -4 ,000 psi S.000 10 000 + .a:J .000 i I EWE 4--·-··----- • 2016 SBHP • 2 017 SBHP o 2018 SBHP • • 2016 Calculated fro m Surface Data 2017 Calculated from Surface Data 2018 Calculated from Surface Data ;-··-, Prudhoe Bay L.._: Unit B ounda ry D Depletion Polygons NOTE: Engineered control points have been added to the fie ld perimeter to provide a more accurate contouring. Xl.000 40 .000 r • .,. + + + 62()000 710000 Ex hib it 1-D + i------.. Prudhoe Oil Pool 2018 Regional Reservoi r P ressu re M ap ,_,, I i :--·-··-··--·-·--··-··-··· ·-··-··--·-·-··-··, I ! '----·--··----··-··1 + G a s C a p -. + I ~-______ ±----·· 11 + + 650000 -. L ·------·-··-... --·-----·---· ------·-·----,·-··-- + 710000 --' '-·,. 8 8 1i1 3900 3800 3700 3000 p 3500 s I A 3400 3300 3200 3100 ,._ I~-= 3000 Dec-82 Jan-87 Exhibit1-E Areal Average Pressure ---PBMGP -----Gra1ity D ra inage --.__ -~ ~ ~--~ ~ ~ ~ ~~ - - - - -- -_.? -------• ~ r-.--------.---. __._ --___... ........ - ~ ---- Jan-91 Jan-95 Jan-99 Jan-OJ Jan-07 Jan-11 Jan-15 Jan-19 Jan-23 Exhibit 1-F Un its=osia DATE FS2 EPWZ WPWZ NWFB GD EWE PBMGP Dec-n 3935 4005 4016 3944 3999 3968 Jul-78 3870 3967 3978 3909 3963 3914 Oec-78 3832 3930 3944 3875 3933 3873 Jul-79 3813 3895 3911 3843 3901 3844 Oec-79 3791 3861 3879 3799 3871 3816 Jul-BO 3799 3831 3848 3770 3856 3798 Dec-BO 3852 3819 3822 3781 3823 3818 Jul-81 3881 3821 3799 3814 3809 3840 Oec-81 3880 3815 3799 3820 3793 3842 Jul-82 3872 3806 3800 3812 3778 3833 Oec-82 3850 3795 3797 3804 3762 3818 Jul-83 3831 3784 3792 3787 3745 3804 Jan-84 3814 3771 3783 3772 3728 3790 Jul-84 3796 3758 3777 3756 3711 3774 Jan-89 3779 3743 3771 3736 3695 3755 Jul-89 3760 3730 3763 3723 3678 3740 Jan-90 3732 3708 3731 3704 3658 3713 Jul-90 3708 3693 3716 3687 3641 3695 Jan-91 3680 3676 3694 3655 3623 3666 Jul-91 3642 3657 3673 3628 3605 3635 Jan-92 3617 3641 3652 3602 3588 3615 Jul-92 3591 3626 3632 3577 3570 3593 Jan-93 3561 3600 3619 3544 3549 3582 Jul-93 3543 3595 3598 3515 3531 3565 Jan-94 3539 3555 3578 3483 3512 3537 Jul-94 3523 3536 3555 3456 3492 3516 Jan-95 3496 3524 3555 3507 3482 3506 Jul-95 3473 3507 3536 3489 3466 3486 Jan-96 3466 3485 3497 3478 3446 3463 Jul-96 3450 3467 3472 3461 3430 3443 Jan-97 3446 3484 3460 3444 3404 3441 Jul-97 3429 3467 3438 3427 3387 3421 Jan-98 3452 3417 3417 3421 3379 3430 Jul-98 3435 3409 3394 3402 3363 3415 Jan-99 3445 3391 3382 3343 3339 3443 Jul-99 3429 3378 3360 3317 3323 3426 Jan-00 3406 3361 3372 3268 3294 3418 Jul-00 3390 3351 3353 3240 3273 3395 Jan-01 3366 3325 3325 3225 3274 3358 Jul-01 3360 3310 3309 3205 3257 3347 Jan-02 3325 3334 3289 3163 3270 3358 Jul-02 3312 3324 3273 3144 3245 3347 Jan-03 3299 3316 3262 3121 3236 3696 3297 Jul-03 3285 3306 3245 3118 3223 3659 3283 Jan-04 3271 3296 3228 3116 3211 3645 3272 Jul-04 3277 3324 3281 3296 3239 3614 3290 Jul-05 3338 3344 3282 3289 3250 3542 3314 Jul-06 3304 3296 3276 3296 3233 3536 3293 Jul-07 3357 3339 3275 3248 3243 3618 3310 Jul-08 3317 3299 3298 3269 3244 3626 3299 Jul-09 3348 3310 3308 3271 3248 3663 3315 Jul-10 3367 3329 3317 3329 3259 3666 3339 Jul-11 3368 3345 3308 3322 3265 3640 3338 Jul-12 3375 3338 3350 3302 3283 3632 3348 Jul-13 3391 3335 3313 3329 3276 3663 3348 Jul-14 3402 3324 3314 3322 3270 3652 3348 Jul-15 3398 3330 3313 3335 3275 3645 3350 Jul-16 3409 3332 3303 3332 3277 3650 3343 Jul-17 3398 3304 3315 3327 3292 3617 3344 Jul-18 3396 3328 3320 3380 3286 3619 3360 Exhibit 1-G EOA Ml Rate MMP MW Average Monthly Mole% MCFD PSI MolWt CO2 C1 C2 C3 IC4 NC4 CS+ 1/1/2018 113,879 3,087 32.61 20 .28% 32.17% 19.08% 24 .34% 1.65% 1.90% 0.00% 2/1/2018 112 ,989 3,026 33 .07 20 .35% 33 .20% 17 .00% 23 .13% 2 .66% 3 .33% 0 .00% 3/1/2018 124,283 3,147 32.73 20 .50% 34 .88% 15 .86% 22 .61% 2 .54% 3.26% 0 .00% 4/1/2018 121,838 3,152 32.64 20 .07% 35.34% 15.84% 22 .35% 2.56% 3.50% 0 .00% 5/1/2018 125,939 2 ,895 33.65 20 .67% 31 .90% 16.44% 24 .33% 2.70% 3.78% 0.00% 6/1/2018 4,128 3,247 32.14 19 .07% 36.23% 17 .92% 20 .77% 2 .38% 3.45% 0 .00% 7/1/2018 28,686 3,166 32.31 18 .63% 36.49% 15.91% 22 .53% 2.42% 3.67% 0 .00% 8/1/2018 35,068 3 ,171 32.51 19 .61% 35.71% 16.32% 22 .11% 2.61% 3.40% 0.00% 9/1/2018 56,262 3,148 32 .70 20.38% 34 .63% 16.65% 22 .51% 2 .51% 3 .08% 0.00% 10/1/2018 84,219 3,184 32.59 20.71% 34 .34% 17 .16% 22 .64% 2 .38% 2.48% 0 .00% 11/1/2018 88,863 3,200 32.76 22.03% 33.41% 16.62% 24 .39% 1.98% 1.38% 0 .00% 12/1/2018 82 ,462 3 ,220 32.77 22 .35% 33 .69% 15.82% 24 .93% 1.92% 1.15% 0.00% Averaae 81,444 3 ,123 32.79 20 .62% 33.99% 16.65% 23 .36% 2.33% 2.74% 0.00% WOA Ml Rate MMP MW Average Monthly Mole% MCFD PSI MolWt CO2 C1 C2 C3 IC4 NC4 CS+ 1/1/2018 92,176 2 ,812 33.83 20 .72% 29 .74% 18 .72% 24 .18% 2.69% 3.59% 0 .00% 2/1/2018 112,508 2,996 33 .19 20.42% 32 .76% 17 .10% 23 .32% 2 .69% 3.37% 0 .00% 3/1/2018 113,334 3,146 32.73 20 .51% 34.86% 15.87% 22 .61% 2.54% 3.26% 0 .00% 4/1/2018 128,472 3 ,163 32.60 20 .03% 35.50% 15.81% 22.30% 2.55% 3.48% 0 .00% 5/1/2018 57,266 3 ,148 32.82 20 .76% 34.78% 15 .95% 22 .39% 2.42% 3.49% 0 .00% 6/1/2018 155,989 3,120 32 .77 20.07% 34.66% 16 .68% 22 .55% 2.59% 3 .29% 0 .00% 7/1/2018 143,676 2,902 33.39 19 .50% 32.80% 16.63% 24 .04% 2.66% 4.12% 0 .00% 8/1/2018 111 ,386 3 ,145 32.66 20 .08% 34.92% 16.45% 22 .64% 2 .67% 3 .00% 0.00% 9/1/2018 127,313 3,133 32.74 20 .29% 34.62% 16.51% 22 .65% 2 .58% 3 .10% 0 .00% 10/1/2018 127,763 3,154 32.71 20.81% 33.91% 17.26% 22 .79% 2.42% 2.52% 0 .00% 11/1/2018 124,466 3 ,196 32.78 22.09% 33 .33% 16.65% 24 .38% 1.99% 1.38% 0.00% 12/1/2018 129,262 3 ,213 32 .79 22 .35% 33 .59% 15.89% 24 .94% 1.93% 1.16% 0 .00% Average 118,516 3 ,091 32.92 20.63% 33.73% 16.67% 23 .28% 2.48% 2.95% 0 .00% Exhibit2 Fieldwide -Exhibit 2 Fieldwide Producing Fluids (MMRB) January February March April M!l June Oil 7 .7 70 77 7.4 74 6 .1 Free Gas 204.9 186 7 206.5 196.1 195.1 155.2 Water 29.3 26 8 30 5 29.6 30.7 23.9 TOTAL 241 .9 220.6 244.8 233,1 233.2 185.2 Injected Fluids (MMRB) Water 38 8 36.9 41 3 39.4 41 1 35.1 Gas 199 3 182.0 201 .7 192,0 191.7 151.4 TOTAL 238 2 218.9 243 0 231.4 232.8 186.5 Net Injection Volumes = Injection • Production (MMRB) TOTAL ·3.7 -1 .7 -1 .7 ·1 .7 -0.4 1 3 Producing Fluids (MMRB) ,lyJy August SeP!ember October November December Totals Oil 6 .3 6.2 6 .6 7.0 73 7 ,3 83.9 Free Gas 160.1 165 2 175.7 185.7 197.8 207 .9 2236.9 Water 27.8 23 1 27.2 29.3 30.0 30,6 338.8 TOTAL 194.1 194.5 209.4 222.0 235 1 245 .9 2659.7 Injected Fluids (MMRB) Water 40.1 28.4 28.5 36 6 38 2 37.5 442.0 Gas 156.0 161 .6 172,1 181 .1 194,1 204.4 2187.4 TOTAL 196,1 190.0 200.6 217 7 232 3 241 .9 2629.4 Net Injection Volumes = Injection - Production (MMRB) TOTAL 1.9 -4.4 -8.8 -4 3 -2 7 -4 0 -30.3 Exhib it 3-A 04-2 1A • bp FS2 LEGEND Gas Injector Gas Injector Shut-in " Miscible Injector Miscible Injector Shut-in • Oil Producer Flowing • O il Producer Shut-in water Injector ,;. Water Injector Shut-in N i 0 ---- --1 "Miles Exhibit 3-B FS2-Exhibit FS2 Produced Fluids (MMRB) 12/31/2017 Janua!:l£ Februa!:l£ March April May June Fluid Properties Used Oil 1,458.9 1.312 1.181 1 .291 1.245 1.128 0.791 Bo (rb/stb) 1.324 Free Gas 4 ,773 .9 23.673 20 .765 21 .961 21.743 19.437 17.002 Bg (rb/mscf) 0.862 Water 4,899.5 10.735 10.234 11 . 714 11.458 11 .621 6 .654 *Bw (rb/stb) 1.040 TOTAL 11,132 .3 35 .720 32 .180 34.966 34.446 32 .186 24.446 Bmi (rb/mscf) 0.700 Rs (scf/stb) 620 .8 Injected Fluids (MMRB) Water 6,885.4 11 .094 10 .627 12 .240 11 .541 11 .581 6 .819 Gas 731 .6 2 .461 2 .215 2.697 2 .559 2 .732 0 .086 TOTAL 7,617 .0 13.554 12.842 14 .937 14.099 14.313 6.905 Net Injection Volumes (Injection - Production (MMRB) TOTAL -3,515 .3 -22 .2 -19 .3 -20 .0 -20 .3 -17 .9 -17 .5 Produced Fluids (MMRB) July August September October November December Cumulative Oil 1.160 0.863 1 .145 1.208 1.151 1.114 1,472.5 Free Gas 19 .300 15.691 19.906 19.922 21 .290 21 .577 5,016 .1 Water 11 .904 8 .331 10 .939 11 .932 10.819 11 .044 5,026 .9 TOTAL 32 .365 24 .885 31 .991 33 .062 33.260 33.735 11 ,515 .6 Injected Fluids (MMRB) Water 11 .901 8.423 10 .977 12 .604 11 .356 11 .364 7,016 .0 Gas 0 .622 0.756 1.177 1.827 1.866 1.789 752 .4 TOTAL 12 .522 9.178 12 .154 14.431 13.222 13 .154 7 ,768 .3 Net Injection Volumes (Injection - Production (MMRB) TOTAL -19 .8 -15 .7 -19.8 -18 .6 -20 .0 -20.6 -3,747.3 Exhibit 3-C FS-2 Areal Average Reservoir Pressure 3900 3800 3700 ia 'iii ~ ~ 3600 Cl) Cl) Cl 3500 Cl CC) co @ ! 3400 :, II) II) ! D.. .!::: 3300 0 ~ G> 0 & 3200 3100 3000 Jan-87 Jan-91 Jan-95 Jan-99 Jan-03 Jan-07 Jan-11 Jan-15 Jan-19 Exhibit3-D 04 -2 1~ bp FS2 LEGENO Gas Injector ·• Gas Injector Shut-ii '"' Miscible Injector Miscible Injector Shut-in • Oil Producer Flowing • Oil Producer Shut-in ,;,-Water Inje ctor ..a Water Injector Shut-in Daily RMI • <200msdl d e 200 -2000 mscf/d • > 2000 mscf/d N I , 0 p-._----, I M iles Exhibit 4A bp EP·wz LEcrEit Gas lnjeclor • Gas Injector Shut-in "' Miscible Injector Miscible Injector Shut-in • Oil Producer Flowing Oil Producer Shut-in Water Injector • Water Injector Shut-in Ambiguous Status N l 1 0 P------, I Miles Exhibit4-B EPWZ-Exhibit EPWZ Produced Fluids (MMRB) 12/31/2017 January February March April ~ June Oil 866.5 0.676 0 539 0 671 0 .697 0 640 0.548 Fluid Properties Used Free Gas 2,811 .0 7 .244 6 ,946 8.580 8.214 8.444 7 461 Bo (rb/stb) 1.321 Water 2,152.3 5 .911 4 671 5.491 5.948 5.821 5.321 Bg (rb/mscf) 0.872 TOTAL 5,829.8 13.8 12.2 14 7 14.9 14.9 13 3 Bw (rb/stb) 1.040 Bmi (rb/mscf) 0 .700 Injected Fluids (MMRB) Rs ( scf/stb) 614.0 Water 2,403.4 4.660 4 346 5 .030 5 .186 5.460 5.864 Gas 453.5 TOTAL 2,856.9 4 .7 4 .3 5.0 5.2 5 .5 5 ,9 Net Injection Volumes (Injection. Production (MMRB) TOTAL -2,973.0 -9.2 -7 .8 -9.7 -9.7 .9.4 -7.5 Produced Fluids (MMRB) 4.!!.!x August September October November December Cumulative Oil 0 ,602 0.482 0.536 0 561 0 601 0.626 873.6 Free Gas 8 .361 5.605 6.408 7 .301 7 458 7 620 2,900.7 Water 6 .233 5.293 5.744 5 950 6.779 7 016 2,222 .5 TOTAL 15.2 11.4 12.7 13.8 14 8 15.3 5 ,996 .8 Injected Fluids (MMRB) Water 6115 3.688 4.365 4 .821 5.264 5.497 2,463.7 Gas 453 5 TOTAL 6 .1 3 .7 4.4 48 5.3 5 .5 2,917.1 Net Injection Volumes (Injection • Production (MMRB) TOTAL -9.1 -7.7 -8 .3 -9 .0 -9.6 -9.8 -3,079 7 Exhibit4-C EPWZ Area l Average Reservoir Pressure ~00 -.----------------------------------------~ ~00 J _3700 t---~~---------------.,,,,,,....---........aa--------~--------------_J Ill -a ~ ~ 3600 +----·---~-~-- Cl) Cl) ~ 3500 r ---...... -~--.,,.,....---"1.c---::------""--"~---------~------------""""""''----_J QO @ i 3400 -I--~-------~--~-------~------------! ! a.. .i:: 3300 I .,.. -::--. 1 " £ + .......-:::w:: 1 0 & W ...... I ~ I ~ 3200 r --------------------------------------------..l 3100 -r--~----~---------~----,------------~~------_J 3000 -l-----'---'--.__-+--_.___.__.__-+--_.___._..__-+-_._---'--'---+----'----'--.__-+--__.___._..__-+-_.____._..__-t-__.___._..__-+-__.___._.L--....t Jan-87 Jan-91 Jan-95 Jan-99 Jan-03 Jan-07 Jan-11 Jan-15 Jan-19 Jan-23 Exhibit4-D ~7-24 bp EPWZ LEGEND Gas Injector Gas Injector Shut-in " Miscible Injector Miscible Injector Shut-fn • Oi l Producer Flowing Oi l Producer Shut-in Water Injector " Water Injector Shut-in ' Ambiguous Status Daily RMI • < 200 mscf/d e 200 -2000 mscf/d • > 2000 mscf/d N t 1 0 P-----, I I Miles Exh ib it 5-A £::] bp WPWZ LEGEN D Gas Injector •· Gas Injector Shut-in Miscible Injector Miscible Injector Shut-in • Oil Producer Flowing Oil Producer Shut-in ·.o Water Injector • Water Injector Sh ut-in N t 1 0 r----...-, I M iles Exhibit 5-B WPWZ-Exhibit WPWZ Produced Fluids (MMRB) 12/31/2017 January February March April ~ June Fluid Properties Used Oil 731.4 0 653 0 ,625 0 .679 0.645 0 .643 0 .563 Bo (rb/stb) 1.322 Free Gas 1,738.0 8 .301 7 .808 8 ,997 7 711 7 .923 6 ,899 Bg (rb/mscf) 0 .869 Water 1,548.1 4 385 4 .124 4 .458 4 .132 4 .369 3.725 Bw (rb/stb) 1.040 TOTAL 4,017.5 13 338 12.558 14.133 12.489 12.934 11 187 Bmi (rb/mscf) 0 .700 Rs (scf/stb) 616.2 Injected Fluids (MMRB) Water 1,934.8 4.448 4 .180 4.480 4 213 4 ,186 3 .539 Gas 439 .7 0 290 0 .238 0.411 0.585 0 .287 0.900 TOTAL 2,374.5 4.738 4 417 4 ,891 4 ,798 4.473 4 439 Net Injection Volumes (Injection - Production (MMRB) TOTAL -1,643.0 -8 6 -8 .1 -9.2 -7.7 -8.5 -6 7 Produced Fluids (MMRB) 4.!!.!x August September October November December Cumulative Oil 0 506 0 .520 0.486 0 ,576 0.597 0 .617 738 5 Free Gas 7 161 7.321 7 .320 8.424 7.787 8.219 1 ,831 .8 Water 3101 2 ,813 2 ,826 3 .255 4 .031 3 .940 1,593.2 TOTAL 10.768 10.654 10.632 12.255 12.415 12.777 4,163 6 Injected Fluids (MMRB) Water 3 540 3 .612 3 .716 3.741 3 .935 4 .098 1,982.4 Gas 0 669 0 ,373 0 .503 0 .733 0 .757 0 600 446.0 TOTAL 4 .209 3 .985 4 .219 4.474 4 .693 4 .698 2,428.5 Net Injection Volumes (Injection - Production (MMRB) TOTAL -6.6 -6 .7 -6 4 -7.8 -7 .7 -8.1 -1 ,735 ,1 Exhibit 5-C WPWZ Average Reservoir Pressure 3900 -r--~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~----, 3800 J__~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~--i 3700 -t-~~~---'._,....~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~--' :i Cl) E:: ~ 3600 U) (/) g 3500 .-~~~~~~~~~~~----~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~--.-! CX) CX) @ Cl) 5 3400 ~~~~~~~~~~~~~~~->:i..--~~~~~~~~~~~~~~~~~~~~~~~~~~~~~---= Cl) Cl) ! 0.. -~ 3300 I ~ A~ ~ • ~ ~ Cl) Cl) Cl) n:: 3200 ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~---' 3100 +-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~- 3000 +--'--'-~----_,____._~..__-+-~__.~..__-1-_.____.~_._-t--'----'~-'--t---'----''--'--t----'-~'--~-r--'-~--...,_-r-___..~~ Exhibit 5-D N-11 1) U-07 ~ ,-35A WPWZ N Gas Injector • Gas Injector Shut-in Miscible Injector Miscible Injector Shut-i n • Oil Producer Flowing Oil Producer Shut-in Water Injector " Water Injector Shut-in Daily RMI • < 200 mscf/d e 200 -2000 mscf/d N t 0 ---M iles -- - Exhibit 6-A H-38 NWFB F-36 • LEG END Gas Injector 0 Gas Injector Shut-ii • Miscible Injector Miscible Inj ector Shut-i n • Oil Producer Flowing Oil Producer Shut-in .. .-Water Injector .. Water Injector Shut-in N i 1 0 - -- - - I Miles Exhibit6-B NWFB-Exhibit NWFB Produced Fluids (MMRB) 12/31/2017 January February March April ~ June Fluid Properties Used Oil 768.2 0 ,343 0.367 0.403 0.371 0 .399 0.409 Bo (rb/stb) 1.318 Free Gas 933.7 2 191 1 .960 2 .216 1845 1 .744 2 019 Bg (rb/mscf) 0.882 Water 1,076.3 2 .291 2 .163 2 .337 1.882 2 .227 2 288 Bw (rb/stb) 1.040 TOTAL 2,778.2 4 825 4.490 4 .956 4.099 4 .370 4 .715 Bmi (rb/mscf) 0.700 Rs ( scf/stb) 607 .3 Injected Fluids (MMRB) Water 1,672.9 2 017 2 .268 2 .619 2 .087 2 .315 2 .419 Gas 440.6 0 .566 0.892 0 .804 0 .772 0 .429 1 ,091 TOTAL 2 ,113.4 2 .583 3.160 3 .422 2 .859 2 .744 3.510 Net Injection Volumes (Injection - Production (MMRB) TOTAL -664.8 -2 2 -1 .3 -1.5 -1 2 -1 .6 -1.2 Produced Fluids (MMRB) 4.!!.!x August September October November December Cumulative Oil 0 .261 0 .305 0.345 0.393 0.355 0 .392 772,6 Free Gas 1 565 2 .116 2 .489 2.526 2 .546 2 682 959 6 Water 1.316 1 130 1.749 1 918 1.802 1.783 1,099 2 TOTAL 3 142 3.551 4 .583 4 837 4 703 4 857 2,831 3 Injected Fluids (MMRB) Water 2 021 2.460 2 .009 2 .578 2 .550 2 647 1,700.8 Gas 1 009 0 ,638 0 847 0 .613 0.406 0 462 449 1 TOTAL 3 .030 3 ,098 2 .856 3,191 2 .956 3.109 2,149.9 Net Injection Volumes (Injection - Production (MMRB) TOTAL -0 1 -0 5 -1 7 -1 6 -1 7 -1 .7 -681.4 :s Ill a. Exhibit 6-C NWFB Areal Average Reservoir Pressure 3900 --.-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~----, 3800 +----------------------------------------------1 3700 -t-----""~----------------------~-----~-----------! i3600 fl) ; 3500 ,---------~~~.t:;~-----------------------------------_J fl) @) GI ~ 3400 r---------------~':-________________________________ __j ! D. ·i3300 r--------------~~------,.=:::::=.;::::::,1""-----"::-1-==~~~~===:::~-----_J GI Ill GI lll::320o r----------------___:~~--f-----------------------J 3100 +-----------------------------------------------, 3000 -+--'--'--~-+---'~~_.___, _ _.___.___..~+-~--'-...__-+-__._...___--+-~--'-......... -+--...._ ......... _~-+--'---......... --+-'--......... ~---1 Jan-87 Jan-91 Jan-95 Jan-99 Jan-03 Jan-07 Jan-11 Jan-15 Jan-19 Jan-23 Exhibit6-D H-38 NWFB LEGEND .,., Gas Injector Gas Injector Shut-in -Miscible Inj ector Miscible In jector Shut-i n • 0 11 Producer Flowing Oil Producer Shut-in Water Injector Water Injector Shut-in Daily RMI < 200 mscf/d • 200 -2000 mscf/d • > 2000 mscf/d N 1 1 0 r---_..., I Miles Exh ibit 7-A RATE-01 bp EWE L~ -'.> Gas Injector o Gas Injector Shut-i"1 ,:-, Miscible Injector ,., Miscible Injector Shut-in • Oil Producer Flowing Oil Producer Shut-in Water Injector -Water Injector Shut-in N i 0 - ----Miles Exhibit 7-B EWE-Exhibit EWE Produced Fluids (MMRB) 12/31/2017 January February March April ~ June Fluid Properties Used Oil 125.0 0.397 0 .337 0 402 0.381 0 .382 0 334 Bo (rb/stb) 1.344 Free Gas 250 7 0.558 0.492 0 618 0.684 0 .736 0 718 Bg (rb/mscf) 0.800 Water 219.4 1.314 1.148 1.531 1 233 1.218 1.156 Bw (rb/stb) 1.040 TOTAL 595.1 2 .268 1.977 2 551 2 298 2 336 2 .208 Bmi (rb/mscf) 0.700 Rs (scf/stb) 667.8 Injected Fluids (MMRB) Water 204.3 1.959 1 .770 2 .037 2 ,164 2 ,215 1.875 Gas 73.8 0 .060 0 .077 0.223 0.414 0 ,187 0 .375 TOTAL 278.2 2 .019 1 .847 2 .260 2.578 2.402 2 .250 Net Injection Volumes (Injection - Production (MMRB) TOTAL -317.0 -0.2 -0.1 -0 3 0.3 0 .1 0.0 Produced Fluids (MMRB) ~ August September October November December Cumulative Oil 0 .220 0 .319 0 350 0 .362 0 .380 0 397 129.3 Free Gas 0.471 0 .677 0 813 0 .801 0 857 1 028 259,2 Water 0.835 1,290 1.577 1,302 1.582 1 578 235 2 TOTAL 1 525 2 286 2.740 2464 2 .818 3 004 623.6 Injected Fluids (MMRB) Water 1,352 0 960 1.045 1 074 1 005 1 478 223.3 Gas 0.231 0.453 0 ,237 0 312 0.409 0 .608 77.4 TOTAL 1.583 1.413 1,283 1.386 1 414 2 086 300.7 Net Injection Volumes (Injection - Production (MMRB) TOTAL 0 1 -0.9 -1 5 -1 .1 -1.4 -0 .9 -322 9 3900 3800 3700 -. !!! Ill .e: ~ 3600 en en g 3500 co co @ ~ 5 3400 Ill Ill ~ D... -~ 3300 C: ~ Ill ~ Q'. 3200 3100 ~ 3000 Sep-02 ~/ ~ . May-OS Exhibit 7-C EWE Areal Average Reservoir Pressure --.... -~ ~ ; --...., -- Feb-08 Nov-10 Aug-13 May-16 Feb-19 Oct Exhibit 7-D RATE-0 1 bp EWE LEG EN -:, Gas Injector " Gas Injector Shut-in -Miscible Injector ,_, Miscible lnjectoc Shut-in • Oil Producer Flowing Oil Producer Shut-in Water Injector Water Inj ector Shut-in Daily RMI • < 200 mscf/d e 200 -2000 mscf/d N t 0 ii---_..., 1 I Miles • ) 2 3 4 .s 6 7 Exhib it 8 2018 Wells Surveyed ror Gas Movement 2018Drllllng Well (oaOafe OH/~ GOC(l\1 0) GOI! (lVOSSI, 0)-36 l ·Jul•18 OH loconclusM!: 04 .5, 21-Apr-l B OH 07-030 17-Ja n-lB OH 07-20C 20-0ct-1B CH 11-238 16-M•v-18 OH 0-07C 28-Ap r-lB CH f-BC 4-Jun·18 CH Key OH -Open Hole log CH -Cased Hole log 9,994 10,365 IO,IB!/l.1,~Sl/H,284 Jl.144/-15,031 U,840 9,496 :t wellbore crossed GOC at multfple depths Not present over logged interval all fluid Not present over foss:ed Interval : all gas 8,604 8824 8,11-11/8.lll9/ll,8U 8.602/8.571 8,919 8,949 • w•~ 1..6'0.• 1 01-13 17-Feb-18 2 01-23 18-Feb-18 3 01-31 13-Feb-18 4 01-32A 14-Feb-18 5 04-13 22-Nov-18 6 05-02A 13-Dec-18 7 06-036 6-Apr-18 8 06-15 18-May-18 9 06-23C 9-Feb-18 10 07-036 13-Feb-18 11 09-04A 25-Jul-18 12 09-38 21-May-18 13 11-26 15-Dec-18 14 11-27 15-Apr-18 15 11-29 29-Jun-18 16 11-35 l9-Jul-18 17 14-188 7-Mar-18 18 14-32A 9-Aug-18 19 15-07D 30-Nov-18 20 15-32C 10-Feb-18 2J 18-068 22-Mar-18 u 18-29C 24-0ct-18 23 D-148 12-Jan-18 24 E-12A 3-Jan-18 25 E-13A 21-Sep-18 26 F-238 21-Mar-18 27 F-348 19-Jun-18 28 F-45C 15-0ct-18 29 H-29A 30-May-18 30 H-38 3-Jun-18 31 J-12 22-Jun-18 32 J-170 29-Dec-18 33 U-09 28-May-18 34 Ll-13 10-Jun-18 35 L2-14C 27-0ct-18 36 l2-33 20-Apr-18 37 N-04A 10-Mar-18 38 N-lOA 16-Aug-18 39 N-12 26-0ct-18 40 N-21A 14-Jan-18 41 N-30 24-5ep-18 42 R-04 18-Mar-18 43 R·12A 21-Aua-18 44 Z-24 12-Aug-18 45 Z-29 28-Aug-18 46 Z-32C 27-Feb-18 2018 Sutwlllance OH/Ill! GOC(l\10) GQC(1VDSS) CH 11,005 8,823 CH 11.005 8 ,823 CH 9.352 8 779 CH 9.284 8.891 CH 10.280 8.528 CH Not ofesent over looed lntaMI CH 10,730 8,958 CH 9,193 8,914 CH 9,680 8,950 CH )0,685 8 916 CH Not present over loued Interval CH fiQI p tbC!nl ,OVtr le>aed inteNAl CH 10,622 8,619 CH 11,912 8,624 CH 9,745 8,572 CH 8,998 8,445 CH )0,855 8..712 CH 11,2 20 8,807 CH 12,183 8,619 CH 9 074 8,802 CH 8,956 8,613 CH 12,749 8,628 CH 9,839 8,946 CH 9,231 8,981 CH 11,217 8 ,846 CH 10,786 8,965 CH 10,586 8,947 CH 9,529 8,959 CH 9,535 8,796.8 CH 10,669 8,727 CH 9,653 8,8555 CH 12,033 8,964 CH 10,910 8,597 CH 13,712 8.576 CH 9 ,200 8.515 CH Inconclusive CH 10.073 8 ,708.4 CH 9,526 8,620.3 CH 9.566 8.725 CH 11.077 8,839 CH 9.452 8,690.5 CH 9.511 8,692.6 CH 10,808 8,730 CH 10.303 8 ,731 CH 11.627 8 ,7585 CH U.885 8,732 Exhibit 9 -,_ P.O Boa tlllfli5'12.QOOIE...s.r.t,o.Bl\.d . ..__.___ AK9951!;J,(i&12 -41 F..:irdi:tod ·--G OOG,o,<y '""'"'-~RliY~~OilPodl """""""' Q.Sl·SG!2?" /tl'1 09 D.API Nl;mCff I \O.~~ 1t~=1l~lu"Jr [ J:J?~ftlMIII "Tap • Bocm! 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SOHl' r.!703 8.800 ,,,., 8,800 0•2 329112 K-09<: 113803 0 ""''"' 9012-9!>,o.R011,aow90QS..00Cll5:as,2..a52a.OOQ6..WC6go12..goog Q007...a,:,oe, 811/20\8 5.560 """" 15' OSOQ '.3210 . .., Q.41 329211 K-12C 500292 t 1S903 0 640150 QOOl-OOOll-9009 ~ IIK2.-8"93,IIS98-8898 899»995 11890-811!1.!1 IIOOll-8006.8ll!l5-8999 ,,,gno,a 11684 SB>iP ... as.o 323< e.eoa 0 10 3'260 l2-C7A 500292291001 0 ...,, .. ~ 8815-8811 e&11..ee13 866"2-86S9 ,88J,a..a&ei,3688..M&c.8&1',3..8,6?-<_8688,,M73 M,4.2-884• "20/201" 1529 ..... 1'591!1 8 BOO 33!1? ..... o;e 3 <69.25 r,,,ea """29208S502 WI """'"' !!l&5--S783.8~5157D2..fJ74S.&!12-383Q 8591-8610 8S82-&S9 1 7/l0l2019 384 Oll<D< ;as \0 9.000 ... J.J.4~ M·20A SQ02fQQG1201 'M ""'''° !!~J5.813& 87l2-873ZS7-C1-87« 8882-H97.8 20-87.il:·l !7.29;-8730,8715-871'7 7/llJ/1018 3$< OTHEA. ,28 10 0.000 ... 3 ..... GI &ull50 11~14-8303.&4.9().8.49Q.8 t71..a213,83S0-8380,SJ93-M11.as, 1.as1a184&T-4482.'4~7~a263427.c.Jsl813-fflJ.rn1. ...... .. .... NGMJ1 soo:momoo 8350 84 .. -8511 ,aw;.&585.6S54-8S63.a32t-8337 llSll-8548 8310-8321 85i3-8802. .. I 1-8<3' W712018 25i05 1n.o 8 500 3353 oca PS!.01 S0029'23t0400 Wl ... ,50 fl5()C...ft...~.&428-~.6388-,8407 S2M-3319 8357..a-3?4 ns6-S2S4 9/'2120II 432 OTHEJI 713 2 aooo o .. PSl•D5 .500m3f74DO WI ""''"' a52M$6T anrnua •32. OTHEA. 2118 3 1,000 PSl-01 SQD212317100 WI ...,,50 f1503,,85,)0 ""2t2015 '32 O™ISI' 28!> 2 ..... PSI-OIi 5002Q'23. 1 , 400 WI ... ,,., .. 22-850!1~!tl29-8:187 111212<11" 43l OTt1ER 2<3 ,, 8.1100 PSl-00 O<J02!12JOi500 WI ... , .. t,.4 74-,8484 $2'9J.8)J5, 8438-M84 ~·\-MG& 826~..&C84-SS4~ 8360-8379 9!212(11. •32 OTHER 291! 3 ,.ooo PSl,.,tQ SOtl2ln3 1 1000 WI M01SO 63$8-8331 !297-83,,CC 8415-M91.'41341!J'51 a/2/2018 •32 OTH£f\ 884 2 8,000 o-ora 5002ll2035202 Q .... 50 00-.9028.QO'lti.9020 1426-8453 1/ll!/2018 U!OO. 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"9~J-llV.7,ll9&3,.898l,9010,.9D)IS,,S9?tM9'14,Ms.nle.~74-8990,906·t·5069,0044.W57..89Qt-a9;S..Bffl-0?.C,.'i1001· S!lf<? ...... w.o, S0Dm1QOJD0 9010 8970-8912 MS7-696'!.SS51-1957.U74-8988 ~990..890o.a!HM5 8110/2'0U! 1817 2Ja2 8000 =• W-<>SA s.oo:N2\a.3901 0 6'0150 !91Mffl.B97i-8975.900l.\-&001 8012-.9012 8013--9012.H17-e978.a9n-897S 901S-9013~.!M9.oli994 !9178-8919 8'1Dl2D16 S12-...... ,.., 5 IIOO 331!2 ...... 0 6401.!,0 ~.W25-!iOl!l1._&012·90l2.,MQft-,8'125.895&-a981.8932-8940,8H2--1M>12.U47-8ffl,895N!Ja1,89'25-a927,!93Q-. SS!,? "-""" W-71 $)Q202\l8900 ~O 8902..-8;W~38T7..aaa5 8902-8908.8164-8873 8S~.S958_fl.930-8932 Sl251'2D't ft 3'500 1 t O 8336 3440 0 ...,,,.., e.971""911 ,&iac.-!971..89'S?-69-&~.89'l1.etM.c.evwlll,(.~.a9'14...a9~.8833.8930,89u,.amam..a11,1,a912a. S8"riP 1.eoo W-58 S<10ml42300 6°""" ~~1 ffl.M!l-30 895&-B:970 3/7Q018 195. 2'l1 .oli2 uoo 32$2 WC3 1.Q7 500292203100 "' "'°'"' 6561-8'S87.3'2S8.ft295 !!l2]446e, a.597-860,C $472-.a:510. 8~71).a2Ql 8001-83HI UI-C-85!6 8S91..affl Qf7Q01! .•. SB+IP 15009 15r,o 3405 ..... Y-1"3>. !iOCl'9lQll3<01 Q ...,,50 4877-3877.a8715-&870 U11-Um.ft855.SBS9 84.Bl).4880,$87>8883 83S0-8853 8884--M8i 31'""'2018 427 58HP 218-J2 1801 2"1S3 ·--Y .. 1_9_A 500192115701 0 640150 8822479:i 8'1M--87!.D.~1M&:2118al7.a:&20.~19_.8J87--8770 1(1 ,. 180. 511>1P 2.2055 HOO ,, .. . .... Exhibit9 8 WellNamel 9 APINumber I HI.Type 1-111 AOGCC ] 12 Zone and Number: SOX.X.XXXXXXXXX Instructions Pool Coda 13.P••~ -Tcp ,eot:omni:oss X NO DASHES WAG 640150 8~5-a5~~!1·903l.896J.8973,S99:J,..gQ01 ,UJJ..8!H1~~·t1028.:902S•-90l1 Ba72-8885,9040-9055,B955-8963,9001- Z-12 500292197700 B019 8979-8987 8903-8927 a 640150 !961-1!97S,8~1-8967,9027-S033,9002-9008,9008-9016,8994-9002,8975-8978,8897-8905,8871-8873,8881..S889,9002- Z-20 50029218.SSUlO 9026 8967-897S,8945-8961,8966-B994 9002-9016 8924-8936 8877-8881 9016-9026 a 640150 !I024-!IOA4,86611 ... ~.1813-1822,M~t,l989-9017,00JA,11967,1865-811ii.M5&-8185.~.89>2-8987-.;. Z-2~ 50Q292j91JOO 9025,9025-9046 8934-8952,8865-8872 Z-<O 5002!l23<11200 0 ..,, .. lli11S..W5.8!l71-.SSIDUISCJJ..a-SJ\ 891:li'1°ti9$2.11,V2 8~_S_58.IB.9~915,8~ 1,US2-.e§J'C1,!995-U049 Put River 02-23A 500292079501 a SA01S2 m:i--:-a264~ al-VA 5002921S9401 0 6'0182 8202-*2~0. !202 iS-C,e 50fQ922,_91.02 o C,&0182 aoe,.a,o, aao~a ;z3 Alk!St!i~heNll"l.,...rl\allo:irl~wbNl~~Mld~lll'l:ctianl:olltw..,._.CNlr.lO ·.ato'I~ "Obw' abave indicates a batlom hole pr'MSIJre r;alculated from liurface data: unless othl!IWl!le noted the value provided indicates p~ gradient across the perfs Box 18: dl!!Jthdtool, in I.he case d "Othet" (8HPcalculated rrwn surface data), the depth stated iii the top affllid level.obbmed by the too! Box 19: "Other" (8HP cak:ulated from sutace dam) the vahJe pnwided i:strw we, head~ ll'hl: folowing well pressu11!1 measixements were excluded for the average pressure map oornp..tation: Y-19A, Y-13A, R-19A,R-30, 16-069 I hereby c:.rtify that the foregoing is true and corract to the best at' my knowledge William L, Brca.lr ~·r ~ ~--Nll'M ... ;...~ • :iJtc.tHI' Jt'~ ~-~~900:Z~f 081 14 Firlel Teall 15 Date Shut- '" r-. HcuB Bt2.12018 336 11.l4/2.0ll 15 917 8/1/2018 = lt1t20·ttl , ... M/2011 21'80. l!il3Dl1Q1S 380 91uno1a 1.133 16 Press t7 SH TB. Oeptn 19 Final 20 Oiltum ~-7l. Surv Type Temp Tool Qb,eNed TVDSS Gtadlent,psilft ....... ( ... TVDSS ........ (input) eat insltuclions a\Tool """" l«oades) Oeplh {col) OTHER -26 • uoo 0.44 J.630. SBHP 2012.7 8600 3621 B,BOO 0A2 l.621 22 SBHP 220 ! 067 3424 8,800 o,o 3717 SBHP 2'7 l!L31Q .3330 Ollal ll33 H92 ..... ,n.-e: 8,100 4S33 B,100 0.-114 4 532 51 SSH!' 1U67 8.100 4061 8,100 0.44 4.fl61 27 $BHP 106"4 1 !ii71 •csa 8.100 gB •12t1.~ n1. Lead Geasciertis.l Date 21-Mar-201 B T& I.No- Date 21-Mar-201 B Exhibit 10-A GCWI Surveillance and Extent 2018 684000 688000 692000 696000 700000 704000 708000 712000 716000 720000 I{ ·· 1~ :::· ·~· ~::A·~ 1.\~>J l~ "° ~ -'--~ ·\ . ~ C) e 2018Water Breakthrough • GCW positive log in 2018 0 . 0 0 (0 ~ ..... a, .,., 0 0 0 N ..... a, ll) 0 0 0 (D <D 0) ll) 0 0 0 V <D 0) ~k "" ll) J / 0 0 0 0 <D a, I() 0 0 0 <D ll) a, ll) 0 0 0 N ll) a, .,., 0 0 0 (D V a, "' 684000 688000 692000 696000 700000 704000 708000 7 12000 "' <D ---J O> 0 ----{ g "' <D ---J "' C) C) C) 01 <D a, a, 0 • GCW negative log in 2018 e pre-2018Water Breakthrough • Water logged pre- 2018 GCW Extent 2005 GCW Extent 2008 g / GCW Extent 2011 ~/ GCW Extent 2014 ... 0 0 0 / GCW Extent 2017 ~/ GCW Extent 2018 0 C) 0 u, <D "' a, 0 0 0 u, ~ Previous year polygons updated slightly to reflect new negative data . Minimal observed change in GCWI aerial extent from 2 017- 2018. However, GCWiss/owly filling zones vertically. See XS A-A'. ~ / r°' > • .,. I ~ C) C) 8000 Horizon (below BSAD) Elevation depth [ftUS] 716000 720000 "' <D ... CD 0 0 C) -8400 .00 -8800 .00 o 2000 4000 6000 8ooonus ••I I I I 1 66161 P£TitU 4lOOO -SOSO -8 160 -8240 -8 320 -84 00 -8480 Exhibit 10-B GCWI 2018 Extent: Southwest -Northeast Section A southwest northeast A' 02l 28 021n 18104 18·C6S l"Sj~5 U l 24 L2 l26 1.2128 15 1:25 Vertical Exaggeration -SSGO I: 'I J sf.CA,_, r,r • I". :ae::; l OGOC -8,575' ~ Graben 2018 2015 20 13 20 10 2008 20 0 5 2 00 3 GCWI Water First Year Observed Waterflood Water Gas Oil Shale/Low N:G Sag RiverSS Methodology : GCWI Zonal Extent interpretation made by Zone for ZlA, 218, Z2A. Z28, Z2C, Z3 , 24 using current and historical survei llan ce logs. Jf any water seen via logs or production, zone siven a positive GCWI interpretation . Polygons drawn by zone for GCW extent. Interpretation mapped by polygon/zone into FFM grid, shown he re ~ """ -8000 -8080 ] -8160 -8240 -8320 -8400 -8480 -8560 -8640 -8720 -8800 -8880 Exhibit 10-C GCWI 2018 Extent: North -South Cross Section 1:25 Vertical Exaggeration 1 L3f03 L3~10 04~21 04f 20 Waterflood injection area is not the focus of this interpretation. Waterflood water shown here Is schematic and for illustrative purpose only. 2018 2015 2013 2010 2008 2005 20 03 ---• GCWIWater First Year Observed Waterflood Water j ~:s ---+Shale/Low N:G ---+Sag River SS Methodology : GCWI Zonal Extent interpretation made by Zone for ZlA, Z1B, llA, Z2B, Z2C, Z3 , Z4 using current and historical surveillance logs. If any water seen via logs or production, zone given a positive GCWI interpretation. Polygons drawn by zone for GCW extent. Int erpretation mapped by polygon/zone into FFM grid, shown here. P£TRE C Exhibit 11-A to 2018 Annual ReseNoir SuNeillance Report Prudhoe Oil Pool, Put River Oil Pool STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION ANNUAL RESERVOIR PROPERTIES REPORT l . Operator: 2 . Address: BP El<DIOrallon (Al .. ka) lne 900 E. S.,,,5,0n BlvG . Ancllorag,,. AK 99519-6612 J. Aekl and 4 .Pool S.ROfa~ncc 6. 7.Porv•lly e. 9 Sv.i ("-) 10 Oil 11 .011 12. 0rj9lna l 13,&bble 14 C1Jrn,nl 15. 0,1 16,Gu 17. Gr.>ss 18. Ne!P:iy 19. Orjglnal 20. Bubble 21 .Gas 22.0 rigiNJ 23. C..rrem Pool Code: Name Datum(ft Temper:au,re (%) Permeability Viscosity@ Viscosity@ Pressure Point or Dew Reservoir Gravity Specific Pay (ft) (ft) Formation Po!n, Comprauabtl GOR GOR TVDSS) ("F) (md) Original Saturation (psi) Point Pressure ("API) Gravity (Air Volume Fo rmation ltyFactor(Z) (SCF/ST8) (SCF/STB) Pressure Pressure Pressure (psi) = 1.0) Factor Volume (cp) (cp) (psi) (RB/STB) Foa« (RB/STB) 6<0150 Pru<1hoeO I 8800 200 22 .2115 30 o .. &1 081 433S 4335 3360 29 o.n 600 475 1,4 , .. 0 .8r.t 730 40403 6<0182 Pul River Oil 9100 182 19 173 46 1.84 NA 4163 2815 4297 26 .9 NA 30 2D 1.293 NA NA !,48 asss I hereby certify that the foregoing is true and correct to the besl of my knowtedge- Signature Gerda Stechauner Title Reservoir Engineer canntod Name Gerda Stechauner Date 2/11/2019 .... ,., ,-i ... I Exhibit 12 Put River Sandstone Distribution \. ltfl~ofll.&ftl)jl,!1 .. l-"1'1'••1HC l GROSS PUT RIVER 55 r CI=l0 / I I -·~·· -. • ~ ,I ' ' • '· ' / ·, Note: Current producers at Ds-02 are 02-23A and 02-27 A