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Home My WebLink About2019 CINGSA Cook Inlet Natural Gas Storage Alaska, LLC 2020 Annual Material Balance Analysis Report To Alaska Oil and Gas Conservation Commission (AOGCC) May 15, 2020 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 2 Cook Inlet Natural Gas Storage Alaska, LLC 2019-2020 Storage Field Injection/Withdrawal Performance and Material Balance Report Executive Summary/Conclusion Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) filed an application with the Alaska Oil and Gas Conservation Commission (AOGCC) on July 27, 2010 for authority to operate the Cannery Loop Sterling C Pool to provide underground natural gas storage service. In that application, CINGSA requested authority to store a total of 18 Bcf of natural gas, including 7 Bcf of base gas and 11 Bcf o f working gas. CINGSA estimated that this initial phase of development would result in a maximum average reservoir pressure of approximately 1520 psia based upon the original material balance analysis of the reservoir, all as more fully described in the application. By Order dated November 19, 2010, AOGCC issued Injection Order No. 9 (SIO 9) granting CINGSA the authorization sought in its application and limiting the maximum allowed reservoir pressure to 1700 psia. In April 2014, CINGSA subsequently applied to the AOGCC requesting authority to increase the maximum reservoir pressure to the original discovery pressure of 2200 psia. By Order dated June 4, 2014, the AOGCC issued Injection Order No. 9A, granting CINGSA the authorization sought in its April 2014 application. Pursuant to SIOs 9 and 9A, An annual report evaluating the performance of the storage injection operation must be provided to the AOGCC no later than May 15. The report shall include material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes. This is the eighth such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012 and has now completed eight full years of operation. This report documents gas storage operational activity during the past twelve months and includes monthly net injection/withdrawal volumes for the facility and total inventory at month-end. A plot of the wellhead pressure versus total inventory of the field since commencing storage operations is contained in this report; the plot demonstrates that the pressure versus inventory performance is generally consistent with design expectations, although actual pressure has trended above design expectations . CINGSA believes the reason for this is related to an isolated pocket (separate reservoir) of native gas, believed to be at or near native pressure conditions, which CINGSA encountered when it perforated/completed the CLU S-1 well. This gas has since commingled with gas in the depleted main reservoir and provides pressure support to the CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 3 storage operation. Based upon currently available data, the estimated volume of gas associated with the separate reservoir is approximately 14.5 Bcf, which remains consistent with past conclusions. This report also documents the injection/withdrawal flow rate performance of each of the five wells. CINGSA conducted a back-pressure test on CLU S-3 in November 2019. The test results indicate that its performance has improved significantly since it was last tested in September 2017. Overall, field deliverability appears to have improved because of the clean out and re-perforating of the CLUS-3 well in April 2018. CINGSA should continue to periodically back-pressure test all five of its storage wells. A 2-3-year rotational basis should be adequate to confirm that all wells are performing consistently, and with no loss of deliverability capability. Following that protocol, CLU S-1, CLUS-4, and CLU S-5 should be tested in 2020. The test results may also provide an early indication of a loss of storage well integrity if a loss of integrity were to occur. At this time, there is no evidence of a decline in deliverability of any of the wells related to a loss of wellbore integrity. Consistent with standard operations, two planned facility shutdowns were conducted during the past twelve months, each approximately one week in duration. The first shutdown occurred during October 2019 and the second during the first full week of April this year. The purpose of these two shutdowns was to suspend injection/withdrawal operations so that each well could be shut-in for pressure monitoring and to allow reservoir pressure to begin to stabilize. The well shut-in pressure data was analyzed via graphical material balance analysis. The pressure versus inventory relationship of the field is consistent with historical performance and does not indicate any evidence of a loss of storage gas or reservoir integrity. These results support the conclusion that all the injected gas remains confined within the reservoir. The CINGSA facility operates with two custody transfer meters , one of which is connected to the “CINGSA lateral” and the other to the KNPL pipeline. Monthly calibration checks are performed on both meters to confirm they are performing within the manufacturer’s specifications. A loss of calibration could result in a measurement error impacting storage inventory and necessitate an adjustment to inventory. No adjustments to storage inventory were required during the period April 2019-April 2020. Each well that penetrates the cap rock of the Sterling C Gas Storage Pool could conceivably be a leak path for injected storage gas. If a loss of wellbore integrity were to occur in a well that penetrates the storage formation, it could manifest itself vi a a rise in the annular pressure of that well. Direct evidence of a loss of integrity could include, but may not be limited to, annulus pressure equal to the storage operating pressure and/or cyclic pressure behavior that matches that of the injection/wit hdrawal wells. This report includes a summary of shut-in pressures recorded on the annular spaces of each of the CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 4 CINGSA storage wells and select annular spaces of the 13 third-party wells which penetrate the Sterling C Gas Storage Pool. Based upon a review of the available information associated with wells which penetrate the storage formation at the time of this report, there is no evidence of any gas leakage from the Sterling C Gas Storage Pool. This analysis also included a review of historical production data from the 13 third-party wells noted above which penetrate the Sterling C Pool. Only seven of the thirteen wells remain on production; the other six are either listed as “suspended” or have been plugged and abandoned. Of the seven which remain on production, five are completed in and producing from the Beluga formation, which is immediately below the Sterling C Storage Pool. The remaining two are completed in and producing from the deeper Tyonek formation. Based upon a review of the production history of all seven wells, there is no evidence which suggests production is being influenced by CINGSA’s gas storage operations. In summary, operating data generally supports the conclusion that reservoir integrity remains intact, and although the reservoir is now effectively functioning as a larger reservoir due to encountering additional native gas in the Sterling C1c int erval of the CLU S-1 well, all of the injected gas appears to remain within the greater reservoir and is accounted for at this time. 2019-2020 Storage Operations The 2019-2020 storage cycle covers the period from April 22, 2019, the final day of the 2019 spring semi-annual shut-down, through April 13, 2020. Total inventory at April 22, 2019 was 13,587,409 Mcf.1 Table 1 lists the remaining native gas-in-place as of April 1, 2012, net injection/withdrawal activity by month during the past 96 months, and the total gas-in-place at the end of each month since storage operations commenced. Note that the figures listed in Table 1 only include total inventory and have not been adjusted to include the 14.5 Bcf of additional native gas associated w ith the isolated reservoir encountered by CLU S-1. The reservoir’s pressure vs. gas-in-place (total inventory) relationship has been monitored on a real-time basis since the commencement of storage operations to aid in identifying a loss of reservoir integrity. This type of plot is widely used in the gas storage industry. By tracking this data on a real-time basis, it’s possible to detect a material loss of reservoir 1 Throughout this report, the term “Total Inventory” refers to the sum of the base gas in the reservoir plus the customer working gas in the reservoir. Total Inventory does not include the native gas CINGSA discovered when drilling the CLU S -1 well. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 5 integrity. CLU S-3 was shut-in for most of the summer of 2012 and for a shorter period in 2013 so that wellhead pressure could be recorded for this purpose; thereafter it has been shut-in periodically to confirm the pressure versus inventory trend has remained consistent. Figure 1 is a plot of the actual wellhead pre ssure readings from CLU S-3 versus total inventory from April 1, 2012 through April 13, 2020 (again, excluding the 14.5 Bcf of native gas in the isolated reservoir). This plot also includes the expected wellhead pressure versus inventory response based on CINGSA’s initial storage operation design and computer modeling studies of the reservoir. The actual shut-in pressure of CLU S-3 initially aligned with simulated pressure from the modeling studies. However, at total inventory levels above approximately 11 Bcf, the shut-in wellhead pressure on CLU S-3 has been consistently higher than expected when compared to predicted shut -in pressure derived from initial computer modeling studies. The shut-in pressure readings have been trending approximately 350 psig above the Stabilized Wellhead Design Pressure. This higher observed pressure of CLU S-3 is attributable to an influx of a portion of the 14.5 Bcf of native gas that CINGSA encountered when it completed the CLU S -1 well. The overall trend of the wellhead shut-in pressure of CLU S-3 versus total inventory plot has maintained a consistent and predictable linear trend; the trend supports the conclusion that there currently is no evidence of gas loss associated with storage operations, nor any other loss of well or reservoir integrity. Well Deliverability Performance The CINGSA facility is equipped with a robust station control automation and data acquisition (SCADA) system, which includes the capability to monitor and record the pressure and flow rate of each well on a real time basis. Monitoring well deliverability is an important element of storage integrity management because a decline in well deliverability may be symptomatic of a loss of well integrity . It may also be an indication of wellbore damage caused by contaminants such as compressor lube oil, or formation of scale across the perforations, etc. Throughout the injection and withdrawal seasons, the deliverability of each well has been monitored via the SCADA system so that individual well flow performance could be tracked against past performance and the results of prior back-pressure tests performed on each well. Well CLU S-1 continues to exhibit the strongest deliverability capability of all five wells, contributing an average of about 42 percent of the field flow during withdrawals. Wells CLU S-2, S-3, and S-4 have historically contributed up to approximately 18, 24, and 12 percent, respectively. Well CLU S-5 contributes only about 1-6 percent of the total flow depending on the amount of water in the wellbore. Since converting the field to storage, this well has consistently exhibited a tendency to water -off during the withdrawal season, and this past season was no exception. The CLUS-5 well was used on a nearly continuous CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 6 basis during the 2019-2020 withdrawal season, unlike prior years when the well was typically opened when demand was higher and shut-in to allow pressure to recover when demand tapered off. This mode of using the well appeared to have worked satisfactorily since the well has exhibited a tendency of loading up with water as reservoir pressure declined; the well remained capable of flow and withdrawal rates increased after shutting it in and allowing pressure to recover. This well has not been used for injection since 2017 due to its tendency to water-off during withdrawals, although it was used for injections during August 2019 to reduce discharge pressure while the CLUS-3 well was unavailable for injections. The CLUS-5 well is scheduled to be retro-fitted this year with a velocity string to aid in removing water from the wellbore. While its overall contribution to flow is relatively small, loss of the well due to water encroachment nonetheless imposes a greater demand load on the remaining wells. CINGSA conducted a back-pressure test on CLU S-3 in November 2019. The test results indicate that its performance has improved significantly since it was last tested in September 2017. Deliverability from the S-3 well increased 2-3-fold since September 2017. This improvement in deliverability is attributable to the clean out and re- perforating work performed on the well in April 2018. Back-pressure test results indicate this well should contribute approximately 15 -20 percent of the total flow from the field, and actual flow data supports that figure. Thus, the back-pressure test process and results generally represent a good proxy for what may be expected in terms of actual well deliverability. CLUS-3 Well Operations 2019-2020 Injection/Withdrawal Seasons The CLUS-3 wellbore loaded up with water and sand in March of 2018, late in the withdrawal season. A coiled tubing clean out was performed in April 2018. Immediately prior to the clean out the subsurface safety valve (SSSV) was removed and a protective sleeve was inserted in its place, as per standard procedure. CINGSA was unable to remove the protective sleeve using conventional methods upon completion of the clean out work. As a result, CINGSA was prohibited from using the well for injections without a functioning SSSV, per AOGCC regulation. The lack of availability of the CLUS-3 well during injections did not result in any restrictions to customer injections because nominated flows were well within the injection capability of the remaining wells. The protective sleeve was ultimately extracted from CLUS -3 in late October 2018 after milling the upper portion of the sleeve. The milling process resulted in some minor damage to the safety valve landing nipple which holds SSSV in place, requiring the landing nipple to be replaced. That work was completed in October 2019 and the sub - surface safety valve was reinstalled and successfully tested, per AOGCC requirements. The well was returned to service immediately thereafter and has since been used for injections and withdrawals. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 7 2019 Injection Season Operations and October 2018 Shut-in Pressure Test The field was released for resumption of active storage operations on April 22, 2019. During the remainder of April, the field was used mainly for withdrawals. Steady net injections began around mid-May and continued until mid-August. Monthly net injection totals ranged from about 500-800 mmscf, which is typical. Thereafter, storage operations consisted mainly of modest withdrawals. The field was shut-in for pressure stabilization on October 21, 2019. The shut-in pressure stabilization period extended from October 21-28, 2019. Total gas inventory at October 21 was 15,000,096 mscf, including 8,000,096 mscf of customer working gas plus 7,000,000 mscf of CINGSA base gas. Table 2 lists the wellhead shut- in pressure for all five wells each day during the shut -in period. It also lists the day-to- day decline in pressure and the overall weighted average pressure of all five wells . On the final day of shut-in, wellhead pressures ranged from a low of 1423.4 psig on CLU S- 3 to a high of 1508.3 psig on CLU S-1. Wellhead pressures did not fully stabilize during the week-long shut-in; average field pressure on the final day of shut-in was still increasing at a rate of 0.6 psi/day. Figure 2 is a plot of the shut-in wellhead pressure of each well and the weighted average wellhead pressure for all five wells. The weighted average wellhead pressure on October 28th was 1499.6 psig and the average reservoir pressure was 1698.9 psia. Table 4 provides a summary of the surface and reservoir pressure conditions and the total gas-in-place at the time the reservoir was discovered. It also lists the same data for the 16 shut-in periods since commencement of storage operations. Lastly, it lists th e gas specific gravity, the percentage of nitrogen and carbon dioxide contained in the storage gas, reservoir datum depth, and reservoir temperature. NOTE, no adjustment has been made at this time to CINGSA’s accounting records nor to the Total Gas -in-Place figures listed in Table 4 to reflect the additional native gas encountered in the isolated reservoir. Table 5 is a modified version of Table 4; this version has been adjusted to reflect the Total Gas-in-Place as if the Sterling C Pool and the isolated reservoir are connected and functioning as a single larger reservoir. Thus, the Total Gas-in-Place listed in Table 5 reflects the storage inventory currently listed in CINGSA’s accounting records plus an additional 14,500,000 mscf (14.5 Bcf) of native gas associated with the isolated reservoir. Figure 4 is a plot of the average bottom hole pressure adjusted for compressibility (BHP/Z) versus gas-in-place during each of the 16 shut-in pressure tests compared to the original discovery pressure conditions. Linear regression analysis of these 1 6 data points indicates there is a strong and consistent linear correlation between reservoir pressure and inventory (gas-in-place); the regression coefficient (R2) is 0.957. In other words, since CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 8 commencing storage operations in April 2012, the reservoir pressure versus inventory relationship has exhibited a very consistent and repeatable pattern. Note, the observed BHP/Z values for all 16 shut-in periods (November 2012 and each subsequent spring and fall shut-in through this April) in Figure 4 plot above the original pressure-depletion line. The reason for this is that there has been no adjustment in this plot to account for the 14.5 Bcf of additional native gas encountered by the CLU S-1 well. 2019-20 Withdrawal Operations and April 2020 Shut-in Pressure Test After the fall shut-in test, CINGSA’s customers resumed injections for the remainder of October and mostly through November and December, albeit at low rates. Steady withdrawals from the field began during the first week of January and continued through the month. Net withdrawals during January, February and March were approximately 1,900 mmscf, 800 mmscf and 600 mmscf, respectively , with January’s figure being the largest ever monthly withdrawal from the facility. Overall withdrawals were similar in volume this withdrawal season relative to the 2018-2019 season. Field Operations reported that approximately 575 barrels of water were produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of April 6th and remained shut-in until the morning of April 13. Total inventory at April 6 was 11,822,427 Mcf, which included 4,822,427 Mcf of customer working gas and 7,000,000 Mcf of CINGSA-owned base gas. Table 5 lists the wellhead shut-in pressure for all five wells each day during the shut -in period. It also lists the day-to-day change in pressure and the overall weighted average field pressure. On the final day of shut-in, wellhead pressures ranged from a hig h of 1,301.2 psig on CLU S-5 to a low of 1,151.8 psig on CLU S-1. Field average pressure had not stabilized but was still building at a rate of about 1.2 psi/day on the final day of shut-in. Figure 3 is a plot of the shut-in wellhead pressure of each of the five wells and the overall field weighted average wellhead pressure . The overall field average wellhead pressure on April 13th was 1,225.6 psig and the average reservoir pressure was 1,390.2 psia. Table 6 provides a summary of the surface and reservoir pressure conditions and the total gas-in-place at the time the reservoir was discovered. It also lists the same data for the 16 shut-in periods since commencement of storage operations. Lastly, it lists the gas specific gravity, the percentage of nitrogen and carbon dioxide contained in the storage gas, reservoir datum depth, and reservoir temperature. Figure 4 is a plot of the average bottom hole pressure adjusted for compressibility (BHP/Z) versus gas-in-place for each of the 16 shut-in pressure tests as compared to the original discovery pressure conditions. Linear regression analysis of these 16 data points indicates there is a strong linear correlation between the points; the regression coefficient (R2) is 0.957. Thus, like Figure 1, Figure 4 strongly supports the conclusion that CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 9 reservoir integrity is intact. The key point to note is that the observed BHP/Z values for all 16 of the shut-in tests since commencement of storage operations are above the original pressure-depletion line, which provides very compelling evidence that integrity is intact, and the reservoir and wells are not losing gas. Figure 5 is a plot of this very same shut -in data but includes the additional 14.5 Bcf of native gas associated with the isolated reservoir. In this plot, t he Sterling C Pool and the isolated reservoir are treated as a single common reservoir which together contained a total of approximately 41 Bcf of gas prior to their discovery (26.5 Bcf in the main reservoir and 14.5 Bcf in the isolated reservoir). A line ar regression analysis of the 16 shut-in points, and assuming the isolated reservoir was at native pressure conditions at the time the CLU S-1 well was completed, yields a regression coefficient (R 2) of 0.968. The strong linear correlation between the shut-in reservoir pressure and total inventory for the two combined reservoirs since the commencement of storage operations provides compelling evidence that there has been no material loss of gas from the reservoir. It also supports the current estimate of additional native gas associated with the isolated reservoir. Thus, Figures 4 and 5 strongly support the conclusion that reservoir integrity is intact, and that there is no evidence of a material loss of storage gas from the storage facility. Estimate of Additional Native Gas Volume As explained in prior annual reports, CINGSA encountered an isolated reservoir of native gas which was possibly still at native discovery pressure when CLU S -1 was initially perforated/completed. Wellhead pressure on the CLU S-1 well rose to approximately 1,600 psi within a few days after completion, while wellhead pressure on the remaining four wells was approximately 400 psi, which was in line with expectations. The C1c sand interval is one of five recognized sand intervals that are common to nearly all the wells that penetrate the Cannery Loop Sterling C Pool. This sand interval was also one of the perforated/completed intervals in the CLU-6 well – the sole producing well during primary depletion of the Cannery Loop Sterling C Pool. Following initial perforation/completion, a temperature log was subsequently run in CLU S-1 to identify the nature and source of the higher pressure. The temperature log exhibited strong evidence of gas influx from the sand interval which correlates to the Sterling C1c sand interval. The higher than expected shut-in pressure and evidence of gas influx strongly suggest the C1c was indeed physically isolated from the other four sand sub - intervals within the Sterling C Pool. It is unknown whether the C1c sand interval was at native pressure (2200 psi) at the time CLU S-1 was completed, or if it had been only partially depleted. If fully isolated from CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 10 the pressure-depleted section of the reservoir, completion of the C1c effectively adds to the remaining native gas in the reservoir. This additional gas also accounts for the weighted average reservoir pressure during each of the twelve field-wide shut-in pressure tests plotting above the original BHP/Z versus gas-in-place line. This previously isolated pocket of native gas provides pressure support to the storage operation and effectively functions as additional base gas. Two independent methods are being used by CINGSA to estimate the volume of incremental native gas encountered by the CLU S-1 well. The first method is based on a material balance analysis which was performed using the shut -in reservoir pressure data gathered during each of the past semi-annual shut-in tests, including the most recent in October 2019, and April 2020, together with observed shut-in pressures from CLU S-3 to estimate the magnitude of additional native gas encountered in the C1c sand interval of CLU S-1. The approach used to analyze this data was to treat the originally defined reservoir and the previously isolated C1c sand interval as two separate reservoirs that became connected during perforation/completion work on the CLU S-1 well. A simultaneous material balance calculation on each reservoir was made in which hydraulic communication was established between the two reservoirs because of completion of CLU S-1 in late January 2012. Gas could migrate between the reservoirs. The connection between the reservoirs was computed by defining a transfer coefficient which , when multiplied by the difference of pressure -squared between the two reservoirs, results in an estimated gas transfer rate. In other words, storage gas is injected and withdrawn from the original reservoir and is supplemented by gas moving from or to the C1c interval according to the pressures computed in each reservoir at any given time. The volume of gas contained in the original reservoir was well defined from the primary production data; initial gas-in-place was determined to be 26.5 Bcf. The volume of gas associated with the C1c sand interval in CLU S-1 and the transfer coefficient was varied to match the observed pressure history using a day-by-day dual reservoir material balance calculation. Figure 6 summarizes the results of the material balance procedure for the C1c sand interval having 14.5 Bcf of original gas-in-place at initial reservoir pressure conditions. It is a graph which illustrates how the simulated bottom hole pressure from the model (Calc BHP) compares to both the observed bottom hole pressure on the CLU S-3 well and the weighted average field pressure during the semi -annual field shut-ins. During most of the shut-in periods, the difference between the simulated bottom hole pressure and the actual observed pressure is less than 50 psi. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 11 Figure 7 illustrates the model-simulated daily gas transfer rate between the main reservoir and the isolated reservoir and, the estimated cumulative net transfer of gas since commencing storage operations. The initial transfer rate was 43 mmscf/d. Thereafter the transfer rate has been a function of the pressure difference between the two reservoirs. Various combinations of C1c sand gas volume and transfer coefficients were explored. A range of C1c sand gas volumes from 14 Bcf to 16 Bcf gave reasonable solutions and can be considered a reasonable range of uncertainty. Given the relative match between observed shut-in reservoir pressure data on CLUS-3 and the semi-annual field average shut-in reservoir pressure, and the reservoir pressure predicted by the dual reservoir model, the value of 14.5 Bcf is the most reasonable estimate at this time. As additional data is obtained, particularly after a significant withdrawal season, this value may be more confidently determined. The second method used by CINGSA to estimate the volume of incremental native gas encountered by CLU S-1 is a three-dimensional computer reservoir simulation model. The initial modeling effort utilized an existing reservoir desc ription/geologic model which was updated in 2014 after the drilling and completion of the five injection/withdrawal wells. It incorporated all available well control data and petrophysical data from electric line well logs, and seismic data that was used to characterize channel boundaries and differentiate possible reservoir versus non -reservoir rock. This simulation work yielded an initial estimate of 18 Bcf of gas associated with the isolated reservoir, or about 3.5 Bcf larger than the dual reservoir model. The 2014 modeling work was updated in 2016 and again in 2017 and 2019. The updated reservoir/geologic model incorporates the results of a more sophisticated seismic analysis which provided insight into the areal extent of the isolated reservoir that was contacted by the CLU S-1. The match between observed pressure and production data versus that computed by the reservoir model was generally within 50 -100 psi (which is considered good-very good) on wells CLU S-1, CLU S-2, CLU S-3 and S-4 over most of the operating history of these wells. The agreement between observed versus computed pressure and production was not quite as good on CLU S-5 (generally ranging between 100-150 psi). The estimated volume of incremental gas associated wit h the isolated reservoir that yielded the best history match was 19.5 Bcf in the 2019 update of the simulation model. This estimate is some 5 Bcf greater that the highest estimate using the dual reservoir model. In comparing the results of the two model ing methods discussed above, there is relatively good agreement between the two, with the range of “found gas” falling between 14 -19.5 Bcf. This difference is relatively small, particularly considering the full working gas inventory has never been cycled since placing the reservoir into storage service and the relatively limited extent of the isolated reservoir that is in contact with the CLUS -1 well. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 12 With greater cycling of the working gas capacity it’s possible that the difference in the estimated additional native gas derived using the two different modeling methods may narrow. However, the 14.5 Bcf estimate associated with the dual reservoir material balance analysis appears to be the most reasonable at this time based on the consistent nature of the relatively small difference between the computed versus the actual observed reservoir pressure using the dual reservoir model. Measurement Calibration Checks The CINGSA facility operates with two custody transfer meters, one of which is connected to the “CINGSA lateral” and the other to the KNPL pipeline. The Measurement Department performs monthly calibration checks on both meters to confirm they are performing within the manufacturer’s specifications. If a loss of calibration were to occur resulting in a measurement error impacting storage inventory, Measurement would alert Operations and Gas Accounting and an adjustment to the storage inventory would be posted to correct the measurement error. No adjustments to storage inventory were required during the period April 2019 – April 2020. Compressor fuel usage, station blowdowns, and other losses are accounted for each month and inventory is adjusted, accordingly. These monthly fuel usage and volume adjustments have averaged approximately 1.5 perce nt of the injected volume per month since storage operations commenced, which is generally in line with industry experience. Table 1 provides a summary of the monthly injection/withdrawal volumes, compressor/station fuel usage, and losses since the commen cement of storage operations. Annulus Pressure Monitoring Each of the CINGSA wells were constructed to the highest of industry and regulatory standards including installing tubing set on a packer inside of the production casing. All flow is through the tubing string. This configuration (flow through tubing set on a packer) satisfies international well construction standards listed in ISO 16530, and is consistent with the “double barrier” requirements for flow containment. This configuration meets the Alaska Oil and Gas Conservation Commission’s storage well con struction requirements and exceeds the new PHMSA gas storage well construction requirements. It provides two complete layers of protection against gas loss/leakage from the wellbore. By monitoring pressure in the annulus between the production tubing and intermediate casing, it’s possible to identify a loss of tubing integrity which , if left unchecked, could potentially result in a loss of storage gas. Prior to CINGSA commencing storage operations, all the Marathon Alaska Production Company (now Hilcorp Alaska LLC) wells that penetrate the Sterling C Gas Storage Pool were subjected to AOGCC-mandated Mechanical Integrity Tests (MIT), and all the wells CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 13 successfully demonstrated integrity. Shortly after commencing storage operations, all the CINGSA wells were also subjected to MITs, and they likewise demonstrated integrity. All five of the CINGSA wells were retested in 2016 and again this year immediately after the April shut-in test, and all five wells passed the MIT. Hilcorp’s wells which penetrate the Cannery Loop Sterling C gas storage reservoir are subject to the same periodic MIT’s and are on the same cycle as CINGSA’s storage wells. CINGSA monitors and records pressure on both the tubing/intermediate casing string annulus (7” x 9 5/8”) and intermediate/surface casing string annulus (9 5/8” x 13 3/8”) of each of its wells daily to identify any evidence of loss of well or reservoir integrity. In addition, Hilcorp monitors and records pressure monthly on each of the annular spaces of its production wells which penetrate the Sterling C . Hilcorp also monitors and records pressure on the tubing string in certain wells monthly. Hilcorp provides a copy of this data to CINGSA each month and CINGSA reviews the data for any evidence of a loss of well/reservoir integrity, in the same manner a s it does for its own wells. All these annulus pressure readings are submitted monthly to the AOGCC and are part of routine and ongoing surveillance activities to identify issues which may indicate a loss of integrity of the storage operation. Figures 8-12 illustrate the historical tubing and annulus pressures on each of the CINGSA gas storage wells. Inner annulus pressure (and to a much lesser extent the outer annulus pressure) on all the CINGSA storage wells generally rise s and falls with the tubing pressure, albeit at a lower level. The inner annulus (7” x 9 5/8”) of all five wells is filled with brine and diesel, while the outer annulus (9/58” x 13 3/8”) is filled w ith cement, largely to surface. Thus, a more pronounced pressure swing is observed on the inner annulus than the outer. In both cases, the pressure swing appears to be due entirely to expansion of the 7” casing string which results from higher pressure a nd higher injection gas temperature when injections are occurring. Any annulus pressure which equals the tubing pressure and tracks with changes in the tubing pressure may be indicative of a loss of tubing and/or tubing seal integrity and warrants investigation. Observed annulus pressure on each of the five CINGSA wells has always been less than the tubing pressure. This observation supports the conclusion that tubing, tubing wellhead seal, and the tubing/packer element seals remain intact and there is no evidence of a loss of integrity in any of the five CINGSA wells. Figures 13-25 illustrate similar data on each of the Hilcorp wells that penetrate the Sterling C gas storage pool. Hilcorp drilled and completed a new well in 2019 to the deeper Tyonek formation—the CLU-14 well—and monthly monitoring of the annulus pressure of this well is now included in the overall annulus pressure program. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 14 Except for CLU-5, all the current annulus and tubing pressure readings on the Hilcorp wells are very low (below 200 psi) and do not track the CINGSA well tubing pressure trends. This supports the conclusion that the remaining Hilcorp wells are isolated from the storage interval and do not exhibit any evidence of a loss of storage integrity. Pressure on the 3 ½ inch x 9 5/8-inch annulus on the CLU-5 well began rising in early 2016 and reached a high of almost 850 psig before flattening out. The 9 5/8-inch x 13 3/8-inch (outer) annulus currently exhibits a pressure of about 15 psig. The 9 5/8-inch string penetrates the storage zone and was originally cemented off across the storage interval. However, this well was side-tracked in late 2015. An 8 1/2-inch window was milled through the 9 5/8-inch casing at 6527 feet measured depth (5354’ true vertical depth), which is just below the storage interval in the Beluga formation. A 7 5/8 -inch liner was run through the window, set at a measured depth of 10448 feet on a liner top packer inside the 9 5/8-inch string at a measured depth 6433 feet, and was cemented in place as the new intermediate casing string. A 4 ½ inch liner was ultimately set and cemented in the Tyonek at a measured depth of 12915 feet. A cement bond log was run on the 7 5/8-inch liner, but it was not possible to determine the top of cement behind the 7 5/8-inch string from the log data. CINGSA contacted Hilcorp in May 2018 to understand the source of the pressure on the 3 ½ x 9 5/8-inch annulus, and to determine whether the elevate d pressure could be indicative of pressure communication with its storage operations. Hilcorp agreed to investigate the issue and attempt to blow down pressure on the 3 x 9 annulus of the CLU - 5 well. When the blow down attempt was made the annulus was fo und to be filled to the surface with liquid – no gas was present. Pressure on the 3 x 9-inch annulus began to decline in August 2019, reached a low of about 300 psi, and as of April 1, was at about 420 psi. The source of annulus pressure on this well may be due to a minor wellhead seal leak and/or very possibly to expansion of the liquid in the annulus that is being warmed by the relatively higher temperature production gas. In either case, there is no evidence that the source is related to CINGSA’s storage operations. Based on a thorough review of the annular pressure data for all wells which penetrate the storage formation, there is no evidence of a loss of integrity of any of the CINGSA injection/withdrawal wells, nor a material loss of integrity of any of the Hilcorp wells which penetrate the Sterling C Pool. This data lends additional support to the conclusion that reservoir and well integrity is intact, and all the storage gas remains within the reservoir and is thus accounted for. Third Party Production A review of historical production data from 13 third party wells which penetrate the Sterling C Pool was completed to examine for evidence of pressure and/or flow CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 15 communication from CINGSA’s storage operations. Only seven of the thirteen wells remain on production, all of which are operated by Hilcorp; these include CLU-01RD, CLU-05RD, CLU-07, CLU-08, CLU-09, CLU-13, and CLU-14. The other six are either listed as “suspended” or have been plugged and abandoned. Of the seven which remain on production, five are completed in and producing from the Beluga formation, immediately below the Sterling C Storage Pool. The remaining two are completed in and producing from the deeper Tyonek formation. The production decline curves for all seven wells are included as Figures 26-32; the producing zone associated with each well is indicated on each of these figures. The CLU-8 well was recompleted in September 2019 in the Upper Beluga , apparently after loading up with water in the lower sections of the Beluga. The recompletion consisted of perforating the Upper Beluga at a depth interval of 5188’- 5196’ true vertical depth (TVD). The top of this new perforated interval is approximately 87’ below the base of the Sterling C sands. A cement bond log of the interval from the Upper Beluga across the Sterling C indicates good bond below the Sterling C but not as good across it and above it. Hilcorp shut-in the CLU-8 well in October 2019 coincident with CINGSA’s fall 2019 shut-in test of its storage wells to confirm whether the Upper Beluga is indeed isolated hydraulically from the Sterling C sands. Shut-in wellhead pressure on the CLU-8 well was 1533 psig on October 23. CINGSA’s CLUS-3 well is the closest well to the CLU-8 well (approximately 425 lateral feet away at depth). However, the CLUS-3 well is not completed into the lowest interval of the Sterling C sands (the C2b, which is immediately above the Upper Beluga), and may be hydraulically isolated from the C2b sand. The closest CINGSA well to the CLU-8 that is completed in the C2b is the CLUS-2 well (approximately 760 lateral feet away at depth). Pressure on the CLUS-2 well on October 23 was 1504 psig. While this pressure difference between the CLUS-2 and CLU-8 wells is relatively small, it may be coincidental, and not indicative of hydraulic communication between the Sterling Sands and Upper Beluga. Further analysis of the pressure difference between these two wells will be required in the future as production from the CLU-8 occurs to confirm hydraulic isolation. Hilcorp also provided CINGSA with a flowing material balance chart of the pressure versus production data from the CLU-8 well. Hilcorp’s early material balance calculations via transient analysis indicated a recoverable volume in the Upper Beluga of approximately 1.3 Bcf. Subsequent updates of their analysis have since indicated a trend in growth of the recoverable volume; as of the first week of April, they reported a recoverable volume of approximately 2.25 Bcf . This growth trend may be attributable to complex sand characteristics or poorly connected reservoir quality rock in the Upper CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 16 Beluga and completely unrelated to CINGSA’s storage operations. Conversely, it could also be indicative of a weak connection to the Sterling C sands. Currently, the results of Hilcorp’s shut-in pressure test and flowing material balance analysis of the CLU-8 well provide no compelling evidence of hydraulic communication between the Sterling C sands and the Upper Beluga. That said, CINGSA should continue to request periodic updates of the flowing material balance analysis chart from Hilcorp. It is also recommended that CINGSA request a follow-up shut-in test of the CLU-8 well to confirm that its shut-in pressure is indeed declining as production occurs. If any of Hilcorp’s other production wells were acting as a conduit for gas leakage from the Sterling C Pool to either the Beluga or Tyonek formations via a poor cement job behind casing or a lack of casing integrity, it’s likely that production from the offending well would either increase or remain flat for an extraordinary period. The production decline curves from Hilcorp’s wells do not a ppear to exhibit such behavior. Thus, none of their wells appear to be serving as a conduit for leakage of storage gas from the storage formation. Based upon a review of the production history of all seven wells (except for CLU-8 noted above), there is no evidence which suggests production is being influenced from CINGSA’s gas storage operations. Hilcorp drilled a new well in early April, the CLU-15, in mid-April. The target formation of the well is the Beluga formation, immediately below the Sterling C sands. As of the time of issuance of this report, the CLU -15 has not yet been completed, and thus, it is unknown whether the well will be a commercial success. The status of this well will be addressed in future reports when more information is availab le. Rule 3 of AOGCC’s SIO9 Under Rule 3 of SIO 9, CINGSA was required to install and maintain a gas detection and alarm system in the building adjacent to the location of the KU 13-08 plugged and abandoned gas well. It did so in 2012. CINGSA has found compliance with Rule 3 to be problematic. Problems encountered have ranged from third party communication provider issues to a faulty detector, but many callouts are due to no power being supplied to the equipment. CINGSA also believes that several of the faults and possibly the detector failure was due to cycling power to the equipment. CINGSA has responded to Inlet Fish system alarms using the same protocol as the CINGSA facility. Inlet Fish has not accommodated access to their property for afterhours events, deferring to a “more reasonable” meeting time. In many instances when personnel are dispatched to Inlet Fish, access to the panels is obstructed with various equipment that must be moved or worked around. CINGSA personnel have CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 17 arrived onsite while the alarm was annunciating to find Inlet Fish employees performing their jobs as normal instead of evacuating the buildings. Summary and Conclusion CINGSA commenced storage operations on April 1, 2012 and has now completed eight full years of storage operations. All the operating data associated with the CINGSA facility indicate that reservoir integrity is intact. The observed pressure vs. inventory trend is consistent with modeling studies of the reservoir prior to placing the facility i n service, although wellhead shut-in pressure on CLU S-3 has trended above the stabilized pressure line developed from initial computer modeling studies of the reservoir . Overall field deliverability appears unchanged from the 2012-2013 initial storage cycle, assuming operability of all CINGSA’s wells. There is no evidence of a decline in deliverability that may be indicative of a loss of well or reservoir integrity. The CLU S-3 well was back-pressure tested in 2019. Results of that test indicate the deliverability performance of CLU S-3 has improved significantly since its last test in September 2017. This improvement in deliverability is attributable to clean-out and reperforating work performed on the well in 2018. During initial completion of the CLU S-1 well, an isolated pocket of native gas was encountered within the Sterling C1c sand interval. This gas has since commingled with gas in the main (depleted) portion of the reservoir, effectively add ing to the remaining native gas reserves and providing pressure support to the storage operation. This additional gas is functioning as base gas and accounts for the higher than expected shut - in wellhead pressure readings on CLU S-3 and the field-wide shut-in pressures observed during each of the eight shut-in periods. Two independent methods have been used to estimate the volume of incremental native gas encountered by CLU S -1. The two methods yield comparable estimates of the volume of this additional native gas of approximately 14.5 Bcf. CINGSA performs semi-annual shut-in pressure tests on the reservoir and conducts an annual material balance analysis using that shut -in pressure test data. A total of 16 shut- in tests have been performed since commencement of storage operations. The field weighted-average shut-in pressure versus inventory relationship during the 16 semi- annual shut-in pressure tests conducted since converting the field to storage service exhibit a strong linear correlation (R2 = 0.957). Thus, the results of these shut-in pressure tests support the conclusion that no loss of gas from the reservoir is occurring, and that all the injected gas remains within the storage reservoir. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 18 Annulus pressure readings on all the CINGSA wells demonstrate confinement of storage gas to the reservoir; none of the CINGSA wells exhibits anomalous annular pressure. Annulus pressure readings on each of Hilcorp’s production wells which penetrate the Sterling C Gas Storage Pool also support the conclusion that well mechanical integrity remains intact in each of Hilcorp’s wells; there is no evidence of pressure communication between the storage reservoir and Hilcorp’s production wells. CINGSA should continue to monitor the pressure of all the Hilcorp wells for any change in character which may be indicative of a loss of storage integrity. Ongoing production from Hilcorp’s wells which penetrate the gas storage pool but are completed in the Beluga and Tyonek formations below it was evaluated to examine for evidence of production support from CINGSA’s storage operations. Seven wells which penetrate the storage field remain on production. There is no compelling evidence of production support from CINGSA’s operations, however, CINGSA should continue to monitor production from the CLU-8 well due to its recent recompletion in the Upper Beluga, immediately below the Sterling C Storage Pool. Currently, production operations appear to be fully isolated from gas storage operations. During initial storage operations, the CLU S-3 well remained largely shut-in and wellhead pressure readings from it were routinely recorded and used to track the field pressure versus inventory relationship. This practice largely ceased in 2014 in favor of utilizing all wells for injections/withdrawals. CINGSA should consider periodically reinstating this practice for short periods of time as a prudent reservoir integrity monitoring practice. A short field-wide deliverability test was performed during March 2015 at a storage inventory level of approximately 4.6 Bcf. The test results effectively confirmed the field can meet the aggregate MDWQ obligations of CINGSA’s customers at a working gas inventory of approximately 4.6 Bcf. Since that time CINGSA has implemented revised drawdown guidelines to mitigate the potential for wells loading up with sand and/or watering off. The revised drawdown guidelines effectively limit the withdrawal capability of the field relative to its capability under the original drawdown guidelines. CINGSA should consider performing similar field-wide deliverability tests in the future to validate withdrawal system capability. CINGSA has a policy which requires the periodic testing and calibration of its custody transfer measurement system. The policy specifies that a health check be performed monthly for all ultra-sonic measurement systems such as the type installed at the CINGSA facility. Operations personnel confirmed that these monthly tests have been performed routinely and that no adjustments to meter volumes were necessary during the past 12 months. There is no evidence of any material measurement error based on the results of the material balance analysis. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 19 Based upon a thorough review of available operating data, storage reservoir integrity remains intact. Although the reservoir may now be effectively larger than expected due to encountering additional native gas in the Sterling C1c interval of the CLU S -1 well, all the injected gas remains with the greater reservoir and is accounted for at th is time. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 20 Table 1 – Monthly Injection and Withdrawal Activity Month Injections - Mcf Withdrawals - Mcf Compressor Fuel &Losses Total Gas in Storage - Mcf Mar-12 0 0 3,556,165 Apr-12 146,132 394 2,289 3,699,614 May-12 1,238,733 1,163 11,540 4,925,644 Jun-12 1,245,041 1,048 16,769 6,152,868 Jul-12 986,472 714 12,529 7,126,097 Aug-12 1,245,260 93 14,038 8,357,226 Sep-12 1,300,153 982 13,221 9,643,176 Oct-12 1,624,167 691 15,285 11,251,367 Nov-12 165,866 72,417 4,895 11,339,921 Dec-12 379,205 470,886 5,839 11,242,401 Jan-13 496,560 209,334 7,976 11,521,651 Feb-13 1,765,296 858 19,372 13,266,717 Mar-13 667,603 554,597 7,594 13,372,129 Apr-13 438,717 254,734 6,315 13,549,797 May-13 509,694 12,769 7,680 14,039,042 Jun-13 615,458 1,274 11,185 14,642,041 Jul-13 468,599 822 12,118 15,097,700 Aug-13 499,748 3,392 11,766 15,582,290 Sep-13 306,323 16,743 9,074 15,862,796 Oct-13 530,289 27,585 10,287 16,355,213 Nov-13 9,608 902,874 214 15,461,733 Dec-13 5 1,156,534 61 14,305,143 Jan-14 261,325 127,655 7,352 14,431,461 Feb-14 4,143 517,884 534 13,917,186 Mar-14 1 766,800 - 13,150,387 Apr-14 97,548 190,563 3,671 13,053,701 May-14 64,435 388,647 1,597 12,727,892 Jun-14 509,445 502,790 7,444 12,727,103 Jul-14 687,386 108,786 11,165 13,294,538 Aug-24 728,130 219 12,423 14,010,026 Sep-24 537,858 4,705 11,712 14,531,467 Oct-14 155,673 189,157 4,477 14,493,506 Nov-14 66,645 291,368 2,126 14,266,657 Dec-14 32,716 380,170 1,897 13,917,306 Jan-15 - 1,104,457 76 12,812,773 Feb-15 - 971,590 288 11,840,895 Mar-15 11,253 719,045 855 11,132,248 Apr-15 99,648 106,458 3,242 11,122,196 May-15 416,773 4,772 10,000 11,524,197 Jun-15 460,797 2,811 9,972 11,972,211 Jul-15 805,820 403 12,120 12,765,508 Aug-15 817,781 527 12,521 13,570,241 Sep-15 590,046 179 12,001 14,148,107 Oct-15 532,624 13,990 11,159 14,655,582 Nov-15 286,336 283,937 5,958 14,652,023 Dec-15 267,908 210,747 5,989 14,703,195 Jan-16 192,325 235,414 5,523 14,654,583 Feb-16 242,504 167,856 5,852 14,723,379 Mar-16 193,549 165,556 3,621 14,747,751 Apr-16 887,796 12,785 9,970 15,612,792 May-16 807,600 66,640 9,628 16,344,124 Jun-16 815,655 499,321 9,553 16,650,905 Jul-16 356,887 136,370 7,744 16,863,678 Aug-16 442,736 134,541 9,013 17,162,860 Sep-16 310,570 351,469 4,015 17,117,946 Oct-16 4,550 454,156 777 16,667,563 Nov-16 189,606 544,376 633 16,312,160 Dec-16 173,058 849,832 3,891 15,631,495 Jan-17 106,318 1,641,030 1,766 14,095,017 Feb-17 63,362 1,043,257 531 13,114,591 Mar-17 107,373 1,270,218 477 11,951,269 Apr-17 261,104 423,606 3,754 11,785,013 May-17 668,488 59,640 8,760 12,385,101 Jun-17 907,436 28,511 10,091 13,253,935 Jul-17 966,690 32,446 10,986 14,177,193 Aug-17 1,115,740 10,710 12,360 15,269,863 Sep-17 331,812 82,700 6,863 15,512,112 Oct-17 225,352 348,377 4,436 15,384,651 Nov-17 193,092 578,271 4,467 14,995,005 Dec-17 457,089 435,777 6,239 15,010,078 Jan-18 89,990 1,012,254 2,006 14,085,808 Feb-18 193,987 857,195 2,935 13,419,665 Mar-18 452,229 234,220 6,758 13,630,916 Apr-18 191,077 392,365 3,365 13,426,263 May-18 161,360 471,695 1,756 13,114,172 Jun-18 819,837 110,434 10,077 13,813,498 Jul-18 919,858 57,356 10,987 14,665,013 Aug-18 949,984 65,379 12,216 15,537,402 Sep-18 614,287 62,221 10,945 16,078,523 Oct-18 698,059 375,131 9,307 16,392,144 Nov-18 677,199 181,701 11,733 16,875,909 Dec-18 321,282 484,572 5,862 16,706,757 Jan-19 65,794 1,644,880 922 15,126,749 Feb-19 143 1,401,125 87 13,725,680 Mar-19 359,739 331,718 5,094 13,748,607 Apr-19 251,075 585,698 5,985 13,407,999 May-19 179,824 234,173 4,405 13,349,245 Jun-19 664,084 90,483 9,957 13,912,889 Jul-19 927,816 120,912 11,955 14,707,838 Aug-19 622,444 88,095 10,849 15,231,338 Sep-19 284,486 262,203 6,568 15,247,053 Oct-19 391,582 514,064 7,921 15,116,650 Nov-19 466,551 409,699 8,517 15,164,985 Dec-19 687,453 500,799 10,257 15,341,382 Jan-20 33,175 1,937,845 787 13,435,925 Feb-20 215,774 1,030,021 2,675 12,619,003 Mar-20 203,541 858,156 3,102 11,961,286 Apr-20 202,521 497,341 4,699 11,661,767 Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Jason Westervelt: 11,822,427 MCF Inventory as of 08:00 on 4/6/20. This does include fuel and station losses. CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 21 Table 2 – October 2019 Wellhead Shut-in Pressure Data Table 3 – April 2020 Wellhead Shut-in Pressure Data Well Name Weight Factor* (Storage Pore-feet = (Por.*net MD*(1-Sw))10/22/2019 10/23/2019 10/24/2019 10/25/2019 10/26/2019 10/27/2019 10/28/2019 CLU S-1 70.235 1498.8 1502.0 1503.7 1505.1 1506.1 1507.1 1508.3 CLU S-2 47.696 1501.5 1504.4 1505.8 1506.5 1507.1 1508.0 1508.3 CLU S-3 24.024 1421.7 1422.3 1422.4 1422.3 1422.4 1423.0 1423.4 CLU S-4 97.011 1493.9 1496.7 1498.2 1499.0 1499.8 1500.6 1501.1 CLU S-5 93.155 1507.5 1507.4 1507.1 1506.6 1506.4 1506.4 1506.7 332.121 Weighted Avg. WHP (WAP)1494.6 1496.5 1497.5 1498.0 1498.4 1499.1 1499.6 Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 WAP Change 1.9 0.9 0.5 0.5 0.6 0.6 Well Name Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 CLU S-1 3.2 1.7 1.4 1 1 1.2 CLU S-2 2.9 1.4 0.7 0.6 0.9 0.3 CLU S-3 0.6 0.1 -0.1 0.1 0.6 0.4 CLU S-4 2.8 1.5 0.8 0.8 0.8 0.5 CLU S-5 -0.1 -0.3 -0.5 -0.2 0 0.3 Wellhead Shut-in Pressures (psig) and Dates Weighted Average Pressure (Day-to-Day Change) Individual Well Pressure (Day-to-Day Change) Weight Factor* - based on Ray Eastwood Log Model Well Name Weight Factor* (Storage Pore-feet = (Por.*net MD*(1-Sw))4/7/2020 4/8/2020 4/9/2020 4/10/2020 4/11/2020 4/12/2020 4/13/2020 CLU S-1 70.235 1130.8 1137.1 1141.2 1144.7 1147.6 1150.0 1151.8 CLU S-2 47.696 1148.1 1153.8 1156.9 1159.5 1161.9 1163.7 1164.6 CLU S-3 24.024 1168.7 1186.8 1201.0 1213.7 1225.4 1236.4 1244.3 CLU S-4 97.011 1212.7 1222.0 1226.4 1228.9 1230.5 1231.5 1231.9 CLU S-5 93.155 1297.0 1299.2 1300.1 1300.6 1301.1 1301.3 1301.2 332.121 Weighted Avg. WHP (WAP)1206.6 1213.4 1217.2 1220.1 1222.6 1224.5 1225.6 NOTE: Red text reflects corected wellhead pressure reading due to fluid in the wellbore. Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 WAP Change 6.8 3.9 2.9 2.4 1.9 1.2 Well Name Day 2 vs. Day 1 Day 3 vs. Day 2 Day 4 vs. Day 3 Day 5 vs. Day 4 Day 6 vs. Day 5 Day 7 vs. Day 6 CLU S-1 6.3 4.1 3.5 2.9 2.4 1.8 CLU S-2 5.7 3.1 2.6 2.4 1.8 0.9 CLU S-3 18.1 14.2 12.7 11.7 11.0 7.9 CLU S-4 9.3 4.4 2.5 1.6 1.0 0.4 CLU S-5 2.2 0.9 0.5 0.5 0.2 -0.1 Wellhead Shut-in Pressures (psig) and Dates Weighted Average Pressure (Day-to-Day Change) Individual Well Pressure (Day-to-Day Change) Weight Factor* - based on Ray Eastwood Log Model CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 22 Table 4 – Shut-in Reservoir Pressure History and Gas-in-Place Summary Table 5– Shut-in Reservoir Pressure History and Gas-in-Place Summary (Adjusted Inventory) Wellhead Pressure - psig.Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Total Gas-in Place - mmscf Date 0 0 10/28/2000 1950 2206 0.8465 2606 26,500 Date Weighted Avg. Wellhead Pressure - psig. Calculated Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Total Gas-in Place - mmscf 11/8/2012 1269.9 1434.9 0.8719 1645.7 11,223.715 4/15/2013 1344.4 1522.35 0.8668 1756.3 13,106.887 11/4/2013 1580.7 1798.1 0.8508 2113.4 16,339.046 4/8/2014 1320.6 1497.7 0.8662 1729.0 13,147.315 10/31/2014 1465.1 1662.3 0.858 1937.4 14,493.502 4/8/2015 1159.6 1315.8 0.877 1500.3 11,123.289 11/8/2015 1499.4 1701.4 0.856 1987.6 14,668.761 3/27/2016 1473.3 1671.6 0.857 1950.5 14,634.101 10/30/2016 1582.4 1792.2 0.853 2100.0 16,667.452 4/10/2017 1212.0 1371.9 0.875 1567.9 11,908.476 10/9/2017 1559.8 1766.5 0.855 2067.3 15,523.158 5/8/2018 1376.1 1557.8 0.864 1803.6 13,424.899 10/8/2018 1621.9 1837.1 0.8517 2157.0 16,081.391 4/22/2019 1370.2 1551.1 0.8647 1793.8 13,587.409 10/28/2019 1499.6 1698.9 0.854 1989.3 15,000.096 4/13/2020 1225.6 1390.2 0.872 1595.0 11,822.427 Gas Gravity:0.56 N2 Conc.:0.3% CO2 Conc.:0.3% Reservoir Temp. (deg. F):105 Datum Depth TVD (ft.):4950 Avg. Measured Depth (ft.):9706 Shut-in Reservoir Pressure History and Gas-in-Place Summary - (No Adjustment for Additional Native Gas) Original (Discovery) Reservoir Conditions Storage Operating Conditions Wellhead Pressure - psig.Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Initial Total Gas-in Place - MMcf Date 0 0 10/28/2000 1950 2206 0.8465 2606 41,000 Adjusted Total Gas-in Place - Est. 14.5 Bcf Found Gas 0 0 10/28/2000 1950 2206 0.8465 2606 41,000.000 11/8/2012 1269.9 1434.9 0.8719 1645.7 25,723.715 4/15/2013 1344.4 1522.35 0.8668 1756.3 27,606.887 11/4/2013 1580.7 1798.1 0.8508 2113.4 30,839.046 4/8/2014 1320.6 1497.7 0.8662 1729.0 27,647.315 10/31/2014 1465.1 1662.3 0.858 1937.4 28,993.502 4/8/2015 1159.6 1315.8 0.877 1500.3 25,623.289 11/8/2015 1499.4 1701.4 0.856 1987.6 29,168.761 3/27/2016 1473.3 1671.6 0.857 1950.5 29,134.101 10/30/2016 1582.4 1792.2 0.853 2100.0 31,167.452 4/3/2017 1212.0 1371.9 0.875 1567.9 26,408.476 10/9/2017 1559.8 1766.5 0.855 2067.3 30,123.158 5/8/2018 1376.1 1557.8 0.864 1803.6 27,924.899 10/8/2018 1621.9 1837.1 0.8517 2157.0 30,581.391 4/22/2019 1370.2 1551.1 0.8647 1793.8 28,087.409 10/28/2019 1499.6 1698.9 0.854 1989.3 29,500.096 4/13/2020 1225.6 1390.2 0.872 1595.0 26,322.427 Gas Gravity:0.56 N2 Conc.:0.3% CO2 Conc.:0.3% Reservoir Temp. (deg. F):105 Datum Depth TVD (ft.):4950 Avg. Measured Depth (ft.):9706 Original (Discovery) Reservoir Conditions Shut-in Reservoir Pressure History and Gas-in-Place Summary - (Adjusted to Account for Additional Native Gas) CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 23 Figure 1 – CLU S-3 Wellhead Pressure versus Inventory CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 24 Figure 2 – October 2019 Wellhead Shut-in Pressures Figure 3– April 2020 Wellhead Shut-in Pressures CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 25 Figure 4 – Material Balance Plot (Unadjusted) CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 26 Figure 5 – Material Balance Plot (Adjusted) CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 27 Figure 6 - Historical and Computed Pressures vs. Rate CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 28 Figure 7 - Estimated Gas Transfer to/from Original Reservoir CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 29 Figure 8 – Annulus Pressure of CLU Storage – 1 Figure 9 – Annulus Pressure of CLU Storage – 2 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 30 Figure 10 – Annulus Pressure of CLU Storage – 3 Figure 11 – Annulus Pressure of CLU Storage – 4 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 31 Figure 12 – Annulus Pressure of CLU Storage – 5 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 32 Figure 13 – Annulus Pressure of Marathon CLU 1 RD Figure 14 – Annulus Pressure of Marathon CLU 3 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 33 Figure 15 – Annulus Pressure of Marathon CLU 4 Figure 16 – Annulus Pressure of Marathon CLU 5 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 34 Figure 17 – Annulus Pressure of Marathon CLU 6 Figure 18 – Annulus Pressure of Marathon CLU 7 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 35 Future 19 – Annulus Pressure of Marathon CLU 8 Figure 20 – Annulus Pressure of Marathon CLU 9 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 36 Figure 21 – Annulus Pressure of Marathon CLU 10 Figure 22 – Annulus Pressure of Marathon CLU 11 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 37 Figure 23 – Annulus Pressure of Marathon CLU 12 Figure 24– Annulus Pressure of Marathon CLU 13 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 38 Figure 25– Annulus Pressure of Marathon CLU 14 Figure 26 – Historical Monthly Production CLU – 01RD Upper Tyonek CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 39 Figure 27 – Historical Monthly Production CLU – 05RD Upper Tyonek Figure 28 – Historical Monthly Production CLU – 7 Beluga CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 40 Figure 29 – Historical Monthly Production CLU – 8 Beluga Figure 30 – Historical Monthly Production CLU – 9 CINGSA Material Balance Report to the AOGCC May 15, 2020 Page 41 Figure 31 – Historical Monthly Production CLU – 13 Figure 32 – Historical Monthly Production CLU – 14