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2018 CINGSA
C< STORAG,-.,7,�� May 15, 2019 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Commissioners 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 RE MAY 15 2019 RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Commissioners: Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) was granted a Storage Injection Order on November 19, 2010 by the Alaska Oil and Gas Conservation Commission, allowing it to operate the Cannery Loop Sterling C Pool for underground natural gas storage service. Per CINGSA's request, the Commission issued an amended Storage Injection Order (SIO) No. 9A, in 2014. Rule 8 of SIO 9A requires that CINGSA annually file with the Commission a report that includes 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. Per Storage Injection Order No. 9.001, the Commission revised the due date for this Report to May 15 of each year. CINGSA has now completed seven full years of operation. The enclosed report, in compliance with Rule 8 of SIO 9A, documents gas storage operational activity during the past eighty-four months and includes monthly net injection/withdrawal volumes for the facility and total gas inventory at month-end. Any questions concerning the attached information may be directed to Richard Gentges at 989-464-3849. Sinc 1 , <3_ J Sims President Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2019 Annual Material Balance Analysis Report To Alaska Oil and Gas Conservation Commission (AOGCC) May 15, 2019 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 2 Cook Inlet Natural Gas Storage Alaska, LLC 2018-2019 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 of 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 seventh such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012 and has now completed seven 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 l5, 2019 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-2 in February 2018. The test results indicate that its performance has improved significantly since it was last tested in July 2012. Overall, field deliverability appears unchanged during the past 12 months. 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-3, and CLU S-5 should be tested in 2019. 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 2018 and the second in April of 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. 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 via 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/withdrawal wells. This report includes a summary of shut-in pressures recorded on the annular spaces of each of the CINGSA storage wells and select annular spaces of the 12 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. CINGSA Material Balance Report to the AOGCC May l5, 2019 Page 4 This analysis also included a review of historical production data from the 12 third party wells noted above which penetrate the Sterling C Pool. Only six of the twelve wells remain on production; the other six are either listed as "suspended" or have been plugged and abandoned. Of the six which remain on production, four 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 six 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 C 1 c interval 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. 2018-2019 Storage Operations The 2018-2019 storage cycle covers the period from May 8, 2018, the final day of the 2018 spring semi-annual shut -down, through April 22, 2019. Total inventory at May 8, 2018 was 13,412,631 Mcf. l Table 1 lists the remaining native gas -in-place as of April 1, 2012, net injection/withdrawal activity by month during the past 84 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 with 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 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 pressure readings from CLU S-3 versus total inventory from April 1, 2012 through April 15, 2019 (again, excluding the 14.5 Bcf of I 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, 2019 Page 5 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 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 indicates 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 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 intermittently during the 2018-2019 withdrawal season, opening the well when demand was higher and closing it in to allow pressure to recover when demand tapered off. This mode of using the well appears to have worked satisfactorily; 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. A continuation of this mode of operation appears warranted — at least until the well can be retro -fitted with a velocity string to aid in removing water from the wellbore. While its overall contribution to flow is relatively CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 6 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-2 in February 2018. The test results indicate that its performance has improved significantly since it was last tested in July 2012. Deliverability from the S-2 well has nearly doubled since it was tested immediately after re -perforating in July 2012. This improvement in deliverability is likely attributable to the well naturally cleaning up with continuous injections/withdrawals over time. 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 2018-2019 Iniection/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 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 nipple be replaced prior to re -installing the SSSV. Replacement of the landing nipple requires the use of a drilling rig and none were available at that time. Consequently, CINGSA requested a waiver from the AOGCC to operate the CLUS-3 well without an SSSV during the 2018-2019 withdrawal season in order to ensure that customer withdrawal nominations could be met during peak withdrawal conditions. The Commission ultimately granted CINGA's request with certain conditions, including: 1. Withdrawal demand from the facility must exceed 60 mmscf/d; 2. The well pad is to be manned for 24-hour operations while the CLUS-3 well is open for withdrawals; 3. The remaining well safety valve system components (low pressure detection device and surface safety valve) must pass a performance test each time the CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 7 CLUS-3 is first returned to service and each time the well is required for withdrawal; and 4. CLUS-3 may not be used for injection service and the waiver approval expires June 1, 2019 and will not be reissued. CINGSA fully complied with all the above requirements. There were several occasions during January and February when withdrawal rates exceeded the 60 mmscf/d threshold. Table 2 and Table 3 provide a summary of the daily storage activity for all five wells during January and February, respectively. The column on the far right illustrates the percent contribution of the CLUS-3 well each day it was used for withdrawals. Daily flow rates typically ranged from 15-24 percent after the first few days of withdrawals. Also, total withdrawals from it during January and February amounted to approximately 10 percent and 9 percent respectively of the total field withdrawals. This data clearly illustrates that clean out operations during April 2018 were successful in restoring the deliverability of the well. Throughout the past 12 months, CINGSA has continued to monitor the integrity of the CLUS-3 well even though the well has not been used for injections and only limited withdrawals. The observed pressure behavior of the 7" x 9 5/8" annulus of CLUS-3 as illustrated in Figure 10 has been largely flat, which is a reflection of the isolated status of the well. This does not indicate a loss of integrity, rather a lack of pressure swing associated with that normally observed during injections and withdrawals. Thus, there are no integrity concerns associated with the observed change in annulus pressure response. CINGSA has completed the engineering and design work associated with replacement of the damaged SSSV landing nipple. It has also started ordering the necessary materials to complete the work. CINGSA anticipates a suitably rated drilling rig will be available during the second half of the year and plans to perform the replacement work at that time. CINGSA expects to return the CLUS-3 well to injection/withdrawal service prior to the beginning of the 2019-2020 withdrawal season. 2018 Infection Season Operations and October 2018 Shut-in Pressure Test The field was released for resumption of active storage operations on May 8, 2018. During the remainder of May the field was used mainly for withdrawals. Steady net injections began in June and continued until the October shut-in test, with monthly totals ranging from a low of about 540 mmcf in September to a high of about 870 mmcf during August. The field was shut-in for pressure stabilization on October 1, 2018 and remained shut-in until the morning of October 8th. Total gas inventory at October 1st was 16,081,391 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 8 mscf, including 9,081,391 mscf of customer working gas plus 7,000,000 mscf of CINGSA base gas. Table 4 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 1579 psig on CLU S-5 to a high of 1664 psig on CLU S-1. It should be noted that the CLU S-5 well remained shut-in for the entire injection season, and this likely accounts for the substantially lower shut-in pressure of this well. Also, pressure on the CLU S-3 well was estimated because the well was out of service at the time of shut-in. Wellhead pressures did not fully stabilize during the week-long shut-in; average field pressure on the final day of shut-in was still declining at a rate of 1.4 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 8t" was 1622 psig and the average reservoir pressure was 1837 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 14 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. 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 6 to reflect the additional native gas encountered in the isolated reservoir. Table 7 is a modified version of Table 6; 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 7 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 14 shut-in pressure tests compared to the original discovery pressure conditions. Linear regression analysis of these 14 data points indicates there is a very strong and consistent linear correlation between reservoir pressure and inventory (gas -in-place); the regression coefficient (R2) is 0.952. In other words, since 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 14 shut-in periods (November 2012 and each subsequent spring and fall shut-in through this April) in Figure 4 plot above the original CINGSA Material Balance Report to the AOGCC May l5, 2019 Page 9 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. 2018-19 Withdrawal Operations and April 2019 Shut-in Pressure Test CINGSA's customers resumed injections for the remainder of October after the fall shut- in test and mostly through November. Steady withdrawals from the field began during the second week of December and continued largely uninterrupted until early March. Overall withdrawals were up this withdrawal season relative to the 2017-2018 season. Net withdrawals from storage during the 2018-2019 winter period amounted to 2,493,982 Mcf. Field Operations reported that approximately 279 barrels of water was produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of April 15'h and remained shut-in until the morning of April 22°d . Total inventory at April 15 was 13,587,409 Mcf, which included 6,587,409 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 high of 1,420.0 psig on CLU S-3 to a low of 1,347.3 psig on CLU S-1. Field average pressure had not stabilized, but was still building at a rate of about 0.9 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 22nd was 1370.2 psig and the average reservoir pressure was 1,551.1 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 14 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 twelve shut-in pressure tests as compared to the original discovery pressure conditions. Linear regression analysis of these 14 data points indicates there is a very strong linear correlation between the points; the regression coefficient (R) is 0.952. Thus, like Figure 1, Figure 4 strongly supports the conclusion that reservoir integrity is intact. The key point to note is that the observed BHP/Z values for all twelve 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. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 10 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, the Sterling C Pool and the isolated reservoir are treated as a single common reservoir which together contained a total of 41 Bcf of gas prior to their discovery (26.5 Bcf in the main reservoir and 14.5 Bcf in the isolated reservoir). A linear regression analysis of the 14 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 (W) of 0.971. 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 C 1 c 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 C I c sand interval. The higher than expected shut-in pressure and evidence of gas influx strongly suggest the Clc was indeed physically isolated from the other four sand sub- intervals within the Sterling C Pool. It is unknown whether the C I c 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 the pressure -depleted section of the reservoir, completion of the Clc 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 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 11 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 2019, together with observed shut-in pressures from CLU S-3 to estimate the magnitude of additional native gas encountered in the C 1 c sand interval of CLU S-1. The approach used to analyze this data was to treat the originally defined reservoir and the previously isolated C 1 c 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 as a result of completion of CLU S-1 in late January 2012. Gas was allowed to 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 C 1 c 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 Bc£ The volume of gas associated with the C I c 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 Clc 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. 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 mmcf/d. Thereafter the transfer rate has been a function of the pressure difference between the two reservoirs. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 12 Various combinations of Clc sand gas volume and transfer coefficients were explored. A range of C 1 c 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 modeling effort utilized an existing reservoir description/geologic model which was updated after the drilling and completion of the five injection/withdrawal wells. This model was again updated in November 2017 and incorporates all available well control data and petrophysical data from electric line well logs. Seismic data was also used to characterize channel boundaries and differentiate possible reservoir versus non -reservoir rock. A history match was then run which spans the operating history of the reservoir, including the entire primary production period and extending through September 2017. A simulation input file was constructed with actual (observed) daily flow from each well, including the CLU -6 well during primary production. The objective was to achieve an acceptable match between the observed flowing and shut-in wellhead pressures and the pressure predicted by the reservoir model. Emphasis was placed on matching the observed pressures during primary depletion, and pressures from October 2012 and beyond (after all five storage wells had been re -perforated and after cleaning up during initial withdrawals). An acceptable match is when the difference between actual pressures versus predicted pressure is less than 100 psi. It was discovered early in the modeling process that some form of external pressure support was necessary to achieve an acceptable history match. Several attempts to provide support via an analytical aquifer yielded unacceptably high rates of water production that did not match historical operating data. A reasonably acceptable history match was ultimately achieved only when additional pore volume outside of the channel boundaries (but within CINGSA's approved storage boundary) was incorporated into the model adjacent to CLU S-1. The match between observed pressure and production data and that computed by the reservoir model was very good on CLU S-1 and CLU S-2, and reasonably good on CLU S-3, but not quite as good on CLU S-4 and CLU S-5. The estimated volume of incremental gas that yielded the best history match was 14.5 Bcf. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 13 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 construction 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 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 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 on each of the annular spaces of its production wells which penetrate the Sterling C, as well as pressure on the tubing string in certain wells. Hilcorp provides a copy of this data to CINGSA monthly and CINGSA reviews the data for any evidence of a loss of well/reservoir integrity, in the same manner as 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 rises 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 with 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 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 14 entirely to expansion of the 7" casing string which results from higher pressure and 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 is always 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 13-24 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 early 2015 to the deeper Tyonek formation—the CLU -13 well—and monthly monitoring of the annulus pressure of this well is now included in the overall annulus pressure program. 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 '/2 inch x 9 5/8 -inch annulus on the CLU -5 well has been rising since early 2016 and is currently almost 850 psig. The 9 5/8 -inch x 13 3/8 -inch annulus exhibits a pressure of about 40 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 '/2 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 31/2x 9 5/8 -inch annulus, and to determine whether the elevated 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 found to be filled to the surface with liquid – no gas was present. Monthly pressure readings on the 3 x 9 annulus of this well have since exhibited a flattening trend. Thus, the source of CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 15 annulus pressure on this well is very likely attributable to expansion of the liquid in the annulus that is being warmed by the relatively higher temperature production gas. 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 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 12 third party wells which penetrate the Sterling C Pool was completed to examine for evidence of pressure and/or flow communication from CINGSA's storage operations. Only six of the twelve wells remain on production, all of which are operated by Hilcorp; these include CLU -01 RD, CLU-05RD, CLU -07, CLU -08, CLU -09, and CLU -13. The other six are either listed as "suspended" or have been plugged and abandoned. Of the six which remain on production, CLU -07, CLU -08, CLU -09, and CLU -13 are completed in and producing from the Beluga formation, immediately below the Sterling C Storage Pool. The CLU- 01RD and CLU-05RD are completed in and producing from the deeper Tyonek formation. The production decline curves for all six wells are included as Figures 25- 30. If any of Hilcorp's production wells were acting as a conduit for gas leakage from the Sterling C Pool to either the Beluga of 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 would remain flat for an extraordinary period. The production decline curves from Hilcorp's wells do not appear to exhibit such behavior. Thus, none of their wells appear to be serving as a conduit for storage gas. Based upon a review of the production history of all six wells, there is no evidence which suggests production is being influenced from CINGSA's gas storage operations. Rule 3 of AOGCC's SIO9 On March 29th, 2017, CINGSA sent a letter to Mr. Goddard regarding the Natural Gas Alarm System installed at the Inlet Fish Producer Plant. On numerous occasions, CINGSA personnel have responded to alarms caused solely by Inlet Fish plant personnel shutting off the power to the monitoring equipment. Under Rule 3, the owner or lessee of the land upon which KU 13-08 is located may prohibit CINGSA's operation and maintenance of the gas detection and alarm system. CINGSA's letter requested clarification as to whether Mr. Goddard wished CINGSA to discontinue monitoring the facilities and requested a response by May 1St, 2017. CINGSA did not receive a response from Mr. Goddard. This issue remains unresolved as of this date. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 16 Summary and Conclusion CINGSA commenced storage operations on April 1, 2012 and has now completed seven 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 in 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 of 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-2 well was back -pressure tested in 2018. Results of that test indicate the deliverability performance of CLU S-2 has improved significantly since its last test in July 2012. This improvement in deliverability is likely attributable to the well naturally cleaning up with continuous injections/withdrawals over time. During initial completion of the CLU S-1 well, an isolated pocket of native gas was encountered within the Sterling Clc sand interval. This gas has since commingled with gas in the main (depleted) portion of the reservoir, effectively adding 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 14 shut- in tests have been performed since commencement of storage operations. The field weighted -average shut-in pressure versus inventory relationship during the 14 semi- annual shut-in pressure tests conducted since converting the field to storage service exhibit a very strong linear correlation (R2 = 0.952). 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. 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 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 17 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. Six wells which penetrate the storage field remain on production. There is no evidence of production support from CINGSA's operations; 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. 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. 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 on a monthly basis 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. 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 C 1 c interval of the CLU S-1 well, all the injected gas remains with the greater reservoir and is accounted for at this time. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 18 Table 1- Monthly Injection and Withdrawal Activity Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwlse) Month Iniections -Mcf Withdrawals -Mcf Compressor Fuel&Losses Total Gas In Storaee-MSF Mar -12 0 0 3,556,165 Apr -12146,132 394 2,289 3,699,614 May -12 1,238,733 1,163 11,540 4,925,604 Jun -12 1,245,041 1,048 16,769 6,152,868 Ju1-12 986,472 714 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 0- 2 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,]17 254,734 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 OR -13 530,289 27,585 10,287 16,355,213 Nov -13 9,608 902,874 214 15,461,733 Deo13 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 728130219 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 - 1,106,457 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 -IS 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 0R-15 532,624 13,990 11,159 14,655,582 Nov -15 286,336 283,937 5,958 14,652,023 0ec-15 26],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 -16807,600 66,640. 9,628 16,344,124 Jun -16 815,655 499,321 9,553 16,650,905 1u1-16 356,887 136,370 7,744 16,863,678 Aug -16 442,736 134,541 9,013 17,162,860 Sap -16 310,570 351,469 4,015 17,117,946 0R-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 -17 307,373. 1,270,218 477 11,951,269 Apr -17 261,104 423,606 3,754 11,785,013 May -17 668,488 59,660 8,760 12,385,101 Jun -17 907,436 28,511 10,091 13,253,935 Ju1-17 966,690 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 -17 225,352 346,377 4,436 15,384,651 N 1 193,092 578,271 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 -18 193,98] 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 Ju1-18 919,858 57,356 10,987 14,665,013 Aug -18 949,984 65,379 12,216 15,537,402 hep -18 614,287 62,221. 10,945 16,078,523 0ct-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 men Wwlarwgz. Mar -19 359,739 331,738 5,094 13,748,60] ^m'yxaf 08:00'on Apr -29' 184,469 31Ct,3g'2' 4(9'411" 13%,587,409. n atigazta, GLNG54 Shue CINGSA Material Balance Report to the AOCCC May 15, 2019 Page 19 Table 2 -January 2019 Well Flow Rates and CLUS-3 Percent Contribution Date AVGWHP PSIG Weill 24 hr '••; MMCF 4hr Wd MMCF VGWHP PSIG Well 24 hr MMCF k4hr Wd VGWHP MMCF PSIG Wella 24hr :.�:� MMCF 4hr Wd VGWHP MMCF PSIG Well4 24hr - MMCF 4hr Wd MMCF VGWHP PSIG We115 24hr MMCF 4hr Wdr MMCF 1/1/2019 1717 19.90 - 1717 7.82 - 1637 - 1717 8.09 3L46 1275 - 1/2/2019 1698' %74 0:89- 1698 3.89, 0.12 1645 - 1697 4.10 2/3/2019 1615, - 31.05 1/3/2019 1624 - 14.91 1624 - 4.92 1640 - 1623 0.22 3.33 1616 2/4/2019 - 1/4/20193S21 25:74 1278 35:31 - 1522 - 13.38 15$3 0.14 - 1521 '9.94 1543 4.18 1/5/2019 1464 - 40.90 1463 - 16.15 1468 - 1.81 1463 - 12.11 1465 9.33 6.03 1/6/201. 1431 2/6/2019 42.53. 1430 22.36 17.16 1429. - 8.13 1430 12961277 12.66 1431. - 5.88 1/7/2019 1320 - 56.16 1319 1282 23.70 1318 - 19.49 1319 17.88 1320 6.45 1/8/2019 1362 6.28 44.12 1362 2.46 18.20 1361 - 15.02 1362 14.90 1176 1363 - 3.20 1/9/2019 1363 - 4204. 1363 1417 17.46 1362 - 13.93 1362 - 11.55 1363 - 2.93 1110/20191359 1338 - 40.12 1359 16.78 1358 - 13.00 1358 - 10.99 1360. 0.11 2.55 1/11/2019 1262 - 52.53 1261 - 22.75 1261 19.35 1261 - 16.38 1263 - 3.65 .1/12/2019 1267 1193 46.40 1266 1288 20.18. 1266 3.36 19.27. 1266 - 13.29 1272. - 2.41 1/13/2019 1381 - 23.13 1381 - 10.16 1306 1387 4.03 1381 4.39 1382 - 1.31 1/14/201 1432 0.03 15.27: 1432 28.01 6.90 1317 - - 1431 0.18 2.87 1484 - 0.68- - 1/15/2019 1400 - 23.70 1399 119$ 10.17 1343 - - 1398 - 6.02 1524 - 0.48 1/16/20191419 - 17.49 1419 1.57 7.69 1349 - 1418 - 3.81 1538 - 1117 1/17/2019 1381 1117 26.91 1381 1118 11.32 1359 - - 1380 1141 7.58 1536 - 1/18/2039 1345 - 31.66 1345 - 13 41 1369.' - 1336 0.55 9.27 1399 - 3.53.. 1/19/2019 1331 - 31.49 1331 - 13.40 1368 - 2.14 1319 1401 9.02 1345 - 2.84 1/20/2019 1265 - .40.94 1264 1197 17.64 1262 - 1930 1273 - 12.95 1354 - 2:51 1/21/2019 1259 - 38.06 1259 16.44 1262 1220 18.04 1259 - 11.31 1260 - 2.22 1/22/2291278 - 0.02 '32.31 1277 - 1413 1269 - 1277 :. '0.02 9.27 1369 - 0.74 1/23/2019 1360 0.05 14.72 1360 1208 7.01 1309 19.11 - 1360 0.06 3.39 1517 - - 1/24/201 - 1385 - 10.47 1386 1.11 5.43 1337 1168. 1385 26.45 Z.54 1513 - .1276. 1/25/2019 1398 0.45 7.43 1398 - 4.30 1374 - - 1398 0.12 1.95 1510 - 1/26/2019 1402 - 8.62 1403 4.53 1408 1165 -1402 - 2.42 1508 30.54: 1/27/2019 1389 14.09 13.17 1389 6.02 1428 - 1388 1197 3.84 1508 - - 2/28/2019 1389 1085 12.11. 1389 - .5.64 1442 5.85 - 1388 3.49 1507 - 1.02 1/29/2019 1398 0.52 6.47 1407 - 3.53 1451 1186 1404 3.62 2.02 1498 - - 1/30/2019 1410 - 7.D6 1410 24.21 3.75 : 1454 - 1410 1179 2.21' 1506 1131 - 1/31/2019 1360 21.31 1360 - 8.75 1455 21.73 1359 - 6.64 1401 - 2.73 Total Mo. Flow 798.21 341.02 154.24 224.87 54.33 1572.68 Daily Average Percent of Total Flow Rate 50.8% 21.751. 9.8% 14.3% 3.5% Table 3 - February 2019 Well Flow Rates and CLUS-3 Percent Contribution Date Weill VG WHP 24hr -+. 4hr Wd PSIG MMCF MMCF Daily Well Readings - 24 Well VG WHP 24hr Inl 4hr Wd PSIG MMCF MMCF hr. AVa. Pressure and Cumulative Wei13 VGWHP 24I hr Inl 4hr Wd PSIG MMCF MMCF Flow Well4 VG WHP 24hr I„. 4hr Wd PSIG MMCF MMCF We115 AVG WHP 24hr 4hr Wdr PSIG MMCF MMCF 2/1/20191283 - 32.99 1283 - 13.67 1339 - 12.28 1283 - 10.51 1284 - 3.39 2/2/2019 1275 3L46 1275 - 13.06.' 1275' - -16.05 1275 - 9.74 1276 - 2.26 2/3/2019 1264 - 31.05 1264 - 12.99 1269 - 6.03 1264 - 9.54 1369 0.64 2/4/2019 1277 25:74 1278 10.97 1260 - 1277 7.67 1488 2/5/2019 1253 - 29.85 1253 12.61 1281 - - 1253 9.33 1491 - - 2/6/2019 . 1277 22.36 1277 - 9.80 12961277 - - - 6.66 1486 2/7/2019 1282 20.72 1282 9.17 1308 1282 - 6.28 1345 - 2.46 2/8/2019 1310 14.90 1310 .6.95 1319 - 1309 4.62 1417 2/9/2019 1309 14.76 1309 - 7.00 1338 - 1304 4.73 1476 - 2/10/2019 1289 0.11 17.80 1289 - 8.41 1347 1279 4.66 .1476 - 2/11/2019 1193 - 33.23 1193 - 14.52 1288 3.36 1189 - 2.78 1284 - 2.62 2/12/2019 1313 0.80 8.18 1333 .2.32 1387 - 1299 4.20 1371 - 0.96- 2/13/2019 1232 - 28.01 1266 - 9.59 1290 - 13.75 1232 - 9.92 1233 - 2.14 2/14/2019 119$ - 31..42 1192. .14.14 1212 14,22 1192 10;81. 1193 - 1.57 2/15/2019 1117 - 39.76 1117 17.91 1117 23.70 1117 - 13.75 1118 - 1.66 2/16/2019 1141 - .33.27 1140 1511 1148 9.80 1141 r 10.86 1196 - 0.55 2/17/2019 1203 0.03 20.30 1203 9.96 1173 - - 1204 - 6.54 1401 - 211812019 1273 0.59.. 7.37 1274 4.72 1197 - - 1274 - 2-66 1447. - 2/19/2019 1247 - 14.76 1247 7.78 1220 - - 1247 5.33 1447 - 2/20/2019 1176 - 27.57 1176 12.93 1216 - 5.79 1175 0.02, 9.31 1251 1.S9 2/21/2019 1208 19.11 1208 - 9.29 1213 - - 1208 - 6.34 1208 1.11 2/2 2/2019 1168. 0:06 26.45 1167 12,38 .1276. - 4.29 '. 1168 8.74 4168 0.02 1.12 2/23/2019 1149 - 27.06 1149 12.71 1242 - 5.13 1149 8.87 1165 - 0.74 2/24/2019 1121 30.54: 1121 14.09 '1197 1122 10.12 1197 0.85 2/25/2019 1086 33.34 1085 15.23 1183 - 5.85 1086 10.88 1086 - 1.02 2/26/20191 1135- - 22.36 1134 10.76 1186 3.62 1135 7.20 1135. 0.02 0.42 2/27/2019 1131 - 24.21 1131 11.24 1179 - - 1131 - 7.94 1131 0.53 2/28/2019 1136. - 21.73 1136 - 10.36 1185 - 1136 7.21 1136 - 0.45 I Otal Mo. tlaw b9U.32 3U9.b/ 123.87 217.20 26.97 1368.04 Daily Average Percent of Total Flow Rate 50.5% 22.6% 9.1% 15.9% 2.0% Daily Percent Contribution of CLUS-3 0.22% 2.35% 9.42% 15.76% 16.27% 15.84% 15.58% 16.87% 18.97% 9.36% 3.63% 21.18% 20.96% Daily Percent Contribution of CLUS-3 16.87% 22.12% 10.00% 5.95% 21.69-A 19.70% 24.49'%, 14.08% 2EtP�! 8.10% 9.42% 8.81% 8.17% CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 20 Table 4 - October 2018 Wellhead Shut-in Pressure Data Weight Factor' - based on Ray Eastwood Log Model Table 5 - April 2019 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures (psig) and Dates Weight Factor• Weight Factor• 15torage Pore -feet = (Storage Pore -feet = Well -Name Will Nam IPor.•net MD•11_Lvdi 10/2/201 110/2018 10/4/2018 10/s 10/6/2018 10/7/201 1018/2018 CLU S-1 70.235 1679.7 1675.7 1672.5 1670.1 1667.7 1664.5 1663.7 CLU 5-2 47.696 1670.9 1666.9 1663.7 1661.3 1658.9 1657.3 1655.7 CLU 5-3 24.024 1630.9 1624.9 1621.7 1619.3 1620.9 1619.3 1618.7 CLU S-4 97.011 1648.5 1639.6 1633.2 1627.6 1623.6 1620.4 1617.2 CLU S-5 93.155 1592.8 1582.0 1581.2 1580.4 1580.4 1578.8 1578.8 332.121 332.121 Weighted Avg. WHP(WAP) Weighted Avg. WHP(WAP) 1365.2 1638.6 1633.9 1630.5 1627.6 1625.7 1623.3 1621.9 NOTE: Red text NOTE: Red text reflects CLUS-3 pressures were estimated based on historical daily shut-in pressure differences work. All relative to CMS- 2'from 2013-2017 readings on CLUS-3 were directly from the tree cap. Weighted Average Pir(D3y-to-Day Chanel Weighted Average Pramre (Dav-to-Dav Chanel Cxy2v C,ay1 Dav3vs.Oay2 Day4vs. Day DayDay4 Day6-DaVS Day7vs Dav6 WAP Change -4.7 -3.5 -2.9 -1.9 -2.4 -1.4 IndividWPuro-Chanel IndHidu IW II Pr ID -t -0av Chanel Well Name Well Name Dav2vDav1 Day3vDay2 Dov4vlDov3 Dov 5 vs. Dav 4 Dav 6 vs. Day 5 Day 7 vs. Day 6 CLU S-1 -4.0 -3.2 -2.4 -2.4 -3.2 -0.8 CLU S-2 -4.0 -3.2 .2.4 -2.4 -1.6 -1.6 CLU S-3 -6 -3.2 -2.4 1.6 -1.6 -0.6 CLU 5-4 -8.9 -6.4 -5.6 -4 -3.2 -3.2 CLU S-5 -0.8 -0.8 -0.8 0 -1.6 0 Weight Factor' - based on Ray Eastwood Log Model Table 5 - April 2019 Wellhead Shut-in Pressure Data Weight Factor' - hazed on Ray Eastwood Log Model Wellhead Shut-in Pressures (psi¢) and Dates Weight Factor• 15torage Pore -feet = Well -Name (Por."net MD•I1-Scall 4116/2019 4/17/201 4/19/2019 4/1912019 4/20/2019 1 019 4L2212019 CLU S-1 70.235 1340.6 1341.9 1343,2 1344.0 1345.6 1345.6 1347.3 CLU S-2 47.696 1347.3 1347.3 1347.3 1349.7 1349.7 1350.5 1351.3 CLU S-3 24.024 1420.0 1420.0 1420.0 1420.0 1420.0 1420.0 1420.0 CLU S-4 97.011 1357.7 1360.1 1362.5 1364.1 1366.5 1368.1 1369.7 CLU S-5 93.155 1386.5 1385.7 1384.9 1385.7 1384.9 1384.9 1384.9 332.121 Weighted Avg. WHP(WAP) 1365.2 1365.9 1366.7 1367.9 1368.7 1369.3 1370.2 NOTE: Red text reflects estimate on 4/17; all wells were isolated from themstrumentetion due to maintenance work. All readings on CLUS-3 were directly from the tree cap. Weighted Average Pramre (Dav-to-Dav Chanel Dav 2 va. Davi Dav 3vs Dav2 Day4vs Dav3 Dav Svs. Dav4 Dav6vs.Dav5 Dav7vs.0av6 WAP Change 0.8 0.8 1.2 0.8 0.6 0.9 IndHidu IW II Pr ID -t -0av Chanel Well Name Dav2 vs Davi Day 3 vs. Da .2 Dav4 vs. Dav3 1) vs Dav4 Dav6vs.DavS Dav7vs Dav6 CLU 5-1 1.3 1.3 0.8 1.6 0.0 1.7 CLU S-2 0.0 0.0 2.4 0.0 0.8 0.8 CLU 5-3 0.0 0.0 0.0 0.0 0.0 0.0 CLU S-4 2.4 2.4 1.6 2.4 1.6 1.6 CLU S-5 -0.8 -0.8 0.8 -0.8 0.0 0.0 Weight Factor' - hazed on Ray Eastwood Log Model CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 21 Table 6 - Shut-in Reservoir Pressure History and Gas- in -Place Summary Gas Gravity: Shut-in Reservoir Pressure History and Gas -in -Place Summary - (No Adiustment for Additional Native Gas) CO2 Con- 0.3% Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): Original IDiscovervl Reservoir Conditions Avg. Measured Depth (ft.): 9706 Wellhead Pressure - psia. Bottom Hole Pressure - psia Z - Factor BHP/Z - psia Total Gas -in piece - mmsd Dae 4/8/2015 1159.6 1315.8 30,839.046 0 O 10/28/2000 1950 2206 0.8465 2606 26,500 25,623.289 4/3/2017 1212.0 1371.9 Storage Operating Conditions 1766.5 29,134.101 Weighted -Avg. Wellhead Calculated Bottom Hole 31,167.452 10/8/2018 1621.9 1837.1 Date Pressure - psie. Pressure - psia Z - Factor SHP/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 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 Con- 0.3% Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): 4950 Avg. Measured Depth (ft.): 9706 Table 7- Shut-in Reservoir Pressure History and Gas- in -Place Summary (Adjusted Inventory) Shut-in Reservoir Pressure History and Gas -in -Place Summary - (Adiusted to Account for Additional Native Gas) Dari Incl (Discowryl Reservoir Conditions Wellhead Pressure - psia, Bottom Hole Pressure - psia Z -Factor SHP/Z - osia Initial Total Gas -in Place - MMcf Date 0 0 10/28/2000 1950 2206 0.8465 2606 41,000 10/28/2000 1950 2206 pJd a ed Total Gas -in P/0-- Est 11/8/2012 1269.9 1434.9 14.58_4f Found Gas 4/15/2013 1344.4 1522.35 11/4/2013 1580.7 1798.1 41,000.000 4/8/2014 1320.6 1497.7 25,723.715 10/31/2014 1465.1 1662.3 27,506.887 4/8/2015 1159.6 1315.8 30,839.046 11/8/2015 1499.4 1701.4 27,647.315 3/27/2016 1473.3 1671.6 28,993.502 10/30/2016 1582.4 1792.2 25,623.289 4/3/2017 1212.0 1371.9 29,168.761 10/9/2017 1559.8 1766.5 29,134.101 5/8/2018 1376.1 1557.8 31,167.452 10/8/2018 1621.9 1837.1 26,408.476 4/22/2019 1370.2 1551.1 30,123.158 Gas Gravity: 1803.6 0.56 N2 Con- 2157.0 0.3% CO2 Con- 1793.8 0.3% Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): 4950 Avg. Measured Depth (ft.): 9706 pJd a ed Total Gas -in P/0-- Est 14.58_4f Found Gas 00 0.8465 2606 41,000.000 0.8719 1645.7 25,723.715 0.8668 1756.3 27,506.887 0.8508 2113.4 30,839.046 0.8662 1729.0 27,647.315 0.858 1937.4 28,993.502 0.877 1500.3 25,623.289 0.856 1987.6 29,168.761 0.857 1950.5 29,134.101 0.853 2100.0 31,167.452 0.875 1567.9 26,408.476 0.855 2067.3 30,123.158 0.864 1803.6 27,924.899 0.8517 2157.0 30,581.391 0.8647 1793.8 28,087.409 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 22 Figure 1 — CLU S-3 Wellhead Pressure versus Inventory 1800.0 1600.0 m w 1400.0 a m 1200.0 N m IL 1000.0 m U 800.0 7 N 600.0 400.0 Me 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmset CINGSA Wellhead Pressure vs. Inventory Hysteresis (Original Reservoir Only) —Initlal Cycle Design —e—Stabilized Wellhead Pressure Design Actual Shut-in Pressure vs. Inventory -CLUS-3 Pressure • Fail 2012 WASIWHP ■ Spring 2013 WASIWHP ■ Fall 2013 WASIWHP Spdng 2014 WASIWHP Fail 2014 WASIWHP Spring 2015 WASIWHP . Fad 2015 WASIWHP + Spring 2016 WASIWHP . Fail 2016 WASIWHP • Spring 2017 WASIWHP Fail 2017 WASIWHP • Spring 2018 WASIWHP Fail 2018 WASIWHP Spdng 2019 WASIWHP 2000.0 1----_-__---_ 1800.0 1600.0 m w 1400.0 a m 1200.0 N m IL 1000.0 m U 800.0 7 N 600.0 400.0 Me 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmset CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 23 Figure 2 — October 2018 Wellhead Shut-in Pressures CINGSA Fall 2018 Wellhead Shut-in Pressures 1690.0 1680.0 1670.0 1660.0 „y --*--CLU StwageI d 1640.0 ____ _— ....__.. 4& -{LU 51-ge2 —CLU Srorage 3 i 1630.0- m _._CLU"_V4 c1620.0 .__.....�._ -. ...-.�.m.:..._..-,,. - _— < _.CLU Stdage 5 m 3 1610.0 - Field Weighted Avg. Press. c 5 r '^ 1600.0 --- 1590.0 ----- 1580.0 x ......____.:: -Y _ - _ �-.—, 1570.0 1560.0 --------r--- 1O/2 10/3 10/4 1015 10/6 10/7 10/8 Shut-in Date Figure 3— April 2019 Wellhead Shut-in Pressures 1440.0 1420.0 m a 1400.0 m 1380.0 d L m 3 c z 1360.0 1340.0 1320.0 4/16 CINGSA Spring 2019 Wellhead Shut-in Pressures 4/17 4/1.8 4/19 4/20 4/21 4/22 Shut-in Date --CLU Storage 1 -d-CLU Storage 2 --CLU St -p 3 --^ CLU Storage 4 CLU Storage 5 -Field Weighted Avg. Press. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 24 FiEure 4 — Material Balance Plot (Unadjusted) Cannery Loop Sterling C Gas Storage Pool - Material Balance Plot November 2012 - April 2019 3,000 2,500 m Q. 2,000 N y 1,500 a` d 0 S E 0 C 1,000 m 500 I # -- — — . 0 5,000 10,000 15,000 20,000 25,000 30,000 Total Gas -in -Place MMcf Discovery BHPJt - 2606 psia Fall 2018Shut-in Pressure = 2157.Opsia t� j Sprang 2019Shut-in Pressure =1793.8 i 1----- f----+ +--- �--- � -�-- � -+-- --- -- -�-Discovery BHPJZ vs. Gas -in -Place -- i j �---, _ � l j � • 2012- 2013 BHPJZ vs. Gas m Place i 2013 - 2014 BHP/Z vs. Gas-in-Place 2014- 2015 BHP/Z vs. Gas -in -Place 2015 - 2016 BHP/Z vs. Gas-in-Place 1 1 ' i 2016 - 2017 BHPJZ vs, Gas -in -Place I, ` y 2017 - 2018 BHPJZ vs, Gas -in -Place -- 2018 - 2019 BHP/Z vs. Gas-in-Place i � t CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 25 flizure 5 — Material Balance Plot (Adiusted) Cannery Loop Sterling C Gas Storage Pool - Preliminary Adjusted Material Balance PLot November 2012 - April 2019 3,000 — i ---- 2,500 Fall 2018 Shut-in Pressure= 2157.0 psia 2,000-}--:—�______.__ 1-- t_— _a a Spring 2019Shut-in Pressure = 1793.8 - �- BHPjZ = 2606 psia I � r - 14.56efAddltion Fai120185hut in Pressf ure 2157-0psia I I ZT_ 1,500 V t Discovm BHP/Z vs. Gas -in -Place } S �.__� ._}__. ,__ } QJ w �� 1 � 1 E+- ?�-- 4-' — o t t • Adjusted 2012 - 2013 8HP/Z vs. Gas -In -Place .�_ •� •_ j- on 1,000 - _ • 2013- 20148HP/Z vs. Gas -in -Place f .� {.._ 500 0 4 0 /Z 2606 Asia l f - �- BHPjZ = 2606 psia I � r - 14.56efAddltion Fai120185hut in Pressf ure 2157-0psia I I ZT_ t Discovm BHP/Z vs. Gas -in -Place } S �.__� ._}__. ,__ r 2012 - 20138HP/Z vs. Gas in Place 1 I i "—f I T- ?�-- —+—Adjusted Discovery BHP/Z vs. Gas -in -Place 1- t t • Adjusted 2012 - 2013 8HP/Z vs. Gas -In -Place .�_ •� •_ j- ��� - _ • 2013- 20148HP/Z vs. Gas -in -Place f .� {.._ i __ • Adjusted 2013 - 2014 8HP/Z—Gas-la-Place 2014-2015 BHP/Z vs. Gas in -Place Spring 2019 Shut-in Pressure 1793.8 , Adjusted 2014 - 2015 8HP/Z vs. Gas -in -Place i r 2015 2016 BHP/Z es. Galin -Place • Adjusted 2015- 20168HP/Z vs. Gas -in -Place �{'__ � I.i ,f 20162017BHP/Z vs. Gasin Place I i • Adjusted 2016- 20178NPJ2 vs. Gas -in -Place I ( • 2017 - 2018 8HP/Z vs. Gas. in- Place -I-,,�--T 7- I -,--.-+. .-�.-,. • Adjusted 2017 - 2018 8HPfZvs. Gas -in -Place ♦ 2018-2019 BHP/Z vs. Gas-in-Place 4-- 6 Adjusted 2018 - 2019 BHP/Z vs. Gas -in -Place 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 Gas -in -Place MMcf CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 26 Figure 6 - Historical and Computed Pressures vs. Rate Figure 1- Historical and Computed Pressures vs. Rate (Based on 14,5 Bcf of "Found Gas") I so oc. 100.00 100.00 -15000 E9 a V& E N111 ��W4�\b�ry�lg\9\�\ P1���,S\��1,\��\ \V \ry1\°���\ti���`'\rye\ 0\T \' ,N \ry�\6��\9��htitiryy\3�6\�� Date —Daily lnj/Wdd Rate - mmscf/d XW S3 BHP- psia" + "Calc BHP - psia° 13 "Obs WASl BHP Avg -psia" 2300 2100 1900 1700 1500 0 a v 1300 g N a a` 1100 e 2 900 700 500 300 100 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 27 Figure 7 - Estimated Gas Transfer to/from Original Reservoir Figure 2 - Estimated Gas Transfer to/from Original Reservoir (Based on 14.5 Bcf of "Found Gas") SO 0C M 0 100.00 150.00 10 o Date ---Gaily dnjjWdd Rate - mfnscfJrl 7ransEer Rate rrmufJA Net Gas Transfected - mmxf a�u 4WO E E v v MOO w c m r` a z 2000 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 28 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, 2019 Page 29 Figure 10 — Annulus Pressure of CLU Storage — 3 Plot of Ibbing mud Annulus Pressure vs Time • CLU S3 2000 —98,8 AnrWus 1800 -- 133/BWOn q& q 1800 _. ______ _ .__ ,--____._ .___. .....-------- - 1400 m1200 — - ._._ ..______r _ _.____ ____ _ ___.-_____.. _ _.. _._.____ .._....--------- .--- --- .. n 1000 -- _ __,_ _.__. .___..._..._. _. a ------------ 800 _,__.____- --------- - ---__.... __ .. ---- `_. ---_. -- ----__-..- ------- 460_____.-------._-- I 200 \112 \i^ry 11R 11^^' 11^x' 1\^, 1\^� 0, " o, ^\�A \\^h o', 1\^h 1\^h 1\^6 \\^6 \116 o' 1\^4 1\^� 11^, \\1� 1\18 o' 1\^8 11^9 1\\9 1l^9 ^\^9 ^\^9 \� o d,P o�P 100 °aP 0SP o1P Ido 04° dP 0�P 1oP 01P d,P °1P 1d° 0,P pp °a\° Ido °11° 0,,P v 1ao 01P 0 01d° 01P 0sP 0�P 10P 01P 0aP Figure 11— Annulus Pressure of CLU Storage — 4 CINGSA Material Balance Report to the AOGCC May l5, 2019 Page 30 Figure 12 — Annulus Pressure of CLU Storage — 5 CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 31 Figure 13 — Annulus Pressure of Marathon CLU 1RD CLU 1RD Annulus Pressure History 140 120 41/2 x 7 CL 100 - 7x95/8 i 80 60 40 U 20 0 titi titi p`ti`'tihti(ti(0ti� ti� 1b00O�tiC)do Month/Year Filzure 14 — Annulus Pressure of Marathon CLU 3 CLU 3 Annulus Pressure History 600 M 500 3 1/2 x 9 5/8 a 400 - :2 300 i d 200 V R N 100 a t eQ at eQ a�' eQ a� �� e`Q roc ep J� ego Joo ems' Jao Qo J� a� `� ,�` `� .1` '� ,�' Q, 4 q• 4 Q � P 4 P << P � Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 32 Figure 15 — Annulus Pressure of Marathon CLU 4 CLU 4 Annulus Pressure History 12 ao 10 —3 1/2 x 13 5/8 Q x-13 5/8 x 20 8 6 i a 4 ' 2 AtLi vs 0 1 'ANY ^y1' I'L ,y`) ^'15 ;it)` IN '�� '�) 'y(° yIb ,y'\ ,yA ,y� 'y00 '�°3 Cee e4 a� eQ 't>� J� e`0 Jho Q`O JQo e`Q J4c e`0 dao e� X00 a� Cee `� `� P 4 P P< P k P 4 P Month/Year Figure 16 — Annulus Pressure of Marathon CLU 5 CLU 5 Annulus Pressure History 1000 800 —31/2x95/8 9 5/8 x 13 3/8 600 m H 400 N d a 200 AEL 0 N -200 ,yh ti(0 tiIb til ti1\ Oe� c' OL� �6, � QQc 6,QQt Pgt' Oe Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 33 Figure 17 — Annulus Pressure of Marathon CLU 6 Fieure 18 — Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 60 --�-31/2 x 9 5/8 •-9 5/8 x 13 3/8 50 WOOA m 40 ar 30 a m 20 u 10 0 06 r� til A o -A' 'Aof aJ �*, �� Qc' � c' � Qc' c Qc' G Month/Year —4 1/2 tbg ■ 11 .! 1 ANEON MEN MEN�-41/2x7-- 0 1/ ■,■■■■.MEM■MEM■ ';; � IMMEMEM� MENS NONE ■ IMEMNON .,, NONE ■o �MOMMEMEM ME MOMEMME ME Fieure 18 — Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 60 --�-31/2 x 9 5/8 •-9 5/8 x 13 3/8 50 WOOA m 40 ar 30 a m 20 u 10 0 06 r� til A o -A' 'Aof aJ �*, �� Qc' � c' � Qc' c Qc' G Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 34 Future 19 — Annulus Pressure of Marathon CLU 8 CLU 8 Annulus Pressure History 120 100 —�— 31/2 x 9 5/8 °Q 9 5/8 x 13 3/8 N p 80 d L C y 50 CLd L 40 20 N O titi^^y�ti°`tih,yhti�ti�til,�A,y'bti� 5p ,y°' AJ 6, PQM d� Month/Year Figure 20 — Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180 140 —31/2x95/8 120 9 5/8 x 13 3/i ONE 100 60 m 40 20 Fe '")-� ,,yon 'yC` ,yh „ h (0 ',�° ,y'1 ,y'1 ,'�� 00 ,' C5 +,yC5 o� �'A of �oma' a"� PQr oL� PQr 4°� Pit o`er PQc ©�� �` ��►^ �� Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 35 Figure 21 — Annulus Pressure of Marathon CLU 10 CLU 10 Annulus Pressure History 60 31/2 x 9 5/8 50 -9 5/8 x 13 3/8 a 40 dl k H 30 N d 20 d U t0 't 10 (n a 0 ti4) yt° ,y(o as p O O Q O P O Month/Year Figure 22 — Annulus Pressure of Marathon CLU 11 CLU 11 Annulus Pressure History 120 mo 100 04 �N 80 60 a —+— 31/2 x 9 5/8 40 u -9 5/8 x 13 3/8 z 20 N � fSJ I 0 94...I........, .. , ... . �,y'L .,'i- Ny y� tib` tib` ti� ti� "y(0 N tiIb l '�A '�� N, N ,y0) aA�oyA�4a�aA 0� Pq OGS PQt Ota PQc' c� PQM Cp- Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 36 Faure 23 – Annulus Pressure of Marathon CLU 12 CLU 12 Annulus Pressure History 30 ��m 9 5/8 Vl 20 d � 3 ' i } a 10 Ivo �i7F�wR�sw��wws��w�*!�'=C= -,A, til Month/Year Fillure 24– Annulus Pressure of Marathon CLU 13 CLU 13 Annulus Pressure History 120 100 — - °' 80 d L 60 d °• 40 2 7/8 x 7 5/8 20 -75/8x103/4 0 ,y<1 (I ;y) ti(0 "y(o tib' ti( til tiA ,�A tiA ,yob y00 ,y(b O, e`Q a� J¢o oJl Q`0 a -A lq of e- ay ,40 of e'a aA 440 Month/Year CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 37 Figure 25 — Historical Monthly Production CLU — 01RD Upper Tyonek 250000 200000 150000 100000 50000 0 (0 ^ ^y1 ,yq� y0) 1 �o ,;o Q, yo Qo Q, ,;o �o �fl �o �fl �o do yo go o �o �o �fl ,�a � �� -, �, '\ ,,\ �^ ^, yy\ 0) �,\ �� moo\ "O\ ti\ ,Yo\ (,\ ,y\ moo\ (,\ -\ CLU -GIRD Upper Tyonek Gas - Mcf/Mo. Figure 26 — Historical Monthly Production CLU — 05RD Upper Tyonek CLU-05RD Upper Tyonek Gas - Mcf/Mo. 250000 200000 /\ _ 150000 1.00000 50000 0 IN ^\ nyA y`1 ^A y00 y10 y4, yCO yIb Cb .0) 0i CINGSA Material Balance Report to the AOGCC May l5, 2019 Page 38 Figure 27 — Historical Monthly Production CLU — 7 Beluga 300000 250000 200000 150000 100000 50000 0 qP D qui q(0 O\ 04, 'y `v CLU -7 Beluga Gas - Mcf/Mo. Figure 28 — Historical Monthly Production CLU — 8 Beluga u�aoo 31.0003 25U0[A] 7tM)IXri) I WOW IOJOJO 500U1 J a" <"a oma='.'.' CLU -8 Beluga Gas - Mcf/Mo. CINGSA Material Balance Report to the AOGCC May 15, 2019 Page 39 Figure 29 — Historical Monthly Production CLU — 9 350000 300000 250000 200000 150000 100000 50000 CLU -9 Beluga Gas - Mcf/Mo. 0VoLAO pp oo 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 p 0 0 0 0 0 0 0 N N N N O O O O O O N N N O N N N N N N N N N N N N N N ry N N N N N N N N N N N N N N N N N N N N N N N N N N N N N e-1 In 1" m C+ m n e-1 N N e-1 H ri �-i N e1 ei N N N r -I N Figure 30 — Historical Monthly Production CLU — 13 35000 30000 25000 20000 15000 10000 5000 CLU -23 Beluga Gas - Mcf/Mo. 0 'Yh tiI tiY by ti� y`/ N ,yam N ,yy �yy ti N �y ti ^r^ "r ^yam .yam .yam .yam ,y`b I y -Y ,y0 �O ,VO ,y0 ,ti0 ,�O ry4 ,v4 ,VO ,y0 ,y0 �O �O O ,�O ,ti0 ,yd �Q ,y0 ,vQ ,y0 SCS ,�4 ,�O NY ti ti ti ti ti ti
