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Home My WebLink About2017 CINGSACook Inlet Natural -Gas STORAQ] rY May 30, 2018 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7t' Ave, Suite 100 Anchorage, AK 99501 Attn: Hollis French — Chair of Commission 3000Spenard Road PO Box 190989 Anchorage, AK 99519-0989 RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Chairman French: 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. Due to a scheduled delay in the shut-in test this year, CINGSA requested, and the Commission granted, an extension of the due date to May 31. CINGSA has now completed six full years of operation. The enclosed report, in compliance with Rule 8 of SIO 9A, documents gas storage operational activity during the past seventy two 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. Sincerely, John Sims President Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2018 Annual Material Balance Analysis Report To AOGCC May 29, 2018 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 2 Cook Inlet Natural Gas Storage Alaska, LLC 2017-2018 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 submitted an application 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 sixth such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012, and has now completed six 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 30, 2018 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. Three wells were back -pressure tested in 2017 — the CLU S-3, S-4, and S-5. The S-3 well ceased flowing early this year and has since been cleaned out. Assuming clean out of the S-3 was successful in restoring its deliverability, there is no evidence of a decline in well deliverability associated with any of the CINGSA wells which could be related to a loss of well bore integrity. Consistent with standard operations, two planned facility shut -downs were conducted during the past twelve months, each approximately one week in duration. The first shut- down occurred during October 2017 and the second in May of this year. The purpose of these two shut -downs 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 of 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 well or storage reservoir integrity were to occur, it is likely that it would manifest itself via a rise in annular pressure of any well that penetrates the storage pool. There are 12 third -party wells owned by Hilcorp which penetrate the Sterling C Pool, plus the five CINGSA wells. This report includes a summary of shut-in pressures recorded on all of the annular spaces of each of the CINGSA storage wells and select annular spaces of each of the Hilcorp wells. Annulus pressure on the Hilcorp CLU -5 has risen sharply to over 900 psi since mid- 2016. Hilcorp reports that no recompletion work has been performed on this well, and there is no obvious reason for the increase in annular pressure. None of the other Hilcorp wells exhibits anomalously high pressure, nor is there any evidence that the increased pressure on CLU 5 is due to a loss of integrity of the CINGSA storage facility. CINGSA should continue to monitor pressure on this well and all other third -party wells which penetrate the storage reservoir for evidence of loss of storage integrity. 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 30, 2018 Page 4 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. 2017-2018 Storage Operations The 2017-2018 storage cycle covers the period from April 10, 2017, the final day of the 2017 spring semi-annual shut -down, through May 8, 2018. Total inventory at April 10, 2017 was 11,887,901 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 72 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 is 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 May 8, 2018 (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 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 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 30, 2018 Page 5 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. 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 3-4 percent of the total flow. Since converting the field to storage, this well has consistently exhibited a tendency to water - off during the withdrawal seasons, and this past season was no exception. 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 capable of flow. The CLU S-3, S-4, and S-5 wells were back -pressure tested during September 2017. Results from testing CLU S-3 indicate its deliverability performance had declined approximately 60 percent relative to the test results from one year earlier. By March of this year, flow from the S-3 had ceased completely and the well was scheduled for a cleanout using coiled tubing. As previously noted, this well has typically contributed about 24 percent of total field flow. Thus, it has been one of the better performing wells in the field. A follow-up test of the well will be performed during the 2018 injection season. Test results from the S-4 well indicate its deliverability performance was virtually unchanged from its test in September 2015. Test results from the S-5 well suggest its deliverability performance may have nearly doubled since last being testing in August 2015. However, these results are questionable since the well quickly appears to load up with water during the withdrawal season and struggles to sustain any material flow. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 6 Based upon a general review of the injection/withdrawal capability of the remaining two wells (S-1 and S-2) during the past 12 months, there appears to be no material loss in their deliverability performance. A more complete assessment of field deliverability capability may be made once the S-3 well is returned to service and tested. Assuming clean out of the S-3 was successful in restoring its deliverability, there is no evidence of a decline in well deliverability associated with any of the CINGSA wells which could be related to a loss of well bore integrity. 2017 Infection Season Operations and October 2017 Shut-in Pressure Test The field was released for resumption of active storage operations on April 10, 2017. During the remainder of April the field was used mainly for withdrawals. Steady injections began in early May and continued largely unabated through September with monthly totals ranging from a low of about 250 mmcf in September to a high of over 1,100 mmcf during August. The field was shut-in for pressure stabilization on October 2, 2017 and remained shut-in until the morning of October 9th. Total gas inventory at October 2nd was 15,523,158 mscf, including 8,523,158 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 1521 psig on CLU S-3 to a high of 1579 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 declining at a rate of 2.0 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 9th was 1560 psig and the average reservoir pressure was 1767 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 12 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 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 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 7 additional 14,500,000 mscf (14.5 Bcf) of native gas associated with the isolated reservoir. Figure 4 is a plot of the average bottomhole pressure adjusted for compressibility (BHP/Z) versus gas -in-place during each of the 11 shut-in pressure tests compared to the original discovery pressure conditions. Linear regression analysis of these 11 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 0.951. 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 11 shut-in periods (November 2012, April 2013, November 2013, April 2014, October 2014, April 2015, November 2015, March 2016, October 2016, April 2017, and October 2017) 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. 2017-18 Withdrawal Operations and May 2018 Shut-in Pressure Test Withdrawals from the field commenced on October 9' and were sporadic for the duration of the month. Generally speaking, overall withdrawals were down considerably this withdrawal season relative to the 2016-2017 season. Net withdrawals from storage during the entire 2017-2018 winter period amounted to 2,096,895 Mcf. Field Operations reported that approximately 137 barrels of water was produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of May 1 and remained shut-in until the morning of May 8a'. Total inventory at May 1 was 13,424,899 Mcf, which included 6,424,899 Mcf of customer working gas and 7,000,000 Mcf of CINGSA-owned base gas. Table 3 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 fmal day of shut-in, wellhead pressures ranged from a high of 1,381.7 psig on CLU S-5 to a low of 1,349.7 psig on CLU S-3. Field average pressure had not stabilized, but was still building at a rate of about 0.3 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 May 8 was 1376.1 psig and the average reservoir pressure was 1,557.8 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 12 shut-in periods since commencement of storage operations. Lastly, it lists the gas CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 8 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 bottomhole 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 12 data points indicates there is a very strong linear correlation between the points; the regression coefficient (R2) is 0.951. Thus, similar to 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. 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 12 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 (R2) of 0.977. 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. Preliminary 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 of the wells that penetrate the Cannery Loop Sterling C Pool. This particular 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. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 9 Following initial perforation/completion, a temperature log was subsequently run in CLU S-1 in an effort 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 1 c sand interval. The higher than expected shut-in pressure and evidence of gas influx strongly suggest the C 1 c was indeed physically isolated from the other four sand sub -intervals within the Sterling C Pool. It is unknown whether the C 1 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 C 1 c 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 2017, and May 2018, 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 -l. 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 Bcf. The volume of gas associated with the C 1 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. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 10 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 bottomhole pressure from the model (Calc BHP) compares to both the observed bottomhole 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 bottomhole 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. Various combinations of C 1 c sand gas volume and transfer coefficients were explored. A range of C I 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 considered to be when the difference between actual pressures versus predicted pressure is less than 100 psi. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 11 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. Annulus Pressure Monitoring Prior to CINGSA commencing storage operations, all of 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 of the wells successfully demonstrated integrity. Shortly after commencing storage operations, all of 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. CINGSA monitors and records both the tubing/production casing string annulus (7" x 9 5/8") and production/intermediate casing string annulus (9 5/8" x 13 3/8") pressure of each of its wells on daily basis 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 analyzes this pressure data for any evidence of a loss of well/reservoir integrity, in the same manner as it does for its own wells. All of these annulus pressure readings are submitted to the AOGCC monthly and are part of routine and ongoing surveillance to confirm the integrity of the storage operation. Figures 8-12 illustrate the historical tubing and annulus pressures on each of the CINGSA gas storage wells. The general character of the inner and outer annulus pressures on CINGSA's storage wells tend to track the tubing pressure; as tubing pressure rises or falls, the annulus pressures tend to do the same. The pressure swing appears to be due entirely to expansion of the 7" casing string which results from higher pressure and temperature when injections are occurring. 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. Insofar as tubing integrity is concerned on all five CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 12 wells, the tubing string and the tubing/casing annulus are never equal, which demonstrates wellbore integrity. 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. With the exception of CLU -5, all of the annulus and tubing pressure readings on the Hilcorp wells are low (below 200 psi). The CLU -5 well has exhibited zero annulus pressure historically. In late 2015, both the tubing/production casing and production/intermediate casing annuli began to exhibit positive pressure, though both were less than 200 psi. Pressure on the 3 'h inch x 9 5/8 inch annulus on the CLU -5 well has been rising since early 2016, and reached a peak of over 900 psi in March, but has since declined to less than 850 psig. The 9 5/8 inch x 13 3/8 inch annulus exhibits a pressure of about 30-40 psig. The 9 5/8 inch string penetrates the storage zone and was originally cemented off across the storage interval, thus, the storage zone appears to remain isolated from the deeper productive intervals that have been completed in this well. Hilcorp confirmed in October 2017 that no rework activity has been performed on the CLU -5 well which might explain the increase in annular pressure. CINGSA should continue to monitor annulus pressure on this well and all of the other Hilcorp wells for evidence of a loss of well and/or reservoir integrity. For the remaining Hilcorp wells, all of the pressure readings are well below tubing pressure of any of the CINGSA wells and do not track the CINGSA well tubing pressure trends, which again demonstrates isolation/integrity. Thus, based on a thorough review of the annular pressure data for all wells, there is no evidence of any loss of integrity of any of the CINGSA injection/withdrawal wells or any of the Hilcorp wells which penetrate the Sterling C Pool. This data lends additional support to the conclusion that reservoir integrity is intact and all of the storage gas remains within the reservoir, and is thus accounted for. Rule 3 of AOGCC's SI09 On March 29th, 2017, CINGSA send 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 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 13 clarification as to whether Mr. Goddard wished CINGSA to discontinue monitoring the facilities and requested a response by May 111, 2017. CINGSA did not receive a response from Mr. Goddard. This issue remains unresolved as of this date. Summary and Conclusion CINGSA commenced storage operations on April 1, 2012 and has now completed six full years of storage operations. All of 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. With the exception of a decline in deliverability capability of the CLU S-3 well due to sanding -off during the just completed withdrawal season, overall field deliverability appears unchanged from the 2012-2013 initial storage cycle. 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, S-4, and S-5 wells were all back -pressure tested in 2017. Results of those tests indicate the performance of CLU S-3 had declined significantly since its last test. This well will be retested this year during the injection season to determine whether the recent clean out of the well was successful in restoring its deliverability. Test results on the S-4 indicated its deliverability capability has not changed since last being tested in 2015. Test results from the S-5 well suggest that its deliverability capability actually may have increased since its last test in 2015. However, as this well routinely waters off during the withdrawal season it's difficult to confirm evidence of any gain. During initial completion of the CLU S-1 well, an isolated pocket of native gas was encountered within the Sterling C 1 c 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 are now yielding comparable estimates of the volume of this additional native gas of approximately 14.5 Bcf. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 14 The field weighted -average shut-in pressure versus inventory relationship during the 12 semi-annual shut-in pressure tests conducted since converting the field to storage service exhibit a very strong linear correlation (W = 0.951). Thus, the results of these 12 shut- in pressure tests support the conclusion that no loss of gas from the reservoir is occurring, and that all of the injected gas remains within the storage reservoir. Annulus pressure readings on all of the CINGSA wells demonstrate confinement of storage gas to the reservoir; none of the CINGSA wells exhibits anomalous annular pressure. The same can be said for all of the Hilcorp production wells which penetrate the Sterling C Gas Storage Pool. With the exception of the CLU -5 well, annulus pressure on all of the Hilcorp wells are very low and exhibit no evidence of pressure communication with the CINGSA facility. The Hilcorp CLU -5 well exhibited a sharp increase in annular pressure beginning in late 2016. The cause of the increase is unclear, though it does not appear to be related in any way to CINGSA's storage operations. CINGSA should continue to monitor the pressure of all of the Hilcorp wells for any change in character which may be indicative of a loss of storage integrity. 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 of the injected gas remains with the greater reservoir and is accounted for at this time. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 15 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 otherwise) Month InlecWns - Mcf Withdrawals- Md Compressor Fuel &Lasses Total Gas in Storage - Mcf 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 4,925,644 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 Det -12 379,205 470,886 5,839 11,242,401 Jan -13 496,S60 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 13,539,797 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 30,287 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 97,546 190,563 31671 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 14531,467 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 99'648206,458 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 Month -End Inventory Balance May -18 Volumes as of 08.00 5/1/2018 13,424,899 Inventory Balance 6,424,899 working Gas 7,000,000 Base Gas CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 16 Table 2 - October 2017 Wellhead Shut-in Pressure Data Wellhead Shift -in Pressures (Dslel and Dates Individual Well Presarre I W v -to- W v Chancel Well Name WV2Vf.WV1 Wellhead Shut-in Pressures (Dsie) and Dates Wv 7 vs. Day CLU S-1 -1 -1.1 -0.5 -1.6 0.1 Weight Factor' CLU S-2 -1.1 -0.6 0 -1.8 0.4 -1.4 CLU 5-3 (storage Pore -feet = -0.4 0.1 0 0 0 CLU S-4 -2.8 Well Name (Por.•net MD-11-Swll 2017 101412027 1015/201 2016/2017 10/7/2017 10 8 017 101912017 CLU S-1 70.235 1584.4 1583.4 1582.3 1581.8 1580.2 1580.3 1578.5 CW 5-2 47.696 1576.7 1575.6 1575.0 1575.0 1573.2 1573.6 1572.2 CLU S-3 24.024 1520.5 1520.9 1520.5 1520.6 1520.6 1520.6 1520.6 CLU S-4 97.011 1572.5 1569.7 1567.2 1565.0 1562.7 1561.6 1559.2 CLU 5-5 93.155 1566.0 1561.5 1558.5 1556.2 1553.5 1552.7 1550.1 NOTES Red text reflects estimate 5-3 was being cleaned out with coiled tubing during a portion 332.121 test Weighted Average Pressure IUav-to-Day Chanael Weighted Aug. WHP (WAP) 1570.0 1567.6 1565.7 1564.3 1562.3 1561.8 1559.8 WAP Change Weighted Average Pressure IWv-to- -Chanel Wv2vs.Wy1 Wv3vs.Wv2 WV4vs. Wv3 WvSvs. Wv4 Wv6Vs.WvS Wy7vs.WV6 -2.4 -1.9 -1.4 -2.0 -0.5 -2.0 Table 3 - May 2018 Wellhead Shut-in Pressure Data Wellhead Shift -in Pressures (Dslel and Dates Individual Well Presarre I W v -to- W v Chancel Well Name WV2Vf.WV1 Wv3vs.Wv2 Wv4vs.Wv3 WVSvs.Day Wv 6vs. Day Wv 7 vs. Day CLU S-1 -1 -1.1 -0.5 -1.6 0.1 -1.8 CLU S-2 -1.1 -0.6 0 -1.8 0.4 -1.4 CLU 5-3 0.4 -0.4 0.1 0 0 0 CLU S-4 -2.8 -2.5 -2.2 -2.3 -1.1 -2.4 CW 5-5 -4.5 -3 -2.3 -2.7 -0.8 -2.6 1373.7 CLU S-3 was opened to the gathering system to re-pressudze the system; Indicated pressure was estimated based on actual pressures from 10/3 - 10/6 1344 1345.0 1346.0 Weight Factor' based on RaVEa stwood Log Model 1349.7 CLU S-4 97.011 Table 3 - May 2018 Wellhead Shut-in Pressure Data WeightFactor- based on Ray Eastwood Log Madel Wellhead Shift -in Pressures (Dslel and Dates Weight Factor (Stange Pore -feet = Well Name IPor.enet MDe(1-Swll 5/2/2018 5/3/2018 420 5/512018 5/6/2018 SLUMS 5/81 18 CLU 5-1 70.235 1372.5 1371.3 1371.3 1375.3 1374.5 1374.5 1375.3 CLU S-2 47.696 1373.6 1372.5 1372.4 1375.3 1374.5 1373.7 1374.5 CLU 5-3 24.024 1344 1345.0 1346.0 1346.4 1348.1 1348.9 1349.7 CLU S-4 97.011 1378.6 1377.6 1377.7 1378.5 1378.5 1378.5 1378.5 CLU 5-5 93.155 1378.5 1379.0 1379.7 1381.7 1380.9 1381.7 1381.7 332.121 Weighted Avg. WHIP ( WAP) 1374.1 1373.6 1373.9 1375.9 1375.6 1375.7 1376.1 NOTES Red text reflects estimate 5-3 was being cleaned out with coiled tubing during a portion of the shut in test Weighted Average Pressure IUav-to-Day Chanael Wv2vs.Dav1 Day3vs.Dav2 Dav 4vs. Davi Dov Svs. Dav4 Dav6vs.Dav5 Dav7vs.Dav6 WAP Change -0.5 0.3 2.1 -0.4 0.2 0.3 Individual Well pressure (Dav-to-Dav Chancel Well Name Dav2vs.Dav1 Day3vs.Dav2 Day4vs.Wv3 Dav Svs. Day4 Dav6vs. WvS Day7ys. Wv6 CLU Sl -1.2 0.0 4.0 -0.8 0.0 0.8 CLU 5-2 -1.1 -0.1 2.9 -0.8 -0.8 0.8 CLU S-3 1.0 1.0 0.4 1.7 0.8 0.8 CLU S-4 -1.0 0.1 0.8 0.0 0.0 0.0 CLU S-5 0.5 0.7 2.0 -0.8 0.8 0.0 WeightFactor- based on Ray Eastwood Log Madel CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 17 Table 4 - Shut-in Reservoir Pressure History and Gas- in -Place Summary Shut-in Reservoir Pressure History and Gas -in -Place Summary - (No Adjustment for Additional Native Gas) Original (Discovery) Reservoir Conditions 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 Table 5- Shut-in Reservoir Pressure History and Gas- in -Place Summary (Adjusted Inventory) Shut-in Reservoir Pressure History and Gas -in -Place Summary - (Adjusted to Account for Additional Native Gas) Original (Discovery) Reservoir 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 Storage Operating Conditions Weighted Avg. Wellhead Calculated Bottom Hole - 14.5 BN Found Gas Date Pressure -psig. Pressure - psia 0 Z - Factor BHP/Z - psia Total Gas -in Place - mmscf 11/8/2012 1269.9 1434.9 41,000.000 0.8719 1645.7 11,223.715 4/15/2013 1344.4 1522.35 4/15/2013 1344.4 0.8668 1756.3 13,106.887 11/4/2013 1580.7 1798.1 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 0.858 1937.4 14,493.502 4/8/2015 1159.6 1315.8 1500.3 0.877 1500.3 11,123.289 11/8/2015 1499.4 1701.4 29,168.761 0.856 1987.6 14,668.761 3/27/2016 1473.3 1671.6 10/30/2016 1582.4 0.857 1950.5 14,634.101 10/30/2016 1582.4 1792.2 1371.9 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 0.864 0.855 2067.3 15,523.158 5/8/2018 1376.1 1557.8 0.864 1803.6 13,424.899 0.3% Gas Gravity: 0.56 CO2 C.- 0.3% N2 Conc.: 0.3% 105 CO2 Conc.: Datum Depth TVD (ft.): 0.3% 4950 Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): 4950 Avg. Measured Depth (ft.): 9706 Table 5- Shut-in Reservoir Pressure History and Gas- in -Place Summary (Adjusted Inventory) Shut-in Reservoir Pressure History and Gas -in -Place Summary - (Adjusted to Account for Additional Native Gas) Original (Discovery) Reservoir 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 Adiusted Total Gas -in Place - Est - - 14.5 BN 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 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 C.- 0.3% Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): 4950 Avg. Measured Depth (ft.): 9706 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 18 Figure 1 — CLU S-3 Wellhead Pressure versus Inventory 2000.0 it -T1111111 1600.0 1400.0 a m 1200.0 a a m a` 1000.0 m v 800.0 W 600.0 400.0 200.0 0.0 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf CINGSA Wellhead Pressure vs. Inventory Hysteresis (Original ReservoirOnly) = Initial Cycle Design a— Stabilized Wellhead Pressure Design • Fa12012 WASIWHP ■ Spdng 2013 WASIWHP ■ Fal 2013 WASIWHP a Spring 2014 WASIWHP Fel 2014 WASIWHP Spring 2015 WASIWHP . Fa12015 WASIWHP Spring 2016 WASIWHP Fag 2016 WASIWHP Spdng 2017 WASIWHP Fag 2017 WASIWHP Spring 2018 WASIWHP 2000.0 it -T1111111 1600.0 1400.0 a m 1200.0 a a m a` 1000.0 m v 800.0 W 600.0 400.0 200.0 0.0 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 19 Figure 2 — October 2017 Wellhead Shut-in Pressures CINGSA Fall 2017 Wellhead Shut -In Pressures 1590.0 1580.0 1570.0 1560.0 6 1550.0 e 3 1540.0 1530.0 1520.0 1510.0 10/3 10/4 10/5 10/6 30/7 10/8 10/9 Shut4n Date Figure 3— May 2018 Wellhead Shut-in Pressures CINGSA Spring 2018 Wellhead Shutdn Pressures 1400.0 1380.0 1340.0 1320.0 4/4 4/5 4/6 4/7 4/8 4/9 Shut-in Date — CLU st«age L t CLU Storage 2 -i-- CLU 5_w 3 —«—CLU 51ore8e 4 a CLU Storage 5 —o—Field Weighted Avg. Press. t CLU Storage 1 t CLU Stage 2 —a-• CLU Storage 3 —CLU Stage 4 a CLU Staage 5 Field Weighted Avg. Press. CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 20 Figure 4 — Material Balance Plot (Unadjusted) 3,000 2,500 m 2,000 a 1,500 a d 0 S E 0 1,000 m 500 0 0 5,000 10,000 Cannery Loop Sterling C Gas Storage Pool - Material Balance Plot November 2012- May 2018 Discovery BHP/Z = 2606 psi, A t � l d A —*—Discovery BHP/Z vs. Gas -in -Place 2012 - 2013 BHP/Z vs. Gas in Mace 6 2013 - 2014 BHP/Z vs. Gas -in -Place 2014 - 2015 BHP/Z vs. Gas -in -Place 1015 - 2016 BHP/Z vs. Gas -in -Place A 2016 - 2017 BHP/Z vs. Gas -in -Place 1 2017 - 2018 BHP/Z vs. Gas -in -Place — Linear (2017 - 2018 BHP/Z vs. Gas -in -Place( 15,000 20,000 25,000 30,000 Total Gas -in -Place MMd 35,000 40,000 45,000 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 21 Figure 5 — Material Balance Plot (Adiusted) 3,000 2,500 2,000 F a 1,500 500 Cannery Loop Sterling C Gas Storage Pool - Preliminary Adjusted Material Balance Plot November 2012- May 2018 0 5,000 10,000 15,000 BHP Z = 2606 is 14.5 B Found GOS j BHP/Z = 2606 psla a 1 + Discovery 8HP/Z vs. Gas -in -Place 2012-2013BHP/Zvs. Gasin Place + Adjusted DBteveiy BHP/Z vs. Gas -In -Place a Adjusted 2012-2013 BHP/Z vs. Ges-inMlsce s 2013 - 2014 BHP/Z vs. Gas -in -Place • Adjusted 2013-2014 BHP/Z vs. Gas -In -Place s 2014- 2015 BHP/Z vs. Gasin-Place Adjusted 2014 - 2015 OHP/Z vs. Gas -In -Place 2015 - 2016 BHP/Z vs. Gas in -Place • Adjusted 2015.2016 BHP/Z va. 68ri"IK6 • 2016- 2017 BHP/Z vs. Gas -in -Place I - • Adjusted 2016-2017 BHP/Z vs. Gas -in -Plate A 2017- 2018 BHP/Z vs. Gas -in -Place • Adjusted 2017 - 2018 6HP/Z vs. 6as4"lece 20,000 25,000 30,000 35,000 40,000 45,000 Gas -in -Place MMcf CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 22 Figure 6 - Historical and Computed Pressures vs. Rate 6[i •Ii -7 MAWL Figure 1- Historical and Computed Pressures vs. Rate (Based on 14.5 Bcf of "Found Gas") L 7J --I 2100 190`_' 1700 1500 m VI, 1300 g v a` 1100 0 v 900 700 500 300 100 �P \�9`, z�,,b\�-\�9\� , \�-�ti�\�6,tiP9\ti�\ b\��\�4,�\��\tib\��,ti9�1\1\ry�\,,�\��,,6\�A�.,�\�b��b�.,b\�1`tib\�b\.y9\�y\A�ryb\.,�`��`tib�b\tie Date Daily Ini/Wdd Rate - mmscf/d • 'TW S-3 BHP- psia" • "Calc BHP - psia" 0 "Obs WA518 HP A. -g - psi?' CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 23 Figure 7 - Estimated Gas Transfer to/from Original Reservoir rr 50.00 V E E v 0.00 d 100 �'T -15000 Figure 2 - Estimated Gas Transfer to/from Original Reservoir (Based on 14.5 Bcf of "Found Gas") 6X0 5000 4000 E D v 3000 -2 M l9 2000 Z 1000 0 e\�91ti9\I, ,\rye\ \�q\ti\\ti�\��\�a�1��?��tib`�gx��\�1\ \rye}`��>>e,��,Q\�e\1�\ryb\" \�1`,�\ryb\tia\�h�1\��\��\��\�o"',tip Date Daily Inj/Wdd Rate - mmscf/d Transfer Rate - mmscf/d Net GasTransferred I I� N iiia � � i::��Il'I��i I) i a►� i/>\ +�:�� •� 1 �,� ' ill I i ljl ,I I 6X0 5000 4000 E D v 3000 -2 M l9 2000 Z 1000 0 e\�91ti9\I, ,\rye\ \�q\ti\\ti�\��\�a�1��?��tib`�gx��\�1\ \rye}`��>>e,��,Q\�e\1�\ryb\" \�1`,�\ryb\tia\�h�1\��\��\��\�o"',tip Date Daily Inj/Wdd Rate - mmscf/d Transfer Rate - mmscf/d Net GasTransferred CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 24 Figure 8 — Annulus Pressure of CLU Storage —1 Plot of Tubing and Annulus Pressure vs "rime - CLU s -I 2000 1800 �mdrc 1800 1400 m 1200 6 1000 � 800 800 400 200 0 "N''s ks,1 \1K" 1�'N \"N ,1,h �1,� 11,h `�\5 '.1�5 �t15 X116 1\6 1\6 6 �1 1'l �� 1 ,8 19 10 �8 19 \9 o o�� vdo o,N Op o�P ,4Q,� �� o�� .,o�O o,° �A "0 ,op o.P ��, o�P, soo,�, ��, 0110,1 100 0,x,1 ��,1 otA, ,00,��1 " Figure 9 — Annulus Pressure of CLU Storage — 2 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 25 Figure 10 — Annulus Pressure of CLU Storage — 3 Figure 11— Annulus Pressure of CLU Storage — 4 Plot of Tubing and Annulus Pressure vs Time - CLU S-4 2000 95/8Annulus 1800 13 3/8 Annulus —Tubing 1600 1400 O0 1200 a 1000 5 N N d y 800 600 400 200 LM rIlly-Illn 0 0 Op\O^ \" OHO^^00�0�0108\00�0110\010 ^\' "vOOI\O, ZP0 S%01��\0,010110, O X101` N\I O A`, 01 q� ,\,'ZOP o\O^ No, Op \' QP,'S", O 1 O O Oa O � O CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 26 Figure 12 — Annulus Pressure of CLU Storage — 5 CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 27 Figure 13 — Annulus Pressure of Marathon CLU 1RD 140 120 ba a 100 80 60 L CL 40 a V 20 0 0 CLU 1RD Annulus Pressure History * ,yon ,y< �< (0 'y�O ,y1 11 ti� ti� ti0) mac �eQ IPJ00 <�e� VZ 0� �J�O � P� <(e� PJ0O Month/Year Figure 14 — Annulus Pressure of Marathon CLU 3 HT1 .N 500 a 400 a a 300 a a 200 V A 100 A CLU 3 Annulus Pressure History 49 mat 49 mat c�eQ mat P,�¢o �e�o PJao <<e�° P�Qo �e� P�4O <<P Pao xe�O Month/Year CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 28 Figure 15 - Annulus Pressure of Marathon CLU 4 12 CLU 4 Annulus Pressure History U Ci fat ��Q mac �� mat' P ao fie; vz 00 � PJB �e� P� �9-o PJac � Month/Year Figure 16 - Annulus Pressure of Marathon CLU 5 CLU 5 Annulus Pressure History 1000 -, - - - - -- --- - 00 800 - 31/2 x 95/8 95/8x 133/8 ° 600400 - ar a` 200 -- - d 0 rr `n -200 -- — - - -- --- - - - - — - -- - - N ,y'1. ;y1' 'y'� ;y� tib` tib` ,yh ti� yto ,yto til til N ti00 Y DA aA A' aX oX 2A OLS PQM p�� PQi OLS' PQt' Month/Year CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 29 Figure 17 — Annulus Pressure of Marathon CLU 6 Ti2mt-111I1: m a 1400 ` 1200 I 1000 a 800 ar 600 v 400 200 r� CLU 6 Annulus Pressure History ,y'y ,1'L ,'L ,y'S ti'�i ,yC` ,yA ,y� ,y� y (0 ti� ,�'� ti� `b �$ as of aA of aA poi �,Q�poi PQc poi QQt, po` QQ� p�` Month/Year Figure 18 — Annulus Pressure of Marathon CLU 7 0-11 no IA, 50 40 30 a 20 A 10 I CLU 7 Annulus Pressure History Illy 'y1' ;y`�' 'y3 'y3 ti� ti� ti� '�) ;y(0 o� aXof a� oa aJ O�� PQt O`er PQc O`er PQc O�� PQt O`er a a � Month/Year CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 30 Figure 19 — Annulus Pressure of Marathon CLU 8 120 oa 100 80 d N 60 d 40 V l0 20 D] CLU 8 Annulus Pressure History Al as oAl as lop V-9 aA OGS' Pit' OLS' PQc CP Pic' O��' VIP Month/Year Figure 20 — Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180 _ - -- --- - - - 160 _ 31/2 x 9 5/8 °D 140 '" —� 9 5/8 x 13 3/8 a 120 L. d 100 80 a 60 - d 0 40 20 0 nT as PQt' O`� Month/Year CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 31 Figure 21— Annulus Pressure of Marathon CLU 10 G'�: .N a 40 d 4A 30 1A d a 20 d u t 10 3 N 0 'y1 'y�' :y�" :''� 'ytK 'yt, tih 'y� 'yl ti( til tiA Ob tiOb �A aA oA aA A' aJ C`� CP PQc' Month/Year Figure 22 — Annulus Pressure of Marathon CLU 11 120 100 80 m y 60 d 40 �o 20 CLU 11 Annulus Pressure History FT • 3 1/2 x 9 5/8 }95/8x 133/8 i 0 T 'S•,y0, ,ytk ,yh ,�� ti� ti� �� 1i ti00 ,y00 CP� Month/Year CINGSA Material Balance Report to the AOGCC May 30, 2018 Page 32 Figure 23 — Annulus Pressure of Marathon CLU 12 CLU 12 Annulus Pressure History 30 n4 • inside 9 5/8 .y 20 d d a 10 a� w m 0 rT r-1 titi ti� ti� tilb ti� ti� tib` tih ti4 ti( ti(0 til til ti� ti00 o� as o aA oaA PQt OGS PoG� PQM' OGS Month/Year Figure 24— Annulus Pressure of Marathon CLU 13 120 100 N a 80 a� m 60 a) 40 v m t 20 N 1 CLU 13 Annulus Pressure History ti<1 ti ti( (0 ti(0 baA P�� °J/ A PJ�O �°< 4a1 P�Qo °� V �aJ PJB Month/Year