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Home My WebLink About2015 CINGSACook Inlet Natural Gas STORAQ May 15, 2016 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster — Chair of Commission 3000Spenard Road PO Box 190989 Anchorage, AK 99519-0989 ,*+� S$x.. r7nl MAY 16 2015 A®GCC RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Chairman Foerster: 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 four full years of operation. The enclosed report, in compliance with Rule 8 of SIO 9A, documents gas storage operational activity during the past forty-eight 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, J ed Green resident Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2015-2016 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 fourth such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012, and has now completed four 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 actual wellhead pressure versus Total Inventory performance of the field 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 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 2 expectations. CINGSA believes the primary reason for this is related to an isolated pocket 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 storage operation. Based upon currently available data, the estimated volume of gas associated with the isolated pocket is approximately 14.5 Bcf. CINGSA believes it will be able to refine this estimate with additional field -wide shut-in data as such shut- ins occur. This report also documents the injection/withdrawal flow rate performance of each of the five wells. The CLU S-4 and CLU S-5 wells were both back -pressure tested during 2015. Results from testing CLU S-4 indicate its deliverability performance has improved approximately 35 percent since the last time it was tested in 2012. The performance of CLU S-5 fell dramatically in 2014-2015 due to water loading. It was tested after cleaning it out with a coiled tubing unit. The coiled tubing clean-out was successful in restoring deliverability to its 2012 level, although its deliverability performance remains unchanged from 2012. Based upon a general review of the injection/withdrawal capability of the remaining three wells during the past 12 months, there appears to be no material loss in their deliverability performance. At this time there is no evidence that suggests a permanent decline in well deliverability that could be related to a loss of well bore integrity in any of the five wells. Consistent with standard operations, two planned facility shut -downs were conducted during the past twelve months, each one week in duration. The first shut -down occurred during November 2015 and the second in March 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 stabilize. The well shut-in pressure data was analyzed via graphical material balance analysis. The results of that analysis confirm 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 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. 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 all third party wells which penetrate the Sterling C Gas Storage Pool. This annular pressure data indicates there is no evidence of any gas leakage from the Sterling C Gas Storage Pool. Mechanical integrity tests were performed on the casing/tubing annular space of all five of the CINGSA wells in April and were witnessed by an AOGCC inspector; all five wells successfully passed the test. CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 3 In summary, all operating data indicate that reservoir integrity remains intact, and although the reservoir may now be 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 remains within the greater reservoir and is accounted for at this time. 2015-2016 Storage Operations The 2015-2016 storage cycle covers the period from April 9, 2015, the final day of the 2015 spring semi-annual shut -down, through March 27, 2016. Total Inventory at April 9, 2015 was 13,147,315 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 48 months, and the total gas -in-place at the end of each month since storage operations commenced. Please 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 pocket encountered by CLU S-1. To identify any anomalous behavior, 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. This type of plot is used in the gas storage industry to monitor reservoir integrity. 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 was shut-in periodically to confirm the pressure versus inventory trend 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 March 27, 2016 (again, excluding the 14.5 Bcf of native gas in the isolated pocket). 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. This sort of pressure response is not atypical of newly commissioned gas storage reservoirs and is often indicative of pressure transients that result from relatively high storage injection rates 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 16, 2016 Page 4 over a relatively short period of time, and not necessarily indicative of a lack of storage integrity. However, in this instance, CINGSA believes the higher than expected pressure is due to the isolated pocket of native gas that CINGSA encountered when it initially perforated/completed the Clc sand interval in the CLU S-1 well. This gas has since commingled with gas in the depleted section of the Cannery Loop Sterling C Pool, occupies a portion of its storage capacity, and provides pressure support to the storage operation. That said, 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 Deliverabflitv 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, or it may 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 was 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. The CLU S-5 well performance exhibited a significant decline in deliverability performance over the past year. The decline was suspected to be attributable to liquid loading in the wellbore as opposed to a loss of well integrity. This well was subsequently cleaned out using coiled tubing in August, 2015. Following the cleanout work on CLU S-5, CINGSA conducted back -pressure flow tests on the CLU S-5 and CLU S-4 wells. The purpose of these tests were to assess injection/withdrawal capability relative to when the wells were re -perforated during the summer of 2012, and in the case of CLU S-5 determine whether the clean out work had successfully restored the deliverability capability of the well. Results from the back -pressure test on CLU S-5 indicate the clean out work was successful in improving the deliverability capability of that well, and that performance decline was not attributable to a loss of well integrity. Also, a comparison of the back- pressure test results for CLU S-4 indicate that its deliverability capability has improved with time. Injection/withdrawal capability of CLU S-4 is up approximately 35 percent over the entire operating pressure range relative to its capability in 2012, while the deliverability of CLU S-5 after the clean-out remains largely consistent with its capability in 2012. With the exception noted above for CLU S-4, overall field CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 5 deliverability appears largely consistent with the withdrawal performance capability at the end of the 2012-2013 withdrawal season, and there is no evidence to suggest a decline in deliverability performance that is a result of a loss of wellbore integrity. 2015 Iniection Operations and October 2015 Shut-in Pressure Test Customer demand resulted in continued withdrawals from the field immediately after the April 2015 shut-in test, followed by a period of injections. Net activity for the month of April was a small reduction in inventory of nearly 7,000 Mcf. Steady injections occurred thereafter from May -October. Total net injections during the summer 2015 season amounted to approximately 3,545,472 Mcf. During this time, average injection rates ranged from 13 to 26 mmscf/d. On the morning of November 2, 2015, all of the wells were shut-in for pressure monitoring and remained shut-in until November 8. Total Inventory at November 8, 2015 was 14,668,761 Mcf, which included 7,668,761 Mcf of customer working gas plus 7,000,000 Mcf of CINGSA- owned 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 high of 1,515 psig on CLU S-1 to a low of 1,470 psig on CLU S-3. It is clear from reviewing this data that wellhead pressure had not fully stabilized during the shut-in period; shut-in pressure on all five wells declined continuously during the period. On the final day of shut-in, field average pressure was still declining at a rate of approximately 1 psi/day. Figure 2 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 November 8 was 1,499 psig and the average reservoir pressure was 1,701 psia. 2015-16 Withdrawal Operations and March 2016 Shut-in Pressure Test Storage withdrawals from the field commenced on November 12 and continued for approximately one week before injections resumed. Injections essentially offset withdrawals for the month resulting in little change in overall inventory. This pattern of short periods of withdrawals followed by re-injection continued largely throughout the winter months. Net withdrawals from storage during the entire 2015-2016 winter period amounted to only 34,660 Mcf. Field Operations reported that approximately 45 barrels of water was produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of March 21 and remained shut-in until the morning of March 28. CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 6 Total Inventory at March 21, was 14,634,101 Mcf, which included 7,634,101 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 pressure of all five wells. On the final day of shut-in, wellhead pressures ranged from a high of 1,476 psig on CLU S-1 to a low of 1,471 psig on CLU S-4, and field average pressure had largely stabilized, with essentially no change in average pressure during the final three days of the shut-in period. 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 March 28 was 1,473 psig and the average reservoir pressure was 1,672 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 eight 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 eight shut-in pressure tests as compared to the original discovery pressure conditions. Linear regression analysis of these eight data points indicates there is a very strong correlation between the eight points; the regression coefficient (R2) is 0.9508. 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 eight 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. Preliminary Estimate of Additional Native Gas Volume As explained last year, CINGSA believes it encountered an isolated pocket 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 Clc 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 16, 2016 Page 7 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 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 six 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 2015, and March 2016, together with observed shut-in pressures from CLU S-3 to estimate the magnitude of additional native gas encountered in the C I 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 Clc 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 communication is allowed between reservoirs after 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 the original reservoir was well defined from the primary production data as having an initial gas -in-place of 26.5 Bcf. The volume of gas associated with the Clc 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 16, 2016 Page 8 Figure 5 summarizes the results of the material balance procedure for the C 1 c sand interval having 14.5 Bcf of original gas -in-place at initial reservoir pressure conditions. Figure 6 illustrates the daily transfer rate between the main reservoir and the isolated pocket 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 Clc sand volume and transfer coefficients were explored. A range of C 1 c sand 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 CLU S-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. Thus, the current model 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 October 2014. 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 50 psi. Several simulation runs were made using various assumptions concerning reservoir configuration—i.e., channel geometry versus a "layer cake" configuration, aquifer support versus no aquifer support. Initial efforts focused on modifying wellbore skin factors and adjustments to grid block transmissibility to achieve an acceptable match to observed pressures. These efforts were largely unsuccessful because they required what CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 9 were considered extreme assumptions for skin factor values and/or transmissibility assumptions that did not honor the basic petrophysical data. 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 -l. The match between observed pressure and production data and that computed by the reservoir model was very good on CLU S-2 and CLU S-4, and reasonably good on CLU S-1, but not quite as good on CLU S-3 and CLU S-5. The estimated volume of incremental gas that yielded the best history match was 18 Bcff, During 2015, CINGSA undertook an extensive effort involving re -processing of seismic data obtained over the Cannery Loop Unit in 1995. That work was completed late last year and provided new insight into the approximate areal extent of the isolated reservoir. CINGSA intends to resume the modeling process in the very near future and incorporate the results of the re -processed seismic data into the model. Once the modeling effort is resumed, key objectives include achieving a better match between observed and simulated pressures on CLU S-3 and CLU S-5, and to a lesser extent CLU S-1. In addition, it may be possible to more fully characterize the volume of incremental gas associated with the C I c sand interval that was encountered when CLU S-1 was initially perforated/completed. 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 had MIT's performed on them this year in compliance with the AOGCC's requirement that the mechanical integrity of gas storage wells be demonstrated every four years. The tests were performed on April 5th and all five CINGSA wells demonstrated mechanical integrity according to AOGCC test requirements. CINGSA monitors and records 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") 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 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 10 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 ensure the integrity of the storage operation. Figures 7-11 illustrate the historical tubing and annulus pressures on each of the CINGSA gas storage wells. The observed inner and outer annulus pressures on all of the CINGSA storage wells track the tubing pressure. 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 entirely to expansion of the 7" casing string which results from higher pressure and temperature when injections are occurring. The key point for all five wells is that the pressure of the tubing string and the tubing/casing annulus are never equal, which demonstrates wellbore integrity. Figures 12-23 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 -6, all of the annulus and tubing pressure readings on the Hilcorp wells are very low (below 200 psi). The CLU -6 well was originally the sole production well associated with the Sterling C Pool. The Sterling C Pool was plugged prior to CINGSA commencing storage operations and the plug was pressure tested to AOGCC specifications at that time. Shortly thereafter, the well was recompleted in the upper (shallower) Sterling Sands. Thus, pressure on CLU -6 was significantly higher than the other Hilcorp wells because it was re -completed in the upper Sterling Sands and its tubing pressure is reflective of native (discovery pressure) conditions associated with this strata. Since its recompletion, pressure on the CLU -6 has declined to near zero in early 2013 and it is clear the well is incapable of producing in its current state. Since pressure on this well is now well below any of the CINGSA wells and is not tracking the operating pressure of the CINGSA wells, there is no evidence of a loss of 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 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 11 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. Summary and Conclusion CINGSA commenced storage operations on April 1, 2012 and has now completed four 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. Overall field deliverability appears unchanged from the 2012-2013 initial storage cycle. Field -wide withdrawal tests were conducted on March 9 and March 13, 2015 and a maximum stabilized withdrawal rate of 117 mmscf/d was achieved during the tests. Results of both tests confirm the facility is capable of meeting the aggregate contract MDWQ obligation of 103 mmcf/d at a working gas inventory level of 4.6 Bcf. There is no evidence of a change in deliverability in any of the CINGSA storage wells that may indicate a loss of well integrity. The CLU S-4 and CLU S-5 wells were both back -pressure tested in 2015. Results of those tests indicate the performance of CLU S-4 has improved somewhat since its last test in 2012. Overall deliverability performance of this well is up approximately 35 percent relative to its capability in 2012. The CLU S-5 well was cleaned out with coiled tubing in 2015 due to a decline in its performance. The post -clean out test results indicate the clean out job was successful in restoring deliverability performance to its performance capability in 2012. There is evidence indicating that initial completion work on CLU S-1 encountered an isolated pocket of native gas 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 methods were used to estimate the volume of incremental native gas encountered by CLU S-1. The two methods yielded volumes that range from 14 to 18 Bcf. The range of this estimate will very likely narrow with additional field -wide shut-in tests. That said, field weighted - average shut-in pressure during the semi-annual shut-in pressure tests including the CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 12 results from the October 2015 and March 2016 shut-in tests exhibit a very strong linear correlation (R2 = 0.9508). Thus, the results of these eight 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. Finally, annulus pressure readings on all of the CINGSA wells and the Hilcorp production wells which penetrate the Sterling C Gas Storage Pool demonstrate the confinement of gas to the storage reservoir. No anomalous pressure increases have been observed on any of the annular spaces associated with the CINGSA or Hilcorp wells, nor are any of these same wells exhibiting annular pressure readings that match the injection tubing pressure on any of the CINGSA wells. Thus, there is no evidence at this time of any loss of integrity based on annulus pressure readings. Accordingly, all operating data indicate that reservoir integrity remains intact, and although the reservoir may now be effectively larger than expected due to encountering additional native gas in the Sterling C I 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 16, 2016 Page 13 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 Injections - Mcf Withdrawals - Mcf Compressor Fuel &Losses Total Gas in Storage - Mcf Mar -12 0 0 3,556,165 Apr -12 146,132 394 2,289 3,699,614 May -12 1,238,733 1,163 11,540 4,925,644 Jun -12 1,245,041 1,048 16,769 6,152,868 Jul -12 986,472 714 12,529 7,126,097 Aug -12 1,245,260 93 14,038 8,357,226 Sep -12 1,300,153 982 13,221 9,643,176 Oct -12 1,624,167 691 15,285 11,251,367 Nov -12 165,866 72,417 4,895 11,339,921 Dec -12 379,205 470,886 5,839 11,242,401 Jan -13 496,560 209,334 7,976 11,521,651 Feb -13 1,765,296 858 19,372 13,266,717 Mar -13 667,603 554,597 7,594 13,372,129 Apr -13 438,717 254,734 6,315 13,549,797 May -13 509,694 12,769 7,680 14,039,042 Jun -13 615,458 1,274 11,185 14,642,041 Jul -13 468,599 822 12,118 15,097,700 Aug -13 499,748 3,392 11,766 15,582,290 Sep -13 306,323 16,743 9,074 15,862,796 Oct -13 530,289 27,585 10,287 16,355,213 Nov -13 9,608 902,874 214 15,461,733 Dec -13 5 1,156,534 61 14,305,143 Jan -14 261,325 127,655 7,352 14,431,461 Feb -14 4,143 517,884 534 13,917,186 Mar -14 1 766,800 - 13,150,387 Apr -14 97,548 190,563 3,671 13,053,701 May -14 64,435 388,647 1,597 12,727,892 Jun -14 509,445 502,790 7,444 12,727,103 Jul -14 687,386 108,786 11,165 13,294,538 Aug -24 728,130 219 12,423 14,010,026 Sep -24 537,858 4,705 11,712 14,531,467 Oct -14 155,673 189,157 4,477 14,493,506 Nov -14 66,645 291,368 2,126 14,266,657 Dec -14 32,716 380,170 1,897 13,917,306 Jan -15 - 1,104,457 76 12,812,773 Feb -15 - 971,590 288 11,840,895 Mar -15 11,253 719,045 855 11,132,248 Apr -15 99,648 106,458 3,242 11,122,196 May -15 416,773 4,772 10,000 11,524,197 Jun -15 460,797 2,811 9,972 11,972,211 Jul -15 805,820 403 12,120 12,765,508 Aug -15 817,781 527 12,521 13,570,241 Sep -15 590,046 179 12,001 14,148,107 Oct -15 532,624 13,990 11,159 14,655,582 Nov -15 286,336 283,937 5,958 14,652,023 Dec -15 267,908 210,747 5,989 14,703,195 Jan -16 192,325 235,414 5,523 14,654,583 Feb -16 242,504 167,856 5,852 14,723,379 Mar -16 193,549 165,556 3,621 14,747,751 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 14 Table 2 - November 2015 Wellhead Shut-in Pressure Data WAP Change Well Name CLU Sl CLU S-2 CLU S3 CLU S-4 CLU S-5 Weight Factor' - based on Ray Eastwood Log Model We anted Average Pressure IDdV-to-Da Ch 1 Day2vs.Dav1 Day3w DeV2 Dav4vs.Dxy3 Dav Sva. Dav4 Day 6vs Days Day jus. Day6 -14.3 -3.4 -1.1 -2.0 -1.9 -1.4 I d. Wellhead Shut-in Pressures (Psie) and Dates Day2ys.Dav1 Dav3w.DaV2 Dav Dav4vs. Dav3 Svs. Dav4 Dav6K. DavS Dav7va.Day6 Weight tactor• -2.3 -0.4 -1.1 -1.5 -1.1 -10.4 -2.1 -0.6 15toraae Pore -feet = -1.2 -1 -26.2 -2.9 -0.4 -0.8 -1.3 Well Name IP.,. -net MD•11-Sw11 22/2/201 11/3/202 11141201 22/5/2015 11/61201 11/7/2015 11/8/201 CLU Sl 70.235 1530.8 1521.2 1518.9 1518.5 1517.4 1515.9 1514.8 CLU S-2 47.696 1525.1 1514.7 1512.6 1512.0 1511.1 1509.9 1508.9 CLU S3 24.024 1501.5 1475.3 1472.4 1472.0 1471.2 1469.9 1469.5 CLU 54 97,011 1525.2 1512.5 1508.9 1507.0 1504.7 1502.3 1500.5 CLU S-5 93.155 1521.1 1502.6 1497.8 1496.7 1493.5 1491.2 1489.4 332.121 Weighted Avg. WHP (WAP) 1523.5 1509.2 1505.8 1504.7 1502.7 1500.8 1499.4 WAP Change Well Name CLU Sl CLU S-2 CLU S3 CLU S-4 CLU S-5 Weight Factor' - based on Ray Eastwood Log Model We anted Average Pressure IDdV-to-Da Ch 1 Day2vs.Dav1 Day3w DeV2 Dav4vs.Dxy3 Dav Sva. Dav4 Day 6vs Days Day jus. Day6 -14.3 -3.4 -1.1 -2.0 -1.9 -1.4 Table 3 -March 2016 Wellhead Shut-in Pressure Data I d. Id I W II P ID -t D Chantel Day2ys.Dav1 Dav3w.DaV2 Dav Dav4vs. Dav3 Svs. Dav4 Dav6K. DavS Dav7va.Day6 -9.6 -2.3 -0.4 -1.1 -1.5 -1.1 -10.4 -2.1 -0.6 -0.9 -1.2 -1 -26.2 -2.9 -0.4 -0.8 -1.3 -0.4 -12.7 -3.6 -1.9 -2.3 -2.4 -1.8 -18.5 -4.8 -1.1 -3.2 -2.3 -1.8 Table 3 -March 2016 Wellhead Shut-in Pressure Data WAP Change Well Name CLU Sl CLU S2 CLU S3 CLU S4 CLU S-5 Weight Factor' - based on Ray Eastwood Log Model We lighted Average Pressure 1DiV-to-Day Chanxl Dav2vs.Dav1 Dav3vs. Dav2 Day 4 vs. Day D,,, rs. Dav4 Dav6vs DavS Day 7 vs. Day 5.2 0.6 0.4 0.0 0.0 0.0 Wellhead Shut-in Pressures (psi¢) and Dates Day 2 vs. Day l Day 3 vs. Day Dav4 vs. Dav3 DavS vs. Dav4 Dav6vs.DavS Dav7vs.Dav6 11.4 Weight Factor' 0.3 0.0 0.1 0 13.2 0.7 CA 0.2 (Storax Pore -feet = 0.1 2.9 0.3 0.1 -0.4 -0.2 -0.3 Well Name (Pr. -net MD•11-Sw11 3/21/201 3 2016 3123/201 3/24/202 3/25/201 3/26/201 3/27/201 CLU S-1 70.235 1463.6 1475.0 1475.8 1476.1 1476.1 1476.2 1476.2 CLU S-2 47.696 1458.4 1471.6 1472.3 1472.7 1472.9 1473.0 1473.1 CLU 5-3 24.024 1471.9 1474.8 1475.1 1475.2 1474.8 1474.6 1474.3 CLU S-4 97.011 1468.9 1469.8 1470.4 1470.8 1470.9 1470.9 1470.9 CLU S-5 93.155 1470.8 1472.4 1473.0 1473.4 1473.4 1473.4 1473.4 332.121 Weighted Avg. WHP ( WAP) 1467.0 1472.2 1472.9 1473.2 1473.3 1473.3 1473.3 WAP Change Well Name CLU Sl CLU S2 CLU S3 CLU S4 CLU S-5 Weight Factor' - based on Ray Eastwood Log Model We lighted Average Pressure 1DiV-to-Day Chanxl Dav2vs.Dav1 Dav3vs. Dav2 Day 4 vs. Day D,,, rs. Dav4 Dav6vs DavS Day 7 vs. Day 5.2 0.6 0.4 0.0 0.0 0.0 Individual Well Pressure IDav-to-Dav Change) Day 2 vs. Day l Day 3 vs. Day Dav4 vs. Dav3 DavS vs. Dav4 Dav6vs.DavS Dav7vs.Dav6 11.4 0.8 0.3 0.0 0.1 0 13.2 0.7 CA 0.2 0.1 0.1 2.9 0.3 0.1 -0.4 -0.2 -0.3 0.9 0.6 0.4 0.1 0.0 0 1.6 0.6 0.4 0.0 0.0 0 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 15 Table 4 - Shut-in Reservoir Pressure History and Gas- in -Place Summary Shut-in Reservoir Pressure History and Gas -in -Place Summary - jNo Adjustment for Additional Native Gas) Original (Discovery) Reservoir Conditions Wellhead Pressure - psig. Bottom Hole Pressure - osia Z - Factor BHP/Z - osia Total Gas -in Place - mmscf Date 0 0 10/28/2000 1950 2206 0.8465 2606 26,500 Storage Operating Conditions Weighted Avg. Wellhead Calculated Bottom Hole Date Pressure - psig. Pressure - osia Z - Factor BHP/Z - osia Total Gas -in Place - mmstf 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 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 Conc.: 0.3% Reservoir Temp. (deg. F): 105 Datum Depth ft): 4950 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 16 Figure 1 — CLU S-3 Wellhead Pressure versus Inventory 2000.0 1800.0 1600.0 1400.0 t7i a a 1200.0 N W d 11000.0 d v t UO 800.0 600.0 400.0 200.0 0.0 CINGSA Wellhead Pressure vs. Inventory Hysteresis (Original Reservoir Only) 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf Initial Cycle Design —+--Second Cycle Design —e—Stabilized Wellhead Pressure Design Actual Shut-in Pressure vs. Inventory -CLUS-3 Pressure • Fall 2012 WASIWHP ■ Spring 2013 WASIWHP ■ Fal 2013 WASIWHP a Spring 2014 WASIWHP Fal12014 WASIWHP Spring 2015 WASIWHP • FaU 2015 WASIWHP • Spring 2016 WASIWHP.. I i I i 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 17 Figure 2 — November 2015 Wellhead Shut-in Pressures CINGSA fall 2015 Wellhead Shut-in Pressures 1540.0 1530.0 i I 1520.0 z. - - x1530.0 - - - - - -- ---- t CLU Storage 1 J ; CLUStuge2 1500.0 — CLU St«age 3 o. Y — CLU Stvage4 al e ■ y3490.0 * : CLUStmgeS I .. _ �. -_z 3 —o—Field Weighted Avg, Press. 1480.0- { I I 1470.0 1460.0 1450.0 11/2 11/3 11/4 11/5 11/6 11/7 11/8 Shut -In Date Figure 3— April 2016 Wellhead Shut-in Pressures CINGSA Spring 2016 Wellhead Shut-in Pressures 1480.0 i m x a 1470.0 1—.—CLU St«age t LI t CLU SI—p 2 --+ —CLU Staage3 —+.—CLU Storage 4 m • CLU Storage 5 3 j -o-Field Weighted Avg. Press. e z A1460.0 j -- j I 1450.0 I 3 3/21 3/22 3/23 3/24 3/25 3/26 3/27 Shut4n Date CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 18 Figure 4 — Material Balance Plot Cannery Loop Sterling C Gas Storage Pool - Material Balance Plot November 2012- March 2016 3,000 Discovery BHP/7= 2606 psia 2,500 m ti 2,000 a d 7 N 2 1,500 o. w 0 x E O 16 1,000 CO 500 Spring 2016 BHP/Z = 1950.5 psia Fall 2015 BHP/Z = 1987.6 psia --*---Discovery 8HP/Z vs. Gas -in -Place Fall 2012 BHP/Z vs. Gas -in Place • Spring 2013 BHP/Z vs. Gas in Place • Fall 2013 8HP/Z vs. Gas -in -Place A Spring 2014 BHP/Z vs. Gas -in -Place Fall 2014 BHP/Z vs. Gas -in -Place c Spring 2015 BHP/Z vs. Gas -in -Place Fall 2015 BHP/Z vs. Gas -in -Place Spring 2016 BHP/Z vs. Gas -in -Place 0 ✓ 0 5,000 10,000 15,000 20,000 25,000 30,000 Total Gas -in -Place MMcf CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 19 Figure 5 - Historical and Computed Pressures vs. Rate 120.00 ]00.00 80 W 60.00 v 40.00 E E a 20.00 s 3 0.00 20.00 0 -40.00 -60.00 -80.00 100.00 Figure 5 - Historical and Computed Pressures vs, Rate (Based on 14.5 Bcf of "Found Gas") M 2300 2100 1900 1700 1500 m a v 1300 g 700 500 300 100 e`�p` �\�s,1a titi��`�a s�ryF\ 6\�s, h °��A,� s,� s,� e\ xl\ Date �— Daily Inj/Wdd Rate - mmscf/d • "KW BHP- psia" • "Calc BHP - psia" 0"Obs Sl BHP Avg - psia° CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 20 Figure 6 - Estimated Gas Transfer to/from Original Reservoir Figure 6 - Estimated Gas Transfer to/from Original Reservoir CO C, 80.00 } 60.00 i T 40.00 E 20.00 `m c m � 0.00 o� v — .20.00 v 2 > -40.00 -60.00. -80.00 7500 6000 u 4500 E v v 3000 IS m Z 1500 -100.0G ` r 0 e\�o�titi �\��titi titi��\�oX, e\�91ti� �\�� ti�ry�\�� 6' P�tin5 h 1;) y � Date Daily Inj/Wdrl Rate mmscf/d Transfer Rate mmscf/d Net Gas Transferred - mmscf CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 21 Figure 7 — Annulus Pressure of CLU Storage — 1 Plot of Tubing and Annulus Pressure vs Time - CLU S-1 2000 -95/8 Annulus 1800 133/B Annulus -Tubing 1600 1400 m 1200 N a 1000 d Cr 600 600 400 200 0 Aa 4\p5\1`4 O�\��\1�1• 1O\p�\11 11\11•�\�`^� "'P1\13 O�\13 ,O\0Nl 1\13 131\13 o\�'s\1p O�\�.�\�`A 10\11, IsIf, �h 1011, O�\1z, 0\O1\�6 Q113 �6 4\O1\.�6 Figure 8 — Annulus Pressure of CLU Storage — 2 Plot of Tubing and Annulus Pressure vs Time - CLU S-2 2000 - —9 5/S Annulus —13 3/8 Annulus 1800 —Tubing 1600 1400 m 1200 N a .d 1000 m 6 600 600 400 200 0 IA^k �ZOIII � O1\z1\try 141, try IZOIZI 1� 6b\01\1� 611111, 1011, 3 O1\111\1A "P\�,s\1p O1\�1\1�' 1O\111\1A O1\01\1h \�1\1h O�\�1\1h 1O\01\1h O1\�1\•"6 \�1\16 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 22 Figure 9 — Annulus Pressure of CLU Storage — 3 Plot of Tubing and Annulus Pressure vs Time - CLU S-3 2000- —95/8 Annulus —133/8 Ann u Ws 1800 —Tubing 1600 1400 1200 ,a 1000 d CL` 800 600 400 200 0 O"\1h 0.N\•,5 `01\•5 0��•�6 01�•�6 1 O O O O 1 O '�0 Ob 01\ Figure 10 — Annulus Pressure of CLU Storage — 4 Plot of Tubing and Annulus Pressure vs Time - CLU S-4 2000 9 5/8 Annulus 1800 j _133/8 An nu lus 1600 —Tubing 1400 eo 1200 n O 1000 d n` 800 600 400 200 0 �lllllllfll Inflall MrTr--IrW—I nAfl 1\1'L �1`6 1\1" 1�1'� ,��1i 1�1� ,`�13 ,`�1Q ^�1A 1�^p 1�1A ,�15 1�1y 115 1�r�5 "b OI'�O 010 �O�O O�`10 Oa�O 010 100 O�`�O Oa�O p1�0 100 ISIP OA�O 01\0 100 OSI�13 Oa�01\ CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 23 Figure 11 — Annulus Pressure of CLU Storage — 5 CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 24 Figure 12 - Annulus Pressure of Marathon CLU 1RD T N d i N N w i a d V A r - z N CLU 1RD Annulus Pressure History 120 100 -. - __ _. _ —w— 4 1/2 x 7 Ih I- 80 7 x 9 5/8 60 - 40 All — — - fu 20 _ ___ 0 lkelo PJao �e`o QJav Month/Year Figure 13 - Annulus Pressure of Marathon CLU 3 CLU 3 Annulus Pressure History 600 -,— - 500 - -- - - 3 1/2 x 9 5/8 IA a' 400 d y 300 - - -- i d 200 u It to 100 --- - O TT N IN << PJao �e� QJao Month/Year CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 25 Figure 14 — Annulus Pressure of Marathon CLU 4 12 10 8 6 4 2 0 tia tib` tih ti� ti� ti(0 SeQ mac 5QQ �a� �eQ mac Q�aO �c�'o PJB �e'o PJB Month/Year CLU 4 Annulus Pressure History Figure 15 — Annulus Pressure of Marathon CLU 5 co CLU 5 Annulus Pressure History 250 I_ 200 ---•— 3 1/2 x 9 5/8 95/8x133/8 150 - --- -- - ---- - --- 100 I 50 - --- -- — { --_- - I 0 i -50 ,y(o ,yto C�eQ �a� ��Q �a�� Q �atP�� 1<e'o PJQo �e� P�Qo Month/Year CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 26 Figure 16 - Annulus Pressure of Marathon CLU 6 Figure 17 - Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 60 --+— 3 1/2 x 9 5/8 p, 50 - 9 5/8 x 13 3/8 40 - t- (0 3020 a 10 0 ti(0 �eQ bac 5e� bac �¢� bac PJB �e� PJB �e`o Month/Year CLU 6 Annulus Pressure History 2000 1800 --�- 4112 tI- o0 4A 1600 - +41/2x a 1400 ` 1200 - - -- --- 1000 - N 800 a w 600 400 - — -- ---- — 200 — in 0 , ,., - ,yti ;y'l' titi 'y3 'y3 ;y0 tip` 'yt° do Ike '0 �eQ fat �eQ mat �eQ �a� PJB �e� Month/Year Figure 17 - Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 60 --+— 3 1/2 x 9 5/8 p, 50 - 9 5/8 x 13 3/8 40 - t- (0 3020 a 10 0 ti(0 �eQ bac 5e� bac �¢� bac PJB �e� PJB �e`o Month/Year CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 27 Figure 18 — Annulus Pressure of Marathon CLU 8 CLU 8 Annulus Pressure History 120 a100 80 4A 60 a� a we 40 d u m 20 N 0 ti( ti(0 Month/Year I - 3 1/2 x 9 5J8 � _^-- —� 9 5/8 x 13 3/8 i Figure 19 — Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180- 160 - 140 -- a 120 a 100 y 80 — 31/2 x 9 5/8 a 60 -- — —+— 9 5/8 x 13 3/8 d v 40 - N 20 - 0 ,y< tih ti� ,yto �eQ �a� �eQ bac 41, �a� PJB �e� PJB 1< PJao Month/Year Figure 19 — Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180- 160 - 140 -- a 120 a 100 y 80 — 31/2 x 9 5/8 a 60 -- — —+— 9 5/8 x 13 3/8 d v 40 - N 20 - 0 ,y< tih ti� ,yto �eQ �a� �eQ bac 41, �a� PJB �e� PJB 1< PJao Month/Year CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 28 Fip,ure 20 — Annulus Pressure of Marathon CLU 10 Figure 21 — Annulus Pressure of Marathon CLU 11 CLU 10 Annulus Pressure History --- 31/2 x 9 5/8 120 60 _ _ - _ - _ - 9 5/8 x 13 3/8 100 50 -- .N a a 40 - -' d L d N 30 -- - - v d d 20 v A V r- 10 3 1/2 x 9 5/8 V1 0 - r 0 Month/Year Figure 21 — Annulus Pressure of Marathon CLU 11 CLU 11 Annulus Pressure History 120 100 .N a 80 d 60 � - v 40 v A 3 1/2 x 9 5/8 20 0 lke�o P��O Month/Year � - CINGSA Material Balance Report to the AOGCC May 16, 2016 Page 29 Figure 22 - Annulus Pressure of Marathon CLU 12 CLU 12 Annulus Pressure History 30 1 00 • inside 9 5/8 .N a 20 d 4A 0 d a 10 __.-- a� m 0 5eQ mac �eQ �a�' �eQ bac P�Qo �Ce'p PJao � � PJB Month/Year Figure 23— Annulus Pressure of Marathon CLU 13 CLU 13 Annulus Pressure History 90 80 — 70 — a 60 -- 50 -- N a�40 _ .---- --- ---- - - - - a 30 20 --�— 2 7/8 x 7 5/8 in 10 — _._ _ 7 5/8 x 10 3/4 0 ti(0 Month/Year