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Home My WebLink About2016 CINGSACook Inlef Nafural> Gas STORAQ�y;,� May 15, 2017 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster, Chair 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 RECEIVED MAY 15 2017 AOGCC RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Chair 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 (AOGCC), 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 five full years of operation. The enclosed report, in compliance with Rule 8 of SIO 9A, documents gas storage operational activity during the past sixty 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, 7_v�/ Jared Green President Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2017 Annual Material Balance Analysis Report To AOGCC May 15, 2017 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 2 Cook Inlet Natural Gas Storage Alaska, LLC 2016-2017 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 fifth such annual report to be filed by CINGSA. The CINGSA facility was commissioned in April 2012, and has now completed five 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 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 3 the pressure versus inventory performance is generally consistent with design expectations, although actual pressure has trended above design 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, which remains consistent with past conclusions. This report also documents the injection/withdrawal flow rate performance of each of the five wells. The CLU S-1 and CLU S-3 wells were both back -pressure tested during 2016. Results from testing CLU S-1 indicate its deliverability performance has improved approximately 30 percent relative to the 2012-2013 performance trend line — the benchmark used for all of the CINGSA wells. Using that same benchmark, the performance of CLU S-3 appears to have increased by nearly 50 percent. 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. CLU S-5 continues to load up with water and deliverability drops essentially to zero from this well on those occasions. At this time there is no evidence of a decline in well deliverability associated with any of the CINGSA wells that 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 2016 and the second in April 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. These results 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 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 600 psi since late last year. This may be a result of recompletion work on the well but should be investigated CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 4 nonetheless. Other than the questionable rise in annular pressure on the Hilcorp CLU 5 well, there is no evidence of any gas leakage from the Sterling C Gas Storage Pool based on a review of all of the wells which penetrate the Pool. In summary, operating data generally supports the conclusion 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 appears to remain within the greater reservoir and is accounted for at this time. 2016-2017 Storage Operations The 2016-2017 storage cycle covers the period from March 28, 2016, the final day of the 2016 spring semi-annual shut -down, through April 10, 2017. Total inventory at March 27, 2016 was 14,634,101 Mcf.l Table 1 lists the remaining native gas -in-place as of April 1, 2012, net injection/withdrawal activity by month during the past 60 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 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 has been 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 April 10, 2017 (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 I Throughout this report, the term "Total Inventory" refers to the sum of the base gas in the reservoir plus the customer working gas in the reservoir. Total Inventory does not include the native gas CINGSA discovered when drilling the CLU S-1 well. CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 5 has been consistently higher than expected when compared to predicted shut-in pressure derived from initial computer modeling studies. The higher observed pressure of CLU S-3 is attributable to an influx of a portion of the 14.5 Bcf of native gas that CINGSA encountered when it completed the CLU S-1 well. The overall trend of the wellhead shut- in pressure of CLU S-3 versus total inventory plot indicates there is currently 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 and automation system, including a supervisory control 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 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 42 percent of the field flow during the 2016-2017 withdrawal season. Wells CLU S-2, S-3, and S-4 contributed an average of 18.9, 23.8, and 11.9 percent respectively. Well CLU S-5 contributed an average of only 3.4 percent of the total flow during the past 12 months. However, CLU S-5 initially contributed over 7 percent in November and over 5 percent in December. As the withdrawal season progressed, the well gradually loaded up with water and overall flow declined accordingly. 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. Two wells were back -pressure tested in 2016: CLU S-1 and CLU S-3. Results from the back -pressure test on CLU S-1 indicate that deliverability capability may have improved by some 30 percent relative to the 2012-2013 operating trend data, which is the most recent baseline for comparison. Likewise, the test results from CLU S-3 indicate its deliverability capability may have increased by nearly 50 percent relative to the 2012- CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 6 2013 operating trend data. This type of behavior is not unusual in the Cook Inlet as wells often "clean-up" over time after their initial completion. With the exception of CLU S-5, overall field deliverability capability appears largely consistent with the withdrawal performance capability of the past few years. There is no evidence which suggests a decline in deliverability performance of any of the wells resulting from a loss of wellbore integrity. 2016 Injection Operations and October 2016 Shut-in Pressure Test The field was on steady injections for most of April 2016, with net monthly injections amounting to 875,011 Mcf. Steady injections occurred during all of May and most of June. Beginning on June 18, the field was placed on continuous withdrawal for about 7 days to support operations associated with the Kenai LNG facility. A total of some 430,000 Mcf was withdrawn during this period, at rates which averaged about 62,000 Mcf per day. Individual well and overall field performance was consistent with expectations during this period. Thereafter, injections resumed at variable rates through August. Total net injections from April -August amounted to 2,415,109 Mcf. During this time, average injection rates ranged from about 7 to 29 mmscf/d, with the highest rates occurring during April and May. Net withdrawals occurred in both September and October. On the morning of October 24, 2016, all of the wells were shut-in for pressure monitoring and remained shut-in until October 30. Total inventory at October 24, 2016 was 16,667,452 Mcf, which included 9,667,452 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 increase 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 1,591.5 psig on CLU S-3 to a low of 1,573.6 psig on CLU S-4. Wellhead pressure did not fully stabilize during the shut-in period; shut-in pressure on all five wells was building continuously during the period because the field had been on steady withdrawals just prior to shut-in. On the final day of shut-in, field average pressure was still increasing at a rate of approximately 1.4 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 October 30 was 1,582 psig and the average reservoir pressure was 1,792 psia. 2016-17 Withdrawal Operations and April 2017 Shut-in Pressure Test Steady withdrawals from the field commenced on November 16, 2016 and continued through most of March 2017. Net withdrawals from storage during the entire 2016-2017 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 7 winter period amounted to 5,209,470 Mcf. Field Operations reported that approximately 810 barrels of water were produced during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of April 3, 2017 and remained shut-in until the morning of April 10, 2017. Total inventory at April 3, was 11,908,476 Mcf, which included 4,908,476 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 1,307 psig on CLU S-5 (estimated due to water in the wellbore) to a low of 1,153 psig on CLU S-1. Field average pressure had not stabilized, but was still building at a rate of about 2.3 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 April 10 was 1,212 prig and the average reservoir pressure was 1,372 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 ten 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 ten shut-in pressure tests as compared to the original discovery pressure conditions. Linear regression analysis of these ten data points indicates there is a very strong linear correlation between the points; the regression coefficient (R) is 0.952. 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 ten 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 in prior annual reports, CINGSA 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 C 1 c sand interval is one of five recognized sand intervals that are common to nearly all of the wells CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 8 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. 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 that correlates to the Sterling C I c sand interval. The higher than expected shut-in pressure and evidence of gas influx strongly suggest the Clc was indeed physically isolated from the other four sand sub -intervals within the Sterling C Pool. It is unknown whether the C 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 I 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 ten 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 2016, and April 2017, together with observed shut-in pressures from CLU S-3 to estimate the magnitude of additional native gas encountered in the C 1 c sand interval of CLU S-1. The approach used to analyze this data was to treat the originally defined reservoir and the previously isolated 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 was 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. CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 9 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 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. Figure 5 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. 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 C1c sand volume and transfer coefficients were explored. A range of Clc 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 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. 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 October 2016 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 2016. 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. 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 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 10 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-3, and reasonably good on CLU S-2, 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) 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 pressure data to CINGSA monthly which CINGSA then analyzes 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 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 11 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 both annuli declined back to zero by June of 2016. However, the tubing/production casing annulus pressure rose back to about 200 psi in July 2016 and remained there until February 2017. Since then, pressure on this annulus has risen to over 600 psi and pressure on the production/intermediate casing has risen to over 500 psi. An effort should be made to contact Hilcorp and determine if they have undertaken any recompletion work on this well that would explain the sudden and sharp rise in pressure. It may be worthwhile to obtain a gas sample analysis from both annuli if Hilcorp is agreeable to allowing access to do so. 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. Summary and Conclusion CINGSA commenced storage operations on April 1, 2012 and has now completed five 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. 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-1 and CLU S-3 wells were both back -pressure tested in 2016. Results of those tests indicate the performance of CLU S-1 has improved somewhat since its last CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 12 test in 2012. Overall deliverability performance of this well is up approximately 30 percent relative to its capability in 2012-2013. Test results from the CLU S-3 well suggest its deliverability capability may have risen as much as 50 percent since the 2012-2013 period. During initial completion of the CLU S-1 well, an isolated pocket of native gas was encountered within the Sterling Clc sand interval. This gas has since commingled with gas in the main (depleted) portion of the reservoir, effectively adding to the remaining native gas reserves and providing pressure support to the storage operation. This additional gas is functioning as base gas and accounts for the higher than expected shut- in wellhead pressure readings on CLU S-3 and the field -wide shut-in pressures observed during each of the ten 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. The field weighted -average shut-in pressure versus inventory relationship during the ten semi-annual shut-in pressure tests conducted since converting the field to storage service exhibit a very strong linear correlation (R2 = 0.952). Thus, the results of these ten 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 demonstrate confinement of storage gas to the reservoir; none of the CINGSA wells exhibits anomalous annular pressure. The same can be said for all but one 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 is very low and exhibit no evidence of pressure communication with the CINGSA facility. The Hilcorp CLU -5 well has exhibited a sharp increase in annular pressure within the past few months. This pressure increase may be a result of some recompletion work performed on the well, though it should be investigated to confirm that is the case. There is no evidence at this time of any loss of integrity based on annulus pressure readings, even taking into account the increased annular pressure in Hilcorp's CLU -5 well. Otherwise, all operating data indicate that storage 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 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. Table 1— Monthly Injection and Withdrawal Activity CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 13 11,908,476 Inventory Balance as of 4/3/2017 Table 2 - October 2016 Wellhead Shut-in Pressure Data Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Month Infections - Mcf Withdrawals- Mcf Compressor Fuel &Losses Total Gas in Storage- Mcf Mar -12 0 0 3,556,165 Apr -12 146,132 394 2,289 3,699,614 May -12 1,238,733 1,163 11,540 4,925,644 Jun -12 1,245,041 1,048 16,769 6,152,868 Jul -12 986,472 714 12,529 7,126,097 Aug -12 1,245,260 93 14,038 8,357,226 Sep -12 1,300,153 982 13,221 9,643,176 Oct -12 1,624,167 691 15,285 11,251,367 Nov -12 165,866 72,417 4,895 11,339,921 Dec -12 379,205 470,886 5,839 11,242,401 Jan -13 496,560 209,334 7,976 11,521,651 Feb -13 1,765,296 858 19,372 13,266,717 Mar -13 667,603 554,597 7,594 13,372,129 Apr -13 438,717 254,734 6,315 13,549,797 May -13 509,694 12,769 7,680 14,039,042 Jun -13 615,458 1,274 11,185 14,642,041 Jul -13 468,599 822 12,118 15,097,700 Aug -13 499,748 3,392 11,766 15,582,290 Sep -13 306,323 16,743 9,074 15,862,796 Oct -13 530,289 27,585 10,287 16,355,213 Nov -13 9,608 902,874 214 15,461,733 Dec -13 5 1,156,534 61 14,305,143 Jan -14 261,325 127,655 7,352 14,431,461 Feb -14 4,143 517,884 534 13,917,186 Mar -14 1 766,800 - 13,150,387 Apr -14 97,548 190,563 3,671 13,053,701 May -14 64,435 388,647 1,597 12,727,892 Jun -14 509,445 502,790 7,444 12,727,103 Jul -14 687,386 108,786 11,165 13,294,538 Aug -24 728,130 219 12,423 14,010,026 Sep -24 537,858 4,705 11,712 14,531,467 Oct -14 155,673 189,157 4,477 14,493,506 Nov -14 66,645 291,368 2,126 14,266,657 Dec -14 32,716 380,170 1,897 13,917,306 Jan -15 - 1,104,457 76 12,812,773 Feb -15 - 971,590 288 11,840,895 Mar -15 11,253 719,045 855 11,132,248 Apr -15 99,648 106,458 3,242 11,122,196 May -15 416,773 4,772 10,000 11,524,197 Jun -15 460,797 2,811 9,972 11,972,211 Jul -15 805,820 403 12,120 12,765,508 Aug -15 817,781 527 12,521 13,570,241 Sep -15 590,046 179 12,001 14,148,107 Oct -15 532,624 13,990 11,159 14,655,582 Nov -15 286,336 283,937 5,958 14,652,023 Dec -15 267,908 210,747 5,989 14,703,195 Jan -16 192,325 235,414 5,523 14,654,583 Feb -16 242,504 167,856 5,852 14,723,379 Mar -16 193,549 165,556 3,621 14,747,751 Apr -16 887,796 12,785 9,970 15,612,792 May -16 807,600 66,640 9,628 16,344,124 Jun -16 815,655 499,321 9,553 16,650,905 Jul -16 356,887 136,370 7,744 16,863,678 Aug -16 442,736 134,541 9,013 17,162,860 Sep -16 310,570 351,469 4,015 17,117,946 Oct -16 4,550 454,156 777 16,667,563 Nov -16 189,606 544,376 633 16,312,160 Dec -16 173,058 849,832 3,891 15,631,495 Jan -17 106,318 1,641,030 1,766 14,095,017 Feb -17 63,362 1,043,257 531 13,114,591 Mar -17 107,373 1,270,218 477 11,951,269 Inventory Balance 11,908,476 Inventory Balance as of 4/3/2017 Table 2 - October 2016 Wellhead Shut-in Pressure Data CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 14 Weight Factor` based on Ray Eastwood Log Model Table 3 -April 2017 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures (Psig) and Dates Day 2 vs. Day 1 Day 3 vs. Dav 2 Dav 4 vs. Dav 3 Dav 5 vs. Dav 4 Day 6 vs. Day 5 WAP Change Weight Factor* 2.6 1.3 1.9 1.4 Individual Well Pressure (Dav-to-Dav Change) Well Name Day 2 vs. Day 1 (Storage Pore -feet = Dav 5 vs. Dav 4 Day 6 vs. Day 5 CLU Sl 4.3 2.6 0.8 1.7 1.1 CLU S-2 Well Name (Por.•net MDNI-Sw)) 10/25/2016 10/26/2016 10/27/2016 10/28/2016 10/29/2016 10/30/2016 CLU S-1 70.235 1574.8 1579.1 1581.7 1582.5 1584.2 1585.3 CLU S-2 47.696 1575.1 1580.2 1582.1 1583.0 1584.2 1585.1 CLU 5-3 24.024 1583.9 1587.6 1588.9 1589.4 1590.5 1591.5 CLU S-4 97.011 1560.0 1564.6 1567.6 1569.4 1571.7 1573.6 CLU S-5 93.155 1572.5 1577.6 1580.4 1582.0 1584.1 1585.5 1202.2 332.121 1207.8 1209.7 1212.0 NOTE: Red text reflects corected wellhead pressure reading due to fluid in the wellbore. Weighted Avg. WHIP (WAP) pressure only. 1570.5 1575.2 1577.8 1579.1 1581.0 1582.4 Weight Factor` based on Ray Eastwood Log Model Table 3 -April 2017 Wellhead Shut-in Pressure Data Weighted Average Pressure (DeY-to-Dav Change) Day 2 vs. Day 1 Day 3 vs. Dav 2 Dav 4 vs. Dav 3 Dav 5 vs. Dav 4 Day 6 vs. Day 5 WAP Change 4.7 2.6 1.3 1.9 1.4 Individual Well Pressure (Dav-to-Dav Change) Well Name Day 2 vs. Day 1 Day 3 vs. Day 2 Dav 4 vs. Dav 3 Dav 5 vs. Dav 4 Day 6 vs. Day 5 CLU Sl 4.3 2.6 0.8 1.7 1.1 CLU S-2 5.1 1.9 0.9 1.2 0.9 CLU S-3 3.7 1.3 0.5 1.1 1 CLU S-4 4.6 3 1.8 2.3 1.9 CLU S-5 5.1 2.8 1.6 2.1 1.4 Weight Factor` based on Ray Eastwood Log Model Table 3 -April 2017 Wellhead Shut-in Pressure Data Weight Factor' - based on Ray Eastwood Log Model Table 4 - Shut-in Reservoir Pressure History and Gas- in -Place Summary Wellhead Shut-in Pressures (psig) and Dates Weight Factor' IStomge Pore -feet= Well Name (Por.•net MD•11-Sw)I 4/4/2017 4 5 01 4/612017 4 7 2017 4/8/2017 4 9 2017 4/10/201 CLU 5-1 70.235 1135.7 1139.3 1142.9 1145.1 1147.0 1148.4 1153.0 CLU 5-2 47.696 1146.4 1152.2 1155.5 1157.7 1159.6 1161.5 1163.1 CLU 5-3 24.024 1182.4 1194.5 1203.1 1210.1 1216.4 1222.5 1227.6 CLU S-4 97.011 1181.7 1168.4 1171.6 1175.0 1177.9 1180.7 1183.2 CLU S-5 93.155 1307.4 1307.4 1307.4 1307.4 1307.4 1307.4 1307.4 332.121 Weighted Avg. WHIP (WAP) 1202.2 1200.8 1203.6 1205.9 1207.8 1209.7 1212.0 NOTE: Red text reflects corected wellhead pressure reading due to fluid in the wellbore. Used last day shut-in pressure only. Weighted Average PressureIDav-to-Dav Chancel Dav2vs.Dav1 Dav3vs.Dav2 Dav4vs.Dav3 Dav Svs Dav4 Dav6vs Davy Dav7vs.Dav6 WAP Change -1.4 2.8 2.3 2.0 1.8 2.3 L divldual Well Pressure IDav-to-Dav Chancel Well Name Dav2 vs. Davl Davi vs. Dav2 pav 4vs. Dav3 Dav Svs. Dav4 Dav6vs.Dav5 Dav7vs.Dav6 CLU S-1 3.6 3.6 2.2 1.9 1.4 4.6 CLU S-2 5.8 3.3 2.2 1.9 1.9 1.6 CLU S-3 12.1 8.6 7.0 6.3 6.1 5.1 CLU S-4 -13.3 3.2 3.4 2.9 2.8 2.5 CLU S-5 0.0 0.0 0.0 0.0 0.0 0 Weight Factor' - based on Ray Eastwood Log Model Table 4 - Shut-in Reservoir Pressure History and Gas- in -Place Summary CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 15 Shut-in Reservoir Pressure History and Gas -in -Place Summary - (No Adiustment for Additional Native Gas Figure 1 - CLU S-3 Wellhead Pressure versus Inventory Original (Discovery) Reservoir Conditions Wellhead Pressure - osig. 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 -osig. Pressure -osia Z -Factor BHP/Z -osia Total Gas -in Place -mmscf 11/8/2012 1269.9 1434.9 0.8719 1645.7 11,223.715 4/15/2013 1344.4 1522.35 0.8668 1756.3 13,106.887 11/4/2013 1580.7 1798.1 0.8508 2113.4 16,339.046 4/8/2014 1320.6 1497.7 0.8662 1729.0 13,147.315 10/31/2014 1465.1 1662.3 0.858 1937.4 14,493.502 4/8/2015 1159.6 1315.8 0.877 1500.3 11,123.289 11/8/2015 1499.4 1701.4 0.856 1987.6 14,668.761 3/27/2016 1473.3 1671.6 0.857 1950.5 14,634.101 10/30/2016 1582.4 1792.2 0.853 2100.0 16,667.452 4/10/2017 1212.0 1371.9 0.875 1567.9 11,908.476 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 Conc.: 0.3% Reservoir Temp. (deg. F): 105 Datum Depth TVD (ft.): 4950 Avg. Measured Depth (ft.): 9706 Figure 1 - CLU S-3 Wellhead Pressure versus Inventory CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 16 CINGSA Wellhead Pressure vs. Inventory Hysteresis (Original Reservoir Only) --+—Initial Cycle Design —+—Second Cycle Design —&—Stabilized Wellhead Pressure Design Actual Shut-in Pressure vs. Inventory - CLUS-3 Pressure Fal 2012 WASIWHP . Spring 2013 WASIWHP m Fal 2013 WASIWHP a Spring 2014 WASIWHP Fal 2014 WASIWHP Spring 2015 WASIWHP Fal 2015 WASIWHP . Spring 2016 WASIWHP Fal 2016 WASIWHP • Spring 2017 WASIWHP 2000.0 1800.0 an 1600.0 a m 1400.0 "m 1200.0 m a 1000.0 m m m 800.0 U) 600.0 400.0 200.0 0.0 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmsci Figure 2 — October 2016 Wellhead Shut-in Pressures CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 17 CINGSA Fall 2016 Wellhead Shut-in Pressures 1600 1590 - — _- �C'U s".gel CLU 521.91 2 -a-- CLU S—ge 3 —w— CLU S(1a91 4 x CLU 5—age 5 —o-- Field Weighted Avg. Press. Figure 3— April 2017 Wellhead Shut-in Pressures CINGSA Spring 2017 Wellhead Shut-in Pressures 1350.0 1300.0 i I �Im i n N 1250.0 - - � v n ?1200.0—�—�. u 1150.0. i I i 1100.0 '- - 4/4 4/5 4/6 4/7 4/8 Shut-in Date Figure 4 — Material Balance Plot 30 x x —f—CLU St -911 —�— CLU Staage 2 --- CLU Staage3 —+— CLU Staage 4 % CLU Staage 5 —Field Weighted Avg. Press. 4/9 4/10 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 18 Cannery Loop Sterling C Gas Storage Pool - Material Balance Plot November 2012- April 2017 3,000 Discovery BHP/Z = 2606 psia 2,500 m I rx 2,000 N a .A/ N v 1,500 a` + Discovery BHP/Z vs. Gas -in -Place d 2012 - 2013 BHP/Z vs. Gas in Place iE A 2013 - 2014 BHP/Z vs. Gas -in -Place 0 1,000 2014 - 2015 BHP/Z vs. Gas -in -Place DO 2015 - 2016 BHP/Z vs. Gas -in -Place . 2016 - 2017 BHP/Z vs. Gas -in -Place Linear (2016 - 2017 8HP/Z vs. Gas -in -Place) 500 --- I 0 0 5,000 10,000 15,000 20,000 25,000 30,000 Total Gas -in -Place MMcf Figure 5 - Historical and Computed Pressures vs. Rate CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 19 150.00 100.00 50.00 E E u 0.00 v` 3 _! -50 00 100.00 Figure 1- Historical and Computed Pressures vs. Rate (Based on 14.5 Bcf of "Found Gas") C .. -150.00 ' yapa tim\�a ya\�a tiW\ Date Daily Inj/Wdd Rate - mmscf/d • "KW BHP- psia" • "Calc BHP - psia" 0 "Obs 51 BHP Avg - psia" Figure 6 - Estimated Gas Transfer to/from Original Reservoir 2300 2100 1900 1700 1500 m a m 1300 v a` 1100 •o v a 900 CC 700 500 300 100 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 20 100 00 50.00 000 50 00 100.00 Figure 2 - Estimated Gas Transfer to/from Original Reservoir (Based on 14.5 Bcf of "Found Gas") 1so.00 xl �, �� o�� \ry��ti$�ti�W, �\��° �\��\��°ry\�,��ti �\�$tih�\v�1ti��\3\�� ee\�^��c �\�� ry\�G�ti� \�� e\��ti� Date Daily Inj/Wdri Rate - mmscf/d Transfer Rate - mmscf/d Net Gas Transferred - mrnscf Figure 7 — Annulus Pressure of CLU Storage — 1 6000 S000 4000 E E a 3000 z 2000 1000 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 21 Plot of Tubing and Annulus Pressure vs Time - CLU S-1 2000 X95/9-1., 1800 13 3/8A .Wf —T.b i 1600 1400 m 1200 n N 1000 I m IL a 800 600 400 200 0 o, 1\1'b 111`L 1\13 1\1A 1\13 1\1� 1�1p 1\1A 1�1p 1\1A 1�1h 1�1� 1�1� 1�1� 116 116 116 116 1\11 1\11 1�1� '0110 110 110 110 1`19 119 4\° 101, 1°\° 01\0 oA\0 0-\° 1°\° 01\° o'\° 61\° 1°0 01\0 "0 d0 10\° 01\° 0'0 d0 100 01\0 0"\0 0k\° 1°\° 01\° oa\O o�\° 10\O o1\° ,Ap Figure 8 — Annulus Pressure of CLU Storage — 2 1 V--. - / 11111 MJ 1 11.JJ— 1 Vl <. V A11.V1 N;r,1. — J CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 22 Figure 10 — Annulus Pressure of CLU Storage — 4 Plot of Tubing and Annulus Pressure vs Time - CLU S4 2000 —95/8 Annulus 1800 I —133/8 Annulus Tubing 1600-- - 1400 m 1200 a 1000 a v 800 600 400 200 0 ILm na= w \o^\^,\�1\II N\1�\01\1,\01\" 01\" 0^\" o,\" o1\" \1, NO. o^\,h o^\110 \1 01\1� 0�\�6 0^\16\0,\10\01\1�\0,\1� \01\,1\off\gyp\o1\�.�\�,\ % N\49 oa ol�0 0 oa o�\ ,o\ o`\ oa\ ",k\, \ o`\ oa\ o \ , \ o \ oa\ o o oa o , 0 " 0 0 oa Figure 11 — Annulus Pressure of CLU Storage — 5 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 23 Plot of Tubing and Annulus Pressure vs Time - CLU S-5 2000 j —95/B Annulus '. 1800 —133/B Annulus —Tubing 1600 1400 Obi 200 n 1000 a a' 800 600 400 200 0 AO",,,�1\", N\", \\", p��\N3,��\N, "\0, 1\N\1, p`1�1pIti1\'\O' 1a �\1��h A\, �1510-\'b Z\N\,Ib NXNX16 A\\\161\, Figure 12 — Annulus Pressure of Marathon CLU 1RD CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 24 CLU 1RD Annulus Pressure History 140 120 4 1/2 x 7 - ao a 100 -� 7x95/8 i 80 — -- - - 3 60 — - -- — a 40 - - d v 20 0 i. PJB �v PJB �eo P�� e� PJoo Month/Year Figure 13 - Annulus Pressure of Marathon CLU 3 CLU 3 Annulus Pressure History 600 - - - --- �- ----- - --- ------ .do ---do 500 —3 1/2X9 5/8 N a 400 — a� A 300 -- a a� 200 J1 - m 0 1;-1 1 'y 1 ti ti ti 1 ti ti ti ti ti ti '�- 4' 4, 4, �a�PJao ��o PJoo �� PJQo lea PJao Month/Year Figure 14 - Annulus Pressure of Marathon CLU 4 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 25 F— CLU 4 Annulus Pressure History 16 14 -- _ r--- • 3 1/2 x 13 5/8 12 - a —•-13 5/8 x 20 10 -- O N S - - d a` 6 d m 4 r- 2 0 T Tom.IF - : N ti 1 'y ti �e'o 'y PJ, <<e', PJao �e� PJao Month/Year Figure 15 — Annulus Pressure of Marathon CLU 5 CLU 5 Annulus Pressure History 700 600 • 3 1/2 x 9 5/8 - — - 500 9 5/8 x 13 3/8 a d 400 N 300 200 100 - m i t 0 v' -100 ')) ,ylb ,yon ,y� y`� ,y1-) ti( ti(0 ,y1\ ti1\ Oen PQc Cc's Oen PQM Oen PQt Oen �a� �eQ bac �eQ Month/Year Figure 16 — Annulus Pressure of Marathon CLU 6 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 26 Figure 17 - Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 r? no 60 • 31/2x95/8 .a 50 9 5/8 x 13 3/8 - 40 30 a ai 20 — V 3 10 N 0 titi yti ,y'L y3 ti� tion yo� y� tih ti(0 ti� 1A til Oc,� PQc Oc'� PQc Oc,� Pic O�� PQM Month/Year Figure 18 - Annulus Pressure of Marathon CLU 8 CLU 6 Annulus Pressure History 2000 T- _ 1800 41/2 tbg ,ao 1600 41/2 x 7 a 1400 — ` 1200 N 1000 — 800 a` _ 600 d V 400 -- 200 - - in 0 ti1-1) ,yh y(0 ti( til til Oc'� Pic Oc,� PQc Oc'� PQc O�� PQM O� Month/Year Figure 17 - Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 70 r? no 60 • 31/2x95/8 .a 50 9 5/8 x 13 3/8 - 40 30 a ai 20 — V 3 10 N 0 titi yti ,y'L y3 ti� tion yo� y� tih ti(0 ti� 1A til Oc,� PQc Oc'� PQc Oc,� Pic O�� PQM Month/Year Figure 18 - Annulus Pressure of Marathon CLU 8 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 27 I CLU 9 Annulus Pressure History CLU 8 Annulus Pressure History 120 — 31/2 x 9 5/8 9 5/8 x 13 3/8 I i y 100 °Q 140 CL 80 a 120 d 60 100 y a� T - - CL 40 v 20 -�.-- 40maned 0 i ,y'� 10` ,y� ,y� ,y(1 ,y(o �c, PQM" O� PQM" Oce QQt" O� PQM" O� �a`" 5eQ bac" 5eQ 0 Ir Month/Year I CLU 9 Annulus Pressure History 180 ' 31/2 x 9 5/8 9 5/8 x 13 3/8 I i 160 °Q 140 - 95/8x 13 3/8 a 120 --. _ 100 80 T - - ST Figure 19 – Annulus Pressure of Marathon CLU 9 Figure 20 –Annulus Pressure of Marathon CLU 10 CLU 9 Annulus Pressure History 180 - -- - r 160 °Q 140 - 95/8x 13 3/8 a 120 --. N 100 80 - - a 60 4 d m -�.-- 40maned 20 { 0 Ir � � � titi ti� titititib` tib` � h titi ( � tititil til Oce PQM" O� PQM" C PQM" C� pQO� �a�" Month/Year Figure 20 –Annulus Pressure of Marathon CLU 10 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 28 loll �1,111 Figure 21 — Annulus Pressure of Marathon CLU 11 CLU 11 Annulus Pressure History 120 T 00 100 a 80 � � E 1A 60 a 40 —31/2x95/8 d i m20 —95/8x133/8 0 Oc'� PQc Oc'� PQc Oc'� PQM Oc'� PQM Oc'� �a� �eQ fat �eQ Month/Year Figure 22 — Annulus Pressure of Marathon CLU 12 CINGSA Material Balance Report to the AOGCC May 15, 2017 Page 29 CLU 12 Annulus Pressure History dqinside 9 S/8 a 20 —� ! d a` 10 - -- - - -- - � l o-, o`� PQM' O�� Pic O`er PQM Oc'� 11?9 C I ae Month/Year Figure 23- Annulus Pressure of Marathon CLU 13 CLU 13 Annulus Pressure History 100 I 90 ob 80 .N a 70 - 2 7/8 x 7 5/8 _ —♦— 7 S/8 x 10 3J4 �_ _rte- 60 ` N 50 °.' 40 11 a 30 t 20 10 0^ ^ ^ A ^ A A A Illy Y� Y� Y� Y� Y� A y� 'Y� ,Y� (< 41, PJB <V Month/Year I - 2 7/8 x 7 5/8 _ —♦— 7 S/8 x 10 3J4 �_ _rte-