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Home My WebLink About2013 CINGSACook Inlef X frurQ1a- oS Q' STORAI y l ¢ May 15, 2014 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 71h Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster — Chair of Commission 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 RE: Cook Inlet Natural Gas Storage Alaska Annual Material Balance and Storage Performance Report Dear Chairman Foerster: RECEIVED MAY 15 2014 AOGCC 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. Rule 8 of Storage Injection Order No. 9 (SIO 009) 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 two full years of operation. The enclosed report, in compliance with Rule 8 of SIO 009, documents gas storage operational activity during the past twenty-four months and includes monthly net injection/withdrawal volumes for the facility and total gas inventory at month-end. Any questions concerning the attached information may be directed to Richard Gentges at 989- 464-3849. Sincerely, M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Attachment Cook Inlet Natural Gas Storage Alaska, LLC 2013-2014 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 limited the maximum allowed reservoir pressure to 1700 psia. In May 2013, the AOGCC certified the storage capacity of the Cannery Loop Sterling C Gas Storage Pool to 10,500,000 Mcf based on actual pressure versus inventory data recorded by CINGSA during its initial year of operation. This pressure versus inventory data suggested the reservoir might not be capable of containing the design working gas capacity (11,000,000 Mcf) without exceeding the maximum reservoir pressure of 1700 psi. Rule 8 of SIO 9 states that CINGSA must 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. This report is the second such annual report to be filed by CINGSA. The facility was commissioned in April 2012, and CINGSA has now completed two 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 gas inventory at month-end. A plot of the actual wellhead pressure versus total gas 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 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 CLUS-1 well. This gas has since comingled 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 ranges from 14-18 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 injection/withdrawal flow rate performance of each of the five wells. Individual well deliverability appears unchanged from the 2012-2013 storage cycle. While CLU S-5 exhibited some performance decline during the 2014 withdrawal period, it appears that hydrates in the well/meter run were likely the cause for the decline in this well's performance. There is no evidence which 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 of which was one week in duration. The first occurred during November 2013 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 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. The 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 also indicates there is no evidence of any gas leakage from the Sterling C Gas Storage Pool. 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 Cl c interval of the CLU Storage -1 well, all of the injected gas remains with the greater reservoir and is accounted for at this time. 2013-2014 Storage Operations The 2013-2014 storage cycle covers the period from April 15, 2013, which was the final day of the spring semi-annual shut-in test last year, through April 9, 2014. Total storage inventory at April 15, 2013 was 13,106,887 Mcf. Table 1 lists the remaining native gas -in-place as of April 1, 2012, net injection/withdrawal activity by month during the past 24 months, and the total gas -in-place at the end of each month since storage operations commenced. 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 Storage -3 was shut-in for most of the summer of 2012 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 Storage -3 versus total inventory from April 1, 2012 through April 9, 2014. 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 Storage -3 initially aligned with simulated pressure from the modeling studies. However, at inventory levels above approximately 1 I Bcf, the shut- in wellhead pressure on CLU Storage -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 over a relatively short period of time, and not necessarily indicative of a lack of storage integrity. In this field, however, the higher than expected pressure appears largely due to an isolated pocket of native gas that CINGSA encountered when it initially perforated/completed the C 1 c sand interval in the CLU Storage -I well. It appears that this gas has since comingled 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 Storage -3 versus total inventory plot indicates there currently is no evidence of gas loss associated with storage operations, nor any other loss of well or reservoir integrity. Well Deliverability Performance The CINGSA facility is equipped with a robust station control automation and data acquisition (SCADA) system, which includes the capability to monitor and record pressure and flow rate for each of the wells 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. 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. During much of the 2013-2014 storage cycle, only CLUS-1, 2, 4, and 5 were used for injections and withdrawals. CLU S-3 remained shut-in much of the time for pressure monitoring, but was opened on a very limited basis during both the injection and withdrawal seasons. Spot checks were made of the deliverability performance of all five wells relative to observed performance during the 2012-2013 cycle and historical back -pressure test results. Generally speaking, none of the wells appear to have experienced any decline in deliverability potential. Analysis of the actual flow data of the four wells that were used for injections and withdrawals indicates that during injections, CLU S-1 typically accounted for 40-45% of the total field flow, CLU S-2 and 4 accounted for approximately 20% each, and CLU S-5 accounted for 15-20% of the total flow. During the withdrawal season, CLU S-1 accounted for approximately 60-65% of total field flow, CLU S-2 and 4 accounted for 15-20% each, and CLU S-5 accounted for less than 10% of total field flow. Field Operations reported that hydrates were observed in the meter run of CLU S-5 later in the withdrawal season, and this could potentially account for what appears to be a reduction in the performance of that well. Other than this issue, there is no clear indication as to why the performance of CLU S-5 appears to have decreased during the withdrawal season and CLU S-1 increased. CLU S-3 was shut-in and not used for injection or withdrawals other than on a limited basis. During the brief periods when CLU S-3 was used during both injections and withdrawals, its deliverability performance was directly in line with its performance during the 2012-2013 season and historical back -pressure test results. Generally speaking, individual well deliverability appears unchanged from the 2012- 2013 season, and there is no evidence which suggests a decline in deliverability performance in any of the five wells which could be indicative of a loss of well bore integrity. 2013 Injection Operations and November 2013 Shut-in Pressure Test Injections into the field resumed on April 16, 2013, immediately after the April 2013 shut-in test, and continued largely uninterrupted through October 280i. Total injections during the summer 2013 season amounted to approximately 3,232,000 Mcf, and rates averaged about 16 mmcf/d. On the morning of October 280, all of the wells were shut- in for pressure monitoring. Total gas inventory at October 29, 2013 was 16,339,046 Mcf, which included 9,339,048 Mcf of customer working gas plus 6,999,998 Mcf of CINGSA base gas. Table 2 lists the wellhead shut-in pressure for all five wells each day during the shut-in period. It also lists the day-to-day decline in pressure and the overall weighted average pressure of all five wells. On the final day of shut-in, wellhead pressures ranged from a high of 1609 psig on CLU S-1 to a low of 1521 psig on CLU S-3. The corresponding calculated bottom hole, or reservoir pressure, for these two wells is 1830 psia and 1730 psia, respectively. It is clear from reviewing this data that wellhead pressure had not fully stabilized during the week-long shut-in; shut- in pressure on Wells 1, 2, 4, and 5 declined continuously during the period and rose slightly on Well 3. On the final day of shut-in, field average pressure was still declining at a rate of 1.5-2.0 psi/day. Figure 2 is a plot of the shut-in wellhead pressure of each of the five wells and the weighted average wellhead ressure data for all five wells. The overall average wellhead pressure on November 49 was 1581 psig and the average reservoir pressure was 1798 psia. Table 2 provides a summary of the individual shut-in wellhead pressure readings for each day during the week-long stabilization period, the weighted average wellhead pressure, and the day to day change in pressure for each well and the overall field. 2014 Withdrawal Operations and April 2014 Shut-in Pressure Test Storage withdrawals from the field commenced on November 4h and were continuous through the remainder of the month and December. January operations consisted of both injections and withdrawals, with a minor net injection occurring for the month. During February and March, the field remained on continuous withdrawals. Withdrawals from storage during the entire winter 2014 period amounted to approximately 3,192,000 Mcf. Field Operations reported that approximately 150 barrels of produced water was recovered during the withdrawal season. The field was shut-in for pressure stabilization and monitoring on the morning of April 1. Total gas inventory at April 1, was 13,147,315 Mcf, which included 6,147,315 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 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 1390 psig on CLU S-3 to a low of 1276 psig on CLU S-1. Itis clear from reviewing this data that wellhead pressure had not fully stabilized during the week-long shut-in; shut-in pressure on Wells 1, 2, 3, and 4 increased continuously during the period. Wellhead pressure on CLU S-5 remained flat throughout the shut-in period because it was shut-in nearly three weeks prior on March 1P. On the final day of shut-in, field average pressure was still increasing at a rate of approximately 1 psi/day. Figure 3 is a plot of the shut-in wellhead pressure of each of the five wells and the weighted average wellhead pressure data for all five wells. The overall average wellhead pressure on April 8a' was 1321 psig and the average reservoir pressure was 1498 psia. Table 3 provides a summary of the individual shut-in wellhead pressure readings for each day during the week-long stabilization period, the weighted average wellhead pressure, and the day to day change in pressure for each well and the overall field. 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 four 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 at November 8, 2012, April 15, 2013, November 4, 2013, and April 9, 2014 compared to the original (discovery pressure) conditions. The actual shut-in pressure in all three instances is higher than would be expected relative to the original BHP/Z versus gas-in-place discovery line (material balance). Linear regression analysis of these four data points indicates there is a very strong correlation between the four points; the regression coefficient (R) is 0.967. As noted above, CINGSA believes it encountered an isolated pocket of native gas which was possibly still at native discovery pressure when CLU Storage-1 was initially perforated/completed. Wellhead pressure on the CLUS-1 well rose to approximately 1600 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 I c sand interval is one of five recognized sand intervals that are common to nearly all of the wells that penetrate the Cannery Loop Sterling C Pool. This particular sand interval was also one of the perforated/completed intervals in the CLU-6 well — the sole producing well during primary depletion of the Cannery Loop Sterling C Pool. Following initial perforation/completion, a temperature log was subsequently run in CLU Storage-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 CLUS-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 Cl c effectively adds to the remaining native gas in the reservoir and thus account for the fall 2012, spring 2013, fall 2013, and spring 2014 shut-in pressure points plotting above the original BHP/Z versus gas-in-place line. Either way, this pocket of native gas provides pressure support to the storage operation and effectively functions as additional base gas. Preliminary Estimate of Additional Native Gas Volume 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 November 2012, April 2013, November 2013, and April 2014, together with observed shut-in pressures from CLU S-3 to estimate the magnitude of additional native gas encountered in the Cle 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 well CLU S-1 in late January 2012. Gas is allowed to migrate between the reservoirs. The connection between the reservoirs is 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 Clc 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 Cl 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 Cl c sand interval having 14.5 Bcf of original gas -in-place at initial reservoir pressure conditions. Figure 6 shows the transfer rate over the period of gas storage operations up until the end of March 2014 as well as the estimated cumulative net transfer of gas through storage history. The initial transfer rate was 43 mmcf/d. Various combinations of Clc sand volume and transfer coefficients were explored. A range of Clc sand volumes from 14 Bcf to 16 Bef gave reasonable solutions and can be considered a reasonable range of uncertainty. Given the early stage of storage operations, 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 can 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 November 2013. 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 as defined here 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 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-1. The match between observed pressure and production data and that computed by the reservoir model was very good on CLU S-2 and S-4, and reasonably good on CLU S-1, but not quite as good on CLU S-3 and S-5. The estimated volume of incremental gas that yielded the best history match was 18 Bcf. The modeling effort thus far has resulted in a reasonably acceptable match between actual observed pressures and pressure predicted by the model. As noted above, the current modeling effort includes operating history through November 2013. CINGSA intends to resume the modeling process in the very near future as soon as technical resources become available to perform the work. Once the 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 Clc sand interval that was encountered when CLU S-1 was initially perforated/completed. 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 four of the shut-in periods (November 2012, April 2013, November 2013, and April 2014) 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. 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. 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 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 is 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 and annulus are never equal, which demonstrates wellbore integrity. Figures 12-22 illustrate similar data on each of the Hilcorp wells that penetrate the Sterling C gas storage pool. 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 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 at April 1, 2012 and has now completed two 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 Storage -3 has trended above the stabilized pressure line developed from initial computer modeling studies of the reservoir Individual well deliverability appears unchanged from the 2012-2013 storage cycle. While CLU S-5 exhibited some performance decline during the 2014 withdrawal period, it appears that hydrates in the well/meter run were likely the cause for the decline in this well's performance. There is no evidence of a change in deliverability in any of the CINGSA storage wells that may indicate a loss of well integrity. There is evidence which indicates that initial completion work on CLU Storage -1 encountered an isolated pocket of native gas within the Sterling CI c sand interval. This gas has since co -mingled with gas in the main (depleted) portion of the reservoir, effectively adds to the remaining native gas reserves, and provides 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 Storage -3 and the field -wide shut-in pressures observed during each of the three 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 14-18 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 November 2012, April 2013, November 2013, and April 2014 exhibit a very strong linear correlation (R2 = 0.967). Thus, the results of these four 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 CIc interval of the CLU Storage -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 Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Month Infections - Md Withdrawals - Md Compressor Fuel&Losses Total GasinStorage - Md Mar -12 0 0 3556,165 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 Table 2 - November 2013 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures fosiel and Dates WAP M.M eiaM1 f Ch wv21aMVI wv3y.M2 DaV4MD S wv5MM4 DaVIM .v5 wv7y.wv6 4.5 .3.3 .19 -2.4 -1.5 .1.6 dhM H w dAm M Punsure IDWO'Dav 1YS/yHDf 0.vi Deva vt9 D.v4 wvz wy6vx5 M)y wv6 CLU SS W.M.. iPwyM MD•u.SwH l0 l0IgInmi3 .2.3 ;J 11 AM13 IMM3 11131M JIAMI3 CLUS3 M351619.5 CLU S4-5.2 165.1 1615.1 1613.2 .3 1811.0 15992 CLU S-2 3 47.6% 41.6% 16000 16051 1604.0 16025 IWI1511.1 16004 15996 CLUS3 24,024 1511.9 15191 15195 15196 1519.5 15304 1205.2 CLU S-4 91.011 1591.1 1382.9 15925 1588] 15855 15860 15649 ism9 CLU SS 53,1ss 15893 IMI..9 3581.1 15161 3580 1560] 15666 1564.9 CLU S5 332.1u IM3.4 1342.9 1342.9 13410 13429 13422 13425 WeIBhu,d AVB.WHPIWAPI 332.121 1596.9 ISIM 1599.1 IL6.2 1583.8 1582.3 1580.7 WAP M.M eiaM1 f Ch wv21aMVI wv3y.M2 DaV4MD S wv5MM4 DaVIM .v5 wv7y.wv6 4.5 .3.3 .19 -2.4 -1.5 .1.6 Table 3 - April 2014 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures fesiel and Dates dhM H w dAm M Punsure IDWO'Dav 1YS/yHDf 0.vi Deva vt9 D.v4 wvz wy6vx5 M)y wv6 CLU SS 2.4 .3A -1.9 .2 1.7 .1 .13 d5 3.8 CW S2 .2.3 ;J -1.5 .1.3 0.3 CLU S3 1.2 0.4 01 On 09 0.3 CLU S4-5.2 44 -3 -32 8 32 .2.5 11 CLU 55 -0 .5 4.E 3.3 3.1 11 Table 3 - April 2014 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures fesiel and Dates Weigh) 2.130•- used o, Pry Eastwood lag M.M W,4h, PMO,• We[On dAm M Punsure IDWO'Dav gM,,j Dav3y.wv1 wv3y wv3 wv4w.M3 0.v5y:0114 Ittorm Pore-hy- Davy D.16 WAP Gun¢ 4.3 3.2 1.1 1.9 1.3 0.6 e'J[MN>me IPor •neL MD•ILSwII 4/2/M14 4/3/2014 443014 4 204 4/6/2014 4/71MI4 3014 CWS -1 10.235 12650 1263.9 1220,2 12210 1213.7 1225.1 1276.1 CWS -2 42.696 12313 12293 1201.1 12026 12030 1204.9 1205.2 CW S3 24.024 1577 1382.9 1386.3 13M2 1389.8 1390.6 13904 C.S. 97,011 1300.6 13113 13186 13234 13275 1330.5 1331.9 CLU S5 931a IM3.4 1342.9 1342.9 13410 13429 13422 13425 332.121 WeiA4M Avg. WHP IWAP) 1302.3 131I.S 1314.7 1316.7 1318.1 1320.0 I3me Weigh) 2.130•- used o, Pry Eastwood lag M.M We[On dAm M Punsure IDWO'Dav gM,,j Dav3y.wv1 wv3y wv3 wv4w.M3 0.v5y:0114 Orv6n MS Davy D.16 WAP Gun¢ 4.3 3.2 1.1 1.9 1.3 0.6 Weli i4 a wv2w.0av1 IMiW May M2 WI well Prywn Iw.m.w. Shine wv4y Dev3 MSw.Dav4 Oav6y wv5 M1y.Dav6 CLUSI 2.9 33 1.0 2.7 1.4 1 CIUS2 2 IS L5 1.2 IA 0.3 CLUS-3 50 34 I.9 16 Oe -02 CLOS. 106 14 48 4.1 3 14 CLVS5 O5 0 -0.I 0.1 -02 -0.2 Weigh) 2.130•- used o, Pry Eastwood lag M.M Table 4 — Shut-in Reservoir Pressure History and Gas- in -Place Summary Total Gas -in Kam -MMd 0 26,500 Total Gas -in Mace - MMd 11,223.715 13,106.887 16,339.046 13,147.315 Shut-in Reservoir Pressure History and Gas -in -Place Summary OrWnal fOlscevervl Resesvok[ondMms Wellhead Pressure-nsa. Bottom Hole Pressure -osia z - Facto r P - PsIa Date 0 10/28/2000 1950 2206 0.8465 2606 Storage Owning 0und3lons W&hted Ave-WelBkad Cakulated Bottom Hole one Pressure-osle. Pressure -osia Z- Factor HP - psis 11/8/2012 1269.9 1434.9. 0.8719 1645.7 4/15/2013 1344.4 1522.35 0.8663 1756.3 11/4/2013. 1580.7 1798.1 0.8508 2113.4 4/8/2014 1320.6 1497.7 0.8662 1729.0 Gas Gravity: 0.56 N2Conc.: 0.3% CO2Conc.: 0.3%' Reservoir Temp. (deg. F): 105' Datum Depth (ft.): 4950 Total Gas -in Kam -MMd 0 26,500 Total Gas -in Mace - MMd 11,223.715 13,106.887 16,339.046 13,147.315 Figure I — CLU S-3 Wellhead Pressure versus Inventory 2000.0 1800.0 1600.0 1400.0 rn a 1200.0 d M d 1000.0 i a d U 800.0 600.0 400.0 200.0 0.0 CINGSA Pressure vs. Inventory Hysteresis 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf --x--Initial Cycle Design —Second Cycle Design —6 Stabilized Wellhead Pressure Design --m—Actual Shut-in Pressure vs. Inventory - CLUS-3 Pressure • Fall 2012 Weighted Average Shut-in Wellhead Pressure Spring 2013 Weighted Average Wellhead Shut-in Pressure ■ Fall 2013 Weighted Average Wellhead Shut-in Pressure c Spring 2014 Weighted Average Wellhead Shut-in Pressure 5,000 10,000 15,000 20,000 25,000 Total Field Inventory, mmscf Figure 2 — November 2013 Wellhead Shut-in Pressures CINGSA Fall 2013 Wellhead Shut-in Pressures 1640 1620 m 1600 — a X ti --CLU Storage 1 1580 — X. a —i—CLU Storage v X. 1560 X --t-CLU Storage I 3 —iI—CLU Storage 4 1540 L x CLU Storage 5 1520 —.r Field Weighted Avg. Press. 1500 10/30 10/31 11/1 11/2 11/3 11/4 10/29 Shut-in Date Figure 3— April 2014 Wellhead Shut-in Pressures CINGSA Spring 2014 Wellhead Shut-in Pressures 1410.0 1390.0 •r 1370.0 CL u+ 1350.0 a x x x - -- ----- - x x CL 1330.0 v L d 3 1310.0 c r 1290.0 v 1270.0 1250.0 4/2 4/3 4/4 4/5 4/6 4/7 4/8 Shut-in Date --#--CLU Storage 1 -41—CLU Storage 2 --t—CLU Storage 3 —M—CLU Storage 4 X CLU Storage 5 —#.—Field Weighted Avg. Press. Figure 4 — Material Balance Plot 3,000 R Q 2,500 N a 2,000 Cannery Loop Sterling C Gas Storage Pool - Material Balance Plot November 2012 - April 2014 v = 1,000 E O O 500 m 0 5,000 10,000 15,000 20,000 25,000 30,000 Gas -in -Place MMd Figure 5 - Historical and Computed Pressures vs. Rate 120 100 80 9 60 E E 40 w M 20 z v` 0 3 -20 -40 0 -60 ISS re 5 - Historical and Computed Pressures vs. Rate 2300 2100 1900 1700 1500 B a 1300 v 1100 h a 700 500 KII -100 100 yti�3y\yy ''��y\yry 6\�o�yti 9\ry��yti 10,y3 1019\y� 9\ro��y� �\3o�ya 6�ti�\yp yti�~9\yry Date yti�ry9\y� Daily Inj/Wdrl Rate - mmcf/d • "KW BHP-psia" • "Calc BHP - psia" O "Obs SI BHP Avg - psia"