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Home My WebLink About2012 CINGSACook Inlet Katurat-G-as STORACa May 6, 2013 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7°i Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster — Chair of Commission Cook Inlet Natural Gas Storage Alaska, LLC 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 Main: 907-334-7980 Fax: 907-334-7671 w .cingsa.com RECEIVED MAY 062013 AOGCC 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. 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. CINGSA has now completed one full year of operations. The enclosed report, in compliance with Rule 8 of SIO 009, 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. Any questions concerning the attached information may be directed to Richard Gentges at 907-310-7322. Sincerely, /K M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Attachment CC: T. Arminski J. Lau J. Sims M. Smith Cook Inlet Natural Gas Storage Alaska, LLC 2012-2013 Storage Field Injection/Withdrawal Performance and Material Balance Report Executive Summarv/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. 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. The facility was commissioned in April 2012, and CINGSA has now completed one full year of operations. 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 consistent with design expectations. This report also includes injection/withdrawal performance data on each of the five wells to illustrate the deliverability capability of each well. Flow rate data from the wells indicates that overall injection/withdrawal capability has improved since late last summer after the wells were re - perforated; overall injection/withdrawal capability now appears to be about 15% higher under typical operating conditions. While overall field deliverability is below what CINGSA hoped to achieve under the original design, the deliverability of each well is nonetheless consistent and predictable. Two planned facility shut -downs were conducted during the first year of operations, each a week in duration. The first occurred during November 2012 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 caprock 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, reservoir integrity remains intact; all of the injected gas remains with the reservoir and is accounted for. Initial Storage Operations CINGSA began storage injections into the Cannery Loop Sterling C Gas Storage Pool on April 1, 2012. At that time, the estimated remaining gas -in-place was 3,556,165 Mcf. Injections into the Pool continued through October 2012. Injection operations were suspended on November 1, 2012 and all five wells were shut-in for a one-week period to monitor wellhead pressure and to allow reservoir pressure to stabilize. The wells were subsequently opened and injections resumed during most of November and December due to relatively warm weather conditions. A week-long period of relatively high rate withdrawals from storage occurred in late December and in late January for a three-day period due to extremely cold weather, after which injections resumed. Other than these two short periods, field operations remained largely on injection throughout the winter until late March, when operations consisted of continuous withdrawal for a period of approximately ten days. Table 1 lists the remaining native gas-in—place as of April 1, 2012, net injection/withdrawal activity by month during the past 12 months, and the total gas -in-place at the end of each month. 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 basic and primary tool 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 15, 2013. 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 aligns well with simulated pressure from the modeling studies. This confirms that pressure response as a function of injection activity is consistent with the historical response during primary depletion of the reservoir, and that there is no evidence of gas loss associated with current storage operations. 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 performance could be tracked against the results of back -pressure tests performed on each well. Spot readings associated with each well were plotted for both injections and withdrawals during periods when the wells were subject to steady and consistent flow. Figures 2-6 illustrate the actual spot flow rate readings for each well relative to its back-pressure test results from the summer of 2012; blue data points indicate injection, red indicates withdrawal, and purple indicate transient conditions due to changes in overall station flow. While there is some scatter in the data, it is clear that each well is generally performing consistent with, or in many instances slightly better than, expectations based on their back-pressure test results. This data supports the conclusion that none of the storage wells are exhibiting any evidence of a loss of integrity. November 2012 Shut-in Pressure Test On November 1, 2012, injections were suspended and all five injection/withdrawal wells were shut-in for pressure stabilization. Total storage inventory was 11,218,827 Mcf, which included 5,735,256 Mcf of customer working gas plus 5,483,571 Mcf of CINGSA base gas. Shut-in wellhead pressure was recorded daily on each of the wells through November 8'h. Figure 7 is a plot of this data. Pressure readings on Wells 1, 2, 4, and 5 initially ranged from 1315 —1345 psig, and declined through the week to a range of approximately 1260 —1290 psig. Shut-in pressure on CLU Storage-3 was initially 1185 prig and declined to about 1170 psig; pressure on this well was lower relative to the other wells due to the limited volume of gas injected into it. The overall average wellhead pressure on November 8`h was 1270 psig and average reservoir pressure was 1435 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. Individual wellhead pressures on the final day of the seven day shut-in period were still declining slightly at a rate of about 2-3 psi/day. The max/min pressure difference between wells on the final day of the shut-in was 123 psi, with Well 1 at 1292 psig and Well 3 at 1169 psig, suggesting a fair amount of pressure instability remained across the reservoir. This is not surprising given that daily injection rates were relatively high during the month of October, and averaged nearly 55 MMcf/d prior to shutting in all of the wells. Reservoir pressure at the time injections began on April 1, 2012 was approximately 400 psia. Thus, during the seven month period preceding shut-in, reservoir pressure increased over 1000 psi — or about 45% of original discovery pressure. Given this relatively rapid increase in pressure, it is reasonable to expect that pressure would not fully stabilize over a week-long shut-in period. Although it is not possible to rigorously project (i.e., via Horner Analysis) where reservoir pressure would have ultimately stabilized had CINGSA been able to leave the wells shut-in for a longer period of time, it is clear from Figure 2 that wellhead (and reservoir pressure) was indeed trending toward a stabilized condition. The shut-in pressure readings of all five wells are consistent with injection operations and the pressure versus volume relationship of this reservoir as noted above. April 2013 Shut-in Pressure Test On April 9, 2013, storage operations were again suspended so that the wells could be shut-in to allow reservoir pressure to stabilize. Total gas inventory at that time was 13,167,606 Mcf, which included 4,183,007 Mcf of customer working gas plus 8,984,599 Mcf of CINGSA base gas. Shut-in wellhead pressure was recorded on each of the wells through April 15`". Figure 8 is a plot of this data. The initial shut-in pressures on CLU Storage -1 and Storage -2 were higher than the other wells because they were shut-in a few days ahead of the other wefts. On the second day of the shut-in, pressures ranged from a low of 1308 psig on CLU Storage - 4 to a high of 1375 psig on CLU Storage - 1. At the end of the six day shut-in, the max/min pressure range narrowed to 1313 —1376 prig between Well 4 and Well 1, respectively. Individual wellhead pressures were still increasing slightly at a rate of about 1 psi/day on the final day of the April shut-in. The magnitude of difference between the highest and lowest pressure wells was approximately half as large as the end of the week-long shut-in in November 2012, but still suggested a fair amount of pressure instability across the reservoir. The overall average wellhead pressure on April 15th was 1344 psig and the average reservoir pressure was 1522 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, and the same data for the two shut-in periods since commencement of storage operations. It also includes 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 (P/Z) versus gas -in- place at November 8, 2012 and April 15, 2013 compared to the original (discovery pressure) conditions. The actual shut-in pressure in both instances is somewhat higher than would be expected relative to the original P/Z versus gas -in-place discovery line (material balance). When CLU Storage -1 was initially completed the shut-in wellhead pressure rose to approximately 1600 psig within a few days after perforating; wellhead pressure on the remaining four wells was approximately 400 psig, which was consistent with the depletion status of the reservoir. During drilling of the new storage wells, CINGSA anticipated that it might encounter isolated regions of the reservoir that remained at elevated pressure given the fluvial deltaic characteristics of the reservoir, and from discussions with producers in the Cook Inlet who relayed similar observations indicating evidence of reservoir compartmentalization. Owing to its higher pressure, Well # 1 [NTD: CLU Storage —1?] remained shut-in when the field was initially opened for injections because its shut-in pressure exceeded the injection pressure (about 700 psi at the time). A temperature log was run in CLU Storage —1 in an effort to fully understand the nature and source of the higher pressure. The temperature log exhibited strong evidence of gas influx in the sand interval which correlates to the Sterling C2a sand interval. The higher than expected shut-in pressure and evidence of gas influx suggest the C2a was indeed physically isolated from the other four sand sub -intervals within the Sterling C Pool. It is unknown whether the C2a was at native discovery pressure (approx. 2200 psi), or only partially depleted. The shut-in pressure of CLU Storage —1 gradually declined over a period of approximately 60 days as pressure equalized within the wellbore, and the well was opened for injections on May 1, 2012 along with the other four wells. If fully isolated from the greater reservoir, as appears to have been the case, completion of the C2a would effectively add to the remaining native gas in the reservoir and thus account for the Fall 2012 and Spring 2013 shut-in pressure points plotting above the original P/Z versus gas -in-place line. Although this is a very plausible explanation for this observation, at this time it is not possible to state definitively that this is the case nor make a definitive statement as to the quantity of additional native gas that may have been added. As noted above, it is also likely that this observed behavior is attributable in part to unstable reservoir pressure over the course of the relatively short (7 day) shut-in periods. It is conceivable that it could take several months for pressure to fully stabilize during this initial re -fill of the reservoir. The observed "hysteresis effect' is illustrated in Figure 1 and is due to having to overcome capillary pressure with injection pressure that is lower than hydrostatic pressure. This type of pressure response is consistent with the initial operation of a depleted gas reservoir that has been converted to storage and is in its first storage operating cycle. Thus, similar to Figure 1, Figure 9 strongly supports the conclusion that reservoir integrity is intact. With time and additional injection and withdrawal activity, it will be possible to make a definitive assessment as to whether the C2a was effectively isolated from the reservoir and an estimate of any incremental native gas associated with that sand sub -interval, or whether pressure instability alone accounts for the higher than expected shut-in pressures on the material balance plot, or some combination of the two. The key point to note is that the observed BHP/Z values for both the November 2012 shut-in and the April 2013 shut-in are above the original pressure -depletion line which provides very compelling evidence that reservoir and well integrity is intact and not "leaking". Annulus Pressure Monitorin¢ 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 10-14 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 15-25 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 is 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 largely remained above the tubing pressure of any of CINGSA's wells, which demonstrates isolation/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 monitoring 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 one full year 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. Also, individual well deliverability has improved somewhat since re -perforating each well last summer, but is now consistent and predictable; 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 completion work on CLU Storage —1 may have encountered an isolated section of the Sterling C2a sand interval and that this has effectively added to the remaining native gas reserves — effectively functioning as additional base gas. If this is indeed the case, the additional gas -in-place accounts for the higher than expected shut-in pressures that were observed during the November 2012 and April 2013 shut-in periods. Given the relatively immature nature of the storage operation, it is not possible at this time to make a definitive assessment of the volume of this additional native gas (if it is native gas); with additional operating experience it will be possible to do so. Shut-in pressure readings of all the wells during the November 2012 and April 2013 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 for 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 of any loss of integrity based on annulus pressure readings. Accordingly, it is concluded that reservoir integrity remains intact; all of the injected gas is accounted for and remains with the reservoir. Table 1— Monthly Injection and Withdrawal Activity Month Mar -12 Apr -12 May -12 Jun -12 Jul -12 Aug -12 Sep -12 Oct -12 Nov -12 Dec -12 Jan -13 Feb -13 Mar -13 4/14/2013` Cook Inlet Natural Gas Storage Alaska Storage Monthly Storage Activity (all volumes reported are at month end unless noted otherwise) Infections -Md Withdrawals -Mcf compressor Fuel&Losses 146,132 1,238,733 1,245,041 986,472 1,245,260 1,300,153 1,624,167 165,866 379,205 496,560 1,765,296 667,603 51,177 394 1,163 1,048 714 93 982 691 72,417 470,886 209,334 858 554,597 254,532 Table 2 — November 2012 Wellhead Shut-in Pressure Data 2,289 11,540 16,769 12,529 14,038 13,221 15,285 4,895 5,839 7,976 19,372 7,594 1,168 Total Gas in Storage - Mcf 3,556,165 3,699,614 4,925,644 6,152,868 7,126,097 8,357,226 9,643,176 11,251,367 11,339,921 11,242,401 11,521,651 13,266,717 13,372,129 13,167,606 Wellhead Shut-in PressursJ2sia1 and Dates Weight Eattor• - based an Ray Eastwood Log Model Table 3 —April 2013 Wellhead Shut-in Pressure Data Weight6artor' Weighted Ay IDw- D Change] Dw3vs.0w1 Dav3vs.bw2 We 4%s. Davi 0av5vs.Cdw Dw6W.D4y5 Dav2vs.0w6 Dar, 8vs Day) WAP Change -17.2 7.5 -6.1 -56 44 IStaraee Pare -1921= Individual Well Pressure (DawtoDw[hange) Well Name Dav2vs Owl Dav3W.Dav2 Dav4Vs.Dw3 DwSvs.Dw4 Wv6VS.Dw$ Dav7vs.Dw6 Davgv.Dav) Welt St.e fPor•net MP'jLjj1 1111191 11/2j2ol 11/31201 1143012 11/51M 11/6IZ01i 112 1IM2012 CLUS-1 70135 ]349 1315 1309 13D4 1300 1292 1296 1292 CLU 5-2 47,6% 1326 1300 12% 1290 12% 1284 1281 1219 CLU S-3 24.024 1185 1128 1175 1123 1121 1171 1169 1169 CLU 5-4 92.011 1330 1320 1312 1305 1298 1292 1282 1283 CLUS 5 93.]55 1314 1300 12W 1282 1275 1269 1264 1261 332.121 Weighted Avg. WNP (WAP) 1312.4 1300.2 1]92.7 12866 1281.1 1226.7 1222.6 1269.9 Weight Eattor• - based an Ray Eastwood Log Model Table 3 —April 2013 Wellhead Shut-in Pressure Data Weighted Ay IDw- D Change] Dw3vs.0w1 Dav3vs.bw2 We 4%s. Davi 0av5vs.Cdw Dw6W.D4y5 Dav2vs.0w6 Dar, 8vs Day) WAP Change -17.2 7.5 -6.1 -56 44 4.1 -2J Individual Well Pressure (DawtoDw[hange) Well Name Dav2vs Owl Dav3W.Dav2 Dav4Vs.Dw3 DwSvs.Dw4 Wv6VS.Dw$ Dav7vs.Dw6 Davgv.Dav) CLU 5-1 -29 -6 -5 -4 -3 -3 .2 CLU S-2 -26 -6 -4 -4 4 -3 2 CLU S-3 -) -3 -2 2 0 .2 0 CLU 5-4 -10 .8 -) -) -6 -5 -4 CWS -5 -14 -10 -g -) -6 -5 -3 Weight Eattor• - based an Ray Eastwood Log Model Table 3 —April 2013 Wellhead Shut-in Pressure Data WAPChange Well CLUS-1 CLU S-2 CLU 5-3 CLU 5-4 CLU S-5 Welght Factor• - Weed on gay Eastwood Log Model Weighted APreesuee IOn- Dzv Ch -MO Oav2vs Dnyl Ona Da 2 Dn4v5.D4v3 pay Svs Dav4 Oav 6vs. Dns 1D 1.1 10 1.0 0.3 ft,di,idwlW Wellhead Shut-in Pressures (Ds'e) and Dates Dav2vs Onl D4y3V Day 2 Dav4vs Ona Dn Svs Oav4 Dav6vs Davi D4 Weight Pad"' 0.5 0.4 0 0.1 0.4 0.6 0.4 literate tore -feet= 0.8 1.6 1.1 1.1 0.7 1 1.3 IPOrenelhlD4LSwO 4110120 11]/21)13 4132M13 4/13/2013 4114/2011 4715/M Well Name CLU S-1 70.235 1374.5 1374.9 1374.7 1375.2 1375.6 1375.6 CW 5-2 47.696 1368.6 1M.7 1369.1 1369.7 1381.1 1370.1 CLUS-3 24.024 1327.6 1328.4 1330 1331.1 1332.2 1332.9 CLU S-4 97.011 1307.2 13Ce.2 1309.5 1310.9 1312.2 1312.9 CLU S-5 93.155 13363 1338.5 1340.6 1341.9 1343.2 1343.4 332.121 Weighted Avg. WHP(WAP) 1340.0 1341.0 1342.1 ]343.1 1 .1 1344.4 WAPChange Well CLUS-1 CLU S-2 CLU 5-3 CLU 5-4 CLU S-5 Welght Factor• - Weed on gay Eastwood Log Model Weighted APreesuee IOn- Dzv Ch -MO Oav2vs Dnyl Ona Da 2 Dn4v5.D4v3 pay Svs Dav4 Oav 6vs. Dns 1D 1.1 10 1.0 0.3 Table 4 -Shut-in Reservoir Pressure History and Gas- in -Place Summary ft,di,idwlW Well Pressure l0a gkliav Chantel Dav2vs Onl D4y3V Day 2 Dav4vs Ona Dn Svs Oav4 Dav6vs Davi D4 -0.2 0.5 0.4 0 0.1 0.4 0.6 0.4 0 0.8 1.6 1.1 1.1 0.7 1 1.3 1.4 1.3 0.7 1.8 2.1 1.3 1.3 0.2 Table 4 -Shut-in Reservoir Pressure History and Gas- in -Place Summary Shut-in Reservoir Pressure History and Gas -in -Place Summa Original 101scovervl Reservoir Conditions Wellhead Pressure -osig. Bottom Hole Pressure - psi Z - Factor BHP - psis Total Gas -in Place -MMd Date 0 0 10/28/2000 1950 2206 0.8465 2606 26,500 Storage Operating Conditions Weighted Avg. Wellhead Date Pressure -osig. Bottom Hole Pressure -osia Z - Factor BHP - psia Total Gas -in Place -MMd 11/8/2012 1269.9 1434.9 0.8719 1645.7 11,218.800 4/15/2013 1344.4 1522.35 0.8668 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 Conc.: 0.3% Reservoir Temp.(deg. F): 105 Datum Depth (ft.): 4950 Figure 1 1756,3 13,167.606 MGM Pressure vs. Inventory Hysteresis moa 800 Iwo �Inidal Cyte � 5ewnd Cycle —Sbbilixed Wellhead Pressure �� Actual Pressure vs. Inventory � CWSd Pressure 1600 Imo or ;0-0 1000 800 600 — 400 200 0 S'Wo,o00 10,000,000 15,000,000 20,000,000 25,000,000 Total Field Inventory, Msd Figure 2 10000000 ITIIIs 10000 1000 CLU S-1 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance Figure 3 10000 Q, Mscf/D 100000 re - perforating U S-1 8-16-12 after re - perforating 'IActual Flowing Conditionsrrend. �Operatlng Data Trend _JIV I■��w��■■■ IIS■■■�1�1 A FAN %��■■.�.�11�✓t�.■■■■■ ■■��Iiisl�d■NN�I �...,��IPOfi■■■�11 mmmmm m m=mmmmm i■■��i�llli■■■��III' Figure 3 10000 Q, Mscf/D 100000 CLU S-2 Preliminary Well Deliverabill Test Results vs. Actual Withdrawal Performance - 10000000Nor- 1000000 � 1 --a—CLUS-2 5-28-12 before re - perforating CLU S-2 7-11-12 after re - perforating Actual Flowing Conditions Operating � 11��■�■111 Il�i.�'/11111. __ ■111111■■111111 Lo N a N IL �■Rl�1�■■■�oIII 0 ��11�Ilill��■111111 100000 �■■■■Iill�■■■■VIII 10000 MM 1000 10000 100000 Q, Mscf/D 4 Figure ■111111■■111111 CLU S-3 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance 10000000 1000000 N R 6 ��JC�1��11_.■.,,111 CL O 100000perforatingimmoMENActual 10000 PAP Flowing Conditions oil 111 -■.,,1 1000 10000 100000 Q, MscflD Figure 5 ��JC�1��11_.■.,,111 illl�' 111 -■.,,1 �e�1111L.-____.111 Figure 6 CLU S-5 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance 10000000 I I - -—CLU S-5 5-28 -12 before re-perforating -c-- CLU S-5 7-23-12 after re-perforating • Actual Flowing Conditions —Operating Trend 1000000 a N ♦ ♦ IL • O 100000 10000 1000 10000 100000 Q, Mscf/D Figure 7 Figure 8 CINGSA Fall 2012 Wellhead Shut-in Pressures 1350 1325 — �CLU Storage 1 1300 m n O —4 --CLU Storage 2 y 1275 O � O O O —�—CLU Storage 3 rt 1250 ----- m t ACLU Storage 4 3 1225 � 1 H o CLU Storage 5 1200 Field Weighted Average Pressure 1175 1150 — — 11/1 11/2 11/3 11/4 11/5 11/6 11/7 11/8 Shut-in Date Figure 8 CINGSA Spring 2013 Wellhead Shut-in Pressures 1380 1� _ --_ 1360 1—.__— _— --e—CLU Storage 1 m {{1JI o. m i —�—CLU Storage 2 a - 1340 —�—CLU Storage 3 O t J O �CLUStorage4 E t f�- o CLU Storage 5 � N � 1320 Weighted }-- ——Field J� J Avg. Press. 1 1 300 +--- 4/10 — — 4/11 4/12 4/13 4/14 5 4/15 Shut-in Date Figure 9 Faure 30—Annulus Pressure of CLU Storage - 1 Cannery Loop Sterling C Gas Storage Pool - Material Balance PLot November 2012 -April 2013 3,000 BHP/Z = 2606 psia 2,500 --- --- --- A a 2,000 ---- --- Spring 2013 BHP/ 1756.3 ' N a m Fall 2012 BHP/z = 1645.7 N Psia m 1,500 ---_ — ---- —_ __—.—. --.—_. 6 W O 2 v --- c 1,000 Discovery BHP/Z vs. Gas -in -Place --- ---- m rt Fall 2012 BHP/Z vs. Gas -in Place 500 —_— ---_ —__ --. --Spring 2013 BHP/Z vs. Gas in Place 0 0 — 0 5,000 10,000 15,000 20,000 25,000 30,000 Gas -in -Place MMcf Faure 30—Annulus Pressure of CLU Storage - 1 Plot of Tubing and Annulus Pressure vs Time - CLU S-1 2000 ..._. m _._....m.�_.a 9 Sm Annulus l 1800 13 3/S Annulus —Tubme J 1600 -- 1400 —Tue�n¢ 1200 e. 1600 1000 L 6r 800 600 a 1200 400 200 0 WA v n` 600 - Z6 N E2 E2 Q N N N N_ N N N N N (O n m 12 N r N t7 Figure 11 -Annulus Pressure of CLU Storage - 2 2000 Plot of Tubing and Annulus Pressure vs Time - CLU S-2 —95/8 Annulus 1800 —133/SAnnulus -- —Tue�n¢ 1600 1400 a 1200 a 1000 v n` 600 - 600 400 nA 200 0 so N N N N_ N N l7 11 5CV1 Faure 12 -Annulus Pressure of CLU Storage -3 2000—.—�"---- Plot of Tubing and Annulus Pressure vs Time - CLU S-3 �95/B Annulus X95/8 Annulus X133/SAnnulus - 1806 _133/s Annulus 1600 100 v 12200 L —Tubing M 1000 1600 0 600 600 1400 400 m 1200 0 n N N N N N N N N1 (2 d 1000 V n` 800 600 400 200 0 Qd Figure 13 —Annulus Pressure of CLU Storage — 4 2000 Plot of Tubing and Annulus Pressure vs Time - CLU S4 �95/B Annulus 1600 X133/SAnnulus - —Tubing 1600 100 v 12200 L M 1000 { 0 600 600 400 200 0 N N N N N N N N1 (2 Faure 14—Annulus Pressure of CLU Storage —5 Figure 15 —Annulus Pressure of Marathon CLU RD -1 CLU 1RD Annulus Pressure History 80 70 w 20 10 0 o�� oti oti oti o'ti o 0 0 0 otic' \~ otic p�ti�� 6\ti�ti �\ �ti tion~\~ titi\~\ry v\1�ti p\ti�ti 0\ti�ti e\ti�ti tio�y\� titin~ Month/Year Figure 16—Annulus Pressure of Marathon CLU 3 � 41/2 x 7 �7x95/8 CLU 3 Annulus Pressure History 60 — m 50 N a a 40 N N d a` 30 v u w � 3 1/2 x 9 5/8 N 20 10 0 �,ti'L D,y'L oy'L O.1'L �,y'Y O.Y3 oy'3 �.�'h o�3 oti'S OtiM Month/Year Figure 17 — Annulus Pressure of Marathon CLU 4 CLU 4 Annulus Pressure History 12 — — —— -- no 10 .y a I 8 — N N d a` 6 a m � 3 1/2 x 13 5/8 4 135/8x 20 2 0 N6 ti'N� ti ti ti ti Month/Year Figure 18 — Annulus Pressure of Marathon CLU 5 Figure 19 —Annulus Pressure of Marathon CLU 6 CLU 5 Annulus Pressure History 250 aN° 200 a a N 150 v a` � 31/2 x 9 5/8 u m 100 3 N 95/8x133/8 50 0 ti6N, v0� ti�� ti�� ti�~� t�, ti��3 INV Month/Year Figure 19 —Annulus Pressure of Marathon CLU 6 2000 1800 1600 a a 1400 1200 v a` 1000 v 0 800 600 400 CLU 6 Annulus Pressure History 2000 30 01ry Ory p1ry ptiry ptiry py9 pti� py'h p1� pti� pti� a Month/Year Figure 20 — Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 35 30 en .N a 25 N v 20 — 3 1/2 x 9 5/8 o. d 15 9 5/8 x 13 3/8 10 5 0 p�,y ptiry ptiry ptiry p1ry pti9 pyq p,Yq py9 p,1.4 pti� ,y�ti�ry b�h\ry b\ti�ry ��~\'L b��ry b�ti\ry 40ry Sp\~�ry ,yy�ti�ry tip\y\ry tiry\~\ry Month/Year Figure 21—Annulus Pressure of Marathon CLU 821—Annulus Pressure of Marathon CLU 8 Figure 22 —Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180 CLU 8 Annulus Pressure History 120 T 160 — -- oe a 100 N d a 140 a a 120 80 N N v 100 N d a a` 60 a u f0 U 80 A 60 �3 1/2 x 9 5/8 5 40 � 31/2 x 9 5/8 40 �95/8x 133/8 — 95/8x133/8 20 20 O'1ti O'1ti O'1ti 0''ti O'1ti 0.13 0.19 0.19 0,13 0,19 0,19 Month/Year 0''ti 0''ti 0''ti Otiti py'L oy3 0.19 0.19 0.13 0,19 O,y'9 Figure 22 —Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180 160 — -- oe a 140 a 120 N N v 100 a U 80 A 60 � 31/2 x 9 5/8 40 — 95/8x133/8 20 0 0''ti 0''ti 0''ti Otiti py'L oy3 0.19 0.19 0.13 0,19 O,y'9 Month/Year Figure 23 — Annulus Pressure of Marathon CLU 10 Figure 24—Annulus Pressure of Marathon CLU 11 CLU 10 Annulus Pressure History 60 ---- — i 90 __ m 50 —f-- a a 80 v n 40 ---- 5 a 70 ig 60 a` 30 v �— 31/2 x 9 5/8 U y A N20 X31/2 x95/8 .9 5/8 x 13 3/8 u 40 10-4 L 04 O~ry O1ry Otiry Otiry Otiry Otis p1M OtiM 0,y3 Oti3 pti� — 95/8x133/8 S,o tiry\�\ry ry\1�ry P�•'\ry b�~\ry 0�y\ry y0�1\ry �'1��\ry Month/Year Figure 24—Annulus Pressure of Marathon CLU 11 Figure 25 — Annulus Pressure of Marathon CLU 12 CLU 11 Annulus Pressure History 100 — 90 a 80 n a 70 ig 60 v y 50 X31/2 x95/8 u 40 — 95/8x133/8 30 20 10 0 Oyry O� Otiry O~ry 01ry O� 01� Otis Otis Otis O~� 'L�1\ry 0.\ry�ry b\ti�ry $\ry�ry 0.�1\ry 6\ry�ry 4\,Y�'L ,10�•'\ry .Y'L�ry\ry tiO�h\ry ti'�1�ry Month/Year Figure 25 — Annulus Pressure of Marathon CLU 12 CLU 12 Annulus Pressure History 10 — 9 •°-�° 8 j— - -- - n w 7 6 a a` 5 v n Q nside 95/8 � 3 2- 1 0 O1,y O1ti olti O1ti Otiti O1� O1� Otis Otis O13 OtiM Month/Year Cook Inlet Natural Gas Storage Alaska, LLC 2012-2013 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. 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. The facility was commissioned in April 2012, and CINGSA has now completed one full year of operations. 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 consistent with design expectations. This report also includes injection/withdrawal performance data on each of the five wells to illustrate the deliverability capability of each well. Flow rate data from the wells indicates that overall injection/withdrawal capability has improved since late last summer after the wells were re - perforated; overall injection/withdrawal capability now appears to be about 15% higher under typical operating conditions. While overall field deliverability is below what CINGSA hoped to achieve under the original design, the deliverability of each well is nonetheless consistent and predictable. Two planned facility shut -downs were conducted during the first year of operations, each a week in duration. The first occurred during November 2012 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 caprock 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, reservoir integrity remains intact; all of the injected gas remains with the reservoir and is accounted for. Initial Storage Ooerations CINGSA began storage injections into the Cannery Loop Sterling C Gas Storage Pool on April 1, 2012. At that time, the estimated remaining gas -in-place was 3,556,165 Mcf. Injections into the Pool continued through October 2012. Injection operations were suspended on November 1, 2012 and all five wells were shut-in for a one-week period to monitor wellhead pressure and to allow reservoir pressure to stabilize. The wells were subsequently opened and injections resumed during most of November and December due to relatively warm weather conditions. A week-long period of relatively high rate withdrawals from storage occurred in late December and in late January for a three-day period due to extremely cold weather, after which injections resumed. Other than these two short periods, field operations remained largely on injection throughout the winter until late March, when operations consisted of continuous withdrawal for a period of approximately ten days. Table 1 lists the remaining native gas-in—place as of April 1, 2012, net injection/withdrawal activity by month during the past 12 months, and the total gas -in-place at the end of each month. 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 basic and primary tool 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 15, 2013. 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 aligns well with simulated pressure from the modeling studies. This confirms that pressure response as a function of injection activity is consistent with the historical response during primary depletion of the reservoir, and that there is no evidence of gas loss associated with current storage operations. 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 performance could be tracked against the results of back -pressure tests performed on each well. Spot readings associated with each well were plotted for both injections and withdrawals during periods when the wells were subject to steady and consistent flow. Figures 2-6 illustrate the actual spot flow rate readings for each well relative to its back -pressure test results from the summer of 2012; blue data points indicate injection, red indicates withdrawal, and purple indicate transient conditions due to changes in overall station flow. While there is some scatter in the data, it is clear that each well is generally performing consistent with, or in many instances slightly better than, expectations based on their back -pressure test results. This data supports the conclusion that none of the storage wells are exhibiting any evidence of a loss of integrity. November 2012 Shut-in Pressure Test On November 1, 2012, injections were suspended and all five injection/withdrawal wells were shut-in for pressure stabilization. Total storage inventory was 11,218,827 Mcf, which included 5,735,256 Mcf of customer working gas plus 5,483,571 Mcf of CINGSA base gas. Shut-in wellhead pressure was recorded daily on each of the wells through November 8`h. Figure 7 is a plot of this data. Pressure readings on Wells 1, 2, 4, and 5 initially ranged from 1315 —1345 psig, and declined through the week to a range of approximately 1260-1290 prig. Shut-in pressure on CLU Storage -3 was initially 1185 psig and declined to about 1170 psig; pressure on this well was lower relative to the other wells due to the limited volume of gas injected into it. The overall average wellhead pressure on November 8th was 1270 psig and average reservoir pressure was 1435 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. Individual wellhead pressures on the final day of the seven day shut-in period were still declining slightly at a rate of about 2-3 psi/day. The max/min pressure difference between wells on the final day of the shut-in was 123 psi, with Well 1 at 1292 psig and Well 3 at 1169 psig, suggesting a fair amount of pressure instability remained across the reservoir. This is not surprising given that daily injection rates were relatively high during the month of October, and averaged nearly 55 MMcf/d prior to shutting in all of the wells. Reservoir pressure at the time injections began on April 1, 2012 was approximately 400 psia. Thus, during the seven month period preceding shut-in, reservoir pressure increased over 1000 psi —or about 45% of original discovery pressure. Given this relatively rapid increase in pressure, it is reasonable to expect that pressure would not fully stabilize over a week-long shut-in period. Although it is not possible to rigorously project (i.e., via Horner Analysis) where reservoir pressure would have ultimately stabilized had CINGSA been able to leave the wells shut-in for a longer period of time, it is clear from Figure 2 that wellhead (and reservoir pressure) was indeed trending toward a stabilized condition. The shut-in pressure readings of all five wells are consistent with injection operations and the pressure versus volume relationship of this reservoir as noted above. April 2013 Shut-in Pressure Test On April 9, 2013, storage operations were again suspended so that the wells could be shut-in to allow reservoir pressure to stabilize. Total gas inventory at that time was 13,167,606 Mcf, which included 4,183,007 Mcf of customer working gas plus 8,984,599 Mcf of CINGSA base gas. Shut-in wellhead pressure was recorded on each of the wells through April 15`h. Figure 8 is a plot of this data. The initial shut-in pressures on CLU Storage -1 and Storage -2 were higher than the other wells because they were shut-in a few days ahead of the other wells. On the second day of the shut-in, pressures ranged from a low of 1308 psig on CLU Storage - 4 to a high of 1375 psig on CLU Storage -1. At the end of the six day shut-in, the max/min pressure range narrowed to 1313 —1376 psig between Well 4 and Well 1, respectively. Individual wellhead pressures were still increasing slightly at a rate of about 1 psi/day on the final day of the April shut-in. The magnitude of difference between the highest and lowest pressure wells was approximately half as large as the end of the week-long shut-in in November 2012, but still suggested a fair amount of pressure instability across the reservoir. The overall average wellhead pressure on April 15th was 1344 psig and the average reservoir pressure was 1522 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, and the same data for the two shut-in periods since commencement of storage operations. It also includes 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 (P/Z) versus gas -in- place at November 8, 2012 and April 15, 2013 compared to the original (discovery pressure) conditions. The actual shut-in pressure in both instances is somewhat higher than would be expected relative to the original P/Z versus gas -in-place discovery line (material balance). When CLU Storage —1 was initially completed the shut-in wellhead pressure rose to approximately 1600 psig within a few days after perforating; wellhead pressure on the remaining four wells was approximately 400 psig, which was consistent with the depletion status of the reservoir. During drilling of the new storage wells, CINGSA anticipated that it might encounter isolated regions of the reservoir that remained at elevated pressure given the fluvial deltaic characteristics of the reservoir, and from discussions with producers in the Cook Inlet who relayed similar observations indicating evidence of reservoir compartmentalization. Owing to its higher pressure, Well # 1 [NTD: CLU Storage —1?j remained shut-in when the field was initially opened for injections because its shut-in pressure exceeded the injection pressure (about 700 psi at the time). A temperature log was run in CLU Storage —1 in an effort to fully understand the nature and source of the higher pressure. The temperature log exhibited strong evidence of gas influx in the sand interval which correlates to the Sterling C2a sand interval. The higher than expected shut-in pressure and evidence of gas influx suggest the C2a was indeed physically isolated from the other four sand sub -intervals within the Sterling C Pool. It is unknown whether the C2a was at native discovery pressure (approx. 2200 psi), or only partially depleted. The shut-in pressure of CLU Storage —1 gradually declined over a period of approximately 60 days as pressure equalized within the wellbore, and the well was opened for injections on May 1, 2012 along with the other four wells. If fully isolated from the greater reservoir, as appears to have been the case, completion of the C2a would effectively add to the remaining native gas in the reservoir and thus account for the Fall 2012 and Spring 2013 shut-in pressure points plotting above the original P/Z versus gas -in-place line. Although this is a very plausible explanation for this observation, at this time it is not possible to state definitively that this is the case nor make a definitive statement as to the quantity of additional native gas that may have been added. As noted above, it is also likely that this observed behavior is attributable in part to unstable reservoir pressure over the course of the relatively short (7 day) shut-in periods. It is conceivable that it could take several months for pressure to fully stabilize during this initial re -fill of the reservoir. The observed "hysteresis effect' is illustrated in Figure 1 and is due to having to overcome capillary pressure with injection pressure that is lower than hydrostatic pressure. This type of pressure response is consistent with the initial operation of a depleted gas reservoir that has been converted to storage and is in its first storage operating cycle. Thus, similar to Figure 1, Figure 9 strongly supports the conclusion that reservoir integrity is intact. With time and additional injection and withdrawal activity, it will be possible to make a definitive assessment as to whether the C2a was effectively isolated from the reservoir and an estimate of any incremental native gas associated with that sand sub -interval, or whether pressure instability alone accounts for the higher than expected shut-in pressures on the material balance plot, or some combination of the two. The key point to note is that the observed BHP/Z values for both the November 2012 shut-in and the April 2013 shut-in are above the original pressure -depletion line which provides very compelling evidence that reservoir and well integrity is intact and not "leaking". Annulus Pressure Monitorin¢ 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 10-14 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 15-25 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 is 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 largely remained above the tubing pressure of any of CINGSA's wells, which demonstrates isolation/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 monitoring 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 one full year 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. Also, individual well deliverability has improved somewhat since re -perforating each well last summer, but is now consistent and predictable; 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 completion work on CLU Storage —1 may have encountered an isolated section of the Sterling C2a sand interval and that this has effectively added to the remaining native gas reserves — effectively functioning as additional base gas. If this is indeed the case, the additional gas -in-place accounts for the higher than expected shut-in pressures that were observed during the November 2012 and April 2013 shut-in periods. Given the relatively immature nature of the storage operation, it is not possible at this time to make a definitive assessment of the volume of this additional native gas (if it is native gas); with additional operating experience it will be possible to do so. Shut-in pressure readings of all the wells during the November 2012 and April 2013 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 for 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 of any loss of integrity based on annulus pressure readings. Accordingly, it is concluded that reservoir integrity remains intact; all of the injected gas is accounted for and remains with the reservoir. 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 -McF Withdrawals -Mcf Comoressor Fuel&tosses Total Gas in Storage - Md 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 4/14/2013* 51,177 254,532 1,168 13,167,606 Table 2 — November 2012 Wellhead Shut-in Pressure Data Weight Fadorr'- based on Ray Eastwood Log Model Table 3 — April 2013 Wellhead Shut-in Pressure Data Wellhead Shut-in Pressures lusial and Dates Dey2..Dav1 Dag Sys. Day 2 Dav4vs.Dav3 DavSW.Csm, Ddy6m Day$ Welaht Faclor' Day 8 vs. Day] WAP Change -17.2 d5 -61 -5.6 -4.4 4.1 -2.7 (Storaee Pme-feet= Individual Well Preuure Mab-to-Dav Chancel W Ie IN P Dav 2 vs. Dav1 Day 3vs. Day2 Day 4m Davi Dnv S vs. DW DBy6ys.WyS Well (Po,-.etM041-5w11 11/1/LH2 1 12 1113 2 11141WI2 11151ml2 11161201 ] 1 U/81202 CLUS-1 70.235 1344 1315 1309 1304 1300 1297 1294 1292 CLU S-2 47.696 1326 230) 12M 1290 1286 1284 1281 12]9 CLU S3 24.024 1185 11]8 1175 1173 1171 1171 1169 1169 CLU S-4 4].011 1330 1320 1312 ]305 1298 1292 128] 12.43 CLU S-5 43.155 U14 1300 1290 1282 12]5 us 1261 1261 332.121 Weighted Avg. WHP(WMI 1317.4 1300.2 152.7 ]286.6 1281.1 12]6.] 128.6 1269.9 Weight Fadorr'- based on Ray Eastwood Log Model Table 3 — April 2013 Wellhead Shut-in Pressure Data WelaMed Awme Pressure MavtpQav Chancel Dey2..Dav1 Dag Sys. Day 2 Dav4vs.Dav3 DavSW.Csm, Ddy6m Day$ Day 7 vs. Day 6 Day 8 vs. Day] WAP Change -17.2 d5 -61 -5.6 -4.4 4.1 -2.7 Individual Well Preuure Mab-to-Dav Chancel W Ie IN P Dav 2 vs. Dav1 Day 3vs. Day2 Day 4m Davi Dnv S vs. DW DBy6ys.WyS Day7vs.Dav6 Dsv8W.Dav7 CLUS-1 -29 -6 -S -4 -3 -3 .2 CLU S2 -m -6 -4 -4 -2 -3 -2 CLU 5-3 -] .3 -2 -2 0 .2 0 CW 5.4 -10 -8 -] J -6 -5 .4 CLU S-5 -14 -10 -8 -] -6 -5 -3 Weight Fadorr'- based on Ray Eastwood Log Model Table 3 — April 2013 Wellhead Shut-in Pressure Data WAP Change Well Name CLU 5 1 CLOS-2 CLU 5-3 CLU 5-4 CLOS-5 Weight Factor' based on Ray Eastwood Log Model Weighted Average Pressure IDw EiwChange) Dav2vs.0av1 Oav3vs.Wv1 Dw4vs.Dav3 D0y5".Ody4 Da,15W.DmS 1.0 1.1 1.0 1.0 0.3 Individual Wellhead Shut-in Pressures IDSIa) and Dates Dw 2vs. Davi Dw 3vs.0av2 Dav4vs.Dw3 Eaa,Svs Dav4 Weight Fxtor• 0.4 -0.2 0.5 0.4 0 0.1 0.4 IStomee Pore -feet= 0.4 0 0.8 1.6 1.1 1.1 Well Name IPor.'net MD'/1-SWII 010120 V}y[M 1.3 4J13[III� 9(j9( Iia /" CLUS-1 70.235 1374.5 1374.9 1314.7 1375.2 1375.6 13)5.6 CLU S-2 Fr. 136&6 136&7 1369.1 1369.1 1370.1 13]0.1 CLU 5-3 24.024 1321.6 1328.4 1330 1331.1 1332.2 1332.9 CLU S 4 91.011 1307.2 1308.2 1309.5 1310.9 1312.2 1312.9 CUl S-5 93.155 1336.1 133&5 1340.6 1341.9 1343.2 1343.4 332.121 Weighted Avg. W HP (WAP) 1307.0 13410 1342.1 1343.1 1344.1 1340.4 WAP Change Well Name CLU 5 1 CLOS-2 CLU 5-3 CLU 5-4 CLOS-5 Weight Factor' based on Ray Eastwood Log Model Weighted Average Pressure IDw EiwChange) Dav2vs.0av1 Oav3vs.Wv1 Dw4vs.Dav3 D0y5".Ody4 Da,15W.DmS 1.0 1.1 1.0 1.0 0.3 Table 4 - Shut-in Reservoir Pressure History and Gas -in -Place Summary Individual Well Pressure IDai Vav Channel Dw 2vs. Davi Dw 3vs.0av2 Dav4vs.Dw3 Eaa,Svs Dav4 Cav6vs.Che, 0.4 -0.2 0.5 0.4 0 0.1 0.4 0.6 0.4 0 0.8 1.6 1.1 1.1 0.1 1 1.3 SA 1.3 0.1 1.8 2.1 1.3 1.3 0.2 Table 4 - Shut-in Reservoir Pressure History and Gas -in -Place Summary Shut-in Reservoir Pressure History and Gas -in -Place Summary Original (Discovery) ReservoirConditions Wellhead Pressure -osig Bottom Hole Pressure - osis Z - Factor 8HP/Z-psi a Date 0 10/28/2000 1950 2206 0.8465 2606 Weighted Avg. Wellhead Date Pressure - osis. Bottom Hole Pressure -psia 11/8/2012 1269.9 1434.9 Storage Operating Conditions 2 -Factor BHP/Z -osia 0.8719 1645.7 4/15/2013 1344.4 1522.35 0.8668 Gas Gravity: 0.56 N2 Conc.: 0.3% CO2 Conc: 0.3% Reservoir Temp. (deg. F): 105 Datum Depth (ft.): 4950 Figure 1 Total Gas -in Place - MMd 0 26,500 Total Gas -in Place - MMd 11,218.800 1756.3 13,167.606 CINGSA Pressure vs. Inventory Hysteresis 1800 1600 laoo — Initial Cycle — Second Cycle — Stabilized Wellhead Preuure �r Actual Pressure vs. Inventory-CLU4S Pressure 1200 X* 1000 800 600 400 no 0 5,000,000 lo,ow,Wo 15,000,o00 20,000,000 35,000,000 Total Field Inventory, Msd Figure 2 10 CLU S-1 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance pool$ ■ ■_ 1rforating Actual Flowing ConditionsIIS■■■■�I�I �Operating Data Trend I■�_____■■■ I■��..■■■■' ■■��Ill�Of■■■■VIII ,.,,. ��►1�1�1�■■■■1111 M i■■■i■Illi■■■■■111 ,,,., �'�■■■1111■■■■■III 1000 Figure 3 10000 Q, Mscf/D 100000 CLU S-2 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance 10000000 1000000 111111111 ' 1 --11--CLUS-2 5-28-12 before re- Em�� Min perforating m�� CLUS-2 7-11-12 after re- perforating Actual Flowing Conditions 11_��■,111, Operating .. 11MMA! _■��R �1�_■■■■,111 �■■Illill�■■111111 �.�■■■�111�1■■■.111 N W N a 0MENNEN 100000 10000 1000 10000 100000 Q, MscflD Figure 4 ,�■■111111■■111111 �IIIIII _■��R �1�_■■■■,111 �■■Illill�■■111111 �.�■■■�111�1■■■.111 CLU S-3 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance 10000000 OEM SIEMENS ==MEMO ME SESSION MENEM No IMM MINIMUM 1000000 PA, Illll.�r�llllll �A �■�■■VIII N a OEMa 0 i■li��s"fll�■■■■VIII 100000ROMSEEM 10000 ��illl�'�"■"III ENOMEE oil own mi. 1000 10000 100000 Q, Mscf/D 5 Figure 111 ■111._ -_---III CLU S-4 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance ,0000000 ��■■■11��■■1111 ■?��■A��Ql1�■■■■111 =04211111mmm '-----1111 KENN INNS ILII perforating l�CLUS-4 7/7/12 after re -perforating Actual Flowing Conditions 1000000 �■f■■��! ��■■1111.__JIII N N N a a 0 100000 ,Ooao �CLU S-4 5/28/12 before re - ___ 1000 10000 100000 Figure 6 Q, MscflD ��■■■11��■■1111 ■?��■A��Ql1�■■■■111 =04211111mmm '-----1111 KENN INNS ILII perforating l�CLUS-4 7/7/12 after re -perforating Actual Flowing Conditions �■f■■��! ��■■1111.__JIII Q, MscflD CLU S-5 Preliminary Well Deliverability Test Results vs. Actual Withdrawal Performance 10000000 �CLU S-5 5-28-12 before re -perforating — CLU S-5 7-23-12 after re -perforating • Actual Flowing Conditions Operating Trend 1000000 000n a 100000 10000 1000 10000 100000 Q, Mscf/D Figure 7 Figure 8 CINGSA Fall 2012 Wellhead Shut-in Pressures 1350 1325 O ACLU Storage 1 1300 m n O ACLU Storage 2 y 1275 p N O m O O �CLU Storage 3 a m 1250 L 3 rt CLU Storage 4 1225 w o CLU Storage 5 1200 Field Weighted Average Pressure 1175 1150 11/1 11/2 11/3 11/4 11/5 11/6 11/7 11/8 Shut-in Date Figure 8 Figure 9 CINGSA Spring 2013 Wellhead Shut-in Pressures 1380 1360 ACLU Storage 1 m N a —ACLU Storage 2 N N d a` m 1340 —ACLU Storage 3 O L O d 3 ACLU storage 4 c 4 H o CLU Storage 5 1320 —�—Field Weighted Avg. Press. 1300 4/10 4/11 4/12 4/13 4/14 4/15 Shut-in Date Figure 9 Cannery Loop Sterling C Gas Storage Pool - Material Balance PLot November 2012 - April 2013 3,000 BHP/Z = 2606 psia 2,500 --- -- m n 2,000 --- --- — Spring 2013 BHP/z= ' 1756.3 psia N a d Fall 2012 BNP/z =1645.7 A y 1500 psia w 0 x P/Z vs. Gas -in -Place 0 e 1,000 --- ---T-0—Fall m /Z vs. Gas -in Place500 --- --- HP/Z vs. Gas in Place 0 0 0 5,000 10,000 15,000 20,000 25,000 30,000 Gas -in -Place MMcf Figure 10—Annulus Pressure of CLU Storaee -1 Plot of Tubing and Annulus Pressure vs Time - CLU S-1 2000 9"8- 1800 3/8M1800 X133/BAnnulus —Tubing 1600 1400 5.-1200 n N 1000 L v 800 600 400 200 0 riAN O O O> m aD r 4 � M M Q N N n n r co Cs o Figure 11—Annulus Pressure of CLU Storage - 2 2000 Plot of Tabling and Annulus Pressure vs Time - CLU S-2 �95/B Annulus 1800 —Tubing 1600 _..__.._.. _.. 1400 m 1200 1000 - --- d is._.. _. __... 600 400 200 0 N N_ N N N t7 l7 (7 �Nl �N9 (NV (NV Figure 12—Annulus Pressure of CLU Storage -3 Figure 13 — Annulus Pressure of CLU Storage — 4 Figure 14 —Annulus Pressure of CLU Storage — 5 Figure 15—Annulus Pressure of Marathon CLU RD -1 CLU 1RD Annulus Pressure History 80 70 nu N a 60 v N 50 N N a` 40 a m X41/2 x7 30 H ��7x95/8 20 10 0 p\1\, 6\'�, \\1\�p•,'y 1\�1 1 'r 0 ,y0 ,S1\ Month/Year Figure 16—Annulus Pressure of Marathon CLU 3 CLU 3 Annulus Pressure History Ell uu 50 .y a a 40 N N v a` 30 v m w H 20 31/2x95/8 10 0 a +r '1\ryp11' 1\vp'y1' 'Y\rypy�' 'Y\tip1�' 1\ryp1�' 'y\ryp1'� Iy\�p1n� 'y\�p'yy .Y\�p13 .y\�p1'i ,y\�py'i Month/Year Figure 17—Annulus Pressure of Marathon CLU 4 CLU 4 Annulus Pressure History 12 ou 10 N 6 d 8 N N P 6 v U X31/2x135/8 4 '^ � 13 5/8 x 20 2 0 yp\1\1p~� 1 1 Month/Year Figure 18 — Annulus Pressure of Marathon CLU 5 250 m 200 a a N 150 v a` CLU 5 Annulus Pressure History 50 Month/Year Figure 19 — Annulus Pressure of Marathon CLU 6 2000 1800 1600 a v 1400 y 1200 v a` 1000 v 800 600 400 200 0 CLU 6 Annulus Pressure History Month/Year Figure 20 — Annulus Pressure of Marathon CLU 7 CLU 7 Annulus Pressure History 35 30 a 'N Q 25 a L 20 v a X31/2 x 9 5/8 a! 15 or �9 5/8 x 13 3/8 10 5 0 1, 6 ,y'L�1��pyv 'L��tip~� b�1�tip� ro�1�tip1� ��tip13 ,yp�y�tip1� ,yy�1�tip~� Month/Year Faure 21—Annulus Pressure of Marathon CLU 8 CLU 8 Annulus Pressure History 120 160 100 ee .N oe a a 140 80 N 120 N d N a` 60 N v 100 a a m 80 —F3 1/2 x 9 5/8 m � 40 A 31/2x95/8 60 �9 5/8x 13 3/8 20 Nei 40 — 9 5/8 x 13 3/8 0 20 '1��p~v ti��p1� ��ptiti ti�~p�ry ti�~pyv y��p'1'' 1�tip1� '1\�p~3 .1��p1� ti�tip1� ti�~py3 Month/Year Figure 22—Annulus Pressure of Marathon CLU 9 CLU 9 Annulus Pressure History 180 160 oe a 140 120 N N v 100 a m 80 A 31/2x95/8 60 Nei 40 — 9 5/8 x 13 3/8 20 t7 0 Month/Year Figure 23 — Annulus Pressure of Marathon CLU 10 60 ec 50 N a 100 a 40 3 N N v a` 30 v N 20 10 L CLU 10 Annulus Pressure History O,y'L O'1'L O,y'L Otiti Otiti O.>"' 0ti3 Otis OtiM O,y'S Oti3 Month/Year Figure 24—Annulus Pressure of Marathon CLU 11 CLU 11 Annulus Pressure History 100 90 80 a w 70 60 a a 50 x-31/2 x 9 5/8 a u m 40 N — 9 5/8 x 13 3/8 30 20 10 0 0•�'L O•y'L O,y'L O,v 01ry O~� Otis 013 O•"'y p�� O,yO Month/Year Figure 25 — Annulus Pressure of Marathon CLU 12 CLU 12 Annulus Pressure History 10 9 en N 8 a v 7 N 6 P 5 v u w 4 �inside 9 5/8 �^ 3 2 1 0 Oy'L 1 1 1 1 Month/Year