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Home My WebLink AboutO 092INDEX OTHER ORDER NO. 92 CINGSA Violation of Rule 7 of Storage Injection Order 9 1.-------------------- Emails between ENSTAR and AOGCC re: CINGSA shut-in pressure data (Attorney — Client emails held confidential in secure storage) 2. November 19, 2013 AOGCC letter to CINGSA re: Violation of Rule 7 of SIO 9 3. December 5, 2013 CINGSA's response to AOGCC's Nov. 19, 2013 letter 4. December 26, 2013 AOGCC's response and follow up questions to CINGSA's Dec. 5, 2013 response 5. January 30, 2014 CINGSA's response to AOGCC's Dec. 26, 2013 follow up questions 6. February 14, 2014 AOGCC's letter to CINGSA re: closing of investigation INDEX OTHER ORDER NO. 92 0 • THE STATE GOVERNOR SEAN PARNELL February 12, 2014 Ms. M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC P.O. Box 190989 Anchorage, AK 99519-0989 Re: Violation of Rule 7 of Storage Injection Order 9 Sterling C Gas Storage Pool Cannery Loop Unit Cannery Loop Field Closing of investigation Dear Ms. Starring: kl U, anic" Gar, 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 After reviewing Cook Inlet Natural Gas Storage Alaska, LLC's (CINGSA) most recent January 30, 2014 response, CINGSA's responses to earlier AOGCC inquiries and other available information, the Alaska Oil and Gas Conservation Commission (AOGCC) has concluded that CINGSA acted in a responsible manner and will not be taking an enforcement action on this incident. On November 6, 2013, CINGSA notified the AOGCC that a recent shut-in reservoir pressure survey indicated the average reservoir pressure of the Sterling C Gas Storage Pool appeared to be above the 1,700 psi limit established by Rule 7 of Storage Injection Order (SIO) 9. In response, the AOGCC instructed CINGSA that injection activities would only be allowed when the calculated bottomhole pressure in the CLU S-3 well was below 1,700 psi. The AOGCC initiated an investigation into the incident. By certified letters on November 191h and December 261h, 2013, the AOGCC requested additional information and data. CINGSA responded on December 5, 2013, and January 3, 2014. Based on review of the information CINGSA provided and other available information, the AOGCC has determined that prior to shutting in the wells on October 28, 2013, for the required semiannual reservoir pressure survey that a prudent operator would not have been able to determine that the average reservoir pressure exceeded the 1,700 psi limit established by SIO 9. Earlier drilling and reservoir pressure survey results indicated that the CLU S-1 well had encountered a pocket of gas that was at initial reservoir pressure and that release of this pocket into the Sterling C Gas Storage Pool effectively reduced the storage capacity of the reservoir. However, an accurate assessment of the impact of the pocket on the storage capacity was not possible. The most recent reservoir pressure survey yielded a more accurate assessment of the impacts on storage capacity: the storage capacity of the pool, at the 1,700 psi limit established in SIO 9, is less than the 10.5 BCF capacity that the AOGCC certified on May 15, 2013. i Violation of Rule 7 of SIO 9 Closing Of Investigation February 12, 2014 Page 2 of 3 When wells were shut-in on October 28, 2013, the volume of gas in storage was about 1 BCF less than the AOGCC's certified capacity and nearly 1.5 BCF less than CINGSA's design capacity. Before the wells were shut-in the calculated bottomhole pressure for the CLU S-3 well was in excess of 1,700 psi, but since this well is located near the center of the injection wells the pressure was expected to drop substantially when the wells were shut-in as the reservoir pressure equilibrated across the pool due to the fact that the volume in storage was significantly less than the design and certified capacity of the pool. When the pressure did not drop as rapidly as anticipated CINGSA reported that it had exceeded the 1,700 psi average reservoir pressure limit established by SIO 9. Prior to the latest reservoir pressure surveys, the volume of gas in storage and the design and certified capacity could have caused a prudent operator to conclude that the average reservoir pressure should be well below the 1,700 psi limit. As a result, an enforcement action is not justified in this matter. To prevent exceeding the reservoir pressure limit in the future CINGSA has proposed using the CLU S-3 well as a monitoring well. However, since the CLU S-3 well is located near other producers/injectors the pressure it records is not an accurate representation of the average reservoir pressure. Additionally, if the CLU S-3 well is put into service it would not be suitable as a monitoring well for an extended period of time. A material balance based method of determining the average reservoir pressure based on the volume of gas in storage more accurately measures the average reservoir pressure for compliance with Rule 7 of SIO 9. Therefore, CINGSA is directed to use its reservoir model to develop a table of volume in storage versus average reservoir pressure and use this table to determine compliance with the reservoir pressure limit established in SIO 9. The table shall be updated whenever the reservoir model is updated to make sure that the table is based on the most up to date data available. Based on current information the storage capacity certification issued in May 2013 is too high. Should CINGSA wish to avoid a reduction in the certified capacity, CINGSA should apply no later than April 1, 2014 to amend SIO 9 to raise the average reservoir pressure limit in Rule 7. Any such application must be supported by evidence sufficient to warrant the relief requested. Questions regarding this matter should be directed to Dave Roby at (907) 793-1232. Sincerely, z/ /0 ; 4'4� Cathy P Foerster Chair, Commissioner Violation of Rule 7 of SIO 9 Clo3�ing Of Investigation • February 12, 2014 Page 3 of 3 RECONSIDERATION AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration" In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Cook Inlet Natural,' -Gas STORACA7a�9� -1` RECEIVED January 30, 2014 State of Alaska JAN 3 0 2014 AOGCG Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster — Chair of Commission RE: Notice of Violation of Rule 7 of Storage Injection Order 9 Sterling C Gas Storage Pool Dear Chair Foerster: 00k Inlet Natural Gas Storage Alaska, LLC 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 Main:907-334-7980 Fax:907-334-7671 www.cingsa.com Via Hand Delivery Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) was granted a Storage Injection Order on November 19, 2010 by the Alaska Oil and Gas Conservation Commission (AOGCC or "Commission"), allowing it to operate the Cannery Loop Sterling C Pool for underground natural gas storage service. On November 6, 2013, CINGSA advised AOGCC that it may have exceeded the maximum reservoir pressure limit of 1700 psia imposed by Rule 7 of Storage Injection Order 9. On December 5, CINGSA responded to the Commission's Notice of Violation. On December 31, 2013, CINGSA received an additional letter from AOGCC requesting additional information regarding the possible violation. CINGSA has prepared the attached response to the Commission's request in conjunction with its expert consultants Rick Gentges and Petrotechnical Resources Alaska. Any questions concerning the attached information may be directed to John Lau at 907-334-7736. Sincerely, 1�k 101�d M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Attachments CC: Regulatory Commission of Alaska City of Kenai Planning and Zoning Commission Cook Inlet Region, Inc. Salamatof Native Association Cook Inlet Natural Gas Storage Alaska, LLC Supplemental Response to AOGCC NOV On November 21, 2013, Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) received a Notice of Violation (NOV) from the Alaska Oil and Gas Conservation Commission (AOGCC) concerning Rule 7 of Storage Injection Order (SIO) 9. Rule 7 of SIO 9 limits the maximum stabilized reservoir pressure to 1700 psia. The NOV requested that CINGSA provide AOGCC with a written explanation within 14 days of how the event occurred, what CINGSA planned to do to remedy the situation, and what steps would be implemented to prevent a reoccurrence. CINGSA provided a written explanation to AOGCC, as requested, on December 5, 2013. On December 31, 2013, CINGSA received a letter from the AOGCC requesting that CINGSA clarify certain elements contained in its December 5th response, and supplement the response with additional shut-in pressure data from the CLU S-3 well. The following is provided in response to AOGCC's December 315t request to CINGSA. Response to Question 1: In October 2013, if CINGSA had had the benefit of the information it has obtained over the last two months, CINGSA clearly would have ceased injections prior to the shut-in. In light of the pressure anomalies CINGSA has experienced, CINGSA will take a more conservative approach to ensure strict compliance with Rule 7 in the future. CINGSA is committed to complying with all of the orders and limits under which it was granted authority to operate. Below is (1) an explanation of the reasons why CINGSA did not expect that the stabilized reservoir pressure would exceed the 1700 psi limit, based on the information available to it in October 2013; (2) a detailed description of what CINGSA has determined to date regarding the unexpected reservoir pressure experienced; and (3) a description of the corrective actions it has taken to prevent the violation of Rule 7 of SIO 9 from recurring. CINGSA was indeed monitoring the shut-in wellhead pressure versus gas inventory data on CLU S-3 during the period prior to the planned late October/early November shut-in period. While so monitoring and as the CLU S-3 wellhead pressure increased, CINGSA did not believe it would be feasible for the calculated bottom hole pressure to have exceeded the Rule 7 limit. Based on the gradual increase in transient reservoir pressure that CINGSA observed in October, CINGSA judged that the stabilized reservoir pressure, if allowed adequate time to fully stabilize, was unlikely to exceed the maximum stabilized reservoir pressure of 1700 psia. When CLU S-1 was initially perforated/completed in February 2012, pressure at the wellhead rose to approximately 1600 psi within a few days. In contrast, all four of the other CINGSA wells exhibited wellhead pressures of approximately 400 psi, consistent with the depletion status of the reservoir. While higher than expected shut-in pressures were observed during the November 2012 Fall shut-in test and the April 2013 Spring shut-in test, CINGSA believed the higher shut-in pressures were largely attributable to the initial re -pressurization of the reservoir — i.e. having to overcome capillary pressure with injection pressures below hydrostatic pressure. Because this storage operation is new and has very limited historical storage operating data, it was not possible at the time to determine whether the higher than expected pressure was attributable to pressure transient behavior resulting from re -filling a depleted gas reservoir for the first time, encountering an isolated pocket of native gas at native pressure conditions in CLU S-1, or a combination of the two. Thus, it did not appear necessary or desirable to cease injections of customer working gas prior to the October 2013 shut-in period. CINGSA now believes the source of this elevated pressure could be attributable in part to high pressure native gas encountered when the C1c was perforated in CLU S-1, and which has since co -mingled with the main Cannery Loop Sterling C Gas Storage Pool. With further additional operating history, it should be possible to assess any incremental volume of native gas associated with this isolated compartment of the Sterling C1c sand interval. In an effort to aid in this determination, however, CINGSA has refocused its efforts on refining a computer reservoir modeling study of the reservoir. A detailed analysis of the Cannery Loop Sterling C Gas Storage Pool using a three dimensional computer reservoir simulation model was initiated in June 2013, and is ongoing. The purpose of this modeling is to better understand the pressure transient behavior of the reservoir, assess pressure support associated with any separate (pressure isolated) compartment of the Sterling C1c sand interval, estimate any incremental volume of gas associated with the separate compartment, and utilize the model for planning/optimizing storage operations. The simulation process includes a detailed history match of the reservoir during primary production and the first 18 months of gas storage operations. The results of the reservoir simulation provide some support for an hypothesis that the Sterling C1c interval within CLU S-1 was isolated from the main portion of the reservoir at the time CINGSA completed the well and that pressure in the C1c was at native discovery pressure (2206 psi) at the time CINGSA perforated the well. A successful history match of the pressure and production data during primary depletion and subsequent storage operations through October 2013 was achieved by the model. This match was possible only by the model incorporating additional pore volume associated with the C1c interval of the CLU S-1 well. A prediction run was then made by the model to assess overall reservoir pressure during the November 2013 shut-in test and extending for a period of two years beyond the test. The purpose of the prediction run was two -fold: 1) to compare the actual weighted average shut-in reservoir pressure at the end of the shut-in period to the reservoir pressure predicted using the computer model, and 2) to assess the magnitude of pressure influence associated with any isolated pocket of native gas in the C1c interval in CLU S-1. The actual weighted average reservoir pressure at the end of the seven day shut-in was 1798 psi versus a predicted weighted average reservoir pressure of 1758 psi. The difference between the actual and predicted pressure of individual wells varied from a low of 3 psi to a high of 84 psi, and the average difference was 36 psi, or an overall difference of approximately two percent relative to actual weighted average reservoir pressure. CINGSA then employed the model to run a predictive assessment of the decay in reservoir pressure transients and the pressure influence from the C1c interval of CLU S-1 assuming the reservoir remained shut-in for an extended period of time beyond the November 2013 shut-in test. FIGURE 1 below illustrates the predicted (simulated) shut-in reservoir pressure of all five CINGSA wells assuming the wells had continued to remain shut-in from November 5, 2013 for a period of two full years. The results of the prediction run indicate that gas influx from the C1c interval in CLU S-1 is likely still occurring and influencing reservoir pressure. As can be seen in Figure 1, pressures initially decline steadily in the wells for a period of several months to approximately March of 2014 rising again. The low point in pressure 0 stabilization is approximately 1730 psi; in light of these preliminary results, as previously stated, CINGSA will pursue an increase in the reservoir pressure allowed by the Commission in Rule 7 in SIO 9. These results support a conclusion that gas influx associated with the C1c interval of CLU S-1 has contributed to the higher than expected reservoir pressure observed during the three shut-in pressure tests that CINGSA has conducted since commencement of storage operations. Such determination was and is not possible with data available from conventional reservoir analysis and has only recently been completed after an extensive effort to utilize computer reservoir modeling to examine a more comprehensive model analysis of the reservoir. The magnitude of simulated influence from the C1c interval in CLU S-1 on overall reservoir pressure was not apparent prior to this study and is now a candidate for the most likely causative factor in CINGSA's exceeding the maximum reservoir pressure stipulated in Rule 7 of SIO 9. Of course, additional real time shut-in pressure data from subsequent April and November shut-in periods will be necessary to physically confirm or reject these modeling predictions. Thus, CINGSA does not presently endorse or adopt the modeled result as established facts. However, this information is provided to AOGCC in response to its December 315t inquiries in order to assist the Commission with its understanding of the subject matter at hand. FIGURE 1 1,840 1,820 1,800 a a i %A 1,780 47 L a c 3 1,760 L O 4 M O m 1,720 1= 1,700 - Simulated Shut-in Reservoir Pressure (psia) versus Time —CLU 5-1 —CLU S-2 CLU S-3 _CLU S-4 —CLU 5-5 Weighted Avg. BHP (Sim.) 1,680 — — — --- w�ti�\y� ti41�\y� ��\�a ��Q\~� �\��tia titi��A\~Q a�`O�y� �\y��tih tio��\�h ti\�~\~� Response to Question 2: ATTACHMENT A is an Excel spreadsheet with the requested daily wellhead and calculated bottomhole pressure for the CLU S-3 well since June 1, 2013 and is included with this transmittal. Response to Question 3: After further consideration of the matter, CINGSA has altered its plans as to CLU S-3. CINGSA intends to leave CLU S-3 shut-in, for use as a monitoring well, indefinitely. It will only use CLU S-3 for withdrawals in the event the region experiences a peak weather event and CINGSA requires deliverability out of the CLU S-3 well. If CLU S-3 is used for withdrawals, there will be a period of time after the well is shut-in when pressure builds. During such times, the shut-in wellhead pressure of CLU S-3 may not be a reliable indicator for assessment of dynamic field pressure conditions. CINGSA is monitoring and plotting the wellhead shut-in pressure of CLU S-3 as a function of gas inventory to establish the correlation between these operating parameters, and plans to continue to do so. CINGSA included a graph of this data as Figure 3 in its December 5th response to AOGCC. In order to ensure effective reservoir pressure monitoring, CINGSA has now applied a dynamic BHP calculation and display into the operating SCADA system for well No 3. The SCADA system is set to alarm in the event the calculated BHP of the well exceeds 1680 psi. CINGSA will automatically shut-in at a calculated BHP of 1690 psi. Screen shots illustrating the SCADA alarm system are attached as ATTACHMENT B. The protocol for SCADA alarm response is outlined in ATTACHMENT C, ENSTAR's SOP # 1601. STANDARD OPERATING PROCEDURES MANUAL ENSE 0 ENSTAR Natural Gas Company (ENSTAR) 2 Alaska Pipeline Company (APC) Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) Natural Gas Company Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Page No. 1 of 9 Authorizing Signature: John Lau Title: Director of Transmission Operations Scope: This procedure outlines the change management process for the transmission and distribution system monitored and controlled by Gas Control from SCADA. This process includes SCADA screen development, point-to-point testing, establishing communications between control room representatives and field technicians, management, and associated field activities as called for in the Federal Register's Control Room Management outline Sections: 192.631(c)(1), (c)(2), f(1), f(2) & f(3) respectively. Policy: Employees shall follow these procedures in order to prevent changes from adversely affecting Gas Control and to verify that the SCADA system is properly configured and tested. Guide: Change Procedures A. This SOP identifies the types of changes and the associated change requirements as well as the change request format, control rooms documentation format, and the point-to- point verification guidelines. Procedure: Section 1 — Types of Changes Refer to existing Company documents and procedures for any specific task, for tasks that are not defined use the general categories below to determine the process to be followed. The general categories are meant to represent all the operational changes that could affect control room operation; however operational changes that do not fit into one of these categories should be designated significant by the recommendation of gas control. Gas controller may also classify any Routine Change as a Significant Change if operations will be affected in a non -routine way. A. Non -routine or significant changes: Non -routine or significant changes generally encompass work that is not performed on an annual basis or could have significant impact on the operation of the gas system such as: 1. A change that dramatically impacts pipeline capacity 2. Taking a transmission line out of service 3. Operating a pipeline on a temporary basis as is done when pigging procedures are in effect. 4. Station equipment is installed, removed, or moved. 5. RTU or PLC program changes. 6. Changing alarm set points outside of the Alarm Plan settings. 7. Any additional SCADA screens developed B. Routine changes: Routine changes generally encompass work that is performed on a regular basis does not have a significant impact on the daily operation of the gas system, such as: 1. Adjusting set pressures of regulators 2. Open/Closing valves that are routinely operated 3. Calibrating transducers 4. Updating RTU or PLC programs 5. Orifice plate changes 6. Odorization rate change 7. Repairing valves C. Changes that do not affect the control room: Changes that do not affect the control room generally encompasses work that is performed on a system with a MAOP less than 100 psig This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE I OF 9 STANDARD OPERATING PROCEDURES MANUAL ENm1Wjo Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) rvarurar Gas company Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Page No. 2 of 9 or work that normally has no impact on the normal daily operation of the system, such as: 1. Cathodic Protection work 2. Work in the right of way that does not affect the daily operation of the pipeline. 3. Changes to monitoring equipment not monitored by SCADA 4. Changes to meters not monitored by SCADA Section 2 — Change Requirements A. Non -routine or a significant change a. Non -routine or significant changes require approval from the appropriate control room representatives, operator's management, and associated field personnel prior to the change. In an emergency situation or if unable to contact the appropriate control room representatives, operator's management, and associated field personnel the Director of Distribution Operations or equivalent can grant approval. All other applicable company standards will be followed. b. Refer to the following sections when performing a non -routine or significant changes i. Section 4 — Change Request ii. Section 5 — Point -to -Point Verification B. Routine changes a. Routine changes do not require approval from the appropriate control room representatives, operator's management, and associated field personnel under this procedure prior to the change, unless deemed a significant change, then see Section 2, A. above. All other applicable company standards will be followed. b. When performing a routine change Gas Control must be notified of the change. Refer to the following sections when performing a routine change i. Section 6 — Notification of Change ii. Section 5 — Point -to -Point Verification C. Non -Covered changes a. Non -covered changes are not covered by this procedure. All other applicable company standards will be followed. b. Non -covered changes do not require documentation under this procedure Section 3 — Control Room Documentation Reference the following guidelines when performing field changes to determine the correct process. A. Sites monitored by SCADA a. When a change is made to a piece of equipment that affects pipeline safety a point-to- point verification will be performed on all associated points that affect safety. Refer to Section 5 — Point -To -Point Verification. b. When a change is made to a SCADA display that affects pipeline safety a point-to-point verification will be performed on all associated points that affect safety. Refer to Section 5 — Point -To -Point Verification. For SCADA screen development see section7 c. When a change is made to a piece of equipment that does not affect pipeline safety Gas Control will be contacted to record the change. Refer to Section 6 — Notification of Change. d. When an emergency condition exists Gas Control will be contacted to record the event. Refer to Section 6 — Notification Of Change e. An emergency situation as covered in SOP 1105. This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 2 OF 9 STANDARD OPERATING PROCEDURES MANUAL ENASTAO Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) !Natural Gas Cornaanv Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Paae No. 3 of 9 B. Sites that are not monitored by SCADA a. When a change is made to a piece of equipment Gas Control will be contacted to record the change. Refer to Section 6 — Notification Of Change. b. When an emergency condition exists Gas Control will be contacted to record the event. Refer to Section 6 — Notification Of Change. c. An emergency situation as covered in SOP 1105. Section 4 — Change Request When a change is requested, the requestor will contact the appropriate control room representatives, operator's management, and associated field personnel with a filled out change request form that will include but not be limited to the information listed below. 1. Permanent or Temporary Change and the expiration date if the change is temporary is provided here. If the change is temporary, a copy of the active change is kept physically in the control room near the sign in sheet as a reminder of activities. 2. If the change is temporary the Originator of this form is responsible for giving notice of the end of the temporary change. The date is notated and the form is filed with old Change Requests. 3. Request description — Short description of the change 4. Areas of Impact — Can denote physical and departmental areas of impact. 5. Impact — What impact the change could have on normal operation 6. Time Required — The time required from the start of the process to the end of the process to make the change and other relevant timing issues. 7. Process — The steps that will be followed when the change is performed 8. Affected Parties — Departments that could be directly affected by the change 9. Change Initiated By — Initiator of the form also informs gas control when the temporary changes have been concluded. 10. Approval Signatures — Covers items 10). to 15). 11. Any applicable procedures, drawings, and training for directly affected employees. Upon the approval of a Change Request a Controller will log the approved Change Request in the Control Room Management of Change Log found on Gas Control's SharePoint Library. The signed Change Request form is filed with all approved Change Requests in Gas Control. Section 5 — Point -To -Point Verification The primary purpose of a point-to-point verification will verify the accuracy of the SCADA displays and record changes to the operation of the system. Point to Point testing should occur on the same day or prior to the points going into service. The Alarm Rationalization from the Alarm Management Plan is followed to update or add the point the Alarm Rationalization spreadsheet if the point is determined to have any alarming functions. The only times a Point to Point procedure should occur is during the following: a. When a change is made to a piece of equipment that affects pipeline safety a point-to- point verification will be performed on all associated points in SCADA that affect safety. b. When a change is made to a SCADA display that affects pipeline safety a point-to-point verification will be performed on all associated points that affect safety. A. Gas Control will document on the point-to-point verification form the following information that may apply in the SCADA Change Management Log located on Gas This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 3 OF 9 STANDARD OPERATING PROCEDURES MANUAL ENST Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) Natural Gas Comnanv Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Pacie No. 4 of 9 Control's SharePoint Library. a. Controllers name b. Technician name c. Date d. Station name or RTU Name e. Point name f. Display name(s) g. Equipment changed h. Found condition or value in the field i. Found condition or value in SCADA j. Type of test performed k. Test condition or value in SCADA I. Left condition or value in the field m. Left condition or value in SCADA n. Verify SCADA alarm set points match the master alarm set points o. All SCADA screen changes and additions are API — 1165 compliant. (Specific only to sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165). B. Testing Process a. Physical tests should be performed when: i. It will not be disruptive to system operation ii. The test will yield a measurable change b. Simulated tests should be performed when: i. Physical tests are impractical ii. A physical test will not yield a measurable change C. Physical test for an analog point a. When possible, the controller should issue a command to perform the measurable change, otherwise the technician can perform the change. The following steps will be followed when performing the test. Gas Control will record the results in the Control Room Point -to -Point Verification Form. i. Verify the value in the field matches the value in SCADA ii. Perform the change iii. Verify the value in the field matches the value in SCADA iv. Perform any additional changes to return the equipment to normal operation D. Simulated test for an analog point a. The technician in the field will follow the following steps when performing the test. Gas Control will record the results in the Control Room Point -to -Point Verification Form. i. Verify the value in the field matches the value in SCADA ii. Disconnect the wire connected to the piece of equipment at the equipment iii. Verify the SCADA point went to zero (0) iv. Reconnect wiring v. Verify values in the field match values in SCADA E. Physical test for a digital point a. When possible, the controller should issue a command to perform the measureable change, otherwise the technician can perform the change. The following steps will be followed when performing the test. Gas Control will record the results in the Control Room Point -to -Point Verification Form. i. Verify the state in the field matches the state in SCADA ii. Perform the change This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 4 OF 9 STANDARD OPERATING PROCEDURES MANUAL ENSENW Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) nracurar Gas company Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Page No. 5 of 9 iii. Verify the state in the field matches the state in SCADA iv. Perform an additional changes to return the equipment to normal operation F. Simulated test for a digital point a. The technician in the field will follow the following steps when performing the test. Gas Control will record the results in the Control Room Point -to -Point Verification Form. i. Verify the state in the field matches the state in SCADA ii. Disconnect the wire connected to the piece of equipment at the equipment iii. Connect a power source to simulate a signal iv. Simulate the opposite state of the found state v. Verify the state in the field matches the state in SCADA vi. Reconnect the wire Section 6 — Notification of Change The primary purpose of a notification of change is for Gas Control to be aware of the changes and for the Operator to record the changes in the Pipeline Operations SharePoint log book. A. Gas Control will document the change in the Pipeline Operations SharePoint log book with the following information: a. Controllers name b. Technician name c. Date d. Site name e. Equipment changed or event f. Relevant status information (ie. Found state or value in the field, Left state or value in the field) g. Timing of the scheduled changes Section 7 — SCADA Screen Development SCADA screens are API — 1165 compliant. (Specific only to sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165). A review of the changed or new screen(s) is documented in the Control Room Management SCADA Screen Development Form (Attachment #3). Before the screen is implemented all controllers are instructed on the workings of the new or changed interface. A. The screen developer or employee overseeing the changes will ensure human factors are considered: a. When applicable, screens follow a mapping to actual positions of field equipment. Most screens use the pipeline schematic. Mapping to the schematic is done as long as the interface follows the rest of the API 1165 prescribed methods. b. Screens are not overloaded (signal to noise ratio). c. Position and size of figures are determined by their relative importance to the viewer. More important control items are made larger and more central. d. Consistency of color representation, shapes, symbols and fonts are followed for similar type screen representations throughout the SCADA system. Normal and abnormal conditions and shape -coding of device symbols such as pumps, valves and meters also remain consistent in the screen. ISA Symbol library is used for a This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 5 OF 9 STANDARD OPERATING PROCEDURES MANUAL EN=1W44 Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) Natural Gas Company Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Paae No. 6 of 9 guideline when choosing shape -coding and symbols. B. Colors and Font considerations a. The number of colors are kept to a minimum. The colors are chosen to allow an optimal contrast in colors as well as contrasting with the background on which they appear. b. The high priority information should use colors that capture the controller's attention. Fonts are chosen to be scalable without deterioration in the quality of the display. Should differing screen resolutions be used, keeping the font with basic lines will keep numbers and letters legible. c. When screens are built feedback is taken from gas controllers to confirm that they are easy to understand and provide the visual cues the controllers are looking for. C. State Based Points a. State based points are given to mean open or closed by their colors. A red valve means a closed valve, while a green valve means an open valve. Alarm states will also change the colors of blocks surrounding the item in alarm. For more on alarms, see Alarm Management Plan. b. The consistency in meaning to color coordinating is essential to helping the controllers to understand the system at a glance. This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 6 OF 9 a - STANDARD OPERATING PROCEDURES MANUAL 2 ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APC) Q NORSTAR Pipeline Company (NORSTAR) .� . 0 Cook Inlet Natural Gas Storage Alaska (CINGSA) Natural Gas Comoan v Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Paqe No. 7 of 9 Attachment 1 Alaska Pipeline Company Control Room Change Request Form Change Number A Date Change Number Format= Yeam(1999) & Mordh(01) & Day(01) & Ned Nwilaorrrom Change Log 1) Select One: Permanent Change ❑ Temporary Change ❑ Temperary Expiration Date: 2) Change event has expired. ❑ Actual Expiration Date: Covered in If any items on this form are already addressed in the procedure or attachent check the 'Covered in Procedure' box. Procedure 3) Reason For & Description of Change(s) & Expectations 4) Areas of Impact (Physical & Departmental) ❑ 5) Implication(s) and Impact(s) of Change to the Affected Areas ❑ 6) Timing, time required, time limitations, restrictions, or other relevant timing issues associated. _❑ 7) Process for change & contingency plan ❑ 8) Names of the management of the affected parties 9) Change Initiated by 10) Is this a significant change that requires specific controller training?: Yes ❑ No ❑ If yes, indicate name of trainer. and attach signed training form. Approval Signatures 11) Gas Controller Date WA ❑ 12) Measurement Supervisor Date WA ❑ 13) Engineering Services Supervisor Date WA ❑ 14) Gas Control Supervisor Date N/A ❑ 15) Final approval and authorization Unless Ns is an emergency, i1 ANYboxes Isom item &J. &ougr 91}, have rwC been chavkcdw,d a is no sigr>saue, do tort sy7n Ws form. Date Control Room Representative (Can be the Control Room Manager/Supervisor or Contrdler) 16) Controller addling entry to the log book Date This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 7 OF 9 �, §3 STANDARD OPERATING PROCEDURES MANUAL ENMS7,A Q ENSTAR Natural Gas Company (ENSTAR) Q Alaska Pipeline Company (APQ "■. Q NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Page No. 8 of 9 Attachment 2 Alaska Pipeline Company ., o�..•. -- Control Room Point to Point Verification Form Notification Change Number Date: _ Select One: Routine Change Non -Routine Change Select One: SCADA Change Non-SCADA Change Reason For Change: Pti Pt 2 Pt 1 Pt 2 0 c O a N E z ei d x N C_ O d V W N A N N J I certify that gas control has reviewed and accepted the change and that all changes are in compliance with API 1165. Initiated By(print) Signature Approved By(print) Signature This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 8 OF 9 STANDARD OPERATING PROCEDURES MANUAL ENST 0 ENSTAR Natural Gas Company (ENSTAR) 0 Alaska Pipeline Company (APC) 2 NORSTAR Pipeline Company (NORSTAR) Q Cook Inlet Natural Gas Storage Alaska (CINGSA) Natural Gas Companv Title: Control Room Management of Change No: 1601 Revision No.: 003 Effective Date: 04/15/2013 Page No. 9 of 9 Attachment 3 t_ Alaska Pipeline Company Control Room SCADA Screen Development Form Notification Change Number # Change Number Format = Year(1999) & MoMh(01) & Day(Ot) 1). Are human factors from AP11165 and SOP1601 considered acceptable? 2). If there are deviations to human factors, explain why: 3). 4). 5). 6). 7). 8). 9). 10). Date Yes No N/A Colors and fonts from API1165 and SOP1601 considered acceptable? Yes No 0 N/A If there are deviations to colors and fonts, explain why: State Based Points from API1165 and SOP1601 considered acceptable? Yes No ET N/A If there are deviations to state based points explain why: Have all controllers been educated with the new/changed SCADA screen? Yes Lj No N/A Screen Name Change Initiated By uaie 11). Has the Measurement Supervisor Approved the Change? Yes No ❑ N/A ❑ 12). Has the Engineering Services Supervisor Approved the Change? Yes No N/A 13). Has the Gas Control Supervisor Approved the Change? Yes No 14). Approval & Authorization Unless Cris is an emergency, N ANYboxes hom item 1). Cnough 13). have been marked'No , ieiihouracceptable explarrafion do nor sign this form. Control Room Representative (Can be the Control Room MenegeriSupervisor or Controller) Date Revised 9/21112 This Standard Operating Procedure is property of ENSTAR Natural Gas Company and may not be copied or otherwise used by anyone other than ENSTAR employees without prior written permission from the Company ATTACHMENT A - PAGE 9 OF 9 �._ � � +. �.. �- � . ` � a a a �< � �`� r, . .. �.�... Calculated CLU S-3 Wellhead Bottomhole Wellhead to Bottom Flow Rate Date Presssure - psi g Pressure - psia Hole Difference MMcf d 6/1/13 1513 1702 189 10300 6/2/13 1498 1686 188 8400 6/3/13 1490 1677 187 7550 6/4/13 1496 1683 187 8040 6/5/13 1511 1700 189 8910 6/6/13 1516 1706 190 8950 6/7/13 1513 1703 190 8040 6/8/13 1514 1704 190 8300 6/9/13 1519 1709 190 8540 6/10/13 1520 1710 190 8370 6/11/13 1518 1708 190 7990 6/12/13 1521 1712 191 8100 6/13/13 1529 1720 191 8570 6/14/13 1528 1720 192 8190 6/15/13 1529 1721 192 8190 6/16/13 1531 1723 192 8230 6/17/13 1524 1715 191 7170 6/18/13 1515 1705 190 6310 6/19/13 1514 1704 190 6120 6/20/13 1516 1708 192 6320 6/21/13 1515 1706 191 6100 6/22/13 1527 1719 192 7090 6/23/13 1522 1713 191 6170 6/24/13 1517 1708 191 5670 6/25/13 1521 1713 192 2810 6/26/13 6/27/13 6/28/13 6/29/13 6/30/13 7/1/13 1495 1684 189 2710 7/2/13 1462 1659 197 Shut-in 7/3/13 1458 1655 197 Shut-in 7/4/13 1455 1651 196 Shut-in 7/5/13 1455 1651 196 Shut-in 7/6/13 1454 1650 196 Shut-in 7/7/13 1453 1649 196 Shut-in 718/13 1454 1650 196 Shut-in 7/9/13 1453 1649 196 Shut-in 7/10/13 1454 1650 196 Shut-in 7/11/13 1454 1650 196 Shut-in 7/12/13 1454 1650 196 Shut-in 7/13/13 1454 1650 196 Shut-in 7/14/13 1454 1650 196 Shut-in 7/15/13 1454 1650 196 Shut-in 7/16/13 1455 1651 196 Shut-in ATTACHMENT C - PAGE 1 OF 6 7/17/13 1455 1651 196 Shut-in 7/18/13 1455 1651 196 Shut-in 7/19/13 1456 1652 196 Shut-in 7/20/13 1456 1652 196 Shut-in 7/21/13 1457 1653 196 Shut-in 7/22/13 1457 1653 196 Shut-in 7/23/13 1458 1655 197 Shut-in 7/24/13 1457 1653 196 Shut-in 7/25/13 7/26/13 7/27/13 7/28/13 7/29/13 7/30/13 7/31/13 8/1/13 1462 1659 197 Shut-in 8/2/13 1463 1660 197 Shut-in 8/3/13 1464 1661 197 Shut-in 8/4/13 1464 1661 197 Shut-in 8/5/13 1465 1663 198 Shut-in 8/6/13 1465 1663 198 Shut-in 8/7/13 1466 1664 198 Shut-in 8/8/13 1466 1664 198 Shut-in 8/9/13 1467 1665 198 Shut-in 8/10/13 1467 1665 198 Shut-in 8/11/13 1468 1666 198 Shut-in 8/12/13 1469 1667 198 Shut-in 8/13/13 1469 1667 198 Shut-in 8/14/13 1470 1668 198 Shut-in 8/15/13 1470 1668 198 Shut-in 8/16/13 1471 1669 198 Shut-in 8/17/13 1472 1671 199 Shut-in 8/18/13 1473 1672 199 Shut-in 8/19/13 1473 1672 199 Shut-in 8/20/13 1474 1673 199 Shut-in 8/21/13 1474 1673 199 Shut-in 8/22/13 1475 1674 199 Shut-in 8/23/13 1475 1674 199 Shut-in 8/24/13 1476 1675 199 Shut-in 8/25/13 1476 1675 199 Shut-in 8/26/13 1477 1676 199 Shut-in 8/27/13 1478 1677 199 Shut-in 8/28/13 1479 1679 200 Shut-in 8/29/13 1479 1679 200 Shut-in 8/30/13 1480 1680 200 Shut-in 8/31/13 1481 1681 200 Shut-in 9/1/13 1481 1681 200 Shut-in 9/2/13 1482 1682 200 Shut-in 9/3/13 1483 1683 200 Shut-in ATTACHMENT C - PAGE 2 OF 6 9/4/13 1484 1684 200 Shut-in 9/5/13 1484 1684 200 Shut-in 9/6/13 1485 1685 200 Shut-in 9/7/13 1486 1686 200 Shut-in 9/8/13 1487 1687 200 Shut-in 9/9/13 1487 1687 200 Shut-in 9/10/13 1488 1689 201 Shut-in 9/11/13 1489 1690 201 Shut-in 9/12/13 1489 1690 201 Shut-in 9/13/13 1490 1691 201 Shut-in 9/14/13 1490 1691 201 Shut-in 9/15/13 1491 1692 201 Shut-in 9/16/13 1491 1692 201 Shut-in 9/17/13 1492 1693 201 Shut-in 9/18/13 1492 1693 201 Shut-in 9/19/13 1493 1694 201 Shut-in 9/20/13 1493 1694 201 Shut-in 9/21/13 1494 1696 202 Shut-in 9/22/13 1494 1696 202 Shut-in 9/23/13 1495 1697 202 Shut-in 9/24/13 1494 1696 202 Shut-in 9/25/13 1496 1698 202 Shut-in 9/26/13 1496 1698 202 Shut-in 9/27/13 1497 1699 202 Shut-in 9/28/13 1497 1699 202 Shut-in 9/29/13 1498 1700 202 Shut-in 9/30/13 1498 1700 202 Shut-in 10/1/13 1498 1700 202 Shut-in 10/2/13 1499 1701 202 Shut-in 10/3/13 1499 1701 202 Shut-in 10/4/13 1500 1702 202 Shut-in 10/5/13 1500 1702 202 Shut-in 10/6/13 1500 1702 202 Shut-in 10/7/13 1501 1704 203 Shut-in 10/8/13 1502 1705 203 Shut-in 10/9/13 1503 1706 203 Shut-in 10/10/13 1503 1706 203 Shut-in 10/11/13 1504 1707 203 Shut-in 10/12/13 1505 1708 203 Shut-in 10/13/13 1506 1709 203 Shut-in 10/14/13 1507 1710 203 Shut-in 10/15/13 1507 1710 203 Shut-in 10/16/13 1508 1712 204 Shut-in 10/17/13 1509 1713 204 Shut-in 10/18/13 1510 1714 204 Shut-in 10/19/13 1511 1715 204 Shut-in 10/20/13 1511 1715 204 Shut-in 10/21/13 1510 1714 204 Shut-in 10/22/13 1513 1717 204 Shut-in ATTACHMENT C - PAGE 3 OF 6 10/23/13 1514 1718 204 Shut-in 10/24/13 1514 1718 204 Shut-in 10/25/13 1515 1720 205 Shut-in 10/26/13 1515 1720 205 Shut-in 10/27/13 1517 1722 205 Shut-in 10/28/13 1518 1723 205 Shut-in 10/29/13 1518 1723 205 Shut-in 10/30/13 1519 1724 205 Shut-in 10/31/13 1520 1725 205 Shut-in 11/1/13 1520 1725 205 Shut-in 11/2/13 1520 1725 205 Shut-in 11/3/13 1521 1726 205 Shut-in 11/4/13 1521 1726 205 Shut-in 11/5/13 1521 1726 205 Shut-in 11/6/13 1521 1726 205 Shut-in 11/7/13 1521 1726 205 Shut-in 11/8/13 1521 1726 205 Shut-in 11/9/13 1521 1726 205 Shut-in 11/10/13 1522 1728 206 Shut-in 11/11/13 1521 1726 205 Shut-in 11/12/13 1520 1725 205 Shut-in 11/13/13 1520 1725 205 Shut-in 11/14/13 1520 1725 205 Shut-in 11/15/13 1518 1723 205 Shut-in 11/16/13 1517 1722 205 Shut-in 11/17/13 1516 1721 205 Shut-in 11/18/13 1514 1718 204 Shut-in 11/19/13 1512 1716 204 Shut-in 11/20/13 1511 1715 204 Shut-in 11/21/13 1510 1714 204 Shut-in 11/22/13 1510 1714 204 Shut-in 11/23/13 1508 1712 204 Shut-in 11/24/13 1508 1712 204 Shut-in 11/25/13 1507 1710 203 Shut-in 11/26/13 1506 1709 203 Shut-in 11/27/13 1504 1707 203 Shut-in 11/28/13 1501 1704 203 Shut-in 11/29/13 1500 1702 202 Shut-in 11/30/13 1498 1700 202 Shut-in 12/1/13 1497 1699 202 Shut-in 12/2/13 1496 1698 202 Shut-in 12/3/13 1495 1697 202 Shut-in 12/4/13 0 Shut-in 12/5/13 0 Shut-in 12/6/13 0 Shut-in 12/7/13 0 Shut-in 12/8/13 0 Shut-in 12/9/13 0 Shut-in 12/10/13 0-- Shut-in ATTACHMENT C - PAGE 4 OF 6 12/11/13 0 Shut-in 12/12/13 0 Shut-in 12/13/13 0 Shut-in 12/14/13 0 Shut-in 12/15/13 0 Shut-in 12/16/13 0 Shut-in 12/17/13 0 Shut-in 12/18/13 0 Shut-in 12/19/13 0 Shut-in 12/20/13 0 Shut-in 12/21/13 0 Shut-in 12/22/13 0 Shut-in 12/23/13 0 Shut-in 12/24/13 0 Shut-in 12/25/13 0 Shut-in 12/26/13 0 Shut-in 12/27/13 0 Shut-in 12/28/13 0 Shut-in 12/29/13 0 Shut-in 12/30/13 0 Shut-in 12/31/13 0 Shut-in ATTACHMENT C - PAGE 5 OF 6 - , �' + is s- tk ;,= 0 2500 2000 1500 1000 E V 'o 500 0 cc 0 0 CLU S-3 Bottomhole Pressure vs. Wellhead Pressure 250 Soo 750 1000 1250 1500 1750 2000 Wellhead Pressure - psig ATTACHMENT C - PAGE 6 OF 6 • THE STATE f GOVERNOR SEAN PARNELL December 26, 2013 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 3507 Ms. M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC P.O. Box 190989 Anchorage, AK 99519-0989 Re: Violation of Rule 7 of Storage Injection Order 9 Sterling C Gas Storage Pool Cannery Loop Unit Cannery Loop Field Follow up questions Dear Ms. Starring: Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Thank you for your December 5, 2013, response to the Alaska Oil and Gas Conservation Commission's (AOGCC) November 19, 2013, Notice of Violation letter. After reviewing Cook Inlet Natural Gas Storage Alaska, LLC's (CINGSA) response, the AOGCC requests CINGSA respond to the following: 1) With a wellhead pressure monitoring system and supervisory control and data acquisition (SCADA) system in place, why did CINGSA not detect that the pressure for the shut-in CLU S-3 well was indicating the reservoir pressure approaching 1700 psi and cease injection before the limit was reached instead of waiting until the planned shut-in period at the end of October/early November when results of the pressure monitoring showed that the bottomhole pressure at the well had exceeded the reservoir limit by approximately 30 PSI? 2) Please provide an Excel spreadsheet containing the average wellhead pressure and calculated bottomhole pressure on a daily basis since June 1, 2013, for the CLU S-3 well. 3) CINGSA states the CLU S-3 well will remain shut-in as a pressure monitoring well, but that the well may be used from time to time if needed to meet injection or production capacity requirements. If the well is used for injection or production, will there be a period of time before the near wellbore pressure stabilizes that will make the well an unreliable indicator of the reservoir pressure? If so, how does CINGSA propose to provide effective reservoir pressure monitoring during these times? Violation of Rule 7 of SIO 9 Follow Up Questions December 26, 2013 Page 2 of 2 Within 30 days of receipt of this letter, CINGSA is requested to provide the AOGCC with responses to the above questions and requests. This request is made pursuant to 20 AAC 25.300. The AOGCC reserves the right to pursue enforcement action in connection with exceeding the pressure limit set forth in Rule 7 of SIO 9 as provided by 20 AAC 25.535. Questions regarding this matter should be directed to Dave Roby at 907-793-1232. Sincerely, V Cathy P. oerster Chair, C mmissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Postal Service,CERTIFIED • MAILT, RECEIPT (DomesticOnly;.• • . 0 m F " I C I A L Us F-7 r-aEr Postage $ m certified Fee 3- Postmark p Return Receipt Fee Here O (Endorsement Required) f-3 Restdcled Delivery Fee (Endorsement Required) Lrl ru Total Postage ' �--- ru Sent To 117 Street, Apt No.; Ms. M. Colleen Starring r3 or PO Box No. President f` Clry �i�, zjp� Cook Inlet Natural Gas Storage Alaska, LLC I Post Office Box 190989 Anchorage, AK 99519-0989 ■ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: Ms. M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Post Office Box 190989 Anchorage, AK 99519-0989 A. Signature � ❑Agent ❑ Addressee B. Received by (Printed Name) G. Date of Delivery D. Is delivery address different from item 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. Service Type ❑ Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail 0 C.O.D. 4. Restricted Delivery? (Extra Fee) ❑ Yes 2. Article Number 7009 2250 0004 3911 3507 (Transfer from service label) -- --- - - - -- PS Form 3811, February 2004 Domestic Return Receipt 102595-02-M-1540 Cook Inlet Natural.' f�aa STORAQ� ;; , December 5, 2013 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Attn: Cathy Foerster — Chair of Commission RE: Violation of Rule 7 of Storage Injection Order 9 Sterling C Gas Storage Pool Dear Chairman Foerster: Sock Inlet Natural Gas Storage Alaska, LLC 3000 Spenard Road PO Box 190989 Anchorage, AK 99519-0989 Main:907-334-7980 Fax:907-334-7671 www.cingsa.com Via Hand Delivery RECEIVED DEC 0 5 2013 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 (AOGCC), allowing it to operate the Cannery Loop Sterling C Pool for underground natural gas storage service. On November 6, 2013, CINGSA advised AOGCC that it may have exceeded the maximum reservoir pressure limit of 1700 psia imposed by Rule 7 of Storage Injection Order 9. CINGSA subsequently received a letter from the AOGCC on November 21, 2013 requesting that it provide AOGCC with an explanation of how the above referenced event happened, what will be done to remedy the problem, and steps CINGSA intends to implement to prevent a recurrence. Enclosed is CINGSA's response to the requested information. Any questions concerning the attached information may be directed to John Lau at 907-334-7736. Sincerely, M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Attachment CC: J. Lau J. Sims M. Smith Cook Inlet Natural Gas Storage Alaska, LLC Response to AOGCC NOV On November 21, 2013, Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) received a Notice of Violation (NOV) from the Alaska Oil and Gas Conservation Commission (AOGCC) concerning Rule 7 of Storage Injection Order (SIO) 9. Rule 7 of SIO 9 limits the maximum stabilized reservoir pressure to 1700 psia. The NOV requested that CINGSA provide AOGCC with a written explanation within 14 days of how the event occurred, what CINGSA planned to do to remedy the situation, and what steps would be implemented to prevent a reoccurrence. Background Gas injection and withdrawal activity at the CINGSA facility is interrupted twice annually for the purpose of conducting a reservoir shut-in pressure test. Results from these tests are used to perform an annual material balance analysis as required by SIO 9. The material balance analysis serves to verify that all of the gas that has been injected into the reservoir indeed remains there, can be accounted for, and that no gas migration from the reservoir has occurred. The shut-in events must be scheduled months in advance of when they actually occur so that CINGSA's customers can coordinate their gas supply purchases with producers and curtail their injection/withdrawal nominations with CINGSA when the facility is shut-in and unable to receive or deliver gas. The most recent shut-in test was conducted from October 28 — November 4th, and pressure data gathered during the test indicates that CINGSA may have exceeded the 1700 psia reservoir pressure limit stipulated in SIO 9. CINGSA contacted the AOGCC on November 6, 2013 to advise AOGCC that reservoir pressure may have exceeded the 1700 psia limit imposed by Rule 7 of SIO 9. CINGSA provided the notice based upon wellhead pressure readings that it had recorded during the seven-day shut-in period. CINGSA felt it prudent to advise AOGCC of the shut-in pressure conditions even though the shut-in data clearly indicate that pressure within the reservoir had not fully stabilized. An overview of the operating conditions leading up to the shut-in pressure test is provided below along with steps CINGSA has since taken to reduce reservoir pressure below the 1700 psia limit, and to prevent a reoccurrence of this event. April — October 2013 Injection Operations Summary The CINGSA facility was last shut-in for pressure testing from April 10-15. With the exception of only a few days, the facility has since been on continuous injection. Injection rates varied from near zero to over 35 mmcf/d during May and June as demand fluctuated with weather conditions, but the injection rate remained fairly constant during July and August at about 16 mmcf/d. During September, injection rates generally declined through the month to the lowest levels of the summer season and averaged only 10 mmcf/d. Injection rates rose significantly during October, particularly during the first half of the month when rates were 20-30 mmcf/d. This higher rate of injection resulted in a more rapid increase in wellhead pressure on CLU S-3 than had been observed during September, and much of the summer injection season. Overall, during the 2013 injection season, injection rates averaged about 16 mmcf/d during the period from April 16th — October 27th. Figure 1 illustrates the daily injection/withdrawal activity for this period as well as the entire period the CINGSA facility has been in storage service; Figure 1 also includes shut-in wellhead pressure readings from CLU S-3 (gaps in the data are indicative of periods when CLU S-3 was open for injection and withdrawal activity). Pressure Stabilization Analysis Injection activity ceased on the morning of October 28th and all five of the CINGSA wells were shut-in for pressure monitoring. Total gas inventory at this time was 16,355,212 mcf. Table 1 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 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 pressure data for all five wells. Generally speaking, all five of the CINGSA wells are used for injections/withdrawals. However, at various times when storage demand has been low, CLU S-3 has been shut-in for purposes of monitoring dynamic field pressure conditions as a function of gas inventory. CLU S-3 is located more or less in the center of the field and the well is completed in three of the five sands that make up the Sterling C Pool. Thus, it provides a reasonable indication of dynamic field pressure as a function of gas inventory. Figure 3 is a plot of the shut-in wellhead pressure of CLU S-3 versus gas inventory (as noted above, gaps in the data are indicative of periods when CLU S-3 was opened up for either injections or withdrawals). It is evident from this plot that CLU S-3 is in pressure communication with the other wells in the field, and while shut-in, responds in a consistent and predictable manner to injection activity, albeit with a minor degree of "lag" in pressure response. While withdrawals have been limited thus far, shut-in wellhead pressure on CLU S-3 is clearly responding in a consistent and predicable manner to storage withdrawals. CINGSA will continue to open CLU S-3 for both injection and withdrawal when customer nominations exceed the capability of the remaining four wells, but will otherwise leave the well shut-in when practicable. CINGSA believes that shut-in pressure readings obtained from CLU S-3 provide a reasonable indication of dynamic pressure conditions in the reservoir. Allowing for some degree of pressure "lag", or hysteresis, Figure 3 illustrates there is a direct relationship between shut-in pressure on CU S-3 and gas inventory. The degree of hysteresis is a function of reservoir complexity and rock quality (porosity and permeability), and results from pressure transient behavior within the reservoir as gas expands out into the greater reservoir during the injection season and returns from it during the withdrawal season. Recognizing that pressure within the reservoir had not stabilized (i.e. the hysteresis), the shut-in pressure of CLU S-3 at November 4th suggests that CINGSA exceeded the maximum pressure limit of 1700 psia by approximately 30 psi. However, given adequate time to fully stabilize, it is reasonably likely that reservoir pressure would have reached equilibrium at or below the 1700 psia limit. Corrective Measures The CINGSA facility was placed on withdrawal status on November 4th and has since remained on withdrawal to reduce reservoir pressure below the maximum approved limit of 1700 psia. As of December 3, approximately 1067 mmcf of gas had been withdrawn from the facility and wellhead shut- in pressure on CLU S-3 had declined to 1495 psig on an instantaneous basis, which equates to a calculated reservoir pressure of 1698 psia. Additionally, CLU S-1 has been used for withdrawals only during peak periods since early November, and otherwise remained shut-in. During the most recent shut-in of CLU S-1, which occurred from November 25-29, wellhead pressure initially built up to 1489 psig by mid -day on November 28th before beginning to decline in response to continued withdrawals from wells 2, 4, and 5. Just prior to re -opening CLU S-1 the following day, its wellhead pressure had declined to 1485 psig, which equates to a calculated reservoir pressure of 1687 psia. Thus, based on recorded shut-in wellhead pressure from both CLU S-1 and S-3, reservoir pressure has decreased below the maximum allowed pressure of 1700 psia. Going forward, CINGSA generally plans to leave CLU S-3 shut-in for pressure monitoring. When practicable or when needed to meet customer injection or withdrawal nominations, CLU S-3 may be used or injection or withdrawal service. . CINGAS will monitor wellhead pressure on CLU S-3 along with storage inventory as a means of remaining below the maximum reservoir pressure limit of 1700 psia stipulated in SIO 9. In addition, CINGSA has prepared a graph that correlates the wellhead shut-in pressure on CLU S-3 with its correlative reservoir pressure (Figure 4). This graph has been distributed to all key operating personnel so that injections can be reduced or terminated as necessary when surface pressure on CLU S-3 approaches 1500 psig. Finally, CINGSA's analysis of overall reservoir/well performance indicates the storage reservoir and wells are performing in a consistent and reliable manner, and there are no indications or evidence of any safety or integrity issues. CINGSA is evaluating the need for greater storage capacity than is possible within the constraints of the current maximum reservoir pressure limit of 1700 psia and will likely petition the AOGCC for an increase in maximum reservoir pressure in the near future. Figure 1 120.00 100.00 80.00 v 60.00 E E 40.00 w 0 20.00 z 3 0.00 c -20.00 Ii -40.00 C -60.00 -80.00 -100.00 titi tiIN Fib Historical CLU S-3 Shut-in Wellhead Pressure vs. Rate Trend - - Daily Inj/Wdrl Rate - mmcf/d 1600 1400 -OV a d 1200 N v a 1000 a s v 800 3 c 600 H M V1 400 u 200 15 ate • CLU S-3 Shut-in Wellhead Pressure - psig CINGSA Fall 2013 Wellhead Shut-in Pressures 1640 �- — 1620 Y 00 -—CLU Storage 1 a 1600 -- -- - -- 0 CLU Storage 2 - 4A n` 1580 ;"CLU Storage 3 X o * * * CLU Storage 4 s 1560 -- — -- -- --- -- 3 X CLU Storage 5 1540_.-- —+— Field Weighted �^ Avg. Press. 1520 - 1500 10/29 10/30 10/31 11/1 11/2 11/3 11/4 Shut-in Date Figure 3 1800 1600 1400 CD U) m 1200 L vi 1000 d CL 800 ev 600 400 200 0 Figure 4 2500 2000 0. v L a r 1000 E 0 V m 500 CINGSA Pressure vs. Inventory Hysteresis wil XX *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 5,000,000 10,000,000 15,000,000 20,000,000 Total Field Inventory, Mscf CLU S-3 Bottomhole Pressure vs. Wellhead Pressure u 0 250 500 750 1000 1250 Wellhead Pressure - psig 1500 1750 2000 • 40 Table 1 Well Name CLU 5-1 CLU S-2 CLU S-3 CLU S-4 CLU 5-5 Weighted Avg. WHIP (WAP) WAP Change Well Name CLU S-1 CLU S-2 CLU S-3 CLU 5-4 CLU S-5 Weight Factor* (Storage Pore -feet = (Por.•net MD•11-Sw)) 70.235 47.696 24.024 97.011 93.155 332,121 Weight Factor' - based on Ray Eastwood Log Model Wellhead Shut-in Pressures (Dsie) and Dates 10 29 2013 10 30 2013 10 31 2013 11 1 2013 11 2013 11 3 2013 11 4 2013 1619.5 1617.1 1615.2 1613.2 1611.5 1611.0 1609.2 1608.0 1605.7 1604.0 1602.5 1601.2 1600.4 1599.6 1517.9 1519.1 1519.5 1519.6 1519.5 1520.4 1520.7 1602.1 1596.9 1592.5 1588.7 1585.5 1583.0 1580.9 1589.2 1581.2 1576.2 1572.0 1568.7 1566.6 1564.9 1596.9 1592.4 1589.1 1586.2 1583.8 1582.3 1580.7 Weighted Average Pressure (Day -to -Day Change) Dav2vs.Dav1 Dav3vs.Dav2 Dav4vs.Dav3 DavSvs.Dav4 Dav6vs.Dav5 Dav7vs.Dav6 4.5 -3.3 -2.9 -2.4 -1.5 -1.6 Individual Well Pressure (Day -to -Day Change) Dav 2 vs. Dav 1 Dav 3 vs. Dav 2 Dav 4 vs. Dav 3 Dav 5 vs. Dav 4 Dav 6 vs. Dav 5 Dav 7 vs. Dav 6 -2.4 -1.9 -2 -1.7 -0.5 -1.8 -2.3 -1.7 -1.5 -1.3 -0.8 -0.8 1.2 0.4 0.1 -0.1 0.9 0.3 -5.2 -4.4 -3.8 -3.2 -2.5 -2.1 -8 -5 -4.2 -3.3 -2.1 -1.7 0 THE STATE Alaska Oil and Gas 01ALASKA Con-servation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Novemberl9, 2013 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7012 3050 0001 4812 5641 Ms. M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC PO Box 190989 Anchorage, AK 99519-0989 Re: Violation of Rule 7 of Storage Injection Order 9 Sterling C Gas Storage Pool Cannery Loop Unit Cannery Loop Field Dear Ms. Starring: On November 6, 2013, John Lau of Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) contacted the Alaska Oil and Gas Conservation Commission (AOGCC) to report that the results of a recent shut-in reservoir pressure survey for the Sterling C Gas Storage Pool indicated the reservoir pressure appeared to be above the 1700 psi limit imposed by Rule 7 of Storage Injection Order 9 (SIO 9). Within 14 days of receipt of this letter, CINGSA is requested to provide AOGCC with an explanation of how this event happened, what will be done to remedy this problem, and what has been or will be done to prevent its recurrence. This request is made pursuant to 20 AAC 25.300. The AOGCC reserves the right to pursue enforcement action in connection with exceeding the pressure limit set forth in Rule 7 of SIO 9 as provided by 20 AAC 25.535. Questions regarding this matter should be directed to Dave Roby at 907-793-1232. Sincerely, Cathy P oerster Chair, Commissioner Violation of Rule 7 of SIO 9 November 19, 2013 Page 2 of 2 AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. M rq Ln For delivery information visit our website at WWW.Usps.como ru r'11 co Postage $ Certified Fee Postmark O Return Receipt Fee Here C3 (Endorsement Required) Restricted Delivery Fee p (Endorsement Required) u7 fO Total Postage - fU Sent To Ms. M. Colleen Starring r-q ---------------- President C3 Street, Apt. No. Cook Inlet Natural Gas Storage Alaska, LLC r%- or PO Box No. Post Office Box 190989 City State, ZIP Anchorage, AK 99519-0989 :ro ■ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: Ms. M. Colleen Starring President Cook Inlet Natural Gas Storage Alaska, LLC Post Office Box 190989 Anchorage, AK 99519-0989 2. Article Number (Transfer from service label' PS Form 3811, February aid -7ON ❑ Agent E c Received by (Printed Name) C. Date of Delivery D. Is delivery address different from Rem 1? ❑ Yes If YES, enter delivery address below: ❑ No 3. Service Type 0 Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Delivery? (Extra Fee) ❑ Yes 7012 3050 0001 4812 5641 A #h; Returr 3,xwi4 102595-02401-1540 Attorney — Client emails held confidential in secure storage 0 0 Roby, David S (DOA) From: Roby, David S (DOA) Sent: Wednesday, November 13, 2013 10:00 AM To: 'John Lau' Cc: Moira Smith; Colleen Starring; Richard Gentges Subject: RE: CINGSA John, You're correct in that injection must be suspended until the average reservoir drops below 1700 psi, but as a point of clarification once injection does commence again the average reservoir pressure must be maintained at or below 1700 psi. Use of the No. 3 well to monitor the reservoir pressure is acceptable, we'd also be open to other methods of determining average reservoir pressure if you could demonstrate that they'd provide satisfactory results. Regards, Dave Roby (907) 793-1232 From: John Lau [mailto:John.LauOenstarnaturalcias.com] Sent: Monday, November 11, 2013 9:48 AM To: Roby, David S (DOA) Cc: Moira Smith; Colleen Starring; Richard Gentges Subject: RE: CINGSA Dave I would like to confirm our telephone discussion of current CINGSA operations, • CINGSA will suspend gas injections until a stabilized reservoir pressure can be demonstrated at 1700 psi or less. • Continued shut-in use of CINGSA No. 3 as a monitor well will suffice to track stabilized reservoir pressure. John John J Lau ENSTAR Natural Gas, Director John. Lau Penstarnaturaleas. com (907)-264-3736 Office (907)-244-3980 Cell From: Roby, David S (DOA) [mai Ito: clave. robyaalaska.gov] Sent: Friday, November 08, 2013 9:58 AM To: John Lau 0 Cc: Moira Smith; Colleen Starring; Pic iard Gentges Subject: RE: CINGSA John, In regards to your fourth bullet displacement of withdrawals is not the determining factor for when gas injection may occur. Gas injection may occur only when it can be demonstrated that the reservoir pressure is less than the limit established by Rule 7 of Storage Injection Order 9. Regards, Dave Roby (907) 793-1232 From: John Lau[mailto:3ohn.Lau((Ienstarnaturalgas.com] Sent: Wednesday, November 06, 2013 2:00 PM To: Roby, David S (DOA) Cc: Moira Smith; Colleen Starring; Richard Gentges Subject: CINGSA Dave As a follow up to our conversation this morning on the CINGSA injection pressure limit. • CINGSA believes the 1700 psi stabilized downhole pressure limit as set by the AOGCC has been reached. • CINGSA suspects reaching the 1700 psi limit prematurely is due to perforating a native pressure zone in CINGSA No. 1. • Additional net gas injection will not occur • Gas can be injected as a matter of displacement of withdrawals • CINGSA will continue to refine the reservoir model and schedule a meeting with the AOGCC to review Let me know if I missed anything Thank you in advance John John J Lau ENSTAR Natural Gas, Director John.Lau@enstarnaturalgas.com (907)-264-3736 Office (907)-244-3980 Cell Roby, David S (DOA) From: John Lau <John.Lau@enstarnaturalgas.com> Sent: Wednesday, November 06, 2013 11:31 AM To: Roby, David S (DOA) Subject: RE: CINGSA Shut In Data Dave See responses below. Feel free to call cell 244-3980 From: Roby, David S (DOA) [mailto:dave.roby0alaska.gov] Sent: Wednesday, November 06, 2013 10:50 AM To: John Lau Cc: Richard Gentges Subject: RE: CINGSA Shut In Data John, A couple of quick questions. First, the pressure for CLU-S3 is wising throughout the shut in period. I assume this is because the well hadn't been used for injection recently, correct? Yes Second, the pressures reported are all wellhead readings, correct? And if so, what is the adjustment used to extrapolate the WHP to BHP for each of the wells? Using a common datum of 5000 ft we calculate 216 psi additional pressure for downhole calculations. Thanks, Dave Roby (907) 793-1232 From: John Lau[mailto:John.Lau@enstarnaturalgas.com] Sent: Wednesday, November 06, 2013 9:52 AM To: Roby, David S (DOA) Cc: Richard Gentges Subject: CINGSA Shut In Data John J Lau ENSTAR Natural Gas, Director John. Lau(@enstarnaturaleas.com (907)-264-3736 Office (907)-244-3980 Cell E • Roby, David S (DOA) From: John Lau <John.Lau@enstarnaturalgas.com> Sent: Tuesday, November OS, 2013 9:00 PM To: Roby, David S (DOA) Subject: CINGSA Dave We finished our fall season shut in for CINGSA. There are some interesting developments I would like to discuss. Are you available Wednesday? Thank you in advance John Lau ENSTAR/CINGSA