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Home My WebLink AboutCO 390 AE • Conservation Order 390A Milne Point Unit 1. May 13, 2015 Notice of Public Hearing, Affidavit of Publication, mailing lists 2. May 29, 2015 Email re: Request for hearing by Hilcorp 3. July 27, 2015 Hilcorp request for hearing continuance 4. July 30, 2015 Revised Notice of Public Hearing, Affidavit of Publication, mailing and email list 5. September 10, 2015 Hearing Transcript, hearing sign -in sheet, hearing slides 6. September 24, 2015 Hilcorp post -hearing additional information Conservation Order 390A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: On its own motion the AOGCC requested review of Conservation Order No. 390, which grants an exception to 20 AAC 25.200(d) to allow ESP completions without a packer in all MPU wells. Docket Number: CO-15-006 Conservation Order No. 390A Milne Point Unit and Adjacent Areas Kuparuk River Oil Pool Schrader Bluff Oil Pool Sag River Undefined Oil Pool November 19, 2015 IT APPEARING THAT: 1. The Alaska Oil and Gas Conservation Commission (AOGCC) decided to review publically Conservation Order No. 390 (CO 390) which allows all Electrical Submersible Pump (ESP) completions in Milne Point Unit (MPU) and adjacent areas to be completed without a packer regardless of flow to surface potential. 2. On May 13, 2015, the AOGCC noticed the hearing for August 6, 2015 and published the notice on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On May 15, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On May 29, 2015, Hilcorp Alaska, LLC (Hilcorp) submitted a written request for the hearing to be held. 4. On July 27, 2015, Hilcorp requested the AOGCC to amend rather than rescind CO 390 and that the amended order apply to the current MPU boundary. Hilcorp also requested a continuance of the August 6 Public Hearing. 5. On July 30, 2015, the AOGCC published public notice changing the date of the hearing to September 10, 2015. The notice was published on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 31, 2015, the notice was published in the ALASKA DISPATCH NEWS. 6. The hearing commenced at 9:00 AM on September 10, 2015, in the public hearing room at the AOGCC's office located at 333 West 7th Avenue, Anchorage, A,K 99501. 7. Testimony was received from Guy Schwartz, AOGCC Senior Petroleum Engineer, representatives of Hilcorp as well as expert witnesses Dr. James Lea and Mr. Jeff Dwiggins. Conservation Order No. 390A • November 19, 2015 Page 2 of 4 8. The record was held open until September 24, 2015 to allow Hilcorp to respond to requests made during the hearing. 9. The AOGCC received the requested additional information from Hilcorp on September 24, 2015 and the record was closed. FINDINGS: Hilcorp is the operator of the leases in the portion of MPU covered by the Affected Area of this order. Hilcorp assumed operatorship of MPU from BP Exploration (Alaska) Inc. in November, 2014. Hilcorp and BP Exploration (Alaska) Inc. are the working interest owners, and the state of Alaska, Department of Natural Resources is the landowner of the Affected Area. 2. The Affected Area is defined in CO 390 and remains unchanged for CO 390A. 3. 20 AAC 25.200(d) requires all wells capable of unassisted flow to surface be completed with downhole tubing and packer that will isolate the tubing by casing annulus from produced fluid, unless otherwise specifically approved by the AOGCC. 4. Milne Point Unit (MPU) is the only operating field in Alaska with a field -wide waiver of the packer requirement for ESP equipped flow to surface wells. 5. MPU wells are not required to install subsurface safety valves under CO 348 (Kuparuk River Oil Pool) and CO 255 (Schrader Bluff Oil Pool) unless required under 20 AAC 25.265(d)(2) or 20 AAC 25.265(d)(3). 6. There are 84 active producing ESP production wells in MPU, 65 are completed in the Kuparuk River Oil Pool and 19 in the Schrader Bluff Oil Pool. Based on bottom -hole pressure (BHP) and watercut calculations 22 of these wells are capable of flow to surface. 21 of theese 22 wells are completed in the Kuparuk River Oil Pool. 7. MPU ESP wells are constructed with either single string casing (i.e. monobore) or multiple string casing (i.e. conventional completion). There are 10 monobore ESP wells in MPU. Only two of these wells are active (MPU G-14 and MPU E-15) and neither is capable of flowing to surface. 8. All packerless ESP completions in the Kuparuk River Oil Pool have multiple casing strings providing two mechanical barriers to flow. The surface casing by production casing annulus provides a liquid filled void to help detect casing leaks. 9. Testimony by Hilcorp documented the advantages and disadvantages of ESP with packers. The installation of packers in ESP wells provides an extra measure of safety but adds considerable cost to the completion and makes some routine well servicing procedures difficult or impossible. 10. According to expert witness testimony most other onshore fields worldwide with ESP completions do not require packers. The testimony did not establish whether these wells were capable of unassisted flow or not. 11. Since Hilcorp has taken over operatorship of MPU the AOGC'C has required sundry approval for all rig workover operations. Part of the sundry application for rig workovers includes an investigation into the last production casing pressure test. The AOGCC requires Conservation Order No. 390A • November 19, 2015 Page 3 of 4 a production casing test to a minimum of 1500 psi on packerless ESP completions at least once every 8 years. 12. Hilcorp voluntarily agreed by letter dated September 24, 2015 to manage reservoir pressures to a seawater gradient .442 psi/ft (8.55 ppg equivalent) in both the Schrader Bluff Oil Pool and Kuparuk River Oil Pool. Pattern In ratios will be used to lower average reservoir pressure at specific wells. Typically this involves reducing the injection rate in the offset service wells to reduce reservoir pressure. Of the twenty-one flow -to - surface MPU Kuparuk River Oil Pool ESP completions eleven have BHP equivalent pressures greater than 8.55 ppg (.442 psi/ft). As these Kuparuk River Oil Pool wells need workovers Hilcorp committed to either run an ESP with a packer or wait until the BHP is reduced enough not to require a packer. CONCLUSIONS: 1. Packerless ESP completions with potential high shut-in surface pressure can be managed by adjusting pattern Injection/Withdraw ratios to lower average reservoir pressure to a seawater gradient (8.55 ppg equivalent). With currently eleven Kuparuk River Oil Pool ESP wells with BHP gradient greater than 8.55 ppg completion requirements can be addressed on a case -by -case basis if pressure reduction is not successful. 2. Monobore (single casing) ESP completions should be phased out at MPU due to having only one mechanical barrier to flow. More frequent casing pressure; tests are warranted for these wells. 3. A blanket waiver for allowing packerless ESP completions in MPU is not justified. Statewide regulations regarding packerless completions are addressed by 20 AAC 25.200(d) which allow annular flow without packers if approved specifically b;y the AOGCC. NOW, THEREFORE, IT IS ORDERED: Rule 1 Casin2 Tests All multi -casing packerless ESP wells will have the production casing pressure tested at intervals not to exceed 8 years or as otherwise directed by the AOGCC. Single casing (monobore) packerless ESP wells will be pressure tested at intervals not to exceed 4 years or as otherwise directed by the AOGCC. Rule 2 Monobore Completions New single casing (monobore) ESP completions will not be approved unless a suitable monitoring annulus is provided as part of the well construction. Rule 3 ESP Packer Requirements Wells currently covered by CO 390 must be brought into compliance with 20 AAC 25.200 (d) the next time a workover that requires pulling the tubing/ESP is performed. Requirement for ESP packer installation will be made on a case by case basis. ESP wells exhibiting an equivalent BHP gradient of greater than 8.55 ppg at the time of the workover will require installation of a packer as part of the completion hardware. Conservation Order No. 390A November 19, 2015 Page 4 of 4 Rule 4 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Conservation Order No. 390 is hereby rescinded and replaced with Conservation Order No 390A *This order shall expire in 5 years or with change in operatorship. DONE at Anchorage, Alaska and dated November 19, 2015. Cathy/ . Foerster Daniel T. Seamount, Jr. Chai , Commissioner �" Commissioner 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. 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 nuns until 5:00 m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, November 19, 2015 2:36 PM To: AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Carrie Wong; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; IDelbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, lames J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); .lulie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Laney Vazquez; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak, Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); kinelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer, Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr, Smith, Graham 0 (DNR); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen 1 (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); K:air, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: Conservation Order 390A (Milne Point Unit) 0 Attachments: cova.pdf Please see attached. Samantha Cartisfe Executive Secretary 11 .Alaska Oil and Gas Conservation Commission 333 'Vest 7rti .Avenue .Anchorage, AX 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.g v. • 9 James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Richard Wagner Darwin Waldsmith David Wilkins P.O. Box 60868 P.O. Box 39309 Senior Vice PresidentP.O. Box 244027 Fairbanks, AK 99706 Ninilchik, AK 99639 Anchorage, AK 99524-4027 No�s�.�ar tot 2c�\� C)�-ssll� Angela K. Singh • Hilcorp Alaska, LLC September 24, 2015 RECEIVED SEP 2 4 2015 AOGCC Cathy Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 David Wilkins Senior Vice President Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone:907/777-8397 Fax: 907/777-8580 dwilkins@hilcorp.com Re: Conservation Order No. 390 / Docket No. CO-15-06 Post -Hearing Response to AOGCC Requests for Additional Information Dear Chair Foerster, Hilcorp Alaska, LLC ("Hilcorp") understands and shares the Alaska Oil and Gas Conservation Commission's ("AOGCC") concerns for safety, well integrity, and optimal performance of Milne Point Field operations. We also appreciate the opportunity to supplement the record and respond to specific questions raised, but not fully answered, during the September 10, 2015, hearing. Testimony presented by Mr. Guy Schwartz, AOGCC Petroleum Engineer, and direct questions posed by the Commissioners made clear: • Conservation Order 390 allows for packerless ESP completions field -wide at the Milne Point Unit. No other field in the state has a similar blanket exemption. • The AOGCC has specific concerns about packerless ESP completions on certain Milne Point Wells within the Kuparuk Oil Pool, particularly wells that exhibit "quite high surface pressures" relative to other ESP wells throughout the state. • The AOGCC does not have similar concerns regarding packerless completions on Milne Point wells within the Schrader Bluff formation. • Likewise, the AOGCC is not concerned about the field's packerless ESP water source wells (all of which are completed in the Ugnu/Price Creek Formation). • Overall, the AOGCC's objective is to ensure safe operation of all wells, and to regulate consistently across the state. Cathy Foerster • • September 24, 2015 Page 2 of 6 • Finally, the AOGCC expressed concerns that assumptions made in 1997 (when CO 390 was granted) may no longer be true today. I. Milne Point: Wells Capable of Unassisted Flow During the hearing, AOGCC requested Hilcorp to provide specific information regarding the ability of ESP wells at Milne Point to flow unassisted to the surface. Utilizing the latest recorded Static Bottom -Hole Pressure (SBHP)1 and Water Cut (WC)2 data available, Hilcorp conservatively predicts that 22 out of 84 active ESP production wells at Milne Point Field are capable of unassisted flow to the surface.3 Of these active wells, 22 are completed in the Kuparuk Oil Pool and one (1) is completed in the Schrader Bluff Oil Pool. No active monobore wells (all completed in the Schrader) are cable of flowing unassisted to the surface. FIGURE 1: Milne Point ESP Summary Active ESP Production Wells Total Count Capable of Unassisted Flow Total Kuparuk Schrader Total Kuparuk Schrader All 84 66 18 22 21 1 Packerless 83 65 18 22 21 1 Monobores 2 0 2 0 0 0 II. Active Reservoir Pressure Management Plan As supported by testimony offered at the hearing, Hilcorp is committed to aggressively reducing overall reservoir pressures throughout the Milne Point Field. Hilcorp's target reservoir pressure ' SBHP data was taken from either slickline operations that used memory gauges, or working ESP gauges. All data was taken from wells that were shut-in for at least 5 days. In each case, the TVD depth at which the pressure was recorded has been adjusted to datum TVD. The datum TVD for the Schrader Bluff is 4000'. The datum TVD for the Kuparuk is 7000'. In all cases, the datum pressure was adjusted using a 0.434 psi/ft gradient, representing a typical aquifer gradient at the Milne Point Unit. 2 WC data was taken from the latest approved well test and was used to estimate a hydrostatic fluid gradient, providing the hydrostatic pressure induced from fluids within the wellbore. 3 This prediction is based upon the criteria required for empirical proof of unassisted flow of hydrocarbons to the surface set forth in 20 ACC 25.265(1)(1). A description of the methodology and results of this analysis are attached hereto as Exhibit A. Cathy Foerster September 24, 2015 Page 3 of 6 is 3260 psi in the Kuparuk Oil Pool and 1860 psi in the Schrader Bluff (i.e., the pressures at which a well can be killed with seawater).4 Of the 21 active Kuparuk ESP wells that Hilcorp estimates to be capable; of unassisted flow, 11 are located at "F" Pad; six wells are located on "L" Pad; two wells are located at " B" pad; one (1) well is located on "K" Pad; and one is located on "C" pad. See attached Exhibit B1 (Kuparuk map). The only active Schrader Buff ESP well estimated to be capable of unassisted flow is located on "L" pad. See attached Exhibit B2 (Schrader Bluff map). This condition correlates directly with the discrete hydraulic units within the both pools that Hilcorp plans to manage by actively reducing overall reservoir pressure. In the event any of these 21 active ESP wells require a workover, Hilcorp commits to empirically testing calculated pressures by conducting no -flow tests prior to rigging up. If the subject well proves capable of flowing unassisted to the surface (i.e., fails the no -flow test), Hilcorp will either: (1) run a packer in connection with the proposed workover; or (2) defer the workover and continue to monitor shut-in reservoir pressures until Hilcorp can demonstrate the particular well is not capable of unassisted flow. Hilcorp is confident this approach will ultimately reduce the localized occurrence of over pressured hydraulic units within both the Kuparuk and Schrader Bluff Oil Pools. A recent case study of MPL-20 (Kuparuk ESP producer) is illustrative: • On April 8, 2013, the ESP on MPL-20 ceased operation due to a suspected shaft failure. On May 8, 2012, a pre -rig workover bottom -hole pressure measurement indicated a pressure of 3838 psi at Kuparuk datum (7000' TVD). At that pressure, the subject well is likely to be capable of unassisted flow. • In order to lower the pressure following the workover operation, BP reduced the offset injection rate in MPL-32 from 1700 bpd to 1200 bpd in July 2013. • After Hilcorp assumed operatorship of the Milne Point Unit, the injection rate in MPL-32 was further adjusted to approximately 1000 bpd in November 2014. This reduced the Injection -Withdrawal -Ratio (IWR) to 0.7 (measured as Injection bpd / Withdrawal bpd at reservoir conditions). • A BHP measurement was taken on September 18, 2015. On that date, Hilcorp found the pressure in MPL-20 was 3077 psi at Kuparuk datum (7000' TVD). This MPL-20 finding demonstrates the ability to successfully manage reservoir pressure through controlling IWR. Most portions of the Kuparuk and Schrader Bluff reservoirs are currently incapable of unassisted flow of hydrocarbons to the surface. Continued IWR management will drive the remaining segments of these reservoirs to reach pressures such that no wells will be capable of unassisted flow of hydrocarbons to the surface. 4 The standard seawater hydrostatic pressure gradient at the North Slope is 0.465 psi/ft. This gradient results in datum pressures of 1860 psi Schrader Bluff datum (4000' TVD) and 3260 psi Kuparuk datum (7000' TVD). Cathy Foerster 10 September 24, 2015 Page 4 of 6 III. Comparison to Similar Fields At the September 10 hearing, Hilcorp was invited — but not required — to respond to the question,: What makes Milne Point different from other fields that also have Kuparuk, Schrader Bluff and Sag ESP wells, but lack similar exemptions from the requirement of completing the wells with a packer? Respectfully, Hilcorp lacks sufficient first-hand information to adequately answer this question. Broadly, Hilcorp acknowledges that AOGCC generally allows North Slope ESP wells to be completed without packers, but only in on -shore fields, and after wells are demonstrated to be incapable of the unassisted flow of hydrocarbons to surface. IV. Modified Proposal to Amend CO 390 On July 24, 2015, Hilcorp requested that AOGCC amend CO 390, rather than vacate the order in its entirety. Hilcorp again renews this request, but in light of new information obtained at the hearing, and additional information presented in this letter, Hilcorp respectfully urges the AOGCC adopt the following guidelines: 1. Schrader Bluff Reservoir: A. Hilcorp requests the exception granted by Conservation Order 390 remain in place for all active and inactive Schrader Bluff ESP wells, so long as reservoir pressure remains at or below 1860 psi (4000' TVD Datum) (see note 4). No -flow tests will be required only if said measured reservoir pressure exceeds 1860 psi in an existing well prior to conducting a proposed ESP workover. If competent data suggests that a particular Schrader Bluff well is capable of unassisted flow to the surface, then Hilcorp will either (a) defer the ESP workover until target reservoir pressure is achieved, or (b) install a packer as a component of the workover. B. Prior to completion of new Schrader Bluff development wells, Hilcorp requests AOGCC consider proposals for packerless ESP completions on a case -by -case basis. A no flow test will not be required if reported reservoir pressures are reasonably demonstrated to be at or below 1860 psi (4000' TVD Datum), and completion of packerless ESP wells will be permitted. Otherwise, Hilcorp will undertake no -flow tests and will install packers for all new Schrader Bluff ESP wells that are capable of unassisted flow of hydrocarbons to the surface. 2. Kuparuk Reservoir: A. Hilcorp requests the exception granted by Conservation Order 390 remain in place for all active and inactive Kuparuk ESP wells, so long as reservoir pressure remains at or below 3260 psi (7000' TVD Datum) (see note 4). No -flow tests will be required only if said measured reservoir pressure exceeds 3260 psi in an existing well prior to conducting a proposed ESP workover. If competent data Cathy Foerster September 24, 2015 Page 5 of 6 reasonably suggests that a particular Kuparuk well is capable of flowing unassisted to the surface, then Hilcorp will either (a) defer the ESP workover until target reservoir pressure is achieved, or (b) install a packer as a component of the workover. B. Prior to completion of new Kuparuk development wells, Hilcorp requests AOGCC consider proposals for packerless ESP completions on a case -by -case basis. A no flow test will not be required if reported reservoir pressures are reasonably demonstrated to be at or below 3260 psi (7000' TVD Datum), and completion of packerless ESP wells will be permitted. Otherwise, Hilcorp will undertake no -flow tests and will install packers for all new Kuparuk ESP wells that are capable of unassisted flow of hydrocarbons to the surface. 3. For the Milne Point Field's packerless ESP water wells (all completed in the Ugnu/Prince Creek Formation), the exemption currently provided by CO 390 is requested to remain in place for all active (7 total) and inactive (one total) packerless wells. V. Dual Barriers in Existing MPU ESP Wells Hilcorp's original proposal to modify CO 390 was in response to a misplaced perception that AOGCC was primarily concerned about the integrity of the Milne Point Field's monobore ESP production wells. As demonstrated herein, all such wells are completed in the Schrader Bluff Oil Pool and none are reasonably capable of flowing to the surface unassisted. No basis exists to question the integrity of this class of wells. As reinforced by AOGCC's own testimony at the hearing, Hilcorp is adequately monitoring and reporting casing data (field wide) on a timely basis. In onshore fields such as Milne Point, ESP wells are considered a lower -risk category of wells and subsurface safety valves (SSSV) are not required. Without an SSSV, the installation of a packer is redundant in wells with two existing barriers (i.e., production casing and surface casing). As supported by the hearing testimony, installation of a shallow set: packer presents risks different than those of a packerless ESP completion. Below that shallow -set packer, there is no tubing isolation and no monitoring is available. Such a completion method still relies on the production casing below the tubing packer as a primary barrier — but the design makes it impossible to monitor or detect pressure or fluid level changes on that annulus. If packers were required on ESP wells, Hilcorp would be unable to diagnose potential production casing leaks by pumping down the inner annulus. The packerless completion, on the other hand, utilizes the uninterrupted production casing as the primary barrier and the surface casing as the secondary barrier. Actual surface casing burst pressures in MPU wells range from 4000-6000 psi which substantially exceeds maximum anticipated surface pressures. Any pressure between the surface casing and the production casing is limited by regulations to a highly conservative 1000 psi. Cathy Foerster September 24, 2015 Page 6 of 6 As such, the 1000 psi limit is more than adequate to handle the worst: case expected surface pressure of any Milne Point ESP well — including all Kuparuk ESP wells (-1000 psi). Furthermore, all Kuparuk ESPs are completed with a surface casing that extends below permafrost (> than 2000') and are completely cemented to surface. VI. Conclusion Evidence now in the record adequately demonstrates that completion of Milne Point ESP wells without a packer can improve operational efficiency, promote safer operations, increase ultimate recovery and extend field life. An exception to the general requirement. of packer completions should only be allowed in onshore wells with reservoir pressures at or below 1860 psi at 4000' TVD Datum in the Schrader Bluff, and 3260 psi at 7000' TVD Datum in the Kuparuk. See note 4. At or below these proposed thresholds, the benefits of packerless ESP operations outweigh the operational, cost and ultimate recovery impacts associated with running ESP completions with packers. Hilcorp is committed to undertaking the steps required to aggressively, reduce such localized conditions in Milne Point by actively managing the field's legacy injection practices. Such efforts are already underway, but will take time, and a transition period of one to three years is required to make this appropriate adjustment. Our proposal to establish field -wide threshold reservoir pressures (1860 psi in the Schrader Bluff and 3260 psi in the Kuparuk) as a means of estimating a particular well's ability to flow unassisted is based on sound reservoir engineering principles. This concept can be empirically tested by witness no -flow tests performed on any of the 21 active Kuparuk ESP wells referenced above that Hilcorp believes may be capable of flowing unassisted. Such tests would be performed prior to commencement of the next scheduled workover. Over time, such no -flow tests may prove unnecessary — and reliance on the proven threshold reservoir pressure will likely be proven sufficient. Through implementation of such performance -driven requirements, an amendment to Conservation Order 390 can be readily crafted to ensure that Hilcorp's Milne Point operations meet or exceed existing state standards. If you have any additional questions concerning this request, please contact Wyatt Rivard at 777- 8547 or by email at wrivard@hilcorp.com. in erely D vid Wilkins cc: Guy Schwartz, AOGCC (via email); James Regg, AOGCC (via email) Ililrurp :Alaska, LLC Exhibit A: Estimation of Active Milne Point ESP Wells to Flow to Surface In order to best estimate a condition in which a well using an Electric, Submersible Pump at Milne Point would be capable of unassisted flow to surface we created a table that lists all of the latest recorded Static Bottom -Hole Pressures and Watercuts for each respective ESP well. Using the WC from the latest approved welltest, we could estimate a hydrostatic fluid gradient, providing the hydrostatic pressure induced from fluids within the wellbore. Using this value in conjuction with the latest SBHP would then provide an estimate of the respective wells Expected Surface Pressure. If positive surface pressure is expected at surface, then unassisted flow was thought to be possible in the respective well. Static Bottom -Hole Pressure (SBHP) Recording A representative SBHP was recorded for each respective well if at least one of the following two criteria were met: 1) Any SBHP gathered from a slickline operation that used memory gauges - as long as the well had been SI for at least 5 days. 2) Any SBHP that was taken from a working ESP gauge - after the well was SI for at least 5 days. The reason for waiting at least 5 days before taking a pressure recording; was to ensure that the well's transient pressure build-up period was given adequate time to adjust and adequately represent static reservoir conditions. Each SBHP was recorded along with the date in which that data was gathered. In each case, the TVD depth at which the pressure was recorded was adjusted to datum TVD. The datum depth was dependent on which reservoir the well produces from. In all cases, the datum pressure was adjusted using a 0.434 psi/ft gradient, representing a typical aquifer gradient at Milne Point. - 2500' TVD Ugnu Source Water - 4000' Schrader Bluff Reservoir - 7000' Kuparuk Reservoir - 8750' Sag Reservoir *It should be worth noting that all SBHP's and hydrostatic gradient calculations are corrected to the respective TVD datum depth, depending on the reservoir in which the respective well is producing. * Watercut Watercuts were pulled from the latest approved welltests at Milne Point. 'The dates at which each watercut reading were recorded are listed on the table. Each watercut reading is checked/monitored by both town engineers (operations & reservoir) and field -based pad engineers. If an operator and/or town -based engineer are uncertain about a particular watercut measurement, a sample may be collected at surface by the operator and measured manually to confirm accuracy. Hydrostatic Pressure Gradient Calculation The following gradients were used in calculating the overall hydrostatic gradient of a particular well. Given that Schrader Bluff oil is more viscous/'heavy' than Kuparuk oil it was estimated that Schrader Bluff oil carries a slightly higher hydrostatic pressure than that of Kuparuk oil. The following gradients were used in the calculations: Field -wide Produced Water Gradient: 0.434 psi/ft Schrader Bluff Oil Gradient (18' API): 0.410 psi/ft Kuparuk Oil Gradient (23' API): 0.397 psi/ft Sag River Oil Gradient (300 API): 0.371 psi/ft Unassisted Flow Conclusion If the calculated hydrostatic pressure at datum is greater than the last recorded SBHP, then the well carries a `negative' Expected Shut -In Surface Pressure and it is predicted that the well would not be capable of flowing to surface unassisted. If the calculated hydrostatic pressure at datum is less than the last recorded SBHP, then the well carries a `positive' Expected Shut -In Surface Pressure and it is predicted that well would be capable of flowing to surface unassisted. FIGURE 1: Milne Point ESP Summary Active ESP Production Wells Total Count Capable of Unassisted Flow Total Ku aruk Schrader Total Ku aruk Schrader All 84 66 18 22 21 1 Packerless 83 65 18 22 21 1 Monobores 2 0 2 0 0 0 Active Schrader Bluff ESP Wells Well MPE-15 API 50029225280000 Type Oil SC Shoe Monobore Packer Packerless Datum 4000 BHP 1502 BHP Date 2/11/2014 WC 93.1 WC Date 8/13/2015 Gradient 0.4324 MASP -227 Unassisted Flow Possible No MPE-20A 50029225610100 Oil 2587 Packerless 4000 1560 9/5/2015 79.5 9/2/2015 0.4291 -156 No MPE-32 50029232610000 Oil 2744 Packerless 4000 1050 11/16/2014 52.4 9/7/2015 0.4226 -640 No MPG-02 50029219260000 Oil 2856 Packerless 4000 1284 3/29/2013 57.7 9/7/2015 0.4238 -411 No MPG-14 50029230310000 Oil Monobore Packerless 4000 1466 2/15/2013 63.1 9/2/2015 0.4251 -235 No MPG-16 50029231890000 Oil 2526 Packerless 4000 1318 10/8/2014 76.6 9/3/2015 0.4284 -396 No MPH-16 50029232270000 Oil 4182 Packerless 4000 1094 8/11/2014 58.9 9/2/2015 0.4241 -602 No MPI-03 50029220670000 Oil 2633 Packerless 4000 1267 3/21/2015 11.4 5/18/2015 0.4127 -384 No MPI-04A 50029220680100 Oil 2599 Packerless 4000 1013 6/14/2015 48.0 5/14/2015 0.4215 -674 No MPI-07 50029226020000 Oil 2680 Packerless 4000 1496 7/5/2014 25.6 5/14/2015 0.4161 -169 No MPI-12 50029230380000 Oil 2905 Packerless 4000 1368 9/15/2015 2.7 3/15/2014 0.4107 -275 No MPI-14 50029232140000 Oil 2698 Packerless 4000 1215 7/22/2012 80.8 8/21/2015 0.4294 -503 No MPI-15 50029231060000 Oil 3085 Packerless 4000 1259 3/7/2015 54.4 9/7/2015 0.4231 -434 No MPI-17 50029232120000 Oil 2378" Packerless 4000 1193 7/22/2012 78.0 8/18/2015 0.4287 -522 No MPI-19 50029232180000 Oil 2999 Packerless 4000 1387 1/29/2013 30.4 9/5/2015 0.4173 -282 No MPJ-0lA 50029220700100 Oil 2409 Packerless 4000 1319 2/1/2015 60.6 8/16/2015 0.4245 -379 No MPJ-04 50029220730000 Oil 2413 Packerless 4000 1832 12/31/2013 73.2 7/24/2015 0.4276 122 Yes MPJ-09A 50029224950100 Oil 2936 Packerless 4000 1521 9/15/2015 53.0 8/7/2015 0.4227 -170 No • • Active Ku aruk ESP Wells Well MPC-01 API 50029206630000 Type Oil SC Shoe 2338 Packer Packerless Datum 7000 BHP 1961 BHP Date 6/14/2015 WC 72.1 WC Date 9/11/2015 Gradient 0.4237 MASP -1005 Unassisted Flow Possible No MPC-13 50029213280000 Oil 4779 Packerless 7000 2101 2/4/2015 81.4 9/13/2015 0.4271 -889 No MPC-14 50029213440000 Oil 5100 Packerless 7000 3260 4/17/2013 90.4 9/13/2015 0.4304 247 Yes MPC-22A 50029224890100 Oil 6715 Packerless 7000 2714 7/22/2012 94.3 9/10/2015 0.4319 -309 No MPC-43 50029232000000 Oil 9363 Packerless 7000 1773 7/22/2012 62.6 9/11/2015 0.4202 -1168 No MPE-04 50029219970000 Oil 5740 Packerless 7000 1290 6/14/2015 90.7 9/14/2015 0.4306 -1724 No MPE-06 50029221540000 Oil 5231 Packerless 7000 2321 6/14/2015 91.4 9/14/2015 0.4308 -695 No MPE-09 50029225130000 Oil 3814 Packerless 7000 2209 6/14/2015 98.1 9/15/2015 0.4333 -824 No MPE-10 50029225210000 Oil 4100 Packerless 7000 2635 6/14/2015 91.5 9/10/2015 0.4309 -381 No MPE-11 50029225410000 Oil 3455 Packerless 7000 3116 2/19/2015 72.3 9/10/2015 0.4237 150 Yes MPE-14A 50029227340100 Oil 5543 Packerless 7000 2272 5/17/2013 81.5 9/11/2015 0.4272 -718 No MPE-18 50029227480000 Oil 4301 Packerless 7000 1 - 3270 9/5/2014 84.8 8/23/2015 0.4284 271 Yes MPE-19 50029227460000 Oil 3955 Packerless 7000 1478 3/12/2014 35.1 9/15/2015 0.4100 -1392 No MPE-22 50029225670000 Oil 3745 Packerless 7000 1555 5/17/2015 91.1 9/11/2015 0.4307 -1460 No MPF-01 50029225520000 Oil 7124 Packerless 7000 � 3399 6/14/2015 89.0 9/7/2015 0.4299 389 Yes MPF-05 50029227620000 Oil 5570 Packerless 7000 3830 7/4/2015 98.0 9/12/2015 0.4333 797 Yes MPF-06 50029226390000 Oil 8767 Packerless 7000 1 2600 1 6/14/2015 85.2 9/12/2015 0.4285 1 -399 1 No MPF-09 5002922 / /30000 Oil 6288 Packerless 7000 2577 4/6/2015 85.5 9/12/2015 0.4286 -424 No MPF-14 50029226360000 Oil 6690 Packerless 7000 2206 6/14/2015 84.7 9/8/2015 0.4283 -793 No MPF-18 50029226810000 Oil 7914 Packerless 7000 2850 5/4/2014 87.3 9/9/2015 0.4293 -155 No MPF-22 50029226320000 Oil 8842 Packerless 7000 2725 6/14/2015 87.8 9/9/2015 0.4295 -281 No MPF-25 50029225460000 Oil 3405 Packer at 10296' w/ ported tubing 7000 2626 6/14/2015 70.7 9/14/2015 0.4232 -336 No L-.] • Well MPF-29 API 50029226880000 Type Oil SC Shoe 8019 Packer Packerless Datum 7000 BHP 1461 BHP Date 8/5/2013 WC 48.4 WC Date 9/14/2015 Gradient 0.4149 MASP -1443 Unassisted Flow Possible No MPF-34 50029228240000 Oil 8680 Packerless 7000 1698 7/24/2012 3.5 9/15/2015 0.3983 -1090 No MPF-37 50029225480000 Oil 6621 Packerless 7000 1453 6/14/2015 86.6 9/15/2015 0.4290 -1550 No MPF-38 50029226140000 Oil 8561 Packerless 7000 3475 7/25/2012 74.3 9/15/2015 0.4245 504 Yes MPF-45 50029225560000 Oil 6678 Packerless 7000 1848 6/14/2015 80.9 9/15/2015 0.4269 -1140 No MPF-50 50029227560000 Oil 9099 Packerless 7000 1316 10/22/2013 43.5 9/11/2015 0.4131 -1576 No MPF-53A 50029225780100 Oil 6750 Packerless 7000 2401 5/4/2014 85.9 9/11/2015 0.4288 -600 No MPF-54 50029227260000 Oil 9903 Packerless 7000 2976 11/8/2014 65.1 9/11/2015 0.4211 28 Yes MPF-57A 50029227470100 Oil 9340 Packerless 7000 2979 6/14/2015 70.5 9/11/2015 0.4231 17 Yes MPF-61 50029225820000 Oil 6586 Packerless 7000 1351 5/4/2014 71.6 9/13/2015 0.4235 -1613 No MPF-65 50029227520000 Oil 8604 Packerless 7000 1679 12/5/2013 59.8 9/13/2015 0.4191 -1255 No MPF-66A 50029226970100 Oil 8223 Packerless 7000 1537 8/6/2013 0.9 9/13/2015 0.3973 -1244 No MPF-69 50029225860000 Oil 5778 Packerless 7000 ' 3672 12/4/2013 89.7 9/14/2015 0.4302 661 Yes MPF-78A 50029225990100 Oil 7919 Packerless 7000 2892 5/4/2014 84.2 9/14/2015 0.4281 -105 No MPF-79 50029228130000 Oil 7340 Packerless 7000 3167 6/15/2014 85.9 9/6/2015 0.4288 165 Yes MPF-81 50029229590000 Oil 7515 Packerless 7000 3496 2/26/2015 80.0 9/6/2015 0.4266 509 Yes MPF-86 50029230180000 Oil 6517 Packerless 7000 3215 6/8/2014 69.8 9/6/2015 0.4228 255 Yes MPF-87A 50029231840100 Oil 4945 Packerless 7000 2703 6/14/2015 87.1 9/6/2015 0.4292 -302 No MPF-93 50029232660000 Oil 7925 Packerless 7000 3336 6/14/2015 84.3 9/7/2015 0.4282 339 Yes MPF-94 50029230400000 Oil 10341 Packerless 7000 3134 11/7/2014 75.4 9/7/2015 0.4249 160 Yes MPH-05 50029225720000 Oil 5335 Packerless 7000 2576 7/22/2012 95.6 9/4/2015 0.4324 -451 No MPJ-06 50029224930000 Oil 2511 Packerless 7000 2303 7/22/2012 86.7 8/10/2015 0.4291 -701 No MPJ-10 50029225000000 Oil 2664 Packerless 7000 2933 2/5/2015 78.0 8/19/2015 0.4259 -48 No MPK-05 50029226700000 Oil 3823 Packerless 7000 2602 12/6/2013 83.7 9/14/2015 0.4280 -394 No MPK-17 50029226470000 Oil 3508 Packerless 7000 2656 7/22/2012 59.7 9/15/2015 0.4191 -278 No MPK-37 50029226740000 Oil 3652 Packerless 7000 3494 2/23/2014 100.0 6/19/2015 0.4340 456 YCfi Active Ku aruk ESP Wells Active Ku aruk ESP Wells Well MPK-38 API 50029226490000 Type Oil SC Shoe 3545 Packer Packerless Datum 7000 BHP 1447 BHP Date 6/14/2015 WC 98.4 WC Date 9/13/2015 Gradient 0.4334 MASP -1587 Unassisted Flow Possible No MPL-01A 50029210680100 Oil 2438 Packerless 7000 1828 6/14/2015 74.4 8/18/2015 0.4245 -1144 No MPL-02A 50029219980100 Oil 5076 Packerless 7000 2076 8/7/2013 70.5 9/7/2015 0.4231 -886 No MPL-03 50029219990000 Oil 2578 Packerless 7000 3393 7/14/2012 76.0 9/14/2015 0.4251 417 Yes MPL-04 50029220290000 Oil 6277 Packerless 7000 3159 3/28/2015 73.3 9/8/2015 0.4241 190 Yes MPL-05 50029220300000 Oil 6044 Packerless 7000 1984 7/24/2012 41.7 9/9/2015 0.4124 -903 No MPL-07 50029220280000 Oil 6850 Packerless 7000 2723 7/24/2012 88.5 9/13/2015 0.4298 -285 No MPL-11 50029223360000 Oil 6715 Packerless 7000 3348 10/6/2012 65.0 9/13/2015 0.4210 401 Yes MPL-12 50029223340000 Oil 2584 Packerless 7000 2013 5/17/2015 65.2 9/11/2015 0.4211 -935 No MPL-13 50029223350000 Oil 6086 Packerless 7000 2896 11/28/2013 72.2 9/11/2015 0.4237 -70 No MPL-14 50029224790000 Oil 7769 Packerless 7000 1723 5/17/2015 5.2 9/14/2015 0.3989 -1070 No MPL-20 50029227900000 Oil 8160 Packerless 7000 3077 9/15/2015 71.9 9/5/2015 0.4236 112 Yes MPL-25 50029226210000 Oil 9019 Packerless 7000 3473 5/17/2015 73.0 9/12/2015 0.4240 505 Yes MPL-28A 50029228590100 Oil 7177 Packerless 7000 2486 2/7/2015 66.3 9/12/2015 0.4215 -464 No MPL-29 50029225430000 Oil 7676 Packerless 7000 2271 3/28/2015 60.5 9/5/2015 0.4194 -665 No MPL-36 50029227940000 Oil 7673 Packerless 7000 3000 11/6/2011 27.0 9/6/2015 0.4070 151 Yes MPL-40 50029228550000 Oil 7560 Packerless 7000 2475 7/24/2012 59.4 9/6/2015 0.4190 -458 No MPL-43 50029231900000 Oil 6097 Packerless 7000 1906 1/23/2015 52.9 9/7/2015 0.4166 1 -1010 No LI • d4 FJ I( \ \ I F-y7j \ � i FJ7A F-79 II L-25 \ I v I, I,F}99 j I I F O�F� VIII � I i I II d i 4 i IN F46 • "' �Rh 'l IVER UNIT HILCORP ALASKA LLC MILNE POINT FIELD WELLS CPPABLED UWISSWMD1-1 aW aMwusyrnmLLat ap KupwtA3 uM Exhibit 131 Map of Active Kuparuk ESP We Its Estimated to be Capable of Fli iw 0 • I -/ IVER UNIT / HILCORP ALASKA LLC MILNE POINT FIELD SCM MR MUFF FOR TIT WELL CAPABLE OF UNASSISTED FLOW Ex ibit ff Map of Milne Point Schrader BI E / Wells Estimated to be Capable f F I MILNE OINT UNIT I B2 SP ow 0 1 0 1 1 2 ALASKA OIL AND GAS CONSERVATION COMMISSION 3 4 Before Commissioners: Cathy Foerster, 5 Chair 6 Daniel T. Seamount 7 In the Matter of the Proposed ) 8 Cancellation of Conservation Order ) 9 No. 390 for the Kuparuk River ) 10 Oil Pool, Schrader Bluff Oil Pool, ) 11 Sag River Oil Pool, Milne Point Unit.) 12 ) 13 Docket No.: CO 15-06 14 ALASKA OIL and GAS CONSERVATION COMMISSION 15 16 Anchorage, Alaska 17 September 10, 2015 18 9:00 o'clock a.m. 19 20 VOLUME I 21 PUBLIC HEARING 22 23 BEFORE: Cathy Foerster, Chair 24 Daniel T. Seamount, Commissioner 1 TABLE OF CONTENTS 2 3 Opening remarks by Chair Foerster 03 4 Remarks by Mr. Schwartz 07 5 Remarks by Mr. Bond 10 6 Remarks by Mr. Elliott 13 7 Remarks by Mr. O'Malley 28 8 Remarks by Mr. McConkey 38 9 Remarks by Mr. Chan 48 10 Remarks by Dr. Lea 75 11 Remarks by Mr. Rivard 101 12 Remarks by Mr. Dwiggins ill 2 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHAIR FOERSTER: Okay. I'll call this hearing 4 to order. It's about 9:00 o'clock in the morning on 5 September loth, 2015. We're located at the offices of 6 the Alaska Oil and Gas Conservation Commission at 333 7 West Seventh Avenue, Anchorage, Alaska. To my left is 8 Dan Seamount, Commissioner, and I'm Cathy Foerster. 9 We're meeting today on Docket CO 15-06, Kuparuk 10 River oil pool Schrader Bluff oil pool, Sag River oil 11 pool, all in the Milne Point unit to consider 12 cancellation of conservation order number 390. The 13 AOGCC is considering canceling this order which exempts 14 Milne Point unit wells from the requirements of 20 AAC 15 25.200(d). 16 Computer Matrix will be recording today's 17 proceedings. If you need a copy you can get a copy of 18 the transcript from Computer Matrix. 19 Before we get started just some housekeeping. 20 During testimony and after testimony the Commissioners 21 ask questions. We may take a recess to consult with 22 staff to determine whether additional questions or 23 clarifying question are necessary. If a member of the 24 audience has a question that he or she feels should be 25 asked please submit it to Samantha Carlisle who's in 3 0 1 the back of the room doing the float wave, she'll 2 provide that question to the Commissioners and if we 3 feel that asking the question will assist us in making 4 our determinations we'll do so. 5 I know this is probably -- this is a first time 6 for Hilcorp, but just an FYI, when you come with 7 presentation materials we need you to bring hard copies 8 of them so put that in your head for future. We don't 9 make your xerox copies for you and we do need hard 10 copies. 11 All right. If you're testifying please keep in 12 mind that you need to speak into the microphone so that 13 the audience can hear you and the court reporter can 14 get a good recording of what you say. And please 15 remember also as you speak to your presentation 16 materials to reference them by title or slide number so 17 that as they become part of the permanent record and 18 somebody tries to reconstruct the hearing five years 19 from now it makes sense to them. You know, when you 20 say well, as you can see in this picture 21 (indiscernible), you got 50 pictures in here, which one 22 are you talking about. And so you understand what I'm 23 saying I hope. 24 Okay. We all -- we have a few ground rules on 25 what is allowed relative to testimony because sometimes M 1 people from the public who don't understand what we're 2 here for like to talk about things. So first of all 3 testimony must be relevant to the purposes of the 4 hearing that we -- that I outlined for you a few 5 minutes ago and they must also be relevant to the 6 statutory authority of the AOGCC. Anyone desiring to 7 testify may do so, but if the testimony drifts off 8 subject we will limit the testimony to three minutes. 9 Additionally testimony may not take the form of cross 10 examination, as I said before the two Commissioners 11 will be asking all the questions today. And finally 12 testimony that's disrespectful or inappropriate, I have 13 to say this because it's happened, will not be allowed. 14 Dan, do you have anything to add for the good 15 of the order? 16 COMMISSIONER SEAMOUNT: I have nothing. 17 CHAIR FOERSTER: All right. So what we'll do 18 is -- I see that several Hilcorp people are planning to 19 testify and then nobody else. So I can swear in all of 20 the Hilcorp people at once which might make things go a 21 little faster and then as you testify we'll do your 22 personal introductions and whether you want to be 23 accepted as an expert. So if you're a Hilcorp person 24 and you're planning to testify why don't you come on up 25 and we'll just swear you in all at one time. And if 0 1 you can get close to the microphone when -- just when 2 you say the I do, you know, each one of you pass by the 3 microphone and say your name and I do. 4 (Oath administered) 5 CHAIR FOERSTER: Go by the microphone, say your 6 name and say I do. 7 MR. ELLIOTT: Keith Elliott. I do. 8 CHAIR FOERSTER: All right. Good job. 9 MR. CHAN: Paul Chan. I do. 10 MR. RIVARD: Wyatt Rivard. I do. 11 JIM LEA: Jim Lea. I do. 12 MR. DWIGGINS: Jeff Dwiggins. I do. 13 MR. O'MALLEY: Mark O'Malley. I do. 14 MR. BOND: Marc Bond. I do. 15 MR. McCONKEY: Anthony McConkey. I do. 16 CHAIR FOERSTER: I now pronounce you man and 17 wife. Just kidding. 18 All right. So let's begin with your testimony. 19 20 (Whispered conversation) 21 CHAIR FOERSTER: Oh, Tab just reminded me of 22 something. You guys don't get to testify first, Guy 23 Schwartz from the AOGCC does. But you guys will remain 24 sworn in. Guy, come on up, you get to -- you're going 25 to set the ground work for today -- ground rules for 2 0 1 today's hearing. 2 MR. SCHWARTZ: (Indiscernible - away from 3 microphone)..... 4 CHAIR FOERSTER: All right. So I'll swear you 5 in. Raise your right hand. 6 (Oath administered) 7 MR. SCHWARTZ: I do. g GUY SCHWARTZ 9 called as a witness on behalf of the AOGCC, testified 10 as follows on: 11 DIRECT EXAMINATION 12 CHAIR FOERSTER: All right. For the record 13 your name, who you represent and if you want to be -- 14 do we need to have him sworn in as an expert? 15 COMMISSIONER SEAMOUNT: We recognize him as an 16 expert. 17 CHAIR FOERSTER: Tab, it's up to you? lg MR. BALLANTINE: (Inaudible response)..... 19 CHAIR FOERSTER: Yes. Okay. So give your 20 qualifications in the area you want to be expert -- 21 recognized as an expert in and we'll decide. 22 MR. SCHWARTZ: Okay. My name is Guy Schwartz, 23 I am a staff engineer -- senior staff engineer at the 24 Oil and Gas Commission. I'm a graduate of the 25 University of North Dakota with a geological 7 • • 1 engineering background or degree and I'm a registered 2 professional engineer in petroleum in the state of 3 Alaska. And that's it, been here for six years working 4 at the Oil and Gas Commission. 5 CHAIR FOERSTER: And you want to be recognized 6 as an expert in..... 7 MR. SCHWARTZ: Yes. 8 CHAIR FOERSTER: .....petroleum engineering. 9 MR. SCHWARTZ: I'd like -- in petroleum 10 engineering, yes. 11 CHAIR FOERSTER: Okay. Dan? 12 COMMISSIONER SEAMOUNT: I have no questions. 13 CHAIR FOERSTER: Nor do I. I have no problems 14 with accepting you as an expert. So please give us 15 your testimony. 16 MR. SCHWARTZ: All right. I guess 390 is a -- 17 just a background, everybody I'm -- everybody here is 18 familiar with it, but it -- that conservation order 19 exempts Milne Point from any packers or ESP completions 20 based on subsurface safety valve requirements, it 21 doesn't need a subsurface valve, packer isn't required. 22 So that's field wide. 23 Part of my job is to review sundries for work -- 24 well work and follow-up on well work that's been done 25 in the 10/404s that are submitted. What brought this 1 up was I started looking at well work histories for 2 many of the ESP wells that were -- have been done and 3 noticed that on the kill part of the well these -- 4 several wells in the Kuparuk field have quite high 5 surface pressures when they shut them in and typically 6 for the rest of the state ESP wells are not -- you 7 don't see high surface pressures and that -- I was kind 8 of surprised at the number of those wells. And then I 9 kept looking back at 390 and decided well, this is the 10 only field in the state of Alaska that has an exemption 11 for packers, everybody else in the state, every other 12 field, every other unit is required to have no flow 13 tests on ESP wells, if not they have to have packers. 14 So that's where it kind of came about. 15 And also I noticed that over the history of the 16 Milne Point field that casing tests were not being 17 done. That's a BP legacy and I -- BP started doing 18 that at my request just before they -- Hilcorp took 19 over the field and Hilcorp has been good about keeping 20 me on top of what's going on with casing integrity 21 which is key for us. 22 So there's about 119 wells at Milne Point that 23 are ESP wells, about 40 or 60 percent are Kuparuk wells 24 which are our biggest concern because Schrader Bluff is 25 a relatively low pressure reservoir and other operators Vol 1 typically run those without packers on the Slope and we 2 don't have a concern. It's really the Kuparuk wells 3 that are my concern. And there's also a concern about 4 the amount of our wells that are in place up there 5 already, but most of those are shut in so it's not a 6 big concern to us right now, it's mostly Kuparuk wells 7 that are ESP wells without packers. 8 390 was written 20 years ago and if you look at 9 the conclusions and statements in that conservation 10 order there's -- it just seems like it's outdated and 11 some assumptions were made that may not be true today 12 and I think it needs to be relooked at and really come 13 to what is our goal -- what is our goal and -- as a Oil 14 and Gas Commission is to ensure safe operation of these 15 wells and I think it needs to be looked at so we're 16 consistent across the state. 17 So that's what I want to say finally. So..... 18 CHAIR FOERSTER: Okay. Commissioner Seamount, 19 do you have any questions? 20 COMMISSIONER SEAMOUNT: I have none. 21 CHAIR FOERSTER: Okay. Neither do I. Thank 22 you, Mr. Schwartz. 23 MR. SCHWARTZ: Okay. 24 CHAIR FOERSTER: All right. All right. Now 25 the Hilcorp people can get back in position and again 10 1 as you testify introduce yourself, you know, your name, 2 who you work for and if you want to be recognized as an 3 expert in an area what that area is and what your 4 qualifications are. 5 MARC BOND 6 previously sworn, called as a witness on behalf of 7 Hilcorp Alaska, testified as follows on: 8 DIRECT EXAMINATION 9 MR. BOND: Thank you, Chair Foerster. We 10 appreciate very much the opportunity to appear before 11 you and state our case respecting conservation order 12 390. It's a rule that we think should be preserved 13 with perhaps some changes and we'll go through those 14 changes that we propose in a minute. 15 The Commission must determine whether it's 16 better to require the installation of packers on Milne 17 Point (indiscernible - simultaneous speech)..... 18 CHAIR FOERSTER: Do you want to be -- you don't 19 -- do you want to be an expert or..... 20 MR. BOND: No..... 21 CHAIR FOERSTER: Okay. 22 MR. BOND: .....I'm just the lawyer. 23 CHAIR FOERSTER: I'm sorry. Okay. Fair 24 enough. 25 MR. BOND: I'm not expert at anything. 11 1 COMMISSIONER SEAMOUNT: You shouldn't have 2 sworn him either. 3 CHAIR FOERSTER: Shouldn't have sworn him in 4 either. 5 MR. BOND: Mandating packers may seem to reduce 6 the risk of well events, but, in fact, as the testimony 7 of the witnesses today will demonstrate the 8 installation of packers on Milne Point ESP wells will 9 not prevent waste, increase the safety of operations or 10 ensure greater recovery of oil and gas, in fact, the 11 opposite is true. Milne Point has been operating under 12 the provisions of CO 390 for 18 years. In that time 13 over 75 wells have been completed with ESPs without 14 packers and there have been no well events related to 15 the absence of packers. 16 Today we will hear from those who operate the 17 field and manage the development of the reservoir. 18 They include Mark O'Malley, our Milne Point field 19 foreman, Keith Elliott and Anthony McConkey, reservoir 20 engineers working Milne Point, Paul Chan, operations 21 engineer working Milne Point and Wyatt Rivard, well 22 integrity engineer working North Slope assets. We will 23 also hear from two experts who have substantial 24 experience in the completion of ESP wells and their 25 operation. Dr. James Lea is the principal of 12 1 Production and Lift Technology and Jeff Dwiggins is the 2 principal of Dwiggins Consulting. Both of these 3 gentlemen have substantial training, knowledge and 4 experience working with artificial lift in general and 5 ESPs in particular. 6 The witnesses will tell you the following 7 points. Milne Point field is a highly faulted and 8 fractured field with four main oil and gas reservoirs. 9 Two of the producing reservoirs produce a substantial 10 amount of sand, particularly the Schrader Bluff 11 reservoir which produces a very fine, flour like sand. 12 The presence of a measurable and usable annulus in 13 Milne Point wells is critical and does two things. It 14 allows the operators to carefully observe and measure 15 well characteristics which enhance safe operations and 16 facilitate better production practices and it allows 17 critical operations to clear sand, remove scale and 18 prepare wells for workover operations. 19 The average life of an ESP at Milne Point is a 20 very respectable 2.7 years. The use of packers in ESP 21 completions substantially increases the complexity of 22 the system and the risk of failure with the ESP and 23 other components of the well. Packers also greatly 24 complicate the ability of the operator to properly 25 handle gas from a well. The use of the packers will 13 1 shorten the life of the ESPs requiring more frequent 2 well interventions. Well work with ESP packers has 3 materially greater risk than well work without the 4 packers. Shortened ESP life and more frequent well 5 interventions will increase risk, reduce reserves, 6 lessen ultimate recovery and shorten field life. 7 Hilcorp is effectively managing the reservoir pressure 8 through waterflood injection and production rates. 9 Hilcorp has also prepared the standard well design 10 which facilities both monitoring and operating through 11 a usable annulus. 12 We propose to amend CO 390 to state two rules 13 as posted on the board there. Wells equipped with an 14 electronic -- electric submersible pump, ESP, and which 15 were constructed with both production casing and 16 surface casing may be completed with an ESP packer 17 assembly. Rule two, water supply wells equipped with 18 an ESP may be completed without an ESP packer assembly. 19 20 I'd like to introduce our first witness, Keith 21 Elliott. 22 KEITH ELLIOTT 23 previously sworn, called as a witness on behalf of 24 Hilcorp Alaska, testified as follows on: 25 DIRECT EXAMINATION 14 1 MR. ELLIOTT: Good morning. Thanks for having 2 us. As Mr. Bond said my name is Keith Elliott and I'm 3 happy to take some time and talk with you this morning. 4 My title is senior reservoir engineer. I am -- as a 5 reservoir engineer I'm expert at finding and 6 effectively developing oil and gas. That's my passion, 7 that's what I do. 8 CHAIR FOERSTER: And what are your -- you know, 9 what your experience, your education? 10 MR. ELLIOTT: I have worked with Hilcorp for 13 11 years now, I started with them in 2003. Prior to that 12 most of my experience was with west -- in west Texas 13 with Anadarko Petroleum Corporation. And my education, 14 I graduated with a bachelor's from Texas A&M and a 15 master's of science in petroleum engineering. The 16 bachelor's was in petroleum engineering as well. I'm 17 also a registered professional engineer in the state of 18 Texas. 19 CHAIR FOERSTER: Commissioner Seamount, do you 20 have any questions? 21 COMMISSIONER SEAMOUNT: I have no questions, no 22 objections. 23 CHAIR FOERSTER: Same here. All right. You 24 may proceed and we recognize you as an expert in 25 reservoir engineering. 15 1 MR. ELLIOTT: Thank you. The two general 2 themes to set the stage this morning, number 1, I will 3 update you on the reservoirs of interest at Milne Point 4 and an economic analysis where I analyze ESP field life 5 with respect to ultimate recovery. 6 So first let me step through our productive 7 formations in order of the cumulative production. The 8 Kuparuk River formation has produced nearly a quarter 9 of a billion barrels of oil from around 7,000 feet. We 10 actively waterflood, these are depletion dry fields, 11 there is no natural water influx or pressure squirt 12 therefore pressure decreases over time. We 13 significantly increase ultimate recovery by 14 waterflooding which displaces oil to productive wells. 15 I will show you that on the next slide. The Kuparuk -- 16 there are 75 active production wells, 62 of these 17 produce the ESPs we call them, electrical submersible 18 pumps. And it is important to know that the sand -- 19 the formation produces sand. 20 The Schrader Bluff reservoir has produced 21 around 73 million barrels of oil from around 4,000 feet 22 deep. As well we actively waterflood and it does 23 produce sand in particular what we call flour sand, the 24 field folks call flour sand, it's very -- it's like the 25 flour you use in baking, it's a very fine sand. That 16 1 can be challenging, but we have mitigated, you know, 2 challenge to reasonably produce the wells via 3 electrical submersible pumps. Sixteen of the 32 active 4 wells in Schrader produce via ESPs. 5 And the Sag and the Ugnu really are yet to be 6 thoroughly developed in the field. 7 As I move on let me highlight pressure 8 management to answer your question. So number 1, it's 9 important to note, you know, our goal is to diligently 10 manage pressure, we diligently manage pressure in the 11 field, it is a waterflood and we have the ability to 12 manage pressure. In part we submit to you an annual 13 waterflood surveillance report, I have a copy in my 14 hand and you have a copy in your records, from the 15 report that we submitted to you on July 1st. In the 16 Kuparuk River field the average reservoir pressure is 17 3,395 psi, that's the average of the pressures that we 18 obtained in the prior year which is with respect to the 19 initial pressure slightly less. The initial pressure 20 was around 3,500 psi. 21 In addition to pressure we also speak about 22 what I like to call injection withdrawal ratios. 23 Synonym for it is volumetric replacement ratio. It's 24 very simple math, simply the volume injected divided by 25 the volume produced. A number that is greater than one 17 1 indicates you're jamming more in the reservoir than 2 you're taking out and you may be increasing reservoir 3 pressure. A number less than one indicates that you're 4 decreasing pressure. So by design we are decreasing 5 pressure in Kuparuk River formations. You can look at 6 this ratio in terms of cumulative numbers from the 7 inception of the waterflood to now and also 8 instantaneous chunks. On a cumulative basis that 9 number's .9 so we've slightly decreased pressure. Last 10 year it was also .9, taking last year's volumes 11 Our target reservoir pressure is .465 psi. We 12 have a target and we're working toward it. And as you 13 can see .9 indicates the fact that we are still 14 managing the pressure down. 15 CHAIR FOERSTER: So why are you working towards 16 a .465 gradient? 17 MR. ELLIOTT: Quite simply .465 psi is about a 18 seawater gradient and it makes workovers efficient if 19 we can readily kill the wells with seawater. Plus in 20 terms of ultimate recovery we like -- you know, more is 21 good oftentimes in terms of delta P, delta pressure. 22 We like high pressure injection wells, low pressure 23 production wells and the more delta pressure you have 24 the more fluids you can produce. So we like high, but 25 we don't like the pressure too high to inhibit safe and 18 1 efficient operations. So it's about a maximum high 2 safe number that's efficient. 3 In the Schrader Bluff the average of the 4 pressures that we obtained last year was 1,736 psi. 5 And that compares to 1,800 psi initial reservoir 6 pressure. we've -- the pressure has dropped since 7 inception of the waterflood and correlatively the 8 injection withdrawal ratio on a cumulate basis is .9. 9 Last year we did inject more than we produced because 10 we are managing pressure up of -- our target is .465 11 psi per foot and the current reservoir pressure's .43. 12 Let me move on to an economic analysis that I 13 performed. The general theme is we drive hard to 14 increase ESP run life. It is expensive to fix broken 15 ones and as we drive to enhance ultimate recovery we do 16 our best to extend the run life of the wells so that 17 they don't break as often. And as Mr. Bond noted the 18 current run life of our ESPs is 2.7 years. The plot 19 that we're looking at shows the average ESP run life in 20 years on the X axis and on the Y axis are economic 21 limit in terms of barrels of oil per day. Economic 22 limit is the rate at which -- the minimum rate at which 23 we won't fix a well if it breaks. 24 CHAIR FOERSTER: To what degree is that oil 25 price dependent? 19 0 0 1 MR. ELLIOTT: It is very dependent on oil 2 price. 3 CHAIR FOERSTER: Okay. So what oil price did 4 you use in that analysis? 5 MR. ELLIOTT: This analysis uses $50 per 6 barrel. 7 CHAIR FOERSTER: Okay. All right. Sorry for 8 the interruption. 9 MR. ELLIOTT: Again the economic limit is the 10 rate at which if a well breaks we will not make enough 11 money to fix it and we won't operate if we lose money. 12 And right now the economic limit is 95 barrels a day. 13 So the star on this graph shows that at an average life 14 of 2.7 years the economic limit is 95 barrels of oil a 15 day. A concern that we have when running packers in 16 the ESPs is that we may degrade run life and increase 17 the cost of workovers and therefore hinder the economic 18 limit. When it comes to economic limit big numbers are 19 bad. If we increase cost and decrease run life I 20 expect that we could say worsen the economic limit to 21 145 barrels a day. On the flip side we drive hard to 22 improve this number every day, you know, in our -- in 23 our drive for constant improvement. well, let me show 24 you again if economic limit -- ESP life degrades and 25 economic limit worsens we show you, you know, what that Iff 1 does. 2 On my next plot titled well production rate 3 review I show in green triangles individual well rates 4 versus production well count. These are ordered by 5 best wells on the right side of the graph to the worst 6 wells. There are about 108 active producing wells. 7 The dark green lines shows the cum production including 8 all the wells. We produce around 19,500 barrels a day. 9 If the economic limit is 145 barrels of oil a day on 10 the plot we will see that my arrow points to wells -- 11 the wells that produce 145 barrels a day and then to 12 the right are those that produce less than 145 barrels 13 a day. There are 43 wells out of the 108 that produce 14 less than 145 barrels of oil a day, those 43 wells 15 produce 3,500 barrels of oil a day. And to be sure not 16 all of those are ESPs, 72 percent of the wells in the 17 field produce via ESPs. And we will continue that 18 ratio because that's the infrastructure that exists. 19 But of the wells that are lower, a lesser rate than 145 20 barrels of oil a day, 30 of those produce via ESPs and 21 they produce 2,700 barrels of oil a day. 22 CHAIR FOERSTER: And how many total wells are 23 below 145? 24 MR. ELLIOTT: Forty-three wells produce less 25 than 145 barrels of oil. 21 C� 1 CHAIR FOERSTER: So 30 of the 43 are ESP? 2 MR. ELLIOTT: Correct. Correct. 3 CHAIR FOERSTER: Okay. 4 MR. ELLIOTT: And what I want to highlight here 5 is certainly my craft if effectively finding and 6 developing oil and gas fields. And in particular I 7 tend to take fields to grave, we buy old, higher fields 8 and we produce them to the end. And the general theme 9 is we drive costs down while efficiently and safely 10 producing to extend field life. And it would be a huge 11 hit for us if we degraded economic limit and it would 12 hinder economic life. 13 And let me relate this to ultimate recovery. 14 Here I show on my recovery efficiency slide average ESP 15 life versus variants in recovery efficiency. Currently 16 at our 2.7 year average run life we have our baseline 17 recovery efficiency. To date the Kuparuk River 18 formation has produced around 25 percent recovery 19 efficiency, about 900 billion barrels in place, we've 20 recovered around 250 million barrels. The Schrader 21 less so, about 7 percent, 70 million out of about a 22 billion in place in the southern part of the field. So 23 each percentage point matters, we claw back and drive 24 to increase recovery 1 percent at a time. And using 25 the same set of assumptions if ESP run life degrades to 22 1 1.7 years and workover costs increase by 33 percent 2 then we think it's reasonable that ultimate recovery 3 efficiency may degrade about 1 percent. And 1 percent 4 is about -- again if you have a billion barrels in 5 place, 1 percent is around 10 million barrels. We 6 produce around 7 million barrels per year and we are 7 certainly in the Kuparuk very mature and really at a 8 point where these numbers are real and prevalent. And 9 each year that we improve rates, lower costs, we are 10 bolting on another percentage point at a time. 11 So again this is significant and real to us and 12 we are very interested in improving ultimate recovery 13 which translates into improving rate (indiscernible). 14 And that is all I have. 15 CHAIR FOERSTER: All right. Do you have any 16 questions for Mr. Elliott at this time, Commissioner? 17 COMMISSIONER SEAMOUNT: Yes, I do. Thank you 18 Mr. Elliott. I'm looking at rule two, you talk about 19 water supply wells, how many water supply wells do you 20 have? 21 MR. ELLIOTT: We have about five or six or 22 seven. 23 COMMISSIONER SEAMOUNT: And what's the source 24 of the water? 25 MR. ELLIOTT: The Prince Creek formation is 23 0 1 what we call it, it's an Ugnu -- generally an Ugnu 2 formation that is water bearing. 3 COMMISSIONER SEAMOUNT: What's the salinity of 4 the water? 5 MR. ELLIOTT: It's very fresh, most of it is -- 6 some of it's down to 3,000 parts per million total 7 dissolved solids. 8 COMMISSIONER SEAMOUNT: And can these water 9 supply wells flow on their own? 10 MR. ELLIOTT: Not at substantial rates. WE 11 have produced them via artificial lift to obtain the 12 rates that we need. And I don't recall us attempting 13 empirically to produce it on their own so I don't know. 14 But they -- you know, given that we -- I do know we 15 produce MVR artificial lift to get the substantial 16 rates that we need. 17 COMMISSIONER SEAMOUNT: Okay. Is the Kuparuk 18 formation the only formation that can flow on its own? 19 MR. ELLIOTT: Well, any formation can flow on 20 its own if the pressure in the reservoir..... 21 COMMISSIONER SEAMOUNT: Right. But here is -- 22 I mean, it seems like the other formations are pretty 23 low pressure. Do you have any knowledge of any of 24 those other formations flowing or having..... 25 MR. ELLIOTT: Not at..... 24 1 COMMISSIONER SEAMOUNT: .....the ability to 2 flow as Mr. Schwartz was talking about, he was 3 saying..... 4 MR. ELLIOTT: Yes. 5 COMMISSIONER SEAMOUNT: .....surface pressures 6 of 1,000? 7 MR. ELLIOTT: I understand. Yes, there are -- 8 and this is -- this is an empirical business, we do 9 things and we observe, we inject water and we observe 10 how the pressure changes. The geology of the field is 11 such that you may describe it as a shattered pain of 12 glass. There are individual we call them hydraulic 13 units with fault blocks. And if we inject too much we 14 can increase the pressure to a point where the wells 15 may flow on their own. And in the case as Mr. Schwartz 16 recommends I can think of a specific well, the Framen 5 17 (ph), where the pressure has become too high. And we 18 are managing it by producing the well and not injecting 19 in the hydraulic unit. So we are managing the pressure 20 back down. 21 CHAIR FOERSTER: What reservoir is that well 22 in? 23 MR. ELLIOTT: In the Kuparuk. 24 CHAIR FOERSTER: Okay. I think..... 25 MR. ELLIOTT: In the Schr..... 25 0 1 CHAIR FOERSTER: .....Commissioner Seamount was 2 asking more about the other reservoir. 3 MR. ELLIOTT: .....the Schrader. The Schrader 4 I can't -- I don't know offhand of wells or hydraulic 5 units that would flow on their own. 6 COMMISSIONER SEAMOUNT: Do you have -- does 7 Hilcorp have plans to expand the pool..... 8 MR. ELLIOTT: We do. 9 COMMISSIONER SEAMOUNT: .....into other areas? 10 MR. ELLIOTT: Well, I -- we have plans to 11 drill..... 12 COMMISSIONER SEAMOUNT: I mean, are you moving 13 out from what's producing now? 14 MR. ELLIOTT: Yes, sir. 15 COMMISSIONER SEAMOUNT: Okay. Now you talk 16 about a decrease in pressure in the Kuparuk, is it 17 possible that pressure will decrease to the point where 18 it won't have the ability to flow? 19 MR. ELLIOTT: It certainly is possible, 20 correct. 21 CHAIR FOERSTER: Is it part of your plan for 22 that to happen? 23 MR. ELLIOTT: Well, our plan is to target .465 24 psi per foot. If the -- at a high watercut it's 25 unlikely that the wells will flow at significant rates. 1 There are no producing wells that flow at commercial 2 rates without artificial lift. They may flow to a tank 3 at atmospheric pressure at a -- literally a trickle we 4 call it, very low rates. 5 COMMISSIONER SEAMOUNT: On a typical well how 6 often do you replace ESPs before you declare the well 7 uneconomic, I mean, you talk about 2.7 years now, how 8 long does a well live, I guess? 9 MR. ELLIOTT: Sure. Well, the Kuparuk was 10 originally built in the mid 180s, it's been 30 years. 11 We certainly expect another decade or two so it could 12 be reasonably 50 years of productive life for these 13 wells. And therefore..... 14 COMMISSIONER SEAMOUNT: Fifty divided..... 15 MR. ELLIOTT: .....20..... 16 COMMISSIONER SEAMOUNT: .....by 2.7? 17 MR. ELLIOTT: Right. 18 CHAIR FOERSTER: Have they had an ESP since day 19 one though? 20 MR. ELLIOTT: I know in the mid 190s when BP 21 aggressively began the development on the field they 22 initially installed ESPs. 23 CHAIR FOERSTER: So it hasn't been 50 years 24 since, it's been..... 25 MR. ELLIOTT: The..... 27 1 CHAIR FOERSTER: .....25? 2 MR. ELLIOTT: .....original pad, Baker pad, is 3 a gas lifted pad. 4 COMMISSIONER SEAMOUNT: So did you say that 5 using packers reduces the life of the ESPs? 6 MR. ELLIOTT: That -- I didn't -- I don't know 7 if I said it, but we will tell you that, my..... 8 COMMISSIONER SEAMOUNT: Okay. 9 MR. ELLIOTT: .....partners here will tell..... 10 COMMISSIONER SEAMOUNT: So I'll wait on that 11 question. 12 MR. ELLIOTT: Sounds good. 13 COMMISSIONER SEAMOUNT: Okay. I'm done. 14 CHAIR FOERSTER: So Commissioner Seamount asked 15 you some questions about will the wells flow naturally 16 and you haven't given them the opportunity to, but as 17 an engineer you have tools at your disposal that you 18 could use to predict whether or not the wells could 19 flow. 20 MR. ELLIOTT: Correct. In flow performance 21 (indiscernible)..... 22 CHAIR FOERSTER: And could -- so could you -- 23 we'll leave the record open and you can provide Mr. 24 Seamount with the answer to his question based on 25 predictive tools. 28 1 MR. ELLIOTT: I can do that. 2 CHAIR FOERSTER: Thank you. All right. Remind 3 me, we'll leave the record open for 10 days. 4 All right. I'll save my questions for later. 5 MR. ELLIOTT: Okay. 6 CHAIR FOERSTER: And, Mr. Bond..... 7 MR. BOND: Yes. 8 CHAIR FOERSTER: .....I assume you're kind of 9 the..... 10 COMMISSIONER SEAMOUNT: MC. 11 CHAIR FOERSTER: .....MC of this show so would 12 you please keep a record of all the questions that we 13 are leaving the record open for an answer on so that we 14 get that answer? 15 MR. BOND: Yes, of course. 16 CHAIR FOERSTER: And at the end of the -- at 17 the end of the hearing we'll determine based on the 18 complexity of those questions how much time you need 19 the record left open. All right. 20 COMMISSIONER SEAMOUNT: I'd also like to know 21 what the exact salinity of the water supply water is. 22 MR. ELLIOTT: I can provide it. 23 COMMISSIONER SEAMOUNT: Oh. 24 MR. ELLIOTT: I..... 25 COMMISSIONER SEAMOUNT: I heard a long time ago 29 1 that they're using it as drinking water, but I don't 2 know if that's true or not. 3 MR. ELLIOTT: In 3,000 tds is very fresh. 4 COMMISSIONER SEAMOUNT: Oh, 3,000. 5 MR. ELLIOTT: Common oil field is well, 6 potentially 60,000 in some of the field I've worked in 7 so it is very fresh. 8 CHAIR FOERSTER: Okay. Is that a satisfactory 9 answer? 10 COMMISSIONER SEAMOUNT: That's satisfactory. 11 CHAIR FOERSTER: Okay. All right. You'll 12 remain under oath and we may bring you back up for 13 questions at, you know..... 14 MR. ELLIOTT: Okay. 15 CHAIR FOERSTER: .....at a later time during 16 the hearing. 17 MR. ELLIOTT: Okay. 18 MARK O'MALLEY 19 previously sworn, called as a witness on behalf of 20 Hilcorp Alaska, testified as follows on: 21 DIRECT EXAMINATION 22 MR. O'MALLEY: Morning. My name is Mark 23 O'Malley, I've -- I'm a -- currently I'm a field 24 foreman for Hilcorp at the Milne Point field. My 25 history, I've been on the Slope since -- well, 35 30 1 years. I've been at Milne for 20 since BP acquired it 2 right -- right afterwards from Conoco. That's -- hard 3 knocks is my history as far as knowledge. I don't know 4 if I'm expert at much of anything other than keeping 5 wells flowing. 6 So I was asked to put together how we utilize 7 the annuluses of the current..... g COMMISSIONER SEAMOUNT: Do you wish to be an 9 expert, Mr. O'Malley? 10 MR. O'MALLEY: Do I wish to be an expert, maybe 11 some day. 12 CHAIR FOERSTER: Do you wish to be recognized 13 as one? 14 MR. O'MALLEY: No. 15 CHAIR FOERSTER: Okay. 16 COMMISSIONER SEAMOUNT: Okay. Not an expert in 17 hard knocks or anything? lg MR. O'MALLEY: Oh, well, yeah, possibly. 19 CHAIR FOERSTER: You got all 10 fingers so..... 20 COMMISSIONER SEAMOUNT: Or a field foreman? 21 MR. O'MALLEY: Field foreman, yes. So I was 22 asked to put together a list of tools of how we utilize 23 the open annuluses, our current completions on our 24 ESPs. One of the major pieces is fluid level shots. 25 We use this for -- to confirm -- we have surface 31 1 readouts, our -- all our ESPs have bottom hole sensors 2 that tell us what the bottom hole pressure is. So 3 whenever there's a doubt in that pressure reading we 4 use fluid level shots to confirm that. We also -- 5 there are times when we lose that sensor, the well is 6 still valuable to us, it hasn't died yet, usually an 7 indication that it's on its way, but we can still flow 8 the well without a bottom hole sensor as long as we can 9 monitor the bottom hole..... 10 CHAIR FOERSTER: Mr. O'Malley, let..... 11 MR. O'MALLEY: .....pressure. 12 CHAIR FOERSTER: .....me interrupt just a 13 second. You're speaking to..... 14 MR. O'MALLEY: I'm sorry, the first slide..... 15 CHAIR FOERSTER: .....you're speaking to some 16 exhibits that..... 17 MR. O'MALLEY: .....first point on the first 18 slide. 19 CHAIR FOERSTER: And the first slide is titled 20 required annular operations..... 21 MR. O'MALLEY: Required annular operations. 22 CHAIR FOERSTER: .....to maximize ESP run life 23 and ultimate recovery. 24 MR. O'MALLEY: Yes, I'm sorry. 25 CHAIR FOERSTER: And the whole -- the whole 32 1 series of slides has got that title. 2 MR. O'MALLEY: That's the same title. 3 CHAIR FOERSTER: So you'll just be speaking to 4 bullet points on a handout with that title so you don't 5 need to say anymore about -- to identify it. 6 MR. O'MALLEY: Okay. Thank you. The second 7 tool we use our fluid level shots for is to monitor our 8 bottom hole pressure prior to a rig workover. We 9 normally go in with a slick line and get a bottom hole 10 pressure prior to the workover, but normally there's a it few days or a week prior to the rig showing up so to 12 confirm that bottom hole is maintaining at that 13 pressure we -- we'll continue to shoot fluid levels to 14 verify it. And this --and the third is very useful, we 15 have -- we create our own power there at Milne Point so 16 from time to time we'll have power outages especially 17 during the winter or prorations for Alyeska so we have 18 to shut some of these wells in and we go around and we 19 shoot fluid levels to determine if the level in the 20 well is below the permafrost and if it is then we do 21 not need to freeze protect that well. So it helps us 22 prioritize our well freeze protection. 23 CHAIR FOERSTER: So, Mr. O'Malley, all these 24 wells you're talking about, you..... 25 MR. O'MALLEY: These are all ESPs, open 33 1 annulus. 2 CHAIR FOERSTER: Right. You shut them in and 3 they achieve a fluid level, this means they don't flow 4 to surface..... 5 MR. O'MALLEY: Right. 6 CHAIR FOERSTER: .....correct? Okay. 7 MR. O'MALLEY: Right. Yeah. And then there's 8 another tool, moving down to the fourth point on this 9 slide, this is one of the most commonly used open 10 annuluses techniques. We use -- we call it a back side 11 flush. There's numerous reasons why we do it and I 12 have -- I've pointed out here, but one of the main 13 reasons is with the surface readouts we can determine 14 if the ESP is struggling, the amperage spikes, things 15 like that. Through our experience we know we -- it's 16 digesting solids so when we see that prior to the well 17 shutting down because eventually if it continues to 18 receive solids into the tubulars it will shut down or 19 lock up. So prior to that we'll go out with a pump 20 truck and we'll pump down the back side with a volume 21 of dead crude and what that does is help flush whatever 22 the pump is digesting, it helps flush the sand through 23 the pump, up and out of the tubing. So it helps. Can 24 we move to the next slide. 25 We also -- there's also wells -- the back sides 34 1 with an open annulus they work like a separator so 2 you'll get a layer of fluids above your intake of your 3 ESP and then your gas migrates out above that. And in 4 our current completions we have a gas lift mandrel 5 about 130 feet that works as a check so anytime your 6 pressure is higher on your annulus to your tubing the 7 check opens up and allows the gas to migrate in -- back 8 into the flow stream and then up, out of the well below 9 the -- below the wellhead. So we have numerous wells 10 that over time that layer above the ESP becomes 11 contaminated with emulsions and other products from the 12 well. So once again we see that well struggling from 13 the surface, either from production of the well itself 14 or the -- how the pump is reacting. So what -- we'll 15 do the same technique, we put a volume of dead crude 16 down the back side which pushes that layer or emulsions 17 through the pump and gives us a fresh dead crude buffer 18 above the intake. we also with that gas lift mandrel 19 at 130 feet we've had times where hydrates have plugged 20 that check valve off. So how we determine that is we 21 see an increase in our in our annular pressure during 22 our normal daily readings, the efficiency of the pump 23 drops off. So what we'll do in the same -- once again 24 all these are pumping dead crude -- warm dead crude 25 down the back side. And in this case what it does is 35 1 it'll follow the hydrates out and allow the gas to 2 migrate through the mandrel again. Same case in some 3 of our Schrader wells since they're -- they flow so 4 slow and cold that the well will actually develop a -- 5 what we call a slush plug. It's not actually a full 6 ice plug we've had. So by putting warm fluids down the 7 back side we were able to thaw that and bring the well 8 back. 9 On treatments on the third -- fourth point down 10 for treatments we actually -- same scenario, but we use 11 acid. Our pumps will show us indications that it's 12 scaling up, bottom hole increases, the pump is working 13 harder so we do what we call these small, little volume 14 acid jobs to get rid of the scale. And from time to 15 time because of the -- some of the pumps, even they're 16 brand new, our rates -- they -- our rates are so low on 17 some of these pumps, they have to size the pump for 18 what the well will give us and the size of the pump 19 determines what the rate you can pump down through the 20 pump is. So in most cases our pumps at our best rate 21 is less than half a barrel a minute. So it's not very 22 effective to pump that slow in a lot of these cases. 23 So we'll -- that's where we bullhead down the back side 24 with these acids. Go on to the next one. 25 And then to eliminate the scaling we have these IM 1 formation squeeze jobs that we use -- we put inhibitors 2 down into the formation in large volumes and then over 3 time it trickles back and it protects our pumps for a 4 longer life. And we have recently in our newer 5 Schrader wells we've drilled them with long lateral -- 6 lateral valves instead of traditional vertical wells. 7 And in some cases the laterals have filled up with sand 8 and what we try to do is these full-blown, large volume 9 flushes. Theoretically it pushes the solids back into 10 the laterals and allows production. And in most cases 11 we see an increase in production after we do these type 12 of jobs. And then of course there's an integrity 13 monitor from inner to out annuluses, we can see. But 14 with all my experience there I believe all these 15 interventions that we're currently using the annulus 16 for has contributed to our extended ESP life. 17 That's about it. 18 CHAIR FOERSTER: Thank you, Mr. O'Malley. Do 19 you have any questions? 20 COMMISSIONER SEAMOUNT: Yeah, I'd like to get 21 something straight. You -- when you flush the well you 22 say you run the fluids down the back side..... 23 MR. O'MALLEY: Uh-huh. 24 COMMISSIONER SEAMOUNT: .....and it comes -- 25 goes through the pump and up the tube? 37 1 MR. O'MALLEY: Tubing. 2 COMMISSIONER SEAMOUNT: Tubing. Okay. I've 3 got an electrical subsurface pump in my pond in my yard 4 and I flush it the opposite way..... 5 MR. O'MALLEY: Oh. 6 COMMISSIONER SEAMOUNT: .....through the tubing 7 -- through the hose and then out. But my pumps don't 8 last 2.7 years. 9 MR. O'MALLEY: Yeah, the -- and I pointed out 10 earlier that the -- the smaller veins in the pump allow 11 a certain volume to go through and out pumps are so 12 small that in some cases we need to do one, two, three 13 barrels a minute and we can't get that through the pump 14 itself. It will physically restrict us from getting 15 that type of rate through the pump itself. 16 COMMISSIONER SEAMOUNT: Is that a real pump 17 there? 18 MR. O'MALLEY: This is a portion of a pump, 19 yes. 20 COMMISSIONER SEAMOUNT: Must be pretty 21 powerful? 22 MR. O'MALLEY: There's -- this is a different 23 stage -- this is a stage of a ESP pump. And all the -- 24 the engineers have determined what the well is capable 25 of and then they determine how many of these stages 38 1 they put in the pump itself. And the scale is -- it 2 gets inside these little holes here so that's what 3 restricts the flow. So when we pump the acid job it 4 eats this away and gives us free paths again. So 5 that's what the acid does. 6 COMMISSIONER SEAMOUNT: Hmmm. 7 MR. O'MALLEY: I'm sure the ESP experts will go 8 further into details on that. 9 COMMISSIONER SEAMOUNT: That's all I have. 10 CHAIR FOERSTER: Well, first, Mr. O'Malley, I'm 11 sure that Hilcorp recognizes and appreciates that you 12 have lots of expertise that keeps the field alive and 13 producing for them every single day. So don't let the 14 expert/nonexpert stuff that we do diminish your 15 importance, your value, your intelligence and your 16 contribution because it shouldn't. 17 Based on your work checking fluid levels can 18 you help maybe with Mr. Seamount's question, what wells 19 do you see that are capable of flow. When you go out 20 to check the fluid levels what, you know, characterize 21 the number and type of wells that have fluid to surface 22 when you shut them in or do you not shut those wells 23 in? 24 MR. O'MALLEY: Well, as was mentioned before 25 they -- they won't flow into our flow lines on any type 39 1 of pressure. If you open it up to the surface..... 2 CHAIR FOERSTER: Even the Kuparuk wells? 3 MR. O'MALLEY: I'm sorry. 4 CHAIR FOERSTER: Even the Kuparuk wells? 5 MR. O'MALLEY: Even the Kuparuk wells. Now 6 there -- there may be a few that will, but very often 7 not, they will not. And that's typically about 180 8 pounds is what our header pressures run, maybe a little 9 higher out at F pad because it's further out away from 10 the facility. But, no, I would suspect over -- if you 11 would open it up to the surface into a tank there may 12 be some residual flow for a short period of time before 13 -- and actually the watercut in the well will really 14 determine if heavier (indiscernible - away from 15 microphone). 16 And to answer your question on our source water 17 wells I do not believe that they would flow to surface. 18 We currently have them freeze protected to a certain -- 19 2,500, 3,000 feet with diesel and there's zero pressure 20 on the annulus (indiscernible - away from microphone) 21 and that's what the lighter color of fluid (ph). 22 CHAIR FOERSTER: How about if the tree were 23 damaged with -- and then the wells were open to -- the 24 annulus was open to the atmosphere, would -- how many 25 of your wells would flow in that situation? .O 1 MR. O'MALLEY: I believe Kuparuk would be 2 more..... 3 CHAIR FOERSTER: Kuparuk wells would. 4 MR. O'MALLEY: .....to do that. I think the 5 Schrader would basically kill themselves I guess is 6 (indiscernible - away from microphone)..... 7 CHAIR FOERSTER: Okay. All right. That's not 8 a surprise and that's -- I think that's the 9 characterization you were expecting to hear, but we to still want to get Mr. Elliott's answer and we'll leave 11 the record open for that. 12 I don't have any other questions for you at 13 this time, but..... 14 MR. O'MALLEY: Okay. 15 CHAIR FOERSTER: .....please stick around 16 because we may have questions for you later. 17 MR. O'MALLEY: Okay. Thank you very much. 18 CHAIR FOERSTER: Thank you. 19 MR. BOND: Our next witness is (indiscernible - 20 away from microphone)..... 21 ANTHONY MCCONKEY 22 previously sworn, called as a witness on behalf of 23 Hilcorp Alaska, testified as follows on: 24 DIRECT EXAMINATION 25 MR. McCONKEY: My name is Anthony McConkey. 41 1 I'm a reservoir engineer for Hilcorp. I graduated from 2 UAF with a bachelor's of science in petroleum 3 engineering. I was hired on by BP after college, this 4 was in 2011, I worked as a production engineer. I 5 started off in Prudhoe Bay as a production engineer, I 6 then worked on the Slope for six months. Part of their 7 training program is to learn about rig workovers, coil 8 tubing intervention work. And about March, 2013 came 9 back, started working on the Milne Point team again as 10 a production engineer. And as a production engineer 11 really your job was to fix broken wells and to make 12 wells that are working even better, I mean, it was -- 13 it was really to get base production up. Arid so 14 developed a lot of skills in that in the two years I 15 was there. I started working Baker, Echo and Charley 16 pads which was mainly Kuparuk and then around the time 17 when it was announced that Hilcorp was purchasing Milne 18 Point I started working the Schrader Bluff reservoir so 19 mainly track 14 and S pad. Worked that for about eight 20 months and then of course after moving to Hilcorp as a 21 reservoir engineer I'm now working the whole field, 22 both Kuparuk and Schrader. And my -- for the most part 23 my responsibilities haven't changed, I still work very 24 closely with rig workovers and coil tubing jobs and 25 just ensuring that we keep the wells going at peak 42 1 optimization and peak performance. 2 CHAIR FOERSTER: So do you want to be 3 recognized as an expert in production engineering? 4 MR. McCONKEY: Yes. 5 CHAIR FOERSTER: Okay. Do you have any 6 questions, Mr. Seamount? 7 COMMISSIONER SEAMOUNT: Do you also want to be 8 recognized as a reservoir engineer expert? 9 MR. McCONKEY: Yes. 10 COMMISSIONER SEAMOUNT: So we'd say petroleum 11 engineer. 12 CHAIR FOERSTER: Petroleum engineer. 13 MR. McCONKEY: Petroleum engineer. 14 COMMISSIONER SEAMOUNT: I have no questions, no 15 objections. 16 CHAIR FOERSTER: Okay. Did you -- are you an 17 Alaskan? 18 MR. McCONKEY: Yes, I am, born and raised. 19 CHAIR FOERSTER: Where'd you grow up? 20 MR. McCONKEY: Here in Anchorage. 21 CHAIR FOERSTER: What school -- what high 22 school did you go to? 23 MR. McCONKEY: I went to Service my first few 24 years and then I went to South the first year. 25 CHAIR FOERSTER: Okay. All right. I have no 43 1 other questions and I have no problems accepting you as 2 an expert. So you may proceed with your testimony. 3 And if you refer to exhibits please give them context 4 for the future. 5 MR. McCONKEY: Right. So what I'm actually 6 going to do is, you know, Mark brought up a lot of good 7 points and I want to just really emphasize a couple of 8 those and some of the things that I've witnessed from 9 Milne Point. So I'm actually going to go back to his 10 slides which is required annular operations to maximize 11 ESP run life and ultimate recovery. And what I really 12 want to talk about is the sand production issues that 13 we have at Milne Point and how having packers would 14 really inhibit ESP wells because of sand production. 15 So as Keith mentioned we produce flour sand in 16 the Schrader Bluff reservoir particularly and we do 17 also produce some sand in the Kuparuk although not as 18 fine. With this flour sand you cannot put screens in 19 the well to prevent the sand because if you do the sand 20 is so fine it will literally pack off the screens. So 21 we've kind of learned to live with it. Each of these 22 wells could produce maybe about .1 so a tenth of a 23 percent of sand. And if you -- I don't know if you 24 know, but our sales -- the sales oil that we take out 25 the back it can have no more than .25 percent. So as 44 1 long as we're in that kind of .1, .2 percent solids 2 range we're okay. However if you have say a 500,000 3 barrel a day well and it's making .1 percent solids 4 that's a barrel of sand every other day so it's 5 significant. And what we found and this happens time 6 and time again that our stages, and using the 7 tolerances in these stages and diffusers, they fill up 8 with sand as well as the tubing will actually fill up 9 with sand because the energy from the flow isn't enough 10 to actually carry the solids all the way to surface. 11 So they kind of sit in suspension in the tubing. Now 12 what happens is when you shut in this well, anytime you 13 have to shut in a well, all of the sand drops on top of 14 that pump and then you try to start it again and those 15 first few stages lock up. And you cannot pump down it 16 to try to wash the solids out because what happens is 17 you compact the solids and you literally make 18 practically a cement on top of the pump. So I just 19 wanted to reemphasize how important these back side 20 flushes are to pump the fluid down the back side and 21 get it up because then we can wash out all the sand not 22 only out of the pumps, but out of the tubing itself. 23 Another part where these back side flushes help 24 is sometimes ESPs will actually build a bridge outside 25 the ESP pump. So between the ESP and the casing you'll 45 1 get a bridge where you'll actually block off your 2 intake ports from the formation. And so suddenly you 3 start creating a vacuum inside that little pocket. And 4 so a lot of times we can -- if we can pump a high 5 enough rate we can actually push that bridge down and 6 knock out that bridge and then reopen the ESP back to 7 the formation. And so that can actually be a safety 8 critical issue if you have a bridge blocking your 9 intake ports during a rig workover operation. 10 With the Kuparuk reservoir in particular we get 11 a lot of scale issues, especially at F and L pad do to 12 the pvd properties we see a lot of scale. And a lot of 13 times the scale as Mark mentioned builds up in the 14 stages and just above the stages in the tubing. And 15 this is because scale is a function of temperature and 16 pressure and you have your largest pressure drop in the 17 stages and just above the pump. And so that's 18 typically where you see scale. If you get enough scale 19 build up again you -- it's dangerous to pump acid down 20 the tubing because you can break out the scale and you 21 can pack off the stages. So again with the really bad 22 scaling wells we like to pump down the back side and 23 push the scale up and out of the tubing and out of the 24 pumps. 25 And the last thing I really want to emphasize 46 1 is the fluid level shots and how important this is both 2 to safety, logistics and really every day operations. 3 The temperature and pressure gauge that we put in all 4 these ESPs, they're prone to failure. They fail fairly 5 often. Sometimes you get really good run lives, but 6 usually when an ESP is about to fail that's the first 7 thing to go. And sometimes the gauge will fail and the 8 ESP will go on forever. So we need to have a way to be 9 able to check the bottom hole pressure regularly, 10 preferably -- especially if it's prior to a rig 11 workover we want to see it on a daily basis to see what 12 pressure we're going to expect when we go in and repair 13 the well. So what we'll do is the first thing we do is 14 we run a stock bottom hole pressure survey and we 15 actually perform it at stops. So we'll take a stop at 16 say 4,000 tvd, at 3,900 tvd, 3,800, and what we're 17 doing is we're trying to find out what the gradient of 18 the fluid is. once we know the gradient because all 19 wells are going to be different, they're going to have 20 a different percentage of water, different percentage 21 of oil, different percentage of gas, and this is going 22 to affect what your bottom hole pressure is based upon 23 your fluid level. So once we know the gradient we can 24 then take fluid level shots and we can actually know 25 the bottom hole pressure to a pretty precise accuracy 47 1 having that access to the inner annulus. 2 And that was it in a nutshell, those were the 3 few things that I really wanted to pinpoint that I 4 found useful in the years that I've worked at Milne 5 Point and have been crucial to keeping production up 6 and safety. 7 CHAIR FOERSTER: Thank you. Mr. Seamount, do 8 you have any..... 9 COMMISSIONER SEAMOUNT: Yeah. Thank you, Mr. 10 McConkey. Are you -- are you saying that or are you 11 indicating that you couldn't do this with a packer in 12 the hole? 13 MR. McCONKEY: No. And the reason why is 14 because you have a -- you can -- you do have a vent 15 port from what I've learned. COMMISSIONER SEAMOUNT: 16 Okay. 17 MR. McCONKEY: I've never worked with packered 18 ESPs, but I have seen that you can have a vent port. 19 And the problem with those vent ports is you cannot get 20 enough rate down or enough pressure to either push a 21 bridge or to push solids through the pump and up the 22 tubing. At least from my understanding of what kind of 23 rate you can get through that vent. 24 COMMISSIONER SEAMOUNT: Sounds like somebody 25 could design something and patent it that would work .m 1 for you. 2 MR. McCONKEY: Well..... 3 CHAIR FOERSTER: I was thinking of that when we 4 were -- yeah. 5 COMMISSIONER SEAMOUNT: Now..... 6 CHAIR FOERSTER: I'm not going to do it. 7 COMMISSIONER SEAMOUNT: .....you're talking 8 about the flour sand and wells sanding up, how often 9 does a Kuparuk well sand up? 10 MR. McCONKEY: Kuparuk, they do not sand up as 11 often. Usually they will -- you will have problems 12 with sanding and it's -- I would say more often than 13 not it's frack sand that you see. A lot of times once 14 you frack a well you produce frack sand for years 15 after. And typically -- well, frack sand often are 16 what we are trying to push out of the well when that 17 does happen. There are times though when you do have 18 unconsolidated formations in the Kuparuk in certain 19 areas of the field and you will see sand production. 20 And usually on those we try to mitigate it by not 21 drawing down as hard as we possibly can so we'll raise 22 the (indiscernible) pressure a bit, but it's still -- 23 it's inevitable in some places. 24 COMMISSIONER SEAMOUNT: How big are the fracks? 25 MR. McCONKEY: So I don't know the -- we -- 49 1 we've pumped very few if any fracks since I joined 2 Milne Point in March of 2013, but as I can remember I 3 would say roughly anywhere from 20 to 50,000 pounds I 4 want to say. 5 COMMISSIONER SEAMOUNT: Okay. That's all I 6 have, Madam Chair. 7 CHAIR FOERSTER: Thank you. So how hard is it 8 to do a no flow test on these wells? 9 MR. McCONKEY: It's -- it's not very difficult. 10 I don't know the exact operation, but I would say you 11 could probably shut in the well at the well head and 12 then you just check the pressure at surface. And 13 typically with these you also want to wait, you know, a 14 certain amount of time for the reservoir to equalize 15 and give it a chance to -- for that transient period 16 to stabilize. 17 CHAIR FOERSTER: So has Hilcorp run no flow 18 tests on any of these wells? 19 MR. McCONKEY: You know, not that I'm aware of. 20 I'm normally not part of that particular operation so I 21 don't know if I can speak to that. 22 CHAIR FOERSTER: Okay. Is there somebody going 23 to come up who could answer that question. 24 MR. O'MALLEY: Well, I could answer that as 25 (indiscernible - away from microphone). 50 1 CHAIR FOERSTER: Okay. Come up to the 2 microphone, please. 3 MR. O'MALLEY: I could..... 4 CHAIR FOERSTER: And introduce yourself again 5 for the..... 6 MR. O'MALLEY: Oh, I'm sorry. 7 CHAIR FOERSTER: .....court reporter. 8 MR. O'MALLEY: Oh, I'm sorry, Mark O'Malley, 9 field foreman, Milne Point. As far as no flows, we've 10 only conducted probably a handful..... 11 CHAIR FOERSTER: Uh-huh. 12 MR. O'MALLEY: .....over the years that I've 13 been there. Our current one -- we just completed one 14 on Sierra 27. And that was due to the type of 15 completion that we ran in the hole and it -- it passed. 16 You know, I'm familiar with the criteria, I'm assuming 17 there's other -- there's gauges that you -- it's a 18 three hour test and determine how much gas, how much 19 fluid you're allowed for a certain amount of time. 20 CHAIR FOERSTER: So is that three hours per 21 well? 22 MR. O'MALLEY: Yes. 23 CHAIR FOERSTER: And..... 24 MR. O'MALLEY: There's a lot of preparation 25 prior to it like Anthony said as far as allowing the 51 1 well to stabilize, bleeding off the gas cap that 2 accumulates initially and then -- and then conducting 3 the test, getting ahold of the agency..... 4 CHAIR FOERSTER: Okay. 5 MR. O'MALLEY: .....to have it witnessed. 6 CHAIR FOERSTER: Okay. Thank you. I have no 7 further questions for you at this time, Mr. McConkey, 8 but please stick around and you remain under oath for 9 the duration of the hearing. 10 MR. BOND: Our next witness is Paul Chan. 11 PAUL CHAN 12 previously sworn, called as a witness on behalf of 13 Hilcorp Alaska, testified as follows on: 14 DIRECT EXAMINATION 15 MR. CHAN: These slides aren't going to really 16 be shown very clearly on the -- on the projector so I'd 17 like to..... 18 CHAIR FOERSTER: You need to..... 19 MR. CHAN: Oh. 20 CHAIR FOERSTER: .....introduce yourself..... 21 MR. CHAN: Yes. 22 CHAIR FOERSTER: .....for the record, who you 23 represent, do you want to be recognized as an expert, 24 what are your -- what kind of expertise do you have, 25 what are your qualifications, and then you can go to 52 1 that. 2 MR. CHAN: My name is Paul Chan, I'm a senior 3 operations engineer for Hilcorp Alaska. I have a 4 bachelor of science degree in petroleum engineering 5 from the Colorado School of Mines. I began my career 6 with Amoco Production Company in Casper, Wyoming. I 7 was a production engineer and a completion engineer for 8 an 1,800 well waterflooded field mostly (indiscernible) 9 units and that was my first introduction to ESPs. My 10 first introduction to ESPs was due to the fact that 11 some of the wells actually we cannot draw down the 12 fluid levels sufficiently so we started to install a 13 limited number of submersible pumps. In 1990 I joined 14 BP as a drilling engineer. I was a drilling engineer 15 for the Endicott field and the Prudhoe Bay field. I 16 drilled 32 -- I planned 32 wells for that. And then in 17 1994 I was the Schrader Bluff PE from -- in 1994 I 18 transferred over to the Milne Point unit and I was a 19 Schrader Bluff production engineer until 1997. And 20 during that time frame I designed all the completions 21 for the Schrader Bluff, all the gravel packs and frack 22 packs. And then in 1998 I went to the southern North 23 Sea and worked gas fields there as a production 24 engineer. In 2000 I joined -- became a consultant and 25 worked as a drilling engineer doing annular disposal 53 1 work for a North Slope operator and then from there I 2 transitioned to being a workover engineer in Prudhoe 3 Bay, Endicott field and Milne Point. And during that 4 time frame from 2002 to 2008 I did approximately a 5 hundred workovers and I've done approximately 30 to 40 6 ESP change outs. And then I was -- I went down to -- 7 had another international assignment, I was doing a 8 plug and abandonment for a Caspian Sea well in the -- 9 outside -- for (indiscernible). It was the -- another 10 major operator, it was one of their top 10 wells, it 11 needed to be -- needed to be P&A'd for well integrity 12 reasons. So I did that for a year and then I came back 13 to Alaska and I was a production engineer on the North 14 Slope and then I was a completion engineer for another 15 operator in the Beluga River unit doing sand control 16 and workovers before I joined Hilcorp as a senior 17 operations engineer. So I have approximately 25 years 18 of well work experience, intervention experience. 19 CHAIR FOERSTER: Commissioner Seamount, do you 20 have any questions? 21 COMMISSIONER SEAMOUNT: Yes. Mr. Chan, it's 22 been a number of years since I've seen you. In the 23 Caspian Sea what field was that? 24 MR. CHAN: Sudanese (ph). 25 COMMISSIONER SEAMOUNT: Okay. 54 1 MR. CHAN: 250 million a day gas field. 2 COMMISSIONER SEAMOUNT: And who did you work 3 for in Casper? 4 MR. CHAN: Amoco Production Company. 5 COMMISSIONER SEAMOUNT: Amoco. When was that? 6 MR. CHAN: 1988 to 1990. 7 COMMISSIONER SEAMOUNT: That's when I was 8 there. I have no objections and no more questions. 9 CHAIR FOERSTER: I don't have any questions and 10 I don't have any objections. So please proceed, Mr. 11 Chan, and remember to give your use of handouts 12 context. 13 MR. CHAN: So in your -- on the easel I have a 14 poster board titled Milne Point ESP life cycle. 15 CHAIR FOERSTER: And you guys brought us a hard 16 copy of that for the record? 17 MR. CHAN: Correct. 18 CHAIR FOERSTER: Thank you. 19 MR. CHAN: It's also up here, it's just..... 20 CHAIR FOERSTER: Okay. 21 MR. CHAN: .....the other slides are going to 22 be harder to see because of the -- because of the fact 23 that the other slides are much bigger. 24 CHAIR FOERSTER: Okay. 25 MR. CHAN: So on the -- on that one what we 55 1 have -- this is that one I'm trying to show on this -- 2 on this poster is that -- the ESP life cycle that we 3 have at Milne Point. we have the day to day operations 4 and what we're doing on that is just that we're going 5 to monitor the well, we're going to monitor the well, 6 we're going to monitor the flowing tubing pressure, 7 we're going to monitor the hertz, the amps, all the 8 other things that are critical to make sure that the 9 ESP or any well, whether it's on jet pump or gas lift, 10 is operating at its peak efficiency for that particular 11 well. Each well of course is unique and so each well 12 acts differently. So every day operators in the field 13 they will actually learn their wells and how they -- 14 and how they behave. 15 But if we have a problem with an ESP that's 16 where Mark O'Malley and his team come in and they start 17 to do the troubleshooting. If the amps start to slag 18 (ph), if you have low amp situation, if the variable 19 speed drive starts to have issues, some of the variable 20 speed drives are relatively old, they're old circuit 21 boards, current -- you know, integrated circuits, it's 22 just like any other variable frequency controller, they 23 do have issues especially if they -- as they get older. 24 So what happens is that we'll actually look at the 25 problems and see what we need to do to take care and 56 1 try to remediate the problems. And in the field they 2 can actually see a well, if it's acting a specific way 3 they can actually identify that this is a solution that 4 could cure the problem. And of course the issue would 5 be is that we want to maintain the ESPs running as long 6 as we can. If there's other issues that are going on 7 then we go into the diagnostic mode and like on the -- 8 on the variable frequency drives what we'll is we'll 9 actually go in there and we'll start replacing boards, 10 doing other operation to try and determine what the 11 problem is. So the diagnostics is all related to the 12 problems and the ESP diagnostics, that's all kind of 13 rolled into one as we -- as we try to keep these wells 14 operational. If the well is down and we can't fix it, 15 so we'll try multiple issue -- multiple items to try 16 and fix it, like if the well becomes plugged with sand 17 we'll do the back side flush, we might try some acid, 18 we'll bail sand off the top of the pump, we'll try 19 starting the ESP and in some cases the torc on the 20 motor is so high and the pump is locked that it will 21 actually break the shaft between the motor and the pump 22 itself. So eventually you can go in and say, okay, 23 hey, we have a failure of the ESP, there's nothing else 24 to do, the cable's blown, there's electrical fault, 25 there's all the issues that cause that that will -- we 57 0 1 will declare an ESP that's dead. 2 Once an ESP is dead what we'll do then is we'll 3 hand the well over to the reservoir engineers and 4 they'll run the economics and as you -- as Keith 5 Elliott and Anthony talked about it, they'll run their 6 economics and we'll decide at that time whether or not 7 it's economic to replace the ESP. Once it's -- if it 8 is determined that it is economic to replace the ESP 9 we'll go into the pre -rig preparation. And on that 10 what we'll do is we'll want to kill the well, we'll 11 want to set a two way check, be able to move the rig 12 in, bleed off all the pressures, et cetera, et cetera, 13 so there's a -- there's quite a bit of operations that 14 go into preparing a well for a -- for a workover. And 15 then we'll -- actually we'll replace the ESP with the 16 rig. 17 what I like to do at this time is to show -- 18 actually, I'm sorry, I seem to have misplaced a 19 document. I'd like to come back to that document at a 20 later time, I'd like to show some evidence that 21 previous -- when Conoco was the operator that they ran 22 into extensive well killing operations with packers in 23 the hole, ESP packers in the hole. And I'll come back 24 to that. Okay. The next slide. 25 Commissioner Foerster, could I take a short 58 1 break? 2 CHAIR FOERSTER: Sure. Of course. We'll -- 3 how long do you need, five minutes? 4 MR. CHAN: Just a drink of water and a..... 5 CHAIR FOERSTER: Potty break. 6 MR. CHAN: Yeah. 7 CHAIR FOERSTER: Okay. We'll..... 8 MR. CHAN: Just a drink of water mostly. 9 CHAIR FOERSTER: Okay. Well, then just keep -- 10 just take a drink of water and then keep going. 11 MR. CHAN: So what I like to do on this slide, 12 this slide shows a North Slope well construction 13 history. And this is going to be from my times as a 14 drilling engineer in the early 1990s. And what this 15 slide shows is that we have in the 180s, late 180s, 16 190s time frame we were drilling what we call a 17 conventional well design with gas lift, a big bore 18 well. And that well is constructed with 13 and three- 19 eighth inch surface casing below the permafrost, nine 20 and five -eighths production casing below -- down to the 21 top of the sand and then typically a production liner 22 through the actual producing horizon. And then for 23 like at Endicott Island we would run four and half inch 24 production tubing, gas lift mandrels and a production 25 packer. And what I like to point out on this one, this 59 0 I is that Hisher IA (ph), you have an inner annulus which 2 actually only sees for a monitoring purpose sees gas 3 lift pressure. And then the OA, that's the 4 (indiscernible) annuli because, you know, that's the 5 one that should be basically at atmospheric pressure or 6 whatever pressure we maintain on that annulus. Next 7 one, Marc. 8 Then in the early 190s, 1991, 192 time frame, 9 the price of oil is dropping, the drive is on to 10 actually try and have the same wellbore, but to try and 11 reduce the cost so what they did is they started taking 12 steel out of the well and they came up with what we 13 call a slim hole well. And what they did then is that 14 they went from 13 and three -eighths production casing 15 which weighed 68 pounds per foot down to 10 and three- 16 quarter inch casing which weighs, oh, I forget it now, 17 10 and three-quarter weighs 47. I can't remember now. 18 Who knows? So then we also reduced the production 19 casing size from nine and five -eighths down to seven 20 and five -eighths. The nine and five -eighths weighs 47 21 pounds and the seven and five -eighths is down to 30 22 pounds. And literally when you buy steel from a mill 23 you pay by the ton, it doesn't matter what connection 24 it is, doesn't matter what size it is, you always -- 25 you're literally paying for steel by the ton. And in 1 some cases they would have a production liner, but in 2 some cases they also would drive this production string 3 all the way through to reservoir and it would be called 4 a long string. And on this well same four and a half 5 inch tubing, same IA that shows gas lift pressure and 6 then the (indiscernible) OA. Next, please. 7 This slide shows -- is the North Slope well 8 construction history for a single string design and 9 what this was that in the further attempt actually to 10 make the wells economic specifically at Milne Point, 11 they -- the operator at the time went in and said, 12 okay, so if we can actually drill down to the reservoir 13 -- through the reservoir with one string of casing then 14 you can actually save a lot on the well construction 15 cost. 16 CHAIR FOERSTER: And was this..... 17 MR. CHAN: And on this..... 18 CHAIR FOERSTER: .....was this design used for 19 Kuparuk and Schrader Bluff or just for Schrader Bluff? 20 MR. CHAN: Just for Schrader Bluff. 21 CHAIR FOERSTER: Okay. 22 MR. CHAN: So on this design here it's a long 23 string that goes all the way through to production 24 interval and in this case I'm showing a gas lift design 25 or a jet pump design, but this can also apply for an 61 1 ESP well. And in this case you can see that there is 2 only an IA, there is no monitorable OA. This design is 3 no longer being used simply because at the end of the 4 day you only have one annulus, there's not any 5 additional barriers if something was to happen to your 6 surface casing. Also on this slide here with the 7 single string design, we call those -- you know, 8 they're mono bores now. Next. 9 So going from the North Slope to the Milne 10 Point field this is currently how we're constructing 11 wells today and how we will construct wells in the 12 future so we can actually have a monitorable annulus. 13 So what we have here is just that we have surface 14 casing all the way down to the top of the sand, we 15 actually will drill a horizontal section, in this case 16 we're drilling roughly around 6,000 foot of horizontal 17 section, we'll run the lower completion. The lower 18 completion will consist of either five and a half inch 19 liner or four and a half inch liner. The liners can be 20 either slotted or screens. And then after the lower 21 completion is run we actually will be running a seven 22 and five -eighths flush joint pipe and sting into the 23 lower completion. And that is roughly 90 tons of steel 24 that we're actually adding to these wells so we can 25 actually have an IA and then an OA that we can monitor. 62 1 So ESP here, IA shows -- is going to show -- basically 2 it's going to show header pressure, 180 to 220 psi like 3 Mark O'Malley mentioned, then we'll have the OA that 4 will be -- that will -- so we can monitor that annulus. 5 6 That's it. 7 CHAIR FOERSTER: So did you find the other that 8 you wanted to show us or are we going to -- you going 9 to come back at a future time? 10 MR. CHAN: You..... 11 CHAIR FOERSTER: Either way..... 12 MR. CHAN: Okay. 13 CHAIR FOERSTER: .....I'm just curious. 14 MR. CHAN: So there's no title on this one, but 15 I'll put a title onto it. I'm just going to -- we can 16 just title it right now, historical ESP packer 17 problems. 18 CHAIR FOERSTER: Okay. And be sure..... 19 MR. CHAN: So..... 20 CHAIR FOERSTER: .....that when you submit it 21 for the record you have..... 22 MR. CHAN: Right. 23 CHAIR FOERSTER: .....that title on it. 24 MR. CHAN: So what on this -- on this one what 25 I'm trying to show is that -- so here's Echo 6, here's 63 1 three pump change outs from 1994, 195 and 196. Here we 2 have Echo 6 in September of 1994, we start the rig 3 operations and then we're attempting to kill the well 4 through the ESP packer and down through the tubing. I 5 shortened up the dialogue from -- so this information 6 actually comes from the AOGCC data set, this is the 7 submitted 10/404 forms. So I've condensed this greatly 8 to just say that we attempted to kill the well through 9 the ESP packer and tubing and I can go into much 10 greater detail at a later date if needed, but you can 11 see here that we spent two to three days trying to kill 12 the well before we can even pull out of the hole and 13 lay down the ESP. And then the same thing happens 14 again in January of 1995 so that pump only ran four or 15 five months and we're having -- this well we're trying 16 to -- still trying to kill it and we're still spending 17 amount -- some amount of time to kill the well. 18 CHAIR FOERSTER: Okay. Mr. Chan, is Echo 6 a 19 Kuparuk completion? 20 MR. CHAN: I mean, I had -- sorry, Chair 21 Foerster, I actually had the depths in here, I believe 22 Echo 6 is a Kuparuk well. 23 CHAIR FOERSTER: Okay. And..... 24 MR. CHAN: Echo 6 is -- Echo 6 is a Kuparuk 25 well. Zd 1 CHAIR FOERSTER: Okay. That -- and what 2 prevented you from killing the well? 3 MR. CHAN: So the packers -- let me -- okay. 4 So I'm back to the -- on the slide titled Milne Point 5 ESP packer scale drawing for seven inch, 26 pound per 6 foot casing. 7 CHAIR FOERSTER: And that will -- a hard copy 8 of that will be submitted for the record? 9 MR. CHAN: Correct. 10 CHAIR FOERSTER: Okay. 11 MR. CHAN: And I'm actually having a actual 12 model built of the dimensions from a machine print from 13 a packer manufacturer. So what the problem is 14 is that you have a hole for your production tubing, you 15 have a hole that you can feed the power cable through 16 and then in this case you can either have heat trace or 17 an annular vent valve. And the wells that I'm going to 18 be talking about for Echo 6, there is no heat trace on 19 a Kuparuk well, this is not there, so this one is where 20 the annular vent valve would go. So that annular vent 21 valve is surface controlled with a control line. And 22 the dimensions through the valve are roughly one inch 23 in diameter. Okay. So that's -- with that in mind 24 what happens when you try to kill a well is that 25 typically you want to kill from the deepest point 65 I possible. So if you pump down the tubing and just like 2 on a drilling operation or workover operation, you pump 3 down the tubing with your heavyweight fluid to kill the 4 well and it goes down the tubing and then out the end 5 and then up the annulus. But what's going to happen on 6 -- for us is that with a packer in a hole at a shallow 7 depth and with the limitations of trying to pump 8 through an ESP, if it's a small diameter ESP, if you 9 can only get a half a barrel a minute, a barrel a 10 minute maybe, what you're trying to do is you're trying 11 to kill a well and it's actually flowing faster than 12 you can actually pump down to get your weight fluid 13 into the annulus. So what we were doing on these wells 14 at the time is that you pump down -- you try to 15 bullhead, if that doesn't work you try to pump down the 16 back side and if you can't get a sufficient enough rate 17 through a one inch port then what's going to happen is 18 that the gas is going to swap, the liquid's going to 19 swap and the well's going to continue to influx. So 20 you'll have gas at the surface, you'll bleed that off 21 through the choke, but when you're bleeding it off if 22 you don't actually have enough kill weight fluid going 23 down the tubing then the well will become under 24 balanced again and then you'll have another influx of 25 fluids, mostly gas and oil, which then causes the well 1 to flow even more. So it's just a vicious cycle where 2 you're trying to kill the well by going down the tubing 3 or through the annular vent valve at usually 4 insufficient rates to kill the well. 5 CHAIR FOERSTER: Okay. Please continue. 6 MR. CHAN: So then in 1996 this well, same at 7 well Echo 19 -- Echo 6, back in July, 1996 so that's a 8 year and a half run life, what I'd like to point out 9 here is that so we accepted the rig at 2:00 o'clock in 10 the afternoon, we did our nipple down, nipple at the 11 tree, nipple down the tree, nipple up the stack test, 12 all those operations, pull out the whole ESP, pick up a 13 new one, run in the hole and the rig was released two 14 days later at 0600 hours and we were 40 hours on the 15 well. We look at it from the standpoint that the less 16 time the well is open the better you are, it's less 17 risk, there's -- the people are not on location as 18 long. So the safety and environmental aspects are 19 critical for us is to try and get these wells done as 20 safely and efficiently as we can. And packers clearly 21 for us do not show that that can be done safely and 22 efficiently. And every time you have an operation, 23 whether it's to make up a packer, splice the 24 penetrators, all that exposes the well to being open at 25 the time and also it requires more people. 67 1 So then the other example I like to give is 2 that here's Lema 7. In 1994 in April here -- here's 3 the issue, this one is not the well kill, actually the 4 well kill went fairly decently, here though we spent 5 many, many, many an hour trying to fix --the fact that 6 is that that ESP packer would not set. And so once 7 again you have multiple moving parts and pieces and 8 we're trying to get these things put together and 9 basically back to containment, you know, have all our 10 pressure control equipment rigged back up and here 11 we're having problems with the packer and if we had a -- 12 we ran in the hole and we actually landed the hanger, 13 ran in the lockdown screws, dropped the ball and rod 14 and attempted to set the packer. Unable to do it, so 15 now you've got to rig up a slick line, pull the ball 16 and rod, pull the RHC (ph) ball catcher, try to -- 17 there's a lot of different operations that we try to 18 attempt at that time. So we pull out of the hole, 19 change out the packer, pick up another one and the 20 first time they attempted to set the second packer it 21 didn't set and so they pressured up again to a much 22 higher pressure and they finally got it to set. So 23 here's, you know, instances where we have mechanical 24 complexity significantly increasing the amount of time 25 spent on a well. 68 1 And that concludes my testimony. 2 CHAIR FOERSTER: Okay. Commissioner Seamount, 3 do you have any questions for Mr. Chan? 4 COMMISSIONER SEAMOUNT: First of all, Mr. Chan, 5 do you -- in other fields in Alaska that require 6 packers do you see the same problems that you just 7 discussed? 8 MR. CHAN: Typically not. 9 COMMISSIONER SEAMOUNT: I mean, are you -- 10 typically not. 11 MR. CHAN: Typically not. So like if I was to 12 do a Prudhoe Bay workover what I would do is I would 13 actually go in there, there's a -- the wells would 14 be..... 15 CHAIR FOERSTER: How many Prudhoe Bay wells 16 have ESPs? 17 MR. CHAN: They have -- to the best of my 18 knowledge they have zero production wells, but they 19 have a few water supply wells. 20 COMMISSIONER SEAMOUNT: Do..... 21 MR. CHAN: Commissioner Seamount, would you 22 like me to elaborate a little bit on the Prudhoe 23 workovers..... 24 CHAIR FOERSTER: How about..... 25 MR. CHAN: .....that I've experienced? •E 1 CHAIR FOERSTER: .....how about Conoco's 2 Schrader Bluff workovers or ENI or Calis' (ph) 3 workovers in comparable reservoirs? 4 MR. CHAN: I'm not -- I don't have that 5 knowledge, Chair Foerster. 6 CHAIR FOERSTER: Okay. 7 COMMISSIONER SEAMOUNT: Are both formations, do 8 you drill about 6,000 foot horizontals, you do it in 9 the Kuparuk? 10 MR. CHAN: Currently all of our future 11 development plans are for the Schrader Bluff interval -- 12 for the Schrader Bluff formation. 13 COMMISSIONER SEAMOUNT: Okay. Is the aerial 14 coverage of the Kuparuk -- I assume that's a lot less 15 than the Schrader Bluff, is the Kuparuk completely 16 developed right now, do you know? 17 MR. CHAN: I would have to defer to Anthony or Keith. 18 MR. ELLIOTT: Yes, it -- well, it is 19 (indiscernible - away from microphone)..... 20 CHAIR FOERSTER: Can you come up and use the 21 microphone and introduce yourself again? 22 MR. ELLIOTT: Keith Elliott, reservoir engineer 23 for Milne Point. Is the Kuparuk completely developed. 24 It is thoroughly developed. We will still find and 25 develop more oil in the Kuparuk, but it is mature and 70 1 thoroughly developed. 2 COMMISSIONER SEAMOUNT: So you're looking for 3 other lenses in the Kuparuk; is that correct? 4 MR. ELLIOTT: Correct. Or fault blocks that 5 are not swept. 6 COMMISSIONER SEAMOUNT: Can you see them on 7 seismic? 8 MR. ELLIOTT: we can see faults on seismic. 9 COMMISSIONER SEAMOUNT: You can't tell if the 10 sand's there? 11 MR. ELLIOTT: Not specifically. 12 COMMISSIONER SEAMOUNT: Mr. Chan or anybody, 13 how many wells are shut in, suspended or abandoned 14 because of economics in the field, just a rough 15 estimate or a percentage? 16 MR. ELLIOTT: This is Keith again. I can give 17 you a rough estimate. There are in the field -- I'm 18 looking at our survey -- waterflood surveillance survey 19 that we submitted to you in July and it shows well 20 counts, doesn't sum them up, but I will sum them up 21 quickly. There are direct (ph) wells in total, there 22 are 108 productive, active wells, producing wells. The 23 number of injectors in total equal about 80, 85. So 24 around 195 active wells, producers plus injectors. And 25 there are about 250 wells in the field. So that leaves 71 • L 1 around 55 idle wells. 2 COMMISSIONER SEAMOUNT: And when you determine 3 they're uneconomic is that uneconomic at -- what was it 4 55 barrels or $55 a barrel and 95 barrels of oil per 5 day? 6 CHAIR FOERSTER: Well, they're idle wells, they 7 can either be broken or -- it doesn't mean they were 8 shut in for uneconomic, it means they were..... 9 COMMISSIONER SEAMOUNT: Right there it says 10 economic to replace, yes or no. That's my question, 11 how many have been determined? 12 CHAIR FOERSTER: But that's talking about an 13 ESP and what I'm saying there might be wells that are 14 shut in because they have parted tubing..... 15 COMMISSIONER SEAMOUNT: Okay. Right. Okay. 16 Well, then let me rephrase it. Due to ESP failure? 17 CHAIR FOERSTER: Yeah, the question that he's 18 trying to ask is how many wells are currently shut in 19 because you can't afford to replace the ESP because 20 they're below the economic limit? 21 MR. McCONKEY: Okay. So it's very few, it's..... 22 CHAIR FOERSTER: And your name is? 23 MR. McCONKEY: Sorry. This is Anthony 24 McConkey. Very few, I would say five to 10 wells are 25 capable of producing through an ESP, but are not being 72 1 replaced because they are uneconomic. 2 COMMISSIONER SEAMOUNT: And why -- what was the 3 production rate when they were determined to be 4 uneconomic? 5 MR. McCONKEY: Typically -- you know, it's hard 6 to say what exactly the rate of all of them would be if 7 we brought it on, but usually it's anywhere from I 8 would say 10 barrels of oil a day to maybe 50 barrels 9 of oil a day or I would say a majority of these wells 10 that are shut in. 11 COMMISSIONER SEAMOUNT: So it's not 95 barrels 12 a day? 13 MR. McCONKEY: Correct. But it's -- again it's 14 a ball park number. I mean, you have distribution. 15 MR. ELLIOTT: Correct. And it's important -- 16 back to Keith Elliott. It's important to note that 17 many of the idle wells are idle because they are below 18 the economic limit about -- as we talked about 50 idle 19 wells in the field that are not being used because 20 they're either -- they're below the economic limit, 21 they may be too expensive to fix or the rate may be too 22 low or some combination. 23 COMMISSIONER SEAMOUNT: Okay. 24 MR. ELLIOTT: Therefore I think it's more 25 insightful to speak of the existing active wells of 73 1 which a $50 oil price where we are about today, we are 2 very much in a scenario where in the plot -- one of the 3 plots that I showed if it were -- you know, the point 4 that I noted was if the economic limit was 145 then 43 5 of those -- of our wells would be below the economic 6 limit in a high priced, low (indiscernible) fee life 7 scenario. The current status quo is 95 barrels of oil 8 a day. And I can reference that plot, but we can look 9 at it and see the number of wells that are active that 10 fall below the economic limit that if they break we 11 will not fix..... 12 COMMISSIONER SEAMOUNT: Okay. 13 MR. ELLIOTT: .....in the current scenario. 14 COMMISSIONER SEAMOUNT: Okay. I understand. 15 And finally, Mr. Chan, the boards that were put up 16 showing the wellbore schematics are different than the 17 handouts and the handouts aren't -- I mean, they're 18 cutoff, is..... 19 CHAIR FOERSTER: Yeah, the handouts are 20 unacceptable. 21 COMMISSIONER SEAMOUNT: .....have you supplied 22 or do we already have in our possession the..... 23 CHAIR FOERSTER: Complete. 24 COMMISSIONER SEAMOUNT: .....the complete 25 wellbore schematics, if not could we get copies of 74 I those, I mean, I -- you could probably just take an 2 Iphone and take pictures of them. 3 CHAIR FOERSTER: Anything that..... 4 MR. CHAN: We have -- we have the complete..... 5 CHAIR FOERSTER: .....anything that we want to 6 have included in the record needs to be in the record. 7 MR. CHAN: Correct. We will have a complete 8 set of slides. What I've done -- typically what I do 9 on drawings like that is I like to print them on 11 by 10 17 because there's a much better..... 11 COMMISSIONER SEAMOUNT: Right. 12 MR. CHAN: .....a lot of area. So these were 13 not turned in on the right..... 14 COMMISSIONER SEAMOUNT: Okay. 15 MR. CHAN: .....size paper. And that will be 16 supplied -- we will supply you with the electronic file 17 and paper copies. 18 CHAIR FOERSTER: Okay. 19 COMMISSIONER SEAMOUNT: Well, these are 20 different because -- well, one big difference is that 21 you don't have the cement going as high as you do on 22 the boards. So I don't know should we -- should we 23 throw these handouts out and get some complete ones? 24 CHAIR FOERSTER: Yes. 25 MR. CHAN: Those slides actually are my -- are 75 1 the ones I showed. 2 COMMISSIONER SEAMOUNT: Well, actually the 3 first one you showed has the cement going above 4 these..... 5 MR. CHAN: which slide are you on? 6 COMMISSIONER SEAMOUNT: I think that's the 7 North Slope..... 8 CHAIR FOERSTER: We don't have a complete..... 9 COMMISSIONER SEAMOUNT: Oh, okay. Okay. We -- 10 I didn't see that one. 11 CHAIR FOERSTER: We don't have any complete 12 slides. 13 COMMISSIONER SEAMOUNT: No, that -- okay. That 14 one is -- okay. That one's correct, I must have been 15 looking at the wrong slide, but in any case we need a 16 slide that shows everything that's on those boards. 17 MR. CHAN: Correct. And this -- this slide 18 pack is identical to the..... 19 COMMISSIONER SEAMOUNT: Okay. 20 MR. CHAN: .....posters. 21 COMMISSIONER SEAMOUNT: That's all I have. 22 CHAIR FOERSTER: Okay. Mr. Chan, Commissioner 23 Seamount was trying to go down a path of what are other 24 operators with similar wells and similar reservoirs 25 doing. And the reason he's doing that, they're -- ENI, 76 1 Calis and Conoco all have operations similar to what 2 Hilcorp has at Milne Point, but ENI, Calis and Conoco 3 do not have a CO similar to 390. They all use packers. 4 And so as we're going through out deliberative process 5 to try to understand why CO 390 needs to remain in 6 effect it's important to us to understand what makes 7 Hilcorp's operation different from ENI's, Calis' and 8 Conoco's in the same reservoirs. So I -- I'm going to 9 add that to the list of questions that we're going to 10 leave the record open for to give you the opportunity, 11 you know, and (indiscernible) is a fine answer, but I 12 just want to make sure we've given you an opportunity 13 to give us a better answer than that to the question of 14 why do Hilcorp wells in these reservoirs need to be 15 operated differently than ENI's, Calis' and Conoco's. 16 So I'm just going to leave the record open for you to 17 answer that question also since you've already said 18 that you did not have that knowledge. 19 Okay. And as I sit here and listen to you talk 20 about how awful these packers are I think about the 21 people in the audience who aren't engineers and they 22 have to be asking then why do we even run these nasty 23 packers. And I'd like for you to educate the audience. 24 MR. CHAN: Why do we even run them? 25 CHAIR FOERSTER: Why do we even run these nasty 77 1 packers in wells, you know, why -- you know, aren't 2 they like horseshoes, you know, shouldn't we have found 3 a better way by now? 4 MR. CHAN: So in some cases the packers are 5 required for ESP lifted wells in large numbers like in 6 the U.S. due to regulatory regulations. So 7 regulations. Mr. Dwiggins..... 8 CHAIR FOERSTER: So we only -- regulators 9 haven't come up to the times and realized that packers 10 should be done away with and that's why we run packers 11 in wells? 12 MR. CHAN: Well, offshore -- offshore -- in an 13 offshore installation the things that the industry came 14 up with for having subsurface safety valves and 15 production packers are due to several elements. One of 16 them is that hurricanes, you need to move all -- you 17 need to move away or the platform gets toppled, you 18 need to be able to have the well shut in and secure so 19 there's damage to the environment. There's documented 20 instances of two platforms at a minimum getting toppled 21 due to a submarine landslide during hurricane Katrina. 22 So the packers and the ESPs, subsurface safety valves 23 at that -- in those types of scenarios, you want to 24 have the ability to actually maintain complete well 25 control. We don't have hurricanes, we don't have 78 1 submarine landslides. The issue comes down to you're 2 going to create more risk, harm to the environment, 3 more chance for something to happen with an ESP packer 4 than if you don't have an ESP packer. And so we're 5 trying to balance out the risk of an offshore 6 installation versus a land installation where we have 7 access, you can drive up to it, if the platform gets 8 buried the ones I'm most familiar with is -- on 9 submarine landslide, there's two platforms that got 10 buried and they're under hundreds and hundreds of feet 11 of sediment offshore and trying to -- trying to regain 12 access to those wellbores would be probably impossible -- 13 nearly an impossible task. 14 CHAIR FOERSTER: Okay. So let me make sure I 15 understood what you said. we -- that it's your feeling 16 that regulatory bodies like the AOGCC should only 17 require packers in environments that have submarine 18 landslides and hurricanes? 19 MR. CHAN: That's not quite true because -- Mr. 20 Dwiggins will talk about the -- in his experience 21 international locations, Australia, the Far East. 22 Australia doesn't require ESP -- packers with ESPs. So 23 from my standpoint as a workover engineer, packers 24 create a large number of problems, they create more 25 problems that you would probably solve with a packer. 79 1 CHAIR FOERSTER: What is the packer in place to 2 solve, what problems are packers in place to solve? 3 MR. CHAN: Well, typically a packer's in place 4 to solve -- if you look at a gas lifted well or if you 5 look at a production well that can naturally flow, the 6 packer -- the main purpose of a packer on a production 7 well that can flow naturally is that you actually want 8 to have kill weight fluid on the back side, if the 9 packer fails it kills the well. So that's part of it. 10 The other thing a packer does is actually allows you to 11 have packer fluid on the back side to protect the 12 casing and the tubing from corrosion. On a gas lifted 13 well if you have a tubing leak like Prudhoe Bay can 14 have due to CO2 corrosion, then basically your 15 production casing is exposed to reservoir pressure 16 until we actually secure the well. And then you have 17 the barriers of the production casing and the surface 18 casing to protect the environment. 19 CHAIR FOERSTER: So the packer helps you 20 provide those two barriers to flow that most regulatory 21 bodies require? 22 MR. CHAN: Unless the packer fails which they 23 can. I mean, Prudhoe Bay does cement packer squeezes 24 because of packer failures. 25 CHAIR FOERSTER: And when a packer fails what .1 9 1 happens? 2 MR. CHAN: Typically on a gas lifted well you 3 can't gas up the well anymore because you're short 4 circuiting the gas lift valves in the gas lift mandrel. 5 CHAIR FOERSTER: So but is a well allowed to 6 operate without two barriers to flow so when -- if that 7 packer fails is the well required to be shut in? 8 MR. CHAN: I think that is regulatory dependent 9 and operator dependent. 10 CHAIR FOERSTER: In the state of Alaska? 11 MR. CHAN: Correct. To my knowledge. 12 CHAIR FOERSTER: Okay. Thank you. All right. 13 I don't have anymore questions for you at this time, 14 but stick around and remember you're under oath until 15 the end of the hearing. 16 Okay. Proceed. 17 DR. LEA: (Indiscernible - away from 18 microphone)..... 19 CHAIR FOERSTER: I beg your pardon. 20 DR. LEA: I'd like to have a short break before 21 we get started. 22 CHAIR FOERSTER: Okay. That's fine. What is 23 short? 24 DR. LEA: Three or four minutes. 25 CHAIR FOERSTER: Okay. We'll take a 10 minute 81 9 1 potty break. We're adjourned -- I mean, we're 2 recessed. 3 (Off record) 4 (On record) 5 CHAIR FOERSTER: Okay. We'll go back on the 6 record at two minutes until 11:00. 7 JAMES F. LEA 8 previously sworn, called as a witness on behalf of 9 Hilcorp Alaska, testified as follows on: 10 DIRECT EXAMINATION 11 DR. LEA: Okay. My name is Jim Lea. I have 12 worked around ESPs quite a bit in my -- right now I'm 13 working with a group called PLTech and we do artificial 14 lift and analysis of wells. There's four or five other 15 people in the group. Before that I spent seven years 16 at Texas Tech Petroleum Engineering Department as head 17 of the department and we're doing PT and also some 18 industry work with respect to artificial lift. For 19 instance we started up the forum on dewatering gas 20 wells which uses all methods of artificial lift which 21 still goes on today even though we're not working on 22 that anymore. I have quite a few publications and a 23 few books. I did the distinguished lecture tour with 24 the SPE two times, it's been a few years since that was 25 done. There's a permanent panel with the ESP 82 1 roundtable which now is held every other year instead 2 of annually as initially was done, but I was a member 3 of one of the four or five companies that initiated 4 that roundtable some years ago and it's been I think a 5 pretty good service to the industry to provide a forum 6 for new products and technical presentations. Member 7 of the API committee on ESPs and chairman of the board 8 they have me down as since we did start up this ALRDC 9 gas well dewatering forum which is one of their bigger 10 events, but they also have events on ESPs and beam 11 pumping and things of that nature. And then later in 12 the slides I'll show you that when I was working at 13 Amoco for some -- approximately 20 years, we had 1,000 14 ESPs company wide and we were working on design 15 programs and well testing and things of that nature. 16 Oh, education. I have a undergraduate degree in 17 mechanical and a master's in mechanical and Ph.D. in 18 mechanical at Southern Methodist which centered on the 19 fluids -- thermal and fluid option. So I really picked 20 up the petroleum from experience by going to different 21 schools and experiencing the company. I started out 22 with a few years at Sun Oil and then 20 years with 23 Amoco so the degree was not a petroleum degree, but 24 after a few years of working there that's what I've 25 done since I've been working almost my entire career. 83 0 1 CHAIR FOERSTER: Thank you, Dr. Lea. 2 Commissioner Seamount, do you have any questions? 3 COMMISSIONER SEAMOUNT: I have no questions and 4 no objections. 5 CHAIR FOERSTER: And neither do I, Dr. Lea. 6 And I think a mechanical engineering degree is just 7 fine, that's what I've got. 8 DR. LEA: Thank you, I like it too. 9 CHAIR FOERSTER: So you may proceed. And don't 10 forget to give your talk context relative to your 11 overheads. 12 DR. LEA: Okay. This slide here gives a little 13 bit of an introduction to what we'll look at during the 14 slides, it says contents of presentation. And we'll 15 just do a quick review of ESP system and then we're 16 back to packers again so I have some issues with 17 packers. Some of that will be a little bit of repeat, 18 some of it will be perhaps a couple of new issues. 19 Then I want to specifically talk about a few more 20 issues with respect to sand and solids and gas 21 handling. And then at the end there I do a little mini 22 survey there on what people see with respect to ESP 23 operations with packers and I'll just go over that 24 quickly. 25 So I don't know, I guess a lot of people here 84 1 know this, maybe not everybody, but here's a typical 2 ESP. 3 CHAIR FOERSTER: You're talking from the slide 4 titled generic ESP installation? 5 DR. LEA: Yes, that -- that's right. Correct. 6 So here's the tubing and this pump which is a stack of 7 centrifugal stages is essentially screwed on to the end 8 of the tubing so when the unit fails you have to pull 9 the tubing except for some particularly novel type 10 devices. So here's a stack of centrifugal stages. You 11 put enough stages in there to develop enough pressure 12 to carry the fluids to the surface, overcome the 13 hydrostatic friction and surface pressure if you're 14 designed right. And then underneath there will be 15 either a gas separator or a standard intake, if it's a 16 gassy well it's probably going to be a rotary gas 17 separator which brings gassy fluids in, does -- puts 18 some gas back in the casing and sends liquid rich 19 fluids into the ESP. And then we have seal protector 20 or equalizer which serves several functions there and 21 it has a thrust bearing, it also protects the motor 22 from wellbore fluids entering into the hydroelectric 23 stream fluids that are contained in the motor. And 24 then the motor's down here on the bottom. Why is it on 25 the bottom, we want the fluids to come past the motor 85 0 1 which gives somewhat of a cooling affect, carries the 2 heat away, keeps the heat from building up and so the 3 fluids go past the motor before they go in the pump. 4 Then we may have some instrumentation down here at the 5 bottom. And in this picture over here on the fight if 6 you'll see this little horizonal line coming off the 7 wellhead, that's very typical of any pumping well, 8 beam, ESP, whatever, if there's gas in the well. So 9 that's the gas that's been separated from the fluid 10 stream and sent up to casing and then (indiscernible) 11 surface, in this case it's tied back to the water and 12 oil rich liquid mixture coming out of the tubing that 13 was pushed to the surface by the pump. 14 Now this first slide here in the side, I see 15 we're going to have to make a correction on the title, 16 but in the slide it says packer set low and I see that 17 we've got to correct the title here, I'm just saying 18 that -- a deep set packer. So let's first talk about a 19 ESP situation with the packer set deep in the well and 20 what some of the concerns might be relative to no 21 packer at all and some of these things have been 22 mentioned and some not. But first of all if you do 23 have the packer set deep in the well you can see either 24 from the board over here on the left or from the slide 25 that we're going to have two additional connections as 0 1 the cable goes through the packer here. And so we're 2 always going to have a splice between the motor lead 3 extension and the power cable right above the ESP and 4 we'll have another typically a splice at the surface to 5 splice into the mandrel feed through at the wellhead, 6 but here we have two more slices -- two more splices. 7 And we think of those splices or connections as being 8 weak points in the cable and the fewer connections the 9 better. So they were introducing a bit more of a risk 10 factor there in the well by introducing two more 11 electrical connections downhole. 12 And I'm going to go ahead and show this quickly 13 a little piece of equipment here, but Jeff Dwiggins is 14 going to elucidate on this and give us a -- give you a 15 bit more detail. But here is a failed connector that 16 was connected, connected the power cable to the feed 17 through there at the packer downhole. And he can give 18 you a little bit more detail, but it's just to point 19 out that splices and connections you have to feed the 20 packer -- feed the cable through the packer adds a bit 21 more risk to the assembly. And then we have this -- a 22 vent that's held open with hydraulic pressure here. 23 And as we talked about earlier it has about a one inch 24 diameter flow through area. 25 Now -- and again if you're set deep you're 87 0 1 probably going to have the producing fluid level above 2 this deep set packer. Now what can happen here if this 3 got restricted or if we got sand building up on the 4 packer or if you built up some scale here or anything 5 that would reduce the flow what can happen is that a 6 cloud of gas can build up under the packer and if that 7 cloud of gas gets to be too big this gas extends down 8 to the pump intake and the pump will bring in that 9 lighter fluid, it'll lose a lot of it on the pump and 10 you'll go off on what we call low amps, no load on the 11 ESP. So that can put you in an on/off mode and we 12 don't like to be in an on/off mode, with ESP starts and 13 stops reduce run life. And if this -- for some reason 14 this vent should be plugged at this point then this 15 well would act like a flowing well, the fluid level 16 would go down to the intake and then all the gas coming 17 from the well would go through the ESP and we'll see 18 here in a minute that gas being included with liquids 19 through the pump reduces the pump out fluid and can 20 even gas lock it and bring the production to a 21 standstill. This is similar to the case that you see 22 sometimes with beam pumps because they run not a 23 packer, but a anchor which has a feed through, but it's 24 somewhat limited and if it doesn't have a big enough 25 feed through you can build this cloud of gas underneath 0 1 here even though there is a gas flow and if the cloud 2 of gas stands down the ESP then you start having 3 problems with your pumping operations. 4 And maybe you do bring some sand in here, you'd 5 have to visualize the gas velocity under the heavy oil, 6 maybe moving up and down when you turn it on and off it 7 brings sand in here. But one of our team mentioned 8 earlier that what if you had a tubing leak here above 9 this packer then you could drop fluids back down here 10 that would be sand laden and then you would have some 11 sand over that packer and it could possibly make it 12 very difficult to pull the packer. 13 So anyway those are a few comments there if you 14 had the deep seated packer. Let's talk now if you 15 seated the packer a little higher in the well what the 16 difference might be. So if you had a shallow set 17 packer the producing fluid level would more like..... 18 CHAIR FOERSTER: I'm sorry I didn't interrupt 19 you last time, but you were talking before on a slide 20 called packer set low and now you're talking on one 21 called -- titled packer set high? 22 DR. LEA: Yes, and..... 23 CHAIR FOERSTER: Okay. So please don't make me 24 interrupt you every time by..... 25 DR. LEA: I know. I'm sorry..... 89 0 1 CHAIR FOERSTER: Okay. 2 DR. LEA: .....about that. 3 CHAIR FOERSTER: Okay. 4 DR. LEA: I need reminding. 5 CHAIR FOERSTER: All right. I will interrupt 6 you, but I don't want to. 7 DR. LEA: Well, no, I'm sorry about that. 8 CHAIR FOERSTER: All right. Sorry for the 9 interruption. Please proceed. 10 DR. LEA: I need a rubber band around my finger 11 here or something, but I'll try to do better. 12 So here this slide says packer set high, our 13 picture over here on the left essentially says shallow 14 set packer. And so what we're saying in this situation 15 is that the producing fluid level would not reach up to 16 the packer so you would have this gas space under here 17 and more than likely you wouldn't extend a cloud of gas 18 all the way down to the ESP just a low flow rate, but 19 if you did plug off this vent the fluid level would 20 however travel all the way down to the pump intake and 21 then all the gas would go into the ESP. But it would 22 be less likely that would occur if you just had cycle 23 restricted flow. But again you would have these two 24 additional connections above and below the feed through 25 for the cable going through the packer and we think •11 1 that's a little higher risk factor. You could have 2 liquids above this top set packer just from 3 condensation of liquids coming out of the -- out of the 4 saturated gas that would go through this gas vent here 5 and you might accumulate some liquids here and if you 6 did that would give you a greater pressure drop, but 7 the gas would have to flow through before it went on up 8 the well and exited through the gas lift and into the 9 containing -- the check valve. 10 And so for good ESP operations what we'd like 11 to have is a restriction free, open annulus to allow 12 the gas from the gas separator or even without a gas 13 separator, we'd like this gas to travel easily up the 14 casing without a lot of restrictions or pressure drops 15 and then exit the well at the top of the well. And if 16 you start putting restrictions in the well in this 17 annular flow the very worst would be if you plugged it 18 up all the gas then would go through the ESP and it 19 might gas lock and quit running all together, probably 20 would considering the amount of gas the well's making. 21 But anything in between there you're going to have a 22 gradual degradation in the performance of the ESP and 23 restrict the flow of the gas coming up. So if you 24 didn't let the gas come up at all then all the gas 25 would go through the ESP, but you put restriction in 91 1 here then you create problem with the separator and 2 don't let the gas escape from the pump as well. So 3 you'd have kind of gradual degradation due to 4 restrictions here up to the point that -- where you're 5 completely plugged off. of course we did mention the 6 case where this can -- this check valve can freeze and 7 that's a restriction there and we were -- I think Mark 8 was talking about freeing that up by putting some hot 9 oil down and melting that away. I don't know that you 10 necessarily hydrate off this vent line, but you would 11 have a restriction to flow if fluids built up and just 12 the gas bubbling through the liquids would be more of a 13 restriction than if it was wide open to flow. 14 So those are just a few of the comments on the 15 deep or high set packer, but thank -- oh, the other 16 things is if you set the packer too high you get in 17 such a cold zone up here that the rubbers in the packer 18 get to be pretty stiff and you try to relax the packer 19 and it's so stiff you may have trouble unseating the 20 packer. So there's pluses and minuses for the shallow 21 set or the deep set packer, but as far as ESP 22 performance I think I would probably prefer to sit it a 23 little higher in the well and not create a gas cloud 24 underneath the packer which would put a low load on the 25 ESP and give a poor performance. So let's go to the 92 1 next slide. 2 Okay. This neck slide here is talking about 3 killing the well with the packer relaxed. There it is 4 on the wall. I believe it's titled the same in both 5 locations there. And some of these problems have 6 already been somewhat alluded to so (indiscernible) 7 this slide or picture, killing the well. So we relax 8 this packer element and we're going to try to kill the 9 well, but again you going to have to flow fuel through 10 this limited area through the vent valve and you li wouldn't have much flow area here on either side 12 especially if the packer wouldn't relax because it's 13 cold, that would be even more of a problem there. So 14 we've talked about some of those problem, the low flow 15 rates Paul showed earlier gives you some headaches 16 there trying to kill the well if you have these low 17 flow restrictions in the well due to the packer 18 elements. 19 So anyway this is just sort of a summary slide 20 here, we're talking about obstructed vent and liquid 21 over the packer and it's just saying that the pump I'd 22 like to see a restriction free, open annulus to allow 23 this gas to come up the annulus and out of the well and 24 the more restrictions you put on here the more the gas 25 has trouble leaving the pump and leaving the separator 93 1 and this gas remains in the pump and doesn't escape as 2 easily, it doesn't perform as well then it -- fluid 3 level builds up and before long you're operating at the 4 higher fluid level and the lower flow rate. So as you 5 continually restrict the gas coming out of the well you 6 go to a lower flow rate and higher fluid level downhole 7 which of course is not a happy thing. 8 Here's a few more packer cons as it says up 9 here on the side. I'm thinking we have a poster for 10 this and some of these have been mentioned so I'll 11 quickly go through this, but you put the packer in, 12 maybe it won't release. You put the packer in, it 13 could become unseated. You put the packer in, maybe it 14 leaks. These things happen when you're working with 15 packers. Some packers break off little jiblets of 16 rubber, it falls downhole, we don't like any trash in 17 the well with an ESP, how many stages does it take to 18 stop the plug to make -- stop the ESP performance. All 19 you got to do is plug off one stage and the whole 20 unit's dead so we like to keep the well trash free and 21 we wouldn't want to have any, you know, little rubber 22 jiblets breaking off, that depends somewhat on the 23 quality and type of packer that you wind up installing. 24 Then we talk about some of our treatments and 25 procedures that are restricted by having a packer in 1 the well, it's not that you maybe can't do them, but 2 life becomes a little bit more difficult. The 3 circulation, you can't get the rate that you'd like. 4 The back side flush which is apparently a really good 5 help there with the sand, I've had good luck with it, 6 I'll comment on that a little bit more in a minute. 7 That's something that we don't want to lose that 8 technique if you don't have to. Fluid level shots to 9 monitor the downhole pressure. We have to do that if 10 we -- if we lose the downhole sensor. If we don't then 11 we have to start looking at things like if you start 12 pumping the well off and the trace gets fuzzy and then 13 you don't know if it's getting fuzzy because of pumping 14 the well off or because of solids. So we lose a lot of 15 diagnostic capabilities there unless we're able to 16 shoot the fluid level down the hole. And it's 17 disruptive for several of the other procedures that 18 aren't listed for you early on. And I just talked 19 about the gas and then we talked about the hole in the 20 tubing over the packer could put sand in the packer and 21 maybe it wouldn't come out of the hole. 22 Just to show you here's a couple of stages 23 where packer rubbers in the well plugged off a phase 24 and the unit failed. So it can happen so how often 25 it's happened I don't know, it can happen. I've heard 95 1 lot of cases where packer rubbers get in the pumps, not 2 just the ESPs. 3 And then we have the splices and connections 4 again. we'll have a little bit more detail on that 5 from Jeff Dwiggins. There's at least this many if -- 6 and probably some more packer that are designed for 7 ESPs where you have the cable feed through and the 8 capability of putting the gas vent through there. Some 9 of these they advertise them as being splice free, but 10 there still are connections that require that you make 11 a connection above and below the packer and you can see 12 that this could be possibly a weak point in the system 13 there anytime you do have an extra connection in the 14 well. For instance some operators will not run a cable 15 once they reach a certain amount of splices per 16 thousand feet because they recognize that splices in 17 the cable are weak points and they -- once they reach a 18 certain number of splices they'll just discard the 19 cable because they recognize that splices even though 20 we do them as best we can can be a weak point and lead 21 to failures, premature failures in the well. So here 22 we're introducing two connections with the packer above 23 and below the packer so that we're able to penetrate 24 the packer. So it's just a risk factor, it's not that 25 you can't do it, but we think it's introducing a bit M 0 1 more risk to the system. 2 I did a little bit of work here, not a lot of 3 work, but I looked at packer set at 600 and 2200 feet. 4 CHAIR FOERSTER: And you're talking to the 5 slide titled..... 6 DR. LEA: This is a slide, annulus producing 7 gassy fluid heights can be calculated to estimate if 8 the packer setting depth will have the fluid level -- 9 have the vent value submerged, seeing gassy fluid at 10 the vent. What I'm saying here is if the fluid level, 11 producing fluid level is up to the packer then as the 12 gas vents through the packer it's going to sort of be a 13 gas lifting affect, it would be restricted flow going 14 through there and it might carry extra liquid above the 15 packer and it might generate more pressure drop above 16 the packer. But if the packer's set high the producing 17 fluid level would be down below the packer and in that 18 case you might have less of a concern of possibly the 19 gas venting through the packer carrying additional 20 fluids above the packets. So that was just kind of a 21 what if thing and to see that the shallow set packers, 22 the producing fluid level would be below the packer, 23 but with the deep set packer, the producing fluid level 24 would most likely be above the packer there and you 25 might be bubbling gas through the vent and carrying 97 1 extra liquid above the packer giving you more pressure 2 drop across the -- in the annulus. 3 And this is just kind of a summary slide here 4 where I'm talking about running speed. And this is 5 really just paying attention to how long it takes to 6 install the unit and if you have a really trouble free 7 unit you can go in as fast as 2,000 feet per hour, but 8 the more trouble you have with cable damage and what 9 have you, you might slow down to 2,00 feet per hour, 10 but if you have to install a picker then we worry about 11 the two additional cable connections and seating the 12 packer and extra running time is going to be required 13 and your average installation time's going to go up 14 which has a -- somewhat of a damaging affect of the 15 overall efficiency of the field. So that's just a 16 reminder there that run time could be longer. 17 So packer issues here. Those are the few that 18 we've already somewhat discussed, introduce maybe a 19 couple more. But packers can introduce additional risk 20 and eliminate some of the current useful procedures 21 that are able to be done now with the open annulus and 22 Mark I think did a good job of highlighting some of 23 those useful procedures that we use now with the open 24 annulus. So this slide here, the packer issues 25 summary. •M 1 All right. Let me just -- I just have one 2 slide here on sand handling and sand and we discussed 3 that already, but I'll bring up maybe one new point 4 here. This is entitled sand and solids, production and 5 handling of -- when sand is present. And so what does 6 sand do with an ESP. Well, sand is not a happy thing. 7 If you have too much sand ESP is maybe not the best way 8 to lift the well. If you had a whole lot of sand you 9 might say well, gas lift would be better because the 10 sand doesn't go through the gas lift valves, but ESPs 11 especially nowadays with new developments can handle a 12 certain amount of sand and we like to use ESP because 13 we get a lower draw down pressure and more rate than 14 gas lift. So what are some of the mitigation 15 productions you might say that are available in the 16 industry for extending the life of the ESP with sand. 17 Well, you can use filters and screens and so called 18 Cavins centrifugal separator to try to keep the sand 19 out of the pump, but as we mentioned earlier this fine 20 powdery sand seems to plug up the filters and the 21 screens so that's not one of our best options. But you 22 can use improved metallurgy and coatings in the stages 23 to try to reduce wear. There's also some little 24 hardened sleeves and bushings that you can intersperse 25 throughout the pump and you can carry any radial and 1 down thrust wear on carbide to carbide which has proved 2 to be a pretty good way to eliminate wear. Another 3 method that's used and I think used here with Hilcorp 4 is use what we call fixed and not floater stages where 5 the stages are essentially fixed to the shaft and then 6 we just pull the shaft up just a little bit and take 7 the thrust off between the stage and the diffuser and 8 that reduces sand wear between the rotating impeller 9 and the stage. So by using a fixed stage we can raise 10 this up a little bit and then we won't have this 11 grinding action there between the impeller and the 12 diffuser. So that's another option that's used. So 13 and then of course we worry about possible sand 14 accumulation over the packer. 15 But the main summary thing that I wanted to 16 bring to your attention here is even with the sand it 17 looks like Hilcorp is doing a good job of managing the 18 sand with the ESPs because I would write this 2.7 year 19 run life as above average. So here we are in these 20 harsh conditions, but getting above average run life. 21 And I think some of that is due to some of those 22 procedures which have been developed like for instance 23 the flush -- the back flush that they use to wash the 24 sand up out of the top of the pump and on up and out of 25 the tubing when the unit goes down so you can start out 100 1 with more of a sand free environment and get the unit 2 started and running again. And as we pointed out 3 earlier or has been pointed out that if the packer's in 4 place then we've got trouble there not being able to 5 flush down the casing and push that sand up out of the 6 tubing and out of the top of the pump when the unit 7 goes down. 8 So the point is we're doing pretty good at 9 Hilcorp with 2.7 run life even with harsh conditions 10 with the sand. And so it's not that you couldn't 11 continue to operate that way, but I feel that the run 12 life is going to go down and I think Mr. Dwiggins will 13 give you that same opinion there because you won't be 14 able to handle some of their developed procedures with 15 the packer in place. 16 So anyway solids can cause pump wear and pump 17 sticking. Addition of the packer will eliminate some 18 of our useful sand management procedures that have led 19 to this pretty good run life of 2.7 years which is I 20 think is well above average for the industry. Which is 21 pretty good when you have harsh conditions. 22 Okay. This next one is just -- says gas here 23 and I'm going to talk a few slides a little bit more in 24 detail about gas and what gas does to the ESP 25 performance and why we want that gas to be able to 101 1 travel up the annulus unimpeded. But anyway gas at the 2 intake of the pump on this slide entitled gas is -- 3 it's sent up the casing and you don't have to have a 4 separator, some of the gas will not go in the pump and 5 it will travel unimpeded on up the casing and up and 6 out of the well, but as the gas gets to be a greater 7 and greater percentage of liquid and gas by volume the 8 greater percentage of the gas, then we add a separator 9 and mechanically separate some of the additional gas 10 and send it up the casing with a separator. But in 11 either case natural separation or putting a separator 12 on the pump, the gas wants to go up the annulus so we 13 have to have the annulus open and few -- and we don't 14 want restrictions to flow as this gas tries to travel 15 up the annulus. It's not that you probably can't 16 operate if there's some restrictions there, but it's 17 just not going to be quite as efficient, but of course 18 if for some reason the annulus got completely blocked 19 off then all the gas has to go through the pump and 20 most likely the ESP wouldn't run in that case. 21 So there's other techniques of separators, 22 special stages for handling gas, but the main point 23 here is that we -- the best situation is the annulus is 24 not restricted and provides an easy path for the 25 separator gas to go up and out of the casing and not 102 0 1 through the pump. 2 This just shows you what gas getting into the 3 pump what happens to..... 4 CHAIR FOERSTER: Effect of free gas on ESP pump 5 stage performance. 6 DR. LEA: Yes, this is talking about the free 7 gas effects on ESP pump stage performance. This is 8 some tests that were done and there's been quite a bit 9 of work on this since then. Some of this was done at 10 (indiscernible) research, some of it was at Amoco and 11 there's been a lot of tests on this since then. So 12 this shows you the effect of free gas on ESP pump stage 13 performance so what we're saying in terms of 14 performance, this line here is a published head curve, 15 a pressure production curve that you would get out of 16 the catalog on an ESP stage. And then as you introduce 17 gas mixed with the liquids what happens is this 18 pressure production or head curve drops down and drops 19 down. Go to the next slide. 20 And this next slide is also entitled effect of 21 free gas on ESP pump stage performance. when we look 22 at the plot it shows even more gas getting in the 23 liquid stream going through the ESP and you can see the 24 head curve has dropped even more. Once this head curve 25 really drops off the (indiscernible) curve, you can't 103 1 really design, you can't really analyze and if it gets 2 really low like these blue points here you won't be 3 able to bring liquid to the surface and you'll 4 essentially be gas locked. So that's why we make such 5 a big deal of keeping the gas out of the ESP because it 6 reduces the performance. 7 And so just to give you a quick look here, 8 here's one of the solutions and this slide's entitled 9 rotary gas separator if needed diverts the gas into 10 annulus before the pump intake. So this is a case 11 where you have a lot of gas coming up from the 12 formation to the pump intake and before we go to the 13 pump intake here's a separator that's installed below 14 the pump intake. And so this is spinning here at 60 15 hertz, about 3,500 RPM, and its centrifuge is the fluid 16 and when you centrifuge the fluid the heavy fluid goes 17 to the outside and the light gas goes to the middle of 18 this separator. And then we have a crossover here that 19 collects that gas in the middle of the separator and 20 sends it into the annulus and then we want it to go on 21 up the annulus unimpeded up and out of the well to our 22 gas lift mandrel and check valve. And then the liquid 23 rich mixture which is centrifuged to the outside, we 24 cross it over and send it on up into the pump. So this 25 does a pretty good job of gas separation when you have 104 0 1 excessive gas that wouldn't normally be able to be 2 handled by the pump. So we knock some additional gas 3 out of the fluid stream and send it on up the casing. 4 So once again it's got to have a nice, unimpeded path 5 to go to the surface even if you have a separator. 6 I don't know maybe you can have one two or 7 three of those rotary separators in tandem, maybe in 8 one unit. Here's a rotary gas separator. The title of 9 this slide, rotary gas separator can be installed as 10 tandem or even triple if the percent of gas is high and 11 it's just showing that you could stack these things 12 back to back for a real gassy environment. I don't 13 think that too many of the wells that are with Hilcorp 14 need these stage separators, but they're available if 15 you knew wells had more gas than anticipated. 16 This slide here is entitled conditions at pump 17 intake can be calculated to estimate the need for gas 18 separator or not. You can put in the flow rate, the 19 GOR and the downhole pressure and temperature and you 20 can calculate how much gas is at the intake of the 21 pump. In this case 60 percent gas is present at the 22 pump intake and we have some industry correlations that 23 tells us that the ESP's not going to work unless you 24 separate it. So we come over here and we put in 80 25 percent separation and then our correlations drop down 105 0 1 below a threshold value that tells us now the ESP can 2 handle the production if we separate 80 percent of that 3 free gas before the pump and send it on up the annulus. 4 And anyways just again alluding to the fact that when 5 we add the separator and knock a lot of this free gas 6 volume back to the annulus before it goes in the pump 7 where does it want to go, it wants to go on up the 8 annulus without restrictions. 9 I probably shouldn't spend much time on this 10 detail side, but this slide, but this slide is ESP 11 performance with gas. And these correlations, the way 12 they work they want to be below one and that's 13 acceptable with gas, if it's above one there's too much 14 gas going in the pump. And so if we look at the curve 15 here, let's just pick out 70 percent of separator 16 efficiency which might be the typical value, we can see 17 here that if we tried to go down to 500 or -- psi or 18 below the value would be above one. So if they had 19 that separation efficiency and that pressure what would 20 happen is that with the same separator efficiency we -- 21 the pump would have to operate at a higher intake 22 pressure to handle that gas. So we don't like to 23 operate at a higher intake pressure because that means 24 less production -- more pressure on the formation and 25 less production comes into the well. So anyway we want 106 0 1 to operate at a low pressure, to do that we have to 2 have high separator efficiency and then that separated 3 gas travels up the annulus. 4 So really just a simple summary, it says ESP 5 and gas summary. To keep gas from the pumps, a flow 6 path up the annulus with minimal restriction up the 7 annulus and out of the well is needed. Gas entering 8 the pump, if it does enter the pump, reduces the 9 performance and can gas lock the pump. And poor pump 10 performance gives higher fluid levels and lower 11 production. And so we get better separation, we get 12 the gas away from the pump and out of the separator if 13 we don't have restrictions in the gas flow coming up 14 the annulus. 15 And now I just have sort of a little -- I'm 16 sure it's not statistically correct, but I just -- I 17 discussed this with some operators, supplies, vendors 18 and just to see what they had to say about packers in 19 onshore wells with ESPs. So I'll have a little 20 discussion of this as well. 21 But anyway here's the first comment. This 22 first essentially operator says never seen a blowout 23 with an ESP with no packer. And here's a pretty strong 24 statement. I know that this particular person here has 25 been around essentially thousands of artificially 107 • 1 lifted wells. I'm opposed to using packers on 2 artificially lifted wells. Packers should be used if 3 there's free gas and a pump. So that's an opinion, I 4 mean, we can make them work, but they're not going to 5 work as well if the flow of gas up the annulus is 6 impeded or not (indiscernible). 7 And then I know who this is, here's a comment I 8 made here while I working at Amoco for 20 years, we had 9 a thousand ESPs and I didn't -- let's see, no packers 10 on onshore wells. I didn't see any or hear of any 11 leakages or discharge events with ESPs with no packers. 12 So and quite a few of our wells were located in Canada 13 and Northern Alberta so you might say those are 14 conditions that you might that would be similar to 15 what's going on here in Alaska. I want to say maybe 16 even 20 percent of those Amoco ESPs were operating in 17 Canada and quite a few of them in Northern Alberta. 18 Here's another comment, hadn't seen wells with 19 packers onshore and no blowouts or discharge events 20 without -- operating with no packers. 21 And just a few more comments. Essentially 22 they're all saying about the same thing, that they 23 don't see packers onshore and they hadn't seen any 24 discharge or blowout events in those particular 25 situations. So that's just a handful of comments 108 I there, I'm not saying that's statistically correct or 2 anything like that, but that has to be several thousand 3 ESPs that these various individuals have looked at over 4 the years. So I just thought I'd bring that to your 5 attention to see what the general consensus is in the 6 industry for onshore wells with or without packers. 7 So anyway I kind of traveled through that 8 pretty quickly so maybe you have some questions or 9 whatever. 10 CHAIR FOERSTER: Thank you. Commissioner 11 Seamount, do you have questions? 12 COMMISSIONER SEAMOUNT: I have none. Thank 13 you, Dr. Lea. 14 CHAIR FOERSTER: I have a few. I'll ask them 15 in the order that I wrote them down just because 16 that'll be easiest for me. Do you know why the state 17 of Alaska requires two component barriers to flow in 18 well construction? 19 DR. LEA: Say that again, Madam Chair. 20 CHAIR FOERSTER: Do you know why the state of 21 Alaska and several other regulatory bodies require two 22 competent barriers to flow in well construction? 23 DR. LEA: Well, just to -- you're saying why 24 would you require a packer is that what you're saying? 25 CHAIR FOERSTER: No, I'm saying why do we 109 1 require two competent barriers to flow when we..... 2 DR. LEA: Oh, you mean the -- the double 3 annulus, the inner and outer annulus that you..... 4 CHAIR FOERSTER: Two competent barriers to 5 flow. 6 DR. LEA: Okay. 7 CHAIR FOERSTER: However we get them. 8 DR. LEA: Well, I don't know that much about 9 the state of Alaska regulations and to be honest I'm 10 not so much a completions person as I am artificial 11 lift and production so I don't know, maybe I'd let 12 somebody else handle this. 13 CHAIR FOERSTER: Okay. I think we'll..... 14 DR. LEA: Would you want to say something on 15 that, why they require the two barriers? 16 Oh, I can answer that. 17 CHAIR FOERSTER: Introduce yourself. 18 DR. LEA: Yeah, let me defer to somebody else 19 because I might get myself into trouble trying to 20 answer..... 21 CHAIR FOERSTER: Okay. 22 DR. LEA: .....a completion question. 23 CHAIR FOERSTER: Okay. 24 WYATT RIVARD 25 previously sworn, called as a witness on behalf of 110 • • 1 Hilcorp Alaska, testified as follows on: 2 DIRECT EXAMINATION 3 MR. RIVARD: Good morning. My name's Wyatt 4 Rivard, well integrity engineer for the North Slope 5 assets. 6 CHAIR FOERSTER: Okay. 7 MR. RIVARD: Would you like me to go into..... 8 CHAIR FOERSTER: Yes, I would like you..... 9 MR. RIVARD: .....background? I've been 10 working for Hilcorp for about a year now. I came over 11 with the acquisition of the North Slope assets. Prior 12 to that I worked for Schlumberger as a wireline field 13 engineer doing downhole diagnostics and integrity 14 troubleshooting. And then before that I went to school 15 at Embry -Riddle Aeronautical University in Prescott, 16 Arizona for a bachelor's in air space engineering. 17 That's my background. 18 CHAIR FOERSTER: Okay. Did you want to answer 19 the question? 20 MR. RIVARD: Yes. So as far as the two 21 barriers is standard industry practice. 22 CHAIR FOERSTER: Standard industry practice. 23 Why is that? 24 MR. RIVARD: It's..... 25 CHAIR FOERSTER: And we've heard that packers III 1 are awful and packers are part of two competent 2 barriers so why..... 3 MR. RIVARD: There's..... 4 CHAIR FOERSTER: .....why do we require two 5 competent barriers? 6 MR. RIVARD: .....multiple methods that achieve 7 two competent barriers, but typically tubing isolating 8 the production casing is the most common. I believe 9 it's API standard, I -- I couldn't reference the exact 10 documents, but it is a standard, it provides protection 11 to the production casing, it provides you a diagnostic 12 method for if there's a failure of one of those 13 barriers you typically have testing methods to 14 determine that prior to a leak or some sort of event. 15 CHAIR FOERSTER: So what's the worse thing that 16 can happen if you don't have two competent barriers to 17 flow in a well? 18 MR. RIVARD: Typically the worse thing that 19 would happen is you have a failure in your primary 20 barrier that results in a flow to surface. 21 CHAIR FOERSTER: A loss of well control? 22 MR. RIVARD: Yes. 23 CHAIR FOERSTER: And there's -- you know, there 24 are always these little buzz phrases that mean a lot to 25 people and, you know, who have been around and they 112 1 don't mean anything to those who don't, so does the 2 buzz phrase A22 have any meaning to you? 3 MR. RIVARD: A22. Yes. 4 CHAIR FOERSTER: Obviously not. 5 MR. RIVARD: Sorry. I believe that was a well 6 on the North Slope that had an issue with a small 7 annular leak, the well was brought on, over pressured 8 the surface casing resulted in a -- basically a release 9 in the wellhouse that resulted in an injury to an 10 operator. 11 CHAIR FOERSTER: Okay. Do you know whether the 12 -- do you mean did he have a hangnail or a broken 13 finger..... 14 MR. RIVARD: I know it was a significant 15 injury, I couldn't -- I couldn't..... 16 CHAIR FOERSTER: It was a catastrophic event. 17 And would you say that well had two competent barriers 18 to prevent flow to the surface? 19 MR. RIVARD: I -- I don't know that I could 20 speak to the competency of the barriers, I'm not 21 familiar with the diagnostic history on it. I know 22 that there were multiple events related to that, 23 thermal expansion was a large factor in that. 24 CHAIR FOERSTER: If you had two competent 25 barriers could it have had that catastrophic event? 113 1 MR. RIVARD: You could have a well that could 2 have that catastrophic event with a competent barrier 3 if it was not managed correctly as far as thermal 4 expansion on a..... 5 CHAIR FOERSTER: So..... 6 MR. RIVARD: .....on the annulus. 7 CHAIR FOERSTER: .....maybe the operator 8 committed an operator error? 9 MR. RIVARD: Possibly. Again..... 10 CHAIR FOERSTER: Okay. I don't think that was 11 the finding. 12 MR. RIVARD: Okay. Sorry. 13 CHAIR FOERSTER: In fact, I know that was not 14 the finding. 15 MR. RIVARD: Okay. 16 CHAIR FOERSTER: So and that's kind of a poster 17 child for Alaska, two competent barriers, so I'd get 18 familiar with that if I were you and you can stay in 19 Alaska. 20 MR. RIVARD: Will do. 21 CHAIR FOERSTER: Okay. So you say there are 22 other ways to have two competent barriers. If -- in 23 these type of completions how would you have two 24 competent barriers if you don't have a packer? 25 MR. RIVARD: So we would still have a -- we 114 1 would have our production casing is still our primary 2 in this instance and then we would have a second string 3 of surface casing that provides a second barrier to 4 surface as well as a monitorable annulus in the form of 5 the OA that should typically just be an applied 6 pressure that we would see there and if we see a 7 significant change in pressurization it indicates 8 communication through that production casing then we 9 would follow further diagnostics. 10 CHAIR FOERSTER: Okay. Okay. I think that's 11 the only well construction question I have at this 12 time. 13 So, Dr. Lea..... 14 DR. LEA: Yes. 15 CHAIR FOERSTER: .....you listed a lot of 16 concerns with wells. Are those concerns all the same 17 for wells that can flow to the surface and wells that 18 cannot flow to the surface or are the wells greater -- 19 are the concerns greater in one type of well versus 20 another? 21 DR. LEA: Well, if you're saying that you would 22 have more of a risk if the well had a lot of pressure 23 and would flow at a high rate to the surface I would 24 agree with you and I think one of the reasons that 25 those thousands of wells covered by those comments is 115 1 that probably they were wells that would flow at a very 2 low rate or not generate very much pressure because we 3 are talking about artificially lifted wells that won't 4 flow at a high rate on their own. So the more tendency 5 the well has to flow at a large -- high rate the more 6 that you would be concerned, but on the other hand it 7 would be a flowing well so once you get the 8 artificially lifted wells we're talking about wells 9 that would flow at a low rate or no rate at all and 10 that the shut in fluid level wouldn't reach the surface 11 when you shut the well in. 12 CHAIR FOERSTER: Do you know how much gas is in 13 the production at Milne? 14 DR. LEA: well, a lot of them I looked at were 15 in the range of two to 300 mcfd total coming out of the 16 wells. It was enough to require a separator on several 17 wells. It's not just the GOR, the GLR, it also has to 18 do with the water cut and the intake pressure, the 19 lower the intake pressure the greater percent of the 20 production that the gas occupies and the -- and also 21 the -- if it's a GOR it depends on the watercut. So 22 but anyway that's roughly what I saw on quite a few 23 wells. 24 CHAIR FOERSTER: Okay. So in general why would 25 you choose ESP over gas lift? 116 1 DR. LEA: Well, there's several reasons, but 2 the biggest reason is that gas lift does not draw the 3 well down to as low a pressure as a good operated ESP 4 will. And so if I'm drawing the well down to the 300 5 psi for the ESP and I put gas lift on it, I'm just 6 making up some numbers, it might only bring it down to 7 500 psi and so you..... 8 CHAIR FOERSTER: So you get more rate..... 9 DR. LEA: You get more rate. 10 CHAIR FOERSTER: .....if you draw down the 11 pressure? 12 DR. LEA: Now of course if you can't control 13 the gas separation and a lot of gas goes into the pump 14 the pump performance is degraded and then you get more 15 of an even shake between gas lift and ESP, but 16 typically with the gas separator that's operating like 17 it should and you can get the gas out of the well up 18 the annulus, you can get more rate with an ESP so 19 that's one reason you would go with an ESP instead of a 20 gas lift. Now sometimes if you have excessive sand 21 production and I don't think we do have excessive sand, 22 we have sand, but it's being managed correctly, but if 23 you have so much gas that you just can't keep the pumps 24 running and they're sticking and they're failing and 25 they're wearing out, you know, maybe gas lift would be 117 1 better because the sand comes right on up the tubing 2 and doesn't leave the gas lift valves and so that's the 3 reason there that gas lift might be applied if you had 4 a really large amount of sand along with your 5 production. 6 CHAIR FOERSTER: Do gas lift completions 7 require as many remedial workovers as ESP completions? 8 DR. LEA: Well, one of the reasons that gas 9 lift is used so much offshore for instance is that you 10 can change the valves without tripping the tubing and 11 so that's a big, big reason why you see gas lift 12 offshore is that we don't have to be tripping the 13 tubing which is very, very expensive in an offshore 14 environment. So ESPs probably fail more frequently 15 with more expensive failures than gas lift would which 16 it's not as critical, I mean, you can have a problem 17 with a gas lift well and maybe instead of injecting on 18 the bottom valve it could make it just injecting in the 19 valve above that or maybe you have a valve that's 20 leaking a little bit, but you're still producing. But 21 in ESP you plug up one study it quits running, you 22 short out the cable it quit running. There's so many 23 things that can totally take your production to zero 24 whereas gas lift it might develop some problems and 25 maybe you can work those out with time when the rig 118 1 gets there or whatever's required, or the wireline, but 2 it doesn't usually go to zero on the production like an 3 ESP can. So it is a little more critical you might say 4 to take really close attention to details and try to 5 eliminate these risk factors. 6 CHAIR FOERSTER: So there's tradeoffs between 7 rate and operating cost in the decision of whether 8 you'd use gas lift versus ESP? 9 DR. LEA: Well, there's a good overlap in rate 10 between gas lift and ESP, but given a -- for -- but for 11 a given well you're able to lower the pressure more on 12 a well with a good operated -- if an ESP well with no 13 problems you're able to lower the pressure more and get 14 more rate. There's a big range of rates, how many 15 barrels per day for so many feet, but for a particular 16 given well I'll be able to draw the pressure down lower 17 with an ESP that I will be able to do with gas lift. 18 It just -- the bubbles rising up through the liquid 19 don't draw the pressure down as much as the centrifugal 20 stages are able to do with the motor attached. 21 CHAIR FOERSTER: Okay. That's all the 22 questions I have at this time, but please stick around 23 and..... 24 DR. LEA: Of course. 25 CHAIR FOERSTER: .....I may ask you back up for 119 0 1 another set of questions. 2 It's 15 minutes until noon. If you have -- how 3 many witnesses do you have? 4 MR. BOND: We have one more witness. 5 CHAIR FOERSTER: And how long do you think his 6 testimony will take? 7 MR. BOND: (Indiscernible - away from 8 microphone)..... 9 CHAIR FOERSTER: Okay. So that -- your choice 10 is we can either recess before or after his testimony, 11 but we will recess so that we can meet with staff and 12 they can give us all the intelligent questions that we 13 weren't smart enough to think to ask. 14 MR. BOND: (Indiscernible - away from 15 microphone)..... 16 CHAIR FOERSTER: Okay. Well, then let's 17 proceed. 18 MR. BOND: Jeff Dwiggins. 19 CHAIR FOERSTER: Okay. So, Mr. Dwiggins, 20 we..... 21 MR. DWIGGINS: Yes, ma'am. 22 CHAIR FOERSTER: .....need you to introduce 23 yourself, who you represent, the expert stuff and 24 please..... 25 MR. DWIGGINS: Refer to the slides. 120 0 • 1 CHAIR FOERSTER: .....refer to the -- you know, 2 in a way..... 3 MR. DWIGGINS: Yes, ma'am. 4 CHAIR FOERSTER: .....that 10 years from now -- 5 you know, if -- for future reference the easiest thing 6 is to number the slides and then rather than have to 7 read a 17 word title, slide number 1, you know..... 8 MR. DWIGGINS: Okay. Yes, ma'am. 9 CHAIR FOERSTER: .....just for future 10 reference. But go ahead. 11 MR. DWIGGINS: Thank you. 12 JEFF DWIGGINS 13 previously sworn, called as a witness on behalf of 14 Hilcorp Alaska testified as follows on: 15 DIRECT EXAMINATION 16 MR. DWIGGINS: I'm going to talk some about 17 discussion on ESPs and packers as have other. 18 CHAIR FOERSTER: My name is Jeff Dwiggins, I 19 work..... 20 MR. DWIGGINS: Yeah, I'm going to that right 21 now, ma'am. 22 CHAIR FOERSTER: Okay. 23 MR. DWIGGINS: Next slide, please. So I'll go 24 right through this list for you. 25 I'm Jeff Dwiggins, the owner of Dwiggins 121 1 Consulting and Artificial Lift Solutions out of 2 Singapore. I've been -- I'll go down this kind of in 3 reverse order of my career, but I've been the 4 continuing education chairman at the ESP workshop for 5 about eight years. I'm actually passing that on to 6 bring in some new younger generation to try to train 7 them up. Prior to that I was vice president of 8 international operations for Middle East and Asia 9 Pacific, for Wood Group ESP and prior to that I was 10 vice president of engineering for Wood Group ESP. And 11 then prior -- I was with REDA Pump Company for many 12 years, I held various roles there with the last couple 13 being divisional manager for the eastern hemisphere for 14 projects as well as being the director of engineering 15 for Lawrence Cable, their manufacturing facility in 16 Lawrence, Kansas. I hold a bachelor of science in 17 mechanical engineering from the University of Oklahoma 18 and I've worked literally all over the world in 50, 60 19 different countries around ESPs, can't say that I've 20 seen it all, but I've certainly been around a great 21 number of ESPs in my career, offshore, onshore, harsh 22 environments and environments that are closer to 23 reality I guess of our world. Next slide. 24 So the topics..... 25 CHAIR FOERSTER: Would you like to be..... 122 0 1 MR. DWIGGINS: .....this is slide number 2. 2 CHAIR FOERSTER: .....would you like to be 3 recognized as an expert? 4 MR. DWIGGINS: Yes, ma'am. I consider myself 5 an expert with regards to electric submersible pumps 6 and artificial lift. 7 CHAIR FOERSTER: Okay. Commissioner Seamount, 8 do you have any questions? 9 COMMISSIONER SEAMOUNT: Do you live in 10 Singapore? 11 MR. DWIGGINS: I have an office and an address 12 there and I hold a work permit in Singapore, sir. 13 COMMISSIONER SEAMOUNT: Okay. But you don't 14 live in Singapore? 15 MR. DWIGGINS: Well, my wife thinks I probably 16 live there as much as I'm gone, sir. 17 COMMISSIONER SEAMOUNT: I have no..... 18 MR. DWIGGINS: But, no, my residence -- I 19 actually have two listed residences, one being Edmond, 20 Oklahoma and the other being Singapore. 21 COMMISSIONER SEAMOUNT: Okay. I have no 22 further questions and no objections to Mr. Dwiggins 23 being considered an ESP expert. 24 CHAIR FOERSTER: I don't have any questions and 25 I don't have any objections either, but I do want the 123 1 record to reflect that I said nothing nasty about 2 either the Aggie or the OU grad. 3 MR. DWIGGINS: I was debating, ma'am, whether 4 to say boomer sooner or not. 5 CHAIR FOERSTER: Well, you made a good choice 6 in not saying that. 7 MR. DWIGGINS: Thank you, ma'am. 8 CHAIR FOERSTER: All right. You may proceed. 9 MR. DWIGGINS: Thank you very much. My third 10 slide titled topics is -- this is just the list of 11 topics that I will attempt to briefly review and in 12 areas where it feels like maybe some of this has been 13 reviewed I'll scan over it a little bit more briefly. 14 We'll talk about ESP with packers and we'll break this 15 up into various logical -- what I consider to be 16 logical sequences. Next slide. 17 My fourth slide, considerations for wells with 18 ESPs and packers. So the breaks that I will attempt to 19 achieve will be pre -rig operations, rig operations and 20 then post rig operating the ESP with the packer system. 21 My next slide which is the fifth slide, let me 22 just briefly describe what a generic packer system 23 would like that we would deploy in an ESP world 24 anywhere around the world if we deployed with a packer. 25 First of all over on the right in the blue portion is 124 1 the packer itself with various sealing elements. And 2 there are a sundry different types of manufacturers 3 that make these as Dr. Lea pointed out. So they might 4 look a little different, but they all achieve the same 5 basic task. And we must get that cable through, we 6 must penetrate that packer in a fashion that we can get 7 electricity down to the ESP and so -- and achieve the 8 sealing capability and we do that with a system called 9 a packer penetrator system. And the most generic of 10 types is you would have an upper pigtail which is the 11 cable running from the surface and then we would 12 penetrate the packer so that's the packer penetrator 13 itself and then we would reconnect that at the lower 14 portion of the cable, to go on -- to carry on to the 15 ESP motor downhole. It is very typical that most 16 packers would have two control lines that would run 17 through for various things that might be down below 18 chemical treatments and various other tools that we may 19 need to access so it's not at all uncommon to see a 20 packer penetrate -- a packer system with two control 21 lines running through it. You may or may not need 22 them, but that's the most common. And then of course 23 the production tubing which is where we move the fluids 24 back up to surface. Next slide. 25 The next slide, shallow set and deep set 125 1 definition is -- in our world that we typically deal 2 with or talk with, a deep set packer is anything that's 3 within 100 to 400 feet above the ESP itself, okay, so 4 it's deep in the wellbore. And what would set that 5 apart is we would try not to break that electrical 6 connection until we reach the packer itself. Okay. So 7 we'd run a motor lead flat all the way up to the bottom 8 of that packer. A shallow set packer, we go to the 9 other end of the wellbore, near the wellhead, and we 10 lower that down 400 to 1,000 feet is the typical ranges 11 that we would see. And typically there are two types 12 of each of those packers. The isolation packer as I 13 call it and the vented or in this -- or we could say 14 vented or non -vented packer. And in the ESP world it's 15 more common to see a vented packer, but I've seen non- 16 vented packers as well. Next slide. 17 This slide I've titled general ESP 18 applications. And so the vast -- I'll walk through 19 these briefly. The vast majority of ESP applications 20 around the world that I deal with operate without 21 packers. And this includes onshore and offshore 22 environments. Of the places that I deal with packered 23 systems I can't think of any that are not offshore. 24 Now that's not to say they don't exist, I'm just saying 25 the ones that I deal with. So when we have an ESP in 126 1 the well we must produce whatever shows up at the pump 2 intake, gas, oil, water and solids or any other debris 3 that might be in the fluid stream. And we must bring 4 that through the pump. If it's a deep set packer then 5 if we're venting that packer then some of those 6 entrained items as they're being vented could vent 7 above the packer and logically gravity taking place 8 settle out on top of that packer as has been discussed. 9 Gas -- as Dr. Lea pointed out and I'll reiterate here, 10 gas production significantly inhibits the efficiency of 11 a pump. And that inefficiency is manifested in the 12 form of heat. As engineers we're used to seeing it 13 that way. So and ESPs don't like additional heat. And 14 so that's one of the drawbacks that we push away from. 15 The addition of a non -vented packer which says I have 16 no choice, gas, oil, water, everything must now go 17 through the ESP, I can't vent, I can't get anywhere 18 with the gas in my experience greatly jeopardizes the 19 ESP system. You would logically expect a stepdown in 20 run life of an ESP system. And I have a photo that I 21 will show you in just a few moments at the end of my 22 presentation of a system that I just literally added 23 the photo yesterday from offshore Gulf of Thailand. 24 And when deep set packers are utilized, the gas vent 25 valve if it's deep set then we -- it is a -- it's a 127 1 fail safe, closed mechanism. So it says we have 2 hydraulic pressure to keep it open. And that being the 3 case then we would have to have higher operating 4 pressures at the surface to maintain that gas vent 5 valve being open. Next slide. 6 This slide I've titled pre -rig operations. 7 These are some of the things that we must think about 8 if we operate a well with a packer, okay, and I'm of 9 the type of engineer that I think well, I need to plan 10 for the worst, hope for the best, but let's plan for 11 the worst in case it shows up. And so we must think 12 about killing the well and it can become as Paul has 13 already discussed a very challenging operation killing 14 it through a gas vent valve. They -- packers -- I 15 don't -- I said typically, but really, in fact, it's 16 factually they're going to restrict circulation. And 17 the circulation concerns that I have when I look at a 18 packered well is do I have debris on top of the packer, 19 is there debris in the tubing which means I can't get 20 down the tubing, I may have to now bail the tubing, all 21 right, and when I unseat that packer, when I let go of 22 it, is there a gas bubble trapped there that I'm going 23 to have to handle. And my reaction time is going to be 24 virtually nil, okay, I have to handle it right now. So 25 you must consider the alternatives and those 128 1 alternatives would include punching below the tubing, 2 establishing circulation and having the wellbore open 3 longer because I've got to wash and bail down now. And 4 for me of everything that I do particularly in 5 sensitive areas not that any place is insensitive, but 6 it's -- in west Texas where we work things seem to 7 happen a little easier, the rigs move faster and all 8 that, but if I've got to have the wellbore open longer, 9 I'm increasing my risk significantly. I prefer to get 10 on the well and get off the well and get it bottled 11 back up, get the lockdown screws run in on the tubing 12 hanger and now I've got it and I can hold it. Okay. 13 This next slide, rig operation. I tell all of 14 my clients and I've worked strictly with operators 15 around the world and I work within a sundry -- a large 16 list of them and I always tell them let's keep it as 17 simple as we logically and safely can, let's not add 18 any jewelry in the hole that's not absolutely 19 necessary. So the more items I put in the wellbore the 20 more my risk goes up, the more opportunities I have to 21 make a mistake. The wellbore with a packer -- I think 22 it is fair to say that with a packer the well is 23 absolutely going to be open longer. we have more 24 jewelry to handle, we got more connections to make, we 25 got more things to do, we got more human hands 129 1 intervening into that operation. A packer penetrator's 2 required and I will -- may I bring this up, ma'am? 3 CHAIR FOERSTER: Sure. 4 MR. DWIGGINS: So this is one and I don't 5 recall, this is old, but this is one -- it is dirty so 6 I'll set it front of you. This is one that burned that 7 we pulled, you can see here the burn occurred right at 8 the base, right. And I would like to say this is the 9 only one I've ever seen, but it is not. Okay. The 10 problem is you create an arc flash or an electrical arc 11 and it just immediately goes (indiscernible). This may 12 operate in a steady state condition for a week or it 13 may last a year, but because of -- what happens is when 14 we make this connection, this is just one lead I'll 15 show you, but this is a typical electrical connection. 16 So when I compress (indiscernible) we got an ESP cable 17 running in, we got ESP cable running out. This becomes 18 a high resistance area which means I'm going to 19 generate more heat. And to insulate that because now 20 we have to strip back to the cable, the way that we 21 insulate it is we use two forms of tape, a high temp 22 tape which is electrical resistance and high modulus 23 tape which is a sealing tape. All right. So we add 24 all of that in and the nature of human beings is 25 occasionally we're going to make a mistake, that's the 130 • • 1 reason people try to automate and try to take human 2 hands out. 3 Releasing the packer, I'll carry on with my 4 slide. Releasing the packer can be problematic. Now I 5 will be honest with you, I've worked in a lot of very, 6 very cold environments, I've not tried to release a 7 packer that I'm aware of or been party to that in a 8 super cold with permafrost like they experience here, 9 but I would only anticipate that it would get more 10 difficult if it's a high set or shallow set packer. 11 And of course I've got a photo I'll show you at the 12 very end of the pulling operations. And all you need 13 is a control line to come loose or the cable to slip 14 and now I start balling it and I can get stuck in hole. 15 And my experience is if you get stuck with a packer 16 coming out the chances of trashing the wellbore or 17 losing the wellbore are exasperated because you can be 18 successful fishing ESP cable, if you try to fish one 19 with a packer that's stuck it becomes very problematic. 20 Next slide. 21 And post rig operations. So I'm not going to 22 hit this very hard because Dr. Lea's already approached 23 it, but the bottom line is solids build up, all of 24 these things can add to some negatives for packers. 25 It's not to say it can't be done, but of the wells that 131 1 I've worked on even a large number of offshore wells we 2 don't run packers because we need to access that 3 annulus as has already been discussed. Next slide. 4 There are -- on this slide, the discussion of 5 the packer penetrator, there's two things. There's 6 multiple types that are available, some of them will be 7 continuous that will feed all the way up through the 8 system and then will make a connection, but the bottom 9 line is we're going to add a minimum, no matter how we 10 shape it up, we add a minimum of two more connections 11 that must be addressed. And my experience is it -- 12 particularly in haz -- in difficult areas, cold, 13 extreme heat and things of that nature, you're adding a 14 minimum of four to six hours just to complete that 15 connection. And that doesn't count into the fact that 16 you got to handle the packer in that additional time. 17 Next slide. 18 Now this is a video and you can wink at me if 19 you get bored and I'll slide right through it, okay, 20 but the -- it's used with permission from Taurus 21 Engineering which is one of the suppliers that I use 22 around the world. Okay. And this -- I'm not trying to 23 make you a packer penetrator expert, all I'm trying to 24 show to you and demonstrate to you here is the 25 complexity of making this connection. you must -- in 132 1 this case they're going to do a horizontal splice, many 2 packers requires you to do the splice in the vertical 3 which makes it even more difficult. Great number of 4 parts that have to be put on and sealing and even 5 though they call this a spliceless it's not because 6 they have to make this field detachable connection 7 right here. And then measurement is absolutely 8 critical. If any of these measurements are wrong you 9 get to start all over, all right, and -- when you're 10 making it up. So and in some cases depending upon 11 where -- how they've entered this with the deep set, it 12 may mean you have to lay the packer back down, recut 13 and retrim and start over. So here again like I said 14 I'm not --Taurus was kind enough to -- when I asked 15 them to show this that they said sure, but you can see 16 the complexity that goes into one of these parts. 17 Okay. Go ahead to the next slide. 18 Okay. So the addition of the gas vent valve, 19 so packers with gas vent valves. The addition of the 20 gas vent valve does allow us some means of expelling 21 the gas which is critical to ESP operations where we 22 have gas void fraction present. The failure of a gas 23 vent valve and I have had this happen offshore China, 24 where the failure of the gas vent valve meant pulling 25 the well because we had to get -- and because of the 133 1 nature once you unseat the packer then everything comes 2 out of the hole, that's just the nature of the beast. 3 Next slide. 4 So in summary, summary of issues, I've got two 5 of these slides, so the first of summary of issues with 6 ESP packers is in my view I will -- I personally cringe 7 when somebody tells me you've got to run a packer with 8 ESP because I know life has just gotten a lot more 9 difficult. It increases the risk of an ESP failure, 10 the -- increases the opportunity to get stuck. We've 11 already talked about solids, we've talked about the 12 venting and non -venting of gas. The last two bullets 13 on this slide I think are the ones that are most 14 important to me and that is less ESP run life equals 15 increased number of well interventions which says I've 16 got to open the wellbore more frequently which means I 17 expose the environment around me to an open wellbore 18 more frequently. And if I -- from the standpoint if I 19 felt like the packer added value from the standpoint of 20 integrity then I would say well, then that's the right 21 thing to do, but from the standpoint of well, I'm not 22 having that problem, why should I introduce the 23 problem, that's where I lean towards on -- lean to on 24 packers. 25 Next slide which is the last of my summary 134 1 slides, forcing higher gas void fraction through the 2 ESP increases inefficiency which increases heat. 3 Increase of heat -- if I may. Increasing heat can lead 4 -- this is a piece of a motor winding so we have a lot 5 of copper in these motors downhole. So anytime I 6 increase heat I increase the opportunity for an 7 electrical burn to occur in these windings which have 8 as you can see a lot of wire involved into them. So I 9 try to -- one of the things that we monitor most 10 frequently with ESPs is our motor temperature. We need 11 it -- we want it down as low as we can get it 12 reasonably, we don't want to do anything to add heat to 13 the system. So my experience is -- and this is just my 14 experience, this is not statistical, but I would say 15 that less than 1 percent of the thousands of ESPs I've 16 been around have packers in them. Now I have worked 17 around them and particularly in the North Sea. I've 18 never seen a water source well with a packer and I 19 cannot recall seeing an onshore well. Now that's to 20 say that it doesn't exist because I'm sure it does, but 21 I have not -- with the thousands of ESPs I've worked 22 around I haven't seen them. And we've already -- the 23 abil -- we've talked about it and I won't revisit it, 24 but the batch treatment issue for ESP down the annulus 25 is a -- is a valuable tool. All right. 135 1 And so this is the slide that I was referring 2 to earlier. This is only four days old. This is a 3 splice that is directly above a packer system and that 4 we pulled -- my company has a few engineers, we're not 5 a very big company, but we are the old gray beards as 6 we like to call ourselves, so we go out to the field. 7 So one of my old gray beards that I work with was out 8 -- he sent me this picture and so we literally -- this 9 was a splice that was made that failed on us. And I 10 can tell you that the cost of this is millions of 11 dollars literally and it -- I don't know that it added 12 anything to the integrity because now we had to -- 13 because this is a hydraulic workover system in this 14 particular case, we're on the well again that we didn't 15 think we'd be on for two more years. Next slide. 16 And of course we were talking a little bit 17 about solids. And so..... 18 CHAIR FOERSTER: You're showing photos now, so 19 you're in the photo section? 20 MR. DWIGGINS: Yes, ma'am. I apologize. 21 CHAIR FOERSTER: That's okay. You're getting 22 carried away with yourself. 23 MR. DWIGGINS: I'll walk through the photos and 24 I'm just going to briefly go through a couple of these. 25 CHAIR FOERSTER: Okay. 136 1 MR. DWIGGINS: So increased starts and stops. 2 This is a top of a pump where sand has fallen back 3 through the tubing and much like Hilcorp's it's a fine 4 grain sand. Now this is not a Hilcorp pump, let me be 5 clear, but you can see how quickly it can pack off. So 6 it -- there is no way that we could have possibly 7 circulated through this pump to circulate out, it was 8 packed solid. And what happens is increased heat with 9 increased gas void fraction. A lot of these bearing 10 systems -- one of the advantages of technology is the 11 development of ceramics. And so these bearing systems 12 now have turned to tungsten carbide or silicon carbide 13 and here's a case of one on the left or on your right 14 that shows tungsten carbide that's got hot and broke. 15 Okay. They're great -- they are fabulous deterrents to 16 sand and regular wear, but they do not tolerate heat at 17 all, they're not generous at all when it comes to one 18 of those. 19 And this next slide called sand in an ESP pump 20 is just showing that we broke a shaft and you can see 21 how the sand can pack in quite quickly, you know, in a 22 fall back. And the one on the right, and this will be 23 my last slide. The one on the right shows you what 24 things look like. If you will look here, obviously you 25 can see the ESP cable that has crammed into the 137 1 wellbore, but what you probably have to look a little 2 closer for you can see here the control line. Now we 3 were fortunate on this one, we got it out of the well. 4 CHAIR FOERSTER: Was there a packer in that 5 well? 6 MR. DWIGGINS: No, ma'am, that's where I 7 headed. And, no, ma'am, not at all. This one had no 8 packer. I'm confident had there been a packer -- this 9 particular well's in the western desert of Egypt. I'm 10 confident had there been a packer we would have never 11 got this out, okay, but that's my opinion and not fact. 12 Okay. 13 And that concludes my presentation, ma'am. 14 CHAIR FOERSTER: Okay. I have a few questions 15 before we recess that -- do you have any questions, 16 Commissioner Seamount? 17 COMMISSIONER SEAMOUNT: No, I guess not. Thank 18 you, Mr. Dwiggins. But I do have a question that -- 19 Mr. Bond, are you going to summarize after this? 20 MR. BOND: Yeah, but perhaps (indiscernible - 21 away from microphone)..... 22 COMMISSIONER SEAMOUNT: Okay. 23 CHAIR FOERSTER: I just have one comment and 24 one question. You know, I used to keep my souvenirs 25 from my trips to the field in my office when I worked 138 1 years ago in Houston. And my boss came in one day and 2 said this isn't a blank, blank oil field museum, it all 3 has to go. So I'm glad you -- you run your own company 4 so you can keep your oil field museum. 5 MR. DWIGGINS: Yes, ma'am. 6 COMMISSIONER SEAMOUNT: Well, we got a bunch 7 around here. 8 MR. DWIGGINS: Yes, sir. 9 CHAIR FOERSTER: Yeah, I know. I know. I like 10 that. I like oil field museums. 11 So why are packers used offshore? 12 MR. DWIGGINS: There's only two reasons that I 13 can think of. One is back side isolation and well 14 integrity. 15 CHAIR FOERSTER: Okay. So those aren't issues 16 onshore? 17 MR. DWIGGINS: The -- in my opinion they're 18 always at issue, ma'am. 19 CHAIR FOERSTER: Okay. So why are packers used 20 offshore? 21 MR. DWIGGINS: Because accessing a failed 22 system offshore becomes much more problematic. For 23 example, I mean, they're -- we're -- everybody's 24 probably aware of Piper Alpha and even though that 25 wasn't a -- they had a unmitigated release of gas and 139 1 the catastrophic damage that occurred and loss of life. 2 So the bottom line is offshore if there is a 3 catastrophic event accessing that wellbore becomes -- 4 can be almost impossible. And the proximity of 5 adjacent wells -- you know, in the North Sea we call 6 them egg crates, but, you know, there's rows and rows. 7 So even though they venture out in a spider diagram the 8 wells are adjacent to each other, very close proximity 9 so there's a knock -on -effect of one wellbore having a 10 problem through the adjacent wellbores. 11 CHAIR FOERSTER: Okay. So you're saying that 12 if there is a catastrophic event it's hard to get to 13 offshore. So having a packer makes it easier to get 14 to? 15 MR. DWIGGINS: No, that's not what I'm saying. 16 CHAIR FOERSTER: No, I know it's not. What 17 you're saying is the packer's there because it helps 18 prevent catastrophic events? 19 MR. DWIGGINS: It helps isolate that back side, 20 it does not mean that the packer won't release in my 21 opinion. 22 CHAIR FOERSTER: Right. 23 MR. DWIGGINS: Yeah. 24 CHAIR FOERSTER: But if the packer releases 25 it's the same as not having a packer? 140 1 MR. DWIGGINS: Agree. 2 CHAIR FOERSTER: So a packer is there -- a 3 packer is in a well because it helps with well 4 integrity? 5 MR. DWIGGINS: Well, I don't know that I share 6 that, but, yeah, I see your point. 7 CHAIR FOERSTER: Okay. All right. I think at 8 this time we'll take a recess. Do you want to recess 9 for lunch or do you want to recess for 20 minutes and 10 come back and grind through this, do you have a 11 preference? 12 COMMISSIONER SEAMOUNT: It's up to you. 13 CHAIR FOERSTER: Does Hilcorp have a 14 preference? 15 MR. BOND: We're at your pleasure. 16 CHAIR FOERSTER: Okay. Why don't we take a 20 17 minutes recess of 17 minute recess, come back as close 18 to 12:30 as we can and then see if we can wrap up. 19 (Off record) 20 (On record) 21 CHAIR FOERSTER: We're going to go back on the 22 record at 12:31. And as it turns out we only have two 23 questions and you -all can decide who can answer them 24 because they're closely related. So the first question 25 will -- whoever answers the first one will probably be 141 1 able to answer the second one. 2 How many of your ESP completions at Milne have 3 packers? And whoever answers it come up, say your name 4 and give the answer. 5 MR. RIVARD: My name is Wyatt Rivard again, 6 well integrity engineer for North Slope. And we have 7 111 ESP wells at Milne Point, 109 are packerless. 8 CHAIR FOERSTER: So two of them have packers? 9 MR. RIVARD: Yes. 10 CHAIR FOERSTER: Are they Kuparuk or Schrader? 11 MR. RIVARD: We have a water source well 12 at..... 13 CHAIR FOERSTER: Okay. 14 MR. RIVARD: .....at Prince Creek and we have a 15 Kuparuk well with a packer at 600 feet roughly. And 16 neither of those is active. 17 CHAIR FOERSTER: Neither of those is what? 18 MR. RIVARD: Active. 19 CHAIR FOERSTER: Oh, those are shut in wells? 20 MR. RIVARD: Yes. 21 CHAIR FOERSTER: Okay. Okay. All right. Go 22 ahead with your closing statement. 23 MR. CHAN: Paul Chan, senior operations 24 engineer for Hilcorp. 25 CHAIR FOERSTER: Well, to the uneducated that 142 1 message certainly -- my point in some of the questions 2 I asked was that if my mom rest in peace was sitting in 3 the audience she would go why don't you outlaw packers. 4 Okay. So that -- thank you for bringing Mr. Chan back. 5 Okay. 6 MR. CHAN: A couple of issues that come out 7 with -- excuse me, I'm sorry. I'm going to have to -- 8 I'd have to say something first, it's just bugging me. 9 In Prudhoe Bay if -- I'm sorry, could we pull up that 10 slide there with the big bore or disassemble well 11 construction? 12 In Prudhoe Bay field which is the one I'm most 13 familiar with the -- I want to get this picture of this 14 North Slope well construction conventional big bore. 15 In Prudhoe Bay you have inner annulus on a gas lifted 16 well that is at gas lift pressure. And that typically 17 would be approximately 1,800 to 2,000 psi. And then 18 the OA is a dead space so speak. It may have a little 19 big of pressure, it may not, it may read zero. This 20 production casing always sees that gas lift pressure. 21 If it's on production it sees that pressure. On an ESP 22 lifted well with our current well construction design 23 of having both surface casing and production casing, 24 even at shut in conditions the wells according to Mark 25 O'Malley will see no more than approximately 1,000 psi. 143 1 So under our shut in conditions we actually have less 2 pressure on production casing than a Prudhoe Bay well 3 on gas lift has on active gas lift. And to me that's a 4 -- and an important point to make is that their casing 5 strings are seeing that pressure continuously and ours 6 typically are around 200 psi under gas -- under ESP 7 lift, that's header pressure. So there's actually a 8 much order of magnitude less pressure on that 9 production casing string nearly all the time unless the 10 well happens to be shut in. 11 Then the other point would be is that if this 12 well ever developed an issue the standard way for us to 13 kill the well if you couldn't set a plug would be to 14 bullhead down the tubing. On a ESP lifted well our 15 standard way to kill the well if we had no packer would 16 be to bullhead down the IA. If we had a packer in 17 there you may never be able to get it killed because 18 the fact is you can't get enough rate through a one 19 inch port. 20 So I just want to make some of those 21 distinctions about high pressures on these wells versus 22 other fields that also have high pressures under normal 23 operating conditions. 24 So packers are not bad, but packers do have 25 their place. In our situation we think and we have -- 144 1 we think we have presented enough factual evidence that 2 packers actually will increase the risk of having an 3 unplanned environment to the environment or causing a 4 safety incident simply because the fact is if you put 5 something mechanically complex in a well, if it fails 6 we've got to go back onto it. If we lose our 7 techniques in order to keep the wells running then 8 they're going to fail quicker. That means we're going 9 to bring the rig out and that's putting 20 odd people 10 in the line of fire every time you do that. So it is a 11 decision that we make that is balanced against say an 12 offshore installation. Offshore installation you get 13 in the lifeboat, that's your alternative. You get in 14 the lifeboat and you jump offshore. On a pad operation 15 if something happens let's evacuate the pad to the 16 muster point. We know that, that's the facts. Adding 17 packers can only complicate the situation, raise the 18 risk, doesn't necessarily improve anything for safety 19 or an environment and actually it could actually make 20 it worse from the standpoint that you have to touch the 21 well that many more times. 22 CHAIR FOERSTER: Do you have any questions? 23 COMMISSIONER SEAMOUNT: No questions. 24 MR. CHAN: That concludes my comments. 25 CHAIR FOERSTER: Nor do I. 145 1 COMMISSIONER SEAMOUNT: Thank you, Mr. Chan. 2 CHAIR FOERSTER: Did you -- was those your 3 concluding comments or do you have concluding comments? 4 MR. BOND: I just have a couple of concluding 5 comments. 6 CHAIR FOERSTER: Okay. Okay. 7 MR. BOND: We live in an environment in an oil 8 field that has risks. Some of those are inherent in 9 the operations and others are created. And what you do 10 in any given environment is try to reduce the risk of 11 safety to the personnel, a risk of an unplanned release 12 to the environment. The question at Milne Point is 13 whether there is additional enhancement to the safety 14 of the personnel or an additional protection against an 15 unplanned release by requiring packers. The testimony 16 of our folks have demonstrated that this is not a field 17 that requires packers in order to have a safer 18 operation or to create a more environmentally sound 19 operation. In fact, our testimony indicates that it 20 would create a more dangerous environment through 21 additional well interventions and more complicated well 22 interventions and through potential unplanned releases 23 to the environment during those interventions. And 24 it's not justified under the circumstances we find in 25 Milne Point. 146 1 That's my conclusion. 2 CHAIR FOERSTER: Okay. So we have two 3 outstanding questions to you and I'll remind you what 4 they were. 5 MR. BOND: Okay. 6 CHAIR FOERSTER: The first question is how many 7 wells at Milne Point can flow to the surface unassisted 8 and the second question -- that first question you 9 should be able to answer that so that's not an optional 10 question. The second question that you can answer if 11 you choose to or you can say (indiscernible) if you 12 don't is what makes Milne different from the other 13 fields that have Kuparuk, Schrader and Sag wells that 14 are operating with ESPs that do not have this exemption 15 from packers. Okay? 16 MR. BOND: All right. 17 CHAIR FOERSTER: And..... 18 MR. BOND: There was another question about the 19 salinity of the water well. 20 CHAIR FOERSTER: But that question got 21 answered. 22 COMMISSIONER SEAMOUNT: That was answered a 23 while ago. 24 CHAIR FOERSTER: That was answered. 25 MR. BOND: Okay. 147 1 CHAIR FOERSTER: And it was pointed out to me 2 that 10 days would be a Sunday so let's just leave the 3 record open for two weeks from today..... 4 MR. BOND: Okay. 5 CHAIR FOERSTER: .....if that's acceptable..... 6 MR. BOND: The 24th. 7 CHAIR FOERSTER: Close of business on the 24th 8 if you have your answers to those two questions. 9 And is there anyone else who wishes to testify 10 on this matter? 11 (No comments) 12 CHAIR FOERSTER: All right. then we are -- at 13 12:40 we are adjourned, but the record will remain open 14 for 14 days. 15 (Adjourned - 12:40 p.m.) 16 (END OF PROCEEDINGS) 148 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Number CO-15-006 Conservation Order 390 September 10, 2015 at 9:00am NAME AFFILIATION TESTIFY (Please Print) (Yes or No) Ks�"1 1 A BL- ,� - I � Al Q C� u � P (re 11 011�0r,-'? A10 COoY, A06, C C C-LC C �1n `eve CC tJc) to , \ c� y e ,�5 Milne Point Field SEP 10 2015 Reservoir Review & Economic Analysis Keith Elliott, Senior Reservoir Engineer September 10, 2015 0 — Kuparuk River • 246,000,000 BO Cumulative Production • 7000 ft depth • Actively Waterflooding • Produces Sand • 62 of 75 active producing wells use Electrical Submersible Pumps — Schrader Bluff • 73,000,000 BO Cumulative Production • 4000 ft depth • Actively Waterflooding • Produces Sand (in particular, "flour sand") • 16 of 32 producers use Electrical Submersible Pumps — Sag River • 3,000,000 BO Cumulative Production • 9000 ft depth • Only two active production wells — Ugnu 0 No commercial production to date — Hilcorp submitted our Annual Waterflood Surveillance Report on July 1, 2015 — We diligently manage pressure 0 — Kuparuk River • Average of Recent Static Pressure Measurements: 3395 psi; 0.485 psi/ft • Cumulative Injection -Withdrawal Ratio: 0.9 = Volume Injected / Volume Produced • Prior Year Injection -Withdrawal Ratio: 0.9 = Volume Injected / Volume Produced • Target Reservoir Pressure Gradient = 0.465 psi/ft — Schrader Bluff 0 • Average of Recent Static Pressure Measurements: 1736 psi; 0.434 psi/ft • Cumulative Injection -Withdrawal Ratio: 0.9 = Volume Injected / Volume Produced • Prior Year Injection -Withdrawal Ratio: 1.3 = Volume Injected / Volume Produced • Target Reservoir Pressure Gradient = 0.465 psi/ft 180 160 140 a� a 120 m 100 so E J 60 •0 40 C 0 W 20 1.5 1.7 1.9 Economic Limit vs. ESP Life If ESP life degrades to 1.7 years and workover costs increase 33%, then Economic Limit is 145 BBL Oil per Day Current Average Run Life = 2.7 Years, Economic Limit = 95 BBL Oil per Day (BOPD) 2.1 2.3 2.5 2.7 2.9 3.1 3.3 3.5 3.7 Average ESP Life (years) * Economic Limit, Base Case Workover Cost (BBL Oil per Day) ■ Economic Limit, Given Higher Workover Cost (BBL Oil per Day) Milne Point Field Individual Well Oil Rate and Cumulative Oil Rate vs. Production Well Count 700 _ _- -_ _ - - _ __-_ _ ____ _ _ - _ __-_ 20,000 18,000 600 o 16,000 0 m a c 500 - --- - ------ — - -- - - - -_ . ___ _ 00 O m � (n o 0 400 If the economic limit is 145 BOPD, then 43 wells 12,000 W may not be repaired when they break, and field rate; o would drop by 3537 BOPD. 10,000 c 300 - --- -- - ---- -- Note: 30 of the 43 wells that produce less than p 145 BOPD use ESPs; their total rate equals 2701 8,000 3 BOPD E 4,000 100 - - - — - -- ---- - - -- --- 2,000 10 20 30 40 50 60 70 80 90 100 110 120 Production Well Count Individual Well Oil Rate (BOPD) amoCumulative Oil Rate (BOPD) C. • Q- =0 M 0 0 ,. o c v � w � o o a) U m O av a, > LL o <t 1.0% 0.5 % 0.0% -0.5 % -2.0% Field Recovery Efficiency Variance vs. ESP Life Current Average Run Life = 2.7 Years If ESP life degrades to 1.7 years and workover costs increase 33%, then Field Recovery Efficiency may drop by1% 1.5 1.7 1.9 2.1 2.3 2.5 2.7 2.9 3.1 3.3 3.5 3.7 Average ESP Life (years) ♦ Recovery Efficiency Variance, Given Base Case Workover Cost (% of OOIP) ■ Recovery Efficiency Variance, Given Higher Workover Cost (% of OOIP) 0 0 ANTHONY MCCONKEY - 11745 Wilderness Dr., Anchorage, AK 99516 • amcconkeyC&hilcorp.com • (907) 529-6199 (C) • (907) 777-8460 (W) Summary of Qualifications • Excellent communication skills and strong leadership qualities in demanding work environments. • Ability to effectively monitor/assess the performance of other team members and organizations in order to make improvements or take corrective actions. • Self-sufficient, capable of managing multiple projects, and a proven record of meeting challenging deadlines. Educational Experience University of Alaska Fairbanks Bachelors of Science in Petroleum Engineering, May 2011 S E P 10 2015 Professional Experience A Or.. r r Reservoir Engineer November 2014 - Present Hilcorp, Anchorage, Alaska • Work in the Alaska North Slope team with a focus on the Milne Point Unit. • Create/Appraise various intervention jobs, rig workovers, new drill wells, and surface optimization tasks. • Responsible for bi-annual reserves booking for the field. • Designed unique solutions to fixing Matrix Bypass Events in Schrader Bluff reservoir with the use of Class G cement. • Aid team in monitoring secondary recovery methods such as waterflood surveillance and Water -Alternating -Gas (WAG). Production Engineer August 2011 —November 2014 BP, Anchorage, Alaska • First year of employment spent as production engineer in East Waterflood team, covering Drillsites 16 & 17. • Constructed large numbers of well intervention jobs in order to increase production in a very mature portion of Prudhoe Bay. • Progressed Prudhoe's depletion plan and FOR methods such as Miscible Injection and Brightwater injection. • Spent six months on the WELLS North Slope rotation. Spent entire hitches with Facilities, Slickline, E-Line, Coiled Tubing, Rigs, Fullbore, Fraccing Operations, and Well Integrity. Learned slope operations and intervention work. • Joined the Milne Point Team as Production Engineer in March 2013. Originally assigned C & K pads and eventually expanded responsibilities in October 2013 to work B, C, E, and Tract-14 Kuparuk wells. • Progressed several RWO's, well interventions, and preliminary stages of a SAG reservoir grass roots pilot project at Milne. • Have worked extensively with three different forms of artificial lift; Gas Lift, ESP, and Jet Pumps. • Worked as Welltest/Metering SPOC for Milne Point, heavily involved with commissioning of VSRD meter at MPB-Pad. • As of December 2013, volunteered to aid in Separator/metering design projects for Prudhoe Bay at Drillsite 3, Drillsite 18, W-Pad, and J-Pad. A majority of the work involved upgrading conventional 3-phase separators to a 2-phase design. Team Lead in Senior Design Project — Electromagnetic Heating for Enhanced Oil Recovery September 2010 — May 2011 University of Alaska Fairbanks • Studied the effects of Electromagnetic Heating to increase the temperature of heavy oils in order to provide economically viable methods of heavy oil production. • Compared the theories of Electromagnetic Heating with current field applications of heavy oil production such as Steam Injection and In -Situ Combustion. • Used COMSOL software to simulate the multi -physics properties of Electromagnetic Heating in Heavy Oil Reservoirs. • Managed and lead a group of undergraduate students to ensure efficient and successful progress that met the deadlines and expectations provided by the UAF petroleum engineering professors. Technical Knowledge • Microsoft Office (Excel, Powerpoint, Word) • JEMS — Weatherford Jet Pump Modeling Software • Dynamic Surveillance System • Uniformance Process Studio • WINGUI & IFIX Scada Systems Professional Organizations • Integrated Asset Modeling - Petroleum Experts Toolkit • SNAP • IHS Toolkit (Harmony, Fekete, Welltest, etc.) • Oil Field Manager (OFM) — Surveillance Software • Petra • Active member of the Society of Petroleum Engineers (SPE). Fall '07 — Present • Active member of the American Association of Drilling Engineers (AADE). Spring ' 10 — Present Required Annular Operations to RECEIVED Maximize ESP Run Life and !+OGCC Ultimate Recovery • Fluid level shots to confirm surface bottom hole read out or when the sensor is no longer operational. • Fluid level shots to monitor EMW prior to RWO once the down hole gauge is no longer available. • Fluid level to determine if the well needs freeze protection during power outages or proration. • Fluid down the back side to help carry solids out of the tubing prior to shutting in the well that produce sand. This assures we have clean fluid in the tubing and no solids above the pump for re -start. Required Annular Operations to Maximize ESP Run Life and Ultimate Recovery • Displace emulsions or rag layer above the intake of the • pump by flushing annulus with clean crude. • Monitor backside pressure to assure the gas lift orifice is clear. Excessive pressure on back side pushes the fluid level below the suction of the pump. • Thaw ice or slush plugs in the tubing to avoid CTU thaw job. • Acidize ESP once the pump is determined to have an inflow issue. • Bull head into the formation when a smaller ESP pump will not allow the rate needed. Different pump when new in the ground will only allow a low rate through them <.5 Bpm. Required Annular Operations to Maximize ESP Run Life and Ultimate Recovery • Displace scale inhibitor formation squeeze jobs. Protect � pump from scale enhance ESP life • Back flush sand back into the formation on wells with horizontal laterals. • An integrity point to monitor the outer annulus against. 0 SEP 10 2015 Milne Point ESP Operations Dr James F Lea • Dr. James F. Lea PLTech LLC — President Texas Tech Petroleum Engineering Department Chair / 1999 — 2005 93 Technical Publications; 8 Patents; 4 Books SPE Distinguished Lecturer x 2 SPE-ESP Roundtable Permanent Board member API Committee Member on ESP's Chairman of the Board Artificial Lift R & D Council (ALRDC) • • Contents of Presentation • Electric Submersible Pump Description • ESP issues with packers • Sand and Solids - Production / Handling • ESP's: Gas • Mini Industry Survey 0 17� Packer or Not Generic ESP Casing Separated gas up annulus Some gas into pump Intake or separator Seal or Equalizer Motor/s Free gas from perfs Instruments Installation Casing Gas Vent at Surface Is E V) z O W z O V) w J a i 1-0 1 Heat Trace GLM Tubing Cable Tubing Packer 1. 2. Set Low Below producing fluid level Fluid through vent valve ' , Control will partially restrict vent Line gas Vent Valve 3. Splices or connections Gas Thru point of possible failure O Separator Vent Casing 4. Fluid partially gaslifted Annulus Gassy through vent valve may Fluid put extra hydrostatic over ESP vent valve and reduce vent gas flow 40 Control Line Packer Set High GLM 1. Above producing fluid level Tubing Cable COULD BE LIQUID 2. Possible liquid over packer, condensation OVER PACKER - CONDENSATION 3. Fluid through vent valve will O U Vent Valve: partially restrict vent gas N O Gas Shown Venting u O Tubing 4. Hydrates at vent? O 5. Splices/connections point of Gas Venting Separator possible failure 00 Or Not 0 6. Liquid over vent may restrict Casing flow of gas from blocking, Annulus Gassy hydrostatic O Fluid ESP 7. In future the annulus pressure will be monitored • • (A c 0 U N C i 0 U N v U a V) Killing the Well: Packer Relaxed 1. Flow of kill fluid limited through the vent valve and around packer 2. Solids accumulation or deposits, if any, above packer, could restrict flow through vent valve and hinder pulling packer. 3. Free solids accumulation above packer more likely with deep set packer. • El WHP Liquid Column Example: Is T WHP: 200 psi Liquid Column: 300ft Gradient: 0.4 psi/ft Gas flow: 200 mscfd Dvent, eff: 0.25 inches P below packer: 366 psi Extra 166 psi on well and pump intake Obstructed vent and liquid � column over packer adds pressure to well for given gas vent rate Some Additional Packer Cons • Packer may not release • Could become unseated • Could leak • Bits of rubber could break off plugging ESP intake • Treatments reduced to stopping unit and going down tubing. Lost production and shut -downs can lead to early failures • • Circulations? Back side flushes? • Fluid level shots to monitor downhole pressures? • • Packer disruptive for some current procedures • Some degree of impediment for separated gas to escape well • Hole in tubing over packer? PACKER RUBBER IN STAGES • Splices/Connections With packer, two additional splices/connections wou be expected , one above and one below. Although car taken with splices they can still be weak points. Showi are details of typical splice. API says (below) splices (connections) best not in fluid level. Jeff Dwiggins will discuss splices and/or connectors in more detail... following presentation EFT Systems Baker E-Pak MRP-Schlumberger PFT systems Praxis RHMB Etc: Connections/Splices: Risk of failure locations 0 CABLE SPLICE DETAILS . API 1196 Figure 3: Evidence of fluid across the cable conductor insulation Annulus producing gassy fluid heights can be calculated to estimate if packer setting depths will have vent valve seeing gassy liquid producing level or not Well L-03 IPR Curve mc L-03 low Kuparek a. aPD �VqN PP-A-�etOsa S�ePlese c• F-01 Kuparek Well F-01 packer set at 4500 ft packer set at 2200 ft packer set at 600 packer set at 4500 ft packer set at 2200 ft packer set at 600 VR Curve 000 G-02 packer set at 2200 ft .. Schrader packer set at 600 ft 3%0 2M _ _ __.__ ' 1-07 packer set at 2200 ft ____.— _.—_— Schrader packer set at 600 ft 1000 ti > 'tea 0 S00--_,_- 1000 1500 2000 25W 3000 O. WO +Vgel"-0-TMDo -.-. SMrePne9l%00e 19tw Pb EOu.ran Well G-02 IPR Curve will vent liquid will not vent liquid will NOT vent liquid 300 350 00^ a* -Rae FbM EQM'CM Well 1-07 will vent liquid will NOT vent liquid will NOTvent liquid will NOT vent liquid - -- - - will NOT vent liquid - --- will NOT vent liquid will NOT vent liquid `--- - 2d'------------- i 300 ZCC 3c_ 40. 500 000 700 a. aP0 s-voce,PR -0-TestDa 5np'e Ph—Steacf Rae FI—EQM,M • Running Speed • Typical running (installation speeds) are 1000- 2000 ft/hr • If packer installed additional time for installation required. Result: more time spent and more cost • Also packer and cable splices/connections for • cable to connect through packer are more points of possible failures. Packer Issues: Summary • Packers can introduce risk and eliminate some � current useful procedures that require an open annulus Sand and Solids — Production and Handling • Solids can cause severe or slight were on impellers/diffusers, shaft bushings etc. as well as pump sticking. Solutions include: — Filters, screens, Cavins — Metallurgy, coatings — Hardened flanged sleeve/bushing in pump — Fixed , not floater pumps • Sand could possibly accumulate over deep set packer, especially with starts and stops. It could partially block gas vent. It could hinder packer removal. Scale or other deposits could be more likely to block vent. 0 • Current run life 2.7 years which is good. Packers eliminate some sand management procedures degrading run life. Run life with sand can be much less than 2.7 years. _, Sand/Solids • Solids can cause pump wear and/or pump � sticking • Addition of packer will eliminate some useful sand management procedures • Gas • Gas at intake is sent up casing either by natural separation or gas separator. � • If some escapes into pump special stages may be needed at pump intake • If annulus restricted (ie: through packer vent ) then gas does not escape as easily. Worst case is no separation and all gas has to go through pump � regardless of separator installed. • Result of restriction: Several effects but production decrease possible Effect of Free Gas on ESP pump Stage Performance What Ms the effect of fee qas on the performance of an F P pump stage? Pvm Prffrn deteriorates as dump in`ake pressure Decrease ;anj fret gasvQIjrne the intake it creases This, graph ( Red _1) show the decreasing pump performance as intake pressure decreases Wth 10% gas volume at the in'ake. 11 Effect of Free Gas on ESP What is the effect cf free gas an the performance of an ESQ' pump stage? This graph (Ref, 1 pshows the dec'easing pump performance as intake pressure decreases th 15% gas volurn e at the intake, Rotary Gas Separator (If Needed) Diverts Gas Into Annulus Before Pump Intake Annulus gas, w/wo separator, must pass through vent valve if packer is installed. Fluids, deposits, hydrostatic above packer could restrict this flow If gas flow restricted, pump performance reduced and PIP will increase If no separator then still "natural separation" still directs gas not entering pump into the csg/tbg annulus to keep gas from pump. 0 • Rotary Gas Separator can be installed as tandem if gas percent is high Gas Out, 3rd stage Head Gas Out, 2nd stage Gas Out, 1s' stage Diffuser: Streamlines the Flow Intake o 0 0 Inducer: Generates Head TC Coated - - - and Vortex TC Bearing Compression MPF 05 Conditions at pump Input producing BHP, Asia (Initial Guess) S19 intake can be calculated Input well G`R, scNbbl-off 332 Input KWI BHT, F 148 to estimate need for gas Input gas .9mvity 0.7o Input Oil API U.00 1.03 separator or not Input tWter Wavily Input bpd, oil 160 No Separation Input bpd , water Calculations in Yellowe For ESP $O1412W calculation GOR - 596.1 9" "ParsW 60MCIPAVy �d e�torae pump �6 MUG Oil Specie% Gravity, calculated 0.87 (far rotary scparatVr for ESP, cstirnoto 90%P Its, solution GOR (scf/bbl-oil) 83.88 f (factor needed for Bo)- 689 1.52 so-- 1.07 PhfJ = SBa v (from irrith?l input far FIP� -I.�.!' Free gas, bpd at intake, BP®- S71 If PHI cI roe.n no yssloair for ESP ppprsflon Free gas, at intake, 41scfO - 103 Dunbar Fbotor' (fror» initial infrut for PIP) 2•470 Liquid at pu►np intake, 13PO - 376 ff ounbar -rf f1ref, head is floe yet redcfcea' bygas i gas at intake - Effective liquid traction before intake - 60.3 0.40 80% Separation i Bubble Point, psi - 2643 MAW gas separator effcieacy before pump 46 001.00 (for rotary 4.e panatar far ESP. 0,9 matV ROW C = 666(VLRYPIP VLR,ibefare sea9rgtf�n= _ PHf = 8-66 W R r Motske ('from ixritisi Input for RM 0.39 Dunbar it P f! -1 rh�vrr fro gs$1ock for RASP .0porati017 factor = 935(VLR)(1.1724r(11PIP) DunbsrF.sotof. ,(fern in1tf9J✓"Puf for PIP) 0:00 If 0unbar -I then Mood is not yvt ricdM00d► by gas ESP Performance with Gas Below factor below 1 is acceptable after separation for ESP performance. Note that for lower PIP acceptable performance is more difficult with gas at intake. If packer creates additional pressure at pump intake due to gas through gas vent then production can be reduced. Dunbar Factor vs PIP and Effcy Effcy=5C Eff, qr=SC ..r - E�C�= 7 C -- Ecy= 5C - Effo '=9C plp,ps • • ESP & Gas: Summary • To keep gas from pumps, a flow path with 0 minimal restrictions up the annulus and out of the well is needed. • Gas entering pump reduces pump performance or can gaslock pumps • Poor pump performance gives higher fluid 0 levels and lower production Next slide summarizes comments from ESP 40 vendors, AL analysis equipment, small and large operators of AL (and ESP) equipment. • Mini Survey: • Seen no ESPs with packers on shore. Quote: "Never seen a blowout. I am opposed to using packers on artificially lifted wells. Packers should NOT be used, if there is free gas and � a pump" 8/21 • Myself: Saw no onshore ESP installations with packer while at Amoco for 20 years... 1000 ESPS. Saw no blowout events or leakages for ESP wells with no packers. A good number of Amoco's ESP's in Northern Alberta. • • Has seen no ESP's with packers in his company or elsewhere on shore. Has seen no blowouts. Mini Survey: Continued • Major independent senior engineer: Seen no ESP's with packers 8/21 • Seen no ESP wells with packers onshore. Worked onshore. Saw no discharges or blowout events operating with no packer. • Has seen none in his field (W Texas) 0 Mini Survey • Of thousands of onshore ESP wells seen with � no packer, no blowouts, or discharges are seen from mini -survey comments • No packers in ESP onshore wells are seen • Absence of packer in onshore wells seems create no industry problems 0 Backup Slides • • (Use this slide as backup??) Vendors have special stages at pump intake to assist with gas if not all gas can be separated from production stream before pump intake Steep Vane Exit Angle LZI Split Vane Design Oversized Balance Holes • • (Use this slide as backup??) One vendor's perspective of various types of stages and their gas handling capacity. Method Effectiveness Radial Flow Stages w Mixed Flow Stages 4 Advanced Gas Handler t Multi -Phase Pumping - • is PLOT OF "PERMISSIBLE GAS" CORRELATIONS ESP Suitability in Gassy Wells Af f-- ['xin ar aM Turpin Suitable for Pumping , { 1 Y+ ♦ C / 000 l ♦ L , 1 RlYi ! cn I� ! Q 4!5 % , .. Not Suitable for Pumping ,- __�__. 0 0-4 OL8 1-;) tS 2 2.4 VatW Liquid Ratio (VIL) -- DunMr Deft Tuon, GI = i -o - - - '` urpin. t7 = 75 • 0 Causes for ESP Failures 1) Excessive overload for an extended period of time. 2) Seal section leak. 3) Well conditions - excessive operating temperature, corrosion, abrasive materials in fluid stream, etc. 4) Bad or faulty installation. 5) Motor controller troubles. 6) Faulty Equipment 7) Worn pump. 8) lightning. 9) Bad electrical system. 'ubing Corrosi 3% Main Catle Cyt 3% Pumpl, 71ugred wii Sunda 3% Pumps Plut Locked,Wel 1 20 Example of ESP Failures `rain Plug RIootor FailureAue of 3% Water in jMotar} From ProteCtar FaiILref Intake Failure 3 Y: Manufacturing 3 or Pothead VGItage i Surge 3% - PQthead cratckc-d 9='c Votor", Damaged f-or� I. VDI-age surge Sit atLatIcyclingfIUiEL I i n g Well. la-flo conditions! 231t • Common Run Life Factors • Proper Sizing of Equipment • Well (BHT) Temperature � • Free Gas • Viscosity • Corrosion • Sand /Foreign Material Production • Deposition Tendencies • Electrical Failures � • Operational Problems • Old Age 000 000 Some Motor Failure Causes 1) Excessive Motor Overload: Resulting from one or more of the following reasons: a. Abnormally high specific gravity of the well fluid. b. Bad design (undersized motor) resulting from poor data. c. Worn out pump. d. High, low, or unbalanced voltage. 2) Seal Section Leak: A leaking seal section allows well fluids to enter the motor and usually results in a failure. Possible reasons for a Seal Section leak are: a. Worn out pump causing seal damaging vibrations. b. Broken mechanical seals from rough handling. c. Defective seal section construction. d. Bad installation methods and/or procedure. 3) Insufficient Fluid Movement: Causes the internal operatingg,�temperature of the motor to exceed the temperature limitation of the insulation, resulting in an electrical failure. a. T is occurs when the fluid velocit by the motor is insufficient to cool it recommended velocity is 1 footysecond). b. Occurs where a unit is set below the perforations in a well and a motor jacket is not installed to direct the fluid by the motor to cool it. Causes of Seal Failure • Vibration —Shaft Seals • Sand —pump vibrates • Bag —chemical attack • • Sand fill — excess sand in top of protector • Temperature — bag, excess venting of fluid • Excess starts/stops — bag/bellows helps • Thrust • Misalignment — mechanical seals, shaft, bushings • Bent housing, shaft, • Other? Causes of Pump Failures A pump failure is usually the result of one of the following reasons: � 1) Downthrust wear, due to producing below peak efficiency. 2) Upthrust wear, due to producing above peak efficiency. 3) Grinding wear, due to producing abrasives. 4) Plugged or locked stages, due to scale build up. 5) Longevity wear. 6) Twisted shaft, due to locked pump, starting during backspin, or absence of VSC. � 7) Corrosion. Causes of Cable Failures 1) Mechanical damage during running or pulling operations caused by: a. Crushing b. Stretching c. Crimping d. Cutting 2) Cable deterioration due to: a. High temperatures b. High pressure gas c. Corrosion d. Normal aging 3) Excessive current creates a high conductor temperature capable of breaking down the insulation .. Surge of power.. lightening 0 0 One Type F POWER FE,HRU -� SYSTYMS t. COMEGT'M Lk.0 of ESP Packer MOMft" IFIC" um t-sm-e11 .0m Black Gatcrr Igo -Splice Packer Penetrator Dart + DR -KIT 1 via 01mv-aela f' - t} duum„ tat u- mrg"d 7r tthb tva art a im *04.040d fte-W. pal W4vp ft " MAM MFC 617s mooft Fmdmfy* uRNW,&trrt -aaa .v ri A9b' F an 1MtS No CO2 aatoa 01 T7 PI u PFrFT AT( —4 aAput xw4rao" CAW 0 E.c) 7NMER SUE 00 ACM Cwr W"OF wP r-Im, 92i:7 !4MLIDIS WIE OTWY PoWn xt • • Type of ESP Packer Penetrator -[-'OFT' POWER FEED-THRU •IOU5frJH rLxr<:; L:A L_ SYSTEMS a CONNECTORS L.1C '-aMAIS+- r a Black Gator' No -Splice Packer Penetrator P.rt t OPAIT i Der gnad are ana name tat t ,procsufu wdk, In4 .U;,Y.W, sor ica u•-1 f.•ffW iD1 AD 4p sD 7U33 psi. 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Fa.r 4w-rR« llrMflw ■ 1}it.C19tl 11 A: {�{#t .. tfiwN M ihCPi- �l 4'. • is Ilk Discussion on ESPs with Packers Prepared by: Jeff Dwiggins Dwiggins Consulting LLC Artificial Lift Solutions Pte Ltd SEP 10 2015 0 Jeff Dwiggins • Founder & Owner of: • Dwiggins Consulting LLC • Artificial Lift Solutions PTE LTD (Singapore) • Continuing Education Chairman of the SPE ESP Workshop • Wood Group ESP, Inc. —Vice President of International Operations Asia Pacific & Middle East Regions • Wood Group ESP, Inc. — Vice President of Engineering and Technology • • REDA Pump Company — Divisional Manager and Project • Management Group Manager • REDA Director of Technical Development for Lawrence ESP cable facility • BSME, University of Oklahoma • Have worked on/around 1000s of ESPs worldwide 0 Topics • ESP with Packers • General ESP Issues and Applications • Pre -rig Operations • Rig Operations • ESP Daily Operations • ESP Packer Penetrators ® Video of Packer Penetrator • ESP Packer Vent Valves • ESP Packer Summary • Photographs and Samples 0 I Considerations for Wells with ESP Packers • This presentation will discuss issues that arise in an � ESP system with a packer. Discussion to include: • Pre -Rig Operations • Rig Operations • Post Rig Operation — Impact to the ESP 0 4 Let's review some general ESP Upper Pigtail Packer Penetrator i Connector Lower Pigtail Packer Control Line E 0 W Shallow Set & Deep Set Definition • A deep set packer is typically very close to the ESP (100'-400'). • A shallow set packer is typically within 400'-1000' of the tubin hanger (closer to wellhead • And, typically there are two types of each of these — vented and non -vented packers. • Further, it is most common to see vented packers as shallow set packers. • • •.I General ESP Applications • The vast majority of ESP applications operate without the use of packers (deep set or shallow set) • Most ESP packer completions are offshore • ESPs must produce oil, gas, water and any other entrained items; fallback is always a concern. Deep set packers are more susceptible to pack off (difficulties unseating). • Gas production significantly reduces pump efficiency & increases motor heating. Packers greatly exasperate this issue. • The addition of a non -vented packer can jeopardize the ESP life cycle and appreciably shorten runlife thereby leading to increased wellbore interventions • When deep set packers with gas vent valves (GVF) are utilized, the GVF requires higher operating pressure (considered non -typical). Typical ESP System ESP with Packer 0 0 Pre -Rig Operations • If an existing ESP system has packer: • Killing the well can become very challenging • Packers will typically restrict circulation rate • Circulation concerns • Debris on top of packer • Debris on top of ESP (tubing) • Gas bubble below packer • Must consider alternatives if circulation is not established • Punching the tubing below the packer • Washing/bailing down to the packer Generic ESP Packer 711 �21181207$ ,•c KD— 1/1112/11 •� 0-111-00 M01 Tiunn EnoleweTMQ .41tt.a 1NY'A' FeedMru -Fk 1.9W NU �.�.. P .. d"- LAYOUT OF TAURUS FLEX.FIT PACKER PENETRATOR WITH 7- 26.2W HALLIBURTON (PER DWG. NO. -1 rcr r. :AYO TAJ .. FLE%- IPACKtlt ENETRA. 4YI'�Ti P � _ `(T rwrw ErWheednp� uNcoxrRol LED oocv#EMT MARKETING LAYOUT ao NOT Co►r Courtesy of Taurus Engineering • • 1.9 Rig Operation • The more items in the wellbore, the more risk in retrieving the system • The wellbore will be open longer due to greater � complexity (more items to deal with) • A packer penetrator is required to pass the ESP cable through the dual bore packer • Releasing the packer can be problematic • Pulling operations have increased risk for `stuck -in - hole' • • Retrieval of stuck packers can lead todays/weeks of additional rig operations • Could lead to loss of wellbore q Post Rig Operations (Operating the ESP) • Deep Set Packer • More susceptible to solids build upon top of packer • Gas interference could occur quicker • • More likely to negatively impact production • Solids fallout above the packer could impact a vent valve (if present) • Shallow Set Packer • Less likely to experience solids build upon top of packer • Gas interference likely deferred, but not negated � Discussion of the Packer Penetrator • Multiple types are available; all require an electrical connection/splice • Typically, the additional time required to make the connection is 4-6 hours (varies based on conditions and the type of packer penetrator) • Increases risk of mechanical damage due to upsetting the OD (splice/connection) P� E Lw With Permission from Taurus Engineering • III Packers with Gas Vent Valves (GVV) • The addition of the GVV provides a method to � expel gas to the annulus • The failure of a GVV isolates the packer and negatively impacts the ESP operation • t�) Summary of Issues with ESP Packers • Increases risk of ESP failure: • Additional electrical connections (x2) downhole; creates greater electrical stress • Vertical splice considerations • Field attachable considerations • • Increased diameter of system due to packer increases mechanical interference • Increased opportunity to be "stuck in hole" due to releasing the packer • Also sensitive to casing upsets • Fishing cable if stuck in hole • Solids fallback on top of packer is a potential issue and must be considered • Venting, or non -venting gas implications • Gas vent valve operation on either shallow set or deep set packers (require pressure to hold open) • Less ESP runlife = increased number of well interventions • More well interventions = increased risk ,4 Summary of Issues with ESP Packers • Forcing higher gas void fraction (GVF) thru ESP increases inefficiency, heat within the ESP; reduces runlife • Addition of packer adds considerable time with the wellbore � open • Dwiggins experience - -less than 1% of ESP systems have packers (been around thousands of ESPs) • Never seen a water source well with a packer • Never seen an onshore well with a packer • Application of ESP packers eliminates the ability to access the backside for operational purposes 0 • Eliminates possibility of batch treatments • Eliminates possibility to break "gas -bubbles' by pumping down backside • Limits ability to free a stuck pump RE Photos Blowout of Splice on Penetrator — Only 4 days ago 0 0 m Photos Increased starts/stops can lead to sand fallback issues Increased GVF leads to increased heat and can lead to bearing breakage 0 40 Ill Sand in ESP (Pump) Shaft Breakage Due to Fallback Plugged Pump Stage • • 1% 1 Photos Horizontal Splice Cable Blow -Out (Electrical Failure) • RIM Photos Mechanically Damaged & Cable Blow Out Cable 0 ab a with Splice 0 Photos Mechanical Damage to Cable Cable Blow Out 0 • Photos Parted Cable Horizontal Cable Splice 0 owl r� u a3 5r *d] \4 �« [\� � ƒ� � � 0 REVISED Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. CO- 15-06 Kuparuk River Oil Pool Schrader Bluff Oil Pool Sag River Oil Pool Milne Point Unit Cancellation of Conservation Order No. 390 The Alaska Oil and Gas Conservation Commission (AOGCC) is considering cancelation of Conservation Order No. 390. Conservation Order 390 exempts Milne Point Unit wells from the requirements of 20 AAC 25.200(d). The public hearing on this application currently scheduled for August 6, 2015 at 9:00 a.m. is here VACATED and rescheduled for September 10, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the September 10, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than September 4, 2015. Cathy Noe/r�st�er� Chair, Commissioner El • STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBFR AO- 16-006 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/30/15 AGENCY PHONE: (907) 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907) 276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE CO-15-06 Initials of who prepared AO: Alaska Non -Taxable 92-600185 " SC BJ1IT INVOICE SIIOwING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED.. COPY Of ADVERTISMENT To: Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page I of 1 Total of All Pa es $ REF Tye Number .Amnmit Date Comments I PvN ADN84501 2 Ao AO-16-006 3 4 FIN AMOUNT SY CC PGDI LGR ACCT F1' DIS'f [,IQ t 16 1 02140100 73451 16 2 3 4 5 Parch Title: P a ' [hori 's igna re Telephone Number h . i� f�R F{f31Sii 13Ilod�f�Eb�2SFe311�5U?/ bCBfiFPdocumen sting to this purchase. 2. state is registered for tax free transactions under Chapter 32, IRS codeistration number 92-73-0006 K. Items are for the exclusive use of the stale and not for re le. DISTRIBI'TION Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form:02-901 Revised: 7/30/2015 270227 0001369316 $189.26 AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Kayla Lavea being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on July 31, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed Subscribed and worn to before me this 4th day of August, 2015 R 2t# LUII JkPMa L Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES �j AUG 0 6 2015 A®GCC Revised Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. CO-15-06 Kuparuk River Oil Pool Schrader Bluff Oil Pool Sag River Oil Pool Milne Pant Unit Cancellation of Conservation Order No. 390 The Alaska Oil and Gas Conservation Commission (AOGCC) is Orderd390 exemptsaMilne Point Unittion of wells tion Owellsfrom he requirements ofrder No. 390. �20 AAC 25.200(d). The public hearing on this application currently scheduled for August 6, 2015 at 9:00 a.m. is here VACATED and rescheduled for September 10, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the . Comment! m0ust at 33:3 7th heAnchorage, ogconclusionof the aska SSeptember 10, 2015 hearing. Ied tc f6mbecause or attennd the f a hears g contaccial t the AOGCC' Smodations peb al Assistant t Jody Colombie, at 793-1221, no later than September 4, 2015. Cathy P. Foerste Chair, Commissione AO-16-006 Published: July 31, 2015 Notary Public BRITNEY L. THOMPSON State of Alaska Ivey 2019 Commission Expires Feb 23, Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, July 30, 2015 10:35 AM To: 'Salena'; 'Nathan Hile (nwhcmatrix@hotmail.com)'; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey, Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: Refed Public Notice CO-15-06 0 Attachments: Revised Notice of Public Hearing, Cancellation of CO 390 (Vacated) and rescheduled.pdf 0 James Gibbs Jack Hakkila Post Office Box 1597 Post Office Box 190083 Soldotna, AK 99669 Anchorage, AK 99519 Gordon Severson Penny Vadla 3201 Westmar Cir. 399 W. Riverview Ave. Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Richard Wagner Darwin Waldsmith Post Office Box 60868 Post Office Box 39309 Fairbanks, AK 99706 Ninilchik, AK 99639 Bernie Karl K&K Recycling Inc. Post Office Box 58055 Fairbanks, AK 99711 George Vaught, Jr. Post Office Box 13557 Denver, CO 80201-3557 rka- Q % & 20 \5 Angela K. Singh I H Hileorp Alaska, LLC July 27, 2015 Cathy Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3572 • Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone:907-777-8300 Fax: 907-777.-8301 Re: Conservation Order No. 390 Request for Revision of Milne Point ESP Waiver to 20 AAC 25.200(d) Request for Hearing Continuance Dear Chair Foerster, RECEIVED JUL 2 7 2015 AOGCC On May 13, 2015, the Alaska Oil and Gas Conservation Commission ("AOGCC") issued public notice of the AOGCC's intent to cancel Conservation Order 390 (issued March 7, 1997). On May 29, 2015, Hilcorp Alaska, LLC ("Hilcorp") submitted a timely written request for a hearing to be held on the matter. The hearing is currently scheduled for August 6, 2015. Hilcorp operates the Milne Point Unit and holds a 50% working interest.' BP Exploration Alaska, Inc. ("BPXA"), former unit/field operator, holds the remaining 50% working interest. Both Hilcorp and BP are directly affected parties to the AOGCC's proposed modification. I. Request for Modification of Conservation Order 390 As Unit Operator, Hilcorp respectfully requests the AOGCC amend CO 390, rather than vacate this order in its entirety. Doing so will increase safety measures while promoting conservation and preventing waste. Specifically, Hilcorp requests that the AOGCC repeal existing Rule 1, and replace it with the following language: Rule 1. Wells equipped with an electric submersible pump (ESP) and which were constructed with both production casing and surface casing may be completed without an ESP packer assembly.2 II. Background Rule 1 of CO 390 currently states: I See Exhibit A, Map of Milne Point Unit. Z Applicable safety valve regulations (20 AAC 25.265(d)(4)), do not require the installation of subsurface safety valves in any onshore wells equipped with an ESP. The regulation makes the reference to SSSVs in the original Rule 1 as set forth in CO 390 unnecessary. Cathy P. Foerster Conservation Order 390 July 24, 2015 Page 2 Wells equipped with an Electric Submersible Pump [ESP] and which do not require installation of Subsurface Safety Valves [SSSV] may be completed without a packer assembly. CO 390 provides a waiver to 20 AAC 25.200(d).3 There are current 119 ESP wells at the Milne Point Unit, of which 84 are active oil producers and seven (7) are active water source wells. Of this total well count, 116 ESP wells (97.5%) were completed without packers ("packerless") under the waiver granted by CO 390. See Exhibit B - Color Coded Spider Map and Supporting Spreadsheet. The majority of these "packerless" wells are constructed with a surface casing string which creates an annulus between the production and surface casing that can monitored for well diagnostics in addition to providing a second barrier to the wellbore. See Exhibit D - Packerless ESP Completion. In such wells, continued allowance for packerless completions is proper.4 This completion method allows for pressure monitoring and adequately protects against surface leaks in the event of a failed production casing. Of the 119 current ESP wells, only 15 (12.6%) are of monobore construction (i.e., lacking a surface casing). See Exhibit E - Monobore Packerless ESP Completion. Of these 15 wells, three (3) are active oil producers and five (5) are active water source wells. The remaining seven (7) are shut-in. Based on historical failure rates, Hilcorp is predicting 31 ESP failures at Milne Point for 2015. Each failure requires a rig workover to repair or replace the ESP. Packers impede efficient operation of ESPs and require alternate methods of accumulating or venting gas away from the pump to avoid premature failure of the ESP. See Exhibit C - Shallow Packer ESP Completion. If ESP wells were required to be completed with packers, such wells could encounter the following issues, resulting in a degradation of safety and a contribution to premature ESP failure. Operational Issues: • Gas locking due to gas accumulating beneath the packer. • Limited capability to circulate through the ESP packer (the ESP packer is the choke point) to perform back side flushes. • Inability to monitor the fluid level below the packer. • Moving the produced gas into the flow line. 3 20 AAC 25.200 (d) requires all producing wells capable of unassisted flow be completed with tubing and a packer that isolates the tubing -casing annulus from fluids being produced. 4 See, e.g., Conclusion No. 1, CO 390 ("Packers installed in conjunction with ESPs may cause premature failures, increase operational risk, reduce production efficiency and potentially reduce ultimate recovery.") Cathy P. Foerster Conservation Order 390 July 24, 2015 Page 3 • Higher risk of ESP failure due to extra cable splices at the packer. Workover Issues: • Increased use of the annular preventer to circulate out gas trapped below the ESP packer. • Increased difficulty in killing the well prior to and during the ESP change out due to accumulated gas above and below the packer (ESP packer is a significant choke point). • Depending upon set depth and hole angle of extended reach wells, difficulties in killing the well and unseating the packer. • Accumulation of debris on top of the packer preventing the release of the packer. While there are many benefits to ESP completions without packers, Hilcorp does recognizes that use of a packer in a monobore production well provides additional protection against the release of wellbore fluids, and affords for tubing -casing annulus pressure monitoring and similar well integrity diagnostics. However, such concerns should only exist for 15 of the field's 119 wells, of which only three (3) are active producers. III. Summary and Request for Hearing Continuance Completing ESP wells without a packer improves operational efficiency, promotes safer operations, increases ultimate recovery and extends field life. In the field's 15 existing monobore ESP wells, the AOGCC should require a packer only at the time of rig workover and only if the well is capable of unassisted flow to the surface as shown by a no -flow test. Instead of cancellation of CO 390, Hilcorp Alaska requests the AOGCC amend Rule 1 of CO 390 to allow "packerless" ESP completions in existing and future wells, but only if such wells are constructed with both a production casing and separate surface casing. Hilcorp's proposal to modify CO 390 will be supported by expert testimony regarding ESP operations at Milne Point Unit and the related impact of the proposed cancellation of said order. In addition, Hilcorp will provide an update as to current Milne Point Unit reservoir management practices and specifically regarding the issue of unit wells to flow unassisted to the surface. Due to the unavailability of a third party expert witness, Hilcorp respectfully request currently scheduled hearing be continued until mid -September 2015. Otherwise, Hilcorp requests the AOGCC schedule a continuation of the hearing in mid -September to allow Hilcorp's expert to present his testimony in person and allow the Commissioners to question him. If you have any additional questions concerning this request, please contact Wyatt Rivard at 777- 8547 or by email at wrivard@hilcorp.com. Sincerely, David Wil ' s Senior Vice President Cathy P. Foerster • • Conservation Order 390 July 24, 2015 Page 4 Hilcorp Alaska, LLC cc: Guy Schwartz, AOGCC (via email); James Regg, AOGCC (via email) th 0 14 114 A Exhibit B - ESP Completion Data Milne ESP Summary July 18, 2015 Oil Wells Water Source Wells All 111 All 8 Packerless 109 Packerless 7 Active 84 Active 7 Inactive 27 Inactive 1 Monobores 10 Monobores 5 Active Mono 3 Active Mono 5 Unassisted Flow* 40 Unassisted Flow* 8 * Note: Unassisted flow estimated by Max Anticipated Surface Pressure calcuation based on most recent BHP and a hydrostatic pressure calculated with water cut and a 1000' TVD oil cap factor of safety. Well API Type Status SC Shoe Packer Datum SHP BHP Date WC WC Date Gradient MASP Flow Possible • MPA-02 7=7r= Water. Active 2897 Packerless 2500 None None 100.0 NA 0.4340 NA Yes MPB-01 50029204900000 ..Water Inactive 2635 Packer at 2565' 2500 None None 100.0 NA 0.4340 NA Yes MPC-01 50029206630000 Oil Active 2338 Packerless 7000 2775 11/14/2012 82.6 4/3/2013 0.4276 -187 No MPC-13 50029213280000 Oil Active 4779 Packerless 7000 3217 12/11/2012 84.7 1/5/2013 0.4283 250 Yes MPC-14 50029213440000 Oil Active 5100 Packerless 7000 3376 4/3/2013 84.6 4/26/2013 0.4283 409 Yes MPC-22A 500 4 901 0 Oil Active 6715 Packerless 7000 2714 7/22/2012 88.0 7/7/2012 0.4296 -260 No MPC-43 50029232000000 Oil Active 9363 Packerless 7000 1773 7/22/2012 78.2 8/3/2012 0.4259 -1180 No MPCFP-1 50029212710000 W Active 2186 Packerless 2500 1551 4/12/1996 100.0 NA 0.4340 570 Yes MPD-01 50029206640000 Oil Inactive 2300 Packer at 588' with surface controlled annular vent 7000 2535 12/28/1992 0.0 11/27/1990 0.3970 -244 No MPE-04 50029219970000 Oil Active 5740 Packerless 7000 1282 5/4/2014 82.9 4/22/2014 0.4277 -1681 No MPE-06 50029221540000 Oil Active 5231 Packerless 7000 2332 9/2/2012 89.4 10/19/2012 0.4301 -645 No MPE-08 50029221560000 Oil Inactive 5947 Packerless 7000 2977 6/11/2013 78.5 1/8/2011 0.4260 24 Yes MPE-09 S0029225130000 Oil Active 3814 Packerless 7000 2405 8/31/2012 91.2 11/1/2012 0.4307 -576 No MPE-10 50029225210000 Oil Active 4100 Packerless 7000 3100 2/14/2013 81.7 3/19/2013 0.4272 140 Yes MPE-11 50029225410000 Oil Active 3455 Packerless 7000 3232 5/22/2013 81.7 6/19/2013 0.4272 272 Yes MPE-14A 50029227340100 Oil Active 5543 Packerless 7000 3070 7/27/2012 77.3 8/17/2012 0.4256 119 Yes MPE-15 50029225280000 Oil Active ' Packerless 4000 1502 2/11/2014 48.2 2/19/2014 0.4216 -173 No MPE-18 5 274 0000 Oil Active 4301 Packerless 7000 3270 9/5/2014 88.0 2/1/2015 0.4296 296 Yes MPE-19 50029227460000 Oil Active 3955 Packerless 7000 1478 3/12/2014 82.9 4/19/2014 0.4277 -1485 No MPE-20A 500292256 0100 Oil Active 2587 Packerless 4000 1444 8/13/2013 85.0 8/16/2013 0.4304 -257 No MPE-21 50029228940000 Oil Inactive Packerless 4000 1041 Estimated From E 323/13/14 36.0 11/9/1998 0.4186 -625 No MPE-22 50029225670000 Oil Active 3745 Packerless 7000 2472 7/22/2012 91.1 7/23/2012 0.4307 -509 No MPE-28 50029232590000 Oil Inactive 3479 Packerless 4000 1231 4/22/2011 83.6 8/17/2010 0.4301 -469 No MPE-32 50029232610000 Oil Active 2744 Packerless 4000 1041 3/13/2014 59.5 3/16/2014 0.4243 -642 No MPE-33 500 9 000 Oil Inactive .,.. Packerless 4000 1624 4/28/2001 50.0 8/25/2000 0.4220 -52 No MPF-01 50 9 255 0000 Oil Active 7124 Packerless 7000 3548 5/1/2014 94.8 4/16/2014 0.4321 559 Yes MPF-02 50029226730000 Active ,y: Packerless 2500 1097 5/10/2014 100.0 NA 0.4340 116 Yes MPF-05 50029227620000 Oil Inactive 5570 Packerless 1 7000 2111 8/6/2013 87.2 11/23/2013 0.4293 -862 No MPF-06 50029226390000 Oil Active 8767 Packerless 7000 2702 8/6/2013 87.2 6/17/2013 0.4293 -271 No MPF-09 50029227730000 Oil Active 6288 Packerless 7000 2287 5/4/2014 90.6 5/10/2014 0.4305 -693 No MPF-14 50029226360000 Oil Active 6690 Packerless 7000 2478 8/5/2013 88.0 6/18/2013 1 0.4296 -496 No Page 1 of 3 • • Exhibit B - ESP Completion Data MPF-18 50029226810000 Oil Active 7914 Packerless 7000 2850 5/4/2014 88.0 5/18/2014 0.4296 -124 No MPF-21 50029226940000 .Water Active Packerless 2500 1084 7/3/2014 100.0 NA 0.4340 103 Yes MPF-22 50029226320000 Oil Active 8842 Packerless 7000 3233 5/4/2014 90.2 5/18/2014 0.4304 254 Yes MPF-25 50029225460000 Oil Active 3405 Packer at 10296' w/ ported tubing joint above pkr. 7000 2413 5/4/2014 76.7 5/18/2014 0.4254 -536 No MPF-29 50029226880000 Oil Active 8019 Packerless 7000 1461 8/5/2013 51.3 11/25/2013 0.4160 -1432 No MPF-34 50029228240000 Oil ActiveE6678 Packerless 7000 1698 7/24/2012 0.7 7/29/2012 0.3973 -1083 No MPF-37 50029225480000 Oil Active Packerless 7000 1725 8/5/2013 87.5 6/6/2013 0.4294 -1248 No MPF-38 50029226140000 Oil Active Packerless 7000 3475 7/25/2012 58.0 8/11/2012 0.4185 567 Yes MPF-45 50029225560000 Oil Active Packerless 7000 2050 5/4/2014 80.4 5/10/2014 0.4267 -907 No MPF-50 50029227560000 Oil Active Packerless 7000 1316 30/22/2013 84.9 12/8/2013 0.4284 -1651 No MPF-53A 50029225780100 Oil Active Packerless 7000 3163 5/4/2014 91.9 5/5/2014 0.4310 180 Yes MPF-54 50029227260000 Oil Active Packerless 1 7000 2976 11/8/2014 1 71.2 10/24/2014 0.4233 39 Yes MPF-57A 50029227470100 Oil Active 9340 Packerless 7000 1 3370 5/4/2014 79.8 5/6/2014 0.4265 414 Yes MPF-58 50029227060000 Water Active Packerless 2500 1098 6/29/2014 100.0 NA 0.4340 117 Yes MPF-61 50029225820000 Oil Active 6586 Packerless 7000 1351 5/4/2014 74.0 5/6/2014 0.4244 -1592 No MPF-65 50029227520000 Oil Active 8604 Packerless 7000 1679 12/5/2013 46.1 12/13/2013 0.4141 -1202 No MPF-66A 50029226970100 oil Active 8223 Packerless 7000 1537 8/6/2013 0.0 6/15/2013 0.3970 -1242 No MPF-69 50029225860000 Oil Active 5778 Packerless 7000 3672 12/4/2013 92.8 12/14/2013 0.4313 687 Yes MPF-77 50029225940000 Water Active j.1111 Packerless 2500 1082 6/27/2014 100.0 NA 0.4340 101 Yes MPF-78A 50029225990100 Oil Active 7919 Packerless 7000 2892 5/4/2014 79.4 5/7/2014 0.4264 -63 No MPF-79 50029228130000 Oil Active 7340 Packerless 7000 3380 7/24/2012 86.7 7/23/2014 0.4291 409 Yes MPF-81 50029229590000 Oil Active 7515 Packerless 7000 2200 8/6/2013 80.2 11/27/2014 0.4267 -757 No MPF-86 50029230180000 Oil Active 6517 Packerless 7000 3215 6/8/2014 69.6 6/21/2014 0.4228 281 Yes MPF-87A 50029231840100 Oil Active 4945 Packerless 7000 3040 8/6/2013 82.5 6/16/2013 0.4275 78 Yes MPF-93 50029232660000 Oil Active 7925 Packerless 7000 3215 5/21/2014 84.2 1 5/27/2014 0.4282 1 249 Yes MPF-94 50029230400000 Oil Active 10341 Packerless 7000 3134 11/7/2014 78.6 12/4/2014 0.4261 181 Yes MPF-96 50029234060000 Oil Inactive 8644 Packerless 7000 2247 8/6/2013 38.8 6/17/2013 0.4114 -618 No MPG-02 50029219260000 Oil Active 2856 Packerless 4000 1284 3/29/2013 85.9 3/31/2013 0.4306 -418 No MPG-04 50029219410000 Oil Inactive 2674 Packerless 4000 1693 11/23/2010 21.4 2/16/2009 0.4151 38 Yes MPG-08A 50029221410100 Oil Inactive 2736 Packerless 4000 1913 8/16/2011 39.8 8/6/2008 0.4196 244 Yes MPG-12 50029227920000 Oil Inactive Packerless 4000 2004 7/8/2001 17.0 6/14/2001 0.4141 352 Yes MPG-14 50029730310000 Oil Active Packerless 4000 1466 2/15/2013 81.8 2/16/2013 0.4296 1 -233 No MPG-15 50029227840000 Oil Active Packerless 4000 1774 1/6/2013 80.2 2/14/2013 0.4292 76 Yes MPG-16 50029231890000 Oil Active 2526 Packerless 4000 1 1318 10/8/2014 45.4 11/1/2014 0.4209 -355 No MPH-01 50029220610000 Oil Inactive 2793 Packerless 4000 1841 12/31/2004 90.0 9/14/1998 0.4316 136 Yes MPH-02 50029220620000 Oil Inactive 2562 Packerless 4000 1789 9/18/2001 20.0 7/8/1998 0.4148 135 Yes MPH-05 50029225720000 Oil Active 5335 Packerless 7000 2576 7/22/2012 97.4 7/25/2012 0.4330 -419 No MPH-07A 50029225970100 Oil Inactive 8149 Packerless 4000 980 9/7/2013 32.5 8/28/2013 0.4178 -683 No MPH-16 50029232270000 Oil Active 4182 Packerless 4000 1155 11/28/2013 77.5 12/2/2013 0.4286 1 -541 No MPI-01 50029220650000 Oil Inactive 3274 Packerless 4000 1791 2/3/1998 60.0 2/24/1998 0.4244 108 Yes MPI-03 50029220670000 Oil Active 2633 Packerless 4000 1299 1/10/2014 4.9 1/21/2014 0.4112 -345 No MPI-04A 50029220680100 Oil Active 2599 Packerless 4000 1560 1/11/2014 80.3 3/14/2014 0.4293 -138 No MPI-06 50029228220000 Oil Inactive Packerless 4000 1560 8/29/2012 62.1 1/24/2009 0.4249 -125 No MPI-07 50029226020000 Oil Active 2680 Packerless 4000 1520 6/23/2014 27.0 7/11/2014 0.4165 -139 No MPI-12 50029230380000 Oil Active 2905 Packerless i 4000 1797 10/10/2014 1 7.5 1 12/18/2014 1 0.4118 152 Yes Page 2 of 3 • Exhibit B - ESP Completion Data MPI-14 50029232140000 Oil Active 2698 Packerless 4000 1215 7/22/2012 49.5 8/21/2012 0.4219 -461 No MPI-15 50029231060000 Oil Active 3085 Packerless 4000 1668 3/25/2014 54.2 7/13/2014 0.4230 -11 No MPI-17 50029232120000 Oil Active 2378 Packerless 4000 1193 7/22/2012 47.4 8/22/2012 0.4214 -481 No MPI-19 50029232180000 Oil Active 2999 Packerless 4000 1387 1/29/2013 35.0 3/16/2013 0.4184 -278 No MPJ-01A 50029220700100 Oil Active 2409 Packerless 4000 1242 12/6/2013 52.7 10/19/2013 0.4226 -436 No MPJ-03 50029220720000 Oil Inactive 2680 Packerless 4000 1460 9/27/2013 55.3 10/20/2013 0.4233 -220 No MPJ-04 50029220730000 Oil Active 2413 Packerless 4000 1832 1 12/31/2013 89.0 1 5/24/2015 0.4314 128 1 Yes MPJ-06 50029224930000 Oil Active 2511 Packerless 7000 2303 7/22/2012 83.2 7/12/2012 0.4278 -661 No MPJ-07 50029221980000 Oil Inactive 2442 Packerless 4000 1612 9/3/2008 40.0 11/9/2003 0.4196 -57 No MPJ-08A 50029224970100 Oil Inactive 2516 Packerless 4000 1717 11/11/2013 86.0 8/20/2013 0.4306 15 Yes MPJ-09A 50029224950100 Oil Active 2936 Packerless 4000 1457 3/31/2013 7.7 6/9/2013 0.4118 -189 No MPJ-10 50029225000000 Oil Active 2664 Packerless 7000 3712 5/19/2013 80.8 5/2/2013 0.4269 754 Yes MPJ-21 50029228250000 Oil Inactive Packerless 4000 1 1347 11/6/2002 16.0 11/1/2002 0.4138 1 -305 No MPK-02 50029226750000 Oil Inactive 4296 Packerless 7000 2217 7/22/2013 100.0 1 8/5/2013 0.4340 1 -784 No MPK-05 50029226700000 Oil Active 3823 Packerless 7000 2602 12/6/2013 65.5 1/15/2014 0.4212 -322 No MPK-06 50029227250000 Oil Inactive 3750 Packerless 7000 2337 7/22/2012 82.7 7/25/2012 0.4276 -626 No MPK-09 50029232470000 Oil Inactive 5173 Packerless 7000 2340 2/17/2009 97.0 3/13/2009 0.4329 -654 No MPK-13 50029226550000 Oil Inactive 3723 Packerless 7000 2416 2/13/2013 93.3 12/1/2010 0.4315 -570 No MPK-17 50029226470000 Oil Active 3508 Packerless 7000 2656 7/22/2012 44.2 7/25/2012 0.4134 -221 No MPK-30 50029227110000 Oil Inactive 6653 Packerless 7000 1 2962 1 12/15/2013 85.6 2/5/2014 1 0.4287 -7 No MPK-34 50029227120000 Water Active 3652 Packerless 4000 1727 5/1/2014 100.0 NA 0.4340 15 Yes MPK-37 50029226740000 Oil Active Packerless 7000 3494 2/23/2614 80.5 4/23/2014 0.4268 536 Yes MPK-38 50029226490000 Oil Active 3545 Packerless 7000 2215 2/23/2014 87.3 3/21/2014 0.4293 -758 No MPL-01A 50029210680100 Oil Active 2438 Packerless 7000 4301 6/13/2014 1.0 6/13/2014 0.3974 1520 Yes MPL-02A 50029219980100 Oil Active 5076 Packerless 7000 2076 8/7/2013 74.1 3/5/2013 0.4244 -868 1 No MPL-03 50029219990000 Oil Active 2578 Packerless 7000 3393 7/14/2012 80.8 7/22/2012 0.4269 435 1 Yes MPL-04 50029220290000 Oil Active 6277 Packerless 7000 1 4229 1 1/24/2014 92.1 12/12/2013 1 0.4311 1246 Yes MPL-05 50029220300000 Oil Active 6044 Packerless 7000 1984 7/24/2012 52.2 7/25/2012 0.4163 -911 No MPL-07 50029220280000 Oil Active 6850 Packerless 7000 2723 7/24/2012 84.1 7/5/2012 0.4281 -243 No MPL-11 50029223360000 Oil Active 6715 Packerless 7000 3348 10/6/2012 75.0 11/28/2012 0.4248 403 Yes MPL-12 50029223340000 Oil Active 2584 Packerless 7000 2683 11/14/2012 60.4 2/14/2013 0.4193 -230 No MPL-13 50029223350000 Oil Active 6086 Packerless 7000 2896 11/28/2013 78.5 12/25/2013 0.4260 -57 No MPL-14 50029224790000 Oil Active 7769 Packerless 7000 2033 2/17/2013 2.5 2/5/2013 0.3979 1 -752 No MPL-17 50029225390000 Oil Inactive 3632 Packerless 7000 1 3459 6/5/2013 99.0 1 7/15/2000 0.4336 460 Yes MPL-20 50029227900000 Oil Active 8160 Packerless 7000 3757 4/11/2013 72.0 3/30/2013 0.4236 818 Yes MPL-25 50029226210000 Oil Active 9019 Packerless 7000 3899 12/5/2013 77.6 1/11/2013 0.4257 948 Yes MPL-28A 50029228590100 Oil Active 7177 Packerless 7000 2321 7/24/2012 89.3 8/7/2012 0.4300 -656 No MPL-29 50029225430000 Oil Active 7676 Packerless 7000 2439 1/13/2014 46.0 3/5/2014 0.4140 -442 No MPL-36 50029227940000 Oil Active 7673 Packerless 7000 3000 11/6/2011 50.4 4/4/2011 0.4156 109 Yes MPL-37A 50029228640100 Oil Inactive Packerless 1 4000 1749 1 8/22/2006 3.0 I1/9/1999 0.4107 107 Yes MPL-40 50029228550000 Oil Active 7560 Packerless 7000 1 2475 7/24/2012 1 0.9 1 7/11/2012 1 0.3973 -306 No MPL-43 50029231900000 Oil Active 6097 Packerless 7000 2377 12/8/2013 1 53.3 1 8/10/2013 1 0.4167 -520 No MPL-45 50029229130000 Oil Inactive Packerless 4000 1590 2/5/2007 23.0 2/23/2001 0.4155 -67 No Page 3 of 3 0 40 C7 Exhibit C: Packerless ESP Completion WELLHEAD; Gen 5 FMC w/ CIW 3 1/8" tree / Tbg. Hgr. has profile. for CIW-H BPV. 13 3/8" CONDUCTOR 80' 9-5/8", 40#/ft,L-80, Btrs Csg 3814' 2 -7/8" 6.5ppf, L-80,8rd EUE tbg, (Drift ID=2.347", cap. = 0.00592bpf.) 7' 26 ppf, L-80 NSCC prod, casing (Drift ID=6.151", cap.=0.0383bpf Intake TVD = 6779' Mid -pert TVD = 7054' Mid-perf MD = 14248' PBTD TVD = 7207' PBTD MD = 14520' 7 1: m Wore immilmmms rod of fl.h ia,ygr /iid (iowar . otf nK�•r iot« �apdam gas sap , t0006 teal sea on 268 hp maco ) I PERFORATING SUMMARY: Ref. Loa: Snerry FWR4 Size SPFl Interval -MD Interval-TVDSS 3 3/8" 6 14002-14084 6914-6947 3 3/8" 6 14132-14200 6980-7007 21/8" 6 14480-14495 7187-7195 RKB = 54 FT AMSL G. LEVEL = 24 FT AMSL MAX DEV �72 DEG KOP = 450 FT Camco 2 7/8" x 1" 168' sidepocket KBMM GLM Cameo 2 7/8" x 1" 11,382' sidepocket KBMM GLM HES 2-7/8" 8rd 2.250 "XN" Profile Nipple 11,472' (No -Go ID 2.205"). Pump Model SXD, Type 100 P31 11,520' Tandem Gas Separator 11,540' GRSffX ARH6 Tandem Seal Section 11,543' GSB3 DB UTILT SBISB PFSA Motor, 204 HP / 2315 Volt, 11,558' 77 Amp, MSP Model Well Lift DGU / MGU 11,582' w/6 fin Centralizer TVD = 6080' 0 .00 BakerFB-1 pkrw/4"ID. (open bore - LLCV removed 13,548' on 11108/97) 7" Baker hanger/ fsol packer 13582' T' 26#, L-80 NSCC casing 1� 37 PBTD 14520' 5", 15#, 13 13cr STL casing 14565' Exhibit D: Monobore Packerless ESP Completion Tree: 2-9116", 5M Cameron Wellhead: 1 T 5M Gen 6 Unibore wl 1 V x 2178" EUE 8rd tbg. hgr., 2.5" "H" BPV profile. 20" 91.1 ppf, H-40, Csg. 113' KOP @ 400' Max Hole Angle: 47' 2600' to 3300' MD 2-718", 6.4 ppf, EUE 8rd. Tubing (cap. = 0.0058 bpf) 7", 26 ppf, L-80, BTC. Casing (cap. = 0.0383 bpf) (cap. w/ tbg inside = 0.02758 bpf) Casing tested to 1500 psi above 4880' MD during 4/29111 RWO. Stimulation Summary: 'N' Sand 44,200 lbs. 16/20 'ON'Sand 122,000 lbs. 16120 Perforation Summary: Ref. Log: DIL nsll 4J4. Size JSPF Interval (TVD). 4.5" 12 4990'-5028' (4301' - 4335') 4.5" 12 5136'-5166' (4432' - 4459') Jumbo Jet ("big hole") 26 gr. charges, 135145 deg phasing, EHD = 0.74", TTP = 5.8" Tagged fill 9/5/95 @ 5283' wim -- MPU E-15 DF = 53.9' (N22E) GL = 24.15' RKB (N22E) to 7" Hgr. = 29.7' Camco 2 718" x 1" KBMG GLM 196' MQ Centrilift heat trace 3450' MD Carrico 2 7/8" x V KBMG GLM 4608' and HES 2 718" XN nipple 4752 'md (2.205 no-go ID) Pump-124-P4, model PMSXD 4763' MD Gas Separator - FPHVDIS 4777' MD Intake TVD 4094' Tandem Seal Section GS 3DB TILT PFSAIFLAS HSN 4782' MD Centrilift KME-1 Motor(Re-rated)4795' MD 55 HP,1259 Volt, 26 Amp PumpMateXTOw1ft09nkALzer 4803' MD XTO ND 4129' RA Collar at 4835' WLM RKB 7" Halliburton "VTL" Pkr 4918' and 20 Gauge Halliburton Welded 304 SS Wire Wrapped Screen 5041' and 7" Halliburton "VTL" Pkr 20 Gauge Halliburton Welded 304 SS Wire Wrapped Screen 5171' wlm 7" x 4" bore HIES "BWD" Sump Pkr. w/ 3,813" XN npl. and WLEG 5302' and PBTD 5391' and 6, 7" Csg. Shoe Exhibit E: Shallow Packer ESP Completion WELL No. D-1 COMPLETION SKETCH MILNE POINT UNIT _() API No.: 50-029-20664 PERMIT No.: 81-144 COMPLETED: 3 20/82 LAST WORKO R: 11/26/89 110' 20", 94# H-40 FMC TBG HANGER W/3" FMC BPV 1/4" S,S. CONTROL LINE 7 JTS 3 1/2'. 9.3f. L-80, &d EUE ESP CABLE — No. 4 REDALENE 10 JTS 3 1/2", 9.3#. L-80, DSS—HT, TBG ANNULAR VENT VALVE 572' OTIS 3 1/2" FMX TRSV NOTES: 1. ALL DEPTHS MEASURED FROM EWS 94 588' 9 5/8' 011S RDH PXR KDB m 20' 602' 3 1/2" OTIS XN NIPPLE 2. MAX. ANGLE - 52,5' 0 480Y 3. SLANT HOLE: YES 4. TREE TYPE: FMC 3 1/8" 50004 W/3 1/2' 8rd TREETOP CONNECTION 5. COMPLETION FLUID. 10.2 PPG NoO/NOBr 6. STIMULATIONS, ACID 9/5/89 $10 GAL. 10% ACETIC ACID 850 GAL, 10% HC1 1700 GAL, MUD ACID 2300' 13 3/8", 72# L-80 PPUMPED 57 2390 16/20 CARBOLITE 8098, TOP 8108' BOY HYDRAULIC LINER HGR � - 8455' 9 5/8", 470. L-80, BTRC � , / 226 JTS 3 1/2'. 9.31, L-80, DSS-HT 8999' OTIS BALL CATCHER X0 9032' X-0 W/BALL CIRCULATING SUB 9033' TOP OF REDA ESP, ON 450, 191 STAGE PERFORATION DATA 9072' BOTTOM OF ESP DEPTH: 916D'-9198' MD DENSITY: 4 SPF, 0' PHASE, 2 1/8' STRIP 9238' TAG FILL 9320' P8TD ':t?,` >•: 9383' EZSV RETAINER 9900' 7-. 290. L-80, BTRC LINER E 0 Colombie, Jody J (DOA) From: David Duffy <dduffy@hilcorp.com> Sent: Friday, May 29, 2015 2:03 PM To: Colombie, Jody J (DOA) Cc: John Barnes; Kevin Tabler Subject: Notice of Public Hearing, CO-15-006 Dear AOGCC, Pursuant to the public notice issued on May 13, 2015, Hilcorp Alaska, LLC respectfully requests the Commission hold a public hearing regarding the Commission's proposal to cancel Conservation Order 390. Thank you, David Duffy, Landman Hilcorp Alaska, LLC Direct: 907-777-8414 Cell: 907-301-2629 dduffy@hilcorp.com This email may contain confidential and / or privileged information and is intended for the recipient(s) only. In the event you receive this message in error, please notify me and delete the message. • n U Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. CO-15-006 Kuparuk River Oil Pool Schrader Bluff Oil Pool Sag River Oil Pool Milne Point Unit Cancellation of Conservation Order No. 390 The Alaska Oil and Gas Conservation Commission (AOGCC) is considering cancelation of Conservation Order No. 390. Conservation Order 390 exempts Milne Point Unit wells from the requirements of 20 AAC 25.200(d). The AOGCC has tentatively scheduled a public hearing on this application for August 6, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 1, 2015. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after July 1, 2015. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 17, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the August 6, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than July 20, 2015. Cathy V Foerster Chair, Commissioner STATE OF ALAS" ADVERTISING ORDER ADVERTISING OFDERNUMBER AO-15-023 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 05/13/15 1(907) AGENCY PHONE: 793-1221 333 West7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: Publish 5/15/15 FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 1 uI �,IV"" tg sgl�IIiIINI III„�u9� HI �;,i�i 'i�5, y i ,1I I k 41u M I� r uIgl E Gll TYI QI� aI : +CCII 'I ppJJpurWI �; $p IaIIIgIIIIP+VI I.I+I. q 9 t IPoI it"��;II INNf -.-Iii61V I..a mT++.�i°;"a .•. ;„ lm'�I�V.4a 6'I�H�I�III�I .:4 T,ak3 7 0;^ �I S ..•. ��lllll�ur :'.." Milli N 'illlll�llllll DESCRIPTION PRICE CO-15-006 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF i PUBLICATION WITH ATTACHED COPY OF ADVFRTISMENT TO; Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pages $ - REF Type Number Amount Date Comments I PVN ADN84501 2 Ao AO-15-023 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ I 15 02140100 73451 15 2 3 4 itle: Pure si gtjteA: Purchasing Authority's Signature Telephone Number DISTRIBUTION: Division Fiscal/Original AO Copies:; Publisher (faxed), Division Fiscal, Receiving. Form:02-901 Revised: 5/13/2015 270227 • • RECEIVED 0001364713 $ 219.14 MA`S 2 0 1015 AFFIDAVIT OF PUBLICATION AOGCC STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said tirne was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on May 15, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed �? Subscribed and sworn to before me t s 15th day of May, 2015 17 tWj) al Notary Pu and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES 512L 15 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket No. CO-15-006 Kuparuk River Oil Pool Schrader Bluff oil Pool Sag River Oil Pool Milne Point Unit Cancellation of Conservation Order No. 390 The Alaska Oil and Gas Conservation Commission (AOGCC) is considering cancelation of Conservation Order No. 390. Conservation Order 390 exempts Milne Point Unit wells from the requirements of 20 AAC 25.200(d). The AOGCC has tentatively scheduled a public hearing on this application for August 6, 2015 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 1, 2015. If a request for a hearing is not timely filed, the AOGCC may issue an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after July 1, 2015. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 17, 2015, except that, if a hearing is held, comments must be received no later than the conclusion of the August 6, 2015 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than July 20, 2015. AO-15-023 Published: May 15, 2015 Cathy P. Foerster Chair, Commissioner • James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 (t Richard Wagner Darwin Waldsmith P.O. Box 60868 P.O. Box 39309 Fairbanks, AK 99706 Ninilchik, AK 99639 (�_�s`� `•'✓(,.f�"..._ Angela K. Singh. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, May 13, 2015 4:10 PM To: 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha J (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); Toerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; Trystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; 'Hunt, Jennifer L (DOA)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov)'; 'Pasqual, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) (dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); 'Wallace, Chris D (DOA) (c h ris.wa I lace@ a laska.gov)'; 'AKDCWellIntegrityCoordinator'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Carrie Wong'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; 'David Tetta'; 'Davide Simeone'; 'ddonkel@cfl.rr.com'; 'Dean Gallegos'; Delbridge, Rena E (LAS); 'Donna Ambruz'; 'Ed Jones'; 'Elowe, Kristin'; 'Evans, John R (LDZX)'; 'Frank Molli'; 'Gary Oskolkosf'; 'George Pollock'; 'ghammons'; 'Gordon Pospisil'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff'; Hulme, Rebecca E (DNR); 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Louisiana Cutler'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan'; 'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; Patty Alfaro; 'Paul Craig'; Paul Decker (paul.decker@alaska.gov); 'Paul Mazzolini'; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; 'Renan Yanish'; 'Robert Brelsford'; 'Ryan Tunseth'; Sara Leverette; 'Scott Griffith'; Shannon Donnelly; Sharmaine Copeland; 'Sharon Yarawsky'; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; 'Stephanie Klemmer'; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Terence Dalton; Teresa Imm; 'Terry Templeman'; Thor Cutler, 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; 'Donna Vukich'; Eric Lidji; Erik Opstad; 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; 'Jason Bergerson'; 'Jill McLeod'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Matt Gill'; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 0 To: 'San ra Lemke'; Shaun Peterson; 'Susan Pollard'; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Hutto'; 'William Van Dyke' Subject: Notice of Public Hearing, CO-15-006 Attachments: Notice of Public Hearing, CO-15-006.pdf