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CO 823
CONSERVATION ORDER 823 Milne Point Field, Milne Point Unit Prudhoe Bay Field, Prudhoe Bay Unit 1. -------------- Background information 2. March 11, 2025 Hilcorp request for public hearing 3. March 24, 2025 AOGCC notice of public hearing 4. May 29, 2025 Public hearing transcript and presentation 5. June 26, 2025 Steve McKeever summarized testimony STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: The APPLICATION OF HILCORP ALASKA, LLC for a waiver to 20 AAC 25.036 (c)(2)(A)(iv) to not require coiled tubing drilling operations to have at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used. ) ) ) ) ) ) ) ) ) Conservation Order 823 Docket Number: OTH-25-014 Milne Point Field, Milne Point Unit Prudhoe Bay Field, Prudhoe Bay Unit July 29, 2025 IT APPEARING THAT: 1. Hilcorp Alaska, LLC (Hilcorp), by letter received March 21, 2025, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) requesting a hearing for a waiver to 20 AAC 25.036 (c)(2)(A)(iv) for coiled tubing drilling (CTD) operations where the blowout prevention equipment (BOPE) is equipped with pipe rams that fit the size of the tubing, liner, or casing used, except that pipe rams need not be sized to BHAs and drill collars. The waiver requested that properly sized rams not be required for CTD operations while running liner or jointed pipe work strings. Hilcorp’s request is to use a safety joint with a drill string safety valve to shut in the well without the availability of pipe rams to fit the jointed pipe. 2. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing for May 29, 2025. On March 9, 2025, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website, the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On March 12, 2025, the notice was also published in the Anchorage Daily News. 3. No written public comments on the application were received prior to the hearing. 4. The hearing commenced at 10:00 a.m. on May 29, 2025. Testimony was received from two Hilcorp representatives and a Hilcorp expert witness. 5. Witnesses from Hilcorp with extensive and relevant experience in coiled tubing operations, well control, and drilling practices testified under oath and were recognized by the AOGCC as experts in their respective fields. 6. One member of the public provided comment during the hearing. 7. The record was closed at the end of the hearing on May 29, 2025. FINDINGS: 1. Hilcorp Alaska, LLC is the operator of leases at the Milne Point Unit (MPU), and Hilcorp North Slope, LLC is the operator of leases at the Prudhoe Bay Unit (PBU), both of which are covered under the Affected Area of this order. Although Hilcorp Conservation Order 823 July 29, 2025 Page 2 of 6 Alaska, LLC and Hilcorp North Slope, LLC are financially distinct S corporations, they are collectively referred to as “Hilcorp” for the purposes of this order due to shared drilling personnel and equipment in CTD operations. Hilcorp assumed operatorship of MPU from BP Exploration (Alaska) Inc. (BPXA) in November 2014 and of PBU on July 1, 2020. Hilcorp Alaska, LLC and Hilcorp North Slope, LLC are the respective working interest owners of MPU and PBU. The Alaska Department of Natural Resources is the landowner of the Affected Area. 2. Hilcorp requested waivers from 20 AAC 25.036(c)(2)(A)(iv) to allow the use of BOPE without pipe rams sized to (a) the casing and (b) the jointed pipe work string being used, both of which may be several thousand feet in length. Under 20 AAC 25.036(c)(2)(A)(iv), the BOPE must be equipped with at least one set of pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to bottomhole assemblies (BHAs) or drill collars. 3. The AOGCC has historically required installation of pipe rams sized to the casing prior to deployment of casing. 4. The AOGCC currently limits jointed pipe below coiled tubing in well service operations to lengths up to 500 feet, which establishes a precedent for considering 500 feet as a reasonable maximum BHA length. 5. Hilcorp and its predecessor, BPXA, have conducted jointed pipe work string operations below continuous coiled tubing without size-specific pipe rams for over 20 years, across more than 1,000 CTD wells, without major well control incidents. 6. Hilcorp contends that long jointed pipe work strings, including those up to 4,000 feet, are integral components of the BHA. Hilcorp further stated that this practice aligns with historical operations by BPXA in the Affected Area. 7. In 2024, the AOGCC identified a compliance gap with 20 AAC 25.036(c)(2)(A)(iv), as CTD permits did not explicitly disclose the use of long jointed pipe work strings, nor did those permits include provisions for corresponding pipe rams. 8. Hilcorp asserted that the use of a standard safety joint in combination with pipe slip rams offers an equivalent level of well control to pipe rams sized to the liner or jointed pipe work string. 9. Hilcorp stated that if pipe rams are required under regulation, they must serve as the primary well control mechanism. 10. CTD has historically been employed in wells with effectively infinite kick tolerance, reducing the risk of a section of the wellbore below surface failing in the event of a large gas influx. 11. Hilcorp’s standing orders designate a safety joint with a drill string safety valve as the primary shut-in method, not pipe rams nor blind-shear rams. The configuration of safety joints and drill string safety valve varies depending on the well and operation. Hilcorp intends to rely on this safety joint method even in the event of escalating well control, including gas on the rig floor. 12. Hilcorp was unable to provide the AOGCC with a procedure for an escalating well Conservation Order 823 July 29, 2025 Page 3 of 6 control scenario where the safety joint was no longer an option. 13. The waiver request applies to wellbores with casing set at the reservoir top and open or cased horizontal sections in the reservoir. 14. Hilcorp asserted that its CTD methods are consistent with historical industry practice in Alaska and that over 1,000 CTD wells have been drilled without a major well control incident related to liner or jointed pipe work string use. However, supporting data was not provided. 15. Hilcorp stated that requiring size-specific pipe rams for various liner and jointed pipe sizes routinely used (3-1/2", 3-1/4", 2-7/8", 1-1/4", and 1") would introduce complexity, reduce well control flexibility, and increase the likelihood of human error. 16. CTD rigs are equipped with blind-shear rams and annular preventers. They also include enhanced kick detection and response capabilities such as continuous circulation and bullheading, not typically available on rotary rigs. 17. Hilcorp believes the safety joint method offers a consistent and crew-familiar procedure, improving reaction time and reducing decision-making errors during well control events. 18. Hilcorp stated additional pipe rams in the BOPE will result in exceeding the restricted vertical space below the CTD rig floor for some wells. 19. The American Petroleum Institute (API) has no Recommended Practice (RP) specific to CTD. API RP 16ST provides guidance for coiled tubing operations and equipment as it relates to well control. 20. Expert witness Martin Walters testified regarding the relative merits of the safety joint method versus dedicated pipe rams for all jointed pipe sizes, emphasizing the importance of shutting in quickly and correctly. CONCLUSIONS: 1. The AOGCC does not require operators to submit well control procedures for approval. The presence of pipe rams in the BOPE does not imply it must serve as the exclusive or primary method of well control. 2. Hilcorp’s characterization of operations as “cased hole,” where portions of formation remain exposed, does not align with accepted industry terminology or its associated implications. 3. The AOGCC considers "open hole drilling" as any drilling operation with a section of the formation walls exposed. Accordingly, CTD is considered as an open hole operation. 4. Well control events involving the rapid displacement of fluids from the wellbore can escalate in seconds. In such scenarios, exclusive reliance on the safety joint method may be impractical, particularly under high-pressure surface release conditions. Pipe rams and blind-shear rams are essential BOPE components designed to enable swift shut-in responses during unexpected well control events. Conservation Order 823 July 29, 2025 Page 4 of 6 5. The sudden escalation of a well control incident poses serious risks to rig personnel and the environment. The safety joint method may not be sufficient as a standalone strategy, particularly if it places personnel in proximity to discharging well fluids. A secondary, independent means of well control should be available to ensure safe and timely shut- in capability during such events. 6. The safety joint method requires increased operational diligence to ensure proper crossover connections are made, which may increase complexity and create the opportunity for human error. 7. Threaded casing connections must be torqued to manufacturer specifications to ensure mechanical integrity and pressure sealing. Under well control conditions, improper make-up or cross-threading may compromise well integrity. 8. While 20 AAC 25.036(c)(2)(A)(iv) requires pipe rams sized to the tubing, liner, or casing being used, the presence of a tested annular preventer and blind-shear rams, in combination with the safety joint method, achieves a level of well control safety equivalent to that intended by the regulation. Requiring pipe rams for every component is not necessary under the specific conditions outlined by Hilcorp. 9. The waiver request satisfies the intent of 20 AAC 25.036(c)(2)(A)(iv) by providing adequate protection to public health and safety, the environment, and the conservation of natural resources through the use of the safety joint method, if supplemented by performance-tested annular and performance-tested blind-shear rams for contingency well control. 10. When paired with routine shear performance testing and rigorous well control drills, granting the waiver will not degrade well control integrity. Instead, it will enhance operational consistency, reduce unnecessary equipment modifications, and may improve safety. 11. API Recommended Practice 16ST provides relevant guidance for CTD well control practices. Annex E of API RP 16ST supports blind-shear ram verification through periodic on-rig performance testing using the heaviest jointed pipe and coiled tubing (including electric line and control wire) expected to be used in CTD completions. 12. Expert witness Martin Walters concluded that the safety joint method is preferable to the use of casing rams or work string rams. However, his analysis did not address scenarios where the safety joint method is combined with casing or jointed pipe rams as a contingency. 13. The safety joint method paired with a contingency mechanism, such as size-appropriate pipe rams and/or performance tested blind-shear rams, provides superior protection compared to the safety joint alone. Escalating well control scenarios may render the safety joint method infeasible or hazardous, particularly if access to the rig floor is limited. NOW THEREFORE IT IS ORDERED: For all oil pools in the Prudhoe Bay and Milne Point Units, the AOGCC approves a waiver of 20 AAC 25.036 (c)(2)(A)(iv) for CTD operations to not require properly sized rams for coil tubing drilling operations while performing jointed pipe operations of length greater than 500 feet subject Conservation Order 823 July 29, 2025 Page 5 of 6 to the following conditions: Rule 1: Escalating Well Control Procedure and Use of Blind-Shear Ram Hilcorp shall maintain and implement a written procedure for escalating well control scenarios that includes the ultimate use of blind-shear rams. All coiled tubing permit-to- drill (PTD) applications shall include standing orders that explicitly reference the potential deployment of blind-shear rams in emergency situations. The PTD submittals must include documentation of the most recent blind-shear ram performance test results, current as of the date of submission. Rule 2: Performance Testing of Blind-Shear Rams In addition to the function-pressure testing requirements of 20 AAC 25.036(d), blind-shear rams shall be performance tested in accordance with Annex E of API RP 16ST. Testing must be performed using the rig's accumulator after cycling the annular preventer and closing the HCR valve. The performance test must include shearing: x The largest outside diameter casing for which no size-specific pipe ram is installed, x The heaviest wall jointed pipe work string expected to be used, and x The heaviest continuous coiled tubing string augmented with electric line (E-line) control and data cables. Tests must include both centered and non-centered positioning of the pipe within the blowout preventer stack. Hilcorp shall provide the performance test procedure to AOGCC for review and approval. Rule 3: AOGCC Witnessed Safety Joint Drills Hilcorp shall conduct well control proficiency drills that specifically demonstrate the use of the safety joint as a primary shut-in method at a frequency or schedule specified by the AOGCC. Hilcorp shall notify AOGCC for the opportunity to witness these drills. Drills must be documented and the records available for AOGCC review upon request. Rule 4: Limitation to Open Hole Operations The waiver is limited to operations in wellbores with casing set and cemented at the reservoir top and open or cased horizontal sections in the reservoir. Rule 5: BOPE Configuration In addition to the requirements of 20 AAC 25.036, the BOPE must include a minimum of two sets of pipe slip rams. Rule 6: Hydrostatic Overbalance Requirement During any jointed pipe operations where appropriately sized pipe rams are not utilized, the wellbore shall be maintained in a hydrostatically overbalanced condition at all times. The hole must remain full of fluid sufficient to ensure overbalance throughout the operation. Conservation Order 823 July 29, 2025 Page 6 of 6 Rule 7: Permits to Drill CTD PTD applications that include plans for jointed pipe work string operations below continuous coiled tubing shall include the following information: x Size and length of jointed pipe, and x Description of jointed pipe operation. DONE at Anchorage, Alaska and dated July 29, 2025. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 3 l.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 othe1wise 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 runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.07.29 15:18:52 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.07.29 16:19:51 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Conservation Order 823 (Hilcorp) Date:Tuesday, July 29, 2025 7:32:30 PM Attachments:CO823.pdf The APPLICATION OF HILCORP ALASKA, LLC for a waiver to 20 AAC 25.036 (c)(2)(A) (iv) to not require coiled tubing drilling operations to have at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used. Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 5 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Steve McKeever To:Coldiron, Samantha J (OGC) Cc:Rixse, Melvin G (OGC) Subject:Hillcorp Public Hearing: Docket Number: OTH-25-014 Date:Thursday, June 26, 2025 9:42:21 AM Samantha – I testified at the public hearing on May 29 regarding Hillcorp’s request for a waiver from the requirement that the BOPs be equipped with pipe rams that fit the size of the tubulars being used. Mel Rixe contacted me last week and asked that I summarize my testimony as he said my testimony was not adequately recorded or transcribed. Following, then, are some of the points I believe I made as I testified as well as others that come to mind as I today review the background material that was provided to me prior to the hearing. I introduced myself a retired drilling engineer, but one who’s experience was all on large rotary rigs with no experience in coil tubing drilling. As I said in testifying I don’t take a position either for or against Hillcorp’s request. But I feel the Commission should consider the following, listed in no particular order. · Hillcorp stated “Liner is short compared to total depth”, but provided no evidence of the relative length of the liner compared to the total depth. Should the waiver be granted AOGCC might consider setting a maximum length of liner that would not require a sized set of pipe rams. As the regulation now states, “..except that pipe rams need not be sized to BHA’s and drill collars.”, with typical BHA’s substantially shorter than liners that are run. · Hillcorp asks for a waiver for “CASED hole Coil Tubing Drilling jointed pipe operations”. AOGCC might consider better defining what are such operations, perhaps by stating that such cased hole operations do not include any liner runs for which liner shoe enters open hole during the picking up of the liner joints. (Should shallower formations, such as West Sak, be further developed with coil tubing drilling in the future I could envision liners that would enter open hole before being fulling picked up. Similarly if coil drilling technology were to include tractors or other downhole devices to extend reach, it is easy to imagine longer and longer liners.) · Hillcorp expressed concern that the current regulation may require a ram be closed below the flow cross, limiting their ability to circulate the well during a kill operation. This seemed moot to me – they could obtain a reconfigured BOP stack that put three of the four rams above the flow cross instead of their current configuration of two rams above the flow cross and two rams below the flow cross without any additional height penalty. And since the BOP’s are nippled up on the Xmas tree they have other outlets on the tree to which they could rig up circulating lines, though perhaps not conveniently. · Hillcorp stated “The current regulations are based on API RP 53 (Rotary Drilling 1997), seeming to imply that the AOGCC regulations are based on a 28 year old document. A quick look at the 2024 API publications catalog does not list an RP 53. Instead there is a 5th edition of STD 53, dated December 2018, entitled “Well Control Equipment for Drilling Wells”, which I assume is the better basis for the current AOGCC regulations. There are also other API documents that Hillcorp didn’t mention: RP 16ST, “Coiled Tubing Well Control Equipment Systems”, dated 2021 with a 2022 addendum. And RP 59, “Recommended Practice for Well Control Operations”, dated May 2006. With in RP 59 is a statement that reads, “The working pressure of ram-type BOPs should exceed the maximum anticipated surface pressure . Provisions should be made for closing BOPs on all sizes of drill pipe, drill collars and casing that may be used." (Italics added). · As Hillcorp testified about their well control procedures I was curious why the annular preventer was not the first preventer that they would close. I recall in my testimony wondering at what closing pressure the annular regulator on the accumulator would be set. To save wear and tear on the packing unit in annular preventers operators often set the pressure during BOP tests as low as possible to effect the needed seal. Good well control practice might be to set it up to 1500 psi during normal operations to gain assurance that it will quickly close if needed in an actual well control situation. · Hillcorp often referred to the use of a safety joint as their preferred shut-in method while running jointed tubulars, but they never described what the safety joint is. Should AOGCC approve the waiver requested, AOGCC might consider defining such a joint in terms of OD, connection type, and required strengths. And Hillcorp testified that their well control procedure would ensure that the proper cross over from the safety joint to the jointed pipe would be readily available on the rig floor. I wondered why the proper cross over was not made up to the safety joint ahead of time, before the jointed pipe operations began. (apparently one liner could consist of three different size tubulars (i.e. 3-1/2”, 3-1/4” and 2-7/8”) so why would they not have three different safety joints, each with the correct crossover on the bottom and eliminate any possible problems making up the crossover to the safety joint.) Additionally I don’t recall any testimony from Hillcorp about the weight and length of the safety joint, where it is stored in liner running operations, and how exactly it is handled, made up, and lowered to a position where the TIW valve on top could easily be closed. And Hillcorp suggested that wellbore pressures may be such that the liner is pushed upward. Could there be a case where such forces prevent the lowering of the safety joint into the needed position to close the pipe/sliprams and close the TIW valve? · Another question I had: Hillcorp said the shear rams could be used as a last resort. Were the shear rams actually tested on all pipe sizes, including the safety joint, or is it interpreted from other tests and calculations that the shear rams will shear the tubulars? · Hillcorp testified they had superior kick detection as they have micro-motion flow sensors. Are such sensors used to measure both flow into the well and flow out of the well? · Hillcorp’s drilling manager stated that if AOGCC does not grant the waiver and a ram to fit the pipe size in use is required, he will have to require that the ram be used, implying that AOGCC would be liable should there be a mishap. I found such a statement preposterous. An annular preventer is required by the regulations but nowhere in their presentation or testimony did they say they are required to use the annular. · No information was provided on the configuration of the liners, in terms of connections, weight, grade and float equipment. If float equipment is run this would perhaps inhibit flow up the inside of the liner in the event of a kick, perhaps making it easier (no mud gushing out of the liner) for the rig crew to install the cross over and safety joint. But float equipment would also increase the upward pressure forces on the string, which is the assumption Hillcorp makes in calculating the upward forces on the liners on the Pipe Jacking slide of their presentation. And if the tubular connections are not flush joint, and have collars, the collars may get stopped by the closed rams, preventing the upward movement. Signed, Stephen McKeever 4 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of Hilcorp Alaska's Request ) for a Waiver to 20 AAC 25.036(c)(2)(A)(iv) ) Coil Tubing Unit Operations Where at Least ) One Preventer Equipped with Pipe Rams that ) Fit the Size of the Tubing, Liner or Casing ) Being Used, Except that Pipe Rams Need Not ) be Sized to BHAs and Drill Collars. ) ____________________________________________) Docket number: OTH-25-014 PUBLIC HEARING May 29, 2025 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Greg Wilson, Commissioner AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Wilson 03 3 Testimony by Mr. McLaughlin 08 4 Testimony by Mr. Perl 46 5 Testimony by Mr. Walters 63 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 COMMISSIONER WILSON: Good morning. I will 4 call this hearing to order. It is approximately 10:00 5 a.m. on Thursday, May 29th, 2025. This is a public 6 hearing on docket number OTH-25-014. By letter 7 received March 21st, 2025, Hilcorp Alaska, LLC, filed a 8 request for hearing with the Alaska Oil and Gas 9 Conservation Commission regarding coiled tubing 10 drilling well control, a waiver request to 20 AAC 11 25.036(c)(2)(A)(iv). I'm Commissioner Greg Wilson and 12 with me is Commissioner Jessie Chmielowski. Today's 13 hearing is being held in person and via Microsoft 14 Teams. The in person location is the Alaska Oil and 15 Gas Conservation Commission at 333 West 7th Avenue, 16 Anchorage, Alaska. For those on Teams please be 17 mindful of any background noise and make sure you are 18 muted when you're not testifying or addressing the 19 AOGCC. 20 If you require any special accommodation please 21 contact Samantha Coldiron, she can be reached at 907- 22 793-1223 or send her a message through Microsoft Teams 23 chat icon and she will do her best to accommodate you. 24 Samantha Coldiron will be recording the 25 hearing, Computer Matrix will be preparing the AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 4 1 transcript. Upon completion and preparation of the 2 transcript anyone desiring a copy will be able to 3 obtain it by contacting Computer Matrix. 4 This hearing is being held in accordance with 5 Alaska statute 44.62 and 20 AAC 25.540 of the Alaska 6 Administrative Code. The notice of hearing was 7 published on the Alaska -- on the state of Alaska 8 Online Notices website as well as the AOGCC's website 9 and was sent through the AOGCC email listserv on April 10 1st, 2025. The AOGCC also published the notice in the 11 Anchorage Daily News on March 26, 2025. To date the 12 AOGCC has received no public comments on this matter. 13 By way of background on March 21st, 2025 14 Hilcorp Alaska, LLC filed a request for public hearing 15 with the AOGCC for a waiver request to 20 AAC 16 25.36(c)(2)(A)(iv) that reads at least one preventer 17 equipped with pipe rams that fit the size of the 18 tubing, liner or casing be used except that the pipe 19 rams need not be sized to BHAs and drill collars. 20 The Commissioners will ask questions during 21 testimony. We may also take a recess to consult with 22 Staff to determine whether additional information or 23 clarifying questions are necessary. 24 Representatives from Hilcorp, are you prepared 25 to make your presentation? AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 5 1 MR. McLAUGHLIN: Yes, we are. 2 COMMISSIONER WILSON: I will now swear in the 3 witnesses. Will all of you please raise your right 4 hands and respond. 5 (Oath administered) 6 IN UNISON: Yes. 7 COMMISSIONER WILSON: Let the record reflect 8 the witnesses all responded in the affirmative. 9 Do any of you presenting wished to be 10 recognized as experts? 11 MR. McLAUGHLIN: Yes, all three of us do. 12 COMMISSIONER WILSON: So one by one then please 13 identify your field of expertise and your credentials. 14 MR. McLAUGHLIN: Sean McLaughlin. I have a BS 15 in mechanical engineering. I've attended many 16 technical schools including coil tubing operations, 17 coil tubing engineering, managing hole problems, stuck 18 pipe, tubing stress analysis, casing design and 19 completion tools. I've performed BOP risk assessments, 20 cap analysis to API and company procedures and 21 performed peer reviews supporting clear platforms, 22 Saudi Arabia and Trinidad. I have 26 years in industry 23 and coil tubing, coil tubing drilling, rig workover and 24 rotary drilling. I'm currently the drilling manager 25 for Hilcorp Alaska. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 6 1 COMMISSIONER WILSON: Thank you. Before we go 2 to the next witness, Sam, was that going through the 3 microphone? 4 MS. COLDIRON: Yes. 5 COMMISSIONER WILSON: It was. Okay. Next, 6 please. 7 MR. WALTERS: Good morning. My name is Martin 8 Walters. I'm an independent oil industry consultant 9 currently specializing in International Association of 10 Drilling Contractors or IADC well control certification 11 training. I've been an Alaska resident for 20 years 12 and have a bachelor of science degree in petroleum 13 engineering from Louisiana State University in Baton 14 Rouge, Louisiana. I've approximately 40 years of oil 15 industry experience in a wide variety of roles 16 including production operations, production 17 engineering, reservoir engineering, project 18 coordination, well intervention, well integrity and 19 well control. 20 COMMISSIONER WILSON: Thank you. 21 MR. PERL: Hi, my name's John Perl. I'm the 22 CTD Hilcorp senior drilling foreman. I've got 28 years 23 of -- in the industry with the last 10 being spent 24 supervising CTD ops with BP and Hilcorp. Started my 25 career in 1997 with Halliburton running slick line and AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 7 1 a couple years with Schlumberger doing that. Went into 2 the wells group for BP in 2006 as wellsite leader, 3 supervising slick line operation and transitioned into 4 Milne Point well operations coordinator for their well 5 work out there. 2012 I transferred back to CTU to work 6 service coils, wellsite leader. 2014 I decided -- I 7 was asked to go to CTU (indiscernible) and have been 8 there since and (indiscernible) Hilcorp 2020. 9 COMMISSIONER WILSON: Commissioner Chmielowski, 10 are you satisfied with the expertise and credentials as 11 presented? 12 COMMISSIONER CHMIELOWSKI: Yes, I am. 13 COMMISSIONER WILSON: You will all be 14 recognized as experts in the field you identified. 15 Before asking Hilcorp to begin their 16 presentation, Commissioner Chmielowski, do you have any 17 questions? 18 COMMISSIONER CHMIELOWSKI: No. Thank you. 19 COMMISSIONER WILSON: Okay. For those of you 20 testifying please remember to speak into the 21 microphone, also reference your slides by number or 22 title so that someone reading the public record can 23 follow along. And each time you speak please state 24 your name and job title clearly for the record. Please 25 begin. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 8 1 SEAN McLAUGHLIN 2 previously sworn, called as a witness on behalf of 3 Hilcorp Alaska, testified as follows on: 4 DIRECT EXAMINATION 5 MR. McLAUGHLIN: Sean McLaughlin, drilling 6 manager for Hilcorp Alaska. Slide one. First a little 7 orientation. We're going to have three of us speaking, 8 we have 21 slides to cover, 14 are mine. I'm going to 9 cover the engineering and planning piece and then I'll 10 pass it over to John, he'll cover the operation piece 11 and then we'll hand it to Martin to cover well control. 12 So that's how it's kind of laid out. I have about 30 13 minutes, maybe John has about 15, 20 minutes and Martin 14 about 15 minutes is kind of what we have planned. 15 Slide one here. You guys have already -- 16 you've read the regulation, the waiver request is -- is 17 for taste (ph) hole coil tubing drilling, jointed pipe 18 operations, use of a safety joint with a TIW valve to 19 shut-in the well is acceptable. 20 And then down below that there's a whole list 21 of jointed pipe that we run in the hole. I'm not going 22 to read it all, it's just -- there's 13 configurations 23 and so there's a lot of -- could be a lot of different 24 methods to shut-in. What we want to get across is that 25 there's safety and standardization and one method of AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 9 1 shutting in is preferable, not going back and forth 2 between methods. For example with the slotted liner 3 and the perforating guns we are required to use a 4 safety joint for shutting in. The request that we're 5 talking about is for the three and a half, three and a 6 quarter and two and seven-eights solid liner. 7 Currently we have variable bore rams, liner rams, we 8 would like to use a safety joint in lieu of those liner 9 rams. And then also for the CS hydril the one and a 10 quarter and one inch CS hydril historically this has 11 been considered part of BHA and we have not had rams, 12 but a change in interpretation will require rams for 13 that. We would prefer to use a safety joint to shut-in 14 on the CS hydril as well. 15 Slide two. 16 COMMISSIONER CHMIELOWSKI: May I ask a couple 17 questions, please. 18 MR. McLAUGHLIN: Yes. 19 COMMISSIONER CHMIELOWSKI: You mentioned case 20 pull operations, but the variable bore rams is that for 21 open hole? 22 MR. McLAUGHLIN: So for running the liner and 23 I'll get a little more into this and -- and I thank you 24 for asking, it kind of bounds the request a little bit 25 for when we run the coil tubing liner. We're only AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 10 1 running that in cased hole. I don't think it would be 2 an appropriate request if you're running a long liner 3 into open hole. You have things like stuck pipe and 4 then usually you're in horizontal where you could run 5 into a kick. So the -- the cased hole and why I have 6 that capitalized is to put a bound on the waiver 7 request saying that we have a short liner section 8 usually running to a vertical part of the well where 9 the risk is smaller. For rotary operations you often 10 have a long liner that is run into open hole and 11 horizontal. So it is a bounding condition. 12 COMMISSIONER CHMIELOWSKI: Okay. So just to 13 clarify you're saying the well would have open hole 14 deeper, but the liner would be in the cased hole? 15 MR. McLAUGHLIN: Yes. Thank you..... 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. McLAUGHLIN: .....for that clarification. 18 COMMISSIONER CHMIELOWSKI: Okay. And then 19 could you just give us some more information about the 20 historical, you know, the hydril being historically 21 considered part of the BHA. Do you have information 22 about when that started and who did it, when, you know, 23 that sort of stuff? 24 MR. McLAUGHLIN: Yeah, it -- it goes back to 25 the mid '90s is when coil tubing first started gaining AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 11 1 popularity in Alaska. And it was just a drilling, a 2 coil tubing drilling with a service unit and then they 3 would move off and a rotary unit would come in and run 4 that liner on jointed pipe. And that's where a lot of 5 the regulation come from. And then later it evolved to 6 coil tubing would run the liner and then they would 7 move off and rotary would come in and cement it. As 8 part of that operation in '95, '97, that's when we 9 started using the CS hydril to clean out after the 10 cement job. So that -- that practice dates at least to 11 '97 that I know of where we're using CS hydril to run 12 inside the liners for a clean out. And so that -- that 13 spans both ARCO, BP and all -- all previous operators. 14 COMMISSIONER CHMIELOWSKI: And, you know, the 15 hydril can be what, several feet in length -- several 16 thousand feet, is that what I said, yeah, several 17 thousand feet in length? 18 MR. McLAUGHLIN: Yeah, up to..... 19 COMMISSIONER CHMIELOWSKI: Yeah. 20 MR. McLAUGHLIN: .....4,000 feet..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. McLAUGHLIN: .....in length. 23 COMMISSIONER CHMIELOWSKI: Yeah. Let's go to 24 the next slide. Thanks. 25 MR. McLAUGHLIN: Okay. Slide two. And so this AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 12 1 is where I talk a little about the regulation and the 2 risk and the history of the regulation. So the 3 regulation that we're talking about is based on API RP 4 53 which is really specifically for rotary drilling. 5 That one was written in 1997 and which was appropriate 6 at the time. Coil tubing drilling was in its early 7 stages, we didn't know a whole lot about it. And we -- 8 like I just said we were still running liners on 9 jointed pipe. But over the last 20 or so years coil 10 tubing has developed quite a bit, we have specific coil 11 tubing drilling rigs and it -- it's kind of a gray area 12 between rotary drilling and interventions, but we 13 operate under RP 53 so it's kind of a clunky fit. But 14 coiled drilling has a different risk profile. Some of 15 those are -- liner is deployed in cased oil, but the 16 liner section is short in comparison to the total 17 depth, there's continuous pipe when tripping which has 18 reduced swab tendency. The wells are horizontals which 19 changes the swab migration. A swab kick would not 20 migrate in a horizontal well. We have unlimited kick 21 tolerance and you're going to hear this a few different 22 times through the presentation. When coil drilling 23 moves on the well the well is already construction -- 24 constructed, the wellbore elements are in place and so 25 it's -- it's more of an intervention activity, but we AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 13 1 don't have the same tolerances that we do in a rotary 2 well, we don't have an FIT test and so we're able to 3 bullhead kill the well which gives us another option 4 for well control that's typically not available in 5 rotary drilling or in RP 53. 6 So with all those things coiled drilling has 7 superior kick prevention, kick detection and well 8 control. There are shear rams present in the stack 9 that are not required by RP 53 and there's a tree and 10 master valve on the well which is typically not 11 something that you would see with a rotary drilling 12 operation. 13 And then as far as the risk piece, over a 14 thousand wells have been drilled on the North Slope, 15 coiled tubing drilled wells on the North Slope with 16 zero significant well control events from running liner 17 or work string so we consider this a low probability 18 event based on historical information. 19 COMMISSIONER WILSON: Could you elaborate on 20 the superior kick detection? 21 MR. McLAUGHLIN: Yes. With a kick detection 22 since we are continuous we can do dynamic flow checks 23 as we're pulling out of the hole and we have 24 micromotions on the rigs and so we have a finer 25 tolerance to measure fluid in and out of the well. The AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 14 1 kick prevention piece that speaks to the continuous 2 circulating we can do while running in and out. We're 3 not making up connections every joint and so we can -- 4 we do continuously circulate on the trip out which 5 reduces swab tendency. 6 COMMISSIONER CHMIELOWSKI: Do you -- do you 7 have any, you know, supporting evidence for the 8 statement about zero significant well control events? 9 MR. McLAUGHLIN: Just a quick look back at my 10 historical knowledge. I've been involved in coil 11 tubing drilling since 2001 and so it's based on my 12 recollection in historically BP and Hilcorp areas..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: .....and the little bit I know 15 about ConocoPhillips. 16 Slide three. I wanted to take a minute and 17 talk about the kick scenarios since this is all has to 18 do with well control and I wanted to set the stage for 19 when we think about the risk matrix where -- where we 20 sit on a probability side of things. So for running 21 and pulling liner, a kick while running and pulling 22 liner where we're talking about either running a safety 23 joint or closing liner rams the situation would be the 24 well has been drilled to TD, it has been circulated 25 clean, it has been flow checked, we've laid down the AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 15 1 drilling BHA and we've observed the well. So there's 2 been significant time to monitor the well before 3 running liner. The liner is run in cased hole and 4 usually a fairly vertical section over a short 5 duration. This has a lower risk for running into a 6 kick. We consider this a low probability and low 7 severity event. It's not going to be an intensity kick 8 and likely there's not going to be a large gas volume 9 and there would be low surface pressure. This kick has 10 a similar probability as to when we're running slotted 11 liner. A safety joint is acceptable for slotted liner 12 and it should be acceptable for solid liner as well. 13 The next one is kick while deploying CS hydril. 14 So this is usually we've already done everything up 15 above, we've already run the liner in the ground and so 16 we've had all this time to monitor the well, the 17 liner's in the bottom, it's typically been cemented, 18 the liner running tool has been pulled and we've laid 19 down those tools and we've monitored the well. 20 Historically AOGCC, Hilcorp and previous operators have 21 considered CS hydril as part of the BHA. This has been 22 since the late '90s. We consider the CS hydril as a 23 tool to allow entry into the liner. The work string is 24 the coil tubing and that's when you're going to take 25 the significant amount of risk when that is at the AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 16 1 bottom of the well you have coil tubing across your BOP 2 stack and that's typically when you would see gas in 3 the horizontal section or when you would swab gas in. 4 We believe both scenarios have lower risk, have 5 a lower well control risk than running perf guns or 6 slotted liner. For example an annular preventer is not 7 effective on perf guns or when running slotted liner 8 there will be flow inside and outside. 9 Slide four. This is a title slide. And we're 10 going to talk about specifically that the two and 11 three-eights by three and a half liner rams next and it 12 will be in two pieces. We'll cover liner rams and then 13 we'll cover CS hydril rams. 14 Slide five. This is an illustration of the BOP 15 stack. On the left-hand side is the current BOP 16 configuration for drilling. Top down we have an 17 annular preventer, blind shear rams, two and three- 18 eights pipe slip rams, a flow cross, three inch pipe 19 slip rams and two and three-eights pipe slip rams. So 20 that's our current setup for drilling. On the right- 21 hand side is what the regulations would require us to 22 do. We would swap out the three inch pipes rams for 23 two and three-eights by three and a half variable bore 24 rams. On that right side I'd like to also point out 25 that those shear rams up above, they're -- they're not AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 17 1 required for running liner, they're in there because of 2 the coil tubing drilling piece and they're just -- 3 they're just extras, but they're not required by RP 53 4 in this case. 5 So slide six. 6 COMMISSIONER CHMIELOWSKI: Could you please 7 talk about those three inch pipe slip rams. Those are 8 I understand needed for drilling with a managed 9 pressure drilling system; is that okay? 10 MR. McLAUGHLIN: Okay. Our B -- our drilling 11 BHA is three inch..... 12 COMMISSIONER CHMIELOWSKI: Okay. 13 MR. McLAUGHLIN: .....and so we use those for 14 deploying the BHA..... 15 COMMISSIONER CHMIELOWSKI: Okay. 16 MR. McLAUGHLIN: .....pressure, deploying and 17 un-deploying the BHA. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. McLAUGHLIN: So that -- that's why those 20 are in place. 21 Slide number 6. We stick with that picture on 22 the right and so we're going to talk about the risk 23 when liner rams are installed. Shutting in on liner 24 rams adds risk to the operation in multiple well 25 control areas. Closing the BBR hinders the management AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 18 1 of well -- of a well control situation. We would be 2 unable to circulate through the choke or kill line 3 because we are shut-in below the flow cross. We'd be 4 unable to kill the well from bottom because we're not 5 able to strip to bottom. Coiled drilling liners are 6 not suitable kill strings. They're not on bottom, 7 typically they're only 500 to 4,000 feet long. And 8 only one ram would be available for well control. 9 There's no backup ram for escalating well control 10 situations. 11 When closing the liner ram there's a scenario 12 where we could be pipe light. This is a situation 13 where the pipe could be jacked out of the DVRs because 14 they're just rubber elements, there's no slips. The 15 VBR does not provide a safeguard for securing the pipe 16 and there could be damage to the VBRs if or when the 17 pipes move due to jacking. 18 And the third bullet point is probably the most 19 important in my opinion, is the inconsistent shut-in 20 procedures. I touched on this in the first slide. We 21 have numerous size of pipes and configurations that are 22 run. When using these rams there would be multiple 23 shut-in procedures for joint and pipe operation. This 24 creates a decision point for the crews and it 25 introduces room for error. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 19 1 COMMISSIONER CHMIELOWSKI: Question. 2 MR. McLAUGHLIN: Uh-huh. 3 COMMISSIONER CHMIELOWSKI: You state that there 4 would be only one ram available for well control, no 5 backup ram. What would be your backup ram in your -- 6 in the preferred BOP configuration? 7 MR. McLAUGHLIN: We would have two, two and 8 three-eights pipe slip rams to shut-in. I'm going to 9 cover that in the next slide, I'll show you what it 10 would look like. So in this, the highlight, if we have 11 liner rams we would shut liner rams and the only ram 12 available would be the two and three-eights by three 13 and a half variable rams. In the preferred situation 14 we would have two and three-eights pipe slip rams on -- 15 below the flow cross and another set of two and three- 16 eights pipe slip rams above the flow cross. 17 COMMISSIONER WILSON: Could you describe the 18 kind of errors that the crew could possibly make you're 19 describing here? 20 MR. McLAUGHLIN: Yes. Muscle memory is what we 21 want the crews to have. And we want and we have a 22 variety of different people, we have two rigs with four 23 different crews and a lot of people coming and going. 24 We have different tool pushers, we have different 25 drillers and so we have this hodgepodge of people that AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 20 1 we need to work as a team, but there's people that 2 change in and out. We would like them to all know 3 their duty, a floorhand on one tower and one rig does 4 the same thing on another rig in any different time. 5 And anytime that they are running pipe in the ground 6 they know that they're going to grab that safety joint, 7 stab it, run it in and close your pipe slip rams. And 8 so that's -- that's the same whether they're running CS 9 hydril or perforating guns or slotted liner or solid 10 liner. They're doing the same thing every time. The 11 risk comes from -- let's say we're running perforating 12 guns in the hole, in that scenario we would pick up a 13 safety joint. And then under the regulations on the 14 top above the perforating guns we have CS hydril slip 15 for (indiscernible) and CS hydril for a couple hours 16 for running perf guns and then we'd have a different 17 shut-in procedure for the CS hydril above that because 18 we'd have a couple thousand feet of CS hydril. So we 19 get in that scenario where okay, we just swapped pipe 20 sizes so we have to completely swap the way that we 21 shut-in the well. 22 COMMISSIONER CHMIELOWSKI: Why not use the same 23 first method, still use the standing joint as the first 24 choice no matter what, if the VBRs are there or not? 25 MR. McLAUGHLIN: Say that again. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 21 1 COMMISSIONER CHMIELOWSKI: Why not use the same 2 first response with the standing joint or safety joint 3 and whether the VBRs are in place or not? 4 MR. McLAUGHLIN: Well, I think if the VBR's in 5 place my understanding is that we should use them. I 6 don't think it's responsible to have a set of rams in 7 place that we're not going to use. So the discussion 8 point here and what the decision's going to be is 9 either we shut-in on a safety joint or we shut-in the 10 liner rams. And I'm going to cover this again in a 11 later slide because I've heard from the Staff that oh, 12 you just put them in because that suits the regs, but 13 then shut-in any way you want. I don't think that's a 14 responsible way, that's not a good use of the BOP stack 15 and I think the Commission or the state is telling us 16 that if you have liner rams you should use them, that 17 -- that's my take. So if you have liner rams I don't 18 think we'd run a safety joint. 19 COMMISSIONER CHMIELOWSKI: Okay. Well, maybe 20 you'll get into this, but I'm just curious, you know, 21 if there's a scenario where it's -- you're not safe to 22 put a person into that area to place a safety joint, 23 you know, what do you do then, but you'll -- you're 24 going to get into that later? 25 MR. McLAUGHLIN: I'll get into that..... AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 22 1 COMMISSIONER CHMIELOWSKI: Okay. 2 MR. McLAUGHLIN: .....a little bit later. 3 COMMISSIONER CHMIELOWSKI: All right. 4 MR. McLAUGHLIN: That's escalating well control 5 and that -- that's..... 6 COMMISSIONER CHMIELOWSKI: Right. 7 MR. McLAUGHLIN: .....the what if scenario. 8 COMMISSIONER CHMIELOWSKI: Yeah. 9 MR. McLAUGHLIN: It's just the same what if 10 scenario, what if you go to shut the liner ram and it 11 doesn't seal, what -- what then. I mean, so these are 12 advanced well control options so yeah. 13 COMMISSIONER CHMIELOWSKI: Okay. You want to 14 talk about that now or later? 15 MR. McLAUGHLIN: Let's talk about it in the -- 16 in the final..... 17 COMMISSIONER CHMIELOWSKI: Okay. 18 MR. McLAUGHLIN: .....slide that I have. 19 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 20 MR. McLAUGHLIN: Slide number 7. This is the 21 justification not to install liner rams. So we're 22 still talking about liner rams and over on the right- 23 hand side we have our preferred stack. We leave the 24 three inch pipe slip rams in place and then we have two 25 and three-eights pipe slip rams above the flow cross AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 23 1 and two and three-eights pipe slip below the flow 2 cross. Using a safety joint allows for better overall 3 well control operation, it removes the operation 4 limiting VBRs as an option. We actually don't want the 5 VBRs in there to be shut, we don't want it to be an 6 option. If they're in there someone might decide that 7 is a good way to shut-in and you limit your well 8 control ability, you -- you're not able to bullhead any 9 longer. 10 Using the safety joint and pipe slip rams 11 provide greater well control ability. You have four to 12 five preventers available, you have -- you now have two 13 ram preventers available. The annular preventer closes 14 on all size of liners, the blind shear rams are proven, 15 the shear enclosed on all jointed pipe sizes. We're 16 able to circulate down the choke and kill line because 17 we're shut-in above the flow cross and we're able to 18 connect the coil to the liner and run the bottom and 19 kill the well. In the other situation when you're 20 shutting in liner rams you have to throw in slips and 21 so you don't have the ability to strip and usually are 22 running for a bottom kill. 23 The reservoir pressure is known, we have an 24 overbalance fluid column. There's no swabbing on the 25 final trip out due to continuous circulation. We have AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 24 1 infinite kick tolerance. The safety joint deployment 2 time averages around three minutes. We're able to 3 strip the bottom to kill the well and there's blind 4 shear rams available if we needed to cut in an 5 emergency. This mitigates the pipe light scenario. A 6 safety joint will utilize the pipe slip rams to prevent 7 the liner from jacking out of the ground. The pipe 8 slip rams would support the liner and this allows us to 9 make up the coil and the injector and run in the 10 bottom. And the -- and we would have consistent shut- 11 in procedures. The safety joint is a single closing 12 practice for all operation, there's no change to the 13 shut-in procedures in the middle of a jointed pipe run 14 and the crews would drill to a single shut-in procedure 15 for all situations. 16 COMMISSIONER CHMIELOWSKI: Is it possible to 17 put a VBR above the flow cross? 18 MR. McLAUGHLIN: No. Well, it -- it's 19 possible, but you would degradate well control in other 20 areas. We spend most of the time with coiled tubing 21 across the stack and that's where we have the greatest 22 risk is running coiled tubing while we're drilling, 23 while we're tripping. We figured 95 percent of the 24 time we have coiled tubing across. We would like the 25 coiled tubing rams up above the flow cross and so you AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 25 1 want blind shears up top and then your two and three- 2 eights coiled tubing rams. So yes, you could, but then 3 you have more significant problems in other areas of 4 well control. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. McLAUGHLIN: Aside from that one other 7 point before I move on with that question is if you're 8 questioning why we have two sets of two and three- 9 eights rams it's for redundancy. If we -- we could 10 take one of those out and add a VBR, but then with the 11 coiled tubing situation now you only have one slip ram 12 and if we ever have a pinhole or we need to cut pipe it 13 is more than nice to have -- to have redundant sets of 14 two and three- eights inch pipe rams. So that's where 15 we have the risk and that's why we like two sets of 16 rams in there. Those two sets of rams are above and 17 beyond what's called for in the regulations, but they 18 are well needed and appreciated. 19 COMMISSIONER CHMIELOWSKI: Because like you say 20 95 percent of the time you have the coil through the 21 BOP? 22 MR. McLAUGHLIN: That is correct. Slide number 23 eight is a title slide. We're going to swap over to 24 one inch and one and a quarter CS hydril rams and I'm 25 going to cover these probably a little quick. It -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 26 1 it's going to be very much the same commentary as the 2 two and three-eights, I just wanted -- there are a few 3 little different nuances. On the left-hand side the 4 same picture you just looked at, our conventional 5 drilling stack, I'm not going to read that again. But 6 in this case after the liner's on bottom and we are in 7 a clean out, logging or perforating situation is when 8 we'd run the one and a quarter or one inch CS hydril. 9 And so where we currently have the three inch pipe slip 10 rams we would change those out to one and a quarter 11 pipe slip rams or slide 10, one inch pipe slip rams. 12 That is determined by the size of the liner we're 13 running. When we're running two and seven-eights liner 14 we have one and a quarter CS hydril, when we're running 15 two and three-eights liner we have one inch CS hydril 16 is the difference. 17 Slide 11. These highlight the risks with 18 installing specific CS hydril rams. Shutting in on CS 19 hydril adds risk to the operation in multiple well 20 control areas. Closing CS hydril rams hinders the 21 management of a well control situation. We'd be unable 22 to circulate through the choke or kill line. CS hydril 23 jointed pipe strings are not suitable kill strings, 24 they're short and in this case they're very skinny. 25 When you shut-in on one inch CS hydril you're very AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 27 1 limited on what you can run through it and what you can 2 circulate through it. And there's only one ram 3 available for well control. 4 We don't believe this is an industry standard 5 piece of well control equipment. NOV has the design, 6 but have not sold a single set in the last 10 years. 7 NOV has only sold three sets of one inch and three sets 8 of one and a quarter inch to date ever. And I'm going 9 to talk a little bit more about this in the last slide. 10 And again it creates inconsistent shut-in 11 procedures. We'd be in a situation where we'd have to 12 have multiple shut-in people -- procedures for jointed 13 pipe operations and again it creates a decision point 14 for crews as to what to shut-in or giving them an 15 option to shut-in when it's not a good option. 16 COMMISSIONER CHMIELOWSKI: Mr. McLaughlin, 17 maybe you're going to get to this because I read the 18 slide pack before you came so I may be jumping ahead, 19 but I understand that post Macondo BP did implement 20 temporarily the use of hydril rams and then they 21 justified to BP Global, Alaska did, why not to. I'm 22 wondering if you have that information with you or are 23 those reasons or -- are you familiar with what I'm 24 saying? 25 MR. McLAUGHLIN: I'm very familiar..... AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 28 1 COMMISSIONER CHMIELOWSKI: Yeah. Okay. 2 MR. McLAUGHLIN: .....but I don't have the 3 documentation. COMMISSIONER CHMIELOWSKI: 4 Okay. 5 MR. McLAUGHLIN: But I was there for the 6 decision. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. McLAUGHLIN: I'll cover that. I have a 9 specific bullet point about that. 10 Slide number 12 is the justification to not 11 install CS hydril rams. This is why we'd like to run a 12 safety joint. We believe a safety joint is 13 operationally safer, more reliable shut-in procedure 14 and it has greater well control versatility. Removing 15 the CS hydril ram allows for better overall well 16 control operations. It removes the limiting CS hydril 17 as an option which is you can't bullhead kill because 18 it's below the flow cross. We would like to remove it 19 so it is not an option to shut-in because it puts you 20 in an inferior well control position. Utilizing the 21 safety joint and pipe slip rams provide greater well 22 control ability. You have four out of five preventers 23 available, you would have two rams to shut-in, you have 24 the annular preventer, blind shear rams. We are able 25 to circulate down the choke and kill line and you're AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 29 1 able to connect the coil to the liner. So these are 2 all the same reasons to run a safety joint as -- as 3 with the liner rams. We have known reservoir pressure, 4 overbalance fluid is confirmed. There's no swabbing on 5 the trip out due to continuous circulation. There's 6 infinite kick tolerance and blind shear rams would 7 allow for cutting the string in an emergency. 8 We'd be removing a nonstandard piece of well 9 control equipment and would not be relying on well 10 control equipment that is not used wisely. The safety 11 joint deployment for well control is an industry 12 accepted and standard practice. And running the safety 13 joint would allow for a consistent shut-in procedure. 14 There would be no change in shut-in procedures for 15 various jointed pipe operations and again the crews are 16 able to drill for a single shut-in procedure for all 17 situations. 18 COMMISSIONER CHMIELOWSKI: Quick question here. 19 There's a bullet that starts blind shear rams or 20 dropping string and below that it says these rams were 21 tested in September, 2024 to 5,000 pounds. Could you 22 tell us more about the test, that was a shear test, 23 what was sheared, what were the conditions, was it a 24 lab test? 25 MR. McLAUGHLIN: Well, I -- there was operation -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 30 1 you -- do you want to talk now, John, or..... 2 COMMISSIONER CHMIELOWSKI: Yeah, just identify 3 yourself and then go ahead, please. 4 MR. PERL: John Perl CTD foreman. What we did 5 prior to RC 119 is we rigged up in the shop with a one 6 inch chunk of..... 7 COMMISSIONER CHMIELOWSKI: Can you move your 8 microphone closer, please. Thanks. 9 MR. PERL: .....a one inch chunk of CS hydril 10 line, an inch and a quarter chunk, sheared both in the 11 shop and immediately went into a 250 low and 5,000 PSI 12 test, bench test right there right after shearing both 13 pipes. 14 COMMISSIONER CHMIELOWSKI: Do you -- was the 15 accumulator system used the same or similar to what's 16 on the rig? 17 MR. PERL: Exactly. 18 COMMISSIONER CHMIELOWSKI: And was the 19 accumulator used to deploy something else. I'm 20 imagining in a well control situation..... 21 MR. PERL: (Indiscernible - simultaneous 22 speech) Nabors test bay is where we..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. PERL: .....(indiscernible - simultaneous 25 speech) that is. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 31 1 COMMISSIONER CHMIELOWSKI: I'm just curious 2 that, you know -- you know, in a -- well, a situation 3 where you have to use a shear (indiscernible) probably 4 already tried something first, right, so I'm just 5 curious, you know, if you deployed the accumulator, you 6 know, or the -- I'm messing up my words, the annular. 7 If you used the accumulator to -- you know, to use the 8 annular and that doesn't work and now you're using the 9 shear ram, you know, how do you know that the 10 accumulator will have enough power, pressure to shear? 11 MR. PERL: Once we get to the -- my slide packs 12 there..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. PERL: .....Madame Commissioner, I'll be 15 going through all that. 16 COMMISSIONER CHMIELOWSKI: Okay. Great. 17 Thanks. 18 MR. McLAUGHLIN: While we're talking about 19 blind shear I'll point out that it is not in the shut- 20 in procedure, it is not in any of our rig procedures, 21 we're just pointing out that it is present if you get 22 into a radical or escalating conditions. We don't 23 proceduralize a shut-in or shear. It's not a surprise 24 that the one inch and one and a quarter sheared and 25 held pressure because we use high strength coil, two AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 32 1 inch, two and three-eights liners that are two and 2 three-eights, two and seven-eights and three and a 3 quarter. So it just -- it was more of a formality, it 4 wasn't a surprise. 5 I have two slides left and I think these are 6 going to get into a lot of your questions, Jessie. 7 We're on slide 13 right now. 8 We talked about this one a little bit earlier. 9 And these are comments, there's been a lot of back and 10 forth with the AOGCC Staff over the last couple years 11 really and these are comments that I've heard. They're 12 not verbatim, but they're more or less what I feel 13 might be some concerns. And so I wanted to just 14 address them and, you know, have opportunity to answer 15 any questions. Something that I've heard is it's okay 16 to swap the rams to be in compliance and not use them 17 and I think you were asking about this earlier. It 18 creates for really poor BOP stack management to have a 19 ram present that you're not going to use. And if the 20 liner rams are required to be in a BOP stack I believe 21 we're required to use them. It gets us in an 22 interesting -- a liability situation if the state says 23 you must have these liner rams I take that as you must 24 use them. So if liner rams or work strings are 25 required to be installed I would be forced to require AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 33 1 the rig to use them to shut-in. In doing so we would 2 significantly degrade well control. And so just to be 3 really clear I think we're asking, while we're here in 4 this hearing, is we're either going to shut-in on the 5 safety joint which is preferred or we're going to use 6 the liner rams to shut-in. We're not going to have 7 liner rams in the stack and then run a safety joint. 8 It's going to be one of those two, either shut-in on 9 the safety joint or shut-in with the liner rams. 10 COMMISSIONER CHMIELOWSKI: Could I clarify. Is 11 that your understanding of what the state wants or is 12 that Hilcorp's position on how it would operate or does 13 operate? 14 MR. McLAUGHLIN: That -- that's how we would 15 need to operate I believe because the regulations I 16 think are telling us that one, you have to have rams, I 17 think it's fair to ascertain from that that if you have 18 rams you should use them. 19 COMMISSIONER CHMIELOWSKI: Okay. So that's 20 your question, that's your understanding. I just want 21 to make sure I understand what you're..... 22 MR. McLAUGHLIN: That is my understanding. 23 COMMISSIONER CHMIELOWSKI: Okay. So..... 24 MR. McLAUGHLIN: And we now have perhaps a 25 hearing where the state is saying you have to have AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 34 1 liner rams, I think we would be remiss as a company to 2 have liner rams and then have procedures where we don't 3 use them to shut-in. 4 COMMISSIONER CHMIELOWSKI: Go ahead. 5 COMMISSIONER WILSON: Yeah, I guess I'll speak 6 for you and then you can maybe correct what I'm saying. 7 But what you're saying I guess basically is that if 8 required to have the liner rams then you're making that 9 a part of your procedure, you feel that your current 10 procedure with the safety joint if you used it there 11 would be more or less liability concerns that you 12 didn't follow AOGCC procedure by using the safety 13 joint? 14 MR. McLAUGHLIN: Not a AOGCC procedure, an 15 AOGCC mandate that you have to have liner rams in the 16 stack and I make the assumption that they should be 17 used else there's no point in having them in the stack. 18 But further to that if liner rams are in the stack and 19 even if we say okay, we're just going to put them in 20 just to be compliant, we're not going to use them, 21 doesn't feel very good. But there's a case where 22 someone will use them, we're going to have a smart guy 23 up there who says hey, we have a little kick, I'm going 24 to make this easy, I'm going to close the liner rams. 25 In which case we have a poor well control response, AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 35 1 we're not able to strip in the hole, we're not able to 2 bullhead kill. That's one of the greatest gifts for 3 coil tubing drilling and we've just taken it away by 4 having a ram in the stack that someone will use. It's 5 safer to not have that ram in the stack and take it 6 away as an option. 7 COMMISSIONER CHMIELOWSKI: So I'm going to 8 preface this by saying like all these scenarios are 9 extremely unlikely, right, but a BOP's there for the 10 last resort, right, like when you need it, you don't 11 expect to need it, but if you need it you need to have 12 it. So you're saying you would never use it, but I'm 13 -- and so maybe educate me or explain why, you know, if 14 you're in a scenario where there's a well control 15 situation and says there's some gas or something coming 16 to surface, I mean, aren't you sending a person into 17 that space to place a safety joint across the BOP? 18 MR. McLAUGHLIN: No, there -- there's a person 19 on the floor and so we would stab a safety joint, 20 flow's coming out to the pits, a slight amount of flow, 21 it's not -- okay, let me ask you -- let me -- let 22 me..... 23 COMMISSIONER CHMIELOWSKI: Because there's no 24 scenario where you wouldn't want someone down there, 25 you'd have to get them out? AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 36 1 MR. McLAUGHLIN: So it's the same, same. 2 You're going to have people working on the floor 3 regardless. Okay. Let's say we're running slotted 4 liner in the ground, you will have someone stabbing a 5 safety joint. So you're running perf guns in the 6 ground, you will have someone stabbing a safety joint. 7 Say you're running solid liner in the ground and 8 someone chooses to shut the liner rams, you still have 9 to have someone on the floor to stab a TIW valve. 10 There's work being done or you're still stabbing 11 something. With coil tubing and it's a very different 12 situation than rotary, we're not talking about a big 13 joint, we're talking about something that's two and 14 three-eights. It's fairly lightweight when you think 15 about things on a rig and it's just fairly easy to 16 stab. And these people they stab it quite easily, 17 quite efficiently, under three minutes, it's not a 18 significant time or significant endeavor. 19 COMMISSIONER CHMIELOWSKI: Okay. So I just 20 want to make sure I understand that you're -- what 21 you're saying is that always someone's going to be down 22 there no matter what the conditions are. 23 MR. McLAUGHLIN: On some -- someone..... 24 COMMISSIONER CHMIELOWSKI: I just -- I thought 25 BOP some of the point of it was some remote options, AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 37 1 right, for well control? 2 MR. McLAUGHLIN: It -- it happens on the floor. 3 No one's down in the BOP room..... 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MR. McLAUGHLIN: .....no one's down in the 6 cellar, it all happens on the floor where they were 7 running pipes. So we have people there running pipe 8 and those same people in that same location grab a 9 safety joint and stab that. So we're not going 10 anywhere, we're not running into a cellar or going 11 anywhere, that's more dangerous. It's happening in the 12 same place that we're running pipe. 13 COMMISSIONER CHMIELOWSKI: Okay. So there 14 could be like gas coming up or something, right, there 15 could be..... 16 MR. McLAUGHLIN: Yeah. 17 COMMISSIONER CHMIELOWSKI: .....and so they 18 would just stay is what you're saying to put the safety 19 joint? 20 MR. McLAUGHLIN: They would just stay and run 21 the safety joint, yes, just as they would when they're 22 running slotted liner or perforating guns or when they 23 have shut-in the rams and they have to stab a full open 24 safety valve. So there -- there's work to be done when 25 you shut-in, it's all part of shut-in. Now if -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 38 1 that's all normal shut-in procedure. If you want to go 2 way down the what if, what if, what if a lot of gas, 3 there's an annular present and that would be enacted 4 either in either case where you're running -- if you 5 are running in with a safety joint or if you have liner 6 across there, I mean, you do have an annular available 7 to shut-in. So there's ways to..... 8 COMMISSIONER CHMIELOWSKI: Which may help or 9 may not, but you have then the shears, right, the shear 10 rams? 11 MR. McLAUGHLIN: We haven't talked about shear 12 -- what do you mean about the shear rams? 13 COMMISSIONER CHMIELOWSKI: Well, you have the 14 shear rams and you talk -- I think you talk in here 15 about how they're, you know, available as a -- as an 16 option even though they're not required, right? 17 MR. McLAUGHLIN: The -- they are in there 18 because we're going to be running coiled tubing in the 19 ground..... 20 COMMISSIONER CHMIELOWSKI: Right. 21 MR. McLAUGHLIN: .....right. But before we get 22 to a shear conversation there have already been a lot 23 of things that have not gone right and that would be 24 conversations after attempted shut-in with the bag or 25 for whatever reason why we can't run a safety joint or AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 39 1 whatever. So the shear conversation is not a hit a 2 button and run, I mean, that's not typical for liner 3 runs and it's not in our shut-in procedures. 4 COMMISSIONER CHMIELOWSKI: Okay. It's just 5 that it's mentioned in your presentation..... 6 MR. McLAUGHLIN: Uh-huh. 7 COMMISSIONER CHMIELOWSKI: .....so I wanted to 8 address it. 9 MR. McLAUGHLIN: Oh, yeah. 10 COMMISSIONER CHMIELOWSKI: Yeah. 11 MR. McLAUGHLIN: Yeah. And that shear ram's 12 present in either scenario, it's not a -- we're not 13 saying that we should run a safety joint because we 14 have a shear ram. That shear ram is present in either 15 case and you can go down well control escalation 16 problems to where you get to that shear ram in either 17 case. So it's really not an added benefit for running 18 a safety joint or liner. I mean, it's going to be 19 there and you could be in a situation where you want to 20 discuss using that in either case. 21 COMMISSIONER CHMIELOWSKI: Let me just look at 22 one thing real quick. 23 MR. McLAUGHLIN: Uh-huh. 24 COMMISSIONER CHMIELOWSKI: It says -- you know, 25 it's part of -- shear rams are part of rejustification AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 40 1 so it should be part of -- the part I've listed on your 2 justification slide that utilizing a safety joint 3 provides greater well control because you have blind 4 shear rams that are proven to shear on all CTD joint 5 pipe. 6 MR. McLAUGHLIN: Uh-huh. 7 COMMISSIONER CHMIELOWSKI: So that has to be 8 part of your -- wouldn't it be also part of your plan 9 if it's part of your justification? 10 MR. McLAUGHLIN: I wouldn't say it's part of 11 the plan. I'm just highlighting that as present, we're 12 not taking away that option that that's there. And 13 like I could have that as a justification for having 14 liner rams as well. You have a liner ram, that liner 15 ram leaks, well, then you have a shear ram to close. 16 It's justification on both sides to be fair. 17 COMMISSIONER CHMIELOWSKI: Yeah. Yeah. Okay. 18 MR. McLAUGHLIN: I mean, it's not -- I can't 19 highlight it as we should run a safety joint because 20 have a shear ram and that's not what we're trying to 21 say. We're just saying that it's there because if I 22 was arguing that hey, we need liner rams I'd be telling 23 you hey, we have a shear ram there and it's available 24 to be used. So it's not a benefit and it wouldn't be 25 placed in either procedure, it's just something that's AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 41 1 present and either when we're running -- when we're 2 closing a liner ram or running a safety joint. 3 COMMISSIONER CHMIELOWSKI: Okay. 4 COMMISSIONER WILSON: I guess just, you know, 5 for the -- if there's anyone from the public listening 6 that is less familiar, but it would be your ultimate 7 shut-in though, the shear ram? 8 MR. McLAUGHLIN: It would be absolutely the 9 last resort, yeah. 10 COMMISSIONER WILSON: Yeah. In any case? 11 MR. McLAUGHLIN: In any case, yeah. In either 12 case. 13 We're still on slide 13. Bullet point two. We 14 talked about this a little bit as well. The previous 15 operator had CS hydril rams so should Hilcorp. And 16 this again is a comment that I've already heard from 17 the AOGCC. That's partly true. It was after Macondo 18 adding (indiscernible) rams became a previous 19 operator's mandate. The previous operator used their 20 company leverage to make -- to have Hydril build the 21 rams. Hydril didn't want to build those rams, they 22 didn't think they were a particular purpose in the 23 stack, but that operator said we -- if you're going to 24 do business with us you're going to build those rams 25 and by the way we just had Macondo so you need to do AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 42 1 them. And we -- and they used quite a bit of leverage, 2 it wasn't something that Hydril wanted to do or thought 3 was a good idea. I was -- I was very much involved in 4 that. There's only six of these ever made and after a 5 very short time Alaska received an exemption because 6 the previous operator understood that adding rams was 7 inferior well control. As far as documentation that 8 all went away in 2020 and I don't have that risk 9 assessment. A risk assessment was done, it was 10 reviewed with the bigger company and it was ultimately 11 approved. 12 COMMISSIONER CHMIELOWSKI: Okay. So I thought, 13 you know, Hilcorp had acquired BP Alaska as an entity, 14 but you're saying you don't have BP Alaska's 15 justification? 16 MR. McLAUGHLIN: We have lost a lot of the 17 documentation because it was just like an online risk 18 assessment tool. Anyway we looked, I don't have the 19 risk assessment..... 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. McLAUGHLIN: .....it didn't come across in 22 whatever, all the data that we got. 23 COMMISSIONER CHMIELOWSKI: I guess I would be 24 surprised because of -- they must have been pretty 25 thorough at that point, you know, BP's corporate AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 43 1 history, you know, to justify. I imagine they were 2 pretty doc -- you know, had a lot of documentation, 3 but..... 4 MR. McLAUGHLIN: Once they -- they -- the well 5 control people went through this and understood where 6 it was going to be in the stack and understood about 7 bullhead kill and understood that closing it on one 8 inch CS hydril and trying to run something through that 9 and then not being able to strip in the hole, when you 10 add all those things together it was a pretty easy 11 sell. It wasn't..... 12 COMMISSIONER CHMIELOWSKI: Okay 13 MR. McLAUGHLIN: .....a tough deviation again. 14 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 15 MR. McLAUGHLIN: The third bullet point. We're 16 just adding extra ram to the stack. We -- we've looked 17 at this and the problem is is it wouldn't work in many 18 cases due to wellhead height. We have two coil tubing 19 drilling rigs and in both cases with tree heights we 20 can't -- we don't have the extra room just to add 21 another stack. But even if we could it would create a 22 poor option for well control. Again you would be 23 shutting in below the flow cross and you'd be giving up 24 your ability to bullhead kill on the annulus and you'd 25 be giving up your ability to strip in because you have AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 44 1 the slip set. 2 Slide 14. And this is the one I've heard most 3 recently, paraphrasing again, what if you can't run a 4 safety joint or it takes a long time to install. This 5 is the -- I think the idea here is well, you just go 6 ahead and try and run the safety joint and your backup 7 would be shutting liner rams which we don't think is a 8 good backup. 9 So the safety joint is an industry standard 10 practice for many operations, there are a significant 11 number of comparable operations to reference. Other 12 coil tubing drillers and operating -- drilling 13 operators in Alaska across the North Slope have run 14 operations for years only relying on a safety joint for 15 well control. Every time the rig picks up perforating 16 guns and lays down perforating guns a safety joint is a 17 pract -- is a safe practice for well control. Kick 18 volume is not a significant factor in coil tubing 19 drilling due to unlimited kick tolerance. It's 20 important, but it's not as significant as in rotary 21 drilling. The liner is run in cased hole and sticking 22 is not a risk. The -- an annular preventer is 23 available to be closed if necessary and the BOP has 24 shear capability. These are available in either shut- 25 in method, whether you're talking about shutting in AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 45 1 with liner rams or shutting in on a safety joint, it's 2 not an extra layer of protection or is it included in 3 the shut-in plan. 4 COMMISSIONER CHMIELOWSKI: Could you please 5 elaborate on the Conoco operation you're referring to? 6 MR. McLAUGHLIN: The operation? 7 COMMISSIONER CHMIELOWSKI: Yeah. 8 MR. McLAUGHLIN: Yes. The other company on the 9 North Slope that has done a significant amount of coil 10 tubing drilling, they operate in Kuparuk. They've had 11 a sustained coil tubing drilling program since 2008. 12 They've drilled a couple hundred wells and many 13 laterals and every single one of those to my knowledge 14 they have used a safety joint as their shut-in method 15 because they are running solid -- slotted liners. 16 COMMISSIONER CHMIELOWSKI: So..... 17 MR. McLAUGHLIN: And so it's another operation 18 where they have years of experience, many, many, many 19 wells running slotted liner and utilizing a safety 20 joint to shut-in. 21 COMMISSIONER CHMIELOWSKI: Okay. So it's for a 22 slotted liner, but you're asking for -- Hilcorp's 23 asking for slotted and solid liner? 24 MR. McLAUGHLIN: For consistency, yes. 25 COMMISSIONER CHMIELOWSKI: Okay. But you -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 46 1 but to be clear Conoco's operation that you're 2 referring to is a slotted liner? 3 MR. McLAUGHLIN: Yes. 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MR. McLAUGHLIN: Just like when we run slottted 6 liner we would run a safety joint. 7 COMMISSIONER CHMIELOWSKI: Right. 8 MR. McLAUGHLIN: When we run solid liner we 9 would like to run a safety joint. 10 COMMISSIONER CHMIELOWSKI: Got it. 11 MR. McLAUGHLIN: At this time I'm going to pass 12 it over to John to talk about well control examples. 13 JOHN PERL 14 previously sworn, called as a witness on behalf of 15 Hilcorp Alaska, testified as follows on: 16 DIRECT EXAMINATION 17 MR. PERL: Okay. John Perl, CTD foreman. 18 Slide 15 here. We're going to talk about the well 19 control example, BOP example and basically the 20 difference between the -- these safety joints if we 21 shut-in with the -- with the liner rams. 22 On your left here we've got -- this is -- this 23 is the shear chart that we have associated with our 24 rams. If you notice that they're -- covers everything 25 from all our coil sizes through our liner rams to work AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 47 1 string. If pressure's there -- on the right-hand side 2 there's two columns, pressure zero to 5,000 wellhead 3 pressure, any of our liner rams here, the example 4 between CDR2, CDR3, after all our draw down tests on 5 our BOP tests, we are usually between a 2,100 pound and 6 2,200 pound hydraulic pressure on the cumi. That would 7 cover everything up there that we've got as far as with 8 the blind shears closed or with the -- utilizing 9 volumetrics to get the blind shears equivalent volume 10 closed, we would still be above any shear pressure on 11 the charts up there for that. 12 The right-hand column there, that is what we're 13 using for our standing orders there. I'm going to read 14 through these. To verify space, that was just make 15 sure that your liners cross, we're already setting the 16 hand slips with our liner. Once we go to installing a 17 safety joint, the guys turn around and they'll pick up 18 a safety joint, the guy on the floor will grab the 19 correct crossover for that thread and screw it into the 20 liner, make it up hand tight, pick up a safety joint, 21 safety joint gets screwed into that, then they both get 22 torqued. Pick up, pull the hand slips which is the 23 biggest advantage here, run the safety joint in and 24 then we close our upper pipes with rams and now your 25 support of the liner's now supported off the upper pipe AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 48 1 slip ram and not hand slips. The biggest advantage 2 right there, that puts you in your best situation for 3 one, stripping over, it's the only way we can get 4 stripped over with the injector with pipe slip rams 5 supporting the liner. We go into that with close -- 6 close up -- pipe close the full opening safety valve, 7 now we're in a good place to sit there and evaluate 8 what we need to evaluate, talk through the next 9 scenarios, get into the tertiary well control methods 10 after that point in time. 11 We'll go to a couple BOP stacks here. 12 COMMISSIONER CHMIELOWSKI: Can I -- are you 13 done with this slide, can I ask a question real quick? 14 MR. PERL: Yeah. 15 COMMISSIONER CHMIELOWSKI: On the shear chart, 16 did I read the date right, that that's 2024, was this 17 all done at the same time as the previous test you 18 mentioned? 19 MR. PERL: Yes, when we went through this here, 20 this has all been compiled between NOV tests that were 21 done and -- Trevor's got the information there, testing 22 that was done with all the shearing, most all this 23 stuff was calculated off of what NOV's shear 24 calculations were for. We've used this for -- this is 25 posted in -- at our accumulator and in our BOP control AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 49 1 in the ops caps. 2 COMMISSIONER CHMIELOWSKI: Okay. So this is a 3 calculated chart, it's not like a test, you just did 4 that one test on the hydril? 5 MR. PERL: The one test here, but we have the 6 information to support the test pressures on this 7 thing. 8 COMMISSIONER CHMIELOWSKI: Okay. And then did 9 you say that the pressure available to do the shear ram 10 assumed already some amount of the volume was used in 11 pressure for the accumulator? 12 MR. PERL: Yeah, and what I was getting at with 13 the accumulator, our accumulator draw down test, we -- 14 annular gets closed, annular get opened..... 15 COMMISSIONER CHMIELOWSKI: The annular, yeah. 16 MR. PERL: .....to do the -- because it's a 17 little bit larger volume than what our blind shears 18 with the boosters are and all of the three rams and our 19 HCRs. At that point in time we are higher pressure 20 than any of these shears with the -- with the whole 21 stack actuated. 22 COMMISSIONER CHMIELOWSKI: Oh, okay. The whole 23 stack's actuated..... 24 MR. PERL: The whole stack's actuated with the 25 blind shears already closed, either we close them or we AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 50 1 use the annular as our volumetric for the blind 2 shear..... 3 COMMISSIONER CHMIELOWSKI: Okay. 4 MR. PERL: .....so that would -- shows you that 5 with the blind shears closed we would still be above 6 any of the highest shear pressures there..... 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. PERL: .....even with a 5,000 pound 9 wellhead. 10 COMMISSIONER CHMIELOWSKI: All right. And is 11 this the same accumulator system that's actively used 12 on the CDR rigs? 13 MR. PERL: Yes. 14 COMMISSIONER CHMIELOWSKI: Okay. And how do 15 you guys test -- make sure the accumulator is -- and 16 all those bottles are properly filled and available for 17 use? 18 MR. PERL: During our BOP test the precharge is 19 checked and then basically we do our accumulator draw 20 down test for the BOP test..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. PERL: .....which tells us example to 23 example of each test you can see the trend if you're 24 starting to lose anything, my source or their source. 25 That's how we test them. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 51 1 COMMISSIONER CHMIELOWSKI: Okay. 2 MR. PERL: Okay. Yeah. This here's basically 3 the example that the di -- Powerpoint we'll use to kind 4 of go through scenarios and use a visualization of how 5 we shut-in with a safety joint, why we think it's 6 better than shutting in with a set of variable rams. 7 Okay. This here's stack configuration with 8 this running liner. This is our flow path right here, 9 that's the flow cross going to the pit, start PVT, get 10 annular open, everything's open, (indiscernible) HCR, 11 kill HCRs are closed and the rest of the stack tree's 12 open. We've got liner across the stack and we were to 13 -- we got the hand slips there. If the guys were to 14 stab across over and shut the well in there and even if 15 we used -- if we used the variables here. The 16 disadvantage here, what we're -- why we don't want 17 these even as a possibility of getting closed is we got 18 the jacking surge (ph) you know, you take away your 19 option to be able to strip in the hole with your 20 injector, get your injector stabbed on which is going 21 to give your best well control to be able to pick that 22 up, stab on, run to bottom, circulate the kick out of 23 the hole. The only other thing we have say the 24 variables do leak is we can close the annular to backup 25 that, but we're still in the same situation with it AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 52 1 being -- not being able to strip into the hole. 2 Another big thing for me is if you -- if we -- in this 3 situation if we had to go into a bullhead kill was our 4 only option of getting the well killed one, we would 5 have to come into here in the NPD line which is for our 6 most -- it's our operational line for pressure 7 deploying and as soon as you start using a 8 (indiscernible) pressure 8,800 and say KCL in the hole 9 you're looking at 1,800 just to start breaking out at 10 12,5. Well, lighter liners you're going to start 11 pushing through the variables, you're going to start 12 pushing through the annular, you'll start jacking out 13 of the hole. So if you've got to get any kind of 14 pressure to the well to start bullheading you put 15 yourself in a place you cannot do that. 16 See here, see the variables take away your flow 17 cross, we can go through here bullheading, but then 18 these are your only two using last resort like Sean's 19 talking way down the rack, around -- you could cut pipe 20 there. But that is -- that's really the only scenario 21 and that's why we want to get the variables out of 22 there so they can't be used because they would put us 23 in a very precarious position right off the get go. 24 COMMISSIONER CHMIELOWSKI: Well, a question 25 though. I know in a future slide that you guys kind of AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 53 1 indicate, you know, to add another ram to the stack, 2 you go from four to six, so how come you can't go four 3 to five and say put three in the top and two in the 4 bottom that you prefer that way you could still 5 circulate? 6 MR. PERL: Even five's is a stretch for our 7 cellars on both -- on -- what happened is when Nabors 8 did their upgrade when we wanted to get a better well 9 control scenario, we used to drill through our well 10 control choke manifold, through the flow cross..... 11 COMMISSIONER CHMIELOWSKI: Hmmm. 12 MR. PERL: .....so all your returns came 13 through here. Once they upgraded that and we put 14 piping into where we started putting in a traditional 15 flow cross per se on top of the annular to take our 16 returns out of there and go down a dedicated drilling 17 line that added a bunch of height to the top of the 18 stack where right now we're very, very limited within. 19 There's a lot of occasions we have to breakdown trees, 20 wellheads to get -- be able to get the stack over 21 the..... 22 COMMISSIONER CHMIELOWSKI: Okay. 23 MR. PERL: Okay. And this is what we're 24 wanting to do. So we stack same scenario, we run our 25 safety joint in, okay, PIW would be in the open AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 54 1 position running in the hole, we would turn around and 2 close our upper pipe slip rams here and then close our 3 TIW. And at that point in time you could open up your 4 choke HCR line up to the well control choke, close well 5 control choke. At this point in times gives you plenty 6 of time to discuss what's going on, next steps, you've 7 had -- you're ready to either run in the hole and 8 circulate the strip over and run in the hole and go to 9 bottom. You've got time to see if the well decides to 10 turn around, you're not worried about it jacking out of 11 the hole because you're on pipe slips at that point in 12 time. We can kill -- we can kill it traditionally 13 through the choke -- choke manifold kill line if we 14 have to here, we could bullhead through here, you got 15 the option here. Where I would go into this -- the 16 pros of the safety joint is number 1 is being able to 17 strip over, that's my number 1 that I like about this 18 shut-in method is that I can get the injector on it 19 immediately and go to bottom if I want to or we can sit 20 here and if we got other things to consider, is a 21 bullhead better, is getting to the hole, that kind of 22 stuff. 23 If we do have things like -- I mean, the 24 question always comes up, okay, pipe slip rams go 25 closed, you get ready to close and they're leaking, AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 55 1 you've got one, you got the annular as a backup there 2 to backup those if you need to. Still have your 3 ability to hang off with the pipe slip, but the annular 4 could do that. Vice versa if you have issues here you 5 can blow this -- set a lower oil tubing slips down here 6 if the -- for one, a leak or if the top slips aren't 7 holding. If you had to turn around and get in here you 8 -- we do have -- I forgot about this thing doing that. 9 10 COMMISSIONER CHMIELOWSKI: Start over. 11 MR. PERL: Yeah, all over again guys. Sorry 12 about that. Okay. We're shut-in there. It's got to 13 be the close. Okay. So let's talk about that, still 14 open there. We can go to opening up here, you're now 15 there we go, thanks, we can go here and we can -- we 16 can bullhead down through here if you have to have 17 anything below the flow cross shut-in and you're 18 controlled by jacking by two sets of pipe rams -- pipe 19 slip rams, excuse me. 20 COMMISSIONER CHMIELOWSKI: Would you still have 21 the scenario of having to pump at a high pressure that 22 would come up? 23 MR. PERL: You can, but with it being on slips 24 we would -- you still have that -- no matter with the 25 bullhead you're going to have to -- if the filter case AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 56 1 is doing it's job you're going to have to break it down 2 to get it really started taking fluid. But that gives 3 you the option here, but that's going way down the 4 realm. And then you -- we still on this scenario here 5 still have the option to close blind shears if that's a 6 last resort. We do have an example here and, I mean, 7 we -- this doesn't happen very often because F89 in 8 2023 we had -- this took a small kick and we had to 9 deploy safety joints with a one inch CS hydril. That 10 got shut-in, took basically a five barrel kick, they 11 monitored it for three, four hours while they were 12 talking about it and then stabbed the injector, on 13 stripped over, went to bottom, circulated everything 14 out and come out started laying down the hydril again. 15 So no incidents, worked very well. That's probably the 16 last -- last time I can remember in CTD we've had to 17 actually do this..... 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. PERL: .....but it -- it makes the best 20 scenario there. 21 COMMISSIONER CHMIELOWSKI: Could you humor me 22 by trying a different scenario where, you know, and I 23 just -- I'm thinking about the human factor, right, 24 because you go on these post incident reviews, you 25 know, there's multiple factors, one of them's the human AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 57 1 factor. So just say that safety joint, they have the 2 wrong one or it's -- you know, it's not put on, it's 3 not sealed, people don't have enough time, they need to 4 leave for whatever reason then what do you do if the 5 safety joint's not there? 6 MR. PERL: We still got the annular and we got 7 backup to shear if we had to. 8 COMMISSIONER CHMIELOWSKI: So it's annular and 9 shear would be -- okay. 10 MR. PERL: To preface a lot of this, Jessie, is 11 the safety joint we've got is laid down, already got 12 the valves open, already got a lifter on it which we 13 color code to the elevators we're using during that 14 run, everything's prepped for that before we ever start 15 running liner. All the safety joint crossovers for the 16 threads that we're going to be using are on the rig 17 floor, the one that is in use at that time has a spot, 18 it sits by itself, they're colored so we try to prep 19 ahead of time to make sure that that -- there's only 20 one they can pick up. 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. PERL: It's in the same spot, it's just off 23 the edge of our skate there. 24 COMMISSIONER CHMIELOWSKI: Right. So because 25 there's multiple sizes it could be, right, and so do AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 58 1 you like go through a safety drill like right before 2 you change sizes, when you change the -- the safety 3 joint, you know what I'm saying..... 4 MR. PERL: Well, that..... 5 COMMISSIONER CHMIELOWSKI: .....like okay, now 6 we're changing to this size so how do we make sure we 7 have the right one? 8 MR. PERL: The safety joint -- we should have 9 brought that. The safety joint is sized to whatever 10 coil size we are. So if we're running big -- big hole 11 liners and we've got two and three-eights pipe slips up 12 top and bottom our safety joint is a chunk of two and 13 three-eights, usually tubulars that we've got an inch 14 and a half MT pin on the bottom and a TIW already 15 installed on the top open. If we're -- if we go to 16 small liner that -- that turns into a two inch safety 17 joint and vice versa, we'll go to two and five-eights 18 coil. We always size our safety joint to the coil size 19 so when we bring -- put the safety joint in there that 20 gives us our upper and lower pipe slip rams that we can 21 use on that safety joint. And that's why we do get so 22 many scenarios that we've got for one, consistent shut- 23 in from the beginning to put us in the best place we 24 possibly can be and give us to where we're not having 25 to act hastily to decide on how we're going to get the AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 59 1 well killed and vice versa. The guy -- we got time. 2 So once it gets in, once it gets shut-in, the guys can 3 monitor, we can talk about it amongst myself and the 4 crew like Sean McLaughlin here. It gives you the 5 option there. The biggest reason with the variables is 6 if you -- if they're there they get shut on the liner, 7 you're -- you can't get the safety joint in, you lose 8 your ability to strip it, you're really unless the 9 well's taking fluid you really can't bullhead of any 10 kind of pressure if you've got to breakdown the 11 pressure. But what we're asking is to get the 12 variables completely out of the mix to where they can't 13 shut because our number 1 concern is make the guys 14 drill to a safety joint to where that is our primary 15 well control as far as getting the -- getting shut-in 16 for the well. And then they can do that across the 17 board. 18 And really the -- really the only thing that 19 changes is our crossovers we have on the -- on the rig 20 floor and our lifters which are all prepped prior and 21 we usually because we got such a short section of three 22 and a half or three and a quarter is we usually have 23 the -- a lifter size the same elevators, use that -- so 24 we just use lifters as we're running those joint pipes 25 so we don't have to change elevators and we can stay on AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 60 1 the same lifters. Trying to keep everything as 2 consistent as possible where there's not a lot of 3 change in the way we do things other than really a 4 crossover change. And the crossovers themselves are -- 5 they got -- we on CDR2, ours are very bright colored to 6 understand that those are and they're also stenciled 7 with red type that they use that they're paid for. And 8 there is usually an inch and a half box by whatever 9 pins are the thread size on the bottom. You know, 10 those guys -- there's been talk through worried about 11 cross-threading and all that kind of stuff, one inch 12 and half MTB in a work string thread is pretty hard to 13 get cross-threaded. The liner thread, the guys are 14 making that up by hand, getting four or five threads 15 and they get them as far as the guys are picking up the 16 safety joints. And then when they both get hand 17 screwed together then the little jerks (ph) go together 18 and they get (indiscernible) they go in, usually in 19 three, three and a half minutes which is kind of -- 20 depending on what the crews are. 21 COMMISSIONER CHMIELOWSKI: How many different 22 safety joints are there sizes, two? 23 MR. PERL: We got two right now, but when we go 24 to two and five-eights coil we'll have to have a third. 25 COMMISSIONER CHMIELOWSKI: Third. Until -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 61 1 what's Hilcorp's procedure, you know, on the rig to 2 make sure everyone's aware the correct size is there or 3 if it changes, you know, during the course of a 4 wellsite, does it -- does it change? 5 MR. PERL: Yeah, when we..... 6 COMMISSIONER CHMIELOWSKI: Okay. 7 MR. PERL: .....when we go into our pipe swap, 8 when we swap between two -- two inch -- two and three- 9 eights coil, that stuff gets changed out. Everything 10 from our safety joint size to our work string size, 11 we'll usually pull the one inch off or the inch and a 12 quarter off, put the one inch on, we go to two inch. 13 Most of the thread crossovers with the smaller liners 14 and stuff there's only usually two and three-eights, 15 there's -- there's only one crossover for that. The 16 safety joints that we -- we utilize, they get put up in 17 our rack and when we're on one coil size like right now 18 being on two and three-eights coil, the only safety 19 joints that laying on that case is the two and three- 20 eights safety joint. 21 COMMISSIONER CHMIELOWSKI: Okay. So I'm asking 22 the question maybe incorrectly, but I'm thinking of the 23 human factor again and is there a procedure like where 24 you have like everybody -- all hands on deck, this is 25 our safety joint, we just switched to this one and AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 62 1 everyone sees it's the correct one, you see what I 2 mean, versus like well, we assume it's the correct one, 3 it should be the correct one. How do you know and make 4 sure it's the correct..... 5 MR. PERL: It's my responsibility and also my 6 driller and..... 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. PERL: .....pushers that elevator gets OD 9 tape, the joint gets OD taped, all that stuff gets -- 10 it's part of the fire line and..... 11 COMMISSIONER CHMIELOWSKI: Okay. 12 MR. PERL: .....yeah. 13 COMMISSIONER CHMIELOWSKI: All right. Thanks. 14 MR. McLAUGHLIN: Let me add in one more thing, 15 Sean McLaughlin here before we move on this slide. 16 When -- I'd just like to point out that the annular you 17 were asking about, we have that as a secondary option 18 that will work for all sizes. When you're talking 19 about rotary that's typically the primary option. 20 COMMISSIONER CHMIELOWSKI: Hmmm. 21 MR. McLAUGHLIN: So we -- we've already -- 22 we're setting ourselves up for better than success with 23 attempting to run the safety joint. And then we still 24 have the annular which would be a great secondary in 25 many cases in many other operations is a primary. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 63 1 COMMISSIONER CHMIELOWSKI: Okay. Thanks for 2 that clarification. 3 MARTIN WALTERS 4 previously sworn, called as a witness on behalf of 5 Hilcorp Alaska, testified as follows on: 6 DIRECT EXAMINATION 7 MR. WALTERS: Martin Walters and I'm on slide 8 18. And I guess we'll forego the introduction since 9 we've already introduced ourselves. 10 I was asked by Hilcorp Alaska to provide some 11 objective scrutiny of their philosophy and testimony 12 and exhibits regarding the subject of coil tubing 13 drilling blowout preventers which we've been discussing 14 so far today. So, you know, a little bit about my 15 methodology. I basically have been attending team 16 meetings since early January and I reviewed the history 17 of the subject. And so a lot of the documentation 18 you've seen already the kick history likelihood, 19 there's some -- a shear study, wellhead height 20 limitations, et cetera that I'm going through and also 21 their current procedures including the well control 22 standing orders, the whole prior to pulling out of the 23 hole to run jointed pipe and I feel like it gave me a 24 good background to study and weigh the pros and cons of 25 the proposed options of using a safety joint versus AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 64 1 installing a set of variable bore rams or small pipe 2 rams to comply with Alaska statutes. 3 So and in my opinion with regards to well 4 control it comes down to an engineering judgment 5 decision based upon comparing the pros and cons with 6 respect to how quickly and how correctly a well can be 7 shut-in after detecting a kick. It's really just about 8 quickly and correctly shutting in to control the well. 9 Slide 19. For -- we've listed the pros and 10 cons of each case and made a comparison of the 11 engineering and operational aspects of each and so some 12 of the topics that we talk about were integrity which 13 would say how resistant the barrier is to potential 14 pressure and forces that it may be exposed to such as 15 jacking that has been described earlier. The shut-in 16 position, whether it's above or below the flow cross, 17 training, how effective the weekly drills will be and 18 how well will the information be retained, right, how 19 the ease at which that information can be communicated. 20 We talk about kick size, what is the relative kick size 21 based upon the time required to shut the well in and 22 compliance, whether or not it complies with the 23 existing Alaska statutes. 24 So slide 20. So just to kind of illustrate 25 some of the thought process that we undertook on each AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 65 1 one of those topics, the safety joint or the -- or the 2 kick joint as it's sometimes referred to, has a higher 3 integrity than variable bore rams due to the reduced 4 ability of the VBRs to prevent jacking when upward 5 forces in the wellbore exceed the weight of the pipe. 6 So not that the VBRs have no resistance against 7 jacking, but it is definitely less than a pipe slip. 8 Compared to the VBRs and the pipe ram case, a safety 9 joint case will always be shut-in above the flow cross 10 which will allow diversion of kick fluids through a 11 choke while the well is shut in. And, you know, as 12 it's been stated and it shouldn't be overlooked that 13 the crew -- the crew drills so that they become 14 proficient at a single shut-in process regardless of 15 which pipe is across the BOP stack. And you've seen 16 the list of possible pipe sizes and it's pretty 17 extensive. 18 So the biggest negative aspect of the safety 19 joint case is kick size. Due to the extra time 20 required to install a safety joint it's always going to 21 have a larger kick than the VBR or CS hydril cases and 22 the quantity's going to largely depend upon the rock 23 permeability fluid viscosity and the amount of 24 underbalance to determine the size of the kick and the 25 time required to take in which has been stated as, you AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 66 1 know, three to three and a half minutes. 2 So after looking at all of the pros and cons in 3 conclusion in my opinion the safety joint is a 4 preferable option because it's largest negative which 5 is kick size is offset by the infinite kick tolerance 6 of a coiled tubing drill coil. 7 COMMISSIONER CHMIELOWSKI: And, Mr. Walters, 8 this is presented as an either/or scenario, but why not 9 have both options available? 10 MR. WALTERS: I would defer to Sean or one of 11 the other guys why they -- you know, I studied the 12 options as given, right, the three options and I think 13 they've addressed those options earlier in their 14 testimony. 15 COMMISSIONER CHMIELOWSKI: Okay. So you don't 16 have an opinion, you're just giving your opinion on one 17 or the other which you would recommend? 18 MR. WALTERS: Right. And I've confined it to 19 my current area of expertise of, you know, shutting in 20 quickly and correctly. I think that, you know, from my 21 area of expertise it comes down to the -- you know, 22 those two topics. 23 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 24 MR. McLAUGHLIN: Sean McLaughlin. Slide 21. 25 In summary Hilcorp believes that a safety joint used to AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 67 1 shut-in a well is an industry standard. Using a safety 2 joint to shut-in is better than adding a liner or CS 3 hydril ram to the BOP. This isn't a -- there's 4 benefits in either case and I really like Martin's 5 matrix that he puts up. We're talking well control, it 6 -- it's not a good situation when we're talking about 7 well control so we look in aggregate and we sum the 8 pros and cons and we believe that a safety joint run 9 without liner rams in the stack is the best course of 10 action for well control. 11 And I agree human error is often what gets us 12 into trouble with well control. We've had many of 13 those conversations, there can be human error on either 14 side or when you have both. We believe that the 15 operation where you have -- run a safety joint and no 16 liner ram in our belief that offers the least potential 17 for human error. 18 I'd also like to point out that is a field 19 driven waiver request, it was the field that came to us 20 and for years asking us to change this. This isn't 21 driven by Hilcorp management or engineering, I'm here 22 in support of my eight drillsite managers and their 23 eight drillers. They all want to see this in place, 24 they all want to see that the preferred stack is in a 25 preferred shut-in method as running a safety joint AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 68 1 without a liner ram in the stack. When they look at -- 2 and they're all well control certified people, they're 3 the ones working in the floor, they're the ones picking 4 up the safety joint and they're all -- a hundred 5 percent of them have this request because they believe 6 it is best for well control. So I looked at it, I 7 questioned them very hard and I'm with them and I'm in 8 support of them. 9 So to sum up the waiver request, Hilcorp Alaska 10 requests a waiver for cased hole coil tubing drilling 11 jointed pipe operations to use a safety joint in lieu 12 of having a preventer equipped with a pipe ram that 13 fits the size of jointed pipe being run. 14 And that is our testimony. 15 COMMISSIONER CHMIELOWSKI: Thank you. Question 16 about -- this might be on the backup slides, but it's a 17 slide title begins other, other justification, but it 18 talks about well efficiency. So is this -- isn't that 19 part of this too, is well efficiency and the time that 20 it takes to change ram? 21 MR. McLAUGHLIN: Oh, there's certainly 22 efficiency. I didn't look at it. I don't care about 23 it when we're talking well control. What we looked at 24 is what is best for well control. 25 COMMISSIONER CHMIELOWSKI: Okay. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 69 1 MR. McLAUGHLIN: It's in there, we look at it, 2 but it wasn't a driver. 3 COMMISSIONER CHMIELOWSKI: Okay. And it just 4 mentions that it would add another well per year so I 5 wondered if it was significant to Hilcorp financially? 6 MR. McLAUGHLIN: No, it's not. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. McLAUGHLIN: Well control incidents are 9 very financially significant to Hilcorp. 10 COMMISSIONER WILSON: Commissioner Chmielowski, 11 anything further? 12 COMMISSIONER CHMIELOWSKI: So -- yeah. Does -- 13 is there anything -- I know the API standard is from 14 1997 geared toward rotary which is not a real perfect 15 fit for coiled tubing drilling, but does API have any 16 recommendations about not having the correct pipe rams 17 and using safety joints and other mitigations that 18 might be used in that situation? 19 MR. McLAUGHLIN: No, not that I'm aware of. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. McLAUGHLIN: Because when we are running 22 liner it is API 53 is the guiding document..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. McLAUGHLIN: .....and so even the updates, 25 it -- there hasn't been a significant change. And then AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 70 1 there hasn't been an integration of coil tubing 2 operations married with API 53. It -- it's really 3 we're in this gray area where it's a hybrid operation, 4 actually I wrote a SB paper on hybrid operations, but 5 98 percent, 99 percent of the drilling as a world is 6 rotary drill and that's covered under API 53. And then 7 you have 1 percent that's coil tubing drilling. The 8 liner running, it kind of sits in between, it's not 9 coil tubing drilling and it's, you know, a little 10 different than API 53 because we have a different -- 11 we're set up differently with kick tolerance and 12 wellbore and -- and the low party in place. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: But 53 is the guiding document 15 for running liner. 16 COMMISSIONER CHMIELOWSKI: Is there a -- you 17 know, when you're talking about running hydril in cased 18 well, right, so it'll be fully cased and that and so I 19 guess it could have slotted liner, but probably not, 20 right? 21 MR. McLAUGHLIN: Probably not. 22 COMMISSIONER CHMIELOWSKI: Yeah, so does the 23 liner lap pressure test, does that come into play with, 24 you know, ensuring that you have a fully cased hole, 25 you know, you're not getting production from the parent AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 71 1 or from the new lateral, you know, how does that come 2 into play, what does the..... 3 MR. McLAUGHLIN: It minimizes your exposure is 4 all it does. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. McLAUGHLIN: Even though we pump cement, we 7 have a failed liner top, pressure test on almost 75 8 percent of our wells. We're playing around with the 9 integral liner top packer in big hole sizes, but you -- 10 we're not completely isolated. Even so liner and 11 cemented you can still have a leak through the liner 12 top absolutely. 13 COMMISSIONER CHMIELOWSKI: Okay. So is that 14 tested, I mean, what -- what importance does it have 15 that the liner top or liner lap is sealing or pressure 16 tested? 17 MR. McLAUGHLIN: It's a financial barrier for 18 us..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. McLAUGHLIN: .....because we're in zone. 21 And there is no requirement for that liner top to pass 22 a test. What it means on production is we would make a 23 lot more gas than what we want, we would not make oil. 24 So it is in our best interest to have a sealing liner 25 top, but from a wellbore utility standpoint it doesn't AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 72 1 need to be sealing. 2 COMMISSIONER CHMIELOWSKI: Does it have 3 anything to do with well safety and well control is 4 what I'm curious too? 5 MR. McLAUGHLIN: It would minimize what -- for 6 the situation where you have liner in the hole and 7 you're pulling CS hydril out or even you are pulling 8 coil out of the ground, there would be less swab risk 9 because you have so much casing down there and you have 10 this liner lap where the OD of our liner running tool 11 is our liner top is 3 800 inside of 3 9. I mean, it's 12 a very small annulus that you -- you're going to swab 13 through. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. McLAUGHLIN: So your total open hole goes 16 from a lot to very, very little with cased hole in the 17 ground. 18 COMMISSIONER CHMIELOWSKI: And is CS hydril 19 ever run without cased hole, like you never run without 20 a liner, right, typically, does cased hole clean out 21 before you perf basically, is that the only scenario? 22 MR. McLAUGHLIN: We used to do completions 23 called bonsai completions..... 24 COMMISSIONER CHMIELOWSKI: Right. Right. 25 Right. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 73 1 MR. McLAUGHLIN: .....David McNamara developed 2 those, I guess it was in the early 2000s, but that's in 3 a case where we have slotted liner and a baffle plate 4 and then solid liner. And then when we cement only the 5 solid liner gets cemented. 6 COMMISSIONER CHMIELOWSKI: Got it. 7 MR. McLAUGHLIN: And that's a case where we run 8 in through the cemented solid liner, drill out the 9 baffle plate and then it would go into the slotted 10 liner. So that -- that's one case I can think of where 11 you run CS hydril into a slotted..... 12 COMMISSIONER CHMIELOWSKI: Into like a..... 13 MR. McLAUGHLIN: But you're running in three 14 joints or something. 15 COMMISSIONER CHMIELOWSKI: Right. Right. Does 16 Hilcorp ever do bonsai completions? 17 MR. McLAUGHLIN: We haven't. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. McLAUGHLIN: Yeah. 20 COMMISSIONER CHMIELOWSKI: Okay. I hadn't 21 heard that word in a long time. That's all I have for 22 now. 23 Thank you. 24 COMMISSIONER WILSON: Would you want to take a 25 short recess? AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 74 1 COMMISSIONER CHMIELOWSKI: Yes, please. 2 COMMISSIONER WILSON: I show 11:27 so we'll 3 take a 20 minute recess. 4 COMMISSIONER CHMIELOWSKI: Maybe a -- maybe 22, 5 make it an even number. 6 COMMISSIONER WILSON: Okay. 7 COMMISSIONER CHMIELOWSKI: So 11:50 we'll come 8 back? 9 COMMISSIONER WILSON: Yeah. 10 COMMISSIONER CHMIELOWSKI: Okay. 11:50. 11 Thanks. 12 (Off record - 11:27 a.m.) 13 (On record - 11:54 a.m.) 14 COMMISSIONER WILSON: I have 11:54, we'll call 15 the meeting back to order. 16 Commissioner Chmielowski, you have additional 17 questions. 18 COMMISSIONER CHMIELOWSKI: Yes, thanks for your 19 patience, we're a little late. First question and this 20 is for anybody so just state your name as you go 21 through. Does Hilcorp have any documentation where 22 AOGCC approved a 4,000 foot long BHA? 23 MR. McLAUGHLIN: Sean McLaughlin. Indirectly, 24 yes. I would say pretty much the drill approved since 25 the late '90s have included a BOP configuration and AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 75 1 plans to run a 4,000 foot BHA in the ground. And so I -- 2 I'd suggest that every one of those permits to drill 3 is approval. 4 COMMISSIONER CHMIELOWSKI: And the 4,000 foot 5 long hydril was explicitly written, do you recall? 6 MR. McLAUGHLIN: It would have been written to 7 clean out to bottom. 8 COMMISSIONER CHMIELOWSKI: Okay. 9 MR. McLAUGHLIN: And so whether we called out 10 the footage, I -- I'd have to go back..... 11 COMMISSIONER CHMIELOWSKI: Okay. 12 MR. McLAUGHLIN: .....and check. 13 COMMISSIONER CHMIELOWSKI: Thank you. Could 14 you please talk through the scenarios in a well control 15 situation where you have to strip in or out of the 16 hole, right. So first scenario is when you're using a 17 safety joint and then the second scenario is VBRs. And 18 so how are those different? 19 MR. PERL: Okay. We got our safety joint 20 diagram here. With the safety joint in the hole as the 21 well would be shut-in after a well control, a -- Madame 22 Commissioner, the important thing here is we've got no 23 hand slips set here which are outside the -- on the 24 base plate where you can't physically get a injector 25 across the top. What would happen here is because AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 76 1 you're supported with the upper pipe slips, TIW is 2 closed, the injector with -- coil tubing injector would 3 come across the floor, we have a swivel that can make 4 up to that inch and a half MT connection right there 5 off the top of that TIW. There's a box here, there's a 6 pin on the end of the coil. That can be made up, you 7 can fork up to the top of that TIW, you can -- in turn 8 you can pump down the coil tubing, get a service break 9 pressure test there to make sure that that connection 10 is holding and you can open up that TIW. From that 11 point what happens is is we go into a scenario just 12 like we pressure test a BHA or pressure deploy a BHA. 13 You dump the train -- the chain traction on the 14 injector which takes the chains off the pipes where the 15 pipes not supported -- the coil tubing's not supported. 16 From -- from there then we can strip down, basically 17 the injector strips down along the pipe leaving the 18 coil stationary. It comes down over the top of that 19 TIW after you -- you'd open up that T -- we'd -- let me 20 back up (indiscernible - away from microphone) here. 21 Once we get the pressure tested this would get open, 22 then we'd strip down, make up the lubricator connection 23 on the bottom of the injector to the stump on the top 24 of the BOP, we've got a quick test of their 25 hydraulically that we can test that connection with AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 77 1 4,000 pounds is what we usually -- we call our test 2 there. Then the -- they can grab traction on the pipe 3 again with a chain to the injector, they can pull to 4 what our known weight would be below the pipe rams. We 5 can come in through this conn -- through here we can 6 actually pressure -- pressure up and equalize across 7 this blind shear or we can come here and we've got -- 8 we've got piping on the other side of this that we can 9 open up, it just basically loops around above and below 10 that pipe ram to equalize the pressure. Then those 11 pipe rams can be opened and then we would run in the 12 hole like normal on coil, run down to bottom, wherever 13 our -- add our BHA into whatever length the liner would 14 happen to get in the hole, run to bottom, start while 15 we're -- while we're circulating, go to bottom, you can 16 circulate on bottom, you can pump it down the middle of 17 the coil, taking returns out your choke line here 18 through your (indiscernible - away from microphone) 19 choke or we got it with our remote choke there, 20 circulate it out, you can do a flow check at that point 21 in time on bottom, pull out of the hole, pop off the 22 top of the well as normal, you -- you'd put your hand 23 slips in and then you can start laying -- break the 24 injector off, lay down the pipe or you could just turn 25 around and keep running pipe in the hole to finish your AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 78 1 liner run. 2 COMMISSIONER CHMIELOWSKI: Okay. 3 MR. PERL: That's -- that is the safety joint 4 style. 5 COMMISSIONER CHMIELOWSKI: Are you actually 6 stripping through the pipe slips? 7 MR. PERL: No, no. 8 COMMISSIONER CHMIELOWSKI: No. 9 MR. PERL: We're stripping on the injector. 10 COMMISSIONER CHMIELOWSKI: On the injector. 11 Okay. 12 MR. PERL: Yeah, you cannot..... 13 COMMISSIONER CHMIELOWSKI: Yeah. Yeah. 14 MR. PERL: ....strip down through that stuff. 15 COMMISSIONER CHMIELOWSKI: Right. Okay. So 16 then -- oh, go ahead. Are you completed with this 17 scenario? 18 MR. PERL: Yeah, that..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. PERL: .....pretty much covers this. 21 COMMISSIONER CHMIELOWSKI: And how about what -- 22 if you have VBRs then how would you strip in the hole? 23 MR. PERL: Liner goes in, there's a liner 24 there, hand slips are in which is just holding the 25 weight of the pipe on the hand slips and they're set AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 79 1 into an actual false bowl there. If it was to happen 2 they turn around and they shut the -- the 3 (indiscernible - away from microphone) shuts that in 4 and they -- they shut the variables like we're talking. 5 You're -- you're not stripping it, you're -- you're 6 right there, you -- at that point in time you're not 7 stripping the hole. It physically cannot be stripped 8 in. 9 COMMISSIONER CHMIELOWSKI: Because you can't 10 get the lubricator, is what you're saying? 11 MR. PERL: No, because this is your limiting 12 factor here is this set of hand slips is this big. You 13 can't take the weight off the -- guarded you're grabbed 14 on to the liner so you can't move that liner anymore. 15 So to get those hand slips out you'd have to be able to 16 support that liner which means moving the liner, get 17 the hand slips out of the way and you can't physically 18 do that. That's one of the biggest reasons I don't 19 like this scenario at all, at least being able to do 20 the -- use the variables because it takes almost all 21 your options away..... 22 COMMISSIONER CHMIELOWSKI: Okay. 23 MR. PERL: .....your good options away 24 immediately. 25 COMMISSIONER CHMIELOWSKI: So the hand slips is AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 80 1 when..... 2 MR. PERL: The hand slips..... 3 COMMISSIONER CHMIELOWSKI: Got it. 4 MR. PERL: .....because they only -- they're a 5 tapered slip and they hang from the -- the pipe hangs 6 inside of them and your weight's supported off the hand 7 slips where the other way around when you shut-in with 8 the safety joint you're actually -- your whole liner 9 weight's hanging off this pipe slip. 10 COMMISSIONER CHMIELOWSKI: Thank you. 11 MR. PERL: Yeah. 12 COMMISSIONER CHMIELOWSKI: Another question 13 then about testing the annular. Does -- how does 14 Hilcorp test the annular, what's the largest and 15 smallest size pipe that it uses, you can go down to one 16 inch and then I guess your biggest would be what three 17 and a half. So how does Hilcorp test the annular on 18 the..... 19 MR. PERL: We -- we..... 20 COMMISSIONER CHMIELOWSKI: ......large and 21 small size? 22 MR. PERL: .....prior to -- prior to us talking 23 about the requirements of the one and a quarter inch, 24 one inch, we test our smallest which is usually our 25 coil site, two and three-eights or two inch, whichever AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 81 1 are up. And the variables get tested to coil size and 2 the biggest liner that we're going to be..... 3 COMMISSIONER CHMIELOWSKI: Okay. So does the 4 annular ever get test down to the hydril..... 5 MR. PERL: No. 6 COMMISSIONER CHMIELOWSKI: .....diameter? No. 7 Okay. 8 MR. McLAUGHLIN: Sean McLaughlin. To add on 9 this it's a seven and sixteenth annular and what we 10 know about annular preventers is the smaller size that 11 you run and try and test, you destroy the integrity of 12 the annular. So when you're shutting in on one inch 13 and testing that annular has a much shorter life. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. McLAUGHLIN: So that -- that's why -- one 16 of the reasons why you -- we don't really want to test 17 on one inch is you could destroy the integrity of that 18 annular much quicker. This is something that..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. McLAUGHLIN: .....that it's a -- it's a 21 fact with all annulars and previously just when 22 considered a BHA, we weren't required to test CS hydril 23 with the annular when we think of it of -- as a BHA. 24 COMMISSIONER CHMIELOWSKI: Okay. So are you 25 familiar with the API 16 ST NXE which talks about shear AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 82 1 rams -- performance tests on shear rams. Could you 2 please comment on that? 3 MR. McLAUGHLIN: I'm familiar with the API 16. 4 It's a coil tubing, API standard, it's a recommended 5 practice. It was I think originally written in 29 or 6 2009, reaffirmed in '14 and then rewritten oh, in 2021 7 or so. We've looked at 16 ST over the years with 8 previous operators and being a recommended practice 9 there -- there's some good ideas in there, there's some 10 good things and there's a lot of things that we don't 11 do because we're a mature operation, we don't believe 12 they apply. NXE is -- talks about shearing coil, it 13 talks about the methods you'd use to shear coil and 14 frequency and all that kind of business. It is a coil 15 tubing standard so I don't think it's material to 16 running jointed pipe. Shearing coil is differently 17 than shearing jointed pipe because of the residual 18 bend. So it's not applicable if we're talking about 19 shearing CS hydril or liner. 20 COMMISSIONER CHMIELOWSKI: Okay. Please 21 describe how Hilcorp tests and requalifies pipe slip 22 rams? 23 MR. PERL: John Perl. The way it -- we perform 24 our BOP tests, the way we perform them is we do our 25 weekly or biweekly BOP tests done on the whole stack, AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 83 1 pipe slip rams included. 2 COMMISSIONER CHMIELOWSKI: So the weekly tests 3 and then is there any sort of requalifying that you do 4 of these rams? 5 MR. PERL: They get basically requalified every 6 time we do a test. 7 COMMISSIONER CHMIELOWSKI: Every time you test. 8 Okay. 9 MR. PERL: Yeah. 10 COMMISSIONER CHMIELOWSKI: Okay. 11 MR. PERL: Yeah, the whole stack gets tested at 12 the same time. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: Sean McLaughlin. And then the 15 stack itself has requirements. Every five years it 16 goes in for a CAT5 inspection. So the BOPs, ram 17 bodies, carriers, blocks, everything, they -- they have 18 a time limit on it, all BOPs do. And it's typically 19 industry standard five years that it goes out of cycle 20 and has to get requalified. 21 COMMISSIONER CHMIELOWSKI: Okay. If the -- say 22 the pipe slip rams were used is there anything 23 additional Hilcorp would do to check those rams and 24 ensure they're still good? 25 MR. PERL: John Perl. Madame, yes, we -- if we AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 84 1 use the rams we -- they get retested as far as..... 2 COMMISSIONER CHMIELOWSKI: Immediately 3 retested? 4 MR. PERL: Immediately tested. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. PERL: First trip to surface..... 7 COMMISSIONER CHMIELOWSKI: Right. 8 MR. PERL: .....we'll retest them, yes. 9 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 10 So talking about, you know, just an escalating well 11 control scenario or say there's gas on the rig floor, 12 what are Hilcorp's well control procedures for that? 13 MR. PERL: John Perl. We escalate as -- if we 14 have gas to surface we'll run a liner, the guys will go 15 through the scenario of picking up the safety joints, 16 getting -- getting it stabbed, trying to get shut-in. 17 If we -- and then we would go into our tertiary stuff 18 as far as -- depending on what's going, is it not 19 hanging, then we've got our other pipe slips, we've got 20 our annular, we got other ways to get shut-in. 21 COMMISSIONER CHMIELOWSKI: Does Hilcorp have a 22 procedure for well control that might assume that say 23 people aren't allowed to be on the rig floor and need 24 to be evacuated immediately so aren't setting the 25 safety joints? AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 85 1 MR. PERL: At that point in time if it got to 2 where we -- the gas alarms were going off, that kind of 3 deal would be a shut-in, we'd have to shear pipe and 4 drop..... 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. PERL: .....and evacuate. 7 COMMISSIONER CHMIELOWSKI: So Hilcorp has a 8 procedure for that? 9 MR. PERL: Nabors/Hilcorp. 10 COMMISSIONER CHMIELOWSKI: Nabors does. Okay. 11 Okay. And I think this is my final question. So again 12 it's like a escalating well control scenario, gas on 13 the rig floor. So just want to clarify that the AOGCC 14 does not dictate an operator's well control procedure. 15 Okay. So there's gas on the rig floor so your gas 16 alarm's going off, there's the safety joint option, I 17 know you're saying there's a VBR only option or you -- 18 say you had both, you could use a safety joint and a 19 VBR. Which is better? 20 MR. PERL: It would be still -- still getting -- 21 getting the safety joint in the hole is number 1, 22 gives you the most forward looking progress of being 23 able to handle escalating because you -- you've got to 24 look at it also if you -- you got to get the well shut- 25 in, but you got to be -- put yourself in a place that AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 86 1 you can get the well back under control also. 2 MR. McLAUGHLIN: Sean McLaughlin. With 3 respect, Commissioner Chmielowski, I think I heard you 4 just say that the AOGCC does not dictate well control, 5 but by dictating what is -- must be in the stack, I 6 think that they may be -- if the AOGCC is dictating 7 what is in the BOP stack they're influencing well 8 control. 9 COMMISSIONER CHMIELOWSKI: So what is your 10 answer to the question, if you have only a safety 11 joint, only a VBR or you have the choice for both, 12 which is better? 13 MR. McLAUGHLIN: Looking at the aggregate of 14 integrity, human factors, timely shut-in, it is best to 15 run a safety joint and not have a liner ram in the 16 stack or CS hydril ram in the stack. That is best for 17 well control. 18 COMMISSIONER CHMIELOWSKI: Okay. I have no 19 further questions. Is there anything I missed? 20 COMMISSIONER WILSON: Nothing additional..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 COMMISSIONER WILSON: .....from me. 23 COMMISSIONER CHMIELOWSKI: We have a little bit 24 more of the hearing to go through with public comment 25 so go through that now. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 87 1 COMMISSIONER WILSON: Yeah. So now I'd like to 2 offer to any member of the public the opportunity to 3 testify or provide comments. As mentioned earlier no 4 written comments were received on this matter. 5 Samantha, is there anyone online? 6 MS. COLDIRON: No. 7 COMMISSIONER WILSON: Is there any member of 8 the public that would like to testify in the room? Put 9 -- yeah, please come forward and state your name for 10 the record. 11 MR. McKEEVER: (Indiscernible - away from 12 microphone). 13 COMMISSIONER CHMIELOWSKI: What's your 14 affiliation, Mr. McKeever? 15 MR. McKEEVER: I'm a member of the public. 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. McKEEVER: (Indiscernibles - either away 18 from the microphone or sounds like his mic is not on) 19 I'm a former -- by way of introduction I'm a 20 former drilling engineer, I've had (indiscernible - 21 microphone not on). I don't -- I'm not (indiscernible - 22 microphone not on) at all (indiscernible - microphone 23 not on) questions that are (indiscernible - microphone 24 not on) most of the -- most of the wells on the North 25 Slope are directional wells (indiscernible - microphone AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 88 1 not on) question in my mind (indiscernible - microphone 2 not on) accumulator pressure as low as possible. 3 (Indiscernible - microphone not on). I guess another 4 question (indiscernible - microphone not on) two or 5 three different liners (indiscernible - microphone not 6 on). Again as I mentioned, you know, again as you 7 consider the waiver if you do grant it, I'm not sure 8 (indiscernible - microphone not on). 9 Okay. Thank you. 10 COMMISSIONER WILSON: Thank you, Mr. McKeever. 11 Is there anyone else for comments? 12 (No comments) 13 COMMISSIONER WILSON: The line is still empty. 14 Well, then hearing no other business I have 12:16. The 15 hearing is now adjourned. 16 (Off record - 12:16 p.m.) 17 (END OF REQUESTED PORTION) 18 19 20 21 22 23 24 25 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 89 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: OTH-25-014, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 best of our knowledge and ability. 8 9 _______________ _______________________________ 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of Hilcorp Alaska's Request ) for a Waiver to 20 AAC 25.036(c)(2)(A)(iv) ) Coil Tubing Unit Operations Where at Least ) One Preventer Equipped with Pipe Rams that ) Fit the Size of the Tubing, Liner or Casing ) Being Used, Except that Pipe Rams Need Not ) be Sized to BHAs and Drill Collars. ) ____________________________________________) Docket number: OTH-25-014 PUBLIC HEARING May 29, 2025 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Greg Wilson, Commissioner AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 2 (Pages 2 to 5) Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Wilson 03 3 Testimony by Mr. McLaughlin 08 4 Testimony by Mr. Perl 46 5 Testimony by Mr. Walters 63 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 COMMISSIONER WILSON: Good morning. I will 4 call this hearing to order. It is approximately 10:00 5 a.m. on Thursday, May 29th, 2025. This is a public 6 hearing on docket number OTH-25-014. By letter 7 received March 21st, 2025, Hilcorp Alaska, LLC, filed a 8 request for hearing with the Alaska Oil and Gas 9 Conservation Commission regarding coiled tubing 10 drilling well control, a waiver request to 20 AAC 11 25.036(c)(2)(A)(iv). I'm Commissioner Greg Wilson and 12 with me is Commissioner Jessie Chmielowski. Today's 13 hearing is being held in person and via Microsoft 14 Teams. The in person location is the Alaska Oil and 15 Gas Conservation Commission at 333 West 7th Avenue, 16 Anchorage, Alaska. For those on Teams please be 17 mindful of any background noise and make sure you are 18 muted when you're not testifying or addressing the 19 AOGCC. 20 If you require any special accommodation please 21 contact Samantha Coldiron, she can be reached at 907- 22 793-1223 or send her a message through Microsoft Teams 23 chat icon and she will do her best to accommodate you. 24 Samantha Coldiron will be recording the 25 hearing, Computer Matrix will be preparing the Page 4 1 transcript. Upon completion and preparation of the 2 transcript anyone desiring a copy will be able to 3 obtain it by contacting Computer Matrix. 4 This hearing is being held in accordance with 5 Alaska statute 44.62 and 20 AAC 25.540 of the Alaska 6 Administrative Code. The notice of hearing was 7 published on the Alaska -- on the state of Alaska 8 Online Notices website as well as the AOGCC's website 9 and was sent through the AOGCC email listserv on April 10 1st, 2025. The AOGCC also published the notice in the 11 Anchorage Daily News on March 26, 2025. To date the 12 AOGCC has received no public comments on this matter. 13 By way of background on March 21st, 2025 14 Hilcorp Alaska, LLC filed a request for public hearing 15 with the AOGCC for a waiver request to 20 AAC 16 25.36(c)(2)(A)(iv) that reads at least one preventer 17 equipped with pipe rams that fit the size of the 18 tubing, liner or casing be used except that the pipe 19 rams need not be sized to BHAs and drill collars. 20 The Commissioners will ask questions during 21 testimony. We may also take a recess to consult with 22 Staff to determine whether additional information or 23 clarifying questions are necessary. 24 Representatives from Hilcorp, are you prepared 25 to make your presentation? Page 5 1 MR. McLAUGHLIN: Yes, we are. 2 COMMISSIONER WILSON: I will now swear in the 3 witnesses. Will all of you please raise your right 4 hands and respond. 5 (Oath administered) 6 IN UNISON: Yes. 7 COMMISSIONER WILSON: Let the record reflect 8 the witnesses all responded in the affirmative. 9 Do any of you presenting wished to be 10 recognized as experts? 11 MR. McLAUGHLIN: Yes, all three of us do. 12 COMMISSIONER WILSON: So one by one then please 13 identify your field of expertise and your credentials. 14 MR. McLAUGHLIN: Sean McLaughlin. I have a BS 15 in mechanical engineering. I've attended many 16 technical schools including coil tubing operations, 17 coil tubing engineering, managing hole problems, stuck 18 pipe, tubing stress analysis, casing design and 19 completion tools. I've performed BOP risk assessments, 20 cap analysis to API and company procedures and 21 performed peer reviews supporting clear platforms, 22 Saudi Arabia and Trinidad. I have 26 years in industry 23 and coil tubing, coil tubing drilling, rig workover and 24 rotary drilling. I'm currently the drilling manager 25 for Hilcorp Alaska. AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 3 (Pages 6 to 9) Page 6 1 COMMISSIONER WILSON: Thank you. Before we go 2 to the next witness, Sam, was that going through the 3 microphone? 4 MS. COLDIRON: Yes. 5 COMMISSIONER WILSON: It was. Okay. Next, 6 please. 7 MR. WALTERS: Good morning. My name is Martin 8 Walters. I'm an independent oil industry consultant 9 currently specializing in International Association of 10 Drilling Contractors or IADC well control certification 11 training. I've been an Alaska resident for 20 years 12 and have a bachelor of science degree in petroleum 13 engineering from Louisiana State University in Baton 14 Rouge, Louisiana. I've approximately 40 years of oil 15 industry experience in a wide variety of roles 16 including production operations, production 17 engineering, reservoir engineering, project 18 coordination, well intervention, well integrity and 19 well control. 20 COMMISSIONER WILSON: Thank you. 21 MR. PERL: Hi, my name's John Perl. I'm the 22 CTD Hilcorp senior drilling foreman. I've got 28 years 23 of -- in the industry with the last 10 being spent 24 supervising CTD ops with BP and Hilcorp. Started my 25 career in 1997 with Halliburton running slick line and Page 7 1 a couple years with Schlumberger doing that. Went into 2 the wells group for BP in 2006 as wellsite leader, 3 supervising slick line operation and transitioned into 4 Milne Point well operations coordinator for their well 5 work out there. 2012 I transferred back to CTU to work 6 service coils, wellsite leader. 2014 I decided -- I 7 was asked to go to CTU (indiscernible) and have been 8 there since and (indiscernible) Hilcorp 2020. 9 COMMISSIONER WILSON: Commissioner Chmielowski, 10 are you satisfied with the expertise and credentials as 11 presented? 12 COMMISSIONER CHMIELOWSKI: Yes, I am. 13 COMMISSIONER WILSON: You will all be 14 recognized as experts in the field you identified. 15 Before asking Hilcorp to begin their 16 presentation, Commissioner Chmielowski, do you have any 17 questions? 18 COMMISSIONER CHMIELOWSKI: No. Thank you. 19 COMMISSIONER WILSON: Okay. For those of you 20 testifying please remember to speak into the 21 microphone, also reference your slides by number or 22 title so that someone reading the public record can 23 follow along. And each time you speak please state 24 your name and job title clearly for the record. Please 25 begin. Page 8 1 SEAN McLAUGHLIN 2 previously sworn, called as a witness on behalf of 3 Hilcorp Alaska, testified as follows on: 4 DIRECT EXAMINATION 5 MR. McLAUGHLIN: Sean McLaughlin, drilling 6 manager for Hilcorp Alaska. Slide one. First a little 7 orientation. We're going to have three of us speaking, 8 we have 21 slides to cover, 14 are mine. I'm going to 9 cover the engineering and planning piece and then I'll 10 pass it over to John, he'll cover the operation piece 11 and then we'll hand it to Martin to cover well control. 12 So that's how it's kind of laid out. I have about 30 13 minutes, maybe John has about 15, 20 minutes and Martin 14 about 15 minutes is kind of what we have planned. 15 Slide one here. You guys have already -- 16 you've read the regulation, the waiver request is -- is 17 for taste (ph) hole coil tubing drilling, jointed pipe 18 operations, use of a safety joint with a TIW valve to 19 shut-in the well is acceptable. 20 And then down below that there's a whole list 21 of jointed pipe that we run in the hole. I'm not going 22 to read it all, it's just -- there's 13 configurations 23 and so there's a lot of -- could be a lot of different 24 methods to shut-in. What we want to get across is that 25 there's safety and standardization and one method of Page 9 1 shutting in is preferable, not going back and forth 2 between methods. For example with the slotted liner 3 and the perforating guns we are required to use a 4 safety joint for shutting in. The request that we're 5 talking about is for the three and a half, three and a 6 quarter and two and seven-eights solid liner. 7 Currently we have variable bore rams, liner rams, we 8 would like to use a safety joint in lieu of those liner 9 rams. And then also for the CS hydril the one and a 10 quarter and one inch CS hydril historically this has 11 been considered part of BHA and we have not had rams, 12 but a change in interpretation will require rams for 13 that. We would prefer to use a safety joint to shut-in 14 on the CS hydril as well. 15 Slide two. 16 COMMISSIONER CHMIELOWSKI: May I ask a couple 17 questions, please. 18 MR. McLAUGHLIN: Yes. 19 COMMISSIONER CHMIELOWSKI: You mentioned case 20 pull operations, but the variable bore rams is that for 21 open hole? 22 MR. McLAUGHLIN: So for running the liner and 23 I'll get a little more into this and -- and I thank you 24 for asking, it kind of bounds the request a little bit 25 for when we run the coil tubing liner. We're only AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 4 (Pages 10 to 13) Page 10 1 running that in cased hole. I don't think it would be 2 an appropriate request if you're running a long liner 3 into open hole. You have things like stuck pipe and 4 then usually you're in horizontal where you could run 5 into a kick. So the -- the cased hole and why I have 6 that capitalized is to put a bound on the waiver 7 request saying that we have a short liner section 8 usually running to a vertical part of the well where 9 the risk is smaller. For rotary operations you often 10 have a long liner that is run into open hole and 11 horizontal. So it is a bounding condition. 12 COMMISSIONER CHMIELOWSKI: Okay. So just to 13 clarify you're saying the well would have open hole 14 deeper, but the liner would be in the cased hole? 15 MR. McLAUGHLIN: Yes. Thank you..... 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. McLAUGHLIN: .....for that clarification. 18 COMMISSIONER CHMIELOWSKI: Okay. And then 19 could you just give us some more information about the 20 historical, you know, the hydril being historically 21 considered part of the BHA. Do you have information 22 about when that started and who did it, when, you know, 23 that sort of stuff? 24 MR. McLAUGHLIN: Yeah, it -- it goes back to 25 the mid '90s is when coil tubing first started gaining Page 11 1 popularity in Alaska. And it was just a drilling, a 2 coil tubing drilling with a service unit and then they 3 would move off and a rotary unit would come in and run 4 that liner on jointed pipe. And that's where a lot of 5 the regulation come from. And then later it evolved to 6 coil tubing would run the liner and then they would 7 move off and rotary would come in and cement it. As 8 part of that operation in '95, '97, that's when we 9 started using the CS hydril to clean out after the 10 cement job. So that -- that practice dates at least to 11 '97 that I know of where we're using CS hydril to run 12 inside the liners for a clean out. And so that -- that 13 spans both ARCO, BP and all -- all previous operators. 14 COMMISSIONER CHMIELOWSKI: And, you know, the 15 hydril can be what, several feet in length -- several 16 thousand feet, is that what I said, yeah, several 17 thousand feet in length? 18 MR. McLAUGHLIN: Yeah, up to..... 19 COMMISSIONER CHMIELOWSKI: Yeah. 20 MR. McLAUGHLIN: .....4,000 feet..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. McLAUGHLIN: .....in length. 23 COMMISSIONER CHMIELOWSKI: Yeah. Let's go to 24 the next slide. Thanks. 25 MR. McLAUGHLIN: Okay. Slide two. And so this Page 12 1 is where I talk a little about the regulation and the 2 risk and the history of the regulation. So the 3 regulation that we're talking about is based on API RP 4 53 which is really specifically for rotary drilling. 5 That one was written in 1997 and which was appropriate 6 at the time. Coil tubing drilling was in its early 7 stages, we didn't know a whole lot about it. And we -- 8 like I just said we were still running liners on 9 jointed pipe. But over the last 20 or so years coil 10 tubing has developed quite a bit, we have specific coil 11 tubing drilling rigs and it -- it's kind of a gray area 12 between rotary drilling and interventions, but we 13 operate under RP 53 so it's kind of a clunky fit. But 14 coiled drilling has a different risk profile. Some of 15 those are -- liner is deployed in cased oil, but the 16 liner section is short in comparison to the total 17 depth, there's continuous pipe when tripping which has 18 reduced swab tendency. The wells are horizontals which 19 changes the swab migration. A swab kick would not 20 migrate in a horizontal well. We have unlimited kick 21 tolerance and you're going to hear this a few different 22 times through the presentation. When coil drilling 23 moves on the well the well is already construction -- 24 constructed, the wellbore elements are in place and so 25 it's -- it's more of an intervention activity, but we Page 13 1 don't have the same tolerances that we do in a rotary 2 well, we don't have an FIT test and so we're able to 3 bullhead kill the well which gives us another option 4 for well control that's typically not available in 5 rotary drilling or in RP 53. 6 So with all those things coiled drilling has 7 superior kick prevention, kick detection and well 8 control. There are shear rams present in the stack 9 that are not required by RP 53 and there's a tree and 10 master valve on the well which is typically not 11 something that you would see with a rotary drilling 12 operation. 13 And then as far as the risk piece, over a 14 thousand wells have been drilled on the North Slope, 15 coiled tubing drilled wells on the North Slope with 16 zero significant well control events from running liner 17 or work string so we consider this a low probability 18 event based on historical information. 19 COMMISSIONER WILSON: Could you elaborate on 20 the superior kick detection? 21 MR. McLAUGHLIN: Yes. With a kick detection 22 since we are continuous we can do dynamic flow checks 23 as we're pulling out of the hole and we have 24 micromotions on the rigs and so we have a finer 25 tolerance to measure fluid in and out of the well. The AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 5 (Pages 14 to 17) Page 14 1 kick prevention piece that speaks to the continuous 2 circulating we can do while running in and out. We're 3 not making up connections every joint and so we can -- 4 we do continuously circulate on the trip out which 5 reduces swab tendency. 6 COMMISSIONER CHMIELOWSKI: Do you -- do you 7 have any, you know, supporting evidence for the 8 statement about zero significant well control events? 9 MR. McLAUGHLIN: Just a quick look back at my 10 historical knowledge. I've been involved in coil 11 tubing drilling since 2001 and so it's based on my 12 recollection in historically BP and Hilcorp areas..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: .....and the little bit I know 15 about ConocoPhillips. 16 Slide three. I wanted to take a minute and 17 talk about the kick scenarios since this is all has to 18 do with well control and I wanted to set the stage for 19 when we think about the risk matrix where -- where we 20 sit on a probability side of things. So for running 21 and pulling liner, a kick while running and pulling 22 liner where we're talking about either running a safety 23 joint or closing liner rams the situation would be the 24 well has been drilled to TD, it has been circulated 25 clean, it has been flow checked, we've laid down the Page 15 1 drilling BHA and we've observed the well. So there's 2 been significant time to monitor the well before 3 running liner. The liner is run in cased hole and 4 usually a fairly vertical section over a short 5 duration. This has a lower risk for running into a 6 kick. We consider this a low probability and low 7 severity event. It's not going to be an intensity kick 8 and likely there's not going to be a large gas volume 9 and there would be low surface pressure. This kick has 10 a similar probability as to when we're running slotted 11 liner. A safety joint is acceptable for slotted liner 12 and it should be acceptable for solid liner as well. 13 The next one is kick while deploying CS hydril. 14 So this is usually we've already done everything up 15 above, we've already run the liner in the ground and so 16 we've had all this time to monitor the well, the 17 liner's in the bottom, it's typically been cemented, 18 the liner running tool has been pulled and we've laid 19 down those tools and we've monitored the well. 20 Historically AOGCC, Hilcorp and previous operators have 21 considered CS hydril as part of the BHA. This has been 22 since the late '90s. We consider the CS hydril as a 23 tool to allow entry into the liner. The work string is 24 the coil tubing and that's when you're going to take 25 the significant amount of risk when that is at the Page 16 1 bottom of the well you have coil tubing across your BOP 2 stack and that's typically when you would see gas in 3 the horizontal section or when you would swab gas in. 4 We believe both scenarios have lower risk, have 5 a lower well control risk than running perf guns or 6 slotted liner. For example an annular preventer is not 7 effective on perf guns or when running slotted liner 8 there will be flow inside and outside. 9 Slide four. This is a title slide. And we're 10 going to talk about specifically that the two and 11 three-eights by three and a half liner rams next and it 12 will be in two pieces. We'll cover liner rams and then 13 we'll cover CS hydril rams. 14 Slide five. This is an illustration of the BOP 15 stack. On the left-hand side is the current BOP 16 configuration for drilling. Top down we have an 17 annular preventer, blind shear rams, two and three- 18 eights pipe slip rams, a flow cross, three inch pipe 19 slip rams and two and three-eights pipe slip rams. So 20 that's our current setup for drilling. On the right- 21 hand side is what the regulations would require us to 22 do. We would swap out the three inch pipes rams for 23 two and three-eights by three and a half variable bore 24 rams. On that right side I'd like to also point out 25 that those shear rams up above, they're -- they're not Page 17 1 required for running liner, they're in there because of 2 the coil tubing drilling piece and they're just -- 3 they're just extras, but they're not required by RP 53 4 in this case. 5 So slide six. 6 COMMISSIONER CHMIELOWSKI: Could you please 7 talk about those three inch pipe slip rams. Those are 8 I understand needed for drilling with a managed 9 pressure drilling system; is that okay? 10 MR. McLAUGHLIN: Okay. Our B -- our drilling 11 BHA is three inch..... 12 COMMISSIONER CHMIELOWSKI: Okay. 13 MR. McLAUGHLIN: .....and so we use those for 14 deploying the BHA..... 15 COMMISSIONER CHMIELOWSKI: Okay. 16 MR. McLAUGHLIN: .....pressure, deploying and 17 un-deploying the BHA. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. McLAUGHLIN: So that -- that's why those 20 are in place. 21 Slide number 6. We stick with that picture on 22 the right and so we're going to talk about the risk 23 when liner rams are installed. Shutting in on liner 24 rams adds risk to the operation in multiple well 25 control areas. Closing the BBR hinders the management AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 6 (Pages 18 to 21) Page 18 1 of well -- of a well control situation. We would be 2 unable to circulate through the choke or kill line 3 because we are shut-in below the flow cross. We'd be 4 unable to kill the well from bottom because we're not 5 able to strip to bottom. Coiled drilling liners are 6 not suitable kill strings. They're not on bottom, 7 typically they're only 500 to 4,000 feet long. And 8 only one ram would be available for well control. 9 There's no backup ram for escalating well control 10 situations. 11 When closing the liner ram there's a scenario 12 where we could be pipe light. This is a situation 13 where the pipe could be jacked out of the DVRs because 14 they're just rubber elements, there's no slips. The 15 VBR does not provide a safeguard for securing the pipe 16 and there could be damage to the VBRs if or when the 17 pipes move due to jacking. 18 And the third bullet point is probably the most 19 important in my opinion, is the inconsistent shut-in 20 procedures. I touched on this in the first slide. We 21 have numerous size of pipes and configurations that are 22 run. When using these rams there would be multiple 23 shut-in procedures for joint and pipe operation. This 24 creates a decision point for the crews and it 25 introduces room for error. Page 19 1 COMMISSIONER CHMIELOWSKI: Question. 2 MR. McLAUGHLIN: Uh-huh. 3 COMMISSIONER CHMIELOWSKI: You state that there 4 would be only one ram available for well control, no 5 backup ram. What would be your backup ram in your -- 6 in the preferred BOP configuration? 7 MR. McLAUGHLIN: We would have two, two and 8 three-eights pipe slip rams to shut-in. I'm going to 9 cover that in the next slide, I'll show you what it 10 would look like. So in this, the highlight, if we have 11 liner rams we would shut liner rams and the only ram 12 available would be the two and three-eights by three 13 and a half variable rams. In the preferred situation 14 we would have two and three-eights pipe slip rams on -- 15 below the flow cross and another set of two and three- 16 eights pipe slip rams above the flow cross. 17 COMMISSIONER WILSON: Could you describe the 18 kind of errors that the crew could possibly make you're 19 describing here? 20 MR. McLAUGHLIN: Yes. Muscle memory is what we 21 want the crews to have. And we want and we have a 22 variety of different people, we have two rigs with four 23 different crews and a lot of people coming and going. 24 We have different tool pushers, we have different 25 drillers and so we have this hodgepodge of people that Page 20 1 we need to work as a team, but there's people that 2 change in and out. We would like them to all know 3 their duty, a floorhand on one tower and one rig does 4 the same thing on another rig in any different time. 5 And anytime that they are running pipe in the ground 6 they know that they're going to grab that safety joint, 7 stab it, run it in and close your pipe slip rams. And 8 so that's -- that's the same whether they're running CS 9 hydril or perforating guns or slotted liner or solid 10 liner. They're doing the same thing every time. The 11 risk comes from -- let's say we're running perforating 12 guns in the hole, in that scenario we would pick up a 13 safety joint. And then under the regulations on the 14 top above the perforating guns we have CS hydril slip 15 for (indiscernible) and CS hydril for a couple hours 16 for running perf guns and then we'd have a different 17 shut-in procedure for the CS hydril above that because 18 we'd have a couple thousand feet of CS hydril. So we 19 get in that scenario where okay, we just swapped pipe 20 sizes so we have to completely swap the way that we 21 shut-in the well. 22 COMMISSIONER CHMIELOWSKI: Why not use the same 23 first method, still use the standing joint as the first 24 choice no matter what, if the VBRs are there or not? 25 MR. McLAUGHLIN: Say that again. Page 21 1 COMMISSIONER CHMIELOWSKI: Why not use the same 2 first response with the standing joint or safety joint 3 and whether the VBRs are in place or not? 4 MR. McLAUGHLIN: Well, I think if the VBR's in 5 place my understanding is that we should use them. I 6 don't think it's responsible to have a set of rams in 7 place that we're not going to use. So the discussion 8 point here and what the decision's going to be is 9 either we shut-in on a safety joint or we shut-in the 10 liner rams. And I'm going to cover this again in a 11 later slide because I've heard from the Staff that oh, 12 you just put them in because that suits the regs, but 13 then shut-in any way you want. I don't think that's a 14 responsible way, that's not a good use of the BOP stack 15 and I think the Commission or the state is telling us 16 that if you have liner rams you should use them, that 17 -- that's my take. So if you have liner rams I don't 18 think we'd run a safety joint. 19 COMMISSIONER CHMIELOWSKI: Okay. Well, maybe 20 you'll get into this, but I'm just curious, you know, 21 if there's a scenario where it's -- you're not safe to 22 put a person into that area to place a safety joint, 23 you know, what do you do then, but you'll -- you're 24 going to get into that later? 25 MR. McLAUGHLIN: I'll get into that..... AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 7 (Pages 22 to 25) Page 22 1 COMMISSIONER CHMIELOWSKI: Okay. 2 MR. McLAUGHLIN: .....a little bit later. 3 COMMISSIONER CHMIELOWSKI: All right. 4 MR. McLAUGHLIN: That's escalating well control 5 and that -- that's..... 6 COMMISSIONER CHMIELOWSKI: Right. 7 MR. McLAUGHLIN: .....the what if scenario. 8 COMMISSIONER CHMIELOWSKI: Yeah. 9 MR. McLAUGHLIN: It's just the same what if 10 scenario, what if you go to shut the liner ram and it 11 doesn't seal, what -- what then. I mean, so these are 12 advanced well control options so yeah. 13 COMMISSIONER CHMIELOWSKI: Okay. You want to 14 talk about that now or later? 15 MR. McLAUGHLIN: Let's talk about it in the -- 16 in the final..... 17 COMMISSIONER CHMIELOWSKI: Okay. 18 MR. McLAUGHLIN: .....slide that I have. 19 COMMISSIONER CHMIELOWSKI: Okay. Thanks. 20 MR. McLAUGHLIN: Slide number 7. This is the 21 justification not to install liner rams. So we're 22 still talking about liner rams and over on the right- 23 hand side we have our preferred stack. We leave the 24 three inch pipe slip rams in place and then we have two 25 and three-eights pipe slip rams above the flow cross Page 23 1 and two and three-eights pipe slip below the flow 2 cross. Using a safety joint allows for better overall 3 well control operation, it removes the operation 4 limiting VBRs as an option. We actually don't want the 5 VBRs in there to be shut, we don't want it to be an 6 option. If they're in there someone might decide that 7 is a good way to shut-in and you limit your well 8 control ability, you -- you're not able to bullhead any 9 longer. 10 Using the safety joint and pipe slip rams 11 provide greater well control ability. You have four to 12 five preventers available, you have -- you now have two 13 ram preventers available. The annular preventer closes 14 on all size of liners, the blind shear rams are proven, 15 the shear enclosed on all jointed pipe sizes. We're 16 able to circulate down the choke and kill line because 17 we're shut-in above the flow cross and we're able to 18 connect the coil to the liner and run the bottom and 19 kill the well. In the other situation when you're 20 shutting in liner rams you have to throw in slips and 21 so you don't have the ability to strip and usually are 22 running for a bottom kill. 23 The reservoir pressure is known, we have an 24 overbalance fluid column. There's no swabbing on the 25 final trip out due to continuous circulation. We have Page 24 1 infinite kick tolerance. The safety joint deployment 2 time averages around three minutes. We're able to 3 strip the bottom to kill the well and there's blind 4 shear rams available if we needed to cut in an 5 emergency. This mitigates the pipe light scenario. A 6 safety joint will utilize the pipe slip rams to prevent 7 the liner from jacking out of the ground. The pipe 8 slip rams would support the liner and this allows us to 9 make up the coil and the injector and run in the 10 bottom. And the -- and we would have consistent shut- 11 in procedures. The safety joint is a single closing 12 practice for all operation, there's no change to the 13 shut-in procedures in the middle of a jointed pipe run 14 and the crews would drill to a single shut-in procedure 15 for all situations. 16 COMMISSIONER CHMIELOWSKI: Is it possible to 17 put a VBR above the flow cross? 18 MR. McLAUGHLIN: No. Well, it -- it's 19 possible, but you would degradate well control in other 20 areas. We spend most of the time with coiled tubing 21 across the stack and that's where we have the greatest 22 risk is running coiled tubing while we're drilling, 23 while we're tripping. We figured 95 percent of the 24 time we have coiled tubing across. We would like the 25 coiled tubing rams up above the flow cross and so you Page 25 1 want blind shears up top and then your two and three- 2 eights coiled tubing rams. So yes, you could, but then 3 you have more significant problems in other areas of 4 well control. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. McLAUGHLIN: Aside from that one other 7 point before I move on with that question is if you're 8 questioning why we have two sets of two and three- 9 eights rams it's for redundancy. If we -- we could 10 take one of those out and add a VBR, but then with the 11 coiled tubing situation now you only have one slip ram 12 and if we ever have a pinhole or we need to cut pipe it 13 is more than nice to have -- to have redundant sets of 14 two and three- eights inch pipe rams. So that's where 15 we have the risk and that's why we like two sets of 16 rams in there. Those two sets of rams are above and 17 beyond what's called for in the regulations, but they 18 are well needed and appreciated. 19 COMMISSIONER CHMIELOWSKI: Because like you say 20 95 percent of the time you have the coil through the 21 BOP? 22 MR. McLAUGHLIN: That is correct. Slide number 23 eight is a title slide. We're going to swap over to 24 one inch and one and a quarter CS hydril rams and I'm 25 going to cover these probably a little quick. It -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 8 (Pages 26 to 29) Page 26 1 it's going to be very much the same commentary as the 2 two and three-eights, I just wanted -- there are a few 3 little different nuances. On the left-hand side the 4 same picture you just looked at, our conventional 5 drilling stack, I'm not going to read that again. But 6 in this case after the liner's on bottom and we are in 7 a clean out, logging or perforating situation is when 8 we'd run the one and a quarter or one inch CS hydril. 9 And so where we currently have the three inch pipe slip 10 rams we would change those out to one and a quarter 11 pipe slip rams or slide 10, one inch pipe slip rams. 12 That is determined by the size of the liner we're 13 running. When we're running two and seven-eights liner 14 we have one and a quarter CS hydril, when we're running 15 two and three-eights liner we have one inch CS hydril 16 is the difference. 17 Slide 11. These highlight the risks with 18 installing specific CS hydril rams. Shutting in on CS 19 hydril adds risk to the operation in multiple well 20 control areas. Closing CS hydril rams hinders the 21 management of a well control situation. We'd be unable 22 to circulate through the choke or kill line. CS hydril 23 jointed pipe strings are not suitable kill strings, 24 they're short and in this case they're very skinny. 25 When you shut-in on one inch CS hydril you're very Page 27 1 limited on what you can run through it and what you can 2 circulate through it. And there's only one ram 3 available for well control. 4 We don't believe this is an industry standard 5 piece of well control equipment. NOV has the design, 6 but have not sold a single set in the last 10 years. 7 NOV has only sold three sets of one inch and three sets 8 of one and a quarter inch to date ever. And I'm going 9 to talk a little bit more about this in the last slide. 10 And again it creates inconsistent shut-in 11 procedures. We'd be in a situation where we'd have to 12 have multiple shut-in people -- procedures for jointed 13 pipe operations and again it creates a decision point 14 for crews as to what to shut-in or giving them an 15 option to shut-in when it's not a good option. 16 COMMISSIONER CHMIELOWSKI: Mr. McLaughlin, 17 maybe you're going to get to this because I read the 18 slide pack before you came so I may be jumping ahead, 19 but I understand that post Macondo BP did implement 20 temporarily the use of hydril rams and then they 21 justified to BP Global, Alaska did, why not to. I'm 22 wondering if you have that information with you or are 23 those reasons or -- are you familiar with what I'm 24 saying? 25 MR. McLAUGHLIN: I'm very familiar..... Page 28 1 COMMISSIONER CHMIELOWSKI: Yeah. Okay. 2 MR. McLAUGHLIN: .....but I don't have the 3 documentation. COMMISSIONER CHMIELOWSKI: 4 Okay. 5 MR. McLAUGHLIN: But I was there for the 6 decision. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. McLAUGHLIN: I'll cover that. I have a 9 specific bullet point about that. 10 Slide number 12 is the justification to not 11 install CS hydril rams. This is why we'd like to run a 12 safety joint. We believe a safety joint is 13 operationally safer, more reliable shut-in procedure 14 and it has greater well control versatility. Removing 15 the CS hydril ram allows for better overall well 16 control operations. It removes the limiting CS hydril 17 as an option which is you can't bullhead kill because 18 it's below the flow cross. We would like to remove it 19 so it is not an option to shut-in because it puts you 20 in an inferior well control position. Utilizing the 21 safety joint and pipe slip rams provide greater well 22 control ability. You have four out of five preventers 23 available, you would have two rams to shut-in, you have 24 the annular preventer, blind shear rams. We are able 25 to circulate down the choke and kill line and you're Page 29 1 able to connect the coil to the liner. So these are 2 all the same reasons to run a safety joint as -- as 3 with the liner rams. We have known reservoir pressure, 4 overbalance fluid is confirmed. There's no swabbing on 5 the trip out due to continuous circulation. There's 6 infinite kick tolerance and blind shear rams would 7 allow for cutting the string in an emergency. 8 We'd be removing a nonstandard piece of well 9 control equipment and would not be relying on well 10 control equipment that is not used wisely. The safety 11 joint deployment for well control is an industry 12 accepted and standard practice. And running the safety 13 joint would allow for a consistent shut-in procedure. 14 There would be no change in shut-in procedures for 15 various jointed pipe operations and again the crews are 16 able to drill for a single shut-in procedure for all 17 situations. 18 COMMISSIONER CHMIELOWSKI: Quick question here. 19 There's a bullet that starts blind shear rams or 20 dropping string and below that it says these rams were 21 tested in September, 2024 to 5,000 pounds. Could you 22 tell us more about the test, that was a shear test, 23 what was sheared, what were the conditions, was it a 24 lab test? 25 MR. McLAUGHLIN: Well, I -- there was operation -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 9 (Pages 30 to 33) Page 30 1 you -- do you want to talk now, John, or..... 2 COMMISSIONER CHMIELOWSKI: Yeah, just identify 3 yourself and then go ahead, please. 4 MR. PERL: John Perl CTD foreman. What we did 5 prior to RC 119 is we rigged up in the shop with a one 6 inch chunk of..... 7 COMMISSIONER CHMIELOWSKI: Can you move your 8 microphone closer, please. Thanks. 9 MR. PERL: .....a one inch chunk of CS hydril 10 line, an inch and a quarter chunk, sheared both in the 11 shop and immediately went into a 250 low and 5,000 PSI 12 test, bench test right there right after shearing both 13 pipes. 14 COMMISSIONER CHMIELOWSKI: Do you -- was the 15 accumulator system used the same or similar to what's 16 on the rig? 17 MR. PERL: Exactly. 18 COMMISSIONER CHMIELOWSKI: And was the 19 accumulator used to deploy something else. I'm 20 imagining in a well control situation..... 21 MR. PERL: (Indiscernible - simultaneous 22 speech) Nabors test bay is where we..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. PERL: .....(indiscernible - simultaneous 25 speech) that is. Page 31 1 COMMISSIONER CHMIELOWSKI: I'm just curious 2 that, you know -- you know, in a -- well, a situation 3 where you have to use a shear (indiscernible) probably 4 already tried something first, right, so I'm just 5 curious, you know, if you deployed the accumulator, you 6 know, or the -- I'm messing up my words, the annular. 7 If you used the accumulator to -- you know, to use the 8 annular and that doesn't work and now you're using the 9 shear ram, you know, how do you know that the 10 accumulator will have enough power, pressure to shear? 11 MR. PERL: Once we get to the -- my slide packs 12 there..... 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. PERL: .....Madame Commissioner, I'll be 15 going through all that. 16 COMMISSIONER CHMIELOWSKI: Okay. Great. 17 Thanks. 18 MR. McLAUGHLIN: While we're talking about 19 blind shear I'll point out that it is not in the shut- 20 in procedure, it is not in any of our rig procedures, 21 we're just pointing out that it is present if you get 22 into a radical or escalating conditions. We don't 23 proceduralize a shut-in or shear. It's not a surprise 24 that the one inch and one and a quarter sheared and 25 held pressure because we use high strength coil, two Page 32 1 inch, two and three-eights liners that are two and 2 three-eights, two and seven-eights and three and a 3 quarter. So it just -- it was more of a formality, it 4 wasn't a surprise. 5 I have two slides left and I think these are 6 going to get into a lot of your questions, Jessie. 7 We're on slide 13 right now. 8 We talked about this one a little bit earlier. 9 And these are comments, there's been a lot of back and 10 forth with the AOGCC Staff over the last couple years 11 really and these are comments that I've heard. They're 12 not verbatim, but they're more or less what I feel 13 might be some concerns. And so I wanted to just 14 address them and, you know, have opportunity to answer 15 any questions. Something that I've heard is it's okay 16 to swap the rams to be in compliance and not use them 17 and I think you were asking about this earlier. It 18 creates for really poor BOP stack management to have a 19 ram present that you're not going to use. And if the 20 liner rams are required to be in a BOP stack I believe 21 we're required to use them. It gets us in an 22 interesting -- a liability situation if the state says 23 you must have these liner rams I take that as you must 24 use them. So if liner rams or work strings are 25 required to be installed I would be forced to require Page 33 1 the rig to use them to shut-in. In doing so we would 2 significantly degrade well control. And so just to be 3 really clear I think we're asking, while we're here in 4 this hearing, is we're either going to shut-in on the 5 safety joint which is preferred or we're going to use 6 the liner rams to shut-in. We're not going to have 7 liner rams in the stack and then run a safety joint. 8 It's going to be one of those two, either shut-in on 9 the safety joint or shut-in with the liner rams. 10 COMMISSIONER CHMIELOWSKI: Could I clarify. Is 11 that your understanding of what the state wants or is 12 that Hilcorp's position on how it would operate or does 13 operate? 14 MR. McLAUGHLIN: That -- that's how we would 15 need to operate I believe because the regulations I 16 think are telling us that one, you have to have rams, I 17 think it's fair to ascertain from that that if you have 18 rams you should use them. 19 COMMISSIONER CHMIELOWSKI: Okay. So that's 20 your question, that's your understanding. I just want 21 to make sure I understand what you're..... 22 MR. McLAUGHLIN: That is my understanding. 23 COMMISSIONER CHMIELOWSKI: Okay. So..... 24 MR. McLAUGHLIN: And we now have perhaps a 25 hearing where the state is saying you have to have AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 10 (Pages 34 to 37) Page 34 1 liner rams, I think we would be remiss as a company to 2 have liner rams and then have procedures where we don't 3 use them to shut-in. 4 COMMISSIONER CHMIELOWSKI: Go ahead. 5 COMMISSIONER WILSON: Yeah, I guess I'll speak 6 for you and then you can maybe correct what I'm saying. 7 But what you're saying I guess basically is that if 8 required to have the liner rams then you're making that 9 a part of your procedure, you feel that your current 10 procedure with the safety joint if you used it there 11 would be more or less liability concerns that you 12 didn't follow AOGCC procedure by using the safety 13 joint? 14 MR. McLAUGHLIN: Not a AOGCC procedure, an 15 AOGCC mandate that you have to have liner rams in the 16 stack and I make the assumption that they should be 17 used else there's no point in having them in the stack. 18 But further to that if liner rams are in the stack and 19 even if we say okay, we're just going to put them in 20 just to be compliant, we're not going to use them, 21 doesn't feel very good. But there's a case where 22 someone will use them, we're going to have a smart guy 23 up there who says hey, we have a little kick, I'm going 24 to make this easy, I'm going to close the liner rams. 25 In which case we have a poor well control response, Page 35 1 we're not able to strip in the hole, we're not able to 2 bullhead kill. That's one of the greatest gifts for 3 coil tubing drilling and we've just taken it away by 4 having a ram in the stack that someone will use. It's 5 safer to not have that ram in the stack and take it 6 away as an option. 7 COMMISSIONER CHMIELOWSKI: So I'm going to 8 preface this by saying like all these scenarios are 9 extremely unlikely, right, but a BOP's there for the 10 last resort, right, like when you need it, you don't 11 expect to need it, but if you need it you need to have 12 it. So you're saying you would never use it, but I'm 13 -- and so maybe educate me or explain why, you know, if 14 you're in a scenario where there's a well control 15 situation and says there's some gas or something coming 16 to surface, I mean, aren't you sending a person into 17 that space to place a safety joint across the BOP? 18 MR. McLAUGHLIN: No, there -- there's a person 19 on the floor and so we would stab a safety joint, 20 flow's coming out to the pits, a slight amount of flow, 21 it's not -- okay, let me ask you -- let me -- let 22 me..... 23 COMMISSIONER CHMIELOWSKI: Because there's no 24 scenario where you wouldn't want someone down there, 25 you'd have to get them out? Page 36 1 MR. McLAUGHLIN: So it's the same, same. 2 You're going to have people working on the floor 3 regardless. Okay. Let's say we're running slotted 4 liner in the ground, you will have someone stabbing a 5 safety joint. So you're running perf guns in the 6 ground, you will have someone stabbing a safety joint. 7 Say you're running solid liner in the ground and 8 someone chooses to shut the liner rams, you still have 9 to have someone on the floor to stab a TIW valve. 10 There's work being done or you're still stabbing 11 something. With coil tubing and it's a very different 12 situation than rotary, we're not talking about a big 13 joint, we're talking about something that's two and 14 three-eights. It's fairly lightweight when you think 15 about things on a rig and it's just fairly easy to 16 stab. And these people they stab it quite easily, 17 quite efficiently, under three minutes, it's not a 18 significant time or significant endeavor. 19 COMMISSIONER CHMIELOWSKI: Okay. So I just 20 want to make sure I understand that you're -- what 21 you're saying is that always someone's going to be down 22 there no matter what the conditions are. 23 MR. McLAUGHLIN: On some -- someone..... 24 COMMISSIONER CHMIELOWSKI: I just -- I thought 25 BOP some of the point of it was some remote options, Page 37 1 right, for well control? 2 MR. McLAUGHLIN: It -- it happens on the floor. 3 No one's down in the BOP room..... 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MR. McLAUGHLIN: .....no one's down in the 6 cellar, it all happens on the floor where they were 7 running pipes. So we have people there running pipe 8 and those same people in that same location grab a 9 safety joint and stab that. So we're not going 10 anywhere, we're not running into a cellar or going 11 anywhere, that's more dangerous. It's happening in the 12 same place that we're running pipe. 13 COMMISSIONER CHMIELOWSKI: Okay. So there 14 could be like gas coming up or something, right, there 15 could be..... 16 MR. McLAUGHLIN: Yeah. 17 COMMISSIONER CHMIELOWSKI: .....and so they 18 would just stay is what you're saying to put the safety 19 joint? 20 MR. McLAUGHLIN: They would just stay and run 21 the safety joint, yes, just as they would when they're 22 running slotted liner or perforating guns or when they 23 have shut-in the rams and they have to stab a full open 24 safety valve. So there -- there's work to be done when 25 you shut-in, it's all part of shut-in. Now if -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 11 (Pages 38 to 41) Page 38 1 that's all normal shut-in procedure. If you want to go 2 way down the what if, what if, what if a lot of gas, 3 there's an annular present and that would be enacted 4 either in either case where you're running -- if you 5 are running in with a safety joint or if you have liner 6 across there, I mean, you do have an annular available 7 to shut-in. So there's ways to..... 8 COMMISSIONER CHMIELOWSKI: Which may help or 9 may not, but you have then the shears, right, the shear 10 rams? 11 MR. McLAUGHLIN: We haven't talked about shear 12 -- what do you mean about the shear rams? 13 COMMISSIONER CHMIELOWSKI: Well, you have the 14 shear rams and you talk -- I think you talk in here 15 about how they're, you know, available as a -- as an 16 option even though they're not required, right? 17 MR. McLAUGHLIN: The -- they are in there 18 because we're going to be running coiled tubing in the 19 ground..... 20 COMMISSIONER CHMIELOWSKI: Right. 21 MR. McLAUGHLIN: .....right. But before we get 22 to a shear conversation there have already been a lot 23 of things that have not gone right and that would be 24 conversations after attempted shut-in with the bag or 25 for whatever reason why we can't run a safety joint or Page 39 1 whatever. So the shear conversation is not a hit a 2 button and run, I mean, that's not typical for liner 3 runs and it's not in our shut-in procedures. 4 COMMISSIONER CHMIELOWSKI: Okay. It's just 5 that it's mentioned in your presentation..... 6 MR. McLAUGHLIN: Uh-huh. 7 COMMISSIONER CHMIELOWSKI: .....so I wanted to 8 address it. 9 MR. McLAUGHLIN: Oh, yeah. 10 COMMISSIONER CHMIELOWSKI: Yeah. 11 MR. McLAUGHLIN: Yeah. And that shear ram's 12 present in either scenario, it's not a -- we're not 13 saying that we should run a safety joint because we 14 have a shear ram. That shear ram is present in either 15 case and you can go down well control escalation 16 problems to where you get to that shear ram in either 17 case. So it's really not an added benefit for running 18 a safety joint or liner. I mean, it's going to be 19 there and you could be in a situation where you want to 20 discuss using that in either case. 21 COMMISSIONER CHMIELOWSKI: Let me just look at 22 one thing real quick. 23 MR. McLAUGHLIN: Uh-huh. 24 COMMISSIONER CHMIELOWSKI: It says -- you know, 25 it's part of -- shear rams are part of rejustification Page 40 1 so it should be part of -- the part I've listed on your 2 justification slide that utilizing a safety joint 3 provides greater well control because you have blind 4 shear rams that are proven to shear on all CTD joint 5 pipe. 6 MR. McLAUGHLIN: Uh-huh. 7 COMMISSIONER CHMIELOWSKI: So that has to be 8 part of your -- wouldn't it be also part of your plan 9 if it's part of your justification? 10 MR. McLAUGHLIN: I wouldn't say it's part of 11 the plan. I'm just highlighting that as present, we're 12 not taking away that option that that's there. And 13 like I could have that as a justification for having 14 liner rams as well. You have a liner ram, that liner 15 ram leaks, well, then you have a shear ram to close. 16 It's justification on both sides to be fair. 17 COMMISSIONER CHMIELOWSKI: Yeah. Yeah. Okay. 18 MR. McLAUGHLIN: I mean, it's not -- I can't 19 highlight it as we should run a safety joint because 20 have a shear ram and that's not what we're trying to 21 say. We're just saying that it's there because if I 22 was arguing that hey, we need liner rams I'd be telling 23 you hey, we have a shear ram there and it's available 24 to be used. So it's not a benefit and it wouldn't be 25 placed in either procedure, it's just something that's Page 41 1 present and either when we're running -- when we're 2 closing a liner ram or running a safety joint. 3 COMMISSIONER CHMIELOWSKI: Okay. 4 COMMISSIONER WILSON: I guess just, you know, 5 for the -- if there's anyone from the public listening 6 that is less familiar, but it would be your ultimate 7 shut-in though, the shear ram? 8 MR. McLAUGHLIN: It would be absolutely the 9 last resort, yeah. 10 COMMISSIONER WILSON: Yeah. In any case? 11 MR. McLAUGHLIN: In any case, yeah. In either 12 case. 13 We're still on slide 13. Bullet point two. We 14 talked about this a little bit as well. The previous 15 operator had CS hydril rams so should Hilcorp. And 16 this again is a comment that I've already heard from 17 the AOGCC. That's partly true. It was after Macondo 18 adding (indiscernible) rams became a previous 19 operator's mandate. The previous operator used their 20 company leverage to make -- to have Hydril build the 21 rams. Hydril didn't want to build those rams, they 22 didn't think they were a particular purpose in the 23 stack, but that operator said we -- if you're going to 24 do business with us you're going to build those rams 25 and by the way we just had Macondo so you need to do AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 12 (Pages 42 to 45) Page 42 1 them. And we -- and they used quite a bit of leverage, 2 it wasn't something that Hydril wanted to do or thought 3 was a good idea. I was -- I was very much involved in 4 that. There's only six of these ever made and after a 5 very short time Alaska received an exemption because 6 the previous operator understood that adding rams was 7 inferior well control. As far as documentation that 8 all went away in 2020 and I don't have that risk 9 assessment. A risk assessment was done, it was 10 reviewed with the bigger company and it was ultimately 11 approved. 12 COMMISSIONER CHMIELOWSKI: Okay. So I thought, 13 you know, Hilcorp had acquired BP Alaska as an entity, 14 but you're saying you don't have BP Alaska's 15 justification? 16 MR. McLAUGHLIN: We have lost a lot of the 17 documentation because it was just like an online risk 18 assessment tool. Anyway we looked, I don't have the 19 risk assessment..... 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. McLAUGHLIN: .....it didn't come across in 22 whatever, all the data that we got. 23 COMMISSIONER CHMIELOWSKI: I guess I would be 24 surprised because of -- they must have been pretty 25 thorough at that point, you know, BP's corporate Page 43 1 history, you know, to justify. I imagine they were 2 pretty doc -- you know, had a lot of documentation, 3 but..... 4 MR. McLAUGHLIN: Once they -- they -- the well 5 control people went through this and understood where 6 it was going to be in the stack and understood about 7 bullhead kill and understood that closing it on one 8 inch CS hydril and trying to run something through that 9 and then not being able to strip in the hole, when you 10 add all those things together it was a pretty easy 11 sell. It wasn't..... 12 COMMISSIONER CHMIELOWSKI: Okay 13 MR. McLAUGHLIN: .....a tough deviation again. 14 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 15 MR. McLAUGHLIN: The third bullet point. We're 16 just adding extra ram to the stack. We -- we've looked 17 at this and the problem is is it wouldn't work in many 18 cases due to wellhead height. We have two coil tubing 19 drilling rigs and in both cases with tree heights we 20 can't -- we don't have the extra room just to add 21 another stack. But even if we could it would create a 22 poor option for well control. Again you would be 23 shutting in below the flow cross and you'd be giving up 24 your ability to bullhead kill on the annulus and you'd 25 be giving up your ability to strip in because you have Page 44 1 the slip set. 2 Slide 14. And this is the one I've heard most 3 recently, paraphrasing again, what if you can't run a 4 safety joint or it takes a long time to install. This 5 is the -- I think the idea here is well, you just go 6 ahead and try and run the safety joint and your backup 7 would be shutting liner rams which we don't think is a 8 good backup. 9 So the safety joint is an industry standard 10 practice for many operations, there are a significant 11 number of comparable operations to reference. Other 12 coil tubing drillers and operating -- drilling 13 operators in Alaska across the North Slope have run 14 operations for years only relying on a safety joint for 15 well control. Every time the rig picks up perforating 16 guns and lays down perforating guns a safety joint is a 17 pract -- is a safe practice for well control. Kick 18 volume is not a significant factor in coil tubing 19 drilling due to unlimited kick tolerance. It's 20 important, but it's not as significant as in rotary 21 drilling. The liner is run in cased hole and sticking 22 is not a risk. The -- an annular preventer is 23 available to be closed if necessary and the BOP has 24 shear capability. These are available in either shut- 25 in method, whether you're talking about shutting in Page 45 1 with liner rams or shutting in on a safety joint, it's 2 not an extra layer of protection or is it included in 3 the shut-in plan. 4 COMMISSIONER CHMIELOWSKI: Could you please 5 elaborate on the Conoco operation you're referring to? 6 MR. McLAUGHLIN: The operation? 7 COMMISSIONER CHMIELOWSKI: Yeah. 8 MR. McLAUGHLIN: Yes. The other company on the 9 North Slope that has done a significant amount of coil 10 tubing drilling, they operate in Kuparuk. They've had 11 a sustained coil tubing drilling program since 2008. 12 They've drilled a couple hundred wells and many 13 laterals and every single one of those to my knowledge 14 they have used a safety joint as their shut-in method 15 because they are running solid -- slotted liners. 16 COMMISSIONER CHMIELOWSKI: So..... 17 MR. McLAUGHLIN: And so it's another operation 18 where they have years of experience, many, many, many 19 wells running slotted liner and utilizing a safety 20 joint to shut-in. 21 COMMISSIONER CHMIELOWSKI: Okay. So it's for a 22 slotted liner, but you're asking for -- Hilcorp's 23 asking for slotted and solid liner? 24 MR. McLAUGHLIN: For consistency, yes. 25 COMMISSIONER CHMIELOWSKI: Okay. But you -- AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 13 (Pages 46 to 49) Page 46 1 but to be clear Conoco's operation that you're 2 referring to is a slotted liner? 3 MR. McLAUGHLIN: Yes. 4 COMMISSIONER CHMIELOWSKI: Okay. 5 MR. McLAUGHLIN: Just like when we run slottted 6 liner we would run a safety joint. 7 COMMISSIONER CHMIELOWSKI: Right. 8 MR. McLAUGHLIN: When we run solid liner we 9 would like to run a safety joint. 10 COMMISSIONER CHMIELOWSKI: Got it. 11 MR. McLAUGHLIN: At this time I'm going to pass 12 it over to John to talk about well control examples. 13 JOHN PERL 14 previously sworn, called as a witness on behalf of 15 Hilcorp Alaska, testified as follows on: 16 DIRECT EXAMINATION 17 MR. PERL: Okay. John Perl, CTD foreman. 18 Slide 15 here. We're going to talk about the well 19 control example, BOP example and basically the 20 difference between the -- these safety joints if we 21 shut-in with the -- with the liner rams. 22 On your left here we've got -- this is -- this 23 is the shear chart that we have associated with our 24 rams. If you notice that they're -- covers everything 25 from all our coil sizes through our liner rams to work Page 47 1 string. If pressure's there -- on the right-hand side 2 there's two columns, pressure zero to 5,000 wellhead 3 pressure, any of our liner rams here, the example 4 between CDR2, CDR3, after all our draw down tests on 5 our BOP tests, we are usually between a 2,100 pound and 6 2,200 pound hydraulic pressure on the cumi. That would 7 cover everything up there that we've got as far as with 8 the blind shears closed or with the -- utilizing 9 volumetrics to get the blind shears equivalent volume 10 closed, we would still be above any shear pressure on 11 the charts up there for that. 12 The right-hand column there, that is what we're 13 using for our standing orders there. I'm going to read 14 through these. To verify space, that was just make 15 sure that your liners cross, we're already setting the 16 hand slips with our liner. Once we go to installing a 17 safety joint, the guys turn around and they'll pick up 18 a safety joint, the guy on the floor will grab the 19 correct crossover for that thread and screw it into the 20 liner, make it up hand tight, pick up a safety joint, 21 safety joint gets screwed into that, then they both get 22 torqued. Pick up, pull the hand slips which is the 23 biggest advantage here, run the safety joint in and 24 then we close our upper pipes with rams and now your 25 support of the liner's now supported off the upper pipe Page 48 1 slip ram and not hand slips. The biggest advantage 2 right there, that puts you in your best situation for 3 one, stripping over, it's the only way we can get 4 stripped over with the injector with pipe slip rams 5 supporting the liner. We go into that with close -- 6 close up -- pipe close the full opening safety valve, 7 now we're in a good place to sit there and evaluate 8 what we need to evaluate, talk through the next 9 scenarios, get into the tertiary well control methods 10 after that point in time. 11 We'll go to a couple BOP stacks here. 12 COMMISSIONER CHMIELOWSKI: Can I -- are you 13 done with this slide, can I ask a question real quick? 14 MR. PERL: Yeah. 15 COMMISSIONER CHMIELOWSKI: On the shear chart, 16 did I read the date right, that that's 2024, was this 17 all done at the same time as the previous test you 18 mentioned? 19 MR. PERL: Yes, when we went through this here, 20 this has all been compiled between NOV tests that were 21 done and -- Trevor's got the information there, testing 22 that was done with all the shearing, most all this 23 stuff was calculated off of what NOV's shear 24 calculations were for. We've used this for -- this is 25 posted in -- at our accumulator and in our BOP control Page 49 1 in the ops caps. 2 COMMISSIONER CHMIELOWSKI: Okay. So this is a 3 calculated chart, it's not like a test, you just did 4 that one test on the hydril? 5 MR. PERL: The one test here, but we have the 6 information to support the test pressures on this 7 thing. 8 COMMISSIONER CHMIELOWSKI: Okay. And then did 9 you say that the pressure available to do the shear ram 10 assumed already some amount of the volume was used in 11 pressure for the accumulator? 12 MR. PERL: Yeah, and what I was getting at with 13 the accumulator, our accumulator draw down test, we -- 14 annular gets closed, annular get opened..... 15 COMMISSIONER CHMIELOWSKI: The annular, yeah. 16 MR. PERL: .....to do the -- because it's a 17 little bit larger volume than what our blind shears 18 with the boosters are and all of the three rams and our 19 HCRs. At that point in time we are higher pressure 20 than any of these shears with the -- with the whole 21 stack actuated. 22 COMMISSIONER CHMIELOWSKI: Oh, okay. The whole 23 stack's actuated..... 24 MR. PERL: The whole stack's actuated with the 25 blind shears already closed, either we close them or we AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 14 (Pages 50 to 53) Page 50 1 use the annular as our volumetric for the blind 2 shear..... 3 COMMISSIONER CHMIELOWSKI: Okay. 4 MR. PERL: .....so that would -- shows you that 5 with the blind shears closed we would still be above 6 any of the highest shear pressures there..... 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. PERL: .....even with a 5,000 pound 9 wellhead. 10 COMMISSIONER CHMIELOWSKI: All right. And is 11 this the same accumulator system that's actively used 12 on the CDR rigs? 13 MR. PERL: Yes. 14 COMMISSIONER CHMIELOWSKI: Okay. And how do 15 you guys test -- make sure the accumulator is -- and 16 all those bottles are properly filled and available for 17 use? 18 MR. PERL: During our BOP test the precharge is 19 checked and then basically we do our accumulator draw 20 down test for the BOP test..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. PERL: .....which tells us example to 23 example of each test you can see the trend if you're 24 starting to lose anything, my source or their source. 25 That's how we test them. Page 51 1 COMMISSIONER CHMIELOWSKI: Okay. 2 MR. PERL: Okay. Yeah. This here's basically 3 the example that the di -- Powerpoint we'll use to kind 4 of go through scenarios and use a visualization of how 5 we shut-in with a safety joint, why we think it's 6 better than shutting in with a set of variable rams. 7 Okay. This here's stack configuration with 8 this running liner. This is our flow path right here, 9 that's the flow cross going to the pit, start PVT, get 10 annular open, everything's open, (indiscernible) HCR, 11 kill HCRs are closed and the rest of the stack tree's 12 open. We've got liner across the stack and we were to 13 -- we got the hand slips there. If the guys were to 14 stab across over and shut the well in there and even if 15 we used -- if we used the variables here. The 16 disadvantage here, what we're -- why we don't want 17 these even as a possibility of getting closed is we got 18 the jacking surge (ph) you know, you take away your 19 option to be able to strip in the hole with your 20 injector, get your injector stabbed on which is going 21 to give your best well control to be able to pick that 22 up, stab on, run to bottom, circulate the kick out of 23 the hole. The only other thing we have say the 24 variables do leak is we can close the annular to backup 25 that, but we're still in the same situation with it Page 52 1 being -- not being able to strip into the hole. 2 Another big thing for me is if you -- if we -- in this 3 situation if we had to go into a bullhead kill was our 4 only option of getting the well killed one, we would 5 have to come into here in the NPD line which is for our 6 most -- it's our operational line for pressure 7 deploying and as soon as you start using a 8 (indiscernible) pressure 8,800 and say KCL in the hole 9 you're looking at 1,800 just to start breaking out at 10 12,5. Well, lighter liners you're going to start 11 pushing through the variables, you're going to start 12 pushing through the annular, you'll start jacking out 13 of the hole. So if you've got to get any kind of 14 pressure to the well to start bullheading you put 15 yourself in a place you cannot do that. 16 See here, see the variables take away your flow 17 cross, we can go through here bullheading, but then 18 these are your only two using last resort like Sean's 19 talking way down the rack, around -- you could cut pipe 20 there. But that is -- that's really the only scenario 21 and that's why we want to get the variables out of 22 there so they can't be used because they would put us 23 in a very precarious position right off the get go. 24 COMMISSIONER CHMIELOWSKI: Well, a question 25 though. I know in a future slide that you guys kind of Page 53 1 indicate, you know, to add another ram to the stack, 2 you go from four to six, so how come you can't go four 3 to five and say put three in the top and two in the 4 bottom that you prefer that way you could still 5 circulate? 6 MR. PERL: Even five's is a stretch for our 7 cellars on both -- on -- what happened is when Nabors 8 did their upgrade when we wanted to get a better well 9 control scenario, we used to drill through our well 10 control choke manifold, through the flow cross..... 11 COMMISSIONER CHMIELOWSKI: Hmmm. 12 MR. PERL: .....so all your returns came 13 through here. Once they upgraded that and we put 14 piping into where we started putting in a traditional 15 flow cross per se on top of the annular to take our 16 returns out of there and go down a dedicated drilling 17 line that added a bunch of height to the top of the 18 stack where right now we're very, very limited within. 19 There's a lot of occasions we have to breakdown trees, 20 wellheads to get -- be able to get the stack over 21 the..... 22 COMMISSIONER CHMIELOWSKI: Okay. 23 MR. PERL: Okay. And this is what we're 24 wanting to do. So we stack same scenario, we run our 25 safety joint in, okay, PIW would be in the open AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 15 (Pages 54 to 57) Page 54 1 position running in the hole, we would turn around and 2 close our upper pipe slip rams here and then close our 3 TIW. And at that point in time you could open up your 4 choke HCR line up to the well control choke, close well 5 control choke. At this point in times gives you plenty 6 of time to discuss what's going on, next steps, you've 7 had -- you're ready to either run in the hole and 8 circulate the strip over and run in the hole and go to 9 bottom. You've got time to see if the well decides to 10 turn around, you're not worried about it jacking out of 11 the hole because you're on pipe slips at that point in 12 time. We can kill -- we can kill it traditionally 13 through the choke -- choke manifold kill line if we 14 have to here, we could bullhead through here, you got 15 the option here. Where I would go into this -- the 16 pros of the safety joint is number 1 is being able to 17 strip over, that's my number 1 that I like about this 18 shut-in method is that I can get the injector on it 19 immediately and go to bottom if I want to or we can sit 20 here and if we got other things to consider, is a 21 bullhead better, is getting to the hole, that kind of 22 stuff. 23 If we do have things like -- I mean, the 24 question always comes up, okay, pipe slip rams go 25 closed, you get ready to close and they're leaking, Page 55 1 you've got one, you got the annular as a backup there 2 to backup those if you need to. Still have your 3 ability to hang off with the pipe slip, but the annular 4 could do that. Vice versa if you have issues here you 5 can blow this -- set a lower oil tubing slips down here 6 if the -- for one, a leak or if the top slips aren't 7 holding. If you had to turn around and get in here you 8 -- we do have -- I forgot about this thing doing that. 9 10 COMMISSIONER CHMIELOWSKI: Start over. 11 MR. PERL: Yeah, all over again guys. Sorry 12 about that. Okay. We're shut-in there. It's got to 13 be the close. Okay. So let's talk about that, still 14 open there. We can go to opening up here, you're now 15 there we go, thanks, we can go here and we can -- we 16 can bullhead down through here if you have to have 17 anything below the flow cross shut-in and you're 18 controlled by jacking by two sets of pipe rams -- pipe 19 slip rams, excuse me. 20 COMMISSIONER CHMIELOWSKI: Would you still have 21 the scenario of having to pump at a high pressure that 22 would come up? 23 MR. PERL: You can, but with it being on slips 24 we would -- you still have that -- no matter with the 25 bullhead you're going to have to -- if the filter case Page 56 1 is doing it's job you're going to have to break it down 2 to get it really started taking fluid. But that gives 3 you the option here, but that's going way down the 4 realm. And then you -- we still on this scenario here 5 still have the option to close blind shears if that's a 6 last resort. We do have an example here and, I mean, 7 we -- this doesn't happen very often because F89 in 8 2023 we had -- this took a small kick and we had to 9 deploy safety joints with a one inch CS hydril. That 10 got shut-in, took basically a five barrel kick, they 11 monitored it for three, four hours while they were 12 talking about it and then stabbed the injector, on 13 stripped over, went to bottom, circulated everything 14 out and come out started laying down the hydril again. 15 So no incidents, worked very well. That's probably the 16 last -- last time I can remember in CTD we've had to 17 actually do this..... 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. PERL: .....but it -- it makes the best 20 scenario there. 21 COMMISSIONER CHMIELOWSKI: Could you humor me 22 by trying a different scenario where, you know, and I 23 just -- I'm thinking about the human factor, right, 24 because you go on these post incident reviews, you 25 know, there's multiple factors, one of them's the human Page 57 1 factor. So just say that safety joint, they have the 2 wrong one or it's -- you know, it's not put on, it's 3 not sealed, people don't have enough time, they need to 4 leave for whatever reason then what do you do if the 5 safety joint's not there? 6 MR. PERL: We still got the annular and we got 7 backup to shear if we had to. 8 COMMISSIONER CHMIELOWSKI: So it's annular and 9 shear would be -- okay. 10 MR. PERL: To preface a lot of this, Jessie, is 11 the safety joint we've got is laid down, already got 12 the valves open, already got a lifter on it which we 13 color code to the elevators we're using during that 14 run, everything's prepped for that before we ever start 15 running liner. All the safety joint crossovers for the 16 threads that we're going to be using are on the rig 17 floor, the one that is in use at that time has a spot, 18 it sits by itself, they're colored so we try to prep 19 ahead of time to make sure that that -- there's only 20 one they can pick up. 21 COMMISSIONER CHMIELOWSKI: Okay. 22 MR. PERL: It's in the same spot, it's just off 23 the edge of our skate there. 24 COMMISSIONER CHMIELOWSKI: Right. So because 25 there's multiple sizes it could be, right, and so do AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 16 (Pages 58 to 61) Page 58 1 you like go through a safety drill like right before 2 you change sizes, when you change the -- the safety 3 joint, you know what I'm saying..... 4 MR. PERL: Well, that..... 5 COMMISSIONER CHMIELOWSKI: .....like okay, now 6 we're changing to this size so how do we make sure we 7 have the right one? 8 MR. PERL: The safety joint -- we should have 9 brought that. The safety joint is sized to whatever 10 coil size we are. So if we're running big -- big hole 11 liners and we've got two and three-eights pipe slips up 12 top and bottom our safety joint is a chunk of two and 13 three-eights, usually tubulars that we've got an inch 14 and a half MT pin on the bottom and a TIW already 15 installed on the top open. If we're -- if we go to 16 small liner that -- that turns into a two inch safety 17 joint and vice versa, we'll go to two and five-eights 18 coil. We always size our safety joint to the coil size 19 so when we bring -- put the safety joint in there that 20 gives us our upper and lower pipe slip rams that we can 21 use on that safety joint. And that's why we do get so 22 many scenarios that we've got for one, consistent shut- 23 in from the beginning to put us in the best place we 24 possibly can be and give us to where we're not having 25 to act hastily to decide on how we're going to get the Page 59 1 well killed and vice versa. The guy -- we got time. 2 So once it gets in, once it gets shut-in, the guys can 3 monitor, we can talk about it amongst myself and the 4 crew like Sean McLaughlin here. It gives you the 5 option there. The biggest reason with the variables is 6 if you -- if they're there they get shut on the liner, 7 you're -- you can't get the safety joint in, you lose 8 your ability to strip it, you're really unless the 9 well's taking fluid you really can't bullhead of any 10 kind of pressure if you've got to breakdown the 11 pressure. But what we're asking is to get the 12 variables completely out of the mix to where they can't 13 shut because our number 1 concern is make the guys 14 drill to a safety joint to where that is our primary 15 well control as far as getting the -- getting shut-in 16 for the well. And then they can do that across the 17 board. 18 And really the -- really the only thing that 19 changes is our crossovers we have on the -- on the rig 20 floor and our lifters which are all prepped prior and 21 we usually because we got such a short section of three 22 and a half or three and a quarter is we usually have 23 the -- a lifter size the same elevators, use that -- so 24 we just use lifters as we're running those joint pipes 25 so we don't have to change elevators and we can stay on Page 60 1 the same lifters. Trying to keep everything as 2 consistent as possible where there's not a lot of 3 change in the way we do things other than really a 4 crossover change. And the crossovers themselves are -- 5 they got -- we on CDR2, ours are very bright colored to 6 understand that those are and they're also stenciled 7 with red type that they use that they're paid for. And 8 there is usually an inch and a half box by whatever 9 pins are the thread size on the bottom. You know, 10 those guys -- there's been talk through worried about 11 cross-threading and all that kind of stuff, one inch 12 and half MTB in a work string thread is pretty hard to 13 get cross-threaded. The liner thread, the guys are 14 making that up by hand, getting four or five threads 15 and they get them as far as the guys are picking up the 16 safety joints. And then when they both get hand 17 screwed together then the little jerks (ph) go together 18 and they get (indiscernible) they go in, usually in 19 three, three and a half minutes which is kind of -- 20 depending on what the crews are. 21 COMMISSIONER CHMIELOWSKI: How many different 22 safety joints are there sizes, two? 23 MR. PERL: We got two right now, but when we go 24 to two and five-eights coil we'll have to have a third. 25 COMMISSIONER CHMIELOWSKI: Third. Until -- Page 61 1 what's Hilcorp's procedure, you know, on the rig to 2 make sure everyone's aware the correct size is there or 3 if it changes, you know, during the course of a 4 wellsite, does it -- does it change? 5 MR. PERL: Yeah, when we..... 6 COMMISSIONER CHMIELOWSKI: Okay. 7 MR. PERL: .....when we go into our pipe swap, 8 when we swap between two -- two inch -- two and three- 9 eights coil, that stuff gets changed out. Everything 10 from our safety joint size to our work string size, 11 we'll usually pull the one inch off or the inch and a 12 quarter off, put the one inch on, we go to two inch. 13 Most of the thread crossovers with the smaller liners 14 and stuff there's only usually two and three-eights, 15 there's -- there's only one crossover for that. The 16 safety joints that we -- we utilize, they get put up in 17 our rack and when we're on one coil size like right now 18 being on two and three-eights coil, the only safety 19 joints that laying on that case is the two and three- 20 eights safety joint. 21 COMMISSIONER CHMIELOWSKI: Okay. So I'm asking 22 the question maybe incorrectly, but I'm thinking of the 23 human factor again and is there a procedure like where 24 you have like everybody -- all hands on deck, this is 25 our safety joint, we just switched to this one and AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 17 (Pages 62 to 65) Page 62 1 everyone sees it's the correct one, you see what I 2 mean, versus like well, we assume it's the correct one, 3 it should be the correct one. How do you know and make 4 sure it's the correct..... 5 MR. PERL: It's my responsibility and also my 6 driller and..... 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. PERL: .....pushers that elevator gets OD 9 tape, the joint gets OD taped, all that stuff gets -- 10 it's part of the fire line and..... 11 COMMISSIONER CHMIELOWSKI: Okay. 12 MR. PERL: .....yeah. 13 COMMISSIONER CHMIELOWSKI: All right. Thanks. 14 MR. McLAUGHLIN: Let me add in one more thing, 15 Sean McLaughlin here before we move on this slide. 16 When -- I'd just like to point out that the annular you 17 were asking about, we have that as a secondary option 18 that will work for all sizes. When you're talking 19 about rotary that's typically the primary option. 20 COMMISSIONER CHMIELOWSKI: Hmmm. 21 MR. McLAUGHLIN: So we -- we've already -- 22 we're setting ourselves up for better than success with 23 attempting to run the safety joint. And then we still 24 have the annular which would be a great secondary in 25 many cases in many other operations is a primary. Page 63 1 COMMISSIONER CHMIELOWSKI: Okay. Thanks for 2 that clarification. 3 MARTIN WALTERS 4 previously sworn, called as a witness on behalf of 5 Hilcorp Alaska, testified as follows on: 6 DIRECT EXAMINATION 7 MR. WALTERS: Martin Walters and I'm on slide 8 18. And I guess we'll forego the introduction since 9 we've already introduced ourselves. 10 I was asked by Hilcorp Alaska to provide some 11 objective scrutiny of their philosophy and testimony 12 and exhibits regarding the subject of coil tubing 13 drilling blowout preventers which we've been discussing 14 so far today. So, you know, a little bit about my 15 methodology. I basically have been attending team 16 meetings since early January and I reviewed the history 17 of the subject. And so a lot of the documentation 18 you've seen already the kick history likelihood, 19 there's some -- a shear study, wellhead height 20 limitations, et cetera that I'm going through and also 21 their current procedures including the well control 22 standing orders, the whole prior to pulling out of the 23 hole to run jointed pipe and I feel like it gave me a 24 good background to study and weigh the pros and cons of 25 the proposed options of using a safety joint versus Page 64 1 installing a set of variable bore rams or small pipe 2 rams to comply with Alaska statutes. 3 So and in my opinion with regards to well 4 control it comes down to an engineering judgment 5 decision based upon comparing the pros and cons with 6 respect to how quickly and how correctly a well can be 7 shut-in after detecting a kick. It's really just about 8 quickly and correctly shutting in to control the well. 9 Slide 19. For -- we've listed the pros and 10 cons of each case and made a comparison of the 11 engineering and operational aspects of each and so some 12 of the topics that we talk about were integrity which 13 would say how resistant the barrier is to potential 14 pressure and forces that it may be exposed to such as 15 jacking that has been described earlier. The shut-in 16 position, whether it's above or below the flow cross, 17 training, how effective the weekly drills will be and 18 how well will the information be retained, right, how 19 the ease at which that information can be communicated. 20 We talk about kick size, what is the relative kick size 21 based upon the time required to shut the well in and 22 compliance, whether or not it complies with the 23 existing Alaska statutes. 24 So slide 20. So just to kind of illustrate 25 some of the thought process that we undertook on each Page 65 1 one of those topics, the safety joint or the -- or the 2 kick joint as it's sometimes referred to, has a higher 3 integrity than variable bore rams due to the reduced 4 ability of the VBRs to prevent jacking when upward 5 forces in the wellbore exceed the weight of the pipe. 6 So not that the VBRs have no resistance against 7 jacking, but it is definitely less than a pipe slip. 8 Compared to the VBRs and the pipe ram case, a safety 9 joint case will always be shut-in above the flow cross 10 which will allow diversion of kick fluids through a 11 choke while the well is shut in. And, you know, as 12 it's been stated and it shouldn't be overlooked that 13 the crew -- the crew drills so that they become 14 proficient at a single shut-in process regardless of 15 which pipe is across the BOP stack. And you've seen 16 the list of possible pipe sizes and it's pretty 17 extensive. 18 So the biggest negative aspect of the safety 19 joint case is kick size. Due to the extra time 20 required to install a safety joint it's always going to 21 have a larger kick than the VBR or CS hydril cases and 22 the quantity's going to largely depend upon the rock 23 permeability fluid viscosity and the amount of 24 underbalance to determine the size of the kick and the 25 time required to take in which has been stated as, you AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 18 (Pages 66 to 69) Page 66 1 know, three to three and a half minutes. 2 So after looking at all of the pros and cons in 3 conclusion in my opinion the safety joint is a 4 preferable option because it's largest negative which 5 is kick size is offset by the infinite kick tolerance 6 of a coiled tubing drill coil. 7 COMMISSIONER CHMIELOWSKI: And, Mr. Walters, 8 this is presented as an either/or scenario, but why not 9 have both options available? 10 MR. WALTERS: I would defer to Sean or one of 11 the other guys why they -- you know, I studied the 12 options as given, right, the three options and I think 13 they've addressed those options earlier in their 14 testimony. 15 COMMISSIONER CHMIELOWSKI: Okay. So you don't 16 have an opinion, you're just giving your opinion on one 17 or the other which you would recommend? 18 MR. WALTERS: Right. And I've confined it to 19 my current area of expertise of, you know, shutting in 20 quickly and correctly. I think that, you know, from my 21 area of expertise it comes down to the -- you know, 22 those two topics. 23 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 24 MR. McLAUGHLIN: Sean McLaughlin. Slide 21. 25 In summary Hilcorp believes that a safety joint used to Page 67 1 shut-in a well is an industry standard. Using a safety 2 joint to shut-in is better than adding a liner or CS 3 hydril ram to the BOP. This isn't a -- there's 4 benefits in either case and I really like Martin's 5 matrix that he puts up. We're talking well control, it 6 -- it's not a good situation when we're talking about 7 well control so we look in aggregate and we sum the 8 pros and cons and we believe that a safety joint run 9 without liner rams in the stack is the best course of 10 action for well control. 11 And I agree human error is often what gets us 12 into trouble with well control. We've had many of 13 those conversations, there can be human error on either 14 side or when you have both. We believe that the 15 operation where you have -- run a safety joint and no 16 liner ram in our belief that offers the least potential 17 for human error. 18 I'd also like to point out that is a field 19 driven waiver request, it was the field that came to us 20 and for years asking us to change this. This isn't 21 driven by Hilcorp management or engineering, I'm here 22 in support of my eight drillsite managers and their 23 eight drillers. They all want to see this in place, 24 they all want to see that the preferred stack is in a 25 preferred shut-in method as running a safety joint Page 68 1 without a liner ram in the stack. When they look at -- 2 and they're all well control certified people, they're 3 the ones working in the floor, they're the ones picking 4 up the safety joint and they're all -- a hundred 5 percent of them have this request because they believe 6 it is best for well control. So I looked at it, I 7 questioned them very hard and I'm with them and I'm in 8 support of them. 9 So to sum up the waiver request, Hilcorp Alaska 10 requests a waiver for cased hole coil tubing drilling 11 jointed pipe operations to use a safety joint in lieu 12 of having a preventer equipped with a pipe ram that 13 fits the size of jointed pipe being run. 14 And that is our testimony. 15 COMMISSIONER CHMIELOWSKI: Thank you. Question 16 about -- this might be on the backup slides, but it's a 17 slide title begins other, other justification, but it 18 talks about well efficiency. So is this -- isn't that 19 part of this too, is well efficiency and the time that 20 it takes to change ram? 21 MR. McLAUGHLIN: Oh, there's certainly 22 efficiency. I didn't look at it. I don't care about 23 it when we're talking well control. What we looked at 24 is what is best for well control. 25 COMMISSIONER CHMIELOWSKI: Okay. Page 69 1 MR. McLAUGHLIN: It's in there, we look at it, 2 but it wasn't a driver. 3 COMMISSIONER CHMIELOWSKI: Okay. And it just 4 mentions that it would add another well per year so I 5 wondered if it was significant to Hilcorp financially? 6 MR. McLAUGHLIN: No, it's not. 7 COMMISSIONER CHMIELOWSKI: Okay. 8 MR. McLAUGHLIN: Well control incidents are 9 very financially significant to Hilcorp. 10 COMMISSIONER WILSON: Commissioner Chmielowski, 11 anything further? 12 COMMISSIONER CHMIELOWSKI: So -- yeah. Does -- 13 is there anything -- I know the API standard is from 14 1997 geared toward rotary which is not a real perfect 15 fit for coiled tubing drilling, but does API have any 16 recommendations about not having the correct pipe rams 17 and using safety joints and other mitigations that 18 might be used in that situation? 19 MR. McLAUGHLIN: No, not that I'm aware of. 20 COMMISSIONER CHMIELOWSKI: Okay. 21 MR. McLAUGHLIN: Because when we are running 22 liner it is API 53 is the guiding document..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. McLAUGHLIN: .....and so even the updates, 25 it -- there hasn't been a significant change. And then AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 19 (Pages 70 to 73) Page 70 1 there hasn't been an integration of coil tubing 2 operations married with API 53. It -- it's really 3 we're in this gray area where it's a hybrid operation, 4 actually I wrote a SB paper on hybrid operations, but 5 98 percent, 99 percent of the drilling as a world is 6 rotary drill and that's covered under API 53. And then 7 you have 1 percent that's coil tubing drilling. The 8 liner running, it kind of sits in between, it's not 9 coil tubing drilling and it's, you know, a little 10 different than API 53 because we have a different -- 11 we're set up differently with kick tolerance and 12 wellbore and -- and the low party in place. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: But 53 is the guiding document 15 for running liner. 16 COMMISSIONER CHMIELOWSKI: Is there a -- you 17 know, when you're talking about running hydril in cased 18 well, right, so it'll be fully cased and that and so I 19 guess it could have slotted liner, but probably not, 20 right? 21 MR. McLAUGHLIN: Probably not. 22 COMMISSIONER CHMIELOWSKI: Yeah, so does the 23 liner lap pressure test, does that come into play with, 24 you know, ensuring that you have a fully cased hole, 25 you know, you're not getting production from the parent Page 71 1 or from the new lateral, you know, how does that come 2 into play, what does the..... 3 MR. McLAUGHLIN: It minimizes your exposure is 4 all it does. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. McLAUGHLIN: Even though we pump cement, we 7 have a failed liner top, pressure test on almost 75 8 percent of our wells. We're playing around with the 9 integral liner top packer in big hole sizes, but you -- 10 we're not completely isolated. Even so liner and 11 cemented you can still have a leak through the liner 12 top absolutely. 13 COMMISSIONER CHMIELOWSKI: Okay. So is that 14 tested, I mean, what -- what importance does it have 15 that the liner top or liner lap is sealing or pressure 16 tested? 17 MR. McLAUGHLIN: It's a financial barrier for 18 us..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. McLAUGHLIN: .....because we're in zone. 21 And there is no requirement for that liner top to pass 22 a test. What it means on production is we would make a 23 lot more gas than what we want, we would not make oil. 24 So it is in our best interest to have a sealing liner 25 top, but from a wellbore utility standpoint it doesn't Page 72 1 need to be sealing. 2 COMMISSIONER CHMIELOWSKI: Does it have 3 anything to do with well safety and well control is 4 what I'm curious too? 5 MR. McLAUGHLIN: It would minimize what -- for 6 the situation where you have liner in the hole and 7 you're pulling CS hydril out or even you are pulling 8 coil out of the ground, there would be less swab risk 9 because you have so much casing down there and you have 10 this liner lap where the OD of our liner running tool 11 is our liner top is 3 800 inside of 3 9. I mean, it's 12 a very small annulus that you -- you're going to swab 13 through. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. McLAUGHLIN: So your total open hole goes 16 from a lot to very, very little with cased hole in the 17 ground. 18 COMMISSIONER CHMIELOWSKI: And is CS hydril 19 ever run without cased hole, like you never run without 20 a liner, right, typically, does cased hole clean out 21 before you perf basically, is that the only scenario? 22 MR. McLAUGHLIN: We used to do completions 23 called bonsai completions..... 24 COMMISSIONER CHMIELOWSKI: Right. Right. 25 Right. Page 73 1 MR. McLAUGHLIN: .....David McNamara developed 2 those, I guess it was in the early 2000s, but that's in 3 a case where we have slotted liner and a baffle plate 4 and then solid liner. And then when we cement only the 5 solid liner gets cemented. 6 COMMISSIONER CHMIELOWSKI: Got it. 7 MR. McLAUGHLIN: And that's a case where we run 8 in through the cemented solid liner, drill out the 9 baffle plate and then it would go into the slotted 10 liner. So that -- that's one case I can think of where 11 you run CS hydril into a slotted..... 12 COMMISSIONER CHMIELOWSKI: Into like a..... 13 MR. McLAUGHLIN: But you're running in three 14 joints or something. 15 COMMISSIONER CHMIELOWSKI: Right. Right. Does 16 Hilcorp ever do bonsai completions? 17 MR. McLAUGHLIN: We haven't. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. McLAUGHLIN: Yeah. 20 COMMISSIONER CHMIELOWSKI: Okay. I hadn't 21 heard that word in a long time. That's all I have for 22 now. 23 Thank you. 24 COMMISSIONER WILSON: Would you want to take a 25 short recess? AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 20 (Pages 74 to 77) Page 74 1 COMMISSIONER CHMIELOWSKI: Yes, please. 2 COMMISSIONER WILSON: I show 11:27 so we'll 3 take a 20 minute recess. 4 COMMISSIONER CHMIELOWSKI: Maybe a -- maybe 22, 5 make it an even number. 6 COMMISSIONER WILSON: Okay. 7 COMMISSIONER CHMIELOWSKI: So 11:50 we'll come 8 back? 9 COMMISSIONER WILSON: Yeah. 10 COMMISSIONER CHMIELOWSKI: Okay. 11:50. 11 Thanks. 12 (Off record - 11:27 a.m.) 13 (On record - 11:54 a.m.) 14 COMMISSIONER WILSON: I have 11:54, we'll call 15 the meeting back to order. 16 Commissioner Chmielowski, you have additional 17 questions. 18 COMMISSIONER CHMIELOWSKI: Yes, thanks for your 19 patience, we're a little late. First question and this 20 is for anybody so just state your name as you go 21 through. Does Hilcorp have any documentation where 22 AOGCC approved a 4,000 foot long BHA? 23 MR. McLAUGHLIN: Sean McLaughlin. Indirectly, 24 yes. I would say pretty much the drill approved since 25 the late '90s have included a BOP configuration and Page 75 1 plans to run a 4,000 foot BHA in the ground. And so I -- 2 I'd suggest that every one of those permits to drill 3 is approval. 4 COMMISSIONER CHMIELOWSKI: And the 4,000 foot 5 long hydril was explicitly written, do you recall? 6 MR. McLAUGHLIN: It would have been written to 7 clean out to bottom. 8 COMMISSIONER CHMIELOWSKI: Okay. 9 MR. McLAUGHLIN: And so whether we called out 10 the footage, I -- I'd have to go back..... 11 COMMISSIONER CHMIELOWSKI: Okay. 12 MR. McLAUGHLIN: .....and check. 13 COMMISSIONER CHMIELOWSKI: Thank you. Could 14 you please talk through the scenarios in a well control 15 situation where you have to strip in or out of the 16 hole, right. So first scenario is when you're using a 17 safety joint and then the second scenario is VBRs. And 18 so how are those different? 19 MR. PERL: Okay. We got our safety joint 20 diagram here. With the safety joint in the hole as the 21 well would be shut-in after a well control, a -- Madame 22 Commissioner, the important thing here is we've got no 23 hand slips set here which are outside the -- on the 24 base plate where you can't physically get a injector 25 across the top. What would happen here is because Page 76 1 you're supported with the upper pipe slips, TIW is 2 closed, the injector with -- coil tubing injector would 3 come across the floor, we have a swivel that can make 4 up to that inch and a half MT connection right there 5 off the top of that TIW. There's a box here, there's a 6 pin on the end of the coil. That can be made up, you 7 can fork up to the top of that TIW, you can -- in turn 8 you can pump down the coil tubing, get a service break 9 pressure test there to make sure that that connection 10 is holding and you can open up that TIW. From that 11 point what happens is is we go into a scenario just 12 like we pressure test a BHA or pressure deploy a BHA. 13 You dump the train -- the chain traction on the 14 injector which takes the chains off the pipes where the 15 pipes not supported -- the coil tubing's not supported. 16 From -- from there then we can strip down, basically 17 the injector strips down along the pipe leaving the 18 coil stationary. It comes down over the top of that 19 TIW after you -- you'd open up that T -- we'd -- let me 20 back up (indiscernible - away from microphone) here. 21 Once we get the pressure tested this would get open, 22 then we'd strip down, make up the lubricator connection 23 on the bottom of the injector to the stump on the top 24 of the BOP, we've got a quick test of their 25 hydraulically that we can test that connection with Page 77 1 4,000 pounds is what we usually -- we call our test 2 there. Then the -- they can grab traction on the pipe 3 again with a chain to the injector, they can pull to 4 what our known weight would be below the pipe rams. We 5 can come in through this conn -- through here we can 6 actually pressure -- pressure up and equalize across 7 this blind shear or we can come here and we've got -- 8 we've got piping on the other side of this that we can 9 open up, it just basically loops around above and below 10 that pipe ram to equalize the pressure. Then those 11 pipe rams can be opened and then we would run in the 12 hole like normal on coil, run down to bottom, wherever 13 our -- add our BHA into whatever length the liner would 14 happen to get in the hole, run to bottom, start while 15 we're -- while we're circulating, go to bottom, you can 16 circulate on bottom, you can pump it down the middle of 17 the coil, taking returns out your choke line here 18 through your (indiscernible - away from microphone) 19 choke or we got it with our remote choke there, 20 circulate it out, you can do a flow check at that point 21 in time on bottom, pull out of the hole, pop off the 22 top of the well as normal, you -- you'd put your hand 23 slips in and then you can start laying -- break the 24 injector off, lay down the pipe or you could just turn 25 around and keep running pipe in the hole to finish your AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 21 (Pages 78 to 81) Page 78 1 liner run. 2 COMMISSIONER CHMIELOWSKI: Okay. 3 MR. PERL: That's -- that is the safety joint 4 style. 5 COMMISSIONER CHMIELOWSKI: Are you actually 6 stripping through the pipe slips? 7 MR. PERL: No, no. 8 COMMISSIONER CHMIELOWSKI: No. 9 MR. PERL: We're stripping on the injector. 10 COMMISSIONER CHMIELOWSKI: On the injector. 11 Okay. 12 MR. PERL: Yeah, you cannot..... 13 COMMISSIONER CHMIELOWSKI: Yeah. Yeah. 14 MR. PERL: ....strip down through that stuff. 15 COMMISSIONER CHMIELOWSKI: Right. Okay. So 16 then -- oh, go ahead. Are you completed with this 17 scenario? 18 MR. PERL: Yeah, that..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. PERL: .....pretty much covers this. 21 COMMISSIONER CHMIELOWSKI: And how about what -- 22 if you have VBRs then how would you strip in the hole? 23 MR. PERL: Liner goes in, there's a liner 24 there, hand slips are in which is just holding the 25 weight of the pipe on the hand slips and they're set Page 79 1 into an actual false bowl there. If it was to happen 2 they turn around and they shut the -- the 3 (indiscernible - away from microphone) shuts that in 4 and they -- they shut the variables like we're talking. 5 You're -- you're not stripping it, you're -- you're 6 right there, you -- at that point in time you're not 7 stripping the hole. It physically cannot be stripped 8 in. 9 COMMISSIONER CHMIELOWSKI: Because you can't 10 get the lubricator, is what you're saying? 11 MR. PERL: No, because this is your limiting 12 factor here is this set of hand slips is this big. You 13 can't take the weight off the -- guarded you're grabbed 14 on to the liner so you can't move that liner anymore. 15 So to get those hand slips out you'd have to be able to 16 support that liner which means moving the liner, get 17 the hand slips out of the way and you can't physically 18 do that. That's one of the biggest reasons I don't 19 like this scenario at all, at least being able to do 20 the -- use the variables because it takes almost all 21 your options away..... 22 COMMISSIONER CHMIELOWSKI: Okay. 23 MR. PERL: .....your good options away 24 immediately. 25 COMMISSIONER CHMIELOWSKI: So the hand slips is Page 80 1 when..... 2 MR. PERL: The hand slips..... 3 COMMISSIONER CHMIELOWSKI: Got it. 4 MR. PERL: .....because they only -- they're a 5 tapered slip and they hang from the -- the pipe hangs 6 inside of them and your weight's supported off the hand 7 slips where the other way around when you shut-in with 8 the safety joint you're actually -- your whole liner 9 weight's hanging off this pipe slip. 10 COMMISSIONER CHMIELOWSKI: Thank you. 11 MR. PERL: Yeah. 12 COMMISSIONER CHMIELOWSKI: Another question 13 then about testing the annular. Does -- how does 14 Hilcorp test the annular, what's the largest and 15 smallest size pipe that it uses, you can go down to one 16 inch and then I guess your biggest would be what three 17 and a half. So how does Hilcorp test the annular on 18 the..... 19 MR. PERL: We -- we..... 20 COMMISSIONER CHMIELOWSKI: ......large and 21 small size? 22 MR. PERL: .....prior to -- prior to us talking 23 about the requirements of the one and a quarter inch, 24 one inch, we test our smallest which is usually our 25 coil site, two and three-eights or two inch, whichever Page 81 1 are up. And the variables get tested to coil size and 2 the biggest liner that we're going to be..... 3 COMMISSIONER CHMIELOWSKI: Okay. So does the 4 annular ever get test down to the hydril..... 5 MR. PERL: No. 6 COMMISSIONER CHMIELOWSKI: .....diameter? No. 7 Okay. 8 MR. McLAUGHLIN: Sean McLaughlin. To add on 9 this it's a seven and sixteenth annular and what we 10 know about annular preventers is the smaller size that 11 you run and try and test, you destroy the integrity of 12 the annular. So when you're shutting in on one inch 13 and testing that annular has a much shorter life. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. McLAUGHLIN: So that -- that's why -- one 16 of the reasons why you -- we don't really want to test 17 on one inch is you could destroy the integrity of that 18 annular much quicker. This is something that..... 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. McLAUGHLIN: .....that it's a -- it's a 21 fact with all annulars and previously just when 22 considered a BHA, we weren't required to test CS hydril 23 with the annular when we think of it of -- as a BHA. 24 COMMISSIONER CHMIELOWSKI: Okay. So are you 25 familiar with the API 16 ST NXE which talks about shear AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 22 (Pages 82 to 85) Page 82 1 rams -- performance tests on shear rams. Could you 2 please comment on that? 3 MR. McLAUGHLIN: I'm familiar with the API 16. 4 It's a coil tubing, API standard, it's a recommended 5 practice. It was I think originally written in 29 or 6 2009, reaffirmed in '14 and then rewritten oh, in 2021 7 or so. We've looked at 16 ST over the years with 8 previous operators and being a recommended practice 9 there -- there's some good ideas in there, there's some 10 good things and there's a lot of things that we don't 11 do because we're a mature operation, we don't believe 12 they apply. NXE is -- talks about shearing coil, it 13 talks about the methods you'd use to shear coil and 14 frequency and all that kind of business. It is a coil 15 tubing standard so I don't think it's material to 16 running jointed pipe. Shearing coil is differently 17 than shearing jointed pipe because of the residual 18 bend. So it's not applicable if we're talking about 19 shearing CS hydril or liner. 20 COMMISSIONER CHMIELOWSKI: Okay. Please 21 describe how Hilcorp tests and requalifies pipe slip 22 rams? 23 MR. PERL: John Perl. The way it -- we perform 24 our BOP tests, the way we perform them is we do our 25 weekly or biweekly BOP tests done on the whole stack, Page 83 1 pipe slip rams included. 2 COMMISSIONER CHMIELOWSKI: So the weekly tests 3 and then is there any sort of requalifying that you do 4 of these rams? 5 MR. PERL: They get basically requalified every 6 time we do a test. 7 COMMISSIONER CHMIELOWSKI: Every time you test. 8 Okay. 9 MR. PERL: Yeah. 10 COMMISSIONER CHMIELOWSKI: Okay. 11 MR. PERL: Yeah, the whole stack gets tested at 12 the same time. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. McLAUGHLIN: Sean McLaughlin. And then the 15 stack itself has requirements. Every five years it 16 goes in for a CAT5 inspection. So the BOPs, ram 17 bodies, carriers, blocks, everything, they -- they have 18 a time limit on it, all BOPs do. And it's typically 19 industry standard five years that it goes out of cycle 20 and has to get requalified. 21 COMMISSIONER CHMIELOWSKI: Okay. If the -- say 22 the pipe slip rams were used is there anything 23 additional Hilcorp would do to check those rams and 24 ensure they're still good? 25 MR. PERL: John Perl. Madame, yes, we -- if we Page 84 1 use the rams we -- they get retested as far as..... 2 COMMISSIONER CHMIELOWSKI: Immediately 3 retested? 4 MR. PERL: Immediately tested. 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. PERL: First trip to surface..... 7 COMMISSIONER CHMIELOWSKI: Right. 8 MR. PERL: .....we'll retest them, yes. 9 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 10 So talking about, you know, just an escalating well 11 control scenario or say there's gas on the rig floor, 12 what are Hilcorp's well control procedures for that? 13 MR. PERL: John Perl. We escalate as -- if we 14 have gas to surface we'll run a liner, the guys will go 15 through the scenario of picking up the safety joints, 16 getting -- getting it stabbed, trying to get shut-in. 17 If we -- and then we would go into our tertiary stuff 18 as far as -- depending on what's going, is it not 19 hanging, then we've got our other pipe slips, we've got 20 our annular, we got other ways to get shut-in. 21 COMMISSIONER CHMIELOWSKI: Does Hilcorp have a 22 procedure for well control that might assume that say 23 people aren't allowed to be on the rig floor and need 24 to be evacuated immediately so aren't setting the 25 safety joints? Page 85 1 MR. PERL: At that point in time if it got to 2 where we -- the gas alarms were going off, that kind of 3 deal would be a shut-in, we'd have to shear pipe and 4 drop..... 5 COMMISSIONER CHMIELOWSKI: Okay. 6 MR. PERL: .....and evacuate. 7 COMMISSIONER CHMIELOWSKI: So Hilcorp has a 8 procedure for that? 9 MR. PERL: Nabors/Hilcorp. 10 COMMISSIONER CHMIELOWSKI: Nabors does. Okay. 11 Okay. And I think this is my final question. So again 12 it's like a escalating well control scenario, gas on 13 the rig floor. So just want to clarify that the AOGCC 14 does not dictate an operator's well control procedure. 15 Okay. So there's gas on the rig floor so your gas 16 alarm's going off, there's the safety joint option, I 17 know you're saying there's a VBR only option or you -- 18 say you had both, you could use a safety joint and a 19 VBR. Which is better? 20 MR. PERL: It would be still -- still getting -- 21 getting the safety joint in the hole is number 1, 22 gives you the most forward looking progress of being 23 able to handle escalating because you -- you've got to 24 look at it also if you -- you got to get the well shut- 25 in, but you got to be -- put yourself in a place that AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 23 (Pages 86 to 89) Page 86 1 you can get the well back under control also. 2 MR. McLAUGHLIN: Sean McLaughlin. With 3 respect, Commissioner Chmielowski, I think I heard you 4 just say that the AOGCC does not dictate well control, 5 but by dictating what is -- must be in the stack, I 6 think that they may be -- if the AOGCC is dictating 7 what is in the BOP stack they're influencing well 8 control. 9 COMMISSIONER CHMIELOWSKI: So what is your 10 answer to the question, if you have only a safety 11 joint, only a VBR or you have the choice for both, 12 which is better? 13 MR. McLAUGHLIN: Looking at the aggregate of 14 integrity, human factors, timely shut-in, it is best to 15 run a safety joint and not have a liner ram in the 16 stack or CS hydril ram in the stack. That is best for 17 well control. 18 COMMISSIONER CHMIELOWSKI: Okay. I have no 19 further questions. Is there anything I missed? 20 COMMISSIONER WILSON: Nothing additional..... 21 COMMISSIONER CHMIELOWSKI: Okay. 22 COMMISSIONER WILSON: .....from me. 23 COMMISSIONER CHMIELOWSKI: We have a little bit 24 more of the hearing to go through with public comment 25 so go through that now. Page 87 1 COMMISSIONER WILSON: Yeah. So now I'd like to 2 offer to any member of the public the opportunity to 3 testify or provide comments. As mentioned earlier no 4 written comments were received on this matter. 5 Samantha, is there anyone online? 6 MS. COLDIRON: No. 7 COMMISSIONER WILSON: Is there any member of 8 the public that would like to testify in the room? Put 9 -- yeah, please come forward and state your name for 10 the record. 11 MR. McKEEVER: (Indiscernible - away from 12 microphone). 13 COMMISSIONER CHMIELOWSKI: What's your 14 affiliation, Mr. McKeever? 15 MR. McKEEVER: I'm a member of the public. 16 COMMISSIONER CHMIELOWSKI: Okay. 17 MR. McKEEVER: (Indiscernibles - either away 18 from the microphone or sounds like his mic is not on) 19 I'm a former -- by way of introduction I'm a 20 former drilling engineer, I've had (indiscernible - 21 microphone not on). I don't -- I'm not (indiscernible - 22 microphone not on) at all (indiscernible - microphone 23 not on) questions that are (indiscernible - microphone 24 not on) most of the -- most of the wells on the North 25 Slope are directional wells (indiscernible - microphone Page 88 1 not on) question in my mind (indiscernible - microphone 2 not on) accumulator pressure as low as possible. 3 (Indiscernible - microphone not on). I guess another 4 question (indiscernible - microphone not on) two or 5 three different liners (indiscernible - microphone not 6 on). Again as I mentioned, you know, again as you 7 consider the waiver if you do grant it, I'm not sure 8 (indiscernible - microphone not on). 9 Okay. Thank you. 10 COMMISSIONER WILSON: Thank you, Mr. McKeever. 11 Is there anyone else for comments? 12 (No comments) 13 COMMISSIONER WILSON: The line is still empty. 14 Well, then hearing no other business I have 12:16. The 15 hearing is now adjourned. 16 (Off record - 12:16 p.m.) 17 (END OF REQUESTED PORTION) 18 19 20 21 22 23 24 25 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 89 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: OTH-25-014, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 best of our knowledge and ability. 8 9 _______________ _______________________________ 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 1 A a.m 1:9 3:2,5 74:12,13 AAC 1:3 3:10 4:5,15 ability 23:8,11 23:21 28:22 43:24,25 55:3 59:8 65:4 89:7 able 4:2 13:2 18:5 23:8,16 23:17 24:2 28:24 29:1,16 35:1,1 43:9 51:19,21 52:1 53:20 54:16 79:15,19 85:23 absolutely 41:8 71:12 acceptable 8:19 15:11,12 accepted 29:12 accommodate 3:23 accommodation 3:20 accumulator 30:15,19 31:5 31:7,10 48:25 49:11,13,13 50:11,15,19 88:2 accurate 89:4 acquired 42:13 act 58:25 action 67:10 actively 50:11 activity 12:25 actual 79:1 actuated 49:21 49:23,24 add 25:10 43:10 43:20 53:1 62:14 69:4 77:13 81:8 added 39:17 53:17 adding 41:18 42:6 43:16 67:2 additional 4:22 74:16 83:23 86:20 address 32:14 39:8 addressed 66:13 addressing 3:18 adds 17:24 26:19 adjourned 88:15 administered 5:5 Administrative 4:6 advanced 22:12 advantage 47:23 48:1 affiliation 87:14 affirmative 5:8 aggregate 67:7 86:13 agree 67:11 ahead 27:18 30:3 34:4 44:6 57:19 78:16 alarm's 85:16 alarms 85:2 Alaska 1:1 3:7,8 3:14,16 4:5,5,7 4:7,14 5:25 6:11 8:3,6 11:1 27:21 42:5,13 44:13 46:15 63:5,10 64:2 64:23 68:9 Alaska's 1:2 42:14 allow 15:23 29:7 29:13 65:10 allowed 84:23 allows 23:2 24:8 28:15 amount 15:25 35:20 45:9 49:10 65:23 analysis 5:18,20 Anchorage 3:16 4:11 annular 16:6,17 23:13 28:24 31:6,8 38:3,6 44:22 49:14,14 49:15 50:1 51:10,24 52:12 53:15 55:1,3 57:6,8 62:16 62:24 80:13,14 80:17 81:4,9 81:10,12,13,18 81:23 84:20 annulars 81:21 annulus 43:24 72:12 answer 32:14 86:10 anybody 74:20 anymore 79:14 anytime 20:5 Anyway 42:18 AOGCC 3:19 4:9,10,12,15 15:20 32:10 34:12,14,15 41:17 74:22 85:13 86:4,6 AOGCC's 4:8 API 5:20 12:3 69:13,15,22 70:2,6,10 81:25 82:3,4 applicable 82:18 apply 82:12 appreciated 25:18 appropriate 10:2 12:5 approval 75:3 approved 42:11 74:22,24 approximately 3:4 6:14 April 4:9 Arabia 5:22 ARCO 11:13 area 12:11 21:22 66:19,21 70:3 areas 14:12 17:25 24:20 25:3 26:20 arguing 40:22 ascertain 33:17 Aside 25:6 asked 7:7 63:10 asking 7:15 9:24 32:17 33:3 45:22,23 59:11 61:21 62:17 67:20 aspect 65:18 aspects 64:11 assessment 42:9 42:9,18,19 assessments 5:19 associated 46:23 Association 6:9 assume 62:2 84:22 assumed 49:10 assumption 34:16 attempted 38:24 attempting 62:23 attended 5:15 attending 63:15 available 13:4 18:8 19:4,12 23:12,13 24:4 27:3 28:23 38:6,15 40:23 44:23,24 49:9 50:16 66:9 Avenue 3:15 averages 24:2 aware 61:2 69:19 B B 17:10 bachelor 6:12 back 7:5 9:1 10:24 14:9 32:9 74:8,15 75:10 76:20 86:1 background 3:17 4:13 63:24 backup 18:9 19:5,5 44:6,8 51:24 55:1,2 57:7 68:16 baffle 73:3,9 bag 38:24 barrel 56:10 barrier 64:13 71:17 base 75:24 based 12:3 13:18 14:11 64:5,21 basically 34:7 46:19 50:19 51:2 56:10 63:15 72:21 76:16 77:9 83:5 Baton 6:13 bay 30:22 BBR 17:25 beginning 58:23 begins 68:17 behalf 8:2 46:14 63:4 belief 67:16 believe 16:4 27:4 28:12 32:20 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 2 33:15 67:8,14 68:5 82:11 believes 66:25 bench 30:12 bend 82:18 benefit 39:17 40:24 benefits 67:4 best 3:23 48:2 51:21 56:19 58:23 67:9 68:6,24 71:24 86:14,16 89:7 better 23:2 28:15 51:6 53:8 54:21 62:22 67:2 85:19 86:12 beyond 25:17 BHA 9:11 10:21 15:1,21 17:11 17:14,17 74:22 75:1 76:12,12 77:13 81:22,23 BHAs 1:5 4:19 big 36:12 52:2 58:10,10 71:9 79:12 bigger 42:10 biggest 47:23 48:1 59:5 65:18 79:18 80:16 81:2 bit 9:24 12:10 14:14 22:2 27:9 32:8 41:14 42:1 49:17 63:14 86:23 biweekly 82:25 blind 16:17 23:14 24:3 25:1 28:24 29:6,19 31:19 40:3 47:8,9 49:17,25 50:1 50:5 56:5 77:7 blocks 83:17 blow 55:5 blowout 63:13 board 59:17 bodies 83:17 bonsai 72:23 73:16 boosters 49:18 BOP 5:19 16:1 16:14,15 19:6 21:14 25:21 32:18,20 35:17 36:25 37:3 44:23 46:19 47:5 48:11,25 50:18,20 65:15 67:3 74:25 76:24 82:24,25 86:7 BOP's 35:9 BOPs 83:16,18 bore 9:7,20 16:23 64:1 65:3 bottles 50:16 bottom 15:17 16:1 18:4,5,6 23:18,22 24:3 24:10 26:6 51:22 53:4 54:9,19 56:13 58:12,14 60:9 75:7 76:23 77:12,14,15,16 77:21 bound 10:6 bounding 10:11 bounds 9:24 bowl 79:1 box 60:8 76:5 BP 6:24 7:2 11:13 14:12 27:19,21 42:13 42:14 BP's 42:25 break 56:1 76:8 77:23 breakdown 53:19 59:10 breaking 52:9 bright 60:5 bring 58:19 brought 58:9 BS 5:14 build 41:20,21 41:24 bullet 18:18 28:9 29:19 41:13 43:15 bullhead 13:3 23:8 28:17 35:2 43:7,24 52:3 54:14,21 55:16,25 59:9 bullheading 52:14,17 bunch 53:17 business 41:24 82:14 88:14 button 39:2 C C 3:1 calculated 48:23 49:3 calculations 48:24 call 3:4 74:14 77:1 called 8:2 25:17 46:14 63:4 72:23 75:9 cap 5:20 capability 44:24 capitalized 10:6 caps 49:1 care 68:22 career 6:25 carriers 83:17 case 9:19 17:4 26:6,24 34:21 34:25 38:4 39:15,17,20 41:10,11,12 55:25 61:19 64:10 65:8,9 65:19 67:4 73:3,7,10 cased 10:1,5,14 12:15 15:3 44:21 68:10 70:17,18,24 72:16,19,20 cases 43:18,19 62:25 65:21 casing 1:4 4:18 5:18 72:9 CAT5 83:16 CDR 50:12 CDR2 47:4 60:5 CDR3 47:4 cellar 37:6,10 cellars 53:7 cement 11:7,10 71:6 73:4 cemented 15:17 71:11 73:5,8 certainly 68:21 CERTIFICATE 89:1 certification 6:10 certified 68:2 certify 89:2 cetera 63:20 chain 76:13 77:3 chains 76:14 change 9:12 20:2 24:12 26:10 29:14 58:2,2 59:25 60:3,4 61:4 67:20 68:20 69:25 changed 61:9 changes 12:19 59:19 61:3 changing 58:6 chart 46:23 48:15 49:3 charts 47:11 chat 3:23 check 75:12 77:20 83:23 checked 14:25 50:19 checks 13:22 Chmielowski 1:11 3:12 7:9 7:12,16,18 9:16,19 10:12 10:16,18 11:14 11:19,21,23 14:6,13 17:6 17:12,15,18 19:1,3 20:22 21:1,19 22:1,3 22:6,8,13,17 22:19 24:16 25:5,19 27:16 28:1,3,7 29:18 30:2,7,14,18 30:23 31:1,13 31:16 33:10,19 33:23 34:4 35:7,23 36:19 36:24 37:4,13 37:17 38:8,13 38:20 39:4,7 39:10,21,24 40:7,17 41:3 42:12,20,23 43:12,14 45:4 45:7,16,21,25 46:4,7,10 48:12,15 49:2 49:8,15,22 50:3,7,10,14 50:21 51:1 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 3 52:24 53:11,22 55:10,20 56:18 56:21 57:8,21 57:24 58:5 60:21,25 61:6 61:21 62:7,11 62:13,20 63:1 66:7,15,23 68:15,25 69:3 69:7,10,12,20 69:23 70:13,16 70:22 71:5,13 71:19 72:2,14 72:18,24 73:6 73:12,15,18,20 74:1,4,7,10,16 74:18 75:4,8 75:11,13 78:2 78:5,8,10,13 78:15,19,21 79:9,22,25 80:3,10,12,20 81:3,6,14,19 81:24 82:20 83:2,7,10,13 83:21 84:2,5,7 84:9,21 85:5,7 85:10 86:3,9 86:18,21,23 87:13,16 choice 20:24 86:11 choke 18:2 23:16 26:22 28:25 53:10 54:4,4,5 54:13,13 65:11 77:17,19,19 chooses 36:8 chunk 30:6,9,10 58:12 circulate 14:4 18:2 23:16 26:22 27:2 28:25 51:22 53:5 54:8 77:16,20 circulated 14:24 56:13 circulating 14:2 77:15 circulation 23:25 29:5 clarification 10:17 63:2 clarify 10:13 33:10 85:13 clarifying 4:23 clean 11:9,12 14:25 26:7 72:20 75:7 clear 5:21 33:3 46:1 clearly 7:24 close 20:7 34:24 40:15 47:24 48:5,6,6 49:25 51:24 54:2,2,4 54:25 55:13 56:5 closed 44:23 47:8,10 49:14 49:25 50:5 51:11,17 54:25 76:2 closer 30:8 closes 23:13 closing 14:23 17:25 18:11 24:11 26:20 41:2 43:7 clunky 12:13 code 4:6 57:13 coil 1:3 5:16,17 5:23,23 8:17 9:25 10:25 11:2,6 12:6,9 12:10,22 14:10 15:24 16:1 17:2 23:18 24:9 25:20 29:1 31:25 35:3 36:11 43:18 44:12,18 45:9,11 46:25 58:10,18,18 60:24 61:9,17 61:18 63:12 66:6 68:10 70:1,7,9 72:8 76:2,6,8,15,18 77:12,17 80:25 81:1 82:4,12 82:13,14,16 coiled 3:9 12:14 13:6,15 18:5 24:20,22,24,25 25:2,11 38:18 66:6 69:15 coils 7:6 Coldiron 3:21 3:24 6:4 87:6 collars 1:5 4:19 color 57:13 colored 57:18 60:5 column 23:24 47:12 columns 47:2 come 11:3,5,7 42:21 52:5 53:2 55:22 56:14 70:23 71:1 74:7 76:3 77:5,7 87:9 comes 20:11 54:24 64:4 66:21 76:18 coming 19:23 35:15,20 37:14 comment 41:16 82:2 86:24 commentary 26:1 comments 4:12 32:9,11 87:3,4 88:11,12 Commission 1:1 3:9,15 21:15 Commissioner 1:11,11 2:2 3:3 3:11,12 5:2,7 5:12 6:1,5,20 7:9,9,12,13,16 7:18,19 9:16 9:19 10:12,16 10:18 11:14,19 11:21,23 13:19 14:6,13 17:6 17:12,15,18 19:1,3,17 20:22 21:1,19 22:1,3,6,8,13 22:17,19 24:16 25:5,19 27:16 28:1,3,7 29:18 30:2,7,14,18 30:23 31:1,13 31:14,16 33:10 33:19,23 34:4 34:5 35:7,23 36:19,24 37:4 37:13,17 38:8 38:13,20 39:4 39:7,10,21,24 40:7,17 41:3,4 41:10 42:12,20 42:23 43:12,14 45:4,7,16,21 45:25 46:4,7 46:10 48:12,15 49:2,8,15,22 50:3,7,10,14 50:21 51:1 52:24 53:11,22 55:10,20 56:18 56:21 57:8,21 57:24 58:5 60:21,25 61:6 61:21 62:7,11 62:13,20 63:1 66:7,15,23 68:15,25 69:3 69:7,10,10,12 69:20,23 70:13 70:16,22 71:5 71:13,19 72:2 72:14,18,24 73:6,12,15,18 73:20,24 74:1 74:2,4,6,7,9,10 74:14,16,18 75:4,8,11,13 75:22 78:2,5,8 78:10,13,15,19 78:21 79:9,22 79:25 80:3,10 80:12,20 81:3 81:6,14,19,24 82:20 83:2,7 83:10,13,21 84:2,5,7,9,21 85:5,7,10 86:3 86:9,18,20,21 86:22,23 87:1 87:7,13,16 88:10,13 Commissioners 4:20 communicated 64:19 company 5:20 34:1 41:20 42:10 45:8 comparable 44:11 Compared 65:8 comparing 64:5 comparison 12:16 64:10 compiled 48:20 complete 89:4 completed 78:16 completely 20:20 59:12 71:10 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 4 completion 4:1 5:19 completions 72:22,23 73:16 compliance 32:16 64:22 compliant 34:20 complies 64:22 comply 64:2 Computer 3:25 4:3 concern 59:13 concerns 32:13 34:11 conclusion 66:3 condition 10:11 conditions 29:23 31:22 36:22 configuration 16:16 19:6 51:7 74:25 configurations 8:22 18:21 confined 66:18 confirmed 29:4 conn 77:5 connect 23:18 29:1 connection 76:4 76:9,22,25 connections 14:3 Conoco 45:5 Conoco's 46:1 ConocoPhillips 14:15 cons 63:24 64:5 64:10 66:2 67:8 Conservation 1:1 3:9,15 consider 13:17 15:6,22 54:20 88:7 considered 9:11 10:21 15:21 81:22 consistency 45:24 consistent 24:10 29:13 58:22 60:2 constructed 12:24 construction 12:23 consult 4:21 consultant 6:8 contact 3:21 contacting 4:3 CONTENTS 2:1 continuous 12:17 13:22 14:1 23:25 29:5 continuously 14:4 Contractors 6:10 control 3:10 6:10,19 8:11 13:4,8,16 14:8 14:18 16:5 17:25 18:1,8,9 19:4 22:4,12 23:3,8,11 24:19 25:4 26:20,21 27:3 27:5 28:14,16 28:20,22 29:9 29:10,11 30:20 33:2 34:25 35:14 37:1 39:15 40:3 42:7 43:5,22 44:15,17 46:12 46:19 48:9,25 51:21 53:9,10 54:4,5 59:15 63:21 64:4,8 67:5,7,10,12 68:2,6,23,24 69:8 72:3 75:14,21 84:11 84:12,22 85:12 85:14 86:1,4,8 86:17 controlled 55:18 conventional 26:4 conversation 38:22 39:1 conversations 38:24 67:13 coordination 6:18 coordinator 7:4 copy 4:2 89:6 corporate 42:25 correct 25:22 34:6 47:19 61:2 62:1,2,3,4 69:16 correctly 64:6,8 66:20 couple 7:1 9:16 20:15,18 32:10 45:12 48:11 course 61:3 67:9 cover 8:8,9,10 8:11 16:12,13 19:9 21:10 25:25 28:8 47:7 covered 70:6 covers 46:24 78:20 create 43:21 creates 18:24 27:10,13 32:18 credentials 5:13 7:10 crew 19:18 59:4 65:13,13 crews 18:24 19:21,23 24:14 27:14 29:15 60:20 cross 16:18 18:3 19:15,16 22:25 23:2,17 24:17 24:25 28:18 43:23 47:15 51:9 52:17 53:10,15 55:17 64:16 65:9 cross-threaded 60:13 cross-threading 60:11 crossover 47:19 60:4 61:15 crossovers 57:15 59:19 60:4 61:13 CS 9:9,10,14 11:9,11 15:13 15:21,22 16:13 20:8,14,15,17 20:18 25:24 26:8,14,15,18 26:18,20,22,25 28:11,15,16 30:9 41:15 43:8 56:9 65:21 67:2 72:7,18 73:11 81:22 82:19 86:16 CTD 6:22,24 30:4 40:4 46:17 56:16 CTU 7:5,7 cumi 47:6 curious 21:20 31:1,5 72:4 current 16:15,20 34:9 63:21 66:19 currently 5:24 6:9 9:7 26:9 cut 24:4 25:12 52:19 cutting 29:7 cycle 83:19 D D 3:1 Daily 4:11 damage 18:16 dangerous 37:11 data 42:22 date 4:11 27:8 48:16 89:10 dates 11:10 David 73:1 deal 85:3 decide 23:6 58:25 decided 7:6 decides 54:9 decision 18:24 27:13 28:6 64:5 decision's 21:8 deck 61:24 dedicated 53:16 deeper 10:14 defer 66:10 definitely 65:7 degradate 24:19 degrade 33:2 degree 6:12 depend 65:22 depending 60:20 84:18 deploy 30:19 56:9 76:12 deployed 12:15 31:5 deploying 15:13 17:14,16 52:7 deployment 24:1 29:11 depth 12:17 describe 19:17 82:21 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 5 described 64:15 describing 19:19 design 5:18 27:5 desiring 4:2 destroy 81:11,17 detecting 64:7 detection 13:7 13:20,21 determine 4:22 65:24 determined 26:12 developed 12:10 73:1 deviation 43:13 di 51:3 diagram 75:20 diameter 81:6 dictate 85:14 86:4 dictating 86:5,6 difference 26:16 46:20 different 8:23 12:14,21 19:22 19:23,24,24 20:4,16 26:3 36:11 56:22 60:21 70:10,10 75:18 88:5 differently 70:11 82:16 DIRECT 8:4 46:16 63:6 direction 89:5 directional 87:25 disadvantage 51:16 discuss 39:20 54:6 discussing 63:13 discussion 21:7 diversion 65:10 doc 43:2 docket 1:6 3:6 89:5 document 69:22 70:14 documentation 28:3 42:7,17 43:2 63:17 74:21 doing 7:1 20:10 33:1 55:8 56:1 draw 47:4 49:13 50:19 drill 1:5 4:19 24:14 29:16 53:9 58:1 59:14 66:6 70:6 73:8 74:24 75:2 drilled 13:14,15 14:24 45:12 driller 62:6 drillers 19:25 44:12 67:23 drilling 3:10 5:23,24,24 6:10,22 8:5,17 11:1,2 12:4,6 12:11,12,14,22 13:5,6,11 14:11 15:1 16:16,20 17:2 17:8,9,10 18:5 24:22 26:5 35:3 43:19 44:12,19,21 45:10,11 53:16 63:13 68:10 69:15 70:5,7,9 87:20 drills 64:17 65:13 drillsite 67:22 driven 67:19,21 driver 69:2 drop 85:4 dropping 29:20 due 18:17 23:25 29:5 43:18 44:19 65:3,19 dump 76:13 duration 15:5 duty 20:3 DVRs 18:13 dynamic 13:22 E E 3:1,1 earlier 32:8,17 64:15 66:13 87:3 early 12:6 63:16 73:2 ease 64:19 easily 36:16 easy 34:24 36:15 43:10 edge 57:23 educate 35:13 effective 16:7 64:17 efficiency 68:18 68:19,22 efficiently 36:17 eight 25:23 67:22,23 eights 16:18 19:16 25:2,9 25:14 61:9,20 either 14:22 21:9 33:4,8 38:4,4 39:12,14,16,20 40:25 41:1,11 44:24 49:25 54:7 67:4,13 87:17 either/or 66:8 elaborate 13:19 45:5 electronic 89:6 elements 12:24 18:14 elevator 62:8 elevators 57:13 59:23,25 email 4:9 emergency 24:5 29:7 empty 88:13 enacted 38:3 enclosed 23:15 endeavor 36:18 engineer 87:20 engineering 5:15 5:17 6:13,17 6:17 8:9 64:4 64:11 67:21 ensure 83:24 ensuring 70:24 entity 42:13 entry 15:23 equalize 77:6,10 equipment 27:5 29:9,10 equipped 1:4 4:17 68:12 equivalent 47:9 error 18:25 67:11,13,17 errors 19:18 escalate 84:13 escalating 18:9 22:4 31:22 84:10 85:12,23 escalation 39:15 et 63:20 evacuate 85:6 evacuated 84:24 evaluate 48:7,8 event 13:18 15:7 events 13:16 14:8 everybody 61:24 everyone's 61:2 everything's 51:10 57:14 evidence 14:7 evolved 11:5 Exactly 30:17 EXAMINATI... 8:4 46:16 63:6 example 9:2 16:6 46:19,19 47:3 50:22,23 51:3 56:6 examples 46:12 exceed 65:5 excuse 55:19 exemption 42:5 exhibits 63:12 existing 64:23 expect 35:11 experience 6:15 45:18 expertise 5:13 7:10 66:19,21 experts 5:10 7:14 explain 35:13 explicitly 75:5 exposed 64:14 exposure 71:3 extensive 65:17 extra 43:16,20 45:2 65:19 extras 17:3 extremely 35:9 F F89 56:7 fact 81:21 factor 44:18 56:23 57:1 61:23 79:12 factors 56:25 86:14 failed 71:7 fair 33:17 40:16 fairly 15:4 36:14 36:15 false 79:1 familiar 27:23 27:25 41:6 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 6 81:25 82:3 far 13:13 42:7 47:7 59:15 60:15 63:14 84:1,18 feel 32:12 34:9 34:21 63:23 feet 11:15,16,17 11:20 18:7 20:18 field 5:13 7:14 67:18,19 figured 24:23 filed 3:7 4:14 filled 50:16 filter 55:25 final 22:16 23:25 85:11 financial 71:17 financially 69:5 69:9 finer 13:24 finish 77:25 fire 62:10 first 8:6 10:25 18:20 20:23,23 21:2 31:4 74:19 75:16 84:6 fit 1:4 4:17 12:13 13:2 69:15 fits 68:13 five 16:14 23:12 28:22 53:3 56:10 60:14 83:15,19 five's 53:6 five-eights 58:17 60:24 floor 35:19 36:2 36:9 37:2,6 47:18 57:17 59:20 68:3 76:3 84:11,23 85:13,15 floorhand 20:3 flow 13:22 14:25 16:8,18 18:3 19:15,16 22:25 23:1,17 24:17 24:25 28:18 35:20 43:23 51:8,9 52:16 53:10,15 55:17 64:16 65:9 77:20 flow's 35:20 fluid 13:25 23:24 29:4 56:2 59:9 65:23 fluids 65:10 follow 7:23 34:12 follows 8:3 46:15 63:5 foot 74:22 75:1,4 footage 75:10 forced 32:25 forces 64:14 65:5 forego 63:8 foregoing 89:3 foreman 6:22 30:4 46:17 forgot 55:8 fork 76:7 formality 32:3 former 87:19,20 forth 9:1 32:10 forward 85:22 87:9 four 16:9 19:22 23:11 28:22 53:2,2 56:11 60:14 frequency 82:14 full 37:23 48:6 fully 70:18,24 further 34:18 69:11 86:19 future 52:25 G G 3:1 gaining 10:25 gas 1:1 3:8,15 15:8 16:2,3 35:15 37:14 38:2 71:23 84:11,14 85:2 85:12,15,15 geared 69:14 getting 49:12 51:17 52:4 54:21 59:15,15 60:14 70:25 84:16,16 85:20 85:21 gifts 35:2 give 10:19 51:21 58:24 given 66:12 gives 13:3 54:5 56:2 58:20 59:4 85:22 giving 27:14 43:23,25 66:16 Global 27:21 go 6:1 7:7 11:23 22:10 30:3 34:4 38:1 39:15 44:5 47:16 48:5,11 51:4 52:3,17 52:23 53:2,2 53:16 54:8,15 54:19,24 55:14 55:15,15 56:24 58:1,15,17 60:17,18,23 61:7,12 73:9 74:20 75:10 76:11 77:15 78:16 80:15 84:14,17 86:24 86:25 goes 10:24 72:15 78:23 83:16,19 going 6:2 8:7,8 8:21 9:1 12:21 15:7,8,24 16:10 17:22 19:8,23 20:6 21:7,8,10,24 25:23,25 26:1 26:5 27:8,17 31:15 32:6,19 33:4,5,6,8 34:19,20,22,23 34:24 35:7 36:2,21 37:9 37:10 38:18 39:18 41:23,24 43:6 46:11,18 47:13 51:9,20 52:10,11 54:6 55:25 56:1,3 57:16 58:25 63:20 65:20,22 72:12 81:2 84:18 85:2,16 good 3:3 6:7 21:14 23:7 27:15 34:21 42:3 44:8 48:7 63:24 67:6 79:23 82:9,10 83:24 grab 20:6 37:8 47:18 77:2 grabbed 79:13 grant 88:7 gray 12:11 70:3 great 31:16 62:24 greater 23:11 28:14,21 40:3 greatest 24:21 35:2 Greg 1:11 3:11 ground 15:15 20:5 24:7 36:4 36:6,7 38:19 72:8,17 75:1 group 7:2 guarded 79:13 guess 34:5,7 41:4 42:23 63:8 70:19 73:2 80:16 88:3 guiding 69:22 70:14 guns 9:3 16:5,7 20:9,12,14,16 36:5 37:22 44:16,16 guy 34:22 47:18 59:1 guys 8:15 47:17 50:15 51:13 52:25 55:11 59:2,13 60:10 60:13,15 66:11 84:14 H half 9:5 16:11,23 19:13 58:14 59:22 60:8,12 60:19 66:1 76:4 80:17 Halliburton 6:25 hand 8:11 16:21 22:23 47:16,20 47:22 48:1 51:13 60:14,16 75:23 77:22 78:24,25 79:12 79:15,17,25 80:2,6 handle 85:23 hands 5:4 61:24 hang 55:3 80:5 hanging 80:9 84:19 hangs 80:5 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 7 happen 56:7 75:25 77:14 79:1 happened 53:7 happening 37:11 happens 37:2,6 76:11 hard 60:12 68:7 hastily 58:25 HCR 51:10 54:4 HCRs 49:19 51:11 he'll 8:10 hear 12:21 heard 21:11 32:11,15 41:16 44:2 73:21 86:3 hearing 1:7 3:4 3:6,8,13,25 4:4 4:6,14 33:4,25 86:24 88:14,15 height 43:18 53:17 63:19 heights 43:19 held 3:13 4:4 31:25 help 38:8 hey 34:23 40:22 40:23 Hi 6:21 high 31:25 55:21 higher 49:19 65:2 highest 50:6 highlight 19:10 26:17 40:19 highlighting 40:11 Hilcorp 1:2 3:7 4:14,24 5:25 6:22,24 7:8,15 8:3,6 14:12 15:20 41:15 42:13 46:15 63:5,10 66:25 67:21 68:9 69:5,9 73:16 74:21 80:14,17 82:21 83:23 84:21 85:7 Hilcorp's 33:12 45:22 61:1 84:12 Hile 89:2,10 hinders 17:25 26:20 historical 10:20 13:18 14:10 historically 9:10 10:20 14:12 15:20 history 12:2 43:1 63:16,18 hit 39:1 Hmmm 53:11 62:20 hodgepodge 19:25 holding 55:7 76:10 78:24 hole 5:17 8:17 8:21 9:21 10:1 10:3,5,10,13 10:14 13:23 15:3 20:12 35:1 43:9 44:21 51:19,23 52:1,8,13 54:1 54:7,8,11,21 58:10 63:23 68:10 70:24 71:9 72:6,15 72:16,19,20 75:16,20 77:12 77:14,21,25 78:22 79:7 85:21 horizontal 10:4 10:11 12:20 16:3 horizontals 12:18 hours 20:15 56:11 human 56:23,25 61:23 67:11,13 67:17 86:14 humor 56:21 hundred 45:12 68:4 hybrid 70:3,4 hydraulic 47:6 hydraulically 76:25 hydril 9:9,10,14 10:20 11:9,11 11:15 15:13,21 15:22 16:13 20:9,14,15,17 20:18 25:24 26:8,14,15,18 26:19,20,22,25 27:20 28:11,15 28:16 30:9 41:15,20,21 42:2 43:8 49:4 56:9,14 65:21 67:3 70:17 72:7,18 73:11 75:5 81:4,22 82:19 86:16 I IADC 6:10 icon 3:23 idea 42:3 44:5 ideas 82:9 identified 7:14 identify 5:13 30:2 illustrate 64:24 illustration 16:14 imagine 43:1 imagining 30:20 immediately 30:11 54:19 79:24 84:2,4 84:24 implement 27:19 importance 71:14 important 18:19 44:20 75:22 inch 9:10 16:18 16:22 17:7,11 22:24 25:14,24 26:8,9,11,15 26:25 27:7,8 30:6,9,10 31:24 32:1 43:8 56:9 58:13,16 60:8 60:11 61:8,11 61:11,12,12 76:4 80:16,23 80:24,25 81:12 81:17 incident 56:24 incidents 56:15 69:8 included 45:2 74:25 83:1 including 5:16 6:16 63:21 inconsistent 18:19 27:10 incorrectly 61:22 independent 6:8 indicate 53:1 Indirectly 74:23 indiscernible 7:7 7:8 20:15 30:21,24 31:3 41:18 51:10 52:8 60:18 76:20 77:18 79:3 87:11,20 87:21,22,23,25 88:1,3,4,5,8 Indiscernibles 87:17 industry 5:22 6:8,15,23 27:4 29:11 44:9 67:1 83:19 inferior 28:20 42:7 infinite 24:1 29:6 66:5 influencing 86:7 information 4:22 10:19,21 13:18 27:22 48:21 49:6 64:18,19 injector 24:9 48:4 51:20,20 54:18 56:12 75:24 76:2,2 76:14,17,23 77:3,24 78:9 78:10 inside 11:12 16:8 72:11 80:6 inspection 83:16 install 22:21 28:11 44:4 65:20 installed 17:23 32:25 58:15 installing 26:18 47:16 64:1 integral 71:9 integration 70:1 integrity 6:18 64:12 65:3 81:11,17 86:14 intensity 15:7 interest 71:24 interesting 32:22 International AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 8 6:9 interpretation 9:12 intervention 6:18 12:25 interventions 12:12 introduced 63:9 introduces 18:25 introduction 63:8 87:19 involved 14:10 42:3 isolated 71:10 issues 55:4 it'll 70:18 J jacked 18:13 jacking 18:17 24:7 51:18 52:12 54:10 55:18 64:15 65:4,7 January 63:16 jerks 60:17 Jessie 1:11 3:12 32:6 57:10 job 7:24 11:10 56:1 John 6:21 8:10 8:13 30:1,4 46:12,13,17 82:23 83:25 84:13 joint 8:18 9:4,8 9:13 14:3,23 15:11 18:23 20:6,13,23 21:2,2,9,18,22 23:2,10 24:1,6 24:11 28:12,12 28:21 29:2,11 29:13 33:5,7,9 34:10,13 35:17 35:19 36:5,6 36:13 37:9,19 37:21 38:5,25 39:13,18 40:2 40:4,19 41:2 44:4,6,9,14,16 45:1,14,20 46:6,9 47:17 47:18,20,21,23 51:5 53:25 54:16 57:1,11 57:15 58:3,8,9 58:12,17,18,19 58:21 59:7,14 59:24 61:10,20 61:25 62:9,23 63:25 65:1,2,9 65:19,20 66:3 66:25 67:2,8 67:15,25 68:4 68:11 75:17,19 75:20 78:3 80:8 85:16,18 85:21 86:11,15 joint's 57:5 jointed 8:17,21 11:4 12:9 23:15 24:13 26:23 27:12 29:15 63:23 68:11,13 82:16 82:17 joints 46:20 56:9 60:16,22 61:16 61:19 69:17 73:14 84:15,25 judgment 64:4 jumping 27:18 justification 22:21 28:10 40:2,9,13,16 42:15 68:17 justified 27:21 justify 43:1 K KCL 52:8 keep 60:1 77:25 kick 10:5 12:19 12:20 13:7,7 13:20,21 14:1 14:17,21 15:6 15:7,9,13 24:1 29:6 34:23 44:17,19 51:22 56:8,10 63:18 64:7,20,20 65:2,10,19,21 65:24 66:5,5 70:11 kill 13:3 18:2,4,6 23:16,19,22 24:3 26:22,23 28:17,25 35:2 43:7,24 51:11 52:3 54:12,12 54:13 killed 52:4 59:1 kind 8:12,14 9:24 12:11,13 19:18 51:3 52:13,25 54:21 59:10 60:11,19 64:24 70:8 82:14 85:2 know 10:20,22 11:11,14 12:7 14:7,14 20:2,6 21:20,23 31:2 31:2,5,6,7,9,9 32:14 35:13 38:15 39:24 41:4 42:13,25 43:1,2 51:18 52:25 53:1 56:22,25 57:2 58:3 60:9 61:1 61:3 62:3 63:14 65:11 66:1,11,19,20 66:21 69:13 70:9,17,24,25 71:1 81:10 84:10 85:17 88:6 knowledge 14:10 45:13 89:7 known 23:23 29:3 77:4 Kuparuk 45:10 L lab 29:24 laid 8:12 14:25 15:18 57:11 lap 70:23 71:15 72:10 large 15:8 80:20 largely 65:22 larger 49:17 65:21 largest 66:4 80:14 late 15:22 74:19 74:25 lateral 71:1 laterals 45:13 lay 77:24 layer 45:2 laying 56:14 61:19 77:23 lays 44:16 leader 7:2,6 leak 51:24 55:6 71:11 leaking 54:25 leaks 40:15 leave 22:23 57:4 leaving 76:17 left 32:5 46:22 left-hand 16:15 26:3 length 11:15,17 11:22 77:13 let's 11:23 20:11 22:15 36:3 55:13 letter 3:6 leverage 41:20 42:1 liability 32:22 34:11 lieu 9:8 68:11 life 81:13 lifter 57:12 59:23 lifters 59:20,24 60:1 light 18:12 24:5 lighter 52:10 lightweight 36:14 likelihood 63:18 limit 23:7 83:18 limitations 63:20 limited 27:1 53:18 limiting 23:4 28:16 79:11 line 6:25 7:3 18:2 23:16 26:22 28:25 30:10 52:5,6 53:17 54:4,13 62:10 77:17 88:13 liner 1:4 4:18 9:2,6,7,8,22,25 10:2,7,10,14 11:4,6 12:15 12:16 13:16 14:21,22,23 15:3,3,11,11 15:12,15,18,23 16:6,7,11,12 17:1,23,23 18:11 19:11,11 20:9,10 21:10 21:16,17 22:10 22:21,22 23:18 23:20 24:7,8 26:12,13,15 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 9 32:23,24 33:6 33:7,9 34:1,2,8 34:15,18,24 36:4,7,8 37:22 38:5 39:2,18 40:14,14,14,22 41:2 44:7,21 45:1,19,22,23 46:2,6,8,21,25 47:3,16,20 48:5 51:8,12 57:15 58:16 59:6 60:13 67:2,9,16 68:1 69:22 70:8,15 70:19,23 71:7 71:9,10,11,15 71:15,21,24 72:6,10,10,11 72:20 73:3,4,5 73:8,10 77:13 78:1,23,23 79:14,14,16,16 80:8 81:2 82:19 84:14 86:15 liner's 15:17 26:6 47:25 liners 11:12 12:8 18:5 23:14 32:1 45:15 47:15 52:10 58:11 61:13 88:5 list 8:20 65:16 listed 40:1 64:9 listening 41:5 listserv 4:9 little 8:6 9:23,24 12:1 14:14 22:2 25:25 26:3 27:9 32:8 34:23 41:14 49:17 60:17 63:14 70:9 72:16 74:19 86:23 LLC 3:7 4:14 location 3:14 37:8 logging 26:7 long 10:2,10 18:7 44:4 73:21 74:22 75:5 longer 23:9 look 14:9 19:10 39:21 67:7 68:1,22 69:1 85:24 looked 26:4 42:18 43:16 68:6,23 82:7 looking 52:9 66:2 85:22 86:13 loops 77:9 lose 50:24 59:7 lost 42:16 lot 8:23,23 11:4 12:7 19:23 32:6,9 38:2,22 42:16 43:2 53:19 57:10 60:2 63:17 71:23 72:16 82:10 Louisiana 6:13 6:14 low 13:17 15:6,6 15:9 30:11 70:12 88:2 lower 15:5 16:4 16:5 55:5 58:20 lubricator 76:22 79:10 M Macondo 27:19 41:17,25 Madame 31:14 75:21 83:25 making 14:3 34:8 60:14 managed 17:8 management 17:25 26:21 32:18 67:21 manager 5:24 8:6 managers 67:22 managing 5:17 mandate 34:15 41:19 manifold 53:10 54:13 March 3:7 4:11 4:13 married 70:2 Martin 6:7 8:11 8:13 63:3,7 Martin's 67:4 master 13:10 material 82:15 matrix 3:25 4:3 14:19 67:5 matter 1:2 4:12 20:24 36:22 55:24 87:4 mature 82:11 McKEEVER 87:11,14,15,17 88:10 McLaughlin 2:3 5:1,11,14,14 8:1,5,5 9:18,22 10:15,17,24 11:18,20,22,25 13:21 14:9,14 17:10,13,16,19 19:2,7,20 20:25 21:4,25 22:2,4,7,9,15 22:18,20 24:18 25:6,22 27:16 27:25 28:2,5,8 29:25 31:18 33:14,22,24 34:14 35:18 36:1,23 37:2,5 37:16,20 38:11 38:17,21 39:6 39:9,11,23 40:6,10,18 41:8,11 42:16 42:21 43:4,13 43:15 45:6,8 45:17,24 46:3 46:5,8,11 59:4 62:14,15,21 66:24,24 68:21 69:1,6,8,19,21 69:24 70:14,21 71:3,6,17,20 72:5,15,22 73:1,7,13,17 73:19 74:23,23 75:6,9,12 81:8 81:8,15,20 82:3 83:14,14 86:2,2,13 McNamara 73:1 mean 22:11 35:16 38:6,12 39:2,18 40:18 54:23 56:6 62:2 71:14 72:11 means 71:22 79:16 measure 13:25 mechanical 5:15 meeting 74:15 meetings 63:16 member 87:2,7 87:15 memory 19:20 mentioned 9:19 39:5 48:18 87:3 88:6 mentions 69:4 message 3:22 messing 31:6 method 8:25 20:23 44:25 45:14 54:18 67:25 methodology 63:15 methods 8:24 9:2 48:9 82:13 mic 87:18 micromotions 13:24 microphone 6:3 7:21 30:8 76:20 77:18 79:3 87:12,18 87:21,22,22,23 87:25 88:1,3,4 88:5,8 Microsoft 3:13 3:22 mid 10:25 middle 24:13 77:16 migrate 12:20 migration 12:19 Milne 7:4 mind 88:1 mindful 3:17 mine 8:8 minimize 72:5 minimizes 71:3 minute 14:16 74:3 minutes 8:13,13 8:14 24:2 36:17 60:19 66:1 missed 86:19 mitigates 24:5 mitigations 69:17 mix 59:12 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 10 monitor 15:2,16 59:3 monitored 15:19 56:11 morning 3:3 6:7 move 11:3,7 18:17 25:7 30:7 62:15 79:14 moves 12:23 moving 79:16 MT 58:14 76:4 MTB 60:12 multiple 17:24 18:22 26:19 27:12 56:25 57:25 Muscle 19:20 muted 3:18 N N 3:1 Nabors 30:22 53:7 85:10 Nabors/Hilcorp 85:9 name 6:7 7:24 74:20 87:9 name's 6:21 necessary 4:23 44:23 need 1:5 4:19 20:1 25:12 33:15 35:10,11 35:11,11 40:22 41:25 48:8 55:2 57:3 72:1 84:23 needed 17:8 24:4 25:18 negative 65:18 66:4 never 35:12 72:19 new 71:1 News 4:11 nice 25:13 noise 3:17 nonstandard 29:8 normal 38:1 77:12,22 North 13:14,15 44:13 45:9 87:24 notice 4:6,10 46:24 Notices 4:8 NOV 27:5,7 48:20 NOV's 48:23 NPD 52:5 nuances 26:3 number 1:6 3:6 7:21 17:21 22:20 25:22 28:10 44:11 54:16,17 59:13 74:5 85:21 numbered 89:3 numerous 18:21 NXE 81:25 82:12 O O 3:1 o'clock 1:9 Oath 5:5 objective 63:11 observed 15:1 obtain 4:3 occasions 53:19 OD 62:8,9 72:10 offer 87:2 offers 67:16 offset 66:5 oh 21:11 39:9 49:22 68:21 78:16 82:6 oil 1:1 3:8,14 6:8 6:14 12:15 55:5 71:23 okay 6:5 7:19 10:12,16,18 11:21,25 14:13 17:9,10,12,15 17:18 20:19 21:19 22:1,13 22:17,19 25:5 28:1,4,7 30:23 31:13,16 32:15 33:19,23 34:19 35:21 36:3,19 37:4,13 39:4 40:17 41:3 42:12,20 43:12 43:14 45:21,25 46:4,17 49:2,8 49:22 50:3,7 50:14,21 51:1 51:2,7 53:22 53:23,25 54:24 55:12,13 56:18 57:9,21 58:5 61:6,21 62:7 62:11 63:1 66:15,23 68:25 69:3,7,20,23 70:13 71:5,13 71:19 72:14 73:18,20 74:6 74:10 75:8,11 75:19 78:2,11 78:15,19 79:22 81:3,7,14,19 81:24 82:20 83:8,10,13,21 84:5,9 85:5,10 85:11,15 86:18 86:21 87:16 88:9 once 31:11 43:4 47:16 53:13 59:2,2 76:21 one's 37:3,5 ones 68:3,3 online 4:8 42:17 87:5 open 9:21 10:3 10:10,13 37:23 51:10,10,12 53:25 54:3 55:14 57:12 58:15 72:15 76:10,19,21 77:9 opened 49:14 77:11 opening 2:2 48:6 55:14 operate 12:13 33:12,13,15 45:10 operating 44:12 operation 7:3 8:10 11:8 13:12 17:24 18:23 23:3,3 24:12 26:19 29:25 45:5,6 45:17 46:1 67:15 70:3 82:11 operational 52:6 64:11 operationally 28:13 operations 1:3 5:16 6:16 7:4 8:18 9:20 10:9 27:13 28:16 29:15 44:10,11 44:14 62:25 68:11 70:2,4 operator 41:15 41:19,23 42:6 operator's 41:19 85:14 operators 11:13 15:20 44:13 82:8 opinion 18:19 64:3 66:3,16 66:16 opportunity 32:14 87:2 ops 6:24 49:1 option 13:3 23:4 23:6 27:15,15 28:17,19 35:6 38:16 40:12 43:22 51:19 52:4 54:15 56:3,5 59:5 62:17,19 66:4 85:16,17 options 22:12 36:25 63:25 66:9,12,12,13 79:21,23 order 3:4 74:15 orders 47:13 63:22 orientation 8:7 originally 82:5 OTH-25-014 1:6 3:6 89:5 outside 16:8 75:23 overall 23:2 28:15 overbalance 23:24 29:4 overlooked 65:12 P P 3:1 p.m 88:16 pack 27:18 packer 71:9 packs 31:11 pages 89:3 paid 60:7 paper 70:4 paraphrasing 44:3 parent 70:25 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 11 part 9:11 10:8 10:21 11:8 15:21 34:9 37:25 39:25,25 40:1,1,8,8,9,10 62:10 68:19 particular 41:22 partly 41:17 party 70:12 pass 8:10 46:11 71:21 path 51:8 patience 74:19 peer 5:21 people 19:22,23 19:25 20:1 27:12 36:2,16 37:7,8 43:5 57:3 68:2 84:23 percent 24:23 25:20 68:5 70:5,5,7 71:8 perf 16:5,7 20:16 36:5 72:21 perfect 69:14 perforating 9:3 20:9,11,14 26:7 37:22 44:15,16 perform 82:23 82:24 performance 82:1 performed 5:19 5:21 Perl 2:4 6:21,21 30:4,4,9,17,21 30:24 31:11,14 46:13,17,17 48:14,19 49:5 49:12,16,24 50:4,8,13,18 50:22 51:2 53:6,12,23 55:11,23 56:19 57:6,10,22 58:4,8 60:23 61:5,7 62:5,8 62:12 75:19 78:3,7,9,12,14 78:18,20,23 79:11,23 80:2 80:4,11,19,22 81:5 82:23,23 83:5,9,11,25 83:25 84:4,6,8 84:13,13 85:1 85:6,9,20 permeability 65:23 permits 75:2 person 3:13,14 21:22 35:16,18 petroleum 6:12 ph 8:17 51:18 60:17 philosophy 63:11 physically 75:24 79:7,17 pick 20:12 47:17 47:20,22 51:21 57:20 picking 60:15 68:3 84:15 picks 44:15 picture 17:21 26:4 piece 8:9,10 13:13 14:1 17:2 27:5 29:8 pieces 16:12 pin 58:14 76:6 pinhole 25:12 pins 60:9 pipe 1:4,5 4:17 4:18 5:18 8:17 8:21 10:3 11:4 12:9,17 16:18 16:18,19 17:7 18:12,13,15,23 19:8,14,16 20:5,7,19 22:24,25 23:1 23:10,15 24:5 24:6,7,13 25:12,14 26:9 26:11,11,23 27:13 28:21 29:15 37:7,12 40:5 47:25 48:4,6 52:19 54:2,11,24 55:3,18,18 58:11,20 61:7 63:23 64:1 65:5,7,8,15,16 68:11,12,13 69:16 76:1,17 77:2,4,10,11 77:24,25 78:6 78:25 80:5,9 80:15 82:16,17 82:21 83:1,22 84:19 85:3 pipes 16:22 18:17,21 30:13 37:7 47:24 59:24 76:14,15 piping 53:14 77:8 pit 51:9 pits 35:20 PIW 53:25 place 12:24 17:20 21:3,5,7 21:22 22:24 35:17 37:12 48:7 52:15 58:23 67:23 70:12 85:25 placed 40:25 plan 40:8,11 45:3 planned 8:14 planning 8:9 plans 75:1 plate 73:3,9 75:24 platforms 5:21 play 70:23 71:2 playing 71:8 please 3:16,20 5:3,12 6:6 7:20 7:23,24 9:17 17:6 30:3,8 45:4 74:1 75:14 82:2,20 87:9 plenty 54:5 point 7:4 16:24 18:18,24 21:8 25:7 27:13 28:9 31:19 34:17 36:25 41:13 42:25 43:15 48:10 49:19 54:3,5 54:11 62:16 67:18 76:11 77:20 79:6 85:1 pointing 31:21 poor 32:18 34:25 43:22 pop 77:21 popularity 11:1 PORTION 88:17 position 28:20 33:12 52:23 54:1 64:16 possibility 51:17 possible 24:16 24:19 60:2 65:16 88:2 possibly 19:18 58:24 post 27:19 56:24 posted 48:25 potential 64:13 67:16 pound 47:5,6 50:8 pounds 29:21 77:1 power 31:10 Powerpoint 51:3 pract 44:17 practice 11:10 24:12 29:12 44:10,17 82:5 82:8 precarious 52:23 precharge 50:18 preface 35:8 57:10 prefer 9:13 53:4 preferable 9:1 66:4 preferred 19:6 19:13 22:23 33:5 67:24,25 prep 57:18 preparation 4:1 prepared 4:24 preparing 3:25 prepped 57:14 59:20 present 13:8 31:21 32:19 38:3 39:12,14 40:11 41:1 presentation 4:25 7:16 12:22 39:5 presented 7:11 66:8 presenting 5:9 pressure 15:9 17:9,16 23:23 29:3 31:10,25 47:2,3,6,10 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 12 49:9,11,19 52:6,8,14 55:21 59:10,11 64:14 70:23 71:7,15 76:9 76:12,12,21 77:6,6,10 88:2 pressure's 47:1 pressures 49:6 50:6 pretty 42:24 43:2,10 60:12 65:16 74:24 78:20 prevent 24:6 65:4 preventer 1:4 4:16 16:6,17 23:13 28:24 44:22 68:12 preventers 23:12 23:13 28:22 63:13 81:10 prevention 13:7 14:1 previous 11:13 15:20 41:14,18 41:19 42:6 48:17 82:8 previously 8:2 46:14 63:4 81:21 primary 59:14 62:19,25 prior 30:5 59:20 63:22 80:22,22 probability 13:17 14:20 15:6,10 probably 18:18 25:25 31:3 56:15 70:19,21 problem 43:17 problems 5:17 25:3 39:16 proceduralize 31:23 procedure 20:17 24:14 28:13 29:13,16 31:20 34:9,10,12,14 38:1 40:25 61:1,23 84:22 85:8,14 procedures 5:20 18:20,23 24:11 24:13 27:11,12 29:14 31:20 34:2 39:3 63:21 84:12 proceedings 89:4 process 64:25 65:14 production 6:16 6:16 70:25 71:22 proficient 65:14 profile 12:14 program 45:11 progress 85:22 project 6:17 properly 50:16 proposed 63:25 pros 54:16 63:24 64:5,9 66:2 67:8 protection 45:2 proven 23:14 40:4 provide 18:15 23:11 28:21 63:10 87:3 provides 40:3 PSI 30:11 public 1:7 3:5 4:12,14 7:22 41:5 86:24 87:2,8,15 published 4:7,10 pull 9:20 47:22 61:11 77:3,21 pulled 15:18 pulling 13:23 14:21,21 63:22 72:7,7 pump 55:21 71:6 76:8 77:16 purpose 41:22 pushers 19:24 62:8 pushing 52:11 52:12 put 10:6 21:12 21:22 24:17 34:19 37:18 52:14,22 53:3 53:13 57:2 58:19,23 61:12 61:16 77:22 85:25 87:8 puts 28:19 48:2 67:5 putting 53:14 PVT 51:9 Q quantity's 65:22 quarter 9:6,10 25:24 26:8,10 26:14 27:8 30:10 31:24 32:3 59:22 61:12 80:23 question 19:1 25:7 29:18 33:20 48:13 52:24 54:24 61:22 68:15 74:19 80:12 85:11 86:10 88:1,4 questioned 68:7 questioning 25:8 questions 4:20 4:23 7:17 9:17 32:6,15 74:17 86:19 87:23 quick 14:9 25:25 29:18 39:22 48:13 76:24 quicker 81:18 quickly 64:6,8 66:20 quite 12:10 36:16,17 42:1 R R 3:1 rack 52:19 61:17 radical 31:22 raise 5:3 ram 18:8,9,11 19:4,5,5,11 22:10 23:13 25:11 27:2 28:15 31:9 32:19 35:4,5 39:14,14,16 40:14,15,15,20 40:23 41:2,7 43:16 48:1 49:9 53:1 65:8 67:3,16 68:1 68:12,20 77:10 83:16 86:15,16 ram's 39:11 rams 1:4,5 4:17 4:19 9:7,7,9,11 9:12,20 13:8 14:23 16:11,12 16:13,17,18,19 16:19,22,24,25 17:7,23,24 18:22 19:8,11 19:11,13,14,16 20:7 21:6,10 21:16,17 22:21 22:22,24,25 23:10,14,20 24:4,6,8,25 25:2,9,14,16 25:16,24 26:10 26:11,11,18,20 27:20 28:11,21 28:23,24 29:3 29:6,19,20 32:16,20,23,24 33:6,7,9,16,18 34:1,2,8,15,18 34:24 36:8 37:23 38:10,12 38:14 39:25 40:4,14,22 41:15,18,21,21 41:24 42:6 44:7 45:1 46:21,24,25 47:3,24 48:4 49:18 51:6 54:2,24 55:18 55:19 58:20 64:1,2 65:3 67:9 69:16 77:4,11 82:1,1 82:22 83:1,4 83:22,23 84:1 RC 30:5 reached 3:21 read 8:16,22 26:5 27:17 47:13 48:16 reading 7:22 reads 4:16 ready 54:7,25 reaffirmed 82:6 real 39:22 48:13 69:14 really 12:4 32:11 32:18 33:3 39:17 52:20 56:2 59:8,9,18 59:18 60:3 64:7 67:4 70:2 81:16 realm 56:4 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 13 reason 38:25 57:4 59:5 reasons 27:23 29:2 79:18 81:16 recall 75:5 received 3:7 4:12 42:5 87:4 recess 4:21 73:25 74:3 recognized 5:10 7:14 recollection 14:12 recommend 66:17 recommendati... 69:16 recommended 82:4,8 record 3:2 5:7 7:22,24 74:12 74:13 87:10 88:16 recording 3:24 89:6 red 60:7 reduced 12:18 65:3 reduces 14:5 redundancy 25:9 redundant 25:13 reference 7:21 44:11 referred 65:2 referring 45:5 46:2 reflect 5:7 regarding 3:9 63:12 regardless 36:3 65:14 regards 64:3 regs 21:12 regulation 8:16 11:5 12:1,2,3 regulations 16:21 20:13 25:17 33:15 rejustification 39:25 relative 64:20 reliable 28:13 relying 29:9 44:14 remarks 2:2 remember 7:20 56:16 remiss 34:1 remote 36:25 77:19 remove 28:18 removes 23:3 28:16 removing 28:14 29:8 Representatives 4:24 requalified 83:5 83:20 requalifies 82:21 requalifying 83:3 request 1:2 3:8 3:10 4:14,15 8:16 9:4,24 10:2,7 67:19 68:5,9 REQUESTED 88:17 requests 68:10 require 3:20 9:12 16:21 32:25 required 9:3 13:9 17:1,3 32:20,21,25 34:8 38:16 64:21 65:20,25 81:22 requirement 71:21 requirements 80:23 83:15 reservoir 6:17 23:23 29:3 resident 6:11 residual 82:17 resistance 65:6 resistant 64:13 resort 35:10 41:9 52:18 56:6 respect 64:6 86:3 respond 5:4 responded 5:8 response 21:2 34:25 responsibility 62:5 responsible 21:6 21:14 rest 51:11 retained 64:18 retest 84:8 retested 84:1,3 returns 53:12,16 77:17 reviewed 42:10 63:16 reviews 5:21 56:24 rewritten 82:6 rig 5:23 20:3,4 30:16 31:20 33:1 36:15 44:15 57:16 59:19 61:1 84:11,23 85:13 85:15 rigged 30:5 right 5:3 16:24 17:22 22:3,6 30:12,12 31:4 32:7 35:9,10 37:1,14 38:9 38:16,20,21,23 46:7 48:2,16 50:10 51:8 52:23 53:18 56:23 57:24,25 58:1,7 60:23 61:17 62:13 64:18 66:12,18 70:18,20 72:20 72:24,24,25 73:15,15 75:16 76:4 78:15 79:6 84:7 right-16:20 22:22 right-hand 47:1 47:12 rigs 12:11 13:24 19:22 43:19 50:12 risk 5:19 10:9 12:2,14 13:13 14:19 15:5,25 16:4,5 17:22 17:24 20:11 24:22 25:15 26:19 42:8,9 42:17,19 44:22 72:8 risks 26:17 rock 65:22 roles 6:15 room 18:25 37:3 43:20 87:8 rotary 5:24 10:9 11:3,7 12:4,12 13:1,5,11 36:12 44:20 62:19 69:14 70:6 Rouge 6:14 RP 12:3,13 13:5 13:9 17:3 rubber 18:14 run 8:21 9:25 10:4,10 11:3,6 11:11 15:3,15 18:22 20:7 21:18 23:18 24:9,13 26:8 27:1 28:11 29:2 33:7 37:20 38:25 39:2,13 40:19 43:8 44:3,6,13 44:21 46:5,6,8 46:9 47:23 51:22 53:24 54:7,8 57:14 62:23 63:23 67:8,15 68:13 72:19,19 73:7 73:11 75:1 77:11,12,14 78:1 81:11 84:14 86:15 running 6:25 9:22 10:1,2,8 12:8 13:16 14:2,20,21,22 15:3,5,10,18 16:5,7 17:1 20:5,8,11,16 23:22 24:22 26:13,13,14 29:12 36:3,5,7 37:7,7,10,12 37:22 38:4,5 38:18 39:17 41:1,2 45:15 45:19 51:8 54:1 57:15 58:10 59:24 67:25 69:21 70:8,15,17 72:10 73:13 77:25 82:16 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 14 runs 39:3 S S 3:1 safe 21:21 44:17 safeguard 18:15 safer 28:13 35:5 safety 8:18,25 9:4,8,13 14:22 15:11 20:6,13 21:2,9,18,22 23:2,10 24:1,6 24:11 28:12,12 28:21 29:2,10 29:12 33:5,7,9 34:10,12 35:17 35:19 36:5,6 37:9,18,21,24 38:5,25 39:13 39:18 40:2,19 41:2 44:4,6,9 44:14,16 45:1 45:14,19 46:6 46:9,20 47:17 47:18,20,21,23 48:6 51:5 53:25 54:16 56:9 57:1,5,11 57:15 58:1,2,8 58:9,12,16,18 58:19,21 59:7 59:14 60:16,22 61:10,16,18,20 61:25 62:23 63:25 65:1,8 65:18,20 66:3 66:25 67:1,8 67:15,25 68:4 68:11 69:17 72:3 75:17,19 75:20 78:3 80:8 84:15,25 85:16,18,21 86:10,15 Salena 89:2,10 Sam 6:2 Samantha 3:21 3:24 87:5 satisfied 7:10 Saudi 5:22 saying 10:7,13 27:24 33:25 34:6,7 35:8,12 36:21 37:18 39:13 40:21 42:14 58:3 79:10 85:17 says 29:20 32:22 34:23 35:15 39:24 SB 70:4 scenario 18:11 20:12,19 21:21 22:7,10 24:5 35:14,24 39:12 52:20 53:9,24 55:21 56:4,20 56:22 66:8 72:21 75:16,17 76:11 78:17 79:19 84:11,15 85:12 scenarios 14:17 16:4 35:8 48:9 51:4 58:22 75:14 Schlumberger 7:1 schools 5:16 science 6:12 screw 47:19 screwed 47:21 60:17 scrutiny 63:11 se 53:15 seal 22:11 sealed 57:3 sealing 71:15,24 72:1 Sean 5:14 8:1,5 59:4 62:15 66:10,24 74:23 81:8 83:14 86:2 Sean's 52:18 second 75:17 secondary 62:17 62:24 section 10:7 12:16 15:4 16:3 59:21 securing 18:15 see 13:11 16:2 50:23 52:16,16 54:9 62:1 67:23,24 seen 63:18 65:15 sees 62:1 sell 43:11 send 3:22 sending 35:16 senior 6:22 sent 4:9 September 29:21 service 7:6 11:2 76:8 set 14:18 19:15 21:6 27:6 44:1 51:6 55:5 64:1 70:11 75:23 78:25 79:12 sets 25:8,13,15 25:16 27:7,7 55:18 setting 47:15 62:22 84:24 setup 16:20 seven 81:9 seven-eights 9:6 26:13 32:2 severity 15:7 shear 13:8 16:17 16:25 23:14,15 24:4 28:24 29:6,19,22 31:3,9,10,19 31:23 38:9,11 38:12,14,22 39:1,11,14,14 39:16,25 40:4 40:4,15,20,23 41:7 44:24 46:23 47:10 48:15,23 49:9 50:2,6 57:7,9 63:19 77:7 81:25 82:1,13 85:3 sheared 29:23 30:10 31:24 shearing 30:12 48:22 82:12,16 82:17,19 shears 25:1 38:9 47:8,9 49:17 49:20,25 50:5 56:5 shop 30:5,11 short 10:7 12:16 15:4 26:24 42:5 59:21 73:25 shorter 81:13 show 19:9 74:2 shows 50:4 shut 19:11 22:10 23:5 36:8 51:14 59:6,13 64:21 65:11 79:2,4 shut-24:10 31:19 44:24 58:22 85:24 shut-in 8:19,24 9:13 18:3,19 18:23 19:8 20:17,21 21:9 21:9,13 23:7 23:17 24:13,14 26:25 27:10,12 27:14,15 28:13 28:19,23 29:13 29:14,16 31:23 33:1,4,6,8,9 34:3 37:23,25 37:25 38:1,7 38:24 39:3 41:7 45:3,14 45:20 46:21 51:5 54:18 55:12,17 56:10 59:2,15 64:7 64:15 65:9,14 67:1,2,25 75:21 80:7 84:16,20 85:3 86:14 shuts 79:3 shutting 9:1,4 17:23 23:20 26:18 43:23 44:7,25 45:1 51:6 64:8 66:19 81:12 side 14:20 16:15 16:21,24 22:23 26:3 47:1 67:14 77:8 sides 40:16 significant 13:16 14:8 15:2,25 25:3 36:18,18 44:10,18,20 45:9 69:5,9,25 significantly 33:2 similar 15:10 30:15 simultaneous 30:21,24 single 24:11,14 27:6 29:16 45:13 65:14 sit 14:20 48:7 54:19 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 15 site 80:25 sits 57:18 70:8 situation 14:23 18:1,12 19:13 23:19 25:11 26:7,21 27:11 30:20 31:2 32:22 35:15 36:12 39:19 48:2 51:25 52:3 67:6 69:18 72:6 75:15 situations 18:10 24:15 29:17 six 17:5 42:4 53:2 sixteenth 81:9 size 1:4 4:17 18:21 23:14 26:12 58:6,10 58:18,18 59:23 60:9 61:2,10 61:10,17 64:20 64:20 65:19,24 66:5 68:13 80:15,21 81:1 81:10 sized 1:5 4:19 58:9 sizes 20:20 23:15 46:25 57:25 58:2 60:22 62:18 65:16 71:9 skate 57:23 skinny 26:24 slick 6:25 7:3 slide 8:6,15 9:15 11:24,25 14:16 16:9,9,14 17:5 17:21 18:20 19:9 21:11 22:18,20 25:22 25:23 26:11,17 27:9,18 28:10 31:11 32:7 40:2 41:13 44:2 46:18 48:13 52:25 62:15 63:7 64:9,24 66:24 68:17 slides 7:21 8:8 32:5 68:16 slight 35:20 slip 16:18,19,19 17:7 19:8,14 19:16 20:7,14 22:24,25 23:1 23:10 24:6,8 25:11 26:9,11 26:11 28:21 44:1 48:1,4 54:2,24 55:3 55:19 58:20 65:7 80:5,9 82:21 83:1,22 slips 18:14 23:20 47:16,22 48:1 51:13 54:11 55:5,6,23 58:11 75:23 76:1 77:23 78:6,24,25 79:12,15,17,25 80:2,7 84:19 Slope 13:14,15 44:13 45:9 87:25 slotted 9:2 15:10 15:11 16:6,7 20:9 36:3 37:22 45:15,19 45:22,23 46:2 70:19 73:3,9 73:11 slottted 46:5 small 56:8 58:16 64:1 72:12 80:21 smaller 10:9 61:13 81:10 smallest 80:15 80:24 smart 34:22 sold 27:6,7 solid 9:6 15:12 20:9 36:7 45:15,23 46:8 73:4,5,8 someone's 36:21 soon 52:7 Sorry 55:11 sort 10:23 83:3 sound 89:6 sounds 87:18 source 50:24,24 space 35:17 47:14 spans 11:13 speak 7:20,23 34:5 speaking 8:7 speaks 14:1 special 3:20 specializing 6:9 specific 12:10 26:18 28:9 specifically 12:4 16:10 speech 30:22,25 spend 24:20 spent 6:23 spot 57:17,22 ST 81:25 82:7 stab 20:7 35:19 36:9,16,16 37:9,23 51:14 51:22 stabbed 51:20 56:12 84:16 stabbing 36:4,6 36:10 stack 13:8 16:2 16:15 21:14 22:23 24:21 26:5 32:18,20 33:7 34:16,17 34:18 35:4,5 41:23 43:6,16 43:21 49:21 51:7,11,12 53:1,18,20,24 65:15 67:9,24 68:1 82:25 83:11,15 86:5 86:7,16,16 stack's 49:23,24 stacks 48:11 Staff 4:22 21:11 32:10 stage 14:18 stages 12:7 standard 27:4 29:12 44:9 67:1 69:13 82:4,15 83:19 standardization 8:25 standing 20:23 21:2 47:13 63:22 standpoint 71:25 start 51:9 52:7,9 52:10,11,12,14 55:10 57:14 77:14,23 started 6:24 10:22,25 11:9 53:14 56:2,14 starting 50:24 starts 29:19 state 4:7 6:13 7:23 19:3 21:15 32:22 33:11,25 74:20 87:9 stated 65:12,25 statement 14:8 stationary 76:18 statute 4:5 statutes 64:2,23 stay 37:18,20 59:25 stenciled 60:6 steps 54:6 stick 17:21 sticking 44:21 strength 31:25 stress 5:18 stretch 53:6 string 13:17 15:23 29:7,20 47:1 60:12 61:10 strings 18:6 26:23,23 32:24 strip 18:5 23:21 24:3 35:1 43:9 43:25 51:19 52:1 54:8,17 59:8 75:15 76:16,22 78:14 78:22 stripped 48:4 56:13 79:7 stripping 48:3 78:6,9 79:5,7 strips 76:17 stuck 5:17 10:3 studied 66:11 study 63:19,24 stuff 10:23 48:23 54:22 60:11 61:9,14 62:9 78:14 84:17 stump 76:23 style 78:4 subject 63:12,17 success 62:22 suggest 75:2 suitable 18:6 26:23 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 16 suits 21:12 sum 67:7 68:9 summary 66:25 superior 13:7,20 supervising 6:24 7:3 support 24:8 47:25 49:6 67:22 68:8 79:16 supported 47:25 76:1,15,15 80:6 supporting 5:21 14:7 48:5 sure 3:17 33:21 36:20 47:15 50:15 57:19 58:6 61:2 62:4 76:9 88:7 surface 15:9 35:16 84:6,14 surge 51:18 surprise 31:23 32:4 surprised 42:24 sustained 45:11 swab 12:18,19 12:19 14:5 16:3 72:8,12 swabbing 23:24 29:4 swap 16:22 20:20 25:23 32:16 61:7,8 swapped 20:19 swear 5:2 switched 61:25 swivel 76:3 sworn 8:2 46:14 63:4 system 17:9 30:15 50:11 T T 76:19 TABLE 2:1 take 4:21 14:16 15:24 21:17 25:10 32:23 35:5 51:18 52:16 53:15 65:25 73:24 74:3 79:13 taken 35:3 takes 44:4 68:20 76:14 79:20 talk 12:1 14:17 16:10 17:7,22 22:14,15 27:9 30:1 38:14,14 46:12,18 48:8 55:13 59:3 60:10 64:12,20 75:14 talked 32:8 38:11 41:14 talking 9:5 12:3 14:22 22:22 31:18 36:12,13 44:25 52:19 56:12 62:18 67:5,6 68:23 70:17 79:4 80:22 82:18 84:10 talks 68:18 81:25 82:12,13 tape 62:9 taped 62:9 tapered 80:5 taste 8:17 TD 14:24 team 20:1 63:15 Teams 3:14,16 3:22 technical 5:16 tell 29:22 telling 21:15 33:16 40:22 tells 50:22 temporarily 27:20 tendency 12:18 14:5 tertiary 48:9 84:17 test 13:2 29:22 29:22,24 30:12 30:12,22 48:17 49:3,4,5,6,13 50:15,18,20,20 50:23,25 70:23 71:7,22 76:9 76:12,24,25 77:1 80:14,17 80:24 81:4,11 81:16,22 83:6 83:7 tested 29:21 71:14,16 76:21 81:1 83:11 84:4 testified 8:3 46:15 63:5 testify 87:3,8 testifying 3:18 7:20 testimony 2:3,4 2:5 4:21 63:11 66:14 68:14 testing 48:21 80:13 81:13 tests 47:4,5 48:20 82:1,21 82:24,25 83:2 thank 6:1,20 7:18 9:23 10:15 43:14 66:23 68:15 73:23 75:13 80:10 84:9 88:9,10 thanks 11:24 22:19 30:8 31:17 55:15 62:13 63:1 74:11,18 them's 56:25 thing 20:4,10 39:22 49:7 51:23 52:2 55:8 59:18 62:14 75:22 things 10:3 13:6 14:20 36:15 38:23 43:10 54:20,23 60:3 82:10,10 think 10:1 14:19 21:4,6,13,15 21:18 32:5,17 33:3,16,17 34:1 36:14 38:14 41:22 44:5,7 51:5 66:12,20 73:10 81:23 82:5,15 85:11 86:3,6 thinking 56:23 61:22 third 18:18 43:15 60:24,25 thorough 42:25 thought 36:24 42:2,12 64:25 thousand 11:16 11:17 13:14 20:18 thread 47:19 60:9,12,13 61:13 threads 57:16 60:14 three 5:11 8:7 9:5,5 14:16 16:11,18,22,23 17:7,11 19:12 22:24 24:2 26:9 27:7,7 32:2 36:17 49:18 53:3 56:11 59:21,22 60:19,19 66:1 66:1,12 73:13 80:16 88:5 three-16:17 19:15 25:1,8 25:14 61:8,19 three-eights 16:11,19,23 19:8,12,14 22:25 23:1 26:2,15 32:1,2 36:14 58:11,13 61:14,18 80:25 throw 23:20 Thursday 3:5 tight 47:20 time 7:23 12:6 15:2,16 20:4 20:10 24:2,20 24:24 25:20 36:18 42:5 44:4,15 46:11 48:10,17 49:19 54:3,6,9,12 56:16 57:3,17 57:19 59:1 64:21 65:19,25 68:19 73:21 77:21 79:6 83:6,7,12,18 85:1 timely 86:14 times 12:22 54:5 title 7:22,24 16:9 25:23 68:17 TIW 8:18 36:9 54:3 58:14 76:1,5,7,10,19 today 63:14 Today's 3:12 tolerance 12:21 13:25 24:1 29:6 44:19 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 17 66:5 70:11 tolerances 13:1 tool 15:18,23 19:24 42:18 72:10 tools 5:19 15:19 top 16:16 20:14 25:1 53:3,15 53:17 55:6 58:12,15 71:7 71:9,12,15,21 71:25 72:11 75:25 76:5,7 76:18,23 77:22 topics 64:12 65:1 66:22 torqued 47:22 total 12:16 72:15 touched 18:20 tough 43:13 tower 20:3 traction 76:13 77:2 traditional 53:14 traditionally 54:12 train 76:13 training 6:11 64:17 transcribed 89:5 Transcriber 89:10 TRANSCRIB... 89:1 transcript 4:1,2 89:4 transferred 7:5 transitioned 7:3 tree 13:9 43:19 tree's 51:11 trees 53:19 trend 50:23 Trevor's 48:21 tried 31:4 Trinidad 5:22 trip 14:4 23:25 29:5 84:6 tripping 12:17 24:23 trouble 67:12 true 41:17 89:3 try 44:6 57:18 81:11 trying 40:20 43:8 56:22 60:1 84:16 tubing 1:3,4 3:9 4:18 5:16,17 5:18,23,23 8:17 9:25 10:25 11:2,6 12:6,10,11 13:15 14:11 15:24 16:1 17:2 24:20,22 24:24,25 25:2 25:11 35:3 36:11 38:18 43:18 44:12,18 45:10,11 55:5 63:12 66:6 68:10 69:15 70:1,7,9 76:2,8 82:4,15 tubing's 76:15 tubulars 58:13 turn 47:17 54:1 54:10 55:7 76:7 77:24 79:2 turns 58:16 two 9:6,15 11:25 16:10,12,17,19 16:23 19:7,7 19:12,14,15,22 22:24 23:1,12 25:1,8,8,14,15 25:16 26:2,13 26:15 28:23 31:25 32:1,1,2 32:5 33:8 36:13 41:13 43:18 47:2 52:18 53:3 55:18 58:11,12 58:16,17 60:22 60:23,24 61:8 61:8,8,12,14 61:18,19 66:22 80:25,25 88:4 type 60:7 typical 39:2 typically 13:4,10 15:17 16:2 18:7 62:19 72:20 83:18 U Uh-huh 19:2 39:6,23 40:6 ultimate 41:6 ultimately 42:10 un-deploying 17:17 unable 18:2,4 26:21 underbalance 65:24 understand 17:8 27:19 33:21 36:20 60:6 understanding 21:5 33:11,20 33:22 understood 42:6 43:5,6,7 undertook 64:25 UNISON 5:6 unit 1:3 11:2,3 University 6:13 unlimited 12:20 44:19 updates 69:24 upgrade 53:8 upgraded 53:13 upper 47:24,25 54:2 58:20 76:1 upward 65:4 use 8:18 9:3,8,13 17:13 20:22,23 21:1,5,7,14,16 27:20 31:3,7 31:25 32:16,19 32:21,24 33:1 33:5,18 34:3 34:20,22 35:4 35:12 50:1,17 51:3,4 57:17 58:21 59:23,24 60:7 68:11 79:20 82:13 84:1 85:18 uses 80:15 usually 10:4,8 15:4,14 23:21 47:5 58:13 59:21,22 60:8 60:18 61:11,14 77:1 80:24 utility 71:25 utilize 24:6 61:16 utilizing 28:20 40:2 45:19 47:8 V valve 8:18 13:10 36:9 37:24 48:6 valves 57:12 variable 9:7,20 16:23 19:13 51:6 64:1 65:3 variables 51:15 51:24 52:11,16 52:21 59:5,12 79:4,20 81:1 variety 6:15 19:22 various 29:15 VBR 18:15 24:17 25:10 65:21 85:17,19 86:11 VBR's 21:4 VBRs 18:16 20:24 21:3 23:4,5 65:4,6,8 75:17 78:22 verbatim 32:12 verify 47:14 versa 55:4 58:17 59:1 versatility 28:14 versus 62:2 63:25 vertical 10:8 15:4 vice 55:4 58:17 59:1 viscosity 65:23 visualization 51:4 volume 15:8 44:18 47:9 49:10,17 volumetric 50:1 volumetrics 47:9 W waiver 1:3 3:10 4:15 8:16 10:6 67:19 68:9,10 88:7 Walters 2:5 6:7 6:8 63:3,7,7 66:7,10,18 want 8:24 19:21 19:21 21:13 22:13 23:4,5 25:1 30:1 33:20 35:24 36:20 38:1 39:19 41:21 51:16 52:21 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 18 54:19 67:23,24 71:23 73:24 81:16 85:13 wanted 14:16,18 26:2 32:13 39:7 42:2 53:8 wanting 53:24 wants 33:11 wasn't 32:4 42:2 43:11 69:2 way 4:13 20:20 21:13,14 23:7 38:2 41:25 48:3 52:19 53:4 56:3 60:3 79:17 80:7 82:23,24 87:19 ways 38:7 84:20 we'll 8:11 16:12 16:13 48:11 51:3 58:17 60:24 61:11 63:8 74:2,7,14 84:8,14 we're 8:7 9:4,25 11:11 12:3 13:2,23 14:2 14:22 15:10 16:9 17:22 18:4 20:11 21:7 22:21 23:15,17,17 24:2,22,23 25:23 26:12,13 26:14 31:18,21 32:7,21 33:3,3 33:4,5,6 34:19 34:20,22 35:1 35:1 36:3,12 36:13 37:9,10 37:12 38:18 39:12 40:11,20 40:21 41:1,1 41:13 43:15 46:18 47:12,15 48:7 51:16,25 53:18,23 55:12 57:13,16 58:6 58:10,15,24,25 59:11,24 61:17 62:22 67:5,6 68:23 70:3,11 71:8,10,20 74:19 77:15,15 78:9 79:4 81:2 82:11,18 we've 14:25 15:1 15:14,15,16,18 15:19 35:3 43:16 46:22 47:7 48:24 51:12 56:16 57:11 58:11,13 58:22 62:21 63:9,13 64:9 67:12 75:22 76:24 77:7,8 82:7 84:19,19 website 4:8,8 weekly 64:17 82:25 83:2 weigh 63:24 weight 65:5 77:4 78:25 79:13 weight's 80:6,9 well's 59:9 wellbore 12:24 65:5 70:12 71:25 wellhead 43:18 47:2 50:9 63:19 wellheads 53:20 wells 7:2 12:18 13:14,15 45:12 45:19 71:8 87:24,25 wellsite 7:2,6 61:4 went 7:1 30:11 42:8 43:5 48:19 56:13 weren't 81:22 West 3:15 whichever 80:25 wide 6:15 Wilson 1:11 2:2 3:3,11 5:2,7,12 6:1,5,20 7:9,13 7:19 13:19 19:17 34:5 41:4,10 69:10 73:24 74:2,6,9 74:14 86:20,22 87:1,7 88:10 88:13 wisely 29:10 wished 5:9 witness 6:2 8:2 46:14 63:4 witnesses 5:3,8 wondered 69:5 wondering 27:22 word 73:21 words 31:6 work 7:5,5 13:17 15:23 20:1 31:8 32:24 36:10 37:24 43:17 46:25 60:12 61:10 62:18 worked 56:15 working 36:2 68:3 workover 5:23 world 70:5 worried 54:10 60:10 wouldn't 35:24 40:8,10,24 43:17 written 12:5 75:5,6 82:5 87:4 wrong 57:2 wrote 70:4 X Y yeah 10:24 11:16,18,19,23 22:8,12 28:1 30:2 34:5 37:16 39:9,10 39:11 40:17,17 41:9,10,11 45:7 48:14 49:12,15 51:2 55:11 61:5 62:12 69:12 70:22 73:19 74:9 78:12,13 78:13,18 80:11 83:9,11 87:1,9 year 69:4 years 5:22 6:11 6:14,22 7:1 12:9 27:6 32:10 44:14 45:18 67:20 82:7 83:15,19 Z zero 13:16 14:8 47:2 zone 71:20 0 02 89:3 03 2:2 08 2:3 1 1 54:16,17 59:13 70:7 85:21 1,800 52:9 10 6:23 26:11 27:6 10:00 1:9 3:2,4 11 26:17 11:27 74:2,12 11:50 74:7,10 11:54 74:13,14 119 30:5 12 28:10 12,5 52:10 12:16 88:14,16 13 8:22 32:7 41:13 14 8:8 44:2 82:6 15 8:13,14 46:18 16 81:25 82:3,7 18 63:8 19 64:9 1997 6:25 12:5 69:14 1st 4:10 2 2,100 47:5 2,200 47:6 20 1:3 3:10 4:5 4:15 6:11 8:13 12:9 64:24 74:3 2000s 73:2 2001 14:11 2006 7:2 2008 45:11 2009 82:6 2012 7:5 2014 7:6 2020 7:8 42:8 2021 82:6 2023 56:8 2024 29:21 48:16 2025 1:9 3:5,7 4:10,11,13 21 8:8 66:24 21st 3:7 4:13 22 74:4 25.036(c)(2)(A... 1:3 3:11 AOGCC 5/29/2025 ITMO: HILCORP ALASKAS REQUEST FOR WAIVER Docket No. OTH-25-014 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 19 25.36(c)(2)(A)... 4:16 25.540 4:5 250 30:11 26 4:11 5:22 28 6:22 29 1:9 82:5 29th 3:5 3 3 72:11,11 30 8:12 333 3:15 4 4,000 11:20 18:7 74:22 75:1,4 77:1 40 6:14 44.62 4:5 46 2:4 5 5,000 29:21 30:11 47:2 50:8 500 18:7 53 12:4,13 13:5 13:9 17:3 69:22 70:2,6 70:10,14 6 6 17:21 63 2:5 7 7 22:20 75 71:7 793-1223 3:22 7th 3:15 8 8,800 52:8 800 72:11 89 89:3 9 9 72:11 907-3:21 90s 10:25 15:22 74:25 95 11:8 24:23 25:20 97 11:8,11 98 70:5 99 70:5 Waiver for CTD Liner and CS Hydril Rams 20 AAC 25.036 (e)(2)(A)(iv) – “at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars”. Waiver Request: For CASED hole Coil Tubing Drilling jointed pipe operations to use a safety joint, in lieu of having a preventor equipped with a pipe ram that fits the size of jointed pipe being run. Jointed Pipe Run in CTD Wells: •BHA’s - rams not needed per regulation •3-1/2” Solid Liner -changing out to 2-3/8”x3-1/2” variable bore rams (VBRs) •3-1/4” Solid Liner -changing out to 2-3/8”x3-1/2” variable bore rams (VBRs) •2-7/8” Solid Liner -changing out to 2-3/8”x3-1/2” variable bore rams (VBRs) •2-3/8” Solid Liner - using 2-3/8” pipe/slip pressure deployment rams (already installed for drilling) •3-1/2” Slotted Liner - rams not needed per regulation •3-1/4” Slotted Liner - rams not needed per regulation •2-7/8” Slotted Liner - rams not needed per regulation •2-3/8” Slotted Liner - rams not needed per regulation •1-1/4” CS Hydril - Historically, considered part of the BHA (changing interpretation will require rams) •1” CS Hydril - Historically, considered part of the BHA (changing interpretation will require rams) •2” Perforation Guns - rams not needed per regulation •1.56” Perforation Guns - rams not needed per regulation 1 Regulations and Risk •The current regulations are based on API RP 53 (Rotary Drilling 1997). CTD has a different risk profile. –The liner is deployed in cased hole. –Short liner section compared to total depth –Continuous pipe when tripping in open hole. Reduced swab tendency –The wells are horizontal (reduced swab migration) –Unlimited kick tolerance –Superior kick prevention, kick detection, and well control –Shear rams are in the stack –There is a tree and master valve on the well •Over 1000 CTD wells drilled on the North Slope with zero significant well control events from running liner or workstring. Low Probability event. 2 Kick Scenarios •Kick while running/pulling liner –A well has been drilled to TD, circulated clean, flow checked, LD BHA, and observed. –Liner is run in cased hole, vertical section, and over a short duration –Low probability and low severity event (not an intensity kick) –Similar probability to running slotted liner. If a safety joint is acceptable for slotted liner, it is acceptable for solid liner. •Kick while deploying CS Hydril –Liner is on bottom and well has been cemented, LRT tool has been pulled, LD tools and monitor the well –Historically the AOGCC, Hilcorp, and the Previous Operator considered the CS Hydril part of the BHA. CSH is a tool to allow entry into the liner. The workstring is the coiled tubing. –Low probability and low severity event (not an intensity kick) –Similar probability of running perforating guns (run below the CSH and uses a safety joint to shut in) •Both scenarios have lower risk than running perforating guns or slotted liner. 3 2-3/8” x 3-1/2” Liner Rams 4 3” Pipe/Slip for Drilling 2-3/8”x3-1/2” Rams for Running Liner Tree Swab Valve Tree Master Valve Tree Swab Valve Tree Master Valve 5 Risks when installing Liner Rams Shutting in on liner rams adds risk to the operation in multiple Well Control areas. Well Control Risk – •Closing the VBRs hinders the management of a well control situations o Unable to circulate through choke or kill line (shut-in below the flow cross) o Unable to kill the well from bottom (not able to strip to bottom - VBRs are not pipe/slip rams) o CTD liners are not suitable killstrings (bottom only ~500-4,000’ from surface) o Only one ram available for well control (no backup ram in escalating well control situations) •Pipe Light Scenario – o CTD liners are light in weight o Possibility of pipe jacking out of the VBRs and well (not pipe/slip rams) o A VBR does not provide a pipe securing safeguard o Damage to VBR rams if/when pipe moves do to jacking •Inconsistent Shut-in Procedures – o Numerous size and make of CTD jointed pipe (creates multiple shut-in procedures) •slotted liner (2-3/8”, 2-7/8”, 3-1/4”, 3-1/2”) •solid liner (2-3/8”, 2-7/8”, 3-1/4”, 3-1/2”) •CS Hydril jointed pipe (1” and 1-1/4”) •perf guns (1.56” and 2”) •BHAs o Multiple shut-in procedures for jointed pipe operations o Creates a decision point for the crews (introducing room for error) Personal Risk when changing rams – •Added personal risk for crew members (working at heights in small cellar) •Dropped Objects (around a tree that is open to the formation) Tree Swab Valve Tree Master Valve 6 Justification to not install Liner rams Operationally safer, more reliable shut-in procedure, and greater well control versatility. Well Control Risk – •Using a safety joint allows for better overall well control operations o Removes the operationally limiting VBRs as an option •Remove from the BOP so they are NOT an option o Utilizing a Safety Joint and pipe/slip rams provides greater well control ability •Four out of five preventors available •Two rams to shut in on pipe (one above flow cross and one below) •Annular Preventor (closes on all sizes of liner) •Blind/Shear Rams (proven to shear and close in on all CTD jointed pipe) •Able to circulate down the choke or kill line (shut-in above the flow cross) •Able to connect the coil to the liner and run to bottom and kill the well. o Known reservoir pressure (TD has been reached - extended flow checks) o Overbalanced fluid confirmed (extended flow checks) o No swabbing on final trip out of hole (continuous circulation and MPD with CTD) – above and beyond regulations o Infinite kick tolerance (safety joint deployment time averages 3 minutes) – above and beyond rotary drilling o Strip to Bottom to kill well (utilize Annular Preventor and pipe/slip rams to make up to coil string) o Blind/Shear rams or dropping string (would allow a bullhead kill if needed) •Pipe Light Scenario – o Safety joint will utilize pipe/slip rams (prevent liner from jacking under pressure) o Pipe/slip rams support the liner (allows coil and injector to be made up to run to bottom) •Consistent Shut-In Procedure – o Safety Joint - Single closing practice for ALL operations o No change to shut-in procedures in the middle of a jointed pipe run o Crews drill to a single shut-in procedure for all situations (muscle memory / consistency) Personal Risk when changing rams – •Removes added personal risk for crew members (working at heights in small cellar) •Removes Dropped Objects potential (around a tree that is open to the formation)7 1” and 1-1/4” CS Hydril Rams 8 3” Rams for Drilling 1-1/4” CS Hydril Rams for Liner Cleanout/Logging/Perforating Tree Swab Valve Tree Master Valve Tree Swab Valve Tree Master Valve 9 2-3/8” Rams for Drilling 1” CS Hydril Rams for Liner Cleanout/Logging/Perforating Tree Swab Valve Tree Master Valve Tree Swab Valve Tree Master Valve 10 Risks with installing CS Hydril Rams Shutting it on CS Hydril adds risk to the operation in multiple Well Control areas. Well Control Risk – •Closing the CS Hydril Rams hinders the management of a well control situations o Unable to circulate through choke or kill line (shut-in below the flow cross) o CS Hydril jointed pipe strings are not suitable killstrings (bottom only ~500-4,000’ from surface) o Only one ram available for well control (no backup ram in escalating well control situations) •NOT an industry standard piece of Well Control equipment o NOV has the design but have not sold a single set in the last 10 years o NOV has only sold 3 sets of 1” and 3 sets of 1-1/4” in existence of the design •Inconsistent Shut-in Procedures o Numerous size and make of CTD jointed pipe (creates multiple shut-in procedures) •slotted liner (2-3/8”, 2-7/8”, 3-1/4”, 3-1/2”) •solid liner (2-3/8”, 2-7/8”, 3-1/4”, 3-1/2”) •CS Hydril jointed pipe (1” and 1-1/4”) •perf guns •BHA o Multiple shut-in procedures for jointed pipe operations o Creates a decision point for the crews (introducing room for error) Personal Risk when changing rams – •Added personal risk for crew members (working at heights in small cellar) •Dropped Objects (around a tree that is open to the formation) 11 Justification to not install CS Hydril Rams Operationally safer, more reliable shut-in procedure, and greater well control versatility. Well Control Risk – •Removing CS Hydril Rams allows for better overall well control operations o Removes the operationally limiting CS Hydril as an option •Remove from the BOP so they are NOT an option o Utilizing a Safety Joint and pipe/slip rams provides greater well control ability •Four out of five preventors available •Two rams to shut in on pipe (one above flow cross and one below) •Annular Preventor (closes on all sizes of liner) •Blind/Shear Rams (proven to shear and close in on all CTD jointed pipe) •Able to circulate down the choke or kill line (shut-in above the flow cross) •Able to connect the coil to the liner and run to bottom and kill the well. o Known reservoir pressure (TD has been reached, liner is cemented on bottom - extended flow checks) o Overbalanced fluid confirmed (extended flow checks) o No swabbing on final trip out of hole (continuous circulation and MPD with CTD) – above and beyond regulations o Infinite kick tolerance (safety joint deployment time averages 3 minutes) – above and beyond rotary drilling o Blind/Shear rams or dropping string (would allow a bullhead kill if needed) •These rams were tested in September 2024 to 5,000 psi •Removing a NON-standard standard piece of Well Control equipment o Not relying on well control equipment that is not widely used o Safety joint deployment for well control is an industry accepted and standard practice •Consistent Shut-In Procedure o Safety Joint - Single closing practice for ALL operations o No change to shut-in procedures for various jointed pipe runs o Crews drill to a single shut-in procedure for all situations (muscle memory / consistency) Personal Risk when changing rams – •Removes added personal risk for crew members (working at heights in small cellar) •Removes Dropped Objects potential (around a tree that is open to the formation) 12 Addressing AOGCC Comments •It is okay to swap the rams to be compliant and not use them –Poor BOP stack management –If liner rams or workstring rams are required to be installed, I would be forced to require the rig to use them to shut in. Doing so would significantly degrade well control. •Previous Operator had CS Hydril rams, so should Hilcorp –Partly True. After Macando, adding workstring rams became a Previous Operator mandate. The Previous Operator used their company leverage to make Hydril build the rams. There were only 6 ever made. After a very short time Alaska received an exemption because the Previous Operator understood adding the rams was inferior well control. •Add an extra ram in the stack –Previous Operator evaluated this as well –It would not work in many cases due to height restrictions –The extra rams offers poor options for well control. If the ram was added it would be used. 13 Addressing AOGCC Comments continued •What if you can’t run a safety joint or it takes a long time to install? –Running a safety joint is an industry standard practice for many operations –There is a significant comparable operation to reference. Other Coil Tubing Drilling operators on Alaska’s North Slope have run operations for years only relying on a safety joint for well control. –Every time the rig picks up perforating guns and lays down perforating guns a safety joint is a safe practice for well control. –Kick volume is not a significant factor in CTD due to unlimited kick tolerance. –The liner is in cased hole and sticking is not a risk. –An annular preventor is available to be closed. –The BOPE has shear capability, close the tree valve. 14 CTD Well Control BOP Examples 15 BOP Shear Chart BOP Shut in Procedure 16 IN OUT Liner + TIWRig Floor Hand SlipsINOUT Annular Blind / Shear Upper CT Pipe/Slips Variables Lower CT Pipe/Slips Upper Flow Cross Managed Pressure Open interactive BOP diagram outside of PowerPoint 17 Martin Walters – Expert Witness •Introduction •Methodology •Attend Team Meetings •Review History •Kick likelihood •Wellhead height limitations •Shear study •Review Procedures •Standing Orders •Hole prep •Study Options •Brainstorm Pros and Cons 18 Safety Joint VBR CS Hydril Integrity SI Position Training Kick Size Compliance Martin Walters – Expert Witness 19 Martin Walters – Expert Witness •Pros and Cons with respect to “Shut In Quickly and Correctly” •Safety (Kick) Joint: •Pros •Higher “integrity” barrier (no jacking) •Shut in above flow cross •Consistent shut in procedure and training •Cons •Larger kick due to increased time to shut in •Does not comply with Alaska statutes •VBRs & CS Hydril: •Pros •Smaller kick due to decreased time to shut in •Complies with Alaska statutes •Cons •VBRs have lower “integrity” barrier (jacking) •Shut in below flow cross •Procedure and training vary depending upon pipe size •Conclusion(s) •Safety joint preferred due to kick size con being offset by infinite kick tolerance20 Summary •Use of a safety joint to shut in a well is an industry standard •Using a safety joint to shut in is better than adding a Liner or CS Hydril Ram 20 AAC 25.036 (e)(2)(A)(iv) Waiver Request – (To be included in all CTD PTDs) Hilcorp Alaska, LLC request a waiver for CASED hole Coil Tubing Drilling jointed pipe operations to use a safety joint, in lieu of having a preventor equipped with a pipe ram that fits the size of jointed pipe being run. 20 AAC 25.036 (e)(2)(A)(iv) – “at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars”. 21 Backup 22 PBU Tree Heights and added ram configuration Max 6 ram 163 172 Wells:ft inch Tree inches CDR2 CDR3 06-18: 15’ 8 ½”SV 15 8.5 188.5 -25.5 -16.5 09-35: 15’ 10 ½”15 10.5 190.5 -27.5 -18.5 16-24: 11’ 2”11 2 134 29 38 D-03: 12’ 6”12 6 150 13 22 J-25B: 13’ 11 ½”13 11.5 167.5 -4.5 4.5 H-02: 12’ 1 ½”12 1.5 145.5 17.5 26.5 H-29: 14’ 6 ½”14 6.5 174.5 -11.5 -2.5 H-17: 12’ 6 ½”12 6.5 150.5 12.5 21.5 B-12: 10’ 3”10 3 123 40 49 D-10: 13’ 3”13 3 159 4 13 09-21: 13’ 5”13 5 161 2 11 16-24: 16’ 11 ½”16 11.5 203.5 -40.5 -31.5 B-30: 11’ 2 ½”11 2.5 134.5 28.5 37.5 13-35: 12’ 2”12 2 146 17 26 There is not adequate room to add extra BOP rams : •Current PBU Well Tree heights range between 134” and 203”. •CDR2 max tree height, with six ram BOP, to fit over the well is 163”. •CDR3 max tree height, with six ram BOP, to fit over the well is 172”. •A six ram BOP stack (to accommodate two extra rams for CTD jointed pipe operations – 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams), is based off two triples. 23 Pipe Jacking Jacking Issues (Pipe light Scenario) BF=(65.5 -Mud Weight ppg)/ 65.5 Buoyancy factor ranges from 0.85 (85%) for 9.8 ppg fluid to 0.82 (82%) for 11.8 ppg fluid 200’ of 3-1/2” 9.2# Liner = 1840# 500’ of 3-1/4” 6.6# Liner = 3300# 2500’ of 2-7/8” 6.5# Liner = 16250# Total weight = 21,390# MASP= ~2400# Ivishak •Example ( 3-1/2” x 3-1/4” x 2-7/8” liner) 21390# lbs of liner in 9.8 ppg fluid = 18,181 lbs / 962lbs = Pressure in excess of 1889 psi would begin to induce jacking with Variable / Annular closed on 3-1/2” Pipe. Very easily see this kind of pressure bull heading. This is if had everything in hole. •Example (3-1/4” x 2-7/8” liner) 19,550# of liner in 9.8 ppg fluid = 16617 lbs / 830 lbs = Pressure in excess of 2002 psi would begin to induce jacking with Variable / Annular closed on 3-1/4” •Example ( 2500’ of 2-7/8” liner) 16250# of liner in 9.8 ppg fluid = 13812 lbs / 649 lbs = Pressures in excess of 2128 psi would begin to induce jacking with a Variable / Annular closed on 2-7/8” •Example ( 1250’ of 2-7/8” liner) 8125# of liner in 9.8 ppg fluid= 6906 lbs / 649 lbs = Pressures in excess of 1064 psi would begin to induce jacking with a Variable / Annular closed on 2- 7/8” •Example (625’ of 2-7/8” liner) 4062# of liner in 9.8 ppg fluid = 3453 lbs / 649 lbs = Pressures in excess of 532 psi would begin to induce jacking with Variable / Annular closed on 2-7/8” •Example ( 312’ of 2-7/8” liner) 2028# of liner in 9.8 ppg fluid = 1723 lbs / 649 lbs = Pressures in excess of 265 psi would begin to induce jacking with Variable / Annular closed on 2- 7/8” 3-1/2” Tubulars = 962 lbs force / 100 psi wellhead pressure 3-1/4” Tubulars = 830 lbs force / 100 psi wellhead pressure 2-7/8” Tubulars= 649 lbs force / 100 psi wellhead pressure 2-3/8” Tubulars = 443 lbs force / 100 psi wellhead pressure 24 OTHER - Justification to not install VBRs and CS Hydril Rams Other reasons to NOT run VBRs. Unstable Hole – •Changing to VBRs for liner runs has been taking 5-6 hours. This is valuable time with shales open in the lateral. Adding this time to the liner run can adversely affect the ability to get liner to bottom and complete the well. •Most recently on the well PBU N-11D. The well was TD’d to plan. An unstable interzonal shale section was open mid lateral. The shale was holding open during final cleanout runs, so a liner run was attempted. However, liner preparation took substantially longer with issues changing/testing VBRs (12 hrs). Liner was run, but wasn’t able to get past the shale section. The shale had collapsed and would not allow further access to the hole. •A more efficient time at surface, making up liner, will greatly improve chances of getting liner to TD and completing the well. •Time is key in CTD and the less time the shale sections are open, the less cleanout runs / plugbacks / sidetracks / reduced reserve offtake (from liners not getting to bottom). Well Efficiency – •10-12 hours spent changing to VBRs and back per well (~12 days per year, per rig = one more well drilled/rig/year). •If 12 days per year, per rig were saved, by not installing VBRs, one more well could be drilled for state production per rig per year. Other reasons to NOT run CS Hydril Rams. Well Efficiency – •10-12 hours spent changing to CH Hydril Rams and back per well (~12 days per year, per rig = one more well drilled/rig/year). •If 12 days per year, per rig were saved, by not installing CS Hydril Rams, one more well could be drilled for state production per rig per year. 25 2-3/8” Pressure Deployment Rams for Drilling and Running Liner Slimhole Ram Configuration •No need to change rams for liner runs. •2-3/8” Pipe/Slip rams are used for BHA pressure deployment and will fit the 2-3/8” liner. •For superior well control functionality, a 2” safety joint is still the preferred option for shutting in. •The 2-3/8” Pipe/Slip rams would still be the last option utilized Tree Swab Valve Tree Master Valve 26 3 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: OTH-25-014 Hilcorp Alaska, LLC (Hilcorp), by letter received March 21, 2025, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) requesting a hearing for a waiver to 20 AAC 25.036 (c)(2)(A)(iv) coil tubing unit operations where at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars. AOGCC regulations require coiled tubing unit operations comply with 20 AAC 25.036(c)(2)(A)(iv), which mandates at least one preventer equipped with pipe rams that match the size of the pipe, tubing, or casing in use. On January 13, 2025, Hilcorp submitted a variance request with supporting documentation for 20 AAC 25.036(c)(2)(A)(iv). After review, the information provided did not adequately justify granting a variance to this regulation. While the proposed mitigations reflect good well control practices for open-hole casing operations, a variance under 20 AAC 25.036(f) requires an equally effective alternative means of well control. On January 16, 2025, the AOGCC responded to Hilcorp’s variance request with the following: Coil drilling operations must comply with 20 AAC 25.036(c)(2)(A)(iv), which mandates at least one preventer equipped with pipe rams that match the size of the pipe, tubing, or casing in use. This notice does not contain all the information filed by Hilcorp. To obtain more information, contact the AOGCC’s Special Assistant, Samantha Coldiron, at (907) 793-1223 or samantha.coldiron@alaska.gov. A public hearing on the matter has been scheduled for May 29, 2025, at 10:00 a.m. The hearing, which may be changed to full virtual, if necessary, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call-in information is (907) 202-7104 Conference ID: 322 641 595#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Coldiron at least two business days before the scheduled public hearing to request an invitation for the MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 west 7th Avenue, Anchorage, AK 99501 or samantha.coldiron@alaska.gov. Comments must be received no later than the conclusion of the May 29, 2025, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Coldiron, at (907) 793-1223, no later than May 22, 2025. Jessie L. Chmielowski Commissioner GreJory C. Wilson Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.24 13:09:07 -08'00' Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2025.03.26 16:29:16 -08'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice (Hilcorp) Date:Tuesday, April 1, 2025 11:58:04 AM Attachments:OTH-25-014 Public Hearing Notice CTD.pdf Docket Number: OTH-25-014 Hilcorp Alaska, LLC (Hilcorp), by letter received March 21, 2025, filed an application to the Alaska Oil and Gas Conservation Commission (AOGCC) requesting a hearing for a waiver to 20 AAC 25.036 (c)(2)(A)(iv) coil tubing unit operations where at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars. Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 2 March 11, 2025 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: Request for AOGCC Public Hearing Coil Tubing Drilling - Well Control Waiver Request to 20 AAC 25.036 (c)(2)(A)(iv) Commissioner Chmielowski: Hilcorp Alaska, LLC (“Hilcorp”) would like to formally request a Public Hearing with the Alaska Oil and Gas Conservation Commission (“AOGCC”) to request a waiver to 20 AAC 25.036 (c)(2)(A)(iv). 20 AAC 25.036 (c)(2)(A)(iv) – “at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars”. Hilcorp requests a waiver to use a safety joint to shut-in a well during jointed pipe operations that will be deployed with coiled tubing. This practice would be in place of a pipe ram sized for the jointed pipe being ran prior to making up the coiled tubing. The use of a safety joint is a superior well control technique for Coil Tubing Drilling operations. Hilcorp believes in a consistent well control shut-in practice using a safety joint while running solid liner, slotted liner, CS Hydril jointed pipe, and perforating guns. The same well control shut-in practice for all jointed pipe operations is good well control. When closing on a safety joint, two sets of pipe/slip rams (above and below the flow cross), an annular preventor and blind/shear rams are available for use, providing better well control options. If you require additional information or have technical questions prior to the hearing, please contact Trevor Hyatt, Senior Drilling Engineer, at (907) 777-8396, or by email at trevor.hyatt@hilcorp.com. Sincerely, Sean Mclaughlin Drilling Manager Hilcorp Alaska, LLC cc: Samantha Carlisle, Assistant, AOGCC (via email) Jack Lau, Senior Petroleum Engineer, AOGCC (via email) By Samantha Coldiron at 8:00 am, Mar 21, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.03.20 16:45:00 - 08'00' Sean McLaughlin (4311) 1 From: Lau, Jack J (OGC) Sent: Thursday, January 16, 2025 10:07 AM To: Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Cc: Ryan Ciolkosz <Ryan.Ciolkosz@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; John Perl <John.Perl@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Chmielowski, Jessie L C (OGC) <jessie.chmielowski@alaska.gov> Subject: RE: Dec 9th Meeting Follow up (Blind/Shear Rams) Good Morning Trevor, Thank you for submitting the variance request and supporting documentation for 20 AAC 25.036(c)(2)(A)(iv). After review, the information provided does not adequately justify granting a variance to this regulation. While the proposed mitigations reflect good well control practices for open-hole casing operations, a variance under 20 AAC 25.036(f) requires an equally effective alternative means of well control. Coil drilling operations must comply with 20 AAC 25.036(c)(2)(A)(iv), which mandates at least one preventer equipped with pipe rams that match the size of the pipe, tubing, or casing in use. The AOGCC will require PTDs to adhere to this regulation for operations beginning on or after March 30, 2025. If Hilcorp cannot comply with 20 AAC 25.036(c)(2)(A)(iv), the next step would be for Hilcorp to request a formal waiver of AOGCC’s regulation which requires publicly noticing a hearing under 20 AAC 25.505 and 20 AAC 25.540. This will provide a formal platform for presenting evidence, testimony, and expert opinions, ensuring the AOGCC can make informed and transparent decisions. Jack Lau Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission (907) 793-1244 Office (907) 227-2760 Cell CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From: Trevor Hyatt <Trevor.Hyatt@hilcorp.com> Sent: Monday, January 13, 2025 11:09 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Cc: Ryan Ciolkosz <Ryan.Ciolkosz@hilcorp.com>; Joseph Lastufka <Joseph.Lastufka@hilcorp.com>; John Perl <John.Perl@hilcorp.com>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: Dec 9th Meeting Follow up (Blind/Shear Rams) Mel / Wade / Jack / Bryan, Just looking to follow up on the discussion we had at the December 9th meeting in your office? Has your team been able to discuss the possibility of CTD jointed pipe operations working under a variance (for not having specific sized rams in the BOP for all of the jointed pipe operations)? I believe your team was going to discuss the idea that our blind shear rams could be considered equal to or better than the jointed pipe sized rams in the BOP (with shear and pressure test data to back it up). Would your team accept the below variance request on our PTDs going forward (if you would like it worded differently let me know and we would be happy to re-work it)? A possible addition to our PTDs to ask for this variance: 20 AAC 25.036 (c)(2)(A)(iv): Variance Request Hilcorp request to NOT have jointed pipe rams sized for every size of jointed pipe ran in the well. Blind/Shear rams would be utilized in place of CTD jointed pipe rams, as a worst-case shut-in scenario (in place of 2-3/8”x3-1/2” VBRs for liner runs and 1” / 1-1/4” CS hydril pipe rams). Reference NOV EG72 WO BOP Shear Performance Test – Document Number D601005160-REP-001 for confirmed shearing and testing data on CTD jointed pipe. This will allow the well to be killed vs not being able to kill the well if jointed pipe rams are closed (below flow cross). Mitigations: Will always maintain required overbalance to the formation. The BHA will be circulated out of hole prior to laying down BHA for jointed pipe operations. The well will be flow checked after laying in KWF, before laying down BHA and before making jointed pipe. In addition, a X-over (for all tubulars to be run in the well) and a safety joint including a TIW valve will be ready on the rig floor. Primary shut-in standing orders will be to use a safety joint while running 2-3/8” or 3- 1/2”x3-1/4”x2-7/8” solid or slotted liner, 1” or 1-1/4” CS Hydril jointed pipe, and perf guns. The desire is to keep the same standing orders for all jointed pipe operations and not change shut in techniques in the middle of jointed pipe operations or from well to well (run safety joint with pre-installed TIW valve). When closing on a safety joint, 2 sets of pipe/slip rams will be available, above and below the flow cross providing better well control option. Please see the attached NOV EG72 WO BOP Shear Performance Test – Document Number D601005160-REP-001 for your records. This document shows blind/shear rams can shut in on all CTD jointed pipe operations and scenarios while holding up to 5k psi pressure from below. Thank you for your time and consideration. Trevor Hyatt Hilcorp Alaska, LLC Drilling Engineer Trevor.Hyatt@hilcorp.com Cell: 907-223-3087 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. 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No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. www.nov.com REFERENCE REFERENCE DESCRIPTION This document contains proprietary and confidential information which belongs to National-Oilwell Varco, L.P., its affiliates or subsidiaries (all collectively referred to hereinafter as "NOV"). It is loaned for limited purposes only and remains the property of NOV. Reproduction, in whole or in part, or use of this design or distribution of this information to others is not permitted without the express written consent of NOV. This document is to be returned to NOV upon request and in any event upon completion of the use for which it was loaned. This document and the information contained and represented herein is the copyrighted property of NOV. © National Oilwell Varco NOV Texas Oil Tools 700 Conroe Park North Conroe Texas, 77303 936.520.5300 Direct 936.756.8102 Fax DOCUMENT NUMBER D601005160-REP-001 REV 01 RIG/PLANT ADDITIONAL CODE SDRL CODE TOTAL PGS REMARKS MAIN TAG NUMBER DISCIPLINE CLIENT PO NUMBER CLIENT DOCUMENT NUMBER Client Document Number ERPT Nordic-Calista Services EG72 WO Test Report for D601005160-PRO-001 ….. EG72 WO BOP Shear Performance Test ….. Tubing Specified by Nordic-Calista Report Document D601005160-REP-001 Revision 01 Page 2 of 19 www.nov.com REVISION HISTORY 01 08 Jan.11 Initial Release CP PLM JD Rev Date (dd.mm.yyyy) Reason for issue Prepared Checked Approved CHANGE DESCRIPTION Revision Change Description 01 First issue Document D601005160-REP-001 Revision 01 Page 3 of 19 www.nov.com SUMMARY REPORT: Status / Contents 12 Dec. 2010 The following is a summary reveiw of results from testing conducted on the EG72 WO BOP s/n 972111015, 7.06 5k, 3k hydraulics utilizing ram assemblies EG72-TS88XB against a wide range of tubing specified by Nordic-Calista Services. This summary report captures the results of the procedure / program per conducted sections as well the relevant charts, documents and associated photographs, reference test procedure D601005160-PRO-001. This report is shown chronological order as performed per section of test procedure along with conclusion, comments and signature of agreement / attestation. Note this report is generated as proceedings occur to ensure accurate and timely reporting of events as they transpire. SUMMARY REPORT: Sections 1.0, 2.0 and 3.0: Scope, Assembly and General Requirements The test set-up was instrumented with the appropriate equipment (pumps, valves, panels, control systems, data aq and pressure transducers) to accomplish all the parameters set forth in test procedure D601005160-PRO-001 SAFEOP along with SJA were conducted and filed in the data package for this test procedure. Equipment utilized in this test set-up include the main article / sample interface control panel, hydraulic control skid, data acquisition system. See attached related documents and photographs. Document D601005160-REP-001 Revision 01 Page 4 of 19 www.nov.com SUMMARY REPORT: Sections 4.0 and 5.0: Shear Operations (reference test procedure D601005160-PRO-001) The EG72 WO BOP was subject to the following shear tests: 1. Suspend sample tubing into BOP at correct height to insure shear at desired location. 2. Preset accumulator to 3000 psi hydraulic operating pressure. 3. Close rams and visually confirm (record) hydraulic force at moment of shear. 4. Apply low pressure 200-300 psi hydrostatic wellbore below rams, hold 15 minutes. 5. Apply high pressure 5,000 psi hydrostatic wellbore below rams, hold 15 minutes. 6. Remove sample, photograph cut and record relevant shear force (hydraulic psi). 7. Repeat this process for all customer specified samples and configurations of samples. See results below, reference corresponding photographs and charts as titled per sample number. Shear Sample 1: 1.250” L-80 CS Hydril Tubing, below tool joint. Hydraulic PSI required: 924 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 2: 2.875” L-80 Tubing, below tool joint. Hydraulic PSI required: 1152 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 3: 3.188” L-80 Tubing, below tool joint. Hydraulic PSI required: 1205 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 4: 3.500” L-80 Tubing, below tool joint. Hydraulic PSI required: 1826 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 5: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Hydraulic PSI required: 1835 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 6: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Hydraulic PSI required: 2040 psi. Disposition: Clean shear, no leaks during low and high pressure test. Document D601005160-REP-001 Revision 01 Page 5 of 19 www.nov.com SUMMARY REPORT: Sections 4.0 and 5.0: Shear Operations (continued) Shear Sample 7: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Hydraulic PSI required: 1400 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 8: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Hydraulic PSI required: 1929 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 9: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Hydraulic PSI required: 2161 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 10: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Hydraulic PSI required: 2162 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 11: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Hydraulic PSI required: 2114 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 12: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Hydraulic PSI required: 2508 psi. Disposition: Clean shear, no leaks during low and high pressure test. Shear Sample 13: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Hydraulic PSI required: 1871 psi. Disposition: Clean shear, no leaks during low and high pressure test. Document D601005160-REP-001 Revision 01 Page 6 of 19 www.nov.com SUMMARY REPORT: Related Photographs Lower ram assembly 2005-2001B – post testing. Upper ram assembly 2005-2002B – post testing. Document D601005160-REP-001 Revision 01 Page 7 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) EG72 WO BOP typical operation. EG72 WO BOP typical operation. Document D601005160-REP-001 Revision 01 Page 8 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 1: 1.250” L-80 CS Hydril Tubing, below tool joint. Shear Sample 2: 2.875” L-80 CS Hydril Tubing, below tool joint. Document D601005160-REP-001 Revision 01 Page 9 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 3: 3.188” L-80 CS Hydril Tubing, below tool joint. Shear Sample 4: 3.500” L-80 CS Hydril Tubing, below tool joint. Document D601005160-REP-001 Revision 01 Page 10 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 5: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Shear Sample 6: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Document D601005160-REP-001 Revision 01 Page 11 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 7: 2.875” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Shear Sample 8: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Document D601005160-REP-001 Revision 01 Page 12 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 9: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Shear Sample 10: 3.188” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Document D601005160-REP-001 Revision 01 Page 13 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 11: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, below tool joint. Shear Sample 12: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint. Document D601005160-REP-001 Revision 01 Page 14 of 19 www.nov.com SUMMARY REPORT: Related Photographs (continued) Shear Sample 13: 3.500” L-80 w/ 1.250” CS Hydril Tubing inside, center tool joint on both pieces of tubing. Shear Samples 1 thru 13: Document D601005160-REP-001 Revision 01 Page 15 of 19 www.nov.com SUMMARY REPORT: Related Charts Shear Sample 1 & 2: Shear Sample 3 & 4: Document D601005160-REP-001 Revision 01 Page 16 of 19 www.nov.com SUMMARY REPORT: Related Charts (continued) Shear Sample 5 & 6: Shear Sample 7 & 8: Document D601005160-REP-001 Revision 01 Page 17 of 19 www.nov.com SUMMARY REPORT: Related Charts (continued) Shear Sample 9 & 10: Shear Sample 11 & 12: Document D601005160-REP-001 Revision 01 Page 18 of 19 www.nov.com SUMMARY REPORT: Related Charts (continued) Shear Sample 13: SUMMARY REPORT: Conclusion Upon completion of the test program per procedure D601005160-PRO-001 removal of the rams and blades ‘EG72-TS88XB’ revealed expected wear conditions commensurate with these shear tests. The blades were subjected to NDE wet mag inspection which revealed no cracks or indications along the leading shear edges. The blades displayed an overall good condition after 13 consecutive shear operations against the subject tubing and combination scenarios and are considered fit for this scope of operation. Ram sealing elements revealed normal expected wear and edge feathering with light extrusion commensurate with extended shear and pressure testing. Note: Based on data obtained thru this testing the blade condition versus required hydraulic pressure (post 13 shear operations) it is reasonable to assume with high probability this same set of blades will continue to successfully shear several more of these samples (combinations) before realizing unsatisfactory results and eventually reaching the limit of hydraulic pressure required to complete a shear operation. Document D601005160-REP-001 Revision 01 Page 19 of 19 www.nov.com SUMMARY REPORT: Agreement / Attestation: The following personnel participated, witnessed or conducted the above program relating to the subject test procedure and agree to the recording and reporting pertaining to procedures, guidelines and safety concerns and certify the testing / reporting to be accurate and compliant with industry standards / expectations. Signature of agreement: … Luis Rodriguez ....................................................................................................................................... (Technician / E-Lab) Signature of agreement: … Don McKay .............................................................................................................................................. (Technician / E-Lab Coordinator) Signature of agreement: … Perry L McClanahan (TOT E-Lab) ............................................................................................... (E-Lab Operations Manager) End test report D601005160-REP-001. www.nov.com CALCULATIONS ECAL-EG72 S/S 1.315" 2.25# L-80 EG72 Shear/Seal Actuator; Required Hydraulic Shearing Pressure for 1.315" 2.25# L-80 Tubing REFERENCE REFERENCE DESCRIPTION This document contains proprietary and confidential information which belongs to National-Oilwell Varco, L.P., its affiliates or subsidiaries (all collectively referred to hereinafter as "NOV"). It is loaned for limited purposes only and remains the property of NOV. Reproduction, in whole or in part, or use of this design or distribution of this information to others is not permitted without the express written consent of NOV. This document is to be returned to NOV upon request and in any event upon completion of the use for which it was loaned. This document and the information contained and represented herein is the copyrighted property of NOV. Ó National Oilwell Varco TEXAS OIL TOOLS 700 Conroe Park North Drive Conroe, TX 77305 Phone 936-520-5300 Fax 936-756-8102 DOCUMENT NUMBER D601008482-CAL-001 REV 01 M60XXX-XXX-CAL-001 Rev.01 Page 2 of 3 www.nov.com REVISION HISTORY 01 20.10.2011 Initial Release CN KM JD Rev Date (dd.mm.yyyy) Reason for issue Prepared Checked Approved CHANGE DESCRIPTION 01 Initial Release M60XXX-XXX-CAL-001 Rev.01 Page 3 of 3 www.nov.com Required Hydraulic Pressure Calculation EG72 Shear/Seal (TECH-1337-Rev.R) 1.315" 2.25# L-80 Tubing OD = Tubing Outer Diameter t = Wall Thickness Sy = Material Yield Strength DP = Piston Diameter Dtr = Tailrod Diameter Dr = Piston Rod Diameter WP = Wellbore Pressure Dpb = Booster Piston Diameter Dbr = Booster Rod Diameter A = Tubing Area TS = Theoretical Shear SA = Shear Area WR = Wellbore Ratio HP = Required Hydraulic Pressure Dp 7.480in:=WP0 0psi:=OD 1.315in:= t 1.315in 0.957in-( ) 0.358 in×=:=Dtr 1.878in:=Dpb 0:=WP5 5000psi:= Sy 51000psi:=Dr 2.000in:=Dbr 0:= A OD 2 OD 2 t×( )-[ ] 2-4 :=A 1.076 in 2×= TS A Sy× .577×:=TS 3.167 10 4´lbf×= SA 4 Dp( ) 2 4 Dpb( ) 2+ 4 Dbr( ) 2- 4 Dtr( ) 2-:=SA 41.173 in 2×= WR SA 4 Dr( ) 2 :=WR 13.106= HP0 TS SA WP0 WR +:=HP0 769 psi×= HP5 TS SA WP5 WR +:=HP5 1151 psi×= www.nov.com CALCULATIONS ECAL-EG72 S/S 1.66" 3.02# L-80 EG72 Shear/Seal Actuator; Required Hydraulic Shearing Pressure for 1.66" 3.02# L-80 Tubing REFERENCE REFERENCE DESCRIPTION This document contains proprietary and confidential information which belongs to National-Oilwell Varco, L.P., its affiliates or subsidiaries (all collectively referred to hereinafter as "NOV"). It is loaned for limited purposes only and remains the property of NOV. Reproduction, in whole or in part, or use of this design or distribution of this information to others is not permitted without the express written consent of NOV. This document is to be returned to NOV upon request and in any event upon completion of the use for which it was loaned. This document and the information contained and represented herein is the copyrighted property of NOV. Ó National Oilwell Varco TEXAS OIL TOOLS 700 Conroe Park North Drive Conroe, TX 77305 Phone 936-520-5300 Fax 936-756-8102 DOCUMENT NUMBER D601008483-CAL-001 REV 01 M60XXX-XXX-CAL-001 Rev.01 Page 2 of 3 www.nov.com REVISION HISTORY 01 20.10.2011 Initial Release CN KM JD Rev Date (dd.mm.yyyy) Reason for issue Prepared Checked Approved CHANGE DESCRIPTION 01 Initial Release M60XXX-XXX-CAL-001 Rev.01 Page 3 of 3 www.nov.com Required Hydraulic Pressure Calculation EG72 Shear/Seal (TECH-1337-Rev.R) 1.66" 3.02# L-80 Tubing OD = Tubing Outer Diameter t = Wall Thickness Sy = Material Yield Strength DP = Piston Diameter Dtr = Tailrod Diameter Dr = Piston Rod Diameter WP = Wellbore Pressure Dpb = Booster Piston Diameter Dbr = Booster Rod Diameter A = Tubing Area TS = Theoretical Shear SA = Shear Area WR = Wellbore Ratio HP = Required Hydraulic Pressure Dp 7.480in:=WP0 0psi:=OD 1.66in:= t 1.66in 1.278in-0.382 in×=:=Dtr 1.878in:=Dpb 0:=WP5 5000psi:= Sy 71000psi:=Dr 2.000in:=Dbr 0:= A OD 2 OD 2 t×( )-[ ] 2-4 :=A 1.534 in 2×= TS A Sy× .577×:=TS 6.283 10 4´lbf×= SA 4 Dp( ) 2 4 Dpb( ) 2+ 4 Dbr( ) 2- 4 Dtr( ) 2-:=SA 41.173 in 2×= WR SA 4 Dr( ) 2 :=WR 13.106= HP0 TS SA WP0 WR +:=HP0 1526 psi×= HP5 TS SA WP5 WR +:=HP5 1908 psi×= Texas Oil Tools Shear data for 7‐1/16" 5,000 psi WP Combi BOPTOT Shear capabilities tableType OD Wall or weight per Grade 0 psi WHP 3,000 psi WHP 5,000 psi WHPReferenceCommentcoiled tubing 2.000 0.134 90,000 912 1,125 TOT tech unit 1337Kcoiled tubing 2.000 0.156 90,000 1,049 1,263 TOT tech unit 1337Kcoiled tubing 2.000 0.175 90,000 1,165 1,378 TOT tech unit 1337Kcoiled tubing 2.000 0.188 90,000 1,243 1,456 TOT tech unit 1337Kcoiled tubing 2.000 0.190 90,000 1,610 TOT engineering 6/8/10coiled tubing 2.375 0.13490,000 1,340 1,553 TOT tech unit 1337Kcoiled tubing 2.375 0.156 90,000 1,547 1,761 TOT tech unit 1337Kcoiled tubing 2.375 0.175 90,000 1,724 1,937 TOT tech unit 1337Kcoiled tubing 2.375 0.188 90,000 1,843 2,056 TOT tech unit 1337Kcoiled tubing 2.375 0.188 90,000 1,800 SAS Technology test 12/10/97 Test at 3,500 psi MASPcoiled tubing 2.375 0.190 90,000 1,820 TOT engineering 6/8/10CS‐Hydril 1.315" 2.25 lbs/ft L‐80769 1,151 TOT engineering 10/20/11CS‐Hydril1.660" 3.02 lbs/ft L‐80 1,526 1,908 TOT engineering 10/20/11Tubing 2.375 4.7 lbs/ft L‐80TOT test report D601005160‐PRO‐001With Shear ram BoosterTubing 2.375 4.7 lbs/ft L‐80w/ 1" CSH inside with shear ram boosterTubing 2.785 6.5 lbs/ft L‐80TOT test report D601005160‐PRO‐001With Shear ram BoosterTubing 2.785 6.5 lbs/ft L‐80TOT test report D601005160‐PRO‐001w/ 1‐1/4" CSH inside with shear ram boosterTubing 3.188 6.2 lbs/ft L‐80TOT test report D601005160‐PRO‐001With Shear ram BoosterTubing 3.188 6.2 lbs/ft L‐80TOT test report D601005160‐PRO‐001w/ 1‐1/4" CSH inside with shear ram boosterTubing 3.500 9.3 lbs/ft L‐802,500 ‐ 2,700TOT test report D601005160‐PRO‐001With Shear ram BoosterTubing 3.500 9.3 lbs/ft L‐80TOT test report D601005160‐PRO‐001w/ 1‐1/4" CSH inside with shear ram booster Updated: 10/21/20113/5/2012
