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Home My WebLink About225-0781 McLellan, Bryan J (OGC) From:Jacob Thompson <jacob.thompson@hilcorp.com> Sent:Friday, February 6, 2026 11:24 AM To:McLellan, Bryan J (OGC) Cc:Doyon 15 Rig Foreman; Rixse, Melvin G (OGC); Regg, James B (OGC); Lau, Jack J (OGC); Sean McLaughlin Subject:Re: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Attachments:Rig_15_-_BOP_Stackup_-_PT_Thompson_Project_Hilcorp[70842].pdf Bryan, They will be tied into the upper double pipe ram outlet. Attached is a diagram. Thanks, Jacob Thompson Email: jacob.thompson@hilcorp.com Cell: 907-854-4377 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, February 6, 2026 11:57:36 AM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: Doyon 15 Rig Foreman <Doyon15RigForeman@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; jim.regg <jim.regg@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Thanks Jacob. Hilcorp has approval to proceed with drilling Intermediate hole section 1. Where will the kill & choke lines will be tied into these BOP stacks. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Thursday, February 5, 2026 8:45 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Doyon 15 Rig Foreman <Doyon15RigForeman@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov>; Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Bryan, Below are replies to your conditions of approval for drilling out of the Surface Casing Shoe through Intermediate I TD. 1. As-built BOP stack diagram, including MPD. There are some inconsistencies among the documents, including kill/choke side outlet location 3 Two stack configurations, both now including the MPD. Two different DSAs will be used to accommodate the added height of the tubing spool. The tubing spool will be added after the 11-7/8” casing has been run and cemented. 2. & 3.) Please see attachments. 4. We are committed to performing kick while tripping and kick while drilling drills in the time outlined in request #4 below. The drills will be documented in our wellview and IADC reports for documentation purposes. We will address the Intermediate I drill our requirements in subsequent emails as the above information should be sufficient to satisfy drilling the 14-1/2” section. Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer RIG 15 BOP STACK MEYER 16-3/4" ANNULAR "GK" 5M PSI STUD x FLANGE BX-162 MEYER Rl(U) SINGLE GATE 16-3/4" IOM PSI FLANGE x FLANGE BX-162 STANDARD OPERATORS VARIABLE PIPE RAMS MEYER R1(U) DOUBLE GATE 16-3/4" IOM PSI FLANGE x FLANGE BX-162 STANDARD OPERATORS VARIABLE PIPE RAMS 4-1/16" 10M MANUAL CHOKE V, 4-1/16" IOM PSI HCR CHOKE VALVE CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:AOGCC Records (CED sponsored) To:Gluyas, Gavin R (OGC) Subject:FW: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Date:Thursday, February 12, 2026 9:42:27 AM Attachments:image002.pngimage003.png From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, February 5, 2026 4:24 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Regg, James B (OGC) <jim.regg@alaska.gov>; Lau, Jack J (OGC) <jack.lau@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Jacob, Before approving a variance to 20 AAC 25.035(e)(3) & (5), the AOGCC needs additional assurance that Hilcorp’s plan will be at least equally effective in preventing loss of well control, as allowed in 20 AAC 25.035(h)(1). Condition of approval #7 in the approved PTD requires variance approval before drilling out of the surface casing shoe. The AOGCC will conditionally defer the variance approval timing, allowing Hilcorp to drill 14-1/2” hole intermediate 1 section before receiving variance approval because the MPSP of the intermediate 1 hole section is below the rated working pressure of the 7500 psi well control equipment. Conditions of approval: Before Drill out of surface casing shoe please provide the following: 1. As-built BOP stack diagram, including MPD. There are some inconsistencies among the documents, including kill/choke side outlet location. 2. BOP spec sheet and certifications. 3. Valid Well control certificates for drillers, assistant drillers and toolpushers, and anyone authorized to shut the well in. 4. Perform kick while drilling or kick while tripping drill. Each subsequent crew shall perform a well control drill before the end of their first tour after drilling out the surface casing shoe. Well control drills to be performed on a regular basis thereafter to ensure crews are ready to respond to a well control event. Before Drill out of Intermediate 1 hole section, Hilcorp must obtain variance approval from AOGCC of 20 AAC 25.035(e)(3) & (5). The AOGCC’s minimum expectations for approving a variance are as follows: 1. Provide a step by step procedure for rigging up, lining up valves and pumping for the following scenarios: a. Pumping down the kill line when pressure exceeds the working pressure of the mud pump (limited to 5500 psi by the liners in the pump). Include P&ID indicating spec breaks and isolation valves. b. Pumping down the standpipe when the pressure exceeds the working pressure of the mud pump (limited to 5500 psi by the liners in the pump). Include P&ID indicating spec breaks and isolation valves. c. Pumping down the standpipe when pressure exceeds the rated working pressure of the existing standpipe, mud pumps and top drive (limited to 7500 psi by the top drive and standpipe). Include P&ID indicating spec breaks and isolation valves. 2. Describe trigger points for swapping to each of the above 3 scenarios. 3. A 10,000 psi pump and piping shall be rigged up and pressure tested to 10,000 psi to react to scenarios 1a & 1b before drilling out of the Intermediate 1 casing shoe. The 10,000 psi equipment shall remain rigged up for the duration of the well, until BOP stack is removed. 4. The 10,000 psi pump and piping shall be rigged up as much as practicable for scenario 1c before drilling out the Intermediate 1 casing shoe. Include P&ID showing what will be rigged up ahead of time. The 10,000 psi equipment shall remain rigged up for the duration of the well, until BOP stack is removed. 5. A drill which includes rigging up the alternate standpipe to the top of the drillstring shall be conducted to verify that all components are readily available in the event this is required. AOGCC shall be given 48 hrs notice for an opportunity to witness the drill. Verify that enough 10,000 psi rated rotary hose is available to reach the top of the drill string if the scenario were to occur with a full stand of drillpipe above the rig floor. All crews to be familiar with the procedure, however the equipment must be rigged up only once. 6. Verify that the 10k rig up and piping is compliant with API RP 53. 7. AOGCC written authorization to proceed. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Wednesday, February 4, 2026 4:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Bryan, See the responses below: Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, February 4, 2026 2:56 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Jacob, The HP Mud system schematic 1-25-26-PTU-19.pdf shows the 10k cement line ties into the 7500 psi standpipe line via the Tee at the Kill line hookup. I’m assuming this is the diagram for normal drilling operations. Yes this will be hooked up prior to drilling out the INT I casing shoe. The HP Mud schematic - Rig 15 – Contingency.pdf diagram doesn’t show any IBOP of FOSV in the drill string, or what’s above the SLB pump-in sub. The FOSV and IBOP will be installed in the drill string below the pump in sub. They are not shown in the diagram but are part of the standing orders for shutting in the well and will be in place. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Wednesday, February 4, 2026 1:49 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Bryan, This is what Doyon provided. It is essentially the same thing that I sent earlier. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, February 4, 2026 11:23 AM To: Jacob Thompson <jacob.thompson@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Jacob, Could you send over Doyon’s P&ID that includes the contingency hardline connecting to the drillpipe? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Thursday, January 29, 2026 2:30 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Bryan, Below are my responses: Please indicate which 10k psi line will be connected to the drillstring in the diagram? I’ve highlighted in yellow the 7500 psi lines that I can see, please indicate if there are other low pressure lines that I missed. The drill string 10k line was not shown in the PNID below. We provided a Rig 15 PTU-19 Well Control Contingency Piping Plan that showed a direct connection from the cement unit to the drill pipe on the rig floor. We are having Doyon create a more comprehensive PNID that shows the contingency hard line connecting the drill pipe and a tee over to the kill line. I edited the Rig 15 PTU-19 Well Control Contingency Piping Plan to show the Tee and how it will connect to the Kill line. This should clarify things. The only “low” pressure line you did not highlight is the external hook up to the cement standpipe which is also 7,500 psi rated. How will this be done if the top drive is 80’ in the air with drill bit on bottom? In case of a well control event with top drive 80' in the air, we would space out (putting us at 90') shut in as normal regardless of 7500 or 10k surface equipment. Send floorhand up in a riding belt and shut lower IBOP. We would then break out of lower IBOP and blow down top drive. R/U head pin to Lower IBOP along with 10k pumping equipment from floor (HP hose). We would tie in a hose to either our rig hp mud system or SLB 10k pumping equipment depending on psi (not both). This is the process to shut the well in on most North Slope rigs (minus the ones with windwalls to crown) in reaction to a well control event at the top of a stand. The only difference between standard operating procedures and our Point Thomson rig up is the 10k line up. One thing to note is that we will have two non-ported drill string floats in the string and actively drilling with MPD. Although the floats are not a barrier they certainly are a mitigating measure preventing flow up the drill pipe. The RCD and Choke effectively shut in the well every connection allowing us to test the drill string floats integrity, mitigate the risk of annular flow, and decrease kick response times. What is the triggering event that would initiate the swap to the cement line on the drill string? The triggering event would be if surface psi was to exceed 5500 psi (500 psi buffer from popoffs set for our planned liner size). We would then transition from our 7500 psi system to 10k system potentially using the volumetric method to manage BHP while transition takes place. The likelihood of Circulating out a kick with > 5,500 psi drill string pressure is extremely low. The drill string should remain full of fluid during a well control situation, and bottom hole pressure should not exceed the maximum reservoir pressure. These facts would lead to the assumption that unless the drill string is partially evacuated, the drillpipe pressure will remain within the capability of the 5,500 psi limitation. Our planned response is to initiate bullheading through the kill line where an influx’s annular surface pressure will be > 5,000 psi. This will be the best way to regain well control and stay under the surface pressure system of the rig. If an event occurs where the surface pressure exceeds 5,000 psi response will be to hook up the cement unit to the kill line and bullhead the influx back into the reservoir. Out of an abundance of caution we will have the capability to swap over to our cement unit for high pressure pumping for both the drill string and annulus. The most likely scenario is that we will only use the kill line. Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, January 28, 2026 10:41 AM To: Jacob Thompson <jacob.thompson@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Jake, Thanks for the updated diagram and explanation. I have a few follow-up questions to your response. My questions are in Green text. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Tuesday, January 27, 2026 11:15 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Bryan, Please find our response to your questions. Regards, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, January 23, 2026 4:55 PM To: Jacob Thompson <jacob.thompson@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Jake, 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. In reviewing this PTD, the variance referred to in Condition 7 is 20 AAC 25.035(e)(3) & (5). Several questions 1. How will you keep the lines to and from the cement pump from freezing? Heat trace? The lines will remain blown down and capped until needed. Air will also be blown through it on a daily basis. No different than the standpipe circulating system on the rig that is exposed to the elements in the derrick. The drilling fluid is OBM and has a pour point of ~-30F so we should not have a concern with freezing the lines. 2. In bullet # 5, did you intend to say “prior to drilling out Intermediate 1 liner”? Was it a typo where it says prior to drilling Intermediate 2? It should be prior to drilling intermediate 1 as I understand. It was a typo. All of the well control contingency equipment will be rigged up prior to drilling out of the Intermediate I casing shoe. 3. Is the hardline in bullet #5 compliant with 20 AAC 25.035(e)(6)? It needs to be. Yes. 4. Will the high pressure cement line have some kind of non-return valve or be connected above the IBOP? It will be connected above the IBOP. 5. In bullet #6, after taking a kick and shutting in, is it Hilcorp’s intention to disconnect the drill string from the top drive with pressure on the drillstring, then install a pump in sub and hammer up hardline before performing a well kill? It’s hard to understand how you can do all this after you get into a well control situation. While this is happening, gas can be migrating and pressures coming up, approaching frac. You are breaking connections with potential pressure below. During a well control situation is not when you want to be making up pipework. Should there be a well control event while drilling that requires the use of the 10,000psi pumping system, the Top Drive Lower Kelly valve would be closed and the connection above it broken, the Top Drive picked up out of the way, the FOSV, IBOP and Head pin installed to secure the well. After the well was secured the cement line will be connected. Please indicate which 10k psi line will be connected to the drillstring in the diagram? I’ve highlighted in yellow the 7500 psi lines that I can see, please indicate if there are other low pressure lines that I missed. The majority of the cement line will be rigged up and ready for use prior to drilling out the shoe. Hard line will need to be run from the rig floor to the BOP mezzanine through one of the mouse holes on the rig floor. Thie is a short run of pipe. The hard line will then tie into the head pin on the drill pipe. How will this be done if the top drive is 80’ in the air with drill bit on bottom? This cement line rig up would be done concurrently while formal notifications are made, wellbore pressures recorded, and the kill plan is developed. Bottom hole pressure would be kept constant using the Volumetric Method if gas migration was noted while the cement line was rigged up. In order for the surface pressure to exceed the rig’s 7,500 psi standpipe pressure rating an extremely large column of gas would be required. Any other well control event that is shut in below the calculated kick tolerance for the hole section would be circulated out using either the Drillers Method or Wait and Weight both of which would not require any change to the standard circulating path. What is the triggering event that would initiate the swap to the cement line on the drill string? In any event the gas begins to migrate the bottom hole pressure would be kept constant using the Volumetric Method until well kill operations can commence. 6. The diagram doesn’t show where the spec breaks are in the piping system. What isolates the low-pressure rig system from the high pressure on the kill and choke side of the BOP flow cross? Where is the spec break in the top drive from 10k to 7.5k? Please see attached PNID for isolation valves and pressure rating on lines. The red arrow depicts the Upper and Lower Kelly Valves which will be tested to 10,000psi on the initial test. Above the Kelly valve is the 7,500psi rated system. The red circled valve junction shows where the 10,000psi Kill line is isolated from the 7,500psi rated system. A three way block will be installed up stream of the non-return valves on the Kill Line and the cement unit will be hooked up to it as well. This line would only be used to bullhead kill the well as a last resort. 7. Rig book shows page 24 shows kill lines are 5000 psi. Is that correct? Please see attached PNID for pressure values and flow paths. An updated Rig Ebook is also attached. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Friday, January 23, 2026 11:33 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping Mel / Bryan, Hilcorp would like to formally request a variance as required by condition of approval 7 of the approved PTD. The below variance is to establish Hilcorp’s readiness to conduct well kill operations, in the event, that a well control scenario arises where the maximum anticipated surface pressure exceeded the rig’s standpipe pressure rating of 7,500 psi. The below contingency equipment will be set in place prior to the drilling of the Intermediate II section and remained rigged up for the duration of the well. The attached piping plan outlines what is described in the below plan. A SLB cement unit will be fed from the rigs low pressure mud system from the gun line connection in the cellar using the existing hard line that is connecting our tank farm. A hose will tie into the suction end of the cement pump to supply fluid from the rig. The rigs transfer pump will be used to supply the fluid to the cement unit. Both sack and bulk barite will be available on location in order to increase the mud density by 1.0 ppg on site at all times. The Prudhoe Bay MI Swaco mud plant is connected via ice road and will be on call to mix and supply additional KWF if nessisary. 1,600 bbls of fluid capacity will be available in the PTU tank farm in addition to the rigs active system. An independent 2” 10kpsi rated hard line (~260’) will be run from the cementing unit currently adjacent to the rig. The line will come in through the cellar, up through the rig floor, and tie directly into the drill pipe string with a pump in sub on top of the FOSV. The hard line will be assembled all the way to the BOP Mezzanine level prior to drilling out of the Intermediate II liner shoe to aid in timely response and fast rig up of the contingency equipment. The line coming from the cementers will not tie into the rigs high pressure mud system at anytime, but will transfer mud directly down the drill string to perform well kill operations. Please let me know if you would like more details. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, January 21, 2026 3:24 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: jim.regg <jim.regg@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] PTU -19 PTD225-078 Conditions of Approval #7 Variance Request to testing SLB piping CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Jacob, Will you be submitting a formal variance request to COA #7? Bryan and I have talked about it, but want to see it in writing and would be good to have pictures and a schematic. AOGCC Inspectors will want to do a walk down for that equipment as well. Bryan McLellan will be primary AOGCC contact for this well for the next three weeks as I will be out of country. I will check emails and can take calls if needed. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Jim Regg, Bryan McLellan 7.) Variance request and AOGCC approval required before drilling below surface casing shoe describing surface piping diagram and the rated working pressure on high pressure pump in equipment. A clear explanation to be included describing how SLB 10,000 psi would be utilized to avoid 7500 psi existing piping on Doyon 15. The Intermediate I hole section has a MASP of < 3,500 psi assuming a gas gradient to surface with fracture gradient of 15.5 ppg applied at the shoe. As mentioned in previous correspondence, we plan to have a SLB cement unit with 10,000 psi pumping capability on location for sections that have a MASP potential greater than the rig’s 7,500 psi standpipe pressure rating. We are finalizing contingency well kill procedures to utilize the cementing unit. With MASP of INTI we are clarifying that this equipment does not have to be rigged up prior to drilling out of the 14-1/2” intermediate I hole section. The equipment will be rigged up prior to the 9-7/8” x 11-3/4” Intermediate II section and remain for the duration of the well where MASP has the potential to exceed our standpipe pressure rating. We will formally request the required Variance and provide the well kill procedure and rig up plan next week. The cement unit is on location and will remain there for the duration of the well. This request is that we do not have to have the hardline rigged up for INTI. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone numberis listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone numberis listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone numberis listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone numberis listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone numberis listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. 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:McLellan, Bryan J (OGC) To:Jacob Thompson Cc:Doyon 15 Rig Foreman; Rixse, Melvin G (OGC); Regg, James B (OGC) Subject:RE: PTU-19 (PTD# 225-078) Change of Operational Sequence Date:Tuesday, February 3, 2026 11:06:00 AM Jacob, Hilcorp has approval to run the Gyro before the witnessed BOP test as outlined in your email below. The surface casing has been cemented and pressure tested. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Tuesday, February 3, 2026 9:46 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Doyon 15 Rig Foreman <Doyon15RigForeman@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: PTU-19 (PTD# 225-078) Change of Operational Sequence Bryan, As discussed on the call we would like to receive permission to proceed with the following order of operations prior to the AOGCC witnessed BOP test. Current rig status: 16-3/4” BOPE has been nippled up and shell tested to 5,000 psi annular, 10,000 psi rams. This was conducted ahead of AOGCC notification due to this being the first time the rental stack was being used. AOGCC notification has been made for the full bop test. The following order of operations are requested to maintain rig efficiency. 1. MU 14-1/2” bit and bit sub. Barriers in place: 10.0 ppg KWF, Tested 16” surface casing 3,500 psi (pressure monitored since end of surface section). 2. RIH with bit and tag float collar. 3. Drop Gyro. (Gyro will resurvey surface casing to determine if high DLS in shallow potion is still present after casing installation.) 4. POOH and lay down BHA and receive gyro. 5. Commence with BOPE test per approved PTD. Thank you and let me know if you have any questions. Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 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. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.govSean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Point Thompson Unit Field, Point Thompson Oil, PTU 19 Hilcorp Alaska, LLC Permit to Drill Number: 225-078 Surface Location: 951' FSL, 935' FEL, Sec 34, T10N, R23E, UM, AK Bottomhole Location: 2598' FSL, 2222' FEL, Sec 35, T10N, R23E, UM, AK DearMr. McLaughlin: Enclosed is the approved application forthe permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071,composite curves for all well logs run must be submitted to the AOGCCwithin 90days after completion,suspension, or abandonment of this well, or within 90days ofacquisition of the data, whichever occurs first. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: *DVPHDVXUHPHQWVPXVWEHUHFRUGHGIURPVSXGWRWRWDOGHSWKRIWKLVZHOO 0XGORJPXVWEHUHFRUGHGIURPVXUIDFHFDVLQJVKRHWRWRWDOGHSWKRIWKLVZHOO This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCCreserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCCspecifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or anAOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this QG day of October 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.02 13:32:42 -08'00' 12-1/4"x10-1/2" 9-1/2"x8-1/2" C1110/13CS110 TH513/SLIJ-II SLHT Timed By Grace Christianson at 1:31 pm, Jul 17, 2025 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.07.17 13:15:33 - 08'00' Sean McLaughlin (4311) * See following page for additional conditions of approval. MGR30SEP2025 225-078 SFD 10/1/2025 50-089-20036-00-00 8580 589 sx DSR-7/18/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.10.02 13:33:17 -08'00' 10/02/25 10/02/25 RBDMS JSB 100625 Point Thomson Unit Well # 19 Permit to Drill 225-078 AOGCC Additional Conditions of Approval 1. Approved to drill 20-inch surface hole without a diverter with the following conditions: a. Gas monitoring equipment properly calibrated, fully and continuously functioning, recording, and monitored. b. PVTϠϙƲĺſϙŕÍîîīôϠϙÍĲîϙŕĖťϙīôŽôīϙıĺĲĖťĺŘĖĲČ equipment fully functional at all times 2. Initial BOPE test to 10,000 psi. Annular to 5000 psi. 48-hour notice to AOGCC. Subsequent bi-weekly BOPE tests to 8580 psi and annular to 5000 psi. 3. Mud logging equipment and services must be calibrated and fully and continuously functioning and recording during all drilling operations from surface casing shoe to total depth of this well. 4. Hilcorp will have 24-hour coverage of mud logger, sample catcher, and two well site geologists on location. 5. Surface casing pressure test variance approved to test to 3500 psi rather than 50% of burst for overdesigned Q-͔͐͑ϙ͕͐ЋϙèÍŜĖĲČϟϙϙVŪŜťĖƱèÍťĖĺĲϡϙIĲťôŘıôîĖÍťô϶͐ϙĺŕôĲϙēĺīôϙ MASP would break down surface casing shoe and provide leak path for surface casing pressure before reaching 3500 psi. 6. Kill string will not be required for planned shutdown after drilling and casing surface hole provided the following criteria are met or exceeded: a. Full column of weighted oil-based mud to assure well bore is overbalanced to highest intersected pore pressure. b. Passing casing pressure test to 3500 psi. c. Daily monitoring of well head pressure. 7. Variance request and AOGCC approval required before drilling below surface casing shoe describing surface piping diagram and the rated working pressure on high pressure pump in equipment. A clear explanation to be included describing how SLB 10,000 psi would be utilized to avoid 7500 psi existing piping on Doyon 15. 8. Submit casing test and LOT/FIT digital data to AOGCC for approval prior to drilling ahead from each casing shoe. Submit updated kick tolerance table and expected ƲŪĖîϙîôĲŜĖťƅ for the next open hole section to AOGCC. 9. IĲťôŘıôîĖÍťô϶͐ϙĺŕôĲϙēĺīôϙîŘĖīīĖĲČϙťĺ casing point to be performed with the following controls: x aĖèŘĺϙıĺťĖĺĲϙſĖīīϙæôϙŪŜôîϙťĺϙıôÍŜŪŘôϙæÍŘŘôīϙĖĲϯæÍŘŘôīϙĺŪťϙċĺŘϙƲŪĖîϟ x Background gas levels to be monitored continuously. x Flowback trends will be monitored to detect deviations at all connections. If ôŽĖîôĲèôϙĺċϙĖĲèŘôÍŜôîϙƲĺſϙæÍèħϙîŪŘĖĲČϙÍϙŜťÍĲîϙèĺĲĲôèťĖĺĲϙÍċťôŘϙ͐͏Ϡ͏͏͏ЍϙTVD, a ıĺŘôϙċŘôŗŪôĲťϙƲĺſϙæÍèħϙıĺĲĖťĺŘĖĲČϙſĖīīϙæôϙŕôŘċĺŘıôîϙĺċϙĲĺϙČŘôÍťôŘϙťēÍĲϙ͓͔ЍϙĺŘϙ half a stand, whichever is smaller. x Functional PWD, gamma-ray, resistivity to be utilized. x Drilling will be stopped if any evidence of pore pressure greater than 12.6 ppg equivalent. x Monitor drilling for sudden increase in ROP when drilling the EO25. x Follow detailed procedure appended “PTU-19 14-1/2” Intermediate Hole Section TD Protocol “ x Approved variance to 20 AAC 25.033 (b)(1)(A) Primary well control for statically ĺŽôŘæÍīÍĲèôîϙîŘĖīīĖĲČϙſĖťēϙƲŪĖîϙèĺīŪıĲϙſôĖČēťϙѭϙa"ϙîŪÍīϙèēĺħôϙŕŘôŜŜŪŘôϙÍĲîϙ full suite of MPD equipment to assure accurate pore pressure sensitivity for drilling to TD of IĲťôŘıôîĖÍťô϶͐. 10. A tank farm to be placed on location and contain 2,500 barrels of 16 ppg ŜŕĖħôϙƲŪĖîϙ for progressive weight ups ſēĖīôϙîŘĖīīĖĲČϙŕÍŜťϙ͐͏Ϡ͏͏͏Ѝ TVD. 11. Daily drilling report to AOGCC when drilling on BOPE. 12. ŪƯĖèĖôĲťϙŜack barite for an entire hole volume to be available on location for weight up in the event of unexpected pore pressure. 13. ŕŕŘĺŽôîϙťĺϙťôŜťϙIĲťôŘıôîĖÍťô϶͑ϙīĖĲôŘϙϼ͘-7/8”) to test pressure of IĲťôŘıôîĖÍťô϶͐ of 5360 psi. 14. If a gas ĖĲƲŪƄϙĖŜϙťÍħôĲϙĖĲ any hole section, the ĖĲƲŪƄϙis to be circulated to surface utilizing IADC approved well control methods and conducted by an IADC ®([[FϙèĺŪŘŜôϙèôŘťĖƱôîϙЊ"ŘĖīīĖĲČϙiŕôŘÍťĖĺĲŜϠϙŪŕôŘŽĖŜĺŘϠϙŪŘċÍèôЋϙŕôŘŜĺĲĲôīϟϙ 15. Separate 10-403 required to commence gravel pack completion operations. 16. A SLB 10,000 psi pumping unit and 10,000 psi hard line to be rigged up for unplanned circulation needs that would exceed 7500 psi standpipe manifold ratings when drilling on BOPE. 17. H2S measures are required. H2S mitigation procedures must be provided to AOGCC prior to spud. 16 July 2025 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill Hilcorp North Slope, LLC PTU-19 Dear Sir/Madam, The PTU-19 well is scheduled to be drilled by Doyon 15. This grassroots well is a producer targeting the Thomson Sand from Central pad in the PTU unit. The planned well is a 4 string design using a 16” surface casing, 11-7/8” intermediate casing, 9-7/8” drilling liner, and 5-1/2” open hole gravel pack completion. The Target for surface hole spud is November 15th. The surface casing will be set in a shale within the OG75. The intermediate casing will be set in the pressure transition zone in the EO25 / PA25, Intermediate II section will be set at the top of the Thomson sand, and the production interval will be completed with a ~1,000’ open hole gravel pack completion across the Thomson Sand. A 7” tubing string will stab into the lower completion’s seal bore. The maximum anticipated surface pressure from the Thomson Sand with a full column of gas from TD to surface is 7,992 psi (assumes 10,040 psi pore pressure 12,952’ TVD and a 0.158 psi/ft rich reservoir gas gradient). The well will be drilled by Doyon 15 using a 10,000 psi 3 ram BOP stack and 5,000 psi annular preventer. The BOP rams will be tested to 8,500 psi, and annular 5,000 psi. A detailed operations summary is included with the permit application. If there are any questions concerning information on PTU-19, please do not hesitate to use the contact 907-854-4377 or email at Jacob.Thompson@hilcorp.com Respectfully, Jacob Thompson Senior Drilling Engineer Hilcorp North Slope, LLC Enclosures: Form 10-401 Permit to Drill Application for Permit to Drill Intermediate II section will be set at the top of the Thomson sand p g intermediate casing will be set in the pressure transition zone gp g 0.158 psi/ft rich reservoir gas gradient Point Thomson (PTU) PTU-19 Permit To Drill Application Version Draft 7/10/2025 Point Thomson Unit PTU-19 Producer Table of Contents 1. Well Name ...................................................................................................................................... 3 2. Location Summary .......................................................................................................................... 3 3. Blowout Prevention Equipment Information ................................................................................. 4 4. Drilling Hazards Information........................................................................................................... 4 5. Procedure for Conducting Formation Integrity Tests ..................................................................... 6 6. Casing and Cementing Program ..................................................................................................... 6 7. Diverter System Information .......................................................................................................... 7 8. Drilling Fluid Program ..................................................................................................................... 7 9. Abnormally Pressured Formation Information .............................................................................. 8 10. Seismic Analysis ............................................................................................................................ 8 11. Seabed Condition Analysis............................................................................................................ 8 12. Evidence of Bonding ..................................................................................................................... 8 13. Proposed Drilling Program ........................................................................................................... 9 14. Discussion of Mud and Cuttings Disposal and Annular Disposal ................................................ 13 15. Proposed Variance Request........................................................................................................ 13 Attachment 1: Location & GIS Maps ................................................................................................ 18 Attachment 2: BOPE Equipment ...................................................................................................... 20 Attachment 3: Drilling Hazards ......................................................................................................... 24 Attachment 4: LOT / FIT Test Procedure .......................................................................................... 27 Attachment 5: Cement Summary ..................................................................................................... 28 Attachment 6: Prognosed Formation Tops ...................................................................................... 3 0 Attachment 7: Well Schematic ......................................................................................................... 32 Attachment 8: Formation Evaluation Program ................................................................................ 34 Attachment 9: Wellhead Diagram .................................................................................................... 35 Attachment 10: Management of Change ......................................................................................... 3 6 Attachment 11: Directional Plan ...................................................................................................... 37 Attachment 12: Pressure Testing ..................................................................................................... 38 Point Thomson Unit PTU-19 Producer As per 20 AAC 25.005 (c), an application for a Permit to Drill must be accompanied by each of the following items, except for an item already on file with the commission and identified in the application. 1. Well Name 20 AAC 25.005 (f) Each well must be identified by a unique name designated by the operator and a unique API number assigned by the commission under 20 AAC 25.040(b). For a well with multiple well branches, each branch must similarly be identified by a unique name and API number by adding a suffix to the name designated for the well by the operator and to the number assigned to the well by the commission. The well for which this application for a Permit to Drill is submitted is designated as PTU-19. This will be a development production well. 2. Location Summary 20 AAC 25.005 (c) (2) A plat identifying the property and the property's owners and showing: (A) the coordinates of the proposed location of the well at the surface, at the top of each objective formation, and at total depth, referenced to governmental section lines; (B) the coordinates of the proposed location of the well at the surface, referenced to the state plane coordinate system for this state as maintained by the National Geodetic Survey in the National Oceanic and Atmospheric Administration; (C) the proposed depth of the well at the top of each objective formation and at total depth Location at Surface Reference to Government Section Lines 951' FSL, 935' FEL, Sec 34, T10N, R23E, UM, AK NAD 27 Coordinate System X: 468,369.54 Y: 5,912,921.88 Doyon 15 Rig KB Elevation 41’ above GL Ground Level 12.6’ above MSL Location at Top of Productive Interval Reference to Government Section Lines 1,857.8' FSL, 1,402.2' FEL, Sec 35, T10N, R23E, UM, AK NAD 27 Coordinate System X: 473,183.4 Y: 5,913,811.54 Measured Depth, Rig KB (MD) 14,745’ Total Vertical Depth, Rig KB (TVD) 12,706’ Total vertical Depth, Subsea (TVDSS) 12,652’ Location at Bottom of Productive Interval Reference to Government Section Lines 2,598' FSL, 2,222 FEL, Sec 35, T10N, R23E, UM, AK NAD 27 Coordinate System X: 472,465 Y: 5,914,554 Measured Depth, Rig KB (MD) 15,892’ Total Vertical Depth, Rig KB (TVD) 12,965’ Total Vertical Depth, Subsea (TVDSS) 12,911’ Point Thomson Unit PTU-19 Producer (D) other information required by 20 AAC 25.050(b); 20 AAC 25.050 (b) If a well is to be intentionally deviated, the application for a Permit to Drill (Form 10-401) must: (1) include a plat, drawn to a suitable scale, showing the path of the proposed wellbore, including all adjacent wellbores within 200 feet of any portion of the proposed well; and Please refer to Attachment 1: Location Maps, Attachment 6: Formation Tops and Attachment 11: Directional Plan for further details. (2) for all wells within 200 feet of the proposed wellbore: (A) list the names of the operators of those wells, to the extent that those names are known or discoverable in public records, and show that each named operator has been furnished a copy of the application by certified mail; or (B) state that the applicant is the only affected owner. The applicant is the only affected owner. 3. Blowout Prevention Equipment Information 20 AAC 25.005 (c) (3) A diagram and description of the blowout prevention equipment (BOPE) as required by 20 AAC 25.035, 20 AAC 25.036, or 20 AAC 25.037, as applicable; BOP test frequency for PTU-19 will be 14-days. Except in the event of a significant operational issue that may affect well integrity or pose safety concerns, an extension to the 14-day BOP test period should not be requested. Summary of BOP Equipment & Test Requirements Hole Section Equipment Test Pressure (psi) 14-1/2” 10-1/2” x 12-1/4” & 8-1/2”x9-1/2” x 16-3/4” x 5M Hydril GK Type Annular BOP x 16-3/4” x 10M Type U Double Ram BOP VBR top Double Gate o Blind ram in bottom cavity x 16-3/4” x 10M Single ram x 3-1/8” x 10M Choke Line x 3-1/8” x 10M Kill line x 3-1/8” x 10M Choke manifold x Standpipe, floor valves, etc. Initial Test: 250/10,000 Annular 250/5,000 Subsequent Tests: 250/8,500 rams 250/5,000 annular Primary closing unit: Control Technology Inc. (CTI), 10 station, 3,000 psi, 540 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Remote panel located in the toolpusher’s office. Please refer to Attachment 2: BOPE Equipment for further details. 4. Drilling Hazards Information Point Thomson Unit PTU-19 Producer 20 AAC 25.005 (c) (4) Information on drilling hazards, including (A) the maximum downhole pressure that may be encountered, criteria used to determine it, and maximum potential surface pressure based on a pressure gradient to surface of 0.1 psi per foot of true vertical depth, unless the commission approves a different pressure gradient that provides a more accurate means of determining the maximum potential surface pressure; 14-1/2” Intermediate Hole Pressure Data Maximum anticipated BHP 7,150 psi at TD (12.5 ppg at 11,000’ TVD) Maximum surface pressure 5,500 psi from TD surface (0.15 psi/ft gas gradient to surface) 2,958 psi gas to surface frac at shoe (0.15 psi / ft gas gradient 15.5 ppg frac at shoe) Planned BOP test pressure Rams test to 8,500 psi / 250 psi Annular test to 5,000 psi / 250 psi Formation Integrity Test 13.8 ppg EMW FIT after drilling 20’ of new hole outside of 16” Surface Casing 25.6 bbl KT based on 12.0 ppg MW 12.5 ppg Pore Pressure 16” Casing Test 3,500 psi, chart for 30 min (Test pressure exceeds gas to surface frac at shoe requirement 15.5 ppg EMW FG and 0.15 psi/ft gas gradient) 10-1/2” x 12-1/4” Intermediate Hole Pressure Data Maximum anticipated BHP 10,000 psi at the Thomson at 12,705’ TVD (15.2 ppg EMW) Maximum surface pressure 7,992 psi at the Thomson (0.158 psi/ft gas gradient to surface) Planned BOP test pressure Rams test to 8,500 psi / 250 psi Annular test to 5,000 psi / 250 psi Formation Integrity Test 16.5 ppg EMW FIT after drilling 20’ of new hole outside of 11- 7/8” 42.9 bbl based on 16 ppg MW, 15.8 ppg Pore Pressure 11-7/8” Casing Test 5,500 psi , chart for 30 min 8-1/2” x 9-1/2” Intermediate Hole Pressure Data Maximum anticipated BHP 10,040 psi at the Thomson at 12,952’ TVD (14.9 ppg EMW) Maximum surface pressure 7,992 psi at the Thomson (0.158 psi/ft gas gradient to surface) Planned BOP test pressure Rams test to 8,500 psi / 250 psi Annular test to 5,000 psi / 250 psi Formation Integrity Test 16.4 ppg EMW FIT after drilling 20’ of new hole outside of 9- 7/8” Infinite kick tolerance based on 16 ppg MW, 15.8 Pore Pressure 9-7/8” Casing Test 5,500 psi , chart for 30 min (B) data on potential gas zones; and 0.1 (0.15 psi/ft gas gradient to surface 8580 psi high approved - mgr 0.1 psi/ ft 9850 - 1270 = 8580 psi MASP 7560 psi - mgr 0.158 psi/ft gas gradient 8580 psi high 8580 - mgr From page 56 14.91 * 12705 * .052 = 9850 psi - mgr APPROVED - mgr 8660 APPROVED - MGR 0.158 psi/ft gas gradient 0.1 psi/ ft for reservoir overburden Production Hole Pressure Data From 11-7/8" casing data 15.14 PPGE Page 55 See attached email from Jacob Thompson to Mel Rixse justifying use of alternate gas gradient. SFD Point Thomson Unit PTU-19 Producer (C) data concerning potential causes of hole problems such as abnormally geo-pressured strata, lost circulation zones, and zones that have a propensity for differential sticking; Please refer to Attachment 3: Drilling Hazards 5. Procedure for Conducting Formation Integrity Tests 20 AAC 25.005 (c) (5) A description of the procedure for conducting formation integrity tests, as required under 20 AAC 25.030(f); Please refer to Attachment 4: LOT / FIT Test Procedure 6. Casing and Cementing Program 20 AAC 25.005 (c) (6) A complete proposed casing and cementing program as required by 20 AAC 25.030, and a description of any slotted liner, pre-perforated liner, or screen to be installed; Casing/Tubing Program Hole Size Tubular O.D. Tubular ID (in)Wt/Ft Grade Conn Length Top MD Bottom MD / TVD 20” 16” 14.69” 109# Q-125 TH523 4954 Surface 4,954’ / 4,510’ 14-1/2” 11-7/8” 10.711” 71.8# TN125SS TH Blue 12,473’ Surface 12,473 / 11,000’ 10.5”x 12-1/4” 9-7/8” 8.625” 62.8#C-110 SM13CS-110 TH513 SLIJ-II 1,994’ 500’~12,250’ 14,744’ /12,705’ 8-1/2” x 9-1/2” 5-1/2” Screen Shunted 4.778” 20# S13CR95 SLHT timed 1,450’ ~14,294’ 15744’ / 12,951’ Tubing 7” 6.004” 35# SM13CRS-95 VAMTOP HC 14,290’ Surface 14,290’ / 1,2478’ Please refer to Attachment 5: Cement Summary for further details. Point Thomson Unit PTU-19 Producer 7. Diverter System Information 20 AAC 25.005 (c) (7) A diagram and description of the diverter system as required by 20 AAC 25.035, unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Please refer to Attachment 2: Diverter & BOP Equipment. 8. Drilling Fluid Program 20 AAC 25.005 (c) (8) A drilling fluid program, including a diagram and description of the drilling fluid system, as required by 20 AAC 25.033; Drilling Fluid Program Summary Surface Intermediate I Intermediate II Production Hole Mud Type Drillplex Rhegaurd X Rhegaurd X Rhegaurd X Mud Properties: Mud Weight PV YP HPHT Fluid Loss pH MBT OWR (OBM Only) 9.0-10.5 ppg ALAP (10-30) 50-80 NA 10.8-11.2 < 25 10.0 – 13 ppg ALAP (10-25) 20-30 < 5 NA NA 75:25-85:15 15.5 – 16 ppg ALAP (15-28) 15-25 < 5 NA NA 75:25-85:15 15.5 – 16 ppg (ALAP, 18-28) 15-25 < 5 NA NA 75:25-85:15 ALAP- As low as possible DRILPLEX MBT levels should be maintained below 25 lb/bbl equivalent, although there are no strict guidelines for this. Drilling fluid practices will be in accordance with appropriate regulations stated in 20 AAC 25.033 unless this requirement is waived by the commission under 20 AAC 25.035(h)(2); Point Thomson Unit PTU-19 Producer 9. Abnormally Pressured Formation Information 20 AAC 25.005 (c) (9) For an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f); N/A – Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis 20 AAC 25.005 (c) (10) For an exploratory or stratigraphic test well, a seismic refraction or reflection analysis as required by 20 AAC 25.061(a); N/A – Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis 20 AAC 25.005 (c) (11) For a well drilled from an offshore platform, mobile bottom-founded structure, jack-up rig, or floating drilling vessel, an analysis of seabed conditions as required by 20 AAC 25.061(b); The PTU-19 is to be drilled from an onshore location. 12. Evidence of Bonding 20 AAC 25.005 (c) (12) Evidence showing that the requirements of 20 AAC 25.025 have been met; Evidence of bonding for Hilcorp North Slope, LLC is on file with the Commission. Point Thomson Unit PTU-19 Producer 13. Proposed Drilling Program 20 AAC 25.005 (c) (13) A copy of the proposed drilling program; the drilling program must indicate if a well is proposed for hydraulic fracturing as defined in 20 AAC 25.283(m); to seek approval to perform hydraulic fracturing, a person must make a separate request by submitting an Application for Sundry Approvals (Form 10-403) with the information required under 20 AAC 25.280 and 20 AAC 25.283; The proposed drilling program to PTU-19 is listed below. Please refer to Attachments for a Well Schematic, Formation Evaluation Program, and Wellhead & Tree Diagram. Completed Pre Rig Work 1. Install cellar / conductor summer 2025 2. Mobilize Doyon 15 to PTU August 2025 3. Spot rig over PTU-19 conductor. Perform rig modifications and commissioning prior to commencement of the surface hole drilling. 4. Build 18,000 bbl surface hole cuttings containment cell. 5. Mobilize all equipment required to complete the Surface hole. Proposed Drilling Program PTU-19 1. MIRU Doyon 15 2. MU 20” Surface hole BHA GR/RES. 3. Spud 20” surface hole and drill surface to TD below OG40 base. 4. BROOH and LD 20” surface hole BHA. 5. RU and run 16” Surface casing to TD. 6. Circulate and condition mud in preparation for Cement. 7. RU false rotary table, MU cement stab in tool. 8. RIH and stab in to float Collar 9. Circulate and condition mud prior to cement job. 10. Cement 16” Surface casing. Spacer and lead cement. Swap to tail when spacer is seen at surface. 11. Unsting from the float collar and displace the inside of the casing to OBM. OBM used for freeze protection. 12. ND Diverter, cut 16” Casing, install Slips, NU 16-3/4” Cameron Wellhead A-Section, and install night cap. 13. Pressure test 16” Casing to 250 low/3,500 high psi for 30 mins. 14. Cold stack rig and perform maintenance / rig modification as required. Await the completion of the Ice road. Wait on Ice road. Ice road completion expected 1/15/26 – 2/15/26 15. MIRU 16-3/4” 10k BOP,ND 16-3/4” night cap, NU, BOP and Beyond RCD. Test annular 5k and 5”x7” VBR upper, blind, and 5”x7” VBR lower 10k. 16. MU 14-1/2” BHA with GR/RES and mud loggers. RIH Tag float collar. 17. CBU and condition 10.0 OBM. 18. Drill shoe track + 20’ of new hole. Approved to test to MASP 3500 psi for INT_1 shoe strength. - mgr Notify AOGCC (48 hour) for opportunity to witness initial BOPE pressure test to rated working pressure. - mgr Approved to drill without diverter. - mgr See drill pipe specifications attached at end of PTD. - mgr riser Point Thomson Unit PTU-19 Producer 19. CBU, condition mud, and perform FIT / LOT. 20. Drill ahead to section TD of INTI. 21. Increase MW to 12.0 ppg by Top of EO25. Begin application of MPD monitoring pressure on connections. Monitor back ground, connection and formation gas readings. 22. Begin control drilling and drill down to ~10,000’ TVD with 12.0 ppg Static MW. Monitor pressure on connections through MPD choke and trend drilled and connection gas. a. Track trend levels of BG (background gas), CG (connection gas) and FG (formation gas). 23. Increase MPD back pressure to maintain > 12.2 ppg BHP on connections to ~10,700’ TVD or when BG increases 2-3 time above established levels. a. Trend connection gas, drilled gas, and whether connection gas is seen early at bottoms up. b. If connection gas trend is rapidly increasing or when BG increases 2-3 times the previous level increase the back pressure 0.2 ppg increments. c. Do not exceed ~11,330’ TVD PA25 projection 24. When BHP is equal to 12.6 ppg and BG and CG are approaching previously determined trend of 2-3 times normal. Perform wellbore cleanup cycle. 25. With wellbore cleanup cycle performed conduct a flow check with 12.6 ppg BHP. 26. Weight up system to 12.7 ppg EMW (Overbalance >110 psi.) 27. Flow check well and confirm MW. 28. BROOH to the Shoe. CBU and strip out of hole to BHA 29. Remove RCD element and LD BHA 30. Change out upper rams from 5”x7” VBR to 11-7/8” fixed bore rams and test. 31. RU and Run 11-7/8” 71.8# TN125SS Casing. 32. Circulate and condition mud, cement 11-7/8” Casing above shallowest hydrocarbon bearing zones. 33. Wait on Cement, split stack, set 11-7/8” casing slips, NU tubing spool, install and test packoff 4,500 psi (80% of collapse on 11-7/8” CSG) for 15 mins. 34. Change out upper rams from 11-7/8” fixed bore rams to 5”x7” VBR and test. 35. Pressure test 11-7/8” casing to 250 low / 5,500 high psi for 30 mins 36. MU 10-1/2” Drilling BHA with GR at-bit, GR/RES and underreamer. 37. RIH and Increase MW to 15.5 ppg. 38. Drill out shoe track and 20’ of new formation. 39. CBU, condition mud, and perform FIT/ LOT. 40. Drill ahead until underreamer is out of the casing shoe. Drop ball and activate UR. Pull test to confirm it open. 41. Drill ahead in INTII section to TD. Utilize MPD to hole 16.0-16.5 ppg back pressure on connections. 42. Drill to TD in Top Thomson Sand. Identify TD with at-bit GR. 43. Perform wellbore clean up cycle CBU and increase MW to 16.0 ppg. 44. Drop underreamer closing ball. 45. BROOH to the 11-7/8” casing shoe and CBU 46. RIH on elevators to TD. 47. Circulate bottoms up at TD and strip out of hole to the BHA. 48. Flow check the well, remove RCD, LD BHA. 49. Change out upper rams from 5”x7” VBR to 9-7/8” fixed bore rams and test. provide logs and obtain approval from AOGCC for target TOC - mgr FIT to minimum 13.8 ppg. Notify AOGCC upon completion and agreement for drilling to measured depth of INT_1. - mgr 30 minute flow monitoring before breaking containment. - mgr All fluids to be statically overbalanced to BHP.-mgr Follow appended procedure "PTU-19 14-1/2” Intermediate Hole Section TD Protocol" - mgr 12.6 ppg Casing test and LOT digital data to AOGCC for approval. - mgr Point Thomson Unit PTU-19 Producer 50. RU and Run 9-7/8” 62.8# C-110 / SM13CS-110 Liner. 51. MU Liner hanger and XO to drill pipe. 52. RIH on DP with 9-7/8” liner to TD. 53. Circulate and condition mud for the upcoming cement job. 54. Cement 9-7/8” liner, bump plug, and set LTP. Release running tool and circulate out excess cement / spacer. 55. POOH and LD liner running tool. 56. Change out upper rams from 9-7/8” fixed bore rams to 5”x7” VBR and test. 57. Pressure test 11-7/8” casing and 9-7/8” liner to 250 low / 5,500 psi high for 30 minutes. 58. MU 8-1/2” drilling BHA with GR/RES/Neu/Dens/Sonic and Underreamer 59. RIH tag float collar. 60. Displace from 16.0 ppg OBM to 15.5 ppg Production Hole OBM. 61. Drill shoe track and 20’ of new hole. Conduct FIT/LOT. 62. Drill ahead until underreamer is out of the casing shoe. Drop ball and activate UR. Pull test to confirm it open. 63. Drill ahead in INTII section to TD. Utilize MPD to hole 16.0 ppg back pressure on connections. 64. Drill to TD (1,000’ of open hole, or when cemented section of Thomson is encountered.) 65. Drop underreamer closing ball and mad pass to the shoe for caliper data. 66. CBU at 9-7/8” Shoe. 67. Strip out of hole holding backpressure with MPD to the BHA. 68. Flow check the well, remove RCD, LD BHA. 69. MU wellbore cleanout BHA. 70. RIH to TD. CBU and condition mud. 71. Spot Filtered OBM from TD to 500’ above the 9-7/8” shoe. 72. POOH to just below the filtered OBM. Circulate and condition fluid for upcoming screen run. 73. Once the OBM is conditioned for the screen run strip OOH to the BHA. 74. Flow check the well, remove RCD element and LD BHA. 75. Clean and clear floor for lower completion installation. 76. RU and run 5-1/2” 20# S13Cr95 2x2 shunted gravel pack screens and gravel pack packer. 77. MU false rotary table and run Inner string / wash pipe. MU combo tool and attach to lower completion. 78. RIH with lower completion to TD. 79. Set gravel pack packer and pressure test 5,500 psi. Release combo tool from packer and perform circulation tests. 80. Pump Gravel pack and displacement pills till screen out. 81. Reverse out gravel and displacement fluids 82. POOH to Fortress valve and shift close. 83. PT fortress valve 4,000 psi (Fortress rated for 6k differential) 84. POOH and lay down running tools. 85. MU Cleanout BHA and RIH and displace to 15.7 ppg ZnBr2 completion brine. 86. POOH lay down Cleanout BHA. 87. RIH with 5-1/2” Intermediate completion. 5,500 psi high for 30 minutes All fluids to be statically overbalance to BHP. - mgr Approved to test to test presure of 5500 (11-7/8" casing. ) End PTD step 70.Spot Filtered OBM from TD to 500’ above the 9-7/8” shoe. 72. POOH to just below the filtered OBM. Circulate and condition fluid for upcoming screen run. 73. Once the OBM is conditioned for the screen run strip OOH to the BHA. 74. Flow check the well, remove RCD element and LD BHA. 75. Clean and clear floor for lower completion installation. 76. RU and run 5-1/2” 20# S13Cr95 2x2 shunted gravel pack screens and gravel pack packer. 77. MU false rotary table and run Inner string / wash pipe. MU combo tool and attach to lower completion. 78. RIH with lower completion to TD. 79. Set gravel pack packer and pressure test 5,500 psi. Release combo tool from packer and perform circulation tests. 80. Pump Gravel pack and displacement pills till screen out. 81. Reverse out gravel and displacement fluids 82. POOH to Fortress valve and shift close. 83. PT fortress valve 4,000 psi (Fortress rated for 6k differential) 84. POOH and lay down running tools. 85. MU Cleanout BHA and RIH and displace to 15.7 ppg ZnBr2 completion brine. 86. POOH lay down Cleanout BHA. 87. RIH with 5-1/2” Intermediate completion. Email casing test and FIT (to 16.4 ppg) digital data to AOGCC. - mgr GR/RES/Neu/Dens/Sonic - Separate 10-403 to be submitted and approved for all completion operations starting at step 71. - mgr production hole Separate 10-403 Point Thomson Unit PTU-19 Producer 88. RIH Stab 5-1/2” intermediate seal assembly into lower completion seal bore. PT lower seal to 4,000 psi. PT upper Seal to 4,000. Set latch and release running tool. 89. POOH and lay down running tool. 90. RU and Run 7” 35# S13Cr95 upper completion. 91. Stab upper completion into SBR. Space out upper completion and land tubing in the tubing head. Terminate control lines and Iwire. 92. Pressure test tubing to 250 psi low / 4,000 psi high 30 mins. Test IA to 250 psi low / 4,000 psi high 30 mins 93. Install TWC. Test TWC to 250 low / 10,000 psi 5 mins. 94. ND BOP, NU and pressure test tree 250 low / 10,000 psi 5 mins. 95. RDMO Doyon 15. Post Rig Work Slickline/Fullbore 1. PT PCE to 250 psi low, 9500 psi high. 2. Pull BPV. 3. Pull DGLV, set Flowsleeve. 4. Circulate TxIA to diesel. 5. Pull Flowsleeve, Set DGLV. 6. MIT-T to 8000 psi target pressure, 8800 psi max pressure. 7. CMIT-TxIA to 8000 psi target pressure, 8800 psi max pressure. 8. Open Fortress Valve with pressure signal. a. Contingent: EL/Tractor/Stroker open Fortress valve if pressure signal fails to open 9. Well Tie In. 10. Put Well on Production. Note: This well will not be fracture stimulated Separate 10-403 88. RIH Stab 5-1/2” intermediate seal assembly into lower completion seal bore. PT lower seal to 4,00 0 psi. PT upper Seal to 4,000. Set latch and release running tool. 89. POOH and lay down running tool. 90. RU and Run 7” 35# S13Cr95 upper completion. 91. Stab upper completion into SBR. Space out upper completion and land tubing in the tubing head. Terminate control lines and Iwire. 92. Pressure test tubing to 250 psi low / 4,000 psi high 30 mins. Test IA to 250 psi low / 4,000 psi high 30 mins 93. Install TWC. Test TWC to 250 low / 10,000 psi 5 mins. 94. ND BOP, NU and pressure test tree 250 low / 10,000 psi 5 mins. 95. RDMO Doyon 15. Post Rig Work Slickline/Fullbore 1. PT PCE to 250 psi low, 9500 psi high. 2.Pull BPV. 3. Pull DGLV, set Flowsleeve. 4. Circulate TxIA to diesel. 5. Pull Flowsleeve, Set DGLV. 6. MIT-T to 8000 psi target pressure, 8800 psi max pressure. 7. CMIT-TxIA to 8000 psi target pressure, 8800 psi max pressure. 8. Open Fortress Valve with pressure signal. a.Contingent: EL/Tractor/Stroker open Fortress valve if pressure signal fails to open 9.Well Tie In. 10.Put Well on Production. Note: This well will not be fracture stimulated Point Thomson Unit PTU-19 Producer 14. Discussion of Mud and Cuttings Disposal and Annular Disposal 20 AAC 25.005 (c) (14) A general description of how the operator plans to dispose of drilling mud and cuttings and a statement of whether the operator intends to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. Due to the remote location a temporary cutting storage pit will be constructed at PTU west pad. Surface hole drilled cuttings, water based drilling fluid, and cement returns will be stored in the cuttings containment cell. Once the ice road is complete the cuttings will be transferred and disposed of at the Prudhoe G&I on DS4. Once the ice road is completed drilling mud and cuttings will be hauled offsite as it is generated via truck. If considered necessary, liquids may be injected into the PTU-DW1 well. It is more likely that that DW-01 would only be used to dispose of clear fluids. There is no intention to request authorization under 20 AAC 25.080 for any annular disposal operation in the well. 15. Proposed Variance Request 20AAC25.35 Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements.h) (2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter is not necessary A diverter vent line variance is requested for the PTU-19 surface hole section. Hilcorp has conducted internal risk assessments and determined that the risk of needing to use a diverter is negligible and operationally could pose an increased HSE risk. PTU-19 surface hole is surrounded by 4 existing surface holes at the PTU Central Pad location. Additionally, PTU-16 and PTU-03 have surface TD locations ~600’ and 1300’ away, see the diagram below. 23 wells have been drilled in the Point Thomson Unit over the last 55 years with no signs or indications of shallow free gas above the OG75 to surface. There are 19 Exploration and Appraisal wells and 4 development wells. The shallowest hydrocarbon bearing zones encountered in the Point Thomson Unit are in the Brookian at 6,600’ TVD. This is significantly deeper than the PTU-19 surface casing point. W-Staines-01 is the shallowest tested brookian sand, which made trace oil at –10,512 SSTVD. However, mudlog and log shows below the Mikkelsen marker have indicated tar to a shallowest depth at Central Pad of –6,827 sstvd in PTU-03. The presence of tar could suggest the migration of mobile hydrocarbons through the area at some point in time and could still be a risk if depth uncertainty were a greater concern. PTU-03 did not encounter any productive hydrocarbon bearing zones until entering the Thomson sand at –12,659 sstvd. PTU-16 is our closest offset well, for the surface hole section. It also did not contain any productive hydrocabon zones until entering the Thomson sand at –12754 sstvd. PTU-16 did contain elevated gas readings, minor fluorescence, and cuts in siltstones and shales at –7946 sstvd. Siltstones and shales are considered to be non-productive rocks and formation tests in these intervals were bypassed at the time of drilling. To remain conservative, we chose the Mikkelsen as the top of the hydrocarbon bearing zone. Still, all of the above zones are considerably deeper than the planned surface hole TD of -4469 SSTVD. The objective of the surface casing point is to drill the 20” hole section to the predominately silty / shaley interval below the base of the OG40 and above the top of the OG75. This is the equivalent stratigraphic section where surface casing was set in PTU-15, PTU-16, PTU-DW1, and PTU-17. During this time period, there have been zero well control events above the OG75 formation. There is very low structural uncertainty and a high confidence with the OG40 and OG40 base markers given the proximity and number of wells already drilled in the area. The area properly calibrated, fully and continuously functioning, recording, and monitored while drilling from spud to surface casing point. SFD Requested Diverter Variance approval recommended as long as all gas-monitoring equipment is Point Thomson Unit PTU-19 Producer around Central Pad is covered by 3D seismic data that is of adequate quality without gaps and obvious noise trains or shallow velocity anomalies. At the projected surface hole TD we expect the seismic to have a minimal depth uncertainty of +/-45’. The close proximity to PTU-03 and PTU-16 further de-risk the seismic depth uncertainty. There are no observed faults in the vicinity of this hole section for the PTU-19 well. The second closest offset well, PTU-3, set surface casing at a shallower depth. PTU-3 drilled the interval next to PTU-19’s casing point with a full logging suite as well as mud logging. PTU-3’s mud log shows minimal total gas readings from surface to the OG75, and no productive hydrocarbon zones in the overburden. The closest offset well, PTU-16, also drilled the interval next to PTU-19's casing point with mud logs from 152’-TD. PTU-16's mud log shows minimal total gas readings and no hydrocarbon shows from cuttings from surface to the OG75. PTU-19 surface casing will be set immediately after the OG40 base is identified on GR. This is to ensure a good shale for the subsequent Intermediate I FIT / LOT integrity. Hydrates have not been encountered on offset wells, but Hilcorp will implement drilling practices to effectively manage any hydrates encountered while drilling surface hole as follows: (1) Mitigate breakout potential: keep mud temperature cool, no extended circulation at any point in the well, optimized drilling and tripping strategies (2) Identify hydrates (i.e. bubbles in the flow both with no signs of pit gain or flow from the well). (3) Handle hydrates at surface (i.e. utilization of degasser and isolation of gas-cut mud in the pits). (4) Drilling practices (i.e. controlling pump rates and maximizing ROP to get through a hydrate zone). Doyon 15’s current diverter line would need to be on the ground level and need to be routed beneath the flowlines and pipe racks, passing through support pilings. Using a diverter will increase HSE risk associated with putting them in place. With the multiple well penetrations at the PTU Central Pad, no free gas above the OG75, the strong geologic understanding, and low structural uncertainty, combined with the increased HSE risks and challenges of running a larger diverter line, it is requested that a diverter variance for PTU-19 be granted. Point Thomson Unit PTU-19 Producer Point Thomson Unit PTU-19 Producer 20 AAC 25.033.(b)(1)(A) Primary well control for drilling: drilling fluid program and drilling fluid system. (a) A drilling operation must be equipped with a drilling fluid system meeting the requirements of this section, unless the commission determines that a drilling fluid system is not necessary for primary well control. The operator shall submit with an application for a Permit to Drill (Form 10-401) a proposed drilling fluid program and a diagram with a list of equipment for a drilling fluid system designed to prevent the loss of primary well control. The drilling fluid system must be designed to maintain the wellbore in overbalanced condition except as otherwise provided under (i) of this section. A drilling operation is also subject to the requirements of 20 AAC 25.527. (b) A drilling fluid program and drilling fluid system intended to maintain the wellbore in overbalanced condition must be designed to provide and maintain (1) a drilling fluid (A) of sufficient density to overbalance the pressure of uncased formations penetrated; and (B) with rheological properties designed to (i) minimize the potential of a hydrostatic pressure surge or swab when the drilling assembly is run into or pulled out of the wellbore; and (ii) enhance the drop-out of solids and the escape of entrained gas; and A variance is requested for the requirement to have a static fluid column as the primary barrier during a discrete portion of the Intermediate I drilling operation. A combination of hydrostatic pressure and choke pressure will be used to provide overbalance while drilling to TD in the Intermediate I hole sections. The technique is called Managed Pressure Drilling. The MPD system will be used to apply surface pressure back pressure to keep the open hole formation in an overbalanced state. In the event an influx occurs it is to be circulated out per conventional well kill protocols through the BOPE, not thorough the MPD system. MPD equipment: x MPD Dual Choke o MPD Control Consol o Coriolis Flowmeter x MPD Remote Control Panel x RCD Body x RCD Bearing assembly with Sealing Elements x Various piping and isolation valves. MPD layout: Attached Planned Overbalance while drilling: 100 -180 psi Maximum expected choke pressure (static fluid column): 12.0 ppg MW, 12.5 ppg reservoir pressure at 11,000’ TVD (TD), 12.7 ppg bottom hole pressure. Influx management: Rig crew to monitor flow and pit levels per standard operations. Rig crew to shut in per standard operations (no change to standing orders). Any influx will be managed conventionally. Use of the Coriolis flow meter enhances kick detection, with increased accuracy of return flow and density readings when compared to conventional methods. In addition, mud loggers will be trending gas readings at surface, flow back on connections, and cuttings characteristics to help identify signs of abnormal pressure. The application of backpressure can be immediately applied through the automated choke allowing an influx to be stopped while the standard shut in orders are carried out, as opposed to allowing the well to flow until the BOPE are functioned. Application of MPD is industry recognized as a enhancement in well control response as compared to conventional overbalanced drilling practices. Rig crew training: MPD awareness only. Additional driller responsibility to notify the MPD technician of a Maximum expected choke pressure (static fluid column): 12.0 ppg MW, 12.5 ppg reservoir pressure at 11,000’ TVD (TD), 12.7 ppg bottom hole pressure. mud loggers will be trending gas readings at surface, flow back on connections, and cuttings characteristics to help identify signs of abnormal pressure. Point Thomson Unit PTU-19 Producer change in pump rate. This is a courtesy notification as the system will automatically increase back pressure when the pump is shut down. On the job training, as the first ~5,000’ of the Intermediate I hole section will be drilled with overbalanced fluid. MPD will only be used to conduct drills and hone operational efficiencies, to build crew competency. Weekly kick while drilling drills while using the MPD system will be conducted including, RCD failure, Choke Washout, flow / pit increase, and float string failure. Point Thomson Unit PTU-19 Producer Attachment 1: Location & GIS Maps Point Thomson Unit PTU-19 Producer Attachment 2: BOPE EquipmentDoyon 15 Rig BOP ArrangementsINTI / INTII Production / Completion Point Thomson UnitPTU-19 ProducerDoyon 15 Rig Choke Manifold Schematic Point Thomson UnitPTU-19 ProducerDoyon 15 / Beyond MPD Process Flow Diagram There are no 16-3/4” Annular Preventors that are rated for 10,000 psi, so a 5,000 psi Annular Preventor has been sourced for PTU-19. The following measures will be put in place for use of the 5,000 psi annular preventor on the PTU-19 well. 1. Initial shut in procedures will specify that the 10,000 psi pipe rams be shut in on the tubular in the hole as the first response. a. Where applicable, safety joint will be readily available to crossover to the tubular being run to drill pipe that fits the ram configuration. 2. If stripping into the hole is required, the surface pressure will not exceed the rated working pressure of the annular. In the event surface pressure is approaching the rated working pressure. Operations will cease, the pipe rams will be closed, and the influx will be removed with BOPE rated to withstand the pressure. Once the influx is removed, and surface pressure is below 5,000 psi the annular preventer may be used again to strip into the well. 3. The Annular preventer will be tested to full rated working pressure of 5,000 psi on each BOP test. Doyon 15 has a 7,500 psi standpipe pressure rating for its circulating system. The 7,500 psi standpipe pressure rating will have sufficient surface pressure rating to handle most drilling well control scenarios. A cementing unit will be stationed on location in the event a scenario should arise that requires a higher pressure rating than the rig can offer. The SLB cementing unit and accompanying hardline will be equipped with 10,000 psi surface pressure rating. SLB cementing unit and accompanying hardline will be equipped with 10,000 psi surface pressure rating 7,500 psi standpipe pressure rating Point Thomson Unit PTU-19 Producer Attachment 3: Drilling Hazards 20” Surface Hole Section Hazard Mitigations Hole Cleaning AVs are low in surface hole due to the large hole diameter and desire to reduce mud temperature while drilling. Utilizing a thixotropic fluid and maintaining tight viscosity parameter will aid in successfully cleaning the hole. Running Gravels Offset wells have experienced running gravels. Utilize thixotropic mixed metal oxide (MMO) drilling fluid with improved suspension capabilities. Inadvertent sidetracking in the Permafrost Utilize a staged approach to work tight spots while running in the hole in the permafrost. Do not ream into the hole unless it is a last resort. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight. Pack Off During Cementing Clean up well bore at TD, and prior to running casing. Stage circulation rates up following circulation schedule circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Keep circulation rates below drilling ECDs, model accordingly, low displacement rates. 14-1/2” Intermediate I Hole Section Hazard Mitigations Hole Cleaning Maintain rheology of mud system, 6 rpm value greater than hole diameter. Maintain flow rates of 200 ft/min AV, 120 rpm. Do not out drill ability to clean the hole. Montior ECD trends reduce ROP if signs are seen of insufficient hole cleaning. Lost Circulation / Breathing Each offset development well has experienced losses in the Intermediate hole. Losses have not been experienced while drilling, but rather while running and cementing casing. Cement objectives have been achieved despite the losses. While drilling MPD will be used to minimize pressure fluctuations and overall ECDs. During casing running limit the speed to mitigate surge losses. Have cement bond log ready for deployment in case the losses are experienced. Utilize flat rheology mud to reduce surge pressure and mud temperature affects. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations – MPD to maintain CBHP. Follow MW recommendations from Geomechanics work. One Way Casing Trip Pick up weights for the 11-7/8” casing run will exceed rig capability causing the trip to be one way. Ensure optimal hole conditions prior to running the 11-7/8” casing. Monitor PU trends prior to one way trip point to determine if TD can be reached. Pack Off During Cementing Clean up well bore at TD, and prior to running casing. Stage Point Thomson Unit PTU-19 Producer circulation rates up following circulation schedule Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Keep circulation rates below drilling ECDS, model accordingly, low displacement rates. Well Control / Drilling Close to Pore Pressure Intermediate I casing point will be selected based on a response to the pore pressure. Nearing TD the well will be drilled with a MW < pore pressure, and require application of surface back pressure through the MPD choke. Mud logging readings will aid in determining when to increase BHP to maintain overbalance. KWF will be on location and readily available to weight up at TD (>1 ppg over static MW). Upon the detection of pit gain the surface back pressure will be increased to maximum safe operating limit. If an influx is identified the rig’s normal shut in procedure will commence closing the BOP. Any influx will be circulated out via the conventional well control equipment. 10-1/2” x 12-1/4” Intermediate II Hole Section Hazard Mitigations Hole Cleaning Maintain rheology of mud system, 6 rpm value greater than hole diameter. Maintain flow rates of 200 ft/min AV, 120 rpm. Do not out drill ability to clean the hole. Pump sweeps as needed. Montior ECDs Lost Circulation / Breathing Monitor ECD with MWD tools. Monitor active mud system and flow back with mud loggers. Pump LCM as needed. Ensure adequate LCM is available, follow lost circulation decision tree, Do not drill into Thomson any further than necessary. Stuck Liner Underreamed hole section, sufficient wellbore clean up, pinned float shoe, circulation schedule while RIH, monitor drag trends Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations – MPD to maintain CBHP Shale Stability Hole section will cross multiple shale formations. Directional plan and MW have been chosen based upon historical stability window. MPD to maintain CBHP to minimize pressure cycling, swab pressures. Ensure sufficient MW is left in the well at TD based on geomechanics report. Pack Off During Cementing Clean up well bore at TD, and prior to running casing. Stage circulation rates up following circulation schedule Circulate bottoms up at multiple depths to condition mud the way in the hole. Circulate at TD to planned cementing rates and ensure hole is clean. Keep circulation rates below drilling ECDS, model accordingly, low displacement rates Gas Cut Mud Gas cut mud has been seen. Ensure sufficient MW is used during hole section. Mudloggers to monitor gas trend and flowback at and monitor wells and MPD while drilling and on connections. Nearing TD the well will be drilled with a Do not drill into Thomson any further than necessary Gas cut mud has been seen MW < pore pressure Well Control / Drilling Close to Pore Pressure KWF will be on location and readily available to weight up at TD (>1 ppg over static MW) Point Thomson Unit PTU-19 Producer Ensure gas detectors are tested and functioning. Watch swab effect while TOOH Abnormal Pressures The Thomson reservoir’s pore pressure is 14.9-15.4 ppg EMW. Offset pressure data is well understood. Pore pressures as high as 15.8 ppg have been experienced in tight sand stringers above the Thomson sand at PTU. Overbalanced drilling fluid and MPD will be used to maintain well control in this section. 8-1/2” x 9-1/2” Production Hole Section Hazard Mitigations Lost Returns Monitor ECD with MWD tools. Have adequate LCM and sufficient fluid available. Monitor reservoir properties to avoid drilling into the Pre-Mississippian formation below the Thomson where losses have occurred on offset wells. Faulting No faults are mapped in the planned well path. Hole Swabbing Reduce tripping speed, lower mud rheology, offset swab with MPD, pump out of the hole if required. Abnormal Pressures The Thomson reservoir’s pore pressure is 14.9-15.4 ppg EMW. Offset pressure data is well understood. Pore pressures as high as 15.8 ppg have been experienced in PTU. Overbalanced drilling fluid and MPD will be used to maintain well control in this section. Tight Hole/Stuck Pipe Conduct wiper trip if required, drilling jars included in BHA, monitor torque and drag trends, use sufficient mud weight / back- pressure to hold back formations. Anti Collision PTU-3 See Close Approaches in Directional Plan attachment. Continually monitor surveys for magnetic interference. PTU-3 is P&A’d well that is acting as the geological well control. The close approach to PTU-3’s P&A’d production section poses no HSE risks. Shale / Wellbore Instability Maintain adequate mud weight / back-pressure for wellbore stability. Monitor cuttings returns, LWD logs, and drilling. Production hole should not encounter any shale, but use of MPD to minimize pressure cycles on formation and prevent collapse. PTU Central Pad has a history of H2S. Ensure detectors are tested and functioning. x AOGCC to be notified withing 24 hours if H2S is encountered more than 20 ppm during drilling operations x Rig will have fully functional automatic H2S detection equipment meeting the requirements of 20 AAC 25.066 x In the event H2S is detected, well work will be suspended and personnel evacuated until a detailed mitigation procured can be developed. PTU H2S History: There are no wells with over 100ppm H2S readings at PTU Central Pad. Trace amounts of H2S have been detected at the first stage separator but no appreciable reading have been detected. PTU-15 & PTU-16 history of H2S H2S measures are required. H2S mitigation procedures must be developed and provided to AOGCC in advance of drilling operations. SFD In the event H2S is detected, well work will be suspended and personnel evacuated until a detailed mitigation procured can be developed reservoir’s pore pressure is 14.9-15.4 ppg EMW Pore pressures as high as 15.8 ppg have been experienced in PTU reservoir’s pore pressure is 14.9-15.4 ppg EMW Pore pressures as high as 15.8 ppg have been experienced in tight sand stringers above the Thomson sand Point Thomson Unit PTU-19 Producer have measured H2S in reservoir in the ranges of 4-30 ppm, but these wells have been in continuous injection. PTU-3 the closes offset wellbore measured trace amounts of H2S while being flow tested. Attachment 4: LOT / FIT Test Procedure measured H2S in reservoir in the ranges of 4-30 ppm Pump rate for FIT/LOT must be held at a steady rate. - mgr Point Thomson Unit PTU-19 Producer Attachment 5: Cement Summary 16” Surface Casing Cement OH x CSG 20” OH x 16” Casing Basis Cement Vol Open hole volume + excess + 85’ ft shoe track TOC Surface Total Cement Volume Spacer 150 bbls of 10.5 ppg Tuned Spacer Cement Lead: 11.0 ppg Deepcrete 1284.2 bbls, 7210.6 ft^3, 3775.2 sks, 1.91 ft^3/sk Tail: 15.8ppg class G 122.6 bbls, 688.5 ft3, 558.5 sks 1.17 cuft/sk BHST 80 deg F 11-7/8” Intermediate Casing Cement OH x CSG 14-1/2” OH x 11-7/8” Casing Basis Cement Vol Open hole volume + excess + 85’ ft shoe track TOC 250’ TVD above shallowest HC. Nearest offset well did not see shallow HC, but there is a potential to encounter some. Total Cement Volume Spacer 80 bbls of 13.25 ppg Tuned Spacer Cement Lead: 13.5 ppg Ext lead,465.4 bbls 2613.3ft^3, 1528.2 sks Tail: 15.8ppg G,53.2 bbls, 298.7 ft3, 257.5 sks BHST 198 deg F 16" 109# CASING to float collar 0 4954 4954 0.208 1031.9 Shoe track length 4869 4954 85 0.208 17.7 TAIL LENGTH 4454 4954 500 0.140 69.9 TAIL EXCESS 50%35.0 LEAD TOP TO BASE OF PERMA 1827 4454 2627 0.140 367.5 EXCESS FACTOR FOR ABOVE 50%183.7 PERMAFROST ANNULUS(Lead)128 1827 1699 0.140 237.7 EXCESS FACTOR FOR ABOVE 200%475.3 CASED HOLE ANNULUS 46 128 82 0.243 19.9 TOP BOTTOM LENGTH CAPACITY VOLUMEDescription 589 (~1.71 ~1.16) SFD Point Thomson Unit PTU-19 Producer 9-7/8” Liner Cement OH x CSG 12-1/4” Underreamed OH x 9-7/8”” Liner Basis Cement Vol CH volume +Liner Lap + excess + 85’ ft shoe track TOC Liner Top Total Cement Volume Spacer 30 bbls of 11.0 ppg Tuned Spacer Cement Tail: 18 ppg Denscrete 160.6 bbls,901.6 ft3, 1048.4 sks, 0.86 cuft/sk BHST 230 deg F 9-7/8" Liner to L/C 12250 14744 2494 0.07227 180.2 Shoe track length 14659 14744 85 0.07227 6.1 TAIL LENGTH 12473 14744 2271 0.05105 115.9 TAIL EXCESS 30%34.8 LEAD LENGTH 12250 12473 0 0.05105 0.0 LEAD EXCESS 30%0.0 Liner Lap 11-7/8" x 9-7/8" LNR 12250 12473 223 0.01672 3.7 PTU-19 9-7/8" INT II CEMENT JOB Description TOP BOTTOM LENGTH CAPACITY VOLUME See attached email for corrected volume and density. Attachment 6: Prognosed Formation Topsi"(F«">[I"[IFi[i@´aIb϶a[϶a³϶iaa(b>((>((@@@@ÍČÍŽÍĲĖŘħťĺħ͐͏͐͒ ͔͘͘®ÍťôŘϱŜťϱē ͗ϟ͔ ͗ϟ͔ ͐͏ôŘıÍċŘĺŜťώÍŜô ͐͗͒͗ ͖͕͐͐®ÍťôŘ ͗ϟ͔ ͗ϟ͔ ͐͏i@͓͏ ͓͒͑͐ ͓͒͐͘®ÍťôŘϱŜť ͗ϟ͔ ͗ϟ͘ ͐͏i@͓͏ώÍŜô ͓͘͏͑ ͓͓͐͑®ÍťôŘŜťϱē ͗ϟ͔ ͘ϟ͑ ͐͏i@͖͔ ͔͏͑͑ ͓͔͔͐®ÍťôŘ ͗ϟ͔ ͘ϟ͖ ͐͐ϟ͓(i͐͏ ͕͕͓͖ ͔͐͘͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͗ϟ͔ ͘ϟ͖ ͐͐ϟ͓aĖħħôīŜôĲώĺĲČŪô ͖͖͐͐ ͕͗͑͒®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͗ϟ͔ ͘ϟ͖ ͐͐ϟ͓(i͔͑϶i ͑͑͑͘ ͗͐͑͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͗ϟ͔ ͘ϟ͖ ͐͐ϟ͓(i͔͑϶i϶a͐ ͐͏͏͓͐ ͗͗͏͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͗ϟ͔ ͐͏ ͐͐ϟ͓(i͔͑϶i϶a͑ ͐͏͔͖͘ ͒͘͏͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͗ϟ͔ ͐͐ ͐͐ϟ͓(i͔͑϶aI"϶a͐ ͓͐͐͑͐ ͗͒͘͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͐͏ϟ͐ ͐͑ ͐͑ϟ͕(i͔͑϶aI"϶a͑ ͔͐͑͗͑ ͐͐͏͔͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͐͏ϟ͒ ͐͑ϟ͘ ͐͒ϟ͕͔͑ώÍīīÍſÍƅ͖͕͐͑͗ ͐͐͒͒͐®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͐͏ϟ͕ ͐͒ϟ͒ ͓͐ϟ͔͐͑϶ÍīīÍſÍƅ϶ÍĲî ͐͒͗͐͏ ͐͑͐͒͏®ÍťôŘϯFώĺŜŜĖæīô ϱŜťϱē ͐͑ϟ͐ ͓͐ϟ͘ ͔͐ϟ͘aÍƄώŕĺŘôώŕŘôŜŜŪŘôŜώæÍŜôîώĺĲώϱ͖͐ťôťēĺŜèĺŕôώŕŘôŜŜŪŘôŜϟώ@ôĺīĺČĖŜťĖĲťôŘŕŘôťŜώŜÍĲîώĲĺťώŕŘôŜôĲťώÍťώϱ͔͐͘͏ ͓͕͐͐͑ ͔͕͐͑͒®ÍťôŘϯFώĺŜŜĖæīô ē ͐͑ϟ͒ ͔͐ ͔͐ϟ͘F¾aÍŘħôŘ ͓͔͐͘͏ ͔͖͔͐͑®ÍťôŘϯFώĺŜŜĖæīô ē ͔͐ϟ͐ ͔͐ϟ͘ ͕͐ϟ͖ĺŕώēĺıŜĺĲώÍĲî ͓͖͓͓͐ ͕͔͐͑͑@ÍŜ ͓͐ϟ͘ ͔͐ϟ͓͔͐ϟ͖ÍŜôώēĺıŜĺĲώÍĲî b ͓͐͑͒͘ ͓͐ϟ͗ ͔͐ϟ͐ ͔͐ϟ͔͒͐ϟ͔͐͘ϟ͘aÍƄώŕĺŘôώŕŘôŜŜŪŘôŜώæÍŜôîώĺĲώϱ͖͐@ôĺīĺČĖŜť͕͐ϟ͖ĖĲťôŘŕŘôťŜώŜÍĲîώĲĺťώŕŘôŜôĲťώÍťώϱ͐͘ PPFG – Hilcorp / Merlin PTU-19 PPFG. Attachment 7: Well Schematic Attachment 8: Formation Evaluation Program 20” Surface Hole LWD Gamma Ray Resistivity 14-1/2” Intermediate I Hole LWD Gamma Ray Resistivity At-bit Gamma 10-1/2” x 12-1/4” Intermediate II Hole LWD Gamma Ray Resistivity At-bit Gamma 8-1/2” x 9-1/2” Production Hole LWD Gamma Ray Resistivity Density Neutron Sonic Mudlogging Standard mudlogging service from INTI – Production including: x Mudlogging daily report x Drilling data LAS Time x Drilling data LAS Depth x total gas detection C1-nC5 x Mudlog x Drillinglog x Gaslog x Sample Catching w/microscope pictures. Gas-monitoring equipment must be calibrated and fully and continuously functioning and recording during all drilling operations from spud to total depth of this well. Mud logging equipment and services must be calibrated and fully and continuously functioning and recording during all drilling operations from surface casing shoe to total depth of this well. SFD Point Thomson Unit PTU-19 Producer Attachment 9: Wellhead Diagram Point Thomson Unit PTU-19 Producer Attachment 10: Management of Change Point Thomson Unit PTU-19 Producer Attachment 11: Directional Plan Production Section Offset Wells with CF < 1.0: x PTU-19 SF<1.0 at 14,900 as it drills past PTU-3 and into Pt. Thomson Res. PTU-19 SF reduces to ~0.5 then increases above 1.0 by 15,500' MD. The entire interval of potential collision is cemented or has a cement retainer between intervals. The potential collision point's pore pressure will be controlled with the planned mud weight. The presence of cement and retainers in the offset wellbore reduces the risk of lost circulation at the collision points. PTU-3 is an exploration well drilled in late 1977. The well was plugged and abandoned after well testing. PTU-3 used primitive directional tools therefore its error ellipse is very large. PTU-3’s center to center distance is 190.7’ at the closest point. The entire interval of potential collision is cemented or has a cement retainer between intervals ! ""# ! $ %& # -1250 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000True Vertical Depth (2500 usft/in)-1250 0 1250 2500 3750 5000 6250 7500 8750 10000 11250 12500 13750 15000 16250 Vertical Section at 67.54° (2500 usft/in) PTU-19 T2 16" x 20" 11-7/8" x 14-1/2" 9-7/8" 12-1/4" 5-1/2" x 9-1/2" 500 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 6 0 0 0 6 5 0 0 7 0 0 0 7 5 0 0 8 0 0 0 8 5 0 0 9 0 0 0 9 5 0 0 1 0 0 0 0 1 0 5 0 0 1 1 0 0 0 1 1 5 0 0 1 2 0 0 0 1 2 5 0 0 1 3 0 0 0 13500 1400014500 1 5 0 0 0155 0015893PTU-19 wp19 Start Dir 1º/100' : 534.3' MD, 534.3'TVD Start Dir 2º/100' : 1034.3' MD, 1033.67'TVD End Dir : 2349.9' MD, 2275.46' TVD Start Dir 3.5º/100' : 11865.22' MD, 10442.48'TVD End Dir : 14294.26' MD, 12480.6' TVD Start Dir 3.5º/100' : 14764.26' MD, 12715.6'TVD End Dir : 15478.55' MD, 12928.69' TVD Total Depth : 15892.86' MD, 12964.8' TVD Sagavanirktok PermFrost bse OG40 OG40 B bse OG75 EO10 Mikkelsen EO25 PA25 Callaway PA50 Hrz_marker TTHOM Hilcorp North Slope, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Plan: PTU-19 12.60 +N/-S +E/-W Northing Easting Latittude Longitude 0.00 0.00 5912921.880 468369.540 70° 10' 23.2983 N 146° 15' 16.5557 W SURVEY PROGRAM Date: 2025-06-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 41.00 1500.00 PTU-19 wp19 (PTU-19) GYD_Quest GWD 1500.00 4954.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag 4954.00 12473.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag 12473.00 14744.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag 14744.00 15892.86 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1012.60 959.00 1013.16 Sagavanirktok 1815.60 1762.00 1838.55 PermFrost bse 3967.60 3914.00 4321.40 OG40 4465.60 4412.00 4901.62 OG40 B bse 4568.60 4515.00 5021.62 OG75 5963.60 5910.00 6646.92 EO10 6876.60 6823.00 7710.65 Mikkelsen 8173.60 8120.00 9221.77 EO25 11384.60 11331.00 12875.54 PA25 Callaway 12409.60 12356.00 14160.99 PA50 12628.60 12575.00 14590.26 Hrz_marker 12705.60 12652.00 14744.26 TTHOM REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Plan: PTU-19, True North Vertical (TVD) Reference:As-Staked @ 53.60usft (Doyon 15) Measured Depth Reference:As-Staked @ 53.60usft (Doyon 15) Calculation Method: Minimum Curvature Project:Point Thompson - ASPZ3 Site:PTU Central Pad Well:Plan: PTU-19 Wellbore:PTU-19 Design:PTU-19 wp19 CASING DETAILS TVD TVDSS MD Size Name 4510.56 4456.96 4954.00 16 16" x 20" 11000.00 10946.40 12473.13 11-7/8 11-7/8" x 14-1/2" 12705.80 12652.20 14744.66 9-7/8 9-7/8" 12-1/4" 12964.80 12911.20 15892.86 5-1/2 5-1/2" x 9-1/2" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 41.00 0.00 0.00 41.00 0.00 0.00 0.00 0.00 0.00 2 534.30 0.00 0.00 534.30 0.00 0.00 0.00 0.00 0.00 Start Dir 1º/100' : 534.3' MD, 534.3'TVD 3 1034.30 5.00 70.00 1033.67 7.46 20.49 1.00 70.00 21.78 Start Dir 2º/100' : 1034.3' MD, 1033.67'TVD 4 2349.90 30.87 92.37 2275.46 13.19 418.64 2.00 26.15 391.92 End Dir : 2349.9' MD, 2275.46' TVD 5 11865.22 30.87 92.37 10442.48 -189.06 5297.17 0.00 0.00 4823.07 Start Dir 3.5º/100' : 11865.22' MD, 10442.48'TVD 6 14294.26 60.00 312.00 12480.60 648.56 5100.79 3.50 -146.33 4961.61 End Dir : 14294.26' MD, 12480.6' TVD 7 14744.26 60.00 312.00 12705.60 909.33 4811.18 0.00 0.00 4793.60 PTU-19 T2 8 14764.26 60.00 312.00 12715.60 920.92 4798.31 0.00 0.00 4786.13 Start Dir 3.5º/100' : 14764.26' MD, 12715.6'TVD 9 15478.55 85.00 312.00 12928.69 1373.14 4296.06 3.50 0.00 4494.77 End Dir : 15478.55' MD, 12928.69' TVD 10 15892.86 85.00 312.00 12964.80 1649.32 3989.34 0.00 0.00 4316.83 Total Depth : 15892.86' MD, 12964.8' TVD -1050-700-350035070010501400175021002450South(-)/North(+) (700 usft/in)-350 0 350 700 1050 1400 1750 2100 2450 2800 3150 3500 3850 4200 4550 4900 5250 5600 5950 6300West(-)/East(+) (700 usft/in)PTU-19 T216" x 20"11-7/8" x 14-1/2"9-7/8" 12-1/4"5-1/2" x 9-1/2"2505007 5 0100 012501500 175020002250250027503000325035003750400042504500475050005250550057506000625065006750700072507500775080008250850087509000925095009750 100001025010500 1 0 7 5 01100011250115001175012000 12250125001275012965PTU-19 wp19Start Dir 1º/100' : 534.3' MD, 534.3'TVDStart Dir 2º/100' : 1034.3' MD, 1033.67'TVDEnd Dir : 2349.9' MD, 2275.46' TVDStart Dir 3.5º/100' : 11865.22' MD, 10442.48'TVDEnd Dir : 14294.26' MD, 12480.6' TVDStart Dir 3.5º/100' : 14764.26' MD, 12715.6'TVDEnd Dir : 15478.55' MD, 12928.69' TVDTotal Depth : 15892.86' MD, 12964.8' TVDCASING DETAILSTVDTVDSS MDSize Name4510.56 4456.96 4954.00 16 16" x 20"11000.00 10946.40 12473.13 11-7/8 11-7/8" x 14-1/2"12705.80 12652.20 14744.66 9-7/8 9-7/8" 12-1/4"12964.80 12911.20 15892.86 5-1/2 5-1/2" x 9-1/2"Project: Point Thompson - ASPZ3Site: PTU Central PadWell: Plan: PTU-19Wellbore: PTU-19Plan: PTU-19 wp19WELL DETAILS: Plan: PTU-1912.60+N/-S +E/-W Northing EastingLatittudeLongitude0.00 0.005912921.880 468369.54070° 10' 23.2983 N146° 15' 16.5557 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: PTU-19, True NorthVertical (TVD) Reference: As-Staked @ 53.60usft (Doyon 15)Measured Depth Reference:As-Staked @ 53.60usft (Doyon 15)Calculation Method:Minimum Curvature ' # $ ( " # ) *+ ) , ,- .(# /! !""# " $ %&'()"* +,-&. +0 / +-$ /+ ) $ %&'()"* +,-&. ! ) 0 " / ($ 1 +$ ' / & ($+$ 12+34 " . , 12+ ,5 5 . $ ) ! # 60 * 66 * 2 $ " " 0 ( !0 30 1# .0 "* ! "* "* 7)'18 9:( & 1(8')1) 8(;(8'))) &')) 2)7)<1)'82;) 8(7&<;'(&&10 , , " 0 " 30 !0 "* 435, 4 5 ( "* "* "* 1 ". "* "* )')) )')) & 1 1';;) 8(;( '&8) 1'(),!3. 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!""# " $ %&'()"* +,-&. +0 / +-$ /+ ) $ %&'()"* +,-&. ! ) 0 " / + ! 6)8 : 678 %;$! 678 435, 6)8 / !0 6)8 / 30 6)8 4 5 6)8 .( * + ! 6)8 *+ ) +" >= * 2)))')) )';2 (1(('(& ;&'(& 1;)1'2( 1'2 822'(8)& 1;18'&18(1')&)'))) 1&&2'8) 2))')) )';2 (&1'8; ;2'2; 1;&8') 1'2 82111'; (& 1;11';&(1 ;';;)'))) 1()' 2 21))')) )';2 (8;' ; ' ) 1 )&') 1'2 82128'&1& 1; ';8&(;8'2)'))) 1(&)'&8 2))')) )';2 (&18'8 1') 1 &('&2 1'2 821&'8);& 1;2'&)((82)'&8 )'))) 1( 2' 28))')) )';2 (() ' 2 8'& ))2';8 1'2 822('((& 1;&'(((&&('2 )'))) 128'(; 2&))')) )';2 (( &';) ('1; )& ' 1'2 82812' & 1;1';12((81'1))'))) 12 )'1& 2())')) )';2 (2;'( ;'8) )'; 1'2 8282 '2&& 1;)'8;2(21;'))'))) 1;(';1 22))')) )';2 (;(2'8( ))'& ('(& 1'2 82&)'8& 1;);'82(;';()'))) 1;;'; 22)'(& )';2 (;2('() ))'2& (2' 1'2 82&&';;;& 1;)2'; ;(;1')))'))) 1;;;'8 /BB 2;))')) )';2 ( &'1 )1'(& 11' 1 1'2 82&;'(;2& 1;)&';);(; '( )'))) 1 1 ' & 2 ))')) )';2 2) '1 )8'2; 1(8' 1'2 82(1' 8& 1;)'8(;( ;&'&1 )'))) 1 2('&1 ;)))')) )';2 218' & )(' ) &'8( 1'2 82(;8' & 1;)'1 2)2'&)'))) )1') ;))')) )';2 21)'2; ) ') (('2 1'2 822&'8&&& 12 ;'2; 2&2';)'))) )( '(( ;1))')) )';2 21 ('( '( 8;')) 1'2 822;('2& 12 ('8&)218'))'))) ('1 ;))')) )';2 2;1'88 '1; 8( '12 1'2 82;2' (2& 12 8')21;';8 )'))) (1';) ;8))')) )';2 28(;'12 &'8 &1)'&8 1'2 82;; '111& 12 '22288'(2 )'))) 1) '( ;&))')) )';2 2&&8') 2'& &2'; 1'2 82 8)'82;& 12; '82&))'&))'))) 1&&' ;())')) )';2 2( ' '(( (1'); 1'2 82 '28& 12;2') 12&;(')'))) )1'&) ;2))')) )';2 221&'2( 1'2; (28'& 1'2 821)81' )& 12;8'2&12(21'()'))) 8 ')2 ;;))')) )';2 2;'& 1' 21&'(1 1'2 821) 8'18(& 12;1'822&2' )'))) &'(8 ; ))')) )';2 2; 2'8 1(') 22(' ) 1'2 8218&'&)1& 12;)')22;8';)'))) 881'1 )))')) )';2 2 ;'1( 1;'( ;1;'2 1'2 821 ('2&;& 1222'282 1 '(()'))) 8;;'2; ))')) )';2 ;)( ') )'1; ;2 '88 1'2 82118;')8& 122&' 8;)&'8 )'))) &&'& 1))')) )';2 ;&8' 1 1'8 )'2 1'2 8211 '12)& 122')&&;)'1 )'))) &;' 11'22 )';2 ;2'() 1';2 8';2 1'2 821)'812& 1221'&8&;1)')))'))) & 1')& 39 ))')) )';2 ;18)'2& 8'&8 ;' ; 1'2 821&)'&1(& 122)'2&;;2'&)'))) (1;'8; 8))')) )';2 ;1('&; ('(( 8)'1& 1'2 8218)'2;& 12(;'2(;121' ;)'))) (2&')& &))')) )';2 ;81'8 ;'2 8);8'&1 1'2 8218&')2& 12((')(;&;';)'))) 21'(1 ())')) )';2 ;8 ;'18 8)' 8&'2 1'2 821&)8'1 & 12('( 2;888'(8 )'))) 2(;' 2))')) )';2 ;&;8')2 8')8 8;2')( 1'2 821&&&'&8 & 12('&2;&)'82 )'))) ;8'2( ;))')) )';2 ;(( ' ) 8&'( 81;' 1'2 821()(';)&& 12& ');;(('))'))) ;(' ))')) )';2 ;2&&'2 82'1 81; '() 1'2 821(&;')(& 12&('(2;;2)1')'))) )2'; ))))')) )';2 ;;8'&( 8 '8 88)';2 1'2 8212) '2& 12&8' ;2;2' ()'))) &8'8( )))')) )';2 ; 12' &'&8 8 1'8 1'2 8212()'&2& 12&' ;;2'2 )'))) 8))') )1))')) )';2 )'11 &'(( 888'8 1'2 821;';1 & 128 '((); & '(1 )'))) 8)82'() )))')) )';2 ) ')& &&'2 88 8'(; 1'2 821;(');&& 1282'1) )8&'8&)'))) 8) 8'2 )8))')) )';2 ;8';; &2' 1 8&8&' & 1'2 821 8'8)& 1288' ;) '1;)'))) 88)'28 )&))')) )';2 12)'2 ()')8 8& 2'11 1'2 821 (&'& (& 1281'(8 12')'))) 8;2' )())')) )';2 &('&8 (1'2 8(8;'8 1'2 82)(';&1& 128)') )1' 8 )'))) 81';2 )2))')) )';2 881'2 (8'1 8( '2( 1'2 82)(;');& 122' (1 ;;'22 )'))) 81;)'88 );))')) )';2 &1;'1) (('81 82&') 1'2 82 '(8& 12&'(11 828'())'))) 812') ) ))')) )';2 (8') (;'&8 8;)1') 1'2 822)'(1)& 12'1; &()'8)'))) 82'&; )))')) )';2 ( ';( 2)'(2 8;&'&2 1'2 8211';2(& 12)' 8 (8('1()'))) 881)'& ' # $ ( " # ) *+ ) , ,- .(# /! 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eparation Factor0 900 1800 2700 3600 4500 5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100Measured Depth (1800 usft/in)PTU-03PTU-15PTU-16No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Plan: PTU-19 NAD 1927 (NADCON CONUS) Alaska Zone 0312.60+N/-S +E/-W Northing EastingLatittudeLongitude0.000.005912921.880 468369.540 70° 10' 23.2983 N 146° 15' 16.5557 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Plan: PTU-19, True NorthVertical (TVD) Reference: As-Staked @ 53.60usft (Doyon 15)Measured Depth Reference:As-Staked @ 53.60usft (Doyon 15)Calculation Method:Minimum CurvatureSURVEY PROGRAMDate: 2025-06-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool41.00 1500.00 PTU-19 wp19 (PTU-19) GYD_Quest GWD1500.00 4954.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag4954.00 12473.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag12473.00 14744.00 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag14744.00 15892.86 PTU-19 wp19 (PTU-19) 3_MWD+AX+Sag0.0030.0060.0090.00120.00150.00180.00Centre to Centre Separation (60.00 usft/in)900 1800 2700 3600 4500 5400 6300 7200 8100 9000 9900 10800 11700 12600 13500 14400 15300 16200 17100Measured Depth (1800 usft/in)PTU-15PTU-16PTU-DW01GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference41.00 To 15892.86Project: Point Thompson - ASPZ3Site: PTU Central PadWell: Plan: PTU-19Wellbore: PTU-19Plan: PTU-19 wp19CASING DETAILSTVD TVDSS MD Size Name4510.56 4456.96 4954.00 16 16" x 20"11000.00 10946.40 12473.13 11-7/8 11-7/8" x 14-1/2"12705.80 12652.20 14744.66 9-7/8 9-7/8" 12-1/4"12964.80 12911.20 15892.86 5-1/2 5-1/2" x 9-1/2" Max FG Shoe Depth TVD Gas Gradient BHP max MASP SF Casing Test ppg TVD (ft)psi/ft psi psi psi psi 15.5 4510 0.15 3635 2959 500 3459 Pore Pressure TD INT1 Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 12.5 11000 0.15 7150 5500 Casing Burst 50% burst psi psi 8970 4485 Comments: PTU-19 Casing and Liner Pressure Testing 16", 109#, Q125, TH523 Surface Casing 50% casing internal Yield Surface Casing Governed by Fracture Gradient at Shoe Gas to Surface. Casing Test Pressure of 3,500 psi satisfies MASP + SF of 500 PSI Fracture at Shoe Gas Gradient to Surface Gas to surface Surface Casing Page 54 6050 0.1 psi/ft 3184 Is this alternate gas gradient valid for this hole section? Variance approved to allow surface casing pressure test to 3500 psi. - Cannot assume Point Thomson reservoir gradient for overburden. Utilize 0.1 psi/ft - Does not meet 50% of burst. See email for Hilcorp justification to test to 3500 psi. 2750.1 Max FG Shoe Depth TVD Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 20 11000 0.158 11440 9702 Pore Pressure TD INT1 Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 15.14 12705 0.158 10000 7993 Casing Burst 50% burst psi psi 10720 5360 MW Reference Depth Pore Pressure External Pressure Test Pressure Internal Test Pressure Differential Pressure SF ppg TVD (ft)ppg psi psi psi psi psi/psi 16 8173 8.3 3540 5500 12300 8760 1.22 13 8400 8.6 3756 6500 12178 8422 1.27 8.5 43 8.6 19 8500 8519 8500 1.26 16 8400 8.3 3639 6500 13489 9850 1.09 Comments: The Intermediate I Casing test will be governed by the 50% internal pressure. A test pressure of 5,500 psi will be sufficient to meet regulations. The Casing test can be taken as high as 6,000 psi without exceeding the burst SF. Note 6500 psi surface pressure brings the SF <1.1 for the 11-7/8" casing string. Gas to surface Internal Yield Pressure Fracture at Shoe Gas Gradient to Surface 11-7/8", 71.8#, TN125SS, TH Blue Intermediate I Casing 50% casing internal Yield 15.14 * .052 * 11,000' = 8660 8660 - 1100 = 7560 psi - mgr - Cannot assume Point Thomson reservoir gradient for overburden. Utilize 0.1 psi/ft - mgr 11,000' Intermediate 1 Page 55 Max FG Shoe Depth TVD Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 20 12705 0.158 13213 11206 Pore Pressure TD INT1 Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 14.91 12952 0.158 10039 7993 Casing Burst 50% burst psi psi 12530 6265 MW Reference Depth Pore Pressure External Pressure Test Pressure Internal Test Pressure Differential Pressure SF ppg TVD (ft)ppg psi psi psi psi psi/psi 16 11000 12.0 6864 5500 14652 7788 1.61 16 12705 12.5 8258 5500 16071 7812 1.60 16 12705 14.9 9844 7750 18321 8477 1.48 8.5 43 8.6 19 8500 8519 8500 1.47 Comments: 9-7/8", 62.8#, C-110 / SM13CRS-110 TH 513 / SLIJ-II Intermediate II Liner Gas to surface 50% casing internal Yield Internal Yield Pressure Fracture at Shoe Gas Gradient to Surface The Intermediate I Casing test will be governed by the 50% internal pressure. A test pressure distributing 6,500 psi of differential across the liner will meet the 50% criteria. A surface pressure test of 5500 psi will give more than 6500 psi of differential across the entire 9-7/8" liner. Intermediate I casing tested to 5500 psi which is lower burst to Intermediate II liner of 50% burst. Approved to test to 5500 psi. 12705 0.1 psi/ft 9850 8580 - mgr 0.1 psi/ft gas gradient required for overburden. 14.91 * 12705 * 0,052 = 9850 psi BHP at TD INT_2 0.1 * 12705 = 1270 psi MASP = 9850- 1270 = 8580 psi mgr INT2 Intermediate II Intermediate 2 Page 56 Max FG Shoe Depth TVD Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 20 12952 0.158 13470 11424 Pore Pressure TD base res Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 14.91 12952 0.158 10039 7993 50% casing internal Yield Tubing Burst 50% burst Valve Rating 70% Diff psi psi psi psi 11830 5915 6000 4200 MW Reference Depth Pore Pressure Below Fortress Test Pressure Above Fortress Differential Pressure SF ppg TVD (ft)ppg psi psi psi psi psi/psi 15.7 12705 15.1 10000 4000 14372 4372 1.37 16 12705 15.1 10000 4000 14571 4571 1.31 MW Reference Depth External Tubing Test Pressure Internal Tubing Differential Pressure SF 15.7 12705 N/A 10372 8000 18372 8000 1.48 16 12705 8.6 10571 8500 19071 8000 1.48 Comments: 7", 35#, SM13CRS-95 Vam Top HC Tubing Fracture at Shoe Gas Gradient to Surface Gas to surface The tubing will be stung into a PBR in the top of the intermediate completion. The lower completion has a fortress valve that isolates the upper and lower completions to act as a temporary barrier, as well as stop fluid losses into the gravel pack completions. The fortress valve has a differential pressure rating of 6,000 psi. The tubing, inner annulus, and fortress valve will be tested to 70% of the maximum differential pressure. Fortress Isolation Valve Pressure Rating Internal Yield Pressure Reservoir gas gradient of 0.158 approved. - mgr 10-403 required for Completion Operations MASP for production hole lower than INT2. Max FG Shoe Depth TVD Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 20 12952 0.158 13470 11424 Pore Pressure TD base res Gas Gradient BHP max MASP ppg TVD (ft)psi/ft psi psi 14.91 12952 0.158 10039 7993 50% casing internal Yield Tubing Burst 50% burst Valve Rating 70% Diff psi psi psi psi 11830 5915 6000 4200 MW Reference Depth Pore Pressure Below Fortress Test Pressure Above Fortress Differential Pressure SF ppg TVD (ft)ppg psi psi psi psi psi/psi 6.8 12705 15.1 10000 8800 13292 3292 1.82 8.6 12705 15.1 10000 8800 14482 4482 1.34 MW Reference Depth External Tubing Test Pressure Internal Tubing Differential Pressure SF 6.8 12705 N/A 4492 8800 13292 8800 1.34 8.6 12705 8.6 5682 8800 14482 8800 1.34 Comments: 7", 35#, SM13CRS-95 Vam Top HC Tubing Fracture at Shoe Gas Gradient to Surface Gas to surface Fortress Isolation Valve Pressure Rating Internal Yield Pressure After the well is completed and tree installed, the tubing and inner annulus will be swapped to diesel freeze protect. With the lighter fluid in the annulus and tubing the well can then be pressure tested to MASP + SF. The maximum test pressure will be 8,800 psi allowing up to a 10% decline to stay above MASP. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Jacob Thompson To:Rixse, Melvin G (OGC) Cc:Lau, Jack J (OGC); McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Question Email - 7 Intermediate_1 cement yield - confirm Date:Friday, August 1, 2025 3:04:45 PM Attachments:image001.png Mel, My apologies for confusion. Your calculated yield of 1.71 ft3/sk for the 13.5 ppg lead, and 1.16 ft3/sk for the 15.8 ppg tail are correct. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, August 1, 2025 3:02 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Question Email - 7 Intermediate_1 cement yield - confirm Jacob, I did the arithmetic because I don’t see Hilcorp’s yield numbers for this 11-7/8” Intermediate casing. (Yield quantities appear in your other cement jobs.) Please confirm my arithmetic or point me to your numbers. I will type them in so commissioners won’t have to do the math when they review your PTD. From: Jacob Thompson <jacob.thompson@hilcorp.com> Sent: Friday, August 1, 2025 2:52 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Question Email - 7 Intermediate_1 cement yield - confirm CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. Mel, The cement yields provided in the PTD are all correct. I used the numbers provided by our venders to populate the PTD information, and have confirmed them all just now. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, August 1, 2025 2:39 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Question Email - 7 Intermediate_1 cement yield - confirm Jacob, Please confirm (my arithmetic) for cement lead yield on Int_1 as: 1.71 ft3/sx and the tail cement yield is 1.16 ft3/sx. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. PTU-19 14 ½” Intermediate Hole Section TD Protocol Objective Drill the 14 ½” hole section deep enough to attain a minimum FIT > 17.2 ppge (ECD management), for drilling of the 10-1/2” x 12-1/4” INTII section to TD. The predicted casing point is 12,473’ MD / 10,946’ TVDss. Identified Geologic Hazards x Based on the PTU-19I PPFG it is anticipated that pore pressure will begin to ramp up at ~8,120 TVDss Criteria for Picking TD in Intermediate Hole Depth uncertainty is high and confidence in well to well correlations in the abnormally pressured section is expected to be low, so a pressure hunt based on drilling parameters and well log responses will be conducted. Drilling will cease and the PTU Pressure Hunt Team, both onsite and offsite, will discuss calling TD when any one of the following criteria has been met: 1. Wellbore parameters indicate the pore pressure is approaching 12.5 ppg EMW as determined by pressure hunt drilling criteria. 2. Severe losses or other adverse wellbore conditions are encountered 3. The maximum depth to be drilled to is 11,331’ TVDss, or when the PA25 Callaway maker has been reached. Note: From the EO25 down to the anticipated section TD, the confidence in correlations with offset wells is expected to be low. Recommended Drilling and Surveillance Practices x Monitor changes in LWD GR-RES data, as well as changes in drilling parameters, particularly mud gases (background, connection, trip), that could indicate increasing formation pressure. The bit-to-LWD sensor distances are: Near bit GR: ~12’ Gamma Ray: ~37' Resistivity: ~36' Sensor distance are subject to changes in final BHA design. x Provide photos of any unusual cuttings / cavings. x Static MW is to be increased to 12.0 ppg by 9,300’ TVDss x With 12.0 ppg static MW obtain baseline gas readings while drilling ahead. x Consider no more than two real connections in the hole before circulating out. This may be reduced to 1/2 connection in the hole as indicators of increasing pore pressure are first observed. x Simulated connections and extended shutdowns are recommended when possible indications of increasing pressure are observed (see parameters to monitor below.) x If there are concerns, perform flow check and / or circulate out any drilling breaks. x As surface gas readings (connection gas, background gas, and drilled gas) increase indicating the pore pressure is approaching mud weight, increase the bottom hole pressure by applying surface back pressure through the MPD choke on connections. Surface back pressure increases will target 0.2 ppg incremental increases in bottom hole pressure (BHP). x When the BHP is equal to 12.4 ppg, and the gas readings indicate the pore pressure is approaching the BHP, increase the mud systems static mud density to 12.5 ppg EMW. x Drill to section TD holding 12.6 ppg BHP with a static MW of 12.5 ppg. Monitor surface gas readings to determine when PP approaches the 12.6 ppg BHP. o While drilling down to TD perform simulated connections at a minimum of every 30’ TVD drilled to limit potential of pore pressure increases. x Once TD is confirmed perform an extended flow check with 12.6 ppg EMW BHP. After completion of the flowcheck increase MW to 12.7 ppg prior to POOH. PTU-19 14 ½” Intermediate Hole Section TD Protocol Note: At any time, the onsite pressure surveillance team can request drilling be stopped to check flow. If circulating bottoms up is recommended, they will inform the rig supervisor Parameters to Monitor x Gas Units: o Background Gas (BGG) – Liberated during drilling, signifies gas bearing zone. o Connection Gas (CG) – Consistent relative increases may signify nearing MW/PP balance. o Trip Gas (TG) – Increases in gas entering hole when pumps are off may indicate static MW nearing PP. o Short Trip Gas (STG) – Same as above x LWD conductivity: Looking for consistent relative decrease in measurement x Lithology: Change to a higher porosity/permeability lithology that has the potential to flow if underbalanced. x Torque and Drag: Increases could indicate wellbore instability, due to insufficient MW x Cuttings: Looking for relative change in amount, size and / or shape of cuttings coming across shakers, i.e. increase in size, splintered or propeller shape. x Flowline Temperature In/Out: Abnormal increase in flowline temperature out could indicate formation fluid flow into wellbore. x Flowline Chlorides In/Out: Increase in chlorides coming out compared to what is going in, is an indication of brine formation water flow into wellbore. x Fill on Connections: Increased bottom fill at connection may signify borehole instability when mud pumps are off, i.e. static MW + MPD back pressure is nearing PP. Onsite Team x Company Man: Onsite team leader. x Wellsite Geologists: Plot and interpret parameters, maintain correlation with offsets, and QC of LWD and mud logging data. x Rig Site Drilling Engineer: Plot and interpret parameters, maintain correlation with offsets, QC of drilling mechanics. Distribute progress reports as necessary. x Mudlogger: Measure and record gas, ROP, lithology, and other abnormal pressure parameters. Notify onsite team of sudden changes in monitored parameters. x MWD Engineer: Prepare MWD/LWD logs x Directional Driller: Plan BHA's to place the LWD as close to the bit as possible allowing for the required directional control. x Toolpusher: Support Drilling Superintendent by leading the rig crews (safety, equipment maintenance, alertness, etc.). x Driller: Rig floor leader. Maintain constant WOB/RPM and be alert to drill breaks (flow checks) and wellbore conditions. Work with the MWD engineer to avoid washouts in the unlogged portion of the hole while circulating. x Shaker Hand: Maintain surveillance of the flowline during trips and connections (flow) and of the cuttings size and volume while drilling (pressured shale). x MPD Choke Operator: Monitor return flow (micromotion), choke function, MPD choke back pressure and communicate with rig team during ramp up and down on connections. Offsite Team x Drilling Manager: Offsite Management x PTU Drilling Engineer: Communicate with onsite drilling personnel and offsite Operations Geologist. x PTU Operations Geologist: Review/interpret parameters obtained from the field and communicate with Wellsite Geologists, , Drilling Engineer(s), and PTU Subsurface Team. Manage subsurface management interactions. Communication PTU-19 14 ½” Intermediate Hole Section TD Protocol x Depth adjustments will be communicated to Drilling from the Operations Geologist. The Operations Geologist will communicate changes in drilling parameters from Drilling to the PTU Subsurface team. x All town support staff will maintain availability during pressure hunt and have open communication with the rig team. x PTU Drilling Engineer will decide when casing point has been reached, after consultation with all relevant personnel. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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:Jacob Thompson To:Rixse, Melvin G (OGC) Cc:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] PTU 19 PTD 225-078 Densecrete tuned spacer Date:Thursday, August 28, 2025 2:07:15 PM Attachments:image001.png Mel, The planned density of the mud push spacer is 17.0 ppg and volume will be 60 bbls. Sorry for the error on the PTD. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, August 21, 2025 12:26 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: [EXTERNAL] PTU 19 PTD 225-078 Densecrete tuned spacer Jacob, I am checking to see if this spacer is actually 11.0 ppg. Would this underbalance to pore pressure after turning the corner? Also, AOGCC is going to require a kill string during the operations shutdown after drilling surface hole. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907- 793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Bryan The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Jacob Thompson To:Rixse, Melvin G (OGC) Cc:Lau, Jack J (OGC); McLellan, Bryan J (OGC); Boman, Wade C (OGC) Subject:RE: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Questions Email - 2 (Justification for utilizing an alternate gas gradient) Attachments:image001.png Mel, The measured wet gas gradient from PTU-17 has a range from 0.138 psi/ft to 0.165 psi. This is from historical observed SITP and downhole pressure gauge data on PTU-17. A gradient of 0.16 psi/ft has been consistently used for other sundry applications and is in line with observations from the field. The MASP documented in the PTU-19 PTD is consistent with what has been documented on the only production well PTU-17. Thanks, Jacob Thompson Hilcorp Alaska, LLC Senior Drilling Engineer Jacob.Thompson@hilcorp.com Cell: 907-854-4377 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, July 25, 2025 4:33 PM To: Jacob Thompson <jacob.thompson@hilcorp.com> Cc: Lau, Jack J (OGC) <jack.lau@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Boman, Wade C (OGC) <wade.boman@alaska.gov> Subject: [EXTERNAL] RE: PTD 225-078 Point Thomson Unit PTU 19 Questions Email - 2 (Justification for utilizing an alternate gas gradient) Jacob, Please provide justification for utilizing gas gradients > 0.1 psi/ft. If I am missing your discussion, please provide the page where you have this discussed. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Lau, McLellan, Boman Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. Gas measurements must be recorded from spud to total depth of this well. Mud log must be recorded from surface casing shoe to total depth of this well. SFD PTU 19 PT THOMSON THOMSON OIL 225-078 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:PTU 19Initial Class/TypeDEV / PENDGeoArea890Unit11606On/Off ShoreOnProgramDEVWell bore segAnnular DisposalPTD#:2250780Field & Pool:PT THOMSON, THOMSON OIL - 668150NA1 Permit fee attachedYes Surface Location lies within ADL0047559; Top Prod Int & TD lie within ADL0047558.2 Lease number appropriateYes3 Unique well name and numberYes4 Well located in a defined poolYes PT THOMSON, THOMSON OIL - 668150 - governed by CO 7195 Well located proper distance from drilling unit boundaryNA Closely approaches to existing well Pt Thomson Unit 3 (P&A'd).6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes 24" 190# set to 120'18 Conductor string providedYes 16" 109# Q-125 set to 4510' TVD19 Surface casing protects all known USDWsYes Fully cemented surface casing20 CMT vol adequate to circulate on conductor & surf csgNo21 CMT vol adequate to tie-in long string to surf csgYes LWD logs will be submitted to assure all hydrocarbon zones isolated22 CMT will cover all known productive horizonsYes23 Casing designs adequate for C, T, B & permafrostYes Doyon 15 has adequate tankage and will have ice road support during BOPE drilling24 Adequate tankage or reserve pitNA Grass roots well. Not a sidetrack25 If a re-drill, has a 10-403 for abandonment been approvedYes Halliburton collision scan identifies no close approaches with HSE risk PTU-3 abandoned26 Adequate wellbore separation proposedYes Diverter waiver request approved based on offset well data27 If diverter required, does it meet regulationsYes Fluids to be statically overbalanced when not circulating. MPD to monitor pore pressure on INT128 Drilling fluid program schematic & equip list adequateYes 10,000 psi stack. Initial test to 10K then tested to MASP of 8580 psi29 BOPEs, do they meet regulationYes 10,000 psi stack. 1 annular test to 5000 psi, 3 ram tested to 8580 psi bi-weekly30 BOPE press rating appropriate; test to (put psig in comments)Yes See 10K psi Choke manifold drawing in PTD31 Choke manifold complies w/API RP-53 (May 84)Yes Planned 3 month shutdown after drilling surface hole, then drill to TD32 Work will occur without operation shutdownNo Not expected but monitoring will be required. No wells >100 ppm at Pt Thomson33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)No H2S measures required: H2S is present in Thomson reservoir.35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.442 to 0.826 psi/ft (8.5 to 15.9 ppg EMW). Operator's planned36 Data presented on potential overpressure zonesNA mud program appears sufficient to control most likely expected pressures and maintain wellbore37 Seismic analysis of shallow gas zonesNA stability. Maximum expected pressure range is 0.519 to 0.868 psi/ft (10 to 16.7 ppg EMW)38 Seabed condition survey (if off-shore)NA Operator's planned mud program appears sufficient to control maximum expected pressures so39 Contact name/phone for weekly progress reports [exploratory only]ApprSFDDate8/7/2025ApprMGRDate9/30/2025ApprSFDDate10/1/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDatelong as Managed Pressure Drilling techniques (MPD) are continuously utilized for the intermediate and production sections of this well. SFD*&:JLC 10/2/2025