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Home My WebLink About193-118MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:31 Township:9N Range:12W Meridian:Seward Drilling Rig:Rig Elevation:Total Depth:10280 ft MD Lease No.:ADL 0017595 Operator Rep:Suspend:X P&A: Conductor:24"O.D. Shoe@ 586 Feet Csg Cut@ Feet Surface:18 5/8"O.D. Shoe@ 2054 Feet Csg Cut@ Feet Intermediate:13 3/8"O.D. Shoe@ 5917 Feet Csg Cut@ Feet Production:9 5/8"O.D. Shoe@ 10257 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet SS Tubing:3 1/2"O.D. Tail@ 7908 Feet Tbg Cut@ Feet LS Tubing:3 1/2"O.D. Tail@ 9775 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Long String Fullbore Bridge plug 10,113 ft 4989 ft 14 ppg Wireline tag Short String Fullbore Bridge plug 10,113 ft 4708 ft 14 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing 2151 2077 2032 1997 IA 2151 2077 2032 1997 OA 400 410 405 400 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Brad Whitten Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): LS cement tag at 4989 ft MD including the correction of 41 ft. SS cement tag at 4708 ft including the correction of 41 ft. Cement in both samples was good cement. 1.9 bbls in and 1.7 bbls back on the MIT-IA. The OOA= 20 psi for the entire test. The OOOA= 50 for the duration of the test as well. August 24, 2025 Guy Cook Well Bore Plug & Abandonment MGS ST 17595 Baker-29 Hilcorp Alaska LLC PTD 1931180; Sundry 324-550 None Test Data: F Casing Removal: rev. 3-24-2022 2025-0824_Plug_Verification_MGS_State_17595_Baker-29_gc                           1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, August 7, 2025 10:48 AM To:Casey Morse Cc:Juanita Lovett; Dan Marlowe Subject:RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, Good plan. Hilcorp has approval to proceed per the procedure below. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <casey.morse@hilcorp.com> Sent: Thursday, August 7, 2025 8:25 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: Re: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Typo in the text below. Step 5 has a 44 bbl displacement. From: Casey Morse <casey.morse@hilcorp.com> Sent: Thursday, August 7, 2025 8:12 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: Re: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Bryan, I want to be sure we close the loop on this program and the conditions of approval regarding pressure limitations. Below is additional detail on the proposed pump schedule and the associated pressures through each step. During the diagnostics, we had approximately 400 psi of pump pressure to circulate around the well, so these calculations assume 400 psi of differential from LS to IA / LS to SS when we circulate these volumes. This should be the upper end of the observed pressures, since we'll have hydrostatics working in our favor to help circulate the cement volumes. 2 Below are the pump stages we're proposing. The detailed steps are slightly different from the sundried steps, and this should give us some additional flexibility through the job: 1. Start pumping cement down LS until the LS is full while taking returns out the IA. SS is closed and building pressure. The volume pumped will be 70 bbls. 2. Return 102 bbls up the IA. After 70 bbls of cement are pumped in step 1, measure the IA returns and pump enough cement in step 2 to get 102 bbls of returns from the IA. a. Calculations are based on IA cement top at ~5,800' TVD. 3. Close IA. Open SS. Measure returns and pump enough cement to get 26 bbls returned up the SS. a. Calculations are based on SS cement top at ~5,000' TVD 4. Close SS. Increase pump pressure to inject 103 bbls into the perfs. Max pressure shown below is 1,000 psi on LS. We would need to hold approximately 2,250 psi on the IA and 2,100 psi on the SS to maintain the cement columns with this injection pressure. 1,000 psi pump pressure puts the bottomhole pressure just below 0.9 psi/ft at the top perf. a. I'd like to keep the pressures below 1,000 psi as shown below during this step if possible. If the injection rate slows to less than approximately 0.5 bpm, we could try stepping above the frac gradient to see if injectivity improves. b. For an absolute limit, I propose 1,250 psi pump pressure, which would put approximately 2,500 psi on the IA. This limitation would provide a safety factor below the burst pressure of the 13-3/8" casing in the event of a failure on the 9-5/8" string. c. If injectivity still declines to sustained rates below approximately 0.5 bpm, continue on to step 5. 5. Open IA, swap to 9.8ppg brine, and pump the 61 bbl displacement while taking returns up the IA. 6. Equalize the pressure across the 3 sides and let the cement set up without any applied surface pressure. Approx Start Pressures Approx End Pressures Stage Start Vol End Vol LS IA SS LS IA SS 1 - 70 400 - - 400 1,660 2,060 2 70 172 400 1,660 2,060 400 1,267 2,060 3 172 198 400 1,667 1,660 400 1,492 1,092 4 198 301 1,000 2,267 2,092 1,000 2,267 2,092 5 301 345 400 1,267 1,492 400 - 400 6 345 345 - - - Thank you, Casey Morse Operations Engineer Cook Inlet Offshore Hilcorp Alaska, LLC (907) 777-8322 3 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, June 4, 2025 4:45 PM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Thanks Casey. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, June 4, 2025 2:32 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com>; Wyatt Rivard <wrivard@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Bryan, CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 4 We do not have equipment available to flow back the LCM from this well. To your other question, the max pressure noted in the cementing steps of 1,000psi would only apply to the injection pressure on the Long String with a full column of 14 ppg cement in the LS. That would keep us below the frac gradient in an attempt to distribute the cement as much as possible across the open perfs. Casey Morse Operations Engineer Cook Inlet Offshore Hilcorp Alaska, LLC (907) 777-8322 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, May 29, 2025 4:06 PM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, I’m working to get this sundry approved. Could you answer my question in the email below max injection pressure. The injectivity test achieved 0.85 bpm @ 2275 psi. If that pressure is reached and injection rate is very low, then consider increasing above frac pressure to ensure as much cement as possible gets bullheaded into the perfs. Also, is it feasible to flow back some of the LCM material in an attempt to improve injectivity into the perfs? Is the jet pump still functional? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 5 Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: McLellan, Bryan J (OGC) Sent: Wednesday, March 26, 2025 5:12 PM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, Based on the results of the temperature log, it’s fair to say that at least most of the bullheaded fluids will be injected into the perfs and not into a shallower casing leak. The temperature is falling as cold seawater is pumped down the IA past the temperature gauge which was stationed in the long string just above the pump attached below along with the job log. The procedure step 2.iv in the sundry application has a max injection pressure limit of 1000 psi. See my initial question #1 at the bottom of this email chain and let me know if the injection pressure limits need to be modified, and also specify which surface pressure has the pressure limit, either the IA, Short String or Long String. I think you should be clear about what max pressure to apply while squeezing into perfs before swapping returns back up the IA. I can edit the sundry application as needed. 6 7 Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 2, 2024 2:22 PM 8 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions That is correct. The spent charges and det cord will still be inside the tubing tail on these designs. Casey From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, October 2, 2024 10:44 AM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Thanks for all that info. One other question about the wellbore configuration. It looks like tubing conveyed guns are hung off the end of the LS tubing and remain in the well. I assume there is not a thru-bore inside those guns and there’s no ability to run CT or slickline through them even if the fill was cleaned out of the LS? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 9 Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 2, 2024 7:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Bryan, We will pump a higher-pressure injection test on this well prior to cementing to confirm expected rates and pressures for the squeeze. We might be able to pump that today. My plan was to stay below the frac pressure to create more even distribution of the cement. We can certainly push past that to target a set amount of cement squeeze volume if you’re comfortable with that approach. The test above should give us some clarity on this too. The procedures are somewhat confusing with how the volumes are spelled out. The squeeze would be 91 bbls, then drop the wiper ball, then continue squeezing into the perfs while we’re pushing the displacement volume of 44 bbls down the LS. So, the effective squeeze volume would still be 135 bbls, but 44 of those bbls would be squeezed in with 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. 10 the 9.8 displacement pushing the cement down. I’ll discuss this with our WSM to make sure that’s clear to him before the job. We can certainly grab some stabilized pressures after cementing like you suggested. Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777-8322 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 1, 2024 5:21 PM To: Casey Morse <Casey.Morse@hilcorp.com> Subject: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, A few questions about the sundry application: 1. In the “Procedural steps section, 3rd bullet, part (i), it says “If perfs lock up before all cement volume is pumped, swap to 9.8 ppg brine for LS displacement and take cement returns up IA.” What LS tubing pressure would you consider to indicate the perfs are locked up? At the end of the document, it says not to exceed 1000 psi surface pressure with a full column of cement, but need to be clear which surface pressure your talking about because with 14 ppg to surface in long string and 9.8 ppg brine to 5000’ md in IA, your IA pressure would be 1000 psi without even pumping. I don’t see any reason not to exceed frac pressure in cased hole since the goal is to push cement past the LCM and into the perfs. Is there a reason to limit your pressure below frac pressure? 2. The pre-rig diagnostics indicate you can’t inject into the perfs with 730 psi over 9.8 ppg brine. Are you planning to do a test with increased injection pressure to confirm you can get cement down below the ported sub? 3. In the same section, second bullet, part (iv), why not pump the full volume to bottom perf of 135 bbls? You are only planning to pump 91 bbls below the ported sub. What’s the basis for 91 bbls? CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 11 4. After the cement job is in place and pumps shut down, please report all surface pressures. The LS, SS and IA should all be approximately balanced, and if not, you can estimate TOC in IA based on the imbalance in the pressures. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. 12 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. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 10,280 N/A Casing Collapse Structural Conductor Surface Intermediate 1,950psi Production 4,760psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Casey Morse Contact Email:Casey.Morse@hilcorp.com Contact Phone:(907) 777-8322 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10/8/2024 3-1/2" (LS & SS) N/A & N/A N/A & N/A 10,257' Perforation Depth MD (ft): 5,917' 8,005 - 9,751 10,257' 7,657 - 8,783 9,173'9-5/8" Surf 32" 24" 18-5/8" Surf 13-3/8"5,917' 2,054' MD 3,450psi 586' 2,054' 5,863' 586' 2,054' Length Size Proposed Pools: 83' 83' L-80 (LS & SS) TVD Burst 7,908 (SS) 9,775 (LS) 6,870psi STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017595 193-118 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20454-00-00 Hilcorp Alaska, LLC MGS ST 17595 29 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY N/A Middle Ground Shoal MGS Oil N/A 9,192 9,775 8,801 1,409psi 9,775 B No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:13 pm, Sep 24, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.09.24 13:40:52 - 08'00' Dan Marlowe (1267) 324-550 See attached conditions of approval X 10-407 A.Dewhurst 26SEP24 -bjm DSR-9/27/24 5/31/2030 X BJM 6/5/25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.05 15:02:58 -08'00'06/05/25 RBDMS JSB 061025 MGS St 17595-29 (PTD 193-118) Suspension Sundry 324-550 Conditions of Approval 1. Variance to 20 AAC 25.112(c)(1)(D) to perform a downsqueeze without a cement retainer or production packer is approved with the following conditions: a. Cement retarder should allow for extra time required to bullhead cement into ŕôŘċŜϙÍťϙÍϙīĺſϙŘÍťôϟϙϙIĲĤôèťĖŽĖťƅϙĖĲťĺϙŕôŘċŜϙſÍŜϙ͏ϟ͔͗ϙæŕıϙЬϙ͖͔͑͑ϙŕŜĖϠϙŽôŘĖƱôîϙťĺϙ be injecting below the KOBE pump with a temp probe stationed just above the KOBE pump, indicating èĺīîϙƲŪĖîϙŕÍŜŜĖĲČϙťēôϙťôıŕϙŕŘĺæôϙſēĖīôϙĖĲĤôèťĖĲČϟϙϙ Minimum of 103 bbls of cement bullheaded below the KOBE pump is the regulatory minimum. b. ĺĲƱŘıϙıÍƄĖıŪıϙŕŘôŜŜŪŘôϙĺĲϙťŪæĖĲČϙÍĲîϙIϙſēĖīôϙæŪīīēôÍîĖĲČϙèôıôĲťϙĖĲťĺϙ ŕôŘċŜϙæÍŜôîϙĺĲϙťēôϙîôĲŜĖťƅϙĺċϙƲŪĖîŜϙĖĲϙťēôϙIϙÍĲîϙťŪæĖĲČϙîŪŘĖĲČϙťēôϙèôıôĲťϙ job. Send calculations for basis of max injection pressure and obtain approval from AOGCC before pumping cement. c. Record ŕĺŜťϙèôıôĲťϙŜēŪťϙĖĲϙ[ϯϯIϙŕŘôŜŜŪŘôŜϙťĺϙèĺĲƱŘıϙèôıôĲťϙĖŜϙ approximately in balance before it hardens and include pressures in the 10- 404. 2. Provide 48 hrs notice for AOGCC opportunity to witness TOC tag in LS & SS and pressure test of cement to 1915 psi. Oil Zone P&A Program Well: Ba-29 Well Name: MGS ST 17595 29 (Ba-29) API Number: 50-733-20454-00-00 Current Status: Shut-In Producer Rig: SL, FB, cement Estimated Start Date: Oct 2024 Estimated Duration: 2 days Reg. Approval Req’d? Yes Regulatory Contact: Juanita Lovett First Call Engineer: Casey Morse 603-205-3780 (M) Second Call Engineer: Ryan Rupert 907-301-1736 (M) Current Bottom Hole Pressure (est): 2169 psi @ 7599’ TVD (Ca. 2007 SBHPS, EMW: 5.5 ppg) Max. Potential Surface Pressure: 1409 psi Gas Column Gradient (0.1 psi/ft) Current Pressures (LS/SS/IA/OA/OOA/OOOA): 0/0/266/180/123/128 psi Max Deviation: 54.3 deg @ 9102’ MD History Drilled and completed in 1993/1994 as an oil producer. The well has never been worked over. The well was SI in 2003. In 2010 it was circulated with 9.8 ppg brine and a 92 bbl pill of LCM was pumped down the LS to plug off the perforations. Notes: 24” Surface Casing @ 586’ MD. Cemented w/ 138 bbls 12.8 ppg & 75 bbls 15.9 ppg. Pumped 15 bbls 15.9 ppg top job. 18-5/8” Casing @ 2054’ MD in UR 24” hole. Cemented w/ 445 bbls 12.9 ppg and 144 bbls 15.8 ppg. Good returns, cement to surface. 13-5/8” Casing @ 5917’ MD in 17.5” hole. Cemented w/ 596 bbls 12.9 ppg and 150 bbls 15.8 ppg. Noted partial returns during cement job. 9-5/8” Casing @ 10,257’ MD in 12-1/4” hole. Cemented w/ 517 bbls 13.2 ppg. Good returns during cement job. Current Status Shut-in. The LS, SS, and IA were loaded with 9.8 ppg brine. Pre-P&A Diagnostics Performed 1. Initial pressures (LS/SS/IA/OA/OOA/OOOA): vac / vac / 273 / 130 / 125 / 128 psi 2. Pump 9.8 ppg brine: a. Pump down LS up IA, FCP = 375psi / 2.4 BPM b. Pump down IA up LS, FCP 375psi / 2.4 BPM c. Pump down IA up SS, FCP 250psi / 2.6 BPM d. Pump down LS up SS, FCP 420psi / 2.6 BPM e. Pump down SS up LS, FCP 250psi / 2.6 BPM f. Pump down SS up IA, FCP 250psi / 2.6 BPM 3. Bled down OA to 100 psi, OOA to 50psi, and OOOA to 0psi. No communication observed across annuli during bleeds. 4. Attempt to inject down LS, pressure up to 730 psi, bled down to 690 psi in 5 min. 5. RU slickline on SS. Injected down IA into perfs 2275 psi at 0.85 bpm after ~150 bbls bullheaded with temp gauge stationed just above KOBE pump. Temp dropped throughtout bullheading operatoin, indicating injection was going below the KOBE pump on 10/13/24. -bjm Oil Zone P&A Program Well: Ba-29 a. RIH w/ 2.75” gauge ring to 7770' SLM, work down to 7802’ SLM. RIH w/ 6’ pump bailer to 7895’ and found less than a cup of scale in bailer. b. MU Holefinder and RIH to 7800’. Unable to set. Work up until able to set at 7706’ SLM. PT tubing to 575 psi, hold for 5 mins – GOOD. 6. RU slickline on LS. a. RIH w/ 1.75” x 3’ bailer, tag at 7929’ SLM, work down to 7935’. POOH, bailer half-filled with scale. b. RIH w/ D&D Holefinder to 7905’ SLM. Set tool and PT to 560 psi for 5 mins – GOOD. 7. Check annulus pressures 1 week later: IA 6 psi, OA 140 psi, OOA 25 psi, OOOA 0 psi. a. Bled off 25 psi from OOA. Gas showed LEL and CO. Top off OOA w/ 15bbls FIW, pressure up to 540 psi, lost 20 psi in 15 min (good test). OA increased from 140 psi to 360 psi when pressuring up, no change in pressure on other annuli. b. OA is fluid packed. Pressure up on OA to 540 psi, lost 10 psi in 15 minutes (good test). No change in other annuli. c. Top off OOOA w/ 19 bbls FIW, pressure up on OOOA to 575 psi, lost 165 psi in 15 min (failed test). No change in other annuli. 8. Pump dye pill to confirm TxIA circulation point: a. Top off well with 33 bbl 9.8 ppg brine. Pump 10 bbl dye pill, chased with 9.8 ppg brine down LS and out IA at 3.1 bpm, 360 psi. Saw dye return after 446 bbls circulated. Confirm circulation is at ported balanced isolation tool at 7933’. Objective Plug and abandon the Middle Ground Shoal Oil Pool perforations. Hilcorp requests a variance to 20 AAC 25.112 (c) (1) (D). Hilcorp requests to cement by the downsqueeze method using the existing completion instead of a packer or cement retainer. Flow from the tubing string to IA occurs at the balanced isolation tool at 7933’ (95’ above the top perforation). Once cement is circulated into the IA at this depth, Hilcorp will downsqueeze the cement into the open perforations by holding pressure on the tubing strings and IA. There is only one Pool between the base of the cement plug and the lowest open perforations at 9774’ MD, the Middle Ground Shoal Oil Pool as defined in Conservation Order 44 A. Procedural steps 1. Fluid pack the tubing strings and IA with 9.8 ppg brine. 2. Pump reservoir abandonment cement plug as follows: ¾ 30 bbls RIW (Raw-Inlet-Water) w/ Surfactant Wash (down LS and out IA) ¾ 333 bbls 14 ppg Class G cement. Record volumes of fluid recovered. i. Start pumping down LS and out IA ii. Return 216 bbls from IA (IA cement volume of 146 bbls plus LS volume of 70 bbl) iii. Close IA and swap to taking returns from the SS. Return 26 bbls. iv. Downsqueeze 91 bbls into the perfs, max pressure of 1000 psi during squeeze v. Drop foam wiper ball, pump 44 bbls 9.8 ppg displacement while squeezing into perfs to place 135 bbl total cement into perfs. ¾ 44 bbls of 9.8 ppg brine displacement puts TOC in LS / SS / IA @ ~5000’ i. If perfs lock up before all cement volume is pumped, swap to 9.8 ppg brine for LS displacement and take additional cement returns up IA. Note: Injected 0.85 bpm at 2275 psi during temp log injection test. Record final shut in LS/SS/IA pressures to confirm cement is approximately in balance before it sets. Include in 10-404 -bjm Max tubing pressure of 1000 psi assumes full column of cement in tubing. IA will be full if seawater, so max IA pressure is 1000 psi + 7580' TVD*.052*(14-8.5 ppg) = 3167 psi max on IA. Adjust as necessary to account for different fluid density. See email from Casey Morse 6/4/25 -bjm max pressure of 1000 psi during Oil Zone P&A Program Well: Ba-29 ¾ LS volume from ported sub to 5000’: 0.0087 bpf * (7933’-5000’) = 26 bbls ¾ IA volume from ported sub to 5000’ = 146 bbls o 7933 to 7908: 0.0613 bpf * 25’ = 2 bbls (tubing tail x IA) o 7908 to 5000: 0.0494 bpf * 2908’ = 144 bbls (LS/SS x IA) ¾ SS volume from Kobe to 5000: 0.0087 bpf * (7908’-5000’) = 26 bbls ¾ Casing / tubing volume from ported sub to bottom perf: 0.0732 bpf * (9774’- 7933’) = 135 bbls Total Cement Volume: 333 bbls ¾ LS volume from 5000’ to surface: 0.0087 bpf * 5000’ = 44 bbls ¾ IA volume from 5000’ to surface: 0.0494 bpf * 5000’ = 247 bbls ¾ SS volume from 5000’ to surface: 0.0087 bpf * 5000’ = 44 bbls Fullbore/Slickline 1. CMIT LSxSSxIA to 1915 psi (0.25 * TVD top perf @ 7657’) – AOGCC Witnessed. 2. Tag TOC in LS and SS – AOGCC Witnessed. Cement Tops: x 13-3/8” Casing o Annulus volume: 5917’ to 2054’: 0.1237 bpf * 3863’ = 478 bbl 2054’ to surf (54’ below KB): 0.1271 bpf * 2000’ = 254 bbl o Cement volume: 746 bbl 746 / 478 bbl = 1.56 Æ With complete returns and 56% washout in open hole, cement would be inside the 18-5/8” shoe. Likely cement top is inside 18-5/8” casing shoe @ 2,054’ because OOA held pressure test >500 psi for 15 minutes. Assuming 50% washout, cement top would be 1876 ft x 9-5/8” Casing o Annulus volume: 10257’ to 5917’: 0.0558 bpf * 4340’ = 242 bbl 5917’ to surf (54’ below KB): 0.0597 bpf * 5863’ = 350 bbl o Cement volume: 517 bbl o Assuming 50% washout in open hole, annuluar volume of open hole becomes 363 bbl o Remaining cement: 154 bbl 154 bbl / 0.0597 bpf = 2576’ 5917 – 2576 = 3341 ft Bottomhole Pressures x Frac pressure: estimated at 0.9 – 1.1 psi/ft as per AIO 7. TVD of top perf: 7657’ x Full column of 9.8 ppg brine at top perf: 3900 psi o Do not exceed 2500 psi with 9.8 ppg brine in well x Full column of 14 ppg cement at top perf: 5600 psi o Do not exceed 1000 psi surface pressure with full column of cement. Attachments Note: this 135 bbl volume assumes guns are not taking space in the hole below the Kobe pump. Regulatory requirement for cement volume is 103 bbls below ported sub, which is enough to place 100' of cement below perf interval, assuming 4.625" OD guns are in the well. -bjm Oil Zone P&A Program Well: Ba-29 Current Schematic Proposed Schematic WBD_Ba-29_July2024 Page 1 of 1 JRN 02/2010 / Revised CDM 07/2024 Offshore Baker Platform Ba-29 N Middle Ground Shoal Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 03-23-1994 Oil Well Size Type Wt/ Grade/ Conn ID Top Btm Depth / Volume 32”Structural B -Welded 28.375”54’83’ BLM Driven 24” Conductor 156, X-42, MTS60AR 22.500” 54’ 586’ Surf / 228 Bbls (req’d top job) 18-5/8” Surface Csg 97#, X-56, QTE 60 17.500” 54’ 2,054’ 1º Surf / 585 Bbls (rtns w/cmt to surf) 13-3/8” Intermediate 68#, K-55, BTC 12.415” 53’ 5,917’ 28º Est TOC 1876’ / 746 Bbls w/losses 9-5/8” Production 47#, L-80, Butt 8.681” 53’ 10,257’ Est TOC 3341’ / 517 Bbls Completion Long String Weight/ Grade ID OD 3 ½” Prod Tubing 9.2# L-80 Butt 2.992 4.250 Short String 3 ½” Prod Tubing 9.2# L-80 Butt 2.992 4.250 Completion Jewelry Detail Depth Length ID OD Item Long String (Power Fluid) 51 1.25 Hanger @ x 50.97’ 7,908 7,856 2.992 4.250 3-1/2” 9.2#, L-80 SC Buttress Tubing 7,930 22.22 2.68 6.5 KOBE 3” Assembly Short String (Production) 51 1.25 Hanger, @ x 50.97’ 7,903 7,852 2.992 4.250 3-1/2” 9.2#, L-80 SC Buttress Tubing 7,904.4 1.0 2.0 4.5 2-3/8” EUE 8rd Pin x 2-1/2” Butt Xover 7,908.4 4.0 2.0 3.0 2-3/8” 4.7# EUE 8rd Pup Joint Tail Assembly 7,930 2.16 2.68 5.5 3-1/2” 8RND Mod Standing Valve Assembly 7,933 2.25 2.50 3.75 2-1/8” Balanced Isolation Tool 7,948 .85 2.32 4.75 2-7/8” 8RND Pressure Transfer Sub 8,017 1.64 --3.38 Mod K-2 Pressure Firing Head 8,018 3.7 --3.58 APF-C Differential Pressure Firing Head 8,022 6.14 --4.625 4-5/8” Blank Gun 8,028 1,746 -- 4.625 Vann Systems 4-5/8” 6SPF 32Gr. Perforation Guns w/ 3-3/8” slick wall spacer guns 2 9,775 .72 --4.625 Vann Bull Plug 0’ Wireline = 23.49’ Tubing 7,935’Tag in LS w/1.75” bailer 07-21-24 Notes:MIT-OA: Pass MIT-OOA: Pass MIT-OOOA: Fail (possible leak path on 18-5/8” x 24”) FISH None Perforation Data (DIL vs. Tbg Tally is 23’ shallow) PBTD =10,113’ TD = 10,280’ MAX HOLE ANGLE = 54.3 @ 9,102’ MD MGS Oil Top 5456’ 32” 83’ 9.8 ppg brine RKB: MSL = 118’ Mudline= 203’ Water Depth= 102’ 9-5/8” 10,257’ Good Rtns & Top Job 24” 586’ 18-5/8” 2,054’ 13-3/8” 5,917’ MGS Gas Base 4552’ Perforations @ Intervals Top 8,028’ Bottom 9,774’ Est TOC @ 1876’ MD 9.8 ppg brine Est TOC @ 3341’ MD KB: MSL Mean Sea Level Mud Line ADL: 17595 PTD: 193-118 API: 50-733-20454-00 Leg 1, Slot 8 MGS St 17595 29 WBD_Ba-29_Proposed Page 1 of 1 JRN 02/2010 / Revised CDM 07/2024 Offshore Baker Platform Ba-29 N Middle Ground Shoal Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 03-23-1994 Oil Well Size Type Wt/ Grade/ Conn ID Top Btm Depth / Volume 32”Structural B -Welded 28.375”54’83’ BLM Driven 24” Conductor 156, X-42, MTS60AR 22.500” 54’ 586’ Surf / 228 Bbls (req’d top job) 18-5/8” Surface Csg 97#, X-56, QTE 60 17.500” 54’ 2,054’ 1º Surf / 585 Bbls (rtns w/cmt to surf) 13-3/8” Intermediate 68#, K-55, BTC 12.415” 53’ 5,917’ 28º Est TOC 1876’ / 746 Bbls w/losses 9-5/8” Production 47#, L-80, Butt 8.681” 53’ 10,257’ Est TOC 3341’ / 517 Bbls Completion Long String Weight/ Grade ID OD 3 ½” Prod Tubing 9.2# L-80 Butt 2.992 4.250 Short String 3 ½” Prod Tubing 9.2# L-80 Butt 2.992 4.250 Completion Jewelry Detail Depth Length ID OD Item Long String (Power Fluid) 51 1.25 Hanger @ x 50.97’ 7,908 7,856 2.992 4.250 3-1/2” 9.2#, L-80 SC Buttress Tubing 7,930 22.22 2.68 6.5 KOBE 3” Assembly Short String (Production) 51 1.25 Hanger, @ x 50.97’ 7,903 7,852 2.992 4.250 3-1/2” 9.2#, L-80 SC Buttress Tubing 7,904.4 1.0 2.0 4.5 2-3/8” EUE 8rd Pin x 2-1/2” Butt Xover 7,908.4 4.0 2.0 3.0 2-3/8” 4.7# EUE 8rd Pup Joint Tail Assembly 7,930 2.16 2.68 5.5 3-1/2” 8RND Mod Standing Valve Assembly 7,933 2.25 2.50 3.75 2-1/8” Balanced Isolation Tool 7,948 .85 2.32 4.75 2-7/8” 8RND Pressure Transfer Sub 8,017 1.64 --3.38 Mod K-2 Pressure Firing Head 8,018 3.7 --3.58 APF-C Differential Pressure Firing Head 8,022 6.14 --4.625 4-5/8” Blank Gun 8,028 1,746 -- 4.625 Vann Systems 4-5/8” 6SPF 32Gr. Perforation Guns w/ 3-3/8” slick wall spacer guns 2 9,775 .72 --4.625 Vann Bull Plug 0’ Wireline = 23.49’ Tubing 7,935’Tag in LS w/1.75” bailer 07-21-24 Notes:MIT-OA: Pass MIT-OOA: Pass MIT-OOOA: Fail (possible leak path on 18-5/8” x 24”) FISH None Perforation Data (DIL vs. Tbg Tally is 23’ shallow) PBTD =10,113’ TD = 10,280’ MAX HOLE ANGLE = 54.3 @ 9,102’ MD MGS Oil Top 5456’ 32” 83’ 9.8 ppg brine RKB: MSL = 118’ Mudline= 203’ Water Depth= 102’ 9-5/8” 10,257’ Good Rtns & Top Job 24” 586’ 18-5/8” 2,054’ 13-3/8” 5,917’ MGS Gas Base 4552’ Perforations @ Intervals Top 8,028’ Bottom 9,774’ Est TOC @ 1876’ MD Est TOC @ 3341’ MD 333 bbl cement w/ 135 bbls squeezed into perfs KB: MSL Mean Sea Level Mud Line ADL: 17595 PTD: 193-118 API: 50-733-20454-00 Leg 1, Slot 8 MGS St 17595 29 HilcorpWell:BA #29Field:Baker10/12/20244060801001201401600100020003000400050006000700014 15 16 17 18 19 20 21 22Temperature (Deg.F)Pressure (psia)Time (hrs)PressureTemperatureGauge at depth7930' RKBPulling out of holeStaticGoing in Hole StaticReport date: 10/16/2024 3 1 McLellan, Bryan J (OGC) From:Casey Morse <Casey.Morse@hilcorp.com> Sent:Wednesday, October 2, 2024 2:22 PM To:McLellan, Bryan J (OGC) Cc:Juanita Lovett Subject:RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions That is correct. The spent charges and det cord will still be inside the tubing tail on these designs. Casey From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, October 2, 2024 10:44 AM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Thanks for all that info. One other question about the wellbore conƱguration. It looks like tubing conveyed guns are hung oƯ the end of the LS tubing and remain in the well. I assume there is not a thru-bore inside those guns and there’s no ability to run CT or slickline through them even if the Ʊll was cleaned out of the LS? 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: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 2, 2024 7:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Bryan, We will pump a higher-pressure injection test on this well prior to cementing to conƱrm expected rates and pressures for the squeeze. We might be able to pump that today. My plan was to stay below the frac pressure to create more even distribution of the cement. We can certainly push past that to target a set amount of cement squeeze volume if you’re comfortable with that approach. The test above should give us some clarity on this too. The procedures are somewhat confusing with how the volumes are spelled out. The squeeze would be 91 bbls, then drop the wiper ball, then continue squeezing into the perfs while we’re pushing the displacement volume of 44 bbls down the LS. So, the eƯective squeeze volume would still be 135 bbls, but 44 of those bbls would be squeezed in with the 9.8 displacement pushing the cement down. I’ll discuss this with our WSM to make sure that’s clear to him before the job. We can certainly grab some stabilized pressures after cementing like you suggested. Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777-8322 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 1, 2024 5:21 PM To: Casey Morse <Casey.Morse@hilcorp.com> Subject: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, A few questions about the sundry application: 1. In the “Procedural steps section, 3rd bullet, part (i), it says “If perfs lock up before all cement volume is pumped, swap to 9.8 ppg brine for LS displacement and take cement returns up IA.” What LS tubing 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 pressure would you consider to indicate the perfs are locked up? At the end of the document, it says not to exceed 1000 psi surface pressure with a full column of cement, but need to be clear which surface pressure your talking about because with 14 ppg to surface in long string and 9.8 ppg brine to 5000’ md in IA, your IA pressure would be 1000 psi without even pumping. I don’t see any reason not to exceed frac pressure in cased hole since the goal is to push cement past the LCM and into the perfs. Is there a reason to limit your pressure below frac pressure? 2. The pre-rig diagnostics indicate you can’t inject into the perfs with 730 psi over 9.8 ppg brine. Are you planning to do a test with increased injection pressure to conƱrm you can get cement down below the ported sub? 3. In the same section, second bullet, part (iv), why not pump the full volume to bottom perf of 135 bbls? You are only planning to pump 91 bbls below the ported sub. What’s the basis for 91 bbls? 4. After the cement job is in place and pumps shut down, please report all surface pressures. The LS, SS and IA should all be approximately balanced, and if not, you can estimate TOC in IA based on the imbalance in the pressures. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. 1 McLellan, Bryan J (OGC) From:Casey Morse <Casey.Morse@hilcorp.com> Sent:Tuesday, October 29, 2024 12:03 PM To:McLellan, Bryan J (OGC) Subject:Baker Temperature Surveys Attachments:BA 28 Temp Survey while Injecting on IA 10-10-24.pdf; MGS St 17595 28 Weekly Operations Summary 10-09-24 to 10-15-24.pdf; BA 29 Temp Survey while Injecting on IA 10-12-24.pdf; Ba-29 Daily Report 10-12-24.pdf Bryan, The Baker 28 (PTD 193-119) sundry 324-552 included a condition for conducting a temperature survey or similar to show injection was occurring below the Kobe BHA. Please Ʊnd attached a survey from Oct 10 and associated daily report of activity. Since the Baker 29 (PTD 193-118) has similar completion design, we went ahead and performed a similar injection test and temperature survey on the Oct 12. Those results and reports are attached as well. Both surveys show a steady drop in temperature while the probe is on bottom and injection is occurring down the IA. No noticeable gradient anomalies are observed on the POOH pass for either well. These results indicate that volumes injected down the IA are passing the temperature probes when set at the Kobe BHA. Let me know if you have any questions about these. Thanks, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777-8322 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: 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. 1 McLellan, Bryan J (OGC) From:Casey Morse <Casey.Morse@hilcorp.com> Sent:Wednesday, June 4, 2025 2:32 PM To:McLellan, Bryan J (OGC) Cc:Juanita Lovett; Wyatt Rivard; Dan Marlowe Subject:RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Bryan, We do not have equipment available to Ʋow back the LCM from this well. To your other question, the max pressure noted in the cementing steps of 1,000psi would only apply to the injection pressure on the Long String with a full column of 14 ppg cement in the LS. That would keep us below the frac gradient in an attempt to distribute the cement as much as possible across the open perfs. Casey Morse Operations Engineer Cook Inlet OƯshore Hilcorp Alaska, LLC (907) 777-8322 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, May 29, 2025 4:06 PM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, I’m working to get this sundry approved. Could you answer my question in the email below max injection pressure. The injectivity test achieved 0.85 bpm @ 2275 psi. If that pressure is reached and injection rate is very low, then consider increasing above frac pressure to ensure as much cement as possible gets bullheaded into the perfs. Also, is it feasible to Ʋow back some of the LCM material in an attempt to improve injectivity into the perfs? Is the jet pump still functional? Thanks 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: McLellan, Bryan J (OGC) Sent: Wednesday, March 26, 2025 5:12 PM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, Based on the results of the temperature log, it’s fair to say that at least most of the bullheaded Ʋuids will be injected into the perfs and not into a shallower casing leak. The temperature is falling as cold seawater is pumped down the IA past the temperature gauge which was stationed in the long string just above the pump attached below along with the job log. The procedure step 2.iv in the sundry application has a max injection pressure limit of 1000 psi. See my initial question #1 at the bottom of this email chain and let me know if the injection pressure limits need to be modiƱed, and also specify which surface pressure has the pressure limit, either the IA, Short String or Long String. I think you should be clear about what max pressure to apply while squeezing into perfs before swapping returns back up the IA. I can edit the sundry application as needed. 4 Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 2, 2024 2:22 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions That is correct. The spent charges and det cord will still be inside the tubing tail on these designs. Casey 5 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Wednesday, October 2, 2024 10:44 AM To: Casey Morse <Casey.Morse@hilcorp.com> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Thanks for all that info. One other question about the wellbore conƱguration. It looks like tubing conveyed guns are hung oƯ the end of the LS tubing and remain in the well. I assume there is not a thru-bore inside those guns and there’s no ability to run CT or slickline through them even if the Ʊll was cleaned out of the LS? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Casey Morse <Casey.Morse@hilcorp.com> Sent: Wednesday, October 2, 2024 7:44 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Juanita Lovett <jlovett@hilcorp.com> Subject: RE: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 6 Bryan, We will pump a higher-pressure injection test on this well prior to cementing to conƱrm expected rates and pressures for the squeeze. We might be able to pump that today. My plan was to stay below the frac pressure to create more even distribution of the cement. We can certainly push past that to target a set amount of cement squeeze volume if you’re comfortable with that approach. The test above should give us some clarity on this too. The procedures are somewhat confusing with how the volumes are spelled out. The squeeze would be 91 bbls, then drop the wiper ball, then continue squeezing into the perfs while we’re pushing the displacement volume of 44 bbls down the LS. So, the eƯective squeeze volume would still be 135 bbls, but 44 of those bbls would be squeezed in with the 9.8 displacement pushing the cement down. I’ll discuss this with our WSM to make sure that’s clear to him before the job. We can certainly grab some stabilized pressures after cementing like you suggested. Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC (907) 777-8322 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, October 1, 2024 5:21 PM To: Casey Morse <Casey.Morse@hilcorp.com> Subject: [EXTERNAL] MGS ST 17595-29 (PTD 193-118) sundry questions Casey, A few questions about the sundry application: 1. In the “Procedural steps section, 3rd bullet, part (i), it says “If perfs lock up before all cement volume is pumped, swap to 9.8 ppg brine for LS displacement and take cement returns up IA.” What LS tubing pressure would you consider to indicate the perfs are locked up? At the end of the document, it says not to exceed 1000 psi surface pressure with a full column of cement, but need to be clear which surface pressure your talking about because with 14 ppg to surface in long string and 9.8 ppg brine to 5000’ md in IA, your IA pressure would be 1000 psi without even pumping. I don’t see any reason not to exceed frac pressure in cased hole since the goal is to push cement past the LCM and into the perfs. Is there a reason to limit your pressure below frac pressure? 2. The pre-rig diagnostics indicate you can’t inject into the perfs with 730 psi over 9.8 ppg brine. Are you planning to do a test with increased injection pressure to conƱrm you can get cement down below the ported sub? 3. In the same section, second bullet, part (iv), why not pump the full volume to bottom perf of 135 bbls? You are only planning to pump 91 bbls below the ported sub. What’s the basis for 91 bbls? 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. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 7 4. After the cement job is in place and pumps shut down, please report all surface pressures. The LS, SS and IA should all be approximately balanced, and if not, you can estimate TOC in IA based on the imbalance in the pressures. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 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. 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. XHVZE Pages NOT Scanned in this Well History File This page identifies those items that were not scanned during the initial scanning project. They are available in the original file and viewable by direct inspection. File Number of Well History File PAGES TO DELETE Complete RESCAN Color items - Pages: Grayscale, halftones, pictures, graphs, charts- Pages: Poor Quality Original- Pages: Other- Pages: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED Logs of various kinds Other COMMENTS: E] Scanned by Dianna Vincent Nathan Lowell _ TO RE-SCAN Notes: Re-Scanned by' Bevedy Dianna Vincent Nathan Lowell Date: /si ) ) Chevron .. Timothy C Brandenburg Drilling Manager Union Oil Company of California P.O. Box 196427 Anchorage, AK 99519-6247 Tel 907 263 7657 Fax 907 263 7884 Email brandenburgt@chevron.com --...'" October 1 0, 2005 Commissioner John Norman Alaska Oil & Gas Conservation Commission ... t::r> ~O\j 0 3 ?J\\15 333 W. th Avenue 5CANN~-'·'" Anchorage, Alaska 99501 Re: Baker Platform Pilot Pre-Abandonment Work Summary ìq3-It~ B~-~ Dear Commissioner Norman, This letter is intended to update the Alaska Oil and Gas Conservation Commission on the status of U nacal' s pilot pre-abandonment work on the Baker Platform in Cook Inlet, Alaska. On October 22, 2004, Unocal proposed that a pilot program be initiated on the Baker platform to develop a safe, cost effective, and optimal method for the abandonment of multiple well bores. As noted in the letter of October 22, 2004, Unocal has operated the Baker and Dillon Platforms under a "lighthouse" mode where all oil and gas production has been shut-in. The Dillon Platform was shut-in December 2002 and the Baker Platfot111 was shut-in August 2003. Unocal commenced the pilot study with a diagnostic program on five water injection wells and three oil wells on the Baker Platfot111 in July 2005. The diagnostic program consisted of pressure and temperature surveys for baseline data, mechanical integrity of the completion, injectivity tests to the fot111ation, and pressure measurement on the outer casing annuli. The injection wells initially surveyed were Baker 7, 8rd, 12, 15rd, and 27. The oil wells surveyed were Baker 13, 28, and 30. Unocal did not anticipate that any of the oil wells on the Baker platform would have a bottom hole pressure (BHP) gradient exceeding seawater. However, when it was discovered that Baker well 28 had a static BHP of9.0 ppg, the diagnostic program was expanded to include all of the oil wells and water injection wells on the Baker Platform as well as six wells on the Dillon Platform. The Baker water injection wells have mostly held their residual pressure since being shut-in. Their BHP gradients range from 5.8 to 9.4 ppg. Three oil wells on the Baker platform have BHP gradients that exceed a seawater gradient. Two additional wells have pressures that exceed an oil gradient but are below a seawater gradient. Under the right conditions, these wells could be capable of unassisted flow. The Baker Platform Well BHP Summary is attached. The Dillon well BHPs are all below a seawater gradient of 8.4 ppg. No additional diagnostic well work on the Dillon platform has been initiated. ~~ 1't" ~JE ~ ~ ~ "¡., ' ,¡,.J ~-' i_ \ t~~ , Union Oil Company of California I A Chevron Company http;f/www.chevron.com ) Commissioner John Norman Alaska Oil & Gas Conservation Commission October 10, 2005 Page 2 No temperature anomalies were noted on the Baker platform with the exception of Baker well 28. Baker 28 exhibited a temperature anomaly at approximately 5,000 feet MD, as noted on the attached Baker Composite Temperature Chart. An assessment of Baker 28 is attached with the recommendation of no remedial activity. Chevron intends to conduct annual temperature/pressure surveys on Baker 28 to monitor the well status. There were no temperature anomalies noted on the Dillon platform wells. The pilot abandonment program commenced with plugging perforations on the water injection wells initially identified (i.e. Baker wells 7, 8rd, 12, 15rd, and 27). The plugging of the perforations received Sundry approval and the integrity testing of the cement plugs was witnessed by an AOGCC representative. In addition, perforations were plugged in the water supply well Baker 501 and in the gas well Baker 32. In light of the Chevron Corporation acquisition ofUnocal, the well plugging operations for the oil wells on the Baker platform has been omitted from the 2005 pilot program to allow time to reassess economic potential under Chevron's criteria. Furthermore, the gas potential from the Baker is also being re-assessed. To better prepare for the winter, Chevron will be applying heat on both the Baker and Dillon platforms. In addition, the wells capable of receiving a freeze protect fluid in their respective annuli will be freeze protected. If you have any questions or concerns, please contact me at 907-263-7657. Sincerely, ~ ~-Óc- .2 ~ c-~ /~=- J Timothy C. Brandenburg Drilling Manager Attachments Cc: Dale Haines Gary Eller Union Oil Company of California I A Chevron Company http://www.chevron.com Baker Platform Well BHP Summary Last Updated: October 7,2005 Pressure Survey Measured Gradient Equivalent Mud Well Well Type Date MD (ft) TVD (ft) BHP (psia) (psi/ft) Weight (ppg) Notes Ba-4 Injector 27 -Jul-05 7850 7843 3141 0.400 7.7 Ba-5 Producer 30-Jul-05 6284 5566 2753 0.495 9.5 Ba-6 Producer 20-Jul-05 5712 5709 2811 0.492 9.5 Ba-7 Injector 7-Jul-05 6244 5630 2712 0.482 9.3 Ba-8rd Injector 7-Jul-05 7100 6937 3288 0.474 9.1 Ba-9rd2 Injector Perfs cemented, no survey planned ~-- Ba-11 Producer 21-Jul-05 8379 8113 3273 0.403 7.8 Ba-12s Injector 6"Juh05 Ba-121 Injector 16-Jul-05 7121 6106 2941 0.482 9.3 Ba-13 Producer 6-Jul-05 7916 7661 3236 0.422 8.1 Ba-14 Gas No survey Ba-15rd Injector 5-Jul-05 6480 6286 3050 0.485 9.3 Ba-16 Injector No survey Ba-17 Injector No survey Ba-18 Gas No survey Ba-20 Producer 28-Jul-05 4134 4030 1242 0.308 5.9 Obstruction in tubing at 4139' Ba-23 Injector 23-Jul-05 8841 8499 2584 0.304 5.8 Ba-25rd Producer 22-Jul-05 9495 9033 3208 0.355 6.8 Ba-27 Injector 6-Jul-05 7779 5999 2928 0.488 9.4 Ba-28 Producer 3-Jul-05 8441 5308 2497 0.470 9.0 ~Ba-29 Producer 28-Jul-05 7923 7594 2165 0.285 5.5 Ba-30 Producer 4-J ul-05 10966 9109 3593 0.394 7.6 ,-,,/ Ba-31 Producer 29-Jul-05 11433 10636 3795 0.357 6.9 Ba-32 Producer No survey ) y '" ~7!Æ~E .:} !Æ~!Æ~~«!Æ A.TA.SIiA OIL AND GAS CONSERVATION COMMISSION Mr. Dave Cole Oil Team Manager UNOCAL P.O. Box 196247 Anchorage, AK 99516-6247 Re: Middle Ground Shoal Unit Platforms Dillon and Baker Dear Mr. Cole: ') FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 f~\tõ \~1J This letter confirms your conversation with CO!1unission Engineer Tom Maunder last week regarding the multiple Applications for Sundry Approval (Form 403) you submitted in mid October regarding changing the monitoring. frequency on the 16 wells on Dillon Platform and 23 wells on Baker Platform. Production and injection operations were halted on these platforms in 4th Q 2002 and 2nd Q 2003 respectively. Attached, please fmd the Sundry Applications, which are being returned without approval~ because the relief you request needs to be sought through a different procedure. The intent of submitting sundry notices for each well was to establish a monthly pressure and general monitoring frequency for all wells on Dillon and Baker. There is a requirement in place. for some of the water injection wells that pressures and rates are to be monitored daily and reported monthly. Since the platforms are unmanned and not operating, it is not possible to obtain daily information. When operations were curtailed, a monthly monitoring frequency was. established in the Plans of Development (POD) annually filed with the Division of Oil and Gas and Unocal desires to assure that this monitoring scheme is accepted by the Commission. As noted in the conversation, changing the monitoring frequency where presently in place and establishing a monthly monitoring frequency in general is not an action that is best accomplished with multiple sundry notices. A letter application requesting the desired monitoring schedule should be made under the applicable Area Injection Orders (AlO 7 for Baker and AIO 8 for Dillon) and Conservation Orders (CO 44 and CO 54) for the platforms/unit. The Commission looks forward to receiving your letter applications. If prior monthly monitoring information has not been submitted to the Commission, that information should be ubmitted forthwith. ~, Sincere~~ . No an Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION DATED this _day of November, 2004 Ene!. SCANNED NOV 2 ¿~: 2004 Abandon U Alter casing 0 Change approved program 0 2. Operator Name: Union Oil of California aka Unocal ~ # 1. Type of Request: 3. Address: 7. KB Elevation (ft): 118' 8. Property Designation: BAKER 11. Total Depth MD (ft): 10,280' Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): 8,005' to 9,751' Packers and SSSV Type: ALAS:) all AND ~:AST~g~S~l:::~ON COMMI~~)ON APPLICATION FOR SUNDRY APPROVAL RECE\\fED 20 AAC 25.280 Operational shutdown U Perforate U OO~eU WQ&ar Dispos. U Plug Perforations D Stimulate D Time Extension a... I' ommQtüm0 AJ Ita nil ¡¿ Ge ^ on~, v Perforate New Pool D Re-enteM5ft~penð"eèJWK~, . r~nitor Frequency 4. Current Well Class: 5. Permit to Dnll Number: / Development [2] Exploratory D 1931180 / Stratigraphic D Service D 6. API Number: / 50-733-20454-00// / // / Suspend U Repair well D Pull Tubing 0 909 West 9th Ave. Anchorage AK 99501 9. Well Name and Number: Ba-29 10. Field/Pools(s): MIDDLE GROUND SHOAL PRESENT WELL CONDITION SUMMARY 'Total Depth TVD (ft): 9,191' Length 630 psi 1,950 psi 4,760 psi Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): 10,113' 9,056' Size 83' 586' 2,054' 32" MD 83 BLM 586' 2,054' 2,053' 5,863' 9,172' Burst Collapse 24" 185/8" 133/8" 95/8" 2,250 psi 3,450 psi 6,870 psi 5,517' 1 0,257' 5,917' 1 0,257' Tubing MD (ft): Perforation Depth TVD (ft): 7,657' to 8,783' Tubing Size: Tubing Grade: Dual 3 2" 9.2# L-80 ackers and SSSV MD (ft): 7,908' Date: 27 -Sep-2004 KOBE BHA @ 7,908' 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program 0 BOP Sketch D 14. Estimated Date for Commencing Operations: 16. Verbal Approval: 13. Well Class after proposed work: Exploratory D Development 15. Well Status after proposed work: Oil [2] GasD WAG 0 GINJ D [2] Service D 0 D Abandoned WDSPL 0 0 Plugged WINJ Commission Representative: 17. I hereby certify that the foregoing is true and correct to the Printed NamrJ..) "'co. I!. SignatureM¥/ ¿2~ Contact Oil Team Supervisor 907-263-7805 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ) 3D4-lf31 Plug Integrity D Other: Subsequent Form Required: Approved by: BOP Test D 0 Location Clearance 0 Mechanical Integrity Test RBDMS BFL NOV 2 2 100~ APPLICATION RETURN NOT APPROVED ED 11/17104 BY COMMISSION ~ECE'VED OCT 12 2004 ÛI, Commission Anchòf¡}ge COMMISSIONER BY ORDER OF THE COMMISSION Date: Lf03 Form 1 0-4t'12rRevised 12/2003 OR\G\NAl Submit in Duplicate THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ,ON OR BEFORE JANUARY 03 2001 M PL ATE T H IS E W IA L UNDER M ARK ER AOGCC individual Well Geological Haterials inventery Page' 1 Date' 10/'13/95 PERH!T DATA T DATA_PLUS 93-118 6088 /1879-10281, OH a CH 1 o.7 ~ - i i 8 4 n '7 93-118 DA=~'' OP =~ WELL 93-i_ IS:~ SURVEY OMP DiTE:01/25/94 ~i/01~0_/190~2~001/2~'/94 RUN DATE_RECVD 04/21/94 07/08/94 07/08/94 07/08/94 93-! 18 BHCA/GR -D~2000-102S0 1 04/21/94 93-ii8 BHP (CDL) ~L~ 2000-I0250 1 04/21/94 93-118 CDL/CNL/GR .L~L~2000-10250 1 04/21/94 93-~.~,~ .......... D_~,/G~:~.~' ~E~2000-10250 1 0~/21/94 93=i18 FMT/GR ~ 8i05~9830 I 04/21/94 93-I18 MUD ~207°, ~-'~ 0280 04/18/94_ 93-1.18 MUD pL~2073-!0280 04/21/94 93-118 SBT ~E~5600-10072 1 04/21/94 Are dry ditch samples required? yes ~) And received?'-e~~' ' Was the well cored? yes ~ Analysis & descriptie~ re eiv-e~d? ~--~. Are wei~ = tests required? ~ yes Received? ~ no Well is in compliance [~ initial COMMENTS .~- STATE OF ALASKA ALA OIL AND GAS CONSERVATION COl~ WELL COMPLETION OR RECOMPLETION ~SION r EPORT AND LOG 1. Status of Well OIL ~ GAS ~--] SUSPENDEDF-] ABANDONEDU SERVICE~--] 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA (UNOCAL) 3. Address P.O. BOX 196247 ANCHORAGE, AK 99519 : ...... - _::i:~li ~ Classification of Service Well 7. Permit Number 93-118 8. APl Number 50-733-20454 9. Unit or Lease Name 4. Location of well at surface Baker Platform, Leg #1, Slot #8 i 1934' FNL & 544' FWL Section 31 TDN R12W SM 2038' FSL & 199' ~L Section 31, ~DN;R~t~;~ .~~~/! ~29 ,tTo D., 418' FSL & 537' ~L Secfi~ 31, TDN, R12W, SM ~~ Middle Ground Sho~ E, F, & G Pools 5. Elevation118'KB in fe~ (indicate KB, DF, etc.) 6. Le~e Designa~onADL 17~5 ~d Seri~ No. 12. Date Spudded 13. Date T.D. Reached 14. Date Comp., Susp. or ~d. 15. Water Dep~, if o~hore ~ 16. No. of Comple~ons 18. 01116/94 01/~/94 102 Feet MSL 1 Plug Back Dep~ (MD+~D) 19. Direcfion~ Su~ey 20. Dep~ where SSSV set 21. ~ickness of Per~rost N/A YES ~ NO ~ N/A feet MD N/A 09/20/93 17. TotaJ Depth (MD+TVD) 10280'/9192' 22. Type Electric or Other Logs Run DILJGR/SP/DRN/NEU/SONIC/DIPMETER/FMT/SBT- GR 23. CASING, LINER AND CEMENTING RECORD CASING SIZE WT. PER FT. GRADE SE3-rlNG DEPTH MD I I TOP IBO'I-rOM HOLESIZE CEMENTING RECORD AMOUNT PULLED 24" 156 X-42 54' 586' 28" 1196' cu. ft. 18-5/8" 97 X-56 54' 2054' 24" 3290' cu. ft. 13-3/8" 68 K-55 53' 5917' 17-1/2" 4189' cu. ft. 9-5/8" 47 L-80 53' 10257' 12-1/4" 2904 cu. ft. 24, Perforations open to Production (MD+TVD of Top and Bottom and intervaJ, size and number) See Attached 25. TUBING RECORD SIZE I DEPTH SET (MD) I PACKER SET (MD) 3-1/2". 9.2#, L-80@ 7908' NA 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) ] AMOUNT & KIND OF MATERIAL USED N/A 27 Date First Production N/A Date of Test Hours Tested Flow Tubing Press. Casing Pressure PRODUCTION TEST IMethod of Operation (Flowing, gas lift, etc.) PRODUCTION FOF~ OIL-BBL TEST PERIOD ! --- CALCULATED ! OIL-BBL 24-HOUR RATE ! --- GAS-MCF GAS- MC F 28. CORE DATA WATER- BBL WATER-BBL CHOKE SIZE [ GAS-OIL RATIO I OIL GRAVITY-APl (corr) N/A Form 10-407 rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29.t 30. GEOLOGIC MARKERS FORMATION TESTS ,_ NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT, DEPTH GOR, and time of each phase. , 31. LIST OF ATTACHMENTS ~¢ 32. ~' I hereby ~rtJfy~g~rect to the best of my knowledge ,, Signed G. RUSSELLSCHMIDT TrUe DRILLING MANAGER Date INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1' Classification of Service Wells' Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21' Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental recordsfor this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate 'none". Baker 29 Perforations Open to Production January 24, 1994 Measure Depth 8005'-8246' DIL 8560'-8614' 8898'-8966' 9008'-9317' 9328'-9512' 9537'-9751' Tree Verticle Depth 7657'-7824' 8025'-8058' 8230'-8273' 8299'-8487' 8494'-8615' 8632'-8783' Footage 241' 54' 68' 309' 184' 214' Interval Name F zone F zone Hemlock G1 Hemlock G2 & G3 Hemlock G3b Hemlock G4 ! KOBE BHA ! 32" Structural @ 83' BLM 24" Conductor @ 586' 156#, X-42, MTS60AR 8-5/8" Surface @ 2054' 97#, X-56, QTE60 13-3/8" Intermediate @ 5917' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC 2) KOBE BHA F/7908'-7931' 3) TCP guns 4-5/8" OD F/8005'-9751' @ INTERVALS RKB = 118' etd 10113' (CMT ON TOP OF FLOAT COLLAR) 9-5/8' Production @ 10257' 47#, L-80, BTC BAKER 29 ACTUAL COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN' CLL DATE: 6-10-94 UNOCAL DALLY HISTORY BAKER #29 WELL #29 DAY 1 (09/20/93) ACCEPT RIG #428 ON BAKER WELL #29 AT 1200 HRS 9-20-93. MIX SPUD MUD & CMPT MUD PMP LINER CHG. PU & STD-BK HWDP & DP. AT-FEMPT TO OFFLOAD BOAT, NEG DUE TO HIGH WINDS. WELL #29 DAY 2 (09/21/93) PU 20-3/4" WH W/RUN TOOLS. RIH & LAND SAME ON ADAPTOR RING. POOH & LD SAME. MU CENTER PUNCH BHA & RIH TO 200'. EXPERIENCED MECH FAILURE W/PIPEHANDLER SWIVEL PACKING. RIG ON DOWN TIME 14 HRS. WELL #29 DAY 3 (09/22/93) CONT REPAIRS. RIH, TAG AT 278' AND C/OUT MUD TO 298'. SPUD WELL AT 0230 HRS. DRILLED 17-1/2" HOLE (CENTER-PUNCH) F/298'-333'. RIG ON DN TIME 10.5 HRS. DRILLED F/333'-391'. WELL #29 DAY 4 (09/23/93) DRILLED TO 661'. RAN GYRO SURVEY. WELLBORE DRIFTED TO CLOSE PROXIMITY OF WELL BA #9, POOH FOR MOTOR ASSEMBLY, TO ALTER WELL PATH. DAY 5-7 (09/24-26/93) DRILLED 17-1/2" HOLE F/670'-825'. POOH. MU UR BHA & RIH. UR 17-1/2' HOLE TO 28" F/308'-815'. CCM. POOH. RU & RIH W/24" CSG TO 491'. CSG TAKING WT. RU CIRC HEAD & CBU. RIH TO 586' & SET DN. ATTEMPT TO PU & WORK FREE, NEG. RU F/STAB-IN CMT JOB. RIH W/CMT ASSY & STAB FC. CCH. M&P CMT F/24" CSG. UNOCAL DALLY HISTORY BAKER #29 DAY 8 (09/27/93) CMPT CMT JOB. CiP @ 0100 HRS. WOC 7 HRS. REM 30" RISER & PREP CSG F/WH ASSY. M&P 15 BBLS CMT F/TOP JOB, ClP @ 1900 HRS. PREP RIG TO SKID. REL RIG AT 2400 HRS. DAY 9-10 (10/16-17/93) RECOMMENCED OPERATIONS ON WELL 29 AT 21:00 HRS ON 10/16/93. SKID RIG FROM WELL 29. N/U BOP'S AND TEST SAME. RIH W/17-1/2" BIT ON 22" UNDERREAMER AND CLEANED OUT SHOE JT. AND PERFORMED LOT TO 200 PSI, 15.5 PPG EMW, FRAC GRADIENT OF 1.17 PSI/FT CLEANED OUT PREVIOUSLY DRILLED 28" HOLE TO 825'. DAY 11 (10/18/93) POOH. RIH W/17-1/2" BIT ON DIRECTIONAL DRILLING ASSY. RUN GYRO CHECK SHOT AT 809'. DRILLED 17-1/2" HOLE F/825'-914', SLOW ROP & ROUGH DRLG ACTION. POOH TO CK TOOLS. DISCOVERED 90% OF BIT CUTTERS BROKEN, APPEARS TO BE RUNNING ON JUNK. RIH W/14" MAGNET TO 914'. POOH, REC'D 20 LBS OF MISC JUNK STEEL. RE-RUN MAGNET BHA FOUR MORE TIMES. REC'D TOTAL OF 87 LBS OF STEEL. DAY 12 (10/19/93) MU DRLG BHA & RIH. DRILLED 17-1/2" HOLE F/914'-1790'. DAY 13 (10/20/93) DRILLED TO 2073', CSG PT. CBU. POOH. MU 24" UR BHA & RIH TO 485' & CIRC, HIGH PRESS INCR. POOH. DN 24" UR & MU SPARE UR. RIH TO 588'. UR 17-1/2" HOLE TO 24" F/588'-960'. DAY 14 (10/21/93) CONT UR HOLE F/960'-2063'. POH TO 1694'. REAM F/1694' TO 2063'. CBU. POOH. DN UR BHA. UNOCAL DALLY HISTORY BAKER #29 DAY 15 (10/22/93) RU & PREP TO RUN 18-5/8" CSG. PU & RIH W/18-5/8" X-56 97# QTE 60 CSG TO 2054'. CBU. PREP TO CMT. M&P 1247 SX (2493 FT3) OF 12.9 PPG LEAD CMT, FOLLOWED W/700 SX (809 FT3) OF 15.8 PPG TAIL CMT W/FULL RTRNS. CIP AT 1745 HRS 10-22-93. POOH W/INNER DP STRING. ND BOP & SECURE WELL W/BLIND FLG. PREP TO SKID RIG TO BA #30. REL RIG #428 AT 2400 HRS. DAY 16 (12/16/93) SKID R428 F/BA#28 TO BA#29. NU BOP & TEST SAME. PERFORM RIG MAINT & BHA CHGS. MU DRLG BHA & RIH. DAY 17-19 (12/17-19/93) PRESS TEST CSG TO 2000 PSI. DRILL FLOAT EQUIP & NEW HOLE TO 2083'. PERFORM LOT TO 13.5 PPG EMW. DRLG 17-1/2" HOLE F/2083'-3496'. POOH. MU BIT & BHA. RIH AND DRILLED F/3496'-4112'. DAY 20 (12/20/93) DRILLED 17-1/2' HOLE F/4112'-4716'. ST TO CSG SHOE. SERVICE RIG. RIH & DRILLED F/4716'-4743'. DAY 21 (12/21/93) DRILLED 17-1/2' HOLE F/4743'-5113'. DAY 22-26 (12/22-26/93) DRILLED TO 5,138', POOH F/BHA & BIT CK. RIH, REAM F/5,052' - 5,138'. DRILLED 17-1/2" HOLE F/5,138' - 5,934'. CCM F/13-3/8" CSG. PULLED TO 4,900', INCORRECT FILL-UP. RIH TO 5,934' CBU, INCR MW F/9.1 TO 9.3 PPG. PULLED TO 4,527'. INCORRECT FILL UP. RIH TO BTM, CIRC INCR MW TO 9.4 PPG & CK F/FLOW, 4 BPH. SI WELL, NO PRESS. INCR MW TO 9.6 PPG. POOH, OK. CHG BOP RAMS F/CSG & RU CSG EQUIP. PU & RIH W/13-3/8", 68#, K-55 TO 5,917', OK. CCH. M&P 596 BBL OF 12.9 PPG LEAD CMT, FOLLOWED W/150 BBL OF 15.8 PPG TAIL CMT, PARTIAL RTRNS. CIP 2230 HRS 12-25-93. INSTALL CSG PACK OFF & TEST SAME TO 3 M, OK. ND & REM 20" BOP STACK. NU "B" SECT OF WH & TEST SAME. NU 13-5/8" 5M BOP STACK & RISER. :" '~ !i '.,:;~ ~:-i 17'i UNOCAL DALLY HISTORY BAKER #29 DAY 27 (12/27/93) CONT NU OF BOP. TEST BOPE TO 5M. LAY DN 17-1/2" TOOLS F/DERRICK. MU BHA & RIH TO 1515'. PU 30 JTS OF 5" DP. RIH TO 5760' (CMT). C/OUT CMT TO FC AT 5833'. PRESSURE TEST CSG TO 2400 PSI F/30 MIN, OK. DRILLED FC & CMT TO 5905'. PRESS TEST CSG TO 2400 PSI F/10 MIN, OK. CiRC & CHG OVER MUD SYS TO PHPA AT 9.2 PPG. C/OUT CMT & FS PLUS NEW HOLE TO 5939'. DAY 28 (12/28/93) CCH. PERFORM LOT TO 15.9 PPG EMW. DRILLED 12-1/4" HOLE F/5939'- 6377'. CBU, CK FLOW. INCR MW F/9.4 TO 9.6 PGG. POOH, CHG BHA. DAY 29 (12/29/93) RIH TO 2800'. PU 10 STD 5" DP & STD BK SAME. CONT TO RIH. DRILLED 12/1/4" HOLE F/6377'-6697'. DAY 30-33 (12/30-31/01-02/94) DRILLED F/6697'-6753'. RIG REPAIR (AC ELEC PROBLEM) DN 3 HRS. ST TO CSG SHOE. RIH, DRILLED TO 6915'. RIG REPAIR (TOP DRIVE ELEC) DN 1 HR. CBU. POOH, INCORRECT FILL AT SHOE. RIH. CCM & INCR MW F/9.8 TO 10 PPG. POOH. CHG BHA. RIH TO 4766 & PU DP. RIG REPAIR (TOP DRIVE ELEC) DN 12 HRS, WILL NEED TO REPLACE RT MOTOR. RIH. DRILLED NEW HOLE F/6915'-7270', ST TO 6893' (SOME TIGHT HOLE), RIH, DRILLED F/7270'- 7569'. ST TO 6541' W/SOME TIGHT HOLE AT INTERVALS. DRILLED F/7569'- 7628'. DAY 34 (01/03/94) DRILLED TO 7649'. CBU. POOH TO CK BIT & BHA. TEST BOPE. MU BHA & RIH. DRILLED TO 7702'. DAY 35 (01/04/94) DRILLED 12-1/4" HOLE F/7702'-7945'. UNOCAL DALLY HISTORY BAKER #29 DAY 36 (01/05/94) DRILLED 12-1/4" HOLE F/7945'-8253'. DAY 37 (01/06/94) DRILLED F/8253'-8280'o TRIP FOR BIT. RIH & DRILLED 12-1/4" HOLE F/8280'- 8369'. DAY 38-40 (01/07-09/94) DRILLED 12-1/4" HOLE F/8369'-8791'. CBU. POOH. CHG BHA & RIH. DRILLED F/8791 '-8985'. DAY 41 (01/10/94) DRILLED 12-1/4" HOLE F/8985'-9165'. KILL LINE HCR VALVE W/MANUAL. DAY 42 (01/11/94) CBU. POOH. TEST DOPE, REPLACE CMPT BOP TEST, MU BHA & RIH. DAY 43 (01 / 12/94) DRILLED 12-1/4" HOLE F/9165'-9345'. DRILLED 12-1/4" HOLE F/9345'-9545', SLOW HOP. POOH. MU NEW BIT. DAY 44 (01/13/94) RIH, PU ADD'L DP. DRILLED F/9545'-9602'. DN HOLE MTR FAILURE. POOH, CHG OUT MTR & RIH. DRILLED F/9602'-9693'. DAY 45-47 (01/14-16/94) DRILLED 12-1/4" HOLE F/9693'-9892'. POOH, TIGHT F/9709'-9577'. CHG BHA & RIH, TAKING WT AT INTERVALS. DRILLED F/9892'-~. ST TO 7926' & RIH. CBU. POOH. RU WL LOGGERS. ,~, · UNOCAL DALLY HISTORY BAKER #29 DAY 48 (01/17/94) LOG RUN #1 (DIL/SP/CNL/NEU/GR/AC) F/10254'-5915'. LOG CASED HOLE W/NEU/GR TO 2000'. RIH W/LOG RUN #2 (DIPMETER), SET DN AT 8550'. WORK DN HOLE UNABLE TO WORK PAST 9015'. LOG F/9015'-5915'. POOH. MU WIPER BHA & RIH, SET DN AT 9940'. WASH DN TO 10280'. CBU. POOH. DAY 49 (01/18/94) POOH, RU WL & LOG RUN #3 (FMT, PRESS SAMPLES). RIH. SUBSTANTIAL TROUBLE RIH F/8280'-8915'. CONT RIH TO 9830'. LOG UP HOLE OBTAINING 30 PRESS SAMPLES. STUCK FMT AT 8530', ON STATION SAMPLE #30 DUE TO APPARENT ELEC FAILURE IN CONDUCTOR LINE. UNABLE TO RE- ESTABLISH COMM W/FMT. A'I-I'EMPT TO WORK E-LINE FREE, NEG. CUT E- LINE & RU TO STRIP IN OVER E-LINE. DAY 50 (01/19/94) STRIP IN OVER E-LINE. SET DN ON FISH AT 8580' & FREE SAME. BRK CIRC & ENGAGE TOF, OK. ATTEMPT TO SHEAR PUMP OUT SUB W/4500 PSI, NEG. PULL E-LINE OUT OF ROPE SOCKET, POOH W/SAME. E-LINE PARTED, __+ 500' REMAINS IN HOLE. POOH W/FISH (FMT) UNABLE TO PULL PAST 13-3/8" C SHOE AT 5915'. WORK FISH & PULLED THROUGH. POOH, 100% RECOVERY. MU WIPER BHA & RIH. C/OUT TO 10280'. CBU. POOH. CHG RAMS TO 9- 5/8". DAY 51 (01/20/94) RU & RIH W/9-5/8", 47#, L-80 BTC CSG TO 10257'. CCH. M&P 517 BBLS OF TLW CMT AT 13.2 PPG, DISP CMTN W/INLET WTR & BUMPED PLUGS W/3M. CIP AT 2230 HRS. PRESS TEST CSG TO 4800 PSI F/30 MINUTES, OK. DN HALLIB & PREP TO LAY DN LANDING JTS. DAY 52-54 (1/21-23/94) INSTALL PACKOFF & TEST SAME TO 5M, OK. CHG RAMS TO 3-1/2" & PERFORM BOPE TEST. MU 8-1/2" BIT & SCRAPER. RIH, PU 3-1/2", 9.2#, L-80 SC BTC TBG TO 10113' ETD. CBU. POOH. RU WL & RUN SBT/GR F/10113'- 5700'. RIH, PU 3-1/2" TBG TO 10113'. REV CIRC WELLBORE W/FUEL OIL (DIESEL), TAKING WTR RETNS TO PROD. POOH. MU & RIH W/VANN 4-5/8" TCP GUNS. ,:", :." ~'~" '.~: '". ~ ~i',i ~"~. 6 ,' :'~'! ., . i ,: h.,,~,_ UNOCAL DALLY HISTORY BAKER #29 DAY 55 (1/24/94) CONT RIH W/TCP GUNS & COMPLETION TBG. BROACH & HYDRO-TEST LS WHILE RIH. CONT RIH W/DUAL 3-1/2" TBG COMPLETION. RU WL & RUN GR/CCL TIE-IN FOR TOP PERF AT 8005' DIL. POOH W/WE DAY 56 (1/25/94) RIG DN WL. MU LANDING PUPS & TBG HGR. LAND SAME. PRESS TEST TBG HGR TO 5M F/30 MINUTES, OK. SET BPV. ND BOP & PULL RISER. A3-FEMPT TO SET PROD TREE, NEG. RU TURN TBG HRG & RE-LAND SAME. RE-LAND TREE & NU SAME. PRESS TEST TREE TO 5M, OK. RU & INSTALL SURFACE EQUIP. INSTALL STANDING VALVE & JET PUMP, PUMP SAME DN HOLE. RIG RELEASED AT 1800 HRS. SKID R428 TO BAKER 30. DAY 57 (1/26/94) PRODUCE WELL TO LOWER THE FLUID LEVEL TO + 6800' MD. INCR BACK PRESSURE AND DETONATE TCP GUNS AT 2030 HRS. PERF ALL INTERVALS AT 6 SPF: 8005'-8246'; 8560'-8614'; 8898'-8966'; 9008'-9317'; 9328'-9512'; 9537'- 9751'. TOTAL 1070' NET OF PERFS. AS OF 0605 HRS: 586 BOPD, PRORATED, HOURLY BASIS. UNOCAL BAKER Platform 8a-29 slot #1-8 Middle Ground Shoals Cook Inlet, Alaska SURVEY LISTING by Baker Hughes INTEQ Your ref : PMSS <2180-10280'> Our ref : svy4133 License : Date printed : 20-Jan-94 Date created : 20-Dec-93 Last revised : 1?-Jan-94 Field is centred on n60 50 4.803,w151 29 11.941 Structure is centred on n60 50 4.803,w151 29 11.941 Slot location is n60 49 45.758,w151 29 0.968 Slot Grid coordinates are N 2498070.739, E 235254.581 Slot local coordinates are 1934.00 S 544.00 E Reference North is True North Date .. J / 3 / o I i ~ UNOCAL BAKER Platform,Ba-29 Middle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 1 Your ref : PMSS <2180-10280'> Last revised : 17-Jan-94 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 250.00 0.20 154.00 250.00 0.39 S 0.19 E 0,08 0.35 300.00 0.40 138.00 300.00 0.60 S 0.35 E 0.43 0.53 350.00 0.70 134.00 350.00 0.94 S 0.68 E 0,60 0.80 400.00 0.80 127.00 399.99 1.36 S 1.18 E 0.27 1.13 450.00 0.80 132.00 449.99 1.81 S 1.72 E 0.14 1.47 500.00 0.90 131.00 499.98 2.30 S 2.28 E 0.20 1.86 550.00 1.50 129.00 549.97 2.97 S 3.08 E 1,20 2.37 600.00 2.00 127.00 599.95 3.90 S 4.28 E 1.01 3.08 620.00 1.90 131.00 619.94 4.33 S 4.81 E 0.84 3.41 674.00 1.30 122.00 67'5.91 5.24 S 6.01 E 1.20 4.09 711.00 0.90 120.00 710.91 5.61 S 6.62 E 1.08 4.35 809.00 0.30 115.00 808.90 6.11 S 7.52 E 0.61 4.67 944.00 0.50 85.00 943.90 6.20 S 8.42 E 0.21 4.61 1033.00 1.90 170.00 1032.88 7.62 S 9.07 E 2.16 5.89 1222.00 2.00 193.00 1221.77 13.92 S 8.87 E 0.41 1406.00 1.80 219.00 1405.68 19.30 S 6.33 E 0.48 1595.00 1.30 250.00 1594.61 22.34 S 2.44 E 0.51 1772.00 0.50 292.00 1771.59 22.73 S 0.16 W 0.56 1969.00 1.00 317.00 1968.57 21.16 S 2.13 W 0,30 12.13 17.87 21.55 22.40 21.20 Gyro Single Shot Tie-in 2180.00 0.60 345.60 2179.55 18.74 S 3.66 W 0.26 19.09 2368.00 1.00 357.50 2367.53 16.15 S 3.97 W 0.23 16.60 2490.00 0.90 44.72 2489.52 14.40 S 3.35 W 0.63 14.77 2586.00 1.20 51.40 2585.50 13.24 S 2.03 ~ 0.34 13.39 2682.00 1.04 75.95 2681.48 12.40 S 0.40 W 0.52 12.27 27-/5.00 1.31 65.67 2774.46 11.76 S 1.39 E 0.37 11.32 2868.00 0.26 354.00 2867.45 11.11 S 2.33 E 1.35 10.52 2941.00 0.43 3.34 2940.45 10.67 S 2.33 E 0.24 10.09 3057.00 0.61 28.37 3056.45 9.69 S 2.65 E 0.25 9.07 3151.00 0.49 58.53 3150.44 9.04 S 3.23 E 0.33 8.32 3249.00 0.99 68.88 3248.44 8.52 $ 4.38 E 0.53 7.61 3345.00 1.27 48.68 3344.42 7.52 $ 5.95 E 0.50 6.34 3440.00 1.24 355.00 3439.40 5.80 S 6.65 E 1.19 4.52 3490.00 1.26 343.96 3489.38 4.73 S 6.45 E 0.48 3.51 3583.00 0.55 98.97 3582.38 3.82 S 6.61 E 1.69 2.58 3681.00 0.74 98.85 3680.37 3.99 S 7.70 E 0.19 2.56 37'/5.00 0.92 94.65 3~4.36 4.14 S 9.05 E 0.20 2.47 3869.00 0.26 262.68 3868.36 4.23 S 9.60 E 1.25 2.46 3962.00 0.37 335.86 3961.36 3.98 S 9.26 E 0.41 2.28 4057.00 0.58 336.58 4056.35 3.26 S 8.95 E 0.22 1.62 4152.00 1.05 26.06 4151.34 2.04 S 9.14 E 0.85 0.39 4245.00 0.38 237.04 4244.34 1.44 S 9.25 E 1.49 -0.22 4340.00 0.33 211.72 4339.34 1.85 S 8.84 E 0.17 0.25 4439.00 0.35 214.90 4438.34 2.34 S 8.52 E 0.03 0.79 4533.00 0.39 280.43 4532.34 2.52 S 8.04 E 0.43 1.05 4626.00 0.87 278.21 4625.33 2.36 S 7.03 E 0.52 1.07 4716.00 0.55 240.00 4715.32 2.48 S 5.98 E 0.62 1.37 4809.00 2.36 188.48 4808.29 4.59 S 5.31 E 2.22 3.58 4906.00 4.47 198.96 4905.12 10.14 S 3.79 E 2.26 9.31 4997.00 5.19 202.42 4995.79 17.30 S 1.07 E 0.85 16.84 All data is in feet unless otherwise stated Coordinates from slot #1-8 and TVD from we[lheed (118.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minim~ curvature method. Presented by Baker Hughes INTEQ UNOCAL BAKER Ptatform,Ba-29 Middle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 2 Your ref : PMSS <2180-10280'> Last revised : 17-Jan-94 Measured [nc[in. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/100Ft Sect 5090.00 6.63 206.06 5088.30 26.01 S 2.89 W 1.60 26.11 5152.00 7.11 204.61 5149.85 32.72 S 6.06 W 0.82 33.27 5245.00 11.47 195.38 5241.61 46.87 S 10.92 g 4.94 48.07 5338.00 14.90 194.29 5332.15 67.38 S 16.32 ~ 3.70 69.21 5436.00 18.58 196.68 5425.98 94.56 S 23.92 ~ 3.82 97.30 5530.00 21.61 196.49 5514.25 125.51 S 33.13 ~ 3.22 129.40 5620.00 22.49 195.02 5597.66 158.02 S 42.29 W 1.15 163.02 5715.00 25.31 197.38 5684.51 194.96 S 53.07 ~ 3.13 201.29 5813.00 28.53 199.63 5771.88 237.01 S 67.20 ~ 3.44 245.17 5866.00 28.64 199.82 5818.42 260.88 S 75.75 g 0.27 270.18 6028.00 28.13 197.80 5960.95 333.77 S 100.59 ~ 0.67 346.32 6122.00 28.24 197.00 6043.80 376.13 S 113.87 W 0.42 390.37 6215.00 27.90 196.02 6125.86 418.09 S 126.31 W 0.62 433.87 6308.00 27.10 194.70 6208.36 459.49 S 137.69 ~ 1.08 476.64 6401.00 27.50 194.20 6291.00 500.80 S 148.33 ~ 0.50 519.18 6494.00 28.70 193.50 6373.03 543.33 S 158.81 ~ 1.34 562.89 6588.00 28.50 193.70 6455.56 587.06 S 169.39 W 0.24 607.81 6682.00 28.50 195.10 6538.17 630.50 S 180.54 W 0.71 652.54 6776.00 28.20 196.80 6620.90 673.42 S 192.80 ~ 0.92 696.95 6868.00 28.40 196.20 6701.91 715.24 S 205.19 ~ 0.38 740.30 6966.00 28.20 195.90 6788.19 759.89 S 218.04 ~ 0.25 786.52 7058.00 28.10 197.40 6869.31 801.47 S 230.47 W 0.78 829.65 7151.00 28.90 196.90 6951.04 843.87 S 243.56 ~ 0.90 873.70 7245.00 29.20 196.80 7033.22 887.56 S 256.78 ~ 0.32 919.04 7338.00 29.90 197.00 7114.12 931.44 S 270.12 ~ 0.76 964.60 7430.00 30.90 195.80 7193.47 976.10 S 283.26 W 1.27 1010.88 7523.00 32.10 192.90 7272.77 1023.17 S 295.28 W 2.08 1059.34 7641.00 33.70 193.40 7371.84 1085.58 S 309.86 ~ 1.38 1123.34 7735.00 35.80 192.00 7449.07 1137.85 S 321.62 ~ 2.39 1176.87 7829.00 39.20 189.00 7523.64 1194.10 S 331.99 ~ 4.10 1234.07 7922.00 40.70 186.50 7594.94 1253.26 S 340.02 W 2.36 1293.72 8016.00 42.70 184.30 7665.12 1315.51 S 345.88 W 2.64 1356.02 8108.00 45.80 181.60 7731.02 1379.60 S 349.14 ~ 3.94 1419.67 8202.00 47.90 179.10 7795.31 1448.16 S 349.54 W 2.96 1487.21 8294.00 49.00 177.80 7856.33 1516.98 S 347.67 W 1.60 1554.61 8388.00 49.90 175.00 7917.45 1588.26 S 343.17 ~ 2.46 1623.95 8481.00 50.90 175.20 7976.73 1659.65 S 337.05 W 1.09 1693.12 8574.00 52.50 173.40 8034.37 1732.26 S 329.79 ~ 2.29 1763.30 8668.00 53.20 171.20 8091.14 1806.50 S 319.75 ~ 2.01 1834.57 8744.00 52.90 170.70 8136.82 1866.48 S 310.19 ~ 0.66 1891.90 8823.00 52.20 170.10 8184.86 1928.32 S 299.74 ~ 1.07 1950.90 8917.00 51.90 168.70 8242.67 2001.18 S 286.10 W 1.22 2020.18 9010.00 51.00 166.30 8300.63 2072.18 S 270.37 g 2.24 2087.26 9102.00 54.30 165.90 8356.44 2143.16 S 252.80 W 3.60 2153.99 9196.00 52.60 164.50 8412.42 2216.16 S 233.52 W 2.17 2222.42 9290.00 51.00 164.00 8470.55 2287.26 S 213.48 ~ 1.75 2288.82 9378.00 49.47 163.02 8526.84 2352.12 S 194.28 W 1.94 2349.25 9476.00 47.90 162.20 8591.53 2422.36 S 172.29 ~ 1.72 2414.47 9559.00 46.30 162.30 8648.03 2480.26 S 153.75 ~ 1.93 2468.16 9633.00 45.60 162.00 8699.48 2530.89 S 137.45 W 0.99 2515.09 All data is in feet unless otherwise stated Coordinates from slot #1-8 and TV]) from wellhead (118.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimu~ curvature method. Presented by Baker Hughes INTEQ UNOCAL BAKER Platform,Ba-29 Middle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 3 Your ref : PMSS <2180-10280'> Last revised : 17-Jan-94 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOFt Sect 9702.00 44.50 162.40 8748.23 2577.38 S 122.52 W 1.65 2558.19 9777.00 43.70 163.50 8802.09 2627.28 S 107.22 W 1.48 2604.58 9849.00 42.90 163.70 8854.49 2674.65 S 93.27 W 1.13 2648.72 9974.00 40.30 161.60 8947.96 2753.86 S 68.57 ~ 2.36 2722.29 10066.00 38.50 161.00 9019.05 2809.17 S 49.85 W 2.00 2773.40 10161.00 36.40 161.00 9094.46 2863.79 S 31.05 ~ 2.21 2823.81 10254.00 34.20 159.00 9170.36 2914.29 S 12.69 W 2.67 2870.25 10280.00 34.20 159.00 9191.87 2927.93 S 7.46 ~ 0.00 2882.74 Projected Data - NO SURVEY All data is in feet unless otherwise stated Coordinates from slot #1-8 and TVD from wellhead (118.00 Ft above mean sea [eve[). Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL SURVEY LISTING Page 4 BAKER P[atform,Ba-29 Your ref : PMSS <2180-10280'> Middle Ground Shoals,Cook Inlet, Alaska Last revised : 17-Jan-94 Comments in wellpath MD TVD Rectangular Coords. Comment 1969.00 1968.57 21.16 S 2.13 W Gyro Single Shot Tie-in 10280.00 9191.87 2927.93 S 7.46 W Projected Data - NO SURVEY Targets associated with this wel[path Target name Position T.V.D. Local rectangular coords. Date revised Ba29 TARGET #3 not specified 10118.00 3616.00S 206.00E 22-Jul-93 Ba29Hemlock Revised not specified 7950.00 1663.00S 300.OOW 8-Jul-93 8a29 TD Revised not specified 8900.00 2930.00S 150.00~ 8-Ju[-93 All data is in feet unless otherwise stated Coordinates from slot #1-8 and TVD from wellhead (118.00 Ft above mean sea [eve[). Bottom hole distance is 2927.94 on azimuth 180.14 degrees from wellhead. Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minim~a curvature method. Presented by Baker Hughes INTEQ ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 JUNE 7,1994 Russell Schmidt Union Oil Company of California P O Box 190247 Anchorage, Alaska 99519 RE: 93-0118 MGS ST 17595 28 93-0119 MGS ST 17595 - 29 93-0120 MGS ST 17595 30 COMPLETION 407 FORM COMPLETION 407 FORM COMPLETION 407 FORM Dear Mr. Schmidt, A review of our well records and correspondence indicates the the referenced wells are producing at this time and to date, the required 10-407 Well Completion Report has not been received. You are out of compliance with 20 AAC 25.072 (2). The attached request, in responce to MGS 29, has gone unanswered. I spoke with Lynn Goard about the other two wells (MGS 28 and MGS 30) the end of April 1994 after the monthly production Was reported for March 1994. The Commission requests this material immediately to correct the problem and update our well files. Sincerely, Steve McMains Statistical Technician atch: letter dated March 4, 1994 Unocal Energy Resource ision Unocal Corporation 909 West 9th Avenue, RO. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL DOCUMENT TRANSMITTAL Alaska April 21, 1994 TO' Larry Grant FROM: Dan Seamount LOCATION: 3OOl PORCUPINE DRIVE LOCATION: P.O.BOX 196247 ANCHORAGE, AK 99501 ANCHORAGE AK 99519 ALASKA OIL & GAS CONSERVATION COMM. UNOCAL .__:~......-_-.-.-.~.. ........................................... :_:_:: ........ ~ .............................. _~__::_-_~::_-:: ....................................... :_:_::_-_:_:__::.:c .......................... :_:::: TRANSMITITNG AS FOLLOWS 1 blueline and 1 sepia of each of the following i MGS BAKER 28 ~/BHC Acoustilog/Gamma Ray X/Compensated Densilog/Neutron/Gamma Ray ,/Compensated Neutron/Gamma Ray V/Dual Induction Focused Log/Gamma Ray "/Dual Propagation Resistivity/Gamma Ray (Measured Depth)/~&~) ~l~ual Propagation Resistivity/Gamma Ray (Subsea TVD)(~ ~/Formation Mudlog ~'§BT/Neutron/Gamma Ray Tape & Listing .~Openhole LIS Tape 2025-1049 MGS BAKER 29 '/'BHC Acoustilog/Gamma Ray/C.~ffi~er ~/Borehole Profile (Compensated Densilog) ""-Compensated Densilog/Neutron/Gamma Ray v"Dual Induction Focused Log/Gamma Ray ~'"Formation Mudlog v~ormation Multi-Tester/Gamma Ray ,//Segmented Bond Log Tape &~/Listing Openhole LIS Tape 1879-10281 MG$ BAKER 30 C Acoustilog/Gamma Ray/Caliper (2" & ~ ?'/~ompensated Densilog/Neutron/Gamma Ray'~ and~ /~Dual Induction Focused Log/Gamma Ray ~r'and~) sB rmation Mudlog T/Gamma Ray Tape & Listing v/Openhole LIS Tape 1900-10700 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT .,, %,.., ' ,.9<~ TRANSMITTAL TO DEBRA CH~ERS~_~~ ~YOU RECEIVED BY: Unocal Energy Resor~";: Division Unocal Corporation 909 West 9th Avenue, F.,... 3-ox 196247 Anchorage, Alaska 99519-6247 Teiephone (907) 276-7600 UNOCAL Alaska DOCUMENT TRANSMITTAL April 19, 1994 TO: Larry Grant LOCATION: 3001 PORCUP~qE DRIVE ANCHORAGE, AK 99501 - ALASKA OIL & GAS CONSERVATION COMM. FROM: Dan Seamount LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL X~AKER 28 BAKER 29// BAKER 30// BOX 1 300- 1710 2040- 3390 2040- 3330 BOX 2 1710 - 3000 3390 - 4680 3330 - 4560 BOX 3 3000 - 4320 4680 - 5940 4560 - 6000 BOX 4 4320- 5550 5940- 7200 6000- 7500 BOX 5 5550 - 6690 7200 - 8340 7500 - 8750 BOX 6 6690 - 7590 8340 - 9000 8750 - 9150 BOX 7 7590- 8700 9000- 9450 9150- 9550 BOX 8 8700- 9900 9450- 9900 9550- 9900 BOX 9 9900- 10582 9900- 10280 9900- 10250 BOX 10 10250 - 10600 BOX 11 10600- 11000 BOX 12 11000- 11275 PLEASE ACKNOWLEDGERECEIPT BY .SIGNING THIS DOCUMENT~AL RECEIVED BY.~/'~,/ DATED: AND RETURNING ONE COPY OF THANK YOU M EMORAND.- ', I State ',:' Alaska Alaska Oil and Gas Conservation Commission TO: David Johann, Chairmad~ ,~~ THRU: Blair Wondzell, '/5'~ ~U~ FILE NO: P. I. Supervisor ~¢- FROM: Lou Grimaldi, SUBJECT: Petroleum Inspector DATE: April 9, 1994 9VEJDHBD.DOC No Flow Verification '~ g'~'" Wells #D-20,12,27,28,&25 Marathon Dolly Varden platform Middle Ground Shoal Field Friday, April 8, 1994: I traveled to Marathon's Dolly Varden platform in the Middle Ground Shoal field of Cook Inlet to verify the No Flow status of five wells. When i arrived the wells had already had their gas lift shut in and the tubing flowed down to the group separator, These were then flowed to the well clean system which has approximately .5 psi back pressure on it. The wells tubing was then routed to open top containers with water in them. All w~ells bled only gas and died off quickly with the exception of well #D-25 which kept flowing gas and would build up to 160 psi rather quickly, this may have been residual gas in the annulus coming through a leaky gas lift valve. The platform needed this well back for production and we did not attempt any further tests on other wells. Recommendations: Wells # D-20, D-12, D-27, and, D-28 exhibited a inability to flow from the formation without the assistance of artificial lift and met the criteria for No Flow status. Well # D-25 would not die off and should be maintained as a flowing well. Summary: I verified the no flow status of 4 wells on Marathon's Dolly Varden platform. cc: Don Lacour (Production Superintendent) ALASKA OIL AND GAS · CONSERVATION COMMISSION ,: ,. WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 MARCH 4, 1994 · RUSSELL SCHMIDT UNION OIL COMPANY OF CALIFORNIA P O BOX 190247 ANCHORAGE, ALASKA 99519 RE: 93-0118 . MIDDLE GROUND SHOAL 29 COMPLETION REPORT DEAR MR. SCHMIDT, OUR RECORDS INDICATES THAT UNOCAL IS THE OPERATOR OF THE REFERENCED WELL. WE RECEIVED THE PRODUCTION REPORT FOR JANUARY 1994, AND WHILE REVIEWING OUR FILES WE FOUND THIS WELLS COMPLETION REPORT ALONG WITH WELL OPERATIONS HAVE NOT BEEN RECEIVED. A 10-407 COMPLETION REPORT FORM AND OTHER DOCUMENTATION NEEDS TO BE SUBMITTED TO COMPLETE OUR WELL FILES. · lAM FORWARDING THIS LETTER AS A RECORD FOR YOU AND ME. THANKS FOR THE QUICK RESPONSE ON THIS MATTER. SINCERELY, STEVE MCMAINS STATISTICAL TECHNICIAN ALASKA OIL AND GAS COi~SERVATION COM~ilSSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 10,1994 Russell Schmidt Unocal P O Box 196247 Anchorage, AK 99519-6247 Dear Mr Schmidt: The Commission is compiling statewide drilling statistics for 1993. Attached is a list of outstanding Permits to Drill issued to your engineering group (permits for which no form 10-407 has been received by this office). Please review this list to determine if any of the wells were drilled in 1993. If so, please note the well name, total measured depth, and class (development, service or exploratory). If any wells were drilling as of 12/31/93, estimate the depth at 12:00 midnight. We would appreciate your reply by the end of January if possible. Thank you for your cooperation with this project. If I may be of any assistance, please call me at 279-1433. Yours very truly, Robert P Crandall Sr Petr Geologist encl jo/A:RPC:\drlstats f~ 'r ~:' ;4' m~r,~,.,d ,~ recycled paper [.~ 5' C:.D. 1/o3/94 OPERATOR UNION OIL CO OF CALI UNION OIL CO OF CALI UNION OIL CO OF CALI UNION OIL CO OF C-ALI I/NION OIL CO OF ' C-ALI UNION OIL CO OF UNION OIL CO OF CALI UNION OIL CO OF C. ALI U~ION OIL CO OF CALI I/NION OIL CO OF CALI ALASKA WELLS BY UNOCAL PERMIT 92~0152-0 93-0073-0 93-0118-0 93-0119-0 93-0120-0 93-0127-0 93-0129-0 93-0165-0 93-0182-0 93-0190-0 WELL NAME IVAN RIVER UNIT 14-31RD1 GRANITE PT ST 18742 42 CHA~CACHATNA MGS B-29 CHAKAC~ATNA MGS 8-28 CPLAKACHATNA MGS B-30 GR3~NiTE PT ST 17586 3RD TRADING BAY I/NIT K-24R~D TRg~DING BAY UNIT K-26 A~4ETHYST STATE TR3~DING BAY LrNIT M-31 PAGE MEMORANDUM TO: David Johns~ Chairman' STATE OF ALASKA ALASKA OIL AND GAS CONSER VA TION COMMISSION DATE: 12-16-93 FILE NO: AV9JLPAD.DOC THRU: Blair Wondzeli P.I. Supervisor FROM: Grimaldi Petroleum Inspector PHONE NO.: 279-t433 SUBJECT: BOP test Rig #428 Unocal Baker platform Middle Ground Shoal PTD # 93-118 Thursday, December 16, 1993 I traveled to Unocal's Baker platform in the Middle Ground Shoal Field of Cook Inlet to witness the initial BOP test on rig # 428. This rig was purchased from Pool Arctic by Unocal and will be used on the Baker and Dillon platforms. When I arrived,the Pool drilling crew was standing by ready to test the B.O.P. equipment. John McCoy (Pool tool pusher) performed a good test with much attention paid to proper function of equipment. The B.O.P. functioned properly and all components held their test pressure. As this was my first visit to this rig since its arrival to the state, I made a bottom to top inspection of the B.O.P. equipment and associated piping. I found a well thought out and constructed rig with much attention paid to accessibility of all components. Don Byrne (Unocal rep.) was in attendance for most of the test, and has been a great help in keeping me informed of the rig's progress. I find him to be a conscientious individual who strives to make good hole. SUMMARY; I witnessed the initial BOP test on Unocal's Baker platform, rig # 428 in the Middle Ground Shoal Field. Test time one and one half hours, no failures. Attachment: AV9JLPAD.XLS STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: Drlg Contractor: Operator: Well Name: Casing Size: Test: Initial X Workover: P~ol Arctic Rig No. 428 PTD# Unocal Rep.: B-29 Rig Rep.: Set @ Location: Sec. X Weekly Other DATE: 12/16/93 93-118 Rig Ph.# 776-6648 Don Byrne John Mc Coy 31 T. 9N R. 12W Meridian seward Test MISC. INSPECTIONS: Quan. Pressure P/F Location Gen.: OK Well Sign OK 1 300\3000 P Housekeeping: OK (Gen) Drl. Rig OK 1 300\3000 P Reserve Pit NH 1 300\3000 P 1 300\3000 P BOP STACK: Annular Preventer Pipe Rams LowerPipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Test Quan. Pressure P/F Test 1 300\3000 P Pressure 15 300\3000 1 300\3000 P 1 300\3000 P 1 300\3000 P 2 300\3000 P 2 300~000 P 2 300~000 P NW NV~ NH MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P P Flow Indicator P P Gas Detectors P P CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes P/F P 38 300\3000 P 1 P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure 0 System Pressure Attained 3 Blind Switch Covers: Master: Nitgn. Btl's: 12 bottles 2250 average 3,000 P 1,600 P minutes 40 sec. minutes 4 sec. OK Rem'ote' OK Psig. Number of Failures: 0 ,C,;Test Time: 1.5 Hours.'" Number of valves tested 23 Repair or Replacement of Failed Equipment will be made within days. Notify the Inspector and follow with Written or Faxed verification to the AOGCC Commission Office at: Fax No. 276-7542 Inspector North Slope Pager No. 659-3607 or 3687 If your call is not returned by the inspector within 12 hours please contact the P. I. Supervisor at 279-1433 REMARKS: Outstanding rig, Good test procedure. Distribution: orig-Well File c - Oper./Rig c - Database .c - Tdp Rpt File c -Inspector FI-021L (Rev. 7/19) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: AV9JLPAD.XLS Louis R. Grimaldi Unoe~! North Arneri~:, Oil .nd Gas Division Unocal CorparaJJon P.O. Box 190247 Anchorage, Ata~ka 99579-0247 Telephone (907) 276-7600 UNOCAL Alaska Region August 20; 1993 State of Alaska AOGCC Attn: Bob Crandell 3001 Porcupine Drive Anchorage, AK 99501 Mr. Crandell In response to your question about productive gas sands at Middle Ground Shoals that would affect the proposed new wells at Baker Platform (Ba. ~28, 29 & 30) the following information is provided for your review. At the north end of the Middle Ground Shoal Field, Baker Platform, gas productive sandstones occur within the middle and upper portions.of the Tyonek Formation. The sandstones range in thickness from 10 to 50 feet, are interbedded with silt~tones, shales and coals, and are interpreted as meandering fluvial channel sandstones. Good sorting and upper-medium to very coarse/pebbly grain size characterize the gas reservoirs which typically exhibit permeabilities in the range of several hundred to several thousands millidarcies. Porosity values are also high, usually 25 to 32 percent. Pores pressures are considered normal to sub- normal with the gradients being 0.33 to 0.45 psi/ft. The type log for the gas reservoir is the Pan American Petroleum Corporation Middle Ground shoal State f4 well. These known productive gas sands at Baker Platform will be present in the proposed well~ (Ba. #28, 29, & 30) from 3200' to 4300' TVD, with the interval being subdivided into Zones 3 and 4. Presently, the Baker Platform has two wells (Baker #14 & 18) producing gas from these zones. cc: Wellfile(s) Ba.28, 29, & 30 Regards, C. Lee Lohoefer Senior Drilling Engineer RECEIVED AU G 0 199 9 Alaska Oil & Gas Cons. Commissio~ Anchorage Memorandum State of Alaska Oil and Gas Conservation Commission To~ August 19, 1993 Fm: Staff Subj' Unocal Request for Diverter Waiver Middle Ground Shoal Platform Baker Wells 28, 29, and 30 DRAFT Unocal has requested a waiver of diverter requirements on the subject wells. They propose to drill the surface hole with a drilling nipple then drill the surface hole with a combination 20 3/4" 3000 psi. BOPE system. They state in their application letter that the fracture gradient anticipated at the surface and intermediate casing shoes are .85 psi/foot and the rock is competent enough to shut in the well and circulate a kick rather than divert. The estimated fracture gradient is based on recent leak off tests which were taken all the way to leak off in the Cook Inlet area. I was told that some of the shallow tests showed a gradient of .9 psi/foot or greater; I did not get a list of wells. I reviewed 7 wells which offset the subject wells. Drilling histories in our files indicate no shallow gas kicks were encountered nor was there any lost circulation. On #25RD (83- 72) a DST was done to test a sand at about 3700' TVD and recovered gas cut mud. The most recent well drilled was #17 (85-217) off the Baker platform. Unocal states that there is no gas above 3200' in the vicinity of the Baker platform based on the information available to them. Regulation 20 AAC 25.035 (b) (3) and (c) (2) authorizes the Commission to waive diverter requirements if drilling experience in the near vicinity indicates a diverter system is not necessary. The same approach and arguments were used to waive diverter requirements on Granite Pt. 42. The proposal to drill the conductor hole, 303-800', with a drilling nipple means there is no annular preventer to divert the well and returns go straight to the shakers and pits. For the hole sections frim 800-6200', their permit application shows a 20 3/4" BOP system that has a diverter spool and a 2000 psi annular preventer. I understood in my conversation with Lee Lohoefer that if the waiver is approved, the diverter would be blinded off and not used. Unocal believes the diverter is not necessary and would rather use positive control measures and shut in on kicks. Batch drilling entails doing each casing segment of the three wells consecutively. As each section of the hole is completed and cased the well will be secured with a wellhead assembly, flanged such that there is a drill pipe connection and gauge to monitor the shut Page 2 in well. This drilling procedure is unusual, however, it is not unlike an operations shutdown. I would advocate a stipulation in the permit allowing this method and waive application for operations shutdown after each hole segment conditioned on securing the well (which they plan to do anyway). In summary, drilling history indicates no shallow gas has been encountered above 3200' at the Baker platform. A review of AOGCC well histories on seven wells in the vicinity of the 3 proposed wells indicated no shallow gas nor lost circulation zones. Most recent drilling at Baker occurred in 1985. The section of hole drilled from the structural pipe (303' RKB) to the conductor depth of 800' RKB would be done without any means to divert. Drilling from 800' RKB to total depth would be accomplished with BOP equipment. Recommendation: Based on no shallow gas in the vicinity of the wells to be drilled, I recommend approval of the waiver of diverter requirements: If there are other circumstances which the Commission thinks would cause a need for diverter use, Unocal should be allowed to address those circumstances in a meeting. The batch drilling procedure should be approved with a stipulation that each casing segment be secured prior to moving the rig to the next well. I don't recommend requiring a 10-403 (operations shutdown) for each segment in that it requires at least 6 filings and operations will be resumed within 60 days baring unforeseen circumstances. ALASKA OIL AND GAS CONSERVATION COMMISSION September 3, 1993 G. Russell Schmidt Regional Drilling Manager UNOCAL P O Box 196247 Anchorage, AK 99519-6247 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Re: Chakachatna MGS Baker #29 UNOCAL Permit No: 93-118 Sur. Loc. 1934'FNL, 544'FWL, Sec 31, T9N, R12W, SM Btmhole Loc. 510'FSL, 383'FWL, Sec 31, T9N, R12W, SM Dear Mr. Schmidt: Enclosed is the approved application for permit to drill the above referenced well. The Commission hereby waives the diverter system requirements per 20 AAC 25.035 and waives the requirements for operational shutdown (20 AAC 25.072) since drilling operations will not be disrupted for more than a 60-day time period. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Sufficient notice (approximately 24 hours) of the BOPE test performed before drilling below the surface casing shoe must be given so that a representative of the Commission may witness the test. Notice may be given by contacting the Commission at 279-1433. Sincerely, Russell u. Dou'~~ Commissioner BY ORDER OF THE COMMISSION dlf/Enclosures CC: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. .---. STATE OF ALASKA ALASK,~ .L AND GAS CONSERVATION COt 'ISSION PERMIT TO DRILL 2O AAC 25.005 la. Type of work Drill ~ Redrill Re-Entry r-'] Deepen I lb. Type of well. Service E] Exploratory ~ Stratigraphic Test [] Development Gas F1 Single Zone [-1 Development Oil [] Multiple Zone r-'] 2. Name of Operator Union Oil Comapny of California (UNOCAL) 3. Address P.O. Box 196247, Anchorage, AK 99519-6247 4. Location of well at surface Baker Pit. Leg #1, Slot #8 1934' FNL & 544' FWL SECT1ON 31, TDN, R12W, S.M. At top of productive interval 8452'MD / 7950q'VD 1683' FSL & 244' FWL SEC. 31, T9N, R12W, S.M. At total depth 9924'MD / 8829"rVD 510'FSL & 383'FWL SEC. 31, T9N, R12W, S.M. 12. Distance to nearest 113. Distance to nearest well property line 3300 feet 4' @ SURFACE feet 16. To be completed for deviated wells Kickoff depth 4700 feet Maximum hole anqle 53 DEG Weight Grade 97 47 N80 18. Casing program size Specifications Coupling MTS60 QTE60 BUTI' BUTT Length 744' 56 1944' 56 6144' 56 9868' 56 Hole Casing 28" 24' 24" 18-5/8" 17-1/2" 13-3/8' 12 - 1/4' 9- 5/8' '-19. To be completed for Reddll. Re-entry. and Deepen Operations Present well condition summary Total depth: measured true vertical Effective depth: measured true vertical Length 247 Casing Structural Conductor Surface Intermediate Production Liner Perforation depth: measured 300 feet 300 feet 300' feet 303' feet true vertical 5. Datum Elevation (DF or KB) 118' RT ABOVE MSL feet 6. Property Designation ADL 17595 7. Unit or property name Chakachatna MGS 8. Well number Baker #29 g. Approximate spud date September 7. 1993 14. Number of acres in property 10. Field and Pool Middle Ground Shoals E,F & G Pool 11. Type Bond (S~E~O^CC~.OZS) UNITED PACIFIC INS. CO. Number U62-9269 Amount $2O0,0O0 5106 __ 9,924' / 8,829' 17. Anticipated Pressure(~, ~o AAC 25.03~ (,)(2)) Maximum surface 729 psi9 At totaJ d~ th ('I~/D) 3973 Settinq Depth Top Bottom MD 'I'VD 15. Proposed depth feet Plugs (measured) psig Junk (measured) Size 30" Cemented DRIVEN Quantity of cement (include stage data) 1400 cu.ft. 2500 cu.ft.+r'~~T,~ 2700 cu.ft. .0ocu... Measured depth True vertical depth 303 RKB (83' BML) 20. Attachments Filing fee E~ Property plat L--] BOP SketchE~ Dive,er Sketch E~ Drilling program E~ Drilling fluid p. rogram ~:: Time vs depth plot E~ Refraction analysis [~ Seabed report ~ 20 AAC 25.050 requirements FI 21. I hereby ~rt~~ correct to the best of my knowledge 1Z · .~, "~ Signed G. F~USSELLSCHMIDT - - Title REGIONALDRI~I!NGMANAGER Date commission Use Only Permit Number IAPI numb~ IApprov~l..d,_~ Ieee cover letter 7,~ '//~' 50-,~..,~3 .2..4::3 ~7",5" z/ ~ ~'__~._"~ for other requirements Conditions of approval Samples required F-] Yes ,~ No Mud Icg required [-] Yes ~ No Hydrogen sulfide measures ~ Yes ,~ No Directional survey required ,~ Yes F-1 No Required working pressure for BOPE [-] 2M; ~ 3M; ~. 5M; [-] 1OM; ~ 15M Other: OFIIGINAL SIGNED l~y by the order of ~_ Approved by RUSSELL A. DOUGLASS Commissioner the commission Date ?; Form 10-401 Rev. 12-1-85 Submit in triplicate Unocal North Ameri, Oil & Gas Division Unocal Corporation P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL ) Alaska Region August 5, 1993 AOGCC Attn: David Johnston Commissioner 3001 Porcupine Drive Anchorage, AK 99501-3192 Dear Mr. Johnston: Please find enclosed applications for a Permit to Drill (Form 10-401) for Baker Platform wells #28, 29 & 30. These wells are scheduled to begin in mid-September and are the first wells of a $120 MM Development drilling program to be drilled with a new drilling rig. The rig is a minimum space modular design drilling system that was designed to accommodate four different platforms; Anna, Baker, Bruce and Dillon. As part of this development drilling program Unocal is requesting that the AOGCC waive the diverter system requirement on both the (30") structural and (24") conductors casing strings for all three wells. As outlined in each well procedure Unocal is intending to drill out the 30" structural casing to ± 800' with a flow nipple then install a 20-3/4" 3M BOP stack on the 24" conductor casing that will be cemented at ± 800'. The 24" casing will then be drilled out to a depth of ± 2600' and 18-5/8" surface casing will be cemented to depth. It has been Amoco's practice (previous operator) at Baker platform to drill and set 20" conductor at ± 600' with a flow riser, install a diverter and drill to ± 3500' at which point 13-3/8" casing is set. Unocal has selected casing points for 24" at ± 800' and 18- 5/8" at ± 2600' to be areas of competent formations. It is anticipated that the minimum formation fracture gradients at both shoe depths will be 0.85 psi/ft. The fracture pressures will be above the maximum expected surface pressures (see MSP calculation in each permit). Since the casing shoes will not break down in a well kick situation and the setting depths are above any indications of known gas sands, Unocal believes these are prudent casing designs and warranted operations. REC[IVED A U G 1 1993 Alaska Oil & Gas Co,is. L;ummission Anchorage. Letter to David Johnston August 5, 1993 Page 2 Additionally, Unocal is proposing to batch drill (see outline) these three wells for the 24" 18-5/8" and 13-3/8" casing strings Once 13-3/8" casing is set on all three wells, then each well will be drilled to total depth and completed one after another. It is Unocal's understanding that for a batch drilling process a single Permit to Drill (Form 10-401) and a single subsequent Well Completion (Form 10-407) is required for each well. Please note that documents in support of a spacing exception, made pursuant to 20AAC25.055, accompany the Permit to Drill for Baker Platform Well #29. Unocal is prepared and willing to discuss with the AOGCC the request for waiver on the diverter system and/or the batch drilling process. Early resolution of these issues will allow Unocal to pursue alternatives if so required. If you have any questions please contact C. Lee Lohoefer (Senior Drilling Engineer) assigned to this project. Thank you for your attention to these matters. Sincerely, G. Russell Schmidt Drilling Manager Enclosures CLL / 1 eg Baker #29 (New Well) RWP Option 5.0 AFE Estimate August 1, 1993 Procedure Davs ® · 4. 5. 6. 7. 8. 9. MIRU, Leg #1, Conductor #8, Install 30" riser. Drill 17-1/2" hole to 800', underream 17-1/2" hole section to 28". Run and cement 24" casing to 800'. Install combination 20-3/4"BOP/Diverter stack Drill 17-1/2" hole to 2000' (ROP 600') Underream 17-1/2" hole section 24". Run and cement 18-5/8" casing. Install 20" BOPE. Drill 17-1/2" hole to 6200'. (ROP 500') Run open hole logs. 10. Run and cement 13-3/8" casing. Install 13-5/8" BOP. 11. Drill 12-1/4" hole to 9924' TD. (ROP 275') 12. Run open hole logs. 13. Run and cement 9-5/8" casing. 14. Run CET/CBT and gyro survey. 15. Clean out, pressure test, change over to 3% KCL. 16. Run Vann TCP guns (4-5/8" OD, 4 spf, DP charge) in combination with Dual 3-1/2" KOBE BHA. 17. Set BPV, Rem BOPE, Install tree and flowlines. 18. Detonate TCP guns and produce well. 2 1 2 2 2 8.5 1.5 2 14.5 2 2 1.5 1.5 4 Time (Days) 51 ~nol~ora§a Depth 0 Baker 29 NEW WELL Depth vs. Days July 28, 199:3 (2,000) AVG. ROP 8OO FPD RUN 24' CSG AVG. ROP 6OO FPD RUN 18-5/8' CSG TIME: 51 DAYS COST: $4.34 MM (4,coo) AVG. ROP 500 FPD (6,000) LOG & RUN 13-3/8" CSG (8,ooo) AVG ROP 275 FPD ( o,ooo) (12,000) LOG & RUN 9-5/8' CSG~ COMPLETION I , I , I 20 30 40 Days Estimate Actual I = I ~ I 50 60 70 "'993 AUG ! Alaska 0il & 6as (;oils. Anchorage IKOBE BRA 32" Structural @ 83' BLM 24" Conductor @ 800' 156#, X-42, MTS60AR 8-5/8" Surface @ 2000' 97#, X-56, QTE60 MISC. DATA RKB = 118' WATER DEPTH = 102' 13-3/8" Intermediate @ 6200' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC 2) KOBE BHA @ 8300' 3) TCP guns 4-5/8" OD net 1000' Hemlock @ Intervals + 1000' 9-5/8" Production ~ 9924' ~Ja8~ .OJJ .~ Gas Ooils, 47~, L-80, BTC A~chor~g~ BAKER 29 PROPOSED COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 7-13-92 iCreated by : jones For: L LOHOEFERi ?ate plotted : 12-Aug-93 .iPl°t Reference is Bo-29 Version iCoordinates ore in feet reference slot #1-8.;. iTrue Vertical Depths ore reference wellhead. ¢ Baker i Hughes INTEQ I I I V 8 SURFACE UNOCA iStructure : BAKER Platform Well : Bo-29 Field : Middle Ground Shoals Location : Cook Inlet, Alaska S 10.22 DEG W L 24- Cog 2820' (TO TD) ***PLANE OF PROPOSAL*** 1200 _ 5200 _ - 3600_ _ _ 4400_ _ - 5200_ _ 5600_ - 8400_ - - 7200_ - 7600_ - 8000_ _ 8400 _ _ 18 5/8' Csg KOP 2.50 7.50 12.50 BUILD 2.,5 DE(;; / 100' 17.50 22.50 7.50 EOC 15 5/8" Csg AVERAGE28.15 DEGANGLE 29.79 Begin Final Build & Turn ~k 33.84 x~,x, 38.08 2.5 DEG / 100' DOGLEG TARGET-T/Hemlock(G-I) Final EOC ]'"*TD - 9 5/8" Cs9 Pt i i I i i I I i i I I I ! I I I J 0 400 I~30 1200 1600 2000 2400 2800 3200 Scale 1 : 200.00 Verllcal Section on 190.22 ozlmuth with reference 0.00 fl, 0.00 E from $1ol jl-8 WELL PRO Point .... I~D Inc iTie on 0 0.00 iEnd of Turn 4700 0.00 iEnd of Drop 5826 28.15 [End of Hold 7288 28.15 iTarget 8452 53.33 !End of Hold 9924 53.33 I- I 000 800 600 400 FILE DATA .... Dir T'VD North East 0.00 0 0 O', 196.67 4700 0 O 196.67 5781 -260 -78i 196.67 7070 -920 -276 17.3.25 7950 - 166`i -.IDa 173.25 8829 -2836__ __ -_ 1¢ lj West 200 0 200 I I I I I 200 -- 0 ~ .. 200 o o 4.00 60O 8O0 100O~ - O _1200 ('~ 1400 16OO I I 18OO V 2000 _ _2200 _2400 _2600 _ _2800 _ Bo29Hemlock Revised TARGET ANGLE 53.33 DEG AUG I Alaska Oil & Gas Cons. ,sm-m'nissio~ Anchorage q~JON anJl s~ 4~JON eoueJe~eB 3 O0'~ff5 $ O0'ff£6L aJe saleu~pJooo leOOl ~o15 ~96'0 6~ LgLM'ffi~Z'~ 6~ 09u s~ uo~eOOl ~OlS L~6'LL 6E LgL~'~Og'~ O~ 09u uo poJ~ue3 s[ eJn~3nJ~S L~6ILL 6~ L~LM'£Og'~ O§ 09u uo poJ~UeO s~ plo~J £6-§n¥-~L : pO$~AeJ ~Seq £6-1nr-g : po~eeJO o~eO £6-6n¥-~L : pa~u!Jd a~eo : asuoo!q 9Z~doJd : ~oJ JnO 9# uo~sJeA 6Z-e8 : ~oJ JnoA OOalOl uem~se3 Aq 9 N I IS I I 3 ¥S0d0 a d e~selV 'lelUl )oo3 SleOqS punoJ9 elPP)W g-L# ~OlS 6~-e8 mJo~eld ~3~¥8 lY30Nn UNOCAL BAKER Platform,Sa-29 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : Ba-29 Version #6 Last revised : 12-Aug-93 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D ! N A T E S Deg/lOOFt Sect 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 196.67 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 196.67 200.00 0.00 N 0.00 E 0.00 0.00 300.00 0.00 196.67 300.00 0.00 N 0.00 E 0.00 0.00 400.00 0.00 196.67 400.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 196.67 500.00 0.00 N 0.00 E 0.00 0.00 600.00 0.00 196.67 600.00 0.00 N 0.00 E 0.00 0.00 700.00 0.00 196.67 700.00 0.00 N 0.00 E 0.00 0.00 800.00 0.00 196.67 800.00 0.00 N 0.00 E 0.00 0.00 900.00 0.00 196.67 900.00 0.00 N 0.00 £ 0.00 0.00 1000.00 0.00 196.67 1000.00 0.00 N 0.00 E 0.00 0.00 1100.00 0.00 196.67 1100.00 0.00 N 0.00 E 0.00 0.00 1200.00 0.00 196.67 1200.00 0.00 N 0.00 E 0.00 0.00 1300.00 0.00 196.67 1300.00 0.00 N 0.00 E 0.00 0.00 1400.00 0.00 196.67 1400.00 0.00 N 0.00 E 0.00 0.00 1500.00 0.00 196.67 1500.00 0.00 N 0.00 E 0.00 0.00 1600.00 0.00 196.67 1600.00 0.00 N 0.00 E 0.00 0.00 1700.00 0.00 196.67 1700.00 0.00 N 0.00 E 0.00 0.00 1800.00 0.00 196.67 1800.00 0.00 N 0.00 E 0.00 0.00 1900.00 0.00 196.67 1900.00 0.00 N 0.00 E 0.00 0.00 2000.00 0.00 196.67 2000.00 0.00 N 0.00 E 0.00 0.00 2100.00 0.00 196.67 2100.00 0.00 N 0.00 E 0.00 0.00 2200.00 0.00 196.67 2200.00 0.00 N 0.00 E 0.00 0.00 2300.00 0.00 196.67 2300.00 0.00 N 0.00 E 0.00 0.00 2400.00 0.00 196.67 2400.00 0.00 N 0.00 E 0.00 0.00 2500.00 0.00 196.67 2500.00 0.00 N 0.00 E 0.00 0.00 2600.00 0.00 196.67 2600.00 0.00 N 0.00 E 0.00 0.00 2700.00 0.00 196.67 2700.00 0.00 N 0.00 E 0.00 0.00 2800.00 0.00 196.67 2800.00 0.00 N 0.00 E 0.00 0.00 2900.00 0.00 196.67 2900.00 0.00 N 0.00 E 0.00 0.00 3000.00 0.00 196.67 3000.00 0.00 N 0.00 E 0.00 0.00 3100.00 0.00 196.67 3100.00 0.00 N 0.00 E 0.00 0.00 3200.00 0.00 196.67 3200.00 0.00 N 0.00 E 0.00 0.00 3300.00 0.00 196.67 3300.00 0.00 N 0.00 E 0.00 0.00 3400.00 0.00 196.67 3400.00 0.00 N 0.00 E 0.00 0.00 3500.00 0.00 196.67 3500.00 0.00 N 0.00 E 0.00 0.00 3600.00 0.00 196.67 3600.00 0.00 N 0.00 E 0.00 0.00 3700.00 0.00 196.67 3700.00 0.00 N 0.00 E 0.00 0.00 3800.00 0.00 196.67 3800.00 0.00 N 0.00 E 0.00 0.00 3900.00 0.00 196.67 3900.00 0.00 N 0.00 E 0.00 0.00 4000.00 0.00 196.67 4000.00 0.00 N 0.00 E 0.00 0.00 4100.00 0.00 196.67 4100.00 0.00 N 0.00 E 0.00 0.00 4200.00 0.00 196.67 4200.00 0.00 N 0.00 E 0.00 0.00 4300.00 0.00 196.67 4300.00 0.00 N 0.00 E 0.00 0.00 4400.00 0.00 196.67 4400.00 0.00 N 0.00 E 0.00 0.00 4500.00 0.00 196.67 4500.00 0.00 N 0.00 E 0.00 0.00 4600.00 0.00 196.67 4600.00 0.00 N 0.00 E 0.00 0.00 4700.00 0.00 196.67 4700.00 0.00 N 0.00 E 0.00 0.00 KOP 4800.00 2.50 196.67 4799.97 2.09 S 0.62 W 2.50 2.17 4900.00 5.00 196.67 4899.75 8.35 S 2.50 W 2.50 8.66 All data is in feet unless otherwise stated Coordinates from slot #1-8 and TVD from wellhead (118.00 Ft above mean sea level) Vertical section is from wellhead on azimuth 190.22 degrees. DecLination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco ,,~iaska Oil & Gas Cons, Cormnission Anchorag~ UNOCAL BAKER Platform,Ba-29 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : Ba-29 Version #6 Last revised : 12-Aug-93 Measured Inclin. Azimuth True Vert. R E C T A N G U L A R Dogleg Vert Depth Degrees Degrees Depth C 0 0 R D I N A T E S Deg/lOOFt Sect 5000.00 7.50 196.67 4999.14 18.78 S 5.62 W 2.50 19.48 5100.00 10.00 196.67 5097.97 33.35 S 9.99 W 2.50 34.60 5200.00 12.50 196.67 5196.04 52.04 S 15.58 ~ 2.50 53.98 5300.00 15.00 196.67 5293.17 74.81 S 22.40 W 2.50 77.60 5400.00 17.50 196.67 5389.17 101.61 S 30.43 ~ 2.50 105.40 5500.00 20.00 196.67 5483.85 132.40 S 39.65 ~ 2.50 137.34 5600.00 22.50 196.67 5577.04 167.12 S 50.05 W 2.50 173.35 5700.00 25.00 196.67 5668.57 205.70 S 61.60 ~ 2.50 213.37 5800.00 27.50 196.67 5758.25 248.07 S 74.29 ~ 2.50 257.32 5826.00 28.15 196.67 5781.24 259.69 S 77.77 ~ 2.50 269.37 5826.08 28.15 196.67 5781.31 259.73 S 77.78 W 2.50 6000.00 28.15 196.67 5934.66 338.33 S 101.31 W 0.00 6500.00 28.15 196.67 6375.53 564.30 S 168.97 ~ 0.00 7000.00 28.15 196.67 6816.39 790.26 S 236.63 W 0.00 7287.99 28.15 196.67 7070.32 920.41 S 275.60 ~ 0.00 269.41EOC 350.94 585.33 819.72 954.72 Begin Final Build & Turn 7300.00 28.38 196.25 7080.90 925.87 S 277.22 ~ 2.50 7400.00 30.31 193.03 7168.07 973.27 S 289.56 W 2.50 7500.00 32.32 190.16 7253.50 1024.18 S 299.97 ~ 2.50 7600.00 34.39 187.60 7337.03 1078.50 S 308.43 ~ 2.50 7700.00 36.50 185.30 7418.49 1136.12 S 314.91 ~ 2.50 960.37 1009.22 1061.17 1116.12 1173.98 7800.00 38.66 183.22 7497.74 1196.92 S 319.42 ~ 2.50 7900.00 40.84 181.33 7574.62 1260.81 S 321.94 W 2.50 8000.00 43.06 179.60 7648.99 1327.65 S 322.46 ~ 2.50 8100.00 45.30 178.01 7720.70 1397.32 S 320.98 ~ 2.50 8200.00 47.56 176.53 7789.62 1469.68 S 317.52 W 2.50 1234.62 1297.94 1363.81 1432.11 1502.71 8300.00 49.84 175.16 7855.61 1544.61 S 312.06 ~ 2.50 8400.00 52.13 173.88 7918.56 1621.94 S 304.63 ~ 2.50 8451.92 53.33 173.25 7950.00 1663.00 S 300.00 W 2.50 8500.00 53.33 173.25 7978.71 1701.30 S 295.46 ~ 0.00 9000.00 53.33 173.25 8277.32 2099.56 S 248.31 ~ 0.00 1575.47 1650.26 1689.84 TARGET-T/Hemlock(G-I) Final EOC 1726.73 2110.29 9500.00 53.33 173.25 8575.92 2497.82 S 201.16 9924.57 53.33 173.25 8829.47 2836.00 S 161.12 0.00 2493.86 0.00 2819.56 TD - 9 5/8" Csg Pt ALl data is in feet unless otherwise stated Coordinates from slot #1-8 and TVD from wellhead (118.00 Ft above mean sea level) Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco Gas Co,is_ 'Co ~"~, ,~ ~.~,:~,"" "" UNOCAL PROPOSAL LISTING Page 3 BAKER Platform,Ba-29 Your ref : Ba-29 Version #6 Middle Ground Shoals,Cook Inlet, Alaska Last revised : 12-Aug-93 Comments in wellpath MD TVD Rectangular Coords. Comment 4700.00 4700.00 0.00 N 0.00 E KOP 5826.08 5781.31 259.73 S 77.78 W EOC 7287.99 7070.32 920.41S 275.60 W Begin Final Build & Turn 8451.92 7950.00 1663.00 S 300.00 ~ TARGET-T/Hemlock(G-I) Final EOC 9924.57 8829.47 2836.00 S 161.12 ~ TD - 9 5/8" Csg Pt Casing positions in string 'A' Top MD Top TVD Rectangular Coords. Bot MD Bot TVD Rectangular Coords. Casing 0.00 0.00 O.OON O.OOE 800.00 800.00 O.OON O.OOE 24" Csg 0.00 0.00 O.OON O.OOE 2000.00 2000.00 O.OON O.OOE 18 5/8" Csg 0.00 0.00 O.OON O.OOE 6194.66 6106.30 426.30S 127.65~ 13 3/8" Csg 0.00 0.00 O.OON O.OOE 9924.57 8829.47 2836.00S 161.12W 9 5/8" Csg Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised Ba29 TD Revised not specified 8900.00 2930.00S 150.00W 8-Jul-93 Ba29Hemlock Revised not specified 7950.00 1663.00S 300.00~ 8-Jul-93 Ba29 TARGET #3 not specified 10118.00 3616.00S 206.00E 22-Jul-93 All data is in feet un[ess otherwise stated Coordinates from slot #1-8 and TVD from wellhead (118.00 Ft above mean sea level) Bottom hole distance is 2840.58 on azimuth 183.25 degrees from wellhead. Total Dogleg for we[[path is 57.25 degrees. Vertical section is from wellhead on azimuth 190.22 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco UNOCAL BAKER Platform Ba-29 slot #1-8 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT by Eastman Teleco Your ref : Ba29 Version #5 Our ref : prop~28 License : Date printed : 8-Jul-93 Date created : 8-Jul-93 Last revised : 8-Jul-93 Field is centred on n60 50 4.803,w151 29 Structure is centred on n60 50 4.803,w151 29 11.9~i Slot Location is n60 49 45.758,w151 29 0.968 Slot ~rid coordinates are fl 2498070.739, E 235254.58~ Slot local coordinates are 1934.00 S 544.00 E Reference ~orth is True ~orth Main calculation performed with 3-D minimum distance method Object wellpath Ba-28 Version #7,,Ba-28,BAKER Platform GMS <0-9645'>,,16,BAKER Platform MSS <0-10000'>,,12,BAKER Platform PGMS <0-9642'>,,20,BAKER Platform GMS <0-7400'>,,6,BAKER Platform GMS <0-11600'>~,27~BAKER Platform GMS <0-10691'>,,13,BAKER Platform MSS <1039-12500'>,,lO,BAKER Platform PGMS <0-9722'>,,23,BAKER Platform GMS <8300-9445'>,,7,BAKER Platform GMS <0-7232'>,,17,BAKER Platform Ba30 Version #3,,Ba-30,BAKER Platform MSS <5626-10231'>,,18,BAKER Platform MSS <765-9543'>,,11,BAKER Platform MSS <6757-9944'>,,9Rch~1,BAKER Platform GMS <0-9760'>,,9Rd~2,BAKER Platform MSS <2653-11495'>,,9~BAKER Platform GMS <0-11128'>,,5,BAKER Platform MSS <3165-10455'>,,14,BAKER Platform MSS <0-9215'>,,4,BAKER Platform PGM$ <0-9544'>,~15,BAKER Platform MSS <6950-10116'>,,15Rd,BAKER Platform PGM$ <7200-9800'>~,25Rd~BAKER Platform MSS <7117-8642'>,,25,BAKER Platform GMS <0-9250'>,,8Rd,BAKER Platform MSS <2008-10314'>,,8,BAKER Platform Closest approach with 3-D minim~ distance method Last revised Distance M.D. Diverging from M.D. 14-Jun-93 5.1 500.0 10100.0 24-May-93 75.3 200.0 300.0 23-May-93 74.0 500.0 10142.6 24-May-93 71.8 500.0 9038.0 24-May-93 50.9 1600.0 1600.0 24-May-93 54.0 1100.0 5826.1 23-May-93 66.8 1200.0 6641.2 23-May-93 63.3 1300.0 5826.1 24-May-93 84.2 1600.0 7400.0 24-May-93 55.4 1600.0 970?.7 24-May-93 36.1 1800.0 1800.0 15-Jun-93 5.4 1600.0 1600.0 24-May-93 5.4 200.0 300.0 23-May-93 5.0 300.0 8215.4 23-May-93 5.0 200.0 5826.1 23-May-93 5.0 200.0 5826.1 23-May-93 5.0 200.0 5826.1 24-May-93 4.8 300.0 6754.6 23-May-93 5.0 300.0 8100.0 24-May-93 58.3 1400.0 1400.0 3-Jun-93 72.2 200.0 3500.0 3-Jun-93 72.2 200.0 3500.0 3-Jun-93 20.9 2300.0 2300.0 3-Jun-93 20.9 2300.0 2300.0 3-Jun-93 50.9 7933.7 7933.7 ~- 3-Jun-93 88.5 700.0 9707.7 Scale I : 250.00 250 0 I I I 3OOO 4OOO 250 500 750 1000 1250 I I 80O0 CD 2000 8500 500 I I I I 2000 4000 2500 5000 55OO 6000 8000 65OO '000 9000 6500 7000 7500 8000 8500 6000 6500 7000 7500 ~00 2250 2500 ,3000 3250 3750 40O0 50 4500 -750 5250 0 ! ! V Scale 1 · 20.00 44O 46O 48O I I I I I I 5OO 120( 1800 120O 1400 1200 1600 52O 1800 5200 ~00 2600 800 0 54O 560 58O I 1200, 4800 2000 2200 5000 2400140( 2200 1800 26OO 600 I 1840 1860 1880 19OO 1920 194O 1960 1980 2020 0 V d d, PAGE OF g D#iling Fluids Co. / ' / Ma~coDar/IMCO ~, Oresser r-lalhl:)urton Company UNOCAL BAKER PLATFORM CHAKACHATNA DEVELOPMENT #29, #30, AND %28 2.L. LOHOEFER Et ]993 · -~_'S;'."',' :...".. :. ,'/ ,-- ~ DEPTH INTERVAL MUD TYPE MUD ADDITIVES POTENTIAL PROBLEMS COST PER BARREL 0 - 800' 17%"/28" HOLE 24" CASING F.I.W./GENERIC MUD #2 M-I GEL/M-I BAR/SODA ASH/ CAUSTIC/LIME HOLE CLEANING/GRAVEL/ GAS KICK/LOST CIRCULATION $6.71 ESTIMATED TREATMENTS/PROCEDURES 1) Build spud mud system with prehydrated bentonite in fresh water and filtered inlet water. a) Treat drill water with Soda Ash as required to reduce calcium content to 40± ppm. b) Pre-Hydrate 25 lbs/bbl bentonite and allow to hydrate for 4-6 hours. Just prior to spud add filtered inlet water as required to yield a 50-70 sec/qt spud mud. 2) Drill hole. 3) Drill to 800'. Underream hole to 28". Use all solids control equipment. Raise viscosity if gravel sections are encountered. Run 24" casing. 4) Save and reuse mud on wells 29 and 30. Build additional volume as required. DM-131.WP (4/93) ~GE ZZ J ' D#lling Fluids Co. / ! Magcooar iMCO /~. Oresser, HamiDurton Company ~' ' '~HOEFER ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels Fluid Loss (API) pH 8.8 - 9.4 ppg 50-100 sec/qt. 10-15 cps 15-30 #/100ft~ 8-20 No Control 8.5 - 9.5 DM-131 .WP (4/93) i DEPTH INTERVAL ~AGE J Driiling Fluids Co. ! / Ma~coDar IMCO ~ Oresser. Haihburton Company / I UNOCAL BAKER PLATFORM C~AKAC~ATNA DEVELOPMENT #29, #30, and #28 "' L.~HOEFER -.', 800' - 3000' 17-1/2"/24" HOLE 18-5/8" CASING MUD TYPE HUD ADDITIVES F.I.W./GENERIC MUD #2 H-I GEL/M-I BAR/SODA ASH/ POLYPAC/SPERSENE/XP-20/ SODIUM BICARBONATE/ CAUSTIC POTENTIAL PROBLEMS COST PER BARREL HOLE CLEANING/TIGHT HOLE/BIT BALLING/ GUMBO CLAYS/HOLE ENLARGEMENT/GAS KICKS / COAL SLOUGHING $5.68 ESTIMATED TREATMENTS/PROCEDURES t) Use the surface mud from well #28 to drill the 24" collar, cement and shoe. Treat this fluid as required to avoid excessive cement contamination. 2) Build additional volume as required with prehydrated bentonite in fresh water and filtered inlet water. 3) Pump viscous sweeps as required. d 4) Control density with barite, F.I.W. water, and solids control equipment. Dump all sand traps as required. If MBT exceeds 25 lbs/bbl, or if low gravity solids exceed 75 ppb, then the system should be diluted to reduce unwanted drill solids. DM-131 .WP (4/93) ~GE J~~~Drilling Fluids Co. _,/ Magcooar-IMCO A Dresser I, talllDUrTon Comoan¥ .' OF ~*.L. LOHOEFER · P F, ~_ 1 !993 11 11 1 I 1 1 t 5) Report drill solids analysis on mud check sheet. 6) Report hydraulics calculations on mud check sheet. 7) Use Defoam-X if foaming becomes a problem. 8) Prehydrate ail bentonite in freshwater. 9) Drill to 3000'. Underream hole to 24". Run 18-5/8" casing. ANTICIPATED MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels API Fluid Loss pH MBT Drilled Solids 9.0-9.4 ppg 45-75 sec/qt 10-15 cps 10-20 #/100ft2 6/12/18 NO CONTROL 8.5 - 9.5 < 25 lbs/bbl < 75 lbs/bbl Note: This mud program is a guideline only. should dictate actual mud properties. Hole conditions DM-131 .WP (4/93) ~GE OF Oriiling Fluids Co. ~ MaacoDar.,iMCO ~, Dresser HalllDurton Comoanv :3.L. LOHOEFER 11 DEPTH INTERVAL MUD TYPE UNOCAL BAKER PLATFORM CHAKACHATNA DEVELOPMENT %29, %30, AND %28 3000' - 7500' 17½" HOLE F.I.W./GENERIC MUD ti iJ MUD ADDITIVES POTENTIAL PROBLEMS M-I GEL/M-I BAR/SODA ASH/ POLYPAC / SPERSENE/XP- 20 / SODIUM BICARBONATE/ CAUSTIC HOLE CLEANING/TIGHT HOLE/ BIT BALLING/GUMBO CLAYS/ HOLE ENLARGEMENT/GAS KICKS/ COAL SLOUGHING 1t COST PER BARREL $7.32 ESTIMATED TREATMENTS / PROCEDURES 1) If possible, isolate a small pit volume of surface mud to drill the 18-5/8" collar, cement and shoe. Treat this fluid as required to avoid excessive cement contamination. 2) Displace this mud with uncontaminated surface mud to drill the 17-1/2" hole. 3) Reduce filtrate with Polypac or Polypac UL to 15 cc (API). 4) Control density with barite, F.I.W. water, and solids control equipment. Dump all sand traps as required. If MBT exceeds 25 lbs/bbl, or if low gravity solids exceed 75 ppb, then the system should be diluted to reduce unwanted drill solids. 5) Report drill solids analysis on mud check sheet. 6) Report hydraulics calculations on mud check sheet. 7) Use Defoam-X if foaming becomes a problem · ii':;, DM-131.WP (4/93) It PAGE ,DF l = Drilling Fluids Co. '" / Maacooar IMCO .-~ Oresser. Hall~Durton Company f I 8) Prehydrate ail bentonite in freshwater. 9) Drill to 7500'. Run 13-3/8" casing. 10) Save and re-use mud on wells 30 and 28. ~"~.~.. LOHOEFER ANTICIPATE MUD PROPERTIES Mud Density Funnel Viscosity Plastic Viscosity Yield Point Gels API Fluid Loss pH MBT Drilled Solids 9.0-9.4 ppg 45-65 sec/qt 10-15 cps 10-20 #/100ft~ 6/12/18 15 cc 8.5 - 9.5 < 25 lbs/bbl < 75 lbs/bbl Note: This mud program is a guideline only. should dictate actual properties. Hole conditions 1 DM-131 .WP (4/93) AGE ~F Drilling Fluids Co. j ~ Maacoear. iMCO & Dresser, Hail,burton Company UNOCAL BAKER PLATFORM CHAF~CHATNA DEVELOPMENT #29, #30, AND #28 .',.' L'S, HOEFER ':.." ' ;993, t II 11 DEPTH INTERVAL MUD TYPE MUD ADDITIVES POTENTIAL PROBLEMS COST PER BARREL STANDARD CONTINGENT 12,000' 14,000' 12-1/4" HOLE 8-1/2" HOLE F.I.W. GENERIC MUD #2 W/PHPA POLYMER M-I GEL/M-I BAR/SODA ASH/ PHPA/TACKLE/DRISPAC/XCD POLYMER/PH-6/CAUSTIC/ SODIUM BICARBONATE/ SOLTEX/RESINEX/TEKMUD 8533 TIGHT HOLE/HOLE ENLARGEMENT/GAS KICKS/ LOST CIRCULATION/ PRESSURED SHALE/KEY SEATING/COAL SLOUGHING/ DIFFERENTIAL STICKING $38.00 ESTIMATED TREATMENTS/PROCEDURES 1) Isolate a small pit volume of surface mud to drill the 13-3/8" collar, cement and shoe. Treat this fluid as required to avoid excessive cement contamination. 2) Pre-mix the PHPA system as follows: a) Pre-hydrate 8-10 ppb of bentonite. b) Add PHPA 0.5-1.0 ppb through shearing device. 3) Maintain PHPA concentration at 0.5 - 1.0 ppb. DM-131.WP (4/93) OF ' Driiling Fluids Co. ,, J MagcoDar IMCO A Dresser Hall,burton ComPany I 3.L. LOHOEFER 'PP 993 4) Control density with barite, drill water, and solids control equipment. Dump all sand traps as required. If MBT exceeds 17 ppb, or if low gravity solids exceed 50 ppb, then the system should be diluted to reduce unwanted drill solids. 5) Report drill solids analysis on mud check sheet. 11 6) Report hydraulics calculations on mud check sheet. 7) Use Defoam-X if foaming becomes a problem. 8) Tekmud 8533 may be added to the system to reduce torque and drag. ii I1 9) Use Polypac UL and/or SP-101 for additional fluid loss control. 10) Add Soltex @ 4-6 ppb for coal stability. 11) Drill to T.D. Short trip to check for fill. Log, run, and cement the 7.0" liner. If fluid is in good condition, reuse on next well. 12) If contingent 5" liner is run, treat the PHPA mud system for cement contamination with PH-6 and Bicarb. ANTICIPATED MUD PROPERTIES Mud Density (ppg) Funnel Viscosity(sec/qt) Plastic Viscosity (cps) Yield Point (#/100ft~) Gels (~/100ft~) API Fluid Loss (cc) *HPHT Fluid Loss (cc) MBT (lbs/bbl) Drilled Solids (lbs/bbl) Polymer Conc. (lbs/bbl) 9.5 13.5 40-50 40-65 10-20 12-25 10-25 10-25 4/12/18 6/12/18 5 5 10 10 <17 <17 <35 <35 O.5 0.5 Note: This mud program is a guideline only. should dictate actual mud properties. * 500 psi @ 150°F or BHT +25°F. DM- 131. WP (4/93) Hole conditions FILL- UP Z>> ~ 3"- 10M CHECK VALVE KILL LINE I FLOW I 1 MSP ANNULAR BOP 20%"200o psi I I s?oo~. II %"a000 psil I / i 20%" 3000 psi BLIND RAMS HeR [ ~Oa/,~' 3000 psi HeR _~ [~ MANUAL I DRILLING [ MANUAL Z~> ~ ~01~000~Lp~~~' ' ~ ' ~' ~- -~' ~-' ' ~ CH O KE CATE VALVES [PIPE RAMS]20s/i'3000 psi GATE VALVES i I RISER 203/4'' 3000 psi LINE CHAKACHATNA RIG 428 BOP/DIVERTER STACK 21 +~' 2000psi/20*/~" 3000psi FILL-UP ~ FLOW 3"-10M CHECK VALVE KILL LINE ~ ANNULAR BOP 13%"5000 psi PIPE RAMS 135/s"5000 psi BLIND RAMS 3%"5000 psi HCR ! HCR ~ i~ MANUAL DRILLING I MANUAL ~ ~,q~ ~~ ~ SPOOL ~ ~1T~1~'1] >~ ~~.3%'5ooo ps~ CHOKE 3"-10M/~ ] [' ~ ~ ~~ 4"-10M GATE VALVES ~ ~IpE ~AMS ~13%.5000 psi GATE VALVES LINE RISER 13%" 5000 psi CHAKACHATNA RIG BOPE STACK 13 %" 5000 psi 428 VENT OUTSIDE OF WlNDWALLS 4 4 1/16-5M HUB tY/'BX155~ BUND HUB ~ t5 CLAMP W/ BX155 -~ \ ~ ~/~" -5~ FLO.-~ E VENT UP DERRICK 3' RELIEF VALVE SET AT 40 PSI 1¢ 150 lb. BLIND FLANGE 10' · 150 lb. FLANGE BLIND HUB EIUJ$ ADJ. ~ST CLAMP HUB CONNECTION BUFFER TANK SEPERATOR 150 lb. FLANGE SIPHON LINE 10,000 HYD. CHOKE TO PRODUCTION SEPARATOR I TO SHAKER 8' MUD RETURN UNE UNOCAL CHOKE MANIFOLD COOK INLET DWC. CY-1:12592 I'='"'l I I *~ Imml~l m =, ,.~'r~ , , CU-1:12592 I o A -A PLAN / ., VIEW' @' NORTHWEST:' LEG fl' m~'~lll~ VIE~ A.-A I I I I I ! I ! ! ! I ! ! ! ,, PM RIG 428 l~'~ ~!~ [/, "iii':, ~/" iBLo~OUT PREVENT~ STACK I'/',..1' i1 IN If-e* mr ~ f - 7'-f' l',.-g' il IH f - f':,-I t/l' IIIl~r I - f - r-I Ill' REFERENCE DRAWING 428.50,39 FOR FURTHER INFORUATION PERTAINING TO DIVERTER LINE SPOOLS. DIVERTER UNE LAYOUT NORTHWEST LEO POSITION POOL RIO 4.28 ~ 19-G \ ,Mk fg-B IP~ 19-A I, IK 19.~c ~k I9-g /[ lEK lg-O ilk 19-8 19-8 ! PI~N VIEW ON SOUTHWEST VIEW A-A LEG PLAN ! - r - r'-~ ~/'r VIEW - SHOWN TYP. BOTH EAST LEGS ON NORTHEAST LEG NOTE: REFERENCE DRAWING 428.50J9 FOR FURTHER INFORMATION PERIAINING TO DIVERER LINE SPOOLS. POOL ARCTIC &~ 5601 SItYM'Odo Way DIVER'[ER UNE LAYOUT SOUTHWEST & EAST LEG PosmoNs POOL RI(; 428 TOP OF PIN RA~. J~ FIG X/RJB T I I :l PLAIFOR~ TOP OF BOP STACK :l .: ' ~ ~ POOL A ~ A 16'-~ W~ 14'-~-4.~ W~ 3'-~'19'-7 5/~ W~ ~ 19'-~ W~ 17'-2;19'-6 11/1~ W~ 19'--7 1/1~1 ~1 ~ W~ HIGH PRE~URE RISERS ~YO~ D~~ STACK ~D BOP STAt[ P~ R~O ~ ... I I ~ ~"~ ~ ~ ~v!r.,.~ - ,~, 428. 1ERNATE JPPER PIONEER S-800 SIOEWINOER MUO HOPPER r' I I LIQUIOS (ALT) CENTRIFUGE t, u ~k TRANSFER TO/FROkl PLATr,"ORt/, · #-'-"i-'--l~-': ..... '-~ 't!' i ItlUO STOl?AGE · I I I · I · U') · I ' '~' (-")1 I. ~1. CENTRIFUGE Q I~':i.~ I. CUTTINGS DISCHARGE J I PILL PIT '"' 55 BBL x / I SUCrO~ : "~' - I MOO CLEANFR I I C--' I PIT ~OBBL.," I I · .., .~, ~ ~~ i L ~.,~gl I -" _..~ t .... I OESANOER I ~ PiT "i''~ I ii'"--' I I " 'l ' ,,~f ll x~ P/rO£C'ASSER L ~ . , 105 BBL · .... SAND TRAP OV~3~rLOl~' , $0 BBL WE-IIR I I I I ! I UP?C~GE ' ...... · PUMP $0Ll05 ~ ...... ..... t.t.~.s.._ .......... }{ .... ~- ~2~.~ · ......... _. ~ .~r~r~ ............. ~ I. PUMP I ........ /.~ GUN . PUMP ~ I ............... PUMP I ~ · N OE~OER · PUMP I PUMP SCRE E;.,'F'D Ut'IDERFLO~t I ~ : · PIONEER T8.-6 . OESANDER · i ! CU171NGS DISCHARGE j F 9" MUD CLEANER J / SCRE.'W , CONVEYOR Ii TRI-FLO TFI-16 MUD CLEANER ::~" SUCTIOI~ SIRAINER __ DITCH GATES J~ ~"..~ BOFI'OM EOUALIZER ,~ ~ .... OVER FLOW ~'EIR DU,¥fP VALVE -- ~ VALVE ~1~ ~/' ADJUSTABLE MUD GUN ~/~ MUD AGITATOR (~ SUCTION VALVE Jt~3G~T I ISSUED JUL 2 0 1995 POOL ~ ALASKA MU~ P',JP, P .f". OiL?,'E£L A-1/OOPT REVISED PRIRT DESTROY PREVIOUS ISSUE 5~Q1 ~ ~,~ ~ SCHEI~IAI'lC LOW PRESSURE MUD SYSTEM UNOCAL CHAKACHAI'NA PROJECT PM RIG 4.28 I .t ~o~ m. ~.~ ~, ~,w, adu J / ~ I'"~!'~ I lC? I":"'1'"~ '""'"-~1 - I'~' I 4.28.5011 I" STORAGE TRANSFER FROM PLAtfORM WELL: BAKER ~29 1. MUD WT. I 8.8 PPG 2. 9.0 PPG 3. 9.5 PPG CASING SIZE FIELD: MIDDLE GROUND SHOAL CASING DESIGN DATE: AUGUST 1, 1993 WEIGHT TENSION W/ BF -TOP OF INTERVAL DESCRIPTION W/O BF X SECTION BOTTOM TOP LENGTH WT. GRADE THREAD LBS LBS 1. 24" 800' 56' MD 744 800' 56' TVD 2. 18-5/8" 2000' 56' MD 1944 2000' 56' TVD · 3. 13-3~8" 6200' 56' MD 6144' 6100' 56' TVD 4. 9-5/8" 9924' 56' MD 9868' 8829' 56' TVD 156~, X-42, MTS 60 AR 116,064 SAME 97#, X-56, QTE 60 188,568 SAME 68#, K-55, BTC 417,792 SAME 47~, L-80, BTC 463,796 SAME DESIGN BY: C.L. LOHOEFER M.S.P. 280 psi 595 psi 729 psi MINIMUM COLLAPSE COLLAPSE STRENGTH PRESS @ RESIST. BURST TENSION BOTTOM TENSION PRESSURE 1000 LBS TD~ PSI PSI CDF PSI 1928 16.61 229 860 3.75 350 1970 1594 8.45 572 960 1.69 1372 2630 1069 2.55 1744 1950 1.12 1986 3450 1086 2.34 3973 4750 1.20 1986 6870 MINIMUM YIELD PSI BDF 5.63 1.92 -- 1. i~ 3.46 NOTES: See attached for calculation of M.S.P. including assumptions & estimates. Rotary Kelly Bushing (RKB) Drill Deck Level Production Deck Level Elev. 118' Bev. 78' Bev. 62' Sea Level (MLW) Bev. O' Mud Line Elev. - 102' 30" Structural @ 303' RKB (83' BLM) 24" Conductor @ 800' RKB (580' BML) 156#, X-42, MTS6OAR 18-5/8" Surface @ 2000' 97#, X-56, QTE60 13-3/8'° Intermediete @ 6200' 68#, K-55, BTC 9-5/8" Production @ 10915' 47#, L-80, BTC BAKER PLATFORM ELEVATION DIMENSIONS UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 7- 15-92 FILE' BAKELEV. drw Baker Platform Well #29 Pressure Calculations August 01, 1993 Depth Interval: 0 - 800' 17-1/2" / 28" hole size 24" casing Mud weight· 8 8 PPG = 46 psi/ft ee·lee®eleeeee·eelle®le··e·eee · · · Shoe (24" ) depth: .............................. 800 ' MD/800 ' TVD Estimated fracture gradient (24" shoe): .......... 0.85 psi/ft. Total depth: ................................. 2000'MD/2000'TVD Bottom hole pressure gradient: ................... 0.35 psi/ft. Maximum surface pressure cannot exceed maximum bottom hole pressure: 800' * 0.35 psi/ft = 280 psi Depth Interval: 800' - 2000' 17-1/2" / 24" hole size 18-5/8" casing Mud weight· 9 0 PPG = 47 psi/ft · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · · Shoe (18-5/$") depth: ....................... 2000'MD/2000'TVD Estimated fracture gradient (15-5/8" shoe): ...... 0.85 psi/ft. Total depth: ................................. 6200'MD/6100 'TVD Bottom hole pressure gradient: ................... 0.45 psi/ft. Gas gradient (assume worst case) .................. 0.0 psi/ft. Wellbore volume with gas kick situation: 3/4 mud & 1/4 gas. Maximum surface pressure = Btm hole press - Hydrostatic press MSP = BHP - (3/4 mud + 1/4 gas) MSP=(6100 ft * .45 psi/ft) - ((·75 (6100 ft * .47psi/ft.)) + (.25 (6100 ft * 0 psi/ft.))) MSP = 595 psi. Therefore, the greatest hydrostatic pressure at the 18-5/8" shoe (HPsh) is when the gas bubble reaches the shoe if a constant BHP is applied. A conservative estimate would be the maximum surface pressure (MSP) plus the hydrostatic pressure at that casing depth (HPcsg). HPsh = MSP + HPcsg HPsh = 595 psi +(2000 ft * HPsh = 1535 psi · 47 psi/ft. ) Baker Platform Well ~29 This (HPsh = 1535 psi) is less than the fracture pressure at the same shoe (FPsh = .85 psi/ft * 2000 ft = 1700 psi) and thus sufficiently adequate to handle the well kick. Depth Interval: 2000' - 6200' 17-1/2" hole size 13-3/8" casing Maximum surface pressure calculation; Mud weight: ............................. 9.5 PPG = .49 psi/ft. Shoe (13-3/8") depth: ....................... 6200'MD/6100'TVD Estimated fracture gradient (13-3/8" shoe): ...... 0.90 psi/ft. Total depth: ................................. 9924'MD/8829'TVD Bottom hole pressure gradient: ................... 0.45 psi/ft. Gas gradient (assume worst case) .................. 0.0 psi/ft. Wellbore volume with gas kick situation: 3/4 mud & 1/4 gas. Maximum surface pressure = Btm hole press - Hydrostatic press MSP = BHP - (3/4 mud + 1/4 gas) MSP=(8829 ft * .45 psi/ft) - ((.75 (8829 ft * .49psi/ft.)) + (.25 (8829 ft * 0 psi/ft.))) MSP = 729 psi. Therefore, the greatest hydrostatic pressure at the 13-5/8" shoe (HPsh) is when the gas bubble reaches the shoe if a constant BHP is applied. A conservative estimate would be the maximum surface pressure (MSP) plus the hydrostatic_~ pressure at that casing depth (HPcsg). ~;~,~;i~"~!~i~,!~,.? ~'~ HPsh = MSP + HPcsg HPsh = 729 psi +(6100 ft * .49 psi/ft.) HPsh = 3717 psi HPsh - Pore Pressure at shoe ( Yield 13-3/8" cas~n~"~::~':~'~~ 3717- (6100''0.45) < 3450 972 psi < 3450 psi This (HPsh = 3717 psi) is less than the fracture pressure at the same shoe (FPsh = .90 psi/ft * 6100 ft = 5490 psi) and thus sufficiently adequate to handle the well kick. These scenarios are considered extreme since actual well kicks of recent history have seen a maximum of 300 psi on the shut-in casing pressure. ,/ . Unocal Energy Reso~ Division Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 263-7602/276-7600 Facsimile 263-7698 UNOCAL Kevin A. Tabler Land Manager Alaska BY REGISTERED MAIL August 13, 1993 Mr. R.G. Blackburn Shell Western E&P Inc. 601 West 5th Avenue; Suite 810 AnChorage, Alaska 99501-2257 Baker Platform Well #29 Middle Ground Shoal Area Cook Inlet, Alaska Application for Spacing Exception Dear Mr. Blackburn' Pursuant to 20 AAC 25.055, please be advised that Union Oil Company of California (Unocal) is seeking approval of a spacing exception for the above-referenced well, to be located 510' FSL and 383'FWL of Section 31, Township 9 North, Range 12 West, S.M. Unocai's application to the Alaska Oil and Gas Association was submitted today. Very truly yours, Elizabeth A.R. Shepherd Landman CC: Mr. Doug Burbank C 0 SENDEI~: · Complete items 1 and/or 2 fo~' a(Jditional services. · Complete items 3, and 4a & b. · Print your name and address on the reverse of this form so that we can return this card to you. · Attach this form to the front of the mailpiece, or on the back if space does not permit. · Write "Return Receipt Requested" on the mailpiece below the article number. · The Return Receipt will show to whom the article was delivered and the date delivered, ~. sl~natUr~ (Agent) ' -- I also wish to receive the following services (for an extra fee): 1. [] Addressee's Address 2. J--] Restricted Delivery Consult postmaster for fee. 4a:.~rticle Number i 4~b.~8'ervice Type n- ~ Registered [] Insurecl [] Certified [] COD .=_ [] Express Mail [] Return Receipt for ", , Merchandise 7. Date of Delivery O 8. Addressee's Address (Only if requested ..~ and fee is paid) DOMESTIC RETURN RECEIPT · , . PS Form 38~ ~, December 1991 ~ U,S.G.P.O.: 1992-307-530 Memorandum UNOCAL ) Pre-Spud Drilling Prognosis Baker Platform July 28, 1993 The following information is intended to familiarize the individual with the upcoming drilling program at Baker Platform. Though this drilling prognosis is not a detailed drilling procedure it should serve as an outline. Many ongoing plans within Unocal and other service companies can and will change this program. Please read it carefully. Batch drilling (Baker wells #28, 29, 30) thru the 13-3/8" casing depths is a planned objective and is expected to yield many practical benefits. Benefits - Eliminates (12) NU/ND requirements of Div/BOPE. - Eliminates RU/RD of dimensional OD equipment. - Allows drilling mud to be re-cycled. - Less transportation of equipment. - Increases crew familiarization with opers. - Improves safety in all aspects. - Minimizes consumable inventory & prioritize usage. - Increases geologic interpretation time allowed. - Maximizes equipment utilization. - Develops learning curve quicker. - Maximizes overall efficiency in all operations. - Decreases well interference (collision) problems. Batch Drilling Procedure ******* STAGE ONE ******* Well #29 (24" Casing) 1) 2) 3) 4) Install 30" drilling nipple or diverter system and drill 17-1/2" hole to 800' MD. Underream from 17-1/2" hole section to 28". Run and cement 24" casing to 800'. Secure wellbore, skid rig to next well #30. FORM 1-0C03 (REV. 8-85) PRINTED IN U.S.A. Baker Pre-Spud Drilling Prognosis July 28, 1993 Page 2 Well ~30 (24" Casing) 1) 2) 3) 4) Install 30" drilling nipple or diverter system and drill 17-1/2" hole to 800' MD. Underream from 17-1/2" hole section to 28". Run and cement 24" casing to 800'. Secure wellbore, skid rig to next well #28. Well ~28 (24" Casing) 1) 2) 3) Install 30" drilling nipple or diverter system and drill 17-1/2" hole to 800' MD. Underream from 17-1/2" hole section to 28". Run and cement 24" casing to 800'. ******* STAGE TWO ******* Well #28 (18-5/8" Casing) 1) 2) 3) 4) Nipple up combination 20-3/4" 3M BOPE / Diverter System. Drill 17-1/2" hole to 2600' underream same to 24" Run and cement 18-5/8" casing to 2600'. Secure wellbore, skid rig to well #29. Well ~29 (18-5/8" Casing) 1) 2) 3) 4) Nipple up combination 20-3/4" 3M BOPE / Diverter System. Drill 17-1/2" hole to 2000' underream same to 24" Run and cement 18-5/8" casing to 2000'. Secure wellbore, skid rig to well #30. Well ~30 (18-5/8" Casing) 1) 2) 3) Nipple up combination 20-3/4" 3M BOPE / Diverter System. Drill 17-1/2" hole to 2000' underream same to 24" Run and cement 18-5/8" casing to 2000'. Baker Pre-Spud Drilllng Prognosis July 28, 1993 Page 3 STAGE THREE ********* Well ~30 (13-3/8" Casing) 1) 2) 3) 4) Nipple up combination 20-3/4" 3M BOPE. Drill 17-1/2" hole to 6200' MD. Run and cement 13-3/8" casing to total depth. Secure wellbore, skid rig to well #28. Well #28 (13-3/8" Casing) 1) 2) 3) Nipple up combination 20-3/4" 3M BOPE. Drill 17-1/2" hole to 6000' MD. Run and cement 13-3/8" casing to total depth. Secure wellbore, skid rig to well #29. Well ~29 (13-3/8" Casing) 1) 2) 3) Nipple up combination 20-3/4" 3M BOPE. Drill 17-1/2" hole to'6200' MD. Run and cement 13-3/8" casing to total depth. This completes the batch drilling process. Each well is now drilled to total depth (12-1/4") using the 13-5/8" 5M BOPE stack and completed one at a time. Since Well #29 is the last well of recent work it will be the first well drilled to total depth and completed. ** CHECK LIST FOR NEW WELL PERMITS ** ITEM APPROVE DATE (1) Fee ~8]~ (2) Loc. [ 2 thru [9 thru 13] 10. [10 & 13] 12. 13. Ca g [14 thru 22] 15. [23 thru 28] (5) BOPE (6) Other ~ r~u~ I~ 29 th geology' engineering: RPC~.~ B~ dDH~ TAB~-~z~ rev 6/93 jo/6.011 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26 27 28. Company UA) o~ / YES 1. Is permit fee attached ............................................... 2. Is well to be located in a defined pool .............................. 3, Is well located proper distance from property line ................... 4. Is well located proper distance from other wells ..................... 5. Is sufficient undedicated acreage available in this pool ............. 6. Is well to be deviated & is wellbore plat included ................... 7. Is operator the only affected party .................................. 8. Can permit be approved before 15-day wait ............................ 29. 30. 31. 32. Does operator have a bond in force ................................... Is a conservat,ion order needed ....................................... Is administrative approval needed .................................... Is lease nLmber appropriate .......................................... Does well have a unique name & nL[nber ................................ Is conductor string provided .......................................... Will surface casing protect all zones reasonably expected to serve as an underground source of drinking water .................. Is enough cement used to circulate on conductor & surface ............ Will cement tie in surface & intermediate or production strings ...... Will cement cover all known productive horizons ..................... Will all casing give adequate safety in collapse, tension, and burst. Is well to be kicked off from an existing wellbore ................... Is old wellbore abandonment procedure included on 10-403 ............. Is adequate wellbore separation proposed ............................. Is a diverter system required .............. .. ......................... Is drilling fluid program schematic & list of equipment adequate ..... Are necessary diagrams & descriptions of diverter & BOPE.attached .... Does BOPE have sufficient pressure rating -- test to ps~g ..... Does choke manifold comply w/API RP-53 (May 84) ....... ,. .............. Is presence of H2S gas probable ...................................... FOR EXPLORATORY & STRATIGRAPHIC WELLS: Are data presented on potential overpressure zones ................... Are seismic analysis data presented on shallow gas zones ............. If offshore loc, are survey results of seabed conditions presented... Name and phone ntrnber of contact to supply weekly progress data ...... 33. Additional requirements ............................................. INITIAL GEOL UNIT ON/OFF POOL CLASS STATUSAREA SHORE UM Exp/(~2< Inj... MERIDIAN: WELL TYPE: SM ~ Red ri 1 l~ Rev om m z Well HistorY File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Tape Subfile 1 is type: LIS **** REEL HEADER **** DIPLOG 94/ 3/29 01 DIPLOG ACCELEROMETER CORRECTED RAW DATA **** TAPE HEADER **** DIPLOG 01 Tape Subfile: 1 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes Tape Subfile 2 is type: LIS **** FILE HEADER **** DIPLOG.000 1024 CN : UNOCAL WN : BAKER NO. 29 FN : MIDDLE GROUND SHOAL COUN : KENAI STAT : ALASKA LIS COMMENT RECORD(s): Raw Diplog pad curves AZ = Pad 1 Azimuth CALl = Diplog 1-3 Caliper CAL2 = Diplog 2-4 Caliper DAZ = Hole Direction DEV = Borehole Deviation GR = Diplog Gamma Ray PADn = Diplog Pad data RB = Relative Bearing TTEN = Total Tension Data has been accelerometer corrected. * FORMAT RECORD (TYPE# 64) Alaska Oil & 6as Cons. Anchorage ONE DEPTH PER FRAME Tape depth ID: F 12 Curves: Name Tool Code Samples Units API API API API Log Crv Crv Size Length Typ Typ Cls Mod 1 AZ 1016 68 1 DEG 2 CALl 1016 68 1 IN 3 CAL2 1016 68 1 IN 4 DAZ 1016 68 1 DEG 5 DEV 1016 68 1 DEG 6 GR 1016 68 1 GAPI 7 PAD1 1016 68 1 MMHO 8 PAD2 1016 68 1 MMHO 9 PAD3 1016 68 1 MMHO 10 PAD4 1016 68 1 MMHO 11 RB 1016 68 1 DEG 12 TTEN 1016 68 1 LB 4 4 91 439 74 6 4 4 66 621 06 0 4 4 88 796 02 5 4 4 96 142 46 6 4 4 88 796 02 5 4 4 88 796 02 5 4 4 14 577 53 5 4 4 13 922 17 5 4 4 13 266 81 5 4 4 12 611 45 5 4 4 25 903 74 6 4 4 88 047 74 6 48 * DATA RECORD (TYPE# 0) 994 BYTES * Total Data Rec~ords:i- 10544 Tape File Start Depth = 9030.000000 Tape File End Depth = 5900.000000 Tape File Level Spacing = 0.015625 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 2604174 datums Tape Subfile: 2 10549 records... Minimum record length: Maximum record length: 62 bytes 994 bytes Tape Subfile 3 is type: LIS .... **** TAPE TRAILER **** DIPLOG 01 **** REEL TRAILER **** DIPLOG 94/ 3/29 01 Tape Subfile: 3 2 records... Minimum. record length: 132 bytes Maximum record length: 132 bytes End of execution: Tue 29 MAR 94 12:42p Elapsed execution time = 1 minute , 51.3 seconds. SYSTEM RETURN CODE = 0