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Home My WebLink About193-119MEMORANDUM 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:10582 ft MD Lease No.:ADL 0017595 Operator Rep:Suspend:P&A: Conductor:24"O.D. Shoe@ 803'Feet Csg Cut@ Feet Surface:18-5/8"O.D. Shoe@ 2140 Feet Csg Cut@ Feet Intermediate:13-3/8"O.D. Shoe@ 5683 Feet Csg Cut@ Feet Production:9-5/8"O.D. Shoe@ 10529 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:2 @ 3-1/2"O.D. Tail@ 8427 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Long String Fullbore Bottom 10476 ft 6146 ft 9.8 ppg Wireline tag Short String Fullbore Bottom 10476 ft 6590 ft 9.8 ppg Wireline tag Initial 15 min 30 min 45 min Result LS Tubing 2180 2022 1971 SS Tubing 2180 2022 1971 IA 2180 2022 1971 OA 75 75 80 OOA 112 110 110 OOOA 170 180 180 Remarks: Attachments: Dual completion, both tubing strings 31/2 inches. Depth of lowest open perf at time of cement job was 10476 ft MD. Used 13/4- inch tool string and roller stem used to get down . The long string took 3 runs with various sizes to get down to a good tag at 6146 ft before getting some good cement back in the bailer SS cement and tag were both good. Passing test with 2 bbls pumped and 1.9 bbls returned. Well Status left as shut in 1-Oil completion. August 23, 2025 Kam StJohn Well Bore Plug & Abandonment MSG ST 17595 Baker-28 Hilcorp Alaska LLC PTD 1931190; Sundry 324-552 none Test Data: P Casing Removal: Brad Whitten Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 3-24-2022 2025-0823_Plug_Verification_MGS_State_17595_Baker-28_ksj                         see Remarks 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, March 26, 2025 3:44 PM To:Casey Morse Subject:RE: Baker Temperature Surveys - Baker 28 (PTD 193-119) 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 Casey, I agree that this Baker 28 temperature log indicates that flow is going past the pump into the perfs below it. Hilcorp has authorization to proceed with the approved sundry 324-552 based on this log result satisfying the following condition of approval copied from the sundry. I’ll address Baker 29 separately since that sundry has not yet been approved. I will consider the results of the log when considering the sundry. Regards 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: Tuesday, October 29, 2024 12:03 PM 2 To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Baker Temperature Surveys 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 find 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. HilcorpWell:BA #28Field:Baker10/10/20244060801001201400500100015002000250030003500400016 17 18 19 20 21 22 23 24 25 26Temperature (Deg.F)Pressure (psia)Time (hrs)PressureTemperatureGauge at depth8446' RKBPulling out of holeStaticGoing in Hole StaticReport date: 10/16/2024 Well Name:MGS ST 17595 28 API #:50733204550000 Field:Middle Ground Shoal Permit #:193119 Sundry #:324-552 10/10/2024 Daily Operations: Weekly Operations Summary Rotate hatch cover over Ba-28. M/u riser to LS. Change tool string to 1.25" w/ roller stem. Stab lubricator and PT to 2000psi-good test. Run #1 RIH w/ 1.75"x4' DD bailer. Having trouble falling. POOH and change tool string to 1.75" w/ roller stem and 2.75" gauge ring. Run #2- RIH w/ 2.75" GR tagging Kobe at 8459' SLM (8448' KB), POOH. Run #3- RIH w/ temp survey tool at 60 fpm to 8446' KB. Inject FIW down IA at 2.75 bpm, 1200 psi (FCP 1325 psi). Inject 430 bbls ;ĞŶƐƵƌŝŶŐĐŽůĚ&/tŐŽƚƚŽƉĞƌĨƐͿ͘/ŶũĞĐƟŶŐĂĚĚŝƟŽŶϰϰďďůƐƚŽŵĂŬĞƐƵƌĞƚĞŵƉĞƌĂƚƵƌĞƐƐƚĂďŝůŝǌĞ;ŝŶũĞĐƚĞĚĂƚŽƚĂůŽĨϰϳϰďďůƐͿ͘ POOH at 60 FPM. Data showing temperature decreasing and stabilizing at Kobe where sensor was parked. Page 1 of 1 1 Gluyas, Gavin R (OGC) From:Casey Morse <Casey.Morse@hilcorp.com> Sent:Tuesday, October 15, 2024 3:57 PM To:McLellan, Bryan J (OGC) Cc:Juanita Lovett Subject:Baker P&A Status Bryan, In order to get ahead of the winter weather, we started rigging down the equipment on the Baker on Sunday. Here is a brief overview of where we left oƯ with each of the approved sundries and some plans / questions for going forward. Ba-04 (Sundry 324-502)  Approved work completed  Preparing 10-404 submittal Ba-31 (Sundry 324-387)  Approved work completed  Preparing 10-407 submittal Ba-25RD (Sundry 324-526)  Approved work completed  Preparing 10-404 submittal Ba-05 (Sundry 324-367)  Not all approved work is completed. Remaining work scope includes witnessed CMIT and tags of the LS and SS.  Given that we rigged down before completing the CMIT and tags, should we continue with the wellsite inspection before November 1, 2024, as per the sundry? If so, we can coordinate this with our Lighthouse crew.  Our plan is to prepare a 10-407 when the remaining work is completed as part of next year’s activities. Ba-11 (Sundry 324-365)  Not all approved work is completed. Remaining work scope includes witnessed CMIT and tags of the LS and SS.  Cementing did not go to plan due to a pump failure during the job. I will send you a separate email detailing the status of this well, so we can discuss a plan forward operationally.  Our plan is to prepare a 10-404 when the remaining work is completed as part of next year’s activities. Ba-23 (Sundry 324-357)  Not all approved work is completed. While running the CIBP into tubing on E-line, the plug hung up and we lost the tool string in the well. We did several days of fishing with slickline and were unable to recover the fish. I will send a separate email to detail our status on this well, so we can discuss a plan forward operationally. 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. 2 Ba-28 (Sundry 324-552)  None of the approved sundry work was performed.  Per the condition of approval, we conducted a temperature survey while injecting down the IA. I will send you the survey results in a separate email, so we can hopefully progress this sundry work in next year’s program. Thank you, 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. 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?N/A 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): 10,582 N/A Casing Collapse Structural Conductor Surface Intermediate 1,950psi Production 4,750psi 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 Middle Ground Shoal Middle Ground Shoal Oil N/A 7,383 10,582 7,383 2,543psi N/A 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 AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Operations Manager STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0017595 193-119 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 50-733-20455-00-00 Hilcorp Alaska, LLC MGS ST 17595 28 Length Size Proposed Pools: 303' 303' L-80 TVD Burst 8,427 6,870psi MD 3,450psi 803' 2,042' 3,509' 803' 2,140' 7,331'9-5/8" 303' 30" 24" 18 5/8" 803' 13-3/8"5,683' 2,140' 10,529' Perforation Depth MD (ft): 5,683' 8,546 - 10,473 10,529' 5,407 - 7,276 10/8/2024 3-1/2" N/A & N/A N/A & N/A 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 4:09 pm, Sep 24, 2024 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267) Date: 2024.09.24 15:48:32 - 08'00' Dan Marlowe (1267) 324-552 Variance to 20 AAC 25.112(c)(1)(D) is conditionally approved. See variance request and condition of approval below in the attached procedure. 10-404 DSR-9/27/24 X A.Dewhurst 26SEP24BJM 10/4/24 Provide 48 hrs notice for AOGCC opportunity to witness CMIT LSxSSxIA to 1900 psi, and TOC tag on LS and SS. JLC 10/7/2024 Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.07 13:59:50 -08'00' 10/7/24 RBDMS JSB 100824 Abandon MGS Oil Pool Program Well: Ba-28 Well Name: MGS ST 17595 28 (Ba-28) API Number: 50-733-20455-00-00 Current Status: Shut-In Producer Rig: SL, FB, cement Estimated Start Date: Sept 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): 2510 psi @ 5083’ TVD (Ca. 2008 SBHPS, EMW: 9.5 ppg) Max. Anticipated Surface Pressure: 2543 psi Gas Column Gradient (0.1 psi/ft) Current Pressures (LS/SS/IA/OA/OOA): 70/135/805/725/0 psi Max Deviation: 71.2 deg @ 5214’ 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 55 bbl pill of LCM was pumped down the LS and displaced w/ 97 bbls to plug off the perforations. Notes: 30” conductor pipe set at 303’. 24” Surface Casing @ 803’ MD and cemented w/ 440 bbls 15.8 ppg cement. Returns were lost while cementing with 275 bbls away on an inner string cement job. Assuming a 50% excess for surface washouts and accounting for the losses, the top of cement is calculated at 16’ MD. A 17 bbl top job was pumped in the 24” x 30” annulus, top of cement is at surface. The float and cement were drilled to within 10’ of shoe on the 24” casing. A pressure test was conducted at 1000 PSI for 5 minutes prior to drilling the float collar. During the pressure test, pressure leaked off at 20 psi/min, and the shoe was determined to be wet. A subsequent leak off test was performed at 0.94 psi/ft. 18-5/8” Casing @ 2140’ MD. The intermediate casing was tested to 2000 PSI. The casing was cemented using 784 bbls of cement – Returns were lost while cementing with 290 barrels away on inner job. Returns were regained after slowing pump rate, averaging 10% returns for the remainder of the job. Assuming 50% washout in open hole, TOC calculated at 1123’ MD. 13-5/8” Casing @ 5683’ MD. The 13-3/8” Annulus was cemented using 673 barrels of cement and pressure tested to 2700 PSI. No losses were noted in the drilling report, but the mud report references 103 bbls of mud lost to formation during cementing. Taking that loss and 50% washout into account, estimated TOC is at 2612’ MD. 9-5/8” Casing @ 10,565’ MD. The 9-5/8” casing was cemented with 615 barrels of cement with no returns. The annulus went on a vacuum post cementing. The SBT showed good quality bond with the top radially continuous bond at ~7,050’. Cement quality deteriorates above 7,000’ with no apparent cement coverage above ~6,500’. Current Status Shut-in. The LS, SS, and IA were circulated with 8.6 ppg FIW. Pre-P&A Diagnostics Performed Abandon MGS Oil Pool Program Well: Ba-28 1. Initial pressures (LS/SS/IA/OA/OOA/OOOA): 90 / 160 / 810 / 700 / 450 / 25 psi 2. Pump 8.6 ppg FIW: a. Pump down LS up IA, FCP 385psi / 2.7 BPM b. Pump down IA up LS, FCP 240psi / 2.7 BPM c. Pump down IA up SS, FCP 475psi / 2.7 BPM d. Pump down SS up IA, FCP 330psi / 2.7 BPM e. Pump down SS up LS, FCP 400psi / 2.6 BPM f. Pump down LS up SS, FCP 425psi / 2.7 BPM 3. Bled down OA to 50 psi, OOA to 0psi, then OOOA to 0psi. No communication observed across annuli during bleeds. 4. Attempt to inject down LS: 1.5 bpm @ 500psi, 2 bpm @ 725psi, 2.5 bpm @ 925psi. 5. RU slickline on LS. a. RIH w/ 2.80” gauge ring, tag at 8454’ SLM on Kobe cavity. b. RIH w/ D&D Holefinder to 8416’ SLM. Set tool and PT to 575 psi for 5 mins – GOOD. 6. Check annulus pressures 1 month later: IA 200 psi, OA 670 psi, OOA 200 psi, OOOA 0 psi. a. Bled off 670 psi from OA. Gas showed LEL. Top off OA w/ 89bbls FIW, pressure up to 570 psi, lost 10 psi in 15 min (good test). Bled down to 25 psi and shut in. No change in pressure on other annuli. b. Bled off 200 psi from OOA. Gas showed LEL. Top off OOA w/ 60bbls FIW, pumping at 1 bpm pressured up to 480 psi, broke over to 400 psi, slow pump to 0.6 bpm and built pressure to 500 psi. Lost 100 psi in 15 min (fail test). Bled down to 68 psi and shut in. No change in pressure on other annuli. c. Top off OOOA w/ 8 bbls FIW, pressure up on OOOA to 560 psi, lost 40 psi in 15 min (good test). OOA went from 68 psi to 115 psi while pressuring up the OOOA, then dropped to 90 psi when OOOA was bled to 0 psi. Objective Plug the MGS Oil Pool perforations in the Ba-28. 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 8453’ (93’ 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 circulating point and the lowest open perforations at 10473’ MD, the Middle Ground Shoal Oil Pool as defined in Conservation Order 44 A. Procedural steps Slickline Diagnostics 1. RU slickline on SS. a. RIH w/ 2.75” gauge ring to Kobe cavity. If successful, MU Holefinder tool. RIH to ~8400’. Set Holefinder and PT tubing to over 500 psi for 5 minutes. b. If unable to make it to bottom with gauge ring, MU ponytail tool. Establish circulation down SS and up LS. RIH and confirm flow path is out bottom of SS. Fullbore 1. Fluid pack the tubing strings and IA with 9.8 ppg brine. Variance approved on the condition that the injected fluid is confirmed to be injecting below the KOBE pump into the perfs and not into a 9-5/8" casing leak above the KOBE cavity. Pump-in temperature log or other Leak Detection log is likely required. Submit log to AOGCC and obtain approval before pumping cement. -bjm Abandon MGS Oil Pool Program Well: Ba-28 2. Pump reservoir abandonment cement plug as follows: ¾ 30 bbls RIW (Raw-Inlet-Water) w/ Surfactant Wash (down Tbg and out IA) ¾ 247 bbls 14 ppg Class G cement. Record volumes of fluid recovered i. Start pumping down LS and out IA ii. After 147 bbls returned from IA (IA cement volume of 73 bbls plus LS volume of 74 bbl), close IA and open SS iii. Return 13 bbls from SS, close SS valve iv. Pressure up on LS (max of 1000 psi on LS/SS/IA) and squeeze 87 bbls cement v. Drop foam wiper ball vi. Pump 61 bbls 9.8 ppg brine displacement while squeezing into perfs to place 148 total bbls cement into perfs. ¾ 61 bbls of 9.8 ppg brine displacement puts TOC in LS/SS/IA @ ~7000’ 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. ¾ LS volume from ported sub to 7000’: 0.0087 bpf * (8453’-7000’) = 13 bbls ¾ SS volume from Kobe to 7000’: 0.0087 bpf * (8448’-7000’) = 13 bbls ¾ IA volume from ported sub to 7000 = 73 bbls o 8453 to 8448: 0.0613 bpf * 5’ = 0.5 bbls (tubing tail x liner) o 8448 to 7000: 0.0494 bpf * 1448’ = 72 bbls (LS/SS x IA) ¾ Casing / tubing volume from ported sub to 10473’: 0.0732 bpf * (10473’-8453’) = 148 bbls ¾ LS/SS volume from 7000’ to surface: 0.0087 bpf * 7000’ = 61 bbls ¾ IA volume from 7000’ to surface: 0.0494 bpf * 7000’ = 346 bbls Fullbore/Slickline 1. CMIT LSxSSxIA to 2140 psi (AOGCC Witnessed). Top perf TVD ~ 8542 ft 2. Tag TOC in LS and SS (AOGCC Witnessed). Cement Tops: x 18-5/8” Casing: Estimated TOC @ 1123’ o Annulus volume: 2140’ to 803’: 1337 ft * 0.2226 bpf = 298 bbl + 50% washout = 446 bbl 803’ to surf: 803 ft * 0.01548 bpf = 124 bbl o Total cement pumped: 784 bbl o Lost returns after 290 bbl pumped. Regained 10% returns for remainder of job 784 – 290 = 494 bbl 10% * 494 = 49.4 bbl 290 + 49.4 bbl = 339.4 bbl cement into annulus o Assume 50% washout in open hole 339.4 / (0.2226 * 1.5) = 1017 ft 2140 – 1017 = 1123 ft o OOOA pressure test held at 500 psi x 13-3/8” Casing: Estimated TOC @ 2612’ o Annulus volume: Abandon MGS Oil Pool Program Well: Ba-28 5683’ to 2140’: 3543 ft * 0.1237 bpf = 438 bbl + 50% washout = 658 bbl 2140’ to surf: 2140 ft * 0.1271 bpf = 272 bbl o Total cement pumped: 673 bbl. Less 103 bbl estimated losses = 570 bbl 570 / (0.1237 *1.5) = 3071 ft 5683 – 3071 = 2612 ft o OOA pressure test failed at 500 psi x 9-5/8” Casing: SBT run 3/20/94 o OA Pressure test held at 500 psi Attachments Current Schematic Proposed Schematic Updated by: CM 9/24/24 Middle Ground Shoal Well: Ba-28 (MGS ST 17595 #28) Last Completed: 03-23-1994 PTD: 193-119 API: 50-733-20455-00 SCHEMATIC Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 30 Structural B -Welded 29.000 Surf 303 Driven 24 Conductor 156, X-42, MTS60AR 22.500 Surf 803 1.9ºSurface 18-5/8 Surface Csg 97#, X-56, QTE 60 17.500 Surf 2140 42º ETOC 1123 13-3/8 Intermediate 68#, K-55, BTC 12.415 Surf 5683 70.6º ETOC 2612 9-5/8 Production 47#, L80, Buttress 8.681 Surf 10529 7000 SBT Completion Long String 3-1/2” Prod Tubing 9.2#, L-80 SC Buttress 2.992 Surf 8427 Short String 3-1/2” Prod Tubing 9.2#, L-80 SC Buttress 2.992 Surf 8427 Completion Jewelry Detail # Depth Length ID OD Item Long String (Power Fluid) Hanger @ x 8427 2.992 3.500 3-1/2” 9.2#, L-80 SC Buttress Tubing (RA Tag in collar at 8400’ MD) 8448 1.48 2.687 6.50 KOBE 3” Standing Valve Shoe Short String (Production) Hanger, @ x 8427 8427 2.992 3.500 3-1/2” 9.2#, L-80 SC Buttress Tubing Tail Assembly 8427 20.72 3.00 7.25 Trico Kobe Cavity Assembly 8449 3.01 2.430 5.25 KOBE Gun Trigger Assembly 8453 2.23 2.938 4.25 3-1/2” Balanced Isolation Tool 8468 .87 2.375 4.625 2-1/8” Pressure Transfer Sub 8534 5.34 3.375 Model K & APF-C Firing Heads 8539 6.5 6.00 6” Blank Gun 8546 6.00 6” Vann Gun (Top Shot) 424 6.00 6 Vann Gun 12 SPF 8970 6.00 6” Vann Gun (Bottom Shot) 64 3.375 3-3/8” Gun Spacer Section 9034 4-5/8” Vann Gun (Top Shot) 1439 4.625 4-5/8” Vann Gun 6 SPF 10473 4-5/8” Gun (Bottom Shot) .70 ---4.625 Bottom Plug (8/05)Static BHP=9.0 ppg.& Tubing bundle test to 1500 psi –good. Two un-cemented & sidetracked ghost holes f/ 3700-4835’ & 2760-5566’. Uncemented gas sand f/ 2200-2400’ w/ fairly strong mud log gas. 24” LOT 14.1 ppg EMW (Wet shoe after cement job & 50’ top job); 18-5/8 LOT 13.6 ppg EMW; 13-3/8 LOT 14.4 ppg EMW 18-5/8” casing has centralizers on joints 1, 2, 33, and 49. FISH None Perforation Data Doglegs 4.8 1707 Top Bottom Status 4.31 2368 8546 8970 Open 3.54 6060 9034 10473 Open 4.57 7922 PBTD =10582’ TD = 10582’’ MAX HOLE ANGLE = 71.2º@ 5214’ MD 30” 303’ RKB: MSL = 118’ Mudline= 203’ Water Depth= 102’ 9-5/8” 10529’ Perfs 9034’ – 10473’ 24” 803’ 18-5/8” 2140’ Perfs 8546’ – 8970’ TOC 7000’ 13-3/8” 5683’ ETOC 1123’ ETOC 2612’ MGS Oil Top 8520’ 9.8 ppg Brine Base MGS Gas 7529’ OCTG Rotating Hours 20” 56 Rotating Hours 18-5/8 98 Rotating Hours 13-3/8” 108 Rotating Hours 9-5/8”” Min Rotating Hours Updated by: CM 9/24/24 Middle Ground Shoal Well: Ba-28 (MGS ST 17595 #28) Last Completed: 03-23-1994 PTD: 193-119 API: 50-733-20455-00 SCHEMATIC Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 30 Structural B -Welded 29.000 Surf 303 Driven 24 Conductor 156, X-42, MTS60AR 22.500 Surf 803 1.9ºSurface 18-5/8 Surface Csg 97#, X-56, QTE 60 17.500 Surf 2140 42º ETOC 1123 13-3/8 Intermediate 68#, K-55, BTC 12.415 Surf 5683 70.6º ETOC 2612 9-5/8 Production 47#, L80, Buttress 8.681 Surf 10529 7000 SBT Completion Long String 3-1/2” Prod Tubing 9.2#, L-80 SC Buttress 2.992 Surf 8427 Short String 3-1/2” Prod Tubing 9.2#, L-80 SC Buttress 2.992 Surf 8427 Completion Jewelry Detail # Depth Length ID OD Item Long String (Power Fluid) Hanger @ x 8427 2.992 3.500 3-1/2” 9.2#, L-80 SC Buttress Tubing (RA Tag in collar at 8400’ MD) 8448 1.48 2.687 6.50 KOBE 3” Standing Valve Shoe Short String (Production) Hanger, @ x 8427 8427 2.992 3.500 3-1/2” 9.2#, L-80 SC Buttress Tubing Tail Assembly 8427 20.72 3.00 7.25 Trico Kobe Cavity Assembly 8449 3.01 2.430 5.25 KOBE Gun Trigger Assembly 8453 2.23 2.938 4.25 3-1/2” Balanced Isolation Tool 8468 .87 2.375 4.625 2-1/8” Pressure Transfer Sub 8534 5.34 3.375 Model K & APF-C Firing Heads 8539 6.5 6.00 6” Blank Gun 8546 6.00 6” Vann Gun (Top Shot) 424 6.00 6 Vann Gun 12 SPF 8970 6.00 6” Vann Gun (Bottom Shot) 64 3.375 3-3/8” Gun Spacer Section 9034 4-5/8” Vann Gun (Top Shot) 1439 4.625 4-5/8” Vann Gun 6 SPF 10473 4-5/8” Gun (Bottom Shot) .70 ---4.625 Bottom Plug (8/05)Static BHP=9.0 ppg.& Tubing bundle test to 1500 psi –good. Two un-cemented & sidetracked ghost holes f/ 3700-4835’ & 2760-5566’. Uncemented gas sand f/ 2200-2400’ w/ fairly strong mud log gas. 24” LOT 14.1 ppg EMW (Wet shoe after cement job & 50’ top job); 18-5/8 LOT 13.6 ppg EMW; 13-3/8 LOT 14.4 ppg EMW 18-5/8” casing has centralizers on joints 1, 2, 33, and 49. FISH None Perforation Data Doglegs 4.8 1707 Top Bottom Status 4.31 2368 8546 8970 Open 3.54 6060 9034 10473 Open 4.57 7922 PBTD =10582’ TD = 10582’’ MAX HOLE ANGLE = 71.2º@ 5214’ MD 30” 303’ RKB: MSL = 118’ Mudline= 203’ Water Depth= 102’ 9-5/8” 10529’ Perfs 9034’ – 10473’ 24” 803’ 18-5/8” 2140’ Perfs 8546’ – 8970’ TOC 7000’ 13-3/8” 5683’ ETOC 1123’ ETOC 2612’ 247 bbl cement w/ 148 bbl squeezed into perfs MGS Oil Top 8520’ 9.8 ppg Brine Base MGS Gas 7529’ OCTG Rotating Hours 20” 56 Rotating Hours 18-5/8 98 Rotating Hours 13-3/8” 108 Rotating Hours 9-5/8”” Min Rotating Hours Pages NOT Scanned in this Well History File XHVZE 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 vadous kinds [] Other COMMENTS: Scanned by: ianna Vincent Nathan Lowell TO RE-SCAN Notes: Re-Scanned by: Bevedy Dianna Vincent Nathan Lowell Date: Is~ 2011 March's Baker /Dillon Produce Well Report • Page 1 of 1 Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Friday, April 15, 2011 1:32 PM To: Maunder, Thomas E (DOA); Regg, James B (DOA) Cc: Cole, David A; Ross, Gary D; Tyler, Steve L; Quick, Mike [ASRC] Subject: 2011 March's Baker /Dillon Production Well Report Attachments: Master Well List TIO Report 2011 03 31.xls Hi Tom & Jim, rc) \ \Q Here is March's monthly report for the Baker and Dillon monitored production wells. The pressures on the Baker 11, 25RD & 28 wells continue the unexpected increases mentioned last month. Both 11 & 25RD look to be increasing slowly, but 28 may have leveled off. Drilling is aware of these pressures and are making sure the abandonment plans for the Baker wells address any wellbore concerns. All the other wells are still showing the same general up trend or seasonal trend (like Di -6) in pressures and appear to show no other pressure anomalies. The general pattern of stable or slowly rising pressures for the Dillon wells continued this month and most of the Baker wells have stabilized. Larry «Master Well List TIO Report 2011 03 31.xis» ALANNEDAPR 1 8 201) 4/18/2011 Plot essure & Rate vs Time - Well Ba -28 • 1600 1400 1 1200 .4 1 rn 1000 /./ 4N,/ E n 800 ._ _. -_._ - _.- -- -_ -__.._ __. ....._..- __. t --`n. V. a` 600 re 400 I -9 5/8" 13 3/8" 200 16.. 26" Tubing -- Tubing 2 o co m m m m rn rn co rn CD CD CD CD CD CD m 0 P P 0 0 P P P 0 P 0 0 0 P P P 0 P P P 0 0 0 P P P P 0 0 0 0 0 co r 0 W co t-- n 0 u] in V V Cl N V N) M N N j O o a Co" 0 r Cr) e CO N N N N N N N N N N N N N N N N N N N N N N N N g O N N 2 8 8 8 8 0 P 0 a N 2 8 0 O 8 8 O 0 N `O N 2 P .- o O O O O P O O O '- � P O O O P O O O O r' O O O Date 9 5/8" 13 3/8" 16" 26" '111bing ` Tubing' TIO Report 04/01/11 700 700 370 50 50 0 02/16/11 690 700 370 50 0 o Data Sheet 02/03/11 ` 660 700 370 50 50 0 01/20/11 670 690 370 50 50 0 12/17/10 t 650 660 370 50 0 0 Ba -28 11/09/10 - 0 670 375 50 0 0 10/31/10 '' 0 590 375 60 0 0 10/30/10 1 0 550 375 60 0 0 BOT HOLE HYD PUMP 10/29/10 0 510 375 60 0 0 10/28/10 0 420 375 60 0 0 10/27/10 ` I 415 375 60 0 0 Permit # 1931190 10/26/10 S 350 370 60 0 10/25/10 0 710 375 50 0 10/24/10 = 720 375 50 API # 50- 733 - 20455 -00 10/23/10 0 710 375 50 0 0 10/22/10 , 0 710 375 50 0 0 10/21/10 ;0 710 375 50 0 09/30/2008 to 04/01/2011 10/20/10 ' 0 710 375 50 0 10/19/10 ; 0 710 375 50 0 10/18/1 i0 710 375 50 0 10/17/10 ", 0 710 375 50 0 0 10/16/10 '_0 710 375 50 0 0 10/10/10 " 500 715 375 55 `, 1125 10/09/10 1500 720 370 55 1130 795 10/08/10 1500 710 375 55 1115 795 10/07/10 - - .1500 720 375 55 1125 770 10/06/10 z 1500 710 375 55 1125 800 10/05/10 ' 1500 720 375 55 1110 790 10/04/10 x'1500 720 375 55 1110 790 10/03/10? 1500 720 375 59 1 1115 790 10/02/10 1500 715 375 55 1115 800 10/01/10 :.. 715 375 55 1120 800 09/30/10 ,# 710 375 60 1120 795 09/29/10 1500 715 375 55 1120 79r 09/28/10 1500 715 375 60 1120 790 09/27/10 1500 710 375 55 112E snr 4/18/2011 5:02 PM - TIO Reports 7e.xls J J Dolan Master Well List TIO Report 2011 03 31 (6).xls Ba -28 . . 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 December 8, 2006 RECEIVED DEC 0 8 2006 Alaska Oil & Gas Cons. Commission Anchorage Commissioner John Norman Alaska Oil & Gas Conservation Commission 333 W. ih Avenue Anchorage, Alaska 99501 SCA.~.n\'Er;) DEt: 2 (t) 200') Re: Baker Well No. 28 ~q:;-ll~ Dear Commissioner Norman, During the 2005 work program on Baker Platform, Well No. 28 was found to have a temperature anomaly at approximately 5,000 feet MD. Pursuant to last year's correspondence to the AOGCC, Chevron has conducted an annual temperature survey on Baker 28 to monitor the well status. Attached you will find a 10-404 with the results from this years survey. The survey conducted in August of this year indicates that the anomaly at 5,000 feet MD is stable and does not indicate a change in profile. Chevron intends to continue the annual temperature monitoring program as set forth last year. Also attached for your consideration is the summary of the Baker 28 anomaly provided to the Commission last year. If you have any questions, please contact me at 907-263-7657. Sincerely, ~ L.../ Timothy C. Brandenburg Drilling Manager Attachments Cc: Dale Haines David Cole Union Oil Company of California I A Chevron Company http://www.chevron.com I u...VL..1 V I::U . STATE OF ALASKA _ ALAS"'bIL AND GAS CONSERVATION cOMM~QEC 0 8 2006 REPORT OF SUNDRY WELL OPEIM~IONS C C " a"DTJ'&"'Gas ons. ommlsslon 1. Operations Abandon Performed: Alter Casing D Change Approved Program D 2. Operator Name: Repair Well Pull Tubing D Ope rat. ShutdownD Plug Perforations Perforate New Pool D Perforate D 4. Well Class Before Work: Development 0 ' StratigraphicD Stimulate r J Shut-In Waiver D Time ExtensionD Re-enter Suspended Well D 5. Permit to Drill Number: 1931190 6. API Number: 50-733-20455-00-00 . 9. Well Name and Number: Baker 28 m4 ~ .st· 17se1Ç ¿ß 10. Field/Pool(s): Middle Ground Shoal, A Oil, B, C and D Oil, E, F and G ExploratoryD Service D Union Oil Company of California 3. Address: PO Box 196247, Anchorage, AK 99519 7. KB Elevation (ft): 118' 8. Property Designation: Baker Platform 11. Present Well Condition Summary: ¿!;a.vÞi. Total Depth measured 10,582' feet true vertical 7,383 feet Effective Depth measured 10,582' feet true vertical 7,383 feet Casing Length Size MD Structural 83' 30" 83' Conductor 803' 24" 803' Surface 2,140' 18-5/8" 2,140' Intermediate 5,683' 13-3/8" 5,563' Production 10,565' 9-5/8" 10.565' Liner Perforation depth: Measured depth: 8,546' to 10,456' Plugs (measured) n/a Junk (measured) n/a TVD Burst Collapse 83' 802' 2,042' 2,510 psi 880psi 3,509' 3,450 psi 1,950 psi 7,365' 6,870 psi 4,760 psi True Vertical depth: 5,409' to 7,268' Tubing: (size, grade, and measured depth) Dual completion. See schematic for tubing detail. Packers and SSSV (type and measured depth) N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Oil-Bbl o o Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure o 0 1,260 o 0 1,260 Tubing Pressure 1,056 1,056 13. 15. Well Class after work: ExploratoryD 16. Well Status after work: oilD Gas 0 . 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Development 0 Service D x WAG D GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. Exempt: Contact Timothy C. Brandenburg Title Drilling Manager Signature Phone 907-276-7600 Date 12/8/2006 l_ Form 10-404 Revised 04/2006 0 R , G , N A L ~ DEC 26 2006 i:-\~/;}1.o /2.' z,t.. Of,. Submit Original Only 500 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 1000 1500 8000 8500 50 60 70 80 90 100 110 120 130 Temperature (Deg, 18 5/8" 13 3/8" ~ Tubing Temperature 7-03-05 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 1 Executive Summary: Baker well 28 is an oil well on the shut-in Baker Platform. It was completed in March of 1994 as a dual, packer-less, KOBE cavity pump well. The well is currently shut in with pressure on the dual tubing strings, all the casing annuli, and a small amount of gas fizzing between the 30" conductor and 24" surface casing. Baker 28 was identified as a plugging candidate due to its annuli pressure in the 2005 campaign. Preliminary diagnostics on the well consisted of a pressure and temperature survey, bleeding of casing pressures, and tubular integrity testing. The diagnostic summary showed Baker 28 capable of flowing unassisted with a static bottom hole pressure (BHP) equaling a 9.0 ppg equivalent. The tubing has integrity and the 9%" production casing appears to have integrity based upon the temperature survey. The annuli are pressured with gas with recharge capacity. In addition, a temperature cooling anomaly was found behind the intermediate 13%" casing at approximately 5,000' MD. A review of the well files from the original drilling campaign shows that generally poor primary cementing was achieved on each of the casing strings. The temperature anomaly at 5000' MD is interpreted as gas flow behind pipe. The gas flow may be due to a cement channel outside the 13%" casing, or it could be gas flow through a "ghost hole" sidetrack around a lost drilling assembly. The source and thief zones are apparently in ..' close proximity. Evaluation ofthe mechanical condition of the wellbore confirms that it poses no threat of reaching the surface. Likewise, the ability to recover the gas resource is likely not substantially impaired by cross flow into slightly shallower sands. Remedial squeezing is not recommended, not only due to a low chance of success but also since it is likely that substantial cross flow has already occurred in the 11 years ofthe well's life. Placing additional holes in the casing in order to conduct squeeze operations will likely only further compromise the completion with additional leak paths. / Baker 28's resource potential is currently being evaluated along with the overall platform viability. The well poses no additional risk in its present condition, and Chevron plans to leave the well shut in during the evaluation period. If deemed uneconomic, this well will be abandoned properly in the future in conjunction with a large scale abandonment program on the Baker platform. The discussion that follows is an engineering assessment of each well annulus. The annuli have been assigned letter designations with the innermost annulus (i.e. dual tubing x 9%" production casing) being assigned "A". Each subsequent outer annulus is assigned a progressive letter. The attached wellbore diagram lists these annuli designations. The discussion begins with the outermost annulus and progresses inward. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 2 E Annulus (30" Conductor x 24" Surface Casine:): The E annulus is defined as the 30" conductor by 24" surface casing. The 24" casing extends down to 803' MD (802' TVD). The 24" casing was cemented with 440 bbl of cement. Returns were lost while cementing with 275 bbl away on an inner string cement job. Assuming a 100% excess for surface washouts, the top of cement is calculated at 370' MD. The 30" shoe is at 303' MD. A small amount of gas is fizzing at the exposed cement top on the 24" by 30" annulus. The 24" casing was tested to 1,000 psi for 5 minutes prior to drilling the float collar. The float and cement was drilled to within 10' of the shoe. Another pressure test was attempted, and it was discovered that the shoe was wet. A subsequent leak off test was recorded at 0.94 psi/ft referencing MSL. A value of 14.1 ppg EMW was recorded referencing RKB for the fonnation below the shoe. A 17 bbl top job was pumped, which equates to approximately 50' of annular head in the 24" x 30" casing. There was no record whether this top job was placed with pipe or free poured in the annulus. The lithologic description is as follows: Interval 100' - 800' MD (30" Conductor & 24" Surface Casing) Although log data starts at 600' MD and mud log descriptions at 380' MD, it appears that this interval is dominantly sand and sandy conglomerate with a few interbedded coals of up to 10' thick. The sandstones appear wet on the logs and mud log gas curve, although there is a slight increase in background methane at the base of a sand which occurs at 750' - 790' MD. E Annulus Summary: Although there is a srp.all amount of gas liberating around the 24" casing, it is most likely coming from the coals in the surface interval as noted in the geologic description. The potential gas sand (750' -790') in the lower interval is covered with cement. Even with the losses encountered during cementing, the lowennost portion ofthe 24" surface casing should have sufficient coverage to prevent vertical migration. With the top job of cement placed in the top 50' of the annulus, no further remedial activities are possible. Based on the 370' top of cement and 220' from RKB to mud-line, only ±150' of formation are exposed. D Annulus (24" Surface Casine: bv 18%" Intermediate): The D annulus is defined as the 24" surface casing at 803' MD by 18%" intennediate casing. The 18%" intennediate casing extends down to 2140' MD (2042' TVD). The 18%" casing was cemented with 784 bbl of cement. Returns were lost while cementing Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 3 with 290 bbl away on an inner string job. Assuming a 50% excess for washout, the top of cement is calculated at 1300' MD. The 18%" casing was pressure tested to 2,000 psi. As noted in the E Annulus summary, the shoe strength of the 24" surface casing is 14.1 ppg EMW. The formation test performed after drilling out the 18%" casing at 2174' was recorded as 13.6 ppg EMW. No additional cement work was performed on the 18%" intermediate casing. There is presently 110 psi of trapped pressure on the D annulus. The lithologic description is as follows: Interval 800' - 2100' MD (18%" Surface casing) This interval is comprised of the typical Cook Inlet succession of interbedded sandstones, tuffaceous (ashy) clay stones and coals. There are at least 15 individual coal seams scattered throughout this interval, ranging in thickness from 2' - 23' (MD). The first coal-related gas show occurs at 1130' MD; above this depth the coals are all largely inert. Below this depth, coals are all degassing to varying degrees of intensity. Sand bodies in this interval range from 20' to 80' thickness. The first increase in background methane in a sand occurs immediately below the coal at 1130' MD. Generally, sands in this interval do not exhibit gas shows much in excess of background. Any mobile gas in this interval is likely evolving from the coals rather than escaping from sands. The mud log suggests that the interval from 1600' to 1800' MD is dominantly comprised oftuffaceous clay stone with two coal seams of 15' and 20' thickness. This interval may act as a seal to the upward migration of gas in the surface casing annulus if it has collapsed against the pipe. D Annulus Summary: It is believed the cement quality from the 18%" shoe at 2140' MD up to ±1300' MD is sufficient to prevent vertical gas migration. For this interval, a worst case BHP pressure at 1300' MD (1296' TVD) is exerted on the surface shoe at 803' TVD. The interval was drilled with a 9.0 ppg mud, therefore the highest gas pressure at 1300' MD is 606 psi (i.e. 1296' x 0.052 x 9.0 ppg). The hydrostatic pressure of gas from 1296' TVD up to 803' TVD is 49 psi assuming 0.1 psi/ft gas gradient. Therefore, the EMW on the 24" surface casing shoe is calculated to be 13.3 ppg [i.e. (606 psi - 49 psi) / 803' /0.052], which is less than the 14.1 ppg leakoff test recorded. The maximum gas pressure on surface would be 476 psi assuming a full column of gas down to 1300' MD with a reservoir pressure of9.0 ppg. The 24" casing was pressure tested to 1000 psi as noted in the E Annulus Summary above. A separate evaluation confirmed that there is no risk of exceeding collapse limitations on the 18%" casing or burst limitations on the 24" casing. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 4 C Annulus 08%" Intermediate x 13%" Intermediate): The C annulus is defined as the 18%" intermediate casing at 2140' MD by 13%" intermediate casing. While drilling the 17Yz" hole section in Baker 28, two unplanned sidetracks were made around lost drilling assemblies. There was no opportunity to cement these two "ghost holes", the first of which was drilled from ±3700' to 4835' MD (±2809' - 3215' TVD) and the second of which was drilled from 2761' to 5566' MD (2430' - 3448' TVD). The 13%" intermediate casing extends down to 5683' MD (3509' TVD). The 13%" casing was cemented with 673 bbl of cement. No losses were recorded on the original drilling report, but a loss of 103 bbl of cement was recorded in the daily mud report along with a record of 438 bbl mud being left behind pipe. The previous day's drilling report indicated the well lost 80 bbl mud to the formation while logging and preparing to run casing. For the purpose of calculating the top of cement, the 673 bbl of cement pumped was adjusted to 540 bbl behind pipe (30 bbl in the 13%" shoe plus 103 bbllosses). The top of cement is therefore estimated at 2900' MD using the given information while assuming a 50% excess. With the previous casing shoe at 2140' MD, ±760' offormation is exposed behind the 13%" casing. The 13%" casing was pressure tested to 2,700 psi. As noted in the D Annulus summary, the shoe strength ofthe 18%" intermediate casing is 13.6 ppg. The formation test performed after drill out was recorded as 14.4 ppg EMW. No additional cement work was performed on the 13%" intermediate casing. There is presently 375 psi of gas pressure on the C annulus. A significant cooling temperature anomaly was noted behind the 13%" casing during the 2005 preliminary diagnostic testing. The anomaly is confined to an interval from 5200' MD (3349' TVD) up to 4600' MD (3144' TVD). The hole inclination here is approximately 70 degrees so the anomaly that spans a 600' measured length represents a 205' vertical distance. Chevron interprets the cooling anomaly to be gas flowing behind the 13%" casing. The conduit for the gas flow may be a channel in the cement behind 13%" casing, which would not be unusual in a 70 degree hole section. Another strong possibility is that flow is occurring through one or both of the uncemented "ghost holes". The lithologic description is as follows: Interval 2100' - 5600' MD (13%" Intermediate casing) This interval is comprised mostly of very thick-bedded sandstones and sandy conglomerates. Individual sand bodies of 50' to 400' thick are common. Interbedded coals range in thickness from 10' to 60' MD, and commonly exhibit gas shows of 20-60 units in excess of background. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 5 There is a 200' thick assemblage of sandstone bodies at 2200' to 2400' MD which display fairly strong mud log gas shows of up to 200 units above background. It is possible that this sand series is capable of producing gas into the annular space behind the 13%" intennediate casing. Other thick assemblages of sand are observed deeper at 2450' - 2700' MD and 3150' - 3600' MD, but these are void of gas shows. There is a thick interval oftuffaceous clay stone and coal which occurs from 2700' - 3150' MD which may act as a seal to the upward migration of gas in the 13%" intennediate casing annulus if these lithologies have collapsed against the pipe. Still more sand-related gas shows are observed at 3690' - 3870' MD, 4630' - 4670' MD and 4750' - 4870' MD. These shows are not as strong as those observed above or below. Fairly strong gas shows of up to 180 units above background are again seen in sands in the interval from 5020' - 5205' MD; these shows may indicate mobile gas that could migrate into the 13%" intennediate casing annulus. (Recall that there may be an annular seal above this interval at 2700' - 3150' MD in the clay stone/coal section described above. ) To summarize, there are at least two thick intervals of gas-charged sands that could provide mobile gas to the 13% intennediate casing annulus (2200' - 2400' and 5020' - 5200' MD). Gas liberated from these intervals could conceivably migrate upward in the casing annulus to charge any of the lower pressure sand bodies above. C Annulus Summary: Although the primary cement job on the 13%" intennediate casing encountered losses, it is believed that cement exists up to ±2,900' MD. There is no bond log to provide quality assurance of the cement, but the cement is expected to be of sufficient quality to prevent gross fluid migration to the 18%" shoe. Cement quality has perhaps been compromised in localized areas due to channeling as noted on the temperature log. Alternately, the two sidetracks around lost drilling assemblies could provide a path for fluid migration. There are two main issues to be analyzed. The first is the lack of cement at the 18%" casing shoe in conjunction with the gas bearing zone open to the 18%" x 13%" annulus. The second issue is the temperature anomaly behind the 13%" casing. As noted from the mud log, a gas sand is present from 2200' MD (2087' TVD) to 2,400' MD (2223' TVD). The associated BHP assuming a 9.0 ppg gradient is 1040 psi (i.e. 2223' x 0.052 x 9.0 ppg). The equivalent mud weight on the 18%" shoe is 9.8 ppg (i.e. 1040 psi / 2042' /0.052), which is well below the 13.6 ppg leak off recorded. Assuming a gas gradient to surface, the highest anticipated pressure on the 18%" x 13%" casing is Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 6 836 psi. An evaluation confirmed that there is no risk of exceeding collapse limitations on the 13%" casing or burst limitations on the 18%" casing. The attached graph depicts the temperature anomaly encountered in Baker 28. The graph also depicts the depths of the two ghost holes from the original drilling operation. The interpretation of the anomaly is that the gas bearing zone from 5,020' - 5,200' MD is cross flowing upwards to other sands. The gas does not appear to be flowing upwards beyond 4,600' MD as the temperature profile returns to normal. The worst-case pressure scenario would be the gas pressure measured from 5200' MD (3,349' TVD) exerted on the formation at 4600' MD (3,144' TVD). Assuming a 9.0 ppg original formation pressure, the 1567 psi (i.e. 9.0 ppg x .052 x 3349') would exert an EMW of9.6 ppg at 4,600' (3144' TVD). With the well having been drilled over 11 years ago, it is reasonable to assume that significant cross flow has already taken place. It should be recognized that mobile hydrocarbons are present but do not pose a risk to the well bore or the sands above. In addition, there is no indication that resources are being wasted due to this cross flow. Chevron would expect the gas to still be severable and recoverable. Finally, the only viable remedial option to stop any additional cross flow would be to perforate through the 9%" and 13%" casing strings and perform a squeeze. Chevron believes that a squeeze operation will have, at best, a low likelihood of success and very well could exacerbate mechanical problems in the wellbore. Chevron recommends that no action be taken to isolate the apparent cross flow taking place at ±5000' MD. B Annulus (13%" Intermediate x 9%" Production Casine:): The B annulus is defined as the 13%" intermediate casing at 5683' MD by 9%" production casing. The 9%" production casing extends down to 10,565' MD (7,365' TVD). While running the 9%" casing, the pipe became stuck at 10,529' MD and subsequently packed off. The 9%" casing was cemented with 615 bbl of cement with no returns. The annulus went on a vacuum post cementing. A Segmented Bond Tool (SBT) was run to evaluate the need for remedial cementing. No additional cementing work was required as sufficient cement existed for the intended target oil zones. The uppermost perforation in Baker 28 is at 8,546' MD. An analysis ofthe SBT is as follows: 10,477' - 8,400' Good cement quality. No apparent channels. 8,400' -7,000' Step change in cement quality. Possible channels noted on log. Generally adequate cement to prevent vertical migration of fluids. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 7 6,460' - 5,600' Spotty cement with occasional sealing of vertical fluid movement. Ringing pipe with no cement isolation. Well most likely packed off at 6,460' MD (3,850' TVD) during cementing. 7,000' - 6,460' As noted in the C Annulus summary, the shoe strength ofthe 13%" intermediate casing was measured at 14.4 ppg. There is presently 700 psi of gas pressure on the B annulus. The lithologic description is as follows: Interval 5600' -7100' MD (behind 9%" casing) This section is dominated by non-reservoir facies such as tuffaceous silty claystones and coals, interbedded with thinner and more widely dispersed sandstone bodies. All of the coals in the section - which range from 10' to 50' thick - appear to be degassing. Numerous sandstones within the section also display prominent gas shows. The gas shows from both coals and sands in this section are noticeably richer than those observed above; C2, C3 and C4 gases are observed in this section, whereas the shallower shows are almost entirely composed of methane (Cl). B Annulus Summary: The worst case pressure scenario would be gas pressure measured from 6460' MD (3,850' TVD) exerted on the 13%" shoe at 5683' MD (3,509' TVD). Assuming a 9.0 ppg original formation pressure yields a pressure of 1802 psi (i.e. 3850' x 9.0 ppg x 0.052). This 1802 psi would exert an EMW of9.9 ppg at 5,683' MD, which is well below the 14.4 ppg EMW leak off test. The 700 psi that is presently on the B annulus is assumed to be gas on mud as a straight gas column would yield approximately 1400 psi surface pressure. The 13%" was tested to 2,700 psi and the collapse pressure of 9%" casing is 4760 psi. Conclusions Baker 28 should be left shut in pending Chevron evaluation of the resource potential from the Baker platform. Chevron will continue monitoring surface pressure and well status on a routine basis, including running annual temperature surveys. Chevron recommends that the best approach to the temperature anomaly noted at ±5000' MD is to leave it alone. Chevron will submit a 10-403 application to the AOGCC prior to commencing any efforts to either return the well to production or initiating plugging operations. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . . Well Ba-28 Casing and Cement Evaluation Baker Platform Page 8 E D C B A Fizz gas 303' MD, 302' TVD, 30" - Driven 803' MD, 802' TVD, 24" 156# - Cemented with 440 bbl, lost all returns @ 275 bbl, TOC estimated @ 370' (100% excess), wet shoe. Pumped a 17 bbl- 50' Top Job. LOT = 14.1 ppg EMW 2140' MD, 2042' TVD, 18%" 97# - Cemented with 784 bbl, lost all returns @ 290 bbl. TOC estimated @ 1300' (50% Excess). LOT = 13.6 ppg EMW 5683' MD, 3509' TVD, 13%" 68# - Cemented with 673 bbl. Daily drilling recorded no information on losses. Mud reports recorded 438 bblleft behind pipe and 103 bbllost while cementing. Best estimate of TOC @ 2900' MD. With 50% excess, mud down to and cement up to ±2,900'. LOT = 14.4 ppg EMW 10,565' MD, 7365' TVD, 9%" 47# - Cemented with 615 bbl. Casing was stuck and packed off during cement job. Annulus was on a loss. Cement good up to 8,400'. Quality change in cement 8,400' to 7,000' with some channeling. Spotty cement wI probable vertical sealing up to 6,460'. 100% Free pipe up to top of log @ 5,600'. Baker 28 summary of cement - AOGCC.doc October 10, 2005 Wen Ba-28 Casing and Cement Evaluation Baker Platform Page 9 Pressure (psia) 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 4000 4100 4200 4300 4400 4500 4600 4100 4800 4900 5000 J:.: ..... 2" 5100 C 5200 5300 5400 5500 5600 5700 5800 5900 6000 90 95 100 105 Temperature (Deg. Baker 28 summary of cement - AOGCC.doc October 10, 2005 . ~ ... ie . ~. l 30· Structural @ 83' BlM ...... ...... 24· Conductor @ S03' 156#,X42, MTS60AR 1S-5/S· Surface @ 2140' 97#, X-56, QTE60 ...... ....... ...... ....... ...... ...... 13-3/S' Intermediate @ 5683' 6S#, K-55, BTC ...... ...... ...... ...... COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC ë.1 2) KOBE BHA F/8436'-8457' ~. 3) TCP guns 4-5/8" & 6" 00 F/8546'-10465' @ INTERVALS 'C . 65 RKB = 118' 9-5/S· Production @ 10565' 47#, L-SO, BTC BAKER 28 ACTUAL COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 07-06-94 FILE: BA28.drw ) ) Chevron III 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 10, 2005 o ~ LOÛ~ SC~~En ~O\J RECEIVED OCT 1 0 2005 Alaska Oil & G C . as ons. Commu;$ion AnchOf8{9 Commissioner John Norman Alaska Oil & Gas Conservation Commission 333 W. th Avenue Anchorage, Alaska 99501 \q3-\\Df,.J ß \\ " '}-'ó Re: Baker Platform Pilot Pre-Abandonment Work Summary Dear Commissioner Norman, This letter is intended to update the Alaska Oil and Gas Conservation Commission on the status of Unocal'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 Platform was shut-in August 2003. Unocal commenced the pilot study with a diagnostic program on five water inj ection wells and three oil wells on the Baker Platform in July 2005. The diagnostic program consisted of pressure and temperature surveys for baseline data, mechanical integrity of the completion, injectivity tests to the formation, 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 (BlIP) 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. "UPUCATE Union Oil Company of California / A Chevron Company http://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, .--:7 ~- ~ é'- .2 ~ c---~ /~ ~ /' ß Timothy C. Brandenburg Drilling Manager Attachments Cc: Dale Haines Gary Eller Union Oil Company of California / 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 -J ul-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 Inject9f 6-Jul..Op 7080 6066 2976 0.491 9.4 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-J ul-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 ---7 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-Jul-05 10966 9109 3593 0.394 7.6 .~ Ba-31 Producer 29-Jul-05 11 433 10636 3795 0.357 6.9 Ba-32 Producer No survey ) ') Well Ba-28 Casing and Cement Evaluation Baker Platform Page 1 Executive Summary: Baker well 28 is an oil well on the shut-in Baker Platform. It was completed in March of 1994 as a dual, packer-less, KOBE cavity pump well. The well is currently shut in with pressure on the dual tubing strings, all the casing annuli, and a small amount of gas fizzing between the 30" conductor and 24" surface casing. Baker 28 was identified as a plugging candidate due to its annuli pressure in the 2005 campaign. Preliminary diagnostics on the well consisted of a pressure and temperature survey, bleeding of casing pressures, and tubular integrity testing. The diagnostic summary showed Baker 28 capable of flowing unassisted with a static bottom hole pressure (BHP) equaling a 9.0 ppg equivalent. The tubing has integrity and the 90/8" production casing appears to have integrity based upon the temperature survey. The annuli are pressured with gas with recharge capacity. In addition, a temperature cooling anomaly was found behind the intermediate 130/8" casing at approximately 5,000' MD. A review of the well files from the original drilling campaign shows that generally poor primary cementing was achieved on each of the casing strings. The temperature anomaly at 5000' MD is interpreted as gas flow behind pipe. The gas flow may be due to a êëiñent channel outside the 130/8" casing, or it could be gas flow through a "ghost hole" sidetrack around a lost drilling assembly. The source and thief zones are apparêntly in close pro-ximity. Evaluation of the mechanical condition of the wellbore confirms that it poses no threat of reaching the surface. Likewise, the ability to recover the gas resource is likely not substantially impaired by cross flow into slightly shallower sands. Remedial squeezing is not recommended, not only due to a low chance of success but also since it is likely that substantial cross flow has already occurred in the 11 years of the well's life. Placing additional holes in the casing in order to conduct squeeze operations will likely only further compromise the completion with additional leak paths. Baker 28' s resource potential is currently being evaluated along with the overall platform viability. The well poses no additional risk in its present condition, and Chevron plans to leave the well shut in during the evaluation period. If deemed uneconomic, this well will be abandoned properly in the future in conjunction with a large scale abandonment program on the Baker platform. The discussion that follows is an engineering assessment of each well annulus. The annuli have been assigned letter designations with the innermost annulus (i.e. dual tubing x 90/8" production casing) being assigned "A". Each subsequent outer annulus is assigned a progressive letter. The attached wellbore diagram lists these annuli designations. The discussion begins with the outermost annulus and progresses inward. Baker 28 summary of cement - AOGCC October 10, 2005 J ) Well Ba-28 Casing and Cement Evaluation Baker Platform Page 2 E Annulus (30" Conductor x 24" Surface CasinlÜ: The E annulus is defined as the 30" conductor by 24" surface casing. The 24" casing extends down to 803' MD (802' TVD). The 24" casing was cemented with 440 bbl of cement. Returns were lost while cementing with 275 bbl away on an inner string cement job. Assuming a 10d% excess for surface washouts, the top of cement is calculated at 370' MD. The 30" shoe is at 303' MD. A small amount of gas is fizzing at the exposed cement top on the 24" by 30" annulus. The 24" casing was tested to 1,000 psi for 5 minutes prior to drilling the float collar. The float and cement was drilled to within 10' of the shoe. Another pressure test was attempted, and it was discovered that the shoe was wet. A subsequent leak off test was recorded at 0.94 psi/ft referencing MSL. A value of 14.1 ppg EMW was recorded referencing RKB for the formation below the shoe. A 17 bbl top job was pumped, which equates to approximately 50' of annular head in the 24" x 30" casing. There was no record whether this top job was placed with pipe or free poured in the annulus. The lithologic description is as follows: Interval 100' - 800' MD (30" Conductor & 24" Surface Casing) Although log data starts at 600' MD and mud log descriptions at 380' MD, it appears that this interval is dominantly sand and sandy conglomerate with a few interbedded coals of up to 10' thick. The sandstones appear wet on the logs and mud log gas curve, although there is a slight increase in background methane at the base of a sand which occurs at 750' - 790' MD. E Annulus Summary: Although there is a small amount of gas liberating around the 24" casing, it is most likely coming from the coals in the surface interval as noted in the geologic description. The potential gas sand (750' - 790') in the lower interval is covered with cement. Even with the losses encountered during cementing, the lowermost portion of the 24" surface casing should have sufficient coverage to prevent vertical migration. With the top job of cement placed in the top 50' of the annulus, no further remedial activities are possible. Based on the 370' top of cement and 220' from RKB to mud-line, only ±150' of formation are ex posed. D Annulus (24" Surface Casin2 by 18%" Intermediate): The D annulus is defined as the 24" surface casing at 803' MD by 180/8" intermediate casing. The 180/8" intermediate casing extends down to 2140' MD (2042' TVD). The 18%" casing was cemented with 784 bbl of cement. Returns were lost while cementing Baker 28 summary of cement - AOGCC October 10, 2005 ) ') Well Ba-28 Casing and Cement Evaluation Baker Platform Page 3 with 290 bbl away on an inner string job. Assuming a 50% excess for washout, the top of cement is calculated at 1300' MD. The 180/8" casing was pressure tested to 2,000 psi. As noted in the E Annulus summary, the shoe strength of the 24" surface casing is 14.1 ppg EMW. The formation test performed after drilling out the 180/8" casing at 2174' was recorded as 13.6 ppg EMW. No additional cement work was performed on the 180/8" intermediate casing. There is presently 110 psi of trapped pressure on the D annulus. The lithologic description is as follows: Interval 800' - 2100' MD (180/8" Surface casing) This interval is comprised of the typical Cook Inlet succession of interbedded sandstones, tuffaceous (ashy) clay stones and coals. There are at least 15 individual coal seams scattered throughout this interval, ranging in thickness from 2' - 23' (MD). The first coal-related gas show occurs at 1130' MD; above this depth the coals are all largely inert. Below this depth, coals are all degassing to varying degrees of intensity. Sand bodies in this interval range from 20' to 80' thickness. The first increase in background methane in a sand occurs immediately below the coal at 1130' MD. Generally, sands in this interval do not exhibit gas shows much in excess of background. Any mobile gas in this interval is likely evolving from the coals rather than escaping from sands. The mud log suggests that the interval from 1600' to 1800' MD is dominantly comprised of tuffaceous clay stone with two coal seams of 15' and 20' thickness. This interval may act as a seal to the upward migration of gas in the surface casing annulus if it has collapsed against the pipe. D Annulus Summary: It is believed the cement quality from the 180/8" shoe at 2140' MD up to ±1300' MD is sufficient to prevent vertical gas migration. For this interval, a worst case BHP pressure at 1300' MD (1296' TVD) is exerted on the surface shoe at 803' TVD. The interval was drilled with a 9.0 ppg mud, therefore the highest gas pressure at 1300' MD is 606 psi (i.e. 1296' x 0.052 x 9.0 ppg). The hydrostatic pressure of gas from 1296' TVD up to 803' TVD is 49 psi assuming 0.1 psi/ft gas gradient. Therefore, the EMW on the 24" surface casing shoe is calculated to be 13.3 ppg [i.e. (606 psi - 49 psi) / 803' /0.052], which is less than the 14.1 ppg leakoff test recorded. The maximum gas pressure on surface would be 476 psi assuming a full column of gas down to 1300' MD with a reservoir pressure of 9.0 ppg. The 24" casing was pressure tested to 1000 psi as noted in the E Annulus Summary above. A separate evaluation confirmed that there is no risk of exceeding collapse limitations on the 180/8" casing or burst limitations on the 24" casing. Baker 28 summary of cement - AOGCC October 10, 2005 ') ) Well Ba-28 Casing and Cement Evaluation Baker Platform Page 4 C Annulus (18%" Intermediate x 13%" Intermediate): The C annulus is defined as the 18Y8" intermediate casing at 2140' MD by 130/8" intermediate casing. While drilling the 17Yz" hole section in Baker 28, two unplanned sidetracks were made around lost drilling assemblies. There was no opportunity to cement these two "ghost holes", the first of which was drilled from ±3700' to 4835' MD (±2809' - 3215' TVD) and the second of which was drilled from 2761' to 5566' MD (2430' - 3448' TVD). The 130/8" intermediate casing extends down to 5683' MD (3509' TVD). The 130/8" casing was cemented with 673 bbl of cement. No losses were recorded on the original drilling report, but a loss of 103 bbl of cement was recorded in the daily mud report along with a record of 438 bbl mud being left behind pipe. The previous day's drilling report indicated the well lost 80 bbl mud to the formation while logging and preparing to run casing. For the purpose of calculating the top of cement, the 673 bbl of cement pumped was adjusted to 540 bbl behind pipe (30 bbl in the 130/8" shoe plus 103 bbllosses). The top of cement is therefore estimated at 2900' MD using the given information while assuming a 50% excess. With the previous casing shoe at 2140' MD, ±760' of formation is exposed behind the 130/8" casing. The 130/8" casing was pressure tested to 2,700 psi. As noted in the D Annulus summary, the shoe strength of the 18Y8" intermediate casing is 13.6 ppg. The formation test performed after drill out was recorded as 14.4 ppg EMW. No additional cement work was performed on the 130/8" intermediate casing. There is presently 375 psi of gas pressure on the C annulus. A significant cooling temperature anomaly was noted behind the 130/8" casing during the 2005 preliminary diagnostic testing. The anomaly is confined to an interval from 5200' MD (3349' TVD) up to 4600' MD (3144' TVD). The hole inclination here is approximately 70 degrees so the anomaly that spans a 600' measured length represents a 205' vertical distance. Chevron interprets the cooling anomaly to be gas flowing behind the 130/8" casing. The conduit for the gas flow may be a channel in the cement behind 130/8" casing, which would not be unusual in a 70 degree hole section. Another strong possibility is that flow is occurring through one or both of the uncemented "ghost holes". The lithologic description is as follows: Interval 2100' - 5600' MD (130/8" Intermediate casing) This interval is comprised mostly of very thick-bedded sandstones and sandy conglomerates. Individual sand bodies of 50' to 400' thick are common. Interbedded coals range in thickness from 10' to 60' MD, and commonly exhibit gas shows of 20-60 units in excess of background. Baker 28 summary of cement - AOGCC October 10, 2005 ) ) Well Ba-28 Casing and Cement Evaluation Baker Platform Page 5 There is a 200' thick assemblage of sandstone bodies at 2200' to 2400' MD which display fairly strong mud log gas shows of up to 200 units above background. It is possible that this sand series is capable of producing gas into the annular space behind the 130/8" intermediate casing. Other thick assemblages of sand are observed deeper at 2450' - 2700' MD and 3150' - 3600' MD, but these are void of gas shows. There is a thick interval of tuffaceous clay stone and coal which occurs from 2700' - 3150' MD which may act as a seal to the upward migration of gas in the 130/8" intermediate casing annulus if these lithologies have collapsed against the pipe. Still more sand-related gas shows are observed at 3690' - 3870' MD, 4630' - 4670' MD and 4750' - 4870' MD. These shows are not as strong as those observed above or below. Fairly strong gas shows of up to 180 units above background are again seen in sands in the interval from 5020' - 5205' MD; these shows may indicate mobile gas that could migrate into the 130/8" intermediate casing annulus. (Recall that there may be an annular seal above this interval at 2700' - 3150' MD in the clay stone/coal section described above.) To summarize, there are at least two thick intervals of gas-charged sands that could provide mobile gas to the 130/8 intermediate casing annulus (2200' - 2400' and 5020' - 5200' MD). Gas liberated from these intervals could conceivably migrate upward in the casing annulus to charge any of the lower pressure sand bodies above. C Annulus Summary: Although the primary cement job on the 130/8" intermediate casing encountered losses, it is believed that cement exists up to ±2,900' MD. There is no bond log to provide quality assurance of the cement, but the cement is expected to be of sufficient quality to prevent gross fluid migration to the 18Y8" shoe. Cement quality has perhaps been compromised in localized areas due to channeling as noted on the temperature log. Alternately, the two sidetracks around lost drilling assemblies could provide a path for fluid migration. There are two main issues to be analyzed. The first is the lack of cement at the 18Y8" casing shoe in conjunction with the gas bearing zone open to the 18%" x 130/8" annulus. The second issue is the temperature anomaly behind the 130/8" casing. As noted from the mud log, a gas sand is present from 2200' MD (2087' TVD) to 2,400' MD (2223' TVD). The associated BHP assuming a 9.0 ppg gradient is 1040 psi (i.e. 2223' x 0.052 x 9.0 ppg). The equivalent mud weight on the 18Y8" shoe is 9.8 ppg (i.e. 1040 psi / 2042' /0.052), which is well below the 13.6 ppg leak off recorded. Assuming a gas gradient to surface, the highest anticipated pressure on the 18Y8" x 130/8" casing is Baker 28 summary of cement - AOGCC October 10, 2005 ) ) Well Ba-28 Casing and Cement Evaluation Baker Platform Page 6 836 psi. An evaluation confirmed that there is no risk of exceeding collapse limitations on the 130/8" casing or burst limitations on the 18%" casing. The attached graph depicts the temperature anomaly encountered in Baker 28. The graph also depicts the depths of the two ghost holes from the original drilling operation. The interpretation of the anomaly is that the gas bearing zone from 5,020' - 5,200' MD is cross flowing upwards to other sands. The gas does not appear to be flowing upwards beyond 4,600' MD as the temperature profile returns to normal. The worst-case pressure scenario would be the gas pressure measured from 5200' MD (3,349' TVD) exerted on the formation at 4600' MD (3,144' TVD). Assuming a 9.0 ppg original formation pressure, the 1567 psi (i.e. 9.0 ppg x .052 x 3349') would exert an EMW of 9.6 ppg at 4,600' (3144' TVD). With the well having been drilled over 11 years ago, it is reasonable to assume that significant cross flow has already taken place. It should be recognized that mobile hydrocarbons are present but do not pose a risk to the well bore or the sands above. In addition, there is no indication that resources are being wasted due to this cross flow. Chevron would expect the gas to still be severable and recoverable. Finally, the only viable remedial option to stop any additional cross flow would be to perforate through the 90/8" and 13%" casing strings and perform a squeeze. Chevron believes that a squeeze operation will have, at best, a low likelihood of success and very well could exacerbate mechanical problems in the wellbore. Chevron recommends that no action be taken to isolate the apparent cross flow taking place at ±5000' MD. B Annulus (13%" Intermediate x 9%" Production Casing): The B annulus is defined as the 13%" intermediate casing at 5683' MD by 90/8" production casing. The 9%" production casing extends down to 10,565' MD (7,365' TVD). While running the 90/8" casing, the pipe became stuck at 10,529' MD and subsequently packed off. The 90/8" casing was cemented with 615 bbl of cement with no returns. The annulus went on a vacuum post cementing. A Segmented Bond Tool (SBT) was run to evaluate the need for remedial cementing. No additional cementing work was required as sufficient cement existed for the intended target oil zones. The uppermost perforation in Baker 28 is at 8,546' MD. An analysis of the SBT is as follows: 10,477' - 8,400' Good cement quality. No apparent channels. 8,400' - 7,000' Step change in cement quality. Possible channels noted on log. Generally adequate cement to prevent vertical migration of fluids. Baker 28 summary of cement - AOGCC October to, 2005 " ') Well Ba-28 Casing and Cement Evaluation Baker Platform Page 7 7,000' - 6,460' Spotty cement with occasional sealing of vertical fluid movement. Ringing pipe with no cement isolation. Well most likely packed off at 6,460' MD (3,850' TVD) during cementing. 6,460' - 5,600' As noted in the C Annulus summary, the shoe strength of the IJ%" intermediate casing was measured at 14.4 ppg. There is presently 700 psi of gas pressure on the B annulus. The lithologic description is as follows: Interval 5600' - 7100' MD (behind 9Y8" casing) This section is dominated by non-reservoir facies such as tuffaceous silty claystones and coals, interbedded with thinner and more widely dispersed sandstone bodies. All of the coals in the section - which range from 10' to 50' thick - appear to be degassing. Numerous sandstones within the section also display prominent gas shows. The gas shows from both coals and sands in this section are noticeably richer than those observed above; C2, C3 and C4 gases are observed in this section, whereas the shallower shows are almost entirely composed of methane (C¡). B Annulus Summary: The worst case pressure scenario would be gas pressure measured from 6460' MD (3,850' TVD) exerted on the 13%" shoe at 5683' MD (3,509' TVD). Assuming a 9.0 ppg original formation pressure yields a pressure of 1802 psi (i.e. 3850' x 9.0 ppg x 0.052). This 1802 psi would exert an EMW of 9.9 ppg at 5,683' MD, which is well below the 14.4 ppg EMW leak off test. The 700 psi that is presently on the B annulus is assumed to be gas on mud as a straight gas column would yield approximately 1400 psi surface pressure. The 130/8" was tested to 2,700 psi and the collapse pressure of 9Y8" casing is 4760 psi. Conclusions Baker 28 should be left shut in pending Chevron evaluation of the resource potential from the Baker platform. Chevron will continue monitoring surface pressure and well status on a routine basis, including running annual temperature surveys. Chevron recommends that the best approach to the temperature anomaly noted at ±5000' MD is to leave it alone. Chevron will submit a 10-403 application to the AOGCC prior to commencing any efforts to either return the well to production or initiating plugging operations. Baker 28 summary of cement - AOGCC October 10, 2005 ) ) Well Ba-28 Casing and Cement Evaluation Baker Platform Page 8 E D C B A ~ ~ ~ ~ ~ Baker 28 summary of cement - AOGCC Fizz gas ... 303' MD, 302' TVD, 30" - Driven 803' M D, 802' TVD, 24" 156# - Cemented with 440 bbl, lost all returns @ 275 bbl, TOC estimated @ 370' (100% excess), wet shoe. Pumped a 17 bbl - 50' Top Job. LOT = 14.1 ppg EMW 2140' MD, 2042' TVD, 18%" 97# - Cemented with 784 bbl, lost all returns @ 290 bbl. TOC estimated @ 1300' (50% Excess). LOT = 13.6 ppg EMW 5683' MD, 3509' TVD, 13%" 68# - Cemented with 673 bbl. Daily drilling recorded no information on losses. Mud reports recorded 438 bblleft behind pipe and 103 bbllost while cementing. Best estimate of TOC @ 2900' MD. With 50% excess, mud down to and cement up to ±2,900'. LOT = 14.4 ppg EMW 10,565' MD, 7365' TVD, 9%" 47# - Cemented with 615 bbl. Casing was stuck and packed off during cement job. Annulus was on a loss. Cement good up to 8,400'. Quality change in cement 8,400' to 7,000' with some channeling. Spotty cement wi probable vertical sealing up to 6,460'. 100% Free pipe up to top of log @ 5,600'. October 10, 2005 Wen Ba-28 Casing and Cement Evaluation Baker Platform 9 Pressure (psia) 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 4000 4100 4200 4300 4400 4500 4600 4700 4800 -:;:::- 4900 (,) ~ - 5000 = ~ 5100 C 5200 5300 5400 5500 5600 5700 5800 5900 6000 90 95 100 105 Temperature (Deg. F) Baker 28 summary of cement - AOGCC October 10, 2005 - ..... Q J! - '" c > 3000 &-;- .s:: ..... Q. Q C 800 o 1400 Pressure (psia) 1600 1800 2000 2200 2400 2600 1000 1200 1000 · I I Pressure-Temperature Profile I TVD I I Q,,, ,t.ln I · --- - a ?= - ro I ) V v ! ¡ I - '? 0 I ("') , v .I · ~ , " I I ~ ~ () I I Õ i: ...... i!> 1:: . I ~ I I ¡: I j I =4 I.. I I · I · , · , I , I - , · I I I I - I - I I I - I - I I , I 2000 4000 5000 6000 50 60 70 100 110 120 130 80 90 Temperature (Deg. F) Report date: 10/7/2005 o -1 ,000 -2,000 -3,000 -4,000 - Q) .e .c:. - Q. Q) 0 1; -5,000 fJ 1:: ~ Q) :J - I- -6,000 -7,000 -8,000 -9,000 -10,000 40 Baker Platform Composite Temperature Chart ... 5 50 80 90 Temperature, deg F 100 110 60 70 Sa-04 Temp RIH 27-07-2005 Sa-05 Temp RIH 30-07-2005 - Sa-06 Temp RIH 20-07-2005 Sa-07 Temp RIH 07-07-2005 Sa-08RD Temp RIH 07-07-2005 Sa-11 Temp RIH 21-07-2005 Sa-12 Temp RIH 16-07-2005 Sa-13 Temp RIH 05-07-2005 Ba-15RD Temp RIH 06-07-2005 Ba-20 Temp RIH 28-07-2005 Sa-23 Temp RIH 23-07-2005 Sa-25RD Temp RIH 22-07-2005 Sa-27 Temp RIH 06-07-2005 Sa-28 Temp RIH 03-07-2005 Sa-29 Temp RIH 28-07-2005 Sa-30 Temp RIH 04-07-2005 Sa-31 Temp RIH 29-07-2005 120 130 160 140 150 ) '~~lÆ~E :,} fÆ~fÆ~~fÆ ) AI¡ASIiA. OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. PH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Dave Cole Oil Team Manager UNOCAL P.O. Box 196247 Anchorage, AK 99516-6247 'C /\\ \ ,,\'3 Re: Middle Ground Shoal Unit Platforms Dillon and Baker Dear Mr. Cole: This letter confirms your conversation with Conunission Engin.eer 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. /:. Sincer~~ . No an Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION DATED this _day of November, 2004 SCANNED NO\! 2; ,12004 Enel. 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): 10,582' Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): 8,546' to 10,465' at intervals Packers and SSSV Type: ') STATE OF ALASKA -, ALAS~r\ OIL AND GAS CONSERVATION COMMIS~16N APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 Operational shutdown U Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: Suspend U Repair well 0 Pull TubingD Perforate U Waiver U Annular Dispos. U Stimulate 0 Time Extension D Other 0 Re-enter Suspended Well 0 Monitor Frequeycy 5. Permit to Drill Number: / Exploratory D 1931190 Service D 6. API Number: / 50-733-20455-00 / / / (measured): 909 West 9th Ave. Anchorage AK 99501 Development Stratigraphic 0 D 9. Well Name and Number: Ba-28 10. Field/Pools(s): MIDDLE GROUND SHOAL PRESENT WELL CONDITION SUMMARY Total Depth TVD (ft): 7,382' Length Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): Size MD 30" 83' BLM 24" 803' 185/8" 2,140' 2,042' 133/8" 5,683' 3,509' Burst Collapse 83' 803' 2,140' 5,683' 10,565' 2,250 psi 3,450 psi 6,870 psi 630 psi 1 ,950 psi 4,750 psi 10'5~5' . 7,365' Tubing Size: .' . Tubing Grade: Dual strin 3 1/2" 9.2 # L-80 ackers and SSSV MD (ft): KOBE BHA @ 8,436' 95/8" Perforation Depth TVD (ft): Tubing MD (ft): 8,436' 5,406' to 7,268' Date: 13. Well Class after proposed work: Exploratory D Development 0 Service D 15. Well Status after proposed work: Oil 0 Gas 0 Plugged D Abandoned 0 WAG D GINJ 0 WINJ 0 WDSPL 0 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for Commencing Operations: Commission Representative: 17.. I hereby certify that the foregoing is true and correct to the7b . st of ~y knowledge. Contact Pnnted Namn.~. A . ole Title Oil Team Supervisor Signatur~.i<' /:1~ Phon; 907-263-7805 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a reiesentative may witness Sundry Number: 3°:t -"ê~f' Plug Integrity 0 BOP Test D ,echanicallntegrity Test D Location Clearance 0 R E eEl VE 0 \ CT 1 2 2004 16. Verbal Approval: Other: Subsequent Form Required: Approved by: 27-Sep-2004 RBDMSBFL NO'V ð I) 2DO. APPLICATION RETURNED 11/17/0b. ~Ñ ~ NOT APPROVED BY COMMISSION' & Gas Cons. Commission Anchorage BY ORDER OF Ce~'f"\ N ÆfECOMMISSION Date: J{o3 Form 1 0-494 Revised 12/2003 Submit in Duplicate THE MATERIAL UNDER THIS COVER HAS BEEN MICROFILMED ON OR'BEFORE JANUARY 03 2001 M PL ATE E THIS IA L UN M A R K E C..LO~M.DOC D W E R R PE ~MT'~n DATA q3-I19 ~0'8 7 ..... , .... lv_~vkdual Well Geological Materials Inventory T DATA_PLUS T 202~ 104~ ~- ~z, OH & CH Page' i Da,te' 10/13/95 DATE RECVD 1 - 2 04 / 2.1 /94 93 119 ~~ 93 - I 19 ~CA/GR a3-!i© ~DL/CNL/~. q3-i!9 ~/GR 93-iic) ~PR/GR 93-119 ~PR/GR 93-! 1 9 ~r~/GR 93-119 ~R/GR 93-ii9 ~T/NGT Are dry ditch samples S 2'*~ 02 ~=0-I 30 R COMP DATE'03/23/94 R 10/04/93-03/23/94 R 0.0.0-10582 L 2100-3510 ~0 L 2100-35~ ~ L 5600-10475 L 2100-3510 L 5655-10570, L 565~-10570, L 5655-i0570, L 5655-10570, L 380-10582 L 5600-10475 MD 19-2 MD 19-2 TVD 19-2 TVD 19-2 Was the wei'i cored? Are well tests [equired?%es ~~ P. eceive "~~~~ Well is in compliance ~_~ Initial COHMENTS 04/19/94 07/08/9~ 07/08/94 o7/os/94 o~/21/94 o4/2~/9~ o4/21/9~ o~/2i/9~ o4/21/94 o~/21/9~ o~/2~/92~ o~/2~/9~ 04/21/94 o4/21/9~ required? yes _~__And received? ~ no yes ~_~nalysis & descriptic, n~~-ee~-?.~-- y~s 110 Kevin A. Tabler Land Manager Alaska Unocal Corporation 909 West 9th Avenue, P.. ~ox 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL November 14, 1994 i COMM ~ [SR ENG J E__N.~ ASST I ENG ASST I GEOL ASSTt _~.E C).L..ASST STAT FILE Mr. Russell Douglass, Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Middle Ground Shoal Field MGS 17595 Well No. 28 Dear Mr. Douglass: Reference is made to Conservation Order No. 335 dated April 29, 1994. Union Oil Company of California (Unocal), as operator of the Baker Platform, does not intend to request extension of the temporary waiver of 20AAC 25.265(2) that allowed flowing production from MGS 17595 No. 28 to proceed without certain subsurface safety equipment having been installed in the well. Baker 28 is no longer capable of flowing unassisted. Baker 28 ceased to flow on July 16, 1994 after a platform-wide shutdown and could not be restarted. Unocal ran a pressure survey on July 22 showing that the bottom-hole pressure had only built up to 1480 psi after being shut-in for over 5 days. This is in contrast to a similar survey performed on April 17, 1994 that indicated that the static bottomhole pressure was 2453 psi. At a true vertical depth of 5270 feet, where the pressure was measured, this works out to a pressure gradient of 0.28 psi per foot on July 22 vs. 0.465 psi per foot on April 17. The most recent pressure is not sufficient to cause either water (0.433 psi/ft) or oil (0.36 psi/ft) to flow to the surface. One can see from the attached graph that the static fluid level was somewhere between 1000 and 2000 feet below the surface (with 0 psi at the wellhead) on July 22. Thus the well was in a "no flow" condition and was capable of safe production with a hydraulic pump and vented casing, as is typical at the Baker Platform. AOGCC November 14, 1994: Page 2 The subsurface safety valve was removed from the well and a hydraulic pump was installed on July 22, 1994. The well was returned to production and has not shown any further evidence of being capable of flowing hydrocarbons to the surface. The high gas-oil- ratio (6000 to 10,000 scf/bbl) observed during the well's initial flowing period has also declined to less than 600 scf/bbl, indicating that the high GOR zone in the well is depleted, rendering Baker 28 incapable of flowing on its own. Unocal intends to continue to produce Baker 28 in the safe and prudent manner typical of other pumping oil producers at Baker, performing periodic production tests as well as daily measurement of tubing and casing pressures to ensure safety. The surface safety valves on the tubing and annulus flowlines have not been removed and remain functional. Please contact Kurt Bair, reservoir engineer, at 263-7646 if you have further questions. Sincerely, /~,~' Kevin A. Tabler POV 1'i/ i90,!. ~x.'.~;.'.~ ..... & Oar..' I;0ri~. 60m)nissir. m Anchor~ 0 O: 5OO baker 28 static bottom-hole surveys pressure, psig 1000 1500 2000 3000 11 |: 7/22/94 . 4/17/94 STATE OF ALASKA · ALA£ OIL AND GAS CONSERVATION COM' 31ON WELL COMPLETi~N OR RECOMPLETION h,cPORT AND LOG 1. Status of Well Classification of Service Well OIL [~ GAS [-~ SUSPENDED [~] ABANDONEDr-~ SERVICE 2. Name of Operator ! . ~ r ~_~ 7. Permit Number 3.UNION OIL COMPANY OF CALIFORNIA (UNOCAL)Address 0 ~ i G / NA L i!:'~~'~ ~;! 8. AP193-119Number P.O. BOX 196247 ANCHORAGE, AK 99519 ~. 50-733-20455 -- ~ . 4. Location ofwell at surface Baker Platform, Leg #1, Slot #1 ~-*',~i~i~i:/!'i~,i~ji~ J 9. Unit or Lease Name At Top Producing Interval 8546' MD/5406' TVD 10. Well Number 1703' FNL & 1619' ~WLSectio, 30. TgN. R12W. ~ '~r'~.~r~ ~ #28 At Total Depth 10582' MD/7383' 'rVD~. ~-"-' ~ ,~ _~.._~_~ "l't ;. ~ 11 . Field and Pool 1283' FNL & 1514' FWL Section 30, T9N, R12W, SM - - Middle Ground Shoal A & B,C,D Pools 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. 118'KB, ADL 17595 12. Date Spudded 10/04/93 13. Date T.D. Reached 03/13/94 14' Date Comp" Susp' or Aband' 115' Water Depth' if °ffshore 116' N°' of Completi°ns 03/23/94 102 FeetMSL 1 19. Directional Surv?_~V 120. Depth where SSSV set 121. Thickness of Permafrost 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) YES [~ NO U N/A feet MD 10582'/7383' N/A N/A 22. Type Electric or Other Logs Run DILJGR/SP/NEU/SBT- GR 23. CASING, LINER AND CEMENTING RECORD CASING SIZE WT. PER GRADE TOP ~ BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 24" 156 ×-42 54' 803' 28" 2471' cu. ft. 18-5/8" 97 X-56 54' 2140' 24" 4404' cu. ft. 13- 3/8" 68 K- 55 53' 5683' 17-1/2" 3779' cu. ft. 9-5/8" 47 L-80 53' 10565' 12-1/4" 3455 cu. ft. 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE I DEPTH SET (MD) I PACKER SET (MD) 3-1/2". 9.2#, L-80 (~ 8436' NA See Attached 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) ] AMOUNT & KIND OF MATERIAL USED N/A 27 PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) N/A Date of Test Hours Tested PRODUCTION FOF OiL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO TEST PERIOD -- - FlowTubing Casing Pressure CALCULATED OIL-BBL GAS-MCF WATER-BBL OILGRAVlTY-API (corr) Press. 24-HOUR RATE 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Form 10-407 Submit in duplicate rev. 7-1-80 CONTINUED ON REVERSE SIDE 29. 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 ~/,,rti~re~correct to the best of my knowledge ~{~"! :' Signed G. RUSSELLSCHMIDT Title 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 records for 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 PLATFORM WELL Cf 28 DAY I (10/04/93) COMMENCE OPERATIONS AT 12:00 HRS. ON 10/04/93. SKID RIG TO SLOT NO. 1, WELL NO. 28. N/U RISER. M/U 25.2" CLEAN OUT ASSY. DAY 2 (10/05/93) RIH TAG SAND AT 147', CLEAN OUT SAND TO 354' SET DOWN AT THAT POINT. RAN GYRO SURVEY. GETTING TOO CLOSE TO WELL NO. 14, POOH. RIH W/DIRECTIONAL DRILLING ASSY. TO STEER AWAY FORM WELL NO. 14 (TWO RUNS) DRILL TO 363'. POOH. RIH W/ROTARY ASSY. DRILL TO 407' RUN SURVEY, POOH, RIH WITH DIR. DRILLING ASSY. TO CORRECT COURSE. DAY 3 (10/06/93) CORRECT COURSE, DRILL 17-1/2" HOLE TO 825'. POOH. UNDERREAM 17-1/2" HOLE TO 30" FROM 304' TO 532'. RIH AND DAY 4 (10/07/93) UNDERREAM 17-1/2" HOLE TO 30" FROM 532' TO 815'. POOH. RIH W/UNDERREAMER AND 2 X 24.2" STABS. CLEAN OUT TIGHT SPOT AT 358', RIH TO 815', POOH. DAY 5-7 (10/08-10/93) RAN AND CEMENTED 24" CASING @ 803'. LOST RETURNS WITH 275 BBLS LEAD SLURRY AWAY. N/D RISER. DO TOP JOB. N/U 20-3/4" BOP'S TEST SAME. CLEAN OUT CEMENT IN 24" CASING DRILL 10' OF NEW HOLE TO 835'. PERFORM LOT 220 PSI, FRAC GRADIENT OF .94 PSI/FT. OR 14.1 PPG EMW. POOH P/U MOTOR ASSY. DAY 8 (10/11/93) DIRECTIONALLY DRILL 17-1/2" HOLE FROM 835' TO 1191', POOH FOR ASSY. CHANGE. RIH REAM 960' TO 1191', DRILL FROM 1191' TO 1283'. DAY 9 (10/12/93) DIRECTIONALLY DRILL 17-1/2" HOLE FROM 1283' TO 1785'. DAY 10 (10/13/93) DIRECTIONALLY DRILL 17-1/2" HOLE FROM 1785' TO 2164'. POOH, SLOW PENETRATION/CASING POINT. DAY 11 (10/14/93) UNDERREAM HOLE FROM 17-1/2" HOLE TO 24" FROM 805' TO 1570'. DAY 12-13 (10/16-17/93) UNDERREAM HOLE FROM 17-1/2" HOLE TO 24" FROM 1570' TO 2152'. POOH. RAN 18-5/8" CASING TO 2140'. LAND CASING AND RAN INNER STRING FOR CEMENT JOB. CEMENTED CASING WITH PARTIAL MUD RETURNS. POOH W/INNER STRING, N/D BOP'S INSTALL BLIND FLANGE. RELEASE RIG TO WELL NO. 28 AT 21:00 HRS ON 10/16/93. DAY 14 (11/16/93) SKID R428 F/BA#30 TO BA#28 AT 0200 HRS. NU BOP & TEST SAME, FAILURE ON REMOTE IBOP & ANN PREV. DN TIME 9 HRS. SECURE REPLACEMENT ITEMS. DAY 15 (11/17/93) REPLACE IBOP VALVE & NEW ELEMENT F/ANN PREV. RETEST BOTH ITEMS, OK. CUT & SLIP DRLG LINE. MU BHA & RIH TO 1935'. DRILL CMT F/1935'- 2108'. TEST CSG TO 2M F/30 MIN, OK. DRLD CMT, FC & FS F/2108'-2174'. PERFORM LOT TO 13.6 PPG EMW. DRILLED 17-1/2" HOLE F/2174'-2581' DAY 16 (11/18/93) DRILLED 17-1/2" HOLE F/2581'-3137'. CBU. DAY 17-19 (11/19-21/93) POOH. MU BHA. DRILLED 17-1/2" HOLE F/3137'-3537', POOH DUE TO DROPPING INCLINATION. MU BHA & RIH TO 3414'. WASH & REAM F/3414'- 3537'. DRILLED F/3537'-4222'. POOH DUE TO POOR ROP. MU BHA & RIH. DRILLED F/4222'-4564'. PLUG BIT W/CARBIDE BOMB, CIRC FREE. DRILLED 4564'-4604'. DAY 20 (11/22/93) DRILLED TO 4676'. LOSS 500 PS! PMP PRESS. POOH. LOCATED WASHOUT IN DC PIN CONNECTION. CHG OUT DC. RIH. DRILL F/4676'-4835'. LOSS 1600 PSI PMP PRESS & 10K IN STRING WT. POOH. LEFT 83' OF FISH IN HOLE. TOF @ 4752'. CONNECTION ON TOP OF 3RD STAB CRACKED RESULTING IN FISH. MU FA #1 & RIH. DAY 21 (11/23/93) MU FA #1 & RIH. SET DN AT 3700', WORK DN TO 3721'. UNABLE TO WORK THRU COAL SECTION F/3700-3740, GAINING PUMP PRESS. CBU. POOH. MU C/OUT BHA & RIH TO 3721'. ROTATE SLOW F/3721'-3800'. UNABLE TO LOCATE ORIG WELLBORE. POOH. MU DRLG BHA & RIH. DAY 22-26 (11/24-28/93) SURVEY WELLBORE W/MWD F/3617'-3757'. SURVEYS DEMOSTRATE A SIDE- TRACK HAS OCCURRED, AT 3800' (PROJECTED) THE SIDE-TRACK WELLBORE IS APPROX 10' BELOW ORIGINAL WELLBORE. DECISION MADE TO CONTINUE DRILLING W/SIDE-TRACK F/3800' MD. SIDE-TRACK WELL, DRLD 17-1/2" HOLE F/3800'-4386', LOSS PMP PRESS. POOH, PROBLEM OCCURRED AT WASHOUT IN BIT AREA ABOVE THE JETS. MU BHA (MOTOR) AND DRLD F/4386'-4880', POOH DUE TO SLOW ROP. TST BOPE, OK. MU BHA (ROTARY) AND RIH, WORKED AND WASHED BHA DOWN F/3795'-4400', CONT TO BTM. DRLD F/4880'-5566', TWISTED OFF WHILE DRLG AT 5566', LOSS PMP PRESS AND STRING WT. UNABLE TO SET DN ON TOF. ClRC HI-VlSC SWEEP, POOH. LOCATED TWIST OFF 3' BELOW BOX CONNECTION ON DRILLPIPE, RECOVERED 3690' OF DP, TOF AT+ 3690'. FISH IN HOLE CONSISTS OF DP, HWDP, JARS AND ROTARY BHA, TOTAL LENGTH OF FISH IS 1876'. MU FA #1 AND RIH TO 3690', LOCATED TOF AND ATTEMPT TO ENGAGE, NEGATIVE. APPEARS TOF IS IN A COAL SEAM AREA THAT IS SUBSTANTIALLY WASHED OUT THUS ENLARGING THE HOLE SIZE. POOH. MU FA #2 AND RIH. Aq-rEMPT TO ENGAGE FISH, NEGATIVE. POOH. DAY 27 (11/29/93) MU FA #2 16-3/4" GUIDE ON 11-3/4" O.S. RIH. ATTEMPT TO LATCH FISH W/O SUCCESS. POOH. RIH W/FA #4 12-3/4" HOOK WALL GUIDE ON O.S. Aq-FEMPT TO LATCH FiSH W/O SUCCESS. POOH. M/U FA #5 12-3/4" HOOK WALL GUIDE W/O.S. ON KNUCKLE JOINT. DAY 28 (11/30/93) RIH Aq-FEMPT TO ENGAGE FISH, NEGATIVE. POOH. PARTED FISH ASSY, JUNK IN HOLE. AGREED TO SIDE-TRACK WELL ABOVE TOF. RIH W/OEDP, SPOT HI-VISC PILL F/3400'-3200'. M&P 1102 SX (1091 FT~) CMT BAL PLUG F/3200'-2700'. CIP AT 1900 HRS. PULL TO 2500' & CIRC DP CLEAN. POOH, LAY UN EXCESS DP. TEST BOPE. DAY 29 (12/01/93) CONT BOPE TEST. MU KICK-OFF DRLG ASSY. RIH TO 2725', C/OUT GRN CMT F/2725'-3098', PLUG UNABLE TO SUPPORT KICK-OFF. POOH. RIH W/DP STINGER, LAY BAL CMT PLUG F/3098'-2700', CIP AT 2035 HRS. POOH. DAY 30 (12/02/93) MU KICK-OFF DRLG ASSY, RIH TO 2490' & SET DN. C/OUT F/2490'-2730', MINIMAL CMT. CIRC CLF__AN. WOC. KICK-OFF CMT PLUG & DRILLED 17-1/2" HOLE F/2761'-2986'. DAY 31-33 (12/03-05/93) DRILLED 17-1/2" HOLE F/2986'-3765'. POOH F/BIT. RIH, DRILLED F/3765'- 3921'. RIG ON DN TIME 8.5 HRS TO REPAIR BLOWER MTR & TRACTION MTR ON MUD PMP #2. DRILLED F/3921'-4340', HOLE CONDITIONS POOR; DIFFICULTY SLIDING MTR ASSY. DAY 34 (12/06/93) DRILLED F/4340'-4477', SLOW POP & DIFF SLIDING. POOH. MODIFY BHA & CHG BIT. RIH, REAM F/4320'-4477'. DRILLED TO 4509'. DAY 35 (12/07/93) DRILLED F/4509' TO 5122'. DAY 36 (12/08/93) DRILLED F/5122' TO 5596'. DAY 37 (12/09/93) DRILLED 17-1/2" HOLE FROM 5617' TO 5678' (DECIDED DRILL TO 5698' CASING POINT). LOST 1100 PSI PUMP PRESSURE. POOH FOUND DRILL STRING SHEAR ABOVE TOP STABILIZER LEAVING 72' FISH ON BO~-FOM. RIH W/FISHING ASSEMBLY LATCH FISH AT 5606'. PULL FREE POOH LOST FISH WHILE WORKING THROUGH TIGHT SPOT AT 3500'. RIH TO 3697' TAG TOP OF FISH A~-FEMPT TO LATCH NEG RESULTS. POOH. DAY 38-40 (12/10-12/93) RIH W/FISHING ASSY NO. 2, COULD NOT WORK BELOW 3681', POOH. RIH W/FISHING ASSY NO. 3, COULD NOT WORK 15" CUT LIP GUIDE AND OVERSHOT PAST 3690', CONCERNED ABOUT SIDETRACKING WELL, POOH. RIH W/FISHING ASSY. NO. 4, (BULL NOSE, W/2 DEG. BENT SUB AND MWD) SET DOWN AT 3691'. ORIENT HIGH SIDE, WASH DOWN, FOUND HOLE RIH TO 4947' COULD MAKE NO FURTHER PROGRESS. POOH. RIH W/FISHING ASSY NO. 5, (11-3/4" LIP GUIDE AND OVER SHOT, ATTEMPT TO LATCH FISH AT 4949' POOH, HAD INDICATION FISH WAS IN OS, BUT DID NOT RETRIEVE IT). RIH W/FISHING ASSY NO. 5, (SAME AS 4 BUT WITH SMALLER GRAPPLE), LATCH FISH AT 4947'. POOH RECOVERED PART OF FISH, 17-1/2" STABILIZER ON TOP OF THE MOTOR HAD PARTED AT THE PIN LEAVING THE MOTOR AND BIT IN THE HOLE. RIH W/FISHING ASSY. NO. 6, (11-3/4" LIP GUIDE AND OVER SHOT) A~-FEMPT TO LATCH FiSH AT 4934' POOH, HAD INClCATION FiSH WAS IN OS, BUT DID NOT RETRIEVE IT. RIH W/FISHING ASSY NO. 7, (SAME AS 6 BUT WITH 15" GUIDE), SET DOWN AT 3685' COULD NOT WORK PAST POOH. RIH W/FISHING ASSY. NO. 8, (11-3/4" LIP GUIDE AND OVER SHOT ON 1.5 DEG BENT SUB) LATCH FISH AT 4922' POOH, RECOVERED COMPLETE FISH. DAY 41 (12/13/93) TESTED BOPS. RIH TO CLEAN OUT HOLE, REAMED NUMEROUS TIGHT SPOTS. DRILLED 12-1/4" HOLE FROM 5678' TO 5698'. DAY 43 (12/15/93) RAN 13-3/8" CASING TO BOq-FOM AT 5698'. CIRCULATE AND CONDITION MUD. CEMENT 13-3/8" CASING. RECIP CASING THROUGHOUT JOB. LAND HANGER IN UNI-HEAD. SET PACK OFF N/D. BOP INSTALL BLIND FLANGE. SUSPEND WELL #28 AT 24:00 HRS OF 12/15/93. DAY 44 (02/28/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 9.2 PPG SKID RIG TO BAKER 28. NU BOPE & TEST SAME. MU BHA & RIH. REPAIR RIG (DRLG NIPPLE). RIH TO 5537' & PRESS TEST CSG TO 2700 PSI FOR 30 MINUTES. DRILLED CMT & FLOAT EQUIP F/5537'-5683'. DISPL MUD TO NEW PHPA SYSTEM. DRILLED 12-1/4" HOLE TO 5708'. DAY 45 (03/01/94) 18-5/8" @ 2140' 13-3/8"@ 5683' 9.2 PPG PERFORM LOT TO 14.4 PPG EMW. DRILLED 12-1/4" HOLE F/5708'-6220'. 46 (03/02/94) 18-5/8" @ 2140' 13-3/8" @ 5683' 9.2 PPG DRILLED 12-1/4" HOLE F/6220'-6497'. ST TO CSG SHOE. DRILLED TO 6812'. DAY 47 (03/03/94) 18-5/8" ~ 2140' 13-3/8" ~ 5683' 9.5 PPG DRILLED TO 6812'-6991'. POOH F/BIT CHG. RIH. DRILLED F/6991'-7100'. DAY 48-50 (03/04-06/94) 18-5/8" ~ 2140' 13-3/8"@ 5683' 9.6 PPG DRILLED 12-1/4" HOLE F/7100'-8345'. DN HOLE MTR STALLING OUT, POOH TO CK TOOLS. APPEARS JUNK (LOSS HAND TOOL DN HOLE 3-1-94) IS ON BTM. PERFORM BOPE TEST. MU JUNK BIT W/BOOT SUB PLUS TELECO DPR TOOL IN BHA. RIH TO 5620'o REPAIR RIG (DN 4.5 HRS). CONT RIH, DRILLED ON JUNK F/8345'-8354'. POOH, LOGGING OH W/DPR TOOL. DAY 51 (03/07/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 9.5 PPG CONT TO LOH. MU BHA (INCL DPR TOOL) & RIH. DRILLED 12-1/4" HOLE F/8354'-8565'. DAY 52 (03/08/94) 18-5/8" @ 2140' 13-3/8"@ 5683' 9.9 PPG DRILLED 12-1/4" HOLE F/8565'-9155'. INCR MW TO 9.9 PPG. DAY 53 (03/09/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 9.9 PPG DRILLED TO 9382'. POOH DUE PRESS INCR. DN HOLE MOTOR HAD FAILED, REPLACE SAME. STD BK 3 STDS HWDP. MU BHA & RIH. DRILLED 12-1/4" HOLE TO 9406'. DAY 54 (03/10/94) 18-5/8"@ 2140' 13-3/8" @ 5683' 9.9 PPG DRILLED 12-1/4" HOLE F/9406'-9810'. DAY 55-57 (03/11-13/94) 18-5/8" ~ 2140' 13-3/8" ~ 5683' 9.9 PPG DRILLED 12-1/4" HOLE F/9810'-10075'. POOH, L/D LWD & MU BHA. RIH & DRILLED F/10075'-10326', ST TO 8626' W/TIGHT HOLE AT INTERVALS. DRILLED F/10326'-10485'. ST TO 8347', MORE TIGHT HOLE AT INTERVALS. DRILLED F/10485'-10556'. POOH F/BIT CHG & LWD TOOL. DAY 58 (03/14/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 9.9 PPG CONT POOH. TEST DOPE. MU BHA & LWD TOOL. RIH TO CSG SHOE & STRING TO 12 LINES. RIH TO 8991' LIH W/LWD TO 10556'. DRILLED 12-1/4" HOLE F/10556'-10582', W/EXCESSIVE TORQUE & LARGE PU WEIGHTS. DRLG BREAKAT 10580' REQ'D 150K OVERPULL. DETERMINED WELL HAD REACHED TD AT 10582'. CBU. DAY 59 (03/15/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 9.9 PPG ST TO 7968', LWD F/8807'-8713'. RIH TO 10570', WORK DN TO 10582'. CCH F/9-5/8" CSG. POOH, LAY DN BHA & CHG RAMS. PU & RIH W/9-5/8", 47#, L80 TO 13-3/8" CSG SHOE. DAY 60 (03/16/94) 18-5/8" @ 2140' 13-3/8"@ 5683' 8.5 PPG WATER HOLE TAKING FLUID (126 BPH). FILL CSG W/133 BBLS MUD & 68 BBLS MUD DN ANNULUS. CONT TO FILL ANNULUS W/H20. OBSERVE WELL. LOSS RATE AT 18.3 BPH. BUILD MUD VOL & PREP TO BRK CIRC. A1-FEMPT TO FILL W/9.7 PPG MUD LOSS RATE 114 BBL/HR. BUILD 9.5 PPG MUD RUN CASING FILL INTERNALLY W/MUD. RAN 9-5/8" CASING TO 10529 COULD NOT PASS THIS POINT, COULD NOT LAND HANGER. DAY 61 (03/17/94) 18-5/8"@ 2140' 13-3/8"@ 5683' 8.5 PPG WATER MIX AND PUMP 50 BBLS DUAL SPACER W/GILSONITE, 109 BBLS OF CEMENT PREFLUSH WITH GILSONITE FOLLOWED BY 506 BBLS OF 15.9 PPG CEMENT, WITH NO MUD RETURNS TO SURFACE, AND THE PIPE COULD NOT BE RECIPROCATED. BUMPED PLUG AND TESTED CASING TO 4800 PSI ANNULUS TAKING 10 BBLS/HR. WOC 5.5 HRS. ATTEMPTED TO SET EMERG. SLIPS, NEGATIVE. ORDER TOOLS & EQUIP. RIH CUT 9-5/8" CSG. AT 181' POOH, REC'D SLIPS. SLIPS DETERMINED TO BE INCORRECT F/WH PROFILE. ~; .,; ',"~ i,~' i?~ :: '-.~ .i ~-' . "' ,.;i';:tjO DAY 62-64 (03/18-20/94) 18-5/8" ~ 2140' 13-3/8"@ 5683' 9-5/8" @ 10565' 8.5 PPG WATER RIH, SET MANDREL CSG. HGR. & PACKOFF. PRESS TEST SAME TO 5M, OK. POOH W/SAME. MU HYD BACKOFF TOOL & RIH. BRK CSG. CONNECTION AT 244'. POOH. RIH W/CSG SPEAR & ENGAGE CSG, BACK OFF CSG & POOH. REC'D 63' OF 9-5/8" CSG. TEST FIT EMG SLIPS IN WH, OK. RIH W/9-5/8" CSG & SCREW INTO CSG STUB AT 249'. TEST PULL TO 525K & PRESS TEST TO 3000 PSI/30 MINS, OK. SET EMG SLIPS W/370 K ON SLIPS CUT & DRESS CSG STUB. INSTALL EMG PACKOFF. NU BOP & CHG RAMS TO VBR'S. RIH W/9- 5/8" CUP TESTER & PRESS TEST SEAL ASSY TO 3500 PSI F/30 MINS, OK. POOH. PERFORM DOPE TEST. MU 8-1/2" BIT W/CSG SCRAPER & RIH. PU 3-1/2" 9.2# L80 TBG TO 10487'. CBU. POOH. RU ATLAS WL & RIH W/LOG RUN #1 (NEU/GR/SBT) TO 10472' WLM, TIE-IN TO OH LWD. LOG ITNERVAL F/10487' TO 5600 WLM. RIH W/8-1/2" BIT ON DP & C/OUT F/10487'-10502' DPM. CBU. POOH. LAY DN 5" DP. DAY 65 (03/21/94) 18-5/8" @ 2140' 13-3/8" ~ 5683' 9-5/8"@ 10565' 7.1 PPG DIESEL CONT LAY DN OF 5" DP. RIH, PU 3-1/2" TBG. CONT RIH TO 10502'. REV FIW INTO PLACE THEN FOLLOWED W/DIESEL POOH, STD BK TBG. DAY 66 (03/22/94) 18-5/8"@ 2140' 13-3/8" @ 5683' 9-5/8"@ 10565' 7.1 PPG DIESEL CHG RAMS TO DUAL 3-1/2". SET TBG HGR & TEST SAME. RU, PU 6" & 4-5/8" OD TCP GUNS ALONG W/KOBE BHA & DUAL 3-1/2" TBG COMPLETION. RU WL & CORRELATE TCP GUNS ON DEPTH. DAY 67 (03/23/94) 18-5/8"~ 2140' 13-3/8"~ 5683' 9-5/8" ~ 10565' 7.1 PPG DIESEL LAND TBG HGR. TEST SEALS TO 5M F/30 MINS, OK. SET BPV. DOPE. INSTALL DUAL 3-1/2" TREE & TEST SAME TO 5M, OK. CLEAN WORK AREAS. RELEASED R428 AT 2400 HRS. ND & REM REM BPV & IKOBE Bt-lA 30" Structural @ 83' BLM 24" Conductor @ 803' 156#, X-42, MTS60AR 18-5/8" Surface @ 2140' 97#, X-56, QTE60 13-3/8" Intermediate @ 5683' 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC 2) KOBE BHA F/8436'-8457' 3) TCP guns 4-5/8" & 6" OD F/8546'-10465' @ INTERVALS RKB = 118' 9-5/8" Production @ 10565' 47#, L-80, BTC BAKER 28 ACTUAL COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN' CLL DATE: 07-06-94 FILE: BA28.drw Baker 28 Perforations Open to Production July 7, 1994 Measure Depth 8546'-8554' 8560'-8626' 8669'-8680' 8686'-8825' 8837'-8888' 8896'-8911' 8924'-8936' 8945'-8950' 8959'-8970' 9034'-9112' 9130'-9175' 9200'-9216' 9250'-9264' 9287'-9302' 9339'-9406' 9410'-9467' 9482'-9530' 9548'-9577' 9633'-9652' 9666'-9760' 9770'-9806' 10092'-10116' 10135'-10152' 10344'-10352' 10383'-10439' 10453'-10458' 10465'-10473' Total Perforations 945' UNOCAL BAKER Platform 28 St#2 slot #1-1 Middle Ground Shoals Cook inlet, Alaska SURVEY LISTING by Baker Hughes !NTEQ Your ref : GSS <0 - 1292'> : PMSS <1420-10582'> Our ref : svy4113 License : Date printed : 29-Jun-94 Date created : 3-Dec-93 Last revised : 21-Mar-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 45.807,w151 29 0.988 Slot Grid coordinates are N 2498075.761, E 235253.694 Slot local coordinates are 1929.00 S 543.00 E Reference North is True North UNOCAL BAKER Platform,28 St#2 M~ddle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 1 Your ref : PMSS <2721-10582'> Last revised : 21-Mar-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 ! 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 0.00 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.60 129.00 200.00 0.33 S 0.41 E 0.60 -0.24 250.00 1.00 100.00 249.99 0.57 S 1.04 E 1.11 -0.36 300.00 0.90 117.00 299.99 0.82 S 1.82 E 0.60 -0.46 347.00 0.80 142.00 346.98 1.25 S 2.35 E 0.81 -0.78 363.00 0.80 94.00 362.98 1.35 S 2.53 E 4.07 -0.84 400.00 1.20 73.00 39<2.97 1.25 S 3.16 E 1.45 -0.62 436.00 0.40 55.00 435.97 1.07 S 3.62 E 2.30 -0.35 497.00 0.40 53.00 496.97 0.82 S 3.97 E 0.02 -0.04 557.00 1.00 282.00 556.97 0.58 S 3.62 E 2.16 0.12 617.00 1.10 306.00 616.96 0.14 S 2.64 E 0.74 0.37 708.00 1.00 318.00 707.94 0.97 N 1.40 E 0.26 1.22 821.00 1.90 333.00 820.90 3.37 N 0.10 W 0.86 3.29 913.00 3.40 335.00 912.80 7.20 N 1.95 W 1.63 6.69 1012.00 5.50 334.00 1011.50 14.13 N 5.27 W 2.12 12.85 1043.00 6.20 339.00 1042.34 17.02 N 6.52 W 2.79 15.46 1104.00 7.50 340.00 1102.90 23.84 N 9.06 ~ 2.14 21.66 1196.00 8.40 353.00 1194.02 36.15 N 11.94 ~ 2.18 33.19 1292.00 11.90 2.50 1288.51 53.01 N 12.36 W 4.03 49.65 1420.00 15.80 6.40 1412.77' 83.52 N 9.84 W 3.13 80.08 1517.00 18.00 9.10 1505.58 111.45 N 6.00 W 2.41 108.23 1609.00 20.80 9.40 1592.34 141.61 N 1.08 ~ 3.04 138.7-/ 1707.00 25.50 8.70 1682.43 179.65 N 4.96 E 4.80 177.26 1799.00 29.80 7.60 1763.90 221.90 N 10.98 E 4.71 219.89 1889.00 32.80 9.40 1840.80 268.13 N 17.92 E 3.49 266.59 1987.00 35.80 12.60 1921.75 322.31 N 28.51 E 3.57 321.79 2082.00 38.10 13.40 1997.67 37'/.94 N 41.36 E 2.47 378.86 2174.00 42.00 12.00 2068.08 435.68 N 54.35 E 4.35 438.02 2274.00 45.60 11.20 2140.24 503.48 N 68.25 E 3.64 507.22 2368.00 49.50 9.70 2203.68 571.67 N 80.80 E 4.31 576.56 2462.00 51.80 10.20 2263.28 643.26 N 93.36 E 2.48 649.22 2556.00 55.50 11.00 2318.98 717.66 N 107.30 E 4.00 724.92 2650.00 56.60 12.80 2371.48 793.96 N 123.38 E 1.97 802.~,B 2721.00 57.40 12.10 2410.15 852.10 N 136.22 E 1.40 862.40 2784.00 58.00 12.80 2443.82 904.10 N 147.70 E 1.34 915.64 2876.00 58.40 14.30 2492.30 980.11 N 166.02 E 1.45 9<23.75 2970.00 60.60 16.40 2540.01 1058.20 N 187.47 E 3.03 1074.51 3063.00 61.70 18.20 2584.88 1135.96 N 211.70 E 2.07 1155.47 3158.00 63.80 18.40 2628.38 1216.14 N 238.22 E 2.22 1239.25 3251.00 66.40 17.10 2667.53 1296.47 N 263.92 E 3.07 1323.02 3345.00 68.50 16.70 2703.58 1379.53 N 289.16 E 2.27 1409.38 3439.00 71.00 15.80 2736.11 1464.19 N 313.83 E 2.81 1497.20 3533.00 70.70 16.00 2766.95 1549.60 N 338.15 E 0.38 1585.68 3625.00 69.70 15.10 2798.11 1632.98 N 361.36 E 1.42 1671.98 3720.00 70.00 15.40 2830.84 1719.03 N 384.82 E 0.43 1760.92 3814.00 70.00 14.40 2862.99 1804.39 N 407.53 E 1.00 1849.06 3908.00 70.20 14.00 2894.98 1890.08 N 429.21 E 0.45 1937.31 4000.00 69.70 14.60 2926.53 1973.82 N 450.56 E 0.82 2023.60 4094.00 68.80 14.70 2959.83 2058.87 N 472.79 E 0.96 2111.32 All data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 11.06 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL BAKER Platform,28 St#2 Middle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 2 Your ref : PMSS <2721-10582'> Last revised : 21-Mar-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 4188.00 69.00 14.40 2993.67 2143.75 N 494.82 E 0.36 2198.86 4282.00 68.50 15.40 3027.74 2228.41 N 517.35 E 1.12 2286.27 4377.00 69.40 13.10 3061.86 2314.34 N 539.16 E 2.45 2374.78 4460.00 68.80 12.90 3091.47 2389.89 N 556.61 E 0.76 2452.28 4551.00 67.00 12.70 3125.71 2472.10 N 575.29 E 1.99 2536.55 4648.00 67.50 12.10 3163.22 2559.47 N 594.49 E 0.77 2625.98 4742.00 69.40 11.70 3197.75 2645.02 N 612.52 E 2.06 2713.39 4833.00 69.80 11.60 3229.47 2728.55 N 629.74 E 0.45 2798.68 4930.00 70.70 11.80 3262.24 2817.95 N 648.26 E 0.95 2889.97 5020.00 71.10 12.00 3291.69 2901.17 N 665.79 E 0.49 2975.01 5118.00 70.90 12.50 3323.60 2991.72 N 685.45 E 0.52 3067.65 5214.00 71.20 12.60 3354.77 3080.34 N 705.18 E 0.33 3158.41 5308.00 71.10 13.40 3385.14 3167.02 N 725.19 E 0.81 3247.32 5402.00 70.60 13.10 3415.98 3253.46 N 745.55 E 0.61 3336.05 5495.00 70.70 13.10 3446.80 3338.92 N 765.44 E 0.11 3423.74 5565.00 70.80 13.50 3469.87 3403.23 N 780.64 E 0.56 3489.78 5613.00 70.60 14.00 3485.74 3447.24 N 791.40 E 1.07 3535.03 5639.00 70.60 13.40 3494.38 3471.06 N 797.21 E 2.18 3559.53 5773.00 69.20 13.80 3540.42 3593.37 N 826.80 E 1.08 3685.24 5867.00 69.00 12.70 3573.96 3678.84 N 846.93 E 1.11 3772.99 5961.00 66.90 12.00 3609.25 3763.95 N 865.56 E 2.34 3860.09 6060.00 63.80 10.20 3650.53 3852.22 N 882.90 E 3.54 3950.05 6146.00 63.10 10.10 3688.97 3927.95 N 896.46 E 0.82 4026.97 6240.00 60.50 8.40 3733.39 4009.70 N 909.79 E 3.19 4109.76 6333.00 58.70 8.90 3780.45 4089.00 N 921.85 E 1.99 4189.90 6427.00 57.50 7.30 3830.13 4168.00 N 933.10 E 1.93 4269.59 6522.00 54.60 6.30 3883.18 4246.24 N 942.44 E 3.17 4348.17 6616.00 52.30 6.10 3939.15 4321.31 N 950.60 E 2.45 4423.41 6709.00 52.20 7.50 3996.09 4394.32 N 959.30 E 1.20 4496.73 6803.00 51.60 7.40 4054.09 4467.67 N 968.90 E 0.64 4570.56 6895.00 51.40 6.80 4111.36 4539.11 N 977.80 E 0.55 4642.39 6989.00 51.20 5.70 4170.14 4612.04 N 985.78 E 0.94 4715.49 7082.00 51.10 5.80 4228.47 4684.10 N 993.04 E 0.14 4787.60 7175.00 51.40 4.70 4286.69 4756.32 N 999.67 E 0.98 4859.76 7267.00 49.40 5.70 4345.33 4826.91 N 1006.09 E 2.33 4930.27 7360.00 47.90 5.00 4406.77 4896.42 N 1012.60 E 1.71 4999.73 7454.00 45.60 3.80 4471.17 4964.68 N 1017.87 E 2.62 5067.73 7546.00 41.90 4.90 4537.62 5028.10 N 1022.67 E 4.10 5130.90 7638.00 40.20 5.10 4607.00 5088.29 N 1027.94 E 1.85 5190.98 7733,00 37.40 4.30 4681.03 5147.61 N 1032.83 E 2.99 5250.13 7827.00 33.30 4.80 4757.68 5201.81 N 1037.13 E 4.37 5304.16 7922.00 29.10 6.90 4838.92 5250.75 N 1042.09 E 4.57 5353.14 8014.00 28.70 6.20 4919.47 5294.92 N 1047.16 E 0.57 5397.47 8108.00 25.90 7.60 5002.99 5337.72 N 1052.31 E 3.06 5440.46 8202.00 24.10 8.90 5088.18 5377.04 N 1058.00 E 2.00 5480.13 8293.00 23.20 8.90 5171.54 5413.10 N 1063.65 E 0.99 5516.61 8386.00 22.50 8.00 5257.24 5448.82 N 1068.96 E 0.84 5552.68 8478.00 20.90 7.20 5342.71 5482.54 N 1073.46 E 1.77 5586.64 8572.00 18.40 4.50 5431.24 5513.96 N 1076.73 E 2.83 5618.11 8665.00 17.50 2.70 5519.71 5542.56 N 1078.54 E 1.14 5646.53 AL[ data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea level). Vertical section is from wellhead on azimuth 11.06 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ UNOCAL BAKER Platform,28 St#2 Middle Ground Shoals,Cook Inlet, Alaska SURVEY LISTING Page 3 Your ref : PMSS <2721-10582'~ Last revised : 21-Mar-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 8758.00 17,20 1.40 5608.48 5570.28 N 1079.54 E 0.53 5673.92 8851.00 17,10 0.30 5697.34 5597.70 N 1079.94 E 0.36 5700.90 8944.00 16,30 2.40 5786.42 5624.41 N 1080.56 E 1.08 5727.24 9038.00 15,30 357.30 5876.87 5649.98 N 1080.53 E 1.82 5752.33 9132.00 15.90 359.20 5967.41 5675.24 N 1079.76 E 0.84 5776.98 9225.00 15,70 358.70 6056.90 5700.56 N 1079.30 E 0.26 5801.73 9319.00 14,80 356.10 6147.58 5725.26 N 1078.20 E 1.20 5825.76 9421.00 14,70 355.10 6246.22 5751.15 N 1076.20 E 0.27 5850.79 9514.00 14,80 354.50 6336.16 5774.73 N 1074.06 E 0.20 5873.52 9607.00 14,30 352.80 6426.18 5797.95 N 1071.48 E 0.71 5895.81 9701.00 13,70 352.50 6517.38 5820.50 N 1068.57 E 0.64 5917.39 9793.00 13,10 351.30 6606.88 5841.61 N 1065.57 E 0.72 5937.53 9887.00 11,20 347.50 6698.77 5861.05 N 1061.99 E 2.19 5955.92 9981.00 9,80 336.40 6791.20 5877.30 N 1056.81 E 2.61 5970.87 10076.00 9,40 329.70 6884.88 5891.41 N 1049.66 E 1.25 5983.35 10169.00 9.10 312.10 6976.68 5902.90 N 1040.36 E 3.05 5992.84 10264.00 9.10 303.20 7070.49 5912.05 N 1028.50 E 1.48 5999.55 10357.00 10,40 287.00 7162.17 5918.53 N 1014.32 E 3.25 6003.19 10449.00 11.50 281.40 7252.49 5922.77 N 997.39 E 1.66 6004.10 10543.00 11,90 274.00 7344.54 5925.30 N 978.53 E 1.65 6002.97 10582°00 11,90 274.00 7382.71 5925.86 N 970.51E 0.00 6001.98 Projected Data - NO SURVEY All data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea level). Vertical section ~s from wellhead on azimuth 11.06 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 Platform,28 St#2 Your ref : PMSS <2721-10582'> Middle Ground Shoals,Cook Inlet, Alaska Last revised : 21-Mar-94 Con~nents in wellpath MD TVD Rectangular Coords. Coffrnent 10582.00 7382.71 5925.86 N 970.51E Projected Data - NO SURVEY Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised Ba-28 T/A Snds not specified 5400.00 5500.00N 1175.00E 14-Jun-93 All data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea level). Bottom hole distance is 6004.81 on azimuth 9.30 degrees from wellhead. Vertical section is from wellhead on azimuth 11.06 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum 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 arch: letter dated March 4, 1994 Alaska Region Unocal North Americar Oil & Gas Division Unocal Corporation 909 West 9th Ave., P.O. Box 190247 Anchorage, Alaska 99519-0247 Telephone (907) 276-7600 UNOCAL April 25, 1994 // Russell Douglass Commissioner 3001 Porcupine Drive Anchorage, AK 99501-3192 DOCUMENT NO.' UOC-94-008 Dear Mr. Douglass: The purpose of this letter is to identify the upper and lower pressure limits of the casing/tubing annulus and flowline of Baker well #28 as well as to state the procedure to be followed in the event that these limits are ever reached. As a prudent operator, Unocal believes that the minimum and maximum pressures listed here, and the procedures described, will adequately protect our personnel and the environment. Flowline The maximum flowline pressure is set at 600 psig. Reaching this pressure wiil initiate a shut in of platform Baker's production system. The surface and sub- surface safety valves will close to isolate well #28 from the surface. At this point the platform personnel would investigate the cause of the high flowline pressure, and take appropriate action. The flowline minimum pressure is set at 300 psig. The normal operating pressure of the Baker #28 flowline will be approximately 500 psig. A Iow pressure setting of 300 psig will actuate a production shut in. As is the case with a high pressure shut in, this will include the closing of both the surface and sub- surface safety valves and will isolate Baker #28. In this event, the platform personnel would investigate the cause of the Iow flowline pressure and begin corrective measures. RECEIVED .,.-~R 2 8 1994 .~,sk~ u~l & Gas Cons. Commission Anchorage Mr. Douglass UOC-94-008 April 25, 1994 Page 2 Depending on the behavior of this well, it may be necessary to lower the minimum tubing pressure. If the well produces in such a way that it intermittently unloads fluid, the surface pressure may regularly drop below 300 psig. If this is found to be the case, as experience is gained from operating the well, the appropriate control adjustments will be made. Annulus The minimum pressure on the casing/tubing annulus will be set at 300 psig. If this pressure is reached the surface and sub-surface safety valves will close, shutting in the well. At this point, the cause of the Iow pressure will be investigated. During any shut in, the well will be monitored and any change will dictate an appropriate action. The maximum pressure on the casing/tubing annulus will be 3000 psig. This is believed to be prudent as the wellhead has been tested to 5000 psig and the casing has been tested to 4800 psig. The burst pressure of the casing is 6870 psig. The 3000 psig maximum represents 44% of the casing's rated maximum pressure and 63% of its tested pressure. The same 3000 psig maximum setting represents 60 % of the rated and tested maximum pressure of the wellhead. If the casing pressure reaches 3000 psig, again, both the surface and sub- surface safety valves will close, isolating the well from the surface. The well will be monitored. At this point a decision will be made as to whether to bleed pressure from the well or maintain a shut in. If the pressure continues to climb to a level of 3500 psig, procedures to kill the well with saltwater will be initiated. If you have any further questions, please do not hesitate to call. My office phone is 263-7655. If l am not in my office, you may leave a message or contact Donna Ambruz, our department secretary. Donna will usually be able to locate me and I will return your call. Her office number is 263-7673. Very Truly, Kriss Wegemer Production Engineer R EEEIVEE ,,',,-, ;; o i994 /",,i"r'~ ., () , Ga..r.: Cons. C0rnrnissi0n Anchorage Safety and Monitoring Procedures for Baker #28 - Flowing Well Well will be continuously in test in a dedicated high-pressure separator. This dedicated system has its own safety shut-down system and is also tied into the platform's own safety systems. Tubing, power oil and casing pressures will be checked at least twice a day and recorded daily. Downhole pressure surveys will be conducted at least every 60 days to monitor pressure decline in well. The flowline on the tubing-casing annulus will be equipped with a locked valve to prevent inadvertent flow from the annulus. Water injection into the "A" zone was discontinued prior to drilling the well and will not be restarted until the well is incapable of unassisted flow or it is determined that no pressure maintenance operation would affect the well. Unocal Energy Resources_~.Division Unocal Corporation 909 West 9th Avenue, P.O. .96247 Anchorage, Alaska 9951 Telephone (907) 276-7600 UNOCAL ) DOCUMENT TRANSMITTAL Alaska April 21, 1994 TO' Larry Grant FROM: Dan Seamount LOCATION: 3OOl PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL _~ _ ..... .: ~ ..... . ...... _ ...... _~ _~-_,- ~-_ _ :~ .... -. _ ._~-_._~._._~._ .~. TRANS ING AS FOLLOWS 1 blueline and 1 sepia of each of the following MGS BAKER 28 ~/BHC Acoustilog/Gamma Ray X/Compensated DensilogfNeutron/Gamma Ray ,/Compensated Neutron/Gamma Ray V'~Dual Induction Focused Log/Gamma Ray ~Dual Propagation Resistivity/Gamma Ray (M~ Depth)/~&~ ~Dual Propagation Resistivity/Gm Ray (Subsea TVD) (~ ~ ~ ~/~ormation Mudlog V~BT/Neutron/Gamma Ray Tape & Listing .~Openhole LIS Tape 2025-10491 MGS BAKER 29 ~BFIC Acousfilog/Gamma Ray/Gat:i~er " '""Compensated Densilog/Neutron/Gamma Ray ~ Induction Focused Log/Gm Ray J ormation Mudlog ormation Multi-Tester/Gm Ray v/'Sogmented Bond Log Tape &~isfing Openhole LIS Tape 1879-10281 MGS BAKER 30 .C Aeoustilog/Gamma Ray/Caliper (2" & ,~/~.ompensated Densilog/Neutron/Gamma Ray ~--~ and~ v"Dual Yaduction Focused Log/Gamma Ray ~and~) sB rmation Mudlog T/Gamma Ray Tape & Listing ~"'Openhole LIS Tape 1900-10700 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT Unocal Energy Resourc .... ivision Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL ) Alaska DOCUMENT TRANSMITTAL April 19, 1994 TO: Larry Grant LOCATION: 3001 PORCUPINE DRIVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. FROM: Dan Seamount LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMITTING AS FOLLOWS BOX1 300 - 1710 2040 - 3390 2040-3330 BOX2 1710-3000 3390 - 4680 3330-4560 BOX3 3000-4320 4680-5940 4560 - 6000 BOX4 4320-5550 5940-7200 6000-7500 BOX9 9900-10582 9900-10280 9900-10250 BY PLEASE ACKNOWLEDGE RECEIPT SIGNING AND RECEIVED BY',/- j ' '~~/~ ~ ~'~'"'- DATED: RETURNING ONE COPY OF THANK YOU Unocal Energy Resource, ",ision Unocal Corporation .~- 909 West 9th Avenue, F 196247 Anchorage, Alaska 9951 Telephone (907) 276-7600 UNOCAL ) Alaska DOCUMENT TRANSMITT~ April 18, 1994 TO' Larry Grant FROM' Richard L. Stewart LOCATION. 3OOl PORCUPINE DroVE ANCHORAGE, AK 99501 ALASKA OIL & GAS CONSERVATION COMM. _ LOCATION: P.O.BOX 196247 ANCHORAGE AK 99519 UNOCAL TRANSMITTING AS FOLLOWS GRANITE POINT 17586-3RD GRANITE POINT 17586-3 RD ~ V~'EGMENTED BOND LOG / 1/05/94 vS'EGMENTED BOND LOG/ 1/12/94 V~OMP DENSII,OG/NEUTRON/GAMMARAy 12/26/93 ~HC ACOUSTILOG GAMMA RAY/CALIPER 12/26/93 VDUAL LATEROLOG/MICRO LATERLOG 1:2/26/93 V~ORMATION MUDLOG ~GAMMA RAY LOG 1/27/94 ~'~EGMENTED BOND LOG 2/11/94 ~AMMA RAY NEUTRON 2/11/94 vl~ORMATION MUDLOG LIS TAPE / LISTING PLEASE ACKNOWLEDGE RECEIFr BY SIGNING AND RETURNING ONE COPY OF THIS DOCUMENT.TRANSMIT'r~ TO D~CHHJ)ERS. THANK YOU DATED' MEMORANDU State o, .Alaska Alaska Oil and Gas Conservation Commission TO: David J ~~t~, Chairm~ THRU: Blair Wondzeil, P. I. Supervisor FROM: Lou Grimaldi, Petroleum Inspector DATE: March 19, 1994 FILE NO: AVBJCSBD.DOC SUBJECT: BOP Test Pool Rig #428 Unocal Baker #28 Middle Ground Shoal PTD ~ Friday, March 18, 1994: I traveled to Unocal~ Baker platform in the Middle Ground Shoal Field to witness the weekly BOP test on Pool rig #428. When I arrived, the rig was in the process of nippling up the stack so we tested the choke manifold and floor valves then stood by until the stack was ready. Saturday, March 19, 1994: The Remainder of the B©PE was tested including a thidy minute test of the annular preventer, this was tested when the 9 5/8 packoff assembly was tested. All equipment's tests that I observed functioned properly and held its pressure tests. I found all equipment on the rig to be in top shape with evidence of regular maintenance. The rig itself was clean and orderly and like its sister rig on the Tyonek, of model design. The rig was well prepared for the upcoming dual tubing program. Spare floor valves with the proper crossovers were on hand. Evan Harness (Unocal Rep) kept me well advised of the rigs progress while I was standing by at home prior to coming out and I find him to be a knowledgeable individual and a pleasure to work with. Summary: I witnessed the weekly BOP test on the Baker platform, Pool rig #428.26 valves, no failures, test time 2 hours. Attachment: AVBJCSBD.XLS CC' Russell Schmidt (Drilling Supt.) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report OPERATION: Drlg: X Drlg Contractor: Pool Arctic Operator: Unocal Well Name: Baker #28 Casing Size: Test: Initial Workover: Rig No. 428 Set @ Weekly X Other DATE: PTD # 93-119 Rig Ph.# Rep.: Evan Harness 3/19/94 776-6648 Rig Rep.: Chuck Sheavey Location: Sec. 31 T. 9N R. 12W Meridian Seward TEST DATA MISC. INSPECTIONS: Location Gen.: Good Housekeeping: Good (Gen) Reserve Pit N/A I Well Sign OK Drl. Rig Good BOP STACK: Annular Preventer Pipe Rams Pipe Rams Blind Rams Choke Ln. Valves HCR Valves Kill Line Valves Check Valve Test Quan. Pressure P/F 1 250/3500 ~ 1 250/5000 ~ I 250/5000 ~ 1 250/5000 ~ 2 250/5000 ~ 2 250/5000 ~ 1 250/5000 ~ N/A N/A N/AI MUD SYSTEM: Visual Alarm Trip Tank P P Pit Level Indicators P 'P Flow Indicator P P Gas Detectors P P FLOOR SAFETY VALVES: Upper Kelly / IBOP Lower Kelly / IBOP Ball Type Inside BOP Test Quan. Pressure P/F 1 250/5000 P 250/5000 250/5000 1 250/5000 CHOKE MANIFOLD: No. Valves No. Flanges Manual Chokes Hydraulic Chokes 15 Test Pressure P/F 250/5000 P 40 250/5000 P 1 P ACCUMULATOR SYSTEM: System Pressure Pressure After Closure 200 psi Attained After Closure System Pressure Attained Blind Switch Covers: Master: Nitgn. Btl's: 12 Bottles 2300 Average 2,800 I P 1,800 P minutes 25 sec. 1 minutes 50 sec. OK Remote: OK Psig. TEST RESULTS Number of Failures: 0 "- ,Test Time: 2 '~ Hours. Number of valves tested 31 Repair or Replacement of Failed Equipment will be made within N/A 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: Rig in top shape, Good testing procedure Distribution: orig-Well File c - Oper./Rig c - Database c - Trip Rpt File c- Inspector FI.O21L (Rev. 2/93) STATE WITNESS REQUIRED? YES X NO 24 HOUR NOTICE GIVEN YES X NO Waived By: Witnessed By: AVBJCSBD.XLS Louis R Grimaldi ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE I ANCHORAGE, ALASKA g9501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 2767542 'January 10, 1994 Russell Schmidt Unocal P O Box 196247 o 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, Robed P Crandall Sr Petr Geologist encl jo/A: RPC.\drlstats e:; ' ' G.D. ,'..-, p. rmmd :m recycled'paper b y 1103194 OP~R3kTOR UNION OIL CO OF CALI UNION OIL CO OF CALX UNION OIL CO OF CALX UNION OIL CO OF C-ALI UNION OIL CO OF 'CALX t.31q~O~ OIL CO OF CALX UNION OIL CO OF CALX UNION OIL C~D OF CALX UNION OIL CO OF CALI UNION OIL CO OF CALI ALASKA WELLS BY UNOCAL PEP. MIT 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 CHAKACHATNA MGS B~29 CHAK~ACHATNA MGS B-28 CH3kK. ACHATNA MGS B~30 GRAIqlTE PT ST 17586 3RD TR3kDING BAY UNIT K-24RD TRADING BaY UNIT K-26 AMETHYST STATE TRADING BAY UNIT M-31 PAGE 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 #28 UNOCAL Permit No: 93-119 Sur. Loc. 1929'FNL, 543'FWL, Sec 31, T9N, R12W, SM Btmhole Loc. 1246'FNL, 1817'FWL, Sec 30, 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, 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. ~,~.. printed on rec¥cleH p,-ff)er I~; ~' C ~'). ALASKA ---,,STATE OF ALASKA - _AND GAS CONSERVATION COM. 3SION PERMIT TO DRILL 20 AAC 25.005 la. Type of work Drill [] Redrill ~ Re-Entry [~ Deepen ~ 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Union Oil Comapny of California (UNOCAL) 118' RT ABOVE MSL feet Middle Ground Shoals 3. Address 6. Property Designation E,F & G Pool P.O. Box 196247, Anchorage, AK 99519-6247 ADL 17595 4. Location of well at surface Baker Pit. Leg #1, Slot #1 7. Unit or property name 11. Type Bond (SEE 20 ACC 25.025) 1929' FNL & 543' FWL SECTION 31, TDN, R12W, S.M. Chakachatna MGS UNITED PACIFIC INS. CO. At top of productive interval 8569'MD / 5400'TVD 8. Well number Number 1709' FNL & 1718' FWL SEC. 30, TDN, R12W, S.M. Baker #28 U62-9269 At total depth 10237'MD / 7000'TVD 9. Approximate spud date Amount 1246'FNL & 1817'FWL SEC. 30, TDN, R12W, S.M. September 7, 1993 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15. Proposed depth (MD and TVD) property line 3300 feet 4' @ SURFACE feet 5106 10,237' / 7,000' feet -- 16. To be completed for deviated wells 17. Anticipated Pressure(,.e 20 AAC 25.035 (e) (2)) Kickoff depth 800 feet Maximum hole angle 71 DEG M~mumsur~ce 683 psig At total depth ('rVD) 3150 psig 18. Casing program Setting Depth size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (include stage data) 28" 24" 156 X42 MTSGO 744' 56 56 800' 800' 1400 cu.fl. 24" 18-5/8" 97 X56 QTEGO 2444' 56 56 2500' 2284' 3000 cu.ft.+?2~c.~'r'r-.,.,~ 17-1/2" 13-3/8" 68 K55 BU'FF 7144' 56 56 7200' 4224' 3200 cu.fl. 12-1/4" 9-5/8" 47 N80 B Lrl-r 10181' 56 56 10237' 7000' 1500 cu.ft. -- 19. To be completed for Redrill, Re-entry, and Deepen Operations Present well condition summary Total depth: measured 303 feet Plugs (measured) true vertical 303 feet Effective depth: measured 303' feet Junk (measured) true vertical 303' feet Casing Length Size Cemented Measured depth True vertical depth Structural 247 30" DRIVEN 303 RKB (83' BML) Conductor Surface Intermediate RECFIVED Production Liner ~ i ii'~: ~, .'~ ~;~,.~ "-.~. ,,,; '.j . , Perforation depth: measured Alask~ (J~l &,4¢..,"-' .... Co~.s. O0~-¢m. issi0rt true vertical _AnchorAg~ 20. Attachments Filing fee ~: Property plat Drilling fluid program ~: f~Tim,e vs depth plot 21. I hereby ~ify~and correct to the best of my knowledge Signed G. RUSSELLSCHMIDT Title REGIONAL DRILLING MANAGER Date Commission Use Only Number APl numberI date_ _ See cover letter Permi~,.~ //~' 150-- .'7 ~ ~ - ~ ~ ~',¢'..¢ IApprpyal · "' ~'~.,,..,~--, ~..~1~ for other requirements Conditions of approval Samples required ~ Yes .~ No Mud log required [] Yes ,~ No Hydrogen sulfide measures ~ Yes ~ No Directionalsurvey required .~ Yes ~ No Required working pressure for DOPE L~ 2M; ~ 3M; ;" 5M; [-J 1OM; ~ 15M Other: ORIGINAL SIGNEDBY RUSSELL A. DOUGLASS by the order of Approved by Commissioner the commission Date ~'- ~ - ,~"~, Form 10-401 Rev. 12-1-85 Submit in triplic~ e Unocal North Americ, 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 MaP 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. R EC F IV F D AL,JO 1 !993 Ancherage 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 Alaska Oil & Gas Cons. ~noho. ra.cJ~. Baker #28 (New Well) RWP Option 9.0 AFE Estimate August 02, 1993 Procedure Days ® · · 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. MIRU, Leg #1, Conductor #1, 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 2500' (ROP 500') (Build 3°/100' maximum angle 71°) Underream 17-1/2" hole section 24". Run and cement 18-5/8" casing. Install 20" BOPE. Drill 17-1/2" hole to 7200'. (ROP 450') Run open hole logs. (see notes below) Run and cement 13-3/8" casing. Install 13-5/8" BOP. Drill 12-1/4" hole to 10237' TD. (ROP to TD = 275') Run open hole logs. (see notes below) Run and cement 9-5/8" casing. Run CET/CBT on DP conveyed tools. Clean out, pressure test, change over to 3% KCL. Run Vann TCP guns (4-5/8" OD, 4 spf, DP charge) in combination with Dual 3-1/2" KOBE BHA. Set BPV, Rem BOPE, Install tree and flowlines. Detonate TCP guns and produce well. 2 1 3.5 2 2 10 1.5 2.5 11 2.5 2.5 1.5 2 4 Time (Days) 52 Depth 0 Baker 28 NEW WELL Depth vs. Days ROP 800 FPD RUN 24' OSG (2,000) AVG. ROP 600 FPD RUN 18-5/8" CSG TIME: 52 DAYS COST: $4.20 MM (4,000) AVG. ROP 500 FPD (6,oeo) LOG & RUN 13-3/8" CSG (8,000) AVG ROP 275 FPD (10,000) (12,000) LOG & RUN 9-5/8' CSG I JI 20 30 Estimate COMPLETION i I 4O Days Actual 5O 6O 7O Alaska Oil & 64as Ooi~.$.. 0or,,~missio~, IKOBE BHA I 30" Structural @ 83' BLM 24" Conductor @ 800' 156#, X-42, MTS6OAR 18-5/8" Surface @ 2500' 97#, X-56, QTE60 MISC. DATA RKB = 118' WATER DEPTH 13-3/8" Intermediate @ 7200' ~1~ 68#, K-55, BTC COMPLETION DESCRIPTION 1) Dual 3-1/2", 9.2#, L-80, SCBTC 2) KOBE BHA @ 8200' 3) TCP guns 4-5/8" OD net 1000' Hemlock @ Intervals +1000' 9-5/8" Production @ 102,37' 47#, L-80, BTC BAKER 28 PROPOSED COMPLETION UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE' 8-01-93 FILE' BA30.drw UNOCAL Sfrucfure : BAKER Plafform Well : Bo-28 ~rield : Middle Ground Shoals Location : Cook Inlet, Alaska WELL PROFILE DATA .... J iCreated by : jones For: L LOHOEFER --- Point .... ! MO Inc git TYD North EastI iDate plotted ' 5-Aug-g3 i iTie on iPIot Reference is Ba-28 Version #9. i iKOP ! i t ]Coordinates ore in feet reference slot #1-1.1 End of 8u,d ~ : iEnd of Hold iTrue Vertical Depths are reference wellhead. ~ ~Torget : [ Baker i !End of Bold i Hughes i iEnd of Hold :; INTEQ o 0.00 o.oe o o at 8o0 o.oo 12.o6 a00 o Dj 3146 70.38 12.06 2599 1241 265j 5875 70.58 12.06 3515 3754 802j 8589 16.50 12.06 5400 5500 1175i 9247 16.50 12.06 6050 5688 1215j 10238 16.50 12.06 7000 5963 1274j .... East 0 400 800 1200 160,0 350 - 700 _ _ 1050_ -.C 1750 -1~ - 2450_ _ 2800_ © - · ~ 3150_ _ > 3850_ _ 4200 _ F-- - 455O_ _ 4900_ _ V 5250_ _ 5950_ _ _ 6650_ _ 7000_ 7350 N 12.06 DEG E 6098' (TO TD) KOP 5.00 9.00 15.00 21.00 BUILD 3 DE(;; / 100' 27.00 33.00 39.00 45.00 51.00 57.00 63.00 69.00 EOC AVERAGE ANGLE 70.38 DEG Begin 2 Dog / 100' Drop 70.( 62.00 58.00 54.O0 50.00 46.00 42.00 DROP 2 DEG / 100'38.00 34.00 30.00 26.00 22.00 18.00 Top A Sands TARGET ANGLE 16.5 DEG ' I I I I I I 0150 I ' I ' I 21100 I ;50 ' I I 31150 ' 35100 I I5 ' ' ' 45150 350 0 350 700 1 1400 1750 2 2800 38 0 4200 4900 5250 5600 5950 Scale1 : 175.00 Vertical Section on 12.06 azimuth with reference 0.00 N, 0.00 E from slot #1-1 - _5200 - _4800 _ =3200 J - .2800Z 0 - _2400 '~ - D-- _2000 600 p l Top B Sands I I' I I I I ' " I · Anchorago UNOCAL BAKER Platform Ba-28 slot #1-1 Middle Ground Shoals Cook Inlet, Alaska PROPOSAL LISTING by Eastman Tekeco Your ref : Ba-28 Version ~9 Our ref : prop819 License : Date printed : 28-Jul-93 Date created : 14-Jun-93 Last revised : 28-Jul-93 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 45.807,w151 29 0.988 Slot Grid coordinates are N 2498075.761, E 235253.694 Slot Local coordinates are 1929.00 S 543.00 E Reference North is True North UNOCAL BAKER Platform,Ba-28 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 1 Your ref : Ba-28 Version #9 Last revised : 28-Jul-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 0.00 0.00 0.00 0.00 0.00 N 0.00 E 0.00 0.00 100.00 0.00 12.06 100.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 12.06 200.00 0.00 N 0.00 E 0.00 0.00 300.00 0.00 12.06 300.00 0.00 N 0.00 E 0.00 0.00 400.00 0.00 12.06 400.00 0.00 N 0.00 E 0.00 0.00 500.00 0.00 12.06 500.00 0.00 N 0.00 E 0.00 0.00 600.00 0.00 12.06 600.00 0.00 N 0.00 E 0.00 0.00 700.00 0.00 12.06 700.00 0.00 N 0.00 E 0.00 0.00 800.00 0.00 12.06 800.00 0.00 N 0.00 E 0.00 0.00 KOP 900.00 3.00 12.06 899.95 2.56 N 0.55 E 3.00 2.62 1000.00 6.00 12.06 999.63 10.23 N 2.18 E 3.00 10.46 1100.00 9.00 12.06 1098.77 22.99 N 4.91 E 3.00 23.51 1200.00 12.00 12.06 1197.08 40.81 N 8.72 E 3.00 41.74 1300.00 15.00 12.06 1294.31 63.64 N 13.60 E 3.00 65.08 1400.00 18.00 12.06 1390.18 91.41 N 19.53 E 3.00 93.48 1500.00 21.00 12.06 1484.43 124.05 N 26.50 E 3.00 126.85 1600.00 24.00 12.06 1576.81 161.47 N 34.50 E 3.00 165.12 1700.00 27.00 12.06 1667.06 203.57 N 43.49 E 3.00 208.16 1800.00 30.00 12.06 1754.93 250.23 N 53.46 E 3.00 255.87 1900.00 33.00 12.06 1840.18 301.32 N 64.37 E 3.00 308.12 2000.00 36.00 12.06 1922.59 356.70 N 76.20 E 3.00 364.75 2100.00 39.00 12.06 2001.91 416.23 N 88.92 E 3.00 425.62 2200.00 42.00 12.06 2077.94 479.73 N 102.49 E 3.00 490.56 2300.00 45.00 12.06 2150.47 547.04 N 116.87 E 3.00 559.38 2400.00 48.00 12.06 2219.30 617.97 N 132.02 E 3.00 631.91 2500.00 51.00 12.06 2284.24 692.32 N 147.90 E 3.00 707.94 2600.00 54.00 12.06 2345.11 769.90 N 164.48 E 3.00 787.27 2700.00 57.00 12.06 2401.74 850.48 N 181.69 E 3.00 869.68 2800.00 60.00 12.06 2453.99 933.86 N 199.50 E 3.00 954.93 2900.00 63.00 12.06 2501.70 1019.79 N 217.86 E 3.00 1042.80 3000.00 66.00 12.06 2544.74 1108.04 N 236.72 E 3.00 1133.05 3100.00 69.00 12.06 2583.01 1198.38 N 256.02 E 3.00 1225.43 3146.12 70.38 12.06 2599.01 1240.68 N 265.05 E 3.00 1268.68 EOC 3500.00 70.38 12.06 2717.82 1566.67 N 334.70 E 0.00 1602.02 4000.00 70.38 12.06 2885.68 2027.25 N 433.09 E 0.00 2073.00 4500.00 70.38 12.06 3053.54 2487.84 N 531.49 E 0.00 2543.98 5000.00 70.38 12.06 3221.40 2948.43 N 629.89 E 0.00 3014.96 5500.00 70.38 12.06 3389.26 3409.02 N 728.29 E 0.00 3485.94 5874.88 70.38 12.06 3515.12 3754.34 N 802.06 E 0.00 3839.06 Begin 2 Deg / 100' Drop 5874.89 70.38 12.06 3515.12 3754.36 N 802.07 E 0.01 3839.07 5894.06 70.00 12.06 3521.62 3772.00 N 805.84 E 2.00 3857.11 5994.06 68.00 12.06 3557.46 3863.29 N 825.34 E 2.00 3950.47 6094.06 66.00 12.06 3596.53 3953.30 N 844.57 E 2.00 4042.51 6194.06 64.00 12.06 3638.79 4041.93 N 863.50 E 2.00 4133.14 6294.06 62.00 12.06 3684.18 4129.06 N 882.12 E 2.00 4222.24 6394.06 60.00 12.06 3732.66 4214.59 N 900.39 E 2.00 4309.69 6494.06 58.00 12.06 3784.16 4298.41 N 918.30 E 2.00 4395.40 6594.06 56.00 12.06 3838.63 4380.42 N 935.82 E 2.00 4479.27 6694.06 54.00 12.06 3895.98 4460.52 N ~52.93 E 2.00 4561.18 6794.06 52.00 12.06 3956.16 4538.62 N 969.61 E 2.00 4641.04 All data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea Level) Vertical section is from wellhead on azimuth 12.06 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-28 Middle Ground Shoals,Cook Inlet, Alaska PROPOSAL LISTING Page 2 Your ref : Ba-28 Version ~9 Last revised : 28-Ju[-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 6894.06 50.00 12.06 4019.09 4614.62 N 985.85 E 2.00 4718.75 6994.06 48.00 12.06 4084.69 4688.42 N 1001.62 E 2.00 4794.22 7094.06 46.00 12.06 4152.89 4759.94 N 1016.89 E 2.00 4867.35 7194.06 44.00 12.06 4223.59 4829.08 N 1031.67 E 2.00 4938.06 7294.06 42.00 12.06 4296.73 4895.78 N 1045.91 E 2.00 5006.25 7394.06 40.00 12.06 4372.19 4959.93 N 1059.62 E 2.00 5071.85 7494.06 38.00 12.06 4449.90 5021.47 N 1072.77 E 2.00 5134.78 7594.06 36.00 12.06 4529.76 5080.32 N 1085.34 E 2.00 5194.96 7694.06 34.00 12.06 4611.67 5136.41 N 1097.32 E 2.00 5252.32 7794.06 32.00 12.06 4695.54 5189.67 N 1108.70 E 2.00 5306.78 7894.06 30.00 12.06 4781.25 5240.03 N 1119.46 E 2.00 5358.28 7994.06 28.00 12.06 4868.71 5287.44 N 1129.59 E 2.00 5406.76 8094.06 26.00 12.06 4957.80 5331.84 N 1139.07 E 2.00 5452.15 8194.06 24.00 12.06 5048.43 5373.16 N 1147.90 E 2.00 5494.41 8294.06 22.00 12.06 5140.48 5411.37 N 1156.06 E 2.00 5533.48 8394.06 20.00 12.06 5233.83 5446.42 N 1163.55 E 2.00 8494.06 18.00 12.06 5328.38 5478.25 N 1170.35 E 2.00 8569.06 16.50 12.06 5400.00 5500.00 N 1175.00 E 2.00 9000.00 16.50 12.06 5813.19 5619.69 N 1200.57 E 0.00 9246.98 16.50 12.06 6050.00 5688.29 N 1215.22 E 0.00 5569.32 5601.87 5624.11 Top A Sands 5746.51 5816.65 Top B Sands 9500.00 16.50 12.06 6292.60 5758.57 N 1230.24 E 0.00 10000.00 16.50 12.06 6772.01 5897.44 N 1259.91 E 0.00 10237.78 16.50 12.06 7000.00 5963.49 N 1274.02 E 0.00 5888.51 6030.52 6098.06 TD All data is in feet unless otherwise stated Coordinates from slot #1-1 and TV[) from wellhead (118.00 Ft above mean sea level) Vertical section is from wellhead on azimuth 12.06 degrees. Declination is 0.00 degrees, Convergence is -1.30 degrees. Calculation uses the minimum curvature method. Presented by Eastman Teleco UNOCAL PROPOSAL LISTING Page 3 BAKER Platform,Ba-28 Your ref : Ba-28 Version ~9 Middle Ground Shoals,Cook Inlet, Alaska Last revised : 28-Jul-93 Con~nts in wellpath MD TVD Rectangular Coords. Comment 800.00 800.00 0.00 N 0.00 E KOP 3146.12 2599.01 1240.68 N 265.05 E EOC 5874.88 3515.12 3754.34 N 802.06 E Begin 2 Deg / 100' Drop 8569.06 5400.00 5500.00 N 1175.00 E Top A Sands 9246.98 6050.00 5688.29 N 1215.22 E Top B Sands 10237.78 7000.00 5963.49 N 1274.02 E TD Targets associated with this wellpath Target name Position T.V.D. Local rectangular coords. Date revised Ba-28 T/A Snds not specified 5400.00 5500.00N 1175.00E 14-Jun-93 All data is in feet unless otherwise stated Coordinates from slot #1-1 and TVD from wellhead (118.00 Ft above mean sea level) Bottom hole distance is 6098.06 on azimuth 12.06 degrees from wellhead. Total Dogleg for wellpath is 124.27 degrees. Vertical section is from wellhead on azimuth 12.06 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-28 slot #1-1 Middle Ground Shoals Cook Inlet, Alaska CLEARANCE REPORT Eastman TeLeco '~-, ~ ,,;.~., r.."! ~ ,. ~Z'~ ., ~ ' -' ~'~ Your ref Our ref : pro~19 L i cerise : ~i?.~, ,. ' ..... ,7,:'~. ~..~,..~;..,... Date print~ Date creat~ : 14-Jun-gl Last revis~ 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 45.807,w151 29 0.988 Slot Grid coordinates are N 2498075.761, E 235253.694 Slot local coordinates are 1929.00 S 543.00 E Reference North is True North Main calculation performed with 3-D minimum distance methed Object wellpath Ba-29 Version ff5,,Ba-29,BAKER Platform MSS <2008-10314'>,,8,BAKER Platform GMS <0-9250'>,,8Rd,BAKER Platform MSS <7117-8642'>,,25,BAKER PLatform PGMS <7200-9800'>,,25Rd,BAKER Platform MSS <6950-10116'>,,15Rd,BAKER Platform PGMS <0-9544'>,,15,BAKER PLatform MSS <0-9215'>,,4,BAKER PLatform MSS <3165-10455'>,,14,BAKER PLatform GMS <0-11128'>,,5,BAKER Platform MSS <2653-11495'>,,9,BAKER PLatform GMS <0-9760'>,,9Rd~2,BAKER PLatform MSS <6757-9944'>,,9Rd~1,BAKER PLatform MSS <765-9543'>,,11,BAKER PLatform MSS <5626-10231'>,,18,BAKER Platform Ba30 Version #4,,Ba-30,BAKER Platform GMS <0-7232'>,,17,BAKER Platform GMS <8300-9445'>,,7,BAKER PLatform PGMS <0-9722'>,,23,BAKER PLatform MSS <1039-12500'>,,lO,BAKER Platform GMS <0-10691'> ,13,BAKER Platform GMS <0-11600'> ,27, BAKER Platform GMS <0-7400'> ,6,BA~ER Platform PGMS <0-9642'> ,20,BAKER Platform MSS <0-10000'> ,12,BAKER Platform GMS <0-9645'> ,16,BAKER Platform Closest approach with 3-D Last revised Distance 28-Jul-93 5.1 3-Jun-93 90.9 3-Jun-93 90.9 3-Jun-93 80.0 3-Jun-93 80.0 3-Jun-93 76.6 3-Jun-93 76.6 24-May-93 63.8 23-May-93 2.8 24-May-93 1.4. 23-May-93 9.8 23-May-93 9.8 23-May-93 9.8 23-May-93 9.9 24-May-93 6.4 13-Jul-93 5.0 24-May-93 72.7 24-May-93 90.2 24-May-93 88.3 23-May-93 80.2 23-May-93 71.7 24-May-93 48.9 24-May-93 62.3 24-May-93 76.4 23-May-93 78.6 24-May-93 79.7 minin~n distance method M.D. Diverging from M.D. 800.0 9320.0 700.0 8569.1 700.0 8900.7 825.0 9422.2 825.0 10237.8 100.0 8900.7 100.0 8900.7 800.0 8569.1 318.0 10237.8 1300.0 8569.1: 118.0 9422.2 118.0 10237.8 118.0 9740.0 118.0 8569.1 418.0 10237.8 800.0 10237.8 850.0 8569.1 618.0 9840.0 500.0 9840.0 975.0 9620.0 800.0 9720.0 1775.0 10237.8 825.0 8569.1 500.0 8569.1 400.0 8569.1 100.0 8569.1 Scale 1 · 20.00 South 0 0 0 0 0 0 o 0 0 0 p... I ' 0 0 0 0 0 c',4 ~t- q:) p.. p.. p.. I I I I I 0 0 0 0 0 0 o 0 0 0 0 0 0 0 0 0 t~l 0 ~0 0 ,-- 0 m 0 0 e~ ~0 ~ 0 ~- ~'~ 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Scale 1 ' 20.00 South 0 cID 0 (x4 -- LO ~ 0 0 -- 0 0 0 0 0 0 0 0 0 0 IZ) CID 0 CO CO ~ (~ ~ ~ ~ 0 0 0 I I I ~1 I .~ I I I I I I ~ I ~1 ! ~1 I ~1 I ~1 i. PAGE OF Jg Drilling Fluids Co. / I Magcobar,'lMCO ~ Dresser Hall,burton Company / I UNOCAL BAKER PLATFORM CHAKACHATNA DEVELOPMENT #29, #30, AND #28 DEPTH INTERVAL MUD TYPE MUD ADDITIVES POTENTIAL PROBLEMS COST PER BARREL 0 - 800' 17½"/28" HOLE 24" CASING F.I.W./GENERIC MUD #2 M-Z 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 OF lg' Drilling Fluids Co. ( ] MagcoDar,'lMCO A Dresser,Halliburton Company I * L ~ '~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 #/100ft2 8-20 No Control 8.5 - 9.5 DM-131 .WP (4/93) i 1 DEPTH INTERVAL MUD TYPE MUD ADDITIVES GE J ' Driiling Fluids Co. ! / MaacoDar IMCO A Dresser,Halliburton Comoany OF ! UNOCAL BAKER PLATFORM CHAKACHATNA DEVELOPMENT #29, #30, and %28 "LOHOEFER 1993 800' - 3000' 17-1/2"/24" HOLE 18-5/8" CASING F.I.W./GENERIC MUD #2 M-I GEL/M-I BAR/SODA ASH/ POLYPAC / SPERSENE / XP- 20 / SODIUM BICARBONATE/ CAUSTIC i POTENTIAL PROBLEMS COST PER BARREL HOLE CLEANING/TIGHT HOLE/BIT BALLING/ GUMBO CLAYS/HOLE ENLARGEMENT/GAS KICKS/ COAL SLOUGHING $5.68 ESTIMATED TREATMENTS/PROCEDURES 1) 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. 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) d '~GE ~-~=~Drilling Fluids Co. / I Maacoear IMCO A. Dresser ~aihburton Comoany ~ 1 ~F "LOHOEFER k ., / il Il 11 ! 1 11 1 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 all 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) ti '~AG E J = Drilling Fluids Co. / ] Magcoear IMCO A Dresser ~amDurton Comoany ¸OF .~-.~.. LOHOEFER 1! DEPTH INTERVAL MUD TYPE UNOCAL BAKER PLATFORM C~%KAC~TNA DEVELOPMENT #29, #30, AND #28 3000' - 7500' 17%" HOLE F.I.W./GENERIC MUD #2 MUD ADDITIVES POTENTIAL PROBLEMS H-Z 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 it il 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. ..... ~ DH- 131. WP CF J ' Driiling Fluids Co. :- ] Ma(]coDar iMCO ~ Dresser Halliburton Company .... ,..OHOEFER 8) Prehydrate all bentonite in freshwater. 9) Drill to 7500'. Run 13-3/8" casing. 10) Save and re-use mud on wells 30 and 28. 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 #/100ft2 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 i DM- 131. WP (4/93) INVOLVED d Drilling Fluids Co. ! I Maacoear IMCO ,~ Dresser HalhDurton Comoanv UNOCAL BAKER PLATFORM CHAKACHATNA DEVELOPMENT #29, #30, AND #28 "' L..~?-tOEFER _ z '". ', ;99,.3 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 DM- 131. WP (4/93) 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. · g Drilling Fluids Co. ! ] MagcoDar iMCO .6, Dresser, Halhburton Comoany OF iL. LOHOEFER 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. 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. 9) Use Polypac UL and/or SP-101 for additional fluid loss control. i0) 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 it Mud Density (ppg) Funnel Viscosity(sec/qt) Plastic Viscosity (cps) Yield Point (#/100ft2) Gels (#/100ft2) 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 0.5 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 > ~ 3"-]_OM CHECK VALVE KILL LINE x1 / MSP ANNULAR 203/4"2000 psi sPooL ~/1'3000 p~si 1 I PIPE RAMS 203/4" 3000 psi BLIND RAMS FLOW 203/4" 3000 psi HCR I HCR _~ ~ MANUAL [DRILLING[ MANUAL [~ ~ ~N4[~~~K~0 ,/s;P3 o°o%~p s~ ~ ~~~<~~ C H 0 K E I RISER eo~/4'' 3000 psi LINE-- CHAKACHATNA. RIG, 4-28 BOP/DlVERTER STACK 21 ~/I' 2000psi/20%" 3000psi ~ ?Low FILL- UP · I ANNULAR BOP PIPE RAMS 135/s"5000 psi BLIND RAMS 3" - 10M 13 %" 5000 psi CHECK ~ALVE HCR ~ HC~ ~ ,~, ~ miLL ~ LINE -~~ ~s~/~'sooo ~s~ CHOKE s,,_~o~// iii i [ ~~4,,_1oMI ~ k 't LINE~~> RISER 13%" 5000 psi CHAKACHATNA RIG 428' BOPE STACK 13 %" 5000 psi VENT OUTSIDE OF WlNDWALLS PANIC LINE E WILLIS ADJ. 4" 5,000 PSI TEST BALL 4 ~/~6-5M FLe. w/R59 -~ x 4 ~/~6-5~ HU~ W/BX~55~ BLIND HUB ~ 10 000 PSI t5 CLNVIP W/ BX155 -'~ I J1~.GCHOKE .4 1/16" -5M FLP~. % I I VENT UP DERRICK 3" RELIEF VALVE SET AT 40 PSI 10" VENT LINE 10" 150 lb. FLANGE CLAMP HUB CONNECTION BUFFER TANK ;MUD SEPERATOR SIPHON LINE 150 lb. FLANGE ,I TO SHAKER TO PRODUCTION SEPARATOR MUD RETURN UNE UNOCAL CHOKE MANIFOLD COOK INLET DWG. CM-1:12592 UNOCAL CHOKE MANIFOLD COOK INLEf ~1 I { ~u~ ,'emTIWl ^, .. ..... I ~ i m I~=1'~"t m-si ',,r'J ~,M-i.,zouz o iii PLAN VIEW @ NORTHWEST LEG IfH VIEW' A-A I I I I I I I I I I I I I PA4 RIC 428 ~o ~/~" - 3a aLOe-OUr P~ ~ " JUL 2 0 RE~RENCE D~WING 428.5039 FOR ~R~ER INFOR~ PERTAINING TO D~R~ UNE 5~OLS. f - I - Ire' ! t - r,-e f - I - 10-4' f - t'4 DNERTER UNE LAYOUT NORTHWEST LEO PosmoN POOL RI(; 428 ~( fg-o MC fg-g PLAN / ! A VIEW ON SOUTHWEST LEG _____ lll I I I lB I I[. I 1%1/11 VIEW A-A PLAN VIEw SHOWN ON NORTHEAST LEG NOTE: REFERENCE DRAWING 428.5039 FOR FURTHER INFORMATION PERIAINING TO DIVERTE. R LINE SPOOLS. DIVERTER UNE LAYOUT SOUTHWEST &: EAST LEO PosmoNs POOL RIO 428 i :1 TOP OF BOP STE. K ~ PLATFORI~ BAKER~! :I TOP OF PIIV RAIL IS,$UEO PLATFORMS DILLON/At,INA, ....,,~ ~\\~ .., ...,. ,, ~ / I 1~-~ W~jT'-2:19~6 11/1~ w~ 19'-7 1/1~; I I' /~1 ~ I~1 ~ ~ ~ A P~~ ~ ~ P~ R~~ ~ ~ ~ ~1 ~ W~ HIGH PRESSURE RISERS ~YO~ D~~ STACK ~D BOP STACK U~ P~ORMS ~ER, DI~ON, & ~ P~ RIO 428 I I I ~~~J ~~*~ ~ ~ ~ v~-~'~ -- ~,~ 42~.5047 ~ AL TERNATE 9PP£R OSITION PIONEER S-800 SIOEWlNDER MUD HOPPER F ] I I I I 1 i I I LIOUIDS (ALT) CENTRIFUGE [ ~ I CENTRIFUGE ~,~..~ ~ o _ i TRAiVSFFR TO/FROM PLAT,r"OR.V, MUD STORAGE CUTTINGS DiSCH4RGE PILL PIT "~ 55 BBL '- ...~ ~r. 3.-, · ~.. ~ ~sucrloN rA,~K i i" - .... ~1 I -' __~ ~ .... I __ ~ ....... I OE~NOER i ~ "~ F--' ~ j x . DENSER ~ PIT I [,[1/, ~O T~P O~R~OW , 30 BBL WEI~ / I I MP2 CHARGE PUMP '. I · I I &[ ' SOUD$ · "~C_.._ ..... ._1 _. l. Lqjllp. s_ .................... I I ~!.,~.~.._~. ............. . · PUMP I "*- ........ r' --~ ~.._ld._~._H ............... , . PUMP I ~.._ ~ t~..-~ ' PUMP I ' t..-~ SCRF E;.:F'D UNDERFLOr~ L,. . · PIONEER !1 T8.-6 · OESANDER ,J I i I-9" MUD CLEAN[-'R I I SC/~.'w , CONVEYOR Ii TRI-FLO TFI-16 MUD CLEANER --- DITCH GATES ,-~-~ BOTTO,~.f EQUALIZER ~ ~ .... OVER FI. Ot, V WEIR DUMP VALVE VAL VIz- ADJUSTABLE MUD GUN MUD AGITATOR SUCTION VALVE ISSUED JUL 2 0 ~ POOl. AEICT~ ALA~,A CUTTII,I¢S DISCH4RCE STRAINER TRANSFER FROM PLATI'ORILI MUD PUMP ,~' OiLY/ELL .4-. !/OOPT ~.fdO STORAGE REVISED PRItfl': DESTROY PREVIOUS ISSUE ~CHEMATIC LOW PRESSURE MUD SYSTEM,. UNOCAL CHAKACI.-IATNA PROJECT PAA RIG 428 _ , i i ,.~.m~.,.~ I ~,~.~,,. ~! I I ~ I~1~1 ....... ic~ ! I'~ I-I~,1 · I Rotary Kelly Bushing (RKB) Drill Deck Level Production Deck Level Elev. 118' Elev. 78' Dev. 62' Seo Level (MLW) Elev. O' Mud Line Elev. - 102' 30" Structurel @ 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" Intermediate @ 6200' 68#, K-55, BTC 9-5/8" Production @ 109 15' 47#, L-80, BTC BAKER PLATFORM ELEVATION DIMENSIONS UNOCAL ENERGY RESOURCES ALASKA DRAWN: CLL DATE: 7- 15-92 FILE: BAKELEV. drw WELL: BAKER ~28 1. MUD WT. I 8.8 PPG 2. 9.0 PPG 3. 9.0 PPG CASING SIZE FIELD: MIDDLE GROUND SHOAL CASING DESIGN DATE: AUGUST 3, 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" 2500' 56' MD 2444 2284' 56' TVD 3. 13-3/8" 7200' 56' MD 7144' 4224' 56' TVD 4. 9-5/8" 10238' 56' MD 10182' 7000' 56' TVD 5. 156~, X-42, MTS 60 AR 116,064 SAME 97~, X-56, QTE 60 237,068 SAME 68~, K-55, BTC 485,792 SAME 47~, L-80, BTC 478,554 SAME MINIMUM STRENGTH TENSION 1000 LBS 1928 1594 1069 1086 DESIGN BY: COLLAPSE PRESS @ BOTTOM PSI C.L. LOHOEFER M.S.P. 280 psi 411 psi 683 psi COLLAPSE RESIST. BURST TENSION PRESSURE PS~ CDF ~! 860 3.75 350 TDF 16.61 229 6.72 653 960 1.47 950 2.20 1208 1950 1.61 1575 2.27 2002 4750 ~'~ 2.37 1575 ... MINIMUM YIELD ~si 1970, .. 2630 .. 3450' 6870 BDF 5.63 2.77 2.19 4.36 NOTES: See attached for calculation of M.S.P. including assumptions & estimates. Baker Platform Well #28 Pressure Calculations August 03, 1993 Depth Interval: 0 - 800' 17-1/2" / 28" hole size 24" casing Mud weight: ............................. 8.8 PPG = .46 psi/ft. Shoe (24") depth: .............................. 800'MD/800'TVD Estimated fracture gradient (24" shoe): .......... 0.85 psi/ft. Total depth: ................................. 2500'MD/2284 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' - 2500~ 17-1/2" / 24" hole size 18-5/8" casing Mud weight' 9 47 psi/ft ............................... 0 PPG = . . Shoe (18-5/8") depth: ....................... 2500'MD/2284'TVD Estimated fracture gradient (18-5/8" shoe): ...... 0.85 psi/ft. Total depth: ................................. 7200'MD/4224'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=(4224 ft * .45 psi/ft) - ((.75 (4224 ft * .47psi/ft.)) + (.25 (4224 ft * 0 psi/ft.))) MSP = 411 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 pressure at that casing depth HPsh = MSP +.HPcsg HPsh = 411 psi +(2284 ft HPsh = 1484 psi (MSP) plus the hydrostatic (HPcsg) . ~:~. .... ~_~,- ......... ~ ... ~ ~ * .47 psi/ft.) Baker Platform Well #28 This (HPsh = 1484 psi) is less than the fracture pressure at the same shoe (FPsh = .85 psi/ft * 2284 ft = 1941 psi) and thus sufficiently adequate to handle the well kick. Depth Interval: 2500' - 7200' 17-1/2" hole size 13-3/8" casing Maximum surface pressure calculation; Mud weight' 9 0 PPG = 47 psi/ft Shoe (13-3/8") depth: ....................... 7200'MD/4224'TVD Estimated fracture gradient (13-3/8" shoe): ...... 0.90 psi/ft. Total depth: ................................ 10238'MD/7000'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=(7000 ft * .45 psi/ft) - ((.75 (7000 ft * .47psi/ft.)) + (.25 (7000 ft * 0 psi/ft.))) MSP = 683 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). HPsh = MSP + HPcsg HPsh = 683 psi +(4224 ft * .47 psi/ft.) HPsh = 2668 psi HPsh - Pore Pressure at shoe < Yield 13-3/8" casing 2668 - (4224' * 0.45) < 3450 767 psi < 3450 psi This (HPsh = 2668 psi) is less than the fracture pressure at the same shoe (FPsh = .90 psi/ft * 4224 ft = 3802 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. 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) Nipple up combination 20-3/4" 3M BOPE / Diverter System. 2) Drill 17-1/2" hole to 2600', underream same to 24". 3) Run and cement 18-5/8" casing to 2600'. 4) Secure wellbore, skid rig to well #29. Well ~29 (18-5/8" Casing) 1) Nipple up combination 20-3/4" 3M BOPE / Diverter System. 2) Drill 17-1/2" hole to 2000' underream same to 24" 3) Run and cement 18-5/8" casing to 2000'. 4) Secure wellbore, skid rig to well #30. Well ~30 (18-5/8" Casing) 1) Nipple up combination 20-3/4" 3M BOPE / Diverter System. 2) Drill 17-1/2" hole to 2000' underream same to 24" 3) Run and cement 18-5/8" casing to 2000'. Alask~ Oil & ~a:~ '3~m~. t, ur~Jlnissio[~ Anchorage Baker Pre-Spud Drilling 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) 4) 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. Uno~.! North Ameri;~ Oil lind Gas Division Unoc~l Corpara~n P.O. Box 1 g0~47 Anc~rage, Ala~ 99579-0247 Telephone (90~ 27~7600 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 wells (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 2 0 199 Alaska Oil & Gas Cons. Commiss%Ot~ Anchorage ** CHECK LIST FOR NEW WELL PERMITS ** ITEM APPROVE DATE ( 1 ) Fee ~/¢~__ _~ (2) Loc /,~ ~2 thru ' - (3) Admin [10 & 13] [14 thru 22' ~ (4) Casg (.5) BOPE ..~'" /Z,,~::~ [23 thru 28] C6) Other ~~/~_¢~ [29 thru [32] (8) Addl ~ _. ~%~ geo 1 ogy' eng i nee r ing' DWJ MTN RAD]) RP ~C,~. B~ dDH~." TAB~ Company (,T, xx2oc.~ / 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 we'll to be deviated & is wellbore plat included ................... ~ 7. Is operator the only affected party .................................. /~ 8. Can permit be approved before 15-day wait ............................ ~ rev 6/93 jo/6.011 e 10. 11. 12. 13. 14. 15. Lease & Well NO REMARKS 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. Does operator have a bond in force ................................... Is a conservation order needed ....................................... '', '~ .... - · Is administrative approval needed .................................... Is lease ncrnber appropriate .......................................... Does well have a unique name & nLrnber ................................ Is conductor string provided ......................................... k.¢~- 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 ..................... k~ .... Will all casing give adequate safety in collapse, tension, and burst.,~Y4- 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 ~oo~,~ psig ..... ~.. Does choke manifold comply w/API RP-53 (May 84) ...................... Is presence of H2S gas probable ...................................... ' 29. 30. 31. 32. 33. FOR EXPLORATORY S 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 nLrnber of contact to supply weekly progress data ...... Additional requ i rements INITIAL GEOLUNITON/OFF POOLCLASS STATUS AREA SHORE .cz,-///¥ /_.o,;/ o/:/' UM __ MERIDIAN: SM )< WELL TYPE: Exp~_~;:X~ Inj Red r i 11 Rev o Iz ~o 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 2 is typ~: LfS **** FILE HEADER **** .001 1024 CN : UNOCAL WN : BAKER NO. 28 FN : MGS COUN : KENAI STAT : ALASKA LIS COMMENT RECORD (s) : m~m RUN 1 MAIN PASS OPEN HOLE DATA: DIFL/CDL/CN/BHC-AC/GR/CAL 2049 - 3553 RUN 2 MAIN PASS CASED HOLE DATA: CN/GR/CCL 5540 - 10492 THE INTERVAL 3553 - 5540 CONTAINS NULL VALUES. * FORMAT RECORD (TYPE# 64) RECEIV[D APR 2 0 Alaska Oil & Bas Cons. Commission Anchorage I ! -- ONE DEPTH PER FRAME Tape depth ID: F 22 Curves: 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Name Tool Code Samples Units AC AC 68 1 US/F ACQ AC 68 1 CAL AC 68 1 IN CHT AC 68 1 LB GR AC 68 1 GAPI RB AC 68 1 DEG SPD AC 68 1 F/MN TEN AC 68 1 LB TTEN AC 68 1 LB CCL 2435 68 1 CN 2435 68 1 PU-L CNC 2435 68 1 PU-S CNCF 2435 68 1 PU-S LSN 2435 68 1 CPS SSN 2435 68 1 CPS CORR CDL 68 1 G/C3 DEN ZDL 68 1 G/C3 RFOC DIFL 68 1 OHMM RILD DIFL 68 1 OHMM RILM DIFL 68 1 OHMM SP DIFL 68 1 MV VILD DIFL 68 1 MV API API API API Log Crv Crv Size Length Typ Typ Cls Mod 4 4 48 852 89 1 4 4 81 285 47 0 4 4 94 885 22 5 4 4 95 558 30 1 4 4 06 969 49 6 4 4 69 189 02 1 4 4 61 094 30 1 4 4 95 558 30 1 4 4 95 558 30 1 4 4 90 640 78 6 4 4 52 326 75 5 4 4 98 211 23 1 4 4 98 211 23 1 4 4 84 023 70 1 4 4 83 368 34 1 4 4 34 168 75 6 4 4 52 443 33 1 4 4 27 515 24 6 4 4 04 903 06 0 4 4 06 213 78 0 4 4 53 419 67 0 4 4 04 522 10 6 88 * DATA RECORD (TYPE# 0) 1018 BYTES * Total Data Records: 3073 Tape File Start Depth = 10495.000000 Tape File End Depth = 2045.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 777424 datums Tape Subfile: 2 3079 records... Minimum record length: Maximum record length: 62 bytes 1018 bytes Tape Subfile 3 is type: LIS **** FILE HEADER **** .001 1024 CN WN FN COUN STAT : UNOCAL : BAKER NO. 28 : MGS : KENAI : ALASKA LIS COMMENT RECORD (s) : RUN 1 REPEAT PASS OPEN HOLE DATA: DIFL/CDL/CN/BHC-AC/GR/CAL 2025 - 2409 RUN 2 REPEAT PASS CASED HOLE DATA: CN/GR/CCL 10187 - 10491 THE INTERVAL 2409 - 10187 CONTAINS NULL VALUES. * FORMAT RECORD (TYPE# 64) ONE DEPTH PER FRAME Tape depth ID: F 22 Curves: 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 Name Tool Code Samples Units AC AC 68 1 US/F ACQ AC 68 1 CAL AC 68 1 IN CHT AC 68 1 LB GR AC 68 1 GAPI RB AC 68 1 DEG SPD AC 68 1 F/MN TEN AC 68 1 LB TTEN AC 68 1 LB CCL 2435 68 1 CN 2435 68 1 PU-L CNC 2435 68 1 PU-S CNCF 2435 68 1 PU-S LSN 2435 68 1 CPS SSN 2435 68 1 CPS CORR CDL 68 1 G/C3 DEN ZDL 68 1 G/C3 RFOC DIFL 68 1 OHMM RILD DIFL 68 1 OHMM RILM DIFL 68 1 OHMM SP DIFL 68 1 MV VILD DIFL 68 1 MV API API API API Log Crv Crv Size Length Typ Typ Cls Mod 4 48 852 89 1 4 81 285 47 0 4 94 885 22 5 4 95 558 30 1 4 06 969 49 6 4 69 189 02 1 4 61 094 30 1 4 95 558 30 1 4 95 558 30 1 4 90 640 78 6 4 52 326 75 5 4 98 211 23 1 4 98 211 23 1 4 84 023 70 1 4 83 368 34 1 4 34 168 75 6 4 52 443 33 1 4 27 515 24 6 4 04 903 06 0 4 06 213 78 0 4 53 419 67 0 4 04 522 10 6 88 * DATA RECORD (TYPE# 0) 1018 BYTES * Total Data Records: 3081 Tape File Start Depth = 10495.000000 Tape File End Depth = 2025.000000 Tape File Level Spacing = 0.250000 Tape File Depth Units = Feet **** FILE TRAILER **** LIS representation code decoding summary: Rep Code: 68 779264 datums Tape Subfile: 3 3087 records... Minimum record length: 62 bytes Maximum record length: 1018 bytes Tape Subfile 4 is type: LIS **** TAPE TRAILER **** 94/ 3/28 01 **** REEL TRAILER **** 94/ 3/28 01 Tape Subfile: 4 2 records... Minimum record length: 132 bytes Maximum record length: 132 bytes End of execution: Mon 28 MAR 94 12:llp Elapsed execution time = 3 minutes, 32.1 seconds. SYSTEM RETURN CODE = 0