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215-106
Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Monday, July 3, 2017 8:51 AM To: 'Starck, Kai' Cc: Loepp, Victoria T (DOA); Bettis, Patricia K (DOA) Subject: Expired Permits to Drill: KRU 30-081-1-01 (PTD 215-105) and KRU 30-081-1-02 (PTD 215-106) Hello Kai, The following Permits to Drill, issued to ConocoPhillips Alaska, have expired under Regulation 20 AAC 25.005 W. The PTDs will be marked expired in the AOGCC database. • KRU 30-081-1-01, PTD 215-105, Issued 30 June 2015 • KRU 30-081-1-02, PTD 215-106, Issued 30 June 2015 If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. THE STATE GOVERNOR BILL WALKER D. Venhaus CTD Engineering Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Kuparuk River Field, Kuparuk River Oil Pool, KRU 30-08L1-02 ConocoPhillips Alaska, Inc. Permit No: 215-106 333 West Seventh Avenue Ancnorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claskc.gov Surface Location: 876' FNL, 1929' FWL, SEC. 22, T13N, R09E, UM Bottomhole Location: 2619' FNL, 227' FWL, SEC. 15, T13N, R9E, UM Dear Mr. Venhaus: Enclosed is the approved application for permit to re -drill the above referenced development well. The permit is for a new wellbore segment of existing well Permit No. 188-064, API No. 50-029- 21828-00-00. Production should continue to be reported as a function of the original API number stated above. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P. Foerster Chair DATED this:. U day of June, 2015. RECEIVED STATE OF ALASKA JUN 18 2015 ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL AOGCO 20 AAC 25.005 1a. Type of Work: 1 b. Proposed Well Class: Development - Oil ❑✓ Service - Winj ❑ Single Zone ❑✓ Drill ❑ , Lateral ✓ Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Redrill ❑ Reentry Exploratory ❑ Service - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: ConocoPhillips Alaska, Inc.,, 5. Bond: ✓ Blanket Single Well Bond No. 59-52-180 11. Well Name and Number: KRU 30-081_1-02 3. Address: P.O. Box 100360 Anchorage, AK 99510-0360 6. Proposed Depth: MD: 9670' , TVD: 6634' 12. Field/Pool(s): Kuparuk River Field Kuparuk River Oil Pool 4a. Location of Well (Governmental Section): Surface: 876' FNL, 1929' FWL, Sec. 22, T13N, R09E, UM Top of Productive Horizon: 1747' FSL, 1475' FWL, Sec. 15, T13N, R9E, UM Total Depth: 2619' FNL, 227' FWL, Sec. 15, T13N, R9E, UM • 7. Property Designation (Lease Number): ADL 25513 . 8. Land Use Permit: 2554 13. Approximate Spud Date: 8/1/2015 9. Acres in Property: 2560 14. Distance to Nearest Property: 4472 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x- 525566 y- 6021944 Zone- 4, 10. KB Elevation above MSL: , 58 feet GL Elevation above MSL: . 33 feet 15. Distance to Nearest Well Open to Same Pool: 30-01 , 1872 16. Deviated wells: Kickoff depth: 8900 ft. Maximum Hole Angle: 91 ° deg 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4822 psig . Surface: 4153 psig - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks (including stage data) Hole Casing Weight Grade Coupling Length MD TVD MD TVD 3" 2.375" 4.7# L-80 ST-L 1570' 8100, 6636' 9670' 6634' slotted liner 19 PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 7770' Total Depth TVD (ft): 6934' Plugs (measured) none Effective Depth MD (ft): 1 7663' Effective Depth TVD (ft): 6849' Junk (measured) 7583' Casing Length Size Cement Volume MD TVD Conductor/Structural 75' 16" 164 sx AS II 110, 110, Surface 2584' 10.75 1300 sx AS III, 225 sx AS II, 2619 2619' Production 7713' 7" 400 sx TLW, 200 sx Cl G, 7746' 6915' 225 sx AS I Perforation Depth MD (ft): 7416-7432, 7439-7462, 7476-7496 Perforation Depth TVD (ft): 6656-6668, 6673-6692, 6703-6719 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Prograrr ❑✓ Time v. Depth Plot ❑ Shallow Hazard Analysis ❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑ 20 AAC 25.050 requirements ❑✓ 21. Verbal Approval: Commission Representative: Date: 22. 1 hereby certify that the foregoing is true and correct. Contact Cody Pohler @ 265-6435 Email Codv.J.Pohleracop.com Printed Name D. Venh us Title CTD Engineering Supervisor CJ7 Gr/7//j- Signature Phone: 263-4372 Date — �7 Commission Use Only Permit to Drill Number: / _� — / rU p API Number: 5 0 - Q� - - �`j Permit Approval Date: ' See cover letter for other requirements Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed m thane, gas hydrates, or gas contained in shales: Other: 30P rf5tp rf55 vrC to 5-v �5, Samples req'd: Yes El No ❑ Mud log req'd: Yes❑ No yC� i4vvr� vl a r f—t ✓L h fC'✓ tl5 t�G v 2 S� 142S measures: Yes f�S [✓j No � Directional svy req'd: Yes [� No ❑ Spacing exception req'd: Yes ❑ No Inclination -only svy req'd: Yes ❑ No �� APPROVED BY THE >,•, Approved by: /-ice✓ COMMISSIONER COMMISSION Date: % X ' S Form 10-401 (Rgwised 10/2012) This permit is valid for 24 months fro a q(2 Croos,g 11 V 7-` 6,z51�� `G R I (iA ConocoP lips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 June 5, 2015 Commissioner - State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Avenue Suite 100 Anchorage, Alaska 99501 Dear Commissioner: RECEIVED JUN 18 2015 ConocoPhillips Alaska, Inc. hereby submits an application for permits to drill a penta-lateral out of the Kuparuk Well 30-08 using the coiled tubing drilling rig, Nabors CDR2-AC. The work is scheduled to begin August 2015. The CTD objective will be to drill five laterals (30-08L1, 30-08L1- 01, 30-08L1-02, 30-081_1-03, 30-081_1-04), targeting the A sand intervals. Note the current A sand perforations are still open below the whipstock. Attached to this application are the following documents: — Permit to Drill Application Form 10-401 for 30-08L1, 30-081_1-01, 30-081_1-02, 30-081_1-03, 30-08L1- 04 — Detailed Summary of Operations — Directional Plans — Proposed Schematic If you have any questions or require additional information please contact me at 907-265-6435. Sincerely, Cody Pohler Coiled Tubing Drilling Engineer upajr^�jj��lq GTD �J ator�j�s NABORS cr*%ASKA tl U 3 ®O8L1, 30-08L1 ®01, 30®08L1 ®02, 30-0®L1-03 IJ 30-OOOL1-04 &C Application for Permit to Drill Document 1. Well Name and Classification......................................................................................................... 2 (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)).................................................................................................................. 2 2. Location Summary.......................................................................................................................... 2 (Requirements of 20 AAC 25.005(c)(2))................................................................................................................................................. 2 3. Blowout Prevention Equipment Information................................................................................. 2 (Requirements of 20 AA 25.005 (c)(3))....................................... ........ .......................... .................................. --................... ............. 2 4. Drilling Hazards Information and Reservoir Pressure.................................................................. 2 (Requirements of 20 AA 25.005 c 4 .......................... 2 5. Procedure for Conducting Formation Integrity tests.................................................................... 2 (Requirements of 20 AA 25.005(c) (5))............ ............................................... .................................................................... —............... 2 6. Casing and Cementing Program....................................................................................................2 (Requirements of 20 AA 25.005(c)(6))............................................................................................................................--................. 2 7. Diverter System Information.......................................................................................................... 3 (Requirements of 20 AA 25.005(c)(7))................................................................................................................................................. 3 8. Drilling Fluids Program .......................... (Requirements of 20 AA 25.005(c) (8))................................................................................................................................................. 3 9. Abnormally Pressured Formation Information............................................................................. 4 (Requirements of 20 AA 25.005(c) (9))..........................................................................................................................................I...... 4 10. Seismic Analysis............................................................................................................................. 4 (Requirements of 20 AA C 25.005(c) (10))............................................................................................................................................... 4 11. Seabed Condition Analysis............................................................................................................ 4 (Requirements of 20 AA 25.005(c)(11))............................................................................................................................................... 4 12. Evidence of Bonding...................................................................................................................... 4 (Requirements of 20 AA 25.005(c)(12))............................................................................................................................................... 4 13. Proposed Drilling Program.............................................................................................................5 (Requirements of 20 AA 25.005(c)(13))............................................................................................................................................... 5 Summaryof Operations................................................................................................................................................... 5 PressureDeployment of BHA.......................................................................................................................................... 6 LinerRunning.................................................................................................................................................................. 6 14. Disposal of Drilling Mud and Cuttings........................................................................................... 6 (Requirements of 20 AAC 25.005(c)(14))............................................................................................................................................... 6 15. Directional Plans for Intentionally Deviated Wells........................................................................ 7 (Requirements of 20 AA 25.050(b))..................................................................................................................................................... 7 16. Attachments.................................................................................................................................... 7 Attachment 1: Directional Plans for 30-081-1, 1-1-01, 1-1-02, L1-03, L1-04..................................................................... 7 Attachment 2: Current Well Schematic for 30-08........................................................................................................... 7 Attachment 3: Proposed Well Schematic for 30-081-1, L1-01, 1-1-02, 1-1-03, L1-04....................................................... 7 Page 1 of 7 6/17/2015 PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 1. Well Name and Classification (Requirements of 20 AAC 25.005(f) and 20 AAC 25.005(b)) The proposed laterals described in this document are 30-081-1, 30-081-1-01, 30-081-1-02, 30-08L1-03 & 30- 081-1-04. All laterals will be classified as "Development — Oil " wells. 2. Location Summary (Requirements of 20 AAC 25.005(c)(2)) These laterals will target the A sand package in the Kuparuk reservoir. See attached 10-401 form for surface and subsurface coordinates of the 30-08L1, 30-08L1-01, 30-081-1-02, 30-081-1-03 & 30-081-1-04. 3. Blowout Prevention Equipment Information (Requirements of 20 AAC 25.005 (c)(3)) Please reference blowout prevention (BOP) schematics on file with the Commission for Nabors CDR2-AC. BOP equipment is as required per 20 AAC 25.036, for thru-tubing drilling operations. — Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 4500 psi. Using the maximum formation pressure in the area of 4822 psi in 30-05, the maximum potential surface pressure, assuming a gas gradient of 0.1 psi/ft, would be 4153 psi.,'See the "Drilling Hazards Information and Reservoir Pressure" section for more details. — The annular preventer will be tested to 250 psi and 2500 psi. 4. Drilling Hazards Information and Reservoir Pressure (Requirements of 20 AAC 25.005 (c)(4)) Reservoir Pressure and Maximum Downhole Pressure (Requirements of 20 AAC 25.005 (c)(4)(a)) The equivalent mud weight as of May 31, 2015 in 30-08 was 10.4 ppg. An updated pressure survey will be obtained on the Kuparuk A -sand only before Coiled Tubing Drilling operations begin. The maximum downhole pressure in the 30-08 pattern is to the north with the 30-05 injector at 4822 psi (13.9 ppg EMW) dating May 2015. Well 30-05 has a high throughput with pressure expected to drop to a target of 12.5 ppg. Our pressure management plan called to shut-in the well within 6 months prior to the spud of 30-08; it is currently offline. As the laterals are drilled we approach 30-01. Well 30-01 has a pressure of 3679 (10.6 ppg EMW) and is planned for CTD sidetrack additionally. Potential Gas Zones (Requirements of 20 AAC 25.005 (c)(4)(b)) Well 30-07 to the east injected lean gas (2014) and well 30-05 to the north injected MI (2013) however all planned laterals are to the northwest; no specific gas zones are expected to be drilled. Potential Causes of Hole Problems (Requirements of 20 AAC 25.005 (c)(4)(c)) The largest, expected risk of hole problems in the 30-08 laterals will be shale instability across the faults, managed pressure drilling (MPD) will be used to reduce the risk of shale instability associated with fault crossing. Along with shale instability as mentioned above the higher pressure risk will also be taken into consideration for potential hole problems. Again MPD will be used to mitigate the high pressure risk. 5. Procedure for Conducting Formation Integrity tests (Requirements of 20 AAC 25.005(c)(5)) N/A for this thru-tubing drilling operation. According to 20 AAC 25.030(f), thru-tubing drilling operations need not perform additional formation integrity tests. 6. Casing and Cementing Program (Requirements of 20 AAC 25.005(c)(6)) Page 2 of 7 6/17/2015 PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 New Completion Details Lateral Liner Top Liner Btm Liner Top Liner Btm Liner Details Name MD MD TVDSS TVDSS 30-08L1 9,750' 11,000, 6,598' 6,641' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-08L1-01 8,900' 11,050' 6,598' 6,608' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-081_1-02 8,100' 9,670' 6,636' 6,634' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on top 30-08L1-03 7,750' 11,000, 6,651' 6,584' 2%", 4.7#, L-80, ST-L slotted liner; aluminum billet on to 30-08L1-04 7,410' 9,170' 6,592' 6,555' 2%" 4.7#, L-80, ST-L slotted liner; deployment sleeve on top Existing Casing/Liner Information Category OD Weight (ppf) Grade Connection Top MD Btm MD Top TVD Btm TVD Burst psi Collapse psi Conductor 16" 62.5 H-40 Welded 36' 110, 31' 110' 1,640 630 Surface 10-3/4" 45.5 J-55 BTC 35' 2,619' 35' 2,618' 3,520 2,020 Production 7" 26.0 J-55 BTC 33' 7,746' 33' 6,915' 4,980 4330 Tubing* 3-1/2" 9.3 L-80 EUE 33' 7,349' 33' 6,603' 10,160 10,530 Tubing Tail* 1 5-1/2" 14 H-40 I STC 7351' 7,435' 6,604' 6,670' 1 3,110 2,610 *Rig workover proposed depths 7. Diverter System Information (Requirements of 20 AAC 25.005(c)(7)) N/A for this thru-tubing drilling operation. Nabors CDR2-AC will be operating under 20 AAC 25.036, for thru-tubing drilling operations. Therefore, a diverter system is not required. 8. Drilling Fluids Program (Requirements of 20 AAC 25.005(c)(8)) Diagram of Drilling System Diagram of Nabors CDR2-AC mud system is on file with the Commission. Description of Drilling Fluid System - Window milling operations: Chloride -based FloVis mud (9.8 ppg) - Drilling operations: Chloride -based FloVis mud (9.8 ppg)." While this mud weight may not hydrostatically overbalance the reservoir pressure, overbalanced conditions will be maintained using MPD practices described below. - Completion operations: Well 30-08 contains a sub -surface safety valve allowing deployment of tool strings and liner without pumping kill weight fluid. If the valve does not hold, BHA's will be deployed using standard pressure deployments and the well will be loaded with 12.0 ppg NaBr completion fluid in order to provide formation over -balance while running completions. Emergency Kill Weight fluid: Two well bore volumes (-195 bbl) of 13.0 ppg Formate emergency kill weight fluid will be within a short drive to the rig during drilling operations. Page 3 of 7 6/17/2015 PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 Managed Pressure Drilling Practice Managed pressure drilling (MPD) techniques will be employed to maintain a constant overbalanced pressure on the openhole formation throughout the coiled tubing drilling (CTD) process. Maintaining a constant BHP promotes wellbore stability, particularly in shale sections, while at the same time providing an overbalance on the reservoir. Through experience with drilling CTD laterals in the Kuparuk sands, 11.8 ppg has been identified as the minimum EMW to ensure stability of shale sections. Since this well is kicking out into the A3 sand turning northwest in Al pay, we plan to hold 11.8 ppg at the window for stability. The constant BHP target will be adjusted to maintain overbalanced conditions if increased reservoir pressure is encountered during drilling. The constant BHP target will be maintained utilizing the surface choke. Any change of circulating friction pressure due to change in pump rates or change in depth of circulation will be offset with back pressure adjustments. Pressure at the 30-08 Window (7,415' MD, 6,650' TVD) Using MPD Pumps On (1.5 bpm) Pumps Off A -sand Formation Pressure (10 ppg) 3473 psi 3473 psi Mud Hydrostatic (9.4 ppg) 3251 psi 3251 psi Annular friction (i.e. ECD, 0.090 psi/ft) 667 psi 0 psi Mud + ECD Combined 3918 psi 3251 psi (no choke pressure) (overbalanced (underbalanced —445 psi) —222 psi) Target BHP at Window (11.8 ppg) 4083 psi 4083 psi Choke Pressure Required to Maintain 165 psi 832 psi Target BHP 9. Abnormally Pressured Formation Information (Requirements of 20 AAC 25.005(c)(9)) N/A - Application is not for an exploratory or stratigraphic test well. 10. Seismic Analysis (Requirements of 20 AAC 25.005(c)(10)) N/A - Application is not for an exploratory or stratigraphic test well. 11. Seabed Condition Analysis (Requirements of 20 AAC 25.005(c)(11)) N/A - Application is not for an exploratory or stratigraphic test well. 12. Evidence of Bonding (Requirements of 20 AAC 25.005(c)(12)) Evidence of bonding for ConocoPhillips Alaska, Inc. is on file with the Commission. Page 4 of 7 6/17/2015 PTD Application: 30-08L1, L1-01, L1-02, L1-03, L1-04 13. Proposed Drilling Program (Requirements of 20 AAC 25.005(c)(13)) Summary of Operations Background Well 30-08 is a Kuparuk A -sand injection well equipped with 3'h" tubing and 7" production casing. The rig work -over this June will replace the existing tubing and packers with new 3-1/2" tubing with a 5-1/2" "Big Tail Pipe" completion. Five laterals will be drilled to the north west of the parent well with the laterals targeting the different A sand lobes. These laterals will access reserves in the adjacent fault blocks targeting the A3, A2, and A 1 sands. A mechanical whip -stock will be set inside the 5 '/2" big tail pipe at the planned kick off point of 7,415' MD. The 30-08L1 lateral will exit through the big tail pipe at 7,415'MD and TD at 11,000' MD. L1 lateral will be completed with 2 3/8" slotted liner from TD up to 9,750' MD with an aluminum billet for kicking off the 30-08L1-01 lateral. The 30-08L1-01 will drill to a TD of 11,050' MD, with the liner top at 8,900' MD. The 30-08L1-02 will drill to a TD of 9,670' MD, with the liner top at 8,100' MD. The 30- 08L1-03 will drill to a TD of 11,000' MD, with the liner top at 7,750' MD. The 30-08L1-04 will drill to a TD of 9,170' MD, with the liner top at 7,410 MD; just above the whipstock. Pre-CTD Work 1. RU Slickline: Pull sheared SOV, dummy all gas lift valves, obtain a KRU A -sand SBHP, and conduct a dummy whipstock drift. 2. RU E-line: Set Baker Hughes 3-1/2" x 5-1/2" Thru-Tubing Whipstock. 3. Prep site for Nabors CDR2-AC, including setting BPV. Rig Work 1. MIRU Nabors CDR2-AC rig using 2" coil tubing. NU 7-1/16" BOPE, test. 2. 30-08L1 Lateral (Al sand to north west) a. Mill 2.80" window at 7,415' MD. b. Drill 3" bi-center lateral to TD of 11,000' MD. c. Run 2%" slotted liner with an aluminum billet from TD up to 9,750' MD. 3. 30-08L1-01 Lateral (A2 sand) a. Kickoff of the aluminum billet at 9,750' MD. b. Drill 3" bi-center lateral to TD of 11,050' MD. c. Run 2%" slotted liner from TD up to 8,900' MD 4. 30-08L1-02 Lateral (Al sand) a. Kick off of the aluminum billet at 8,900' MD. b. Drill 3" bi-center lateral to TD of 9,670' MD. c. Run 2%" slotted liner from TD up to 8,100' MD 5. 30-08L1-03 Lateral (A2 sand) a. Kickoff of the aluminum billet at 8,100' MD. b. Drill 3" bi-center lateral to TD of 11,000' MD. c. Run 21/8" slotted liner from TD up to 7,750' MD 6. 30-08L1-04 Lateral (A3 sand) a. Kick off of the aluminum billet at 7,750' MD. b. Drill 3" bi-center lateral to TD of 9,170' MD. c. Run 2%" slotted liner from TD up to 7,410' MD, above the whipstock. Page 5 of 7 6/17/2015 PTD Application: 30-081-1, L1-01, L1-02, L1-03, L1-04 7. Freeze protect. Set BPV, ND BOPE. RDMO Nabors CRD2-AC. Post -Rig Work 1. Pull BPV. 2. Install GLV's. Pressure Deployment of BHA The planned bottom hole assemblies (BHAs) are too long to simply isolate by closing the double swab valves on the Christmas tree. MPD operations require the BHA to be lubricated under pressure, so installed in this well is a sub -surface safety valve. This valve, when closed using hydraulic control lines from surface, isolates the well pressure and allows long BHA's to be deployed/un-deployed without killing the well. If the sub -surface safety valve fails, operations will continue using the standard pressure deployment process. A system of double swab valves on the Christmas tree, double deployment rams, double check valves and double ball valves in the BHA, and a slick -line lubricator can be used. This pressure control equipment listed ensures there are always two barriers to reservoir pressure, both internal and external to the BHA, during the deployment process. During BHA deployment, the following steps are observed. — Initially the double swab valves on the tree are closed to isolate reservoir pressure. The lubricator is installed on the BOP riser with the BHA inside the lubricator. — Pressure is applied to the lubricator to equalize across the swab valves. The swab valves are opened and the BHA is lowered in place via slickline. — When the BHA is spaced out properly, the double deployment rams are closed on the BHA to isolate reservoir pressure via the annulus. A closed set of double ball valves and double check valves isolate reservoir pressure internal to the BHA. Slips on the double deployment rams prevent the BHA from moving when differential pressure is applied. The lubricator is removed once pressure is bled off above the deployment rams. — The coiled tubing is made up to the BHA with the double ball valves plus the double check valves in the closed position. Pressure is applied to the coiled tubing to equalize internal pressure and then the double ball valves are opened. The injector head is made up to the riser, annular pressure is equalized, and the deployment rams are opened. The BHA and coiled tubing are now ready to run in the hole. During BHA undeployment, the steps listed above are observed, only in reverse. Liner Running — The 30-08 well has a sub -surface safety valve installed. It will serve to deploy liners into the newly drilled laterals. If the valve fails the laterals will be displaced to an overbalancing fluid (12 ppg NaBr) prior to running liner. See "Drilling Fluids" section for more details. — While running 23/" slotted liner, a joint of 2%" non -slotted tubing will be standing by for emergency deployment. A floor valve is made up onto this joint ahead of time, and the rig crew conducts a deployment drill with this emergency joint on every slotted liner run. The 2%" rams will provide secondary well control while running 2%" liner. 14. Disposal of Drilling Mud and Cuttings (Requirements of 20 AAC 25.005(c)(14)) • No annular injection on this well. ® All solid waste will be transported to the grind and inject facility at DS-4 Prudhoe Bay for disposal. ® Incidental fluids generated from drilling operations will be injected in a Kuparuk Class II disposal well (1 R-18 or 1 B disposal facilities) or Prudhoe DS-4 if a Kuparuk facility is unavailable. ® All wastes and waste fluids hauled from the pad must be properly documented and manifested. ® Contact Kuparuk Environmental Coordinator for questions regarding waste classification. (670-4200). Page 6 of 7 6/17/2015 PTD application: 30-08L1, L1-01, L1-02, L1-03, L1-04 15. Directional Plans for Intentionally Deviated Wells (Requirements of 20 AAC 25.050(b)) — The Applicant is the only affected owner. — Please see Attachment 1: Directional Plan — Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. — MWD directional, resistivity, and gamma ray will be run over the entire openhole section. — Distance to Nearest Property Line (measured to KPA boundary at closest point) Lateral Name Distance 30-0811-1 3382' 30-08L1-01 5730' 30-08L1-02 4472' 30-08L1-03 3805' 30-08L1-04 3506' — Distance to Nearest Well within Pool Lateral Name Distance Well 30-08L1 921' 30-01 30-08L1-01 752' 30-01 30-08L1-02 1872' 30-01 30-08L1-03 792' 30-01 30-08L1-04 3506' 30-05 16. attachments Attachment 1: Directional Plans for 30-08L1, L1-01, L1-02, L1-03, L1-04 Attachment 2: Current Well Schematic for 30-08 Attachment 3: Proposed Well Schematic for30-08L1, L1-01, 0-02, L1-03, L1-04 Page 7 of 7 6/17/2015 i O O O N a3 Cn U) U U) X U E cc U ca E O V U) I-- u O w O i2 O d 00 O M a) U O O 9 F- _0 M W D LU O O J Cl? N Cl) p O O O N a) a3 L a7 pw LO I— LO a) N � N C C cA c0 CU a7 N E O O)) U N E m ca Y �I N O Z N a) C 9 m U -o p Q) � C M a) O U r C 2 3 � \p in w O M N p II M O w C 0 J N ns m co) p n 7 co fO C I - a)So CO �rn y J c6 cu cL d oU� (U o a) N = — f9 O O _ _ _O N C "ry Co Co O N a) I — CD N N 2 V' � II -0 Q C LO CN N a7 h 7 a� m d a) LL N�2 Y O m CO _ a3 N N V) v C O p m 7 CO ol N CO U 2 a) d O CL N O-F- C m x m N N M c0 p p � o o ,n `i o o _ n u p p ~ c:o 0 �mca, oo�n O J 00f9 O N OM �_ O o _ N m no N m LO Nr y C C O Cc) 3� N M iO LO a) v r N rn o m Q) NN1 a) r N O Q V 9 O N C c� O O O a a) O U,rL ca O rC n U) 'n o N r LOn0� N �NNCO 41) O. V VO C23 (O CO c0 `?dv� p O r O W I I 0 � C - oO -oo a) C) J O 00 N N OCM N m ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 30 Pad 30-08 30-08L1-02 Plan: 30-081-1-02_wp02 Standard Planning Report 01 April, 2015 ConocoPhillips Database: EDM Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well; 30-08 Wel (bore: 30-08 L 1-02 Design: 30-0 8 L 1-02_wp02 Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-08 Mean Sea Level 30-08 @ 58.00usft (30-08) True Minimum Curvature Project Kuparuk River Unit, North Slope Alaska, United States Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor NkII BAKER HUGHES Site Kuparuk 30 Pad Site Position: Northing: 6,022,094.67 usft Latitude: 70° 28' 17.333 N From: Map Easting: 525,478.25 usft Longitude: 149° 47' 30.897 W Position Uncertainty: 0.00 usft Slot Radius: - 0.000in Grid Convergence:- 0.20 ° Well 30-08 Well Position +N/-S 0.00 usft Northing: 6,021,943.75 usft Latitude: 70° 28' 15.845 N +E/-W 0.00 usft Easting: 525,566.00 usft Longitude: 149° 47' 28.332 W Position Uncertainty 0.00 usft Wellhead Elevation: usft Ground Level: 0.00 usft Wellbore 30-08L1-02 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2014 7/1/2015 18.78 81.01 57,569 Design 30-08L1-02_wp02 Audit Notes: Version: Phase: PLAN Tie On Depth: 8,900.00 Vertical Section: Depth From (TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 0.00 0.00 0.00 315.00 Plan Sections Measured TVD Below Dogleg Build Turn Depth Inclination Azimuth System +N/-S +E/-W Rate Rate Rate TFO (usft) (°) (I (usft) (usft) (usft) (°/100ft) (°/100ft) (°/100ft) (°) Target 8,900.00 91.35 298.87 6,598.10 3,056.39 -1,128.50 0.00 0.00 0.00 0.00 9,050.00 80.85 298.87 6,608.29 3,128.55 -1,259.36 7.00 -7.00 0.00 -180.00 9,180.00 89.95 298.87 6,618.71 3,191.06 -1,372.72 7.00 7.00 0.00 0.00 9,280.00 88.02 305.60 6,620.48 3,244.36 -1,457.23 7.00 -1.93 6.73 106.00 9,480.00 88.02 319.61 6,627.40 3,379.34 -1,603.98 7.00 0.00 7.00 90.00 9,670.00 88.02 332.92 6,633.96 3,536.90 -1,709.19 7.00 0.00 7.00 90.00 41112015 10:05:38AM Page 2 COMPASS 5000.1 Build 61 ConocoPhillips Planning Report BAKER HUGHES Database: EDM Alaska Sandbox Local Co-ordinate Reference: Well 30-08 Company: ConocoPhillips (Alaska) Inc. -Kup2 TVD Reference: Mean Sea Level Project: Kuparuk River Unit MD Reference: 30-08 @ 58.00usft (30-08) Site: Kuparuk 30 Pad North Reference: True Well: 30-08 Survey Calculation Method: Minimum Curvature Wellbore: 30-081-1-02 Design: 30-08 L1-02_wp02 Planned Survey Measured TVD Below Vertical Dogleg Toolface Map Map Depth Inclination Azimuth System +N/-S +E/-W Section Rate Azimuth Northing Easting (usft) V) (o) (usft) (usft) (usft) (usft) (°/100ft) (°} (usft) (usft) 8,900.00 91.35 298.87 6,598.10 3,056.39 -1,128.50 2,959.16 0.00 0.00 6,024,995.94 524,427.13 TIP/KOP 9,000.00 84.35 298.87 6,601.85 3,104.61 -1,215.95 3,055.10 7.00 -180.00 6,025,043.86 524,339.52 9,050.00 80.85 298.87 6,608.29 3,128.55 -1,259.36 3,102.72 7.00 -180.00 6,025,067.65 524,296.03 Start 7 dls 9,100.00 84.35 298.87 6,614.73 3,152.49 -1,302.78 3,150.35 7.00 0.00 6,025,091.43 524,252.54 9,180.00 89.95 298.87 6,618.71 3,191.06 -1,372.72 3,227.07 7.00 0.00 6,025,129.76 524,182.47 3 9,200.00 89.56 300.22 6,618.79 3,200.92 -1,390.11 3,246.35 7.00 106.00 6,025,139.56 524,165.04 9,280.00 88.02 305.60 6,620.48 3,244.36 -1,457.23 3,324.53 7.00 106.04 6,025,182.76 524,097.78 4 9,300.00 88.02 307.00 6,621.17 3,256.19 -1,473.34 3,344.29 7.00 90.02 6,025,194.54 524,081.63 9,400.00 88.02 314.01 6,624.63 3,321.07 -1,549.28 3,443.86 7.00 90.12 6,025,259.15 524,005.48 9,480.00 88.02 319.61 6,627.40 3,379.34 -1,603.98 3,523.74 7.00 90.10 6,025,317.22 523,950.58 6 9,500.00 88.02 321.01 6,628.09 3,394.72 -1,616.74 3,543.64 7.00 90.02 6,025.332.56 523,937.77 9,600.00 88.02 328.02 6,631.55 3,476.04 -1,674.72 3,642.14 7.00 90.12 6,025.413.68 523,879.52 9,670.00 88.02 332.92 6,633.96 3,536.90 -1,709.19 3,709.55 7.00 90.08 6,025,474.40 523,844.84 Planned TD at 9670.00 0 41112015 10:05:38AM Page 3 COMPASS 5000.1 Build 61 ConocoPhillips Database: EDM Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-08 Wel (bore: 30-08L1-02 Design: 30-08 L 1-02_wp02 Targets Target Name Planning Report Local Co-ordinate Reference TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-08 Mean Sea Level 30-08 @ 58.00usft (30-08) True Minimum Curvature WERI BAKER HUGHES hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting Shape 0 V) (usft) (usft) (usft) (usft) (usft) Latitude Longitude 30-081-1-02_T01 0.00 0.00 6,610.00-1,030.031,138,869.22 6,024,825.00 1,664,319.00 70' 13' 55.132 N 140' 34' 6.859 W plan misses target center by 1140005.04usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Point 30-081-1-02_T02 0.00 0.00 6,619.00-973.671,138,766.40 6,024,881.00 1,664,216.00 70° 13' 55.832 N 140' 34' 9.561 W plan misses target center by 1139902.02usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Point 30-081-1_Fault4 0.00 0.00 0.00 -615.481,138,428.60 6,025,238.00 1,663,877.00 70' 13' 59.810 N 140' 34' 17.680 W plan misses target center by 1139582.11 usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Rectangle (sides W365.00 H1.00 D0.00) 30-081-1_Fault3 0.00 0.00 0.00 -955.71 1,138,776.47 6,024,899.00 1,664,226.00 70' 13' 55.991 N 140' 34' 9.193 W plan misses target center by 1139931.12usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Rectangle (sides W370.00 H1.00 D0.00) 30-08L1_Fault5 0.00 0.00 0.00 -295.81 1,137,953.65 6,025,556.00 1,663,401.00 70' 14' 3.617 N 140' 34' 29.902 W plan misses target center by 1139106.18usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Rectangle (sides W375.00 H1.00 D0.00) 30-08 CTD Polygon 0.00 0.00 0.00 -2,183.521,140,139.39 6.023,676.00 1,665,593.00 70' 13' 42.050 N 140' 33' 35.492 W - plan misses target center by 1141298.99usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) - Polygon Point 1 0.00 0.00 0.00 6,023.676.00 1,665,593.00 Point 0.00 374.09 279.29 6,024,051.01 1,665,870.98 Point 0.00 1,267.73-1,064.82 6,024,939.94 1,664,523.94 Point 0.00 2,062.29-2,090.24 6,025,730.89 1,663,495.90 Point 0.00 2,634.88-2,838.39 6,026,300.86 1,662,745.86 Point 0.00 2,301.27-2,964.53 6,025,966.85 1,662,620.88 Point 0.00 1,758.01-2,313.30 6,025,425.88 1,663,273.91 Point 8 0.00 1,381.24-1,800.52 6,025,050.91 1,663,787.93 Point 9 0.00 1,116.13-1,482.38 6,024,786.92 1,664,106.94 Point 10 0.00 753.26-941.55 6,024,425.95 1,664,648.96 Point 11 0.00 557.21-636.18 6,024,230.97 1,664,954.97 Point 12 0.00 292.20-346.05 6,023,966.98 1,665,245.98 Point 13 0.00 0.00 0.00 6,023,676.00 1,665,593.00 30-081-1-02_T03 0.00 0.00 6,634.00 -626.471,138,427.56 6,025,227.00 1,663,876.00 70' 13' 59.705 N 140° 34' 17.757 W plan misses target center by 1139562.01 usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Point 30-081-1_Faultl 0.00 0.00 0.00 -1,516.731,139,640.63 6,024,341.00 1,665,092.00 70° 13' 49.263 N 140° 33' 46.870 W - plan misses target center by 1140797.37usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) - Rectangle (sides W363.00 H1.00 D0.00) 30-08L1_Fault2 0.00 0.00 0.00 -1,247.251,139,217.51 6,024,609.00 1,664,668.00 70° 13' 52.507 N 140° 33' 57.822 W plan misses target center by 1140373.22usft at 8900.00usft MD (6598.10 TVD, 3056.39 N,-1128.50 E) Rectangle (sides W360.00 H1.00 D0.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (in) (in) 9,670.00 6,633.96 2 3/8" 2.375 3.000 41112015 10:05:38AM Page 4 COMPASS 5000.1 Build 61 ConocoPhillips Database: EDM Alaska Sandbox Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Site: Kuparuk 30 Pad Well: 30-08 Wellbore: 30-08L1-02 Design: 30-081-1-02_wp02 Planning Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well 30-08 Mean Sea Level 30-08 @ 58.00usft (30-08) True Minimum Curvature rf.s BAKER HUGHES Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 8,900.00 6,598.10 3,056.39 -1,128.50 TIP/KOP 9.050.00 6,608.29 3,128.55 -1,259.36 Start 7 dls 9,180.00 6,618.71 3,191.06 -1,372.72 3 9,280.00 6,620.48 3,244.36 -1,457.23 4 9,480.00 6,627.40 3,379.34 -1,603.98 5 9,670.00 6,633.96 3,536.90 -1,709.19 Planned TD at 9670.00 41112015 10.05:38AM Page 5 COMPASS 5000.1 Build 61 4 5 9 E V) a 0 u O c V NCL 'EhM � 0 0 r_ rn Co N BOA C _ 19 m ¢HUJM�u'Jd U O N n M V �fJ Q) Z (lJON�CN �� O N N N O p � l f 7 O � N M N co Cl) M Cl) C J �00 d 0 0 0 0 0 0 07 O N J U p 00000 p 0 O LL �—0 m M m N o ono 0 0 0 0 0 mooppoo O c D N M N 0 Oi N Io cC 0) Lo f— Lo O O C O N M V (Oco 1� J cD Lo LU Lo (n Q N M l Q O M M� F � Z } toN On: m: m ) LU OM M M 04 cMo CMJ J J L.LI cD u) DN W O CO (� N I� V; 'IscI L() C r � V > �tOO CO GNO (ND CMO H O co OOOO O O N W W N t 0 (p O J O co <N W W O V O) m O O M N N N M M M U cq t A a A C V N N C M W 0 0 0 0 c m W W W W O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O) O N V O Cn O) O J co O O U N M N C O Z O + U) (ui/lisn 001) gjdaQ juoivan arul ConocoPhillips ConocoPhillips (Alaska) Inc. -Kup2 Kuparuk River Unit Kuparuk 30 Pad 30-08 30-08L1-02 30-08L1-02_wp02 Travelling Cylinder Report 12 June, 2015 Baker Hughes INTEQ as ConocoPhillips Travelling Cylinder Report BAKER HUGHES Company: ConocoPhillips (Alaska) Inc. -Kup2 Project: Kuparuk River Unit Reference Site: Kuparuk 30 Pad Site Error: 0.00usft Reference Well: 30-08 Well Error: 0.00usft Reference Wellbore 30-08L1-02 Reference Design: 30-08L1-02_wp02 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Output errors are at Database: Offset ND Reference: Well 30-08 30-08 @ 58.00usft (30-08) 30-08 @ 58.00usft (30-08) True Minimum Curvature 1.00 sigma OAKEDMP2 Offset Datum Reference 30-08L1-02_wp02 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 8,900.00 to 9,670.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 1,161.20usft Error Surface: Elliptical Conic Survey Tool Program Date 6/12/2015 From To (usft) (usft) Survey (Wellbore) Tool Name Description 100.00 7,400.00 30-08 (30-08) BOSS -GYRO Sperry -Sun BOSS gyro multishot 7,400.00 8,900.00 30-08111_wp04 (30-081-1) MWD MWD - Standard 8,900.00 9,670.00 30-08L1-02_wp02 (30-0811-02) MWD MWD - Standard Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 9,670.00 6,691.96 2 3/8" 2-3/8 Summary Site Name Offset Well - Wellbore - Design Kuparuk 30 Pad 30-01 - 30-01 - 30-01 30-02 - 30-02 - 30-02 30-02 - 30-02A - 30-02A 30-02 - 30-02ALl - 30-02ALl 30-02 - 30-02ALl P81 - 30-02AL1 PB1 30-02 - 30-02AL2 - 30-02AL2 30-02 - 30-02AL2-01 - 30-02AL2-01 30-04 - 30-04 - 30-04 30-06 - 30-06 - 30-06 30-08 - 30-0811 - 30-081-1_wp04 30-08 - 30-081-1-01 - 30-08L1-01_wp02 30-08 - 30-081-1-03 - 30-08L1-03_wp04 30-08 - 30-081-1-04 - 30-08L1-04_wp01 30-10 - 30-10 - 30-10 30-15 - 30-15 - 30-15 I Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (usft) from Plan (usft) (usft) (usft) (usft) Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range 8,925.00 8,925.00 0.26 1.07 -0.52 FAIL- Minor 1/10 8,925.00 8,925.00 0.26 1.07 -0.52 FAIL- Minor 1/10 9,016.71 9,025.00 32.35 1.37 32.13 Pass - Minor 1/10 8,919.13 8,925.00 39.53 0.30 39.31 Pass - Minor 1/10 Out of range Out of range CC - Min centre to center distance or covergent point, SF - min separation factor, ES - min ellipse separation 611212015 12:33:48PM Page 2 of 7 COMPASS 5000.1 Build 65 Loepp, Victoria T (DOA) From: Venhaus, Dan E <Dan.Venhaus@conocophillips.com> Sent: Wednesday, June 24, 2015 11:53 AM To: Loepp, Victoria T (DOA) Cc: Pohler, Cody J; Ohlinger, James J; Eller, J Gary Subject: RE: KRU 30-081-1, 30-081-1-01, 30-081-1-02, 30-081-1-03, 30-081-1-04(PTDs 215-104,-105,-106,-107,-108) Follow Up Flag: Follow up Flag Status: Flagged Victoria, As mentioned in Cody's first response, overbalanced would be achieved by choke and mud weight adjustment. We primarily rely on choke adjustment which is almost instantaneous and mud weight secondarily. Many of our wells are designed with an underbalanced mud in combination with annular friction and choke to maintain overbalance and well control as already outlined in the verbiage and table on page 4 of the permit. As an example, the 30-08 permit application pg. 4 table notes expected choke pressures in order to maintain 11.8 ppg EMW. These choke pressures would increase another —450 psi, should 13.4 ppg pressure be encountered and there were no changes to mud weight. This surface pressure change is well within the capability of our surface equipment. To switch from drilling mode to completion requires utilizing mud hydrostatic as the primary for overbalance. We would achieve this by adding solid weighting material to 13.0 ppg brine for pressures over 13.0 ppg. We try to avoid this since the solids inhibit weight transfer. We therefore target expected reservoir pressures below 13.0 ppg with pressure management plans on all our candidates. I hope this helps answers your questions. I am curious as to why this particular well is garnering attention when it's not technically different from many of our wells. Please call me if you need more clarification. Thanks, Dan Venhaus CTD Engineering Supervisor - Alaska Cell 907-230-0188 Office 907-263-4372 From: Pohler, Cody J Sent: Wednesday, June 24, 2015 10:03 AM To: Ohlinger, James J; Eller, J Gary; Venhaus, Dan E Subject: FW: KRU 30-081-1, 30-08L1-01, 30-08L1-02, 30-081-1-03, 30-08L1-04(PTDs 215-104,-105,-106,-107,-108) Her response below From: Loepp, Victoria T (DOA)[ma iIto: victoria. loepp(aalaska.gov] Sent: Wednesday, June 24, 2015 9:57 AM To: Pohler, Cody J Subject: [EXTERNAL]RE: KRU 30-08L1, 30-08L1-01, 30-081-1-02, 30-081-1-03, 30-08L1-04(PTDs 215-104,-105,-106,- 107,-108) Cody, If 13.4 to 13.9 ppg formation pressure is encountered, can overbalance be maintained through choke adjustment and changes in mud weight? Could you please outline the calculation in a summary table. Thanx, Victoria From: Pohler, Cody J [mailto:Cody.J.Pohler@conocophillips.com] Sent: Tuesday, June 23, 2015 3:18 PM To: Loepp, Victoria T (DOA) Cc: Venhaus, Dan E; Ohlinger, James J; Eller, J Gary Subject: RE: KRU 30-081-1, 30-081-1-01, 30-08L1-02, 30-08L1-03, 30-08L1-04(PTDs 215-104,-105,-106,-107,-108) Victoria, With a maximum downhole pressure in the 30-08 pattern of 4822 psi(13.9 ppg EMW) is 13.0 ppg KWF nearby adequate? For Kuparuk CTD operations, it is fairly common and expected to encounter formation pressures significantly lower than the maximum pressure in the area. This is due to the faulting and/or drilling distance from the high- pressure injectors. In well 30-08, as in many cases, the well path is towards development well 30-01 (10.6 ppg formation pressure, Feb 2015), and maintains 1600' standoff from the injector 30-05. Therefore we do not anticipate to encounter formation pressures above 12.0 ppg. Please explain how this high pressure risk will be mitigated if encountered? As per standard CTD operations, we will use MPD practices of increasing the choke pressure and possibly the mud weight to maintain overbalance. The completion phase would then require adding weighting material to the 13.0 ppg killweight fluid to run liner. Will another pressure be obtained in 30-05 before drilling? Yes, our expectation is that 30-05 will have declined to at least 13.4 ppg by 30-08 spud date. One, if not several more, formation pressure measurements will be obtained by that time. Is the Baker whipstock flow through? There is substantial area for flow around the Baker 5Y," through -tubing whipstock, so the perforations in the 30- 08 completion will continue to produce after the CTD laterals are drilled and completed. Thanks, Cody From: Loepp, Victoria T (DOA) [ma iIto: victoria. loepp@alaska.gov] Sent: Monday, June 22, 2015 3:01 PM To: Pohler, Cody J Subject: [EXTERNAL]KRU 30-08L1, 30-08L1-01, 30-081_1-02, 30-08L1-03, 30-08L1-04(PTDs 215-104,-105,-106,-107,- 108) Cody, With a maximum downhole pressure in the 30-08 pattern of 4822 psi(13.9 ppg EMW) is 13.0 ppg KWF nearby adequate? Please explain how this high pressure risk will be mitigated if encountered? Will another pressure be obtained in 30-05 before drilling? Is the Baker whipstock flow through? Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793-1247 Victoria. LoeppCa)alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria.Loerpp@alaska.gov TRANSMITTAL LETTER CHECKLIST WELL NAME: /Q u— C2 PTD: Development _ Service _Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit / LATERAL No. ] 88 -- 0 %y , API No. 50- ©2,- a, / 8 2 $ - da - 0Q). i� (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -_� from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where sample are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well1 until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KUPARUK RIVER, KUPARUK RIV OIL - 490100 PTD#:2151060 Company CONOCOPHILLIPS ALASKA INC Initial Class/Type Well Name: KUPARUK RIV UNIT 30-081-1-02 Program DEV Well bore seg 0 DEV / PEND GeoArea 890 Unit 11160 On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0025513, entire wellbore 3 Unique well name and number Yes KRU 30-081-1-02 4 Well located in a defined pool Yes KUPARUK RIVER, KUPARUK RIV OIL - 490100, governed by Conservation Order No. 432C. 5 Well located proper distance from drilling unit boundary Yes CO 432C contains no spacing restrictions with respect to drilling unit boundaries. 6 Well located proper distance from other wells Yes CO 432C has no interwell spacing restrictions. 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property line where ownership or landownership changes. 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes PKB 6/19/2015 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.0300.1.A),0.2.A-D) NA 18 Conductor string provided NA Conductor set in KRU 30-08 Engineering 19 Surface casing protects all known USDWs NA Surface casing set in KRU 30-08 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing set and fully cemented 21 CMT vol adequate to tie-in long string to surf csg NA 22 CMT will cover all known productive horizons No Productive interval will be completed with a slotted liner 23 Casing designs adequate for C, T, B & permafrost Yes 24 Adequate tankage or reserve pit Yes Rig has steel tanks; all waste to approved disposal wells 25 If a re -drill, has a 10-403 for abandonment been approved NA 26 Adequate wellbore separation proposed Yes Anti -collision analysis complete; no major risk failures 27 If diverter required, does it meet regulations NA Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation pres is 4822 psi(13.9 ppg EMW); will drill w/ 9.8 ppg&MPD; 13.0 KWF nearby VTL 6/22/2015 29 BOPEs, do they meet regulation Yes 30 BOPE press rating appropriate; test to (put psig in comments) Yes MPSP is 4153 psi; will test BOPs to 4500 psi 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of 112S gas probable Yes 112S measures required 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures No Wells on 30-Pad are 112S bearing. M2S measures required. Geology 36 Data presented on potential overpressure zones Yes Max reservoir pressure is 13.9 ppg EMW; will be drilled using 9.8 ppg mud and MPD Appr Date 37 Seismic analysis of shallow gas zones NA technique. Two wellbore volumes of 13.0 ppg KWF will be available. PKB 6/19/2015 38 Seabed condition survey (if off -shore) NA 39 Contact name/phone for weekly progress reports [exploratory only] NA Onshore development well to be drilled. Geologic Engineering Public Date: Date Date Commissioner: Commissioner: Commissioner
