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214-106
RECEIVED MAR 14 2017 GLACIER ACCCC March 141h, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Cancelation of Permit to Drill: 214-106 Cook Inlet Energy, LLC: Redoubt Shoal Unit 12 Dear Ms. Foerster, Cook Inlet Energy, LLC, requests the cancelation of Permit to Drill #214-106, for well Redoubt Shoal Unit 12. CIE has determined the well will not be drilled. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff Sr. Drilling Engineer Cook Inlet Energy, LLC (a Glacier Oil & Gas wholly owned company) 601 W. 5th Avenue, Suite 310 Anchorage, AK 99501 Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Wednesday, March 01, 2017 1:36 PM To: Conrad Perry Cc: Schwartz, Guy L (DOA); Bettis, Patricia K (DOA) Subject: Expired Permits to Drill: 214-163 and 214-106 Conrad, During a review of the well files the following permit to drills were noted to be expired: • 214-163, W McArthur River Unit 8A, issued 4 November 2014 • 214-106, Redoubt Shoal Unit 12, issued 2 September 2014 The permits to drill expired under Regulation 20 AAC 25.005 (g). The PTDs will be marked expired in the AOGCC database. 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. Carlisle, Samantha J (DOA) From: Courtney Rust <Courtney.Rust@cookinlet.net> Sent: Wednesday, September 03, 2014 9:50 AM To: Carlisle, Samantha J (DOA) Subject: Re: Redoubt Unit #12 We will note it in our records. Thank you, and sorry for the error on the form From: <Carlisle>, "Samantha J (DOA)" <samantha.carlisle@alaska.gov> Date: Wednesday, September 3, 2014 12:47 PM To: courtney Rust <courtney.rust@cookinlet.net> Subject: Redoubt Unit #12 Courtney, Yesterday we sent back a 10-401 for Redoubt Unit #12. In box 4a. the total depth should read: 3598.94' FSL, 1567.73' FEL, SEC. 18, T7N, R13W, SM, AK, the change is in rPH. The same change should be made on the cover letter for the bottomhole location. Please let me know if you have questions or you can send the permit back to our office and I will be happy to make the changes. Thanks! Samantha Carlisle Executive Secretary 11 Alaska Oil and Gas Conservation Commission 333 West 7" Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. THE STATE 7- pA GOVERNOR SEAN PARNELL Conrad Perry Drilling Manager Cook Inlet Energy, LLC 601 W. 5`i' Ave., Suite 310 Anchorage, AK 99501 4 U !''`_ �f 333 Wesf Sevenin Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fry : 9�7.276.7542 Re: Redoubt Shoal Field, Redoubt Shoal, Undefined Oil Pool, Redoubt Unit #12 Cook Inlet Energy, LLC Permit No: 214-106 Surface Location: 1964.54' FSL,-215.56' FEL, SEC. 14, T7N, R14W, SM, AK Bottomhole Location: 3598.94' FSL,,e67.73' FEL, SEC. 18, T7N, R13W, SM, AK Dear Mr. Perry: Enclosed is the approved application for permit to drill the above referenced development well. Variance requests: Cook Inlet Energy, LLC's (CIE) request for a variance to set structural casing at 63 feet vs. the required 70 feet below mudline as per 20 AAC 25.030(c)(1) is APPROVED. 36" structural casing was driven during platform construction to refusal at this depth. Several wells have been drilled with this penetration depth with no issues since platform startup. CIE's request for a waiver to set conductor casing after drilling out structural casing is APPROVED per 20 AAC 25.030(c)(2)(B). Multiple wells have been drilled on the Osprey platform without conductor casing being set and there have been no indications of shallow gas in the area. A Diverter system (attached to structural casing) will be utilized to drill the surface hole section and will provide adequate protection while drilling the 16" hole section to a TD of 3400 feet MD. (2870 feet TVD) CIE request for alternate Diverter routing is APPROVED. Closest ignition source (North platform crane) is approximately 65 feet from the end of diverter line. Required distance is 75feet per 20 AAC 25.035(c)(2)(C). The Crane will not be utilized unless absolutely necessary during surface hole operations and will be in direct contact with the driller at all times. CIE request for placement of the SVS out of vertical run of production tree is APPROVED per 20 AAC 25.265(o)(1). CIE is currently applying for a blanket variance for the Osprey platform regarding SVS placement. Permit No.: 214-106 Cook Inlet Energy, LLC Page 2 of 2 Conditions of Approval: 1. 5000 psi 13 5/8" BOPE to be tested to 5000 psi for 12.25" and 8.5" hole sections. (Annular to 2500 psi - min) 2. Casing tests as follows: • 13 3/8" surface casing test pressure = 2500 psi (50% of burst) • 9 5/8" Intermediate casing test pressure = 4000 psi (58% of burst) • 7" liner test pressure = 4000 psi 3. BOP Casing Rams to be tested as per following: • 9 5/8" casing rams to 3000 psi • 7" casing rams to 3000 psi 4. Weekly drilling report to be submitted to AOGCC by email. 5. Gamma Ray to be recorded from bottom of conductor to total depth. 6. CBL required over 9 5/8" and 7" casing to determine TOC and cement quality. 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 CIE in the attached application, the following well logs are also required for this well: Gamma ray shall be recorded from base of conductor to total depth. Per AS 31.05.030(d)(2)(B) and 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. 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 this2eday of September, 2014. STATE OF ALASKA A OIL AND GAS CONSERVATIOt MM PERMIT TO DRILL 20 AAC 25.005 RECEIVED DN JUL 15 2014>, 1a. Type of Work:Llb.roposed Well Class: Development -Oil ❑✓ , Service - Winj ❑ Single Zone © 1c. Specify if well is proposed for: Drill Lateraltigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Coalbed Gas ❑ Gas Hydrates Redrill ❑ Reentryloratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas 2. Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11. Well Name and Number: COOK INLET ENERGY, LLC Bond No. 61212870 REDOUBT UNIT #12 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 601 W 5TH AVE SUITE 310, ANCHORAGE, ALASKA 99501 MD: 16250 TVD: -12-&% REDOUBT SHOAL UNDEFINEDr l 4a. Location of Well (Governmental Section): U 7. Property Designation (Lease Number): Surface: 1964.54' FSL,-215.56' FEL, SEC 14 T7 R14W SM AK n ADL 381203, ADL 378114 Top of Productive_ Horizon: 3599, 4 a FSt- (gg1.7q FEL �) 8. Land Use Permit: 13. Approximate Spud Date: SEA 17 I -�N it I� w, S• 0\ • 12 Y A l3 W N/A 7/21/2014 Total Depth: 3598.94' FSL, j 567.73' FEL, SEC 14TTR44W-SM AK 9. Acres in Propertv: AP� 14. Distance to Nearest Propertv: 951 S 5,086' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above 1 90 feet 15. Distance to Nearest Well Open Surface: x- 200682.26 y- 2449980.15 Zone- i{ GL Elevation above I N/A feet to Same Pool: 3965 16. Deviated wells: Kickoff depth: 5W 4S4 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 44 degrees • Downhole: --,10 4624"PSI Surface: 4448 PSI 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 36" 150# A-36 N2 215' 0 0 215' % ' 215' N/A 16" 13 3/8" 68# L80 BTC 3,400' 0 0 _21187T 2,874' 1390 sacks 12 1/4" 9 5/8" 47# L80 BTC 12,941' 0 0 9,869' 800 sacks 8.5" 7" _2ei< L80 BTC 3,609' 12,641' 9,649' 16,250' 12,898' 310 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Dep Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth Perforation Depth TVD (ft): 20. Attachments: Property Plat ❑ BOP Sketch ❑✓ Drilling Program ❑✓ 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 1-Jul-14 22. 1 hereby certify that the foregoing is true and correct. COURTNEY RUST 433-3809 Contact COURTNEYRUST @ COOKINLET.NET Email Printed Name CONRAD PERRY Title DRILLING MANAGER Signature Phone 907-727-7404 Date 1-Jul-14 i Commission Use Only Permit to Drill r a` API Number - Permit Approval See cover letter for other Number: �Q 5 - �33 oG3� - oo - Od Date: - 2- -..)-� requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: [✓] No u Other: 4 , — nS L %� (J � �5 f Samples req'd: Yes ❑ No LZ Mud log req'd: Yes RNo /' H2S measures: Yes ❑ No 0 Directional svy req'd: Yes ❑l � f� j ff✓� [_ Spacing exception req'd: Yes El � Inclination -only svy req'd: Yes El APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 2S`! d I I � Submit Form and Form 1)-ao1 (Revised 10/2 12) �Ft e IaNbA Months from the date of a ro�aGl/(20 AAC 25.005(g)) Attachments in Duplicate Cook Inlet Energy_ RECEIVED July 15, 2014 Ms. Cathy Foerster, Chair JUL 15 2014 Alaska Oil and Gas Conservation Commission AOGCC 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Permit to Drill Cook Inlet Energy, LLC: Redoubt Unit #12 Dear Ms. Foerster, Cook Inlet Energy (CIE) hereby submits a Permit to Drill application to drill the Redoubt Unit #12 well located on CIE lease #381203 and 378114 off the Osprey Platform. Attached are completed Form 10-401, outline procedures, current and proposed wellbore schematics, Directional Plan/Close Approach calculations, MASP calculations, Rig Drawing, and a BOP configuration diagram. Rig #35 will be used to complete this operation commencing approximately August 4, 2014. Maximum Anticipated Surface Pressure: 4448 PSI. CIE is requesting variances: • To set structural casing at 63' vs the required 70' below the mud line • To set conductor casing after drilling out the structural casing • Alternate diverter routing to 65' instead of 75'. • To set the SVS out of vertical run of production tree If you have any questions, please contact me at (907)-727-7404. Sincerely, G Conrad Perry Drilling Manager Cook Inlet Energy, LLC Table of Contents WaiverRequest............................................................................................................................... 4 Rig#35 Schematic.......................................................................................................................... 5 RU-12 Proposed Completion.......................................................................................................... 6 RU12 Outline Drilling Procedure................................................................................................... 7 Runand Cement 7" Liner........................................................................................................... 9 Perforation and ESP Completion.............................................................................................. 10 TimeVS Depth............................................................................................................................. 12 DiverterSketch............................................................................................................................. 13 BopSketch.................................................................................................................................... 14 WellheadSchematic.................................................................................................................... 15 GeologicalSummary.................................................................................................................... 16 Geo-Mechanical Plot..................................................................................................................... 18 CasingProgram........................................................................................................................... 19 DrillingFluid Program.................................................................................................................. 21 CementProgram........................................................................................................................... 22 DirectionalPlan............................................................................................................................ 27 SolidsControl and Equipment.................................................................................................... 31 DrillingWaste Storage................................................................................................................ 31 BitProposal.................................................................................................................................. 32 9 Waiver Request CIE is requesting a variance to set structural casing at 63' instead of the required 70' below the mudline as stated in 20 AAC 25.030C(1). 36" structural casing was driven during the platform construction to refusal at this depth and several wells have been drilled with this penetration depth with no issues. CIE is requesting a waiver to set conductor casing after drilling out the structural casing as stated in 20 AAC 25.030 C(2)(B). Multiple wells have been drilled on the Osprey platform without conductor casing being set and there have been zero indications of shallow gas in the area. A diverter system will be used to drill the surface hole section and will provide protection while drilling the 16" hole section to a TD of 3400'. CIE request alternate diverter routing as the closest ignition source, the North platform crane is approximately 65' from the end of diverter line. 20 AAC 25.035 C(2)c. The crane will not be used unless necessary during the surface hole operations and would be in direct contact with the driller at all times. CIE request a variance on SVS placement out of vertical run of production tree. CIE is currently in the application process of a blanket variance for all Osprey wells. 20 AAC 25.265 Il Rig #35 Schematic DRILLING RIG ARRANGEMENT -- EAST SIDE .�,.aL. au RU-12 Proposed Completion Redoubt Unit #12 Proposed Completion 1/1114 3 1/2" SSSV @ 345' MD Baker Hughes Twin Seal Packer @2,500' MD TOL @ 12,718' M D �J 13 3/8" 68 # A-36 215'TVD Welded 215' MD L-80 2,874'TVD BTC 3,400' MD 3 1/2" 12.95# P110 PH6 Tubing 8,000'MD 3 1/2" 9.3# L80 EUE-M Tubing 14,999'MD 95181, L80 9,869' TVD 47 # BTC 12,941' M D Centrilift ESP Assembly (top of discharge head) @ 15, 000'M D 7" L80 12,898'TVD 29# BTC 16,250' MD m RU12 Outline Drilling Procedure Leg 2 Slot 9 Pre -Spud 1. Install 36" starting head on 36" conductor which was pre -driven to 215' Drilling 1. Move in and Rig Up Miller Rig #35 ✓ 2. Nipple up 21 1/4" diverter and 16" diverter lines. 3. Function test diverter and witness by AOGCC awl"_ 4. Pick up and stand back 5 drill pipe. 8 jc�_ 5. Pick up 16" bit, Motor, MWD, collars, and stabilizers. Have Gyro and eLine on standby. 6. Drill 16" hole to 500' kick off point. 7. Directionally drill 16" hole to 3400' MD/ 2,874' TVD. 8. Circulate Hole Clean. POH. Stand back directional tools 9. Rig up to run 13 3/8" casing. 10. Run 13 3/8" 68# L80 Butt casing to 3400' with Float Shoe and Stab -in float Collar. Land casing elevators on wood blocks close to RT. Centralizer program to follow. 11. Make up false rotary. Pick up cementing stinger and centralizer. RIH. 12. Stab into float collar. Establish circulation slowly. 13. Rig up cementers. Test Lines. t 5 C. c Y 14. Pump 12.5 ppg lead cement until returns to surface. Tail with 500' of1-5J8 ppg. Have cement retarder on hand. 15. Un-sting from collar and check for back flow. Drop wiper ball and circulate drill pipe clean. 16. POH with drill pipe. 17. Check for flow. Nipple down 21 '/4" diverter after WOC 12 hours. 18. Dress conductor and 13 3/8" casings. Check cement to surface. Perform top job if cement is not at surface. 19. Install and test Vetco 13 5/8" multi -bowl wellhead. 20. Nipple up and test 13 5/8" BOPE with 5" pipe rams, Blinds in middle. Test Rams to 5000 psi, Bag to 2500 psi. Clean pits and make up new mud system. 21. Pick up and stand back 5" drill pipe. 7 22. Pick up 12 '/4" PDC bit, Rotary steerable, MWD/GR and Collars. 23. RIH to 1000' and perform shallow MWD test. 15,3 lL 24. Continue RIH. Test Casing to 2500 psi. Drill out float collar, shoe track and float shoe. Drill 20' of new formation and perform FIT to minimum 12.5 ppg EMW. (12.5 is minimum, take to leak off pressure) 25. Change over from spud mud to LVT Oil base. 26. Directionally drill 12'/4" hole to 12,941' MD / 9,869' TVD according to directional program. 27. Circulate hole until clean. 28. Pump out of hole to 13 3/8" shoe. Make wiper trip if needed 29. POH. 30. Rig up to run casing. Change upper rams to 9 5/8" and test to 300�0 psi. 31. Run 9 5/8" 47# P110 BTC casing to 12,921'. Run one spiral glider per joint for first 10 jts, then one per 4 jts to 13 3/8" shoe. 32. Circulate hole clean while slowly reciprocating casing. 33. Land 9 5/8" mandrel hanger. Rig up and test cementers. Cement 9 5/8" casing according to program. Bump plug with 3000 psi. Release pressure and check floats. Note: TOC must be 1000' above any potential hydrocarbon zones. Rig down cementers. 34. Pick up and stand back 5" drill pipe. 35. Change upper rams back to 5". Test BOPE to 500 psi/2500 psi Hydril 36. Pick up 8 ''/2" PDC bit, Rotary steerable, MWD/LWD triple combo, and BHA. 37. RIH to 1000'. Perform shallow MWQ/LWD 7 st�µr,r �- 38. Continue RIH. Test Casing to 4psi for 30 minutes on chart. Drill out float collar, shoe track and float shoe. Drill 20' of new formation. Circulate and condition mud. Perform FIT to minimum 12.0 ppg EMW. (12.0 is minimum, take to leak off pressure) 39. Directionally drill 8 '/2" hole to 16,250' MD /12,898' TVD. Circulate hole clean. 40. Pump out of hole to +/- 3400' MD. Continue POH. Run and Cement 7" Liner f 41. M/U and run 7" 29# L80 BTC liner on 5" drill pipe as follows: l a. Perform all measurements and equipment checks before running the liner. b. Ensure liner hanger is located +/- 300' above 9-5/8" Liner top. c. 1 joint 7" liner w/float collar made up on pin end of joint #2 d. 1 joint 7" liner landing collar made up on the pin end of joint #3. e. 7" 29# L80 BTC liner f. Baker Hughes 9-5/8" x 7" liner hanger g. drill pipe wiper plug and liner wiper plug. h. Baker -Lock all float equipment and the bottom 4 joints of liner. Solid body Centralizers will be run on every joint through Hemlock and across any other hydrocarbon zone then every 4th jt to TOL) 42. RIH w/ liner hanger assembly. 43. Continue RIH with liner on DP. Break circulation every 4000'. Break circulation at shoe. Obtain pick-up and slack -off values. Liner speed to be run with a calculated ECD less than when drilling! 44. Continue to RIH to TD with liner on drill pipe. Tag bottom with liner. Top of the liner is planned at +/- 12,700' MD. Set 10' off bottom. 45. P/U a sufficient distance to allow a safe and convenient make-up operation of the cementing head and test lines to 500/7,500 psi. Circulate and condition the hole for cementing while reciprocating and rotating the liner. Do not exceed 80% of make-up torque of liner. Maximize flow rate while cleaning hole. Do not exceed the liner hanger setting pressure. M 46. The top of cement is planned for 1000' above highest hydrocarbon zone. While reciprocating (rotate at 5 rpm if possible) the liner again with a calculated ECD less than what it was during drilling, pump cement as follows, carefully monitoring torque and flow rate while rotating: • Verify DP indicator is activated • Pump weighted spacer • 40% excess cement in open hole (See detailed cement program for 7" liner) • Follow the cement with the DP wiper dart and displace with drilling mud. • Slow pump down 5 bbls short of the DP wiper dart landing on the landing collar. • Bump plug w/ 500 psi above final pumping pressure. • Limit over -displacement to 5 bbls 47. Once liner wiper plug bumps, hold the pressure for 2 minutes. Do not exceed 500psi over the final pumping pressure. Release pressure and check floats. 48. Set Baker Hughes Liner Hanger according to recommendations. Release running tool. 49. Pull up 1 stand and reverse out cement at maximum rate while reciprocating and rotating drill pipe. 50. POH laying down excess 5" drill pipe. Perforation and ESP Completion 51. Change Casing rams to VBR if not already in place. Test to 3 1/2". o (--' r 52. RIH picking up 6 1/8" mill, 7" scraper, 3 1/2" tubing with 9 5/8" scraper spaced out appropriately. Run assembly on 5" drill pipe. 53. Tag bottom. CBU til clean. 54. Hold PJSM with Production and all parties. Rig up and test lines. Displace well with filtered produced water mixed to 8.6 ppg with KCL. Use displacement spacer. 55. Test casing and liner to 4000 psi. NOTE: Do not test casing until WOC for 24 hours! 56. Continue circulating and filtering brine until returns are <30NTU. lLr 57. POH, stand back 3 1/2" tubing. 58. Hold PJSM on handling guns, communications, roles and responsibilities. 59. Pick up 4 5/8" guns to perforate the following intervals 6 spf. a. PERFORATIONS: TBD b. Use dual drop bar/pressure firing head 60. Pick up test packer and burst disk. 61. Run in with assembly on drill pipe. Short fill drill pipe last 3000'. This will give a 1,100 10 psi underbalance at the top perforations and potentially allow 53 bbls of oil into the well. 62. Rig up run GR/CCL Log. Re -space guns on depth. Re -run Gr/CCL to confirm. Work with Greg for double check correlation. 63. Set packer. Test backside to 2000 psi. Rig up to rig choke. Test lines 64. Hold Firing PJSM. Drop bar, perforate well, flow fluid to surface. 65. Once brine is to surface, shut in at surface. 66. Reverse well slowly dead over choke. Monitor losses. Note if 53 bbl of oil enters the drill string, there will be approximately 300 psi surface pressure prior to reversing clean. 67. Check for flow. Well should be dead. 68. Unseat packer. Circulate well clean, Check for flow. 69. POH 70. PJSM prior to pulling guns through rotary. Lay down guns being aware of potential trapped pressure. 71. Rig up spoolers, sheaves, etc. — 72. Test and inspect new ESP and new Phoenix tool before running in hole. i 73. Pick up new ESP completion and RIH. Run flat pack to bottom pump anode. Test cable every 1000'. 74. Install Baker ESP packer and vent valve at200.0' with SSSV assembly at 300'. Maintain pressure on control line. 75. Monitor trip tank for proper hole filling. Splice cable as needed. At TD, confirm pipe tally, MU landing joint and set string in slips. 76. Dress hanger and control lines. Land hanger, run in screws, test hanger to 5000 psi. note: run control line to rig floor to operate SSSV and vent valves. 77. Rig up slickline. Run Test tool to 3 %"R nipple below packer. Pressure up on tubing to Baker recommendations setting packer. Recover Test Tool. 78. Test Annulus to 2000 psi for 30 minutes on chart. - 79. Perform final electrical checks on cable. 80. Lay down landing joint and install BPV. Observe well dead. 81. Nipple down riser and BOPE. 82. Install and test production tree. Turn over well to production. 83. Release Rig 11 Time VS Depth MD,R io 5 :J m G n G o 8 s s a s gs a n a .i m a g a a $ 0 0 0 0 0 0 0 0 0 0 0 I I I I J ol b ��III II I + m _ I I a I n 1-0 tl I I I ;moo r Diverter Sketch Full Open H1d 16' 150 Kn i S' 150 Rani INN Deok Deck Elevalial =227 27 104 23! Pl m F d 12 Wdl L-80 Fd- 4 1 M 62m &aln Zee 36` Iby20' Weld Adepk, Ne�af m = 1.70 3E B75 Hell St -Wrel Di— Pipe Dd— to. F 70' SUL —irg pe� O Ir.l. 24.4'frameubbaee to End of 16" D—b. �A dine I II 6'Irom Nibbese 1] Edge of Upper Ceck 155'ton VMI Omkar to OutMW 14A'hom 9ibbamlo V oflolll1edc ��/ Val eta Edge of Lola Deck I I I Edge of u pper Oak 13 Bop Sketch COOK INLET ENERGY OSPREY PLATFORM 13-5/8" 5M BOPE 54" 13-5/8" 5M HYDRILGK 13-5/8" 5M SHAFFER LXT DBL GATE 31" W/ 2-7/8" - 5-1/2" VBR IN TOP W/ BLIND RAMS IN BOTTOM 13-5/8" 5M MUD CROSS 24" W/ 2 EACH 4-1/16" 5M SIDE OTL 13-5/8" 5M CAMERON SNGL GATE 33.5" _�-7 I^ �� I T-L W/ 2-7/8" - 5" VBR TOTAL STACK HEIGHT IS 142.5" 14 Wellhead Schematic 0GE Oil & Gus �•••�••v.s..c x.•r: s�:+aw,�m.�.tv.a�c.o. _+.+r•.,".+ee-�u .ac , a I. �.r,.ot U-.4 I.,.,a, r:v« ,t........,. ca,.I . 13-318" x 9-518" x 3-112" 5M SH2 Wellhead Assembly, With SH2-UPR-LR False Bowl, SH2-LR-EN-CCL Tubing Hanger and A4EN-CCL Adapter Flange 15 Geological Summary Formation Evaluation Mud Logger A two man mud logging crew should be on location and rigged up and logging from 6500' MD. Logging unit should be equipt with hot wire and chromatograph equipment with 30' ditch samples being collected and sample descriptions prepared. Ten foot samples to be collected through potential pay zones as needed. Logs including a "=100' MD and TVD log are to be emailed twice daily to individuals named on a separate distribution sheet. Note that logs and a morning report are to be sent before 5:30 AM daily and logs to be emailed before 2:30 PM daily. Two sets of dry cut are to be prepared and held until end of well. At end of well one set to be provided to State of Alaska AOGCC. Second set is to be provided to Cook Inlet Energy. Open Hole Loj!s r� � Baker Hughes LWD logs or comparable logs are to be run over each interval at casing points ; �� i,4� from 9 5/8" casing shoe to Total Depth. Evaluation minimum shall be a Gamma Ray Resistivity log suite for the 9 5/8" hole section and a triple combo logging suite consisting of a Gamma Ray, Resistivity, Caliper, Density, Neutron log suite below the 9 5/8" shoe. A 1"=100' , 2"=100' and 5"=100' MD and TVD log to be provided twice daily with one report to be received no later than 5:30 am and the second no later that 2:30 PM daily by email to people designated on a separate list. Data in a .las format to be provided to Company man, Cook Inlet Energy geologist in the Anchorage office, and State of Alaska AOGCC ASAP after logging concluded. Cased hole Logs Engineers are to be provided a Borehole volume survey at each casing point in order to assist in determining cement volumes necessary. If well is cased for production, a Cement Bond Log / Cement evaluation Type survey is to be run from PBTD to shallowest potential evaluated in wellbore. A 5"=100' MD and TVD log to be provided (No. of copies to be determined) after each run including both paper copies and digital data. Data in a .las format to be provided to Company man, Cook Inlet Energy Anchorage office, geologist, drilling personnel and State of Alaska AOGCC ASAP after logging concluded. 16 Geologic Hazards Primary geologic hazards expected to be encountered in this well are similar to those encountered in other wells previously drilled in the Redoubt structure. Numerous coal beds are expected to be encountered throughout the Beluga, Tyonek and into the Hemlock section. These can range from a few feet thick to upwards of fifty feet in thickness. Sloughing coals have proven problematic in drilling operations to date. Although no abnormal pressures are expected, care should be exercised when drilling the correlative Tyonek section currently being utilized in the RU-D1 well for disposal of cuttings and fluids. -'We will be drilling the section within''/z to 3/ mile of the injection well. Abnormal pressures could be expected. Normal care should be exercised for unexpected shallow gas accumulations, although none have previously been encountered within the field. 17 GEO-MECHANICAL PLOT Geothermal Temperature Profile MD TVD Temperature Gradient M) tit) (dead) (deaF,i,1.UAft) 0.0 0.0 80 0.0 90.0 90.0 80 -0.0 160.0 159.9 77 -1.8 15226.0 12345.4 190 0.9 a 0 I 0 degF Temp. Profile & 119 min Casing Program Cook Inlet Energy Casing Plan Well information WELL NAME: RU9 ENGINEER: Courtney Rust DATE: 7-Nov-13 Hole Sizes (in) Casing Size (in) MD (ft) TVD (ft) Max EMW (Pore Pressure) Estimated Frac Grad at Shoe Estimated Range - Mud Weight (ppg) Mud Type Comments - 30" — — — — — Conductor pipe 16" 133/8" 3,400 2,874 8.5 17.2 8.8 9.2 WBM Normal gradient, no shallow gas 12 1/4" 9 5/8" 12,941 9,869 8.6 14.9 8.8 9.2 OBM Norm grad Based on offests 81/2" 7" 16,250 12,898 8.6 14.7 8.8 9.8 OBM I hemlock oil Casing Plan ENT ER YELLOW CELLS MANUALLY Casing Size (in) Wt (Ib/ft) Grade Connection API rating MD (ft) TVD (ft) Type OD (in) Burst (psi) Collapse (psi) Tension Ikips) 36" 150 A-36 N2 — — — — 0 0 133/8" 68 L80 BTC 10.63 5020 2260 952 3400 2874 95/8" 47 L80 BTC 10.625 6870 4760 1161 12941 9869 7" 29 L80 7 BTC 7.875 8160 7020 718 16250 12898 Variables & Formulas Wellhead 1 5,000 1 psi Gas Gradient 0.10 psi/ft Pore Pressure Gradient 1 0.460 Ipsi MAWP = (0.80 X CASING BURST) or Limiting Wellhead Pressure MASP = Lessor of (Frac Pressure @ (0.052 X (M W + 0.5ppg SF) X TVD) - GasGRD X TVD)) or (Max Pore Pressure - (GasGRD X TVD)) MASCP = (0.80 X CASING BURST) - (MW - Backup FluidWt.) X .052 X TVD SF Burst = Burst Value/MASP SF Collapse = Collapse Value/((0.052 X Max EMWPore Pressure XTVD)-(gas gradient X TVD)) SF Tension =Tension Value/(Length X lb/ft) Le, Max Allowable Working Pressure MAWP = (0.80 X CASING BURST) or Limiting Wellhead Pressure Hole Sizes Casing Size Safety MD (ft) ND (ft) Burst (psi) MAWP (psil (in) (in) Factor 16" 13 3/8" 3,400 2,874 5020 0.8 4016 12 1/4" 9 5/8" 12,941 9,869 6870 0.8 5496 M 81/2" 7" 16,250 12,898 8160 0.8 1 6528 Max Anticipated Surface Pressure MASP = Lessor of (Frac Pressure @ (0.052 X (M W +0.5ppg) X TVD) - GasGRD X TVD)) or (Max Pore Pressure - (GasGRD X TVD)) Hole Sizes Casing Size Max EM W Frac Grad at M W Safety Gas Frac Max PP at (in) (in) MD (ft) TVD (ft) (ppg) Shoe Factor Gradient Pressure at Next TVD MASP (psi Shoe 16" 13 3/8" 3,400 2,874 8.5 17.2 0.50 0.10 2358 3,375 2,358 12 1/4" 9 5/8" 12,941 9,869 8.6 14.9 0.50 0.10 6916 4,478 4,478 91/2" 7" 16,250 12,898 8.6 14.7 0.50 0.10 8905 4,478 4,478 Max Allowable Surface Casing Pressure MASCP = (0.80 X CASING BURST) - (M W - Pore Pressure) X .052 X TVD Hole Sizes Casing Size Safety Max EM W (in) (in) MD (ft) TVD (ft) Burst (psi) Factor MW (Pore MASCP (psil Pressure) 16" 13 3/8" 3,400 2,874 5020 0.8 9.2 8.5 3911 12 1/4" 9 5/8" 12,941 9,869 6870 0.8 9.2 8.6 5188 81/2" 7" 16,250 12,998 8160 0.8 9.8 8.6 5723 Safety Factors Hole Sizes Casing Size Collapse Tension Liner Length SAFETY FACTORS (In) (in) MD (ft) TVD (ft) Burst (psi) (psi) (kips) Wt (IbJft) (ft) Surat Collapse Tension 16" 13 3/8" 3400 2874 5020 2260 952 68 - 2.1 2.3 4.2 12 1/4" 9 5/8" 12941 9869 6870 4760 1161 47 - 1.5 1.4 1.9 8 1/2" 7" 16250 12898 8160 7020 718 29 3609 2.8 1.6 6.9 SF Burst = Burst Value/MASP SF Collapse = Collapse Value/((0.052 X Max EMWPore Pressure X TVD)-(gas gradient X TVD)) SF Tension =Tension Value/(Length X lb/ft) 20 Drilling Fluid Program AOUAGEL/freshwater scud mud MD Viscosity I PV YP API FL I pH Weight 100'-3400' 1 8.6-9,2 60-85 10-28 1 25-35 1 10 1 8.5-9.0 Spud the well with a freshwater AQUA GEL spud mud at 8.6 ppg. The mud weight will be held in the 9.0 to 9.2 ppg mud weight range to the surface hole TD unless hole conditions dictate otherwise. Our primary focus for surface hole drilling operations will be adequate mud weight for well control and sufficient mud viscosity for efficient hole cleaning. LCM will be added to help strengthen the wellb ore. Intermediate Hole 9.2 M OBM Tareet Proaerties MD Mud Viscosity PV YP HTHP WPS t Wei3,400'- 9.2 50-80 10-25 18-25 <5 250- 13,018' 300K An 7 5/25 -80/2 0 OWR, MOBM mud will be used in this section. Baracarb and barite will be used for the initial weight up. The WPS will begin at 24OK and then be raised to 30OK. Bridging agents/asphal tine s will be maintained to help stabilize the coals. Our coal sealing strategy will be used in this intermediate section; it will be detailed in the interval mud sections. If any of this MOB will be reconditioned mud from another job, make sure to pilot test any changes made to condition this mud. Production Hole 9A-9.6 MOBM TareetProperties MD Mud Viscosity PV YP HTHP WPS W 13,'1" 9.4-9.6� 50-80 10-25 18-25 <5 250- 16,250' 300K An 75/25-80/20 OWR, MOB M mud will be used in this section. Baracarb and barite will be used for the initial weight up. The WPS will begin at 240K and then be raised to 300K. Bridging agents/asphal tines will be maintained to help stabilize the coals. Our coal sealing strategy will be used in this production section; it will be detailed in the interval mud sections. This MOB M will reconditioned mud from the previous hole section, make sure to pilot test any changes made to condition this mud. 21 Cement Program Calculations Surface Casing Spacer: Total Spacer = 168.44 fe = 30.00 bbl Cement: (2900.00 ft fill) 215.00 ft * 5.4224 ft3/ft * 0 % = 1165.81 W 2685.00 ft * 0.4206 ft'/ft * 100 % = 2258.44 ft3 Total Tail Cement = 3424.25 W = 609.88 bbl Sacks of Cement = 1390 sks Cement : (500.00 ft fill) 415.00 ft * 0.4206 W/ft * 100 % = 349.07 fe 85.00 ft * 0.4206 WIft * 100 % = 71.50 ft Lead Cement = 420.57fe = 74.91 bbl Shoe Joint Volume: (85.00 ft fill) 85.00 ft * 0.8407 W/ft = 71.46 W = 12.73 bbl Tail plus shoe joint = 492.02 W = 87.63 bbl Total Tail = 254 sks Total Pipe Capacity: 3315.00 ft * 0.0997 W/ft = 330.59 fe 85.00 ft * 0.8407 W/ft = 71.46 W = 71.61 bbl Displacement Volume to Shoe Joint: Capacity of Pipe - Shoe Joint = 71.61 bbl - 12.73 bbl = 58.88 bbl 22 Job Recommendation Surface Casing Fluid Instructions Fluid 1: Water Based Spacer TUNED SPACER III Fluid Density: 10.50 lbm/gal Fluid Volume: 30 bbl Fluid 2: Tail Cement VARICEM (TM) CEMENT Fluid Weight 12 lbm/gal Slurry Yield: 2.46 fl /sk Total Mixing Fluid: 14.52 Gal/sk Top of Fluid: 0 ft Calculated Fill: 2900 ft Volume: 609.88 bb] Calculated Sacks: 1389.71 sks Proposed Sacks: 1390 sks Fluid 3: Lead Cement VARICEM (TM) CEMENT Fluid Weight 13 Ibm/gal Slurry Yield: 1.94 ft /sk Total Mixing Fluid: 10.57 Gal/sk Top of Fluid: 2900 ft Calculated Fill: 500 ft Volume: 87.63 bbl Calculated Sacks: 254.14 sks Proposed Sacks: 260 sks Fluid 4: Mud DISPLACEMENT FLUID Job Procedure Fluid Density: 9.20 Ibm/gal Fluid Volume 58.88 bbl Surface Casing Fluid # Fluid Fluid Name Surface Estimated Downhole TNpe Density Avg Rate Volume lbm/gal bbl/min 1 Spacer TUNED SPACER III 10.5 4.0 30 bbl 2 Cement SWIFTCEM (TM) 12.0 4.0 1390 sks SYSTEM 3 Cement SWIFTCEM (TM) 13.0 4.0 260 sks SYSTEM 4 Mud DISPLACEMENT FLUID 9.2 8.0 58.88 bbl 23 Job Information Well Name: RU Well #: 12 Surface Casing 0 - 3400 ft (MD) Outer Diameter 13.375 in Inner Diameter 12.415 in Linear Weight 68 lbm/ft Open Hole 3400 - 13018 ft (MD) Inner Diameter 12.250 in Job Excess 40 % Intermediate Casing 0 - 13018 ft (MD) Outer Diameter 9.625 in Inner Diameter 8.681 in Linear Weight 471bm/ft Intermediate Casing Mud Type Water Based Mud Mud Weight 9.201bm/gal Calculations Intermediate Casing Spacer: 768.31 ft * 0.3132 W/ft * 40 % = 336.88 ft' Total Spacer = 336.88 ft = 60.00 bbl Cement: (2000.00 ft fill) 2000.00 ft * 0.3132 W/ft * 40 °.o = 876.93 f Lead Cement = 876.93 ft = 156.19 bbl Shoe Joint Volume: (85.00 ft fill) 85.00 ft * 0.411 W/ft = 34.94 ft = 6.22 bbl Tail plus shoe joint = 911.86 f = 162.41 bbl Total Tail = 790 sks Total Pipe Capacity: 13018.00 ft * 0.411 WIft = 5350.71 ft = 953.00 bbl Displacement Volume to Shoe Joint: Capacity of Pipe - Shoe Joint = 953.00 bbl - 6.22 bbl = 946.78 bbl 24 Job Recommendation Intermediate Casing Fluid Instructions Fluid 1: Rheologically Enhanced Spacer TUNED SPACER III Fluid Density: 10.50 lbm/gal Fluid Volume: 60 bbl Fluid 2: Lead Cement HALCEM (TM) SYSTEM Fluid Weight 15.80 lbm/gal Slurry Yield: 1.15 ft /sk Total Mixing Fluid: 4.96 Gal/sk Top of Fluid: 11018 ft Calculated Fill: 2000 ft Volume: 162.41 bbl Calculated Sacks: 790.18 sks Proposed Sacks: 800 sks Fluid 3: Mud Mud Displacement Fluid Density: 10 lbm/gal Fluid Volume 946.78 bbl 25 Job Procedure Production Liner Fluid # Fluid Type Fluid Name Surface Density lbm/gal Estimated Avg Rate bbl/min Downhole Volume l Spacer TUNED SPACER III 10.5 4.0 30 bbl Cement HALCEM (TM) SYSTEM 15.8 5.0 310 sks 3 Mud Mud Displacement 9.2 8.0 357.10 bbl Calculations Spacer: 948.77 ft * 0.1268 ft/ft * 40 % = 168.44 fe Total Spacer = 168.44 fe = 30.00 bbl Cement: (2000.00 ft fill) 2000.00 ft * 0.1268 WIft * 40 % = 355.07 fY Primary Cement = 355.07 fe = 63.24 bbl Shoe Joint Volume: (0.00 ft fill) 0.00 ft * 0.2086 ft /ft = 0.00 W = 0.00 bbl Tail plus shoe joint = 355.07 fe = 63.24 bbl Total Tail = 307 sks Total Pipe Capacity: 12718.00 ft * 0.0997 W/ft = 1268.30 W 3532.00 ft * 0.2086 ft /ft = 736.69 fe = 357.10 bbl Displacement Volume to Shoe Joint: Capacity of Pipe - Shoe Joint = 357.10 bbl - 0.00 bbl = 357.10 bbl Production Liner Directional Plan Cook Inlet Enerr WIN Fag Location: Cook In let, Masks (Offshore) Slot LegA9, Sot U12) _Cook. I nlet Energy Feld' Redoubt Shoal Welt. Redoubt Une#12 BAKER Facility re I or RUi HUGHES Targets �. a Yw:mJ wi °rr:nu m.. m Well Profile Data Location Information nor ®.10 0® ra.rtz can om °mom om x iDuix wse a;e Do v. IJy °rum Iom Easting(ft) Tin Casng 9.6351n Casing y 1111 RU1 �1 Z50 WF RU12 13.375in Casng t3 " 10h Conductor .� t " Vetfical Section (ft) -`-- Azimuth 79 46' with reference 0.00 N. 0.00 E N N I; Oa��wSaLAIJd)DD'rJdi' iY¢DSCJ.1 �t Dq�te MSY t MIDJRpnban�pbrUTx� Mwt pt6lplAlq aYn epxrr n miedsY�• b YyRmbC x]wIwRMOryxe� 'asing Tangent 0(S) (r1100fl nd of 3D Arc p(S) rid ofTangert Q(6) 7m Caaing 27 N 8 O In O N S S S S Northing (ft) O to N O S 8 0 8 $ In O S 8 - 0 o RD D1 ° 0� 8 dJ� S 0 0 8 0 S 0 bn 0 0 8 r N S Np S m O m .m. N�13 Nu� m O 1�$G} ao ad' So ,ra gd o �faada �_ G= oD o jEpG If�i�g mm \ S D a4ap� 00 a6 m om mCD J L T � 1 O 8 O 8 G L G CD b g Amm 'oud YC r: f0 LLLU S N � O N j N 8 8 8 O C Y c O O Y a b ZI CM, 9 0 w N Q- m tixn6� � m u u A � m 0 8u 0 S W N u w o cn c S o m o S S S 8 8 8 o 8 8 S (u) 61JiUuoN Cook Inlet Energy_ Operator Cook Inlet Energy Area Cook Inlet, Alaska (Offshore) Field Redoubt Shoal Facility Osprey Platform Clearance Summary Report RU12 Rev 3.0-Closest Approach Page 1 of 2 Slat ;Leg#3, Slot 9 (RU12) 'Well RedoubtUnit#12 Ff PP_ - 'A use (Projection System jNAD271TM Alaska SP, Zone 4 (5004), US feet (Software System lWeBArddtect@ 4.0 0 North Reference lGrid User jRagbyos Scale 11 Report Generated V5/Apr/2014 at 00:53 Convergence at slat 1.46- West jDatabase/Source filejWA_Andtorage Server/RU12 CR-xml Local coordinates I Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US 1t] Northing[US ft] Latitude Longitude Slot Location r 1964.54 r-215.56 200682.26 t 2449980.15 _ 60°41'44.141'N 151-40'13.424"W ,Facility Reference Pt C- 200897.82 2448015.61 60°41'24.856N 151°40'08.093"W IFieldReferencePt j j 200897.82 2448015.61 i 60°41'24.856N 151°40'08.093"W Calculation method lMlnimum Curvature ✓ '.Miller Rig #34 (89.1Oft) (RKB) to Mean Sea 89.10ft `` Level Horizontal Reference Pt Slot Miller Rig #34 (89.1 Oft) (RKB) to Mean Sea 89.10ft Level Vertical Reference Pt Mller Rig #34 (89.1011) (RKB) Miller Rig #34 (89.10ft) (RE B) to Mud Line at 134.10ft Slot (Leg#3, Slot 9 (RU12)) MD Reference Pt Miller Rig #34 (89. LOft) (RICB) Field Vertical Reference Mean Sea Level Ellipse Confidence Limit 3.00 Std Dev Ellipse Start MD '134.10ft Surface Position Uncertainty included Declination 16.831 East orTN Dip Angle 73.57 Mag Field Strength 55425 nT Slot Surface Uncertainty @1SD Horizontal 2.000ft Vertical 1.000ft Facility Surface Uncertainty (d1SD Horizontal 50.000ft Vertical 5.00011 Positional Uncertainty, values in the WELLPATH DATA table are the projection of the ellipsoid of uncertainty onto the vertical and horizontal planes ANTI -COLLISION RULE Rule Name E-type Closest Approach w/Hde&Csg Unilt:O, StdDev:3.00 Rule Based On Ellipsoid Separation w/Surface Uncert Plane of Rule Closest Approach Threshold Value 0.00ft Subtract Casing & Hole Size yes Apply Cone of Safety no HOLE & CASING SECTIONS - Ref Weubore: RU12 Ref Wellpath: RU12 Rev 3.0 Strinq/D[ameter Start MD End MD Interval Start TVD ; End TVD Start NIS Start E/W End NUS End FJW [ft] [ft] [ft] [ft] [ft] [ft] [ft] [ft] [it] 20in Conductor 89.10 215.00 125.90 89.10 215.00 0.00 0.00 0.00 0.00 13.375in Casing 89.10 3400.00 3310.90 89.10 2874.63 0.00, 0.00 284.53 1528.07 9.625in Casing 89.10 1294153 12852.43 89.10 9869.00 0.00 0.00 1472.57 7908.37 Tin Casing 1301823 16250.00 3231.77 9925.22 12898.43 1482.12 7959.65 1634.40 878329 29 Cook Inlet Energy Operator Cook Inlet Energy Area Cook Inlet, Alaska (Offshore) Field Redoubt Shoal Facility Osprey Platform Clearance Summary Report RU12 Rev 3.0-Closest Approach Page 2 of 2 `Slot Leg#3, Slot 9 (RU12) Well Redoubt Unit #12 Wellbore �RU12 Ff 101-- 'A Fag Start MD Ind MD Positional Uncertainty Model LogNamm elComent Wttlbort IN In] 134.10' 700.00Generic gyro - continuous (Standard) 0,U12 700.00 3400.00NaviTrak (SAG, MagColr) IltU12 F 3400.o0 13018.000nTrak(SAG) Tr U12 F- 13018.00: 16250.000nTrak (SAG) U12 (CALCULATION RANGE & CUTOFF From: 89.10ft MD To: 16250.00ft MD C-C Cutoff. (none) OFFSET WELL CLEARANCE SUMMARY (r8 Offset wellpsths selected) Ellipse separations calculated in Closest Approach plane C-C Clearance Distance AZ E11 se 3 aration Distance Ref Mtn C-C ivergm Ref MD d Min in Ea Sep ACR Offset Offset Offset Onset Offset MD ClearD franMD ioEusep Ell Sep Dvra gfrn Status Faca Slot Well ellbo We ath [rt] [ft] [ft] [ft] [ft] [ft] Redoubt Bay Unit#1,Slot#t RBU#1 RBU#1 ;OyroMS<0-13740> 11914.23 206.32, 11914.2-3 12034.11 129.56 12034.11L.FAIL Osprey Platform:Leg#2,Slot 12(RU7&7ST1) _-- - _-� RedoubtUnit#7'RU7 -RM(AWP)<0-11348'> 89.10. 9.38' 300.00 189.10 1.28. 300.001PASS Osprey Platform L 2, Slot 12 (RU7 & 7ST7) Wei' � iRU7 STl '�RU7 STl R5950 1 (AWP) <10921 89.10 9.38, 300.00 189. 10 1.28 15489.101 PASS Osprey PlatformLeg#2,Slot 7(RU9) �Redoubt unit #9'RU#9 'RU#9_awp I 303.81 9.69, 303.8] 18910 142. 30381 PASS 3&Slot14(RU4,4PB1, Osprey Platform 4PB RedoubtUnit#4 RU4 RU4<11400-20135'> I{ 497.89 65.26 497.89 524.01 57.12 524.01 PASS Osprey Platform ; g 3&Slot 14 (RU4,4PB1, oubt Unit # 4 RU4 PB1 :RU4 PBl <177-15162> 497.89 6526 497.89 524.01 57.12. 524.01 PASS PRB Osprey Platform iLeg#3, Slot 14 (RU4,4PB1, Redoubt Unit #4 RU4 PB2:' RU4 PB2 <10600- 497.89 65.26 497.89 524.01 S7.12 524.01 PASS �4PB2&4A) :PB2 :12986> Osprey Platform 4PB23& lot 14 (RU4,4PB1, Redoubt Unit '.RU4A RU4A <14820 - 18091'> 497.89 65.26 497.89I 52401 57.12, 524.01' PASS Osprey Platforrn'.143, Slot 19 (RUl & 1A) Redoubt Unit #1 RUi RUl MWD <0-15323'> 314.44 6'7.07 16089.10 288.70 58.43 16089.10 PASS `Osprey Platform Leg03, Slot 19 (RUl & IA) Redoubt Unit RU1A 'RUTA (AVM <12263- 31444 67.07 158W 10 328.71 59.09 15889.10 PASS #lA 15050> Osprey Platform Leg#3, Slot 18 (RU2 & 2A) :Redoubt Unit #2'RU2 RU2 (AWP) <0-15325> 89.10 71.54 89.10 212.12 63.09' 16189,10. PASS Osprey Platform iLeg#3, Slot 18 (RU2 & 2A) ;� Redoubt Und 'RU2A RUZA (AVM <1472- 89.10 71.54. 15789.10� 212.12 63.76 15789.10 PASS 15360> Osprey Platform ,LegO, Slot 15 (RU3) RedoubtUnd #3 �RU3 ;RU3 <0-16940'> 89.10 72.11 89.10 208.69 64.01 208.69 PASS Osprey Platform !Leg#3,Slot 17(RUDI) RedloubtUmt 'RUD1 RUD1 (AWP)<0-8611'> 99.10 75.77. 300oo 215.00 67.08 300.00 PASS Osprey Platfonn,Leg#3, Slot 20 (RU5 & 5A) Redoubt Unit #5 RU5 RU5 <0-15438> 178.44 76.12 178.441 191.55 67.88 191.55 PASS Osprey Platform Leg#3, Slot 20(RU5 & 5A) Redoubt RU5A ;U R <11473- 17844. 76.12 178.44� 191.55 67.88�, 191.55 PASS t#SA 0�'AWP) ;Leg#3, Slot 16 (RU6 & 6 OspreyPlatform'PB1) 'RedoubtUnit#6 RU6 RU6 (AWP) <13308- 89.10 77.72 89.101 189.10- 69.76� 189.10�,PASS 16100> Slot 16 (RU6 & 6 'Redoubt Unit #6 fRU6 B1 (AWP) < 0- Osprey Platform PBg#3, PBl l P 89.10 77 72:. 89.101 189.10 6976 189,10. PASS 30 Solids Control and Equipment Item Equipment Specifications Shakers 2- 4 panel (2'x4') shale shakers Desander 3 cone desander Desilter 20 cone desilter Mud Cleaner 4 panel (2'x4') mud cleaner Centrifuge MI-Swaco Drilling Waste Storage Drilling wastes will be either granular solids (cuttings), or liquids (drilling mud or water). Cuttings will be ground and injected into CIE Class 1 non -hazardous disposal well RU-DI. 31 Bit Proposal s'.tiie -heel FAVARa BAKER HUGHES 161, MX-1 (4116.4 nun) • Single Energizer Seal & Bea rift System ISEM)MX utilizes a patented single energizer metal sealing system (SEM) with a more robust design to provide consistency and reliability in high speed drilling and other demanding applications. ■ NIX Motar Drilling Package The MX motor package includes: 1) a premium integral wear pad (P) to reduce leg wear, 2) motor hate facing (M) for additional leg and seal protection, and 3) a centerjel (C) to reduce bit balling. ■ Grease & Lubrication System (Equalizer) Increase reliability with Equalizer packages includes a proven grease formulation better lubricates the seal faces and compensation system increases reliability. ■ Anti -Mud Packing System (Excluder) A secondary static seal eliminates the detrimental effects ofmud packing, creating a seal between the mud and the seal package. Also working against the effects of mud packing are the mud wiper and the cone backface groove, which work in tandem to wipe away mud. ■ Wear/Stabilization Pad (P) Wcarlstabilization pads are steel blocks containing flush mounted carbide inserts added to the outer diameter of a rolling cutter bit to minimize wear on the bit leg or body. Reference Pholo: 11, in. ( 406.4mm) MX-) Product Specillicalions IADC: 115 Rearing' Seal Package: Ball & Roller a Metal Cutting Structure: Inner Raw Radial Wedge ;wBaring Hcel Row Wedge Chisel Gauge Trimmers N?A Gauge Row N,A OD Hardfacing: Motor Nozzle Type. Standard Center Jet Display: FKurVK .Makeup Torque: 28.0 - 32.0 kIhGR (38,0 -43.4 kNm) Connection: 6-5 8 REG API Approx. Shipping Weight: 450 lb ( 204.1 kg) Reference Pan Number: X601C2 Operating Recoinrnendations*: Weight On Bit: 25 - 62.5 klb (I I - 28 to or kdaN) Rotation Speed: For High Speed Rotery/Motor Applications "The ranges of bit w•nght and RPM shown um repr—ntalive oftypical operating parameters, but will not necessarily yield optimum bit life orlowxsl drilling cost. It is not recommended That the upper limits of both wcighl and RPM be run sinmltanmusly. Contact your hxal Hughes Christensen representalive for rwornmcmdutimds in your area. ww%v.bakerhuuhes l,tu 0 2012 Baker I lughes Inecvporrded. All rights reserved. 32 rl.s BAKER HUGHES 12 1/491 QD605X 1.111.2111111) Reference Photo: 12-1/4 in. (311.2mm) QD605X S:vlee Sheet Quantec D TM ■ Application Quantec Directional PDC bits combine the very latest in HCC bit technology: Best in Class cutter technology, superior stability and hydraulic efficiency together with a design philosophy that is tailored to your drilling objectives. Designs are customized to achieve continual performance improvement in the toughest applications while minimizing bit vibration for enhanced tool life. Uiamomt Volume Management Diamond Volume Management (DVM) designs ensure dial neither ROP or stability is compromized in the bit design. Profile and cutter placement are tailored to the application in order to achieve the longest run length at high overall ROP. ■ Quantec Cuners Quanta cutters offer the very latest in technology. Optimized diamond feed and engineered non -planer interfaces combine to give superior wear resistance and outstanding toughness. Speak to your HCC rep for the cutter best suited to your application. ■ Gauge Protectlun High quality TSP material is utilized to give superior w ear resistance and thus long bit runs. Optional Hex -shaped TSP material allows tighter packing for ultra abrasive environments. ■ QD Gauge Design Engineers select gauge length and gauge geometry to meet dogleg, hole quality and system specific requirements. IADC: (v1323 +� Numbcr of Blades: 5 Cutter Quantity (Total, Face): 58,32 Primary Cutter Size .75 in (19.0 mm) Number ofNuzzles: 7 y j L Nozzle Type: SP Fixed TFA 0in'(0.0mm') �. Gauge length 3.5 in (88.8 nun) Junk Slot Area 38 in' (245.1 cnt') Bit Breaker: F Connection: 6-5M API REG Makeup Torque: 7 1 /2" , Bit Sub 37.1 -42.4 kfi-lb (50.3 - 57-5 kNm) Reference Pan Number: N18343 Operating Recommendations*: Hydraulic Flow Rate: 550 - 1200 gpm (2100 - 45501pm) Rotation Speed: For Rotary and Motor Applications Max. Weight On Bit: 38 klb (17 in or kdaN) *I he ranges ofhil weight and W'M shown arc rgrrcaemnlivc of lypiQl operating paminctcrs, but will not necessarily yield optimum bit life or lowest drilling eest. It is not nvommcndod that the upper limits orboth weight and RPM be run simultaneously. Conlao your local Hughes Christensen representative for reuanmendatina5 in you area. www.bakerhuehes.com P 20 12 Bakerflughes Incorlx1rated. All rights reserved. 33 �44row BAKER HUG HES M ,y. 12 1 /4" QD505XX (3 11.2 matt Reference Photo: 12-1/4 in. (311.2inin) QD505XX S:vie sheet Quantec D Im • Application Quantec Directional PDC bits combine the very latest in HCC bit technology: Best in Class cutter technology, superior stability and hydraulic efficiency together with a design philosophy that is tailored to your drilling objectives. Designs are customized to achieve continual performance improvement in the toughest applications while minimizing bit vibration for enhanced tool life. ■ Diamond Volume Management Diamond Volume Management (DV M) designs ensure that neither ROP or stability is compromised in die bit design. Profile and cutter placement are tailored to the application in order to achieve the longest run length at high overall ROP. • Quantec Cutlem Quantec cu0crs offer the very latest in technology. Optimized diamond feed and engineered non -planer interfaces combine to give superior wear resistance and outstanding toughness. Speak to your "CC rep for the cutter best suited to your application. in Gauge Protection High quality TSP material is utilized to give superior wear resistance and thus long bit runs. Optional Hcx-shaped ISP material allows tighter packing for ultra abrasive environments. • QD (:augv Design Engineers select gauge length and gauge geometry to coed dogleg, hole quality and system specific requirements. Product SpC011L.1110111 IADC: h1323 Number of Blades: 5 Cutter Quantity (Total. Face): 96,38 Primary Culler Size .625 in 05.8. nun) Numbcr of Nozzlcs: 8 Nozzle type: SP Fixed TFA 0 in' (0.0 mm') Gauge Length 3.5 in (88.8 mm) Junk Slot Area 30 in' (193.5 ent') Bit Breaker: F Connection: 6-51;8 API REG Makeup Torque: ? 1;2" r Bit Sub 37.1 - 42.4 kft-lb (30.3 - 57.5 kNm) Reference Part Number: N18981 Operating Recommendations*: I ydraulic Flow Rate: 550 - 1200 gpm (2100 - 4550 Ipm) Rotation Speed: For Rotary and Motor Applications Max. Weight On Bit: 40 klb (I8 to or kdaN) •The ranges of bit weight and RPM shown are representative oftypical operating parameters, but will not nocessarily yield optimum bit life or lowest (tilting coat. It is not recommended that the upper limits ol'both weight and RPM he rat simulumatusly. Contact ynm local Hughes Christensen relrrescntative for recommendations in your atra. wwti .bakerhu�hes.cutn 2012 Baker Hughes Invopcvatod. All rights resen•ed. 34 rG.2 BAKER HUGHES S 1/2t'QD506X (21�,.q milt) Reference Photo: 8-1/2 in. (215.9mm) QD506X S:vle Sheet Quantec D TM ■ Application Quantoc Directional PDC bits combine the very latest in "CC hit technology: Best in Class cutler technology, superior stability and hydraulic efficiency together with a design philosophy that is tailored to your drilling objectives. Designs are customized to achieve continual performance improvement in the toughest applications while minimizing bit vibration for enhanced tool life. ■ Diamond Volume Management Diamond Volume Management (DVM) designs ensure [hat neither ROP or stability is compromized in the bit design. Profile and cutter placement arc tailored to the application in order to achieve the longest run length at high overall ROP. ■ Quantec Culters Quantec cutters offer the very latest in technology. Optimized diamond feed and engineered non -planer interfaces combine to give superior wear resistance and outstanding toughness. Speak to your I WC rep for the cutter best suited to your application. • Gauge Protection High quality TSP inaterial is utilized to give superior wear resistance and thus long bit runs. Optional Hex -shaped TSP material allows tighter packing for ultra abrasive environments. ■ QD Gauge Design Engineers select gauge length and gauge geometry to meet dogleg, hole quality and system specific requiretnents. IADC: M 323 Number of Blades: 6 CuncrQuaniity (Total, Face): 57.29 Primary Cutter Size .625 in (15.9 mm) Number of Nozzles: 6 Nozzle Type: MSP Fixed TFA 0 in' (0.0 mm') Gauge Length 4 in (101.6 mm) Junk Slot Area 1 1.016 in' (71.0 cot') Hit Hreaker. Q Conneclion: 4.112 API REG Makeup Torque 51,2"Bit Sub 12.5-13.7k0-Ib(17.0-18.6kNm) 5 34" Bit Sub 16.5 - I8.0 left -lb (22.4 - 24.4 Win) 6" i Bit Sub 17.6 - 19.5 kf1-Ib (23.9 - 26A kNm) Reference Part Number: N 17872 Operating Recommendations*: Hydraulic Flow Rate: 300 - 750 gpm (1 150 - 2850 Ipm) Rotation Speed: For Rotary and Motor Applications Max. Weight On Bit: 30 kab (13 to or kdaN) v the rangy of bit weight and RPM shown arc representative ofiypical opciating parameters, but will not necessarily yield uplinwni bit life or lowest drilling cost. It is not rccommeadal that the upper limits ofboth weight and RPM be run simultaneously. onti ct your local Ilughes Christensen mpmcroafive fbr recommendation, in your area. www,Wkcrhuphcs.coin C 21112 Bulter l lughm Incorporated. All nghis reserved. 35 f S.vI- Sheet reA &2 BAKER HUGHES 8 1/21' QD507FX (21 �'.9 1111111 ■ Application Quantec Directional PDC bits combine the very latest in HCC bit technology: Best in Class cutter technology, superior stability and hydraulic efficiency together with a design philosophy that is tailored to your drilling objectives. Designs are customized to achieve continual performance improvement in the toughest applications while minimizing bit vibration for enhanced tool lira ■ Diamond Volume Management Diamond Volume Management (DVM) designs ensure that neither ROP or stability is compromized in the bit design, Profile and cutter placement are tailored to the application in order to achieve the longest run length at high overall ROP. ■ Quantm Cutters Quantee cutters offer the very latest in technology. Optimized diamond feed and engineered non -planer interfaces combine to give superior wear resistance and outstanding toughness. Speak to your HCC rep for the cutter best suited to your application. • Gouge Protection High quality TSP material is utilized to give superior wear resistance and thus long bit runs. Optional Hex -shaped TSP material allows lighter packing for ultra abrasive environments. ■ QD Cauge Design Engineers select gauge length and gauge geometry to meet dogleg, hole quality and system specific requirements. Reference Photo: 8-1/2 in. (215.9mm) QD507FX IADC: M323 Number of Blades: 7 it Cutter Quantity (Total, Face): 71,31 401, w Primary Cutter Size .62$ in (15.8 mm) Number of Noules: Nozzle Type: 7 � . Fixed TFA Micro SP 0 in' (0.0 mm) Gauge Length 4 in (101.6 mm) Junk Slot Area7.J in' (47.0 cm') fill Breaker: Q iW Connection: 4-1 i2 API REG Makcup lorque: 5 I r "' Bit Sub 12.5 - 13-7 kft-lh (171l - 1 R.6 kNrn) >3i4"Bit Sub 16.5-18.0kfalbt."-4-24.4kNm) 6"* Bit Sub 17.6 - 19.5 kfr-Ih (_t y - 264 kNm) Reference Part Number: X 15309 Operating Recommendations*: Hydraulic Flow Rate: 300 - 750 gpm (1150 - 2850 Iprn) Rotation Speed: For Rotary and Motor Applications Max. Weight On Bit: 33 klb (14 in or kdaN) 'The ranges ol'bit weigh) and Rl'M shown are representative ottypical operating pamlueten, but will not necessarily yield oplimum bit life or Immi drilling cost. h is in[ recommended that the upper limits otboth weight and RPM be run simultaneously. m iacl your local Hughes Christensen representative for recommendations in your area. w N w.bakediuehcs cum C. 2012 Baker Hughes Incorporated, All rights reserved. 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R Mi S S N N �r ^ � 0 O n N h a is ey ao ` N W E W � O Q M W m O m Y Ln taTO ti a Y I cC (� CIN w Cl e-"1 Bettis, Patricia K (DOA) From: Courtney Rust <Courtney.Rust@cookinlet.net> Sent: Thursday, July 17, 2014 3:02 PM To: Bettis, Patricia K (DOA) Subject: Re: Redoubt Shoal Unit #12: Permit to Drill Attachments: RU12 Rev 3.0 Draft Geo Report.xlsx Patricia, Apologies on the missing information. Yes, the objective is the hemlock, I have the guesstimated depths, but I will work on getting you the coordinates I have attached the RU12 Directional Plan. The MASP is 4447 PSI The Max downhole pressure is: 4611 PSI I would assume the slight variance from the 10-401 would be due to a slight change in TVD when they did the directional revisions. Would you like us to submit a new 10-401 form? Courtney Rust Cook Inlet Energy Drilling Engineer Office- 907-433-3809 cell-907-350-0091 CONFIDENTIALITY NOTICE: This e-mail transmission and any document, files or previous e-mail messages attached to it, are confidential. If you are not the intended recipient, or a person responsible for delivering it to the intended recipient, you are hereby notified that any review, disclosure, copying, dissemination, distribution or use of any of the information contained in, or attached to this e-mail transmission is STRICTLY PROHIBITED. If you have received this transmission in error, please notify us immediately by forwarding this message to the original sender or by telephone at 907.350.0091 and then delete this message and its attachments from your computer. From: <Bettis>, "Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: Thursday, July 17, 2014 2:07 PM To: Courtney Rust <courtney.rust@cookinlet. net> Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis(c@alaska.gov. Bettis, Patricia K (DOA) From: Courtney Rust <Courtney.Rust@cookinlet.net> Sent: Monday, August 11, 2014 12:02 PM To: Bettis, Patricia K (DOA) Subject: Re: Redoubt Shoal Unit #12: Permit to Drill Attachments: RU12 SecTwnshpRngeCalcsl.pdf Patricia, We have the coordinates, but the service company had issues with the governmental section so I have am having them look that up and will be complete. The section line offset is: Section 18, 3599.42' FSL 1991.79' FEL I apologize, I thought this had been done, let me finish this today and will get it right back to you. From: <Bettis>, "Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: Monday, August 11, 2014 10:56 AM To: courtney Rust <courtney.rust@cookinlet.net> Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, What is the status of CIE providing the location of Top of Productive Horizon (footage and governmental section information) for Redoubt Shoal Unit #12? Thanks, Patricia From: Bettis, Patricia K (DOA) Sent: Thursday, July 17, 2014 11:07 AM To: courtney Rust (courtney.rust(&cookinlet. net) Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia 1 Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis(c@alaska.gov. Bettis, Patricia K (DOA) From: Courtney Rust <Courtney.Rust@cookinlet.net> Sent: Monday, August 11, 2014 2:28 PM To: Bettis, Patricia K (DOA) Subject: Re: Redoubt Shoal Unit #12: Permit to Drill Patricia, Just in from geology: Sec18 T7NR13W NW Thank you so much! From: <Bettis>, "Patricia K (DOA)" <patricia.bettis@alaska.Rov> Date: Monday, August 11, 2014 10:56 AM To: courtney Rust <courtney.rust@cookinlet.net> Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, What is the status of CIE providing the location of Top of Productive Horizon (footage and governmental section information) for Redoubt Shoal Unit #12? Thanks, Patricia From: Bettis, Patricia K (DOA) Sent: Thursday, July 17, 2014 11:07 AM To: courtney Rust (courtney.rustcookinlet. net) Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Monday, August 11, 2014 10:56 AM To: courtney Rust (courtney.rust@cookinlet.net) Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, What is the status of CIE providing the location of Top of Productive Horizon (footage and governmental section information) for Redoubt Shoal Unit 412? Thanks, Patricia From: Bettis, Patricia K (DOA) Sent: Thursday, July 17, 2014 11:07 AM To: courtney Rust (courtney.rust@cookinlet.net) Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Friday, July 18, 2014 1:08 PM To: 'Courtney Rust' Subject: RE: Redoubt Shoal Unit #12: Permit to Drill Courtney, On plotting the wellbore on a map, it appears that the bottom hole location lies within Section 18, Township 7 North, Range 13 West, S.M. Is this correct? The proposed wellbore survey shows the TVD of the well to be 12809.28'. On the Form 10-401, TVD is stated as 12898'. Please verify which is right. Thank you, Patricia P.S. What is the status of providing the location of "Top of Productive Horizon"? From: Courtney Rust[mailto:Courtney.Rust@cookinlet.net] Sent: Thursday, July 17, 2014 3:02 PM To: Bettis, Patricia K (DOA) Subject: Re: Redoubt Shoal Unit #12: Permit to Drill Patricia, Apologies on the missing information. Yes, the objective is the hemlock, I have the guesstimated depths, but I will work on getting you the coordinates. I have attached the RU12 Directional Plan. The MASP is 4447 PSI The Max downhole pressure is: 4611 PSI I would assume the slight variance from the 10-401 would be due to a slight change in TVD when they did the directional revisions. Would you like us to submit a new 10-401 form? --------------------- Courtnev Rust Cook Inlet Energy Drilling Engineer Office- 907-433-3809 cell-907-350-0091 CONFIDENTIALITY NOTICE: This e-mail transmission and any document, files or previous e-mail messages attached to it, are confidential. If you are not the intended recipient, or a person responsible for delivering it to the intended recipient, you are hereby notified that any review, disclosure, copying, dissemination, distribution or use of any of the information contained in, or attached to this e-mail transmission is STRICTLY PROHIBITED. If you have received this transmission in error, please notify us immediately by forwarding this message to the original sender or by telephone at 907.350.0091 and then delete this message and its attachments from your computer. From: <Bettis>, "Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: Thursday, July 17, 2014 2:07 PM To: Courtney Rust <courtneV.rust@cookinlet.net> Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Courtney Rust <Courtney.Rust@cookinlet.net> Sent: Thursday, July 17, 2014 3:02 PM To: Bettis, Patricia K (DOA) Subject: Re: Redoubt Shoal Unit #12: Permit to Drill Attachments: RU12 Rev 3.0 Draft Geo Report.xlsx Patricia, Apologies on the missing information Yes, the objective is the hemlock, I have the guesstimated depths, but I will work on getting you the coordinates. I have attached the RU12 Directional Plan. The MASP is 4447 PSI The Max downhole pressure is: 4611 PSI I would assume the slight variance from the 10-401 would be due to a slight change in TVD when they did the directional revisions. Would you like us to submit a new 10-401 form? Courtnev Rust Cool. Inlet Energy Drilling Engineer Office- 907-433-3809 cell-907-350-0091 CONFIDENTIALITY NOTICE: This e-mail transmission and any document, files or previous e-mail messages attached to it, are confidential. If you are not the intended recipient, or a person responsible for delivering it to the intended recipient, you are hereby notified that any review, disclosure, copying, dissemination, distribution or use of any of the information contained in, or attached to this e-mail transmission is STRICTLY PROHIBITED. If you have received this transmission in error, please notify us immediately by forwarding this message to the original sender or by telephone at 907.350.0091 and then delete this message and its attachments from your computer. From: <Bettis>, "Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: Thursday, July 17, 2014 2:07 PM To: Courtney Rust <courtney.rust@cookinlet. net> Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, July 17, 2014 11:07 AM To: courtney Rust (courtney.rust@cookinlet.net) Subject: Redoubt Shoal Unit #12: Permit to Drill Good morning Courtney, On Form 10-401, Box 4a, the location at Top of Productive Horizon (footage and governmental section information) is missing. Is the objective for the well Hemlock? Also, the supporting document package to the application is missing a proposed directional survey for the wellbore. Finally, would you please verify on Form 10-401, Box 17, the maximum anticipated surface and downhole pressures. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. WELL NAME: L cx I± 0'1-� $ 12 PTD: , 9I H — J�(� Development _ Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: ?JA O _b� :10i POOL: ,-���� �1�� (�i,�� 6, -) Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL The permit is for a new wellbore segment of existing well Permit (If last two digits No. , API No. 50- - - - in API number are Production should continue to be reported as a function of the original between 60-69) API number stated above. 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 name Pilot Hole ( 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 Spacing Exception conservation 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 samples 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 well) 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 to s to be run. In addition to the well logging program proposed by / c�C r�fy in the attached application, the following well logs are �i / Well Logging alsorequiredfor th1's w II: ,�� — r°`y rLccrJ4J lc� I a Conch fi, l�Iz,l d!�f l 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 4/2014 WELL PERMIT CHECKLIST Field & Pool REDOUBT SHOAL. UNDEFINED OIL - 720100 PTD#: 2141060 Company COOK INLET ENERGY, LLC Initial Class/Type Well Name: REDOUBT SHOAL UNIT 12 Program DEV Well bore seg r DEV / PEND GeoArea 820 Unit 11810 On/Off Shore Off Annular Disposal Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0381203, Surf Loc; ADL0378114, Top Prod Intery & TD. 3 Unique well name and number Yes Redoubt Unit #12 4 Well located in a defined pool No REDOUBT SHOAL, UNDEFINED OIL - 720100 5 Well located proper distance from drilling unit boundary Yes Well spacing conforms with 20 AAC 25.055(a)(1) 6 Well located proper distance from other wells Yes Well spacing conforms with 20 AAC 25.055(a)(3) 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 8/12/2014 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 AS31.05.030(j.1.A),(j.2.A-D) NA 18 Conductor string provided Yes Conductor driven to 215' md. (63ft BML.. Variance approved) Engineering 19 Surface casing protects all known USDWs Yes No aquifers... offshore. 20 CMT vol adequate to circulate on conductor & surf csg Yes 13 3/8" surface casing will be fully cemented... using sting in cement collar. 21 CMT vol adequate to tie-in long string to surf csg No 9 5/8" casing will have cement top at about 11000 ft. 22 CMT will cover all known productive horizons Yes ESP completion... TCP for perfs. Will use packer set at 2000 ft 23 Casing designs adequate for C, T, B & permafrost Yes BTC calculations are provided.. Meet industry SF standards. 24 Adequate tankage or reserve pit Yes Rig has steel pits.. All waste disposed per DEC permit. 25 If a re -drill, has a 10-403 for abandonment been approved NA grassroots well. 26 Adequate wellbore separation proposed Yes Close approach to RU #1 at depth of 11900 ft md. 27 If diverter required, does it meet_ regulations Yes Diverter variance approved per 20 AAC 25.035 (h)(2).. 65 ft to crane. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press= 5767 psi ( 8.6 pgp EMW) Will drill with 8.8-9.8 ppg mud GLS 8/28/2014 29 BOPEs, do they meet regulation Yes Miller rig 34 has 5000 Psi 13 5/8" BOPE 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP =4448 psi Will test BOPE 5000 psi (Casing rams to 3000 psi) 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No H2S not expected. Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S is not expected. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 8.6 ppg EMW; will be drilled using 8.6 to 9.6 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA Abnormal pressures may be present while drilling the Tyonek, as the Tyonek is utilized in the RU-D1 well PKB 8/12/2014 38 Seabed condition survey (if off -shore) NA_ for disposal of cuttings & fluids.. RU #12 will be within 1/2 to 3/4 miile of injection well -at Tyonek depth. 39 Contact name/phone for weekly- progress reports_ [exploratory only) NA_ Development well from platform._ Geologic Engineering Public ESP completion with packer. GIs. Commissioner: Date: Commissioner: Date Commissioner Date (� � 772 - / D S rA 5 /'%&(
