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216-015
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, July 2, 2024 SUBJECT:Mechanical Integrity Tests TO: FROM:Kam StJohn P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-29 MILNE PT UNIT B-29 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/02/2024 B-29 50-029-23564-00-00 216-015-0 W SPT 4393 2160150 1500 537 537 535 536 4YRTST P Kam StJohn 5/23/2024 AOGCC 4 Year MIT-IA, Monobore 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT B-29 Inspection Date: Tubing OA Packer Depth 637 1757 1692 1675IA 45 Min 60 Min Rel Insp Num: Insp Num:mitKPS240524132021 BBL Pumped:1.7 BBL Returned:1.6 Tuesday, July 2, 2024 Page 1 of 1 9 9 9 9 9 9 9 9 9 9 9 99 9 9 9James B. Regg Digitally signed by James B. Regg Date: 2024.07.02 13:14:05 -08'00' MEMORANDUM TO: Jim Regg P.I. Supervisor FROM: Adam Earl Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Friday, May 29, 2020 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC B-29 MILNE PT UNIT B-29 Ste: Inspector Reviewed By., P.I. Sup" Comm Well Name MILNE PT UNIT B-29 API Well Number 50-029-23564-00-00 Inspector Name: Adam Earl Permit Number: 216-015-0 Inspection Date: 5/20/2020 Insp Num: mitAGE200524185741 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well— B-29 Type Inj `rW'TVD 4393 -Tubing 769 772 770 770 ' PTD 2160150 " Type Test SPT Test psi 1500 _ IA 294 1671 1597 1590 " BBL Pumped: 1.9 - IBBL Returned: 2 OA 0 0 0 0 Interval 4vRTST P/F P Notes: MIT IA Friday, May 29, 2020 Page I of I • • c)% Lc"- 0 151 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 0 7 2018 June 5, 2018 SCANNED ,JIJN; RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 0 6 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions,please contact me at 777-8547 or wrivard@hilcorp.com. Sincerely, Wyatt Rivard Well Integrity Engineer Hilcorp Alaska, LLC • • U) a) a) a) a) a) a) a) Cl) Q) a) a) a) a) a) a) 2 ° c c c c c c c c c C C C c J J J J J J J J J J J J J O O Q c c c c c c c c c c C c C f, }, O L L L L L L L L L L L L L U U 0 D O D D D O D D D M D O m _ a) a) a) a) a) Cl) a) a) a) Cl) a) a) a) Q- Q- 3 c O Q c ct Q Q Q � cc w ec C C c c c c c c c c c c c cc L L C a) a) a) a) a) a) () a) a) a) (1) a) a) O O E E E E E E E E E E E E E U U a) a) a) a) a) a) a) a) a) a) (1) a) (1) D O 00000000 (-) 00000 Q Q Q Q Q Q Q Q Q Q Q Q Q o O o Q Q cE U ^ _ a) U LL d 0O 0 0 0 0 0 0 0 0 0 0 0 r c- N N O O O ' ' ' N O V O O C co co co 0 0 0 0 0 oo CO co O O co co 0 C .4' N N N N N N N N N N N N N N 0 co ci 0 O N NN N CO CO CO Cj N N N N N N N N N N N N N ( O LOO U 11: (D 0 0 0 0 0 0 0 0 0 0 0 0 0 N N- O C) N- NI- d) co N- CO O O) N I' CO Cl N r- O O CO CO O O M N d) CO UC) N D 0 0 •-• N- O %- O N- N- O N c d O Cfl CO CO CO CO U) LU O O O O ti N0 NO N N N N NNNNN N N NNNN L O Uy.d 7 -0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (� O O 0 0 0 0 0 0 0 0 O 0 0 0 0 A (.4 0 CO 0) N- CO N- N O O CO CO CO CflO ti N- N- O O O O O O CO N- N a U) O O O O O O O O O O 0 0 0 U < co co co co Cr) co co co Cr) M Co co co Cr) CO N N NNNCNINNNNCNINNNN 0) O) 0) 0) 0) 0) 0) 0) C)) 0) 0) 0) 0) 0) CA N N N N N N N N N N N N N N N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O 0 0 0 0 0 0 0 0 0 0 0 0 0 O I; a a a a a a a a a a a a a. cn cn ii 2 2 2 2 2 2 2 2 z z O 0) O N CO I ti CO co O) O co N N M CO CO M N N d' O O if, m m m m m m —) Y J J J J ' I• • 21 60 15 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 4 7- 7 RECEIVEDrage Tele: AK Ancho907,777-83083 + nilrnrp:tb*ska,i.[.: Fax: 907 777-8510 AUG 0 9 2017 E-mail: snolan@hilcorp.com DATA LOGGED V/15/2017 AOGCC M. K. BENDER DATE 08/09/17 �'"��� V To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-29 scow AUG 8 7Cl1 Production profile and digital data Prints: GR/CCL/PRES/TEMP/SPIN CD1: Hilcorp MPB-29 MEM IPROF 21-3UL-17 7/26/2017 3:58 PM File folder Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: D���t(f?.a�•ftoi,,, tJ�...fG"f��h DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160150 Well Name/No. MILNE PT UNIT B-29 MD 11000 TVD 4402 Completion Date 3/4/2016 REQUIRED INFORMATION DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Mud Log No f Operator HILCORP ALASKA LLC Completion Status 1WINJ Samples No Current Status 1WINJ API No. 50-029-23564-00-00 UIC Yes Directional Survey Yes ✓ ROP-DGR-ADR-EWR-HORIZONTAL FRES 21N MD,DGR-ADR-EWR (data taken from Logs Portion of Master Well Data Maint) Log/ Electr Data Digital Dataset Type Med/Frmt Number Name ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data ED C 26933 Digital Data Log C 26933 Log Header Scans Log Log Run Interval OH / Scale Media No Start Stop CH Received Comments 166 11000 3/16/2016 Electronic Data Set, Filename: MPB-29 FS+ADR FINAL.las 3/16/2016 Electronic File: MPB-29 EWR_ADR MD.cgm - 3/16/2016 Electronic File: MPB-29 EWR_ADR TVD.cgm ` 3/16/2016 Electronic File: MPB-29.txt ' 3/16/2016 Electronic File: MPU B-29 - Definitive Survey.pdf' 3/16/2016 Electronic File: MPB-29 FS+ADR FINAL.dlis 3/16/2016 Electronic File: MPB-29 FS+ADR FINAL.ver 3/16/2016 Electronic File: MPB-29 EWR ADR MD.emf ' 3/16/2016 Electronic File: MPB-29 EWR ADR TVD.emf 3/16/2016 Electronic File: MPB-29_Geosteering+Image . Data.dlis 3/16/2016 Electronic File: MPB-29_Geosteering+Image . Data.ver P 3/16/2016 Electronic File: MPB-29 EWR_ADR MD.pdf -10 3/16/2016 Electronic File: MPB-29 EWR_ADR TVD.pdf 3/16/2016 Electronic File: MPB-29 EWR ADR MD.tif 3/16/2016 Electronic File: MPB-29 EWR ADR TVD.tif ' 0 0 2160150 MILNE PT UNIT SB B-29 LOG HEADERS AOGCC Page 1 of 2 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160150 Well Name/No. MILNE PT UNIT B-29 Operator HILCORP ALASKA LLC MD 11000 TVD 4402 Completion Date 3/4/2016 Completion Status 1WINJ Current Status 1WINJ Well Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments INFORMATION RECEIVED Completion Report V Production Test Information Y / 1 Geologic Markers/Tops COMPLIANCE HISTORY Completion Date: 3/4/2016 Release Date: 2/10/2016 Description Comments: Compliance Reviewed E Directional / Inclination Data 9) Mechanical Integrity Test Information Y /1e) Daily Operations Summary Date Comments API No. 50-029-23564-00-00 UIC Yes Mud Logs, Image Files, Digital Data Y Core Chips Yo Composite Logs, Image, Data Files 6 Core Photographs Y/@ Cuttings Samples Y /6) Laboratory Analyses Y Date: / I q /I — AOGCC Page 2 of 2 Thursday, January 19, 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISb„)N REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon L1 Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Lj Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: CTU Clean-out ❑✓ 2. Name: 4. Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska LLC Development ❑ Exploratory ❑ Stratigraphic❑ Service 0 2 k(4-. `"S 3. Address: 6. API Number: 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-029-23564-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL047437 / ADL047438 MPU B-29 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): JUN 0 6 ZU16 N/A Milne Point Unit/ Scrader Bluff Oil Pool 11. Present Well Condition Summary: AOGCO v Total Depth measured 11,000 feet Plugs measured 10,994 feet true vertical 4,402 feet Junk measured N/A feet Effective Depth measured 10,994 feet Packer measured 4,871 feet true vertical 4,402 feet true vertical 4,395 feet Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 5,068' 9-5/8" 5,068' 4,420' 5,750psi 3,090psi Liner 6,120' 4-1/2" 10,999' 4,402' 9,020psi 8,540psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4-1/2" 12.6#/ L-80/ Supermax 4,879' 4,395' Packers and SSSV (type, measured and true vertical depth) 7" Liner Top Pkr N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 80 0 Subsequent to operation: 0 0 1,549 180 426 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations Exploratory F] Development❑ Service 0 Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas ❑ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ FZ] WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 31 le - Z 3'-I Contact Ted Kramer Email tkramerCcDhilcorp.com Printed Name Bo York Title Operations Engineer i l Signature Phone 777-8345 Date 6/7/2016 & C-4 6 611/1-1� Form 10-404 Revised 5/2015 RBDMS 0- JU'l 0 8 2016 Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP B-29 CTU 50-029-23564-00-00 216-015 5/4/16 5/5/16 Daily Operations: 5/4/2016 - Wednesday Move equipment to location. Hold safety meeting. Discuss and review JSA. Back up CTU to well. Rig up SLB CTU 14 with 2" CT. Start BOPE test. Draw down test complete. Test all BOPE rams, valve, Choke skid valves to 250psi low/4,500psi high. Had one failure. Found small drip on inside reel iron 1502. Tightened fitting. Retested and passed (noted on AOGCC BOPE test form). Continue BOPE testing. Sucessful BOPE test completed. Blow down stack. Pop of well. Isolate all vales and disconnect fluid hoses. Set injector head down on back deck. Install night cap on BOPE. Location secure. Crews off location. 300 bbls of 80 degree seawater in upright for tomorrows intervention. 5/5/2016 - Thursday Fire equipment. Hold safety meeting. Discus and review JSA and job procecure. Pick injector head. Make up CC, DFCV, 2 straight joints all at 2.0" OD. Instal 3.5" jet swirl nozzle. Stab on well. Pressure test stack to 250psi low/4,500psi high. Good PT. Bleed down. Close choke. Open well. 225psi whp. Start RIH at 80 ft/min. Fluid returns to tank. Peak vac truck loading 300 bbls of seawater in upright tank. 4,.980' Noticed counter slipping. inspect with man basket. Come online with fluid at 1 bbl/min increasing rate when passing ICD's. Continue in hole and start seeing significant weight stack at 10,350'. Slow ROP to 16 fpm. Weight breaking back. Getting 1:1 returns. Steady WHP 50 psi. Stop pumping. Reel swivel leaking. Hammer up 1502 connection. Pressure test standing iron. Continue operation. WHP increasing. Check returns. Returns are thick. Choke plugging off. Open both sides of choke and bypass. Start POOH. Stop at 4,500'. Increase rate to 2 bbls min. Returns and WHP back inline with pump rates. Thick oil has cleared or warmed up. Wellbore is flowing on its own. Getting more than 1:1. Continue back in hole pumping across ICD's. Counter continues to slip. Shut down for 20 minutes head up in man basket. Operate for 20 minutes. Reel swivel starts to leak. Break apart and change 1502 gasket. Continue in hole washing across ICD's. Tag PBTD @ 10,968' CT measured depth. Pick up and confirm tag at 10,968'. Start circulating bottoms up (156 bbls). 50 bbls of seawater around corner. Start POOH slowing down across ICD's. Bottoms up complete. Swap to 60/40 freeze protect down CT. 60/40 turning corner at 2,000' lay in 60/40 1:1 from 2,000' to surface. 28 bbls of freeze protect in well bore. SLB at surface. Wellbore closed. Start rigging down. 300 bbls of 80 degree seawater used for operation. 670 bbls returned to surface. -128 bbls of fluid for freeze protect. 302 bbls returned to surface from formation during CT intervention. Move to S-35. 5/6/2016 - Friday No activity to report. 5/7/2016 - Saturday No activity to report. 5/8/2016 -Sunday No activity to report. 5/9/2016 - Monday No activity to report. 5/10/2016 - Tuesday No activity to report. I H Ilileorp Alaska, LLC Orig. KB Elev.: 56.7/ GL Elev.: 23.7' 2a' Cementer @ 1,931' 4-1/2" 35/8" 1 2 3/4 f 5 See ICD Detail Tag @ 10,968' Cr MD 5/5/2016 6 TD =11,000' (MD) / TD = 4,402'(TVD) PBTD =10,994' (MD) / PBTD = 4,402'(TVD) SCHEMATIC Milne Point Unit Well: MPU B-29 Last Completed: 3/5/2016 PTD: 216-015 TREE & WELLHEAD Tree Seaboard 4 1/16" 5M Wt/ Grade/ Conn Seaboard 16 3/4" 3M x 11" 5M Multibowl w/11" x 41/2" EUE Wellhead Top and Bottom; with 4"CIW "H" BPV profile. 2ea 3/8" NPT BPF control lines. 4 1/2" EUE x Supermax x -over on pup OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" 328.8 bbis in 12-1/4" Hole Cement to Surface 8 1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TC II 8.525 Surface 5,068' 0.0732 4-1/2" Liner 13.5 / L-80 / HTTC 3.833 4,871' 10,999' 0.0152 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 1 3.833 1 Surf 1 4,879' 1 0.0152 WELL INCLINATION DETAIL KOP @ 455' Max Hole Angle = 92.4 deg. @ 10,929' MD JEWELRY DETAIL No Depth Item ID 1 2,992' 3-1/2" SLB KBMG GLM w/ 1" pocket and a SBEK-2C latch. 3500 psi shear 2 4,743' XN Nipple profile (No Go 3.72") 3.813 Polish Bore 3 4,869' No -Go Locater on Tieback Assy. 4 4,879' Tieback Shoe 5 4,871' 7" Liner Top Packer 6 10,994' WIV (Ball on Seat/ Closed) ICD DETAIL No Depth ICD Detail 1 5,237.60' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (9) 1/8" nozzles 2 5,871.45' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 3 6,507.42' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 4 7,145.70' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 5 7,778.26' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 6 8,410.17' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 7 9,045.73' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 8 9,681.93' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 9 10,271.65' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 10 10,907.16' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles GENERAL WELL INFO API: 50-029-23564-00-00 Drilled and Cased by Doyon 14 - 3/5/2016 Revised By: TDF 6/7/2016 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission To: Jim ReDATE: Tuesday, May 31, 2016 gg `� P.I. Supervisor �«6? I (I SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC B-29 FROM: Bob Noble MILNE PT UNIT SB B-29 Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry NON -CONFIDENTIAL Comm Well Name MILNE PT UNIT SB B-29 API Well Number 50-029-23564-00-00 Inspector Name: Bob Noble Permit Number: 216-015-0 Inspection Date: 5/30/2016 Insp Num: mitRCNI60530161640 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well TYPe InI I TVD#4393- PTD 1- PTD 2160150 Type TCStI SPT TCSt pTUbin 330 330 331 331 B-29 W0 g 865 ]802 1736 ]727 Interval IINITAL PAF :I OA 4 4 4 4 Notes: Ncw well Tuesday, May 31, 2016 Page I of I Wallace, Chris D (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Wednesday, May 18, 2016 2:43 PM To: Wallace, Chris D (DOA) Subject: MPB-29 (PTD#2160150) Ready For Injection Chris, Water injector MPB-29 (PTD#2160150) was recently drilled and completed at Milne Point. As previously discussed, the well has a highly deviated horizontal completion with a packer 366' MD from the uppermost ICD for which Hilcorp will seek a variance. The well had a passing IA pressure test on the rig to 1500 psi on 3/2/16 and is ready for injection. Hilcorp plans to place the well on injection for stabilization and compliance testing. Plan Forward—Operations 1) Place well on injection. Use caution, annuli are fluid packed. 2) AOGCC MIT-lA when well is on injection and thermally stable. Thank You, Wyatt Rivard I Well Integrity Engineer 0: (907) 777-8547 1 C: (509)670-80011 wrivard0hilcorp.com 3800 Centerpoint Drive, Suite 1400 1 Anchorage, AK 99503 THE STATE Alaska Oil and Gas of A L A K A Conservation ConlIillSSlOi! GOVERNOR BILL WALKER Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-29 Permit to Drill Number: 216-015 Sundry Number: 316-234 Dear Mr. York: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. DATED this Lg!dlay of April, 2016. Sincerely, Cathy P Foerster Chair RBDMS LV APR 19 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED APR 14, 2016 ID r5 rt4` g(1,6 A,OG 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. CTU Clean-out Q• 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: t j 2- Hilcorp Alaska LLC . Exploratory ❑ Development ❑ Stratigraphic ❑ Service Q- 216-015 , 3. Address: 6. API Number: 3800 Centerpoint Dr, Suite 1400 50-029-23564-00-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 477.05 , Will planned perforations require a spacing exception? Yes ❑ No ❑Q MPU B-29 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL0 / ADL047437 �t3� Milne Point Unit / Scrader Bluff Oil Pool . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): • 11,000' 4,402' , 10,994' 4,402' 2,165 10,994' N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 5,068' 9-5/8" 5,068' 4,420' 5,750psi 3,090psi Liner 6,120' 4-1/2" 10,999' 4,402' 9,020psi 8,540psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic , See Attached Schematic 4-1 /2" 12.6#/ L-80/ Supermax 4,879' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 7" Liner Top Pkr and N/A , 4,871(MD)/ 4,395(TVD) and N/A 12. Attachments: Proposal Summary ❑ Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development ❑ Service ❑✓ 14. Estimated Date for 15. Well Status after proposed work: 4/27/2016 Commencing Operations: OIL WINJ WDSPL ❑ ❑ ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Ted Kramer Email tkramer hilco .com Printed Name Bo York Title Operations Manager Ile Signature "�— Phone 777-8345 Date 4/14/2016 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test EY( Mechanical Integrity Test ❑ Location Clearance ❑ Other: �'S Od r Z 1�cj ,k' Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS l-�- APR 19 2016 Spacing Exception Required? Yes ❑ No Subsequent Form Required: 1 •- ®' 1 APPROVED BY Approved by: W44COMMISSIONER THE COMMISSION Date: _ _l 74 Form 10-403 Revised 11/2015 0pRv1Q, 14ALid for 12 months from1� the date of approval. Submit Form and Attachments in Duplicate IHilcorp Alaska, LL' Well Prognosis Well: MP B-29 Date: 4/14/16 Well Name: MP B-29 API Number: 50-029-23564-00-00 Current Status: Water Injection well Leg: Estimated Start Date: 4/27/16 Rig: CTU Reg. Approval Req'd? No Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 216-015 First Call Engineer: Ted Kramer (907) 777-8420 (0) (907) 867-0665 (C) Second Call Engineer: Stan Porhola (907) 777-8412 (907) 331-8228 (C) AFE Number: 1610002C MASP = 2,165 psi (Assumes 9.2ppg EMW from drilling, 1,000 psi treating pressure and 0.1psi/ft gas gradient) Previous Interventions. Rig new well completion. 8.9 PPG brine left in hole. Work to be Performed Coil simulations indicate that 2.0" CT needs to be ran to reach the plug at 10,994'. During rig completion well was drinking fluid at 3 bbls/min while TIH. 55 bbl losses over 24 hrs and 481 bbl losses over total rig completion. Recently, the well was flowed back to a surface tank recovering 10 bbls of freeze protect fluid before wellbore loaded up and died. The recent flow back of well gives a good indication that the wellbore will hold a column of fluid. This cleanout is to be performed with seawater only. / If the well will not circulate, then a combination of N2 and sea water will be utilized to clean out the well according to the Standard Nitrogen Procedure (attaShe.d)• C-G� Necessary notifications will be made prior to pumping nitrogen in this well. Coiled Tubing Procedure: 1. RU CTU. Notify AOGCC 24 hours prior to testing at http://doa.alaska.gov/ogc/form�estWitnessNotif.html 2. PT BOPE to 250psi low/3 si high. Fill out state BOPE test form. 3. Pick up lubricator. Make up CC pull test 25k. Make up MHA, DFCV,CIRC sub, disco. Make up VBR extended reach vibratory tool. 4. Stab on well. Pressure test stack 250/3500psi. 5. Start running in hole circulating down CT at 1.5 -2.0 bbls/min with seawater. Slow down for XN nipple at 4,743' with ID of 3.72" perform weight checks every 1,000' or as necessary. 6. Ensure CT hand straps return tank every 10 bbls pumped. Adjust rates if needed to ensure 1:1 injection / returns. Continue in hole until PBTD @ 10,994' is reached. Make 2 passes up and down over ICM's. 7. Once CT is at PBTD, circulate bottoms up at Max pump rate until wellbore is clean. Continue at Max rate and POOH across ICM's at 10 ft/min while on final trip OOH. Hilcorp Alaska, LL' Well Prognosis Well: MP B-29 Date:4/14/16 8. Check with wellsite operator for plan forward. If well is to be swapped over to injection post CT work do not freeze protect wellbore. IF well is to remain shut in for unknown amount of time Freeze protect well bore from 2,500' to surface with diesel. 9. RDMO. � �\ Contingency: J 1. If unable to obtain 1:1 returns or it is indicated that losses great enough to drop annular velocity is unable to maintain a minimum of 95 ft/min Nitrogen will be used to assist in cleanout. 2. Pressure test N2 lines to 250/4500psi. Ensure return side of choke is hooked up to an open top tank with diffuser tubes. 3. Come online with N2 @ 500-800 scf/min. While pumping seawater at .75-1 bbl/min. This will lighten the hydrostatic head and enable CT to cleanout wellbore if BHP is low. 4. Continue RIH to tag PBTD at 10,994'. Circulated calculated bottoms up to ensure wellbore is clean. POOH. Make sure all N2 is bleed off prior to shutting in well. 5. RDMO. Turn well over to production. ATTACHMENTS: Nitrogen Procedure Nitrogen Flow Diagram Well Schematic Wellhead Diagram Coil Tubing BOP Sketch 14 STANDARD WELL PROCEDURE EliieorpAlaska, UC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 Coil Tubing g Fluid Flow Diagram Cleanout w/ Nitrogen Hileorp Alaska, LLC Orig. KB Elev.: 56.7'/ GL Elev.: 23.7' TD = 11,000' (MD) / TD = 4,402'(TVD) PBTD =10,994' (MD) / PBTD = 4,402'(TVD) '4ilne Point Unit Well: MPU B-29 SCHEMATIC Last Completed: 3/5/2016 PTD: 216-015 TREE & WELLHEAD Tree 5M Seaboard 3-1/8" Wellhead Seaboard MB -225M OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" 328.8 bbls in 12-1/4" Hole Cement to Surface 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TC II 8.525 Surface 5,068' 0.0732 4-1/2" Liner 13.5 / L-80 / HTTC 3.833 4,871' 10,999' 0.0152 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 1 3.833 1 Surf 1 4,879' 1 0.0152 WELL INCLINATION DETAIL KOP @ 455' Max Hole Angle = 92.4 deg. @ 10,929' MD JEWELRY DETAIL No Depth Item 1 2,992' 3-1/2" SLB KBMG GLM w/ 1" pocket and a SBEK- 2C latch. 3500 psi shear 2 4,743' XN Nipple profile (No Go 3.72") 3.813 Polish Bore 3 4,869' No -Go Locater on Tieback Assy. 4 4,879' Tieback Shoe 5 4,871' 7" Liner Top Packer 6 1 10,994' WIV (Ball on Seat/ Closed) ICD DETAIL No Depth ICD Detail 1 5,237.60' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (9) 1/8" nozzles 2 5,871.45' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 3 6,507.42' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 4 7,145.70' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 5 7,778.26' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 6 8,410.17' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 7 9,045.73' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 8 9,681.93' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 9 10,271.65' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 10 10,907.16' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles GENERAL WELL INFO AP I: 50-029-23564-00-00 Drilled and Cased by Doyon 14 - 3/5/2016 Revised By: CJD 3/30/2016 n Hilcorp 47.3 EST 4-1/16 5M 4-1/16 5M — 4-1/16 5M 60.2 57.5 EST EST O O 4-1/16 5M — O p O O O 162 3 ADAPTER, SM-E-CLN EST 11 5M X 4-1/15 5M 11 SM TUBING HANGER SM -E -CL 11 X 4-1/2 25.9 EST 9-5/8 DBL D _ rr.., CASING HANGER SMB -22 16 X9-5/8— W/PRIMARY SEAL 31.6 C EST SWAGE ADAPTER, 20 SOW x 16 SUP ON PIN 2-1/16 5M 16-3/4 3M 2 LP 5M HILCORP ALASKA B-29 4-1/16 5M ADJUSTABLE, CHOKE a 20 CASING _p 9-5/8 CASING . 4-1/2 TUBING 5,000 PSI WELLHEAD & TREE ASSEMBLY NOTE: 20 X 9-5/8 X 4-1/2 DIMENSIONS SHOWN ON THIS DRAWING ARE ESTIMATES ONLY AND CAN VARY SIGNIFICANTLY RESTRICTED CONFIDENTIAL DOCUMENT „w aaa DEPENDING ON RAW MATERIAL LENGTHS.„oC,,,,,,,,,,,,ou,,�,,,,,v,,,,.,, w„ f: RPL 1:10 jn6JAN16 NO GUARANTEE OF STACKUP HEIGHT IS IMPLIED.Y a g� �,� W wo AN 9JSfflm d m�oW1Ud M9! qLY. M ROO1f AYI� m ® DR�WINC NO. DIMENSIONS SHOWN SHOULD BE CONSIDERED wor m max= nc au�wt m �uW n ura� cater No WTW�OMWIKMA owTwN,=„xw P-20954 FOR REFERENCE PURPOSES ONLY. �nm �u z W= m • nim w =WT v WMn .w wm caort a aiswio Mmeui m n Milne Point Unit COIL BOPS MPU B-29 4/14/2016 MPU S-05 20X7% X4% Coil Tubing BOP Lubricator to injection head 2.00" Single Stripper Blind/Shear--]r 1/16 10B1ind/Shear ONE<,> = i=ce �- rmm Pipe } — i '-- { Pipe Crossover spool 4 1/16 10M X4 1/16 5M STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED APR 0 4 2016 O WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas E] SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 20AAC 25.105 20AAC 25.110 GINJ ❑ WINJ Q WAG[] WDSPL ❑ No. of Completions: 1 1b. Well Class: Development ❑ Exploratory ❑ Service E] Stratigraphic Test ❑ 2. Operator Name: Hilcorp Alaska, LLC 6. Date Comp., Susp., or Aband.: 3/4/2016 14. Permit to Drill Number/ Sundry: 216-015 3 3. Address: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 7. Date Spudded: February 17, 2016 15. API Number: 50-029-23564-00-00 4a. Location of Well (Governmental Section): Surface: 5199' FSL, 4287' FEL, Sec 19, T13N, R11 E, UM, AK Top of Productive Interval: 552' FSL, 363' FEL, Sec 13, T13N, R10E, UM, AK Total Depth: 846' FNL, 637' FWL, Sec 13, T13N, R10E, UM, AK 8. Date TD Reached: February 28, 2016 16. Well Name and Number: MPU B-29 9. Ref Elevations: KB: 56.7 GL: 23.7 BF: 23.7 17. Field / Pool(s): Milne Point Unit Schrader Bluff Oil Pool 10. Plug Back Depth MD/TVD: 10,994' MD / 4,402' TVD a 18. Property Designation: ADL047438 (SHL) ADL047437 (TPH/BHL) 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 572006 y- 6023042 Zone- 4 TPI: x- 570710 y- 6023663 Zone- 4 Total Depth: x- 566394 y- 6027504 Zone- 4 11. Total Depth MD/TVD: 11,000' MD / 4,402' TVD 19. Land Use Permit: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: 1,588' MD / 1,580' TVD 5. Directional or Inclination Survey: Yes ❑✓ (attached) No ❑ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary ROP-DGR-ADR-EWR-HORIZONTAL PRIES 21N MD, DGR-ADR-EWR 2IN TVD 23. CASING, LINER AND CEMENTING RECORD CASING WT. PER FT GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 78.6# A-53 Surface 80' Surface 80' Driven Driven 9-5/8" 40# L-80 Surface 5,068' Surface �} 12-1/4" Stg 1 L-187 bbls / T-40 bbls Stg 2 L-226 bbls/T-55.8 bbls 50 bbls 180 bbls 4-1/2" 13.5# L-80 4,871' 10,999' 4,395' 4,402' 8-1/2" Cementless liner w/ [CD's 24. Open to production or injection? Yes a No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): (10) Injection Control Devices See Wellbore Schematic for Detail' COMPLETION �A 4 f I LIP VERIFIED L_L- 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" / 12.6# / L-80 4,879' Tieback Assy. 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No Q Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: N/A Hours Tested: N/A Production for Test Period __Jo. Oil -Bbl: N/A Gas -MCF: N/A Water -Bbl: N/A Choke Size: N/A Gas -Oil Ratio: N/A Flow Tubing Press. N/A Casing Press: N/A Calculated 24 -Hour Rate Jo� Oil -Bbl: N/A Gas -MCF: N/A Water -Bbl: N/A Oil Gravity - API (corr): N/A i ,-Oki X� 0 & �� f Z -1346- AAf,4 Form 10-407 Revised 11/2015 CONTINUED ON PAGE 2 BBDMS Irl. APR 0 5 2016 Submit ORIGINIAL ori`' 28. CORE DATA Conventional C 3): Yes ❑ No ❑✓ Sidewall Cores es ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No 0 If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base 1,589' 1,583' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Sv1 2,632' 2,613' Ugnu MA 4,349' 4,161' Schrader Bluff NA 4,789' 4,370' Schrader Bluff ND 5,173' 4,428' Formation at total depth: 31. List of Attachments: Wellbore Schematic, Composite Drilling and Completion Report, Days vs Depth, MW vs Depth, Definitive Directional Surveys, Casing and Cement Report Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Luke Keller Email: Ikeller hIICOf .com Printed Name: Luke Keller Title: Drilling Engineer (, / Signature: ZL Phone: 777-8395 Date: INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only I K Hilcorp Alaska, LLC Orig. KB Elev.: 56.7/ GL Elev.: 23.7 TD =11,000' (MD) / TD = 4,402'(TVD) PBTD =10,994' (MD) / PBTD = 4,402'(TVD) SCHEMATIC Milne Point Unit Well: MPU B-29 Last Completed: 3/5/2016 PTD: 216-015 TREE & WELLHEAD Tree SM Seaboard 4-1/16" Wellhead I Seaboard MB -225M OPEN HOLE / CEMENT DETAIL 20" 350 sx of Arcticset I (Approx) 12-1/4" 328.8 bbls in 12-1/4" Hole Cement to Surface 8-1/2" Cementless Injection Liner in 8-1/2" hole CASING DETAIL Size Type Wt/ Grade/ Conn Drift ID Top Btm BPF 20" Conductor 78.6 / A-53 / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TC II 8.525 Surface 5,068' 0.0732 4-1/2" Liner 13.5 / L-80 / HTTC 3.833 4,871' 10,999' 0.0152 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / Supermax 1 3.833 1 Surf 1 4,879' 0.0152 WELL INCLINATION DETAIL KOP @ 455' Max Hole Angle = 92.4 deg. @ 10,929' MD JEWELRY DETAIL No Depth Item 1 2,992' GLM w/ 3500 psi shear 2 4,743' XN Nipple profile (No Go 3.72") 3.813 Polish Bore 3 4,869' No -Go Locater on Tieback Assy. 4 4,879' Tieback Shoe 5 4,871' 7" Liner Top Packer 6 10,994' WIV (Ball on Seat/ Closed) ICD DETAIL No Depth ICD Detail 1 5,237.60' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (9) 1/8" nozzles 2 5,871.45' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 3 6,507.42' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 4 7,145.70' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 5 7,778.26' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 6 8,410.17' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 7 9,045.73' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 8 9,681.93' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 9 10,271.65' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles 10 10,907.16' 4-1/2" 17# DWC/C BxP, WOT ICD w/ (10) 1/8" nozzles GENERAL WELL INFO AP l: 50-029-23564-00-00 Drilled and Cased by Doyon 14 - 3/5/2016 Revised By: CJD 3/30/2016 Hilcorp Energy Company Composite Report Well Name: MP B-29 Field: County/State: , Alaska n (LAT/LONG): levation (RKB): 34.08 API #: Spud Date: 2/18/2016 Job Name: 1610002D MP B-29 DRILLING Contractor AFE #: 1610002D AFF $ $4 818 800 Activity Date Ops Summary 2/15/2016 Notify pad operator, PJSM for pulling rig off L-47, with well secure, jack up rig, move off well, stage rig on far side of pad. Clear mats and cleanup around L-47, Pad inspection with DSO, Notify well;PJSM Install rear boosters, continue to mobilize equipment to B -PAD and cleanup around L -pad. Cleanup severe drifting from blow and dig out for rig move.;PJSM with oncoming crew for rig move, move rig to pad entrance. Continue to clear drifts from pad entrance to allow enough room for rig to get by.;Notify security, pad operator, well support and roads and pads. Mobilize rig to MPB-pad, currently between MPC and a-pad.;Hauled 0 bbis to G&I for total = 0 bbis Hauled 0 bbls to B-50 for total = 0 bbis Hauled 0 bbls from 6 mi lake for total = 0 bbis Hauled 0 bbis from L -Pad for total = 0 bbis 2/16/2016 Move rig from A -pad turnoff to B -pad. Note: Send 24 hr notification to AOGCC for Diverter test @ 06:48 on 2/16/2016;PJSM, remove rear boosters, position mats for camp to get around rig. Set diverter equipment behind B-29. align and spot rig over B-29. Move rig camp from L -pad to D -pad, spot and R/U same;Notify DSO, align and spot rig over B-29. Shim and level rig. Note: Rig accepted on MPU -B29 @ 16:00 hrs;Skid rig floor into drilling position. Continue to haul equipment from L-pad.;Skid #2 drag chain into drilling position, connect steam and water, Spot rock washer, Sperry shack, fuel tanks.;N/U diverter system, install diverter tee, set diverter in place, install flanged riser, flow nipple and flowline. M/U high pressure mud lines, Start R/U diverter line exiting out ODS of rig.;Continue to R/U diverter line, ready mud pits for fluid. Spot and connect power to mud, geo and hot shacks. Continue to load out equipment from L-pad,;Spot rig mats in front of beaver slide and hopper loading area, clear snow and ice from cellar box. Install 3" ball valves on conductor. Spot Hilcorp drlg connex. Working on rig acceptance checklist;Load MWD tools into pipe shed.;Hauled 0 bbis to G&I for total = 0 bbls Hauled 0 bbis to B-50 for total = 0 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbis Hauled 0 bbls from L -Pad for total = 0 bbls 2/17/2016 Load MWD BHA in Pipe Shed. Load, strap and tally 160 jts DS -50 DP in pipe shed. Continue Pre Spud Check List. Continue prepping Mud Pits for Spud Mud. Continue trucking equipment from L -Pad to B-Pad.;Pick Up and rack back 5000', 5" DS -50 Drill pipe. Continue to Mob Mud Products from L -Pad to B-Pad.;Test Diverter System. Test gas alarms. Test witness waived by Brian Bixby via email on 2/17/16 @ 7:40 AM. Load pits w/ 580 bbis 8.8 ppg spud mud, load pit 4 w/ water for testing and conductor cleanout;Set Wear Bushing. Pick up and rack back 17 jts HWDP with Jars and 3 NMFC.;PJSM, slip and cut 40' drlg line, reset and test crown saver. Inspect saver sub.;Perform pre spud derrick inspection, Install 15 1/4" wear bushing, R14LDS and mark same.;Pre spud meeting with both crews, DSM, TP, DD, MWD, Rig support, Mud man in attendance. Load tools to rig floor.;M/U 12 1/4" used VMD3 bit, 1.5 deg mud motor, stab, XO, 1 std HWDP, tag ice @ 38',;Break circulation filling stack and lines. PT mud lines to 3500 psi. Note: complete rig acceptance checklist.;Wash and ream pumping 350 gpm, 270 psi, cleaning out conductor from 38' to 144'.;Spud well, swap to 8.8 ppg spud mud while drilling 12 1/4" hole from 144' to 226' pumping 355 gpm, 390 psi. 40 rpm.;Wash and ream, circulate hole clean. Pull into conductor with pumps off. ;Rack 2 stds HWDP back, blow down TD. L/D 12 1/4" cleanout bit, M/U new 12 1/4" VMD -3 bit, MM w/stab, stab, DM, DGR, EWR-P4, PWD, HCIM, TM HOC collars. UBHO sub;;Hauled 8 bbis to G&I for total = 8 bbls P Hauled 0 bbis to B-50 for total = 0 bbis S1OL&- Hauled 0 bbis from 6 mi lake for total = 0 bbls Hauled 67 bbis from L -Pad for total = 67 bbis �a 2/18/2016 Continue to PU MWD Tools and UBHO Sub. Measure MWD to motor offset and line up UBHO to Motor bend.;Plug into MWD/LWD, program tools and perform confidence test while rigging up GYRO.;TIH with NMFC, set down @ 160'. L/D Flex Collar & P/U stand HWDP. Ream f/154'-215' w/40 rpm/350gpm/630psi. Work up & down w/no pumps, small bobble when stab comes up through conductor.;Rack back HWDP & P/U NMFC & set back down again @ 165'. L/D Flex Collar & P/U stand HWDP. Ream f/151'-226' w/40 rpm/350gpm/630psi.;Drill f/226' -245'w/40 rpm/350gpm/630psi.;Wash up & down through tight spot, kill pumps & rotary and work through 2X. Rack back HWDP, TIH w/NMFC to 180' with no issues. Make connection and wash to bottom. Cycle pumps, Shallow test MWD.;Drill 12 1/4" hole f/245'- 275'. w/500 gpm/1170 psi/40 rpm/10-15 WOB. Seeing a lot of gravels at shaker, along w/sticky clay.;Circulate hole clean. Orient to 274 Mag TF, pump up survey, survey showed mag interference. Break off/blow down TD/Run Gyro survey @ 275';Drill 12 1/4" Surface hole from 275' to 365'(90') AROP 90 FPH. 504 GPM, 1170 PSI ON, 980 PSI OFF, 40 RPM, 1-2K TQ ON, 1 K TQ OFF, PU 70K, SO 76K, ROT 75K, WOB 5-15K;MW IN 8.9, MW OUT 8.9, ECD 9.15 PPG;Circulate hole clean. Run Gyro Survey @ 365';Drill 12 1/4" Surface hole from 365' to 458' (93') AROP 186 FPH. 504 GPM, 1170 PSI ON, 980 PSI OFF, 40 RPM, 1-2K TQ ON, 1 K TQ OFF, PU 70K, SO 76K, ROT 75K, WOB 5-15K;Circulate hole clean. Blow down TD. Run Gyro Survey @ 458'. Stand back 1 stand HWDP. RIH with stand of HWDP/Jars. Make connection.; Drill 12 1/4" Surface hole from 458/' to 742'(248') AROP 81.2 FPH. 496 GPM, 1290 PSI ON, 1190 PSI OFF, 60 RPM, 1-2K TQ ON, 1 K TQ OFF, PU 93K, SO 97K, ROT 92K, WOB 15-18K;MW IN 9.0, MW OUT 9.1, ECD 10.1 PPG WATER ON @ 50 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. GYRO Surveys @ every 90'. Last Gyro @ 732';Drill 12 1/4" Surface hole from 742' to 1340' (598') AROP 100 FPH. 500 GPM, 1357 PSI ON, 1260 PSI OFF, 80 RPM, 1-21K TQ ON, 1 K TQ OFF, PU 96K, SO 99K, ROT 96K, WOB 20-25K Release Gyro @ 21:00;Note: Reduce pump rate from 550 to 500 gpm @ 1194' due to losses @ 24 bph and adding water @ 35 bph, increase baracarb from 5 ppb to 12 ppb, staging pump to 530 gpm, 1600 psi;Drill 12 1/4" Surface hole from 1340' to 1873'(533') AROP 89 FPH. 550 GPM, 1620 PSI ON, 1580 PSI OFF, 80 RPM, 2-3K TQ ON, 1 K TQ OFF, PU 115K, SO 131 K, ROT 11 OK, WOB 20-25K;MW IN 9.2, VIS 155 /MW OUT 9.3, VIS 240. ECD 10.5 PPG WATER ON @ 35 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Losses to formation last 24 hrs= 113 bbls, total losses 113 bbls. 3.07 slide hrs, 9.18 rotate hrs. Currently 5' above the line, .07' left of the Iine.;;Hauled 835 bbls to G&I for total = 843 bbis Hauled 0 bbis to B-50 for total = 0 bbls Hauled 0 bbis from 6 mi lake for total = 0 bbis Hauled 564 bbis from L -Pad for total = 631 bbls Drill 12 1/4" Surface hole from 1873', 34'(661') AROP 110 FPH. 495 GPM, 1480 PSI ON, 1430 PSI OFF, 80 RPM, 2-31K TQ ON, 1-21K TO OFF, PU 130K, SO 127K, ROT 130K, WOB 5-20K;MW IN 9.4, VIS 120 /MW OUT 9.4, VIS 166. ECD 10.5 PPG WATER ON @ 35 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES Currently 9.2' above the line, .2.9' right of the Iine.;Note: Encounter 7778 units hydrate gas @ 2165'. Continued drilling ahead with no other hydrates encountered.;Circulate and condition for wiper trip. Blow down Top Drive.;TOH on elevators from 2534' to 740' (BHA) Working through several tight spots on elevators and wipe clean with no issues.; Continue TOH working BHA from 740' to 88' to UBHO sub. L/D UBHO sub. Park @ 88'. Monitor well on trip tank.;Wait on Rig Electrician and Facility Electricians to swap the rig to shore power. Swapped rig to shore power on first attempt with no issues, or having to black out the rig.;Service rig, clean up floor rig floor after wet trip while waiting on shore power.;Pull bit to surface. Clean balled up clay/gravel from bit and stab. Gauge bit. Bit in gauge. TIH on elevators from surface to 1500' with no issues. Fill pipe, blow down TD. Cont to TIH on elevators.;Work past ledges @ 1750', 1785', wash and ream f/ 1835' to 1860', 2167' to 2245', ream last std to bttm @ 2534', tag T of fill on bttm. P/U 130K, S/O 127K, ROT 130K, 1 bbl over calc disp on TIH.;CBU pumping 350 gpm, rotate 40 rpm, work pipe up slow and down fast to prevent side tracking.;Drill 12 1/4" Surface hole from 2534' to 3095'(561') AROP 80 FPH. 500 GPM, 1620 PSI ON, 1560 PSI OFF, 80 RPM, 2-31K TQ ON, 1-2K TQ OFF, PU 140K, SO 131 K, ROT 135K, WOB 5-20K;MW IN 9.4, VIS 157 /MW OUT 9.4, VIS 132. ECD 10.07PPG. WATER ON @ 50 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES.;Losses to formation last 24 hrs= 0 bbls, total losses 113 bbls. 1.55 slide hrs, 7.87 rotate hrs. Currently 15.3' above the line, 0.76' right of the Iine.;Hauled 966 bbls to G&I for total = 1809 bbls Hauled 0 bbls to B-50 for total = 0 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbis Hauled 547 bbls from L -Pad for total = 1178 bbls 2/20/2016 Drill 12 1/4" Surface hole from 3095' to 3570' (475') AROP 79 FPH. 550 GPM, 1850 PSI ON, 1730 PSI OFF, 80 RPM, 4-6K TQ ON, 3/4K TO OFF, PU 157K, SO 145K, ROT 152K, WOB 15-25K;MW IN 9.2, VIS 99 /MW OUT 9.3, VIS 121. ECD 9.8 PPG WATER ON @ 20 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Drill 12 1/4" Surface hole from 3570' to 4040'(470') AROP 78 FPH. 609 GPM, 1850 PSI ON, 1730 PSI OFF, 80 RPM, 4-6K TQ ON, 3/41K TQ OFF, PU 157K, SO 145K, ROT 152K, WOB 15-25K;MW IN 9.2, VIS 99 /MW OUT 9.3, VIS 121. ECD 9.8 PPG WATER ON @ 20 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Note: Crossed UG Coal 1 @ 3636'-3646' (10' Thick), UG Coal 2 @ 3709'-3732' (23' Thick), UG Coal 3 @ 3782'-3790'(8' Thick); Circulate and condition hole for wiper trip. Flowcheck well, Blow down top drive.;POH on elevators f/ 4040' to 3890', attempt to work past with 30k overpull. Pump out f/ 3890' to 3567', attempt to pull on elevators, cont to pump out f/ 3567';to 3377', pull on elevators to 2960', swabbing continues, pump out f/ 2960' to 2690', pull on elevators to 2428'w/ no other issues. Blow down top drive.;TIH on elevators f/ 2428' to 2651', work past tight spot @ 2651' to 2700' passing thru and cleaning up. TIH on elevators f/ 2700' to 3089' attempting to work past several times.;Wash and ream tight hole f/ 3089' to 3270', TIH f/ 3270' to 3959' with no other issues, M/U last stand, wash and ream to bttm @ 4040', no fill, load 35 bbl hi vis sweep in DP;Pump 35 bbl hi vis sweep w/ 10 ppb nut plug around 550 gpm, 1670 psi, rotate 80 rpm, reciprocating pipe slow up and down fast. 3800 stks into circulation well unloaded with cuttings,;Slow pump to 500 gpm, Sweep back 300 stks early, 100% increase in cuttings, mostly balls of clay with small amount of coal, circulate until clean.;Drill 12 1/4" Surface hole from 4040' to 4242' (202') AROP 45 FPH. 570 GPM, 1900 PSI ON, 1800 PSI OFF, 80 RPM, 6.5K TQ ON, 4K TQ OFF, PU 173K, SO 151K, ROT 161K, WOB 5-20K;Note: @ 4200' slow to 500 gpm, 1500 psi, seeing losses of 7-9 bph @ 600 gpm, slowly increase pump back to 550 gpm.;MW IN 9.2+, VIS 88 /MW OUT 9.2+ VIS 109. ECD 9.69 PPG WATER ON @ 35 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Losses to formation last 24 hrs= 9 bbls, total losses 122 bbls. 5.70 slide hrs, 5.98 rotate hrs. Currently 13.7' above the line, 13.3' right of the Iine.;Hauled 926 bbls to G&I for total = 2735 bbls Hauled 0 bbis to B-50 for total = 0 bbls Hauled 0 bbis from 6 mi lake for total = 0 bbls Hauled 995 bbls from L -Pad for total = 2173 bbis Drill 12 1/4" Surface hole from 4242' to 4356'(114') AROP 38 FPH. 570 GPM, 1900 PSI ON, 1800 PSI OFF, 80 RPM, 6.51K TQ ON, 4K TQ OFF, PU 173K, SO 151 K, ROT 161 K, WOB 5-20K;Ddll on hard spot from 4356-4361'. Adjusting parameters as needed, staging WOB up to 30K. Broke through @ 4361' w/motor and TD stall. Pick up, wash and ream through with 10-12 WOB.;Drill 12 1/4" Surface hole from 4361' to 4513'(152') AROP 101 FPH. 600 GPM, 2060 PSI ON, 2020 PSI OFF, 80 RPM, 6-91K TQ ON, 5-8K TQ OFF, PU 176K, SO 147K, ROT 162K, WOB 5-20K;Pumped Hi Vis sweep at 4348' with no substantial change in cuttings increase @ shakers.;Drill 12 1/4" Surface hole from 4513' to 4823' (310') AROP 52 FPH. 600 GPM, 2060 PSI ON, 2020 PSI OFF, 80 RPM, 6-9K TQ ON, 5-8K TQ OFF, PU 176K, SO 147K, ROT 162K, WOB 5-20K;Drill 12 1/4" Surface hole from 4823' to 5078'@ 9 5/8" csg point (255') AROP 46 FPH 600 GPM, 2100 PSI ON, 1960 PSI OFF, 80 RPM, 6-9K TQ ON, 5-81K TQ OFF, PU 185K, SO 140K, ROT 155K, WOB 10-25;Note: TD for 9 5/8 casing point in NC sand @ 5078' per Geo. ( top INC sand @ 503T) 1.7' above the line, 4.7' right of the line. 5.7 slide hrs, 5.98 rotate hrs.;MW IN 9.2, VIS 69 /MW OUT9.2 VIS 69. ECD 9.59 PPG WATER ON @ 35 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Pump 35 bbl hi vis sweep w/ 12 ppb walnut 500 gpm, 80 rpm, reciprocate up slow and down fast, sweep back 500 stks early, 25% increase, mostly clay and sand. Condition mud, lower YP f/ 40 to 27;Rack 1st std back, Flowcheck well, static. Pump out of the hole @ 500 gpm, 1500 psi from 5038' to 2532', Blow down top drive, POH on elevators f/2532' to 2380',;with 25k overpulls, pump out f/ 2380' to 2150', pull on elevators to 1948';Hauled 1271 bbls to G&I for total = 4006 bbis Hauled 938 bbls to B-50 for total = 0 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbis Hauled 0 bbis from L -Pad for total = 3111 bbis 2/22/2016 Continue to POOH on elevators from s' to 740'. (BHA);Work BHA. Rack back 6 stds HWDP w/Jal NMFCs. Plug in and down load MWD. Break off and UD Bit, motor and MWD tools. Bit grade= 2 -2 -WT -A -E -3 -BU -TD, Pull wear bushing. Clean and clear rig floor of BHA.. Kick out BHA from pipe shed. load in casing hanger and landing joint.;R/U 250T 9 5/8" side doors. Continue rigging up casing equipment. M/U Volant CRT. Rig up bail extensions to drilling bails, 250T side doors, false bowl w/ hand slips.;Size up rig tongs and safety clamp. Prep Centralizers.; M/U hanger to landing jt. RIH and land out on depth as per Wellhead Rep (Dean Norris). UD hgr and landing jt.; PJSM with crews on running casing.;M/U shoe track and baker lock connections. Flashlight shoe track and check floats (good). Verify baffle bypass plate installed (Glen Fisher).; Continue to run 9 5/8', 40#, L-80, TC II Casing f/120'. Filling pipe every 5 joints with CRT, Break circulation every 1000'. CBU from 11 15'staging up to 5 bpm. Lost 7 bbls on circulation.; Continue running casing from 1116- 2510', fill every 5 jts, break circulation every 1000'.;Condition mud, 150k P/U, 125k S/O, Reciprocate pipe slow, stage pump up slow, Pump 1 bpm 50 psi increasing to 5 bpm, 130 psi. Reduce vis from 110 to 50, YP 22. No losses while circulating.; Continue running casing from 2510' to 3133' @ jt #76. fill every 5 jts, break circulation every 1000', (install 1 centralizer ea, on 3 jts below ES CMTR).;Ensure tool pinned w/6 opening shear pins, Bakerlock and M/U ES cementer tool per Halliburton rep. Continue running casing from 3136' to 4481', (install 1 centralizer ea, on 3 jts above ES CMTR);With 112 jts in wash 10 remaining jts pumping 1 bpm 750 psi from 4581' to 5030', 17 bbls under calculated displacement on TIH;M/U pup jt, hanger and landing jt, P/U 245K, S/O 120K, Pump 1.6 bpm, 750 psi, land hanger 34.37' in per wellhead rep. shoe @ 5068'. P/U out of hanger 8 inches.; Circulate and condition mud, stage pump from 1.6 bpm, to 3 bpm 250 psi. lower YP from 22 to 17;Hauled 337 bbls to G&I for total = 4343 bbls Hauled 0 bbls to B-50 for total = 0 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbls Hauled 680 bbls from L -Pad for total = 3791 bbls 2/23/2016 Continue to circulate and condition mud, stage pump from 1.6 bpm, to 3 bpm 250 psi. lower YP from 22 to 17.;Land Csg Hgr. Rig down Volant tool, blow down TD. Rig up CMT Head. Witness loading Bypass plug. Rig up circulating iron. Start transfer fluid from pit to tank farm.;Continue circulate through fluted casing hanger @ 5 bpm 240 psi. No losses on circulation. Continue to lower volume in pits to tank farm. Hold PJSM while transfer fluid to tank farm.;PJSM with Halliburton Cementers. Perform cmt job as follows: Pump 5 bbls FW, Pressure test lines to 3500 psi, Pump 60 bbls of spacer at 10.5 ppg @ 4 BPM, Drop by pass plug w/last 2 bbls spacer.;Shut down and load shut off plug. Mix and pump 420 sxs (187 bb1s)(1050 ft) of class G Lead cement at 11.7 ppq. Mix and pump 195 sxs (40 bbls)(224 ft) of class G Tail cement at 15.8 ppp ron Shut off Plug with last 2 bbls cement.; Displace cmt w/ 20 bbis FW f/ Cmt Unit, turn over to rig, pump 172 bbls, 9.3 ppg Mud, pump 80 bbls FW f/cmt unit, turn over to rig, pump 106.4 bbls Mud. Bump plug with 500 psi over FCP.;Bump plug and hold 1600 psi for 5 min. Bleed off 1.5 bbl. Using rig pump, stage pressure up 2700 psi and shear open ES Cementer.;1st Stage Details: Maintain returns through ( outjob. Pump Cement @ 6 BPM Average. Pump Displacement @ 5.5 BPM Average. Calculated Displacement 378 bbl, Actual Displacement 378 bbl.; Check floats. Held with 1.5 bbls back to pits. Total cement circulated to surface 50 bbl + 60 bbl spacer. Final lift pressure 1080 psi @ 3 bpm. 50 bbls lost during job. Cement In Place @ 12:42 hrs.;Circulate bottoms up from ES Cementer @ 1932' bringing 50 bbls of cement to surface. CBU @ 3 bpm, staging up to 5 bpm after bottoms up. Continue to circulate while prepping for 2nd stage.;Continue to circulate while prepping for 2nd stage. Flush stack with contaminate pill. Reload water tank. Clean pits and rock washer. Drain/flush Diverter stack through conductor outlets.;PJSM for pumping 2nd stage cement. DSM witness loading of closing plug. With cement unit Pump 10 bbls water, test lines to 3500 psi, ensure kickouts operating correctly, reset to 1500 psi.;Pump 60 bbls 10.5 ppg spacer with red dye marker 4 bpm. Batch and pump 226 bbls 10.7 ppq Perm -L lead cement 5.5 bpm 270 psi, 210 bbls away see spacer returns. Final 6 bpm, 350 psi,;Pump 55.8 bbls 15.8 ooa tail cement 5 bpm. 900 psi. 24 bbls away see cmt returns. final 5 bpm, 800 psi. 2 bbls cmt left drop closing plug. Note: 76 bbis lost pumping Iead.;Pump 20 bbls water, swap to rig pump. Displace cmt w/126.4 bbls 9.5 ppg spud mud 5 bpm, 260 psi, 106 bbls away slow to 3 bpm 710 psi @ FCP, closing plug bumped @ 126.4 bbls per calculated disp.;Pressure up to 1100 psi over FCP @ 1810 psi and close tool. Hold pressure for 5 min with no bleed off. CIP @ 20:45 hrs. bleed off pressure. 60 bbls spacer and 180 bbls cement returned to surface.;R/D cementers. Drain and Flush stack and lines with 30 bbls black water, R/D cement head and 9 5/8 pup jt on top landing jt.;Back out landing jt, pull same. M/U running tool, Install 16 x 9 5/8 packoff. RILDS per well head rep, UD running tool and landing jt.;R/D casing handling equipment and load out same, Load out cement head.;Flush out flowline pumping 8 bpm. Clean mud pits and rock washer. R/D diverter Iines.;N/D diverter stack, knife valve, continue R/D diverter lines and cleaning pits.;M/U tbg spool, test packoff per wellhead rep, Prep BOPE for N/U.;Hauled 1068 bbls to G&I for total = 5411 bbls Hauled 0 bbls to B-50 for total = 0 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbls s Hauled 373 bbls from L -Pad for total = 4164 bbls 2/24/2016 Continue to N/U Tubing Spool and multi 11" 5M wellhead. Test packoff 500 low w/ 5 min hold (good) and 3000 high w/ 15 min hold (good).;Nipple up BOP -bowl- equipment. Load, strap and tally 5' DP in pipe shed. Change out TO Saver Sub. Rig up Geo Steer Skid to mud manifold.;Rig up to test BOPE with 4 1/2" and 5„ test joints. Set test plug. Attempt shell test. Had gland nut leaking. Pull test plug, drain stack, replace gland packing. set test plug and Obtain good test.;Test BOPE with 4 1/2" and 5" pipe size. Test BOP components 250/3000 w/ 5 min hold. Chart and record same. Test annular 250/2500 w/ 5 min hold. Test gas alarms. Perform Accumulator Test.;Test Witnessed waived by Lou Grimaldi with the AOGCC. All tests pass. No issues.;R/D test equipment. Blow down choke/kill line, choke manifold. Install 10" ID wear bushing. RILDS x 4.;Load tools to rig floor, M/U Cleanout BHA, 8 1/2" used tricone bit, 1.22 deg mud motor, FS, 3 NMFCs, 1 HWDP, jars, 1 HWDP=216.76.; Drift and P/U 33 jts 5" NC50 DP, continue to single in with 21 jts 5" DS50 DP tag cement Q 1919'.: /U top drive, P/U 100K, S/O 100K, ROT 100K, Drill soft cmt f/ 1919' to 1925', Drill plugs, Drill ESC on depth @ 1932' pumping 450 gpm, 40 rpm, 5k wob. exit ESC @ 1935' Note: plug rubber @ shaker.;Close Bag. Do a brief PT on casing to 3000 psi to ensure integrity of ES cementer. bleed off pressure, open bag. Blow down top drive.;Continue to single in the hole from 1948' to 2800';Hauled 1456 bbls to G&I for total = 6867 bbis Hauled 290 bbls to B-50 for total = 290 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbls Hauled 140 bbls from L -Pad for total = 4304 bbls Gg 2/25/2016 Continue to TIH picking up 5" DS -50 DP from 3050'-4838'. Tag soft cement @ 4838'.;Drill soft cement/stringers from 4838'-4913' picking up drill pipe on connections. Drill hard cement from 4913'-4985'(2' above Baffle Adapt)„CBU @ 500 gpm/1530 psi. Break off/blow down top drive. Rig UP 2” HP hose to drill pipe. Open Choke and Kill line, flood same, Close bag.;Test 9 5/8" casing from 4985' to 3000 psi. Chart same for 30 min. Test Good. Rig down test equipment. Blow down Choke, Kill and 2 " HP lines. MU Top Drive.;Drill cement and float equipment from 4985' to 5078'picking up drill pipe on connections. Drill 20' new formation to 5098', while displacing hole over to new 8.8 Mud.;Pull up into shoe. Perform FIT to 12 ppg MW. Blow down top drive, choke and kill lines. Monitor well.;TOH from 5068'- 216'. Work BHA and lay down bit and motor. Bit grade= 1-2-WT-A-E-1-CT-BHA.;M/U BHA #3, 8 1/2" HYC SK616M bit, geopilot, DGR, PWD, ILS, ADR, DM, download MWD data, M/U TM, FS, 3 NMFCs, 1 HWDP, jars, 1 HWDP= 269.23',;Surface test MWD. Unable to get a readable surrey, troubleshoot same, Blow down top drive.;TIH w/ 11 stds 5" NC50 DP from 351' to 1305';Shallow hole test MWD, reboot MWD surface computer, able to get a good survey. BD top drive,;Single in with 18 jts DS50 DP from 1305' to 1871', continue to RIH w/ stands from derrick to 4890', fill pipe every 2000' Correct displacement on trip in.;Monitor well. PJSM, install FOSV, slip and cut 52' drlg Iine,;Service top drive, blocks and drawworks. UD FOSV. Reset and test crown saver.;Continue RIH from 4980', M/U last std and top drive. Break circulation, P/U 174K, S/O 130K, ROT 155K, tag F/C @ 5024', ream FC, tag shoe @ 5065', ream shoe, ream to bttm @ 5098'; Hauled 784 bbls to G&I for total = 7651 bbls Hauled 0 bbls to B-50 for total = 290 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbls Hauled 188 bbis from L -Pad for total = 4492 bbls 2/26/2016 Drill 8 1/2" hole section from 5098' to (641') AROP 106.8 FPH. 496 GPM, 1180 PSI ON, 1060 PSI OFF, 80 RPM, 9-1 OK TO ON, 8-9K TO OFF, PU 170K, SO 115K, ROT 144K, WOB 8-14K.;MW IN 8.8, VIS 44 /MW OUT 8.8, VIS 44. WATER ON @ 10 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Note: Adjust parameters as needed while drilling to mitigate pipe bounce.;Drill 8 1/2" hole section from 5739' to 6304' (511') AROP 85 FPH. 450/500 GPM, 1310 PSI ON, 1130 PSI OFF, 75 RPM, 9-1 OK TO ON, 8-9K TO OFF, PU 174K, SO 115K, ROT 140K, WOB 8-14K.;MW IN 8.8, VIS 44 /MW OUT 8.9, VIS 44. WATER ON @ 10 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Drill 8 1/2" hole section from 6304' to 6950'(646') AROP 108 FPH. 450 GPM, 1300 PSI ON, 1180 PSI OFF, 80 RPM, 10-12K TO ON, 9-10K TO OFF, PU 175K, SO 105K, ROT 140K, WOB 10-12K.;Note: @ 6580', pump 10 bbl hi vis sweep, followed with 20 bbl mud, pump remaining 15 bbl sweep. Sweep back on time, 200% increase, mostly fine sand.;MW IN 8.8, VIS 44 /MW OUT 8.9, VIS 48. ECD 9.9 WATER ON @ 15 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES.;Drill 8 1/2" hole section from 6950' to 7573'(623') AROP 104 FPH. 450 GPM, 1210 PSI ON, 1180 PSI OFF, 80 RPM, 11-13K TO ON, 10-11 K TO OFF, PU 195K, SO 95K, ROT 140K, WOB 10-13K.;MW IN 8.8+, VIS 47 /MW OUT 8.9+, VIS 52. ECD 10 WATER ON @ 15 BPH, BOTH CENTRIFUGES AND MUD CLEANER RUNNING. CURRENTLY NO LOSSES;Note: @ 7339' pump tandem 30 bbl Lo vis / 30 bbl 10.3 ppg weighted sweep, back on time, 100% increase, mostly sand, some clay. Currently 3.24' above the line, 22.80' right of the Iine.;Hauled 399 bbls to G&I for total = 8050 bbls Hauled 0 bbls to B-50 for total = 290 bbis Hauled 0 bbis from 6 mi lake for total = 0 bbis Hauled 442 bbls from L-Pad for total = 4934 bbis 2/27/2016 Drill 8 1/2" hole section from 7573' to 8380'(807') AROP 134.5 FPH. 500 GPM, 2000 PSI ON, 1290 PSI OFF, 85 RPM, 15K TO ON, 12K TO OFF, PU 190K, SO 78K, ROT 140K, WOB 10-13K.;MW IN 8.8, VIS 44 /MW OUT 8.8, VIS 44. ECD 10.16 WATER ON @ 30 BPH, BOTH CENTRIFUGES RUNNING CURRENTLY NO LOSSES Crude oil in returns w/gas @ 3500u-4500u 'Work 90' of pipe rotating 80-90 rpm/600g pm/1 700 psi, pump tandem 30 bbl Lo vis / 30 bbl 10.3 ppg weighted sweep, back on time, 100% increase, mostly sand, some clay. Max gas @ 6130u.;Drill 8 1/2" hole section from 8380' to 9031' (651') AROP 144.6 FPH. 450-500 GPM, 1540 PSI ON, 1480 PSI OFF, 85 RPM, 16-18K TQ ON, 12K TO OFF, PU 200K, SO 70K, ROT 142K, WOB 11-13K.;MW IN 9.1, VIS 44 /MW OUT 9.1, VIS 44. ECD 9.96 WATER ON @ 30 BPH, BOTH CENTRIFUGES RUNNING Estimated 2.5 bph losses while drilling. Note Increase MW from 8.8 to 9.1 over several circulations.; Drill 8 1/2" hole section from 9031' to 9310' (279') AROP 62 FPH. 500 GPM, 1560 PSI ON, 1500 PSI OFF, 90 RPM, 16-18K TO ON, 13K TO OFF, PU 205K, SO 70K, ROT 136K, WOB 8-10K.;MW IN 9.1, VIS 41 /MW OUT 9.1, VIS 43 ECD 10.46 WATER ON @ 15 BPH, BOTH CENTRIFUGES RUNNING. Losses approx 6 bph.;Work 90' of pipe rotating 80-90 rpm/600gpm/1700 psi, pump tandem 30 bbl Lo vis / 30 bbl 10.3 ppg weighted sweep, back on time, 100% increase, mostly sand, little clay. Max gas @ 6087u.;Drill 8 1/2" hole section from 9310' to 9886' (576') AROP 88.6 FPH. 500 GPM, 1560 PSI ON, 1500 PSI OFF, 80 RPM, 16-17K TO ON, 13-15K TO OFF, PU 205K, SO 70K, ROT 137K, WOB 8-10K.;MW IN 9.1, VIS 41 /MW OUT 9.1, VIS 43 ECD 10.32. WATER ON @ 15 BPH, BOTH CENTRIFUGES RUNNING. Currently no Iosses.;Daily losses to formation 65 bbls, total losses, 307 bbls. Currently 13.83' below the line, 17.04 right of the Iine.;Hauled 458 bbis to G&I for total = 8508 bbis Hauled 0 bbls to B-50 for total = 290 bbis Hauled 0 bbls from 6 mi lake for total = 0 bbls Hauled 579 bbls from L-Pad for total = 5513 bbls 2/28/2016 Drill 8 1/2" hole section from 9886' to 10,362'(79.3') AROP 88.6 FPH. 520 GPM, 1840 PSI ON, 1800 PSI OFF, 75 RPM, 15-20K TO ON, 15-16K TO OFF, PU 220K, SO 126K, ROT 137K, WOB 8-15K.;Adjust parameters as needed to drill concretions.;MW IN 9.1, VIS 40 /MW OUT 9.1, VIS 40. ECD 10.16 WATER ON @ 30 BPH, BOTH CENTRIFUGES RUNNING Crude oil in returns w/Max Gas @ 5570u. Note: Geoligist extend TD to 11,000';Drill 8 1/2" hole section from 10362'to 11000'@ TD(638') AROP 159.5 FPH. 525 GPM, 1930 PSI ON, 1890 PSI OFF, 80 RPM, 18-19K TO ON, 17-18K TO OFF, PU 225K, SO 120K, ROT 140K, WOB 8-15K.;Oily returns are increasing. Increase MW to 9,2 ppg @ 10,462' Note: Experiencing detection issues with MWD periodically.; MW IN 9.2, VIS 40 /MW OUT 9.2, VIS 40. ECD 10.24 WATER ON @ 25 BPH, BOTH CENTRIFUGES RUNNING Losses to well @ +-10 bph while drilling.;Final @ TD: 32.6' below the line, 26.54' right of the Iine.;Work 70' of pipe rotating 80-90 rpm/600 gpm/2070 psi, pump tandem 30 bbl Lo vis / 30 bbl 10.3 ppg weighted sweep, back on time, 25% increase, mostly sand, circulate hole clean.;Pump out of the hole 600 gpm, 2100 psi from 11 000'to 10530', flowcheck well static, continue pumping out to 9885';Continue pumping out from 9885' to inside 9 5/8" shoe @ 5000' with no issues.;Daily losses to formation 119 bbis, total losses, 426 bbls.;Hauled 461 bbls to G&I for total = 8969 bbls Hauled 0 bbls to B-50 for total = 290 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbis Hauled 705 bbls from L-Pad for total = 6218 bbls 2/29/2016 Pump 25 bbl hi vis sweep @ 4984' inside 9 5/8 casing, 600 gpm, 1650 psi working pipe 90', w/ 25% increase at shakers, circulate hole clean.; Flow check well for 30 min, 2 bph static loss rate. Pump dry job, blow down top drive.;POH L/D 5" DP from 4984' to 3570', RIH with 12 stds from derrick to 4701', continue POH L/D singles to 2909';Service top drive, blocks and drawworks. Inspect brake Iinkage.;Continue to single out of the hole from 2909' to 269', monitor well 10 min. Note: 17 bbis over calculated displacement on trip out.;L/D BHA #3, jars, MWD tools, download MWD data, L/D Geo steer assembly, bit grade= 1-1-CT-N-X-1-NO- TD;Clear rig floor, R/U 4 1/2" handling equipment, R/U fill up line, ready FOSV with XO, remove drilling BHA from pipeshed.;PJSM with Baker, Vam, Weatherford reps, DSM and crew for running 4 1/2" lower completion. Vam rep on location for HTTC thread M/U.;M/U 4 1/2" Shoe track, xo, 1 jt, ensure float operation. P/U and run 4 1/2", L-80, 13.5# HTTC lower completion per tally and baker rep, Use 8200 ft/lb optimum M/U torque, BOL 401 ONM pipe dope;fill on the fly and every 5 jts w/ 8.9 ppg brine to prevent plugging ICDs, use collar clamp on first 15 jts. RIH to 4995' M/U top drive and xo, P/U 107k, S/O 97k. 10/20/30 rpm, 1 k/1.5k/1.5k torque;Continue RIH from 4995' to 6100', continue to fill on fly and every 5 jts. (10- 4 1/2" ICDs w/ 1/8" nozzles and 143 jts 4 1/2" liner ran) Note: well taking 3 bph while TIH.;Losses to well last 24 hrs, 55 bbis, total losses 481 bbls.;Hauled 571 bbls to G&I for total = 9540 bbis Hauled 0 bbls to B-50 for total = 290 bbls Hauled 0 bbis from 6 mi lake for total = 0 bbis Hauled 197 bbls from L-Pad for total = 6415 bbls Hilc. d Energy Company Composit teport Well Name: MP B-29 Field: County/State: , Alaska i (LAT/LONG): evation (RKB): API #: Spud Date: Job Name: 1610002C MP B-29 COMPLETION Contractor AFE #: 1610002C AFE $: $1,525,200 Activity Date I Ops Summary 3/1/2016 R/D 4.5 running equipment. M/U false table & R/U for running inner stringer M/U XO to triple connect for safety valve.,M/U 2 3/8 slick stick & XO to 2 3/8 PH -6 tubing. Run tubing with false table T/ 6082.7 ' no go depth. Set down 26.5' in on jt 197.,Space out. UD jt 197. M/U two pups. 6.10 & 8.22. Change elevators. M/U swivel on skate chain tong tight. P/U SLZXP LT packer/hanger. M/U to inner string & M/U to liner. Vam rep verified M/U of thread on liner. Good. P/U string. Took 75K over to break over. Up/Dn 135/110,Mix pal mix and install in LT.,RIH on 5" dp from the derrick to 11,000' md. Tag upon depth w/ 10k. P/U 5' after seeing wt indicator break over for final set depth of 10995' MD. TOL @ 4862'. 65k S/O, 205k P/U.,Fill pipe every 10 jts and record P/U and S/O same. PJSM for displacement and stage trucks., Displace 9.2 Baradril-N w/ 8.9# KCL brine. Pumped 3x 40 bbl sapp pills in a attempt to remove wall cake from wellbore. Saw no wall cake w/ sapp pill @ surface. Circulate @ 2.7 BPM w/ 1430 psi, 11% flow. Max allowable psi 1500 as per BOT rep. 21 bbl loss during displacement.,Hauled 285 bbls G&I for total = 9825 bbls Hauled 0 bbls to B-50 for total = 290 bbls Hauled 0 bbls from 6 mi lake for total = 0 bbls Hauled 59 bbls from L -pad for total = 6474 bbls Daily losses 41 bbls for total losses to formation = 522 bbls 3/2/2016 2nd displacement with clean 8.9 ppg KCL brine @ 10,995' (final set depth). Pump @ 2.8 bpm, 1460 psi, 13% flow. Max allowable psi 1500 as per BOT rep due to set psi on packer. Mud check showed trace of oil in 1st and 2nd brine displacements., Drop 1.25" phenalic ball. Pump down @2-3 bpm. Seated @ 530 stks. Psi up to 3000 then stage up to 4100 psi and hold. Felt running tool shift @ 3400 psi. Bleed off psi, psi up on annulus to test packer (1500 psi w/ 10 min hold). Packer tested w/ no issues. Chart and record same. Bleed off.,Blowdown choke, TDS, and kill. POOH F/ 10995'- T/ 9824' MD.,Service drawworks/ST-80 and inspect floor equipment.,Continue pulling out of hole standing back 5" F/ 9824'- T/ 7558' MD., Inspect and repair chainlink on drawworks.,Continue trip out standing back F/ 7558'- T/ 6132' MD (Liner running tool). UD liner running tool.,M/U safety jt. Perform kick while tripping drill. 2:32 resp time.,P/U 2 jts 2-3/8" PH6 to replace liner run tool length for inner string. Trip in hole F/ 6132'- T/ 7932' MD. Stacked out w/ 20k @ 7932' MD. Attempt to work past w/ pumps (4 bpm, 2090 psi) No -Go. Decision made to trip out.,Pull out of hole laying down 5" drill pipe F/ 7932'- T/ 6116' MD.,R/U Weatherford casing equipment. M/U xo's on safety jt and stage in shed. Continue trip out of hole laying down 2-3/8" PH6 inner string via double stacks F/ 6116' - T/ 4851' MD (TOL). 71 K P/U, 70K S/O.,Circulate 2x Btm's up @ top of liner +/- @ 4851' MD. Stage up to 4.2 bpm, 2530 psi. Rig down and blowdown circulating equipment., Continue pulling out of hole laying down 2-3/8" PH6 inner string F/ 4851'- T/ 900' MD. 24 bbl loss to formation over calculated for total trip displacement., Hauled 1378 bbls to G&I for total = 11203 bbls Hauled 0 bbls to B-50 for total = 290 bbls Hauled 1967 bbls from 6 mi lake for total = 1967 bbls Hauled 165 bbls from L -pad for total = 6632 bbls Daily losses to formation 31 for total = 553 bbls to well 3/3/2016 POOH & UD 2 3/8 inner string & mule shoe. Inspect. Good.,RIH with 5" DP from derrick to 3300'. Slip & cut drilling line. POOH UD 5" DP F/ 3300 Well lost 18 bbl while tripping DP. Monitor well. Slight Ioss.,M/U running tool. Drain stack. Pull WB. Well started flowing @ 9 bph. Fill stack & well started losing again. 14.3 psi difference of HP.,PJSM, Change handling equipment to 4.5". P/U 7" seal assembly 3 joints & XN nipple. RIH with 4.5 12.6# supermax tubi TQ 3500 opt. T/ 4837' MD.,From 4837' washed do @ 1 bpm, 40 psi. Seals engaged @ 4871'. Flow out ceased but saw no increase in pump psi. SD pumps and continue S/O to final landout depth on No -Go @ 4871' MD w/ 12k set do wt. Pull out of hole and UD jt #146-148. M/U 15' pup, 8' pup then M/U jt #146. M/U xo. C/O elevators and M/U hanger w/ 5" dp landing jt.,Line up and reverse circulate to spot corrosion inhibitor. Pump via kill w/ annular closed taking returns up tbg @ 4 bpm, 90 ` \/b psi. Pump 110 bbls 1 % baracor 100 then chase with 173 bbls brine (8.9 ppg for both). 92 bbls loss for total displacement. SD pumps, bleed back 5 bbls and J� �w trending down.,Open annular. Saw slight flow with initial rate of 3.5 bpm trending to 1.2 bpm over next 30 min and continually decreasing. Continue operations while monitoring returns via trip tank. S/O and landout hanger on depth as per Cameron Rep (Greg Ruge). Final spaceout and landout depth 4868.81' from No - Go to surface. RILDS. B/D TDS. B/O and laydown landing jt. 35k string wt in wellhead.,Shut blinds. R/U and pump down annulus w/ injection line. Test 9 5/8" casino to 3k w/ 30 min hold. Psi up @ .5 bpm, w/ 4 bbls total pumped to final shut in psi of 3050 psi. 30 min hold w/ final psi 3010. Chart and record same. 3. bbls bleed back to trip tank.,Psi up on 9 5/8" x 4 1/2" annulus @ .5 bpm to 3550 psi. Saw GLM shear @ 3550 psi. Establish circulating reversing @ 2 bpm, 500 psi - 3 bpm, 1400 psi for upcoming freeze protect.,Set TWC. N/D BOP stack.,Hauled 104 bbls to G&I for total= 11307 bbls Hauled 150 bbls to B-50 for total = 440 bbls Hauled 0 bbls from Vern lake for total= 1967 bbls gyp, Hauled 48 bbls from L -Pad for total = 6680 bbls /• _ Daily losses to formation 54 bbls for total = 607 bbls 3/4/2016 N/D BOPs, N/U adaptor flange & tree. Test void to 250/3000 psi good. Test tree to 5000 psi. Good. Pull TWC. Open annulus and well flowing @ 9 bph. R/U & pump down annulus with diesel. Pump with rig pumps @ 3 bpm STS. diesel back @ 216 bbl.,R/D circ lines. Blow down all lines & pumps. Secure tree. Clear cellar, Prep to skid floor. Skid floor. Clean pits. Release rig from B-29 @ 1800.,Move rig to B-28. MPB-29 Days vs Depth FINAL 0 500 1000 MPB-29 Actual MPB-29 Plan MPB-29 Stretch Goal 1500 2000 2500 3000 3500 4000 4500 5000 r 5500 CL a 6000 a m 6500 d 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 12000 0 5 10 15 20 25 30 Days s C CL a 0 a L H a /-- MPB-29 MW vs Depth 0 T-, MPB-29 Plan 1000 MPB-29 Actual 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density (ppg) Hilcorp Energy Company Milne Point M Pt B Pad MPB-29 50-029-23564-00-00 50-029-23564-00-00 Sperry Drilling Definitive Survey Report 07 March, 2016 HAt..1 IBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPB-29 Project: Milne Point TVD Reference: B-29 Actual @ 57.54usft Site: M Pt B Pad MD Reference: B-29 Actual @ 57.54usft Well: MPB-29 North Reference: True Wellbore: MPB-29 Survey Calculation Method: Minimum Curvature Design: MPB-29 Database: Sperry EDM - NORTH US + CANADA Project Milne Point, ACT, MILNE POINT 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 Well MPB-29 Well Position +N/ -S 0.00 usft Northing: 6,023,042.84 usft Latitude: 70° 28'23.661 N +E/ -W 0.00 usft Easting: 572,006.48 usft Longitude: 149° 24'42.682 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.70 usft Wellbore MPB-29 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (1) (°) (nT) BGGM2015 2/29/2016 18.76 81.08 57,506 Design MPB-29 Date 3/7120116 Audit Notes: From To Version: 1.0 Phase: ACTUAL Tie On Depth: 33.84 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction 732.00 SRG-MS (MPB-29) (usft) (usft) (usft) (I 791.70 32.80 0.00 0.00 308.69 Survey Program Date 3/7120116 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 732.00 SRG-MS (MPB-29) SRG-MS Surface readout gyro multishot 02/19/2016 791.70 5,032.74 MWD+IFR2+MS+sag (MPB-29) MWD+IFR2+MS+sag Fixed:v2JIFR dec & 3 -axis correction + sag 02/29/2016 5,105.59 10,929.82 MWD+IFR2+MS+sag(2) (MPB-29) MWD+IFR2+MS+sag Fixed:v2:IIFR dec & 3 -axis correction + sag 02/29/2016 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 33.84 0.00 0.00 33.84 -23.70 0.00 0.00 6,023,042.84 572,006.48 0.00 0.00 UNDEFINED 100.00 0.45 105.84 100.00 42.46 -0.07 0.25 6,023,042.77 572,006.73 0.68 -0.24 SRG-MS(1) 167.00 0.58 80.58 167.00 109.46 -0.09 0.84 6,023,042.76 572,007.32 0.39 -0.71 SRG-MS (1) 262.00 0.29 84.01 261.99 204.45 0.02 1.55 6,023,042.87 572,008.03 0.31 -1.20 SRG-MS (1) 358.00 0.85 269.07 357.99 300.45 0.03 1.08 6,023,042.88 572,007.56 1.19 -0.82 SRG-MS (1) 455.00 2.87 274.74 454.94 397.40 0.22 -2.06 6,023,043.04 572,004.42 2.09 1.74 SRG-MS (1) 549.00 4.50 270.95 548.74 491.20 0.47 -8.09 6,023,043.24 571,998.38 1.75 6.61 SRG-MS (1) 636.00 5.30 266.92 635.42 577.88 0.32 -15.52 6,023,043.01 571,990.96 1.00 12.31 SRG-MS (1) 732.00 6.71 273.02 730.89 673.35 0.37 -25.55 6,023,042.97 571,980.93 1.61 20.17 SRG-MS(1) 791.70 6.21 274.38 790.21 732.67 0.80 -32.25 6,023,043.33 571,974.23 0.88 25.67 MWD+IFR2+MS+sag (2) 884.46 6.52 270.99 882.40 824.86 1.28 -42.52 6,023,043.71 571,963.96 0.53 33.98 MWD+IFR2+MS+sag (2) 979.47 6.46 269.22 976.80 919.26 1.30 -53.25 6,023,043.62 571,953.22 0.22 42.38 MWD+IFR2+MS+sag (2) 3/7/2016 1:12:21PM Page 2 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPB-29 Project: Milne Point TVD Reference: B-29 Actual @ 57.54usft Site: M Pt B Pad MD Reference: B-29 Actual @ 57.54usft Well: MPB-29 North Reference: True Wellbore: MPB-29 Survey Calculation Method: Minimum Curvature Design: MPB-29 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) 0 (") (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1,074.27 6.68 266.93 1,070.98 1,013.44 0.93 -64.09 6,023,043.15 571,942.39 0.36 50.61 MWD+IFR2+MS+sag (2) 1,168.63 6.95 268.97 1,164.67 1,107.13 0.53 -75.28 6,023,042.65 571,931.20 0.38 59.09 MWD+IFR2+MS+sag (2) 1,262.40 5.77 275.52 1,257.86 1,200.32 0.88 -85.65 6,023,042.90 571,920.84 1.48 67.40 MWD+IFR2+MS+sag (2) 1,357.42 5.68 275.70 1,352.41 1,294.87 1.81 -95.08 6,023,043.73 571,911.40 0.10 75.34 MWD+IFR2+MS+sag (2) 1,451.80 5.81 278.16 1,446.32 1,388.78 2.95 -104.45 6,023,044.78 571,902.01 0.30 83.38 MWD+IFR2+MS+sag (2) 1,546-31 5.83 279.78 1,540.34 1,482.80 4.45 -113.92 6,023,046.18 571,892.53 0.18 91.70 MWD+IFR2+MS+sag (2) 1,640.20 6.17 269.55 1,633.72 1,576.18 5.22 -123.66 6,023,046.86 571,882.78 1,19 99.79 MWD+IFR2+MS+sag (2) 1,734.48 6.20 267.26 1,727.45 1,669.91 4.93 -133.82 6,023,046.48 571,872.63 0.26 107.53 MWD+IFR2+MS+sag (2) 1,828.95 5.97 267.90 1,821.39 1,763.85 4.51 -143.82 6,023,045.96 571,862.64 0.25 115.08 MWD+IFR2+MS+sag (2) 1,923.11 6.28 269.59 1,915.01 1,857.47 4.29 -153.86 6,023,045.65 571,852.60 0.38 122.78 MWD+IFR2+MS+sag (2) 2,018.31 6.26 269.76 2,009.64 1,952.10 4.24 -164.26 6,023,045.49 571,842.20 0.03 130.86 MWD+IFR2+MS+sag (2) 2,112.06 6.82 255.06 2,102.79 2,045.25 2.78 -174.75 6,023,043.93 571,831.73 1.88 138.14 MWD+IFR2+MS+sag (2) 2,205.02 7.35 239.51 2,195.04 2,137.50 -1.66 -185.21 6,023,039.39 571,821.31 2.13 143.53 MWD+IFR2+MS+sag (2) 2,300.64 9.29 225.52 2,289.66 2,232.12 -10.17 -195.99 6,023,030.77 571,810.62 2.92 146.62 MWD+IFR2+MS+sag (2) 2,394.81 11.81 223.72 2,382.23 2,324.69 -22.47 -208.08 6,023,018.36 571,798.65 2.70 148.37 MWD+IFR2+MS+sag (2) 2,489.79 12.96 218.80 2,475.01 2,417.47 -37.79 -221.47 6,023,002.91 571,785.41 1.64 149.24 MWD+IFR2+MS+sag (2) 2,580.18 13.60 218.98 2,562.98 2,505.44 -53.95 -234.50 6,022,986.63 571,772.53 0.71 149.31 MWD+IFR2+MS+sag (2) 2,674.68 14.09 219.98 2,654.73 2,597.19 -71.40 -248.88 6,022,969.04 571,758.32 0.58 149.63 MWD+IFR2+MS+sag (2) 2,766.36 12.44 218.70 2,743.96 2,686.42 -87.66 -262.23 6,022,952.65 571,745.14 1.83 149.88 MWD+IFR2+MS+sag (2) 2,861.43 11.32 218.90 2,837.00 2,779.46 -102.92 -274.49 6,022,937.28 571,733.02 1.18 149.92 MWD+IFR2+MS+sag (2) 2,955.59 11.58 219.40 2,929.28 2,871.74 -117.41 -286.29 6,022,922.68 571,721.36 0.30 150.07 MWD+IFR2+MS+sag (2) 3,050.79 11.74 221.28 3,022.52 2,964.98 -132.07 -298.75 6,022,907.89 571,709.05 0.43 150.62 MWD+IFR2+MS+sag (2) 3,145.69 11.59 219.44 3,115.46 3,057.92 -146.69 -311.17 6,022,893.16 571,696.77 0.42 151.19 MWD+IFR2+MS+sag (2) 3,240.39 11.71 220.15 3,208.21 3,150.67 -161.38 -323.41 6,022,878.35 571,684.67 0.20 151.55 MWD+IFR2+MS+sag (2) 3,334.88 11.55 238.68 3,300.79 3,243.25 -173.63 -337.68 6,022,865.96 571,670.53 3.94 155.03 MWD+IFR2+MS+sag (2) 3,428.81 12.52 255.21 3,392.68 3,335.14 -181.12 -355.56 6,022,858.30 571,652.72 3.80 164.31 MWD+IFR2+MS+sag (2) 3,523.80 14.98 275.67 3,485.00 3,427.46 -182.54 -377.75 6,022,856.67 571,630.55 5.70 180.74 MWD+IFR2+MS+sag (2) 3,618.62 18.40 291.71 3,575.86 3,518.32 -175.79 -403.87 6,022,863.17 571,604.37 6.02 205.35 MWD+IFR2+MS+sag (2) 3,713.17 23.79 299.59 3,664.05 3,606.51 -160.84 -434.35 6,022,877.82 571,573.75 6.43 238.48 MWD+IFR2+MS+sag (2) 3,807.35 28.15 302.42 3,748.71 3,691.17 -139.54 -469.64 6,022,898.78 571,538.26 4.81 279.35 MWD+IFR2+MS+sag (2) 3,901.85 31.30 304.18 3,830.76 3,773.22 -113.79 -508.77 6,022,924.15 571,498.88 3.46 325.99 MWD+IFR2+MS+sag (2) 3,994.31 36.22 305.61 3,907.61 3,850.07 -84.37 -550.88 6,022,953.15 571,456.50 5.39 377.24 MWD+IFR2+MS+sag (2) 4,089.47 39.94 307.85 3,982.51 3,924.97 -49.24 -597.87 6,022,987.82 571,409.17 4.17 435.88 MWD+IFR2+MS+sag (2) 4,182.59 44.43 309.69 4,051.49 3,993.95 -10.07 -646.58 6,023,026.52 571,360.09 5.00 498.39 MWD+IFR2+MS+sag (2) 4,278.31 48.84 312.13 4,117.21 4,059.67 35.53 -699.12 6,023,071.60 571,307.12 4.97 567.90 MWD+IFR2+MS+sag (2) 4,372.31 54.42 312.13 4,175.53 4,117.99 84.95 -753.75 6,023,120.48 571,252.01 5.94 641.43 MWD+IFR2+MS+sag (2) 4,466.76 57.69 312.05 4,228.27 4,170.73 137.46 -811.89 6,023,172.42 571,193.38 3.46 719.64 MWD+IFR2+MS+sag (2) 4,561.61 60.01 314.35 4,277.33 4,219.79 193.03 -871.04 6,023,227.42 571,133.70 3.21 800.54 MWD+IFR2+MS+sag (2) 4,656.23 64.31 315.37 4,321.51 4,263.97 252.04 -930.32 6,023,285.85 571,073.85 4.64 883.71 MWD+IFR2+MS+sag (2) 4,749.91 69.38 315.06 4,358.33 4,300.79 313.15 -990.98 6,023,346.36 571,012.61 5.42 969.25 MWD+IFR2+MS+sag (2) 317/2016 1:12:21PM Page 3 COMPASS 5000.1 Build 73 S Company: Hilcorp Energy Company Project: Milne Point Site: M Pt B Pad Well: MPB-29 Wellbore: MPB-29 Design: MPB-29 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPB-29 B-29 Actual @ 57.54usft B-29 Actual @ 57.54usft True Minimum Curvature Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing Easting DLS Section (usft) V) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°I100') (ft) Survey Tool Name 4,843.87 74.08 315.34 4,387.78 4,330.24 376.45 -1,053.83 6,023,409.04 570,949.16 5.01 1,057.88 MWD+IFR2+MS+sag (2) 4,938.77 82.08 316.27 4,407.37 4,349.83 442.97 -1,118.50 6,023,474.93 570,883.85 8.48 1,149.94 MWD+IFR2+MS+sag (2) 5,032.74 86.34 316.52 4,416.85 4,359.31 510.66 -1,182.96 6,023,541.98 570,818.75 4.54 1,242.56 MWD+IFR2+MS+sag (2) 5,105.59 85.00 318.82 41422.35 4,364.81 564.35 -1,231.87 6,023,595.20 570,769.32 3.65 1,314.31 MWD+IFR2+MS+sag (3) 5,195.50 85.99 320.98 4,429.41 4,371.87 632.91 -1,289.60 6,023,663.19 570,710.94 2.64 1,402.22 MWD+IFR2+MS+sag (3) 5,290.10 87.47 323.06 4,434.81 4,377.27 707.35 -1,347.72 6,023,737.05 570,652.11 2.70 1,494.12 MWD+IFR2+MS+sag (3) 5,384.72 89.08 325.89 4,437.65 4,380.11 784.31 -1,402.67 6,023,813.47 570,596.43 3.44 1,585.12 MWD+IFR2+MS+sag (3) 5,478.57 91.42 327.27 4,437.25 4,379.71 862.64 -1,454.35 6,023,891.29 570,543.99 2.89 1,674.42 MWD+IFR2+MS+sag (3) 5,572.20 91.61 325.68 4,434.77 4,377.23 940.66 -1,506.04 6,023,968.80 570,491.55 1.71 1,763.54 MWD+IFR2+MS+sag (3) 5,666.67 90.80 324.27 4,432.78 4,375.24 1,018.00 -1,560.25 6,024,045.61 570,436.60 1.72 1,854.20 MWD+IFR2+MS+sag (3) 5,760.67 89.57 322.70 4,432.48 4,374.94 1,093.55 -1,616.18 6,024,120.60 570,379.95 2.12 1,945.07 MWD+IFR2+MS+sag (3) 5,854.94 90.13 320.63 4,432.73 4,375.19 1,167.49 -1,674.65 6,024,193.96 570,320.78 2.27 2,036.93 MWD+IFR2+MS+sag (3) 5,948.71 90.31 318.40 4,432.37 4,374.83 1,238.80 -1,735.52 6,024,264.68 570,259.22 2.39 2,129.03 MWD+IFR2+MS+sag (3) 6,042.75 90.00 316.64 4,432.11 4,374.57 1,308.16 -1,799.03 6,024,333.41 570,195.05 1.90 2,221.95 MWD+IFR2+MS+sag (3) 6,138.15 92.04 316.03 4,430.41 4,372.87 1,377.15 -1,864.88 6,024,401.76 570,128.54 2.23 2,316.48 MWD+IFR2+MS+sag (3) 6,231.89 91.23 313.84 4,427.74 4,370.20 1,443.33 -1,931.21 6,024,467.28 570,061.58 2.49 2,409.62 MWD+IFR2+MS+sag (3) 6,324.67 89.82 313.23 4,426.89 4,369.35 1,507.23 -1,998.47 6,024,530.53 569,993.72 1.66 2,502.06 MWD+IFR2+MS+sag (3) 6,421.20 89.88 311.28 4,427.14 4,369.60 1,572.14 -2,069.91 6,024,594.73 569,921.65 2.02 2,598.40 MWD+IFR2+MS+sag (3) 6,514.81 89.69 308.78 4,427.49 4,369.95 1,632.34 -2,141.58 6,024,654.23 569,849.41 2.68 2,691.98 MWD+IFR2+MS+sag (3) 6,610.49 90.68 307.13 4,427.18 4,369.64 1,691.19 -2,217.02 6,024,712.34 569,773.41 2.01 2,787.64 MWD+IFR2+MS+sag (3) 6,703.98 90.43 305.38 4,426.28 4,368.74 1,746.47 -2,292.40 6,024,766.89 569,697.50 1.89 2,881.04 MWD+IFR2+MS+sag (3) 6,798.38 89.88 302.69 4,426.02 4,368.48 1,799.30 -2,370.62 6,024,818.95 569,618.78 2.91 2,975.12 MWD+IFR2+MS+sag (3) 6,893.26 90.13 303.24 4,426.01 4,368.47 1,850.93 -2,450.23 6,024,869.80 569,538.69 0.64 3,069.53 MWD+IFR2+MS+sag (3) 6,986.74 90.87 303.37 4,425.20 4,367.66 1,902.25 -2,528.35 6,024,920.37 569,460.08 0.80 3,162.59 MWD+IFR2+MS+sag (3) 7,081.97 90.99 304.75 4,423.65 4,366.11 1,955.58 -2,607.23 6,024,972.92 569,380.70 1.45 3,257.49 MWD+IFR2+MS+sag (3) 7,175.76 90.74 303.06 4,422.24 4,364.70 2,007.89. -2,685.06 6,025,024.47 569,302.37 1.82 3,350.94 MWD+IFR2+MS+sag (3) 7,269.03 90.37 306.86 4,421.33 4,363.79 2,061.32 -2,761.49 6,025,077.16 569,225.44 4.09 3,443.99 MWD+IFR2+MS+sag (3) 7,365.06 90.50 308.70 4,420.60 4,363.06 2,120.15 -2,837.38 6,025,135.24 569,148.99 1.92 3,540.00 MWD+IFR2+MS+sag (3) 7,459.05 90.62 309.15 4,419.69 4,362.15 2,179.20 -2,910.50 6,025,193.58 569,075.31 0.50 3,633.99 MWD+IFR2+MS+sag (3) 7,552.60 90.68 310.38 4,418.62 4,361.08 2,239.03 -2,982.40 6,025,252.71 569,002.84 1.32 3,727.51 MWD+IFR2+MS+sag (3) 7,648.56 90.06 310.98 4,418.00 4,360.46 2,301.58 -3,055.17 6,025,314.54 568,929.47 0.90 3,823.41 MWD+IFR2+MS+sag (3) 7,742.77 90.19 311.55 4,417.80 4,360.26 2,363.72 -3,125.98 6,025,375.98 568,858.07 0.62 3,917.53 MWD+IFR2+MS+sag (3) 7,836.89 89.08 312.85 4,418.40 4,360.86 2,426.93 -3,195.71 6,025,438.52 568,787.75 1.82 4,011.47 MWD+IFR2+MS+sag (3) 7,931.84 88.52 312.87 4,420.39 4,362.85 2,491.51 -3,265.29 6,025,502.41 568,717.55 0.59 4,106.14 MWD+IFR2+MS+sag (3) 8,025.62 90.43 312.69 4,421.25 4,363.71 2,555.19 -3,334.12 6,025,565.42 568,648.12 2.05 4,199.68 MWD+IFR2+MS+sag (3) 8,119.88 89.39 311.26 4,421.39 4,363.85 2,618.23 -3,404.19 6,025,627.77 568,577.44 1.88 4,293.78 MWD+IFR2+MS+sag (3) 8,214.04 90.68 312.90 4,421.34 4,363.80 2,681.33 -3,474.07 6,025,690.19 568,506.96 2.22 4,387.77 MWD+IFR2+MS+sag (3) 8,305.10 91.05 312.46 4,419.96 4,362.42 2,743.05 -3,541.01 6,025,751.25 568,439.44 0.63 4,478.60 MWD+IFR2+MS+sag (3) 8,401.96 90.68 312.56 4,418.50 4,360.96 2,808.50 -3,612.40 6,025,816.00 568,367.42 0.40 4,575.23 MWD+IFR2+MS+sag (3) 8,495.81 91.24 312.82 4,416.93 4,359.39 2,872.12 -3,681.37 6,025,878.94 568,297.84 0.66 4,668.84 MWD+IFR2+MS+sag (3) 3/7/2016 1:12:21 PM Page 4 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well MPB-29 Project: Milne Point TVD Reference: B-29 Actual @ 57.54usft Site: M Pt B Pad MD Reference: B-29 Actual @ 57.54usft Well: MPB-29 North Reference: True Wellbore: MPB-29 Survey Calculation Method: Minimum Curvature Design: MPB-29 Database: Sperry EDM - NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1 -S +E/ -W Northing Easting DLS Section (usft) (1) (1) (usft) (usft) (usft) (usft) (ft) (ft) (-/I ow) (ft) Survey Tool Name 8,589.07 89.88 311.96 4,416.02 4,358.48 2,934.99 -3,750.25 6,025,941.14 568,228.37 1.73 4,761.90 MWD+IFR2+MS+sag (3) 8,684.88 90.43 312.54 4,415.76 4,358.22 2,999.41 -3,821.17 6,026,004.86 568,156.84 0.83 4,857.52 MWD+IFR2+MS+sag (3) 8,778.83 90.50 310.77 4,414.99 4,357.45 3,061.85 -3,891.36 6,026,066.61 568,086.05 1.89 4,951.34 MWD+IFR2+MS+sag (3) 8,873.40 90.31 309.53 4,414.33 4,356.79 3,122.82 -3,963.64 6,026,126.88 568,013.19 1.33 5,045.87 MWD+IFR2+MS+sag (3) 8,967.54 90.87 310.58 4,413.36 4,355.82 3,183.40 -4,035.69 6,026,186.75 567,940.56 1.26 5,139.98 MWD+IFR2+MS+sag (3) 9,063.46 90.43 310.21 4,412.27 4,354.73 3,245.56 -4,108.74 6,026,248.19 567,866.92 0.60 5,235.85 MWD+IFR2+MS+sag (3) 9,157.50 90.31 309.85 4,411.66 4,354.12 3,306.04 -4,180.74 6,026,307.97 567,794.34 0.40 5,329.86 MWD+IFR2+MS+sag (3) 9,251.83 90.37 310.36 4,411.10 4,353.56 3,366.81 -4,252.89 6,026,368.03 567,721.62 0.54 5,424.16 MWD+IFR2+MS+sag (3) 9,343.34 89.88 310.00 4,410.90 4,353.36 3,425.85 -4,322.81 6,026,426.39 567,651.14 0.66 5,515.64 MWD+IFR2+MS+sag (3) 9,440.36 90.25 309.88 4,410.79 4,353.25 3,488.13 -4,397.19 6,026,487.94 567,576.16 0.40 5,612.64 MWD+IFR2+MS+sag (3) 9,534.67 89.88 310.55 4,410.68 4,353.14 3,549.02 -4,469.21 6,026,548.13 567,503.57 0.81 5,706.91 MWD+IFR2+MS+sag (3) 9,628.26 90.19 309.91 4,410.63 4,353.09 3,609.47 -4,540.66 6,026,607.87 567,431.54 0.76 5,800.47 MWD+IFR2+MS+sag (3) 9,723.28 91.11 308.96 4,409.55 4,352.01 3,669.82 -4,614.04 6,026,667.51 567,357.59 1.39 5,895.47 MWD+IFR2+MS+sag (3) 9,817.33 91.05 308.50 4,407.78 4,350.24 3,728.65 -4,687.40 6,026,725.62 567,283.67 0.49 5,989.50 MWD+IFR2+MS+sag (3) 9,911.29 90.80 308.66 4,406.26 4,348.72 3,787.24 -4,760.84 6,026,783.49 567,209.67 0.32 6,083.45 MWD+IFR2+MS+sag (3) 10,006.03 90.68 308.68 4,405.04 4,347.50 3,846.43 -4,834.80 6,026,841.96 567,135.15 0.13 6,178.18 MWD+IFR2+MS+sag (3) 10,100.39 90.62 310.07 4,403.97 4,346.43 3,906.29 -4,907.74 6,026,901.10 567,061.64 1.47 6,272.53 MWD+IFR2+MS+sag (3) 10,194.91 90.99 312.74 4,402.64 4,345.10 3,968.79 -4,978.62 6,026,962.91 566,990.17 2.85 6,366.92 MWD+IFR2+MS+sag (3) 10,288.90 89.57 312.75 4,402.18 4,344.64 4,032.58 -5,047.64 6,027,026.02 566,920.54 1.51 6,460.68 MWD+IFR2+MS+sag (3) 10,382.89 88.15 311.61 4,404.05 4,346.51 4,095.68 -5,117.28 6,027,088.43 566,850.30 1.94 6,554.47 MWD+IFR2+MS+sag (3) 10,477.02 88.15 311.87 4,407.09 4,349.55 4,158.31 -5,187.48 6,027,150.38 566,779.51 0.28 6,648.42 MWD+IFR2+MS+sag (3) 10,572.46 89.14 312.05 4,409.34 4,351.80 4,222.10 -5,258.43 6,027,213.48 566,707.95 1.05 6,743.67 MWD+IFR2+MS+sag (3) 10,666.54 90.25 312.40 4,409.84 4,352.30 4,285.33 -5,328.09 6,027,276.02 566,637.68 1.24 6,837.57 MWD+IFR2+MS+sag (3) 10,759.99 90.74 313.00 4,409.04 4,351.50 4,348.70 -5,396.77 6,027,338.72 566,568.41 0.83 6,930.79 MWD+IFR2+MS+sag (3) 10,855.02 91.17 314.20 4,407.45 4,349.91 4,414.22 -5,465.57 6,027,403.57 566,498.97 1.34 7,025.45 MWD+IFR2+MS+sag (3) 10,929.82 92.41 314.78 4,405.12 4,347.58 4,466.61 -5,518.91 6,027,455.44 566,445.14 1.83 7,099.83 MWD+IFR2+MS+sag (3) 11,000.00 92.41 314.78 4,402.17 4,344.63 4,516.00 -5,568.68 6,027,504.34 566,394.90 0.00 7,169.56 PROJECTED to TD brian.wheeler@haliiburton.na�W^ cary.taylor@halliburton.w�.�..« Checked By: com �so� o,� Approved By: con., Date: 3/7/2016 1:1221 PM Page 5 COMPASS 5000.1 Build 73 Lease & Well No. Hilcorp Energy Company CASING & CEMENTING REPORT i MP B-29 -ate Run 23 -Feb -16 County State Alaska Sup, J. Lott / D. Yessak Casing (Or Liner) Detail Csg Wt. On Slips: 65,000 CASING RECORD Jts. Component Surface � Wt. TD 5,078.00 Shoe Depth: 5,068.59 PSTD: 5,024.00 No. As. Delivered 130 No. Jts. Run 122 No. As. Returned 8 Fig. Delivered 5,194.06 Fig. Run 4,869.53 Ftg. Returned 324.53 Length Measurements W/O Threads Ftg. Cut Jt. Ftg. Balance 42.55 RKB 34.08 RKB to BHF RKB to CHF RKB to THF Csg Wt. On Hook: 190,000 Type Float Collar: No. Hrs to Run: Casing (Or Liner) Detail Csg Wt. On Slips: 65,000 Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top 1 SHOE IT 95/8 40.0 L-80 TCII 42.55 5,068.59 5,026.04 2 FC JT 95/8 40.0 L-80 TCII 39.68 5,026.04 4,986.06 3 BAFFLE IT 95/8 40.0 L-80 TCII 41.40 4,987.24 4,947.66 76 ITS 4 THRU 76 95/8 40.0 L-80 TCII 3,012.80 4,947.66 1,934.86 77 CMTR AND 1 IT 95/8 40.0 L-80 TCII 80.48 1,934.86 1,854.38 78 ITS 78 THRU 122 95/8 40.0 L-80 TCII 1,816.46 1,854.38 37.92 79 PUP 95/11 40.0 L-80 TCII 2.70 37.92 35.22 80 HANGER 16 Type: Density (ppg) TCII 0.85 35.22 34.37 Type: Spud Mud Density (ppg) 9.5 Rate (bpm): 5 Volume (actual / calculated): 146.4/146.4 FCP (psi): 710 Pump used for disp: Rig/Halliburton Bump Plug? X Yes No Bump press 1810 Csg Wt. On Hook: 190,000 Type Float Collar: No. Hrs to Run: 13.5 Csg Wt. On Slips: 65,000 Type of Shoe: Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg _ Yes X No 15 Ft. Min. 9.3 PPG Fluid Description: Spud mud Displacement: Liner hanger Info (Make/Model): Type: Mud Density (ppg) Liner top Packer?: -Yes -No Liner hanger test pressure: FCP (psi): 1100 Pump used for disp: Rig/Halliburton Floats Held X Yes _ No Centralizer Placement: 2 @ 10' from each end on shoe jt, 2 @ 10' from each end on FC jt. 1 on every otherjoint from 4906' to 4388'. 1 ea On 3 jts above and below ES cementer. ( 18 total centralizers ) Cement returns to surface? X Yes _No Spacer returns? X Yes _No Vol to Surf: 50 CEMENTING REPORT Date: 2/23/2016 Shoe @ 5068 FC @ 5,024.00 Top of Liner ES Cementer Depth Preflush (Spacer) Type: Spacer Clean Density (ppg) 10.5 Volume pumped (BBLs) 60 J Slurry Class G sity, (ppg) 11.7 Volume pumped (BBLs) 167 Mixing / Pumping Rate (bpm): 6 Slurry Class G WELLHEAD Make Type Serial No. Size W.P. Test head to PSIG MIN OK Remarks: www.wellez.net WellEz Information Management LLC ver. �h r rte amu✓ WW1 Density (ppg) 15.8 Volume pumped (BBLs) 40 Mixing / Pumping Rate (bpm): 6 y Post Flush (Spacer) _rc Type: Density (ppg) Rate (bpm): Volume: u_ Displacement: Type: Mud Density (ppg) 9.3 Rate (bpm): 5.5 Volume (actual / calculated): 378/378 FCP (psi): 1100 Pump used for disp: Rig/Halliburton Bump Plug? X Yes No Bump press 1600 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Retums during job 100 Cement returns to surface? X Yes _No Spacer returns? X Yes _No Vol to Surf: 50 Cement In Place At: 12:42 Date: 2/23/2016 Estimated TOC: 1,932 Method Used To Determine TOC: ES Cementer Depth Stage Collar @ 1931 Type 1AL ES CementE Closure OK Yes Preflush (Spacer) Type: Spacer Clean Density (ppg) 10.5 Volume pumped (BBLs) 60 Lead Slurry Type: Permafrost Density (ppg) 10.7 Volume pumped (BBLs) 226 Mixing / Pumping Rate (bpm): 5.5 Tail Slurry Type: Class G N Density (ppg) 15.8 Volume pumped (BBLs) 55.8 Mixing / Pumping Rate (bpm): 5 Z Post Flush (Spacer) (0J Type: Density (ppg) Rate (bpm): Volume: W h Displacement: Type: Spud Mud Density (ppg) 9.5 Rate (bpm): 5 Volume (actual / calculated): 146.4/146.4 FCP (psi): 710 Pump used for disp: Rig/Halliburton Bump Plug? X Yes No Bump press 1810 Casing Rotated? Yes X No Reciprocated? Yes X No q Returns during job 100 _ Cement returns to surface? X Yes _ No Spacer returns? X Yes -No Vol to Surf: 180 Cement In Place At: 20:45 Date: 2/23/2016 Estimated TOC: 0 Method Used To Determine TOC: Cement Returns WELLHEAD Make Type Serial No. Size W.P. Test head to PSIG MIN OK Remarks: www.wellez.net WellEz Information Management LLC ver. �h r rte amu✓ WW1 11 6015 Maile Sweigart 26 93 3 Alaska North Slope Team C EIV Hilcorp Alaska, LLC 3800 Centerpoint Drive, Ste 1400 Anchorage, Alaska 99503 1161d ,r�, �i:,%k;,. l.t.t Office: 907.777.8473 h�AR 6 2�iiJ msweigart@hilcorp.com ®ATA LOGGED OC M K.SENDER 3� Date: 3/16/16 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 B-29 Prints: ROP-DGR-ADR-EWR-HORIZONTAL PRES 2IN MD, DGR-ADR-EWR 21N TVD E log data CD 1 : Final Well Data Name MPB-29_DATA CD Date modified Type 3/8/201611:51 AM File folder Each folder contains subfolders: Name Gate modified Type CGM 3/8/2016 11:513 AM File fclder Definitive Survey 3;`8:201611:50 AM File folder DUS+LAS 3/8;201611:50 AM File fclder EMF 3/8/201611:51 AM Filefclder Geosteering Data 3/8/201611:51 AM File folder PDF 3/8;`2111611:51 AM File folder TIFF 3.8;'201611:51 AM File folder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Receive �� J� Date: .at2c� a� THE STATE 01ALASKA GOVERNOR BILL WALKER Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 WWW.aogcc.alaska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-29 Hilcorp Alaska, LLC Permit to Drill Number: 216-015 Surface Location: 5199' FSL, 4287' FEL, SEC. 19, TI 3N, R1 IE, UM, AK Bottomhole Location: 1157' FNL, 954' FWL, SEC. 13, RI OE, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced service well. 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. 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 jU day of February, 2016. STATE OF ALASKA A KA OIL AND GAS CONSERVATION COMM i JN PERMIT TO DRILL 20 AAC 25.005 1 a. Type of Work: 1 h. Proposed Well Class- Exploratory - Gas ❑ Service - WAG ❑ Service - Disp ❑ 1 c. Specify if well is proposed for: Drill ❑� , Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service - Winj Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket Q ,- Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC , Bond No. 022035244, YIN -'P V B-29 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 10,552' • TVD: 4421' Milne Point Unit Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 5199' FSL, 4287' FEL, Sec 19, T1 3N, R11 E, UM, AK (SHL) - ADL047438 / (TPH/BHL) - ADL047437 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 532' FSL, 338' FEL, Sec 13, T1 3N, R1 OE, UM, AK N/A 2/15/2016 9. Acres in Propertv: 14. Distance to Nearest Propertv: Total Depth: 1157' FNL, 954' FWL, Sec 13, T13N, R10E, UM, AK ADL047438 - 2544 / ADL047437 - 2560 2635' to nearest unit boundary 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 56.7 . 15. Distance to Nearest Well Open Surface: x- 572006 y- 6023042 Zone -4 GL Elevation above MSL (ft): 23.7 to Same Pool: B-02 1,320' 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 91 degrees Downhole: 1600 - Surface: 1158 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade I Coupling Length MD TVD MD TVD (including stage data) 20" 20" 78.6# A-53 Weld 110' Surface Surface 110' 110' Driven 12-1/4" 9-5/8" 40# L-80 TC -ll 5,187' Surface Surface 5,187' 4,427' Stg 1 - 1,374 ft3 / Stg 2 - 1,688 ft3 8-1/2" 4-1/2" 13.5# L-80 VAM HTTC 5,552' 5,000' 4,410' 10,552' 4,421' Cementless w/ ICD's and Swell Pkrs 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): 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 MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch ❑✓ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Luke Keller Email Ikeller hiicor .com Printed Name Luke Keller Title Drilling Engineer Signature Phone Date 777-8395 Commission Use Only Permit to Drill _ API Number: Permit Approval I See cover letter for other Number: a a./ t' S 50- — 3E64 — 00 —OQ Date: a 11 ( 1 �-p requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methan gas hydrates, or gas contained in shales: Other: 3 pc c le51 Samples req'd: Yes No K] Mud log req'd: Yes ❑ No `� f ^ c HzS measures: Yes No El Directional svy req'd: Yes R No❑ I 111t e. e Spacing exception req'd: Yes ❑ No [ Inclination -only svy req'd: Yes ❑ No[" Post initial injection MIT req'd: Yes [ZNo❑ APPROVED BY Z 40 — l Approved by: COMMISSIONER THE COMMISSION Date: !1IrySubmit Form and Form 10-401 ( evised 11/2015) (MIL V al + A tnths from the date pproval (20 AAC 25.005(g)) Attachments in Duplicate Luke Keller Drilling Engineer Hilrnrp Mai;Aa, LLC January 13th, 2016 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: MPB-29 JAN 15 2016 OGCC Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Dear Commissioner, � f MPU B-29 is a grassroots water injector planned to be drilled in the Schrader Bluff ND sand. B-29 is part of a (2) well pilot program targeting the ND sand. B-29 will be paired with a grassroots producer, B-28. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff ND sand. A lateral section will then be drilled in the reservoir. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately February 15th, 2016,` Doyon Rig #14 will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. WIN Sincerely, .�`� ►✓ Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page i of i C IrpSS I ( 06 � � L Hilcorp Alaska, LLC Milne Point Unit (MPU) B-29 Drilling Program Version 0 Dec 7th, 2015 ff Hilcorp Energy Company Contents Milne Point Drilling Procedure 1.0 Well Summary................................................................................................................................................2 2.0 Management of Change Information............................................................................................................3 3.0 Tubular Program: .......................................................................................................................................... 4 4.0 Drill Pipe Information: .................................................................................................................................. 4 5.0 Casing Inspection............................................................................................................................................4 6.0 Internal Reporting Requirements.................................................................................................................5 7.0 Planned Wellbore Schematic.........................................................................................................................6 8.0 Drilling / Completion Summary....................................................................................................................7 9.0 Mandatory Regulatory Compliance / Notifications.....................................................................................8 10.0 R/U and Preparatory Work.........................................................................................................................10 11.0 N/U 21-1/4" 2M Diverter System.................................................................................................................10 12.0 Drill 12-1/4" Hole Section............................................................................................................................13 13.0 Run 9-5/8" Surface Casing...........................................................................................................................17 14.0 Cement 9-5/8" Surface Casing.....................................................................................................................22 15.0 BOP N/U and Test........................................................................................................................................27 16.0 Drill 8-1/2" Hole Section..............................................................................................................................29 17.0 Run 4-1/2" Injection Liner...........................................................................................................................33 18.0 Run Injection Assembly ...............................................................................................................................36 19.0 RDMO...........................................................................................................................................................36 Doyon 14 Rig Layout....................................................................................................................................44 20.0 Diverter Schematic.......................................................................................................................................37 21.0 BOP Schematic.............................................................................................................................................38 22.0 Wellhead Schematic.....................................................................................................................................39 23.0 Days Vs Depth...............................................................................................................................................40 24.0 Formation Tops............................................................................................................................................41 25.0 Anticipated Drilling Hazards.......................................................................................................................42 26.0 Doyon 14 Rig Layout....................................................................................................................................44 27.0 FIT Procedure...............................................................................................................................................45 28.0 Choke Manifold Schematic..........................................................................................................................46 29.0 Casing Design Information..........................................................................................................................47 30.0 8-1/2" Hole Section MASP...........................................................................................................................48 31.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................................49 32.0 Surface Plat (As Built) (NAD 27)................................................................................................................50 33.0 Offset MW vs TVD Chart............................................................................................................................51 34.0 Drill Pipe Information 5" 19.5# 5-135 DS-50...............................................................................................52 1.0 Well Summary Milne Point Unit B-29 Drilling Procedure Well MPU B-29 Pad Milne Point "B" Pad Planned Completion Type 4-1/2" Injection string Target Reservoir(s) Schrader Bluff "ND" Sand Planned Well TD, MD / TVD 10,552.47' MD / 4,421.5' TVD PBTD, MD / TVD 10,550' MD / 4,421.5' TVD Surface Location (Governmental) 5,199' FSL, 4,287' FEL, Sec 19, TON, RI IE, UM, AK Surface Location (NAD 27 — Zone 4) X=572,006.48, Y=6,023,042.84 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 532' FSL, 338' FEL, Sec 13, T13N, R10E, UM, AK TPH Location (NAD 27) X=570,736.26, Y=6,023,642.74 TPH Location (NAD 83) BHL (Governmental) 1157' FNL, 954' FWL, Sec 13, T13N, RIOE, UM, AK BHL (NAD 27) X=566,714.3, Y=6,027,197.6 BHL (NAD 83) AFE Number 1610002 AFE Drilling Das 22 days AFE Completion Das 5 days AFE Drilling Amount $4,818,800 AFE Completion Amount $1,525,200 AFE Facility Amount $350,000.00 Maximum Anticipated Pressure (Surface) 1158 psig Maximum Anticipated Pressure (Downhole/Reservoir) 1600 psig Work String 5" 19.5# S-135 DS -50 (Weatherford Rental) KB Elevation above MSL: 33 ft + 23.7 ft = 56.7 ft GL Elevation above MSL: 23.7 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Enema Company 2.0 Management of Change Information 11 Hilcorp Alaska, LLC Hilcorp Changes to Approved Pennit to Drill Date: 12-7-2015 Subject Changes to Approved Permit to Drill for MPU B-29 File #: MPU B-29 Drilling and Completion Program Any modifications to MPUB-29 Drilling & Completion Program will be documented and approved below_ Changes to an approved APD will be communicated & approved by the AOGCC. Sec Page Date Procedure Change Approved Approved BY BY Approval: Prepared: Drilling Manager Drilling Engineer Date Date Page 3 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure HilmTEnergy Company 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD in(#/ft) Wt Grade Conn Burst (psi) Collapse (psi) Tension (k -lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 TC -Il 5,750. 3,090 916 8-1/2" 4-1/2" 3.849" 3.75" 4.93" 13.5 L-80 VAM HTTC 9,020 8,540 307 4.0 Drill Pipe Information: Hole OD (in) ID (in) Section TJ ID in TJ OD in(#/ft) Wt Grade Conn M/U Min NIX Max(k-lbs) Tension All 5" 4.276" 3.25" 6.625" 19.5 5-135 GPDS50 36,100 43,100 560k 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit :BB -29 :]Drilling Procedre 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to pmazzolinighilcorp.com , Ike ller e hilcorp.com and cdingerga hilcorp.com 6.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager & Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As -Run" Casing tally to lkeller o,hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to Ikeller@hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 lkeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Vanessa Hughes 907.777.8445 vhughes@hilco .com Drlg Environmental Coord Julieanna Orczewska 907.777.8444 907.715.7060 lorczewska@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com EHS Field Coordinator Jimmy Watson 907.777.8450 907.744.7376 jiwatson@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Version 1 Jan, 2016 Hilcorp Energy Company 7.0 Planned Wellbore Schematic SCHEMATIC. 2 3 4 1 20" Milne Point Unit B-29 Drilling Procedure Milne Point Uni tAjcll NIPB-29 PTD API JEWELRY DETAIL No. Item Top N90 %M NOD ID Cl) CASING DETAIL Tubing Manger 32' 2 Size Type Wt Grade Conn. ID Top Btm 20" Conductor 78.6 A-53 Weld 19.25" Surf 11U' 9-5/8" Surf. Csg 40 L-80 TC -II 8.835" Surf 5,187' 4-1/2" Prod Liner 13.5 L-80 VAM HTTC 3.849" 5,000' 10,552' TUBING DETAIL 4-1/2" Tubing 12.6 1 L-80 I EUE 8rd 1 3.958" 1 Surf 1 5,000' JEWELRY DETAIL No. Item Top N90 %M NOD ID Cl) I Tubing Manger 32' 2 x Nipple 2,093' 3 StageTDOI — ES Cementer f, 900' 4 GLNi w'/ sheer uahve set @ 2500 psi 3,000 5 Liner Top Packer 5,004' 5 5ullet5eal&5�a 5,020' 7 Injection Control Device (ICD) (11 Tota l} See Below e Swell Packer(ATots I-5eaDetailBelow } See Below ICD DETAIL Top (MD) Btm (MD) 5504' 5' SWELL PACKER DETAIL Top (MD) Btm (MD) 6700' 6710' 7700' 7714' 8740" 8710' 9704' 9714' 9--"S" Shoe 11Z pP� 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O O O O O O MEN ONE PBTD =18; 350' = ; 4,421' n'D TD= I0, 552' B M ; 4,421' T4'D 5 6 hiss Dewaton: 90.73' S Page 6 Version 1 Jan, 2016 8.0 Drilling / Completion Summary Milne Point Unit B-29 Drilling Procedure MPU B-29 is a grassroots water injector planned to be drilled in the Schrader Bluff ND sand. B-29 is part of a (2) well pilot program targeting the ND sand. B-29 will be paired with a grassroots producer, B-28. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff ND sand. A lateral section will then be drilled in the reservoir. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately February 15'', 2016. Doyon Rig #14 will be used to drill and complete the wellbore. Surface casing will be run to 5,187' MD / 4,427' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on `B" pad. d` General sequence of operations: 1. MOB Doyon # 14 to well site 2. N/U 21-1/4" conductor and 16" diverter line. 3. Drill 12-1/4" hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. N/D diverter, N/U & test 13-5/8" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" liner. 6. Run Injection string. 7. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR + Res 2. Production Hole: No mud logging. On site geologist. LWD: GR + Res Page 7 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of MPU B-29. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • There are no variance requests at this time. Page 8 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 21-1/4" 2M diverter (Hydril MSP) w/ 16" diverter line Function Test Only • 13-5/8" x 5M Hydril "GK" Annular BOP • 13-5/8" x 5M Hydril MPL Double Gate Initial Test: 250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/ 3" x 5M side outlets 13-5/8" x 5M Hydril MPL Single ram • 3-1/8" x 5M Choke Line Subsequent Tests: • 3-1/8" x 5M Kill line 250/3000 • 3-1/8" x 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc Primary closing unit: NL Shaffer, 6 station, 3000 psi, 180 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is a 30:1 air pump, and emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event (BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector/ (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer/ (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.g_ov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria. loeppga,alaska.gov Primary Contact for Opportunity to witness: AOGCC.InspectorsAalaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.htmi Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 1 Jan, 2016 0 Hilcorp Energy Company 10.0 RX and Preparatory Work Milne Point Unit B-29 Drilling Procedure 10.1 B-29 will utilize the existing conductor on B -pad to the north of B-17. 10.2 Dig out and set impermeable cellar. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3" threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack -off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 Confirm that the rig is over the appropriate well slot. 10.8 MIRU Doyon # 14. 10.9 Mud loggers WILL NOT be used on either hole section. 10.10 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.11 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.12 Install 6" liners in mud pumps. • Continental EMSCO FB -1600 mud pumps are rated at 4665 psi, 462 gpm @ 110 spm @ 95% volumetric efficiency. 11.0 NX 21-1/4112M Diverter System 11.1 N/U 21-1/4" Hydril MSP 2M diverter System (Diverter Schematic at Sec 20 at back of program). • N/U 16-3/4" 3M x 21-1/4" 2M DSA on 16-3/4" 3M wellhead. • N/U 21-1/4" diverter "T". • Knife gate, 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source • Place drip berm at the end of diverter line. Page 10 Version 1 Jan, 2016 0 Hilcorp Energy Company Milne Point UnitB-29 Drilling Procedure :1 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set 15.375" ID wearbushing in wellhead. 11.5 Pad Drawing 1� Page 11 Version 1 Jan, 2016 MPU B PADLj, A A n a o GRAPHIC SCALE o w eo uo o■ FEE ( w ret* ) 7 loch n. 1� Page 11 Version 1 Jan, 2016 ff HilcoT Energy Company 11.6 Rig & Diverter Orientation on "B" pad: Exoan�ion 70.9461' 577.3006' Milne Point UnitB-29 Drilling Procedure 2-1 6" Diverter Line 127.0000' Doyon 14 Doyon 14 N Ncn Page 12 Version 1 Jan, 2016 0 Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section Milne Point Unit B-29 Drilling Procedure 12.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 12.2 12-1/4" BHA (GR + Res LWD and PWD planned in surface hole): ' COMPONENT ItemDescription 1 Tricone a. 8.000 3.000 .. 12.250 147.22 .. P 6-5/8" REG Length 1.10 Total Location 2 8" SperryDrill Lobe 4/5 - 5.3 stg 8.000 5.000 5.000 103.09 B 6-5/8" REG 31.47 32.57 Stabilizer 12.125 4.28 3 Float Sub 8.000 2.880 2.880 149.10 B 6-5/8" REG 2.40 34.97 4 IStabilizer 8.000 1 3.000 3.000 10.250 1 147.22 B 6-5/8" REG 6.00 1 40.97 35.97 5 8" DM Collar (Directional) 8.000 3.500 3.544 147.40 B 6-5/8" REG 9.20 50.17 6 8" DGR Collar (Gamma) 8.000 1.920 4.997 142.70 B 6-5/8" REG 4.55 54.72 7 8" EWR-P4 Collar (Resistivity) 8.000 1.985 5.205 151.00 B 6-5/8" REG 12.19 66.91 8 8" PWD (Pressure ECDs) 8.000 1.920 4.760 1 143.40 1 B 6-5/8" REG 4.44 71.35 9 8" HCIM Collar (Processor) 8.000 1 1.920 4.309 149.90 B 6-5/8" REG 4.97 1 76.32 10 8" POS PULSER (Telemetry) 8.000 4.000 4.257 145.20 B 6-5/8" REG 15.44 91.76 11 Orienting Sub UBHO 8.000 2.875 3.000 149.18 B 6-5/8" REG 2.50 94.26 12 NM Flex Collar 8.000 2.813 150.13 B 6-5/8" REG 31.00 125.26 13 NM Flex Collar 8.000 2.813 150.13 1 B 6-5/8" REG 31.00 156.26 14 1 NM Flex Collar 8.000 1 2.813 150.12 B 6-5/8" REG 31.00 187.26 15 8jts x 5" X 3" HWDP #49.3 - NC50(IF) 5.000 3.000 49.30 240.00 427.26 16 Jar 7.500 2.813 2.813 129.38 B 4-1/2" IF 35.00 462.26 17 12jts x 5" X 3" HWDP #49.3 - NC50(IF) 5.000 3.000 49.30 360.00 822.26 822.26 Page 13 Version I Jan, 2016 Hilcorp F-ap Company 12.3 Primary Bit: 12-1/4" VMD -3 (311.2 mm) Milne Point Unit B-29 Drilling Procedure • Uttra,pbtasiv�e Formation Cutting Structure 5peciFicaily engineered for utha-abrasive formations_ This steel tooth cutting structure has extra -thick hardfacing to ensure teeth stay scarper longer and deliver extended runs with improved penetration rates. • Metal Face Seal & Bearing Systern Longer bit life in high -RPM, motor, and high-temperature drilling applications, up to 400'F (204°C), with the patented VM metal -to -metal sealing system. • XL & LX Hardfacing Features A patented, strategically placed bead of hardfacing is added to key areas on specific teeth to retard tooth wear and improve tooth strength and durability. • Boss StabilUatfon System These u*Lie integrated stati liters provide near six -point contact with the borehole wall for unequaled stability and cutting structure protection. • STL Hardfacing Increased bit life and reliability with a precisely controlled application of patented, highly wear - resistant STL- hardfacing that covers the entire shirttail and leg areas for superior protection from the potentiallydan-Mingeffects of hole -wall contact • Ceuta Jet (C) A fourth jet is positioned in the center of the bit and utilized to prevent bit balling and the associated reduction in penetration rate. • Clean Sweep Hydrardics (CS2) Biased nozzle configuration directs fluid toward areas where bit balling occurs. The Clean Sweep high -velocity cone strikes heel and adjacent heel area on the backside of the cone. PRODUCT SPECIFICATIONS: IADC. 137 Bearing / Seat Package: Journal I Metal Cutting Structure: Inner Row. ST Heel Row. ST Gauge Row: ST Gauge Trimmers: N/A Tooth Hardfacing: XL )LX OD Hardfacing: STL Nozzle Type: Standard Center Jet Display. • FK or VK Makeup Torque: 28.0 - 32.0 klbf-ft (38.0 - 43.4 kNm) Connection: 6-&B REG API Approx. Shipping Weight: 235 Ib ( 106.6 kg) Reference Part Number: H2187000 OPERATING RECOMMENDATIONS: * Weight On Bit: Rotation Speed: 20 - 50.0 klb (9 - 22 to or kdaN) For High Speed Rotary/Motor Applications Page 14 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 12.4 5" Workstring, HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 Drill 12-1/4" hole section to 5,187' MD / 4,427' TVD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating) immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 600 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • For producer wells only: • Ensure to leave a "Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg / 100. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section just into the target sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled (95' intervals). • Watch returns closely for signs of gas when near the base of the permafrost and circulate out all gas cut mud before continuing to drill. There have been no indications of hydrates on any of the "B" pad wells to date. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is > 4. • Do not slide for 100' MD above the base of the permafrost (1700' TVD) or 100' below the base. We want to leave this transition as undisturbed as possible. • Plan a bit trip (if necessary) before penetrating the UGNU LA3 sand. This interval caused an unintentional sidetrack on L-48. Page 15 Version 1 Jan, 2016 Hilcorp Energy Company i d Milne Point Unit B-29 Drilling Procedure 12.7 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. ' • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high -clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 - 9.0 range with caustic soda. Daily additions of ALDACIDE G / X- CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP < 20 (check with the cementers to see what YP value they have targeted). System Type: 8.8 - 9.2 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point AN FL H 110-5187 8.8 — 9.2 85-250 20-40 25-75 <10 1 8.5 Page 16 System Formulation: Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl soda Ash 0.5 ppb AQUAGEL 15 - 20 ppb caustic soda 0.1 ppb (8.5 - 9.0 pH) BARAZAN D+ as needed BAROID 41 as required for 8.8 - 9.2 ppg PAC -L /DEXTRID LT if required for <10 FL ALDACIDE G 0.1 ppb Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp EneW Company 12.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 20" conductor shoe. 12.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure at least 3 — 4 B/U have been circulated to get hole as clean as possible. • Pump at full drill rate (600 — 700 gpm), and maximize rotation. • Pull slowly, 5 — 10 ft / minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.10 TOH with the drilling assy, handle BHA as appropriate. 12.11 No open hole logging program planned. 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull 15.375" wearbushing. 13.2 Make a dummy run with the 9-5/8" casing hanger. 13.3 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" TC -II x DS50 XO on rig floor and M/U to FOSV. • Use Jet Lube Seal or BOL 72733 thread compound. Dope pin end only w/ paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.525" on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 13.4 P/U shoe joint, visually verify no debris inside joint. 13.5 Continue M/U & thread locking shoe track assy consisting of- * £• (1) Shoe joint w/ float shoe bucked on (thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end & thread locked. Install (1) centralizer mid tube over a stop collar. Page 17 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure • Ensure bypass baffle is correctly installed on top of float collar. Page 18 This end up. Bypass Baffle (1) Joint with Halliburton bypass baffle adapter bucked on pin & threadlocked. Install (1) centralizer mid tube over a stop collar. Ensure proper operation of float equipment while picking up. Ensure to record S/N's of all float equipment and stage tool components. Version 1 Jan, 2016 13.6 Float equipment and Stage tool equipment drawings: Type H ES Cementer Part No. SO No, Closing Sleeve No. Shear Pins Opening Sleeve No. Shear Pins ES Cementer Depth Baffle Adapter (if used) iD Depth Bypass or Shut-off Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Section 5 Page 19 "A Overall length B Min. ID After Drillout C Max. Tool OD D Openng Seat ID E Closing Seat ID Plug Set Part No. SO No_ Closing Plug 11 OD Opening Plug OD OD Shut-off Plug OD Bypass Plug (if used) OD Version 1 Milne Point UnitB-29 Drilling Procedure Jan, 2016 ./ Hikorp ES -11 Running Order E541 Cementer .1. L. Shut ON Phg Raffle Adapter 10 "SSS By Pass Baffle float Collar RM Shoe Jan, 2016 ./ Milne Point Unit B-29 Drilling Procedure Hilcorp Enew Company 13.7 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 13.8 Install the Halliburton Type H ES -II Stage tool so that it is positioned at 1900' MD / 1892' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer, this can cause damage to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes, the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40# L-80 TC -II Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 11,600 ft -lbs 13,600 ft -lbs 13.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.10 Slow in and out of slips. 13.11 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 13.12 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 13.13 Have emergency slips ready to go in the event we cannot land the hanger. Page 20 Version 1 Jan, 2016 Hilcorp Energy Company Connection Type: TC -II Casing standard Technical Specifications size(o.D.): Weight (Wall): 9-5/8 in 40.00 lb/ft (0.395 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 9.625 Nominal Pipe Body O.D. (in) 8.835 Nominal Pipe Body I.D.(in) 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight (lbs !ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916,000 Minimum Pipe Body Yield Strength (lbs) 3,090 Minimum Collapse Pressure (psi) 5,750 Minimum Intemal Yield Pressure (psi) 5,300 Hydrostatic Test Pressure (psi) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees110t? ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Milne Point Unit B-29 Drilling Procedure Grade: L-80 VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Housbn, Tx 77441 Phone: 713-4791-3200 Fax: 713479-3234 E-mail: VAMUSAsalesg�vam-usazom 13.14 RX circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 13.15 After circulating, lower string and land hanger in wellhead again. Page 21 Version 1 Jan, 2016 Connection Dimensions 10.235 Connection O.D. (in) 8.835 Connection I.D. (in) 8.750 Connection Drift Diameter (in) 5.23 Make-up Loss (in) Connection Performance Properties 916,000 (1) Joint Strength (lbs) 16,360 Reference String Length (ft) 1.4 Design Factor 916,000 Compression Rating (lbs) 3,090 Collapse Pressure Rating (psi) 5,750 Internal Pressure Rating (psi) 38.1 Maximum uniaxial bend rating [degrees110t? ft] Recommended Torque Values 11,600 (2) Minimum Final Torque (ft -lbs) 13,600 (2) Maximum Final Torque (ft -lbs) Milne Point Unit B-29 Drilling Procedure Grade: L-80 VAM USA 4424 W. Sam Houston Pkwy. Suite 150 Housbn, Tx 77441 Phone: 713-4791-3200 Fax: 713479-3234 E-mail: VAMUSAsalesg�vam-usazom 13.14 RX circulating equipment and circulate B/U. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Elevate hanger slightly above hang off point while circulating to avoid plugging the flutes. 13.15 After circulating, lower string and land hanger in wellhead again. Page 21 Version 1 Jan, 2016 0 Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing Milne Point Unit B-29 Drilling Procedure 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug). Mix and pump cmt per below calculations for the 1St stage. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated Total Cement Volume: ( �'-r- 54�'j�` Section: Calculation: Vol (BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing annulus: (4687'- 1900') x.0558 bpf x 1.3 = 202 1134 Total LEAD: 202 bbls 1134 ft3 12-1/4" OH x 9-5/8" Casing annulus: (5187'- 4687') x.0558 bpf x 1.3 = 36 202 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 38 Total TAIL: 43 bbls 240 ft3 Page 22 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure Cement Slurry Design (both 1St and 2"d stage cement jobs): ✓� 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 14.11 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 14.12 Displace nt--calculation: 5100' x . 758 = 387 bbls total (203 bbl mud + 80 bbl water + 104 bbl mud) - The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 10 bbls before consulting with drilling engineer. 14.15 If plug is not bumped consult with drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 23 Version 1 Jan, 2016 Lead Slurry Tail Slurry System ArcticCEM T"^ System SwiftCEM TM System Density 10.7 Ib/gal 15.8 Ib/gal Yield�t.298 /sk' --1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits. 14.11 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. To operate the stage tool hydraulically, the plug must be bumped. 14.12 Displace nt--calculation: 5100' x . 758 = 387 bbls total (203 bbl mud + 80 bbl water + 104 bbl mud) - The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 10 bbls before consulting with drilling engineer. 14.15 If plug is not bumped consult with drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. Page 23 Version 1 Jan, 2016 Milne Point UnitB-29 Drilling Procedure Hi1mTEnergy Company 14.17 Increase pressure to 3300_ psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if'TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP < 20 again in preparation for the 2 stage of the cement job. 14.18 Be prepared for cement returns to surface. Dump cmt returns in the cellar or open the shaker bypass line to the cuttings tank. Have sacks of sugar available and vac trucks ready to assist. Ensure to flush out any rig components used to route cmt. Page 24 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company Second Stage: 14.19 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 14.20 Load ES cementer closing plug in cmt head. 14.21 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.22 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.23 Mix and pump cmt per below recipe for the 2nd stage. 14.24 Cement volume based on annular volume + 200% open hole excess. Job will consist of lead & tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is observed at surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3) 20" Conductor x 9-5/8" casing annulus: (110') x.27 bpf x 1 = 29.7 bbls 167 ft3 12-1/4" OH x 9-5/8" Casing (1400'- 110') x.0558 bpf x 3 = 215 1207 annulus: Total LEAD: 244.7 bbls 1374 ft3 12-1/4" OH x 9-5/8" Casing (1900'- 1400') x.0558 bpf x 2 = 56 314 annulus: Total TAIL: 56 bbls 314 ft3 14.25 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 14.26 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 14.27 Displacement calculation: 1900' x.0758 bpf = 144 bbls mud Page 25 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 14.28 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.29 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 14.30 Land closing plug on stage collar and pressure up to 1000 — 1500 psi to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure and check to ensure stage tool has closed. Back out and L/D landing joint. Flush out wellhead with FW. 14.31 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 14.32 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to lkellerAhilcorp. com and cdingerAahilcorp. com This will be included with the EOW documentation that goes to the AOGCC. Page 26 Version 1 Jan, 2016 Milne Point UnitB-29 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter & N/U 11" 5M tubing spool. 15.2 N/U 11" x 5M BOP as follows: • BOP configuration from Top down: 13-5/8" x 5M annular / 13-5/8" x 5M Double gate / 13- 5/8" x 5M mud cross / 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 5" Fixed rams • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 15.3 Run 5" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" (for 5" DP workstring) 4-1/2" (for 4-1/2" production liner & tubing) 15.4 R/D BOP test assy. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 15.7 Set 10" ID wearbushing in wellhead. 15.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.9 Keep 6" liners in mud pumps. 15.10 P/U used 8-1/2" Baker Hughes mill tooth bit and clean out BHA and TIH to TOC. Shallow test MWD and LWD on trip in. 15.11 Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. Page 27 Version 1 Jan, 2016 0 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure • After drilling out, chase any remaining debris to bottom with the drill bit. 15.12 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.13 R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = —2875 psi, but maximum test pressure on the well is 3000 psi. 15.14 Drill out shoe track and 20' of new formation. 15.15 CBU and condition mud for FIT. 15.16 Conduct FIT to 12 ppg EMW. ------- 15.17 TOH with clean out assy for lateral drilling assy. Page 28 Version I Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Install ported float in the BHA. 16.2 8-1/2" Rotary Steerable (Includes at bit GR, at bit incl, ADR for geosteering, PWD): COMPONENT Item 9 DATA Description Serial Number • M (in) 10 (in) Gauge (in) Weight (tbpf) Top Conrmction Length (it) Cumulative Length (ft) 1 PDC - Long Gauge 6.360 2.250 8.500 94.72 P 4-112" REG 2.19 2.19 Stabilizer 8.469 2 Geo -Pilot 7600 XL 25KSI 7.625 1.490 8.375 113.00 B 4-112" IF 20.16 22.35 Ref Housing Stabilizer 8.375 3 6-3/4" DrilIDOC (WOBITOB) 7.100 2.000 108.41 B 4-112" IF 7.10 29.45 4 6-3/4' DGR (Gamma) 6.750 1.920 97.80 B 4-112" IF 8.43 37.88 5 6-3/4' PWD (Pressure) 6.750 1.920 96.30 B 4-112" IF 4.40 42.28 6 Inline Stabilizer (ILS) 6.750 1.920 8.250 112.09 B 4-112" IF 2.25 44.53 7 6-314" ADR Collar (Resistivity) 6.750 1.920 109.40 B 4-112" IF 24.30 68.83 8 6-314" DM Collar (Directional) 6.750 3.125 103.40 B 4-112" IF 9.20 78.03 9 6-314" TM Collar (Mud Pulse Telemetry) 6-750 3.250 103.60 B 4-112" IF 10.00 88.03 10 6-314" Float Sub 6.750 2.250 108.40 B 4-112" IF 2.00 90.03 11 NMDC Slick 6.750 2.813 100.77 B 4-112" IF 31.00 121.03 12 NMDC Slick 6.750 2.813 100.77 B 4-112" IF 31.00 152.03 13 NMDC Slick 6.750 2.813 100.77 B 4-112" IF 31.00 183.03 14 lit x 5" X 3" HWDP #49.3 - 4.51F 5.000 3.000 49.30 31.00 214.03 15 Weatherford 6.25" Jar 6250 1 2.250 91.01 B 4-112" IF 30.00 244.03 16 1# x 5" X 3" HWDP #49.3 - 4.51F 5.000 3.000 49.30 31.00 275.03 17 5" X 4276" - 19.5# 6-518" X 2-3/4" - 4.51E 5.000 4.276 22.60 31.00 306.03 306.03 Page 29 Version 1 Jan, 2016 Hilcorp Energy Company 16.3 Primary Bit: K AmiiZ Ar 'DIV Wellbore Technologies ec alogies 8 '/Z" SK61+6M-J1 D Design Features of this bit Seeker T" Directional Drill Bits Seeker"" directional drill bits are designed to overcome directional drilling challenges for both motor or RSS tools in a wide range of directional applications. HellosTM InfernoTM Cutters- Specialized cutter technology engineered for specific applications that may require increased thermal resistance, increased abrasion resistance or increased toughness. Each Helios"" InfernoT' cutter has a unique cutter index value indicating performance characteristics. SmoothTorque'" Torque Control Components- Smooth-rorque" torque control components are inserts placed between primary cutters to provide a predictable torque response to applied weight -on -bit and reduction in torque variance. SmoothSteerl Gauges SmoothSteert" gauges deliver maximum gauge contact. lowering resistance to steer by reducing torque, and leading to improved ROP and extended bit and tool life_ TSP Gauge Protection- Thermally stable product (TSP) tiles and welded hardmetai gauge protection give both a highly durable and ultra -smooth gauge. Spiral Gauge- Stability is improved by increasing the circumferential contact of the bit gauge. Improved stability enhances steerability and ROP. This bitfunit can accommodate BlackBoxrw HD drilling recorder. This bodied PDG bit features computer aided cutter placement and hydraulics optimized by nozzle location to deliver high performance and longer bit life. Milne Point UnitB-29 Drilling Procedure Design Specifications Make up Length iffy= .92 Shank Bore (ins): 2.300 Shank Diam (ins): 6.400 Connection std: Y Connection Size(ins): 4.500 Connection Type_ Api Reg Pin Make up Torque (ft -lbs): 20000 IADC Code: M422 Diameter.(ins) 8 1/27 Body Material: Matrix HDK JSA(in2)_ 18.440 Face Volume:(in') 71.66 Normalised Face vol: 53.26°, Blade Qty: 6 Gauge Length:(ins) 4.000 Gauge Geometry: Spiral -Trailing Gauge Profile: SmoothSteer Gauge Protection: TSR Tiled Bit Profile: snort Taper - srvriaw Cone Recommended Operating Parameters Max Operating WtiOB (klbs):38 Min TFA (in2): 0.2946 Max TFA (in2): 2.2272 Max Flow (gpm): 934 HSI: 2-7 Bit Breaker. Thick 116* kr same agpYcaWns MM bW rs rar =ccessW)r paymd Mesa patameber.. Cmfac7 your NOV ReedHycabg RepresereafMe.M rKppVl.Yll "a aperavnp PM eters M yaw appArewZn. Nov Reiad yc.abg:ese"s are rbnr to kW Mew Ap-iftanbn5- based an ad --es and knpo-rnenfs M tech—logy. This report is va:id for 30 days from 02 -Sep -201'5 Cutting Structure Nozzles & Ports Type City Location Diameter Shape Qty Type tyke Primary 31 FACE 16 mm CYLINDER 6 TNZ VARIABLE Primary 12 GAGE 13 mm CYLINDER Primary 6 BACK -ANGLE 13 mm CYLINDER TCC 6 FACE 11 mm DOME TOPPED Page 30 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 16.4 8-1/2" hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N -VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use water or low vis sweeps. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9 — 9.2 ppg Baradrill-N drilling fluid Pro erties: Depths Density Plastic Viscosity Yield Point Total Solids MBT HPHT pH 5187— 10,552 8.9-9.2 15-25 15-25 <10% <7 <1 1.0 8.5-9.5 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N -VIS 1.0 — 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppg BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb Page 31 Version 1 Jan, 2016 Milne Point UnitB-29 Drilling Procedure Hilcorp Energy Company 16.5 TIH w/ 8-1/2" directional assy. 16.6 On -bottom staging technique: Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. If BHA begins to show excessive vibrations / whirl / stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. 16.7 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Pump at 600 - 650 gpm. I • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500 — 2000 ft if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and DO NOT want to serpentine between the upper and lower lobes. • Limit maximum instantaneous ROP to < 200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. 16.8 Concretion drilling strategy: • Past experience has shown that no two hard streaks are the same. WOB and RPM may have to be constantly changed to drill effectively. • When a hard streak is encountered, first attempt to drill through it with low WOB (5k WOB, 150 RPMs at the bit). Gradually increase one or the other or both. Allow enough time to elapse after a parameter adjustment to make note of increased or decreased drilling efficiency. • DO NOT backream through concretions. This practice has been attributed to cutter damage in the past. • Normal backreaming can be done through soft / high ROP drilling areas. • Make all attempts at prolonging bit life when working through concretion intervals. Once the shoulder row of cutters has been chipped or damaged, the steerability and ROP will be significantly reduced. 16.9 Open hole sidetracking practice: • If a known fault is coming up, put a slight "kick-off ramp" in wellbore ahead of the fault so we have a nice place to low side. Page 32 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure Attempt to lowside in a fast drilling interval where the wellbore is headed up. Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 16.10 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (600 — 650 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.11 TOH with the drilling assy, stand back BHA if possible. Rabbit DP on TOH. 16.12 No open hole logs are planned for the production hole section. 17.0 Run 4-1/2" Injection Liner 17.1 Ensure VAM rep on location to assist with running the HTTC connection. 17.2 R/U 4-1/2" casing running equipment. ' • Ensure 4-1/2" HTTC x NC -50 crossover is on rig floor and M/U to FOSV. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 17.3 Run 4-1/2" production liner per completion tally. • Use "Best O Life 4010NM" thread compound. Dope pin end only w/ paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers & ICDs as per Operations Engineer guidance. • Ensure all plastic packing is removed from swell pkr elements. • Do not place tongs or slips on pkr elements or ICDs. 4-1/2" HTTC M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 6,910 ft -lbs 9,350 ft -lbs 12,350 ft -lbs Page 33 Version 1 Jan, 2016 Hilcorp Energy Company Issued an: 433 )un. 7013 bV leen-Guaume Besse DATA ARE INFORMATIVE ONLY. BASED ON SI -PD 101156 Milne Point Unit B-29 Drilling Procedure Connection Data Sheet OD Weight Wall Th. Grade API Drift I Connection 4 1/2 In. 1 13.501 0.290 in. I LSO 3."S In. VAMM HTTC Nominal ID 3.920 in. Connection OD (nom) 4.930 in. Nominal Cross Section Area 3.836 sqin. Connection ID (nom) 3.849 in. Grade Type API 5CT Make -Up Loss 4.380 in. Min. Yield Strength 80 ksi Coupling Length 9.917 in. Max. Yield Strength 95 ksi Critical Cross Section 3.836 sqin. Min. Ultimate Tensile Strength 95 ksi Tension Efficiency 100 90 of pipe Tensile Yield Strength 307 k1b Compression Efficiency 100 DIB of pipe Compressive Yield Strength 307 klb Compression Efficiency with Sealability 80 gra of pipe Internal Yield Pressure 9,020 psi Internal Pressure Efficiency 100 DAB of pipe Collapse pressure 8,540 psi External Pressure Efficiency 10o % of pipe • s rTORQUE Ie Yield Strength 307 klb Min. Make-up torque 6,910 ft.ib i iression Resistance 307 klb Opti. Make-up torque 8,130 ft.lb gression with Sealability 246 klb Max. Make-up torque 9,350 ft.lb tial Yield Pressure 9,020 psi Max. Torque with Sealabi9ity 12,350 ft.lb nal Pressure Resistance 8,540 psi Max. Torsional Value 14,400 ft. Ib Bending 77 0/1008 Bending with Sealability 33 -/100ft Load on Coupling Face 158 klb Do you need help on this product? - Remember no one knows VAN* like VAN conodapyamflehiservrce.com uk[mvamf a dservlce_com ch#wlpvom&Wservke.com usogavanifAWservke.com dubefelvam8eldservke.cam bakulplvomheldservke.corn mexko@yam8eldservkr.cam nigerlapvamheWservke.cam singapare@vamfteMservke.com brazd@vamAeldservke.corn angola+avamfteldservice.com oustralla€rvamReMservice.com Over 140 VAN@ Specialists available worldwide 24/7 for Rig Site Assistance '.7acr eonnaCnan Data sheets are available at nww.Va'M1•1-r VCc Crm 17.4 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 17.5 RAJ false rotary and run inner string. 17.6 Before picking up Baker ZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 17.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with "Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.9 RIH w/ liner on DP no faster than 1-1/2 min / stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 34 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 17.10 DP should autofill. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth + S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.16 Rig up to pump down the work string with the rig pumps. 17.17 Displace entire wellbore to completion fluid (8.9 ppg KCl). Pump at 10-12 bpm. Catch mud for future use if feasible. Once KCl observed at surface shut down pumps. 17.18 Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 17.19 Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. 17.20 Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 30 min and chart record same. 17.21 Bleed off pressure and pickup to verify that the HRD setting tool has released. If packer did not test, rotating dob sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 17.22 POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. 17.23 L/D remaining DP out of derrick. Page 35 Version 1 Jan, 2016 Milne Point UnitB-29 Drilling Procedure Hilcorp EncrV Company 18.0 Run Injection Assembly 18.1 M/U injection assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 18.2 Land hanger, RILDs and test hanger. 18.3 Circulate freeze protect down IA, allow freeze protect to U-tube down tubing. 18.4 �et packer. Jest annulus taj MMpsi f/ 30 min. l 18.5 Install BPV and N/D BOP. 18.6 N/U tree adapter and tree. Conduct pressure tests of same to 250/3000 psi. 18.7 Shut in well. L e_ 1_V _ i Aj TA 'Ira 4.: 19.0 RDMO ""J e Page 36 Version 1 Jan, 2016 Hilcorp Energy Company 20.0 Milne Point Unit B-29 Drilling Procedure Diverter Schematic Page 37 Version 1 Jan, 2016 Hilcorp Energy Company 21.0 BOP Schematic Kill Line Page 38 Hydril GK Annular BOP 13-518" x 5M J U 13-518" x 5M U L ❑❑oFlo ❑❑ 0, ❑❑ 13-5/8" x 5M 9-5/8" DBL D Casing Hanger SMB -22 16-314" NOM 9-518" BTC Bim x 10.5" -4 SA Pin Top W/ Prima Sea Milne Point Unit B-29 Drilling Procedure �3" x SM HCR ----Choke Line �3" x 5M Manual Gate Valve 11"x 5M -2-1/16" x 5M 16-3/4" x 3M `2-1116" x 5M ry I I I 1 T--- 9-5/8CCasing Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic SWAGE ADAPTER, 20 SOW x 18 SUP ON Pei Page 39 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth 0 2000 4000 r 8000 Iu A i 12000 14000 16000 0 5 10 15 20 25 30 35 Days Page 40 Version 1 Jan, 2016 - - --- - -MPU B-29AFE L-49 Actual L-46 Actual L-48 with N PT removed MPU B-29 STRETCH PLAN +t.+ Piot Area -49 L-46 L -4S 0 5 10 15 20 25 30 35 Days Page 40 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure 24.0 Formation Tops MPU B-29 Projected Formation Tops Formation Top TVD Bottom TVD SV6 1152 1172 SV1 2630 2650 UgnuLA3 3918 3938 Schrader Bluff NA 4347 4357 Schrader Bluff ND 4420 4430 GENERALIZED GEOLOGICAL - SS GEOLOGICAL TVD[ FM LITH DESCRIPTION SUGGESTED MUD INT. All Geol.' • ° •' g-5 B 0 9�5 19.0 10.5 Depths Gubik 1'ss Unconsolidated coarse to medium ry tolerant 000 with MUD PPG sand and small gravel wminor o siltstone. Note: This is _ Heavy gravel conglomerate to 1400'. a generic mud 1,0(10 _ Wood fragments throughout Iwo I weight chart. Q) permafrost zone. 1 See individual well plan for 1700' •� Base permafrost specific mud 2,000 C weights. Sagava riirktok L e 9.2 to 9.3 ppg „ Ainterbeds Predominantly clay to +J• 3000' with of sand. clays and silt- I a stones with occasional shows of coal 9.4 2pq around 2700'. Pebbley gravel (up to 50%) down to 2700'. 3,000 Continued interbeds of sand, clays and siltstones with heavy coal sections no 2800.3200. KA: 3800- 3900 UGNU: Series of coarsening upward K -sands (-A B C D) UGN tj L -sends sands which are made up of: (from top MA: (-A•B) to bottom) coarse sand, fine sand, silty 4070- M -sands shale and some coal. Better developed 4140 (-A,B•C) intervening shales as you progress into the Land M (deeper), 4,000° Possible hydrocarbon bearing sands f00° Schrader Bluff Sands NA: 4300- N -Sands Continued layered coarsening upward sands as 4600- (-A,B,C,D above except more condensed. Possible EY) hydrocarbon bearing and potentially productive OA: o -Sands in the "O" and "N" sands. Tend to be water wet 4550- 4800' I-A,B,c, D.Efl more than a mile to the east. C' 9• I ' Primarily clay with some silty sandstone Page 41 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non -pressurized mud scale. The non -pressurized scale will reflect the actual mud cut weight. Add 1.0 — 2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti -Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 42 Version 1 Jan, 2016 0 Hilcorp Enema Company Milne Point Unit B-29 Drilling Procedure 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low -vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of > 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least (1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a "ramp" in the wellbore to aid in kicking off (low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for 1-12S. No 1-12S events have been documented on drill wells on `B" pad. 1. The AOGCC will be notified within 24 hours if 1-12S is encountered in excess of 20 ppm during drilling operations. 2. The rig will have fully functioning automatic 1-12S detection equipment meeting the requirements of 20 AAC 25.066. 3. In the event 1-12S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: There are no abnormal pressures or temperatures observed on this pad. Page 43 Version 1 Jan, 2016 Hilcorp eoey company 26.0 Do n 14 Rig Lavout T o 11 �---C 01 Cn -T- 4 Lbce- Milne Point Unit B-29 Drilling Procedure N v Page 44 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 ,minutes or until the pressure stabilizes. Record time vs. pressure in 1 -minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 45 Version 1 Jan, 2016 Milne Point UnitB-29 Drilling Procedure Hilcorp Energy Company 28.0 Choke Manifold Schematic y z:,=Z 0 y w w a w - ro0 �:J wry I --IC> ftp N 1�D M = N Z Z Lal ! r71 N y N N N p a O S 7 w a p w — d w ;3 ro aa P a t Oi `° � w A a 0 a A w M a — w fl v V,o ro T ro ro i — w m V � W N 1" a W r o ro o• 00 .a j r �o a ro O � •s � AD Cn Page 46 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure 29.0 Casing Design Information Calculation & Casing Design Factors Hale Size 8-112" Hole Size Hole Size DATE: 116/2016 WELL: MPU B-29 DESIGN BY:Luke Keller Design Criteria: Mud Density: 9.5 ppg Mud Density: Mud Density: Drilling Mode MASP: 1158 psi (see attached MASP determination R calculation) MASP: Production Mode MASP: Collapse Calculation: Section Calculation 1158 psi (see attached MASP determination & calculation) Normal gradient external stress (0.494 psilft) and the casing evacuated for the internal stress If I Page 47 Version 1 ', Jan, 2016 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-518" 4-112" Top (MD) 0 5,000 To D 0 4,410 Bottom MD 5,187 10,552 Bottom TVD 4,427 4,421 Length 5,187)5,552 ) Weight 40 13.5 Grade L-80 L-80 Connection TC -II VAM HTTC Weight w/o Bouyancy Factor lbs 207,480 74,952 Tension at Top of Section lbs 207,480 74,952 Min strength Tension 1000 lbs 916 307 Worst Case Safety Factor Tension 4.41 4.10 Collapse Pressure at bottom Psi 2,187 2,184 Collapse Resistance w/o tension (Psi) 3,090 8,540 Worst Case Safety Factor (Collapse) 1.41 3.91 MASP(psi) 1,158 1,158 Minimum Yield (psi) 5,750 9,020 Worst case safety factor Burst 4.97. 7.79 If I Page 47 Version 1 ', Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Enerp Company 30.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation Fifloor� 8-1/2" hole Section MPU B-29 Milne Point Unit MD TVD Planned Top: 5187 4427 Planned TD: 10552 4421 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NDSand 1 4,421 1 1600 1 Oil/Wet 7.0 1 0.362 Offset Well Mud Densities Well MW ranee TOD (TVDI Bottom ITVDI Date MPB-11 9.5-9,6 Surface 4,500 1985 MPB-12 9.0-9.8 Surface 4,500 1985 MPB-13 9.5-9.6 Surface 4,500 1985 MPB- 14 9.1-9.4 Surface 4,500 1985 MPB-15 8.6-9,8 Surface 4,500 1985 MPB- 16 8.9-9.6 Surface 4,500 1985 MPB- 17 8.6-9.7 Surface 4,500 1985 MPB -19 9.2-9.7 Surface 4,500 1985 MPB - 21 9.3-10.1 Surface 4,500 1986 MPB - 25 8.3-9.4 Surface 4,500 1997 Assumptions: 1. Field test data suggests the Fracture Gradient in the Schrader Bluff is btwn 11.5 and 15 ppg EMW. 2. Maximum planned mud density for the 8-1/2" hole section is 9.5 ppg. 3. Calculations assume full evacuation of wellbore to gas Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 4427 (ft) x 0.78(psi/ft)= 3453 psi 3453(psi) - [0.1(psi/ft)*4427(ft))= 3011 si MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff sand) 4427 (ft) x 0.362(psi/ft)= 1600 si 1600(psi) - 0.1(psi/ft)*4427(ft)= 1158 psi i Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 48 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) tiMilne Point Unit o ,cco 2,00c "` o° ."r12m MPB-29 Well smo oner. 12m 5)2015 Feet Page 49 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) J p � ! � p-PAp Q + 0 14 I 13 -i4- 1 a B -PAD 'S eLIm rnojwr '?1 of � • A -P '3 , � re 18■ A.S,P, ■ ■24 ' 8• GEODETIC ■12 7■ NO, ■14 its POSITION DMS ■13 9■ I OFFSETS ■16 10■ N 1,387.97 ■1S �-_ 23■ 60 23.7' ■22 �- X= 572,006,48 -SSA B-29 .'f 149,4118561' ■3 25■ n ■ 10 ■ fO GRAVEL SITE i ra str ry--� H.T.S. LEGFND• �A B p ........................... +N 1080 + AS -BUILT CONDUCTOR ������������'�����• ■ EWING CONDUCTOR 1k,'. r.1,Otnr F. euflnDTt •,�. 10200 .� RENAMED CONDUCTOR REVISION NOTE �''••..,..•• WELL MP B-29 IOWL THIS AS-BI1tT DRAVANG IS A REISSUE OF PRE140US AS -&AT DRAW1#G FOR CONDUCTOR MP 9-26. RENAMED CONDUCTOR IS AS FOLLCWM' SURVEYOR'S CERTIFICATE OLD COND. NAME NEW COND, NAME PROPERLY RREEGISTERED AND LICENSED TO MP B-26 MP B-29 TA STATE>E OITICE L ALBA AND "MAT NOTES: MADEBYMELOR UNDER MY DIRELY SUPERVISION AND TNA? ALL 1. DATE OF SURVEY: NOVEMBER 6-7. 2004 DIMENSIONS AND OTHER DETAILS ARE 2 REFERENCE FIELD BDOK; MP04-04, PGS. 3-7. CORRECT AS OF NOVEUKR 7, 1004. 3. ALASKA STATE PLANE COORDINATES ARE ZONE 4 NA027. GEODETIC COORDINATES ARE NA027. 4. HORIZONTAL AND 'VERTICAL CONTROL ARE BASED O1 MP B -PAD GRAPHIC SCALE OPERATOR MONUMENTS 9-1 AND 9-2. 200 490 800 5. ELEVATIONUM S ARE MILNE PT, B -PAD DAT, MEAN SEA LEVEL (M.S.L). 0 6. MEAN PAD SCALE FACTOR IS: 0.999905887 ( IN FEET ) 1 Inch . 400 ft. I INr`ATCII MATWIM DDATOAPTCII CCP 10 T IA M R 11 C IIUTAT L VPOIAN At ACIrA WELL A.S,P, PLANT GEODETIC GEODETIC CELLAR SECTION NO, COORDINATES COORDINATES POSITION DMS POSITION D.OD BOX ELEV. I OFFSETS Y■6,023,042.84 N 1,387.97 70'28'23.661' 70.4732392' 23.7' 5,199' FSL B-29 X= 572,006,48 E 600.32 149'24'42,682' 149,4118561' 4,287' FEL KLA Hilcorp Alaska r MILNE POINT 8 -PAD RENAMED CONDUCTOR WELL B-29 T a l Page 50 Version 1 Jan, 2016 Hilcorp Energy Company 33.0 0 1000 2000 3000 w O 4000 5000 6000 7000 8000 Milne Point Unit B-29 Drilling Procedure ffset MW vs TVD Chart -- B-21 (1986) B-25 (1997) .B-12 (1985) -B-11 (1985) B-15 (1985) B-14 (1985) B -13(1985) B-17 (1985) 9. B-19 (1985) B-16 (1985) ;i a 8.0 9.0 10.0 11.0 12.0 Mud Weight (PPG) Page 51 Version 1 Jan, 2016 Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company 34.0 Drill Pipe Information 5" 19.5# S-135 DS -50 Drill Pipe Configuration I f Pipe Body OD - 5-000 Pipe Body Wall TNckness m 0.362 Pipe Body Grade S-135 Drill Pipe Length Rarow Connection GPOS50 Tool Joint OD 6.625 Tod Joint ID cm 3.250 Pin Tong 19 Box Tong m 12 80 % Inspection Class Nominal Weight Designation 19.50 Drill Pipe Approximate Length Ian 31.5 SmoolhEdge Height (n) 3132 Raised Tool Joint SMYS (P-1120,000 Upset Type IEU Mex Upset OD (DTE) onl 5.125 Friction Factor 11.0 Note- Tong space may Include hardtacing. Drill Pipe Performance Drill -Pipe Lenge' Rangge2 of Drill Pipe with Pipe Body at operational t t ■ Nominal (teas(awurale) 23.29 0.36 0.0085 0.72 0.0172 IMS 36,100 Tenai. Only 10 156.0.800 Drift Size _ , - ilm 3.125 - - U0 c,crnbrted-fng 32,100 1467,400 Note. ON held barrel equis as us gallons. Nota: Drill pipe assembly values are best esbm**s and may vary dtae to pipe body mdl toleranCe, In(erral plastic -Ung, and other taclofs. Connection Performance GPDS50 ( 6.625 (1n) OD X 3.250 (n) ID ) 120,000 (moi) A)PVW Maaaup Term= at Shoulder T.V-M C.;=m T001 Joint Dimensions Balanced 00 (ln6.435 Mtrrmr't TOW "CM oD for API 5.930 I.... C4055 (In 6arrman Tow Jgad oD for 5.93 Colriterbora (In Tbrque Sep" to -es) Maximum Macre-up Torque 143,100 ITensil Minimum Make-up Torque 136,100 11.202 Note: The MWIMuhl make- * lotll a should Lm appiled ®Ren possible Note: To rnaslmize connecim operational tensile. a Ni (Tar - ]7.190 (ftabsl should Ie applied. 21i, 712,100 Tool Joint Torsional Strength rlt m:) 71.800 Pipe Torsional Strength Tod Joint Tensile Strength (aa) 1.250.000 58,100 TJ/PlpeBody Torsional Ratio Shoulder Information Elevator 1.24 SmoothEdge Height mlb) 59.300 3132 Raised 46,500 Box OD tin) 6.812 Elevator Capacity (lbs)1,658,000 15.638 Elevator OD 3132 Raised 6.812(1-) Tool Joint Wom to Bevel Wom to Min TJ OD for OD I Diameter I API Premum Class i . 5 219 Nola: Elevator capacity tmwd on assumed Elevator Sore. no wear ractm, and conlact stress at 1 la, 10Dp51. Assumed Elevator Bore Diameter Nolte: A raised elevator OD Increases elevates capaco a4hwt alfecllig rnake-lap torque. Pipe Body Slip Crushing Capacity pipe Body Configuration If 5 (n) OD 0.362 („) Wall S-135) Nominal 1 80 % Inspection Gass I API Premium Class tq Slio Crushing Capacity (6-) 498,300 396,500 396,500 ly/ N. Slry C-Wq Slip vtftlng kw Is dcuokH Hh 12 SpY°.RelnMd egLLYlu` ftom Vf' DOG D.11 Rpe Assumed SlipLen th (n) 16.5 Fal in to Stp rues" MM C!. 19M 1cf as fit W'l h are haiarerm low rattor sr. -are is tar naerenoe Transverse Load Factor (Kl 4.2 y r., darn `t"� S depended on the slp &!iVn aro ccrd0on. creeklenl u (dile,, kiaddr0 =oNro-e.. tine h pis p" 00 and wall araban, xZMC (Barns. Car" Wile d1e s/p maufachre for aoamrol lVorrktllm. Pine Bodv Performance Pipe Body Configuration ( 5 {in) OD 0.362 (in) Wan S-135) Page 52 Version 1 Jan, 2016 Nde: No.*.] Burst ca --ted at 07.58 RBW Per API. Nominal 80 % Inspection Gass API Premitam Gass Pipe Tensile Strengitih 21i, 712,100 560.800 560,800 Pipe Torsional Strength (n -lbs) 74,100 58,100 58,100 TJ/PlpeBody Torsional Ratio 0.97 1.24 1.24 80% Pipe Torsional Strength mlb) 59.300 46,500 46,500 Burst (Pull 17,105 15.638 15,638 Colla iv-si) 15,672 10,029 10,029 Pipe OD inn) 5.000 4.855 4.855 Wall Thickness om 0.362 0.290 0-11W Nominal fte ID (in) 4.276 4.276 4.276 Cross Sectional Area of Pipe Body un -21 5275 4.154 4.154 Cross Sectional Area of OD (in -2) 19.635 18.514 18.514 Cross Sectional Area of ID nn^z1 14.360 14.360 114.360 Section Modulus (In"3) 5.708 4.476 14A76 Polar Section Modulus (l. -I11.4115 18.953 18.953 Version 1 Jan, 2016 Nde: No.*.] Burst ca --ted at 07.58 RBW Per API. Milne Point Unit B-29 Drilling Procedure Hilcorp Energy Company Operational Limits of Drill Pipe Connection GPDS50 Tod Joint OD „n> 6.625 Tool Joint ID tin 3.250 Tool Joint Specified Minllaurn 1� 040 Yield Strength tcs l Pipe Body 80 % Inspection Class j Pipe Body OD (3n)15 I IWall Thickness MI 0.362I Pipe Body Grade S-135 Combined Loading for Drill Pipe at Maximum Make-up Torque = 43,100 (n -m5) Operational Assembly Torque Max Tension (MMS) Ibbs' 0 560.800 2,100 560 400 4,200 559.300 6,300 557.500 8,300 555,000 10,400 551,700 12,500 547,600 14,600 542.800 16,700 537.100 18,800 530,600 20,600 523,600 22,900 515,400 25.000 506.200 27,100 496,100 29,200 484.800 31,300 472,500 33,300 459 600 35,400 444,700 37,500 428,400 39,600 410,500 Pipe Body ccnnecnon Mex Max Tension Tension (1051 'Ib:l 560,800 1,046.900 560,400 1,046,900 559,300 1,046.900 557,500 j 1,046,900 555,000 11,046.900 551,700 11.046.9W 547.600 1,046,900 542,800 1,046.9D0 537,100 1,046.900 530,600 1,046,900 523,600 1,046,900 515,400 1,046,900 506,200 1,046.900 496,100 1,046.900 484,800 1,046.900 472,500 1,046,900 459,600 1.046.900 444,700 1,046,900 428,400 1,046.900 410,500 1,046,900 Operational ding torque is limited by the Make-up Torque. Min MUT Max MUT Combined Loading for Drill Pipe at Minimum Make-up Torque = 36,100 In4bsr Operational Assembly I Torque Max Tension 014bs {Ib! 0 560,800 1,700 560,500 3,400 559,800 5,100 1558.600 6,800 556,900 8,400 554,900 10,100 552,200 11,800 549100 13,500 545,400 15,200 541,200 16,900 536,500 18,600 531,300 20,300 525,400 22,000 519,000 23,700 512,000 25,300 504.800 27,000 496,600 28.700 487,600 30,400 477,900 32,100 467,400 Pim BOOy Ccrrecacn Mnx Tern n Max Te 11 n pb ilbsl 560.800 1,202,500 560.500 1,202,500 559.800 1,202,500 558,600 1,202,500 556.900 1,202,500 554.900 1,202,500 552.200 1,202,500 549.100 1.202,500 545.400 1,202,500 541,200 11,202.SN 1,046,900 536.500 1,202,500 531.300 1,202,500 525.400 1,202,500 519.000 1,202,5tNJ 512.000 1,202,500 504,800 1,202,500 496.600 11.202.500 487.600 1,202,600 477.900 1,202,500 467,400 1,202,500 Operational drilling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max rn-lbsI Tension Vbsl. 36,100 1,202,500 36,900 1,229,200 37,700 1,243,600 38,400 1,218,100 39,200 1,189,000 40,000 1,159,800 40,800 1,130,700 41,500 1,105,200 42,300 1,076,100 43,100 1,046,900 Page 53 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point Unit B-29 Drilling Procedure Connection Wear Table connection GPDS50 jTooIJointID „,; 3250 Tool Jit Specified Minimum 120 fl00 YieldSlrength ��� Connection Wear New OD, Worn OD Max MUT 11.41-J 43,100 Connection Max Tension 1111-1 1,046,900 43,100 1,034, 900 43,100 11,022,600 35,900 43,100 1,009 , ,009, 800 42,700 1,008,100 40,800 1,057,300 38,900 1,104,800 37,000 1,150,400 35,200 1,190,900 33,300 1,232,300 31,500 1,227,200 29,800 1,187,100 Pipe Body Combined Loading Table (Torque -Tension) Min MUT Connection Max Tension f".br'65� fib-. 35,900 1,195,900 35,900 1,208,700 35,900 1,222,400 35.900 1,237.500 35,600 1,245,200 34,000 1,207.700 32.400 1,169.800 30,800 1,131,300 29,300 1,096.100 27.800 1,060.800 26,300 1,024.600 24,800 987.900 Pipe Boli► 80 % Inspection Class jPipeBodyOD WO Thickness ,1, 0.362 Pipe Body Grade S-135 III Pipe Body Torque 0 5.300 10.600 15.800 21.100 26,400 31.700 37A0 42.300 47,500 52.800 58.100 rn4hsr Pipe Body Maxx Ten Tension 560.800 558,400 551,400 539.600 522.500 499.600 470,000 432,400 384,500 323,100 234.300 12.200 ne-r Page 54 Version 1 Jan, 2016 Hilcorp Energy Company Milne Point M Pt B Pad Plan MPB-29 MPB-29 Plan: MPB-29 WP01 Standard Proposal Report 15 December, 2015 HALLIBURTON Sperry Drilling Services MALLIBURTON SECTION DETAILS REFERENCE Sec MD Inc Azi TVD 1500 Project: Milne Point TFace VSed Target 2000 0.00 0.00 32.80 0.00 0.00 Site: M Pt B Pad C-rdinete(N/E)Rer ante: 2 300.00 3000 0.00 0.00 Well: Plan MPB-29 Veli-l(M)Rereren°e: Section (VS)nd 3587.35 5.75 272.19 586.87 p0 Wellbore: MPB-29 Meed Depth Ref - 4 1877.97 5.75 272.19 1871.00 9 5/8" Design: MPB-29 WP01 ho& ce1`utns°°Mea'°d; -500- 272.19 2069.99 6.25 -163.54 0.00 0.00 131.56 6 2398.97 12.10 220.63 2387.37 -18.73 -201.61 3.00-79,04 1 500 SECTION DETAILS 1000 Sec MD Inc Azi TVD 1500 Dleg TFace VSed Target 2000 0.00 0.00 32.80 0.00 0.00 2500 0.00 0.00 2 300.00 3000 0.00 0.00 0.00 3500 3587.35 5.75 272.19 586.87 p0 2.00 272.19 11.58 4 1877.97 5.75 272.19 1871.00 9 5/8" MPB-29 Heel INFORMATION WELL DEfARS: PI. MTB -29 NAD 1927(NADCON CONUS) Alaska Z-04Web Plan MTB -29, T.. North Gmund Levet 23.70 Plan WB -29 56 SOusft (Doyon 14) +NAS +F/ -W Nortlmtg Resting IAtittude Longkude Slot Plmc M Slat -N 002,PB-29 @ 56,SOuaft (Doyon 14) . 0.00 0.00 6023042.84 572006.49 70° 29 23.661 N 149° 24'42.682 W bimimum C-.,..,6.n�e CASING DEEMS TVD TVDSS MD Size Nara 4426.50 4370.00 5176.69 9-5/8 9 5/8" 4421.50 4365.00 10552.47 5-1/2 51/2" 5 1/2" ---- MP13-29 WP01 MPB-29 Toe N -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 308.69° (1000 usft/in) 8000 SECTION DETAILS Sec MD Inc Azi TVD +N/ -S -E/-W Dleg TFace VSed Target 1 32.80 0.00 0.00 32.80 0.00 0.00 0.00 0.00 0.00 2 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 3587.35 5.75 272.19 586.87 0.55 -14.39 2.00 272.19 11.58 4 1877.97 5.75 272.19 1871.00 5.49 -143.53 0.00 0.00 115.46 5 2077.975.75 272.19 2069.99 6.25 -163.54 0.00 0.00 131.56 6 2398.97 12.10 220.63 2387.37 -18.73 -201.61 3.00-79,04 145.66 7 3285.41 12.10 220.63 3254.10 -159.79 -322.66 0.00 0.00 151.97 8 5026.69 85.00 320.00 4413.43 497.75 -1168.43 5.00 100.20 1223.16 9 5176.69 85.00 320.00 4426.50 612.22 -1264.48 0.00 0.00 1369.68 MPB-29 Heel 10 5306.30 90.73 321.11 4431.33 712.20 -1346.73 4.50 10.96 1496.38 11 5649.07 90.73 321.11 4426.98 978.97 -1561.93 0.00 0.00 1831.11 12 5852.47 90.05 310.96 4425.60 1125.16 -1702.94 5.00 -93.77 2032.57 1310552.47 90.05 310.96 4421.50 4206.16 -5252.23 0.00 0.00 6728.87 MPB-29 T- 5 1/2" ---- MP13-29 WP01 MPB-29 Toe N -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 308.69° (1000 usft/in) 8000 HALLIPUPTON Project: Milne Point REFERENCE INFORMATION WELL DE IS: PI. MTB -29 NAD 1927(NADCON CONUS) Aladin 7nne 04 Site: M Pt B Pad C—dinata (WE) Rales— W.H Ph, MP629, T. N— Gmtmd LeveL 23.70 Well: Plan MPB-29 WW I(TVD)RaN—.: Plan: MP&29 Q W,Wuft(Do 14) +NIS +F/ -W Northng Fasting Leliltude Longitudc Slut Measured O pth ReI--: =: wN @ 58. W"ft (Doyon 14) 0.00 O.00i023042.84 572006.48 70° 28 11.111N149- 24' 42.682 W Wellbore: MPB-29 --m a Method: Minimum Curvature Plan: MPB-29 WP01 CASING DETAU S West( -)/Fast(+) (1000 ustt<n) WALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt B Pad Well: Plan MPB-29 Wellbore: MPB-29 Design: MPB-29 WP01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan MPB-29 Plan: MPB-29 @ 56.50usft (Doyon 14) Plan: MPB-29 @ 56.50usft (Doyon 14) True Minimum Curvature Project Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Model Name Using Well Reference Point Declination Map Zone: Alaska Zone 04 Field Strength Using geodetic scale factor Site M Pt B Pad, TR -13-11 (nT) Site Position: Northing: 6,021,548.49 usft Latitude: 70° 28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149° 24'49.895 W Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55 ° Well Plan MPB-29 Design MPB-29 WP01 Well Position +N/ -S 0.00 usft Northing: 6,023,042.84 usft Latitude: 70° 28'23.661 N +E/ -W 0.00 usft Easting: 572,006.48 usft Longitude: 149° 24'42.682 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 23.70 usft Wellbore MPB-29 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (nT) BGGM2015 12/4/2015 18.90 81.09 57,509 Design MPB-29 WP01 Audit Notes: Version: Phase: PLAN Tie On Depth: 32.80 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I 32.80 0.00 0.00 308.69 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100u8ft) (°) 32.80 0.00 0.00 32.80 -23.70 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 243.50 0.00 0.00 0.00 0.00 0.00 0.00 587.35 5.75 272.19 586.87 530.37 0.55 -14.39 2.00 2.00 -30.56 272.19 1,877.97 5.75 272.19 1,871.00 1,814.50 5.49 -143.53 0.00 0.00 0.00 0.00 2,077.97 5.75 272.19 2,069.99 2,013.49 6.25 -163.54 0.00 0.00 0.00 0.00 2,398.97 12.10 220.63 2,387.37 2,330.87 -18.73 -201.61 3.00 1.98 -16.06 -79.04 3,285.41 12.10 220.63 3,254.10 3,197.60 -159.79 -322.66 0.00 0.00 0.00 0.00 5,026.69 85.00 320.00 4,413.43 4,356.93 497.75 -1,168.43 5.00 4.19 5.71 100.20 5,176.69 85.00 320.00 4,426.50 4,370.00 612.22 -1,264.48 0.00 0.00 0.00 0.00 5,306.30 90.73 321.11 4,431.33 4,374.83 712.20 -1,346.73 4.50 4.42 0.85 10.96 5,649.07 90.73 321.11 4,426.98 4,370.48 978,97 -1,561.93 0.00 0.00 0.00 0.00 5,852.47 90.05 310.96 4,425.60 4,369.10 1,125.16 -1,702.94 5.00 -0.33 -4.99 -93.77 10,552.47 90.05 310.96 4,421.50 4,365.00 4,206.16 -5,252.23 0.00 0.00 0.00 0.00 12/152015 11:10.08AM Page 2 COMPASS 5000.1 Build 73 Halliburton HALLiBURT©N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPB-29 Company: Hilcorp Energy Company TVD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Project: Milne Point MD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Site: M Pt B Pad North Reference: True Well: Plan MPB-29 Survey Calculation Method: Minimum Curvature Wellbore: MPB-29 Depth Inclination Design: MPB-29 WP01 TVDss +N/ -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -23.70 32.80 0.00 0.00 32.80 -23.70 0.00 0.00 6,023,042.84 572,006.48 0.00 0.00 100.00 0.00 0.00 100.00 43.50 0.00 0.00 6,023,042.84 572,006.48 0.00 0.00 200.00 0.00 0.00 200.00 143.50 0.00 0.00 6,023,042.84 572,006.48 0.00 0.00 300.00 0.00 0.00 300.00 243.50 0.00 0.00 6,023,042.84 572,006.48 0.00 0.00 400.00 2.00 272.19 399.98 343.48 0.07 -1.74 6,023,042.89 572,004.74 2.00 1.40 500.00 4.00 272.19 499.84 443.34 0.27 -6.97 6,023,043.04 571,999.51 2.00 5.61 587.35 5.75 272.19 586.87 530.37 0.55 -14.39 6,023,043.25 571,992.09 2.00 11.58 600.00 5.75 272.19 599.45 542.95 0.60 -15.65 6,023,043.29 571,990.82 0.00 12.59 700.00 5.75 272.19 698.95 642.45 0.98 -25.66 6,023,043.57 571,980.81 0.00 20.64 800.00 5.75 272.19 798.45 741.95 1.36 -35.67 6,023,043.86 571,970.80 0.00 28.69 900.00 5.75 272.19 897.95 841.45 1.75 -45.67 6,023,044.14 571,960.80 0.00 36.74 1,000.00 5.75 272.19 997.44 940.94 2.13 -55.68 6,023,044.43 571,950.79 0.00 44.79 1,100.00 5.75 272.19 1,096.94 1,040.44 2.51 -65.69 6,023,044.72 571,940.78 0.00 52.84 1,200.00 5.75 272.19 1,196.44 1,139.94 2.89 -75.69 6,023,045.00 571,930.77 0.00 60.89 1,300.00 5.75 272.19 1,295.94 1,239.44 3.28 -85.70 6,023,045.29 571,920.76 0.00 68.94 1,400.00 5.75 272.19 1,395.43 1,338.93 3.66 -95.70 6,023,045.57 571,910.75 0.00 76.99 1,500.00 5.75 272.19 1,494.93 1,438.43 4.04 -105.71 6,023,045.86 571,900.74 0.00 85.04 1,600.00 5.75 272.19 1,594.43 1,537.93 4.42 -115.72 6,023,046.14 571,890.74 0.00 93.09 1,700.00 5.75 272.19 1,693.93 1,637.43 4.81 -125.72 6,023,046.43 571,880.73 0.00 101.14 1,800.00 5.75 272.19 1,793.42 1,736.92 5.19 -135.73 6,023,046.72 571,870.72 0.00 109.19 1,877.97 5.75 272.19 1,871.00 1,814.50 5.49 -143.53 6,023,046.94 571,862.92 0.00 115.46 Interp @ 1871.00 (MPB-29 MPB-29 MPB-29 WP01) 1,900.00 5.75 272.19 1,892.92 1,836.42 5.57 -145.74 6,023,047.00 571,860.71 0.00 117.24 2,000.00 5.75 272.19 1,992.42 1,935.92 5.96 -155.74 6,023,047.29 571,850.70 0.00 125.29 2,077.97 5.75 272.19 2,069.99 2,013.49 6.25 -163.54 6,023,047.51 571,842.90 0.00 131.56 2,100.00 5.91 265.87 2,091.91 2,035.41 6.21 -165.78 6,023,047.45 571,840.67 3.00 133.28 2,200.00 7.37 242.96 2,191.26 2,134.76 2.93 -176.63 6,023,044.06 571,829.85 3.00 139.70 2,300.00 9.58 229.02 2,290.17 2,233.67 -5.45 -188.63 6,023,035.56 571,817.93 3.00 143.83 2,398.97 12.10 220.63 2,387.37 2,330.87 -18.73 -201.61 6,023,022.16 571,805.08 3.00 145.66 2,400.00 12.10 220.63 2,388.38 2,331.88 -18.90 -201.75 6,023,022.00 571,804.94 0.00 145.67 2,500.00 12.10 220.63 2,486.15 2,429.65 -34.81 -215.41 6,023,005.95 571,791.44 0.00 146.38 2,600.00 12.10 220.63 2,583.93 2,527.43 -50.72 -229.06 6,022,989.91 571,777.94 0.00 147.09 2,700.00 12.10 220.63 2,681.71 2,625.21 -66.63 -242.72 6,022,973.87 571,764.44 0.00 147.80 2,800.00 12.10 220.63 2,779.48 2,722.98 -82.55 -256.37 6,022,957.82 571,750.94 0.00 148.51 2,900.00 12.10 220.63 2,877.26 2,820.76 -98.46 -270.03 6,022,941.78 571,737.44 0.00 149.23 3,000.00 12.10 220.63 2,975.04 2,918.54 -114.37 -283.69 6,022,925.74 571,723.94 0.00 149.94 3,100.00 12.10 220.63 3,072.81 3,016.31 -130.29 -297.34 6,022,909.69 571,710.44 0.00 150.65 3,200.00 12.10 220.63 3,170.59 3,114.09 -146.20 -311.00 6,022,893.65 571,696.94 0.00 151.36 3,285.41 12.10 220.63 3,254.10 3,197.60 -159.79 -322.66 6,022,879.95 571,685.41 0.00 151.97 3,300.00 12.00 224.09 3,268.37 3,211.87 -162.04 -324.71 6,022,877.68 571,683.38 5.00 152.16 3,400.00 12.42 247.81 3,366.17 3,309.67 -173.57 -341.91 6,022,865.98 571,666.30 5.00 158.38 3,500.00 14.63 267.15 3,463.44 3,406.94 -178.27 -364.50 6,022,861.07 571,643.76 5.00 173.08 3,600.00 17.97 280.49 3,559.44 3,502.94 -176.08 -392.29 6,022,862.99 571,615.94 5.00 196.14 3,700.00 21.94 289.47 3,653.44 3,596.94 -167.04 -425.09 6,022,871.71 571,583.06 5.00 227.39 3,800.00 26.24 295.73 3,744.73 3,688.23 -151.21 -462.64 6,022,887.18 571,545.37 5.00 266.60 12/1512015 11:10:08AM Page 3 COMPASS 5000.1 Build 73 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPB-29 Company: Hilcorp Energy Company TVD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Project: Milne Point MD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Site: M Pt B Pad North Reference: True Well: Plan MPB-29 Survey Calculation Method: Minimum Curvature Wellbore: MPB-29 Depth Inclination Azimuth Design: MPB-29 WP01 +Nl-S +E/ -W Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +Nl-S +E/ -W Northing Easting DLS Vert Section (usft) V) V) (usft) usft (usft) (usft) (usft) (usft) 3,776.10 3,900.00 30.75 300.29 3,832.60 3,776.10 -128.71 -504.66 6,022,909.27 571,503.14 5.00 313.46 4,000.00 35.37 303.77 3,916.40 3,859.90 -99.71 -550.82 6,022,937.82 571,456.70 5.00 367.62 4,100.00 40.08 306.54 3,995.48 3,938.98 -64.43 -600.77 6,022,972.61 571,406.41 5.00 428.66 4,200.00 44.84 308.81 4,069.24 4,012.74 -23.14 -654.14 6,023,013.38 571,352.65 5.00 496.13 4,300.00 49.64 310.73 4,137.12 4,080.62 23.85 -710.52 6,023,059.81 571,295.83 5.00 569.50 4,400.00 54.46 312.39 4,198.60 4,142.10 76.17 -769.48 6,023,111.55 571,236.38 5.00 648.23 4,500.00 59.31 313.86 4,253.22 4,196.72 133.43 -830.56 6,023,168.21 571,174.74 5.00 731.70 4,600.00 64.17 315.20 4,300.56 4,244.06 195.19 -893.31 6,023,229.36 571,111.40 5.00 819.29 4,700.00 69.04 316.42 4,340.26 4,283.76 260.99 -957.25 6,023,294.53 571,046.84 5.00 910.33 4,800.00 73.92 317.57 4,372.02 4,315.52 330.32 -1,021.89 6,023,363.23 570,981.54 5.00 1,004.12 4,900.00 78.81 318.66 4,395.59 4,339.09 402.66 -1,086.74 6,023,434.93 570,916.00 5.00 1,099.96 5,000.00 83.69 319.72 4,410.80 4,354.30 477.45 -1,151.31 6,023,509.08 570,850.72 5.00 1,197.10 5,026.69 85.00 320.00 4,413.43 4,356.93 497.75 -1,168.43 6,023,529.22 570,833.40 5.00 1,223.16 5,100.00 85.00 320.00 4,419.82 4,363.32 553.70 -1,215.37 6,023,584.70 570,785.92 0.00 1,294.77 5,176.69 85.00 320.00 4,426.50 4,370.00 612.22 -1,264.48 6,023,642.74 570,736.26 0.00 1,369.69 95/81, 5,187.00 85.46 320.09 4,427.36 4,370.86 620.10 -1,271.08 6,023,650.56 570,729.58 4.50 1,379.77 MPB-29 Heel 5,200.00 86.03 320.20 4,428.32 4,371.82 630.05 -1,279.39 6,023,660.43 570,721.18 4.50 1,392.47 5,300.00 90.45 321.05 4,431.40 4,374.90 707.30 -1,342.78 6,023,737.05 570,657.05 4.50 1,490.23 5,306.30 90.73 321.11 4,431.33 4,374.83 712.20 -1,346.73 6,023,741.91 570,653.05 4.50 1,496.38 5,400.00 90.73 321.11 4,430.14 4,373.64 785.12 -1,405.56 6,023,814.26 570,593.52 0.00 1,587.89 5,500.00 90.73 321.11 4,428.87 4,372.37 862.95 -1,468.34 6,023,891.46 570,530.00 0.00 1,685.54 5,600.00 90.73 321.11 4,427.61 4,371.11 940.78 -1,531.12 6,023,968.67 570,466.47 0.00 1,783.19 5,649.07 90.73 321.11 4,426.98 4,370.48 978.97 -1,561.93 6,024,006.56 570,435.30 0.00 1,831.11 5,700.00 90.56 318.57 4,426.41 4,369.91 1,017.88 -1,594.77 6,024,045.15 570,402.09 5.00 1,881.07 5,800.00 90.23 313.58 4,425.73 4,369.23 1,089.88 -1,664.12 6,024,116.46 570,332.05 5.00 1,980.21 5,852.47 90.05 310.96 4,425.60 4,369.10 1,125.16 -1,702.94 6,024,151.37 570,292.89 5.00 2,032.57 5,900.00 90.05 310.96 4,425.56 4,369.06 1,156.32 -1,738.84 6,024,182.18 570,256.70 0.00 2,080.06 6,000.00 90.05 310.96 4,425.47 4,368.97 1,221.88 -1,814.36 6,024,246.99 570,180.56 0.00 2,179.98 6,100.00 90.05 310.96 4,425.39 4,368.89 1,287.43 -1,889.87 6,024,311.81 570,104.42 0.00 2,279.91 6,200.00 90.05 310.96 4,425.30 4,368.80 1,352.98 -1,965.39 6,024,376.62 570,028.28 0.00 2,379.83 6,300.00 90.05 310.96 4,425.21 4,368.71 1,418.54 -2,040.91 6,024,441.43 569,952.14 0.00 2,479.75 6,400.00 90.05 310.96 4,425.12 4,368.62 1,484.09 -2,116.42 6,024,506.25 569,876.00 0.00 2,579.67 6,500.00 90.05 310.96 4,425.04 4,368.54 1,549.64 -2,191.94 6,024,571.06 569,799.86 0.00 2,679.59 6,600.00 90.05 310.96 4,424.95 4,368.45 1,615.19 -2,267.46 6,024,635.87 569,723.72 0.00 2,779.51 6,700.00 90.05 310.96 4,424.86 4,368.36 1,680.75 -2,342.97 6,024,700.69 569,647.58 0.00 2,879.43 6,800.00 90.05 310.96 4,424.77 4,368.27 1,746.30 -2,418.49 6,024,765.50 569,571.44 0.00 2,979.36 6,900.00 90.05 310.96 4,424.69 4,368.19 1,811.85 -2,494.01 6,024,830.31 569,495.30 0.00 3,079.28 7,000.00 90.05 310.96 4,424.60 4,368.10 1,877.41 -2,569.52 6,024,895.13 569,419.16 0.00 3,179.20 7,100.00 90.05 310.96 4,424.51 4,368.01 1,942.96 -2,645.04 6,024,959.94 569,343.02 0.00 3,279.12 7,200.00 90.05 310.96 4,424.43 4,367.93 2,008.51 -2,720.56 6,025,024.75 569,266.87 0.00 3,379.04 7,300.00 90.05 310.96 4,424.34 4,367.84 2,074.07 -2,796.08 6,025,089.57 569,190.73 0.00 3,478.96 7,400.00 90.05 310.96 4,424.25 4,367.75 2,139.62 -2,871.59 6,025,154.38 569,114.59 0.00 3,578.88 7,500.00 90.05 310.96 4,424.16 4,367.66 2,205.17 -2,947.11 6,025,219.19 569,038.45 0.00 3,678.81 12/152015 11:10:08AM Page 4 COMPASS 5000.1 Build 73 Halliburton H A LL I B U RTO N Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Plan MPB-29 Company: Hilcorp Energy Company TVD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Project: Milne Point MD Reference: Plan: MPB-29 @ 56.50usft (Doyon 14) Site: M Pt B Pad North Reference: True Well: Plan MPB-29 Survey Calculation Method: Minimum Curvature Wellbore: MPB-29 Depth Inclination Design: MPB-29 WP01 TVDss +NI -S Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI -S +EI -W Northing Easting DLS Vert Section (usft) V) (') (usft) usft (usft) (usft) (usft) (usft) 4,367.58 7,600.00 90.05 310.96 4,424.08 4,367.58 2,270.73 -3,022.63 6,025,284.01 568,962.31 0.00 3,778.73 7,700.00 90.05 310.96 4,423.99 4,367.49 2,336.28 -3,098.14 6,025,348.82 568,886.17 0.00 3,878.65 7,800.00 90.05 310.96 4,423.90 4,367.40 2,401.83 -3,173.66 6,025,413.63 568,810.03 0.00 3,978.57 7,900.00 90.05 310.96 4,423.81 4,367.31 2,467.39 -3,249.18 6,025,478.45 568,733.89 0.00 4,078.49 8,000.00 90.05 310.96 4,423.73 4,367.23 2,532.94 -3,324.69 6,025,543.26 568,657.75 0.00 4,178.41 8,100.00 90.05 310.96 4,423.64 4,367.14 2,598.49 -3,400.21 6,025,608.07 568,581.61 0.00 4,278.33 8,200.00 90.05 310.96 4,423.55 4,367.05 2,664.05 -3,475.73 6,025,672.89 568,505.47 0.00 4,378.25 8,300.00 90.05 310.96 4,423.47 4,366.97 2,729.60 -3,551.24 6,025,737.70 568,429.33 0.00 4,478.18 8,400.00 90.05 310.96 4,423.38 4,366.88 2,795.15 -3,626.76 6,025,802.51 568,353.19 0.00 4,578.10 8,500.00 90.05 310.96 4,423.29 4,366.79 2,860.71 -3,702.28 6,025,867.33 568,277.05 0.00 4,678.02 8,600.00 90.05 310.96 4,423.20 4,366.70 2,926.26 -3,777.79 6,025,932.14 568,200.91 0.00 4,777.94 8,700.00 90.05 310.96 4,423.12 4,366.62 2,991.81 -3,853.31 6,025,996.95 568,124.77 0.00 4,877.86 8,800.00 90.05 310.96 4,423.03 4,366.53 3,057.36 -3,928.83 6,026,061.77 568,048.63 0.00 4,977.78 8,900.00 90.05 310.96 4,422.94 4,366.44 3,122.92 -4,004.34 6,026,126.58 567,972.49 0.00 5,077.70 9,000.00 90.05 310.96 4,422.85 4,366.35 3,188.47 -4,079.86 6,026,191.39 567,896.35 0.00 5,177.63 9,100.00 90.05 310.96 4,422.77 4,366.27 3,254.02 -4,155.38 6,026,256.21 567,820.21 0.00 5,277.55 9,200.00 90.05 310.96 4,422.68 4,366.18 3,319.58 -4,230.89 6,026,321.02 567,744.07 0.00 5,377.47 9,300.00 90.05 310.96 4,422.59 4,366.09 3,385.13 -4,306.41 6,026,385.83 567,667.93 0.00 5,477.39 9,400.00 90.05 310.96 4,422.51 4,366.01 3,450.68 -4,381.93 6,026,450.65 567,591.79 0.00 5,577.31 9,500.00 90.05 310.96 4,422.42 4,365.92 3,516.24 -4,457.44 6,026,515.46 567,515.65 0.00 5,677.23 9,600.00 90.05 310.96 4,422.33 4,365.83 3,581.79 -4,532.96 6,026,580.27 567,439.51 0.00 5,777.15 9,700.00 90.05 310.96 4,422.24 4,365.74 3,647.34 -4,608.48 6,026,645.09 567,363.37 0.00 5,877.08 9,800.00 90.05 310.96 4,422.16 4,365.66 3,712.90 -4,683.99 6,026,709.90 567,287.23 0.00 5,977.00 9,900.00 90.05 310.96 4,422.07 4,365.57 3,778.45 -4,759.51 6,026,774.71 567,211.09 0.00 6,076.92 10,000.00 90.05 310.96 4,421.98 4,365.48 3,844.00 -4,835.03 6,026,839.53 567,134.95 0.00 6,176.84 10,100.00 90.05 310.96 4,421.89 4,365.39 3,909.56 -4,910.54 6,026,904.34 567,058.81 0.00 6,276.76 10,200.00 90.05 310.96 4,421.81 4,365.31 3,975.11 -4,986.06 6,026,969.15 566,982.67 0.00 6,376.68 10,300.00 90.05 310.96 4,421.72 4,365.22 4,040.66 -5,061.58 6,027,033.97 566,906.53 0.00 6,476.60 10,400.00 90.05 310.96 4,421.63 4,365.13 4,106.22 -5,137.09 6,027,098.78 566,830.39 0.00 6,576.53 10,500.00 90.05 310.96 4,421.55 4,365.05 4,171.77 -5,212.61 6,027,163.60 566,754.25 0.00 6,676.45 10,552.47 90.05 310.96 4,421.50 4,365.00 4,206.16 -5,252.23 6,027,197.60 566,714.30 0.00 6,728.87 MPB-29 Toe 12/15/2015 11:10:08AM Page 5 COMPASS 5000.1 Build 73 HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Milne Point Site: M Pt B Pad Well: Plan MPB-29 Wellbore: MPB-29 Design: MPB-29 WP01 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well Plan MPB-29 Plan: MPB-29 @ 56.50usft (Doyon 14) Plan: MPB-29 @ 56.50usft (Doyon 14) True Minimum Curvature Targets Measured Vertical Casing Hole Depth Depth Target Name (usft) (usft) Name (") (") 5,176.69 4,426.50 95/8" 9-5/8 12-1/4 10,552.47 hit/miss target Dip Angle Dip Dir. TVD +N/ -S +EI -W Northing Easting Shape (I V) (usft) (usft) (usft) (usft) (usft) MPB-29 Heel 0.00 0.00 4,426.50 684.11 -1,194.63 6,023,715.30 570,805.40 - plan misses target center by 99.71usft at 5186.90usft MD (4427.35 TVD, 620.03 N, -1271.02 E) -Circle (radius 100.00) Interp @ 1871.00 (MPB-29 MPB-29 MPB-29 WP01) 0.00 0.00 1,871.00 5.49 -143.53 6,023,046.94 571,862.92 plan hits target center Point MPB-29 Toe 0.00 0.00 4,421.50 4,206.16 -5,252.23 6,027,197.60 566,714.30 - plan hits target center -Circle (radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 5,176.69 4,426.50 95/8" 9-5/8 12-1/4 10,552.47 4,421.50 51/2" 5-1/2 8-1/2 121152015 11:10:08AM Page 6 COMPASS 5000.1 Build 73 Hilcorp Energy Company Milne Point M Pt B Pad Plan MPB-29 MPB-29 MPB-29 WP01 Sperry Drilling Services Clearance Summary Anticollision Report 15 December, 2015 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt B Pad - Plan MPB-29 - MPB-29 - MPB-29 WP01 Well Coordinates: 6,023,042.84 N, 572,006.48 E (70" 28'23,66" N, 149° 24' 42.68" W) Datum Height: Plan: MPB-29 @ 56.50usft (Doyon 14) Scan Range: 0.00 to 10,552.47 usft. Measured Depth. Scan Radius is 1,251.97 usft . Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Scan Type: 25.00 HALLIBURTON Sperry Orilling Services HALLIBURTON Anticollision Report for Plan MPB-29 - MPB-29 WP01 Hileorp Energy Company Milne Point Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt B Pad - Plan MPB-29 - MPB-29 - MPB-29 WP01 Scan Range: 0.00 to 10,552.47 usft. Measured Depth. Scan Radius is 1,251.97 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usit M Pt B Pad MPB-0I-MPB-0I-MPB-01 MPB-01 - MPB-01 - MPB-01 MPB-01-MPB-0I-MPB-01 MPB-02 - MPB-02 - MPB-02 MPB-02 - MPB-02 - MPB-02 MPB-02 - MPB-02 - MPB-02 MPB-02 - Plan MPB-02A- MPB-02Awp03 MPB-02 - Plan MPB-02A- MPB-02Awp03 MPB-02 - Plan MPB-02A- MPB-02Awp03 MPB-03 - MPB-03 - MPB-03 MPB-03 - MPB-03 - MPB-03 MPB-03 - MPB-03 - MPB-03 MPB-04 - MPB-04 - MPB-04 MPB-04 - MPB-04 - MPB-04 MPB-04 - MPB-04 - MPB-04 MPB-04 - MPB-04A- MPB-04A MPB-04 - MPB-04A- MPB-04A MPB-04 - MPB-04A- MPB-04A MPB-05 - MPB-05 - MPB-05 MPB-05 - MPB-05 - MPB-05 MPB-05 - MPB-05 - MPB-05 MPB-05 - MPB-05A- MPB-05A MPB-05 - MPB-05A- MPB-05A MPB-05 - MPB-05A- MPB-05A MPB-06 - MPB-06 - MPB-06 MPB-08 - MPB-08 - MPB-08 MPB-08 - MPB-08 - MPB-08 MPB-08 - MPB-08 - MPB-08 305.98 143.52 305.98 139.80 295.60 38.546 Centre Distance Pass - 400.00 144.03 400.00 139.22 389.87 29.945 Ellipse Separation Pass - 2,750.00 295.69 2,750.00 269.84 2,720.81 11.440 Clearance Factor Pass - 609.83 77.70 609.83 71.69 598.73 12.933 Centre Distance Pass - 675.00 78.02 675.00 71.35 663.52 11.697 Ellipse Separation Pass - 1,000.00 88.35 1,000.00 78.61 986.56 9.065 Clearance Factor Pass - 328.07 80.50 328.07 78.13 317.39 34.021 Centre Distance Pass - 400.00 80.65 400.00 78.01 388.53 30.613 Ellipse Separation Pass - 850.00 104.26 850.00 99.07 829.44 20.080 Clearance Factor Pass - 32.80 205.21 32.80 204.51 35.20 293.865 Centre Distance Pass - 325.00 205.88 325.00 202.05 327.53 53.763 Ellipse Separation Pass - 4,000.00 253.04 4,000.00 217.17 4,138.26 7.056 Clearance Factor Pass - 329.57 243.52 329.57 239.30 334.51 57.746 Centre Distance Pass - 350.00 243.59 350.00 239.14 354.81 54.715 Ellipse Separation Pass - 2,300.00 417.71 2,300.00 395.57 2,297.54 18.865 Clearance Factor Pass - 3,802.51 107.74 3,802.51 67.06 3,995.06 2.649 Centre Distance Pass - 3,825.00 108.63 3,825.00 66.36 4,014.19 2.570 Ellipse Separation Pass - 3,850.00 111.73 3,850.00 67.86 4,035.17 2.547 Clearance Factor Pass - 302.53 234.54 302.53 230.43 305.20 57.024 Centre Distance Pass - 400.00 235.17 400.00 229.96 405.51 45.126 Ellipse Separation Pass - 1,000.00 294.45 1,000.00 282.65 965.13 24.958 Clearance Factor Pass - 302.53 234.54 302.53 230.43 305.20 57.024 Centre Distance Pass - 400.00 235.17 400.00 229.96 405.51 45.126 Ellipse Separation Pass - 1,000.00 294.45 1,000.00 282.65 965.13 24.958 Clearance Factor Pass - 1,667.06 45.82 1,667.06 26.20 1,689.26 2.336 Clearance Factor Pass - 797.03 792.84 797.03 783.01 759.54 80.663 Centre Distance Pass - 7,025.00 899.08 7,025.00 641.21 5,270.98 3.487 Ellipse Separation Pass - 7,200.00 920.27 7,200.00 651.48 5,380.50 3.424 Clearance Factor Pass - 15 December, 2015 - 11:12 Page 2 of 7 COMPASS HALLIBURTON Hilcorp Energy Company Milne Point Anticollision Report for Plan MPB-29 - MPB-29 WP01 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt B Pad - Plan MPB-29 - MPB-29 - MPB-29 WP01 Scan Range: 0.00 to 10,552.47 usft Measured Depth. Scan Radius is 1,251.97 usft. Clearance Factor cutoff Is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Nama Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPB-08 - Plan MPB-08A- MPB-08A Wp6 797.03 792.84 797.03 783.17 773.64 81.966 Centre Distance Pass - MPB-08-Plan MPB-08A - MPB-08A Wp6 7,025.00 899.08 7,025.00 641.36 5,285.08 3.489 Ellipse Separation Pass - MPB-08 - Plan MPB-08A- MPB-08A Wp6 7,200.00 92027 7,200.00 651.64 5,394.60 3.426 Clearance Factor Pass - MPB-09 - MPB-09 - MPB-09 1,758.02 336.24 1,758.02 312.04 1,788.32 13.893 Centre Distance Pass - MPB-09 - MPB-09 - MPB-09 1,800.00 336.71 1,800.00 311.73 1,826.51 13.479 Ellipse Separation Pass - MPB-09 - MPB-09 - MPB-09 2,050.00 359.77 2,050.00 330.68 2,051.73 12.368 Clearance Factor Pass - MPB-10 - MPB-10 - MPBA 0 98.40 322.03 98.40 320.96 100.88 302.029 Centre Distance Pass - MPB-10 - MPB-10 - MPB-10 625.00 324.09 625.00 318.22 615.51 55.145 Ellipse Separation Pass - MPB-10 - MPB-10 - MPB-1 0 6,750.00 692.62 6,750.00 602.37 5,442.93 7.675 Clearance Factor Pass - MPB-11 - MPB-11 - MPB-11 5,694.59 217.99 5,694.59 77.64 4,982.29 1.553 Centre Distance Pass - MPB-II-MPB-II-MPB-11 5,700.00 218.04 5,700.00 77.63 4,985.72 1.553 Clearance Factor Pass- MPB-I5-MPB-I5-MPB-15 1,578.22 328.93 1,578.22 315.62 1,628.45 24.711 Ellipse Separation Pass - MPB-I5-MPB-I5-MPB-15 1,800.00 343.46 1,800.00 328.95 1,824.11 23.682 Clearance Factor Pass - MPB-17-MPB-I7-MPBA 7 159.52 29.84 159.52 27.69 156.52 13.863 Centre Distance Pass - MPB-17 - MPBA 7 - MPB-17 400.00 31.17 400.00 26.15 397.30 6.212 Ellipse Separation Pass - MPB-17 - MPB-17 - MPB-17 575.00 37.22 575.00 30.24 571.94 5.333 Clearance Factor Pass - MPB-18 - MPB-18 - MPB-18 6,856.56 871.19 6,856.56 696.97 5,108.18 5.001 Centre Distance Pass - MPS -18 - MPB-18 - MPB-18 7,100.00 889.77 7,100.00 681.69 5,277.04 4.276 Ellipse Separation Pass - MPB-18 - MPB-18 - MPB-18 7,700.00 1,063.85 7,700.00 777.08 5,716.92 3.710 Clearance Factor Pass - MPB-20 - MPB-20 - MPB-20 4,281.72 487.36 4,281.72 422.31 4,547.07 7.492 Ellipse Separation Pass - MPB-20 - MPB-20 - MPB-20 4,300.00 487.73 4,300.00 422.48 4,551.00 7.475 Clearance Factor Pass - MPB-21 ( Needs Review) - MPB-21 - MPB-21 2,859.62 171.04 2,859.62 107.28 3,255.00 2.682 Centre Distance Pass - MPB-21 ( Needs Review) - MPB-21 - MPB-21 2,875.00 17128 2,875.00 106.92 3,267.54 2.661 Ellipse Separation Pass - MPB-21 ( Needs Review) - MPB-21 - MPB-21 2,900.00 172.69 2,900.00 107.56 3,287.96 2.651 Clearance Factor Pass - MPB-21 ( Needs Review )- MPB-21 PB1 - MPB-21 PBI 2,859.62 171.04 2,859.62 107.28 3,255.00 2.682 Centre Distance Pass - MPB-21 ( Needs Review )- MPB-21 PB1 - MPB-21 PBI 2,875.00 171.28 2,875.00 106.92 3,267.54 2.661 Ellipse Separation Pass - MPB-21(Needs Review) - MPB-21 PB1 -MPB-21 PB1 2,900.00 172.69 2,900.00 107.56 3,287.96 2.651 Clearance Factor Pass - MPB-22 - MPB-22 - MPB-22 1,855.33 99.77 1,855.33 74.64 1,915.58 3.969 Centre Distance Pass - MPB-22 - MPB-22 - MPB-22 1,875.00 100.06 1,875.00 74.41 1,933.62 3.901 Ellipse Separation Pass- MPB-22-MPB-22-MPB-22 1,900.00 101.34 1,900.00 75.08 1,956.29 3.860 Clearance Factor Pass - 15 December, 2015 - 11:12 Page 3 of 7 COMPASS Hilcorp Energy Company HALLI BU RTO N Milne Point Anticollision Report for Plan MPB-29 - MPB-29 WP01 Closest Approach 3D Proximity Scan on Current Survey Data (Highside Reference) Reference Design: M Pt 8 Pad - Plan MPB-29 - MPB-29 - MPB-29 WP01 Scan Range: 0.00 to 10,552.47 usft. Measured Depth. Scan Radius is 1,251.97 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) (usft) usft MPB-22 - MPB-22A - MPB-22A 1,855.33 99.77 1,855.33 74.64 1,915.58 3.969 Centre Distance Pass - MPB-22 - MPB-22A - MPB-22A 1,875.00 100.06 1,875.00 74.41 1,933.62 3.901 Ellipse Separation Pass - MPB-22 - MPB-22A- MPB-22A 1,900.00 101.34 1,900.00 75.08 1,956.29 3.860 Clearance Factor Pass - MPB-22 - MPB-22APB1 - MPB-22APB1 1,855.33 99.77 1,855.33 74.64 1,915.58 3.969 Centre Distance Pass - MPB-22 - MPB-22APB1 - MPB-22APB1 1,875.00 100.06 1,875.00 74.41 1,933.62 3.901 Ellipse Separation Pass - MPB-22 - MPB-22APB1 - MPB-22APB1 1,900.00 101.34 1,900,00 75.08 1,956.29 3.860 Clearance Factor Pass - MPS -23 - MPB-23 - MPB-23 1,487.79 221.52 1,487.79 204.97 1,483.00 13.386 Centre Distance Pass - MPB-23 - MPB-23 - MPB-23 1,525.00 221.69 1,525.00 204.71 1,518.61 13.055 Ellipse Separation Pass - MPB-23 - MPB-23 - MPB-23 1,800.00 240.78 1,800.00 220.47 1,769.61 11.855 Clearance Factor Pass - MPB-25 - MPB-25 - MPB-25 105.83 59.85 105.83 58.68 103.13 50.842 Centre Distance Pass - MPB-25 - MPB-25 - MPB-25 1,200.00 65.33 1,200.00 56,34 1,199.65 7.271 Ellipse Separation Pass - MPB-25 - MPB-25 - MPB-25 1,250.00 66.84 1,250.00 57.54 1,247.81 7.189 Clearance Factor Pass - MPB-27 - MPB-27 - MPB-27 351.20 48.51 351.20 44.61 351.48 12.450 Centre Distance Pass - MPB-27 - MPB-27 - MPB-27 400.00 48.70 400.00 44.41 399.81 11.338 Ellipse Separation Pass - MPB-27 - MPB-27 - MPB-27 550.00 53.67 550.00 48.22 547.50 9.839 Clearance Factor Pass - MPB-27 - MPB-27 - MPB-27 wp05 291.28 50.11 291.28 46.76 291.68 14.942 Centre Distance Pass - MPB-27 - MPB-27 - MPB-27 wp05 400.00 50.47 400.00 46.25 400.00 11.965 Ellipse Separation Pass - MPB-27 - MPB-27 - MPB-27 wp05 600.00 56.24 600.00 50.71 597.57 10.167 Clearance Factor Pass - MPB-50 - MPBSO - MPB-50 wp03 300.00 231.44 300.00 227.84 301.40 64.243 Centre Distance Pass - MPB-50-MPBSO-MPB-50 wp03 325.00 231.54 325.00 227.73 326.61 60.855 Ellipse Separation pass - MPB-50-MPB-50-MPB-50 wp03 900.00 274.96 900.00 267.42 898.94 36.494 Clearance Factor Pass - MPB-50 - MPB-50 - MPB-50 32.80 231.44 32.80 230.10 34.10 172.184 Centre Distance Pass - MPB-50 - MPB-50 - MPB-50 175.00 232.19 175.00 229.47 174.38 85.283 Ellipse Separation Pass - MPB-50 - MPB-50 - MPB-50 1,000.00 292.20 1,000.00 284.06 998.81 35.890 Clearance Factor Pass - Plan MPB-28 - MPB-28 - MPB-28 WP01 250.00 89.97 250.00 86.88 250.00 29.069 Centre Distance Pass - Plan MPB-28 - MPB-28 - MPB-28 WP01 375.00 90.39 375.00 85.86 374.78 19.970 Ellipse Separation Pass - Plan MPB-28 - MPB-28 - MPB-28 WP01 775.00 122.18 775.00 113.08 763.31 13.425 Clearance Factor Pass - M Pt D Pad MPD -02 -MPD -02A -MPD -02A 10,000.00 536.22 10,000.00 379.38 5,700.00 3.419 Clearance Factor Pass - MPD -02 -MPD -02A -MPD -02A 10,075.00 526.29 10,075.00 374.37 5,722.01 3.464 Ellipse Separation Pass - 15 December, 2015 - 11:12 Page 4 of 7 COMPASS HALLIBURTON Anticollision Report for Plan MPB-29 - MPB-29 WP01 Closest Approach 3D Proximity Scan on Current Su may Data (Highside Reference) Reference Design: M Pt B Pad - Plan MPB-29 - MPB-29 - MPB-29 WP01 Scan Range: 0.00 to 10,552.47 usft. Measured Depth. Scan Radius is 1,251.97 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Site Name Depth Distance Depth Comparison Well Name - Wellbore Name - Design (usft) (usft) (usft) MPD -02 -MPD -02A -MPD -02A 10,112.85 525.02 10,112.85 Survey tool program Ellipse @Measured Clearance Summary Based on Separation Depth Factor Minimum (usft) usft 375.27 5,731.53 3.506 Centre Distance From To Survey/Plan Survey Tool (usft) (usft) 32.80 300.00 MPB-29 WP01 SRG-SS 1,000.00 8,000.00 MPB-29 WPOt MWD+IFR2+MS+sag 8,000.00 10,552.47 MPB-29 WPOt MWD+IFR2+MS+sag Ellipse error terms are correlated across survey tool tie -on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor = Distance Between Profiles /(Distance Between Profiles - Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. Hilcorp Energy Company Milne Point Separation Warning Pass - 15 Oecember, 2015 - 11:12 Page 5017 COMPASS HALLIBURTON Anticollision Report for Plan MPB-29 - MPB-29 WP01 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Plan: MPB-29 @ 56.50usft (Doyon 14). Northing and Easting are relative to Plan MPS -29. Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04. Central Meridian is -150,00°, Grid Convergence at Surface is: 0.55 Hilcorp Energy Company Milne Point ----------------------------------- Ladder Plot MPB-02,MPB-02,MPB-02V10 MPB-02, Plan MPB-02A, MPB-02Avtp03 V26 MPB-03,MPB-03,MPB-03V4 I � I MPB-04, MPB-04, MPB-04 V1 c I I I I MPB-04, MPB44A, MPB-04A V1 N 12 MPB-05,MPB-05, MPB-05V1 3 MPB-05, MPB-05A, MP8-05A V2 p CD MPB-06, MPB-06, MPB-06 V1 ----- - -' -' --- -- -------------------'--- MPB-08,MPB-08,MPB08V1 O MPB-08, Plan MPB-0BA, MPB-08AN/p6 V1 i MPB-09,MPB-09, MPB-09V1 800- tp -X- MPB-10,MPB-10,MPB-10V18 Q N I I I I MPB-15, MPB-15, MPB-15 V21 W MPB-17,MPB-17,MPB-17V1 MPB-18,MPB-18,MPB-18V1 C N MPB-20, MPB-20, MPB-2O V1 U 4 MPB-21(NeedsReview), MPB-21, MPB-21 V1 y MPB-21(NeedsReview),MPB-21P81,MPB-21PB1V O MPB-22, MPB-22, MPB-22 V1 -_-�_-------- --------- ---------- MPB-22,MPB-22A,MPB-22A\/2 (� I I I I MPB-22,MPB-22APB1,MPB-22APB1V2 MPB-23, MPB-23, MPB-23 V1 MPB-25, MPB-25, MPB-25 V1 0 2000 4000 6000 8000 10000 MPB-27, MPB-27, MPB-27 V1 2 Measured Depth (2000 usftfin) MPB-27,MPB-27,MPB-27vrpO5V65 MP B-50. MPBSO MPB-50V4 15 December, 2015 - 11:12 Page 6 of 7 COMPASS HALLIBURTON Anticollision Report for Plan MPB-29 - MPB-29 WP01 Clearance Factor Plot: Measured Depth versus Separation(Clearance) Factor Hilcorp Energy Company Milne Point 15 December, 2015 - 11:12 Page 7 of 7 COMPASS B-01,MP6-01 V1 -- -X- MPB-02, MPB-02, MPB-02 V1 0 10.00 - -- - --- - --- - -- - _._ .. - - - ----- - -- - $ MPB-02,Plan MPB-02A,MPB-02Awp03V26 $ MPB-03,MPB-03,MPB-03 V4 $ MPB-04,-04,MPB-04V1 8.75 - - __ _ ------ -- �------- - �- MPB-04,MPB04A,MPB-04A V1 $ MPB-05,MPB-05,MPB-05V1 $ MPB-05,MPB-05A,MPB-05AV2 7.50 c $ MPB-06,MP6-06,MP6-06V1 o $ MPB-08,MPB-08,MPB-08V1 No 6.25 $ MPB-08,Plan MPB-0BA,MPB-08AWp6V1 � $ MPB-09, MPB-09, MPB-09 V1 t5 U. - - MPB-110,MPB-10,MPB-10V18 C 5.00 - - -- -- ---- - - - - - - - - --- - --f -------- $ MPB-15,MPB-15,MPB-15V21 $ MPB-17,MPB-17,MPB-17V1 CL "�' MPB-18,MPB-18,MPB-16V1 U) 3.75 -d- MPB-20,MPB-20,MPB-20V1 -f MPB-21 (Needs Review), MPB-21,MPB-21 V1 $ MPB-21(NeedsReview),MPB-21PB1,MPB-21PB1V4 2.50 $MPB-22,MPB-22,MP6-22V1 Collision Avoidance Req $ MPB-22,MPB-22A,MPB-22AV2 No -0o Zone -Stop Drill in $MPB-22,MPB-22AP61,MPB-22AP61 V2 1 25 -� MPB-23,MPB-23,MP13-23V1 -'E- MPB-25,MPB-25,MPB-25V1 0.00 MPB-27, MPB-27, MPB-27 V1 2 II 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 0 $ MPB-27, MPB-27, MPB-27 wp05 V65 Measulied Depth (M t 64/in) $ MPB50, MPB50, MPB-50 V4 15 December, 2015 - 11:12 Page 7 of 7 COMPASS Area of Review — Proposed MPB-29 Injection Well Prior to completion of the MPB-29 Schrader Bluff ND injection well, an Area of Review (AOR) must be conducted. The tables below illustrate the wells within the AOR, the distance from MPB-29, completion details and integrity conditions based on in-depth review of each well. Well Name PTD Distance, Ft. Annulus Integrity MPB-03 182-056 1080 Leaking IBP with TBGxlA comms. Passing CMIT-TxIA to 3000 psi on 9/1/12 verified casing integrity. CBL TOC of 7" at 7,100'. 7"x13-3/8" cemented with 950 sks at 2091'. 13-3/8" cemented with 3200 sks with full returns to surface. MPB-04A 182-100 1060 Passing CMIT-TxIA to 2500 psi on 6/5/14. 7" casing cemented with 1000 sks Class G with estimated TOC at 8000. 7"x13-3/8" cemented with 300 sks Perm C at 2094'. 13-3/8" casing cemented to surface. MPB-20 186-005 1085 MIT -IA passed to 2000 psi on 4/22/2012. 9-5/8" Surface casing cemented back to surface with 1615 sxs of Perm E and Class G. MPB-11 185-043 230 Shut in with tubing & possible 7" casing leak. Non operable well. 9-5/8" is cemented with 800 bbls cement pumped in 9-5/8" x 15" OH. Lost returns after 80 bbls displace. Followed by 19 bbls cement top job. MPB-10 185-017 670 MIT -OA passed to 1200 psi on 8/9/2010. 9-5/8" casing was cemented back to surface with 868 bbls cement. Full returns throughout job, 50 bbls cement returned to surface. MPB-18 185-229 1080 MIT -IA to 2740 psi (passed). Cemented 9-5/8" casing with 601 bbls of Permafrost E and 56 bbls Class G. Top job with 11 bbls Permafrost E. MPB-08 185-063 900 Last MIT -IA to 1500 psi passed on 4/26/86. Long term shut-in injector with no known problems. 9-5/8" casing cemented to surface with good cement returns. MPB-19 185-230 1205 Long term shut-in producer with no known problems. Last MIT -IA to 1800 psi passed on 6/6/91. 9-5/8" casing cemented to surface with good returns. MPD -02A 183-040 820 Long term shut-in producer withTxlA comm — MITIA failed on 3/15/2008. TTP set at 8,459' on 4/4/08. CMIT— TxIA passed to 2500 psi on 2/13/2010 verifying 7" casing. 7" cemented with 925 sks class G with additional 400 sks set in 7"x13-3/8" annulus from 1760' -2400'. 13- 3/8" casing cemented to surface. Well Name Casing Size Hole Size Vol Cement Schrader Bluff ND Depth (MD) MPB-03 7" 8-1/2" 167 bbls 4560 MPB-04A 7" 8-1/2" 311 bbls 5059 MPB-20 9-5/8" 12-1/4" 512 bbls 4672 MPB-11 9-5/8" 15" 800 bbls 4902 MPB-10 9-5/8" 12-1/4" 868 bbls 5410 MPB-18 9-5/8" 12-1/4" 657 bbls 6018 MPB-08 9-5/8" 15-1/2" 878 bbls 5389 MPB-19 9-5/8" 14" 608 bbls 5984 MPD -02A 7" 8-1/2" 352 bbls 5090 � D-02 -- I , ) D -02A / \ , -19 HILCORP ALASKA LLC MILNE POINT FIELD ti� _ \_\ AOR MAP / \ \ Prreooaea uPeas Nacv —, \` FEET Bey POSTED WELL DATA Well NYTOaa WELL SYMBOLS • nch.e oa ® HJ Wce llYa4r Floopr 1 P" W BwD Phq Ba:Ju h)ccbr t.a�ean aroouccr Locaam well eymOd al roD REMARKS ND cane "Y v pea[a h ND NM agNOa ptNt 18-02. E-1 t ) 09fGk Wft+GKle - 1120 reGlYf flOrn Oropofo0 No mo macer ecce ro tmar h uPe-zs .reeuerr e. zo+e I 4.0 B-07 B-09 B-42 z®r SCHEMATIC CASI NG Milne Pcin`Llni+ Well: N1?I,1 3-03 1-ast Completed:10/02/i 985 OTD 132-055 Size Type "Grade/Conn Drill ID Top 24' Conductor 915 / Grade B / PE 18.936 t2,32 13-3/8' Surface 72 / L-80 f BTC 12.191 v 7' Production 29 / L-80 / BTC 6.459 0 TUBING DETAIL 3-1/2' 1 Tubin ;.3/L -30/ DSS -HT 1 2.992 4 7 348' JEWELRY DETAIL Ifi L: 50.3 jc- a ra3_Kwj milt-.. rs WA 3/01/11 10 (ELTDC 7 5/15'M i. is I 1: 3.csY, kS sots L_ T3 �L�15 l�a No Depth Item 1 1,904' 35"C2mco TROP -1A S54 SCSW, M=2212" WRDP Valve, &6 Lxk. 7 =1552" 1 2 2,115' 35"KBUG6LM vtf V vahre, BK-2latch, ID= 2.813' 3 2,814' 3.5"KBUG GLM 1' wf vat -, BK-2latch. ID-- 2;613' 4 3,421' 3.5"KBUG6LMw/17V2K%BK-2latch,ID-2813' 5 4,C;2 3.5"KBUG GLM w/ 1" vater. BK-212tck ID= 2.813' 6 4,667' 3.5'KBUG GLM w/1'vatre.BK-2latch,ID-2AWr 7 5,245' 35"KBUG GLM W r valee BK -2 latch, ID=2213' 8 5,826' 35"KBUGGLM w/1" V21Ve. BK -2 latch, ID=2.813' 9 6,334' 35-KBUGGLM w/r walmBK-2latckID-2$13" 10 6912' 35"KBUG GLM w/1" v2kt BIF2latch,1D=2.813' it 7,267' 35"BakerXt6 ID= 2.813- 12 7,248' 35' Baker PBRSeai Assents , ID= 3.00T 13 7,269' 7' x 3.5' Baker FHL Px' ker x55' Ext 14 7,348' 3.5'B2kerXN 1D=2.813' 15 7,344' Me:hank=al -Release 16 7,347' Pressure se Relea- !cttam @ 7,3 T 17 7,353' Baker Inflatable Brid-ePl set10/20f2C12 18 7,378' Cement To t--edwfwirefine 19 7,384' 3/8" Shear Rod lehon MPBT 24 7,389' MnPBT Machaal Plu- Back Tool 21 7,774' Fish - S reTCP Guns 22 7,841' To of Cut 3-1f2' ' 23 7,878' 7" x 35" Baker FHL Packer 24 7,952' Pressure Release- Bottom @ 7,953' 25 7,973' Fish - S ntTCPGuns A8" drs based on WO ' RX9 325' ' 9KB c'24 ;. PERFORATION DETAIL Sands Tap(MD) ZM(MD) Top(TVD) ZM (TVD) FT Date Status Sqj�lserf 7360' 7,362' 6,929, 6,934" 2 8/17/1982 KUP Sands 7,374' 7,386' 6,937' 6,958' 16 4/47/2441 Dper KULSands 7391' 7,411' 6,957' 6,976' 24 5/21/1982 Isolate Perf 7,548' 7,554' 7,147' 7,149' 2 8/1711982 WELL INCLINATION DETAIL KOP @ 2A40 Max Hole Angle=525 deg. @4,3W OPEN HOLE / CEMENT DETAIL TREE & WELLHEAD Trac 3'118"5MCRM8R4 Tree Ca .5 Ibg0.dapter i1" x 3-1/8' 5M C1W Welihe� Zhgliyc.11"x3-1d2'IBT 13-318' BPi Profile �''. -. l GENERAL WELL INFO TD=8,3V (Nq /TD=7,777(TUDj API: 50 429.211732 -w -cc P6M=%CV (W PBID=7,61Y(T0 Drilled, Cased and Ccompleted by kahors27E-5/2Zf1982 RWOtoRun G Mandrels-10MA1985 _ 7,,, .5 24' CementedtoSurfacein 26' }tole 13-318' 3200."PerrnwfcstCement in L71f2` Hole 954 ss Penrufrost Cs eezed at Shoe 7" 444 3E Cbss'G in 8-1[2' tick �''. -. l GENERAL WELL INFO TD=8,3V (Nq /TD=7,777(TUDj API: 50 429.211732 -w -cc P6M=%CV (W PBID=7,61Y(T0 Drilled, Cased and Ccompleted by kahors27E-5/2Zf1982 RWOtoRun G Mandrels-10MA1985 0t13FEksV.:52.VG-15-P.,:''5.dNR DIE- fsh 10FP1r6@ F"sk Van Il:rforatirggu3 CatJaiedtrp @4305W Well: ?4,IP'j.�,-iO4A SCHEMATIC Last Ccprnpleted11/3/1985 ?T2D 182-100 TREE & WELLHEAD 'ree 3-1f8-51VICN911D Tree Ca " Grade/ Cann Tbg Adapter 11" x 3-118" 5M CfVi Wellhead Tbg j1gt.11" x 3 V2' 15T BPF 3" CN1-H BPV Prof e OPEN HOLE / CEMENT DETAIL 20' CementedtoSurbcein Nr Hole 13-319' 36CC $k4PemcafrostCerrern in 17-1/2" Hak 7„ 1,CCCsk4Clus"G,30DA.%ClassV 200bblsofArctic Pack &&8-112- Mote CASING DETAIL Sire Type " Grade/ Cann Drift I D Top i BPF 20' Conductor 434E f N/A NIA 0 8C' 0.355 13-W Surface 72 f L -W f BTC 12.347 0 2,3C0' 0.148 7- Production 291 L -W / BTC 6.184 0 9,476' 0.0372 TUBING DETAIL r -S6 3-1f2' 1 Tubing433E 1-80f D5.5 -HT 1 2.992 1 0 8,916' 0.87 WELL INCLINATION DETAIL Al I> �--/ �.(,) 0) KOP @ 2,200' Max HoleAn81e = 58 deg. @49(V -5 2Cd JEWELRY DETAIL 00 r✓ No Depth Item 11 j.,11f4,1 TD=9.5W INUS/TD=7,210" PBTD=8362' I,Nq/PBfD=7,191'DXq PERFORATION DETAIL 1 I 1,889' I Cameo 7ROP-1 ABC SMSV- locked Out '9y IAM- lfl= 2 212 GLM Detail -Cameo 3-117" KBUG w/ BK Latch, r Dummy traIva & 2.875" 1D 2 2,117 ST 10: TVD= 2,117, Dev.=d 3 2,787' ST9: TVD-- 2,786.. Dew. -_9 4 3,455' STB: TVD-- 3,394', Dev.=34 5 4,310' ST7: TVD-- 3,997, Dew= 51 6 5,203' ST6: TVD-- 4,507, Dev.=57 7 6,032' ST 5: TVD= 4,994', Dew=52 8 6,802' ST4:TVD= 5,4191, Der.=411: 9 71144' ST3: TVD= 5,9D1', Dew=53 10 8,117' ST2: TVD= 6,319, Dew=50 11 8,790' ST 1: TVD-- 6,760', Dew=45 12 8,816' Baker SBR Seal Assem wf 2.813" HES X'Ifipple 13 8,842' Baker FML Packer ilk 3.00" 14 8,878' 3-1f2'Of75 W Ni le IN 2,813, 15 8,916' Tubin Tail PERFORATION DETAIL Sands Top(MD� %M(MD) Top(TVD) XM(TVD) FT SPF Status MK -1 8,936' 8,954' 6,864' 6,877' 18 R Open 2 8,960 I 8,940' 6,881' 61902' 9,182` 1 9,184' 7,0:42' 7,043' 30 2 Open Sq ueezed GENERAL WELL INFO Drilled Cues oral Completed byNaborsVE -1 85 NOTE: SPM 84 h asa D4' with no latch attached. The wobble washeran4i 'n•arelostinthewelll»re J TREE: s 1.l H7 1•&Ic .N; 3 trz, CYA% (X&t:k union WELLHEAD l i- vim F -r v; ww° 3 12- H HF^.t prod®. 13 WS', 48#, H-40 �08, PELP 9 &W, 36#. K-65 SD34' BTRC KUP 612 ZINCIV MAX Holo Angi.: 41.5 t?LLi q 4GC0 Baker Pebch covering SPM (gg 48916 1.83" min ID. Dwerenitial psi rating = 2500 psi_ 4882 - 4R3Q7' 3 112'. 9.3#, WKS L-80 I L43INC3 L3mF t 47: 2-mr CAPAC:I TY: U.DUU? HHL+I 7" . 2V,#, L-80, U I HG ca: ng uFi1F 1 ID 19.151" C:Af-Aca r Y '6d igg,. <);mt 4 tape Casing RA Tag 7723' PERFORATION SUMMARY fDl'L Loa dated ell Zom Sian SPF MD' TVD" MK -1 5' FAK-2 3- 12 13 7994' - 6413' 5017'- 6447' 0963' - 0964' C903'- 74DO' BVI PB -20 KB Elev. = 551' NtatSoes 27E GL E3ew_ = 35' Nabors 27E .12-81- CS -I ock vd 5116' ctw*e set 9-27-12 Cemco TRDP-IASSA SCSSV 499' (2.812' ID) (CS profile) 1' x 3 1.2" McMurray FMHO w/ SK latch # and tvd dg 9 2185' 2185' 0 8 2882' 2881' 8 7 3522- 3492' 24 6 4239' 4487' 37 5 4896' 4588' 40 *4* 5555' 5495' 39 3 6213' 5598' 39 2 6871' 6100' 41 1 7555` 1 6623' 1 39 Nlkste: Station 4 Q 5555 has brokers latch, Ko -Go is stA attached to DMY valve. Baker 'POR' Seal Assy (9.00- ID) 7914' Baker 'HB' Packer (3.(Y ID) 7927' Tubing Tail Jet Cut (9.5-90) Flslt:Est. Top of Tubing Tall 8047` Est. Tap of Part guns 80G4• PBTD MWI Cour') 7'26 u shoe 3957' 8146' 827U' DAI6 Ia>=v.er cxntmEiNI5 MILNE POINT UNIT WELL MPH -20 API NO: 50-0 1524 9W25/�6 M. Ross Convert drawing to Canvas BP EXPLORATION (AK) TREE: 31,8--:im v -&x; w.' 3 1.lF Wei taWcp co rwctcr, ',4€LLHEAD: t i' tn1 Fhx: w,, 3 v 2' H HF -V protia 13 X&'. 484. H-40 1 1 d' PELP 9 WS'% 36#. K-55 BTC Ki.3P $L' ZOOO' WL AX H010 Aroo- 48 M -E n 45D0' 3 UZ- 9.34, UIRS. L-W71LEUNG uFt1 r ®: 2,ss7• GAF'AG'ITY O.I61 ULU-4-7 T" . ;W4. L -8U, 13 TL: L:as3^.q DKIF7 IU G.151- CAPACG.I I Y W.' tbq:.UZG4 t3pf Tubing RA Tag 8027' Gassing RA Tag Top of f1N taWad mW CTU on 11119188 40 815V Mb PERFORATION SUMMARY (DIL Loa dated 3t29t85) Zona Sine SPF MQ' T1/D' MK -1S2 5- 1.7 61091' - 021[3' 6973' - 6990' MPB-1 '1 KB Elev. = 34' Nabors 27E GL Elev. = 24' Nabors 27E CamcoTRaP-tA-SSASCSS'd F1808' 1" x 3 112' KBUG wl BK latch ## fl d Wd g 10 2078` 2078' 2 9 2804' 2791' 17 8 3490' 3413` 33 7 4307` 403-3' 46 6 5002` 4504' 43 5 5630' 4986' 40 4 6289' 5492' 40 3 6888' 5952' 40 2 7613' 6514' 38 1 8058 6868' 36 Camco Alpha Soft Set tbg packoff set 8066 -� 8075' across SPM! on 2111195. Mfrr►tnum ID 1.937" Baker'PBR' Seal Assy (3.00- ID) 8096` Baker `HB' Padua' (2.89` ID) - 8111' Camco 2.750 'D' nipple 8149' WLEG 8162 WLEG (ELMD) Top of fish at 8954• MO P13TD 1Fkxt CoUq —" 7' 26 n Shoe 84.g4 DAT-L HEY. 9r Cx—A%"15 MILNE POINT UNIT WELL - Mpg -11 API NO: 50-029 213o5 9/2/06 L. Hulme Convert to Canvas Drawing BP EXPLORATION (AK) TREE: :t 173" - 51A I-NfU •A,' 3 UZ- Otis (.kart[ UrKr I VVELLHEAJ3 11- 5" 13 378`, 49#. H-40 107' PELF 19 518', 36#,K-55 L-80 STRC 5769` KUP gQ 50rJ' rlv )x Hao Ainyb: 49 C7ECiYQ 'S437{Y Minimum Restriction is Camra 'D' fMippte 2.75" @ 9114- :5 172', 92X, atRS L430 ILK31NU L)mFr :LJ: Zour L:AF+ACIIY: D.0087HHL,'F i r' , 260, L -IM, U I HG CazJng LIKII-r 117: u.151" C:AF'AC:I r Y 'fie ibe o;m4 bpo NOTE 31 /2" catcher 24" long 'G" Fish Neck 9090' SLM rm mred withsand 8-1409 PERFORATH31N SUMMARY Zone Size SPF I MD' TVD' K4K LK -1 3116, 2785' 1. 12 9000'- 98"x4' 92a2' - 9290, a9115'- 69^.54' 71011- 7137' PBA [} K8 Elev. = 59 Nabors 27E G1_ E1ev- = 35' Nabors 27E CAmco TRDP-IA-SSA SCSSV 1 (2-812` ID) (CS profile) CA:MCO 3 112" KBUG Gas LA Mavd'els # and tad dg 14 2205' 2098' 35 9 3116, 2785' 43 8 3960' 3404' 46 7 4808' 4045' 45 6 5469' 4457' 49 5 6132' 4894' 49 4 6819' 5358' 47 3 7447' 5793' 46 2 8146' 6260' 46 1 8731' 6700' 42 BOT PBR- Seal Assembly (3.(Y' I.D.) 6$6�• ear 'HB' Hydraulic Packer (2.99' I -D.) $B72• Camca 1N-1' Selective Nipple $g12' (2.813- I.D.j Camca'?JW3-2' GU41 1 la- I 894T Gutted Circ Vahres w/ RKP Latches 1 8988' 3 172' Blast Joints BOT Seal Bore Receptacle BOT '2-B' Permanent Parker 909T Camco'D' Nipple 2.750' 1. D. 9114' CA2 Blanking Plug Tubing Tail w7 Re-entry Guide 9116• y Fish: Under Roaming Arm with carbide Wallas and retaining pin r 9290' Tag Fill Eline 7/29/93 F 9291' 7" 213# L-80 BTRS 6.276" I.D. 9436' 111A 16 keEv Etre LXAWU4Ts MILNE POINT UNIT 10114/12 B. Bixby Convert drawing to Canvas WELL PAPB4o API IMO- 50-0.29,21280 13P EXPLORATION (AK) WELL No, B-18 CASING SKETCH 1111,NE POINT UNIT ja API Flo,; 50-029-21450 PERMIT No.: 115-229 DRILLM. 10/2/85 ARC71C PACKED: 1/23/06 OPERATOR: COLNOCO INC. SURFACE LOCATION: 013'FSL, 702'FW, SEC lk T13N. R-lE, UM BOTTOM KYLE LOCATION.- 1552'F&, 1361'FEL, SEC 14, PON. RIOF, UM SPUD DATE: 9/17/85 29N. L-80. BTRC SFT 0 10908 Wk ?8 [)330LS. 3�SXS CLASS *G' PHID 10,633, 017ME, - (.1 M 11 W/ C;'R 2, -5% h6 24. CONOCO INC. Li25 Z -F ;NCHCRAGE B". s,:. V I'Mc CSG Spool' -9KB = 32' 13 3/8',480,H-40YELP, SET 0 '15' to cy 7' X 9 518' ARCTIC PACK DATA; 180 SX VERUAFRCEST "C", 60 BELS ARCTIC PACK EST TOC 2450! 13 5/8 36j, K-554 BTRC, SET 0 6405' CEMENT DATA, 601 81ILS, 1715 $K5 PERMAFR057 W1 5 //SK OILSONITE. 55 OBILS, 275 SKS CLASS V CMT W/ 3X NOCL, ix CFR -2. EST TUC SAID' ECD 10,456' A ECP 10.517' 29N. L-80. BTRC SFT 0 10908 Wk ?8 [)330LS. 3�SXS CLASS *G' PHID 10,633, 017ME, - (.1 M 11 W/ C;'R 2, -5% h6 24. CONOCO INC. Li25 Z -F ;NCHCRAGE B". s,:. V WELI, No. B-8 CASING SKETCH MANE POINT UNITI} API No.: 50-029-21325 PERMIT No.: 85-63 ORILLED: 4/29/85 ARCTIC PACKED: 5/15/85 OPERATOR: CONDCO INC. SURFACE LOCATION: 697'FSL, 731'FWL, SEC 16, T13N, R11E, UM 4)0rrOM HOLE WCATICN= boa' FNL, 1078' FEL, SEC 13. T13N, RIDE, UM SPUD DAT€: 4/19/93 FVC CSC SPOOL 13 3/0',40#,H -4O PELF, SET 0 110' 06 ae 7" X 9 5/6' ARCTIC PACTS DATA: •` 31 BI S, 186 SKS ARCTIC SET I CMT j 86 BOLE ARCTIC PACK '�,. " 4 s/a•,3sq.tc-55,BTRC,S::' a X905' CEMENT DATA: 889 BBLS.2600 SKS ARCnC si_T nl 25 BBL5/18 0-29 (CELLO FLAKES) 56 BELS, 275 SKS CLASS `1r CMT W/ 1% CaCL AKD .2% D-46 DEFOAMER. DOWNSQUEEZE 15 BELS ARCTIC SET 170W4 EST TOC O 7895' ANNULUS. ECP 9959' 7', 26#. L-90, 9TRC SEi O 9209' CEMENT DATA: 76 BBLS, 370 SK5 CL -55 +I ANT W/ ,9% D-80, .2% D-46 CONOCO INC. APPROVED BY: HCS ter?=: ys A140HORAGE OF-ISiON DRAilLD i3Y-. SJN/CF= CA � iLE: C ,gib YELL No. B-19 _ CASING SKETCH MILNE POINT UNIT (P) API No.: 50—G29-21451 PERMIT No.: 85-230 DRIU-ED: 10/17/85 ARCTIC PACKED: 9/24/89 OPERATOR: CONOCO INC. SURFACE LOCATON: 881'FSL, 890'FWL, SEC 16, T:3N, RITE, UM BOTTOM NOLE LOCATION: 364'FSL, 4126FEL, SEC 12, T13N, RICE. UM SPLID DATE: 10/6/85 POTD 10,599' FMC CSG SPOCk 13 3/8',48f,H--40,PLP, SET 0 109' 7' x 9 5/6' ARCTIC PACK DATA: 18D S% (30 BBL) 15,7 PPG ARCTIC SET 1 AND 60 BBL DEAD CRUDE 4 5/8',36j,K-55,$TRC,SET O 6392' CEMENT DATA: 552 88I.S. 1575 SKS PERMAFROST 'E' W/ 5 #/SK GILSONITE. 56 $BLS, 275 SKS CLASS 'O' CMT W/ 3% NOCL. 1% CfR-2, EST TOC 9260'— 16100' 26p. L-80, STKC SET A 10685' CEMEK` DATA. 68 BBLS, 3GO SKS C:ASS 'G' x".kt' ti+'/ 1R CFI? -2. .3% HALAD 24. TD 14,716 CONOCO INC. APPROVED BY: HDS DAZE: _ -CHCRACE 51.1Si;a:; DRAr7ED BY: SJPt/C=P CAS I: uGr,9;g 2800' WELL bio- D -2A CASING SKETCH MILNE POINT UNIT (P) API No.; 50-029-20900-01 PERMIT No.: 83-40 DRILLED: 3/6/83 ARCTIC PACKM 3/9/83 OPERATOR: CONOCO 14C, SURFACE LOCATION: 1149' FNL. 1436' FEL, SEC, 13. TQN, RIM U.M. BDTrQM ROLE LOCAVON: 2069' FNL. 5711` FEL, SEDC. 14, 113N. RIDE, U.M. SPUD DATE- 2%10/63 TO 9340' CAMERON C% SPOOL 20-, 94#, H-40, SET 0 115' ARCTIC PACK DATA: 400 SX COLD SET it 176 BELS ARCTIC PACK 13 3/8'. 720, L-80, 8TRC. SFT ip 2545' CEMENT DATA; 2000 SKS COLO SET Ili tk .%l 5KS CGT 5EW'r dl 4968' 7` 290, L-80 BTRC SET 8 9305 - CEMENT DATA; 1st STAGE: 92.5 SKS CLASS 'C' A' 1% D-31. 0-2% R-5. 02% D—A, 59. KCL 2nd STAGE; 400 SKS COLD SE 1 II 180 BBLS ARCTIC PACK CONOCO INC. — APPR OED 8Y: R -S {SATE' 4/2€1/g2 AA ICHQRAGE 01VISION DRAFTED BY: S34/CFP CAD FILE: YrK:AD2A Schwartz, Guy L (DOA) From: Luke Keller <lkeller@hilcorp.com> Sent: Wednesday, February 03, 2016 4:14 PM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA); Cody Dinger - (C); Wyatt Rivard Subject: RE: B-29 AOR (PTD 216-015) Guy, I found reports & CBLs for both mentioned wells and can verify the following info: B-03: 7" casing cemented with 400 sacks on 5-16-1982, then DV tool opened immediately after cmt job and 300 bbls arctic pack and 300 sacks cmt pumped. CBL showed cmt bond up to 7200' MD / 6800' TVD. This would place cmt above the HRZ shale in the lower Seabee. There is no isolation across the Schrader Bluff sand, but the injection is isolated in the well from 6800' TVD to 13-3/8" shoe at 2323' MD / TVD. e =�' `r 5- Depth a 8240 Running 7" csR. rfu circ. bead, waah d%R708'-0214', Ao. - ..�.1 2,,, 241 Ito. (92;.1.) 7". 29//ft..l.-89 butt & met R 6274', F.S. 0 8234', F -C. r� ` 1% 8471'. DR # '09" ."k pipe. Nap %S bbla. aeplol4te -pacer, tont lines to 5080 p-1, pump 401) %kw. coat. A displace W.Halliburton. Crap 0V bomb. open tool. Cire. 140 hl.ls. vatr.r. 100 .c0NFJ LNJJAL. bbla. ArCLIc pack, 300 aka.. cat. Drop plug A dinplace WhIalliburcen cla.ee tool. to -t to 4400 pai - o.k. N(0 R0P'm. auc el ipo R wake rough tut, ..yoke final cut A Install tbx. %pool. teat to ISDO pat n. o,k, Install elupka lino A adapter spool. NAU HOP'-. Mud Wt.10.4f. Vtwe. 46 B -04A: 7" casing was cemented with 1000 sacks on 7-14-1982, then DV tool opened immediately after cmt job and 200 bbls arctic pack followed by 300 sacks cmt pumped. CBL showed cmt bond up to 6100' MD / 5000' TVD. This would place cmt in the upper Seabee. There is no isolation across the Schrader Bluff sand, but the injection is isolated in the well from 5000' TVD to surface casing shoe at 2300' MD/2300' TVD. 7-14 -- LID drill string b kelly. Change pipe rams. pull wear bushing, 14 RIV cnrterg. Run 242 jt -n. 7" 290 L-80 burtregs cug. to 9476', pipe stuck while installing, circ. head. Circ. h cond. hole to cant.. Cmt. 1st stage w/T000 sks. Class "C3" w/1Z CFR -2. .3Z Halad-9. 8 5Z KC'... Good returns during cementing. Mud tit. - 1.0.5 Viae. - 42 7-15 - Cementing. Displace cmt., bump plug, flouts held. C.T.P. Drop bomb S open D,V. @ 2094'. Displace 7"x13-318" annulus w/water; pump 200 bbl;l. 9.3 ppg Arctic Pack, followed by 300 ttkA. Permafrost "C" cmt. displace h close D.V. collar. C.I.P. stipple down BOP, hang -off b set slips On 7" csg. cut off csg.N/1' tbg. spool a cost w/5004#. NIL, 30P stack. change f/7" cog. rams to 3-118" pipe rams. Test 90P stack, choke & kill lines naI500# a 5000*. D.V. collar @ 2094', Cmt. bafflo plate @ 9354', float collar (f 9397'. 7" csg. shoe @ 9476'. Mud Wt. - 16.5 Visc. - 44 Let me know if you need anything further. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L (DOA)[maiIto: guy. schwa rtz@alaska.gov] Sent: Wednesday, February 03, 2016 2:43 PM To: Luke Keller Cc: Bettis, Patricia K (DOA) Subject: B-29 AOR (PTD 216-015) Luke, Can you verify cement placement in the 7" casing for B-03 and B-04 wells in the AOR. Can't tell if the SB is covered or not. If it is open verify it is isolated by cement below and above zone. Here is a chart that helps organize AOR data. (see attached) Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov). Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Thursday, January 21, 2016 12:42 PM To: Bettis, Patricia K (DOA); Paul Chan Subject: RE: MPU B-29: Permit to Drill Application (PTD: 216-015) Patricia, We will not be pre -producing B-29. We did discuss it, but the ND sand under B -pad is unconsolidated, and would likely plug our injection string. Paul - Correct me if anything has changed regarding pre -production of this well. Luke Sent via the Samsung Galaxy S16 active, an AT&T 4G LTE smartphone -------- Original message -------- From: "Bettis, Patricia K (DOA)" <patricia.bettis@alaska.gov> Date: 01/21/2016 12:38 PM (GMT -09:00) To: Luke Keller <Ikeller@hilcorp.com> Subject: MPU B-29: Permit to Drill Application (PTD: 216-015) Good afternoon Luke, Does Hilcorp plan to pre -produce B-29; and if so, what will be the duration? Thank you, Patricia Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, January 21, 2016 12:39 PM To: Luke Keller (Ikeller@hilcorp.com) Subject: MPU B-29: Permit to Drill Application (PTD: 216-015) Good afternoon Luke, Does Hilcorp plan to pre -produce B-29; and if so, what will be the duration? Thank you, Patricia TRANSMITTAL LETTER CHECKLIST WELL NAME: m Pu- 'n - 27 PTD: a � - o/s- Development /Service _ Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: AjilL �,1nr POOL: i/lE?C)I'F ��c/4 r 3 /(, 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. , API No. 50- - - - (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 sam les 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 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 MILNE POINT, SCHRADER BLFF OIL - 525140 Well Name: MILNE PT UNIT SB B-29 Program SER Well bore seg ❑ PTD#: 2160150 Company HILCORP ALASKA LLC Initial Class/Type SER/PEND GeoArea 890 Unit 11328 On/Off Shore On Annular Disposal ❑ Administration 17 Nonconven. gas-conforms toAS31.05.030(j.1_.A),(j.2.A-D) - - - _ . - - - _ _ - - - - - NA- - - - - - - - - - - - - - - - - - - - _ _ .. _ _ - - - - - - _ _ _ _ _ _ _ _ - - 1 Permit fee attached- --------- -------------- ------------NA-- --------- - --------------- ------ - - --- -- 2 Lease number appropriate- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - ADL0047438, Surf Loc; ADL0047437, Top Prod_ Interv._ & TD - - - - - - - - - - 3 Unique well name and number Yes - _ _ _ _ _ _ MPU B-29 4 Well located in-a_defined_pool- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - MILNE POINT, SCHRADER BLFF OIL:- 525140, governed by Conservation Order No. 477.05. 5 Well located proper distance from drilling unit-boundary_ - - _ - Yes _ - _ _ _ _ _ CQ 477.05 contains no spacing restrictions with-respect to drilling unit boundaries, - _ - _ - 6 Well located proper distance-from other wells- - - _ - _ _ _ _ _ - - - - - - . _ - - - - - Yes - - - - - - CO 477.05 has no interwell spacing restrictions._ - - - - . 7 Sufficient acreage.available in_dril_ling unit- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ _ 8 -if _deviated, is_wellbore plat-included ----- - ----------- Yes-------------------------------- ------------------------- 9 Operator only affected party - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - _ - _ Wellbore_will be_ more than 509 from the exterior boundary of-CO 477.05 affected-area. 10 Operator has-appropriate bond in force - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Appr Date 11 Permit_ can beissued -without conservation order -------- ____________________ - Yes -. 12 Permit can be issued without administrative_approval - - - - - - - - - - - - - - - - - - - - - - - Yes - - _ _ _ _ _ _ _ _ _ _ _ - _ - - - - _ _ _ _ _ _ - _ _ - - - _ _ _ .. _ - -------------------------------- PKB 1/21/2016 13 Canpermitbeapprovedbefore 15-day wait------------- --------------- Yes------------------------------------------ -- ----------- 14 Well located within area and-strata authorized by Injection Ord er# (put 10# in-comments)_(For_ Yes - - - _ _ _ _ AIO-10-B - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 15 All wells-within-1/4_mil_e_area_of review identified (For service well only)- - - - - - - - - - - - - - - Yes - _ _ - _ _ _ MPU B-03, B-04A, B-20, B-11, B710, B-18,_B-08, B-19, D-02A - _ _ 16 Pre-produced injector: duration of pre production less than 3 months_ (For service well only) _ - No- , - - _ _ -Luke Keller (1- - - - 16) - - - - - - - - - - - - - - - 18 _Conductor string_ provided _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - _ - - - - Yes 20" conductor driven to 110ft._ --- - -- - -- - -- Engineering 19 Surface casing-protects all-known USDWs - - - - - - .. _ _ _ _ _ . _ NA_ - - - - _ - - NO aquifers in permafrost_ area. Surface/Prod_casing will be fully cemented-- - - - - - - - - - - - 20 CMT_v_ol adequate to circul_ate_on conductor & surf_csg Yes _ _ _ _ _ _ _ ES cementer is staged at 1900 ft. MD_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 21 CMT_v-ol_ adequate to tie-in-long string to-surf csg- - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - 9 5/8" will be drilled on_diverter to the SB sand. - - - - - - - - - - - 22 -C-MT-will coverall known -productive horizons- - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Slotted liner with swell_packers_is planned for the lateral section. - - - - - - 23 -Casing designs adequate for C,_T, B &_ permafrost- - - - - - - - - - - -- - - - - - - - - - - - Yes - - - - _ _ - BTC calculations provided. _Meet industry standards._ - - - - - - - - - - - - - - _ _ - _ _ _ - 24 Adequate tan_kage_or reserve pit - - - - - - - - - - - - - - - - - Yes - - - _ _ _ _Rig has steel pits, All waste to_approved disposal well.- - - _ - ----------------------- 25 If_a_ re-drill, has- a- 1.07403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - - - NA- _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - _ _ _ - - - _ - _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - 26 Adequate wellbore separation-proposed - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - - - - - - No issues with collision ,.._ - _ - - - - _ _ _ . _ - - - - - - - _ _ _ - - - - _ - _ - 27 If_diverter required, does it meet regulations_ _ - - _ - _ _ _ - Yes _ - Doyon 14 has 16" diverter line. Schematic of layout is provided. - _ _ - - - - - - - - Appr Date 28 Drilling fluid_ program schematic_& equip list adequate- - - - - - - - - - - - - - - - - - - - - - - - Yes _ - - - - - - Max formation_ pressure =-1600 psi (7_ppg EMW) will drill with-9.5 ppg_mu_d_ GLS 2/3/2016 29 BO_PEs,_do they meet regulation _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ _ _ _ _ _ _ Doyon 14 has-5000 psi 13 5/8"_BORE_ - - _ _ _ - - - _ _ - . _ _ - _ _ _ _ - _ _ - - 30 BOPE_press rating appropriate; test to-(put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - _ MASP = 1158-psi-will test-BOPE_to 3000_psi_(annular to 2500 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 _ - _ - _ _ _ H2S on pad._ Rig-has sensors and- alarms ._ - - - - _ _ _ _ _ - _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - - - 34 Mechanical-condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - - Yes - - - - - - - AOR of complete..:B-Q3 and B-04A have_cmt above and below SB -------------- 35 35_ Permit_can be issued w/o hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No - - - _ H2S measures required- _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ _ - - - - - _ - _ - _ _ - - _ _ - - - _ - _ - - - - - - - Geology 36 _Data-presented on potential overpressure zones- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - _Expected reservoir-pressure is 7,0_ppg EMW; will_be drilled using 8.8 to-9.2 ppg mud. - - - - Appr Date 37 Seismic_analysis of shallow gas-zones----------------------------------- N_A_ _ _ _ _ _ _ _ - - - _ _ _ _ _ _ _ - _ - - - - - - - - - - _ - - - - - - - - - - - - - - - - - - - - - PKB 1/21/2016 38 Seabed-condition survey _(if off-shore) ----------------------------------- A_ - _ _ _ _ _ - _ ------------------------------------------------------------------- 39 Contact name/phone for weekly_progress reports [exploratory only] - - _ _ _ _ _ _ _ NA_ Onshore service well to be drilled_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Geologic Engineering Public grassroots SB injector... targeting Schrader ND sand. Part of pilot program to determine ND sand prooductivity. GLS Commissioner: Date: Commissioner, Date Commissioner Date �s Zell l
