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Home My WebLink About219-096MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Tuesday, October 17, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC E-39 MILNE PT UNIT E-39 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/17/2023 E-39 50-029-23640-00-00 219-096-0 W SPT 4149 2190960 1500 619 588 619 589 4YRTST P Adam Earl 9/4/2023 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 E-39 Inspection Date: Tubing OA Packer Depth 70 2150 2079 2056IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE230905125148 BBL Pumped:5.1 BBL Returned:4.6 Tuesday, October 17, 2023 Page 1 of 1            Debra Oudean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: doudean@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: Date: DATE 7/21/2020 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU E-39(219-096) Memory Injection Profile MPU E-39 Received by the AOGCC 07/27/2020 PTD: 2190960 E-Set: 33627 Abby Bell 07/27/2020 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Shift ICD Closed Hilcorp Alaska Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 15,531 feet N/A feet true vertical 4,204 feet N/A feet 7,570 Effective Depth measured 15,515 feet 8,288 feet 4,155 true vertical 4,204 feet 4,366 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3 / L-80 / EUE 8,332' 4,366' 4-1/2” x 9-5/8” Ret. Packers and SSSV (type, measured and true vertical depth)LTP 9-5/8” x 4-1/2” ZXP N/A See Above N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Chad Helgeson Contact Name: Authorized Title:Operations Manager Contact Email: Contact Phone: WINJ WAG 0 Water-Bbl MD 107' 8,557' 12,650' TVD 107' 1,057 Oil-Bbl measured true vertical Packer 15,520' Junk measured 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: 4. Well Class Before Work: 0 Representative Daily Average Production or Injection Data 3401,389 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 219-096 50-029-23640-00-00 Plugs ADL025518 / ADL380110 5. Permit to Drill Number: Milne Point Field / Schrader Bluff Oil Pool 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 415 Authorized Signature with date: Authorized Name: David Haakinson dhaakinson@hilcorp.com Size 0 MPU E-39 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Casing Pressure Tubing Pressure 0 N/A measured 8,288' N/A OB Liner Casing Conductor Length Surface Surface 7,903' Surface OA Liner 20" 9-5/8" 4-1/2" 4-1/2" 4,365' 4,182' 4,204' 8,540psi 8,540psi Burst N/A 5,750psi 9,020psi 9,020psi 777-8343 2. Operator Name Senior Engineer: Senior Res. Engineer: Collapse N/A 3,090psi Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:32 pm, Jul 16, 2020 Chad A Helgeson 2020.07.16 14:13:36 -08'00' DSR-7/16/2020 RBDMS HEW 7/17/2020 SFD 7/17/2020MGR21JUL2020 _____________________________________________________________________________________ Revised By: TDF 7/14/2020 Milne Point Unit Well: MPU E-39 & L1 Last Completed: 08/14/2019 PTD: 219-096 TD =15,531’(MD) / TD =4,205’(TVD) TOW @ 7,853 MD TOL @ 7,903’ MD 9-5/8” 20” ESCmtr @ 2,438’ 22 7 21“OA” Lateral PBTD =15,515’ (MD) / PBTD =4,204’(TVD) “OB” Lateral 34-35 -36 4 3 1 Orig. KB Elev.: 48.3’/ Orig. GL Elev.: 21.7’ 5 6 Min ID = 2.75” 23-33 11-20 10 2 8-9 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 215 / X-42 / Welded N/A Surface 107' 9-5/8” Surface 40 / L-80 / TXP 8.835 Surface 8,557’ 4-1/2”Liner “OA” Injection Liner w/ ICDs 13.5 / L-80 / Hyd 625 3.920 7,903’ 12,650’ 4-1/2”Liner “OB” Injection Liner w/ ICDs 13.5 / L-80 / Hyd 625 3.920 8,288’ 15,520’ TUBING DETAIL 3-1/2” Tubing/Tieback 9.3 / L-80 / EUE 2.992 Surface 8,332’ JEWELRY DETAIL No Depth Item Upper Completion 1 2430’ 3-1/2” X-Nipple (ID-2.813’) 2 7512’ Downhole Gauge 3 7570’ 4-1/2”x9-5/8” Retrievable Packer (DLH) 4 7630’ 3-1/2” X-Nipple (ID=2.813”) GLM Detail: 3-1/2” x 1.5” Camco w/ BK Latch 5 7683’ Sta #2: Valve – 750 BWPD WFRV: Set Date 2/29/2020 6 7774’ Sta #1: Valve – 750 BWPD WFRV: Set Date 2/29/2020 7 7834’ 3-1/2” XN-Nipple (Min ID=2.75”) 8 8314’ No-Go/xover sub 9 8332’ PBR Seal assembly (4- ¾” holes) OA Lateral 10 7903’ Top of Liner Page 2 Tendeka Water Swell Packer #1-9 Page 2 Tendeka SSD w/ Screen & ICD #1-7 (See Page 2 for Detail) 21 12650’ Solid Bull Nose Shoe OB Lateral 22 8288’ Liner Top Packer 9-5/8” x 4-1/2” Baker ZXP Page 2 Tendeka Water Swell Packer #1-10 Page 2 Tendeka SSD w/ Screen & ICD #1-10 (See Page 2 for Detail) 34 15,493’ OB Lateral 4-1/2” Drillable Pack-off 35 15,515’ OB Lateral 4-1/2” WIV 36 15,518’ OB Lateral 4-1/2” Btm of Guide Shoe OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42” Hole 9-5/8"Stg 1 L –908 sx / T – 400 sx Stg 2 L –530 sx / T – 270 sx (294 bbls back) WELL INCLINATION DETAIL KOP @ 290’ MD Max Wellbore Angle = 97.5 deg @ 13,687’ MD WELLHEAD Wellhead FMC Gen 5 GENERAL WELL INFO API: 50-029-23640-00/60-00 Drilled and Completed by Innovation Rig – August 2019 LATERAL WINDOW DETAIL Top of “OB” Window @ 8,557’ MD Angle @ top of window is 89 deg Top of “OA” Window @ 7,853’ MD Angle @ top of window is 69 deg GENERAL WELL INFO API: 50-029-23640-00-00 Drilled, Cased and Completed by Nabors 22E - 7/5/1997 RWO by Nabors 4ES – 8/19/1996 Frac Kuparuk ‘A’ Sand – 4/24/2001 Depth MD Depth TVD MPE-39 ICD/Swell Packer Detail 8,583’ 4,365’Tendeka Water Swell Packer #10 8,852’ 4,353’Tendeka- ICD w/ 250L mesh, Sliding Sleeve (Closed 06/28/2020) 9,212’ 4,341’Tendeka Water Swell Packer #9 9,606’4,327’Tendeka- ICD w/ 250L mesh, Sliding Sleeve (Closed 06/28/2020: 600 BPD Drop) 9,840’ 4,323’Tendeka Water Swell Packer #8 10,068’ 4,320’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 10,467’ 4,300’Tendeka Water Swell Packer #7 10,859’ 4,283’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 11,299’ 4,256’Tendeka Water Swell Packer #6 11,766’ 4,227’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 11,993’ 4,213’Tendeka Water Swell Packer #5 12,378’ 4,192’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 12,727’ 4,180’Tendeka Water Swell Packer #4 13,273’ 4,209’Tendeka Water Swell Packer #3 13,333’ 4,214’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 13,603’ 4,210’Tendeka Water Swell Packer #2 13,871’ 4,181’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 14,506’ 4,155’Tendeka Water Swell Packer #1 15,265’ 4,183’Tendeka- ICD w/ 250L mesh, Sliding Sleeve Depth MD Depth TVD MPE-39L1 ICD/Swell Packer Detail 7,931’ 4,297’Tendeka Water Swell Packer #9 7,992’ 4,315’Tendeka Water Swell Packer #8 8,095’ 4,335’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 8,160’ 4,344’Tendeka Water Swell Packer #7 8,553’ 4,331’Tendeka Water Swell Packer #6 8,696’ 4,318’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 8,849’ 4,305’Tendeka Water Swell Packer #5 9,328’ 4,281’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 9,688’ 4,374’Tendeka Water Swell Packer #4 10,043’ 4,267’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 10,528’ 4,240’Tendeka Water Swell Packer #3 10,920’ 4,224’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 11,277’ 4,201’Tendeka Water Swell Packer #2 11,588’ 4,181’Tendeka- ICD w/ 250L mesh, Sliding Sleeve 11,945’ 4,163’Tendeka Water Swell Packer #1 12,340’ 4,149’Tendeka- ICD w/ 250L mesh, Sliding Sleeve Well Name Rig API Number Well Permit Number Start Date End Date MP E-39 CTU 50-029-23640-00-00 219-096 6/28/2020 6/28/2020 No operations to report. No operations to report. 6/27/2020 - Saturday No operations to report. 6/30/2020 - Tuesday 6/28/2020 - Sunday MIRU SLB CTU #6 with 2" CT. Well on injection at 1,380 bpd at 350 psi WHP. MU Renown extended arm sliding sleeve shifting tool BHA. PT to 300/4,000 psi. RIH and close sliding sleeves across ICD's #1 and #2 at 8,852' and 9,606' MD. ICD's 3-9 are OPEN. Shut off over 500 bpd injection rate at 700 psi WHP by closing the top two sleeves. Final injection rate and pressure was 960 bpd at 707 psi WHP. POOH. Secure well and request Pad Op to leave well on injection targeting 600 psi WHP as per Ops Eng. RDMO. 6/29/2020 - Monday 6/26/2020 - Friday No operations to report. 6/24/2020 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 6/25/2020 - Thursday No operations to report. Surface Casing by Conductor Annulus Fill Coat Corrosion Inhibitor (CI) Applications Well Field API PTD Top of Cement (ft.) Corrosion Inhibitor Fill Volume (gal) Final Cl Top (ft.) Corrosion Inhibitor Treatment Date E-35 Milne Point 50029236150000 2181520 Surface 22.5 Top of Cond 10/24/2019 E-36 Milne Point 50029236200000 2190050 Surface 15 Top of Cond 10/24/2019 E-38 Milne Point 50029236260000 2190440 Surface 20 Topof Cond 10/24/2019 E-.39 Milne Point 50029236400000/60-00 2190960 Surface 20 Topof Cond 10/24/2019 E-40 Milne Point 50029236260000 2190440 Surface 25 Top of Cond 10/25/2019 E-41 Milne Point 50029236220000 2190310 Surface 15 Top of Cond 10/24/2019 E-42 Milne Point 50029236350000/60-00 2190820 Surface 17 Topof Cond 10/25/2019 M-18 Milne Point 50029236320000 2190700 3 50 Top of Cond 10/26/2019 M-06 Milne Point 50029236460000 2191130 3 30 Top of Cond 10/26/2019 Cement to surface means cement is up to the 4" outlets below the wellhead. From the 4" outlets up to the top of conductor was filled with Fill Coat Notes: #7 Initial top of Cement footage measurement was taken from the 4" outlet down to the TOC The 4" conductor outlets are any where from 1 to T down from the top of the conductor f �, u U O o � 0 m 0 aa N \ \ a U U 9 N T N 6 ¢ ::. ❑ f0 ❑ D N ci m F F H g= m U w w m m o U y > O 7 _ a N m 2 > c c c c c c c c U a a c c . �' N iz I>L (n T( N I>L l>l I>L I>L C N 0 m ti ti >> U U c � � >LL > >LL > N >> > > m Z 2 E E E J J a a LL ❑I ❑I 01 J J CJ (D J J J J W O. Q .-. m m m M M M M M M M M M M M M Z � FLE� W W w W W W W W w W w W w W W W W W W W J O - p 7 ❑ J J J 7 J 7 ❑ ❑ J ❑ M ❑ ❑ F Z a a a a a a a a a a a a a a a a a z m U U i o c U ti ai m d d ti ai d d d d d d ui =i = N ❑ E ❑ a ll IL ll LL LL LL LL ll IL ll IL IL IL ll LL I1 o g v g v g v o a v v y v v v v v p v E o o A o 0 0 c 0 c 0 c 0 c 4 o r c o c 0 L 0 C 0 C o C a E o E 0 E 0 E o m m V u m d o a> > m vd p v N LL y W LL W O W W W W W W K W W W W W W W W W W N V O JY U > 0 000oOooOo00CL 0 0 0 NU y N (7 N mM NW N N N N N N N N N N N N N N N m d a m m rn m m m rn m m m m m m m m rn m Q K a W V - Z =_ O U Q j0 N O uMj O Q O J g g /� 0c. N p C Z ❑ > = C N m o O N o Go N m N H N O O N E E m n V ` o E v U Q C z Q K m M O W K O N O C7 J C w N ❑ � Z � N a J N a o in W Z Om r! Q fV Z o EU w 3 z U K U, m m m m m m m m m m m m m m m m m m a ❑ d M m m m m m m m m m m m m m m m m m o 3 E ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ A m m m m m m m m m m m m m :? S m Z° .m. .`° a o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o J 0 b j p U a d o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 A E r r r r r r r r r r r r r r r r r r r N O L W G Z K — O LL ¢ a E E — Z i O O Orn c v S U o ; w z U i U U U U U U U U U U U U U U U U E j O J ❑ O H = rn:9 6 ❑ ❑ ❑ ❑ O ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ ❑ O O O o d p j; J f W W W W W W W W W W W W W W W W W W J u U O � a } U D Z m 0 E U c N E Z (� Q Z E E c O � E O U N l 0 0 C d E E V � T J O N N C C O p Q C O U m O m O V T C4 o o 4 m 0 N m 0 N C 1 w U 0 O E n o o r O H i m v K on Q m K ✓ m m 2 w U m m ❑ c y R y Q O wn o O v 6 o ° d Q J a O O❑ o. o N m d O, 0 O y m E a U 0 0 ? U LL U K ❑ U U U N A C MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg f� DATE: Thursday, September 12, 2019 P.I. Supervisor i SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC FROM:E-39 Bob Noble Petroleum Inspector MILNE PT UNIT E-39 Well Name MILNE PT UNIT E-39 Insp Num: mitRCN190909171150 Rel Insp Num: Sre: Inspector Reviewed By: P.I. Suprvj7RP-- NON -CONFIDENTIAL API Well Number 50-029-23640-00-00 Inspector Name: Bob Noble Permit Number: 219-096-0 Inspection Date: 9/8/2019 - Packer Depth Pretest Initial 15 Min 'A Min 45 Min 60 Min r- -- _ Well E-39 Typelnj �� TVD rso Tubin 1)¢ 9u PTD 2190960 Q 915 - 914 Type Test srr Test psi isoo - lA we nos 1666 1651 . BBL Pumped: 1.8 " BBL Returned: is L OA Interval INITAL P/F — P —1 — Notes: New well. Mono bore well Thursday, September 12, 2019 Page I of I MEMORANDUM TO: Jim Regg 9 / P.I. Supervisor �n9 ` jl/a FROM: Guy Cook Petroleum Inspector I Well Name MILNE PT UNIT E-39 IInsp Num: mitGDC190831153521 Rel Insp Num: State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, September 10, 2019 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska LLC E-39 MILNE PT UNIT E-39 Sre: Inspector Reviewed P.I. Supry B NON -CONFIDENTIAL r,......, API Well Number 50-029-23640-00-00 Inspector Name: Guy Cook Permit Number: 219-096-0 Inspection Date: 8/31/2019 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well i E-39 _,Type Inj w TTVD 4359 —�-- __ __ _ t Tubin� sss - 557 - 554 -1 553 PTDT 2I90960� Type Test S�Test psi Is00 IA o 1645 1545 1502 - BBL Pumped: 14.4 ' BBL Returned: _33' OA Interval L P/F ✓ Notes: Test completed with a Little Red Services pump track with calibrated gauges. The well was flowing at 61 degrees F. and the pump truck had 60 degree diesel to pump for this test. Too close to the 1500 psi minimum and the 10% allowable total loss, with the addition of over I I bbl loss on the return for me to feel comfortable giving it a pass. Mono -bore well with no OA. Tuesday, September 10, 2019 Page I of I 4 Pa &-3 1 Regg, James B (CED) PM 7m ou, From: Regg, James B (CED) Sent: Friday, September 6, 2019 4:21 PM\ff 1/6 To: Darci Horner - (C); Brooks, Phoebe L (CED); DOA AOGCC Prudhoe Bay; Wallace, Chris D (CED) Cc: Wyatt Rivard; Taylor Wellman; Alaska NS - Milne - Wellsite Supervisors; William Kruskie; Matthew Linder Subject: RE: MIT -IA of Milne Point well E-39 AOGCC is deeming this test inconclusive — the significant volume pumped for the test and 10 bbl discrepancy between volumes pumped and returned are inconsistent with AOGCC criteria for a passing MIT. Please coordinate a retest with our North Slope Inspectors. Jim Regg Supervisor, Inspections AOGCC 333 W.7'h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 Jim Regg at 907- 793-1236 or iim.regg@alaska.eov. From: Darci Horner- (C) <dhorner@hilcorp.com> Sent: Tuesday, September 3, 2019 5:30 PM To: Regg, James B (CED) <jim.regg@alaska.gov>; Brooks, Phoebe L (CED) <phoebe.brooks@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov> Cc: Wyatt Rivard <wrivard@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com>; Alaska NS - Milne - Wellsite Supervisors <AlaskaNS-Milne-WellsiteSupervisors@hilcorp.com>; William Kruskie <wkruskie@hilcorp.com>; Matthew Linder <mlinder@hilcorp.com> Subject: MIT -IA of Milne Point well E-39 All, Milne Point well E-39 (PTD # 2190960) successfully passed the initial AOGCC witnessed MIT -IA on August 31, 2019. Please call myself or Wyatt Rivard (777-8547) with any questions. Regards, Darci Horner (Northern Solutions) Technologist H ilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim. moadalaska.aov'. AOGCC. InsDectors0ailaskaI Dhoebebmoks0alaska.00v OPERATOR: Hilcop Alaska LLC FIELD / UNIT / PAD: Milne Point / MPU / E DATE; 08/31/19 OPERATOR REP: Matthew Linder AOGCC REP: Guy Cook chits wallaces4alaake.Dov Well E-39Pressures: INTERVAL Codee Result Cetln Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, 4=Four Year Cycle PTD 2190960/ Type Inj N Tubing 555 557 1 554 553 N=Not lnjeping Type Test P Packer TVD 43% BBL imp 1 14.4 IA 0 1645 1545 1502 Interval Test psi 1500 BBLRetum 3.3 1 OA I I I I Ranson Notes Test performed using desel. Initial MITIA on new injedoL Well Pressures: Pretest Indial 15 Min. 30 Min. 45 Min. 60 Min. PTP Type Int Tubing Type Tesl Packer ND BBLPump IA Interval Test psi I BBL etumj IOA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type lnj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA 'ResuR Notes: Well Pressures: Pretest Insist 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBI -Pump IA IInterval Test psi BBL Return OA Result Notes: Wall Pressures', Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBI -Pump IA te Inrval Test psi BBL Return OA Result Notes: Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Typa Inj Tubing Type Test Packer ND 88L Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest initial 15 Min. 30 Min. 45 Min, 60 Min. PTD Type lnj Tubing Type Test Packer ND BBLPump IA Interval Test psi IBBL etuml I OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BB PUMPI IA I Interval Test psi BBL Return OA Result Nolen: TYPE INJ Cells TYPE TEST Co4ee INTERVAL Codee Result Cetln W=Water P=Pnusure Tell Is Initial Test P=Pett G=Gas 0= 01her(deecnbe In Nate.) 4=Four Year Cycle FFail S=Slurry V= Required Ey Varlance 1=lnwndudve I = Indaunal wanewver 0=env (deeodbe m nae.) N=Not lnjeping Form 10426 (Revised 0112017) MIT MPU E-39 adt-ta ..r STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas SPLUG ❑ Other ❑ Abandoned ❑ Suspended[] 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ Q WAGE] WDSPL ❑ No. of Completions: _ 1 Service Q Stratigraphic Test ❑ 2. Operator Name: 6. Date Comp., Strap., or 14. Permit to Drill Number/ Sundry: Hilcorp Alaska, LLC Aband.: 8/12/2019 219-096 3. Address: 7. Date Spudded: 15. API Number: 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 July 11, 2019 50-029-23640-00-00• 4a. Location of Well (Governmental Section): 8. Date TO Reached: 16. Well Name and Number: Surface: 3519' FSL, 1863' FEL, Sec 25, Tl 3N, R10E, UM, AK July 26, 2019 MPU E-39 Top of Productive Interval: 1879' FSL, 2055' FWL, Sec 36, TI 3N, R1 OE, UM, AKGL: 9. Ref Elevations: KB: 48.3' 21.7' BF: 21.7' 17. Field / Pool(s): Milne Point Field Schrader Bluff Oil Pool Total Depth: 10. Plug Back Depth MDfrVD: 18. Property Designation: 694' FSL, 714' FWL, Sec 6, T12N, R11 E, UM, AK 15,515' MD / 4,204' TVD 'ADL025518 / ADL380110 4b. Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. DNR Approval Number: Surface: x- 569284 y- 6016057 • Zone- 4 15,531' MD / 4,205' TVD LONS 94-017 TPI: x- 567988 y- 6009126 Zone- 4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 566701 y- 6002648 Zone- 4 N/A 2,223' MD / 1,780' TVD ' 5. Directional or Inclination Survey: Yes � (attached) No__rj 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) 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 evaluat(Qn,_0Co ppll�dogajor, �elry, and perforation record. Acronyms may be used. Attach a separate page if necessary RI hs LLLL�.� V� I�r ROP/ABG/DGR/EWR/ADR 2"/5" MD ABG/DGR/EWR/ADR 275" TVD SEP 05 2019 AOGCC 23. CASING, LINER AND CEMENTING RECORD CASING" PER FT. GRADE M SETTING DEPTH D SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 20" 215 X-42 Surface 107' Surface 107' 42" ±270 ft3 9-5/8" 40# L-80 Surface 8,557' Surface 4,365' 12-1/4" Stg1 L-908 sx /T-400 sx Stg 2 L - 530 sx / T - 270 sx 294 bbls 3-1/2" 9.3# L-80 Surface 8,332' Surface 4,366' Tieback Tieback Tubing 4-1/2" 13.5# L-80 8,288' 15,520' 4,366' 4,204' 8-1/2" Cementless Liner w/ICDs& Swell Packers 24. Open to production or injection? Yes 0 No ❑ 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): SIZE DEPTH SET (MD) IPACKER SET (MD/iVD) 3-1/2" 8,332' 7,570' MD / 4,155' TVD *** Please see attached schematic for ICD/Swell Packer Detail *** Liner run on 7/29/2019 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. COMPLETION Was hydraulic fracturing used during completion? Yes No v DATE Oi9 V RIF ED Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) JAMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc): N/A N/A Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period Flow Tubing Press. Casing Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (torr): Form 10-407 Revised �..,/ J�/,�z, CONm EOPAGE2 RBDMShEWSEP 112019 X� ORIGINAL onlx 28. CORE DATA Conventional Corals): Yes ❑ No 0 Sidewall Cores: Yes ❑ No Q If Yes, list formations and intervals cored (MD/TVD, From/ro), 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 ❑� If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Tap Permafrost - Base 2,223' 1,780' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval SB OB 8,852' 4,353' information, including reports, per 20 AAC 25.071. SV5 2,003' 1,662' Sv1 3,865' 2,509' Ugnu LA3 6,588' 3,708' ' SB NA 7,649' 4,188' ' SB OA 7,989' 4,318' ' SB OB 8,477' 4,364' Formation at total depth: SB OB 31. List of Attachments: Wellbore Schematic, Drilling and Completion Reports, Definitive Directional Surveys, Csg and Cmt 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. Authorized Name: Monty Myers Contact Name: Cody Dinger Authorized Title: Drilling Manager Contact Email: Cdjr1 er hIICOr .COIN Authorized Contact Phone: 777-8389 Signature: ' Date: `� • �� INSTRUCTIONS General: This form and the required attachmen 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 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the tap 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 5/2017 Submit ORIGINAL Only K HBosrp Alaska. LI.0 Orig. KB Elev.:48Y/Ori& GL Elev.: 21.7 TD = 15,531'(MD)/TD=4,205'(M) PBTD=15,515' (MD)/ PBTD=4,21M'(M) WELLHEAD Wellhead FMC GenS Milne Point Unit Well: MPU E-39 & Ll Last Completed: 08/14/2019 PTD: 219-096 OPEN HOLE / CEMENT DETAIL 20" Cmt w/ 260 sx of Arcticset I in 42" Hale 9S/8" SLg1L-908 sx/T-400 sx Top Stg 2 L —530 sx / T— 270 sx (294 bbls back) WELL INCLINATION DETAIL KOP @ 290' MD Max Wellbore. Angle =97,5 deg @ 13,687' MD GENERAL WELL INFO API: 50-029-23640-00/60-00 Drilled and Completed by Innovation Rig —August 2019 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm 20" Conductor 215/X-42/Welded N/A Surface 107' 9-5/8" Surface 40/L-80/TXP 8.835 Surface 8,557' 4-1/2" Liner "OA" Injection 13.5 / L-80 / Hyd 625 3.920 7,903' 12,650' Sta p2: Valve — Circ Valve / Date xx/xx/xx [WFRV] Liner w/ [CDs 7774' Sta Nl:Valve — Circ Valve/Date xx/xx/xx[WFRV) 7 7834' 4-1/2" Liner "OB" Injection 13.5 / L-80 / Hyd 625 3.920 8,288' 15,520' PBR Seal assembly (4- N" holes) Liner w/ ICDs TUBING DETAIL 3-1/2" Tubing/Tieback 1 9.3 / L-80 / EUE 1 2.441 1 Surface 8,332' JEWELRY DETAIL No Depth Item Upper Completion 1 2430' 3-1/2" X -Nipple (ID -2.813') 2 7512' Downhole Gauge 3 7570' 4-1/2"x9-5/8" Retrievable Packer(OLH) 4 7630' 3-1/2" X-Nipple(ID=2.813") GLM Detail: 3-1/2" x 1.5" Carrico w/ BK Latch 5 7683' Sta p2: Valve — Circ Valve / Date xx/xx/xx [WFRV] 6 7774' Sta Nl:Valve — Circ Valve/Date xx/xx/xx[WFRV) 7 7834' 3-1/2" XN-Nipple (Min 10=2.75") 8 8314' No-Go/xover sub 9 8332' PBR Seal assembly (4- N" holes) OA Latenl 10 7903' Top of Liner Paget Tendeka Water Swell Packer #1-9 Page 2 Tendeka SSD w/ Screen & ICD #1-7 (See Page 2 for Detail) 21 12650' Solid Bull Nose Shoe OB Lateral 22 8288' Liner Top Packer 9-S/8" x 4-1/2" Baker ZXP Paget Tendeka Water Swell Packer #1-10 Page 2 Tendeka SSD w/ Screen & ICD $11-30 (See Page 2 for Detail) 34 15,493' OB Lateral 4-1/2" Drillable Pack -off 35 15,515' OB Lateral 4-1/2" WIV 36 15,518' OB Lateral 4-1/2" Btm of Guide Shoe of "OA" Window WINDOW DETAIL Revised By: CID 9/4/2019 Depth MD Depth ND MPE-391CD/Swell Packer Detail 8,583' 4,365' Tendeka Water Swell Packer #10 8,852' 4,353' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.54 bxp 625 Wedge #9 9,212' 4,341' Tendeka Water Swell Packer #9 9,606' 4,327' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #8 9,840' 4,323' Tendeka Water Swell Packer #8 10,068' 4,320' Tendeka-ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #7 10,467' 4,300' Tendeka Water Swell Packer 47 10,859' 4,283' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge 46 11,299' 4,256' Tendeka Water Swell Packer #6 11,766' 4,227' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #5 11,993' 4,213' Tendeka Water Swell Packer #5 12,378' 4,192' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #4 12,727' 4,180' Tendeka Water Swell Packer #4 13,273' 4,209' Tendeka Water Swell Packer #3 13,333' 4,214' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.54 bxp 625 Wed e #3 13,603' 4,210' Tendeka Water Swell Packer #2 13,871' 4,181' Tendeka-ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge#2 14,506' 4,155' Tendeka Water Swell Packer #1 15,265' 4,183' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bx 625 Wed e #1 Depth MD Depth ND MPE-39LI ICD/Swell Packer Detail 7,931' 4,297' Tendeka Water Swell Packer #9 7,992' 4,315' Tendeka Water Swell Packer #8 8,095' 4,335' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #7 8,160' 4,344' Tendeka Water Swell Packer 47 8,553' 4,331' Tendeka Water Swell Packer #6 8,696' 4,318' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #6 8,849' 4,305' Tendeka Water Swell Packer #5 9,328' 4,281' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #5 9,688' 1 4,374' 1 Tendeka Water Swell Packer #4 10,043' 4,267' 1 Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.54 bxp 625 Wedge #4 10,528' 4,240' Tendeka Water Swell Packer #3 10,920' 4,224' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #3 11,277' 4,201' Tendeka Water Swell Packer #2 11,588' 4,181' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bxp 625 Wedge #2 11,945' 4,163' Tendeka Water Swell Packer #1 12,340' 4,149' Tendeka- ICD w/ 250L mesh, Sliding Sleave 13.5# bx 625 Wedge #1 County/State: , Alaska (IAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1910943D MPU E-39 Drilling Contractor Innovation AFE #: c e. Hilcorp Energy Company Composite Report ACtIYY.. _..... Ops Summary Well Name: MP E-39 Field: Milne Point Unit County/State: , Alaska (IAT/LONG): avation (RKB): API #: Spud Date: Job Name: 1910943D MPU E-39 Drilling Contractor Innovation AFE #: c e. Hilcorp Energy Company Composite Report ACtIYY.. _..... Ops Summary 7/9/2019 Spot MPD equipment behind rig. Spot, center, and level sub base over MP E-39 Set rig mats and spot cattle chute. Spot pipe shed. Continue with mud pump maintenance. 7/10/2019 Spot and level mud and motor mods. Spot beyond choke, cuttings tank and enviro vac. Safe out rig. Hook up all interconnects. Get air, water and steam online. Hookup diverter sections at end of catwalk. Plug in and swap to gen power at 11:30. Begin working on rig acceptance checklist.; Nipple up diverter system and knife valve. NIUBOP. Rotate break shack and plug in. SimOps: Cont. with mud pump maintenance, change out bearings on drag chain. Cont. working on rig acceptance checklist.;Cont. R/U MP E-39: Use crane to spot mats and diverter tie -down. UO TIO Mezz kill valve. install 1502 Comp flange and valve to Kill line. Add 5 gal hyd oil to dmwworks brake HPU. Scope Denick up. Bridle down and detach yoke. Grease crown, post rig move derrick inspection.;Change out saver sub and gripper dies. Grease spinners, blocks and top drive. Wrap service loop. Load and process 5" drill pipe in shed.;Cont. working on rig acceptance checklist. processing drill pipe, wrapping service loop with spiral guard. Unpin tongs. Energize accumulator. Install mouse hole.;Rig accepted at 03:OO.;Slip and cut drill line. Check brake air gap. Check dead man mount bolts. Set TD & drawwork limits. SimOps: Start bringing on mud. R/U hawk law 7/11/2019 PJSM pickup drift and rack back 5" drill pipe. Pull mousehole and prep for diverter test. Sirri Prime and function test mud pumps. Trouble shoot PCL network issue. Reconfigure network switches and update frmwam.;Test diverter system: function test flow paddle, test 112S and LEL alarms. Knife valva open in 7 seconds, annular close in 9 seconds. (6) N2 bottles at 2283 psi average. 200 psi recharge 14 seconds, full recharge 46 seconds. Test witnessed by AOGCC Adam Earl.;Cont. to pickup drift and rack back a total of 274 joints of 5" NC -50 DP, 19 joints HWDP with jars. Rig down Hawk Jar. Clean and clear rig floor.;Pre-spud meeting. R/U surface tongs. M/U 12-1/4" bit, motor, XO and 1 stand HWDP. RIH and tag bottom at 100'MD.;Flood stack. PT high pressure lines to 3000 psi for 5 minutes good.;Spud well: Cleanout conductor. Swap to spud mud on the Fly. Drill 12-1/4" hole from 107' to 220'; 400 gpm1445 psi, 40 rpms/1800f1-lbs. WOB 2-5K. PUW 47, SOW 46K, ROTW 46K. CBU x2 and POOH.;M/U remaining BHA: DM collar, measure RFO = 4.81/8.13'360 =212.98. M/U DGR, EWR P-4, PWD, HCIM, TM collar, UBHO. Plug in and upload MWD while hanging Pollard sheave. Orientate UBHO. Pick up drill collars. RIH to 220' with no issues.;Hauled 0 bible Fluid to MP G&I total = 0 bbls Hauled 650 We H2O from A -Pad reserve total = 650 bbis Lost 0 bible to formation Total fluid lost production = 0 bbis 7/12/2019 Drill 12-114" surface hole from 220' to 525'(245', AROP 41 fph) 420 gpm/900 psi with 90 psi diff, WOB 6 -SK, 40 rpms/2500 ft -lbs. PUW, 58K, SOW 69K, ROTW 59K. Gyro each connection to bit depth of 521' (survey depth 414'). Sliding as needed from 3°/100 build at 280'.;Drill 12-1/4" surface hole from 525' to 1028' (503', AROP 84 fph) 475 gpm/1225 psi with 190 psi diff, WOB 13-15K, 40 rpms/2000 ft -lbs. ECD 9.75 ppg EMW with 8.9 ppg drilling fluid. PUW, 75K, SOW 74K, ROTW 74K. Sliding as needed to maintain 4°/100 build from 559.;Drill 12-1/4" surface hole from 1028' to 1600'(572', AROP 95 fph) 525 gpm/1530 psi with 150 psi diff, WOB 13-15K, 80 rpms/4500 ft -lbs. ECD 10.2 ppg EMW with 8.9 ppg drilling fluid. PUW, 84K, SOW 77K, ROTW BOK. Sliding as needed to maintain 4°/100 build.;Drill 12-1/4" surface hole from 1600' to 2177' (57T, AROP 96 fph) 525 gpm/1730 psi with 150 psi diff, WOB 13- 18K, 80 rpms/6500 ft -lbs. ECD 10.5 ppg EMW with 9.1 ppg drilling fluid. PUW, 89K, SOW 75K, ROTW BOK. Sliding as needed to maintain W P07.;Hauled 969 bbis Fluid to MPG&I total = 969 bbis Hauled 1040 bbis H2O from A -Pad reserve total = 1690 bbls Lost 0 bible to formation Total fluid lost production = 0 bible Distance to WP07: 14.25' 13.85' High, 3.34' Left 7/13/2019 Drill 12-1/4" surface hole from 2177' to 2747' (570', AROP 95 fph) 550 gpm/1975 psi with 115 psi diff, WOB 6-7K, 80 rpms/6900 ft -lbs. ECD 11.2 ppg EMW with 9.15 ppg drilling fluid. PUW, 98K, SOW 67K, ROTW 80K. Maintenance slides as needed through tangent. Base of permafrost at 2,22TMD/1,780'TVD.;Drill 12-1/4" surface hole from 2747'to 3193' (446', AROP 75 fph) 550 gpm/1690 psi with 110 psi diff, WOB 10K, 80 Prins/8000 ft -lbs. ECD 10.9 ppg EMW with 9.3 ppg drilling fluid. PUW, 101 K. SOW 66K, ROTW 78K. Maintenance slides as needed through tangent.;Drill 12-1/4" surface hole from 3193' to 3511'(318', AROP 106 fph) adjust flow from 475gpm/1500psi to 550 gpm/1660 psi to maintain mud on shakers, WOB 10K, 80 rpms/8000 ft -lbs. ECD 10.62ppg EMW with 9.3ppg drilling fluid. PUW, 101K, SOW 66K, ROTW 78K.;Observe first gas 1340U gas at 3214'MD, 2207'TVD.;Cleanup cycle; CBU x2 ; 550 gpm/1815 psi, 80rpms. Reciprocating pipe. Max gas 22000 during first bottoms off, diminishing to BGG -250U during 2nd bottoms up. ECD 10.03 ppg EMW with 9.3 ppg mud.;Drill 12-1/4" surface hole from 3511' to 3703'(192', AROP 96 fph) adjust flow from 475gpm/1500psi to 550 gpm/1660 psi to maintain mud on shakers, WOB 4-5K, 80 rpms/8900 ft -lbs. ECD 10.07ppg EMW with 9.3ppg drilling fluid. PUW, 115K, SOW 69K, ROTW 85K. Max gas 761 U.;DnI112-1/4" surface hole from 3703' to 4346'(1343', AROP 107 fph) 550 gpm/1760 psi, WOB 6-7K, 80 rpms/1000 ft -lbs. Max Gas 1708U. ECD 10.5 ppg EMW with 9.3 ppg drilling fluid. PUW, 127K, SOW 73K, ROTW 88K.;Hauled 1254 bbis Fluid & Cuttings to MPG&I total = 2223 bbis Hauled 910 bible H2O from A -Pad reserve total = 26000 bbls Lost 0 We to formation Total fluid lost production = 0 bible Distance to W P07: 5.85', 5.68' High, 1.42' Left -Ti 4120-19 Drill 12-1/4" surface hole from 4346' to 4880'(534', AROP 89 fph) 550 gpm/2090 psi, WOB 7K, 80 rpms/11800 ft -lbs. Max Gas 1880U. ECD 10.1 ppg EMW with 9.3 ppg drilling fluid. PUW, 138K, SOW 72K, ROTW 96K. Backream full stands.;Drill 12-1/4" surface hole from 4880' to 5422' (542', AROP 90 fph) 550 gpm/2060 psi, WOB 7.5 K, 80 rpms/12-15K ft -lbs. Max Gas 17000. ECD 10.13 ppg EMW with 9.3 ppg drilling fluid. PUW, 152K, SOW 70K, ROTW 99K. Backream full stands.;Drill 12-1/4" surface hole from 5422' to 5962' (540', AROP 90 fph) 550 gpm/2360 psi, WOB 16-18 K, 80 rpms/16K ft -lbs. Max Gas 1111 U. ECD 10.52 ppg EMW with 9.3 ppg drilling fluid. PUW, 163K, SOW 74K, ROTW 102K. Backream full stands.;Drill 12-1/4" surface hole from 5962'to 6501' (539', AROP 90 fph) 600 gpm12600 psi, WOB 12 K. 80 rpms/16K ft -lbs. Max Gas 10490. ECD 10.4 ppg EMW with 9.3 ppg drilling fluid. PUW, 174K. SOW 72K, ROTW 107K. Backream full stands.;Hauled 1379 bbis Fluid & Cuttings to MP G&I total = 3602 bbls Hauled 780 bbis H2O from A -Pad reserve total = 3380 bbis Hauled 520 bbis H2O from B -Pad Creek total = 520 bbis Lost 0 bbls to formation Total fluid lost production = 0 bbls Distance to WP07: 17.9, 16.5' High, 5.83' right 7/15/2019 Drill 12-1/4" surface hole from 6501' to 7170' (669', AROP 111 fph) 600 gpm/2750 psi, WOB 17 K, 80 rpms/19.5K ft -lbs. Max Gas 1737U. ECD 10.2 ppg EMW with 9.5 ppg drilling fluid. PUW, 202K, SOW 79K, ROTW 117K. Backream full stands.;Drill 12-1/4" surface hole from 7170' to 7520'(35V, AROP 59 fph) 600 gpm/2710 psi, WOB 12-18 K. 80 rpms/23K ft -lbs. Max Gas 1430U. ECD 10.0 ppg EMW with 9.5 ppg drilling fluid. PUW, 210K, SOW 75K, ROTW 118K. Backream full stands.;Drill 12-114" surface hole from 7520'to 7902' (382', AROP 76 fph) 600 gpm/2715 psi, WOB 12-18 K, 80 rpms/21 K ft -lbs. Max Gas 461 U. ECD 10.05 ppg EMW with 9.5 ppg drilling fluid. PUW, 210K, SOW 77K, ROTW 119K. Backream full stands.;Clean up cycle. Rack one stand back. Pump tandem sweep: low vis - high vis/high wt (on time 10% increase). Circulate total 2 x BU at 600 gpm12400 psi, 80 rpms/21 Kft-lbs reciprocating pipe.;Ddll 12-1/4" surface hole from 7902' to 8153' (251', AROP 56 fph) 600 gpm/2710 psi, WOB 12-19 K, 80 rpms/21.7K ft -lbs. Max Gas 568U. ECD 10.0 ppg EMW with 9.5 ppg drilling fluid. PUW, 215K, SOW 77K, ROTW 119K. Backream full stands. Observe OA sands at 7989'. Begin 5'/100' build.;Hauled 1140 bbis Fluid & Cuttings to MP G&I total = 4742 bbis Hauled 780 bbis H2O from A -Pad reserve total = 4160 bbls Hauled 390 totals H2O from B -Pad Creek total = 910 bbis Lost 0 blas to formation Total fluid lost production = 0 blas 7/16/2019 Distance to W 07: 26.1g. 26.18' right Drill 12-1/4" surface hole from 8153'to 8570' (417, AROP 70 fph) 600 gpm/2670 psi, WOB 10 K. 80 rpms/21 K ft -lbs. Max Gas 288U. ECD 10.2 ppg EMW with 9.5 ppg drilling fluid. PUW, 210K, SOW 71 K, ROTW 121 K. Backream full stands. Sliding as needed for 5'/100' build.;Circulate hole clean. Pump tandem High vis, low wt vis sweep (no increase in cuttings) and CBU x 2, 600 gpm/2450 psi, 80 rpms/200-lbs, reciprocating pipe while racking two stands back to 8409'.;RIH to 8570' with no issues.;BROOH from 8570'to 5358'; 600 gpm/2175psi, 80 rpms/170-lbs, at 30 fpm adjusting speed as hole dictates with erratic torque. Max gas 260U. PUW 162K, SOW 73K, ROTW 104K. Lost 30 blas over displacement.; BROOH from 5358' to 2747'; 600 gpm/1880psi, 80 rpms/9Kft-lbs, at 30-35 fpm Max gas 177U. PUW107K, SOW 66K, ROTW 78K. ECD 10.3 ppg with 9.5 ppg mud. Lost 26.1 bbls over displacement.; Hauled 859 bbis Fluid & Cuttings to MP G&I total = 5601 bbls Hauled 650 bbis H2O from A -Pad reserve total = 4810 bbis Hauled 130 bbls H2O from B -Pad Creek total = 1040 bbis Lost 30 bbls to formation Total fluid lost production = 30 bbis _7711712019 Distance to WP07: 24.85' 17.97' High, 17.16' right BROOH from 2747to 400' MD (BHA). Backreamed at 600 9pm11880psi, 80 rpms to 1550' MD then reduce rams to 60 and flow to 550 gam. Continued backreaming to 1100' MD and reduced rates again to 40 rpm (sub 30° Inc +/-) and 500 gpm. Saw 12k stalls @ 960'w/ minimal psi increase.;Reduced pulling speed (10-20 fpm) and backmam thru tight spots with moderate issues from 960' to 75U MD before cleaning up. Saw significant increase at shakers of clay/sand w/ some pea gravel while working thru tight spots then cleaned up.;Monftored well (static). Backreamed out to jars (40 rpm, 500 gpm @ 5-15 fpm) pulled clean on elevators from jars to surface. Racked back HWDP w/ jars. BIO and UD B" DC's. Download MWD. BIO and laydown MWD. Drain and milk mud mfr. BIC, bit and clean same. Bit grade 2,3,BT,A,E,2,CT,TD.;Service rig. Grease/inspect: Crown, blocks, top drive, welds on TD carriage. Check oil levels. Monitor well on TT with 3 bph static loss rete.; Rig up to RIH with casing. Remove pup joint on Volant tool. Remove bell guide from TD. M/U Volant CRT. R/U bail extensions, elevators, power tongs. Bring centralizers on rig floor.; Baker lock and M/U shoe track: shoe, 2 joints casing, float collar with baffle bypass installed, 1 joint, baffle adapter, 1 joint casing. Check floats - good.;PJSM, RIH with 9-5/8", 408, L-80, TXP casing to 2365' M/U torque 21 Kft-lbs. Slow running speed to 30 fpm as loss rate increased to 81sph. PUW 116K, SOW 81 K.;Circulate hole clean 2 x bottoms upstaging pumps up to 7 bpm/141 psi reciprocating pipe.;Hauled 402 bbis Fluid & Cuttings to MP G&I total = 6003 bbis Hauled 390 bbls H2O from A -Pad reserve total = 5200 bbls Hauled 130 bbis H2O from B -Pad Creek total = 1170 bbis Lost 100 bbis to formation Total fluid lost production = 130 bbls 7/18/2019 Continue RIH with 9-5/6', 40k, L-80, TXP casing F/ 2365'- T/ 4749' MD. M/U torque 21 Kft-lbs. Static loss rate 8 bph. PIU 162K, SIO 64K. Tripped caean.;Continue RIH with 9-5/8", 40#, L-80, TXP casing FI 4749'- T/ 6209' MD. M/U torque 21 Kft-lbs. Static loss rate 8 bph. PIU 240K, S/O 38K. M/U ESICP between jts 154 & 155 (Bakeraok). ESICP witnessed by HES rep Jesse Slaughter. 3060 fpm running speed. Losing down wt and started floating csg.;Circulate and condition mud @ 6209' MD. Rot/Recip 2-5 rpm w/ 14k tq in down stroke (no rot on up stroke). Stage pumps up to 8 bpm, 455 psi, 71 %flow with minimal losses at full rate. 240k up before12061k up after, 38k do before/80k do after conditioning mud. 20% returns while running pipe (disp).;Continue RIH with 9-5/8", 40#, L-80, TXP casing F/ 6209'- 717570' MD. M/U torque 21 Kft-lbs. Static loss rate 3.5 bph. Tripped clean.;Circulate hole clean and condition mud reciprocating pipe. ICP 2bpm at 660 psi, stage pumps up slowly to 8 bpm FCP 375 psi. PUW 280K, SOW 95K. Circulate annular volume after staging up to 5.5 bpm.;Continue RIH with 9-5/8", 40#, L-80, TXP casing F/ 7570'- T/ 8557' MD. WU torque 21 Kft-lbs. Static loss rate 4 bph. Wash last joint down.;Circulate hole clean and condition mud reciprocating and rotating pipe 2-3 rpm 170 -lbs. ICP 2.5 bpm at 620 psi, stage pumps up to 8 bpm FCP psi. PUW 280K, SOW 95K. Funnel Vis initially coming out of hole 270+ down to 135 sec, pumping FV 55 (20YP) mud.;SimOps: RID bail ext., elevators, power tongs. Prep for cement job. Build black water.; Hauled 342 bbls Fluid & Cuttings to MPG&I total = 6345 bbis Hauled 130 bbls H2O from A -Pad reserve total = 5330 blas Hauled 0 bbis H2O from B -Pad Creek total = 1170 bbls Lost 57 blas to formation Total fluid lost production = 187 blas 7!19/2019 Rotate and reciprocate 9-5/8" costo while conditionin mud for upcoming cement lob. 8 bpm, 345 psi, 2-4 rpm w/ 18.5k tq. 320k up, 88k do wl no MP.; SM, Wet lines w/ 5 bbls H2O (HES) and P/T w/ 1000 low/ 4000 high. Failed high test 2x - Changed out 2x plug valves and retest (test good). Pump 1st stage cement job as follows: 60 bbls 10# Tuned spacer w/ 4# red dye & .5 Ib/bbl poly flake (1 st 10 bbls)Drop bypass plug 380 bbls 12# Lead cmt 2.349 - yld 6 bpm 700 psi 82.4 bbls 158# Tail cmt, 1.157 vld 5 bpm 530 psi. Drop shutoff plug. Displace w/ 20 bbls H2O (HES) then turn over to rig. Rig disp w/ 424 bbls 9.5# spud mud, 8 bpm, 460 psi. HES disp 88 bbls 10# spacer, 5 bpm.;Rig disp 111.4 bbls 9.5# spud mud, 6.6 bpm, 915 psi. Reduced rate last 20 bbls to 3 bpm, FCP 720 psi. Bump plug (1240 psi) with 643.4 bbls actual / 641.5 bbls calculated. Held pressure for 5 minutes, check floats - good. CIP @ 12:31 hrs. Full returns throughout iob.,Pressure up to 3000 psi to open ES cementer. Circulate at 6 bpm/1750 psi. Observe 50 bbls of green cement at surface at bottoms up. Continue circulating at 6 bpm, observe pressure drop to 550 psi after 5 x bottoms up. Stage rate up to 8 bpm/875 psi to clean wellbore.;Flush stack - Drain stack. Fill with black water. Disconnect knife valve from accumulator. Workbag several times, and repeat x2. Flush flow, line with black water.;Continue circulating 6 bpm/550 psi. Prep pits for 2nd stage cement iob. Break out of volant and re-engage.;Pump 2nd stage cement job as follows:60 bbls 10# Tuned spacer w/ 4# red dye & .5 Ib/bbl poly flake (1st 10 bbls) at 3.5bpm/280 psi. 416 bbls 10# Lead Perm L cmt, 4.407 yld, 6 bpm/660 •+t Li psi. Observe good cement back 370 bbls into cement. 56.2 bbls 15.8# Class G tail cement, 1.169 yld, 3.2 bpm/380 psi.; Drop closing plug. Displace with 20 bbls water (HES) then tum over to rig. Rig displaced with 170.7 bbls (165.2 Calc) 9.4 drilling mud at 6 bpm/800 Slow 3 bpm l it ppg psi. to with 10 bbls to go. FCP 500 psi, bump plug and pressure up to 1950 psi with positive indication ESICP closed. CIP 22:48.; Hold pressure for 5 minutes and bleed off to confirm tool closed. No losses during cement job. 294 bbls of green cement returned to surface. Drain stack. Fill with black water. Disconnect knife valve from accumulator. Work bag several times and repeat. Flush flow line with black water at 10 bpm through bleeder.; PJSM. R/D Volant tool. Suck out casing joint. Install casing elevators. Remove mouse hole. Hook up bridge cranes to stack. R/D chains on stack. Remove diverter sections downstream of knife valve. Remove nuts on diverter T. SimOps; continue to clean flowline and surface equipment. clean pits.;Lift stack. Install 'E' slips, center casing. Set 100K on slips. Rough cut casing. UD joint and measure (27.98'). R/D casing elevators. R/U DP elevators.; Hauled 1763 bbls Fluid, Cuttings and cement to MP G&I total= 8108 bbls Hauled 1300 bbls H2O from A -Pad reserve total = 6630 bbls Hauled 0 bbls H2O from B -Pad Creek total = 1170 bbls Lost 0 bbis to formation Total fluid lost production = 187 bbls 7/20/2019 PJSM, Set stack and hot bolt to wellhead. Flush stack w/ Johnny whacker using H2O and Black water to treat residual cmt. Blow down surface equipment. Replace master bushing w/ split bushings. N/D riser and rack back BOP'S on stump. N/D and remove diverter equipment from cellar.;N/D starter head and make final cut (dress same). Install T-103 adapter along with casing spool. Sym Ops - Continue cleaning pits, filter koomey hydraulic oil, Bring wellhead bushing and test plug to rig floor.;Install DSA and spacer spool. Pick up MPD bearing and suspend. NIU BOPE assembly. Test T-103 void 500/5min, 2470 (80% casing burst)/15 min, test wellhead void 500/5 min, 5000/15 min - witnessed by Co. Man SimOps: continue cleaning pits. Shut down boiler #2 for annual inspection. Clean hotwell tank.;Cont. N/U BOPE. Install MPD bearing. Rig up MPD hard lines. Install riser, drip pan. Connect choke and kill lines. SimOps: Take on new Bamdril- N drilling fluid.;M/U 5" test joint, TIW, Dart, side entry. Install test plug and fill stack. Observe leak on riser and MPD clamp. Tighten same. Pressure up accumulator lines and inspect hydraulic Iines.;Test BOPE 5" test joint 250/3500 psi. AOGCC's right to witness waived by Guy Cook. Fail on mezzanine Kill, troubleshoot. Attempt to bleed air and grease, still fails. Continue testing while rebuilding valve. Currently on test 93.;Hauled 1280 bbls Fluid, Cuttings and cement to MP G&I total = 9388 bbls Hauled 520 bbls H2O from A -Pad reserve total = 7150 bbls Hauled 0 bbls H2O from B -Pad Creek total = 1170 bbls Lost 0 bbls to formation Total fluid lost production = 187 bbls 7/21/2019 Continue test BOP's. Test 250 low 13500 high on BOP components. 5/5 min ea, chart and record same. Witness waived by AGOCC rep Guy Cook via email. Rebuilt Me= Kill and retested (test good). Tested w/ 4.5" and 5" test its. Drawdown - 3050 start, 1500 drawdown, 22 sec for 200 psi, 86 sec inal;6 bottle avg NO2 - 2300 psi. Test PVT and flow paddle monitoring system & alarms (test good), Test gas alarms 10/20 ppm 112S, 20/40% LEL (test good).;R/D BOP test equipment. Install Beyond MPD test cap. P/T MPD system to 1000 psi w/ 15 min hold (test good). R/D all test equipment. Install flow riser. Remove test plug and install 10" ID wear bushing, RILDS. B/O test subs from TIW, Blow down choke manifold and lineup for drilling operations.;lnstall long mousehole and R/U floor for making up BHA. PJSM, M/U 8.5" milltooth w/ 1.5° 6.0 stg motor. RIH w/ Jars and HWDP T/ 655' MD.;RIH with drill out assembly from 655' to 2441', tag up with SK x 2. PUW 88K, SOW 54K.;Wash and ream drilling cement stringers and ESICP from 2414'to 2445'; tag ESICP on depth at 2437'. 40 rpms/5500 ft -lbs, 400 gpm/550 psi, WOB 3-8K. Work through x3, last with no pumps rotary -good.; RIH with drill out assembly from l derrick from 2445' to 8350', wash and ream last two stands down at 420gpm/1020 psi, 30 rpms/23Kft-Ibs. Tag up on cement stringers with 10K down.;Circulate and condition mud at 420 gpm/1020 psi, 30 rpms/23Kft-lbs, ROTW 112K. Cement observed at bottoms up.; Rig up and flood lines, purge air. L5 Test casing to 2500 psi for 30 minutes -good. 6.9 bbls pumped, 6.9 bbls returned.;Drill cement, shoe track and 20' new hole from 8450' to 8590' with 40 rpms/24Kft-Ibs, 420 gpm/1200 psi, WOB 5K. Tag up on baffle adapter (8437), float collar (8476'), and shoe (8555') on depth.; PJSM displace to 8.9 ppg Baradril-N drilling fluid. Pump 58 bbls high viscosity sweep followed by Baradril-N at 350 gpni psi. CBU for even MW in and out. Rack back 1 stand to 8539.;Pump through choke and kill lines and flood system. Shut UPR and perform FIT to 12 o nog EMW. 3 bbls pumped, 2.4 bbls returned.;Hauled 342 bbls Fluid, Cuttings and cement to MPG&I total = 9730 bbls Hauled 260 bbls H2O from A -Pad reserve total = 7410 bbls ' Hauled 0 bbls H2O from B -Pad Creek total = 1170 bbls Lost 0 bbls to formation Total fluid lost production = 187 bbls 7/22/2019 R/D FIT test equipment. Grease, Blow down choke & kill. Line up for drilling operations.;Monitor well (static). Pump dry job and POOH F/ 8,436- T/ 655' MD. Hold took proper displacement. Tripped thru stage tool clean.;Monitor well @ HWDP (655). UD excess HWDP, rack back 2 stds hwdp (w/ jars), 1 std flex DC's. Drain mtr, B/O bit and UD same. Bit graded - 1, 1, NO,A,E,I, NO, BHA.;PJSM, M/U 8.5" Geo Pilot rotary steerable, MWD/LWD. Upload MWD, M/U flex DC's (install corrosion ring on top of DC's).;PJSM, P/U 5" 5-135, NC50 drill pipe from shed F/ 275'- T/ 3088' MD. Drift 3.125".;Fill pipe, shallow pulse test. Continue to P/U, drift and single in the hole with NC50 DP from 3088' to 7712'. RIH out of derrick to 8475'. Fill pipe. Calculated displacement for trip. PUW 193K, SOW 80K.;Slip and cut 94' of drilling line. Check brakes. Calibrate drawworks, floor/crown saver.;PJSM. Remove riser, stab and install RCD bearing . Pump at 2 bpm checking for leaks. Obtain SPR's.;Service rig, grease Top drive, blocks, crown and floor equipment.; RIH from 8475', washing down last stand 475 gpm/1300 psi no issues. PUW 178K, SOW 68K, ROTW 110K.;Drill 8-1/2" hole from 8590'to 8866' (total 276' AROP 92 fph) 475gpm/1300 psi, staging rotary up from 60 rpms to 140 rpms/19Kft-lbs. Max gas 730U, ECD's 10.1 ppg with 8.9 ppg drilling fluid. PUW 185K, SOW 78K, ROTW 107K.;Distance to WP #7: 13.78', 2.4' High, 13.55' Right. 1 concretion has been drilled so far this lateral for a total footage of V (0.5%). 188' drilled in the OBa-1 sands.;Hauled 927 bbls Fluid, Cuttings and cement to MPG&I total = 10657 bbls Hauled 260 bbls H2O from A -Pad reserve total = 7670 bbls Hauled 0 bbls H2O from B -Pad Creek total = 1170 bbls Lost 0 bbls to formation Total fluid lost production = 187 bbls Drill ahead 8.5 Hole FI 8,866' to 9,685' MD (4,325' TVD) 819' total (136.5' AROP) 550 GPM, 1,760 PSI, 135 RPM, TRQ ON 16-25K, TRQ OFF 18- Back ream 60' every connection.;SPR @ 9,895' MD (4,323' TVD) —T/23/2019 PJSM 25K, WOB 3K, Max Gas 1,357U, ECD 10.3, MW 8.9 pp9. P/U 220K, SLK 44K, ROT 109K. MP 2 32-220, 48-275.;Cont drilling ahead 8.5" Hole F/ 9,685' to 10,280' MD (4,310' TVD) 595'total (99.2' AROP) 550 MW GPM, 8.9 ppg MP 1 32-221. 48-272 1,804 PSI, 160 RPM, TRQ ON 17-25K, TRQ OFF 20-25K, WOB 12K, Max Gas 1,084U, ECD 10.43, MW 9.0 ppg. P/U 222K, SLK 42K, ROT 108K. Circ. out. TRQ returned to average 24-25K. Back ream 60' every connection.;At 9,760' MD Pumped 10% Baro-Lube 50 bbl pill, torque dropped to 22K until 48-320.;PJSM Drill ahead 8.5" Hole F/ 10,280' to 10,960' MD (4,281' SPR @ 10,064' MD (4,3241 TVD) MW 9.0 ppg MP 1 32-265. 48-317. MP 2 32-267, AROP) 550 GPM, 1,876 PSI, 145 RPM, TRQ ON 20-25K, TRQ OFF 24-26K, WOB 1OK, Max Gas 1,2000, ECD 10.46, MW 9.0 ppg. Torque TVD) P/U 680' total (113.3' 208K, SLK 48K, ROT 106K. Back ream 60' every connection.;At 10,514' MD Pumped 2% EZ- Glide, 2 % Baro-lube, 6 % NXS- Lube 50 bbl pill, MP 1 32-254, 48-312 MP 2 32-252, 48-314.;Cont drilling ahead smoothed out and P/U SLK weights improved. SPR at 10,509' MD (4,297' TVD) MW 9.0 ppg MD TVD) 569' total (94.8' AROP) 550 GPM, 1,985 PSI, 140 RPM, TRQ ON 26K, TRQ OFF 24-26K, WOB 8K, Max 8.5" Hole F/ 10,960' to 11,529' (4.243' Gas 1,264U, ECD 10.8, MW 9.0 pp9. PIU 230K, SLK 35K, ROT 102K. Control drill 150 ROP to reduce ECD. Lost SLK at 11,342' MD.;At 11,457' MD Pumped increase of mostly Clay. SPR at 11,529 MD (4,243' TVD) tandem 50 bbl Low Vis 8.7 ppg 37 Vis, 50 bbi Hi Vis 9.0 ppg, 300 Vis. Returned on time W/ 50% 2 32-350, 48-415.;Distance to WP #7: 21.8', 19.24' Low, 10.25' Left MW 9.0 ppg MP 1 32-345, 48-410 MP 25 concretions have been drilled so far this lateral for a total footage of 111' (3.8%). 520 bbls to G&I total = 11,117 bbls 1,263' drilled in OB-1, 357' drilled in OB-2, 1,288' drilled in OB-3;Daily hauled Hauled 650 bbls H2O from A-Pad reserve total = 8,320 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1170 bbls Lost 0 bbls to formation Total fluid lost production = 187 bbis Cont drilling ahead 8.5" Hole F/ 11,529' - T/ 12,169' MD, 640' total (107' AROP) 550 GPM, 2069 PSI, 140 RPM, TRQ ON 25K, TRQ OFF 25K, WOB 12K, SLK 35K, ROT 100K.;Cont drilling ahead 8.5" Hole F/ 12,169' -T/ 12,930' MD, 761'total (12T AROP) 550 7/24/2019 Max Gas 1,365u, ECD 11, MW 9.0 ppg. P/U 234K, GPM, 2,190 PSI, 160 RPM, TRQ ON 24K, TRQ OFF 23K, WOB 8K, Max Gas 1,288u, ECD 11.1, MW 9.1 ppg. Drilled expected fault @ 12,754' MD. Reduce Wts to adding inclination to 85° to drill down in structure and re-enter the OA sand.;Add NXS lubes (primarily for metal to metal contact) to mud system. prior 12,930'to 13,446' MD (4,218' TVD) 638' total (106.3' lube: 245k up, no do wt, 100k rot. Wits after: 153k up, 57k on, 97k rot.;Cont drilling ahead 8.5" Hole F/ RPM, TRQ ON 26K, TRQ OFF 28K, WOB 13K, ECD 11.7, MW 9.1 ppg. Started turn at 13,056'3.5'/l 00, build 3°1100. AROP) 550 GPM, 2,305 PSI, 160 Reentered OA1 sand at 13,300' MD.;Encountered losses at 13,466', initial dynamic rate 210 bph. Drill ahead at 125 ROP F/ 13,466to 13,568' MD 400 GPM, Dynamic rate slowing to 125 bph. Lost 150 1,470 PSI, MPD FO 300 GPM, 120 RPM, TRQ ON 23K, WOB 4-71K, Max Gas 1,002U, ECD 10.9, MW 9.15 ppg. Bare Carb 5, 25 & 150 F/ 9 ppb to 15 ppb throughout the system. Came out of OA sand at 13,526 MD.;Drill ahead at 125 ROP F/ ECD bbls to formation.;lncreased 13,568'to 13,752' MD 400 GPM, 1,470 PSI, MPD FO 300-350 GPM, 120 RPM, TRQ ON 20-22K, TRQ OFF 21K. WOB 10-14K, Max Gas 1,464U, loss 100-180 bph. Increased BareCarb F/ 15 to 21 11.1, MW 9.25 ppg. P/U 165K, SLK 35K, ROT 100K. Reentered OA3 at 13,675' MD.Dynamic rate Reduce ROP to 60 FPH for hole cleaning and BU Gas. FI 13,752' to 13,897' MD same parameters. pp;Started encountering ballooning during connections. after 5 Min Beyond on dFO at 19 Max Gas 680U. MPD FO increased F/ 300 GPM to 375 GPM almost matching flow in.;Flow check well, about 35 bbls back WP #7: 44.51', 44.30' High, g 9 OA Sand GPM. Cont. drilling at 60 FPH W/ —30 BPH dynamic losses, Total lost 395 bbls.;Distance to far this lateral for a total footage of 258' (4.9%). formation still in zone.;50 concretions have been drilled so Fault at 12,754' MD. throw of at least 145' SD. 2,552' drilled in OB-1, 357' drilled in OB-2, 1,288' drilled in OB-3 68' drilled in OA-1, 36drilled in OA-2, 31' drilled OA-3 Total out of zone 695'; Daily hauled 519 bbls to G&I total = 11,696 bbls Hauled 780 bbls H2O from A-Pad reserve total = 9,100 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1170 bbls Lost 545 bbls to formation Total fluid lost production = 545 bbls Drill ahead 8.5" Hole F/ 13,752' to 14,458' MD. 480 GPM, 1820 PSI, 140 RPM, TRQ ON 27K, TRQ OFF 21 K. W08 14K, Max Gas 1175u, ECD 11.1, MW 9.2 5" Hole F/ Maintain 15 Baracarb (LCM) background. Maintain 4% Iube.;Drill he d 8.5, 7/25/2019 ppg. P/U 185K, SLK N/A, ROT 103K. 30-90 bph dynamic loss rate. ppb SLK MD. 480 GPM, 1940 PSI, 140 RPM, TRQ ON 19K, TRQ OFF 19K. WOB 14K, Max Gas 1113u, ECD 9.9, MW 9.15 ppg. PIUN/A, 14,458' to 15,079' ROT 97K. Drilled out btm of OA @ 14,547' as planned. Drilled down in section re-entering OB sand @ 15,000' MD / 4,173' TVD.;Obsewed significant background when losses started again. Maintain losses after drilling in OB sand @ 15,000' MD. 470 bph initial loss rate @ 480 gpm. 11 ppb Baracarb (LCM) from 300-450 gpm, 160-100 rpm, 30-200 ROP in attempt to heal Iosses.;Shut down for svy. We saw no 4% lube ( NXS / Baroseal). Vary parameters overpulls with rotation or no rotation when picking up which indicates no signs of differential sticking. We saw no increase or erratic tq, no signs of packing off Rotate and reciprocate at 300 GPM Increasing Baracarb FI 11 issues. ECD's dropped from 11.3 to 9.9 once we incurred high losses. 15 - 20% returns.;PJSM 450 bph. Bring on 100 bbls F/ VAC Truck.;Drill ahead F115,079' to 15,188' MD (4,179 TVD) at 312 GPM, 941 PSI, 100 ppb to 20 ppb in active. Loss rate at RPM, TRQ ON 19K, TRQ OFF 19K, 4-10K WOB, Max Gas 168U, ECD 10.5 ppg. Beyond FO 84 GPM. Dynamic loss rate at 360 bph. Bring on last 290 bbl Running water at 50 bph. Ordered another 290 F/ Mud Vac Truck.;Baracard going down hole at 20 ppb showed no signs of slowing dynamic losses. to 15,150' MD. Reduced flow rate F/ 300 GPM to 100 GPM 430 PSI, 130 RPM, TRQ 18.5-19K, ROT 112K, at 100 GPM Plant.;Rotate and Recip FI 15,185 Initial loss rate 71 BPH. Build 2 50 bbl LCM Pills 40 ppb. ( Baracarb 25 20 ppb, 50 20 ppb) (Baracarb 150 10 ppb, 50 15 ppb, 5 15 ppb).;Pumped 30 bbls to 90 GPM( Beyond FO 33 GPM W( dynamic down drill string and blended 80 in suction Pit to add volume. Surface volume at 300 bbls. Reduced flaw rate the bit. Beyond FO increased to 45 GPM W/ dynamic loss at 65 BPH.;Building 50 bbl batches for volume. losses at 86 bph 36% returns as LCM pill came out W/ losses. Lost 1,618 bbls for tour.;Cont Rot & Recip building 50 bbl batches for volume. Pumping at 90 GPM, 440 Doyon 14 sent over 135 bbls to keep up PSI, Beyond FO 43 GPM loss rate 67 BPH 47% returns. Maintaining 18 ppb in active system. Increased flow rate to 110 GPM, 480 PSI, Beyond FO 50 gpm Baracarb 150 25 50 10 ppb 25 5 ppb) 110 GPM, 495 PSI, 45% returns. MW in 8.9 ppg, MW out 9.3 ppg.;At 01:45 Pump 50 bbl 40 PPB LCM Pill ( ppb, Max Gas 685U. Unload 290 bbis Vac Waitingat 290 F1 Mud Planl OI out ofibit 10K, Beyond FO 61 GPM, Max Gas 727Ut Loo02:00. a Beyond FO 52bph. Water at 50 bph. 03:30 LCM P GPM, 550 PSI, 130 RPM, TRQ 18K,47% returns, 'c loss ROT 182. Stage rate F/ 90 to 110 GPM, 512 PSI.;Beyond FO reduced to 90 GPM, 503 PSI, Beyond FO 60 GPM 66% return Received 135 bbls F/ Doyon 14. up pump Maintaining 20 Baracarb. Received another 135 bbl FI Doyon 14. Lost 360 bbls. Max 69 GPM, 63% returns 58 bph loss rate. ppb Max Gas 4%rU. BeyondeFO TVD) 315 GPM, 945 PSI, 130 RPM, TRQ ON 19K, TRQ OFF 16K, WOB 4-12K. ECD 10.1 ppg. in 15,188' to 15,218' MD. (4,182' 332 BPH. P/U 168K, SLK 35K, ROT I I0K.;Distance to WP #7: 30', 29.02' High, 7.58' Right. Following OA Sand formation still 84 GPM, 27% returns. zone.;55 concretions have been drilled so far this lateral for a total footage of 303' (4.6%). Fault at 12,754' MD. throw of at least 145' SD. 2,739' drilled in OB-1, 35T drilled in OB-2, 1,288' drilled in OB-3 68' drilled in OA-1, 256' drilled in OA-2, 774' drilled OA-3 Total out of zone 1,148';Daily hauled 288 bbls to G&I total = 11,984 bbls Hauled 1,300 bbls H2O from A-Pad reserve total = 10,400 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1170 bbls Lost 2 098 bbis to fo atio Total fluid lost rot uctio = 2 643 bl 7/26/2019 Continue drilling ahead F/ 15,187' - T/ (TD) 15,531' MD 14205' TVD. TD called early due to high loss rates seen in the OB sands. Drilled ahead w/ 40-50% returns @ 315 gpm in, 945 psi, 12k wob, 130 rpm, 19k tq on, 16k tq off, 10.1 ECD's. 435u Max gas observed.;Pumped 60 bbls 40 ppb (Baracarb) LCM pill @ 15,187' MD with no change in loss rate.;Obtain SPR's and final svy @ TD. Circulate 30 mins attempting to heal losses (no change) 330 BPH dynamic loss rate. Vary parameters 300-450 gpm, 1100-1550 psi, 100-140 rpm w/ return rate 40-50%. Move pipe without issue w/ pumps on or off. 164k up. 107k rot, 17k [q. Well breathing.;BROOH F/ 15,531'- T/ 14,500' MD @ 30 fpm, 325 gpm. 1100 psi, 100 rpm, 13-15k tq. 40-50% returns during backreaming w/ well breathing back fluid with pumps off. Clean trip out with no issues. 164k up, 107k rot.;BROOH F/ 14,500'- T/ 13,186' MD @ 15 fpm, 450 gpm, 1600 psi, 100 rpm, 10-13k tq. Still seeing 40-50% returns and well breathing @ connections. Increase pump rate @ 13,870' to 475 gpm, 1700 psi, 240 gpm return rate (Beyond MPD meter). Seeing fine sand @ shakers. ECD's bouncing between 10-10.1.;Shut down and monitor well. 180 gpm initial return flow rete and slowed to 15 gpm over 25 min. Remove rotating head and install flow riser while pits were preparing for brine displacement. MT pit 5 and replace valve seal in pit. Free pipe movement with no issues up or dn.;Continue BROOH F/ 13,186 - T/ 12,527' MD @ 15 fpm, 500 gpm, 1600 psi, 36% F/0, 100 rpm, 10-13k tq, 155k up, 107k dn. Pulled clean with no issue. Increase pump rate to yield higher return rates and help clean wellbore.;Flow check well for ballooning. Initial 10 min bleed back 28 bbls, 20 min 16 bbls, 30 min 11 bbis, 40 min 8 bbls. Total 63 bbls bled back with flow out still declining. Breaking over string every 10 min without issue.;Cont. BROOH F/ 12,527' to 11,214' MD 500-475 GPM, 1,550 PSI, 130 RPM, TRQ 10.5K, FO 48%, P/U 141, SLK 82K, ROT 109K, Well still breathing in between connection. At 11,680' MD Checked dynamic loss rate at 198 bph, 475 GPM, 1,400 PSI, 130 RPM, TRQ 10K, FO 47%. 10.1 ECD.;PJSM for displacing to 9.1 ppg Quick Drill (Brine). Pump Chem Train (35 bbl SAPP, 35 bbl Brine, 35 bbls SAPP, 35 bbl Brine, 35 bbl SAPP) into string at 8 GPM, 870 PSI, 130 RPM, TRQ 9K, FO 43%. BROOH 1 stand to 11,151' MD.;PJSM BROOH while displacing to 9.1 ppg Quick Drill taking returns to cutting box. F/ 11,151'to 10,810' MD 336 GPM, 610 PSI, 130 RPM, TRQ 10.9-12K, FO 46%, 4 fUmin for hole cleaning W/ 155 AV in casing. Well breathing during connection but progressively slowing down by the end.;Chem trains came back as calculated. No issues BROOH during displacement. Was no noticeable difference in TRQ or string weights. Flow checked well for 10 min bled back 7 bbls and almost static.;Cont. BROOH F/ 10,810' to 9,494' MD 475- 500 GPM, 1,090 PSI, 130 RPM, TRQ 10-11 K, FO 52%, 20-25 ft/min PIU 136K, SLK 93K, ROT 108K, Well almost static at connections. Dynamic loss about 9-11 BPH. Lost 24 bbls.;Distance to WP #7: 9.19', 3.72' High, 8.41' Right. Following OA Sand formation in zone.;80 concretions were drilled this lateral for a total footage of 324' (4.6% of the lateral). Fault at 12,754' MD. throw of at least 145' SD. 2,882' drilled in OB-1, 435' drilled in OB-2, 1,380' drilled in OB-3 68' drilled in OA-1, 256' drilled in OA-2, 774' drilled OA-3 Total out of zone 1,14&;Daily hauled 114 bbls to G&I total = 12,098 bbls Hauled 390 bbls H2O from A-Pad reserve total = 10,790 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1,430 bbls Lost 2,108 bbls to formation Total fluid lost production = 4,751 bbls 7/27/2019 Continue BROOH F/ 9494'- T/ 8539' MD @ 20-25 fpm. 565 gpm, 1245 psi, 125 rpm, 11 k lq. 156k up, 90k dn, 112k rot. 17 bbl loss. 9 bph dynamic losses. Slowed rotary to 30 rpm while pulling BHA into 9-518" shoe. Pulled clean into shoe.;Circulate and condition to clean casing @ 8539 MD. Pump tandem sweep (back on time w/ no increase). 565 gpm, 1245 psi, 125 rpm, 11k tq. 156k up, 90k dn, 112k rot.;Grease traveling equipment, Crown and TOS (Wash pipe). Monitor well (static after 15 min).;TOOH F/ 8539'- T/ 7309' MD on elevators. Pulled 5 wet, pumped dry job, B/D TDS prior to tripping. 3.4 bbl Ioss.;TOOH F/ 7309'- T/ 3490' MD on elevators. 149k up, 84k dn. Dropped 2.375" drift on wire on std #91.;PJSM, UD excess drill pipe F/ 3490' - T/ BHA. 37 bbl loss for trip.;PJSM Rack back Jars, 5" HWDP and FC. Retrieve corrosion ring. Download MWD tool. Monitor well on TT, Static loss rate 7-9 BPH. UD remaining BHA as per Sperry DD & MWD. Bk Grade 1-1-BT-C-X-I-CT TD.;PJSM R/U Weatherford tools and Equip. Stage 20 7" Centralizers on rig floor. Install stop rings in Pipe Shed. Stage Baker Equip on rig floor. Load Pipe Shed W/ ICDS and SP. M/U Triple Connect X/O TIW and 4.5" Lift Sub.;PJSM for running 4.5" Liner. PIU MIU 42' Round Nose Float Shoe, W IV, Drillable Pae Off Sub Shoe Track. Check floats, good. Cont. PIU M/U 4.5" 13.5# L-80 W625 Liner, ICDS and Swell Packers as per tally to 700' MO. TRQ 4.5" to 9,600 ft/lb. Static loss rate -9 bph. Total lost for tour 92 bbls.;PJSM Cont RIH W/ 4.5" 13.5# L-80 W625 Liner, ICDS and Swell Packers as per tally F/ 700' to 3,881' MD. TRQ 4.5" to 9,600 ft/lb. Static loss rate -9 bph. Topping off every 20 Jnts. Total lost 52 bbls.;Daily hauled 1,400 bbls to G&I total = 13,498 bbls Hauled 130 bbls H2O from A-Pad reserve total = 10,920 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1,430 bbls Lost 187 bbls to formation Total fluid lost production = 4,500 bbls 7/28/2019 Cont RIH W/ 4.5" 13.5# L-80 W625 Liner, ICDS and Swell Packers as per tally F/ 3,881' to 7,188' MD. TRQ 4.5" to 9,600 ft/Ib. Calc Disp 14 bbls, actual -13 bbis, Lost 27 bbls. Topping off every 20 Tis. Total lost 52 bbls. C/O JNT 163 & 164 Bad. W/ 166 & 167.;PJSM Clean and clear rig floor of 4.5" handling Equip. WU Safety Jnt. C/O Elevators to 2 318". R/U False Rotary Table. Static loss rate 5.5 bph.;PJSM P/U M/U Slick Stick and RIH 2 3/8" 5.959 PH6 to 7,139' MD. TRQ to 3,100 ft/lb. Skipped Jnt 132 bad. P/U 65K, SLK 45K. Drift W/ 1.66" OD Rabbit F/ Skate. Static loss rate -5 bph.;Tag at 7,139' set down 4K 2X. PJSM UD i Jnt 2 3/8" PH6. Space out inner string 14.37' WI X/O PH6 P X fird B, 4,09'& 10.14' Pup. P/U SLZXP M/U 2 3/8" Swivel, 10.15', 6.17', 4.87' pups on bottom. P/U Seal Bore Assy set in Mouse Hole. Lower SLZXP and 2 3/8" tail through Seal Bore.;M/U 7" H563 connection to 7,800 ft/lb W/ rig tongs. MIU 2 318" inner string to stump. Inner String P/U 68K, SLK 50K. Remove False Bowl and table. M/U 4.5" Liner to Seal Bore Assy TRQ to 9,600 fUlb. P/U 123K, SLK 81 K. RIH W11 stand 5" D.P. to 7,288' MD.;Slick Stick no/go 6.18' above Pack Off and 8' swallowed. Stage pump 2 bpm 530 PSI FO 21%, 2.5 bpm 735 PSI FO 24%, 3 bpm 948 PSI FO 27.5%. P/U 123K, SLK 81 K. SIMOPS Clean and clear rig floor of 2 3/8" handling Equip. R/U for RIH S' D.P.;PJSM RIH SLZXP and 4.5" Liner on 5" D.P. F/ 7,288'to 9,790' MD. P/U 135K, SLK 65K. AT 8,510' prior to OH establish parameters Rate 1 bpm 288 PSI, 5 RPM 7.2K TRQ, 10 RPM 7.8K TRQ, 15 RPM 8K TRQ ROT 104K. Run speed 50 ft/min pushing 25% of displacement away.;Started drifting stands out of Derrick at 9,535' MD W/ 2.75" OD drift. Filling every 2,000'. Calc Disp 11 bbls, actual -8 bbls, lost 18 bbls.;RIH SLZXP and 4.5" Liner on 5" D.P. F/ 7,288'to 13,036' MD. PIU 154K, SLK 74K. Run speed 50 ft/min to control losses. Drift stands out of Derrick W/ 2.75" OD drift. Filling every 2,000'. P/U 154K, SLK 74K. Decision was made to start RIH W/ HWDP to ensure emergency release F/ SLZXP.;PJSM Single in hole SLZXP and 4.5" Liner W/ 5" HWDP F/ Pipe Shed . F/ 13,036'to 13,436' MD. P/U 174K, SLK 77K. Run speed 50 ft/min. Drift pipe on the skate W/ 2.75" OD drift. Filling every 2,000' or as needed. Calc Disp 23, actual -31 bbls. Lost 54 bbls.;Daily hauled 57 bbls to G&I total = 13,555 bbls Hauled 0 bbls H2O from A-Pad reserve total = 10,920 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1,430 bbls Lost 203 bible to formation Total fluid lost production = 4,703 bbls 7/29/2019 Continue RIH w/ 4.5" 625W, 13.5# injection liner on 5" NC50 HWDP singling in F/ 13,436'-TI 15,017' MD (66 jts HWDP total). 210k up, 52k dn. Started having to work pipe down intermittently F/ 13,788' MD.;Continue run 4.5" liner on 5" NC50 drill pipe out of derrick F/ 15,017' - TI 15,522' MD. Washed down @ 2.5 bpm, 880 psi. Tagged btm @ 15,522' MD 2x wl 30k. 214k up, 70k dn. 38 bbls lost. Worked pipe down and floated liner last 500'.;P/U and put liner on depth @ 15,521' MD as per tally in tension. Park wl 210k on wt indicator. Last wts 214k up, 70k dn. Circulate Ix string volume @ 2.7 bpm, 960 psi. 22 bph dynamic Iosses.;Drop 1.25" phenolic ball. Pump do @ 3 bpm, 1150 psi. Slow to 2 bpm, 750 psi last 10 bbls. Ball seated 2175 stks (2387 stks calc). Psi up 1800 and hold 5 min. Psi up 3100 psi, saw psi drop to 2800 psi indicating packer set (Lost 13k wt). Hold 5 min. S/O F/ 195k to blk wt (36k).;Psi up 4880 to release neutralizing tool. PIU 9 and slack back off tagging up 1' higher indicating dog sub released. PIU 6' from break over @ 200k. R/U and test 9-518" x 5" annulus (against packer) 1500 psi w/ 10 min hold (test good). Chart and record same TOL @ 8287.83'.;Grease traveling equipment - TDS, Blocks, Crown and handling equipment. C/O differential psi switch.;POOH 5" D.P. on elevators F/ 15,498'to 15,01T MD. P/U 196K. Calc Disp 4 bbls, actual -10. Total bbls.;PJSM POOH UD 5" HWDP to Pipe Shed F/ 15,017' to 13,034' MD. PIU 170K. Calc Disp 38 bbls, actual -41. Lost 3 bbls.;Cont POOH 5" D.P. on elevators F/ 13,034' to 7,240' MD. PIU 73K. Calc Disp 46 bbls, actual -75. Total 27 bbls.;PJSM R/U Weatherford tools and Equip for 2 318" inner string. Clean and clear rig floor of 5" handling Equip.;PJSM Break down Packer running tool and UD.;PJSM POOH UD 2 3/8" inner string F/ 7,138' to 5,980' MD. Static loss about - 9 bph. Lost 54 bbls.;Daily hauled 0 bbls to G&I total = 13,555 bbls Hauled 0 bbls H2O from A-Pad reserve total = 10,920 bbls Hauled 0 bbls H2O from B-Pad Creek total = 1,430 bbls Lost 262.7 bbls to formation Total fluid lost production = 4,966 bbls n Well Name: MP E-39 Field: Milne Point County/State: , Alaska (LAT/LONG): oration (RKB): API #: Hilcorp Energy Company Composite Report Spud Date: Job Name: 1913307C MPU E -39L1 Completion Contractor AFE #: AtitiNS€. Date Ops Summary 8/9/2019 Cont. to Slip and cut drilling line - 17 wraps Static loss rate 8 bph POOH laying down drill pipe from 7693' to 6724'. Pump dry job., Rig service. Inspect and grease TD, tongs, draw works, and cobra heads. Cant to POOH racking back drill pipe from 6724' to surface. Calculated hole fill 64 bbls, actual 100 bbls. UD Bullnose, MWD, XO's and running tool. Clear rig floor.,Rig up to RIH with cleanout assembly. rig up Weatherford power tongs, 3-1/2" handling equipment. Bring Baker tools to rig floor and strap. Static loss rete 6 bph.,M/U BHA. 3-1/2" mule shoe, XO, (2) magnets, XO, (15) joints of 3-1/2" 8rd EUE tubing, boot baskets, 8.25" magnet, bumper sub, Oil Jar, (12) HWDP.,RIH with cleanout assembly on drill pipe from 936' to 7803'. PUW 150K, SOW 101 K. Displacement pale 62 bbls, actual 46 bbls.,Work pipe down from 7803' through hook hanger. Tag up at 7910' with 1 OK down. Muleshoe tracked into lateral and collar on mule shoe is tagging upon crossover below hook hanger. Pickup above hook hanger, turn 112" turn and slack off tagging up at same depth. Establish circulation at 6 bpm/280 psi. Pickup and observe pressure drop to 220 psi as mule shoe exits XO and liner joint. Pickup above hook hanger, turn, 114 turn and attempt to enter mother bore, still stack out at 7910.- Attempt multiple times with no success.,POOH from 7850' to 936'. Lay down HWDP to 562'.,UD BHA. UD magnet and clean approximately 0.5 gallon of fine metal shavings recovered. UD boot baskets -no recovery. Clean and clear rig floor.,Daily hauled 0 bbls to G&I total = 4,027 bbls Hauled 0 bbls H2O from A -Pad reserve total = 2,210 bbls Hauled 0 bbls H2O from B -Pad Creek total = 780 bbls Lost 127 bbls to formation Total fluid lost 39-L1 = 1031 bbls Total Metal 246 lb 8/10/2019 Rig up Weatherford power tongs. M/U XO to safety valve. UD 15 joints 3-1/2" EUE tubing. UD magnets, mule shoe.,M/U WLE BHA: mule shoe, (2) joints 3- 1/2" EUE tubing, XO to 4-1/2" IF.,RIH with wireline entry BHA: pickup, drift and single in the hole to 852'. Continue RIH out of derrick and tag up at 7909'. pickup and space out to 7882'. Ml PUW 140K, SOW 1001(.,Rig up Pollard E -line. M/U E -line tools. RIH with 2-1/2" RCT and CCL on E -Line to 7966' WLM. Log collars on swell packer and 1st 4-1/2" liner joint. Cut mid joint: 7892' WLM, 7905' DP measurement. Attempt to log cut, Tool string hanging up in XO.,POOH and rig down POIIard.,POOH on elevators to 7,725'. Monitor well, slight loss. Pump dryjob. Cont to POOH to 6898'. PUW 140K, SOW 100K.,Observe small leak on spinners hydraulic hose. Replace hydraulic hose. Static loss rate 4.4 bph.,Service rig. C/O cable tail, cold shot, and cable anchor on cobra head -Cont POOH on elevators from 6898' to suface. UD 3-112" 8rd tubing. Hole fill calculated 53.7 bbls, actual 73.9 bbls.,M/U fishing BHA; Ball seat, HR running tool, Bumper sub and fishing jars., RIH with fishing BHA from 61' to 7886'. PUW 141K, SOW 100K.,Daily hauled 57 bbls to G&I total= 4,084 bbls Hauled 0 bbls H2O from A -Pad reserve total = 2,210 bbls Hauled 0 bbis H2O from B -Pad Creek total = 780 bbls Lost 115 bbls to formation Total fluid lost 39-1-7 = 1146 blols Total Metal 246 Ib 8/11/2019 Attempt to engage hook hanger. PUW 141 K, SOW 100K. Slack off and observe 11 K down at 7886'. Pick up with 7K drag falling off. Put 1/4 turn and slack off putting 10K down at 7886'. Pick up and observe overpull. Work over pull up to 60K over before breaking over. Continue to Pick up observing 5-15K drag for several feet. Slack off and tag with IOK down - 3' high. Pick up observing 2-3K higher weight., POOH from 7886' to 78'. Racking back drill pipe. Calculated hole full 67 bbls, actual 91.6 bbls.,UD BHA, oil jars, bumper. UD recovered hook hanger assembly and 18.08' cut joint., Pick up cleanout assembly #2: 3-1/2" jetting tool, (2) magnets, 1 joint 3-1/2" tubing, (2) boot baskets, 8.25" OD magnet, Bumper sub, Oil jars. Loss rate 5 bph.,RIH: pick up, drift (3.125") and single in the hole from 129' to 446. PUW 50K, SOW 48K.,Continue to RIH from 445'to 8271' from derrick. PUW 145K, SOW 100K. Calc displacement 64.3 bbls, actual 59.3 bbls.,Wash down from 8,271' to 8,331' inside SBE while displacing to clean brine, work through SBE x 2 at 415 gpm/600 psi.,Monitor well, slight loss. POOH laying down drill pipe from 8,331' to 8,175. Pump dryjob. Continue to POOH laying down drill pipe from 8,175' to 129'. Inspecting hard bands in pipe shed. Displacement calculated 67.6 bbls, actual 91.1 bbls.,UD BHA, bumper sub, oil jars, 8.25" OD magnet, boot baskets, 1 jnt tubing, (2) magnets, jetting tool. 451bs of fine metal cuttings with a few 1"-2" metal chunks recovered from magnets. (1) 2' piece of rubber recovered on top of boot basket.,Clear rig floor. Pull wear bushing.,Rig up to RIH with upper completion. Rig up SLB spooler, hang sheave. Rig up Weatherford. Bring cannon clamps to rig floor.,PJSM RIH with 3.5" EUE L-80 upper completion as per tally from surface to 178'. Make up torque 3200 ft-Ibs.,Daily hauled 699 bbls to G&I total = 4,783 bbls Hauled 0 bbls H2O from A -Pad reserve total = 2,210 blots Hauled 0 bbls H2O from B -Pad Creek total = 780 bbls Lost 98 bbls to formation Total fluid lost 39-L1 = 1244 bbls Vaily Metal 48lbs Total Metal 294 to 8/12/2019 Continue to R I from8' to 8310' with 3-1/2" 8 - 0 upper completionRunning speed 60 fpm once packer made up. M/U downhole gauge after joint 21 and test -good, Continually monitor gauge while RIH. Calculated displacement 33.1 bbls, actual 18.8 bbls.,Work seals through SBE at 8317, tagging up with 10K down. Establish circulation at 1 bpm 60 psi. Work seals down to 8335' observing a pressure increase as ports are covered. Continue to get returns. Appear to be pumping through the GLM's water flood valves. No -Go at 8335'. Rig up, shut in annular and PT back side 500 psi to ensure seals are engaged - holding pressure.,Space out 2.34' off no-go. UD three joints, M/U space out pumps and full joint below hanger. Terminate [-wire and feed through hanger. Drain stack. RIH and land tubing.,Rig up to reverse circulate corrosion inhibited brine and freeze protect. Attempt to space out with hanger below bag and ports in seal assembly not engaged. Pick up with hanger just below bag. Shut in, attempt to pump through seals, holding pressure, seals still engaged. Open annular. Space out so 1st joint below hanger is at the bag.,PJSM, displace annulus with 340 bbis corrosion inhibited brine (1 % Conqor 100) and 185 bbis diesel for freeze protect. ICP 4.5bpm/450 psi FCP 4 bpm/618 psi. Open bleeder to backside, Open bag, slack off and engage seals. Drain stack. Land tubing hanger. RILDS.,Break out landing joint. M/U pump in sub, TIW and DP pup joint on top of landing joint. Install Ball and rod on top of closed TIW. M/U to hanger, M/U TD. Freeze protect tubing bull heading 22 bbis of diesel clear lines with 10 bbls brine at i bpm ICP 480 psi, FCP 700 Hauled 0 hauled 0fr 661s to G&I total = 5,061 bbis Hauled 0 bbis H2O from A -Pad reserve total = 2,210 bbis Hauled 0 bbls H2O from B -Pad Creek total = 780 bbls n Lost 125 bbls to formation Total fluid lost 39-L1 = 1369 bbls J' Dailv Metal 10lbs Total Metal 304 lb 8/13/2019 Open TIW and launch ball and rod with roller stem. Allow to fall on seat for 30 minutes. Pressure up to 3500 psi and hold for 5 minutes to set Tri -Point packer..Ria up to perform Pre -MIT -IA. Flood lines. Pressure up to 700 psi and observe pin hole leak on hose. Change out hose. Pressure up on packer to 3800 psi to ensure set for 5 minutes. Bleed down. Line up on IA and perform pre -MIT -IA to 2120 psi; 2090 after 15 minutes, 2090 after 30 minutes. Took 4.8 bbis to pressure up, 4.0 bbis retumed.,Rig down 10' pup, TIW, and pump in sub from landing joint. Set BPV. R/D Weatherford and Schlumberger spooling unft.,Pick up stack washing tool. Wash BOP at 7.5 bpm. Flush and blow down choke, kill and surface lines. De -energize accumulator. Remove drip pan from BOP. Open ram doors and remove rams, prep for inspection. Disassembly MPD ;lard lines. Clean pipe handling equipment and prep for inspection. Break bolts on BOP. Simops: Continue replacing pinion seal on MP#1.,N/D MPD RCD. Rig up slings. Pick up RCD with TD and suspend. Set BOP on pedestal. Lower RCD on spacer spool. PIU with tugger and tail to door.,N/D BOP'S: break apart BOP's for CTI Cat III inspection, measure ram cavities, PT ram close/open position, inspect ram polish rod. SimOps: remove drag chain, remove spinners. Con. to wire wheel welds for MP inspection. Cont. to clean and disassemble rig floor handling equipment for inspection.,Daily hauled 731 bbls to G&I total = 5,792 bbis Hauled 0 bbis H2O from A -Pad reserve total = 2,210 bbls Hauled 0 bbis H2O from B -Pad Creek total = 780 bbls Lost 10 bbis to formation Total fluid lost 39 -Ll = 1379 bbis Daily Metal Olbs Total Metal 304 lb Hilcorp Milne Point M Pt E Pad MPU E -39i 500292364000 Alaska, LLC Sperry Drilling Definitive Survey Report 09 August, 2019 HALLIBURTON Sperry Drilling Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-39 Project: Milne Point TVD Reference: MPU E-39 Actual RKB @ 48.33usft Site: M Pt E Pad MD Reference: MPU E-39 Actual RKB @ 48.33usft Well: MPU E-39 North Reference: True Wellbore: MPU E -39i Survey Calculation Method: Minimum Curvature Design: MPU E-39 Database: NORTH US+CANADA 'roject Milne Point, ACT, MILNE POINT Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Seo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU E-39 Well Position +NI -S 0.00 usft +E/ -W 0.00 usft Position Uncertainty 0.00 usft Wellbore MPU E -39i Magnetics Model Name BGGM2018 Northing: 6,016,057.25 usfl Easting: 569,284.13 usfl Wellhead Elevation: 0.00 usfl Sample Date Declination (°) 7/15/2019 16.62 Latitude: 70° 27'15.210 N Longitude: 149° 26'4.636 W Ground Level: 21.70 usft Dip Angle Field Strength (°) (nT) 80.96 57,423.34975604 Design MPU E-39 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.63 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (usft) (usft) (I 26.63 0.00 0.00 190.86 Survey Program Date 7/26/2019 From To (usft) (usft) Survey (Wellbore) Tool Name Description Survey Date 100.00 414.00 MPU E-39 NSG -GC Surveys (MPU E-39 2_Gyro-NS-GC_Drill colt H029Ga: North seeking single shot in drill colla 07/08/2019 483.39 8,531.15 MPU E-39 MWD+IFR2+MS+Sag (1) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec & multi -station analysis +sa 07/12/2019 8,570.00 15,462.14 MPU E-39 MWD+IFR2+MS+Sag (2) (MF 2_MWD+IFR2+MS+Sag A013Mb: IIFR dec& multi -station analysis +sa 07/19/2019 Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (-1100') (ft) Survey Tool Name 26.63 0.00 0.00 26.63 -21.70 0.00 0.00 6,016,057.25 569,284.13 0.00 0.00 UNDEFINED 100.00 0.16 173.75 100.00 51.67 -0.10 0.01 6,016,057.15 569,284.14 0.22 0.10 2_Gym-NS-GC_DnII collar (I 165.00 0.27 194.83 165.00 116.67 -0.34 -0.02 6,016,056.91 569,284.11 0.21 0.34 2_Gyro-NS-GC_Drill collar(1 226.00 0.65 201.29 226.00 177.67 -0.80 -0.18 6,016,056.45 569,283.96 0.63 0.82 2_Gym-NS-GC_Drill collar (1 290.00 1.42 215.29 289.99 241.66 -1.79 -0.77 6,016,055.46 569,283.38 1.26 1.90 2_Gymo NS-GG_Drilicollar(1 350.00 2.52 218.79 349.95 301.62 -3.42 -2.03 6,016,053.81 569,282.14 1.84 3.74 2_Gymo-NS-GC_Drill collar (1 414.00 4.11 222.27 413.84 365.51 -6.22 4.45 6,016,050.99 569,279.74 2.50 6.94 2 Gyro-NS-GC_Drill collar (1 483.39 5.69 219.37 482.98 434.65 -10.72 -8.31 6,016,046.46 569,275.93 2.30 12.09 2_MWD+IFR2+MS+Sag (2) 545.28 7.12 223.23 544.48 496.15 -15.88 -12.88 6,016,041.25 569,271.40 2.41 18.02 2_MWD+IFR2+MS+Sag(2) 608.08 9.12 220.18 606.65 558.32 -22.52 -18.76 6,016,034.56 569,265.59 3.26 25.65 2_MWD+IFR2+MS+Sag (2) 669.71 12.39 214.46 667.19 618.86 -31.71 -25.65 6,016,025.31 569,258.78 5.58 35.97 2_MWD+IFR2+MS+Sag (2) 732.21 14.12 212.37 728.02 679.69 -43.68 -33.53 6,016,013.27 569,251.01 2.87 49.21 2_MWD+IFR2+MS+Sag(2) 8/92019 11:40:25AM Page 2 COMPASS 5000.15 Build 91 Company: Project: Site: Well: Wellbore: Design: Survey Hilcorp Alaska, LLC Milne Point M Pt EPad MPU E-39 MPU E -39i MPU E-39 Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well MPU E-39 MPU E-39 Actual RKB @ 48.33usft MPU E-39 Actual RKB @ 48.33usft True Minimum Curvature NORTH US + CANADA Map Map Vertical MD Inc Azi TVD TVDSS +NIS +El -W Northing Easting DLS Section (usft) (°) (') (usft) (usft) (usft) (usft) (ft) (ft) ("1100') (ft) Survey Tool Name 796.36 17.22 209.97 789.78 741.45 -58.51 -42.46 6,015,998.35 569,242.22 4.94 65.47 2_MWD+IFR2+MS+Sag (2) 860.19 20.43 207.20 850.19 801.86 -76.61 -52.28 6,015,980.16 569,232.57 5.22 85.09 2_MWD+IFR2+MS+Sag (2) 923.22 22.95 206.77 908.75 860.42 -97.37 -62.84 6,015,959.31 569,222.20 4.01 107.47 2_MWD+IFR2+MS+Sag (2) 987.15 24.05 204.62 967.38 919.05 -120.34 -73.88 6,015,936.24 569,211.38 2.18 132.11 2_MWD+IFR2+MS+Sag (2) 1,050.81 26.18 202.06 1,025.02 976.69 -145.15 -84.56 6,015,911.33 569,200.93 3.76 158.49 2_MWD+IFR2+MS+Sag (2) 1,114.19 27.06 199.56 1,081.68 1,033.35 -171.70 -94.64 6,015,884.70 569,191.10 2.25 186.45 2_MWD+IFR2+MS+Sag(2) 1,176.60 30.83 195.70 1,136.29 1,087.96 -200.48 -103.73 6,015,855.83 569,182.28 6.74 216.44 2 MWD+IFR2+MS+Sag(2) 1,241.39 34.65 192.05 1,190.78 1,142.45 -234.50 -112.07 6,015,821.75 569,174.26 6.63 251.41 2_MWD+IFR2+MS+Sag(2) 1,304.06 37.46 190.27 1,241.44 1,193.11 -270.68 -119.19 6,015,785.50 569,167.48 4.78 288.29 2_MWD+IFR2+MS+Sag(2) 1,369.22 40.87 188.73 1,291.96 1,243.63 -311.26 -125.96 6,015,744.86 569,161.08 5.44 329.42 2_MWD+IFR2+MS+Sag(2) 1,432.23 42.43 188.57 1,339.04 1,290.71 -352.66 -132.25 6,015,703.41 569,155.17 2.48 371.26 2_MWD+IFR2+MS+S39 (2) 1,496.09 45.99 187.80 1,384.81 1,336.48 -396.73 -138.58 6,015,659.29 569,149.26 5.64 415.73 2_MWD+IFR2+MS+Sag (2) 1,559.03 49.51 188.24 1,427.12 1,378.79 -442.85 -145.09 6,015,613.11 569,143.18 5.62 462.26 2_MWD+IFR2+MS+Sag (2) 1,623.25 52.97 188.47 1,467.32 1,418.99 -492.39 -152.36 6,015,563.51 569,136.36 5.39 512.28 2_MWD+IFR2+MS+Sag (2) 1,686.43 56.22 188.70 1,503.92 1,455.59 -543.30 -160.05 6,015,512.53 569,129.15 5.15 563.73 2_MWD+1FR2+MS+Sag (2) 1,750.72 59.42 189.11 1,538.15 1,489.82 -597.05 -168.48 6,015,458.71 569,121.23 5.01 618.10 2_MWD+IFR2+MS+Sag (2) 1,814.09 60.89 189.80 1,569.69 1,521.36 -651.27 -177.51 6,015,404.42 569,112.70 2.50 673.05 2_MWD+IFR2+MS+Sag(2) 1,877.70 60.67 190.03 1,600.74 1,552.41 -705.96 -187.07 6,015,349.65 569,103.65 0.47 728.56 2_MWD+IFR2+MS+Sag (2) 1,941.46 60.78 189.09 1,631.92 1,583.59 -760.80 -196.30 6,015,294.73 569,094.93 1.30 784.16 2_MWD+IFR2+MS+Sag (2) 2,005.54 60.48 189.34 1,663.35 1,615.02 -815.92 -205.25 6,015,239.53 569,086.50 0.58 839.98 2_MWD+IFR2+MS+Sag (2) 2,069.38 57.99 189.39 1,696.00 1,647.67 -870.04 -214.17 6,015,185.33 569,078.08 3.90 894.81 2_MWD+IFR2+MS+Sag (2) 2,132.74 55.16 190.23 1,730.90 1,682.57 -922.15 -223.18 6,015,133.15 569,069.56 4.60 947.68 2_MWD+IFR2+MS+Sag(2) 2,196.24 57.50 190.72 1,766.10 1,717.77 -974.11 -232.79 6,015,081.11 569,060.43 3.74 1,000.52 2_MWD+IFR2+MS+Sag(2) 2,259.77 62.05 190.68 1,798.07 1,749.74 -1,028.03 -242.97 6,015,027.10 569,050.75 7.16 1,055.40 2_MWD+IFR2+MS+Sag (2) 2,323.62 63.55 189.88 1,827.26 1,778.93 -1,083.91 -253.11 6,014,971.14 569,041.14 2.60 1,112.19 2_MWD+IFR2+MS+Sag (2) 2,387.61 64.76 191.07 1,855.15 1,806.82 -1,140.54 -263.58 6,014,914.42 569,031.19 2.53 1,169.77 2_MWD+IFR2+MS+Sag (2) 2,450.95 63.13 190.89 1,882.97 1,834.64 -1,196.40 -274.42 6,014,858.47 569,020.88 2.59 1,226.67 2_MWD+IFR2+MS+Sag (2) 2,514.68 65.54 190.57 1,910.57 1,862.24 -1,252.83 -285.11 6,014,801.94 569,010.71 3.81 1,284.11 2_MWD+IFR2+MS+Sag (2) 2,578.51 65.91 191.37 1,936.82 1,888.49 -1,309.95 -296.18 6,014,744.72 569,000.17 1.28 1,342.30 2_MWD+IFR2+MS+Sag (2) 2,642.23 65.88 191.56 1,962.84 1,914.51 -1,366.96 -307.74 6,014,687.62 568,989.14 0.28 1,400.46 2_MWD+IFR2+MS+Sag (2) 2,706.01 65.29 190.52 1,989.20 1,940.87 -1,423.96 -318.87 6,014,630.53 568,978.55 1.75 1,458.53 2_MWD+IFR2+MS+Sag (2) 2,769.85 65.16 191.46 2,015.96 1,967.63 -1,480.86 -329.92 6,014,573.53 568,968.03 1.35 1,516.49 2_MWD+IFR2+MS+Sag (2) 2,832.93 64.91 191.64 2,042.58 1,994.25 -1,536.88 -341.37 6,014,517.40 568,957.10 0.47 1,573.68 2_MWD+IFR2+MS+Sag (2) 2,897.27 63.29 191.16 2,070.68 2,022.35 -1,593.62 -352.81 6,014,460.57 568,946.19 2.61 1,631.55 2_MWD+IFR2+MS+Sag (2) 2,960.99 64.56 189.56 2,098.69 2,050.36 -1,649.92 -363.09 6,014,404.19 568,936.43 3.01 1,688.78 2_MWD+IFR2+MS+Sag (2) 3,024.66 64.81 189.01 2,125.92 2,077.59 -1,706.72 -372.38 6,014,347.31 568,927.67 0.87 1,746.31 2_MWD+IFR2+MS+Sag(2) 3,088.50 64.75 188.79 2,153.12 2,104.79 -1,763.78 -381.32 6,014,290.17 568,919.27 0.33 1,804.03 2_MWD+IFR2+MS+Sag (2) 3,152.22 64.11 189.91 2,180.62 2,132.29 -1,820.49 -390.65 6,014,233.38 568,910.46 1.88 1,861.49 2_MWD+IFR2+MS+Sag (2) 3,216.03 63.59 190.06 2,208.74 2,160.41 -1,876.90 400.58 6,014,176.88 568,901.05 0.84 1,918.76 2_MWD+IFR2+MS+Sag (2) 3,279.04 62.41 189.28 2,237.35 2,189.02 -1,932.24 410.02 6,014,121.46 568,892.14 2.17 1,974.89 2_MWD+IFR2+MS+Sag (2) 6WO19 11:40:25AM Page 3 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-39 Project: Milne Point TVD Reference: MPU E-39 Actual RKB @ 48.33usft Site: M Pt E Pad MD Reference: MPU E-39 Actual RKB @ 48.33usft Well: MPU E-39 North Reference: True Wellbore: MPU E-39i Survey Calculation Method: Minimum Curvature Design: MPU E-39 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +l Northing Easting DLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) ("1100') (ft) Survey Tool Name 3,343.25 61.59 189.64 2,267.49 2,219.16 -1,988.17 419.33 6,014,065.46 568,883.34 1.37 2,031.57 2_MWD+IFR2+MS+Sag(2) 3,407.04 64.48 189.78 2,296.42 2,248.09 -2,044.20 428.92 6,014,009.34 568,874.27 4.53 2,088.40 2_MWD+IFR2+MS+Sag (2) 3,470.52 63.88 190.02 2,324.07 2,275.74 -2,100.49 338.75 6,013,952.97 568,864.98 1.00 2,145.54 2_MWD+IFR2+MS+Sag(2) 3,534.56 62.81 190.01 2,352.79 2,304.46 -2,156.85 348.70 6,013,896.52 568,855.55 1.67 2,202.77 2_MWD+IFR2+MS+Sag(2) 3,597.84 62.04 189.45 2,382.09 2,333.76 -2,212.14 358.18 6,013,841.16 568,846.58 1.45 2,258.85 2_MWD+IFR2+MS+Sag(2) 3,661.91 61.66 189.64 2,412.31 2,363.98 -2,267.85 367.55 6,013,785.37 568,837.73 0.65 2,315.32 2_MWD+IFR2+MS+Sag(2) 3,725.51 61.86 190.16 2,442.41 2,394.08 -2,323.04 377.18 6,013,730.09 568,828.62 0.79 2,371.34 2_MWD+IFR2+MS+Sag (2) 3,789.72 61.79 190.11 2,472.73 2,424.40 -2,378.76 387.14 6,013,674.29 568,819.17 0.13 2,427.94 2_MWD+IFR2+MS+Sag(2) 3,853.22 61.14 190.34 2,503.06 2,454.73 -2,433.66 -497.04 6,013,619.30 568,809.78 1.07 2,483.72 2_MWD+IFR2+MS+Sag (2) 3,917.36 61.51 190.22 2,533.84 2,485.51 -2,489.03 -507.09 6,013,563.85 568,800.26 0.60 2,539.99 2_MWD+IFR2+MS+Sag(2) 3,981.11 64.64 189.38 2,562.70 2,514.37 -2,545.03 -516.75 6,013,507.76 568,791.11 5.05 2,596.82 2_MWD+IFR2+MS+Sag(2) 4,044.65 64.41 189.48 2,590.03 2,541.70 -2,601.62 -526.15 6,013,451.09 568,782.24 0.39 2,654.16 2_MWD+IFR2+MS+Sag (2) 4,108.10 64.27 189.64 2,617.51 2,569.18 -2,658.02 -535.65 6,013,394.62 568,773.27 0.32 2,711.34 2_MWD+IFR2+MS+Sag(2) 4,171.10 64.51 190.19 2,644.74 2,596.41 -2,713.98 -545.43 6,013,338.57 568,764.01 0.87 2,768.14 2_MWD+IFR2+MS+Sag(2) 4,235.37 64.36 190.84 2,672.47 2,624.14 .2,770.99 -556.01 6,013,281.48 568,753.96 0.94 2,826.12 2_MWD+IFR2+MS+Sag(2) 4,298.71 63.98 190.55 2,700.07 2,651.74 -2,827.01 -566.59 6,013,225.36 568,743.90 0.73 2,883.13 2_MWD+IFR2+MS+Sag (2) 4,362.45 63.38 190.53 2,728.33 2,680.00 -2,883.17 -577.04 6,013,169.11 568,733.97 0.94 2,940.26 2 MWD+IFR2+MS+Sag(2) 4,426.23 66.64 190.87 2,755.27 2,706.94 -2,939.97 -587.78 6,013,112.22 568,723.77 5.13 2,998.06 2_MWD+IFR2+MS+Sag (2) 4,489.08 67.84 190.52 2,779.59 2,731.26 -2,996.92 -598.53 6,013,055.18 568,713.55 1.98 3,056.01 2_MWD+IFR2+MS+Sag(2) 4,553.18 66.80 190.92 2,804.30 2,755.97 -3,055.03 -609.53 6,012,996.97 568,703.09 1.72 3,115.16 2_MWD+IFR2+MS+Sag(2) 4,616.52 67.11 191.27 2,829.10 2,780.77 -3,112.22 -620.75 6,012,939.68 568,692.40 0.71 3,173.44 2_MWD+IFR2+MS+Sag(2) 4,679.61 64.83 191.30 2,854.79 2,806.46 -3,168.73 -632.02 6,012,883.08 568,681.66 3.61 3,231.06 2_MWD+IFR2+MS+Sag (2) 4,744.00 64.90 191.74 2,882.14 2,833.81 -3,225.85 -643.67 6,012,825.86 568,670.55 0.63 3,289.35 2_MWD+IFR2+MS+Sag(2) 4,807.79 64.14 190.83 2,909.58 2,861.25 -3,282.32 -654.94 6,012,769.29 568,659.80 1.75 3,346.93 2_MWD+IFR2+MS+Sag(2) 4,871.13 62.53 190.64 2,938.00 2,889.67 -3,337.93 -665.48 6,012,713.59 568,649.78 2.56 3,403.53 2_MWD+IFR2+MS+Sag(2) 4,935.30 62.08 190.21 2,967.83 2,919.50 -3,393.81 -675.76 6,012,657.63 568,640.02 0.92 3,460.35 2_MWD+IFR2+MS+Sag (2) 4,998.60 61.68 190.22 2,997.66 2,949.33 -3,448.75 -685.66 6,012,602.60 568,630.63 0.63 3,516.17 2_MWD+IFR2+MS+Sag (2) 5,062.66 63.68 190.33 3,027.06 2,978.73 -3,504.75 -695.81 6,012,546.51 568,621.00 3.13 3,573.08 2 MWD+IFR2+MS+Sag (2) 5,126.34 64.52 190.21 3,054.88 3,006.55 -3,561.12 -706.03 6,012,490.06 568,611.31 1.33 3,630.36 2_MWD+IFR2+MS+Sag(2) 5,189.87 64.82 190.19 3,082.06 3,033.73 -3,617.63 -716.20 6,012,433.46 568,601.67 0.47 3,687.78 2_MWD+IFR2+MS+Sag(2) 5,253.86 63.67 189.73 3,109.86 3,061.53 -3,674.39 -726.16 6,012,376.61 568,592.23 1.91 3,745.40 2_MWD+IFR2+MS+Sag (2) 5,317.79 62.29 189.64 3,138.90 3,090.57 -3,730.53 -735.75 6,012,320.39 568,583.17 2.16 3,802.34 2_MWD+IFR2+MS+Sag (2) 5,381.29 62.86 189.49 3,168.15 3,119.82 -3,786.11 -745.11 6,012,264.73 568,574.33 0.92 3,858.69 2_MWD+IFR2+MS+Sag (2) 5,445.37 62.51 189.68 3,197.56 3,149.23 -3,842.25 -754.59 6,012,208.51 568,565.37 0.61 3,915.61 2_MWD+IFR2+MS+Sag(2) 5,509.05 62.13 189.99 3,227.14 3,178.81 -3,897.82 -764.22 6,012,152.87 568,556.26 0.74 3,972.00 2_MWD+IFR2+MS+Sag(2) 5,572.69 62.31 189.92 3,256.80 3,208.47 -3,953.27 -773.96 6,012,097.32 568,547.04 0.30 4,028.29 2_MWD+IFR2+MS+Sag(2) 5,636.28 62.43 190.17 3,286.29 3,237.96 3,008.75 -783.78 6,012,041.77 568,537.73 0.40 4,084.63 2_MWD+IFR2+MS+Sag(2) 5,699.38 63.18 190.35 3,315.13 3,266.80 3,063.97 -793.78 6,011,986.45 568,528.25 1.22 4,140.75 2_MWD+IFR2+MS+Sag(2) 5,763.25 64.26 190.75 3,343.41 3,295.08 3,120.27 -804.27 6,011,930.07 568,518.29 1.78 4,198.01 2_MWD+IFR2+MS+Sag (2) 5,826.53 64.41 190.34 3,370.81 3,322.48 3,176.35 -814.70 6,011,873.90 568,508.37 0.63 4,255.05 2_MWD+IFR2+MS+Sag(2) 8/9/2019 11:40:25AM Page 4 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-39 Project: Milne Point TVD Reference: MPU E-39 Actual RKB @ 48.33usft Site: M Pt E Pad MD Reference: MPU E-39 Actual RKB @ 48.33usft Well: MPU E-39 North Reference: True Wellbore: MPU E -39i Survey Calculation Method: Minimum Curvature Design: MPU E-39 Database: NORTH US + CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting OLS Section (usft) (°) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 5,890.02 65.36 190.58 3,397.76 3,349.43 -4,232.88 -825.14 6,011,817.28 568,498.46 1.53 4,312.53 2_MWD+IFR2+MS+Sag(2) 5,953.28 63.74 189.48 3,424.94 3,376.61 4,289.12 -835.09 6,011,760.95 568,489.03 3.00 4,369.65 2_MWD+IFR2+MS+Sag(2) 6,016.58 63.50 189.85 3,453.07 3,404.74 -4,345.03 -844.61 6,011,704.97 568,480.03 0.65 4,426.34 2_MWD+IFR2+MS+Sag (2) 6,080.00 63.74 190.12 3,481.25 3,432.92 -4,400.98 -854.47 6,011,648.93 568,470.70 0.54 4,483.15 2_MWD+IFR2+MS+Sag(2) 6,143.80 64.63 190.04 3,509.03 3,460.70 -4,457.53 -864.52 6,011,592.30 568,461.18 1.40 4,540.58 2_MWD+IFR2+MS+Sag (2) 6,207.16 64.67 190.05 3,536.16 3,487.83 4,513.91 -874.50 6,011,535.83 568,451.72 0.06 4,597.83 2_MWD+IFR2+MS+Sag (2) 6,270.30 62.98 189.08 3,564.01 3,515.68 -4,569.78 -883.92 6,011,479.88 568,442.82 3.01 4,654.48 2_MWD+IFR2+MS+Sag (2) 6,333.47 63.75 188.48 3,592.33 3,544.00 -4,625.59 -892.54 6,011,424.00 568,434.72 1.49 4,710.91 2_MWD+IFR2+MS+Sag (2) 6,396.51 64.55 188.55 3,619.82 3,571.49 -4,681.69 -900.94 6,011,367.82 568,426.84 1.27 4,767.59 2_MWD+IFR2+MS+Sag (2) 6,461.33 62.17 188.45 3,648.88 3,600.55 4,738.99 -909.50 6,011,310.45 568,418.81 3.67 4,825.48 2_MWD+IFR2+MS+Sag(2) 6,524.83 62.02 188.36 3,678.60 3,630.27 4,794.51 -917.71 6,011,254.87 568,411.13 0.27 4,881.54 2_MWD+IFR2+MS+Sag(2) 6,588.52 61.71 189.03 3,708.63 3,660.30 -4,850.02 -926.20 6,011,199.28 568,403.16 1.05 4,937.67 2_MWD+IFR2+MS+Sag(2) 6,652.27 61.72 189.22 3,738.84 3,690.51 -4,905.45 -935.10 6,011,143.78 568,394.77 0.26 4,993.78 2_MWD+IFR2+MS+Sag(2) 6,715.48 61.89 189.53 3,768.70 3,720.37 4,960.42 -944.18 6,011,088.74 568,386.21 0.51 5,049.47 2_MWD+IFR2+MS+Sag(2) 6,779.43 62.54 188.84 3,798.51 3,750.18 -5,016.27 -953.21 6,011,032.81 568,377.70 1.39 5,106.02 2_MWD+IFR2+MS+Sag(2) 6,842.93 62.70 189.97 3,827.72 3,779.39 -5,071.89 -962.42 6,010,977.11 568,369.00 1.60 5,162.39 2_MWD+IFR2+MS+Sag(2) 6,905.95 63.01 190A4 3,856.47 3,808.14 -5,127.09 -972.36 6,010,921.83 568,359.58 0.83 5,218.46 2_MWD+IFR2+MS+Sag (2) 6,970.39 62.42 190.24 3,886.01 3,837.68 -5,183.43 -982.64 6,010,865.40 568,349.83 0.96 5,275.73 2_MWD+IFR2+MS+Sag (2) 7,033.67 62.56 191.17 3,915.24 3,866.91 -5,238.57 -993.06 6,010,810.16 568,339.92 1.32 5,331.86 2_MWD+IFR2+MS+Sag(2) 7,097.26 63.77 191.14 3,943.95 3,895.62 -5,294.24 -1,004.04 6,010,754.40 568,329.46 1.90 5,388.60 2_MWD+IFR2+MS+Sag(2) 7,161.01 63.72 191.39 3,972.15 3,923.82 -5,350.31 -1,015.21 6,010,698.23 568,318.81 0.36 5,445.77 2_MWD+IFR2+MS+Sag(2) 7,224.50 63.21 191.43 4,000.51 3,952.18 -5,405.99 -1,026A4 6,010,642.46 568,308.09 0.81 5,502.57 2_MWD+IFR2+MS+Sag(2) 7,287.83 64.01 191.32 4,028.66 3,980.33 -5,461.61 -1,037.63 6,010,586.75 568,297.42 1.27 5,559.29 2_MWD+IFR2+MS+Sag (2) 7,351.53 65.24 192.54 4,055.96 4,007.63 -5,517.92 -1,049.53 6,010,530.33 568,286.05 2.59 5,616.84 2_MWD+IFR2+MS+Sag(2) 7,415.12 62.35 192.27 4,084.04 4,035.71 -5,573.63 -1,061.79 6,010,474.51 568,274.31 4.56 5,673.86 2_MWD+IFR2+MS+Sag (2) 7,478.87 62.47 193.01 4,113.56 4,065.23 -5,628.76 -1,074.15 6,010,419.27 568,262.46 1.05 5,730.34 2_MWD+IFR2+MS+Sag (2) 7,542.91 62.76 193.58 4,143.02 4,094.69 -5,684.10 -1,087.23 6,010,363.82 568,249.90 0.91 5,787.15 2_MWD+IFR2+MS+Sag (2) 7,606.59 65.09 191.98 4,171.01 4,122.68 -5,739.88 -1,099.87 6,010,307.93 568,237.78 4.30 5,844.31 2_MWD+IFR2+MS+Sag (2) 7,670.07 66.51 190.87 4,197.03 4,148.70 -5,796.63 -1,111.34 6,010,251.08 568,226.84 2.75 5,902.20 2_MWD+IFR2+MS+Sag (2) 7,734.06 66.21 192.83 4,222.69 4,174.36 -5,854.00 -1,123.37 6,010,193.61 568,215.34 2.84 5,960.81 2_MWD+IFR2+MS+Sag (2) 7,797.61 67.03 193.89 4,247.91 4,199.58 -5,910.75 -1,136.85 6,010,136.74 568,202.39 2.00 6,019.09 2 MWD+IFR2+MS+Sag (2) 7,860.90 67.90 193.32 4,272.16 4,223.83 -5,967.57 -1,150.60 6,010,079.81 568,189.17 1.61 6,077.48 2_MWD+IFR2+MS+Sag (2) 7,923.58 68.57 193.93 4,295.41 4,247.08 -6,024.14 -1,164.32 6,010,023.11 568,175.99 1.40 6,135.62 2_MWD+IFR2+MS+Sag (2) 7,987.56 71.16 194.09 4,317.43 4,269.10 -6,082.42 -1,178.86 6,009,964.71 568,161.99 4.05 6,195.59 2_MWD+IFR2+MS+Sag (2) 8,050.38 75.07 195.64 4,335.67 4,287.34 -6,140.50 -1,194.28 6,009,906.49 568,147.11 6.66 6,255.54 2_MWD+IFR2+MS+Sag (2) 8,114.46 79.45 193.71 4,349.80 4,301.47 -6,200.95 -1,210.11 6,009,845.90 568,131.85 7.44 6,317.89 2_MWD+IFR2+MS+Sag (2) 8,177.99 83.37 190.97 4,359.29 4,310.96 -6,262.30 -1,223.52 6,009,784.44 568,119.01 7.50 6,380.67 2_MWD+IFR2+MS+Sag(2) 8,241.51 87.07 190.73 4,364.58 4,316.25 -6,324.46 -1,235.43 6,009,722.18 568,107.67 5.84 6,443.96 2_MWD+IFR2+MS+Sag (2) 8,304.93 89.76 190.93 4,366.34 4,318.01 -6,386.72 -1,247.34 6,009,659.81 568,096.34 4.25 6,507.35 2_MWD+IFR2+MS+Sag (2) 8,368.67 91.88 190.71 4,365.42 4,317.09 -6,449.31 -1,259.31 6,009,597.12 568,084.96 3.34 6,571.08 2_MWD+IFR2+MS+Sag(2) 8x92019 11:40:25AM Page 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-39 Project: Milne Point TVD Reference: MPU E-39 Actual RKB @ 48.33usft Site: M Pt E Pad MD Reference: MPU E-39 Actual IRKS @ 48.33usft Well: MPU E-39 North Reference: True Wellbore: MPU E -39i Survey Calculation Method: Minimum Curvature Design MPU E-39 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI -S +E/.W Northing Easting DLS Section (usft) (1) 0 (usft) (usft) (usft) (usft) (ft) (ft) (°1100-) (ft) Survey Tool Name 8,432.33 91.11 190.80 4,363.76 4,315.43 -6,511.83 -1,271.18 6,009,534.49 568,073.67 1.22 6,634.71 2_MWD+IFR2+MS+Sag (2) 8,495.58 87.96 190.87 4,364.28 4,315.95 -6,573.95 -1,283.07 6,009,472.28 568,062.36 4.98 6,697.95 2_MWD+IFR2+MS+Sag (2) 8,531.15 89.73 190.85 4,364.99 4,316.66 -6,608.87 -1,289.77 6,009,437.30 568,055.99 4.98 6,733.51 2_MWD+IFR2+MS+Sag (2) 8,593.66 89.51 191.39 4,365.41 4,317.08 -6,670.21 -1,301.83 6,009,375.86 568,044.51 0.93 6,796.02 2_MWD+IFR2+MS+Sag(3) 8,659.30 91.74 192.94 4,364.69 4,316.36 -6,734.36 -1,315.66 6,009,311.58 568,031.27 4.14 6,861.64 2_MWD+IFR2+MS+Sag(3) 8,722.16 93.28 193.96 4,361.94 4,313.61 -6,795.44 -1,330.26 6,009,250.38 568,017.24 2.94 6,924.37 2_MWD+IFR2+MS+Sag (3) 8,785.89 94.01 193.55 4,357.89 4,309.56 -6,857.21 -1,345.38 6,009,188.47 568,002.69 1.31 6,987.89 2_MWD+IFR2+MS+Sag (3) 8,850.07 93.71 193.04 4,353.57 4,305.24 -6,919.53 -1,360.11 6,009,126.03 567,988.55 0.92 7,051.86 2_MWD+IFR2+MS+Sag (3) 8,913.65 91.23 191.41 4,350.83 4,302.50 -6,981.60 -1,373.56 6,009,063.84 567,975.68 4.67 7,115.36 2_MWD+IFR2+MS+Sag(3) 8,977.34 91.67 190.85 4,349.22 4,300.89 -7,044.08 -1,385.85 6,009,001.26 567,963.97 1.12 7,179.03 2_MWD+IFR2+MS+Sag(3) 9,040.29 92.29 191.50 4,347.04 4,298.71 -7,105.80 -1,398.04 6,008,939.43 567,952.35 1.43 7,241.94 2_MWD+IFR2+MS+Sag (3) 9,103.95 91.79 193.08 4,344.77 4,296.44 -7,167.95 -1,411.58 6,008,877.16 567,939.39 2,60 7,305.54 2_MWD+IFR2+MS+Sag(3) 9,167.28 91.92 194.44 4,342.72 4,294.39 -7,229.43 -1,426.64 6,008,815.55 567,924.91 2.16 7,368.75 2_MWD+IFR2+MS+Sag(3) 9,231.45 91.92 196.83 4,340.57 4,292.24 -7,291.19 -1,443.92 6,008,753.64 567,908.20 3.72 7,432.66 2_MWD+IFR2+MS+Sag(3) 9,294.68 92.47 198.10 4,338.15 4,289.82 -7,351.46 -1,462.88 6,008,693.20 567,889.80 2.19 7,495.42 2_MWD+IFR2+MS+Sag (3) 9,358.57 92.35 198.77 4,335.47 4,287.14 -7,412.02 -1,483.07 6,008,632.46 567,870.18 1.06 7,558.70 2_MWD+IFR2+MS+Sag(3) 9,421.58 91.98 198.78 4,333.09 4,284.76 -7,471.63 -1,503.33 6,008,572.67 567,850.48 0.59 7,621.06 2_MWD+IFR2+MS+Sag(3) 9,486.40 92.29 197.70 4,330.67 4,282.34 -7,533.15 -1,523.61 6,008,510.97 567,830.78 1.73 7,685.30 2_MWD+IFR2+MS+Sag (3) 9,550.03 91.30 195.22 4,328.68 4,280.35 -7,594.14 -1,541.63 6,008,449.82 567,813.33 4.19 7,746.59 2_MWD+IFR2+MS+Sag(3) 9,613.45 91.67 192.91 4,327.03 4,278.70 -7,655.63 -1,557.03 6,008,388.20 567,798.50 3.69 7,811.88 2_MWD+IFR2+MS+Sag (3) 9,677.26 91.73 192.20 4,325.14 4,27681 -7,717.89 -1,570.90 6,008,325.82 567,785.21 1.12 7,875.64 2_MWD+IFR2+MS+Sag(3) 9,740.95 91.05 192.46 4,323.60 4,275.27 -7,780.09 -1,584.49 6,008,263.50 567,772.20 1.14 7,939.29 2_MWD+IFR2+MS+Sag (3) 9,804.80 90.06 192.31 4,322.98 4,274.65 -7,842.45 -1,598.19 6,008,201.02 567,759.08 1.57 8,003.11 2_MWD+IFR2+MS+Sag(3) 9,867.80 89.76 192.48 4,323.08 4,274.75 -7,903.98 -1,611.71 6,008,139.37 567,746.13 0.55 8,066.09 2_MWD+IFR2+MS+Sag (3) 9,931.96 89.70 191.64 4,323.38 4,275.05 -7,966.72 -1,625.12 6,008,076.51 567,733.31 1.31 8,130.23 2_MWD+IFR2+MS+Sag(3) 9,995.32 91.61 192.25 4,322.65 4,274.32 -8,028.71 -1,638.23 6,008,014.42 567,720.78 3.16 8,193.57 2_MWD+IFR2+MS+Sag(3) 10,059.47 92.84 192.35 4,320.16 4,271.83 -8,091.33 -1,651.88 6,007,951.67 567,707.71 1.92 8,257.65 2_MWD+IFR2+MS+Sag (3) 10,123.02 92.35 193.26 4,317.29 4,268.96 -8,153.24 -1,665.95 6,007,889.64 567,694.22 1.63 8,321.10 2_MWD+IFR2+MS+Sag(3) 10,187.14 92.48 194.11 4,314.58 4,266.25 -8,215.48 -1,681.11 6,007,827.27 567,679.64 1.34 8,385.09 2_MWD+IFR2+MS+Sag(3) 10,250.44 93.09 195.04 4,311.51 4,263.18 -8,276.67 -1,697.02 6,007,765.94 567,664.30 1.76 8,448.18 2_MWD+IFR2+MS+Sag (3) 10,314.14 93.03 194.15 4,308.11 4,259.78 -8,338.23 -1,713.05 6,007,704.24 567,648.85 1.40 8,511.65 2_MWD+IFR2+MS+Sag(3) 10,377.68 93.15 193.18 4,304.68 4,256.35 -8,399.88 -1,728.04 6,007,642.46 567,634.44 1.54 8,575.02 2_MWD+IFR2+MS+Sag (3) 10,441.67 93.15 191.55 4,301.17 4,252.84 -8,462.29 -1,741.72 6,007,579.93 567,621.34 2.54 8,638.89 2_MWD+IFR2+MS+Sag(3) 10,505.35 92.84 191.03 4,297.84 4,249.51 -8,524.65 -1,754.17 6,007,517.46 567,609.47 0.95 8,702.48 2_MWD+IFR2+MS+Sag (3) 10,569.21 93.03 191.58 4,294.57 4,246.24 -8,587.19 -1,766.67 6,007,454.82 567,597.55 0.91 8,766.26 2_MWD+IFR2+MS+Sag(3) 10,632.87 93.15 190.47 4,291.14 4,242.81 -8,649.58 -1,778.83 6,007,392.32 567,585.97 1.75 8,829.82 2_MWD+IFR2+MS+Sag (3) 10,696.88 92.29 188.55 4,288.10 4,239.77 -8,712.64 -1,789.39 6,007,329.17 567,576.00 3.28 8,893.74 2_MWD+IFR2+MS+Sag(3) 10,760.88 91.79 186.11 4,285.82 4,237.49 -8,776.07 -1,797.55 6,007,265.68 567,568.43 3.89 8,957.57 2_MWD+IFR2+MS+Sag (3) 10,824.66 91.48 185.57 4,284.00 4,235.67 -8,839.49 -1,804.04 6,007,202.20 567,562.53 0.98 9,021.08 2_MWD+IFR2+MS+Sag(3) 10,888.72 91.12 187.87 4,282.55 4,234.22 -8,903.09 -1,811.53 6,007,138.54 567,555.63 3.63 9,084.95 2_MWD+IFR2+MS+Sag (3) MJ2019 11:40:25AM Page 6 COMPASS 5000.15 Build 9f Halliburton Definitive Survey Report Company: Hilcorp Alaska, LLC Local Co-ordinate Reference: Well MPU E-39 Project: Milne Point TVD Reference: MPU E-39 Actual RKB @ 48.33usft Site: M Pt E Pad MD Reference: MPU E-39 Actual RKB @ 48.33usft Well: MPU E-39 North Reference: True Wellbore: MPU E -39i Survey Calculation Method: Minimum Curvature Design: MPU E-39 Database: NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NIS +EI -W Northing Easting DLS Section (usft) (°) V) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,951.63 91.12 190.49 4,281.32 4,232.99 -8,965.18 -1,821.56 6,007,076.37 567,546.18 4.16 9,147.82 2_MWD+IFR2+MS+Sag(3) 11,015.11 92.17 193.06 4,279.50 4,231.17 -9,027.29 -1,834.51 6,007,014.14 567,533.81 4.37 9,211.26 2_MWD+IFR2+MS+Sag (3) 11,079.12 93.84 196.08 4,276.14 4,227.81 -9,089.15 -1,850.59 6,006,952.15 567,518.31 5.39 9,275.04 2_MWD+IFR2+MS+Sag(3) 11,142.37 95.38 198.09 4,271.06 4,222.73 -9,149.41 -1,869.11 6,006,891.72 567,500.35 4.00 9,337.70 2_MWD+IFR2+MS+Sag (3) 11,205.76 96.13 199.47 4,264.70 4,216.37 -9,209.12 -1,889.41 6,006,831.83 567,480.61 2.47 9,400.17 2_MWD+IFR2+MS+Sag (3) 11,269.27 94.76 198.77 4,258.67 4,210.34 -9,268.85 -1,910.12 6,006,771.91 567,460.46 2.42 9,462.74 2_MWD+IFR2+MS+Sag(3) 11,332.21 93.65 196.20 4,254.06 4,205.73 -9,328.72 -1,928.98 6,006,711.88 567,442.16 4.44 9,525.08 2_MWD+IFR2+MS+Sag (3) 11,396.24 93.34 194.28 4,250.15 4,201.82 -9,390.38 -1,945.77 6,006,650.07 567,425.94 3.03 9,588.80 2_MWD+IFR2+MS+Sag (3) 11,460.12 94.27 194.47 4,245.91 4,197.58 -9,452.12 -1,961.60 6,006,588.19 567,410.69 1.49 9,652.42 2 MWD+IFR2+MS+Sag (3) 11,524.14 94.08 194.51 4,241.25 4,192.92 -9,513.94 -1,977.57 6,006,526.23 567,395.29 0.30 9,716.14 2_MWD+IFR2+MS+Sag(3) 11,587.72 93.46 194.76 4,237.07 4,188.74 -9,575.32 -1,993.60 6,006,464.71 567,379.84 1.05 9,779.45 2_MWD+IFR2+MS+Sag (3) 11,650.77 93.15 194.63 4,233.44 4,185.11 -9,636.21 -2,009.57 6,006,403.68 567,364.44 0.53 9,842.25 2_MWD+IFR2+MS+Sag (3) 11,714.74 93.53 194.94 4,229.71 4,181.38 -9,697.96 -2,025.87 6,006,341.79 567,348.72 0.77 9,905.96 2_MWD+IFR2+MS+Sag(3) 11,779.01 93.59 194.41 4,225.72 4,177.39 -9,760.01 -2,042.12 6,000279.60 567,333.04 0.83 9,969.97 2_MWD+IFR2+MS+Sag (3) 11,841.94 93.21 193.92 4,221.99 4,173.66 -9,820.92 -2,057.49 6,006,218.55 567,318.24 0.98 10,032.68 2_MWD+IFR2+MS+Sag (3) 11,905.92 93.22 193.81 4,218.40 4,170.07 -9,882.94 -2,072.80 6,006,156.40 567,303.51 0.17 10,096.47 2_MWD+IFR2+MS+Sag (3) 11,969.98 93.15 194.88 4,214.84 4,166.51 -9,944.90 -2,088.65 6,006,094.30 567,288.24 1.67 10160.32 2_MWD+IFR2+MS+Sag(3) 12,033.46 94.33 197.19 4,210.70 4,162.37 -10,005.78 -2,106.14 6,006,033.27 567,271.32 4.08 10,223.40 2_MWD+IFR2+MS+Sag (3) 12,097.84 93.27 199.03 4,206.43 4,158.10 A0,066.83 -2,126.11 6,005,972.04 567,251.92 3.29 10,287.12 2_MWD+IFR2+MS+Sag (3) 12,161.32 93.09 200.76 4,202.91 4,154.58 -10,126.43 -2,147.68 6,005,912.25 567,230.91 2.74 10,349.71 2_MWD+IFR2+MS+Sag(3) 12,224.48 93.28 201.64 4,199.40 4,151.07 -10,185.22 -2,170.48 6,005,853.25 567,208.65 1.42 10,411.75 2_MWD+IFR2+MS+Sag(3) 12,288.70 92.72 202.49 4,196.04 4,147.71 -10,244.65 -2,194.57 6,005,793.60 567,185.12 1.58 10,474.66 2_MWD+IFR2+MS+Sag (3) 12,352.64 92.72 203.04 4,193.01 4,144.68 -10,303.55 -2,219.29 6,005,734.49 567,160.95 0.86 10,537.15 2 MWD+IFR2+MS+Sag(3) 12,416.18 92.29 203.05 4,190.23 4,141.90 -10,361.96 -2,244.14 6,005,675.85 567,136.65 0.58 10,599.20 2_MWD+IFR2+MS+Sag (3) 12,47977 92.16 202.86 4,187.76 4,139.43 -10,420.47 -2,268.92 6,005,617.12 567,112.42 0.36 10,661.33 2_MWD+IFR2+MS+Sag(3) 12,543.79 91.73 202.00 4,185.59 4,137.26 -10,479.61 -2,293.33 6,005,557.76 567,088.56 1.50 10,724.01 2_MWD+IFR2+MS+Sag(3) 12,606.76 91.61 202.43 4,183.75 4,135.42 -10,537.88 -2,317.13 6,005,499.27 567,065.31 0.71 10,785.72 2_MWD+IFR2+MS+Sag(3) 12,670.72 91.73 201.88 4,181.89 4,133.56 -10,597.10 -2,341.24 6,005,439.84 567,041.75 0.88 10,848.42 2_MWD+IFR2+MS+Sag (3) 12,733.99 91.98 202.44 4,179.84 4,131.51 -10,655.66 -2,365.09 6,005,381.07 567,018.45 0.97 10,910.43 2_MWD+IFR2+MS+Sag(3) 12,797.12 90.99 203.19 4,178.20 4,129.87 -10,713.83 -2,389.56 6,005,322.68 566,994.52 1.97 10,972.17 2 MWD+IFR2+MS+Sag(3) 12,859.72 88.51 204.98 4,178.48 4,130.15 -10,770.97 -2,415.10 6,005,265.30 566,969.51 4.89 11,033.10 2_MWD+IFR2+MS+Sag (3) 12,923.64 86.91 205.39 4,181.03 4,132.70 -10,828.77 -2,44228 6,005,207.26 566,942.87 2.58 11,094.98 2_MWD+IFR2+MS+Sag(3) 12,986.94 85.37 205.74 4,185.29 4,136.96 -10,885.74 -2,469.53 6,005,150.05 566,916.15 2.49 11,156.07 2_MWD+IFR2+MS+Sag (3) 13,051.22 85.43 205.03 4,190.45 4,142.12 -10,943.63 -2,497.00 6,005,091.91 566,889.23 1.10 11,218.09 2_MWD+IFR2+MS+Sag (3) 13,114.61 85.12 204.32 4,195.67 4,147.34 -11,001.03 -2,523.38 6,005,034.27 566,863.39 1.22 11,279.44 2 MWD+IFR2+MS+Sag(3) 13,177.21 85.00 202.68 4,201.06 4,152.73 -11,058.23 -2,548.24 6,004,976.85 566,839.06 2.62 11,340.29 2_MWD+IFR2+MS+Sag(3) 13,240.49 85.24 200.71 4,206.44 4,158.11 -11,116.81 -2,571.55 6,004,918.06 566,816.30 3.12 11,402.22 2_MWD+IFR2+MS+Sag (3) 13,304.38 85.00 198.21 4,211.88 4,163.55 -11,176.82 -2,592.76 6,004,857.86 566,795.66 3.92 11,465.15 2_MWD+IFR2+MS+Sag(3) 13,368.56 86.67 196.86 4,216.54 4,168.21 -11,237.86 -2,612.04 6,004,796.65 566,776.94 3.34 11,528.73 2_MWD+IFR2+MS+Sag (3) 13,432.29 89.58 196.11 4,218.63 4,170.30 -11,298.93 -2,630.11 6,004,735.42 566,759.44 4.72 11,592.11 2_MWD+IFR2+MS+Sag (3) M/2019 11:40:25AM Page 7 COMPASS 5000.15 Build 91 Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: MPU E-39 Wellbore: MPU E-391 Design: MPU E-39 Survey MD Inc Azi TVD (usft) (') (') (usft) 13,495.55 92.30 195.18 4,217.59 13,559.13 94.21 193.88 4,213.98 13,622.94 96.07 191.70 4,208.26 13,686.52 97.50 188.52 4,200.75 13,749.34 96.12 185.28 4,193.30 13,813.80 95.51 183.83 4,186.77 13,877.57 96.01 182.78 4,180.37 13,941.43 94.19 181.13 4,174.69 14,004.32 93.40 14,067.58 92.53 14,131.78 92.54 14,195.26 91.92 14,258.39 90.74 14,320.95 90.62 14,384.96 92.11 14,450.33 91.73 14,513.68 89.19 14,577.39 87.34 14,641.60 87.16 14,704.61 86.98 14,768.28 86.98 14,831.64 86.54 14,895.01 88.34 14,958.39 87.90 15,021.82 87.23 15,085.61 89.21 15,148.90 90.31 15,212.63 88.76 15,276.16 86.42 15,339.31 84.18 15,403.10 85.49 15,462.14 85.37 15,531.00 85.37 180.31 179.98 181.15 180.88 180.68 180.87 182.95 184.80 183.23 181.71 180.40 179.24 177.66 177.68 177.61 177.49 177.59 178.02 179.49 180.11 179.75 179.35 179.68 179.89 179.89 4,170.53 4,167.25 4,164.41 4,161.94 4,160.48 4,159.74 4,158.21 4,156.02 4,155.51 4,157.44 4,160.52 4,163.74 4,167.10 4,170.68 4,173.51 4,175.59 4,178.28 4,180.26 4,180.53 4,181.05 4,183.72 4,188.89 4,194.63 4,199.34 4,204.90 Halliburton Definitive Survey Report Local Coordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Map TVDSS +Nl-S +EI -W Northing (usft) (usft) (usft) (ft) 4,169.26 -11,359.83 -2,647.17 6,004,674.37 4,165.65 -11,421.27 -2,663.09 6,004,612.79 4,159.93 -11,483.24 -2,677.16 6,004,550.70 4,152.42 -11,545.39 -2,688.25 6,004,488.46 4,144.97 -11,607.30 -2,695.74 6,004,426.48 4,138.44 -11,671.23 -2,700.83 6,004,362.52 4,132.04 -11,734.57 -2,704.49 6,004,299.15 4,126.36 -11,798.13 -2,706.66 6,004,235.58 4,122.20 -11,860.88 -2,707.44 6,004,172.83 4,118.92 -11,924.05 -2,707.60 6,004,109.66 4,116.08 -11,988.19 -2,708.24 6,004,045.53 4,113.61 -12,051.61 -2,709.36 6,003,982.11 4,112.15 -12,114.71 -2,710.22 6,003,919.01 4,111.41 -12,177.26 -2,711.06 6,003,856.46 4,109.88 -12,241.21 -2,713.20 6,003,792.49 4,107.69 -12,306.39 -2,717.61 6,003,727.28 4,107.18 -12,369.58 -2,722.05 6,003,664.06 4,109.11 -12,433.20 -2,724.79 6,003,600.43 4,112.19 -12,497.32 -2,725.97 6,003,536.30 4,115.41 -12,560.25 -2,725.77 6,003,473.39 4,118.77 -12,623.80 -2,724.05 6,003,409.86 4,122.35 -1207.01 -2,721.48 6,003,346.68 4,125.18 -12,750.26 -2,718.88 6,003,283.47 4,127.26 -12,813.55 -2,716.17 6,003,220.21 4,129.95 -12,876.86 -2,713.45 6,003,156.93 4,131.93 -12,940.57 -2,711.01 6,003,093.25 4,132.20 -13,003.84 -2,709.64 6,003,030.00 4,132.72 -13,067.57 -2,709.41 6,002,966.29 4,135.39 -13,131.04 -2,709.34 6,002,902.83 4,140.56 -13,193.97 -2,708.84 6,002,839.91 4,146.30 -13,257.50 -2,708.31 6,002,776.40 4,151.01 -13,316.35 -2,708.08 6,002,717.56 4,156.57 -13,384.98 -2,707.95 6,002,648.93 Well MPU E-39 MPU E-39 Actual RKB @ 48.33usft MPU E-39 Actual RKB @ 48.33usft True Minimum Curvature NORTH US + CANADA Map Vertical Easting DLS Section (ft) (-lloo-) (ft) Survey Tool Name 566,742.95 4.54 11,655.13 2 MWD+IFR2+MS+Sag (3) 566,727.60 3.63 11,718.48 2_MWD+IFR2+MS+Sag (3) 566,714.11 4.48 11,781.99 2_MWD+IFR2+MS+Sag (3) 566,703.61 5.45 11,845.11 2_MWD+IFR2+MS+Sag (3) 566,696.69 5.57 11,907.32 2_MWD+IFR2+MS+Sag(3) 566,692.20 2.43 11,971.06 2_MWD+IFR2+MS+Sag (3) 566,689.13 1.82 12,033.96 2_MWD+IFR2+MS+Sag (3) 566,687.55 3.84 12,096.79 2_MWD+IFR2+MS+Sag (3) 566,687.35 1.81 12,158.56 2_MWD+IFR2+MS+Sag(3) 566,687.77 1.47 12,220.64 2_MWD+IFR2+MS+Sag (3) 566,687.74 1.82 12,283.74 2_MWD+IFR2+MS+Sag(3) 566,687.20 1.07 12,346.24 2_MWD+IFR2+MS+Sag (3) 566,686.93 1.90 12,408.38 2_MWD+IFR2+MS+Sag (3) 566,686.67 0.36 12,469.97 2_MWD+IFR2+MS+Sag (3) 566,685.13 4.00 12,533.17 2_MWD+IFR2+MS+Sag(3) 566,681.32 2.89 12,598.02 2_MWD+IFR2+MS+Sag (3) 566,677.47 4.71 12,660.91 2_MWD+IFR2+MS+Sag (3) 566,675.32 3.76 12,723.90 2_MWD+IFR2+MS+Sag (3) 566,674.74 2.06 12,787.10 2_MWD+IFR2+MS+Sag (3) 566,675.52 1.86 12,648.86 2_MWD+IFR2+MS+Sag(3) 566,677.83 2.48 12,910.96 2_MWD+IFR2+MS+Sag(3) 566,680.99 0.70 12,972.55 2_MWD+IFR2+MS+Sag (3) 566,684.18 2.84 13,034.17 2_MWD+IFR2+MS+Sag (3) 566,687.47 0.72 13,095.82 2_MWD+IFR2+MS+Sag(3) 566,690.78 1.07 13,157.49 2_MWD+IFR2+MS+Sag(3) 566,693.82 3.18 13,219.59 2_MWD+IFR2+MS+Sag (3) 566,695.78 2.90 13,281.47 2_MWD+IFR2+MS+Sag (3) 566,696.59 2.62 13,344.01 2_MWD+IFR2+MS+Sag (3) 566,697.26 3.73 13,406.33 2_MWD+IFR2+MS+Sag (3) 566,698.34 3.60 13,468.04 2_MWD+IFR2+MS+Sag(3) 566,699.47 2.12 13,530.33 2_MWD+IFR2+MS+Sag (3) 566,700.24 0.41 13,58809 2_MWD+IFR2+MS+Sag(3) 566,701.01 0.00 13,655.47 PROJECTED to TD ' Mitch Laird Date: 08-09-2019 Checked By: Chelsea Wright�..w ''� .. Approved By: 8/92019 11:40:25AM Page 8 COMPASS 5000.15 Build 91 i Hilcon, Energy ComPsny CASING & CEMENTING REPORT Lease & Well No, MP E-39 Date Run 17 -Jul -19 County State Alaska Sup, S. Better/C. Montague Csg Wt. On Hook: 270 type noav zona,. ao Casing Crew: WeatherfpM Cal M. On Slips: 100 Type of Shoe: Bullnose Rotate Csg X Yes _ No Recip Csg X Yes _ No 40 FL Min. 9_5 PPG Fluid Description: Spud Mud Uner Liner hanger lnfo(MakelModel): Floats Held X Yea No p Packed: Yea No liner hanger test pressure: Floats Centralizer Placement: 2 on him 1. 1 every joint Jay2.15, 1 every joint Jt# 19 - 31,1 every other jointJT #33.55, 1 every joint Joel 49-153 1 pup joints above2elow ES cementer, 1 every joint J#t156-1W, 1 every other pint J81169-213. CEMENTING REPORT Shoe @ 8557 CASING RECORD Casing (Or Liner) Detail Top of Liner #N/A sarfare Depths TO 8,570.00 Shoe Depth: 8,557.00 PBTD: Grace No. Jts. Delivered 240 No. JtA Run 215 No, Jts. Returned 25 Bottom Ftg. Delivered 9,4913.42 Ftg. Run 8,513.04 Fig. Returned! 983.3& Length Measurements Wb Threads Fig. Cut Jl. Fig. Balance BTC RKS 26.50 RKB to BHF RKB to CHF RKB to THF Csg Wt. On Hook: 270 type noav zona,. ao Casing Crew: WeatherfpM Cal M. On Slips: 100 Type of Shoe: Bullnose Rotate Csg X Yes _ No Recip Csg X Yes _ No 40 FL Min. 9_5 PPG Fluid Description: Spud Mud Uner Liner hanger lnfo(MakelModel): Floats Held X Yea No p Packed: Yea No liner hanger test pressure: Floats Centralizer Placement: 2 on him 1. 1 every joint Jay2.15, 1 every joint Jt# 19 - 31,1 every other jointJT #33.55, 1 every joint Joel 49-153 1 pup joints above2elow ES cementer, 1 every joint J#t156-1W, 1 every other pint J81169-213. CEMENTING REPORT Shoe @ 8557 FC @ 8,476.59 Casing (Or Liner) Detail Top of Liner #N/A Setting Depths its. Component Size WL Grace THD Make Length Bottom Top Shoe 103/4 40.0 L-80 BTC Innovex 1.59 8,557.00 8,555.41 2 Casio 95/8 40.0 L-80 TXP 7,74].00 8,555.41 8,477.94 Float Collar 103/4 40.0 L-80 eTC Innovez 1.35 8,4]].94 8,4]6.59 1 Casing 95/8 40.0 L-80 TXP FPost rc Flush (Spacer) Type: Water 8,4]6.59 8,439.02 Rate(bpm): 6 Volume: Baffle Adapter 103/4 40.0 L-80 BTC Halliburton 1.5 37.5 151 Casin 95/8 40.0 L-80 TXp 5,9 290 8,43].51 2,4464.61 Casing Rotated? X Yes Pup Joint 95/8 40.0 L-80 TXP Cement returns to surface? X 15.15 2,464.61 2,449.46 50100 ECP 103/4 1 40.0 IL -80 TXP Halliburton 11.92 2,449.46 2,437.54 Pup Joint 95/8 40.0 L-80 TXP 15.21 2,43].54 2,422.33 60 Casing 9516 1 40.0 1 L-80 TXP 2,385.32 1 2,422.33 1 37.01 Lead Slurry Cut Joint 95/8 40.0 L-80 TXP Type: 'Prom L' 11.80 37.01 Mixing I Pumping Rale (bpm): 8 Density (ppg) 10.7 25.21 25.21 RKB 1.17 w. r Type' Class G Density (ppg) 15.8 d (BBL.) 56 2 No Histm Run: 28.5 Csg Wt. On Hook: 270 type noav zona,. ao Casing Crew: WeatherfpM Cal M. On Slips: 100 Type of Shoe: Bullnose Rotate Csg X Yes _ No Recip Csg X Yes _ No 40 FL Min. 9_5 PPG Fluid Description: Spud Mud Uner Liner hanger lnfo(MakelModel): Floats Held X Yea No p Packed: Yea No liner hanger test pressure: Floats Centralizer Placement: 2 on him 1. 1 every joint Jay2.15, 1 every joint Jt# 19 - 31,1 every other jointJT #33.55, 1 every joint Joel 49-153 1 pup joints above2elow ES cementer, 1 every joint J#t156-1W, 1 every other pint J81169-213. CEMENTING REPORT Post lob Calculations: gu 6 Calculated Cm Vol @ 0% excess: 51007 Total Volume cot Pumped: Can returned to surface: 394 Calculated cement left in vrellbore: 590.8 OH volume Calculated: 471.3 OH volu--- Aual 551.8 Actual % Washout: ^ 17 Shoe @ 8557 FC @ 8,476.59 Top of Liner #N/A Pre0ush(Spacer) Density ON) 10 Volume pumped(SBLS) 60 Type' Tuned Spacer Lead Slum Sacks: 908 Yieltl'. 2.35 Type: Typo 1111 Volume (BBL.) 380 Mixing / Pumping Rate (bpm): 6 Density (pPg) 12 pumped Tail Slurry Sacks: 400 Yield : 1.16 Type' Class G Volume (BBLs) 8204 Mixing I Pumping Rate (bpm: 5 Density (ppg) 15.8 pumped FPost rc Flush (Spacer) Type: Water Density(ppg) 8_34 Rate(bpm): 6 Volume: 20 LL Displacement 9_5 Raze (bpm): 6_6 Volume (actual / calculated): 643.4/641.5 Type: Drilling Fluid Density (ppg) disp: Rig Bump Plug? X Yes Bump press 1240 FCP(psi): 720 Pump used for -No %Retums dunN job Casing Rotated? X Yes No Reciprocated? X Yes _No Cement returns to surface? X Yes Spacerretums? X Yes No Vol to Surf.2437 50100 Cement In Place At: 12:31 _No Date: 7/192019 Estimated TOC: Method Used To Determine TOC: Retums after opening ES cementer Stage Collar@ 2437,54 Type ESICP Closure OK Yes Prenush (Spacer) Density (ppg) 10 Volume pumpetl (Ei 80 Type: Tuned Spacer Lead Slurry Sacks: 530 Yield: Type: 'Prom L' tl (BB") 418 Mixing I Pumping Rale (bpm): 8 Density (ppg) 10.7 Tall Slurry Sacks: 2]0 Yield: 1.17 w. r Type' Class G Density (ppg) 15.8 d (BBL.) 56 2 Mixing / Pumping Rate (bpm): 32 o Post Flush (Spacer) 5.5 0 Type: Water Density(ppg) 834 Rete (bpm): 20 Volume: Displacement: Rate Aga 6 Volume I calculated): 1]0.7/165.2 Type' Drilling Fluid Density(ppg) Bump Plug? X Yes Bump press 1950 FCP(psi): 500 Pump used foRig X _No No % Retums during job 100 Casing Rotated? iprocated? _Yes 294 _Ves Cement returns to surface? X YesSpacerretums? X Yes Vol to Sun: Cement In Place At 22:48]/192019 Es6ma[et TOC: 25 Method Used To Determine TOC: Post lob Calculations: gu 6 Calculated Cm Vol @ 0% excess: 51007 Total Volume cot Pumped: Can returned to surface: 394 Calculated cement left in vrellbore: 590.8 OH volume Calculated: 471.3 OH volu--- Aual 551.8 Actual % Washout: ^ 17 219036 De .. Judean Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 1400 3 1 1 ., 0 t Anchorage, AK 99503 Tele: 907 777-8337 Hil""p al:,.k.,. LL1. Fax: 907 777-8510 E-mail: doudean@hilcorp.com DATE 8/30/2019 To: Alaska Oil & Gas Conservation Commission Abby Bell RECEIVED Natural Resource Technician II 333 W 7th Ave Ste 100 SEP 0 3 2019 Anchorage, AK 99501 AOGCC CD 1: ROP DGR ABG EWR ADR WELLBORE_PROFILE MD AND TVD DEFINITIVE SURVEY CGM 8/3020199:14 AM Filefclder Definitive Survey 8/30/2019 9:14 AM Filefolder EMF 813012019 9:15 AM Filefolder LAS 8/30/20199:15 AM Filefolder PDF 8/30,120199;15AM Filefolder TIFF 8/30/2019 9:15 AM Filefolder Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Monty Myers Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 vvvvw.a ogcc. a I aska.gov Re: Milne Point Field, Schrader Bluff Oil Pool, MPU E-39 Hilcorp Alaska, LLC Permit to Drill Number: 219-096 Surface Location: 3519' FSL, 1863' FEL, SEC. 25, TI 3N, RI OE, UM, AK Bottomhole Location: 36' FSL, 728' FWL, SEC. 6, TI 2N, R11E, UM, AK Dear Mr. Myers: Enclosed is the approved application for the 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, Daniel T. Seamount, Jr. Commissioner y� DATED this day of July, 2019. STATE OF ALASKA AL,—KA OIL AND GAS CONSERVATION COMMIa iON PERMIT TO DRILL 9n AAr 95 001 RECEIVE® JUN 272019 1a. Type of Work:1 b. Proposed Well Class: Exploratory - Gas ❑ Service - WAG Service - Disp ❑ 1c Sp ie fy' v s K pged for: Drill 2Lateral ❑ Stratigraphic Test ❑ Development - Oil ❑ Service- Winj ❑� Single Zone ❑✓ Coalb rates ❑ 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 MPU E-39 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 MD: 16,181' TVD: 4,189' Milne Point Field Schrader Bluff Oil Pool 4a. Location of Well (Governmental Section): 7. Property Designation: , Surface: 3519' FSL, 1863' FEL, Sec 25, T1 3N, R1 OE, UM, AK ADL025518, ADL380110 Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: 1733' FSL, 2032' FWL, Sec 36, T1 3N, R1 OE, UM, AK LONS 94-017 7/18/2019 ' Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 36' FSL, 728' FWL, Sec 6, T12N, R1 1E, UM, AK 4997 8,559' to nearest unit boundary . 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 48.2 15. Distance to Nearest Well Open Surface: x- 569284 y- 6016057 Zone -4 GL / BF Elevation above MSL (ft): 21.7 to Same Pool: 700' to MPU S-12 . 16. Deviated wells: Kickoff depth: 400 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 96.8 degrees , Downhole: 1918 Surface: 1475 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) Cond 20" 215# X-42 Weld 80' Surface Surface 107' . 107' ±270 ft3 12-1/4" 9-5/8" 40# L-80 TXP 8,950' Surface Surface 8,950' . Stg 1 L - 2219.6 ft3 / T - 458 ft3 4,337' Stg 2 L - 1937 ft3 / T - 314 ft3 8-1/2" 4-1/2" 13.5# L-80 Hyd 625 7,496' 8,685' 4,368' 16,181' . 4,189' Cementless Injection Liner w/ [CDs + Swell Packers 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): Hydraulic Fracture planned? Yes ❑ No ❑- - 20. Attachments: Property Plat O BOP Sketch Div re, Sketch e Drilling Program Time v. Depth Plot Shallow Hazard Analysis Seabed Report 8 Drilling Fluid Program e 20 AAC 25.050 requirementse 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 Name: Joe Engel Authorized Name: Monty Myers Contact Email: 'en el hIICOr .Com Authorized Title: Drilling Manager Contact Phone: 777-8395 Authorized Signature: Date: - Z -7, Z 0 19 Commission Use Only Permit to Drillumber: Number: Permit Approval �r /� /� / 1'1 See cover letter for other — 0916 50- p �, .. 6 94.0 — 00— 0 0 Date: ,1 Irequirements. Conditions of approval : If box is checked, well may not be used to explore,for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: �yGC L vr - f/3 PE.�65-1TQ 3�! ^st Samples req'd: Yes El No [9' Mud log req'd: Yes ❑ No Rr Jg _ 1 — HzS measures: Yes❑ No rf❑ f Directional svy req'd: Yes No /S pacing.%jxception req'd: Yes ❑ No &' Inclination -only svy req'd: Yes ❑ No [T ❑ Post initial injection MIT req'd: Yes No❑ Approved by: APPROVED BY (� % �/ / COMMISSIONER THE COMMISSION Date: / Submit Form and Foo, 4 evi d /zo 7 This permit is valid for 24 o s foritl a o a roval per 20 C 25. O5() Atta^ychym�ents in Du iicate a aoF— o a sem ° O c O c O m ut v v c m v a ai o _ O YN d U \ Y (O C U N Y U N U O O t0 C C w E N wO£ C O m I� u m d. u O YO YO C n v i ti O c O O m W Y '� 10 N O. N ❑. yOj O N O O. O O u u s u v v v v v ca u u a C u u u u u E t r° co U N VI t/I VI Vf u ca m m m COL mo v a a a a r O 2 Zn N N m m 00 N tNll C � 00 O T ^ N r N K K p i0 V ~O a a o- vari 9 a m o0 3 U a a J V N N m N J LLI Uj LLJ W N V1 0 0 0 0 0 0 0 p 0 0 0 0 0 0 0 0 0 N m m N N N N N N N Ck O O O O O 00 00 f�Yl O N N O Obi O O d N N r1 N N S-18 S-16 S-90 S-17 E-20 r I� / I k --4A2 \ 14JE-39_wp06 1 I \ E -2y e -z4 ItI I 1� I 5-19 / I Y S-02 S 2j S-05 ' S-1 DA I -- S-16 HILCORP ALASKA LLC MILNE POINT FIELD AOR MAP � EJB xyuorl�w�) fPEi _ W91 SA@MS l Wp E-29 t S-01 B S-07 S- 1 S-01PB1 , S -01A S-04 S-09 S-03 Hilcorp Alaska, LLC Milne Point Unit (MPU) E-39 Drilling Program Version 1 6/27/2019 Table of Contents 1.0 Well Summa 2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: .......................................................................................................................... *4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summa 7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work..........................................................................................................10 10.0 N/U 13-5/8" 5M Diverter Configuration.....................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................13 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................21 14.0 BOP NIU and Test.........................................................................................................................26 15.0 Drill 8-1/2" Hole Section...............................................................................................................27 16.0 Run 4-1/2" Injection Liner...........................................................................................................31 17.0 End of E-39 Operations / Begin E -39L1 Operations (Separate PTD)......................................35 18.0 Innovation Rig Diverter Schematic.............................................................................................36 19.0 Innovation Rig BOP Schematic....................................................................................................37 20.0 Wellhead Schematic......................................................................................................................38 21.0 Days Vs Depth................................................................................................................................39 22.0 Formation Tops & Information...................................................................................................40 23.0 Anticipated Drilling Hazards.......................................................................................................42 24.0 Innovation Rig Layout..................................................................................................................45 25.0 FIT Procedure................................................................................................................................46 26.0 Innovation Rig Choke Manifold Schematic................................................................................47 27.0 Casing Design.................................................................................................................................48 28.0 8-1/2" Hole Section MASP............................................................................................................49 29.0 Spider Plot AD 27 Governmental Sections 50 30.0 Surface Plat (As Built) (NAD 27).................................................................................................51 31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart ..................................................................52 Milne Point Unit E-39 SB Injector Hilcorp EDrilling Procedure ,v Campoy 1.0 Well Summary Well MPU E-39 Pad Milne Point "E" Pad Planned Completion Type 3-1/2" Injection Tubing Target Reservoir(s) Schrader Bluff OB Sand Planned Well TD, MD / TVD 16,181' MD / 4,189' TVD PBTD, MD / TVD 16,161' MD / 4,189' TVD Surface Location (Governmental) 3519' FSL, 1863' FEL, Sec 25, T13N, R10E, UM, AK Surface Location (NAD 27) X= 569,284.12 Y= 6,016,057.25 Top of Productive Horizon (Governmental) 1733' FSL, 2032' FWL, Sec 36, T13N, R10E, UM, AK TPH Location AD 27) X= 567,966.51 Y= 6,008,979.6 BHL (Governmental) 36' FSL, 728' FWL, Sec 6, T12N, RI 1E, UM, AK BHL (NAD 27) X= 566,720.99, Y=6,001,991 AFE Number 1910943 AFE Drilling Das 25 days AFE Completion Das 0 days AFE Drilling Amount $5,568,155 AFE Completion Amount $0 AFE Facility Amount $391,000 Maximum Anticipated Pressure (Surface) 1475 psig Maximum Anticipated Pressure Downhole/Reservoir 1918 psig Work String 5" 19.5# S-135 DS -50 & NC 50 KB Elevation above MSL: 26.5 ft + 21.7 ft = 48.2 ft GL Elevation above MSL: 21.7 ft BOP Equipment 13-5/8" x 5M Annular, (3) ea 13-5/8" x 5M Rams Page 2 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp 2.0 Management of Change Information Hilcorp Alaska, LLC Changes to Approved Permit to Driii Date: 6/27/2019 (Subject: Changes to Approved Permit to Drill for MPU E-39 14 Hilcorp SWC. Y File #: MPU E-39 Drilling and Completion Program Any modifications to MPU E-39 Drilling & Completion Program will be documented and approved below. Changes to an approved APD will be approved in advance to the AOGCC. Approval: r a�P Prepared: Page 3 Milne Pointr E-39 SB Injector Hilcorp Drilling Procedure U moey 3.0 Tubular Program: 4.0 Drill Pipe Information: Hole OD ID (in) TJ H) TJ O ra tion in in in #/ k -1b Surface & 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k1b Production 5" 4.276" 3.25" 6.625" 19.5 5-135 I NC50 I 31,032 I 560klb All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery) Page 4 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure �4�. 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on WeIIEZ. • 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. • 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. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hileorp.com. com mmyers hilcorp jenael@hilcorp.com and cdinger@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by 7am on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. 5.4 EHS Incident Reporting • Health and Safety: Notify EHS field coordinator. • Environmental: Drilling Environmental Coordinator • Notify Drilling Manager & Drilling Engineer on all incidents • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Rud' Casing tally to mmyers hilcorp,com iengel2hilcor2.com and cdinizer@hilcoW.com 5.6 Casing and Cement report • Send casing and cement report for each string of casing to mmyers@hilcorp.com jengel hilcoM.com and cdinger(a),hilcorp.com 5.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Monty Myers 907.777.8431 907.538.1168 mmyers@hilcorp.com Drilling Engineer Joe Engel 907.777.8395 805.235.6265 lengel@hilcorp.com Completion Engineer Taylor Wellman 907.777.8449 907.907.9533 twellman@hiLlcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Reservoir Engineer Reid Edwards 907.777.8421 907.250.5081 reedwards@hilcorp.com Drilling Env. Coordinator Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Manager Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com Page 5 Milne Point Unit E-39 SB Injector HilDOJp Drilling Procedure Hilc a 6.0 Planned Wellbore Schematic Moe O6. 0 El .:382'/ 0,jGLEer.: M7' Milne Point Unit Well: MPU E-39 & U PROPOSED Last Completed: xx/�/Doo PTD: W -x ._____________________________,----- ______ OPFN HOSE /CEMENT DETAIL t k'&W 1 LMCG.s il 4510 WELL INCLINATION DETAIL OP @ Mr MD laaj7-el,-6=%.e AyryL@8.537• MD TD=Jfi186JNq/TO D -4.I IYr peTDz 1§176 {N1>) /P6TD>:i�•{f Vq Page 6 ______________ ______--_____ .________.----------------------------------- CASINGDETAIL No I ____-_____-.____CASING nM 5ife Type W Grade/Conn ID Top Bbn 7p' [arduum 2i5/W+12/Weld NIA Surface 107' 45R- Surface w/t-80/T8p MS Sur v 8.950' 4f/Y iiner'Q1"InlCfien Uner w/ICOs 13.5/L-B7/11Vd525 3920 0.7W 12,376 41/P Irtwr "OB"lnjeclion Uaer w/ICO% 13.S/L-BO/LWd62S 3920 2205- 16,181' 8 TBD TUBING DETAIL 9 760 OB Ia9eralD�liner Top Packer HIP I Tutfw vb:k I "JLC/D1[ 1 2441 1Sudam 28.610 _ ---------- ------- .--------------------------------- __________.._, JEWELRY DETAIL No I Depth nM u 1 I 22.2W 3 -Ur Wipple 11029/37 2 TBD Ovunhole Gau 3 1 760 3-1(Yi&W Retrievable Packer 4 1 1 3ilNur BOPb PD=2813") Gt Detail:3E/2"x1.5"iYOW7w BW IY.ch 5 6 760 T1, SL,yK Vu, Dummy)Oaee%a/»hn SINI: Value-Dummy/Dam WWv 7 1 3-1/2-WN-NIPplelhe 1-1L ' 064eeal 8 TBD Sealasx I 9 760 OB Ia9eralD�liner Top Packer to TBD OBl>neral9-5]g'a41/3"BakerSP liner) SPuirlAWater5w 1Rs Nlfi jppSSpw%Sueen B ICp pi -6 11 760 CB - -l4-112'1)611 tele Packs" 12 TBD 08L -14 M 13 TBD 1-6, nmral4-UP of Guide Stene OALwural( 8d&W i1/Y kaionl IC TBD OA lamml9-SI8"ad-U2"Bier B-11mk11 IeW,i:1 WwerSwen Pr1er Y7-17 7YidritSSDwlScreen &ICO tl7-]T ]5 760 DA Lamra143/Y Drillable Padtdf 16 TBO QAlamml4E)Y SVIV 17 TO 0ALateral4-i.. Blm of GuiJeSMe _______. ------------------------------------------------ --------------------------- LATERAL WINDOW DETAIL Topaf"W Window@R= MD Boemm@"Sly Mq le@m pfwindowi%9] Topaf"DA'Wirdvu@],750'M68o2mm@],lifl'Ml}An e@mppf window is fi7 kc.i.ed &t -CID W2712013 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure E�� vmr 7.0 Drilling / Completion Summary MPU E-39 is a grassroots dual lateral injector planned to be drilled in the Schrader Bluff OB/OA sand. E-39 is part of an eight well program targeting the Schrader Bluff sand on E -Pad. The directional plan is a catenary well path build, 12.25" hole with 9-5/8" surface casing set into the top of the Schrader Bluff OB sand. An 8.5" lateral section will then be drilled. A 4-1/2" injection liner will be run in the open hole section. Once liner is ran, operations for the second lateral, E -39L1, will begin and will be included on a separate PTD. ✓ s The Innovation Rig will be used to drill and complete the wellbore. Drilling operations are expected to commence approximately July 18, 2019, pending rig schedule. Surface casing will be run to 8,950' MD / 4,337' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, necessary remedial action will then be discussed with AOGCC authorities. All cuttings & mud generated during drilling operations will be hauled to the Milne Point `B" pad G&I facility. General sequence of operations 1. MIRU Innovation to well site 2. N/U & Test 13-5/8" Diverter and 16" diverter line 3. Drill 12-1/4" hole to TD of surface hole section. Run and cement 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. Note: Remaining operations will be covered under the E -39L1 PTD application 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 + ADR (For geo-steering) Page 7 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. 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 E-39. 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 or control fluid flow from the well bore, AOGCC is to be notified and 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". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: None requested Page 8 Milne Pointr E-39 SB Injector o co Drilling Procedure 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the all applicable AOGCC regulations, specific regulations are listed below. 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 E-39. 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 or control fluid flow from the well bore, AOGCC is to be notified and 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". o Ensure the diverter vent line is at least 75' away from potential ignition sources • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: None requested Page 8 Milne Point o E-39 SB Injector Hilcorp Drilling Procedure E,Co T Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure si 12 1/4" 13-5/8" 5M CTI Annular BOP w/ 16" diverter line Function Test Only 13-5/8" x 5M Control Technology Inc Annular BOP Initial Test: 250/3000 • 13-5/8" x 5M Control Technology Inc Double Gate o Blind ram in btm cavity • Mud cross w/ 3" x 5M side outlets 8-1/2" 13-5/8" x 5M Control Technology Single ram Subsequent Tests: • 3-1/8" x 5M Choke Line 250/3000 • 3-I/8" x SM Kill line • 3-1/8" x 5M Choke manifold • Standpipe, floor valves, etc Primary closing unit: Control Technology Inc. (CTI), 6 station, 3000 psi, 220 gallon accumulator unit. Primary closing hydraulics is provided by an electrically driven triplex pump. Secondary back-up is an electric triplex pump on a different electrical circuit 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.reee alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy schwartzgalaska.eov Victoria Loepp / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria loepp@alaska.goy Mel Rixse / Petroleum Engineer / (0): 907-793-1231 / (C): 907-xxx-xxxx / Email: melvin rixsegalaska.gov Primary Contact for Opportunity to witness: AOGCC Innectors@alaska.gov Test/Inspection notification standardization format: httl2 /Hdoa alaskagov/ogc/forms/TestWitnessNoti£html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 H Hilcorp 9.0 R/U and Preparatory Work Milne Point Unit E-39 SB Injector Drilling Procedure 9.1 E-39 will utilize a newly set 20" conductor on E Pad Expansion. Ensure to review attached surface plat and make sure rig is over appropriate conductor. 9.2 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 9.3 Install landing ring. 9.4 Insure (2) 4" nipples are installed on opposite sides of the conductor with ball valves on each. 9.5 Level pad and ensure enough room for layout of rig footprint and R/U. 9.6 Rig mat footprint of rig. 9.7 MIRU Innovation Rig. Ensure rig is centered over conductor to prevent any wear to BOPE or wellhead. 9.8 Mud loggers WILL NOT be used on either hole section. 9.9 Mix spud mud for 12-1/4" surface hole section. Ensure mud temperatures are cool (<80°F). 9.10 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Ensure 5" liners in mud pumps. • White Star Quattro 1300 Hp mud pumps are rated at 4097 psi, 381 gpm @ 140 spm @ 96.5% volumetric efficiency. Page 10 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Eve Cep y 10.0 N/U 13-5/8" 5M Diverter Configuration 10.1 N/U 13-5/8" CTI BOP stack in diverter configuration (Diverter Schematic attached to program). • N/U 20" x 13-5/8" DSA • N/U 13 5/8", 5M diverter "T". • NU 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 i¢nition source • Place drip berm at the end of diverter line. • Utilized extensions if needed. 10.2 Notify AOGCC. 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. 10.3 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. 10.4 Set wear bushing in wellhead. Page 1 I H Hilcorp E,m 10.5 Rig & Diverter Orientation: • Note: Diverter Orientation May Change On Location I, E - 39- I F 18 ■ 20 ■ 24 ■ Sl ■ 15 ■ Milne Point Unit E-39 SB Injector Drilling Procedure ■ t6 ■ 23 ■ '9 34 E-37 E-36 E-35 /S ,Redmt 0-e, of ignilion Sources Dierrtei Lne MPU E Pad Expansion Drawing Not To Scale Diverter Line May Be Oriented Different On Location Pace 12 n Hilcorp 11.0 Drill 12-1/4" Hole Section Milne Point Unit E-39 SB Injector Drilling Procedure 11.1 P/U 12-1/4" directional drilling assembly: • 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 for wireline gyro • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Drill string will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 11.2 5" Drill string, HWDP, and Jars will come from Weatherford. 11.3 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 11.4 Drill 12-1/4" hole section to section TD, in the Schrader OB sand. 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. • 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. • 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 400-600 gpm. Monitor shakers closely to ensure shaker screens and return lines can handle the flow rate. • Ensure to not out drill hole cleaning capacity, perform clean up cycles or reduce ROP if packoffs, increase in pump pressure or changes in hookload are seen • Slow in/out of slips and while tripping to keep swab and surge pressures low • Ensure shakers are functioning properly. Check for holes in screens on connections. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of pea gravel, clay balling or packing off. • Adjust MW and viscosity as necessary to maintain hole stability, ensure MW is at a 9.2 minimum at TD (pending MW increase due to hydrates). • Perform wireline gyros until clean MWD surveys are seen. Take MWD surveys every stand drilled. J • Gas hydrates have been encountered on E -Pad, typically around 2100-2400' TVD (fust below permafrost). Be prepared for hydrates: Page 13 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Eoeg P=y • Gas hydrates can be identified by the gas detector and a decrease in MW or ECD • Monitor returns for hydrates, checking pressurized & non -pressurized scales • Do not stop to circulate out gas hydrates — this will only exacerbate the problem by washing out additional permafrost. Attempt to control drill (150 fph MAX) through the zone completely and efficiently to mitigate the hydrate issue. Flowrates can also be reduced to prevent mud from belching over the bell nipple. Consider adding Lecithin to allow the gas to break out. Gas hydrates are not a gas sand, once a hydrate is disturbed the gas will come out of the well. MW will not control gas hydrates, but will affect how gas breaks out at surface. 11.5 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite or spike fluid 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 and TD wrm 9.z+ ppg. Depth Interval MW Surface — Base Permafrost 8.9+ Base Permafrost - TD 9.0-9.2 (Increase if needed) IN • PVT System: MD Toteo 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, and mud loggers 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 — 9.8 ppg Pre -Hydrated Aquagel/freshwater spud mud Page 14 H Hill= ProDertles: Milne Point Unit E-39 SB Injector Drilling Procedure Section Density Viscosity Plastic Viscosity Yield Point AN FL pH Tem Surface 8.8-9.8 75-175 20-40 25-45 <10 8.5-9.0 if required for <10 FL 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 11.6 At TD; PU 2-3 stands off bottom, CBU, pump tandem sweeps and drop viscosity. 11.7 RIH t/ bottom, proceed to BROOH t/ HWDP • Pump at full drill rate (400-600 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. 11.8 TOOH and LD BHA 11.9 No open hole logging program planned. Page 15 Milne Point Unit E-39 SB Injector Hilcor Drilling Procedure 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment (CRT & Tongs) • Ensure 9-5/8" TXP x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • 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 8.75" 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. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking 120' shoe track assemhfv rnnQiQtina nf- 9-5/8" Float Shoe 1 joint — 9-5/8" DWC, 2 Centralizers 10' from each end w/ stop rings 1 joint — 9-5/8" DWC, I Centralizer mid joint w/ stop ring 9-5/8" Float Collar w/ Stage Cementer Bypass Baffle 'Top Hat' 1 joint — 9-5/8" DWC, 1 Centralizer mid joint with stop ring 9-5/8" HES Baffle Adaptor l~nsure bypass battle is correctly installed on top of float collar. This end up. Bypass Baffle CD • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. Page 16 Milne Point Unit E-39 SB Injector Hilco�T Drilling Procedure sure 12.5 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-0ff Baffle ID Depth Float Collar Depth Float Shoe Depth Hole TD "Reference Casing Sales Manual Sac .5 Page 17 "A Rikorp fill Running Order Part No. Overall Length B 510rt OR Plug Alin, ID Ager Dnllout C OD Maa. Tool OD D OD l r Openicg Seat ID E Shut-off Plug closing Seat ID Plug Set Rikorp fill Running Order Part No. ES41 Cementer SO No. 510rt OR Plug Closing Plug OD Opening Plug OD l r OD t Shut-off Plug OD Bypass Plug (if used) OD Rikorp fill Running Order ES41 Cementer RJ 510rt OR Plug Baffle Adapter By -Pass Plug l r t By Pass Bathe float When Elust Sime Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure L.� tLT 12.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. Centralization: • 1 centralizer every Joint t/ — 1000' MD from shoe • 1 centralizer every 2 joints to —2,000' above shoe (Top of Uanu) • Ensure there are no centralizers on 2 joints (minimum) above or below planned window depth of 7750' MD • Confirm formation depths and window depth after well is drilled to see if this needs adjusting from plan • Verify depth of lowest Ugnu water sand for isolation with Geologist 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 cement returns to surface. 12.7 Install the Halliburton Type H ES -Il Stage tool so that it is positioned at least 100' TVD below the permafrost (— 2,500' MD). • Install centralizers over couplings on 5 joints below and 5 joints above stage tool. • Do not place tongs on ES cementer, this can cause damaged to the tool. • Ensure tool is pinned with 6 opening shear pins. This will allow the tool to open at 3300 psi. 9-5/81140# L-80 TXP Make Up Torques: Casing OD Minimum Optimum Maximum 9-5/8" 18,860 ft -lbs 20,961) ft -lbs 23,060 ft -lbs Page 18 Milne Point Unit E-39 SB Injector Hilc E �2,Torp Drilling Procedure TXPO BTC Outside Diameter 9.625 si Mia Wall 87.5% ("1 Grade Leo Correotm 00 Makeup Loss Thickness Coupfing Length Thn mads per in Type 1 Connecdan ID Con ... don OD Colon 8,823 in. REGULAR Cannecfion 00 REGULAR WallThickness 0.3951n. Option COUPLING Body Red Grade L80 Type V Dnff API SLMard Is; Band! : Broom 2M B3nd: - Type Casing 31d Band. - PIPEBODYDATA GEOMETRY Nominal GD 9.625 in. Wrrinal Weight 40ItUlt Oda Nominal ID 8.935 in. Via9Thiceness 0.395 n. lawn End Might 00 T hear. API Page 19 1110812018 son PIPE 900Y 1st Band: Red 2nd BaM: Brown 3rd Band: - 4y Sand: - 9 679 in 38,57 lbstt PERFORMANCE Body Yda Sragh 916 X10001bs IrmmalYeld 5750 psi Sh1Ys 80000 psi Cooapsa 3090 psi GEOMETRY Correotm 00 Makeup Loss 10.625 in. 4.891 in. Coupfing Length Thn mads per in 10.825m 5 Connecdan ID Con ... don OD Colon 8,823 in. REGULAR PERFORMANCE Teraion Elrviencd 100.0% him Y#ldShas lh 916 000 x1000 Interval Pressure Capacny In 5750.000 psi Ihs compression Efrciencg 100?: Compression Strang, 916.000x1000 Ida..Alla.bleSending Wl ioOa the Eaemal Pms.re Capacity 3090.W0 ps: MAKE-UP TORQUES Mmm.ro 18860 ft -±e. cptimum 28980fHbs Nizamum 23068 ft4bs OPERATION LIMIT TORQUES Operawq Tar ire- 35600 a as Yield Torque 43400 84os Notes This connection is fulry interchangeable With' TXP® BTC - 9.625 in. - 36143.5147153.51 58.4 lbslR 11] Intemal Pressure Capacity related to structural resistance only. Internal pressure leak resistance as per section 10.3 API 5031 ISO 10400 - 2007. Oatasheet is also valid for Special Bevel option when applicable - except for Coupling Face Load, Which will be reduced. Please contact a local Tanans technical sales representative. H Hilcorp Ev -a Milne Point Unit E-39 SB Injector Drilling Procedure 12.8 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use BOL 2000 thread compound. Dope pin end only w/ paint brush. • Centralization: o 1 centralizer every 2 joints to base of conductor 12.9 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.10 Slow in and out of slips. 12.11 P/U landing joint and M/U to casing string. Position the casing shoe +/- 10' from TD. Strap the landing joint prior to the casing job and mark the joint at (1) ft intervals to use as a reference when getting the casing on depth. 12.12 Lower casing to setting depth. Confirm measurements. 12.13 Have slips staged in cellar, along with necessary equipment for the operation. 12.14 Circulate and condition mud through CRT. Reduce YP to < 20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. If possible reciprocate casing string while conditioning mud. Page 20 H Hilcorp Enugy Cumpmy 13.0 Cement 9-5/8" Surface Casing Milne Point Unit E-39 SB Injector Drilling Procedure 13.1 Hold a pre job safety meeting over the upcoming cement 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 cementing unit at acceptable rates. • How to handle cement returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pumps 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 cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 13.2 Document efficiency of all possible displacement pumps prior to cement job. 13.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 13.4 RILJ cement line (if not already done so). Company Rep to witness loading of the top and bottom plugs to ensure done in correct order. 13.5 Fill surface cement lines with water and pressure test. 13.6 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.7 Drop bottom plug (flexible bypass plug) — HEC rep to witness. Mix and pump cement per below calculations for the 1St stage, confirm actual cement volumes with cementer after TD is reached. 13.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead & tail, TOC brought to stage tool. Estimated 1' Stage Total Cement Volume: Page 21 Section Calculation Vol (bbl) Vol (ft3) � 12-1/4" OH x 9-5/8" (7,950'- 2500') x .0558 bpf x 1.3 = 395.3 2219.6 a9 Casing J Total Lead 395.3 2219.6 12-1/4" OH x 9-5/8" (8,950'- 7,950') x.0558 bpf x 1.3 = 72.5 407 Casing 9-5/8" Shoe Track 120' x .0758 bpf = 9.1 51.09 Total Tail 1 81.6 458 Page 21 n Hilcorp ft B CnmPmY Milne Point Unit E-39 SB Injector Drilling Procedure Cement Slurry Design (V Stage Cement Job): 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 8,830' x .0758 bpf = 669.3 bbls 80 bbls of tuned spacer to be left behind stage tool. With Tuned spacer ahead of lead and across stage tool, we have seen reduction in clabbered up mud/interface while CBU through the open stage tool. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 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. Page 22 Lead Slurry Tail Slurry System ExtendaCEM'"'System SwiftCEM'"System Density 11.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed Water 21.13 gal/sk 5.04 gal/sk 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets "sticky", cease pipe reciprocation and continue with the cement job. 13.9 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits, spotting water across the HEC stage cementer. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, HEC Rep and HES Cementers during the entire job. 13.10 Ensure rig pump is used to displace cement. Displacement calculations have proven to be very accurate using 0.0625 bps (5" liners) for the Quattro pump output. To operate the stage tool hydraulically, the plug must be bumped. 13.11 Displacement calculation: 8,830' x .0758 bpf = 669.3 bbls 80 bbls of tuned spacer to be left behind stage tool. With Tuned spacer ahead of lead and across stage tool, we have seen reduction in clabbered up mud/interface while CBU through the open stage tool. 13.12 Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. Be prepared to pump out fluid from cellar. Have black water available to contaminate any cement seen at surface. 13.13 If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 50% of shoe track volume, t4.5 bbls before consulting with Drilling Engineer. 13.14 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. Page 22 Milne Point Unit E-39 SB Injector Hilcor Drilling Procedure 13.15 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, this is to ensure the stage tool is not prematurely opened. 13.16 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 and volume pumped to see the returns. Circulate until YP < 20 again in preparation for the 2nd stage of the cement job. 13.17 Be prepared for cement returns to surface. Dump cement returns in the cellar or open the shaker bypass line to the cuttings tank. Have black water available and vac trucks ready to assist. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. Page 23 Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: Section Milne Point Unit Vol (bbl) Vol (ft3) v E-39 SB Injector (110') x .26 bpf x 1= H�ilc Drilling Procedure Second Stage Surface Cement Job: 13.18 Prepare for the 2nd stage as necessary. Circulate until first stage reaches sufficient compressive strength. Hold pre job safety meeting. 13.19 HEC representative to witness the loading of the ES cementer closing plug in the cementing head. 13.20 Fill surface lines with water and pressure test. 13.21 Pump remaining 60 bbls 10.5 ppg tuned spacer. 13.22 Mix and pump cmt per below recipe for the 2nd stage. 13.23 Cement volume based on annular volume + open hole excess (200% for lead and 100% for tail). Job will consist of lead & tail, TOC brought to surface. However cement will continue to be pumped until clean spacer is observed at surface. Estimated 2"d Stage Total Cement Volume: Cement Slurry Design (2nd stage cement job): Section Calculation Vol (bbl) Vol (ft3) v 20" Conductorx 9-5/8" Casing (110') x .26 bpf x 1= 28.6 161 a 12-1/4" OH x 9-5/8" Casing (2000'- 110') x .0558 bpf x 3 = 316.4 1776.3 5.08 gal/sk Total Lead 345 1937 m 12-1/4" OH x 9-5 8" Casin (2500'- 2000') x .0558 bpf x 2 = 55.8 314 ~ Total Tail 55.8 314 Cement Slurry Design (2nd stage cement job): Page 24 Lead Slurry Tail Slurry System Permafrost L SwiftCEM Tm System (Hal Cem) Density 10.7 lb/gal 15.8 lb/gal Yield 4.3279 ft3/sk 1.16 ft3/sk Mixed Water 21.405 gal/sk 5.08 gal/sk Page 24 Milne Point Unit E-39 SB Injector Hilo Drilling Procedure 13.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 13.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 13.26 Displacement calculation: 2500' x.0758 bpf = 190 bbls mud 13.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Wellhead side outlet valve in cellar can be opened to take returns to cellar if required. Be prepared to pump out fluid from cellar. Have black water available to retard setting of cement. 13.28 Decide ahead of time what will be done with cement returns once they are at surface. We should circulate approximately 100 - 150 bbls of cement slurry to surface. 13.29 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. Slips will be set as per plan to allow full annulus for returns during surface cement job. Set slips 13.30 Make initial cut on 9-5/8" final joint. L/D cut joint. Make final cut on 9-5/8". Dress off stump. Install 9-5/8" wellhead. If transition nipple is welded on, allow to cool as per schedule. 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 jenzet@hilcorp.com and cdingerQhilcorn com This will be included with the EOW documentation that goes to the AOGCC Page 25 Milne Point Unit E-39 SB Injector Hilo Drilling Procedure 14.0 BOP N/U and Test 14.1 N/D the diverter T, 16" knife gate, 16" diverter line & N/U 11" x 13-5/8" 5M casing spool. 14.2 N/U 13-5/8" x 5M CTI 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" x 5M single gate • Double gate ram should be dressed with 2-7/8" x 5.5" VBRs in top cavity, blind ram in bottom cavity. • Single ram should be dressed with 2-7/8" x 5.5" VBRs or 5" Solid Body Rams • N/U bell nipple, install flowline. • Install (1) manual valve & HCR valve on kill side of mud cross. (Manual valve closest to mud cross). • Install (1) manual valve & HCR valve on choke side of mud cross. (manual valve closest to mud cross) 14.3 Run 5" BOP 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 monitor side outlet valves and annulus valve pressure gauges to ensure no pressure is trapped underneath test plug • Once BOPE test is complete, send a copy of the test report to town engineer and drilling tech 14.4 R/D BOP test equipment 14.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 14.7 Set wearbushing in wellhead. 14.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 14.9 Ensure 5" liners in mud pumps. Page 26 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp 15.0 Drill 8-1/2" Hole Section 15.1 M/U 8.5" Cleanout BHA (Milltooth Bit & 1.220 PDM) 15.2 TIH w/ 8-1/2" cleanout BHA to stage tool. Note depth TOC tagged on AM report. Drill out stage tool. 15.3 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.4 R/U and test casing to 2500 psi / 30 min. Ensure to record volume / pressure and plot on FIT grap . A reg is o o burst =687 / 2 =-3500 psi, but max test pressure on the well is 2,500 psi as per AOGCC. Document incremental volume pumped (and subsequent pressure) and volume returned. Ensure rams are used to test casing as per AOGCC Industry Guidance Bulletin 17-001. 15.5 Drill out shoe track and 20' of new formation. 15.6 CBU and condition mud for FIT. 15.7 Conduct FIT to 12 ppg EMW. Chart Test. Ensure test is recorded on same chart as FIT. Document incremental volume pumped (and subsequent pressure) and volume returned. �� V' ` + L €` TAT 2, 15.8 POOH & LD Cleanout BHA 15.9 PIU 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 TF offset is measured accurately and entered correctly into the MWD software. • 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. • Drill string will be 5" 19.54 5-135 DS50 & NC50. • Run a ported float in the production hole section. 15.10 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. Page 27 Milne Point unit E-39 SB Injector Drilling Procedure Hilcorp E -w C22- • 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 viscosifrer concentrations can decrease return permeability. Do not pump high vis sweeps, instead use tandem sweeps. Ensure 6 rpm is > 8.5 (hole diameter) for sufficient hole cleaning • 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: 8.9-9.5 ppg Baradrill-N drilling fluid Properties: Section lenityPlastic Viscosit 15:41 11111111 Total Solids I T NPHT Production 8.9-9.5 15-25 20-25 <10% <7 <11.0 System Formulation: Baradrill-N Page 28 f:71ly�ss = 8.5 Mt✓E �' 3:7T✓D5 Product ration Water l KCL KOH 7ppb N -VIS ppb DEXTRID LT BARACARB5 pp BARACARB 25 4 ppb BARACARB 50 2 ppb BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 p2b Milne Point Unit E-39 SB Injector Drilling Procedure H rp Cww 15.11 TIH with 8-1/2" directional assembly to bottom 15.12 Displace wellbore to 8.9 ppg Baradrill-N drilling fluid 15.13 Begin drilling 8.5" hole section, 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 tpms, monitoring stick slip and BHA vibrations • 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. If stick slip continues, consider adding .5% lubes 15.14 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Flow Rate: 350-550 gpm, target min. AV's 200 ft/min, 385 gpm • RPM: 120+ • 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. • Keep pipe movement with pumps off to slow speeds, to keep surge and swab pressures low • Take MWD surveys every stand, can be taken more frequently if deemed necessary, ex: concretion deflection • Monitor Torque and Drag with pumps on every 5 stands • Monitor ECD, pump pressure & hookload trends for hole cleaning indication • 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. • Limit maximum instantaneous ROP to < 250 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. • Target ROP is as fast as we can clean the hole without having to backream connections • Schrader Bluff NB Concretions: Historically 4-6% of lateral • MPD will be used to monitor for abnormal pressure on connections 15.15 Reference: 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. • 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 fl, 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. 15.16 At TD, CBU at least 4 times at 200 ft/min AV (385+ gpm) and rotation (120+ rpm). Pump tandem sweeps if needed • Monitor BU for increase in cuttings, cuttings in laterals come back in waves and not a consistent stream, circulate more if necessary Page 29 Milne Point Unit E-39 56 Injector Micorp Emory Drilling Procedure Comp�oY Ensure mud has necessary lube % for running liner If seepage losses are seen while drilling, consider reducing MW at TD to 9.Oppg minimum 15.17 BROOH with the drilling assembly to the 9-5/8" casing shoe • Circulate at full drill rate (385 gpm max). • 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 15.18 If abnormal pressure has been observed in the lateral, utilize MPD to close on connections while BROOH 15.19 CBU minimum two times at 9-5/8" shoe and clean casing with high vis sweeps. 15.20 Monitor well for flow. Increase mud weight if necessary. If abnormal pressure has been seen, displace to higher MW (determined on closed connections) from surface shoe to surface. Wellbore breathing has been seen on past MPU SB wells. Perform extended flow checks to determine if well is breathing, treat all flow as an influx until proven otherwise 15.21 POOH and LD BHA. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. 15.22 Continue to POH and stand back BHA if possible. Rabbit DP on TOH, ensure rabbit diameter is sufficient for future ball drops. Only LWD open hole logs are planned for the hole section (GR + Res). There will not be any additional logging runs conducted. Page 30 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure .. �rp 1.6.0 Run 4-1/2" Injection Liner 16.1. Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" liner with ICD and swell packers, the following well control response procedure will be followed: • With ICD across the BOP: P/U & M/U the 5" safety joint (with 4-1/2" crossover installed on bottom, TIW valve in open position on top, 4-1/2" handling joint above TIW). This joint shall be fully M/U and available prior to running the first joint of 4-1/2" liner. • With 4-1/2" solid joint across BOP: Slack off and position the 4-1/2" solid joint to MU the TIW valve. Shut in ram or annular on 4-1/2" solid joint. Close TIW valve. 16.2. Confirm VBR have been tested on 3-1/2" and 5" test joints to 250 psi low/3000 psi high. 16.3. In the event of an influx of formation fluids while running the 2-3/8" inner string inside the 4- 1/2" liner: • P/U & M/U the 5" safety joint (with 4-1/2" x 2-3/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-3/8" handling joint above TIW). M/U 2-3/8" and then 4-1/2" to triple connect. • This joint shall be fully M/U with crossovers and available prior to running the first joint • Slack off and position the 5" DP across the BOP, shut in ram or annular on 5" DP. Close TIW valve. Proceed with well kill operations. 16.4. R/U 4-1/2" liner running equipment. • Ensure 4-1/2" Hydril 625 x DS -50 crossover is on rig floor and M/U to FOSV. • Ensure the liner 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. 16.5. Run 4-1/2" injection liner. • Use API Modified or "Best O Life 2000 AG" thread compound. Dope pin end only w/ paint brush. Wipe off excess. Thread compound can plug the ICDs. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Use lift nubbins and stabbing guides for the liner run. • Fill 4-'/2" liner with PST passed mud (to keep from plugging ICDs with solids) • Install ICDs and swell packers as per the Running Order (Estimate 8 evenly spaced, Operations Engineer to provide confirmation of set depths). • Do not place tongs or slips on swell packer elements or ICDs. • ICD and swell packer placement ±40' • The ICD connection is 4-1/2" 13.54 Hydril 625 • Remove protective packaging on swell packers just prior to picking up • If liner length exceeds surface casing length, ensure centralizers are placed 1/jt for each joint outside of the surface shoe. This is to mitigate difference sticking risk while running inner string. Page 31 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure CrmryoY • Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10 and 20 rpm 4-1/2" 13.5# L-80 Hydril 625 Casing OD Minimum [ Optimum Maximum � Operating Torclue Yield Torque 4.5" 8,000 ft -lbs 9,600 ft -lbs 12,800 ft -lbs 15,000 ft -lbs Page 32 For the latest perfonance data. always visit our website: www.tenarts.com Wedge 625® Milne Point Unit E-39 SB Injector Drilling Procedure 12ro412017 Outside Diameter 4.500 n. Min. Wall 07.5% GEOMETRY Thkknees t9 Grade LM 41111111W Nominal CD 4300 In, Narina weig¢ 1330 tos+0 Type 1 3]95 in. Wall Thickness 0290 u. Cmmema n GD REGUI IUR Ran End We1gM 13ffibs+R NTdsance NPI Option COUPLING PIPE BODY PERFORMANCE Body: Red I Bane: Red Grade L00 Type i Drill NPI Standard 151 Band: Brown ad Band' Collapse I1540pa ad Band:- aroam CONNECTION DATA Type casing ad Band:- 3n1Rand: - GEOMETRY 4M Band: - PIPE BODY DATA GEOMETRY Nominal CD 4300 In, Narina weig¢ 1330 tos+0 DM! 3]95 in. Nominal ID 3920 m. Wal nielmes 0290 In. Ran End We1gM 13ffibs+R NTdsance NPI PERFORMANCE eptly Yield 56angN 30TAODOlbs nlema Yeid 9020 psi SMYS mDDO,i Collapse I1540pa CONNECTION DATA GEOMETRY CommotonoD 4.714 v. Comeeala"i lD 39d9 n. Makeup Loss aam.. Threads Perm 159 Cimemean OD op9m REGUI Vt PERFORMANCE Temm Efficiency 91.0% Joint Yekl S englh 279.370 x1000 Intima Presw2 Caaaory 9020 ON Psi lbs Compena. Efteny 943% Compression Sm,,J, 290.115x1000 Mez.A9wrable Bering 73.7'lix't lbs External Pressure Capacity 95m900 psi MAKE-UP TORQUES Minnum III'l optiman 9600 fta Mar. 12M 14ba OPERATION LIMN TORQUES operamgTaque 12000 Nei Y2M Taque 15000Rabs Notes For further information on concepts indicated in this datasheet, download the Datasheet Manual from W W WAM31IIs.com 16.6. Ensure that the liner top packer is set— 150' MD above the 9-5/8" shoe. • AOGCC regulations require a minimum 100' overlap between the inner and outer strings as per 20 AAC 25.030(d)(6). Ensure hanger/packer will not be set in a 9-5/8" connection. 16.7. RAJ false rotary and run 2-3/8" 4.7 #/ft inner string. Page 33 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Enema C Hwy 16.8. Before picking up Baker SLZXP liner hanger / packer assy, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 16.9. M/LJ Baker SLZXP liner top packer to inner string and 4-1/2" liner. 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. 16.10. Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 16.11. RIH w/ liner on DP no faster than 30 ft/min — this is to prevent buckling the liner and drill string. Watch displacement carefully and avoid surging the hole or buckling the liner. Slow down running speed if necessary. 16.12. The liner and inner string will prevent the DP from auto filling. Fill DP every 5 stands, more frequently if SOW trend indicates. 16.13. 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. 16.14. If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. A� 16.15. TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 16.16. Rig up to pump down the work string with the rig pumps. 16.17. 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. 16.18. Rig up to pump down the work string with the rig pumps. 16.19. Break circulation and begin displacing wellbore to --9.2 ppg KCl/NaCl (adjust brine weight if needed). Note the large OD on the ICDs. Begin circulating at —1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 16.20. Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the ICDs. Note all losses. Catch mud for future use if feasible. 16.21. Monitor the returned fluids carefully and when no more filter cake appears at the shaker begin pumping SAPP pill. 16.22. Mix and pump 3 tandem 40 bbl 10 ppb SAPP pills (120 bbl total SAPP pill) with 100 bbl in between. Keep circulation rate low to keep from packing off around the ICDs. Monitor shakers for returns of mud filter cake and calcium carbonate. Circulate the well clean. Page 34 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Eon®' Campvy 16.23. Repeat pumping SAPP pills as needed until the wellbore is clean. Losses during the cleanup of the wellbore are a good indication that the mud filter cake is being removed, including an increase in the loss rate. Monitor the returned fluids to ensure as much mud and wall cake has been removed from the wellbore as possible so as to not impact wellbore injectivity. 16.24. Displace 1.5 OH & Liner volumes. 16.25. Shut down pumps. 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. Pressure up to 1,500 psi to shift the wellbore isolation valve closed. 16.26. Continue pressuring up to 2700 psi to set the SLZXP liner hanger/packer. Hold for 5 minutes. Slack off 20K lbs on the ZXP to ensure the 11KIDE setting tool is in compression for release from the SLZXP liner hanger/packer. Continue pressuring up 4100 psi to neutralize and release running tools. 16.27. Bleed DP pressure to zero, Pick up to expose Rotating Dog Sub and set down 50k# without pulling sleeve packoff. Contingency (if suspected not released from running tool) - Pick back up without pulling sleeve packoff, begin rotating at 10-20 rpm and set down 50k# again. 16.28. PU to neutral weight, close BOP and test annulus to 1500 psi for 10 min and chart record same. 16.29. Bleed off pressure and open BOPE. Pickup to verify that the HRD setting tool has released. If packer did not test, rotating dog sub can be used to set packer. If running tool cannot be hydraulically released, apply LH torque to mechanically release the setting tool. 16.30. Displace 2-3/8" x Liner, pump 2 circulations. 16.31. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. Rack back enough 5" drill pipe for liner top clean outrun 16.32. Make up 3.5" wash tool & RIH on 5" DP to 4.5" liner top. 16.33. Flush liner top at max rate while displacing out well to clean brine. 16.34. POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. L/D 2-3/8" inner string. 17.0 End of E-39 Operations / Begin E -39L1 Operations (Separate PTD) Page 35 Milne Point Unit E-39 SB Injector Drilling Procedure Hilc=2. 18.0 Innovation Rig Diverter Schematic 3-118' Itiu Line 13-518' SM Technology Sip 13.518 Page 36 ntrol Technology -51F 5M Conhol Onology Double Ram 1/8' Choke Line X16' Dnder Line Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure �M- 19.0 Innovation Rig BOP Schematic 3-1/8" Kill 9-5/8" DBL D Casing 13-5/8" NOM 9-5/8" BTC Btm x 10.5" A SA Pin Top W/ Primary Seal Page 37 L 13-5/8" 5M Control Technology Annular BOP —13-5/8" 5M Control Technology Double Ram �-3-1/8" Choke Line `--13-5/8" 5M Control Technology Single Ram -5/8" x 5M 11" x 5M 2-1/16"x 5M x 5 `2-1/16" x 5M -20" Casing 9-5/8" Casing Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Eva® Cmnpmy 20.0 Wellhead Schematic Nero D�w•imui vrfexaumezafiectM on Ni: dramny ax ntimaud Page 38 V H Hilm 21.0 Days Vs Depth 0 2000 I s v MPU E-39 SB Dual Lat OA/OB Injector ' OB Lat Days vs Depth 12000 14000 I Page 39 Milne Point Unit E-39 SB Injector Drilling Procedure 1/OB 0 5 10 15 20 25 30 Days 22.0 Formation Tops & Information Mi=Procedure E-3 Drill MPU E-39 Formations (wp07) MD (ft) (ft) TVDssP4201 Formation Pressure (psi) EMW (ppg) Base Permafrost 1962 1729 781.88 8.46 LA3 6588 3677 1639 8.46 Schrader Bluff NA 7770 4153 1848.44 8.46 Schrader Bluff OA 8040 4258 1894.64 8.46 Schrader Bluff OB 8210 4312 4360 1918.4 8.46 Page 40 Milne Point Unit E-39 S8 Injector Hilc o27orp Drilling Procedure Page 41 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp MCmpnY 23.0 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 Gas hydrates have been seen on E Pad. Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates, but can help control the breakout at surface. 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 Lecithin 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 wells in close proximity. 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 between 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: J Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. Page 42 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp 1. The AOGCC will be notified within 24 hours if H2S 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 H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Page 43 Milne Point Unit E-39 SB Injector Drilling Procedure Hilco22rp M 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 > 300 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 H2S events have been documented on drill wells on this 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 H2S is detected, wellwork will be suspended and personnel evacuated until a detailed mitigation procedure can be developed. Abnormal Pressures and Temperatures: Abnormal pressure has been seen on E -Pad. Utilize MPD to mitigate any abnormal pressure seen. Anti -Collision There are no wells with a clearance factor <1.0 on this lateral. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor drilling parameters for signs of magnetic interference with another well. Page 44 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure Em® Comy y 24.0 Innovation Rig Layout Page 45 n Hilc Ew ,2m rp 25.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: Milne Point Unit E-39 SB Injector Drilling Procedure 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. Ensure that casing test and subsequent FIT tests are recorded on the same chart. Document incremental volume pumped and returned during test. Page 46 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure =T - 26.0 Innovation Rig Choke Manifold Schematic Page 47 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp Ercgy Cnmgny 27.0 Casing Design 14 Calculation & Casing Design Factors E21= DATE: 6127/2019 WELL: MPU E-39 DESIGN BY: Joe Engel Hole Size 12-1/4" Hole Size Hole Size Drilling Mode MASP: MASP: Criteria: Mud Density: 9.2 ppg Mud Density: 9.2 ppg Mud Density: 1475 psi (see attached MASP determination & calculation) Production Mode MASP: 1475 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress Page 48 Casin Secflon Calculation/specification ecification 1 2 3 4 Casino OD 95/8" 4-1/2" Top (MD) 0 7,750 Top (TVD) 0 4,211 Bottom (MD) 8,9`50 11.949 Bottom (TVD) 4,337 4,222 Length 81,950 41199 Weight (ppf) 40 13.5 Grade L-80 L-80 Connection Tom' H825 Weight w/o Bouyancy Factor (Ibs) 358,000 56,687 Tension at Top of Section (Ibs) 358,000 56,687 Min strengthTension 1000 Ibs) 916 279 Worst Case Safety Factor (Tension) 2.56 4.92 Collaps Pressure at bottom (Psi) 2,142 2,086 Ce Resistance w/o tension (Psi) ollapse 3,090 8,540 Worst Case Safety Factor (Collapse 1.44 4.09 MASP (psi) 1,475 1,475 Minimum Yield (psi) 5,750 9,020 Worst case safet factor (Burst) 3.90 6.12 Page 48 Milne Point Unit E-39 SB Injector Drilling Procedure Hilcorp Ewp CmpnY 28.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 14 8-1/2" Hole Section Hi rp MPU E-39 Milne Point Unit MD TVD Planned Top: 8950 4337 Planned TD: 16181 4189 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SchraderBluff OBSand 4,337 1908 1 Oil 8.46 0.440 Offset Well Mud Densities Well MW range Top (TVD) Bottom (ND) Date MPU E-24 9.1-9.3 Surface 4208 2001 MPU E-42 9.1 Surface 4355 2019 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: 4,337 (ft) x 0.78(psi/ft)= 3383 3383(psi) - [0.1(psi/ft)*4337(ft))= 2949psi MASP from pore pressure (complete evacuation of wellbore to gas from Schrader Bluff OA sand) 4337 (ft) x 0.44(psi/ft)= 1908 psi 1908(psi)-0.1(psi/ft)*4337(ft) 1475psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of entire wellbore togas at 0.1 psi/ft. Page 49 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure .—. C22- 29.0 Spider Plot (NAD 27) (Governmental Sections) i 1 cln+ -.•_._ ___ E.XIIPB1 .a_17`e ifFF' 1 4 13a; - __ - -fro Pc_'.,' r Legends'_� � _ :- _ E ;��...- • MPU E-39i_SHL ' - - X- 1 MPC X MPU E -39i #' MPU E -39i _BHL 5x. 2: . l Other Surface Hales (SHL) • Other Bottom Holes (BHL) I ` - - - - Other Well Paths Q06 and Gas Unit BoulldarY , ♦` Pad Foo7+rin1 / `♦\ ADLo2823.1 ' 1 ;'—ADL-025519-1.1611314-ii—OC -l "h `'' '♦ U013N011E � 1 £ F_1 E -t R i t E2'RBt \: £2} ` 1 s z. l 1 E. -=e3 1 1 1 l 1 E i 1 1 _.; S.C. 35 \` • Er, Sec. 36 1 (639) 1 1 1 aL1 S9 A, PL' E-391 TPN MILNE�POINT UNIT - , / 1 i 1 plr .6 E e cresssre �sa i.._ - y H.ra } sreLs ♦ '11 ;Fet sol - 1 1 ` ♦♦�• -r le 1, n2� � • rel , 1\ Zt 5 1 $ Sec i"i r r Sec 5 Sec.1 \ . - 1 _ �{ 1 s�f577I i � / / i• Jila c ADL380105 U012N010E r ADLi380110 U012N011E/J„” s> S 1 ♦\ \ \\ 1 � J r J i J \ ♦Zz.SK.B Milne Point Unit MPE-39 Well 0 1.300 2.600 T Feet wp07 Page 50 Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure E mSlm7 30.0 Surface Plat (As Built) (NAD 27) LAiAD -M- cRm I 3■ ■6 I - 2or I r1c . L - ■ 33 C -`I■ 2 27 ■ ■ 32 '"AD a IN 31 28 ■ j I 22 ■ ■ E� 201 ■ ■ 5 THS PROJECT 3 ■ 26 ■ ■52 q ■ ■ 6 -N 25 ■ ■ 21 VICINITY MAP It ■ 117 I N.LS. 6 ■ ■ 16 ASU E -PAD 20 ■ ■ 23 24 ■ ■ IS12 I (E �F•A�9 m ■ 1 34 V. ,f,0 >*: 9 -ili E- 9E 36 � ••, E-41 E-35 ..:. ........ .. ........ � �(• nnatlry ...ut. 10200 NOTES, LEGEND AS-OULT OS TON SURVEYOR'S CERTIFICATE 1. A & VAT ft.Y,E WOMMAIES ARE ZONE 4. NAD27, I HEREBY CERTRY SHAT I AM 2 005 a LDCATM 6 H;kAIMCNIS CFP -3 AND E-1, ■ UO511NG CONDUCTGA PROPERLY RCgSTERZD AND UCINSEO 3 1A$15 0[ MEYATIM MNNE PDNT DAVM MSL TO PRACTCE LAND WRWYING IN A GEOCETC PMT06 ARE NAD27. TH VA -M OF ALASKA AND NAT 5 PID MEAN SGLLE [ALTER is, IXON H GRAPHIC SCALE THS AS -BUILT RE"ESEN75 A S Wy 3LA•2Y DAIE MAY 31. NIS IN J LY I, 2014. 0 100 208 ,DO MMC BY u[ OR UNDER MY DIRECT 7. RUV,,, E Fl 8001L NCB -02 PBS 24-29 SUPEA CIMS ANANND MAT ALL ARE NCIB-02 PDS 68-73 ( IN FEET ) CORRECT AS G 4A X 31. 20Th I Ina -200 ft LOCATED WITHIN PROTRACTED SEC 23 T 13 N R 10 E. UMIAT MERIDIAN, ALASKA • ,AGCRS -T bell P 60tANER HiknlrpAlaska 6 6 [CH MD. WE POINT, ALASKA AECOfig9 1& E -PAD, 'HELLS 36, 36, 37. 38, 39 A 41 M M ._ 2R0• CONDUCTOR AS -BUILT t M 1 Nal ase Atww Page 51 NOL COORDINATES COORDINATES PO�TION(OMS) POSITION (D.DD) BO%LELEV. OFFSETS V=6,016,133.2' N=1,829.99' 70'2775.945" 70.4544292' 21.7' 3,594'FSL 1 720' FEL E-35 X■ 569 426.37' E= 1,x50.(72" 14926'00.438" 149.4334550' Y�6,016.15fi.74' N=1,860.12' 70'27"16.178" 70.4344934' 21.7' 3,817' FSL 7,738' FEL E-� %= 569.407.52' E= 1 450.03' 74926'00.964" 749.4336067' Y=6,076,160.37 N-1 ,840.58' 70'2716.412" 70.4545389' 21-7 3,641' FSL 1 757 FEL E-37 %= 569.388.31' E= t 449.84' 149.26'01.542" 749.4337677' Y-6,076,081.06' N=1.890.22' 702715.446" 70.4542906' 21.8' 3.543'FSL 1.581' FEL E-� %: 569.265.%2* E= 1,291-58' 149'26'05.169" 149.434774] Y=6 076.057.25' N- 7,859.75' 70'27'15.210" 70.4542250' 21.7' 3.519' FSL 1.863' FEL E-39 %= 569 284.73' E= 1291,52 149'26'04.636" 149.4346211' Y�6,018.034.09' N=1,829.93' 70'2714981" 70.45x7614' 218• 3,496•F$L 1 844' FEL E-41 %� B .90' E� t 291.68' ta928'04.091" 149.4344697• Milne Point Unit E-39 SB Injector Hilcorp Drilling Procedure U 31.0 Schrader Bluff OA Sand Offset MW vs TVD Chart Schrader Bluff OA Sand Offset MW vs ND MW, ppg 8.5 8.7 8.9 9.1 9.3 9.5 9.7 9.9 10.1 10.3 10.5 0 1 11111 m 1500 2000 G 2500 Mr 3500 4000 4500 Page 52 -MPU L-46 (2015) -MPU L-47 (2015) -MPU L-48 (2015) MPU L-49 (2015) -MPU L-50 (2015) -MPU F-106 (2017) -MPU F-107 (2017) -MPU F-108 (2017) -MPU F-109 (2017) -MPU F-110 (2017) Hilcorp Alaska, Milne Point M Pt E Pad Plan: MPU E-39 MPU E -39i Plan: MPU E-39 wp07 LLC Standard Proposal Report 25 June, 2019 HALLIBURTON Sperry Drilling Services HALLIBURTON HiFpP Naska. LLC CakulCUOnwre Eno' S,atorn c,WS,, scan Me.w Cloacal A aam 3D E- S.... P. Curve Wandn9 McMod: Eno, Relu SECTION DETAILSSao MD ( _ Axl WD tNI-S +EI -W DIa9 TFPCe V6ed Ta't 1 28.50 -U0 0.00 26.50 0.00 POP Or(P) D.w 0.00 2 280.00 GAO 0.00 300.00 0.00 o0O GOD ON 9.00 3 550.00 610 22000S19-111 -14,60 -12.25 3.00 22D.00 1684 4 196250 6372 19008 1655.24 -1516 -202.44 400 -32.35 799.71 5 7492.33 63.44 190.08 4128.22 -5645.72 4080.18 0.00 0.00 574506 6 7584.04 67.00 19085 4166.44 -5]2].13 -1083.20 400 12.69 5828.66 7 793404 67.00 190,95 4303.20 -6043.44 -1144.48 0 00 000 8150.04 E-39 wp06 DA TOP 8 0532.53 96 78 193.97 430671 -651530 -1 P1.44 SOO 6.02 673638 9 899394 96.78 193.97 4332.25 -7059.93 -1312.16 ODD D00 719389 10 9100.90 9250 19380 4323.60 -7163.48 -1407.65 4.00 -177.72 7300.40 11 10600.90 92.50 193.80 4250.17 48618]9 -1765.11 0.00 0.00 8797.00 E-39 wP06 CP1 12 108228991.64 193.80 4257.34 -864006 -197034 30O 179.98 881887 13 1131430 91.84 19300 4233.11 -9311.16 -1935.18 0.00 0.00 9509.01 14 11332.39 9130 193.80 423481 -9328]2 -1939.49 3.00 -17997 9527.07 15 119323991.30 193.80 422100 -9911.25 -2002.57 ODD 000 1D126.12 E-39 w106 CP2 i6 12514.89 00.39 205.06 4222.58-10459.50 -2276.11 2.00 1D4.43 10701.11 1] 13135.1] 88.39 20500 4240.00 -11021.16 -2530.96 0.00 0.00 11302.14 E" wpO6 CPS 18 13724E 1 91.96 18476 423810 -11507.55 -2689,91 3.50 -0011 11686.03 19 13905.41 8196 184.76 423200.11787.72 -10492 OOO 000 12066,60 E-39 WIM CP4 20 14002.63 94.05 179.52 422].35 41944.69 -2711.54 3.00 -9980 12241.65 21 16176.59 91.05 179.52 418900-14030.23 -2694.12 0.90 000 14294.41 22 1618169 9090 179.52 4189OD-14043,13 -260408 9.00 -178.]] 1429922 E-39 WPG4 Tae Pepin MoPa oa ox Nprw,nvn nM . 0 UO E.Nv[OT OaPU ESI/ LM �'M'-nCJMOmller atop f350W ."aauy7...13MWMIRR-MSISIR a95p,W 181¢1 OB FPI/Ed9u9n.7/0606/ E.IDII ? MNU�IFR2•M6r5vp D � SMn D'c3°I1W :250'720, 280'060 61an Dird'/ILO':550'M1O,5481'IY9 500 ' 10 6p0 End Ort :15625 MD. 1655U'ND SVS na-.. 10 svi to s CooMnale (0615) Relennw: Wetl Plan '"IE Tue NOM Project: Milne Point Site: MPtEPad Well: Plan: MPU 639 Wellbore: MPU E-391 Design: MPU E39 wp07 HiFpP Naska. LLC CakulCUOnwre Eno' S,atorn c,WS,, scan Me.w Cloacal A aam 3D E- S.... P. Curve Wandn9 McMod: Eno, Relu SECTION DETAILSSao MD ( _ Axl WD tNI-S +EI -W DIa9 TFPCe V6ed Ta't 1 28.50 -U0 0.00 26.50 0.00 POP Or(P) D.w 0.00 2 280.00 GAO 0.00 300.00 0.00 o0O GOD ON 9.00 3 550.00 610 22000S19-111 -14,60 -12.25 3.00 22D.00 1684 4 196250 6372 19008 1655.24 -1516 -202.44 400 -32.35 799.71 5 7492.33 63.44 190.08 4128.22 -5645.72 4080.18 0.00 0.00 574506 6 7584.04 67.00 19085 4166.44 -5]2].13 -1083.20 400 12.69 5828.66 7 793404 67.00 190,95 4303.20 -6043.44 -1144.48 0 00 000 8150.04 E-39 wp06 DA TOP 8 0532.53 96 78 193.97 430671 -651530 -1 P1.44 SOO 6.02 673638 9 899394 96.78 193.97 4332.25 -7059.93 -1312.16 ODD D00 719389 10 9100.90 9250 19380 4323.60 -7163.48 -1407.65 4.00 -177.72 7300.40 11 10600.90 92.50 193.80 4250.17 48618]9 -1765.11 0.00 0.00 8797.00 E-39 wP06 CP1 12 108228991.64 193.80 4257.34 -864006 -197034 30O 179.98 881887 13 1131430 91.84 19300 4233.11 -9311.16 -1935.18 0.00 0.00 9509.01 14 11332.39 9130 193.80 423481 -9328]2 -1939.49 3.00 -17997 9527.07 15 119323991.30 193.80 422100 -9911.25 -2002.57 ODD 000 1D126.12 E-39 w106 CP2 i6 12514.89 00.39 205.06 4222.58-10459.50 -2276.11 2.00 1D4.43 10701.11 1] 13135.1] 88.39 20500 4240.00 -11021.16 -2530.96 0.00 0.00 11302.14 E" wpO6 CPS 18 13724E 1 91.96 18476 423810 -11507.55 -2689,91 3.50 -0011 11686.03 19 13905.41 8196 184.76 423200.11787.72 -10492 OOO 000 12066,60 E-39 WIM CP4 20 14002.63 94.05 179.52 422].35 41944.69 -2711.54 3.00 -9980 12241.65 21 16176.59 91.05 179.52 418900-14030.23 -2694.12 0.90 000 14294.41 22 1618169 9090 179.52 4189OD-14043,13 -260408 9.00 -178.]] 1429922 E-39 WPG4 Tae Pepin MoPa oa ox Nprw,nvn nM . 0 UO E.Nv[OT OaPU ESI/ LM �'M'-nCJMOmller atop f350W ."aauy7...13MWMIRR-MSISIR a95p,W 181¢1 OB FPI/Ed9u9n.7/0606/ E.IDII ? MNU�IFR2•M6r5vp D � SMn D'c3°I1W :250'720, 280'060 61an Dird'/ILO':550'M1O,5481'IY9 500 ' 10 6p0 End Ort :15625 MD. 1655U'ND SVS na-.. 10 svi to s CooMnale (0615) Relennw: Wetl Plan '"IE Tue NOM Witcal(TVO) ReW= Prelim RKB®4830ue0 (Inmwtiwl SEI NorlMn MeawrM Depth ReNrenre: PWIm RKa ® 48 aft (InlwNtlm) ,NAB OOO -W 090 601601 Celurlabn Mnth.cl Mvrlmum Cu- _ _ sAMer6WIl OB FORIMTWN TnP 051.4065 Ed9 wyb CP4 E.19 v.L0l Toe mpst, TVDUPa. NOP. F -aa. 1888.20 154000 2036.21 aV5 1717.20 1729.00 223524 B.. Pemulmal 12000 12800 13600 14400 15200 251220 2464.00 3810.92 BVI 3725.20 3617W 6591.58 Dan.w 4X1120 4153 f0 16]299 sof, d sun NA 4306.20 4208.00 ]001.]6 s naPer BluXnA 436030 4312.00 611].52 Sonredx Bluff OE Annotation Stilt Dir 3' Stan Dir 4' End Dir :' D9 Sort Or 3°/100': 113143 720, 4]]111' 1 v Endow : 11332.39' MD, 4234.61' WD Siad Dir VJIW:1193239' MD, 4221170 End Dir : 12614.89' MD, 4222.56' WO Pat Dir 3.5°1100' : 13135.1T MD, 4240'000 Erd Dir :1384.51' MD, 4230.10' WO filen Dir 3° 1100': 13935.41' MD, 4231 End Dir : 1409265 M0, 4n7Ss WD Total Dentin 16176.55 MD, 4109' WD WELL DETAILS: PMn: MPU EdS Ground Lerel: 21.M B East, La.d. Lo'lam. LS SHP.13 70'27IS210N 1.-26'4826W WDSS MD Si. Name 428924 895000 9610 958'x121.' 4140.60 15131.49 44rz 41rz'x 812' .cN 4.c+° "I 'u .rzP ,aP Y P 6E M1� M1M1 'f` p. ra'd' 'I pM1' 4x t3h �a 4 oA ctd° o .*° arp' .*° `° ' IRAD" ed� ,�,'p ,�, y °g ,1ye4.,.>',,�2�1 d1 ve° Ayt� P _'0'M1A 45 g jamtA2 s� cF6o4 6\13 �.°" Hd3 e`P 30,. `Y J od' �.'.�e 1 <it ,g 8 S,o4 o' std* o" d•5 e o VS 5 z ga _ 41z xe 1r� Vertical Section at 190.88° (1600 usfV!n) EJn 0027 ^ gp $ trMPU ��- _S _ _8-672 _ _ _ sAMer6WIl OB EJ9 w9Lb LP2 E-39 v.900 W] Ed9 wyb CP4 E.19 v.L0l Toe 509 vgO80A Too Ea9 wyCe CP1 gyg-x I21H' 9600 10400 11200 12000 12800 13600 14400 15200 0 BOO 1600 2400 3200 4000 4000 56000 640 6400 800 8000 8000 Vertical Section at 190.88° (1600 usfV!n) - HALLIBURTON 0- 6PerrY Crllling 50 San Dh 4w100': 55W MD, 549.ITVD 1500 -1033- -1033- End Dn :1962.5' FID, 1655.24' TVD 1]50 _ Project: tSite: Well: 7Point E-39-2067. Wellbore: iPlan: wp07 LL DETAILS: Plan: NSU E-39 Gmund Lcvel: 21.70 -3100 +N/ -S -w-W Eavtinp Lanwdc longitude 26'4.636 W 0.00.00 569284.13 70° 27' 15.210N 149° C aNi waa (NE) Rekrenra: Well Plan: MPU 1538, Tme Nodh VeNwl CND) Rehrence: Pref Rn @ 48.20usft (Innovation) Measured Depth Relerelwe: Prelim RKB ® 48.20usft pnnova4an) Celwlatian Method: Minlmum CU—Wta CASING DETAILS WD WDSS MD Size Name 4337.44 4289.24 8950.00 9-518 9 5M- x 12 114" 4189.00 4140.80 16181.49 4-112 41/2'x81/2° -7233 -6200 -5167 -4133 3000 4000 - _- - Sun Da4°/100' : 7492 83' hID, 4 -83TVD E-39 wp06 OA Tap - - - - /�S�D"'*"'l 250 EndDir : 758404'F03,4166A4'TVD ': 7934.04 M ' D, 4303.2WD 9518"x1214' FM ar : 8532.53' MD, 438671' TVD d_ Stun Dir 4°/100' : 8993.94' MD, 4332 ad.2STVD d Dir :9100.90' FID, 4323.6' TVD E-39 w,"CPI S=Dir3°/100': 10600.98'FID,4258ATWD End Dir :10622.89' FID, 4257.34' TVD Start M YAW : 11314.3' MD, 4235A I" ad Dir : 11332.39' FID, 4234.61' TVD E -J9 -ph CP2 Sun Dv 2°/100' : 11932.39' MD, 4321WD End Dv :12514.89' MD, 4222.58' TVD E-39 wp06 CP3 Sun Dir 35"/100' : 13135.17' MD, 424DWD 139 wp06 CP4 - - - Fnd Dir : 13724.51' MD, 4238.18' TVD Sun Da 3°/100': 13905.41' MD, 4232'WD End Dir : 14082.63'FID, 4227.35' TVD E-39 wp04 Tae LThat Depth: 16176.59' FID, 4189'TVD 4U, x812" !9 MPU E-39 wp07 -3100 -2067 -1033 West( -)/East( -F) (1550 DSWin) 0 1033 2067 3100 Stan Dr3"/m0: 280' MD, 28oTVD D _ 50 San Dh 4w100': 55W MD, 549.ITVD 1500 End Dn :1962.5' FID, 1655.24' TVD 1]50 20M 3000 4000 - _- - Sun Da4°/100' : 7492 83' hID, 4 -83TVD E-39 wp06 OA Tap - - - - /�S�D"'*"'l 250 EndDir : 758404'F03,4166A4'TVD ': 7934.04 M ' D, 4303.2WD 9518"x1214' FM ar : 8532.53' MD, 438671' TVD d_ Stun Dir 4°/100' : 8993.94' MD, 4332 ad.2STVD d Dir :9100.90' FID, 4323.6' TVD E-39 w,"CPI S=Dir3°/100': 10600.98'FID,4258ATWD End Dir :10622.89' FID, 4257.34' TVD Start M YAW : 11314.3' MD, 4235A I" ad Dir : 11332.39' FID, 4234.61' TVD E -J9 -ph CP2 Sun Dv 2°/100' : 11932.39' MD, 4321WD End Dv :12514.89' MD, 4222.58' TVD E-39 wp06 CP3 Sun Dir 35"/100' : 13135.17' MD, 424DWD 139 wp06 CP4 - - - Fnd Dir : 13724.51' MD, 4238.18' TVD Sun Da 3°/100': 13905.41' MD, 4232'WD End Dir : 14082.63'FID, 4227.35' TVD E-39 wp04 Tae LThat Depth: 16176.59' FID, 4189'TVD 4U, x812" !9 MPU E-39 wp07 -3100 -2067 -1033 West( -)/East( -F) (1550 DSWin) 0 1033 2067 3100 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Protect: Milne Point Site: M Pt E Pad Well: Plan: MPU E-39 Wellbore: MPU E -39i Design: MPU E-39 wp07 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 TVD Reference: Prelim RKB @ 48.20usft (Innovation) MD Reference: Prelim IRKS @ 48.20usft (Innovation) North Reference: Tice Survey Calculation Method: Minimum Curvature Protect Milne Point, ACT, MILNE POINT Declination Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Usino Well Reference Point Map Zone: Alaska Zone 04 Usino geodetic scale factor Site M Pt E Pad, TR -13-10 Declination Site Position: 80.96 Northing: om: Map Easting: Position Uncertainty: _ 0.00 usft Slot Radius: WeII Plan: MPU E-39 Well Position -NIS 0.00 usft Northing: Tie On Depth: +E1 -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore MPU E -39i 6,013,798.68 usft Latitude: 569,440.72usft Longitude: 0" Grid Convergence: 6,016,057.25 usft Latitude: 569,284.13 usft Longitude: 0.00 usft Ground Level: Magnetics Model Name Sample Date BGGM2018 7115/2019 Declination Dip Angle 16.62 80.96 Design MPU E-39 wp07 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From (TVD) +N/ -S +E/ -W Direction (usft) (ui (usft) 1°) 26.50 0.00 0.00 190.86 70° 26'52.982 N 149" 26'0.655 W 0.53 ° 70° 27' 15.210 N 149° 26'4.636 W 21.70 usft Field Strength mfr) 57 423.34975604 6/252019 2:10:19PM Page 2 COMPASS 5000.15 Build 91 Halliburton HALLI B U RTO N Standard Proposal Report Database: NORTH US+CANADA Local Co-ordinate Reference: Well Plan: MPU E-39 Companv: Hilcorp Alaska, LLC TVD Reference: Prelim RKB @ 48.20usft (Innovation) Project: Milne Point MD Reference: Prelim RKB @ 48.20usft (Innovation) Site: M Pt E Pad North Reference: True Well: Plan: MPU E-39 Survev Calculation Method: Minimum Curvature Wellbore: MPU E -39i Depth Inclinatio Deafen: MPU E-39 wp07 System +N/S Pian Sections i Measured Vertical NO Dogleg Build Turn Depth Inclinatio Azimut Depth System +N/S +E/ -W Rate Rate Rate Tool Face (usft) n In (usft) usft (usft) (usft) (°/100usft) (°/100usft (°/100usft (') 26.50 0.00 0.00 26.50 -21.70 0.00 0.00 0.00 0.00 0.00 0.00 280.00 0.00 0.00 280.00 231.80 0.00 0.00 0.00 0.00 0.00 0.00 550.00 8.10 220.00 549.10 500.90 -14.60 -12.25 3.00 3.00 0.00 220.00 1,962.50 63.44 190.08 1,655.24 1,607.04 -775.46 -202.44 4.00 3.92 -2.12 -32.35 7,492.83 63.44 190.08 4,128.22 4,080.02 -5,645.72 -1,068.16 0.00 0.00 0.00 0.00 7,584.04 67.00 190.95 4,166.44 4,118.24 -5,727.13 -1,083.28 4.00 3.91 0.95 12.69 7,934.04 67.00 190.95 4,303.20 4,255.00 -6,043.44 -1,144.48 0.00 0.00 0.00 0.00 8,532.53 96.78 193.97 4,386.71 4,338.51 -6,615.30 -1,271.44 5.00 4.98 0.50 6.02 8,993.94 96.78 193.97 4,332.25 4.28405 .7,059.93 -1,382.06 0.00 0.00 0.00 0.00 9,100.98 92.50 193.80 4,323.60 4.27540 -7,163.48 -1,407.65 4.00 4.00 -0.16 -177.72 10,600.98 92.50 193.80 4,258.17 4,209.97 -8,618.79 -1,765.11 0.00 0.00 0.00 0.00 10,622.89 91.84 193.80 4,257.34 4.209.14 -8,640.06 .1,770.34 3.00 -3.00 0.00 179.98 11,314.30 91.84 193.80 4,235.11 4,185.91 -9,311.16 .1,935.18 0.00 0.00 0.00 0.00 11,332.39 91.30 193.80 4,234.61 4,186.41 -9,328.72 -1,939.49 3.00 -3.00 0.00 -179.97 11,932.39 91.30 193.80 4,221.00 4.172.80 -9,911.25 -2,082.57 0.00 0.00 0.00 0.00 12,514.89 88.39 205.08 4,222.58 4,174.38 -10,459.60 -2,276.11 2.00 -0.50 1.94 104.43 13,135.17 88.39 205.08 4,240.00 4.191.80 -11,021.16 -2,538.96 0.00 0.00 0.00 0.00 13,724.51 91.96 184.76 4,238.18 4.189.98 -11,587.55 -2,689.91 3.50 0.61 -3.45 -80.11 13,905.41 91.96 184.76 4,232.00 4.183.80 -11,767.72 -2,704.92 0.00 0.00 0.00 0.00 14,082.63 91.05 179.52 4,227.35 4,179.15 -11,944.69 -2,711.54 3.00 -0.51 -2.96 -99.80 16,176.59 91.05 179.52 4,189.08 4,140.88 -14,038.23 -2,694.12 0.00 0.00 0.00 0.00 16,181.49 90.90 179.52 4,189.00 4,140.80 -14,043.13 -2,694.08 3.00 -3.00 -0.06 -178.77 6252019 2:10:19PM Peoe 3 COMPASS 5000.15 Build 91 Halliburton H ALL I B U R TO N Standard Proposal Report Database: NORTH US + CANADA Local Co-ordinate Reference: Well Plan: MPU E-39 Companv: Hilcorp Alaska, LLC TVD Reference: Prelim RKB @ 48.20usft (Innovation) Project: Milne Point MD Reference: Prelim RKB @ 48.20usft (Innovation) Site: M Pt E Pad North Reference: True Well: Plan: MPU E-39 Survev Calculation Method: Minimum Curvature Wellbore: MPU E -39i Depth Inclination Design: MPU E-39 wp07 TVDss +NIS Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NIS +EI -W Northing Easting DLS Vert (usft) (°) (°) (usft) usft (Usft) (usft) (usft) (usft) -21.70 Section 26.50 0.00 0.00 26.50 -21.70 0.00 0.00 6,016,057.25 569,284.13 0.00 0.00 100.00 0.00 0.00 100.00 51.80 0.00 0.00 6,016,057.25 569,284.13 0.00 0.00 200.00 0.00 0.00 200.00 151.80 0.00 0.00 6,016,057.25 569,284.13 0.00 0.00 280.00 0.00 0.00 280.00 231.80 0.00 0.00 6,016,057.25 569,284.13 0.00 0.00 Start Dir 3°1100' : 280' MD, 280'TVD 300.00 0.60 220.00 300.00 251.80 -0.08 -0.07 6,016,057.17 569,284.06 3.00 0.09 400.00 3.60 220.00 399.92 351.72 -2.89 -2.42 6,016,054.34 569,281.73 3.00 3.29 500.00 6.60 220.00 499.51 451.31 -9.70 -8.14 6,016,047.48 569,276.09 3.00 11.06 550.00 8.10 220.00 549.10 500.90 -14.60 -12.25 6,016,042.54 569,272.02 3.00 16.64 Start Dir 4-1100': 550' MD, 549.1'TVD 600.00 9.85 213.73 598.49 550.29 -20.85 -16.89 6,016,036.25 569,267.44 4.00 23.66 700.00 13.55 206.19 696.40 648.20 -38.48 -26.81 6,016,018.52 569,257.68 4.00 42.85 800.00 17.39 201.89 792.76 744.56 -62.87 -37.56 6,015,994.04 569,247.16 4.00 68.82 900.00 21.28 199.11 887.11 838.91 -93.89 -49.07 6,015,962.91 569,235.94 4.00 101.46 1,000.00 25.21 197.16 978.97 930.77 -131.40 -61.29 6,015,925.30 569,224.07 4.00 140.60 1,100.00 29.15 195.70 1,067.92 1,019.72 -175.21 -74.17 6,015,881.37 569,211.60 4.00 186.05 1,200.00 33.11 194.57 1,153.50 1,105.30 -225.11 -87.64 6,015,831.36 569,198.59 4.00 237.59 1,300.00 37.07 193.66 1,235.31 1,187.11 -280.86 -101.63 6,015,775.49 569,185.12 4.00 294.97 1,400.00 41.04 192.89 1,312.94 1,264.74 -342.17 -116.08 6,015,714.04 569,171.24 4.00 357.92 1,500.00 45.02 192.25 1,386.03 1,337.83 -408.77 -130.92 6,015,647.32 569,157.03 4.00 426.11 1,60D.00 49.00 191.68 1,454.20 1,406.00 -480.31 -146.07 6,015,575.65 569,142.55 4.00 499.23 1,700.00 52.98 191.18 1,517.14 1,468.94 -556.46 -161.45 6,015,499.37 569,127.87 4.00 576.91 1,800.00 56.96 190.73 1,574.52 1,526.32 -636.84 -177.01 6,015,418.85 569,113.07 4.00 658.78 1,900.00 60.95 190.32 1,626.09 1,577.89 -721.06 -192.65 6,015,334.50 569,098.21 4.00 744.44 1,962.50 63.44 190.08 1,655.24 1,607.04 -775.46 -202.44 6,015,280.01 569,088.93 4.00 799.71 End Dir : 1962.5' MD, 1655.24' TVD 2,000.00 63.44 190.08 1,672.01 1,623.81 -808.49 -208.31 6,015,246.94 569,083.37 0.00 833.25 2,036.21 63.44 190.08 1,688.20 1,640.00 -840.37 -213.98 6,015,215.00 569,078.00 0.00 865.64 SV5 2,100.00 63.44 190.08 1,716.72 1,668.52 -896.55 -223.96 6,015,158.74 569,068.54 0.00 922.69 2,200.00 63.44 190.08 1,761.44 1,713.24 -984.61 -239.62 6,015,070.54 569,053.70 0.00 1,012.13 2,235.24 63.44 190.08 1,777.20 1,729.00 -1,015.66 -245.13 6,015,039.46 569,048.48 0.00 1,043.64 Base Permafrost 2,300.00 63.44 190.08 1,806.16 1,757.96 -1,072.68 -255.27 6,014,982.34 569,038.87 0.00 1,101.56 2,400.00 63.44 190.08 1,850.87 1,802.67 -1,160.74 -270.92 6,014,894.15 569,024.04 0.00 1,191.00 1 2,500.00 63.44 190.08 1,895.59 1,847.39 -1,248.81 -286.58 6,014,805.95 569,009.20 0.00 1,280.44 2,600.00 63.44 190.08 1,940.31 1,892.11 -1,336.87 -302.23 6,014,717.75 568,994.37 0.00 1,369.87 2,700.00 63.44 190.08 1,985.02 1,936.82 -1,424.94 -317.89 6,014,629.55 568,979.54 0.00 1,459.31 2,800.00 63.44 190.08 2,029.74 1,981.54 -1,513.00 -333.54 6,014,541.35 568,964.70 0.00 1,548.75 2,900.00 63.44 190.08 2,074.46 2,026.26 -1,601.07 -349.20 6,014,453.16 568,949.87 0.00 1,638.18 3,000.00 63.44 190.08 2,119.17 2,070.97 -1,689.13 -364.85 6,014,364.96 568,935.04 0.00 1,727.62 3,100.00 63.44 190.08 2,163.89 2,115.69 -1,777.20 -380.50 6,014,276.76 568,920.20 0.00 1,617.06 3,200.00 63.44 190.08 2,208.61 2,160.41 -1,865.26 -396.16 6,014,188.56 568,905.37 0.00 1,906.49 3,300.00 63.44 190.08 2,253.32 2,205.12 -1,953.33 -411.81 6,014,100.36 568,890.54 0.00 1,995.93 3,400.00 63.44 190.08 2,298.04 2,249.84 -2,041.39 -427.47 6,014,012.17 568,875.70 0.00 2,085.37 625/2019 2:10:19PM Paas 4 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Local Co-ordinate Reference: Companv: Hilcorp Alaska, LLC TVD Reference: Proiect: Milne Point MD Reference: Site: M Pt E Pad North Reference: Well: Plan: MPU E-39 Survev Calculation Method: Wellbore: MPU E -39i Desitin: MPU E-39 wp07 Halliburton Standard Proposal Report Well Plan: MPU E-39 Prelim RKB @ 48.20usft (Innovation) Prelim RKB @ 48.20usft (Innovation) True Minimum Curvature Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert (usft) (1 (') (usft) usft (usft) (usft) (usft) (usft) 2,294.56 Section 3,500.00 63.44 190.08 2,342.76 2,294.56 -2,129.45 -443.12 6,013,923.97 568,860.87 0.00 2,174.80 3,600.00 63.44 190.08 2,387.47 2,339.27 -2,217.52 -058.77 6,013,835.77 568,846.04 0.00 2,264.24 3,700.00 63.44 190.08 2,432.19 2,383.99 -2,305.58 -474.43 6,013,747.57 568,831.20 0.00 2,353.68 3,800.00 63.44 190.08 2,476.91 2,428.71 -2,393.65 490.08 6,013,659.37 568,816.37 0.00 2,443.12 3,878.92 63.44 190.08 2,512.20 2,464.00 -2,463.15 502.44 6,013,589.77 568,804.66 0.00 2,513.70 SV1 3,900.00 63.44 190.08 2,521.62 2,473.42 -2,481.71 -505.74 6,013,571.18 568,801.54 0.00 2,532.55 4,000.00 63.44 190.08 2,566.34 2,518.14 -2,569.78 -521.39 6,013,482.98 568,786.71 0.00 2,621.99 4,100.00 63.44 190.08 2,611.06 2,562.86 -2,657.84 -537.05 6,013,394.78 568,771.87 0.00 2,711.43 4,200.00 63.44 190.08 2,655.77 2,607.57 -2,745.91 -552.70 6,013,306.58 568,757.04 0.00 2,800.86 4,300.00 63.44 190.08 2,700.49 2,652.29 -2,833.97 -568.35 6,013,218.38 568,742.21 0.00 2,890.30 4,400.00 63.44 190.08 2,745.21 2,697.01 -2,922.04 -584.01 6,013,130.19 568,727.37 0.00 2,979.74 4,500.00 63.44 190.08 2,789.92 2,741.72 -3,010.10 -599.66 6,013,041.99 568,712.54 0.00 3,069.17 4,600.00 63.44 190.08 2,834.64 2,786.44 -3,098.16 -615.32 6,012,953.79 568,697.71 0.00 3,158.61 4,700.00 63.44 190.08 2,879.36 2,831.16 -3,186.23 -630.97 6,012,865.59 568,682.87 0.00 3,248.05 4,800.00 63.44 190.08 2,924.07 2,875.87 -3,274.29 -646.62 6,012,777.39 568,668.04 0.00 3,337.48 4,900.00 63.44 190.08 2,968.79 2,920.59 -3,362.36 -662.28 6,012,689.20 568,653.21 0.00 3,426.92 5,000.00 63.44 190.08 3,013.51 2,965.31 -3,450.42 -677.93 6,012,601.00 568,638.37 0.00 3,516.36 5,100.00 63.44 190.08 3,058.22 3,010.02 -3,538.49 -693.59 6,012,512.80 568,623.54 0.00 3,605.79 5,200.00 63.44 190.08 3,102.94 3,054.74 -3,626.55 -709.24 6,012,424.60 568,608.71 0.00 3,695.23 5,300.00 63.44 190.08 3,147.66 3,099.46 -3,714.62 -724.90 6,012,336.41 568,593.87 0.00 3,784.67 5,400.00 63.44 190.08 3,192.37 3,144.17 -3,802.68 -740.55 6,012,248.21 568,579.04 0.00 3,874.10 5,500.00 63.44 190.08 3,237.09 3,188.89 -3,890.75 -756.20 6,012,160.01 568,564.21 0.00 3,963.54 5,600.00 63.44 190.08 3,281.81 3,233.61 -3,978.81 -771.86 6,012,071.81 568,549.37 0.00 4,052.98 5,700.00 63.44 190.08 3,326.52 3,278.32 -4,066.87 -787.51 6,011,983.61 568,534.54 0.00 4,142.41 5,800.00 63.44 190.08 3,371.24 3,323.04 -4,154.94 -803.17 6,011,895.42 568,519.71 0.00 4,231.85 5,900.00 63.44 190.08 3,415.96 3,367.76 -4,243.00 -818.82 6,011,807.22 568,504.88 0.00 4,321.29 6,000.00 63.44 190.08 3,460.67 3,412.47 .4,331.07 -834.47 6,011,719.02 568,490.04 0.00 4,410.72 6,100.00 63.44 190.08 3,505.39 3,457.19 -4,419.13 -850.13 6,011,630.82 568,475.21 0.00 4,500.16 6,200.00 63.44 190.08 3,550.11 3,501.91 -4,507.20 -865.78 6,011,542.62 568,460.38 0.00 4,589.60 6,300.00 63.44 190.08 3,594.82 3,546.62 4,595.26 -881.44 6,011,454.43 568,445.54 0.00 4,679.03 6,400.00 63.44 190.08 3,639.54 3,591.34 -4,683.33 -897.09 6,011,366.23 568,430.71 0.00 4,768.47 6,500.00 63.44 190.08 3,684.26 3,636.06 -4,771.39 -912.75 6,011,278.03 568,415.88 0.00 4,857.91 6,591.56 63.44 190.08 3,725.20 3,677.00 -4,852.02 -927.08 6,011,197.28 568,402.30 0.00 4,939.80 Ugnu LA3 6,600.00 63.44 190.08 3,728.97 3,680.77 -4,859.46 -928.40 6,011,189.83 568,401.04 0.00 4,947.35 6,700.00 63.44 190.08 3,773.69 3,725.49 4,947.52 -944.05 6,011,101.63 568,386.21 0.00 5,036.78 6,800.00 63.44 190.08 3,818.41 3,770.21 -5,035.59 -959.71 6,011,013.44 568,371.38 0.00 5,126.22 6,900.00 63.44 190.08 3,863.12 3,814.92 -5,123.65 -975.36 6,010,925.24 568,356.54 0.00 5,215.66 7,000.00 63.44 190.08 3,907.84 3,859.64 -5,211.71 -991.02 6,010,837.04 568,341.71 0.00 5,305.09 7,100.00 63.44 190.08 3,952.56 3,904.36 -5,299.78 -1,006.67 6,010,748.84 568,326.88 0.00 5,394.53 7,200.00 63.44 190.08 3,997.27 3,949.07 -5,387.84 -1,022.32 6,010,660.64 568,312.04 0.00 5,483.97 7,300.00 63.44 190.08 4,041.99 3,993.79 -5,475.91 -1,037.98 6,010,572.45 568,297.21 0.00 5,573.40 7,400.00 63.44 190.08 4,086.71 4,038.51 -5,563.97 -1,053.63 6,010,484.25 568,282.38 0.00 5,662.84 6/2512019 2:10:19PM Pace 5 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Wag; PlanMPU E-39 Wellbore: MPU E -39i Design: MPU E-39 wp07 Planned Survey Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 TVD Reference: Prelim RKB @ 48.20usft (Innovation) MD Reference: Prelim IRKS @ 48.20usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +FJ -W Northing Easting DLS Vert (usft) (°) (') (usft) usft (usft) (usft) (usft) (usft) 4,080.02 Section 7,492.83 63.44 190.08 4,128.22 4,080.02 -5,645.72 -1,068.16 6,010,402.37 568,268.61 0.00 5,745.86 Start Dir 4°1100' : 7492.83' MD, 4128.22'TVD 7,500.00 63.72 190.15 4,131.41 4,083.21 -5,652.04 -1,069.29 6,010,396.04 568,267.54 4.00 5,752.28 7,584.04 67.00 190.95 4,166.44 4,118.24 -5,727.13 -1,083.28 6,010,320.84 568,254.25 4.00 5,828.66 End Dir : 7584.04' MD, 4166.44' TVD 7,600.00 67.00 190.95 4,172.68 4,124.48 -5,741.55 -1,086.07 6,010,306.39 568,251.59 0.00 5,643.35 7,672.99 67.00 190.95 4,201.20 4,153.00 -5,807.52 -1,098.84 6,010,240.31 568,239.44 0.00 5,910.54 Schrader Bluff NA 7,700.00 67.00 190.95 4,211.75 4,163.55 -5,831.93 .1,103.56 6,010,215.87 568,234.95 0.00 5,935.40 7,800.00 67.00 190.95 4,250.83 4,202.63 -5,922.30 -1,121.04 6,010,125.34 568,218.31 0.00 6,027.45 7,900.00 67.00 190.95 4,289.90 4,241.70 -6,012.67 -1,138.53 6,010,034.82 568,201.67 0.00 6,119.50 7,934.04 67.00 190.95 4,303.20 4,255.00 -6,043.44 -1,144.48 6,010,004.00 568,196.00 0.00 6,150.83 Start Dir 91100' : 7934.04' MD, 4303.2TVD 7,941.78 67.38 190.99 4,306.20 4,258.00 -6,050.44 -1,145.84 6,009,996.98 568,194.71 5.00 6,157.97 Schrader Bluff OA 8,000.00 70.28 191.32 4,327.22 4,279.02 -6,103.70 -1,156.34 6,009,943.64 568,184.70 5.00 6,212.25 8,100.00 75.25 191.85 4,356.84 4,308.64 .6,197.24 -1,175.52 6,009,849.94 568,166.40 5.00 6,307.73 8,113.52 75.93 191.92 4,360.20 4,312.00 -6,210.05 -1,178.21 6,009,837.10 568,163.82 5.00 6,320.82 Schrader Bluff OB 8,200.00 80.23 192.35 4,378.06 4,329.86 -6,292.76 .1,196.00 6,009,754.24 568,146.81 5.00 6,405.39 8,300.00 85.21 192.84 4,390.73 4,342.53 -6,389.53 -1,217.63 6,009,657.28 568,126.08 5.00 6,504.51 8,400.00 90.18 193.33 4,394.75 4,346.55 -6,486.82 -1,240.25 6,009,559.79 568,104.37 5.00 6,604.32 8,500.00 95.16 193.81 4,390.09 4,341.89 -6,583.90 -1,263.68 6,009,462.51 568,081.85 5.00 6,704.07 8,532.53 96.78 193.97 4,386.71 4,338.51 -6,615.30 -1,271.44 6,009,431.04 568,074.37 5.00 6,736.38 End Dir : 8532.53' MD, 4386.71' TVD 8,600.00 96.78 193.97 4,378.75 4,330.55 -6,680.32 .1,287.62 6,009,365.88 568,058.81 0.00 6,803.28 8,700.00 96.78 193.97 4,366.95 4,318.75 -6,776.68 -1,311.59 6,009,269.31 568,035.73 0.00 6,902.43 8,800.00 96.78 193.97 4,355.14 4,306.94 -6,873.05 -1,335.56 6,009,172.73 568,012.66 0.00 7,001.59 8,900.00 96.78 193.97 4,343.34 4,295.14 -6,969.41 -1,359.54 6,009,076.16 567,989.58 0.00 7,100.74 8,950.00 96.78 193.97 4,337.44 4,289.24 -7,017.59 -1,371.52 6,009,027.87 567,978.05 0.00 7,150.32 9518'x 121W' 8,993.94 96.78 193.97 4,332.25 4,284.05 -7,059.93 -1,382.06 6,008,985.44 567,967.91 0.00 7,193.89 Start D1,0100' : 8993.94' MD, 4332.25'TVD 9,000.00 96.54 193.96 4,331.55 4,283.35 -7,065.78 -1,383.51 6,008,979.58 567,966.51 4.00 7,199.90 9,100.00 92.54 193.80 4,323.64 4,275.44 -7,162.53 -1,407.42 6,008,882.62 567,943.50 4.00 7,299.43 9,100.98 92.50 193.80 4,323.60 4,275.40 -7,163.48 -1,407.65 6,008,881.67 567,943.28 3.99 7,300.40 End Dir : 9100.98' MD, 4323.6' TVD 9,200.00 92.50 193.80 4,319.28 4,271.08 -7,259.55 -1,431.25 6,008,785.39 567,920.58 0.00 7,399.20 9,300.00 92.50 193.80 4,314.92 4,266.72 -7,356.57 -1,455.08 6,008,688.16 567,897.65 0.00 7,498.97 9,400.00 92.50 193.80 4,310.56 4,262.36 -7,453.59 -1,478.91 6,008,590.93 567,874.73 0.00 7,598.75 9,500.00 92.50 193.80 4,306.19 4,257.99 -7,550.62 -1,502.74 6,008,493.70 567,851.80 0.00 7,698.52 9,600.00 92.50 193.80 4,301.83 4,253.63 -7,647.64 -1,526.57 6,008,396.47 567,828.88 0.00 7,798.29 9,700.00 92.50 193.80 4,297.47 4,249.27 -7,744.66 -1,550.40 6,008,299.24 567,805.95 0.00 7,898.07 9,800.00 92.50 193.80 4,293.11 4,244.91 -7,841.68 -1,574.23 6,008,202.01 567,783.03 0.00 7,997.84 9,900.00 92.50 193.80 4,288.75 4,240.55 -7,938.70 -1,598.07 6,008,104.79 567,760.10 0.00 8,097.61 6/252019 2A0:19PM Peoe 6 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well; Plan: MPU E-39 Wellbore: MPU E-391 Design: MPU E-39 wp07 Planned Survey Measured Well Plan: MPU E-39 Vertical Depth Inclination Prelim RKB @ 48.20usft (Innovation) Azimuth Depth (usft) (1) V) (usft) 10,000.00 92.50 193.80 4,284.38 10,100.00 92.50 193.80 4,280.02 10,200.00 92.50 193.80 4,275.66 10,300.00 92.50 193.80 4,271.30 10,400.00 92.50 193.60 4,266.94 10,500.00 92.50 193.80 4,262.57 10,600.00 92.50 193.80 4,258.21 10,600.98 92.50 193.80 4,258.17 Start Dir 3°1100' : 10600.98' MD, 4258.17 -TVD 10,622.89 91.84 193.80 4,257.34 End Dir :10622.89- MD, 4257.34' TVD 10,700.00 91.84 193.80 4,254.86 10,800.00 91.84 193.80 4,251.65 10,900.00 91.84 193.80 4,248.43 11,000.00 91.84 193.80 4,245.21 11,100.00 91.84 193.80 4,242.00 11,200.00 91.84 193.80 4,238.78 11,300.00 91.84 193.80 4,235.57 11,314.30 91.84 193.80 4,235.11 Start Dir 3°1100' : 11314.3' MD, 4235.11'fVD 11,332.39 91.30 193.80 4,234.61 End Dir :11332.3W MD, 4234.61' TVD 11,400.00 91.30 193.80 4,233.08 11,500.00 91.30 193.80 4,230.81 11,600.00 91.30 193.80 4,228.54 11,700.00 91.30 193.80 4,226.27 11,800.00 91.30 193.80 4,224.00 11,900.00 91.30 193.80 4,221.73 11,932.39 91.30 193.80 4,221.00 Start Dir2°1100' : 11932.39' MD, 422Vl7i 12,000.00 90.96 195.11 4,219.66 12,100.00 90.46 197.05 4,218.42 12,200.00 89.96 198.98 4,218.05 12,300.00 89.46 200.92 4,218.55 12,400.00 88.96 202.86 4,219.92 12,500.00 88.46 204.79 4,222.17 12,514.89 88.39 205.08 4,222.58 End Dir :12514.89' MD, 4222.58' TVD 12,600.00 88.39 205.08 4,224.97 12,700.00 88.39 205.08 4,227.78 12,800.00 88.39 205.08 4,230.59 12,900.00 88.39 205.08 4,233.39 13,000.00 88.39 205.08 4,236.20 13,100.00 88.39 205.08 4,239.01 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 Prelim RKB @ 48.20usft (innovation) TVD Reference: Prelim RKB @ 48.20usft (Innovation) MD Reference: TVDss North Reference: True SurveV Calculation Method: Minimum Curvature 6252019 2:10:19PM Pace 7 COMPASS 5000.15 Build 91 Map Map TVDss +NlS +El -W Northing Easting DLS vert usft (usft) (usft) (usft) (usft) 4,236.18 Section 4,236.18 -8,035.72 -1,621.90 6,008,007.56 567,737.18 0.00 8,197.39 4,231.82 -8,132.74 -1,645.73 6,007,910.33 567,714.25 0.00 8,297.16 4,227.46 -8,229.76 -1,669.56 6,007,813.10 567,691.33 0.00 8,396.93 4,223.10 -8,326.78 -1,693.39 6,007,715.87 567,668.40 0.00 8,496.71 4,218.74 .8,423.80 .1,717.22 6,007,618.64 567,645.47 0.00 8,596.48 4,214.37 -8,520.83 -1,741.05 6,007,521.41 567,622.55 0.00 8,696.25 4,210.01 -8,617.85 -1,764.88 6,007,424.18 567,599.62 0.00 8,796.03 4,209.97 -8,618.80 -1,765.11 6,007,423.23 567,599.40 0.00 8,797.00 4,209.14 -8,640.06 -1,770.34 6,007,401.92 567,594.38 3.00 8,818.87 4,206.66 -8,714.90 -1,788.72 6,007,326.91 567,576.69 0.00 8,895.84 4,203.45 -8,811.97 -1,812.56 6,007,229.64 567,553.75 0.00 8,995.65 4,200.23 -8,909.03 -1,836.40 6,007,132.37 567,530.82 0.00 9,095.47 4,197.01 -9,006.09 -1,860.24 6,007,035.10 567,507.88 0.00 9,195.29 4,193.80 -9,103.16 -1,884.09 6,006,937.83 567,484.95 0.00 9,295.10 4,190.58 -9,200.22 -1,907.93 6,006,840.56 567,462.01 0.00 9,394.92 4,187.37 -9,297.28 -1,931.77 6,006,743.29 567,439.08 0.00 9,494.74 4,186.91 -9,311.16 -1,935.18 6,006,729.38 567,435.80 0.00 9,509.01 4,186.41 -9,328.72 -1,939.49 6,006,711.78 567,431.65 3.00 9,527.07 4,184.88 -9,394.37 -1,955.62 6,006,645.99 567,416.14 0.00 9,594.57 4,182.61 -9,491.45 -1,979.46 6,006,548.70 567,393.19 0.00 9,694.42 4,180.34 -9,588.54 -2,003.31 6,006,451.40 567,370.25 0.00 9,794.26 4,178.07 -9,685.63 -2,027.16 6,006,354.10 567,347.31 0.00 9,894.10 4,175.80 -9,782.72 -2,051.00 6,006,256.81 567,324.37 0.00 9,993.94 4,173.53 -9,879.81 -2,074.85 6,006,159.51 567,301.43 0.00 10,093.79 4,172.80 -9,911.25 -2,082.58 6,006,128.00 567,294.00 0.00 10,126.13 4,171.46 -9,976.71 -2,099.45 6,006,062.39 567,277.74 2.00 10,193.59 4,170.22 -10,072.79 -2,127.14 5,005,966.07 567,250.94 2.00 10,293.16 4,169.85 -10,167.88 -2,158.06 6,005,870.71 567,220.91 2.00 10,392.38 4,170.35 -10,261.87 -2,192.18 6,005,776.41 567,187.67 2.00 10,491.11 4,171.72 -10,354.65 -2,229.46 6,005,683.30 567,151.26 2.00 10,589.25 4,173.97 -10,446.10 -2,269.84 6,005,591.48 567,111.73 2.00 10,686.67 4,174.38 -10,459.60 -2,276.12 6,005,577.93 567,105.58 2.00 10,701.11 4,176.77 -10,536.65 -2,312.18 6,005,500.55 567,070.24 0.00 10,783.58 4,179.58 -10,627.18 -2,354.56 6,005,409.64 567,028.71 0.00 10,880.48 4,182.39 -10,717.72 -2,396.93 6,005,318.72 566,987.19 0.00 10,977.37 4,185.19 -10,808.25 -2,439.31 6,005,227.80 566,945.66 0.00 11,074.27 4,188.00 -10,898.79 -2,481.68 6,005,136.89 566,904.13 0.00 11,171.17 4,190.81 -10,989.32 -2,524.06 6,005,045.97 566,862.60 0.00 11,268.06 6252019 2:10:19PM Pace 7 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Companv: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well: Plan: MPU E-39 Wellbore: MPU E -39i Design: MPU E-39 wp07 Planned Survey Measured Map Vertical Depth Inclination Azimuth Depth TVDss (usft) (1 (') (usft) usft 13,135.17 88.39 205.08 4,240.00 4,191.80 StartDir 3.5'1100' : 13135.17' MD, 4240'1VD 11,302.14 13,200.00 88.78 202.85 4,241.60 4,193.40 13,300.00 89.39 199.40 4,243.20 4,195.00 13,400.00 90.00 195.95 4,243.74 4,195.54 13,500.00 90.60 192.51 4,243.21 4,195.01 13,600.00 91.21 189.06 4,241.63 4,193.43 13,700.00 91.81 185.61 4,238.99 4,190.79 13,724.51 91.96 184.76 4,238.18 4,189.98 End Dir : 13724.51' MD, 4238.18' TVD -2,689.91 13,800.00 91.96 184.76 4,235.60 4,187.40 13,900.00 91.96 184.76 4,232.18 4,183.98 13,905.41 91.96 184.76 4,232.00 4,183.80 Start Dir 3°1100' : 13905.41' MD, 4232T/D -2,704.92 14,000.00 91.47 181.97 4,229.17 4,180.97 14,082.63 91.05 179.52 4,227.35 4,179.15 End Dir : 14082.63' MD, 4227.35' TVD 6,004,088.99 566,684.03 14,100.00 91.05 179.52 4,227.03 4,178.83 14,200.00 91.05 179.52 4,225.20 4,177.00 14,300.00 91.05 179.52 4,223.38 4,175.18 14,400.00 91.05 179.52 4,221.55 4,173.35 14,500.00 91.05 179.52 4,219.72 4,171.52 14,600.00 91.05 179.52 4,217.89 4,169.69 14,700.00 91.05 179.52 4,216.07 4,167.87 14,800.00 91.05 179.52 4,214.24 4,166.04 14,900.00 91.05 179.52 4,212.41 4,164.21 15,000.00 91.05 179.52 4,210.58 4,162.38 15,100.00 91.05 179.52 4,208.76 4,160.56 15,200.00 91.05 179.52 4,206.93 4,158.73 15,300.00 91.05 179.52 4,205.10 4,156.90 15,400.00 91.05 179.52 4,203.27 4,155.07 15,500.o0 91.05 179.52 4,201.45 4,153.25 15,600.00 91.05 179.52 4,199.62 4,151.42 15,700.00 91.05 179.52 4,197.79 4,149.59 15,800.00 91.05 179.52 4,195.97 4,147.77 15,900.00 91.05 179.52 4,194.14 4,145.94 16,000.00 91.05 179.52 4,192.31 4,144.11 16,100.00 91.05 179.52 4,190.48 4,142.28 16,176.59 91.05 179.52 4,189.08 4,140.88 16,181.49 90.90 179.52 4,189.00 4,140.80 Total Depth : 16176.59' MD, 4189' TVD .4 112" x 81/2" Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 TVD Reference: Prelim RKB @ 48.20usft (Innovation) MD Reference: Prelim RKB @ 48.20usft (Innovation) North Reference: True Survev Calculation Method: Minimum Curvature 6/25/2019 2:10:19PM Pace 8 COMPASS 5000.15 Build 91 Map Map -NIS +E/ -W Northing Easting IDLE Vert (usft) (usft) (usft) (usft) 4,191.80 Section -11,021.16 -2,538.96 6,005,014.00 566,848.00 0.00 11,302.14 -11,080.38 -2,565.28 6,004,954.54 566,822.23 3.50 11,365.26 -11,173.64 -2,601.31 6,004,860.96 566,787.08 3.50 11,463.63 -11,268.90 -2,631.66 6,004,765.43 566,757.61 3.50 11,562.91 -11,365.82 -2,656.24 6,004,668.30 566,733.94 3.50 11,662.72 -11,464.02 -2,674.94 6,004,569.93 566,716.16 3.50 11,762.69 -11,563.16 -2,687.70 6,004,470.70 566,704.32 3.50 11,862.45 -11,587.55 -2,689.91 6,004,446.28 566,702.33 3.50 11,886.83 -11,662.74 -2,696.18 6,004,371.05 566,696.77 0.00 11,961.85 -11,762.33 -2,704.47 6,004,271.39 566,689.40 0.00 12,061.22 -11,767.72 -2,704.92 6,004,266.00 566,689.00 0.00 12,066.60 -11,862.10 -2,710.47 6,004,171.58 566,684.33 3.00 12,160.33 -11,944.69 -2,711.54 6,004,088.99 566,684.03 3.00 12,241.65 -11,962.06 -2,711.40 6,004,071.63 566,684.33 0.00 12,258.68 -12,062.04 -2,710.57 6,003,971.67 566,686.09 0.00 12,356.71 -12,162.02 -2,709.73 6,003,871.71 566,687.86 0.00 12,454.74 -12,262.00 -2,708.90 6,003,771.75 566,689.62 0.00 12,552.78 -12,361.98 -2,708.07 6,003,671.79 566,691.38 0.00 12,650.81 -12,461.96 -2,707.24 6,003,571.83 566,693.14 0.00 12,748.84 -12,561.94 -2,706.41 6,003,471.88 566,694.90 0.00 12,846.87 -12,661.92 -2,705.57 6,003,371.92 566,696.66 0.00 12,944.91 -12,761.90 -2,704.74 6,003,271.96 566,698.42 0.00 13,042.94 -12,861.88 -2,703.91 6,003,172.00 566,700.19 0.00 13,140.97 -12,961.86 -2,703.08 6,003,072.04 566,701.95 0.00 13,239.00 -13,061.84 -2,702.25 6,002,972.08 566,703.71 0.00 13,337.04 -13,161.82 -2,701.41 6,002,872.13 566,705.47 0.00 13,435.07 -13,261.80 -2,700.58 6,002,772.17 566,707.23 0.00 13,533.10 -13,361.78 -2,699.75 6,002,672.21 566,708.99 0.00 13,631.13 -13,461.76 -2,698.92 6,002,572.25 566,710.76 0.00 13,729.17 -13,561.74 -2,698.08 6,002,472.29 566,712.52 0.00 13,827.20 -13,661.72 -2,697.25 6,002,372.33 566,714.28 0.00 13,925.23 -13,761.70 -2,696.42 6,002,272.38 566,716.04 0.00 14,023.26 -13,861.68 -2,695.59 6,002,172.42 566,717.80 0.00 14,121.30 -13,961.66 -2,694.76 6,002,072.46 566,719.56 0.00 14,219.33 -14,038.23 -2,694.12 6,001,995.90 566,720.91 0.00 14,294.41 -14,043.13 -2,694.08 6,001,991.00 566,721.00 3.00 14,299.22 6/25/2019 2:10:19PM Pace 8 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Companv: Hilcorp Alaska, LLC Project: Milne Point Site: M Pt E Pad Well; Plan: MPU E-39 Wellbore: MPU E -39i Design: MPU E-39 wp07 Tarqets Target Name - hitimiss target DI Shape E-39 wp06 CP3 - plan hits target center - Point E-39 wp06 CP1 - plan hits target center - Point E-39 wp06 OA Top - plan hits target center - Circle (radius 50.00) E-39 wp04 Toe - plan hits target center - Circle (radius 50.00) E-39 wp06 CP4 - plan hits target center - Point E-39 wings CP2 - plan hits target center - Point Caslnq Points Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 TVD Reference: Prelim RKB @ 48.20usft (Innovation) MD Reference: Prelim RKB @ 48.20usft (Innovation) North Reference: True Survev Calculation Method: Minimum Curvature p Angle Dip Dir. TVD +NIS +E/ -W (^) V) (usft) (usft) (usft) 0.00 000 4,240.00 11,021.16 -2,538.96 0.00 0.00 4,258.17 -8,618.79 -1,765.11 0.00 0.00 4,30320 -6,043.44 .1,144.48 0.00 0.00 4,189.00 -14,043.13 -2,694.08 0.00 0.00 4,232.00 -11,767.72 -2,704.92 0.00 0.00 4,221.00 .9,911.25 -2,082.57 Northing Easting (usft) (usft) 6,005,014.00 566,848.00 6,007,423.23 567,599.40 6,010,004.00 568,196.00 6,001,991.00 566,721.00 6,004,266.00 566,689.00 6,006,128.00 567,294.00 Measured Vertical Casing Hole Depth Depth Diameter Diameter Wahl (usft) Name (") (") 8,950.00 4,337.44 9 5/8"x 12 1/4" 9-5/8 12-1/4 16,181.49 4,189.00 41/2"x81/2" 4-1/2 8-1/2 Formations — - - �� -- Measured Vertical Vertical o�p Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithologv 6,591.56 3,725.20 Ugnu LA3 7,941.78 4,306.20 Schrader Bluff OA 7,672.99 4,201.20 Schrader Bluff NA 2,036.21 1,688.20 SV5 3,878.92 2,512.20 SV1 8,113.52 4,360.20 Schrader Bluff OB 2,235.24 1,777.20 Base Permafrost 62512019 2:10: 19PM Pace 9 COMPASS 5000.15 Build 91 HALLIBURTON Database: NORTH US+CANADA Company: Hilwrp Alaska, LLC Protect: Milne Point Site: M Pt E Pad Well: Plan: MPU E-39 Wellbore: MPU E -39i Design: MPU E-39 wp07 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 280.00 280.00 550.00 549.10 1,962.50 1,655.24 7,492.83 4,128.22 7,584.04 4,166.44 7,934.04 4,303.20 8,532.53 4,386.71 8,993.94 4,332.25 9,100.98 4,323.60 10,600.98 4,258.17 10,622.89 4,257.34 11,314.30 4,235.11 11,332.39 4,234.61 11,932.39 4,221.00 12,514.89 4,222.58 13,135.17 4,240.00 13,724.51 4,238.18 13,905.41 4,232.00 14,082.63 4,227.35 to 1A1 dg 4.189.00 Halliburton Standard Proposal Report Local Co-ordinate Reference: Well Plan: MPU E-39 TVD Reference: Prelim IRKS @ 48.20usft (Innovation) MD Reference: Prelim RKB @ 48.20usft (Innovation) North Reference: True Survey Calculation Method: Minimum Curvature Local Coordinates +NIS +El -W (usft) (usft) Comment 0.00 0.00 Start Dir 3°/100' : 280' MD, 280 -TVD -14.60 -12.25 Start Dir 4"/100':550' MD, 549.1 TVD -775.46 -202.44 End Dir : 1962.5' MD, 1655.24' TVD -5,645.72 -1,068.16 Start Dir 4°/100': 7492.83' MD, 4128.22'TVD -5,727.13 -1,083.28 End Dir :7584.04' MD, 4166.44' TVD -6,043.44 -1,144.48 Start Dir 5°1100': 7934.04'MD, 4303.2T/D -6,615.30 -1,271.44 End Dir : 8532.53' MD, 4386.71' TVD -7,059.93 -1,382.06 Start Dir 4°/100': 8993.94' MD, 4332,25 -TVD -7,163.48 -1,407.65 End Dir : 9100.98' MD, 4323.6' TVD -8,618.80 -1,765.11 Stan Dir 3°1100' : 10600.98' MD, 4258.17'TVD -8,640.06 -1,770.34 End Dir : 10622:89' MD, 4257.34' TVD -9,311.16 -1,935.18 Start Dir Wit OV: 11314.3' MD, 4235.11 -TVD -9,328.72 -1,939.49 End Dir : 11332.39' MD, 4234.61' TVD -9,911.25 -2,082.58 Start Dir 2°/100': 11932.39' MD, 4221 -TVD -10,459.60 -2,276.12 End Dir : 12514.89' MD, 4222.58' TVD -11,021.16 -2,538.96 Start Dir 3.5°/100' : 13135.17' MD, 4240'TVD -11,587.55 -2,689.91 End Dir : 13724.51' MD, 4238.18' TVD -11,767.72 -2,704.92 Start Dir 3°/100': 13905.41' MD, 4232 -TVD -11,944.69 -2,711.54 End Dir : 14082.63' MD, 4227.35' TVD -14,043.13 -2,694.08 Total Depth: 16176.59' MD, 4189' TVD 6/252019 2:10: 19PM Pace 10 COMPASS 5000.15 Build 91 Hilcorp Alaska, LLC Milne Point M Pt E Pad Plan: MPU E-39 MPU E -39i MPU E-39 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 25 June, 2019 Closest Approach 30 Proximity Sean on Current Survey Data (Hi96s1de Reference Reference Design: M Pt E Pad -Plan: MPII E-09 - MPU E39i -MPU E-39 wp07 Wall Coordinates: 6,016,057 25 N, 569,264.13 E p0° 27' 15.21" N,149° 26' 06.64" M Datum Height Prelim RKB a46.20ush(Innovation) Swn Range: 26.50 to 6,950.00 ran. Measured Depth. Sean Bedius is Unlimited . Clearance Factor cutoff is Unlimited. May Ellipse Separation I5 Unhmiied Geodesic Swle Factor Applied Version: 5000.15 Build 91 scan Type: e Swn Type: 25.00 HALLIBURTON Sperry Drilling SerWces Hilcorp Alaska, LLC Milne Point HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 wp07 Closest APPmach 3D Prooimtry Seen an Current Survey Data (Hiahslde Reference) Reference Design: M Pt E Patl -Plan: MPU E-39 -MPU E49i - MPU E419 Wp07 Scen pane: 26.50 to 8,950.00 pan. Measured Depth. Scan Radius is Unlimited. Clea rance Factor cutoff is Unlimited. Max Ellipse Separation in Unlimited Measure Minimum MMeanure Ellipse ®Measure Clearance Summary Rased Site Name d Distance d Separation d Factor on Minimum Separation M.1.9 Comparison Well Name. Wellbore Name - Design ...h luafn nnnrh I -M Dan. M Pt E Pad MPE-11 -MPE-11 -MPE-11 MPE-11 - MPE-11- MPE-11 MPE-11 - MPE-11- MPE-11 MPEA2-MPE-12-MPE-12 MPE-12- MPE-12-MPE-12 MPE-12 - MPE-12 - MPE-12 MPE-14 - MPE-14 -MPE-14 MPE-14-MPE44-MPE14 MPE-14 - MPE-14 - MPE-14 MPE-14 - MPE-14A - MPE-14A MPE-14 - MPE-14A- MPE-14A MPE-14 - MPE-14A- MPE-14A MPE-14-MPE-I4APB1 -MPE-I4APB1 MPE-14-MPE-14AP81 -MPE-I4APB1 MPE-14- MPE-14APB1- MPE-14AP81 MPE-15 - MPE-15 - MPE-15 MPE-15 - M PE -15 - MPE-15 MPE-15-MPE-15-MPEA5 MPE-9-MPE-17-MPE-17 MPE-17 - MPE-17 - MPE-17 MPE-1 7 - MPE-17 - MPE-17 MPE-10 - MPE-18 - MPE-10 MPE-18 - MPE-18 - MPE-18 MPE-18-MPEI8-MPE-18 MPE-19 - MPE-19 - MPE-19 MPE-19 - MPE-19 - MPE-19 MPE-19 - MPE-1 9 -MPE-19 MPE-20- MPE-20 - MPE-20 288.50 209.51 28850 206.16 294.37 62.683 Centre Distance Pass - 37650 209.07 376.50 205.70 38230 50.306 Ellipse5epanumn Pass - 901.50 26357 901.50 255.44 902.38 32,425 Clearance Factor Pasn- 26.50 182.71 26.50 181.64 35.84 189.009 Centre Danish. Pass - 276.50 183.60 276.50 179.70 283.34 47.133 Ellipse Separation Pass - 50150 203.56 501.50 197.94 497,32 36.186 Clearance Factor Pass- 270.74 90.05 270,74 BZ56 280.24 36.136 Cape DiMWrc Pass - 351.50 90.37 351.50 87.25 360.97 29021 Ellipse Separation Pass - 691.50 99.17 601.50 94.40 fi09.90 20.812 Clearance Factor Pass - 270.74 9005 270.74 07.56 280.24 36.136 Centre Distance Pass - 351,50 9037 351.50 87,25 36097 29.022 Ellipse Separation Pass - 601.50 99.17 60150 94.40 609.90 20,812 Clearance Factor Pass - 27074 9005 270.74 97.56 200?4 36.136 Centre DINIonx Pass - 351.50 90.37 35150 87.25 360.97 29022 Ellipse Separation Pass - 601,50 99.17 601.50 94.40 609.90 20.812 Clearance Factor Pass - 339.57 5972 33957 54.54 345.61 11.511 Centre Distance Pass - 451.50 60A3 451.50 53.52 49.44 8742 Ellipse Sep neon Pass - 626.50 68.31 626.50 5908 631,76 7.396 Clearance Factor Pass- 2650 169.99 26.50 169.07 31.81 185.189 Centre Distance Pass - 251.50 17127 251.50 160.29 255.30 57.418 Ellipse Sn"pumn Pass - 96.50 202.36 576.50 19847 91.82 34.342 Clearance Factor Pass - 2650 180.50 26.50 179.15 36.53 133.756 Centre Distance Pass - 10150 lea" 101.50 178.85 110.90 100.527 Ellipse Separation Pass - 926.50 280.55 926.50 25158 913.75 37.421 Clearance Factor Pass - 26.50 199.19 26.50 198.27 36.85 217.250 Gene Distance Pass - 27fi50 193.55 276.50 197.02 295.52 78843 Ellapse Separation Pass - 751.50 25]31 751,50 251,72 75842 46.071 Clearance Factor Pass - 377.2B 148.83 377.26 145.05 384.51 39.352 Centre Date. P... 25 Juror, 2019 . 16:11 Page 2 079 COMPASS I Hilcol Alaska, LLC Milne Point HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 wp07 Closest Approach 30 Proximlly Sean on Cummm Survey Data (Highslde Reference) Reference Design. MPt E Pad - Plan: MPU E49 -MPU Ed9i-MPU E-39 wp07 Scan Range: 26.50 to 8,950.00 usR. Measured Depth. Son Radius is Unlimited. Charente Father cutoff is Unlimited Max Ellipse Sapareti in Is Unlimited Measure Minimum @Measure Ellipse qsM... up, Cleann- Summary Saeed Factor on Minimum Separation Warning Site Nam. d Distance it Separation it Cpmnertun Well Name -Wellbore Name - Design need, mann Dean InaXl Damp 40150 14899 401.50 1".92 408.40 37.522 Ellipse Sepmalion pass - MPE-20-MP&20-MPE-20 72650 16949 721350 163.66 72988 29.067 Cleared. Factor Pass - MPE-20-MPE-20-MPE-20 3n.28 148.83 W.28 145.05 389.26 39]52 Centre Distance Pass - MPE-20 - MPE-20A - MPE-20A 401.50 1"92 413.15 37.522 Ellilma Separaliod Pass - MPE-20 - MPE-20A - MPE-20A 401.50 148.89 726.50 163,66 734.73 29.067 Clearedc, Factor Plains - MPE-20 - MPE-20A - MPE-20A 726.50 16949 377.28 148.83 377,28 145.05 389.26 39.352 Cense Distance Pass - MPE-20-MPE-20ALl-MPE-20ALl 401.50 1".92 413.15 37.522 Ellipse Separated Pass - MPE-20-MPE-20AL1-MPE-20AL1 401.50 148.89 Pass- 726.50 16949 726.50 163.66 734.73 29,067 eleance Factor MPE-20-MPE-20AL1-MPE-20ALi 148.83 377,28 14505 309.26 39.352 Centre Distance Pa. - MPE-20-MPE-20AL1 Pat -MPE-20ALl P0t 377.20 Ellipse Saparetiod Pace - 40150 148.89 401.50 1".92 413.15 37.522 MPE-20 - MPE-20ALl Pat -MPE-20ALl Pat 72650 163.66 734.73 29067 Clearance Faced, Pass- MPE-20-MPE-20AL1 P81-MPE-20AL1 PBI 726.50 169.49 28D.63 217.74 280.63 214.60 286.88 69.365 Cearc Dlslsd. Pass - MPE-23-MPE-23-MPE-23 217.81 301.50 214.47 307,77 65.290 Ellipse Separated Pass- MPE-23 - MPE-23 - MPE-23 301.50 753.01 39.658 Clasrance Factor Pass - MPE-23-MPE-23-MPE-23 751.50 271.95 751.50 265.09 28647 11946 28607 11643 29549 45.338 Cenlrc Distance Pass - MPE-24 - MPE-24 - MPE-24 119.75 351.50 116.51 360.24 38.201 Ellipse Separation Pass- MPE-24-MPE-24-MPE-24 351.50 6,101.50 21390 6,483.02 1.973 Clearance Fachor Pass - MPE-24-MPE-24-MPE-24 6,101.50 432.47 28647 11946 28647 116.94 29209 47.301 Centre Distun. Pass - MPE-24 - MPE-24A - MPE-24A 35150 11975 Well 11672 35684 39.503 Ellipse Separation Pass - MPE-24 - MPE-24A - MPE-24A 43247 6.101.50 214.68 6,479.62 1.906 Cimmm. Factor Pass - MPE-24 - MPE-24A - MPE-24A 6,101.50 286.47 11694 292.09 47.301 Cenlrc Data. Pass - MPE-24-MPE-24ALl-MPE-24ALl 286.47 119.46 Pass - 351.50 119.75 351.50 11672 358.84 39.582 Ellipse Separetion MPE-24 - MPE-24ALl - MPE-24ALl 432A7 6,101.50 214.46 6,479.62 1.984 Clearance Fa dor Pass- MPE44-MPE-24AL1-MPE-2,Wki 6.10150 302.19 240.03 302.19 23123 306.57 85.564 Centre Distance Pass - MPE-26-MPE-25-MPE-25 240.39 40150 236.81 406.75 67.149 Ellipse Separated Pass - MPE-25 - MPE-25 - MPE-25 401.50 8wleD 1,13220 10.550.00 4.906 Ckarants, Factor Pass - MPE-25 - MPE-25 - MPE-25 8,801.50 1,422.09 237.23 31152 85.564 Cense Dimence, Pass - MPE-25 - MPE-25A - MPE-25A 302.19 240.03 302.19 Pass - 40150 240.39 40L50 236.01 411.70 67.150 Ellipse 8epa"s MPE-25-MPE-25A-MPE-25A 4,626.50 1,617,69 4,626.50 1,498.55 6,870.68 13579 Clearan. Factor Pass - MPE-25-MPE-25A-MPE-25A 302.19 240.03 302.19 23723 308.57 85.564 Ceare Distance Pass - MPE-25-MPE-25L1-MPE-25L1 25June, 2019 . 1&II Page 3 of 9 COMPASS Hilcorp Alaska, LLC Milne Point HALLIBURTON Antieollision Report for Plan: MPU E-39 - MPU E-39 wp07 Closest Approach 3r, Proximity Scan on Cement Survey Data (HIghside Reference) Reference Deeper: M Pt E Pad -Plan: MPU 5 -so -MPU E.391- MPU E39 wp07 Soon Ranee: 26.50 to 6,950.90 usR. Measured Depth. Scan Radius la Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is Unlimited Measure Minimum @Measure Ellipse "'Measure Clearance Summary Based Separation Warning d Distance d Separation tl Fact., on Minimum Site Name Comparison Well Name - Wellpore Name -Design Damp 1ua01 on.IM1 9rsN1 Drmh 401.50 2,10.39 401.50 23881 406.75 67.149 Ellipse Separation Pass - MPE-25-MPE-25LI-MPE-251-1 1,537.12 31301.50 1,497.44 3,160.04 38.732 Clearance Factor sees - MPE-25-MPE-251-1-MPE-25L1 3,301.50 24003 302.19 23723 30fi.57 85.564 Centre Distance Pass - MPE-25-MPE-251,1 Pat -MPE-25L1 P81 302.19 491.50 236.81 406.75 67.149 Ellipse Separation Pass - MPE-25-MPE-25L1 P81-MPE-251-1 set 40150 2,10.39 3,301.50 1.697.44 3,166.04 38.732 Clearance Factor Pass- MPE-25 - MPE-251-1 P81-MPE-25L1 Pat 3,301.50 1,537.12 302.19 240.03 302.19 237.12 306.57 82.353 Centre Delphos Pasa- MPE-25-MPE-25PBI-MPE-25PS1 401.50 240.38 401.50 23610 406.75 65.159 Ellipse Separation Paes- MPE-25-MPE-25PB1-MPE-25PB1 3301.50 1,537.12 3,301.50 1,49673 3,16604 38.054 Clearance Facror Pass- MPE-25-MPE-25PB1-MPE-25PB1 302.19 237.23 308.57 85.564 Centre Distance Pass - MPE-25-MPE-25PB2-MPE-25P82 302.19 240.03 406 75 fi].169 Ellipse Separatmn u Pa- MPE-25-MPE-25PB2-MPE-25PB2 401.50 240.38 60150 3,301.50 236.01 1,49].64 3.168.04 38.735 Clearanss Factor pass - MPE-25-MPE45PB2-MPE-25PB2 3301.50 1,537.12 302.19 240.03 302.19 237.23 306.57 85.564 Centre Distance Pass - MPE-25-MPE-25PB3-MPE-25PB3 401.50 236.81 40615 67.149 Ellipse Separation Pau- MPE-25-MPE-25PB3-MPE-25PB3 40150 240.39 3,301.50 1,49744 3.168.04 38735 Clearer. Factor Pass- MPE-25-MPE-25PB3-MPE-25PB3 3301.50 1,537.12 4,237.06 205.70 4,]99.4] 3370 Centre Distance Pass - MPE-29-MPE-29-MPE-29 4,237.06 29249 4,451.50 185.76 4,991.26 2.553 Ellipse Separellch pass - MPE-79 - MPE-29 - MPE-29 4,45150 305.41 195.67 5,146.31 2.393 Clearance Factor Pace - MPE-29-MPE-29-MPE-29 4,626.50 335.09 4,626.50 3.932.98 309.97 3,932.98 238.21 4,482.09 4.319 Centre Distance Pass- MPE-29-MPE-29PB1-MPE-29P81 31404 4.37650 213.91 4,917.66 2.644 Ellipse Sep6rati0n Pau- MPE-29-MPE-29PB1-MPE-29PBI 4,37650 4.651.50 231.18 5,172.88 2A86 Clearance Factor Peas - MPE-29-MPE-29PB1-MPE-29PB1 4.651.50 388.72 158.90 208.16 70.811 Carlo, Distance Pass - MPU E -35 -MPU E -35 -MPU EdS 207.64 161.18 207.64 158.57 276,38 59.203 Elllpse Separator, Paas - MPU E -35 -MPU E -35 -MPU E35 27650 161.30 27650 107.13 50453 45.272 Clearance Factor Fees- MPU E -35 -MPU E35 -MPU E35 52650 191.36 526.50 207.66 WAS 20764 15890 208.16 79611 Centre Distance Pass - MPU Ed5-MPU E35 Pal - MPU Edi P61 276.50 158.57 278.30 59.203 Ellipse Separation Pass - MPU E35 -MPU E35 Pat - MPU E35 Pat 276.50 161.30 107.13 504.53 45.272 Clearance Factor Pass - MPU E-35 - MPU E,25 Pin - MPU E-35 Pat 526.50 191.36 526.50 15761 26.65 173.841 Centre Distance Pass - MPU E-3fi-MPU E -36 -MPU E-36 26.50 158.52 26.50 156.26 274.84 51372 Ellipse Sepera8on Pass - MPUE-36-MPU E -36 -MPU E-% 276.50 159.37 27650 551.50 10896 52]59 34.829 Clearance Factor Pau - MPU E -36 -MPU E-3fi-MPU E-36 551.50 19656 26.50 158.52 26.50 157,61 26.65 173.841 Centre Distance Pass - MPU E -36 -MPU E -36P81 -MPU E-36PB1 25 Jona, 2019 . 16'11 Page 40/9 COMPASS I Hileorp Alaska, LLC Milne Point HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 wpO7 Closest Approach 3D Proargain Seen on Comem Survey Data (Mgbside Referencel Reference Design: M Pt E Pad -Plan: MPU E39 -MPU E491- MPU Ed9 wear Scan Range: 26.50 to 8,950-00 usft. Measured Depth. Scan Radius is Unlimited. Clearance Factor cutoff is Unlimited Max Ellipse Sepamtlon Is Unlimited Measure Minimum Measure Ellipse aMmdame Clearance Summary Based Separation Warning Sit. Name d Orn.m. d Se,ndtn d Factor on Minimum Comparison Well Name. Wellbore Name -Design Dmrb 6,.01 truth w.n1 Dmula 276,50 159.37 276.50 156.26 274.84 51.372 Ellipse Separation Pass - MPU E -36 -MPU Ea6PB1-MPU E-36PB1 55150 195.55 551.50 18996 527.59 34.929 Clearance Factor Pass - MPU E -36 -MPU E36P81-MPU E36PB1 16039 26.78 V6889 Centre Distance Pass - MPU E -37 -MPU E -3] -MPU E-37 26.50 161.30 16118 26.50 176.50 159.78 17536 81 Ellipse Sepa2tton Pass - MPU E -3] -MPU E -3] -MPU E37 17650 526.50 20242 526.50 198.19 501.78 47,766 Clearance Factor Pass- MPU E -]7 -MPU E37 -MPU E-37 2650 161.30 26.50 160.39 26.78 176889 Centre Distance Pass - MPU E37 -MPU E37 P01 -MPU E37 PBI 176.50 161.78 176.50 159.78 175,36 80.675 Ellipse Separation Pass - MPU E -3] -MPU E-37 PBI - MPU E-37 PBI 202.42 526.50 198.19 501.70 47,766 Clearance Factor Part - MPU E -3] -MPU E-37 PBI - MPU E-37 P81 526.50 2648 33.409 Centre Distance Pass - MPUE-38-MPU E -38 -MPU E-38 26.50 3017 26.50 29.55 28,89 251.19 11.935 Ellipse Beguiled., Pass - MPU E -38 -NPU E38 -MPU E-38 251.50 31.53 251.50 32.37 399.B1 9.294 Cie... Factor Pass- MPU E -3B -MPU E38 -MPU E-38 401.50 35.26 40150 25.50 30.47 26.50 2956 26.48 33.409 Centre Dlsmam gass- MPU E -3B -MPU E-3BPBI-MPU E30PB1 31.53 251.50 28.89 25119 11.935 Ellipse Separation Pass - MPU E30 -MPU E-38PB1-MPU E-38PB1 251.50 32.37 39981 9.294 CMarance Factor Pass - MPU E -38 -MPU E-38PB1-MPU E38PB1 401.50 36.28 40150 33.409 Centre Disputes Pass - MPU E -30 -MPU E-30PB2-MPU E -38P82 26.50 3047 26.50 29.58 26.'18 Pass 251.50 31.53 251.50 20.89 251.19 11.935 Ellipse Separation - MPU E -30 -MPU E-30PB2-MPU E-38PB2 401.50 32.37 399.81 9.294 Clearen. Factor Pass- MPU E38 -MPU E38PB2-MPU E-38PB2 401.50 36.28 42242 59.16 422.42 55.09 42150 14.528 Centre Distance Pass - MPU E -40 -MPU E40i-MPU E401 451.50 59.28 451.50 54.9] 449]9 13.743 Ellipse Separation Pass - MPUE-0O-MPU E-0oI-MPU E-0Oi 551.50 57.63 546.47 12.730 Clearance Fac[or Pass - MPU E40 -MPU E-0Oi-MPU Ed0i 551.50 6233 55.9 42150 14.520 Centre Distance Pass - alE-90-MPU E40PRI-MPU E40PB1 422.42 59.16 422.42 Pass 45150 59.20 451.50 54.97 449.79 13.743 Ellipse Separation - Apt, E -0O -MPU E-0OPBI-MPU E-00PB1 62.33 55150 57.43 546.47 12]38 Ckarance Factor Pass - MPU E40 -MPU EAUPBI - MPU E40PEI 551.50 473.42 27.80 473.42 2570 473.57 6.770 Centre Cutups Pass - MPU E41- MPU E-41- MPU E41 27.90 501.50 23.58 50142 6,458 Ellipse Separation Pass - MPU E -0i -MPU EAI - MPU E41 501.50 626.50 25.47 624.93 6.171 Clearance Factor Pass - MPUEat- MPU E -0I -MPU EAI 62650 30.40 2310 4]3.5] 6170 Cargo Distance Pass - MPUE-0I-MPU E4I PBI - MPU E41 PW 473.42 27.80 473.42 Pass - 50150 27,90 W150 2358 501.42 6.450 EIIIpse Sepanumn MPU E -0I -MPU E4I PBI - MPU EAI PBI 3040 626.50 25.47 624.93 6.171 Clearance Factor Pass- MPU Ei1-NPU E41 PBI - MPU E41 P81 626.50 473.42 27.00 47342 23.70 473.57 6770 CenVe Disputes Pass - MPU Edt - MPU E41 PB2-MPU E41 P82 25JMM, 2019 . 16:11 Pawiltdo COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 wp07 Hilcorp Alaska, LLC Milne Point Closest Appraac6 3D Pmxlmlty Scan on Cumnl Survey Dafa (Hlghslde Reference) 619.90 87.91 619.98 82.74 654.05 17.014 Centre Downes Reference Design: MPtEPad-Plan: MPUE.M-MPUE49i-MPUE.i9wp07 Pmllm: MPU E-Pw Expansion Plaullolder- Wellbore It 651.50 07.98 651.50 82.67 684.98 Sun Range: 26.50 to 8,950.00 uaft. Measured Depth. Pass - Prelim: MPU E -Pad Expansion Placcholder- Wellbore # 801.50 9388 801.50 67.77 Sun Radius is Unlimited. Clemnu FactorcutoU Is Unlimited Max Ellipse Separation is Unlimited 15.374 Clearance Faclor Pass - Rig: MPU E42 -MPU E42 -MPU E42 108.60 235.13 Measure Minimum (.Measure Ellipse ®Measure Clearers. Summary Based 551.50 Site Name d Distance d Separation d Factor on Minimum Separetlon Warning Comparison Well Name -WeII6are Nam. - Design OeotM1 I -al Deeth I -M ...In 5.172 Clearance Factor Pass- MPU EAI - MPU E41 PB2-MPU E-41 PB2 501.50 27.90 501.50 23.58 501.42 6.458 Ellipse Separation Pass - MPUEAI - MPU E41 PB2-MPD E41 P132 828.50 30,40 826.50 2547 624.93 6.171 Clearance Factor Paw - MPU E41 -MPU EJI P83-MPII E41 PB3 473.42 27,80 473.42 M.70 473.57 6.770 Centre Distance Pass - MPUC--4I-MPU EJI PB3-MPU E-41 P93 501.50 27.90 501.50 23.58 501,42 6.458 Elio. Separation Paw - MPUE41-MPU E41 PB3-MPU EJI PB3 626.50 30AO 626.50 25.47 624.93 6.171 Clearance Factor Pae. - Prelim: MPU E -Pad Expansion Plata..ol-Wellbore# 619.90 87.91 619.98 82.74 654.05 17.014 Centre Downes Pass - Pmllm: MPU E-Pw Expansion Plaullolder- Wellbore It 651.50 07.98 651.50 82.67 684.98 16.555 Ellipse Separation Pass - Prelim: MPU E -Pad Expansion Placcholder- Wellbore # 801.50 9388 801.50 67.77 030A9 15.374 Clearance Faclor Pass - Rig: MPU E42 -MPU E42 -MPU E42 108.60 235.13 108.60 233.68 108.83 162,672 Centre Dlsionce Pass - Rig: MPU E42 -MPU E42 -MPU E42 551.50 236.49 551.50 231.42 558.79 46564 Sps. Separation Pas.- Rig:MPUE422-MPU E42 -MPU E42 8,950,40 989.48 8,950.00 798.17 9,264.09 5.172 Clearance Factor Pass- Rig: MPU E42 -MPU E421.1 -MPU E42LI yro06 100.60 235.13 108.60 MAE 108.83 162.672 Centre Distance Pass - Rig: MPUE42-MPU E42L1-MPU E42LI em06 551.50 236.9 551.50 231.42 55879 46.564 Ellipse Separation Pass - Rig: MPU E42- MPU E4211 - MPU E -42L1 am06 0,950.00 969.55 8,950,40 779.29 9.184.70 5 096 Clearance Fwtor Pas. - R1,MPU E42 -MPU E42L1-MPU E42LI 108.60 235.13 108.60 233.68 108.83 162.672 Centre Date. Pass - ft: MPUE42-Man E42L1-MPU E42LI 551.50 236.49 551.50 231.42 55879 46.564 Ellipse Separation Pass - Rig :MPU 242 -MPU E42L1-MPU E42LI 7,601.50 973.30 7,601.50 811.48 7,810.00 6,012 Clearanu Factor gas. - M Pt S Pad Survey tool oraotam From To Survey)Plan SurreyTool lusnl fusel 26.50 550.00 MPU E-39 "07 2_Gyio-NS-GC_Od1l collar 550.00 8,950.00 MPU E39 wF07 2_MWD+IFR2+MS+Sag 8,950.00 16,181.49 MPU Ed9"07 2MWD+IFR2+MS+Sag 2S Jare, 2019 - 16.11 Pepe 60l9 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 till Ellipse ermrterms are tionelateol across sunray tool tieun points. Calculated ellipses Inmtporate surl errors. Separation is Me actual disease beM'ean elli, ide. Distance Benueen contras is trip itrents line distance between wellbore centres. Clearence Fades=Distance Between Profiles / (Distance BeNmen Profiles- Ellipse Separation). All station ceerdinales were calculated using Me Minimum Curvature method. Hilcorp Alaska, LLC Milnc Point 25June, 419 - 16:11 Pegs 7&9 COMPASS ( REFERENCE INFORMATION IFEFAR Nue ATRE-1V KMI>P IFACCOV COWS) AI.hM M NALLI®URTON Project: Milne Paint Site: MPtEPad am.i, IxrEl Rmertrce: w.n Pi... ww E.19. rm.Nm e �y,wa cpwa U.a: 2110 sP.•ry o.unae Well: Plan: MPU E-39 oval R.mmu: rsa.n RMa®4eausnumwanml M..s"°'ra Rm..m.: Ptien Rxe®4em.mn.ro+mlont .nvs .vre Nam�m• ewm vat v'^sM� 9a9 9.w mla9n& s69z9+i3 ro°xz'Is.n9v u9•zs443sw Wellbore: MPU E -39i w„ua,aaaF..., a,ww. suRJEY PaOGRAM NO G1A6AL FIBER: Usiy use. BaM1red zeleGbn a fiMny cnbrM Plan: MPU E-39 wp07 26.50 To 8950.00 ® Oe01M1 rsu Oe550 Ta SurvryMe Tool x6.59 55000 MPU E18 wp0](MPU E391)2 GymN5GC ONl collet C ING DETAILS Typ TVO55 MO Size Name Ladder/SJ Plots 55000 8950.00 MPUE39wp1](MPUE.i9)2_MNp�IFNb:n: eg 0950A0 1a1B149 MPU Ed9 wyW (MPU E-39113 MWO�IFRR�Me�Sag 4ll].H 4x8924 895000 9-58 959"x 12114" SH(1 of 2) 4189.00 414080 1616149 4.1'2 41a'x81q" 18000 I j I ^ ylsoco - I MPE- MK -2p E�B3 0o MPE- AL1 61PU E t , 0120.00 c MPE-2 MPU ul PlaceM1a1FL 290.00 wPU y MP E<Oi I I H4 I U5UW --I 30.00 0.00 0 500 1000 1500 2000 2500 3000 3500 4000 4500 good 5500 6000 6500 ]000 ]500 8000 5500 8000 9500 Measured Depth (1000 usflln) I 1 4,0 I I j 9 340 m j LL Collision Risk Procedures Req. @ 2.00 m d Collision Awidance Req. m j No -GO Zone - Stop Dolling LoG 0.00 0 500 1000 1500 2000 2500 3000 3500 40W 4500 5000 5500 6000 6500 ]000 ]500 8000 6500 9000 95M Measured Depth (1000 usltrn) Hilcorp Alaska, LLC Milne Point M Pt E Pad Plan: MPU E-39 MPU E -39i MPU E-39 wp07 Sperry Drilling Services Clearance Summary Anticollision Report 25 June, 2019 Closest Approach 3D Proximity Scan on Current Sc,p, Data IMipmaide Refereneel Reference Design: M PI E Pad Plan: MP11 E 39 -MPU E -391 -MPU E-39 w,07 We11 Communist— 6,016,05735 N. 569,21i E I70° 27' 1521' N. 149. 26' .4d4" WI Datum Height: Prelim RKD 0, 40.20ush (me ... her) Scan Range: 8,950.00 to 1fi,191.C9 ush. Measur.d Daplh Scan Radius Is Unlimited. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applletl Version: 5000.15 Build 91 .can Type: Scan Type: 25.00 e =I_\11114I=1IIIJ=il[-]L9 Sperry Drilling Services HALLIBURTON Anticollision Report for Plan: MPU E39 - MPU E-39 wp07 closest Approach 3D Preslmhy Seen on Current Survey Data IHipbslde paramount Reference Design: M Pt E Pad -Plan: MPU E49 -MPU E -39i -MPU Ell wall Seen Ranpe: 8.950.00 to 16,181.49 usn. Measured Depth. Seen Radius is Unlimited. Clearance Fadorcuedfis Unlimited Max Ellipse Separation is Unlimited Measure Minimum siasure Site Name d Distan. d Comparison Well Name -Wellbore Name - Design Dandh nmm ..am M Pt E Pad MPE-24 - MPE-24 - MPE-24 MPE-24 - MPE-24 - MPE-24 MPE-24 - MPE-24 - MPE-24 MPE-24 - MPE-24A - MPE-24A MPE-24 - MPE-24A- MPE-24A MPE-24 - MPE-24A- MPE-24A MPE-24-MPE-24AL1 -MPE-24ALl MPE-24 -MPE-24AL1-MPE-2471-1 MPE-25 - MPE-25 - MPE-25 MPE-29 - MPE-29 - MPE-29 Rig: MPU E42 - MPU E42 - MPU E42 Rig: MPU E42- MPU E42 - MPU E42 Rip: MPU E42 - MPU E -42L1 -MPU E42LI wpDS Rig: MPU E42 - MPU E42L1 - MPU E42L1 wp06 M Pt S Pad MP$05 - MPS -05 - MPS -05 MPS -05 -MPS -051 -1 -MPS -051-1 MPS-05-MPS-0SP8I-MPS-0SPBi MPS -07 -MPS -07 -MPS -07 MPS -0I -MPS -07 -MPS -01 MPS -07 -MPS -07 -MPS -07 MPS -08 -MPS -08 -MPS -O8 MPS -08 -MPS -08 -MPS -08 MP&M-MPS 8 -MPS -08 MPS -I2 -MPS -I2 -MPS -12 MPS -I2 - MPS -12 - MPS -12 MPS -I2 - MPS -12 - MPS -12 Hileorp Alaska, LLC Milne Point Ellipse amm,sure Clearance Summary Based Separation d Factor an Minimum Sepmatt-Wamin9 1 -In pan. 8195000 85790 8,950.00 512.56 9,204.30 2A84 Calls Distance Pass - 9,664.17 81493 9,654.7 510.53 10,127.49 2,401 Ellipse Separation Pass - 9,675.00 874.94 9,67507 510.53 10,136.75 2,401 Clearance Factor Pass - $95600 857.98 8,950.00 514.83 91200.90 2.500 Centre Distance Pasc- 10,975.00 88577 10,975.00 488.33 11,365.32 2.229 Ellipse Sa,.tbn Pass - 11,175.00 893.99 11,115.00 490.63 11,536.78 2.216 Clearer. Faclar Pass - 8,950.00 857.98 8.950.00 51451 9,20090 2,498 Ellipse separation Pass - 11,850.00 1,030.21 11,850.0o MAE 12,180]6 2460 Clearer. Fedor Pass - 8,950.00 1,435.15 8,950.00 1,145.88 10,550.00 4.961 Clearance Factor Pass - 8,950.00 1,648.03 6950.00 1,298.75 9,165.17 4.718 Clearer. Factor Pass - 9,75266 96156 9,752.66 761.83 8,999.73 4.814 Centre Distance Pass - 11,125.00 988.70 11.725.00 74606 11,96900 4.075 Clearance Factor Pass - 9,005.59 969.5D 9,005.59 770.60 9,240.12 5.079 Centre Distance Pace - 11,725.00 980.67 11,75.00 760.82 11,950.51 4.339 Clearance Fodor Pass - 16181.49 1,238.90 16181.49 1,080.37 4,17.09 8.231 Clearance Fodor Pass - 16,181.49 1.238.90 16,181.49 1,088.21 4,17709 8,222 Clearance Fodor Pass - 16;18139 1,230.90 16.181.49 1,088.37 4,177.09 8,230 Cloonan. Factor Pass - 14,900.00 1,662.48 14,900.00 1,494.69 5,061.19 9.908 Clearance Factor Pass - 15,500.00 1,556.12 15,500.00 1,419.88 4,727.16 11.422 Ellipse Separation Pass - 15,816.88 1,546.71 15.816.88 1,433.58 4,454.89 13.671 Centre Demand, Pass - 15,22500 790,67 15,225.00 508.24 10,09 DO 2.800 Clearance Factor Pass - 15,275.00 787.71 15,215.00 507.11 10,009.00 2.007 Ellipse Separetipn Pesa- 16,181.49 163.01 18,181A9 516.42 9,038.14 3,094 centre Distance Pass - 14,725,0 713.00 14,75.00 469.52 7,44185 2.928 Clearance Factor Pass - 14,800.00 707.82 14,000.00 467.01 7,395.67 2.939 Ellipse S.,ndon Pass - 14,90697 70591 14,906.97 460.95 7,322.50 2.981 Centre Distance Pass - 25June, 2019 . 182) Pa, 2 F COMPA6S Hilcorp Alaska, LLC HALLIBURTON Milne Point Anticollision Report for Plan: MPU E-39 - MPU E-39 wp07 TO Sursaygrian Survey Totl meet luafll ClasestAppro-in 3D Proximity Scan an Cufrent Survey Data ifthelde Reference) 2650 55000 MPU E-39 wp07 2Gyro-NS-GG DMl collar 550.00 Reference Design: MPt E Pad - Plan: MPU EJ9-MPU EJ91-MPU E49 wp07 MPU E39 wp07 2MWD+IFR2+MS+Sag 8,950.00 16,181.49 MPU E-39 wp07 2MWD+IFR2+MS+Sag Scan Range: 8,950.09 to 16,181.49 usX. Measured Delad. Scan Radius is Unlimited. Clearance Factor contain Unlimited Max Ellipse separation is Unlimited Measure Minimum ®Measure Ellipse 40Measure Clearance Summary Based Site Name d Distance d Separation it Factor an Minimum Separation Weming Compadmn Well Name - Wellbore Name - Deaian oeetn 0uM (term I.... nmdh MPS -I2 -MPS -12L1 -MPS -12L1 14,725.0) 771.58 14)25.00 524.62 7,364.17 3.124 Clearance Factor Pass - MPS -I2 -MPS -121 -1 -MPS -12L1 14,90000 758.59 14,900.00 517.45 7,249.36 3.146 Ellipse Separation Pass - MPS -I3 -MPS -121 -1 -MPS -1211 14,962.68 757.30 14,96268 519.12 7.21761 3.179 Gamine Distance Pasa- MPS-I2-MPS-12PB1-MPS-12PB1 14,725.00 713.00 14,725.00 469.64 7,441.85 2.930 Clearance Factor Pass - MPS-I2-MPS-12PB1-MPS-12PB1 14,800.00 707.82 14,800.00 467.11 7,395.67 2.941 Ellipse Separation Pass- MPS-I2-MPS-12PB1-MPS-12PB1 14,9)6.50 705.71 14,906.97 469.05 7,322.58 2.992 Centre Distance Pass- MPS -I5 -MPS -I5 -MPS -15 16,181.49 1,381.90 16,181.49 1,269.87 4,463.75 12.336 Clearance Factor Pasa- MPS-I9-MPS-I9-MPS-19 13,250.00 403.94 13,250.00 149.75 7,053.96 1.589 Clearance Factor Pass - MPS -I9 -MPS -I9 -MPS -19 13,300.00 39449 13,300.00 147,02 7,019.53 1.594 Ellipse Separation Pass - MPS -I9 -MPS -I9 -MPS -19 13,41921 385.60 13,419.21 157.60 6,930.02 1.690 Centre Distance Paes- MPS-I9-MPS-19A-MPS-19A 13,250.00 403.94 13,250.00 150.00 7,060.16 1.591 Clearance Factor Pass- MPS-I9-MPS-I9A-MPS-19A 13,300.00 394.49 13,300.00 147.27 7,025.73 1.5% Ellie, Separation Pass - MPS-I9-MPS-I9A-MPS-19A 13,419.21 385.60 13,419.21 15772 6,935.22 1.692 Centre Distance Pass- MPS-I9-MPS-19AL1-MPS-19AL1 13.250.00 403,94 13,250.00 149.95 7,060.16 1,590 Clearance Factor Pass- MPS-I9-MPS-19AL1-MPS-19AL1 13.300.00 394.49 13,300.00 147.22 7,025.73 1595 Ellipse Separation Pass- MPS-I9-MPS-19AL1-MPS-19AL1 13,419.21 385.60 13.419.21 157.69 6,936.22 1.692 CenOe Distance Pass - MPS-I9-MPS-I9APB1-MPS-19APB1 13,250.00 403.94 13,250.00 150.23 7,060.18 1.592 Clearance Factor Pass- MPS-I9-MPS49APB1-MPS-I9APB1 13,30000 39449 13,30.00 147.48 7,@573 1.597 Ellipse Separation Pass- MPS-I9-MPS-19AP81-MPS-1 RAPB1 13,419.21 386.60 13,419.21 157.91 6.936.22 1694 Centre Distance Pass - Survey too/ orgo. From TO Sursaygrian Survey Totl meet luafll 2650 55000 MPU E-39 wp07 2Gyro-NS-GG DMl collar 550.00 8,950.00 MPU E39 wp07 2MWD+IFR2+MS+Sag 8,950.00 16,181.49 MPU E-39 wp07 2MWD+IFR2+MS+Sag 25June, 2019 . 15:23 Paga3of5 COMPASS HALLIBURTON Anticollision Report for Plan: MPU E-39 - MPU E-39 wp07 Ellipse error reins are correlated across survey tool tie -on points. Calculated ellipsis inccewrate..dace errors. Separation is Me actual distance beM en ellipsoids. Distance Between contras is the sbaight line distance between wellbore ceras. Clearance Factor= Distance BeMeen Profiles I (Oistonce BeNrcen Profiles - Ellipse Separation). All station coordinates were calculated uebg Ne Minimum Conature method. Hilcorp Alaska, LLC Milne Point 25J., Wfg . I&M Page a oil COMPASS NALLIBURTON Project: Milne Point REFERENCE INF0flM4TION 1nEG11STIm', fi1PU 819 NAa I., ACCGN"=) Pm": wu ^°'^'^•m loal R... C`k^kal M AhaYa�[w Sell: MP1EPU Bgery �rlllinp Well: Plan: MPU E-39 .1 1.1.1.4 el.Tme�� liYDl Re4aarta-PnAmons'.." 1 N•„°,eepepu n.ons'.." GrourvJ l�exl: ]I.)0 wrs +O,W ry ,."1 cnm.l. w°91114,9. Wellbore: MPU E -39i 0"""•"°"I"vtliv°'"e'�'"a"G'"'°"` 000 ow solwsi s se9au vu°xr is nun' ur xs'anxw Plan: MPU E-39 WpOl SURV�umeoli PRocRAM NO GL00AL FILTER: Uair9 wer 16181seleGbn dlillenn9 cNe�v sew oD r9 tslsles ® OcpN Frcm Ceptll To $urveyiPlan Tool Ladder/S. F. Plots G-SGO_D8lmlar N907 207 CASING DUMM MD TUD Wass MD Size Nam PH(2 of 2) SW.O s.00 WUE-A 2 BBND.00 16181A9 MPU E. W7 3 M D IFR2+AIs+sag 4DTM 9389.34 9-5/8 95R"x I? Ili" 4189.00 414080 15181,49 4-Irz 41n^x81a^ 180.0 _ I c �tso.00 a 0 0120,00 — -_- � n 90 00 ' N N I 0 U fi0.0 I c 30.00 ' U 0.00 850 9000 9500 10D00 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000 15500 18000 18500 17000 17500 1800 Measured Depth (1000 usfi/in) 4.00- .00 I I - 300– 300 Collision Risk Procedures q. o_ n rn zoo " CollisiOnAwidance Req. I No -Go Zone - Stop Ddlling 8500 woo 95100 10000 10500 11000 11500 12000 12500 13000 13500 14000 14w0 1500 15500 18000 18500 17000 17500 18000 Measured Depth (1000 usfi/in) From: Joe Eneel To: Boyer David L (CED) Subject: RE: [EXTERNAL] MPU E-39 PTD Review Date: Tuesday, July 2, 2019 12:17:07 PM Hello Dave — Both E-39 laterals will not be pre produced. Please let me know if you have any other questions. Thank you for your time. -Joe Joe Engel I Drilling Engineer I Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 1 Anchorage I AK 199503 Office: 907.777.8395 1 Cell: 805.235.6265 From: Boyer, David L (CED)[mailto:david.boyer2@alaska.gov] Sent: Tuesday, July 2, 2019 10:17 AM To: Joe Engel <jengel@hilcorp.com> Subject: [EXTERNAL] MPU E-39 PTD Review Hi Joe, I began reviewing the PTD application for the MPU E-39 dual lateral water injector today. Will either of the laterals be preproduced? If so, will they be produced for longer than 3 months? Thankyou, Dave Boyer AOGCC The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e- mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Transform Points i Source coordinate system A^ nr I Target coordinate system / l be State Plane 1927 -Alaska Zone 4 el Albers Equal Area( -1501 GONVeV51Oki Datum:Datum: NAD 1927 - North America Datum of 1927 (Mean) E 3 NAD 1927 - North America Datum of 1927 (Mean) ----a — - Type values into the spreadsheet or copy and paste columns of data from a spreadsheet using the keyboard shortcuts Ctd+C to copy and Ctrl+V to paste. Then click on the appropriate arrow button to transform the points to the desired coordinate system. t Back finish Cancel Help TRANSMITTAL LETTER CHECKLIST WELL NAME: b P a., PTD: _a 19 -0,16 Development t/Service Exploratory _ Stratigraphic Test _ Non -Conventional FIELD: M, l Vie— Po 1 h+ POOL: sC 6a Q e(/ V f u f -E 0 t I 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- _ function the (If last two digits Production should continue to be reported as a of 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 e . 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 samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Comnany 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 VVV within 90 days after completion, suspension or abandonment of this well. 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