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Home My WebLink About216-164MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Friday, July 18, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-33 MILNE PT UNIT B-33 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 07/18/2025 B-33 50-029-23573-00-00 216-164-0 W SPT 4428 2161640 1500 770 770 768 768 4YRTST P Adam Earl 5/10/2025 MIT IA- Monobore 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT B-33 Inspection Date: Tubing OA Packer Depth 1150 1725 1696 1690IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE250512092007 BBL Pumped:0.7 BBL Returned:0.7 Friday, July 18, 2025 Page 1 of 1 9 9 9 9 9 9 9 9 9 999 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2025.07.18 15:29:34 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, June 1, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Austin McLeod P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-33 MILNE PT UNIT B-33 Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 06/01/2023 B-33 50-029-23573-00-00 216-164-0 N SPT 4428 2161640 1500 336 337 337 337 OTHER P Austin McLeod 5/4/2023 Post tree/conductor work. Monobore 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:MILNE PT UNIT B-33 Inspection Date: Tubing OA Packer Depth 97 1730 1662 1640IA 45 Min 60 Min Rel Insp Num: Insp Num:mitSAM230506122908 BBL Pumped:2 BBL Returned:2 Thursday, June 1, 2023 Page 1 of 1 9 9 9 9 9 9 9 9 999 9 9 9 James B. Regg Digitally signed by James B. Regg Date: 2023.06.02 10:44:27 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Conductor Retrofit 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 10,933 feet N/A feet true vertical 4,408 feet N/A feet Effective Depth measured 10,272 feet 5,076 feet true vertical 4,408 feet 4,419 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)4-1/2" 12.6# / L-80 / Supermax 5,087' 4,420' Packers and SSSV (type, measured and true vertical depth)HRD-E ZXP LTP 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 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 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: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Wells Manager Contact Phone: N/A 3,090psi 8,540psi 5,750psi 9,020psi10,277' 4,408' Burst N/A 5,248'Surface Production 20" X 34" 9-5/8" 4-1/2" 80' 5,248' MILNE PT UNIT B-33 Plugs Junk measured Length Collapse measured TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-164 50-029-23573-00-00 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Hilcorp Alaska LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: ADL0047437 & ADL0047438 MILNE POINT / SCHRADER BLUFF OIL measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MD 80' Size 80' 4,429' Casing Conductor 5,201' N/A Ryan Thompson ryan.thompson@hilcorp.com 907-564-5280 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 0 338 6400 0 00 250 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 322-604 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 3:05 pm, May 16, 2023 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143) Date: 2023.05.16 12:43:32 - 08'00' Taylor Wellman (2143) DSR-8/16/23 RBDMS JBS 072723 WCB 1-8-2024 Well Name Rig API Number Well Permit Number Start Date End Date MP B-33 Wells Spec. 50-029-23573-00-00 216-164 12/30/2022 5/4/2023 No operations to report. Wellhead: Open all tree valves and vac truck suck out tree down to BPV, Install tree lift device, bleed off tbg hgr void and ND tree/adapter. Use loader to pull tree/adapter and set on RIG mat at edge of pad. Wellhead support structure to be arriving in am. 12/31/2022 - Saturday No operations to report. 1/3/2023 - Tuesday 1/1/2023 - Sunday No operations to report. 1/2/2023 - Monday 12/30/2022 - Friday Wellhead: Set 4" BPV w/ S-10 lubricator (minimal preasure) pre Seaboard retrofit. 12/28/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 12/29/2022 - Thursday No operations to report. Well Name Rig API Number Well Permit Number Start Date End Date MP B-33 Wells Spec. 50-029-23573-00-00 216-164 12/30/2022 5/4/2023 1/6/2022 - Friday No operations to report. 1/4/2022 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 1/5/2022 - Thursday No operations to report. No operations to report. BPV/0/0 Spotted WSS over wellhead, removed all carrier bolts, wrapped legs with visqueen and installed heaters. Having issues with legs not moving. Continued with heat on legs for 48 hrs. Was able to get A,B,C legs moving but unable toget D leg to move. Decision was made to R/D WSS and take back to GPB. Removed knuckle from wellhead and installed tree. BPV still in hole Final WHP's BPV/0/0. 1/7/2022 - Saturday Nipple up Seaboard tree/adapter post WSS removeal. Tested adapter to 500 / 5000 psi for 10 mins, all tested good. BPV still in well with signage. 1/10/2023 - Tuesday 1/8/2023 - Sunday No operations to report. 1/9/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP B-33 Wells Spec. 50-029-23573-00-00 216-164 12/30/2022 5/4/2023 4/28/2023 - Friday N/D TREE. REMOVE SNOW FROM CELLAR. SPOT WELL SUPPORT STRUCTURE. APPLY HEAT TO ALL FOUR LEGS. REMOVE TRAVELLING BOLTS. SPOT CONTROL SHACK AND MAKE CONNECTIONS TO EACH LEG. MAKE UP KNUCKLE TO WELLHEAD. ENCODER C NOT FUNCTIOING. RAISE LEGS. LEGS FUNCTIONING PROPERLY. LEG A LAGS BEHIND THE OTHER THREE LEGS. FLY IRON CROSS THROUGH WELL SUPPORT STRUCTURE AND MAKE UP TO KNUCKLE. RAISE STRUCTURE TO CONTACT IRON CROSS. FLY IN BONNETT. M/U BONNETT. SDFN. 4/26/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary No operations to report. 4/27/2023 - Thursday No operations to report. No operations to report. PJSM / Sign off on Hot Work Permit / Zero tare weight and then PU well into tension to 8K / No movement in WH/ PU well tinto tension to 38k/ Cut out Seaboard bell nipple between casing head and 20¿ conductor using Air Arc and Oxygen/Acetylene / See increase in tension to 48k when bell nipple cut off/ Remove bell nipple in two pieces/ Final tension weight = 48k / Neck of bell nipple retained inside bottom of casing head / Dress off entry in bottom of casing head for ease of entry with the Reverse Slip-Lock assembly /Install Reverse Slip-Lock assembly as per procedure and tighten bottom flange bolts to 125 ft/lbs / Release tension and no slippage of Slip-Lock observed / Sit down and reduce tension to 38k/ No slippage seen/ Sit down and release all tension/ No slippage seen/ MIT-IA to 1450 psi passed. Pressured up IA to 1450psi with ~3.2 bbls diesel ¿ OAP =0 psi / MIT-IA lost 20 psi in 1st 15 minutes and 8 psi in 2nd 15 minutes for a total of 18 psi loss in 30 minutes / Bled back ~3.2 bbls / Final pressures = 0 psi IA / 0 psi OA / tubing has BPV / Remove top bonnett and cross from WSS / Prep WSS for travel mode. SDFN. 4/29/2023 - Saturday No operations to report. 5/2/2023 - Tuesday 4/30/2023 - Sunday No operations to report. 5/1/2023 - Monday Well Name Rig API Number Well Permit Number Start Date End Date MP B-33 Wehels Spec. 50-029-23573-00-00 216-164 12/30/2022 5/4/2023 No operations to report. No operations to report. 5/6/2023 - Saturday No operations to report. 5/9/2023 - Tuesday 5/7/2023 - Sunday No operations to report. 5/8/2023 - Monday 5/5/2023 - Friday No operations to report. 5/3/2023 - Wednesday Hilcorp Alaska, LLC Weekly Operations Summary WELL S/I ON ARRIVAL. PULL EVO @ 4570' SLM. WELL S/I ON DEPARTURE. 5/4/2023 - Thursday T/I = 336/97 AOGCC MIT-IA 1500 psi Witnessed by Austin McCloud **Passed**, 2 bbls diesel to pressure up, First 15 min IA lost 68 psi, Second 15 min IA lost 22 psi, FWP = 336/95 AOGCC MIT-IA 1500 psi Witnessed by Austin McCloud **Passed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y Anne Prysunka at 8:43 am, Oct 19, 2022 'LJLWDOO\VLJQHGE\'DYLG +DDNLQVRQ '1FQ 'DYLG+DDNLQVRQ RX 8VHUV 'DWH 'DYLG+DDNLQVRQ 6)'0*52&7 '65*&: Jessie L. 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Chmielowski Date: 2022.10.20 14:49:55 -08'00' RBDMS JSB 102522 tĞůůŚĞĂĚZĞƚƌŽĨŝƚ tĞůů͗DWhͲϯϯ ĂƚĞ͗ϬϵͬϮϵͬϮϬϮϭ tĞůůEĂŵĞ͗DWhͲϯϯ W/EƵŵďĞƌ͗ϱϬͲϬϮϵͲϮϯϱϳϯͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗tĂƚĞƌ/ŶũĞĐƚŽƌ WĂĚ͗ͲWĂĚ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ϭϬͬϮϵͬϮϬϮϮ ZŝŐ͗t^^ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍zĞƐ ĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗dŽŵ&ŽƵƚƐ WĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϭϲͲϭϲϰ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗:ĞƌŝŵŝĂŚ'ĂůůŽǁĂǇ ;ϵϬϳͿϱϲϰͲϱϬϬϱ;KͿ ;ϴϮϴͿϱϱϯͲϮϱϯϳ;DͿ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗dŽĚĚ^ŝĚŽƚŝ ;ϵϬϳͿϳϳϳͲϴϰϰϯ;KͿ ;ϵϬϳͿϲϯϮͲϰϭϭϯ;DͿ &EƵŵďĞƌ͗:ŽďdǇƉĞ͗tĞůůŚĞĂĚZĞƉĂŝƌ ƵƌƌĞŶƚŽƚƚŽŵ,ŽůĞWƌĞƐƐƵƌĞ͗ Ϯ͕ϭϮϭƉƐŝΛϰ͕ϯϮϬ͛ds ;^,W^ƚĂŬĞŶŽŶϳͬϮϵͬϭϴDtʹϵ͘ϰϰWW'Ϳ DĂǆŝŵƵŵǆƉĞĐƚĞĚ,W͗ Ϯ͕ϭϮϭƉƐŝΛϰ͕ϯϮϬ͛ds ;^,W^ƚĂŬĞŶŽŶϳͬϮϵͬϭϴDtʹϵ͘ϰϰWW'Ϳ DW^W͗ ϭ͕ϵϬϵƉƐŝ ;Ϭ͘ϭƉƐŝͬĨƚŐĂƐŐƌĂĚŝĞŶƚͿ DŝŶ/͗ ϯ͘ϳϮϱ͟/ϰͲϭͬϮyEEŝƉĂƚϰ͕ϵϱϴ͛D DĂǆĞǀ͗ ϴϭ͘ϱĞŐĂƚyEƉƌŽĨŝůĞĂƚϰ͕ϵϱϴ͛D ƌŝĞĨtĞůů^ƵŵŵĂƌǇ͗ dŚĞDŝůŶĞWŽŝŶƚͲϯϯǁĂƐĚƌŝůůĞĚĂŶĚĐĂƐĞĚĂƐĂ^ĐŚƌĂĚĞƌůƵĨĨŝŶũĞĐƚŝŽŶǁĞůůŝŶĞĂƌůǇϮϬϭϳ͘dŚĞǁĞůů͛ƐƐƵƌĨĂĐĞ ĐĂƐŝŶŐǁĂƐĨƵůůǇĐĞŵĞŶƚĞĚĂŶĚŚƵŶŐŽĨĨĂƐůŝƉƐƚǇůĞĐĂƐŝŶŐŚĂŶŐĞƌĂƐƉĂƌƚŽĨĂĐŽŶĚƵĐƚŽƌƐƵƉƉŽƌƚĞĚǁĞůůŚĞĂĚ 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WƌĞƉĂƌĞƚŽƚƌĂŶƐĨĞƌůŽĂĚƚŽƚŚĞtĞůů^ƵƉƉŽƌƚ^ƚƌƵĐƚƵƌĞ͘WƌĞƚĞŶƐŝŽŶůŽĂĚĐĞůůƐĂĐĐŽƌĚŝŶŐƚŽŽƉĞƌĂƚŝŶŐ ŵĂŶƵĂů͘ ϭϱ͘ WƵůůϴ͕ϬϬϬůďƐ;tĞůůŚĞĂĚtĞŝŐŚƚͿŐƌĂĚƵĂůůǇďƵŝůĚŝŶŐƵƉůŽĂĚŝŶϭ͕ϬϬϬůďŝŶĐƌĞŵĞŶƚƐ͘ Ă͘ DŽŶŝƚŽƌ ƚŚĞ ǁĞůůŚĞĂĚ ĨŽƌ ĂŶǇ ƐŝŐŶƐ ŽĨ ŵŽǀĞŵĞŶƚ ĂŶĚ ĚŝƐĐŽŶƚŝŶƵĞ ŝŶĐƌĞĂƐŝŶŐ ƚĞŶƐŝŽŶ ŝĨ ŵŽǀĞŵĞŶƚŽďƐĞƌǀĞĚ͘ ϭϲ͘ /ŶĐƌĞĂƐĞǁĞŝŐŚƚƵƉƚŽϯϴ͕ϬϬϬůďƐ;ϯϬ<ƉƌĞůŽĂĚŝŶŐͿ ϭϳ͘ KŶĐĞƉƌĞͲůŽĂĚĞĚ͕ďĞŐŝŶĐƵƚƚŝŶŐĐŽŶĚƵĐƚŽƌŚŽƌŝǌŽŶƚĂůůǇĂƚďŽƚƚŽŵŽĨĐŽŶĚƵĐƚŽƌďĞůůŶŝƉƉůĞƵƐŝŶŐĂŝƌĂƌĐ ĐƵƚƚĞƌ͘ Ă͘ DŽŶŝƚŽƌůŽĂĚŽŶtĞůů^ƵƉƉŽƌƚ^ƚƌƵĐƚƵƌĞŝŶĂĚĚŝƚŝŽŶƚŽǁĞůůŚĞĂĚǀĞƌƚŝĐĂůĚŝƐƉůĂĐĞŵĞŶƚĚƵƌŝŶŐ ĐƵƚƚŝŶŐŽƉĞƌĂƚŝŽŶƐ͘ Ă͘ DĂǆŝŵƵŵĚƌǇ͕ƚƵďŝŶŐĂŶĚǁĞůůŚĞĂĚůŽĂĚсϭϮ͘ϲηΎϱϬϴϳ͛нϴ<сϳϯ< ď͘ DĂŝŶƚĂŝŶĐŽŶƐƚĂŶƚǀĞƌƚŝĐĂůĚŝƐƉůĂĐĞŵĞŶƚǁŚŝůĞǁĞůůƐƵƉƉŽƌƚƐƚ ƌƵĐƚƵƌĞŝƐůŽĂĚĞĚďǇǁĞůů͘ ϭϴ͘ WƌŽĐĞĞĚƚŽĐƵƚĐŽŶĚƵĐƚŽƌďĞůůŶŝƉƉůĞďĞůŽǁƚŚĞƐƚĂƌƚŝŶŐŚĞĂĚĂŶĚƚŚĞŶƌĞŵŽǀĞĐŽŶĚƵĐƚŽƌďĞůůŶŝƉƉůĞ ƐĞĐƚŝŽŶ͘ Ă͘ ŶƐƵƌĞŵŝŶŝŵƵŵŽĨϭϮ͟ŽĨĐůĞĂƌĂŶĐĞďĞƚǁĞĞŶďŽƚƚŽŵŽĨƐƚĂƌƚŝŶŐŚĞĂĚĂŶĚƚŽƉŽĨĐŽŶĚƵĐƚŽƌ͘ ď͘ ZĞĐŽƌĚtĞůů^ƵƉƉŽƌƚ^ƚƌƵĐƚƵƌĞ>ŽĂĚŝŶt^ZŽŶĐĞĐŽŶĚƵĐƚŽƌĨƵůů ǇůŽĂĚĞĚ͘ ϭϵ͘ >ĞĂǀĞƌĞŵĂŝŶŝŶŐďĞůůŶŝƉƉůĞƐĞĐƚŝŽŶĞŶŐĂŐĞĚŝŶƐƚĂƌƚŝŶŐŚĞĂĚ͘ĞǀĞůĂƐŶĞĞĚĞĚƚŽĞŶƐƵƌĞƐŵŽŽƚŚĞŶƚƌǇ 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Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Conductor Retrofit 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 10,933'N/A Casing Collapse Conductor N/A Surface 3,090psi Production Liner 8,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Chad Helgeson Contact Name: David Gorm Operations Manager Contact Email: Contact Phone: 777-8333 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng MILNE PT UNIT B-33 C.O. 477.05 HRD-E ZXP LTP and N/A 5,076 MD/ 4,419 TVD and N/A Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: 10/15/2021 4-1/2" Perforation Depth MD (ft): See Schematic See Schematic 80' 20" X 34" 9-5/8" 4-1/2" 5,248' 5,201' 5,750psi 9,020psi 4,429' 4,408' 5,248' 10,277' 80' 80' 12.6# / L-80 / Supermax TVD Burst 5,087' MD N/A 50-029-23573-00-00 Hilcorp Alaska LLC Length Size 4,408' 10,272' 4,408' 1,909 N/A MILNE POINT / SCHRADER BLUFF OIL Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0047437 & ADL0047438 216-164 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 dgorm@hilcorp.com COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): ory Statu Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 12:49 pm, Oct 12, 2021 321-539 Digitally signed by David Haakinson (3533) DN: cn=David Haakinson (3533), ou=Users Date: 2021.09.30 15:50:45 -08'00' David Haakinson (3533) 10-404 DSR-10/12/21MGR13OCT2021SFD 10/12/2021 JLC 10/14/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.14 12:04:31 -08'00' RBDMS HEW 10/19/2021 Wellhead Retrofit Well: MPU B-33 Date: 09/29/2021 Well Name:MPU B-33 API Number:50-029-23573-00 Current Status: Water Injector Pad:B-Pad Estimated Start Date:10/15/2021 Rig:WSS Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Tom Fouts Permit to Drill Number:216-164 First Call Engineer:David Gorm (907) 777-8333 (O) (505) 215-2819 (M) Second Call Engineer:Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number:Job Type:Wellhead Repair Current Bottom Hole Pressure: 2,121 psi @ 4,320’ TVD (SBHPS taken on 7/29/18 EMW – 9.44 PPG) Maximum Expected BHP: 2,121 psi @ 4,320’ TVD (SBHPS taken on 7/29/18 EMW – 9.44 PPG) MPSP: 1,909 psi (0.1 psi/ft gas gradient) Min ID: 3.725” ID 4-1/2 XN Nip at 4,958’ MD Max Dev: 81.5 Deg at XN profile at 4,958’ MD Brief Well Summary: The Milne Point B-33 was drilled and cased as a Schrader Bluff injection well in early 2017. The well’s surface casing was fully cemented and hung off a slip style casing hanger as part of a conductor supported wellhead system. The system has since been identified as having the potential to cause wellhead movement in the event of conductor subsidence. In order to fully tie well load back to the single 9-5/8” casing string, conductor will be cut and a reverse acting slip style hanger assembly will be installed. Notes Regarding Wellbore Condition x MIT-IA passed to 1,500 psi for 30 min on 5/03/2021. x Well is currently online injecting at ~500 bwpd. x Well’s only XN profile was landed at 82 deg deviation and should be considered inaccessible for well securement. x Previous slickline runs experienced reduced RIH speeds below 4700’ MD and deviated out around ~4850’ MD (9/25/2018). Objective: Cut conductor bell nipple below starting head and install Seaboard Reverse Slip Loc assembly to ensure fully supported by surface casing. Procedure: Pre-Sundry Work Slickline 1. MIRU SL unit. 2. Pressure test to 300 psi low and at least 2,000 psi high. 3. MU plug and DPU setting toolstring and set 4-1/2” mechanical plug mid joint at ~4600’ MD. a. Bleed down the tubing pressure to confirm set. 4. RDMO Prep Work 5. Disconnect flowline and instrumentation. 6. Verify tubing and IA pressures have been bled to 0 psi. -00 Pressure test against plug to 500 psi for 10 minutes. Wellhead Retrofit Well: MPU B-33 Date: 09/29/2021 7. Sniff cellar and adjacent area with multi-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations. 8. Vac out gravel from well cellar down to cellar liner to remove residual hydrocarbons. 9. Install fire blankets around well to prevent hot debris from falling downhole. Sundry Work (Approval required to proceed) Surface Casing Support Retrofit – Note: Photo Document Repair Work on a Daily Project Timeline. 10. Sniff cellar and adjacent area with multi-gas meter for LEL, CO, H2S and 02. Ensure confined space, egress and ventilation is adequate for operations. 11. Flush conductor with water from the conductor starting head valve and while taking fluid returns from the cement return line bull plug. Flush with hot diesel until clean returns are observed. 12. Move in and rig up Well Support Structure. Place rig mats as needed to level out support structure legs. 13. Install BPV and nipple down tree at master valve or tubing head adapter as needed to makeup Wellhead Support Structure adapter flange. 14. Prepare to transfer load to the Well Support Structure. Pretension load cells according to operating manual. 15. Pull 8,000 lbs (Wellhead Weight) gradually building up load in 1,000 lb increments. a. Monitor the wellhead for any signs of movement and discontinue increasing tension if movement observed. 16. Increase weight up to 38,000 lbs (30 K preloading) 17. Once pre-loaded, begin cutting conductor horizontally at bottom of conductor bell nipple using air arc cutter. a. Monitor load on Well Support Structure in addition to wellhead vertical displacement during cutting operations. a. Maximum dry, tubing and wellhead load = 12.6#*5087’ + 8K = 73K b. Maintain constant vertical displacement while well support structure is loaded by well. 18. Proceed to cut conductor bell nipple below the starting head and then remove conductor bell nipple section. a. Ensure minimum of 12” of clearance between bottom of starting head and top of conductor. b. Record Well Support Structure Load in WSR once conductor fully loaded. 19. Leave remaining bell nipple section engaged in starting head. Bevel as needed to ensure smooth entry of slip assembly. 20. Place each half of Reverse Slip Loc assembly around surface casing, bolt halves together. 21. Install energizing plate halves at 90 degree offset from slip assembly such that joint between halves are perpendicular to slips. 22. Lift Reverse Slip Loc up inside conductor starting head. 23. In a criss cross pattern, begin to tighten bolts on energizing plates initially to 50 ft-lbs on first pass then to a final torque of 100-125 ft-lbs on second pass. 24. Mark casing at the bottom of the Reverse Slip Loc 25. Release tension, observe for any slippage. If slipping occurs, retension and tighten bolts to 150 ft-lbs. 26. Once load is released to Reverse Slip Loc, conduct MIT-IA to at least 1,500 psi to confirm casing and packer integrity is unchanged. a. Notify AOGCC at least 24 hrs prior to pressure testing injector Inner Annulus. b. Provide test results to Darci Horner (dhorner@hilcorp.com or 907-777-8406) for submission to AOGCC. 27. Unbolt and remove the adapter flange. 28. Reinstall 5K injection tree. 29. Remove BPV and install TWC. Pressure test tree to 5,000 psi. Wellhead Retrofit Well: MPU B-33 Date: 09/29/2021 30. Re-install flowline and instrumentation. 31. Weld centralizer/landing ring onto top of conductor. 32. Reinstall well house and backfill gravel over cellar liner. 33. Install Corrosion Inhibitor in SC by Conductor Annulus up to the conductor top. Slickline 34. MIRU SL unit. 35. Pressure test to 300 psi low and at least 2,000 psi high. 36. RIH and pull 4-1/2” mechanical plug at ~4600’ MD. 37. RDMO. 38. Turn well back over to operations. Operations Attachments: -Wellbore Schematic ___________________________________________________________________________________ Updated by DH 5/25/18 SCHEMATIC Milne Point Unit Well: MPB-33 PTD: 216-164 API: 50-029-23573-00-00 CASING DETAIL Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20”x34” Conductor 78.6/A-53/Weld N/A Surface 80’ N/A 9-5/8” Surface 40/L-80/DWC/C 8.679” Surface 5,248’ 0.0758 4-1/2" Prod Liner 13.5/L-80/Vam HTTC 3.795” 5,076’ 10,277’ 0.0149 TUBING DETAIL 4-1/2” Tubing 12.6/L-80/Supermax 3.833” Surface 5,087’ 0.0152 20” 9-5/8” @ 5,248’ MD JEWELRY DETAIL No. Item Top MD Btm MD Drift ID OD 1 Tubing Hanger 24.45’ 25.03’ - - 2 Stage Tool – Halliburton ES Cementer 1,912’ 1,915’ 8.679” 9.625” 3 4-1/2” KBMG GLM w/1” BK-DGLV (Set 4/03/17) 3,072’ 3,080’ 3.833” 6.437” 4 4-1/2” XN Profile (Min ID = 3.725” No-Go) 4,958’ 4,960’ 3.725” 4.785” 5 BOT Bullet Nose Seal (5.75” No-Go OD) 5,078’ 5,087’ 4.000” 5.235” 6 Liner Top Packer (HRD-E ZXP) 5,076’ 5,098’ 4.360” 5.960” 7 XO, 5” Hydril 521 x 4-1/2” Vam HTTC 5,098’ 5,085’ 3.920” 5.250” 8 Tendeka SwellRight Water Swell Packer #7 5,477’ 5,502’ 4.767” 8.125” 9 Halliburton ICD #7 w 3-0-1 Nozzle Configuration 6,002’ 6,011’ 3.833” 6.035” 10 Tendeka SwellRight Water Swell Packer #6 6,515’ 6,540’ 4.767” 8.125” 11 Halliburton ICD #6 w 3-0-1 Nozzle Configuration 6,795’ 6,804’ 3.833” 6.035” 12 Tendeka SwellRight Water Swell Packer #5 7,058’ 7,083’ 4.767” 8.125” 13 Halliburton ICD #5 w 3-0-1 Nozzle Configuration 7,298’ 7,307’ 3.833” 6.035” 14 Tendeka SwellRight Water Swell Packer #4 7,564’ 7,589’ 4.767” 8.125” 15 Halliburton ICD #4 w 3-0-1 Nozzle Configuration 7,844’ 7,854’ 3.833” 6.035” 16 Tendeka SwellRight Water Swell Packer #3 8,109’ 8,134’ 4.767” 8.125” 17 Halliburton ICD #3 w 3-0-1 Nozzle Configuration 8,473’ 8,483’ 3.833” 6.035” 18 Tendeka SwellRight Water Swell Packer #2 8,822’ 8,847’ 4.767” 8.125” 19 Halliburton ICD #2 w 3-0-1 Nozzle Configuration 9,266’ 9,276’ 3.833” 6.035” 20 Tendeka SwellRight Water Swell Packer #1 9,779’ 9,804’ 4.767” 8.125” 21 Halliburton ICD #1 w 3-0-1 Nozzle Configuration 10,183’ 10,192’ 3.833” 6.035” 22 BOT WIV Valve (Ball on Seat/Closed) 10,272’ 10,275’ - 4.980” 4-1/2” shoe @ 10,277’ 1 2 6 PBTD =10,272’ MD / 4,408’ TVD TD = 10,933’ MD / 4,408’TVD Max Deviation:93.13º 22 4 5 16 17 18 19 20 21 Orig. KB Elev: 49.2’ / Orig. GL Elev: 22.7’ RKB – Hanger: 24.45’ (Innovation Rig) 7 GENERAL WELL INFO API: 50-029-23573-00 Drilled and Cased by Innovation - 4/02/2017 10 11 12 13 14 15 8 9 OPEN HOLE / CEMENT DETAIL 42” 50 bbls (10 Yards Pilecrete dumped down backside) 12-1/4” 1st stage 500 sx 11.7# Extenda, 210 sx 15.8# SwiftCEM 12-1/4” 2nd stage 450 sx 10.7# Perm L, 275 sx 15.8# SwiftCEM 8-1/2” Cementless Liner w/ ICDs/Swell Pkrs in 8-1/2” hole WELL INCLINATION DETAIL KOP @ 300’ Max Hole Angle = 81.50 deg. @ XN profile Max Hole Angle = 86.13 deg. @ Tubing tail Max Hole Angle = 93.13 deg. @ 5,482’ MD Min ID = 3.725” 3 SAFETY NOTE Seaboard conductor supported wellhead. 50-80 Klbs max compressive load. Well Name MILNE PT UNIT B-33 State of Alaska MEMORANDUM Permit Number: 216-164-0 Inspection Date: 5132021 Alaska Oil and Gas Conservation Commission DATE: Tuesday, May 11, 2021 Regg �I�q,�227� TO: Jim Supery P.L1\ isor SUBJECT: Mechanical Integrity Tests Hilcorp Alaska. LLC Packer Depth Pretest Initial B-33 FROM: Matt Herrera MILNE PT UNIT B-33 Petroleum Inspector W TVD 7zs SM: Inspector ns Reviewed By: P.I. Sup" NON -CONFIDENTIAL Comm Well Name MILNE PT UNIT B-33 API Well Number 50-029-23573-00-00 Inspector Name: Man Herrera Permit Number: 216-164-0 Inspection Date: 5132021 Insp Num: mitMFH210503165327 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well B-33 Type Inj W TVD 7zs ns ns 7zs. pTp z1616ao Type Test sPr Test psi TA 467 1750 - 684 ' 1668BBL Pumped: 1.5 , q2Tubing BBL Returned:OA Interval 4YRTST PAF Notes: MIT -IA pressure tested to 1750 PSI per Operator for pass at minimum requirement. Well is a monobore completion no OA pressure to record Page 1 of l Tuesday, May 11, 2021 • • Hilcorp Alaska,LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Phone: 907/777-8547 SCANNEO JUN O7ZO16 June 5, 2018 RECEIVED Mr. Guy Schwartz Alaska Oil and Gas Conservation Commission JUN 0 6 2018 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 AOGCC Re: Conductor Annulus Corrosion Inhibitor Treatments 4/20/18-5/12/18 Dear Mr. Schwartz, Enclosed please find multiple copies of a spreadsheet with a list of wells that were treated with corrosion inhibiting casing filler in the surface casing by conductor annulus. The heavier than water "grease-like" filler displaces water to prevent external casing corrosion that could result in a surface casing leak. The attached spreadsheets include the well names, field, PTD and API numbers, treatment volumes and treatment dates. This treatment campaign represents primarily new Milne Point HAK drill wells along with two Northstar wells which previously had excavations and external surface casing leak repairs. If you have any additional questions,please contact me at 777-8547 or wrivard@hilcorp.com. 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Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: ., /� �JjDate: • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,May 09,2017 TO: Jim Regg �� , s I P.I.Supervisor t 7 SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC B-33 FROM: Bob Noble MILNE PT UNIT B-33 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name MILNE PT UNIT B-33 API Well Number 50-029-23573-00-00 Inspector Name: Bob Noble Permit Number: 216-164-0 Inspection Date: 5/1/2017 Insp Num: mitRCNI70501163017 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well B-33 - Type Inj W TVD 4428 Tubing 539 539 541 541 PTD 2161640 - Type Test SPT Test psi 1500 " IA 1021 1716 - 1684 - 1676 BBL Pumped: 1 BBL Returned: 1 OA Interval INITAL ✓ P/F P Notes: Mono-bore well. Tuesday,May 09,2017 Page 1 of I . �_ �� - -` `~ . ~ �� M-b 7-1( ) (0-1-0 Regg, James B (DOA) From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Thursday, May 4, 2O174:S2PK4 '/(5/(/ To: Regg, James B (DOA) Cc: Brooks, Phoebe L (DOA) Subject: RE: MIT of MPB3] (PTD #2161640) on 05/1/17 Attachments: MPB-33 Schematic 4-03-17.doc; MPU B-33 - Definitive Survey.pdf Jim, Sorry about the mixed up attachments. I've double checked the attached dev survey and schematic for B-33. If they still aren't going through properly, I will try a different format. Thanks, Wyatt Rivard I Well Integrity Engineer UUlco/yAlaska, LLC 0: (907) 777-8547 | C: (5UO)67U'80Ol IvvrivardPbUcorp.conn 3O00CeotcrpoinrDrive, Suite l4U0I Anchorage,AKY9503 %ANNEk��' I 1 >�)� From: Regg,James B (DOA) [nnaihojinn.regg@a|aska.gox] Sent:Thursday, May 04, 2017 1:00 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Brooks, Phoebe L(DOA) <phoebe.brooks@alaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 I asked because the attachments named B-33 were for B-34. If you have the well schematic and directional survey for B- 33 please send.Thank you. From: Wyatt Rivard [maiho:wrivard@hi|mrp.com] Sent:Thursday, May 4, 2017 12:55 PM To: Regg,James B (DOA)<jim.regg@alaska.gov> Cc: Brooks, Phoebe L(DOA)<phoebe.brooksalaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 Jim, By coincidence we had separate MIT-lAs on two newly drilled 8-Pad injectors within a few weeks of each other.This MIT-IA/email was conducted on produced water injector MPB-33 (PTD#2161640) on 5/1/17. We also had an EPA witnessed MIT-IA on the Class 1 UIC disposal well MPB-34 (PTD# 2161390) on 4/10/17 (sent on 5/2/17). I've attached both M|Ts again for reference. Please let me know if there is any additional information that I can provide. Thank You, Wyatt Rivard I Well integrity Engineer IUUcorp&|asba, LL[ 0: (907) 777-8547 | C: (5O9)670-8OO1 IvvdvardPhi|curp.com 3000CcotrrpoiutDrive,Suite l4OUI Anchorage,AK 99503 �� V From: Regg [mailto:iimsegg@alaska.gov] Sent:Thursday, May 04, 2017 12:06 PM To: Wyatt Rivard <wrivard@hilcorp.com> Cc: Brooks, Phoebe L(DOA) <phoebe.brooks@alaska.gov> Subject: RE: MIT of MPB-33 (PTD#2161640) on 05/1/17 Please confirm that the well should be MPU B-34 (PTD 2161390). From:Wyatt Rivard [mailto:wrivard@hilcorp.com] Sent:Wednesday, May 3, 2017 7:55 AM To: Wallace, Chris D (DOA)<chris.wallace@alaska.gov>; Brooks, Phoebe L(DOA)<phoebe.brooks@alaska.gov>; Regg, James B (DOA)<iim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe.bay@alaska.gov> Cc:Alaska NS- Milne -Wel!site Supervisors<AlaskaNS-Milne-WellsiteSupervisors@hilcorp.com>; Stan Porhola <spurho|a@hUcorp.com> Subject: MIT ofMPB'33 (PTD#2161640) on0S/1/17 All, Milne Point water injector MPB-33 (PTD#216164O) had a passing initial AOGCC witnessed MIT-IA on 5/1/17. Please see attached MIT form for reference. Deviation survey and wellbore schematic are also attached as this is a new drill well. Thank You, Wyatt Rivard I Well Integrity Engineer jFlilcorp Alaska, LLC 0: (907) 777-8547 C: (509)670'8002Ivvrvacd@bdoorp.000n 38OOCrntccpuintDrive,Suite 14O01Auchora#e,&Kg9S03 0 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.read(cDalaska.aov' AOGCC.Inspectors(talaska.dov phoebe.brooks(ojalaska.aov ch�ris..wallace(6 alaska.gov OPERATOR: Hilcorp Alaska,LLC ?IA 61 SI 0 FIELD/UNIT/PAD: Milne/MPU/B-Pad 1 `� DATE: 05/01/17 OPERATOR REP: Bill Kruskie AOGCC REP: Bob Noble Well MP B-33 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD 216-164 Type lnj W Tubing 539 539 541 541 Type Test P Packer TVD 4419 BBL Pump 1.0 IA 1021 ' 1716 - 1684 1676 1 Interval I Test psi 1500 ' BBL Return 1.0 ' OA Result P ✓ Notes: Initial pressure test for newly drilled injector.Monobore,No OA Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL 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 TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. • PTD Type Inj Tubing Type Test Packer TVO BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test I=Initial Test P=Pass G=Gas 0=Other(describe in Notes) 4=Four Year Cycle F=Fail S=Slurry V=Required by Variance I=Inconclusive I=Industrial Wastewater 0=Other(describe in notes) N=Not Injecting Form 10-426(Revised 01/2017) MIT MPU 0-33 5-1-17 ' • • Milne Point Unit 11 Well: MPB-33 SCHEMATIC PTD: 216-164 API: 50-029-23573-00-00 Hii,orp:1lnsk,,,1.1 Orig.KB Elev:49.2'/Orig.GL Ele5. v:22.7' RKB—Hanger:24.45'(Innovation Rig) CASING DETAIL A /1 kkl Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20" 20"x34" Conductor 78.6/A-53/Weld N/A Surface 80' N/A tif) ie 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,248' 0.0758 4-1/2" Prod Liner 13.5/L-80/Vam HTTC 3.795" 5,076' 10,277' 0.0149i ; TUBING DETAIL a 4-1/2" Tubing 12.6/L-80/Supermax 3.833" Surface 5,087' 0.0152 ifil JEWELRY DETAIL No. Item Top MD Btm MD Drift ID OD 261: 1 Tubing Hanger 24.45' 25.03' - - 2 Stage Tool—Halliburton ES Cementer 1,912' 1,915' 8.679" 9.625" 3 4-1/2"KBMG GLM w/1"BK-DGLV(Set 4/03/17) 3,072' 3,080' 3.833" 6.437" 4 4-1/2"XN Profile(Min ID=3.725"No-Go) 4,958' 4,960' 3.725" 4.785" 3 5 BOT Bullet Nose Seal(5.75"No-Go OD) 5,078' 5,087' 4.000" 5.235" ' ,` 6 Liner Top Packer(HRD-E ZXP) 5,076' 5,098' 4.360" 5.960" �� if1,1: 7 X0,5"Hydril 521 x 4-1/2"Vam HTTC 5,098' 5,085' 3.920" 5.250" ,:pi 8 Tendeka SwellRight Water Swell Packer#7 5,477' 5,502' 4.767" 8.125" 9 Halliburton ICD#7 w 3-0-1 Nozzle Configuration 6,002' 6,011' 3.833" 6.035" till Ph': 10 Tendeka SwellRight Water Swell Packer#6 6,515' 6,540' 4.767" 8.125" 11 Halliburton ICD#6 w 3-0-1 Nozzle Configuration 6,795' 6,804' 3.833" 6.035" 12 Tendeka SwellRight Water Swell Packer#5 7,058' 7,083' 4.767" 8.125" 13 Halliburton ICD#5 w 3-0-1 Nozzle Configuration 7,298' 7,307' 3.833" 6.035" 14 Tendeka SwellRight Water Swell Packer#4 7,564' 7,589' 4.767" 8.125" 15 Halliburton ICD#4 w 3-0-1 Nozzle Configuration 7,844' 7,854' 3.833" 6.035" ' 16 Tendeka SwellRight Water Swell Packer#3 8,109' 8,134' 4.767" 8.125" ' + 17 Halliburton ICD#3 w 3-0-1 Nozzle Configuration 8,473' 8,483' 3.833" 6.035" 3„;»a 18 Tendeka SwellRight Water Swell Packer#2 8,822' 8,847' 4.767" 8.125" 19 Halliburton ICD#2 w 3-0-1 Nozzle Configuration 9,266' 9,276' 3.833" 6.035" 20 Tendeka SwellRight Water Swell Packer#1 9,779' 9,804' 4.767" 8.125" 9 21 Halliburton ICD#1 w 3-0-1 Nozzle Configuration 10,183' 10,192' 3.833" 6.035" 'a ) ivitk. 4 .; 22 BOT WIV Valve(Ball on Seat/Closed) 10,272' 10,275' - 4.980" ail PO - Min ID=3.725" OPEN HOLE/CEMENT DETAIL 42" 50 bbls(10 Yards Pilecrete dumped down backside) 12-1/4"1st stage 500 sx 11.7#Extenda,210 sx 15.8#SwiftCEM 5 12-1/4"2nd stage 450 sx 10.7#Perm L,275 sx 15.8#SwiftCEM kwl rkillg . nii. 6 8-1/2" Cementless Liner w/ICDs/Swell Pkrs in 8-1/2"hole iiit1 9-5/8" 4-1/2"shoe *5,248' MD @ 10,277' 8 10 12 14 1618 20 ,,, „;ii_lif !,..,..,,,, ,. . .,,„,,„ , 21 22 I i WELL INCLINATION DETAIL GENERAL WELL INFO PBTD=10,272'MD/4,408'TVD KOP @ 300' API:50-029-23573-00 TD=10,933'MD/4,408'TVD Max Hole Angle=81.50 deg.@ XN profile Drilled and Cased by Innovation-4/02/2017 Max Deviation:93.13° Max Hole Angle=86.13 deg.@ Tubing tail Max Hole Angle=93.13 deg.@ 5,482'MD Updated by STP 4/05/17 . i ! Hilcorp Alaska, LLC Milne Point M Pt B Pad d ` MPU B-33 _;" / te IC-1t( ) 50-029-23573-00-00 F Drilling Definitive Survey Report 03 April, 2017 ,Ir / • �f r r / / a ' • awry Drilling • • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU 6-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt 6 Pad MD Reference: Actual:©48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU 8-33 Well Position +N1-S 0.00 usft Northing: 6,023,149.85 usft Latitude: 70°28'24.717 N +E/-W 0.00 usft Easting: 571,978.15 usft Longitude: 149°24'43.484 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.70 usft I Wellbore MPU B-33 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2016 3/20/2017 17.85 81.06 57,559 Design MPU B-33 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 26.00 0.00 0.00 314.00 Survey Program Date 4/3/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 728.00 MPU B-33 SRG-SS(MPU B-33) SRG-SS Surface readout gyro single shot 03/08/2017 789.17 5,221.05 MPU B-33 MWD+IFR2+MS+sag(1)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 03/18/2017 5,292.82 10,863.92 MPU B-33 MWD+IFR2+MS+sag(2)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 03/27/2017 Survey I Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 26.00 0.00 0.00 26.00 -22.70 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 UNDEFINED 100.00 0.40 159.44 100,00 51.30 -0.24 0.09 6,023,149.61 571,978.24 0.54 -0.23 SRG-SS(1) 165.00 0.22 68.61 165.00 116.30 -0.41 0.29 6,023,149.44 571,978.44 0.71 -0.49 SRG-SS(1) 228.00 0.42 108.61 228.00 179.30 -0.44 0.62 6,023,149.42 571,978.77 0.46 -0.75 SRG-SS(1) 290.00 0.94 56.96 289.99 241,29 -0.23 1.26 6,023,149.63 571,979,41 1.22 -1.07 SRG-SS(1) 352.00 2.25 34.28 351.97 303.27 1.05 2.37 6,023,150.92 571,980.51 2.31 -0.98 SRG-SS(1) 414.00 3.88 29.83 413.88 365.18 3.87 4.10 6,023,153.76 571,982.21 2.65 -0.26 SRG-SS(1) 476.00 4.94 25.61 475.69 426.99 8.10 6.30 6,023,158.01 571,984.37 1.79 1.10 SRG-SS(1) 539.00 6.17 25.09 538.40 489.70 13.61 8.91 6,023,163.55 571,986.92 1.95 3.05 SRG-SS(1) 602.00 6.15 28.08 601.03 552.33 19.66 11.93 6,023,169.62 571,989.89 0.51 5.07 SRG-SS(1) 665.00 6.17 22.47 663,67 614.97 25.76 14.81 6,023,175.75 571,992.71 0.96 7.24 SRG-SS(1) 728.00 6.36 22.81 726.29 677.59 32.11 17.46 6,023,182.12 571,995.30 0.31 9.74 SRG-SS(1) 4/3/2017 11:59:20AM Page 2 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 1 789.17 6.66 22.81 787.07 738.37 38.50 20.15 6,023,188.54 571,997 92 0.49 12.25 MWD+IFR2+MS+sag(2) 851.97 6.26 6.31 849.48 800.78 45.26 21.94 6,023,195.32 571,999.65 3.01 15.66 MWD+IFR2+MS+sag(2) 914.92 6.64 353.53 912.03 863.33 52.29 21.90 6,023,202.35 571,999.54 2.35 20.57 MWD+IFR2+MS+sag(2) 977.28 7.40 342.95 973.93 925.23 59.71 20.32 6,023,209.75 571,997.89 2.40 26.86 MWD+IFR2+MS+sa9(2) 1,040.25 8.65 332.25 1,036.28 987.58 67.78 16.93 6,023,217.79 571,994.42 3.09 34.91 MWD+IFR2+MS+sag(2) 1,103.54 9.99 321.38 1,098.74 1,050.04 76.28 11.28 6,023,226.23 571,988.69 3.49 44.87 MWD+IFR2+MS+sag(2) 1,166.35 10.95 318.85 1,160.50 1,111.80 85.03 3.96 6,023,234.91 571,981.28 1.69 56.22 MWD+IFR2+MS+sag(2) 1,229.56 11.82 313.90 1,222.47 1,173.77 94.04 -4.66 8,023,243.83 571,972.58 2.07 68.68 MWD+IFR2+MS+sag(2) 1,292.93 11.94 313.44 1,284.48 1,235.78 103.05 -14.10 6,023,252.75 571,963.06 0.24 81.72 MWD+IFR2+MS+sag(2) 1,355.16 11.73 313.54 1,345.39 1,296.69 111.83 -23.36 6,023,261.44 571,953.72 0.34 94.48 MWD+IFR2+MS+sag(2) 1,418.13 12.41 315.38 1,406.97 1,358.27 121.06 -32.75 6,023,270.58 571,944.24 1.24 107.65 MWD+IFR2+MS+sag(2) 1,480.94 11.44 312.14 1,468.42 1,419.72 130.04 -42.11 6,023,279.47 571,934.79 1.88 120.62 MWD+IFR2+MS+sag(2) 1,543.66 10.67 310.18 1,529.98 1,481.28 137.96 -51.16 6,023,287.30 571,925.67 1.37 132.63 MWD+IFR2+MS+sag(2) 1,606.58 10.74 309.83 1,591.80 1,543.10 145.48 -60.11 6,023,294.72 571,916.64 0.15 144.29 MWD+IFR2+MS+sag(2) 1,669.71 10.61 310.98 1,653.84 1,605.14 153.05 -69.01 6,023,302.22 571,907.67 0.40 155.96 MWD+IFR2+MS+sag(2) 1,732.36 10.66 310.41 1,715.41 1,666.71 160.59 -77.78 6,023,309.67 571,898.83 0.19 167.50 MWD+IFR2+MS+sag(2) 1,795.18 10.62 311.43 1,777.15 1,728.45 168.19 -86.54 6,023,317.18 571,889.99 0.31 179.09 MWD+IFR2+MS+sag(2) 1,857.92 10.80 314.50 1,838.80 1,790.10 176.14 -95.07 6,023,325.04 571,881.39 0.95 190.74 MWD+IFR2+MS+sag(2) 1,921.25 11.03 314.89 1,900.99 1,852.29 184.57 -103.60 6,023,333.39 571,872.78 0.38 202.73 MWD+IFR2+MS+sag(2) 1,984.31 10.67 313.48 1,962.92 1,914.22 192.84 -112.11 6,023,341.58 571,864.20 0.71 214.60 MWD+IFR2+MS+sag(2) 2,047.14 9.72 312.17 2,024.76 1,976.06 200.41 -120.26 6,023,349.07 571,855.97 1.56 225.72 MWD+IFR2+MS+sag(2) 2,109,97 10.02 312.51 2,086.66 2,037.96 207.66 -128.22 6,023,356'.24 571,847.94 0.49 236.48 MWD+IFR2+MS+sag(2) 2,173.54 9.81 311.72 2,149.28 2,100.58 215.00 -136.34 6,023,363.50 571,839.75 0.39 247.42 MWD+IFR2+MS+sag(2) 2,235.95 9.99 313.19 2,210.76 2,162.06 222.25 -144.25 6,023,370.67 571,831.77 0.50 258.15 MWD+IFR2+MS+sag(2) 2,299.04 10.27 313.70 2,272.86 2,224,16 229.88 -152.31 6,023,378.22 571,823.64 0.47 269.24 MWD+IFR2+MS+sag(2) 2,361.65 10.50 314.14 2,334.45 2,285.75 237.71 -160.44 6,023,385.97 571,815.44 0.39 280.53 MWD+IFR2+MS+sag(2) 2,424.79 9.99 313.17 2,396.58 2,347.88 245.46 -168.56 6,023,393.65 571,807.24 0.85 291.76 MWD+IFR2+MS+sag(2) 2,487.57 10.55 312.86 2,458.35 2,409.65 253.09 -176.74 6,023,401.20 571,798.98 0.90 302.95 MWD+IFR2+MS+sag(2) 2,550.74 10.79 312.89 2,520.43 2,471.73 261.05 -185.32 6,023,409.07 571,790.34 0.38 314.64 MWD+IFR2+MS+sag(2) 2,613.68 9.61 313.03 2,582.38 2,533.68 268.65 -193.47 6,023,416.59 571,782.11 1.88 325.79 MWD+IFR2+MS+sag(2) 2,675.82 9.45 310.83 2,643.66 2,594.96 275.52 -201.12 6,023,423.39 571,774.39 0.64 336.07 MWD+IFR2+MS+sag(2) 2,739.39 9.82 312.67 2,706.33 2,657.63 282.61 -209.06 6,023,430.40 571,766.39 0.76 346.70 MWD+IFR2+MS+sag(2) 2,802.20 10,09 317.10 2,768.20 2,719.50 290.27 -216.74 6,023,437.98 571,758.63 1.29 357.55 MWD+IFR2+MS+sag(2) 2,865.27 9.89 316.11 2,830.31 2,781.61 298.22 -224.26 6,023,445.86 571,751.04 0.42 368.48 MWD+IFR2+MS+sa9(2) 2,927.72 10.52 319.79 2,891.77 2,843.07 306.44 -231.66 6,023,454.01 571,743.56 1.45 379.51 MWD+IFR2+MS+sag(2) 2,991.01 10.85 319.99 2,953.97 2,905.27 315.41 -239.22 6,023,462.91 571,735.92 0.52 391.18 MWD+IFR2+MS+sag(2) 3,053.99 9.69 313.48 3,015.94 2,967.24 323.60 -246.87 6,023,471.02 571,728,18 2.60 402.38 MWD+IFR2+MS+sag(2) 3,117.13 9.44 312.42 3,078.20 3,029.50 330.75 -254.55 6,023,478.09 571,720.43 0.48 412.87 MWD+IFR2+MS+sag(2) 3,179.65 9.91 314.42 3,139.83 3,091.13 337.98 -262.18 6,023,485.24 571,712.74 0.92 423.37 MWD+IFR2+MS+sag(2) 3,242.77 10.22 315.74 3,201.98 3,153.28 345.79 -269.97 6,023,492.98 571,704.88 0.61 434.40 MWD+IFR2+MS+sag(2) 4/3/2017 11:59:20AM Page 3 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey I Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (0) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3.305.61 10.12 315.00 3,263.83 3,215.13 353.68 -277.76 6,023,500.80 571 697.01 0.26 445.49 MWD+IFR2+MS+sag(2) 3,368.58 10.58 317.80 3,325.78 3,277.08 361.88 -285.56 6,023,508.92 571,689.13 1.08 456.79 MWD+IFR2+MS+sag(2) 3,431.35 10.60 318.71 3,387.48 3,338.78 370.48 -293.24 6,023,517.45 571,681.37 0.27 468.30 MWD+IFR2+MS+sag(2) 3,493.98 10.63 318.99 3,449.04 3,400.34 379.17 -300.83 6,023,526.06 571,673.70 0.10 479.79 MWD+IFR2+MS+sag(2) 3,556.99 12.85 318.41 3,510.73 3,462.03 388.80 -309.29 6,023,535.60 571,665.14 3.53 492.57 MWD+IFR2+MS+sag(2) 3,620.10 14.38 317.01 3,572.06 3,523.36 399.78 -319.30 6,023,546.49 571,655.03 2.48 507.39 MWD+IFR2+MS+sag(2) , 3,682.54 17.07 316.75 3,632.16 3,583.46 412.13 -330.87 6,023,558.72 571,643.35 4.31 524.29 MWD+IFR2+MS+sag(2) 3,745.68 20.98 315.08 3,691.84 3,643.14 426.89 -345.20 6,023,573.34 571,628.87 6.25 544.88 MWD+IFR2+MS+sag(2) 3,808.79 24.40 314.37 3,750.06 3,701.36 444.01 -362.50 6,023,590.29 571,611.40 5.44 569.20 MWD+1FR2+MS+sag(2) 3,871.63 28.51 312.83 3,806.30 3,757.60 463.29 -382.79 6,023,609.37 571,590.93 6.63 597.18 MWD+IFR2+MS+sag(2) 3,934.88 31.40 312.85 3,861.10 3,812.40 484.76 -405.94 6,023,630.62 571,567.57 4.57 628.75 MWD+IFR2+MS+sag(2) 3,997.49 33.13 314.12 3,914.04 3,865.34 507.77 -430.19 6,023,653.39 571,543.11 2.97 662.17 MWD+IFR2+MS+sag(2) 4,060.51 36.50 313.79 3,965.77 3,917.07 532.73 -456.09 6,023,678.10 571,516.97 5.36 698.15 MWD+IFR2+MS+sag(2) 4,123.76 39.46 313.31 4,015.62 3,966.92 559.55 -484.30 6,023,704.63 571,488.51 4.70 737.07 MWD+IFR2+MS+sag(2) I 4,186.63 42.25 313.18 4,063.17 4,014.47 587.72 -514.25 6,023,732.51 571,458.28 4.44 778.18 MWD+IFR2+MS+sag(2) 4,249.66 46.84 313.86 4,108.08 4,059.38 618.16 -546.30 6,023,762.64 571,425.95 7.32 822.38 MWD+IFR2+MS+sag(2) 4,310.90 52.09 314.26 4,147.87 4,099.17 650.52 -579.73 6,023,794.67 571,392.21 8.59 868.91 MWD+IFR2+MS+sag(2) 4,375.80 53.38 315.75 4,187.16 4,138.46 687.05 -616.24 6,023,830.84 571,355.35 2.70 920.55 MWD+IFR2+MS+sag(2) 4,438.51 56.81 315.36 4,223.04 4,174.34 723.76 -852.25 6,023,867.20 571,318.99 5.49 971.95 MWD+IFR2+MS+sag(2) 4,501.59 57.97 315.58 4,257.04 4,208.34 761.64 -689.51 6,023,904.71 571,281.37 1.86 1,025.07 MWD+IFR2+MS+sag(2) 4,564.46 61.74 315.78 4,288.60 4,239.90 800.53 -727.49 6,023,943.23 571,243.02 6.00 1,079.40 MWD+IFR2+MS+sag(2) 4,627.07 64.31 315.26 4,317.00 4,268.30 840.33 -766.58 6,023,982.65 571,203.55 4.17 1,135.18 MWD+IFR2+MS+sag(2) 4,690.53 67.68 314.72 4,342.81 4,294.11 881.31 -807.58 6,024,023.23 571,162.16 5.37 1,193.13 MWD+IFR2+MS+sag(2) 4,753.00 71.43 313.53 4,364.63 4,315.93 922.05 -849.59 6,024,063.55 571,119.76 6.26 1,251.65 MWD+IFR2+MS+sag(2) 4,815.76 75.63 312.74 4,382.42 4,333.72 963.19 -893.50 6,024,104.26 571,075.46 6.80 1,311.82 MWD+IFR2+MS+sag(2) 4,878.72 78.85 311.35 4,396.33 4,347.63 1,004.30 -939.10 6,024,144.93 571,029.47 5.55 1,373.18 MWD+IFR2+MS+sag(2) Rc"- 4,941.48 81.46 310.57 4,407.06 4,358.36 1,044.83 -985.79 6,024,185.00 570,982.39 4.34 1,434.92 MWD+IFR2+MS+sag(2) 5,004.15 85.43 310.43 4,414.21 4,365.51 1,085.26 -1,033.13 6,024,224.96 570,934.67 6.34 1,497.05 MWD+IFR2+MS+sag(2) OP 5,040.32 86.79 310.19 4,416.66 4,367.96 1,108.60 -1,060.65 6,024,248.04 570,906.93 3.82 1,533.06 MWD+IFR2+MS+sag(2) 1� 5,067.17 86.13 311.06 4,418.32 4,369.62 1,126.05 -1,080.99 6,024,265.29 570,886.43 4.06 1,559.81 MWD+IFR2+MS+sag(2) 5,100.83 86.53 310.85 4,420.48 4,371.78 1,148.07 -1,106.35 6,024,287.06 570,860.85 1.34 1,593.36 MWD+IFR2+MS+sag(2) 5,130.21 85.68 311.11 4,422.47 4,373.77 1,167.29 -1,128.48 6,024,306.08 570,838.54 3.02 1,622.63 MWD+IFR2+MS+sag(2) 5,221.05 87.87 308.51 4,427.58 4,378.88 1,225.35 -1,198.14 6,024,363.44 570,768.33 3.74 1,713.07 MWD+IFR2+MS+sag(2) 5,292.82 87.32 315.49 4,430.60 4,381.90 1,273.30 -1,251.40 6,024,410.87 570,714.61 9.75 1,784.69 MWD+IFR2+MS+sag(3) 5,355.73 89,61 315.83 4,432.28 4,383.58 1,318.27 -1,295.35 6,024,455.41 570,670.23 3.68 1,847.54 MWD+IFR2+MS+sag(3) 5,418.33 92.26 316.18 4,431.26 4,382.56 1,363.30 -1,338.82 6,024,500.01 570,626.33 4.27 1,910.09 MWD+IFR2+MS+sag(3) 5,481.68 93.13 315.16 4,428.28 4,379.58 1,408.56 -1,383.04 6,024,544.84 570,581.68 2.11 1,973.34 MWD+IFR2+MS+sag(3) 5,543.98 91.77 314.97 4,425.62 4,376.92 1,452.62 -1,427.00 6,024,588.47 570,537.30 2.20 2,035.57 MWD+IFR2+MS+sag(3) 5,607.01 90.78 313.60 4,424.22 4,375.52 1,496.62 -1,472.11 6,024,632.02 570,491.77 2.68 2,098.59 MWD+IFR2+MS+sag(3) 5,670.17 90.23 311.98 4,423.66 4,374.96 1,539.52 -1,518.46 6,024,674.47 570,445.02 2.71 2,161.73 MWD+IFR2+MS+sag(3) 4/3/2017 11:59:20AMPage 4 COMPASS 5000.1 Build 81 \ 4411 ' ,T • • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA j Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +E/-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (0/1001 (ft) Survey Tool Name 5,732.80 90.90 310.99 4,423.04 4,374.34 1,581.01 -1,565.37 6,024,715.50 570,397.71 1.91 2,224.29 MWD+IFR2+MS+sag(3) 5,795.79 91.65 311.42 4,421.64 4,372.94 1,622.49 -1,612.75 6,024,756.52 570,349.94 1.37 2,287.19 MWD+IFR2+MS+sag(3) 5,858.83 91.71 311.44 4,419.79 4,371.09 1,664.19 -1,660.00 6,024,797.75 570,302.30 0.10 2,350.14 MWD+IFR2+MS+sag(3) 5,921.86 90.90 311.55 4,418.36 4,369.66 1,705.94 -1,707.19 6,024,839.04 570,254.70 1.30 2,413.09 MWD+IFR2+MS+sag(3) 5,984.62 90.16 311.68 4,417.78 4,369.08 1,747.62 -1,754.11 6,024,880.26 570,207.39 1.20 2,475.80 MWD+IFR2+MS+sag(3) 6,047.51 90.97 311.33 4,417.16 4,368.46 1,789.29 -1,801.21 6,024,921.47 570,159.89 1.40 2,538.62 MWD+IFR2+MS+sag(3) 6,110.44 90.16 312.03 4,416.54 4,367.84 1,831.13 -1,848.20 6,024,962.85 570,112.50 1.70 2,601.50 MWD+IFR2+MS+sag(3) 6,173.96 90.10 311.92 4,416.39 4,367.69 1,873.62 -1,895.43 6,025,004.87 570,064.87 0.20 2,664.98 MWD+IFR2+MS+sag(3) 6,236.09 89.86 312.25 4,416.41 4,367.71 1,915.26 -1,941.54 6,025,046.06 570,018.37 0.66 2,727.07 MWD+IFR2+MS+sag(3) 6,299.00 89.67 313.03 4,416.67 4,367.97 1,957.87 -1,987.81 6,025,088.22 569,971.68 1.28 2,789.96 MWD+IFR2+MS+sag(3) 6,361.66 89.67 313.77 4,417.03 4,368.33 2,000.92 -2,033.34 6,025,130.83 569,925.75 1.18 2,852.62 MWD+IFR2+MS+sag(3) 6,425.48 90.23 314.81 4,417.09 4,368.39 2,045.49 -2,079.02 6,025,174.94 569,879.64 1.85 2,916.44 MWD+IFR2+MS+sag(3) 6,488.02 90.23 316.22 4,416.84 4,368.14 2,090.10 -2,122.85 6,025,219.13 569,835.39 2.25 2,978.95 MWD+IFR2+MS+sag(3) 6,551.00 89.42 316.09 4,417.03 4,368.33 2,135.53 -2,166.47 6,025,264.12 569,791.33 1.30 3,041.89 MWD+IFR2+MS+sag(3) 6,613.62 89.73 317.43 4,417.49 4,368.79 2,181.14 -2,209.37 6,025,309.32 569,748.00 2.20 3,104.43 MWD+IFR2+MS+sag(3) 6,676.59 89.86 317.67 4,417.72 4,369.02 2,227.60 -2,251.87 6,025,355.36 569,705.06 0.43 3,167.28 MWD+IFR2+MS+sag(3) 6,739.66 90.23 318.19 4,417.67 4,368.97 2,274.42 -2,294.13 6,025,401.77 569,662.35 1.01 3,230.20 MWD+IFR2+MS+sag(3) 6,802.39 90.35 318.11 4,417.35 4,368.65 2,321.15 -2,335.98 6,025,448.08 569,620.05 0.23 3,292.77 MWD+IFR2+MS+sag(3) 6,865.38 90.35 317.21 4,416.97 4,368.27 2,367.71 -2,378.40 6,025,494.22 569,577.19 1.43 3,355.63 MWD+IFR2+MS+sag(3) 6,928.33 89.67 313.75 4,416.96 4,368.26 2,412.58 -2,422.53 6,025,538.67 569,532.63 5.60 3,418.55 MWD+IFR2+MS+sag(3) 6,991.29 89.48 312.42 4,417.42 4,368.72 2,455.59 -2,468.51 6,025,581.22 569,486.24 2.13 3,481.49 MWD+IFR2+MS+sag(3) 7,054.14 89.61 311.32 4,417.92 4,369.22 2,497.54 -2,515.31 6,025,622.71 569,439.04 1.76 3,544.30 MWD+IFR2+MS+sag(3) 7,116.83 89.86 311.17 4,418.21 4,369.51 2,538.87 -2,562.45 6,025,663.58 569,391.51 0.47 3,606.91 MWD+IFR2+MS+sag(3) 7,179.92 89.86 311.47 4,418.37 4,369.67 2,580.52 -2,609.83 6,025,704.77 569,343.73 0.48 3,669.94 MWD+IFR2+MS+sag(3) 7,242.84 69.98 310.52 4,418.46 4,369.76 2,621.80 -2,657.32 6,025,745.58 569,295.85 1.52 3,732.77 MWD+IFR2+MS+sag(3) 7,305.86 89.86 309.70 4,418.54 4,369.84 2,662.40 -2,705.52 6,025,785.71 569,247.27 1.32 3,795.64 MWD+IFR2+MS+sag(3) 7,368.63 90.10 308.74 4,418.56 4,369.86 2,702.09 -2,754.15 6,025,824.92 569,198.26 1.58 3,858.19 MWD+IFR2+MS+sag(3) 7,431.16 90.78 308.75 4,418.08 4,369.38 2,741.22 -2,802.92 6,025,863.58 569,149.12 1.09 3,920.46 MWD+IFR2+MS+sa9(3) 7,494.24 91.09 307.98 4,417.06 4,368.36 2,780.37 -2,852.37 6,025,902.24 569,099.30 1.32 3,983.23 MWD+IFR2+MS+sag(3) 7,557.38 89.36 306.72 4,416.81 4,368.11 2,818.67 -2,902.56 6,025,940.05 569,048.74 3.39 4,045.94 MWD+IFR2+MS+sag(3) 7,620.13 89.42 305.13 4,417.48 4,368.78 2,855.48 -2,953.37 6,025,976.37 568,997.59 2.54 4,108.06 MWD+IFR2+MS+sag(3) 7,683.60 89.61 305.64 4,418.01 4,369.31 2,892.23 -3,005.11 6,026,012.62 568,945.49 0.86 4,170.81 MWD+IFR2+MS+sag(3) 7,746.34 89.86 307.16 4,418.30 4,369.60 2,929.46 -3,055.61 6,026,049.35 568,894.64 2.46 4,233.00 MWD+IFR2+MS+sag(3) 7,809.26 90.10 307.53 4,418.33 4,369.63 2,967.63 -3,105.63 6,026,087.03 568,844.26 0.70 4,295.49 MWD+IFR2+MS+sag(3) 7,871.89 89.92 307.91 4,418.31 4,369.61 3,005.95 -3,155.17 6,026,124.86 568,794.36 0.67 4,357.75 MWD+IFR2+MS+sag(3) 7,934.96 90.16 308.04 4,418.27 4,369.57 3,044.76 -3,204.89 6,026,163.19 568,744.27 0.43 4,420.47 MWD+IFR2+MS+sag(3) 7,997.95 90.53 307.76 4,417.89 4,369.19 3,083.45 -3,254.59 6,026,201.39 568,694.20 0.74 4,483.10 MWD+IFR2+MS+sag(3) 8,060.82 91.15 306.99 4,416.97 4,368.27 3,121.61 -3,304.55 6,026,239.06 568,643.88 1.57 4,545.55 MWD+IFR2+MS+sag(3) 8,121.91 90.90 307.36 4,415.88 4,367.18 3,158.52 -3,353.21 6,026,275.50 568,594.86 0.73 4,606.19 MWD+IFR2+MS+sag(3) 8,184.88 90.66 307.83 4,415.02 4,366.32 3,196.93 -3,403.10 6,026,313.42 568,544.61 0.84 4,668.76 MWD+IFR2+MS+sag(3) 4/3/2017 11:59:20AM Page 5 COMPASS 5000.1 Build 81 Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU 5-33 Project: Milne Point TVD Reference: Actual:©48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,249.00 90.53 307.79 4,414.35 4,365.65 3,236.24 -3,453.76 6,026,352.23 568,493.58 0.21 4,732.51 MWD+IFR2+M5+sag(3) 8,311.62 90.72 308.40 4,413.67 4,364.97 3,274.87 -3,503.04 6,026,390.38 568,443.94 1.02 4,794.79 MWD+IFR2+MS+sag(3) 8,377.60 90.41 308.99 4,413.02 4,364.32 3,316.12 -3,554.53 6,026,431.13 568,392.05 1.01 4,860.49 MWD+IFR2+MS+sag(3) 8,438.11 90.29 310.19 4,412.65 4,363.95 3,354.68 -3,601.16 6,026,469.23 568,345.06 1.99 4,920.81 MWD+IFR2+MS+sag(3) 8,501.45 90.41 310.57 4,412.26 4,363.56 3,395.71 -3,649.41 6,026,509.79 568,296.42 0.63 4,984.03 MWD+IFR2+MS+sag(3) 8,564.69 91.65 312.03 4,411.13 4,362.43 3,437.44 -3,696.91 6,026,551.06 568,248.52 3.03 5,047.18 MWD+IFR2+MS+sag(3) 8,627.85 91.59 311.43 4,409.34 4,360.64 3,479.46 -3,744.02 6,026,592.62 568,201.01 0.95 5,110.27 MWD+IFR2+MS+sag(3) 8,690.82 91.52 311.99 4,407.64 4,358.94 3,521.21 -3,790.87 6,026,633.91 568,153.77 0.90 5,172.97 MWD+IFR2+MS+sag(3) 8,753.12 90.47 311.87 4,406.55 4,357.85 3,562.97 -3,837.36 6,026,675.21 568,106.88 1.69 5,235.41 MWD+IFR2+MS+sag(3) 8,816.21 90.29 312.28 4,406.13 4,357.43 3,605.25 -3,884.18 6,026,717.03 568,059.65 0.71 5,298.47 MWD+IFR2+MS+sag(3) 8,878.76 89.98 308.58 4,405.99 4,357.29 3,645.80 -3,931.79 6,026,757.12 568,011.66 5.94 5,360.88 MWD+IFR2+MS+sag(3) 8,942.00 88.62 305.08 4,406.76 4,358.06 3,683.70 -3,982.39 6,026,794.52 567,960.69 5.94 5,423.61 MWD+IFR2+MS+sag(3) 9,004.97 89.98 307.15 4,407.53 4,358.83 3,720.81 -4,033.26 6,026,831.14 567,909.48 3.93 5,485.98 MWD+IFR2+MS+sag(3) 9,066.90 90.84 309.03 4,407.08 4,358.38 3,759.01 -4,081.99 6,026,868.86 567,860.38 3.34 5,547.58 MWD+IFR2+MS+sag(3) 9,131.11 90.41 312.02 4,406.38 4,357.68 3,800.73 -4,130.79 6,026,910.10 567,811.19 4.70 5,611.66 MWD+IFR2+MS+sag(3) 9,193.31 90.78 314.29 4,405.74 4,357.04 3,843.27 -4,176.16 6,026,952.19 567,765.41 3.70 5,673.84 MWD+IFR2+MS+sag(3) 9,256.41 90.10 314.09 4,405.25 4,356.55 3,887.25 -4,221.41 6,026,995.73 567,719.75 1.12 5,736.94 MWD+IFR2+MS+sag(3) 9,319.41 90.23 313.38 4,405.07 4,356.37 3,930.80 -4,266.93 6,027,038.84 567,673.81 1.15 5,799.94 MWD+IFR2+MS+sag(3) 9,382.18 90.90 314.90 4,404.45 4,355.75 3,974.51 -4,311.97 6,027,082.10 567,628.35 2.65 5,862.70 MWD+IFR2+MS+sag(3) 9,445.30 91.03 315.32 4,403.39 4,354.69 4,019.22 -4,356.51 6,027,126.38 567,583.39 0.70 5,925.80 MWD+IFR2+MS+sag(3) 9,507.86 90.84 315.47 4,402.37 4,353.67 4,063.76 -4,400.43 6,027,170.48 567,539.04 0.39 5,988.34 MWD+IFR2+MS+sag(3) 9,570.67 90.16 314.08 4,401.82 4,353.12 4,107.99 -4,445.02 6,027,214.28 567,494.03 2.46 6,051.14 MWD+IFR2+MS+sag(3) 9,633.58 89.98 313.58 4,401.74 4,353.04 4,151.56 -4,490.40 6,027,257.40 567,448.24 0.84 6,114.05 MWD+IFR2+MS+sag(3) 9,696.85 91.52 315.60 4,400.92 4,352.22 4,195.97 -4,535.45 6,027,301.37 567,402.76 4.01 6,177.30 MWD+IFR2+MS+sag(3) 9,759.65 89.55 315.03 4,400.33 4,351.63 4,240.61 -4,579.61 6,027,345.58 567,358.18 3.27 6,240.08 MWD+IFR2+MS+sag(3) 9,822.62 88.81 314.06 4,401.23 4,352.53 4,284.78 -4,624.48 6,027,389.31 567,312.89 1.94 6,303.04 MWD+IFR2+MS+sag(3) 9,885.60 88.50 312.62 4,402.71 4,354.01 4,327.99 -4,670.27 6,027,432.07 567,266.68 2.34 6,365.99 MWD+IFR2+MS+sag(3) 9,948.28 88.50 309.96 4,404.35 4,355.65 4,369.34 -4,717.35 6,027,472.95 567,219.21 4.24 6,428.58 MWD+IFR2+MS+sag(3) 10,011.51 89.05 309.24 4,405.70 4,357.00 4,409.63 -4,766.06 8,027,512.77 567,170.12 1.43 6,491.61 MWD+IFR2+MS+sag(3) 10,074.80 89.42 310.06 4,406.55 4,357.85 4,450.01 -4,814.78 6,027,552.67 567,121.01 1.42 6,554.71 MWD+IFR2+MS+sag(3) 10,137.68 89.79 310.24 4,406.98 4,358.28 4,490.55 -4,862.84 6,027,592.75 567,072.57 0.65 6,617.44 MW0+1FR2+MS+sag(3) 10,200.54 89.48 310.96 4,407.38 4,358.68 4,531.46 -4,910.57 6,027,633.19 567,024.45 1.25 6,680.19 MWD+IFR2+MS+sag(3) 10,263.26 89.86 311.51 4,407.74 4,359.04 4,572.80 -4,957.74 6,027,674.07 566,976.89 1.07 6,742.84 MWD+IFR2+MS+sag(3) 10,326.53 89.98 312.21 4,407.83 4,359.13 4,615.02 -5,004.86 6,027,715.82 566,929.37 1.12 6,806.06 MWD+IFR2+MS+sag(3) 10,389.26 90.60 313.82 4,407.51 4,358.81 4,657.81 -5,050.72 6,027,758.17 566,883.10 2.75 6,868.78 MWD+IFR2+MS+sag(3) 10,452.31 90.60 314.74 4,406.85 4,358.15 4,701.83 -5,095.86 6,027,801.74 566,837.54 1.46 6,931.83 MWD+IFR2+MS+sag(3) 10,515.10 89.61 313.29 4,406.74 4,358.04 4,745.46 -5,141.01 6,027,844.93 566,791.97 2.80 6,994.61 MWD+IFR2+MS+sag(3) 10,577.99 90.10 312.10 4,406.90 4,358.20 4,788.10 -5,187.23 6,027,887.12 566,745.35 2.05 7,057.49 MWD+IFR2+MS+sag(3) 10,640.33 90.10 311.82 4,406.79 4,358.09 4,829.78 -5,233.59 6,027,928.34 566,698.59 0.45 7,119.79 MWD+IFR2+MS+sag(3) 10,704.13 90.04 310.21 4,406.71 4,358.01 4,871.65 -5,281.73 6,027,969.74 566,650.06 2.53 7,183.50 MWD+IFR2+MS+sag(3) 4/3/2017 11:59:20AM Page 6 COMPASS 5000.1 Build 81 4- • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,766.71 89.42 308.83 4,407.01 4,358.31 4,911.47 -5,330.00 6,028,009.09 566,601.41 2.42 7,245.88 MWD+IFR2+MS+sag(3) i 10,830.00 89.48 308.07 4,407.61 4,358.91 4,950.83 -5,379.56 6,028,047.96 566,551.47 1.20 7,308.87 MWD+IFR2+MS+sag(3) 10,863.92 89.61 307.87 4,407.88 4,359.18 4,971.69 -5,406.30 6,028,068.56 566,524.53 0.70 7,342.61 MWD+IFR2+MS+sag(3) 10,933.00 89.61 307.87 4,408.35 4,359.65 5,014.10 -5,460.83 6,028,110.44 566,469.60 0.00 7,411.29 PROJECTED to TD mitchell.laird@halliburton.com benjamin.hand@halliburton.com Checked By: 2017.04.0310:20:30-08'00' Approved By: 2017.04.0309:24:07-08'00' Date: 4/3/2017 4/3/2017 11:59:20AM Page 7 COMPASS 5000.1 Build 81 0 • o n O ' O o -o N N O a ;D > c) r in _ tY CC 0 a) 7, McL) M ❑ a Z a a ❑ ❑ N 45 ❑ ❑ 0 0 is CO < Q D < < < < "° > Q Q < < Ch U f� �I CC a) CC CC CC CC c c CC 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V c C E I O � d M V V 216164 Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 RECEIVED Hilcorp AK 99503 Tele: 907 777-8308 1lileurp.tlsieka,1.1A; Fax: 907 777-8510 DATA LOGGED JUN 29 2017 E-mail: snolan@hilcorp.com 1 i 3/201/ r1. K.BENDER AOGCC DATE 05/02/17 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL MPU B-33 Production profile and digital data Prints: ROP-DGR-EWR-ADR-Horizontal Presentation 2"/5" MD DGR-EWR-ADR 2"/5"TVD CD1: 2 8 3 3 1 _Log Viewers 4/3/2017 10:33 PM File folder CGM 4/3/201710:33 PM File folder Definitive Survey 4/3(201710:33 PM File folder EMF 4/3/2017 10:33 PM File folder LAS 4/3/2017 10:33 PM File folder PDF 4/3/2017 10:33 PM File folder , TIFF 4/3/2017 10:33 PM File folder CD2: 2 8 3 3 2 j MPU B-33 Geosteering Log.emf 3/30/2017 7:58 AM EMF File 10,418 KB MPU B-33 Geosteering Log.pdf 3/30/2017 7:55 AM PDF Document 1,720 KB MPU B-33 Geosteering Log.tif 3/30/2017 7:56 AM TIF File 6,340 KB MPU 6-33 Geosteering EQW Report.pdf 4/1/2017 3:10 PM PDF Document 7,026 KB I `I MPU B-33 Post-Well Geosteering X-Section S... 3/29/2017 8:06 PM Microsoft PowerPoi... 922 KB Z. MPU 6-33 recorded Geosteering Log.emf 3/30/2017 7:49 AM EMF File 13,245 KB MPU 6-33 recorded Geosteering Log.pdf 3/30/2017 7:45 AM PDF Document 16,910 KB MPU B-33 recorded Geosteering Log.of 3/30/2017 7:48 AM TIF File 6,642 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: /�j Date: 0 • RECEIVED STATE OF ALASKA MAY 01 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT MAW 1 a.Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑ Exploratory ❑ GINJ ❑ WINJ ❑✓ , WAGE] WDSPL❑ No. of Completions: _1 Service ❑., Stratigraphic Test ❑ 2.Operator Name: 6. Date Comp., Susp.,or 14. Permit to Drill Number/ Sundry: I Hilcorp Alaska, LLC . Aband.: 4/2/2017 216-164 . 3.Address: 7. Date Spudded: /4/14- 15.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 March 16,2017 t, 50-029-23573-00-00 ' 4a. Location of Well(Governmental Section): 8. Date TD Reached: 16.Well Name and Number: Surface: 4313'FEL,27'FSL, Sec 18,T13N, R11 E, UM,AK March 28,2017 MPU B-33 . Top of Productive Interval: 9. Ref Elevations: KB: 49.2' 17. Field/Pool(s): N/A GL:22.7' BF:22.7' Milne Point Field/Schrader Bluff Oil Pool ' Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 241'FNL,718'FWL,Sec 13,T13N, R10E, UM,AK 10,272'MD/4,408'TVD ADL047438/ADL047437 • 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 571978 y- 6023149 Zone- 4 10,933'MD/4,408'TVD , N/A TPI: x- y- Zone- 12.SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 566469 y- 6028110 Zone- 4 N/A 1,588'MD/1,574'TVD 5. Directional or Inclination Survey: Yes ❑(attached) No ❑ 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 evaluation,,casing collar locator,jewelry,and perforation record. Acronyms may be used.Attach a separate page if necessary 2"MDITVD Gamma/Res+ADR; 5"MD/TVD Gamma/Res+ADR; 2"/5"MD Stratasteer Geosteering Logs 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 20" 78.6# A-53 Surface 80' Surface 80' 42" 50 bbls dumped(Backside) Stg 1 L-500 sx/T-210 sx 40 bbls 9-5/8" 40# L-80 Surface 5,248' Surface 4,429' 12-1/4" Stg 2 L-450 sx/T-275 sx 228.6 bbls 4-1/2" 13.5# L-80 5,076' 10,277' 4,419' 4,407' 8-1/2" Cementless Liner w/ICDs 24.Open to production or injection? Yes Q No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforatio (MIX TVD) SIZE DEPTH SET(MD) PACKER SET(MTVD) Size and Number): 58 `NJC.'• 6.441=+, /&+�`'-c-r�`- 4-1/2" 5,087'MD Tieback Seal @ (7)Halliburton Injection Control Devices w/3-0-1 Nozzle Configuration 5,087'MD/4,419 ND *See attached schematic for ICD&Swell Packer detail" 26.ACID,FRACTURE,CEMENT SQUEEZE, ETC. z 77' MLS Was hydraulic fracturing used during completion'? Yes❑ No 0 G ti sit 7 7. y ut I z(ii- Per 20 AAC 25.283(i)(2)attach electronic and printed information 4:-A;Teitit- DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED /,�. �'i' i ..:-a-i7 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 0.. ! Flow Tubing Casing Ppess: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate — ii(ki 440– Form 10-407 Revised 11/2015 "1°07 CONTINUED ON PAGE 2 BDMS kA, t:-,•'' - 2 2017 Submit ORIGINIAL only 28.CORE DATA Conventional (s): Yes ❑ No ❑] Sidewall CoreYes ❑ No ❑Q If Yes, list formations and intervals cored(MD/TVD, From/To), and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed). Submit detailed descriptions,core chips, photographs,and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No Ei Permafrost-Top If yes, list intervals and formations tested, briefly summarizing test results. Permafrost-Base 1,588' 1,574' Attach separate pages to this form, if needed,and submit detailed test Top of Productive Interval N/A N/A information, including reports,per 20 AAC 25.071. SV3 2,154' 2,130' Ugnu UG4 2,941' 2,904' Ugnu LA3 3,998' 3,915' Schrader NA 4,829' 4,385' Schrader NC 5,139' 4,423' Formation at total depth: Schrader NC 31. List of Attachments: Wellbore Schematic, Daily Drilling and Completion Reports, Definitive Directional Surveys,Casing and Cement Report, Surveillance Graphs 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. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Cody Dinger Email: cdinger(c�hilcorp.com Printed Name: Cody Din er Title: Drilling Tech Signature: Phone: 777-8389 Date: 5/1 /20 VI- INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item la: 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 1 b: Well Class-Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation, or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level,and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost.Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in, or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips,photographs,and all subsequent laboratory analytical results, including, but not limited to:porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey,and other tests as required including,but not limited to:core analysis, paleontological report,production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only Milne Point Unit H . • Well: MPB-33 PTD:216-164 SCHEMATIC API: 50-029-23573-00-00 Hileorp Alaska,LLC Orig.KB Elev:49.2'/Orig.GL Elev:22.7' RKB—Hanger:24.45'(Innovation Rig) CASING DETAIL \____71 '' �' Size Type Wt/Grade/Conn Drift ID Top Btm BPF 20" . 20"x34" Conductor 78.6/A-53/Weld N/A Surface 80' N/A 1 9-5/8" Surface 40/L-80/DWC/C 8.679" Surface 5,248' 0.0758 P '• 4-1/2" Prod Liner 13.5/L-80/Vam HTTC 3.795" 5 076' 10 277' 0.0149 .. , a44 TUBING DETAIL 4*' 4-1/2" Tubing 12.6/L-80/Supermax 3.833" Surface 5,087' 0.0152 , -P _si JEWELRY DETAIL No. Item Top MD Btm MD Drift ID OD 2. ry 1 Tubing Hanger 24.45' 25.03' - - '''.4 2 Stage Tool—Halliburton ES Cementer 1,912' 1,915' 8.679" 9.625" ` _' 3 4-1/2"KBMG GLM w/1"BK-DGLV(Set 4/03/17) 3,072' 3,080' 3.833" 6.437" 1 ' 4 4-1/2"XN Profile(Min ID=3.725"No-Go) 4,958' 4,960' 3.725" 4.785" air:.4. 3 4 5 BOT Bullet Nose Seal(5.75"No-Go OD) 5,078' 5,087' 4.000" 5.235" ri ': 1 6 Liner Top Packer(HRD-E ZXP) 5,076' 5,098' 4.360" 5.960" . a 7 XO,5"Hydril 521 x 4-1/2"Vam HTTC 5,098' 5,085' 3.920" 5.250" * M 8 Tendeka SwellRight Water Swell Packer#7 5,477' 5,502' 4.767" 8.125" 9 Halliburton ICD#7 w 3-0-1 Nozzle Configuration 6,002' 6,011' 3.833" 6.035" '; 10 Tendeka SwellRight Water Swell Packer#6 6,515' 6,540' 4.767" 8.125" 11 Halliburton ICD#6 w 3-0-1 Nozzle Configuration 6,795' 6,804' 3.833" 6.035" 12 Tendeka SwellRight Water Swell Packer#5 7,058' 7,083' 4.767" 8.125" 13 Halliburton ICD#5 w 3-0-1 Nozzle Configuration 7,298' 7,307' 3.833" 6.035" 14 Tendeka SwellRight Water Swell Packer#4 7,564' 7,589' 4.767" 8.125" ` °' 15 Halliburton ICD#4 w 3-0-1 Nozzle Configuration 7,844' 7,854' 3.833" 6.035" 16 Tendeka SwellRight Water Swell Packer#3 8,109' 8,134' 4.767" 8.125" ' '4 17 Halliburton ICD#3 w 3-0-1 Nozzle Configuration 8,473' 8,483' 3.833" 6.035" '; 18 Tendeka SwellRight Water Swell Packer#2 8,822' 8,847' 4.767" 8.125" 19 Halliburton ICD#2 w 3-0-1 Nozzle Configuration 9,266' 9,276' 3.833" 6.035" ' '', 20 Tendeka SwellRight Water Swell Packer#1 9,779' 9,804' 4.767" 8.125" 4 21 Halliburton ICD#1 w 3-0-1 Nozzle Configuration 10,183' 10,192' 3.833" 6.035" 22 BOT WIV Valve(Ball on Seat/Closed) 10,272' 10,275' 4.980" .„ yiMin ID=3.725" OPEN HOLE/CEMENT DETAIL ' 42" 50 bbls(10 Yards Pilecrete dumped down backside) r 12-1/4"1st stage 500 sx 11.7#Extenda,210 sx 15.8#SwiftCEM 5 n4 12-1/4"2nd stage 450 sx 10.7#Perm L,275 sx 15.8#SwiftCEM i= ' „ � 6 8-1/2" Cementless Liner w/ICDs/Swell Pkrs in 8-1/2"hole 9-5/8" 4-1/2"shoe 5,248'MD 8 10 12 14 16 18 20 @ Io,277' 9 11 13 15 17 19 � + 122 Spiv. SA.,c4- "N�: 11 s,4N2 1!11� ;. cTFurir . ma 111 II IIII II III IN IN im WELL INCLINATION DETAIL GENERAL WELL INFO PBTD=10,272'MD/4,408'TVD KOP @ 300' API:50-029-23573-00 TD=10,933'MD/4,408'TVD Max Hole Angle=81.50 deg.@ XN profile Drilled and Cased by Innovation-4/02/2017 Max Deviation:93.13° Max Hole Angle=86.13 deg.@ Tubing tail Max Hole Angle=93.13 deg.@ 5,482'MD Updated by STP 4/05/17 • • Hilcorp Energy Company Composite Report Well Name: MP B-33 Field: Milne Point County/State: ,Alaska (LAT/LONG): :vation(RKB): 26.65 API#: Spud Date: 3/15/2017 Job Name: 1612656D MPB-33 Drilling Contractor AFE#: AFE$: MINN* ....... . .r.. :. .. . :: . :.. .......:..::.::::. 3/11/2017 Blow down steam to rig, Put rig on cold start power.Fuel Day tanks,Disconnect interconnects, Prep derrick to scope down.Scope down Derrick.Note:Rig released from B-32©0600.;Move Power Mod,Pits,Pipe shed,Cat Walk&Sub off of well and out f the way of B-32. Install heaters in Pump Room&Sub to perform maintenance on pumps&Flow Line.;W/O production-Slick line working on B-32.Assist White star rep work on mud pump#2.Fab and install interconnect insulation between modules.;Remove 45 Degree section of flowline for modification. Remove snow on roof tops of Pump/Mud and pipe shed modules.;Continue to Remove snow F/Pump/Mud and Pipe shed modules.Install modified flow box,install weather stripping between modules. 3/12/2017 Transport 45 deg flowline to weld shop on D-Pad for modification.Modify handrails on mezzanine for flowline.Remove rig mats from around B-32,Continue loading 5"DP into pipeshed,;Finish installing 5"liners on#1 mud pump.Begin plumbing in skimmer system for boilers.;Assist white star rep working on#2 mud pump.Lay heculite and set rig mats around 13-33 for sub.Stage drum of oil on rig floor for top drive.Begin installing 45 deg section of flowline at mezzanine.;Submit 24 hr notification to AOGCC for diverter function test©13:58.;Finish up working on#2 MP.Complete installing 45 deg flowline section© mezzanine.Install diverter tee,Place dry hole tree and DSA behind B-33.Finish setting rig mats for sub base.;Trucks on location @ 20:00,line up and spot subase over B-33,Roads and pads grade pad before setting catwalk module.Lay mats and set catwalk module in place.;Finish spotting catwalk.Lay rig mats and spot pipeshed.Spot pit and motor modules,set up exterior stairways.Install sub base outriggers,R/U power and utility lines between modules.Insulate rig.;Get rig air turned on and steam circulating.Set cuttings box in place. Currently 65%rigged up. 3/13/2017 Install steam traps in heaters around rig. Plug in interconnect electrical,swap to rig power,shut down cold start engines.Spot buildings,finish setting cuttings box.Install cellar grating.;Service crown.Turn on water throughout rig.Swap to hi line power.Continue working on flow line. Repair kicker plate on pipe handler.Scope derrick up, R/D bridal line.R/U interconnect lines.;N/U diverter tee and stack,finish installing flow line.R/U pipe rack drains.Install diverter knife valve.start R/U diverter line.C/O gear lube in top drive.;Drain oil for MP#1 for installing new gasket on bearing housing.C/O swivel packing on top drive.;Finish installing knife valve on diverter line. Install riser and extra air boots.Install diverter lines and secure same.Set diverter warning signs and containment in place 4V; y at end of diverter.;Finish installing gasket on bearing housing on#1 MP.Fill top drive and mud pump#1 with gear lube. Prep pits for spud mud.R/U diverter �U accumulator lines.Perform derrick inspection.;P/U single 5"it DP,function diverter.annular closed ir1.15 sec.knife valve opened in 9 sec.Install 12.375"ID wear bushing.;P/U 5"DS50 DP and rack 105 stands in derrick,currently @ 38 stds. Fill pill pit with water,circulate all low pressure equipment.Load pits w/ 580 bbls 8.7+ppg spud mud.;Note:AOGCC rep Chuck Scheve waived witness for diverter function test @ 05:45. Continue to work on rig acceptance checklist.;Hauled 0 bbls to G&I for total=0 bbls Hauled 750 bbls H2O from 6 mile lake for total=750 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/14/2017 Finish P/U 5"DS50 DP and rack stands in derrick.PU HWDP and Jars.Continue to work on acceptance checklist.Continue mixing Spud Mud to 230 Visc. Stage BHA components in Pipe Shed.;Stage 12%"Bits on floor.Install flow box catch can in cellar below rotary table.Service TD IBOP.Finish working on Mud Pump 1. Installed new suction screens.;Slipped and cut drill line 125'.;Service Rig.;Test diverter system.Test gas alarms.(Knife Open=5 sec.)(Annular Close=12 sec.)Test witness waived by AOGCC Rep.Chuck Scheve.;Fill#1 with gear lube. Prepped liner wash. Rig up flow line jets. House keep around rig. Clean up pump room.Continue with check lists for spud.;Clean and organize rig,service rig equipment,Complete and review rig acceptance checklist. Rig accepted©21:30.;Conduct pre spud meeting with all parties involved.nConduct table top rig evacuation drill,discuss rolls and responsibilities,primary and secondary muster areas.;M/U conductor cleanout BHA,12 1/4"tricone bit mud motor,XO,=35.83,M/U 1 std HWDP,tag ice in conductor @ 33'.;Circulate and fill conductor with water,check riser and flowline for leaks,close IBOP,pressure test circulating lines to 3000 psi,good,rack std back,blow down top drive.;Trouble shoot top drive cooling system,glycol cooling radiator not circulating glycol due to restriction in radiator,causing radiator to pressure up and overflow out cap.;Bypass radiator so it can be flushed.;Spud well,M/U std HWDP and top drive,pump 350 gpm,260 psi,30 rpm,1700 torq,cleanout conductor f/33'to 106',drill 12 1/4"hole to 110'.;Swap to 8.8 ppg 230 vis spud mud,drill to 139',flowline plugging off.;P/U into conductor @ 97',jet and flush out flowline,getting wood,chunks of insulation and gravel.;Daily losses to formation 0 bbls for total=0 bbls;Hauled 3 bbls to G&I for total=3 bbls Hauled 300 bbls H2O from 6 mile lake for total=1050 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/15/2017 POOH f/139'due to flow line issues.Rack Back BHA under 1 jt HWDP.Begin rigging down 10"45 Deg section of flow line.;Remove 10"45 deg section of flow line and check for debris.Very little gravels down stream of 45.Gravels built up in the 10"x 12"reducer.Install 2 x 1"jets up stream of reducer.;Reinstall flow line section.;TIH to 67',wash and ream to 132'staging pump to 420 gpm,observe flow line packing off.;POOH into conductor standing back 1 stand.Clear flow line,stage pumps to 450 gpm reducing visc to 180.Could not establish circulation over 450 gpm with out running over flow box.;Wash down from 97'to 128' ©450 gpm.Reduced flow rate to 350 gpm before flow line packed off with gravels.;POOH from 128'standing BHA back in derrick in preparation to remove flow box,fab and install 16"x 12"outlet Pitcher Nipple.;R/D flow line. R/D catch can.Pull riser.Remove flow box. Off load spud mud to trucks to keep cold. Welder start fabricating 16"flow riser.;Fabricate 16"flow riser and modify flow line using Peak welder and GBR welder to assist,clean in cellar and rig floor.;Fabricate new flow riser with 12"outlet for flow line with 4 deg drop.C/O 10"45 deg with 12"45 deg on flow line where it exits from cellar to mezzanine.;Move 12"to 10"transition down stream of flow line after any turns(by flow sensor).;Daily losses to formation 0 bbls for total=0 bbls.;Hauled 114 bbls to G&I for total=117 bbls Hauled 300 bbls H2O from 6 mile lake for total=1350 bbls Hauled 0 bbls to B-50 for total=0 bbls • S 3/16/2017 Assist welders, Fabricate new flow riser with 12"outlet for flow line with 4 deg drop. fabricate new 12"45 deg on flow line where it exits from cellar to mezzanine.;Install flow riser,fit and make modification as needed.Clean gravel from vac system. Plumb SS tubes to grease ports on drag chain. Load 5" DS50 DP into shed.;Continue to modify 12"flow line from riser.Continue to load 5"DP,86 jts DS50 and 46 jts NC50 into pipe shed,strap and tally same. Install SS grease lines to drag chain.;lnstall 2"jet on new 12"45,;P/U cleanout BHA w/12 1/4"tricone bit.M/U top drive,test flow line @ 97'.stage pumps to 750 gpm, 1300 psi,no issues with flow Iine.;Wash and ream f1 97'tag fill @ 126'wash and ream to bttm at 139', 300 gpm,290 psi 10 rpm,1000 torque,;Daily losses to formation 0 bbls for total=0 bbls;Hauled 88 bbls to G&I for total=205 bbls Hauled 150 bbls H2O from 6 mile lake for total=1500 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/17/2017 Drillin 12 1/4"surface hole f/139'to 250'pumping 350 gpm,400 psi,30 rpm, 1.5k TQ.60 rop.;Attempt to POOH on elevators, 15-25k overpull. Back ream out of hole ft 250'to 126'pumping 300 gpm,320 psi,20 rpm, 1.5-4k TQ. POH on elevators f/126'to 67', BD top drive.;L/D Clean out BHA,drain motor, LID tricone bit.M/U 12 1/4"PDC bit, 1.5 deg motor,M/U directional BHA#1.offset @ 328.07 deg.:Service top drive,draworks,and blocks.Open pumps,clean and re-torque valve guide bolts.;Continue to P/U directional BHA per sperry to UBHO sub,upload data. Finish servicing mud pumps,clear flowline pumping thru bleeder. R/U gyro while downloading data.;M/U BHA,M/U 1 NMFC WI XO on single jt HW,rack in derrick,M/U NMFC and jt HW,tag fill @ 150'.;Pull dresser sleeve on lower end of flow line,cleanout gravel from same,reassemble dresser sleeve.;Wash and ream ft 150'to 250',75-100 fph.400 gpm,475 psi,40 rpm 1.5k TQ.;Drilling 12 1/4"hole f/250'to 576'Av rop 59'fph( 326') 400 gpm,680 psi,3-5k wob,30 rpm, 1-1.3k TQ. PU/SO/ROT 59/67/65 MW 8.9,vis 180;Survey with Gyro every stand, Both centrifuges running/adding water 20 bph;Drilling 12 1/4"hole f/576'to 954'Av rop 63'fph( 378') 450 gpm,900 psi,3-9k wob,60 rpm,2.k TQ. PU/SO/ROT 66/71/71 MW 9,vis 180, ECD 10.1;Survey with Gyro every stand, Both centrifuges running/adding water 10 bph Currently 2.5'above the line,5.3'right of the line. 1.09 slide hrs,5.18 rotate hrs.;Daily losses to formation 0 bbls for total=0 bbls;Hauled 231 bbls to G&I for total=436 bbls Hauled 300 bbls H2O from 6 mile lake for total=1800 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/18/2017 Drilling 12 1/4"hole f/954'to 1515'(561')AROP 93.5'fph 450 gpm,900 psi,2-6k wob,60 rpm,3.7k TQ. PU/SO/ROT 81/71/71 MW 9.2 vis 210, ECD 10.1 Release GYRO @ 1017';Drilling 12 1/4"hole f/1515'to 2148'(633')AROP 105.5'fph 575 gpm,1515 psi,2-6k wob,80 rpm,4k TQ. PU/SO/ROT 95/90/87 MW 9.2 vis 190, ECD 10.2;Drilling 12 1/4"hole f/2148'to 2778'(630')AROP 105'fph 500 gpm,1300 psi,2-6k wob,80 rpm,4.2k TQ. PU/SO/ROT 104/99/103 MW 9.3 vis 140, ECD 10.1;Drilling 12 1/4"hole N 2778'to 3408'(630')AROP 105'fph 523 gpm, 1500 psi,2-9k wob,80 rpm,5.9k TQ. PU/SO/ROT 115/106/112 MW 9.3 vis 150, ECD 10,2;Note:back ream full stand before connections.;Both centrifuges are running,adding water 50 bph. 2.48 slide hrs, 10.28 rotate hrs. 2.9'right of the line.;Daily losses to formation 0 bbls for total=0 bbls;Hauled 749 bbls to G&I for total=1183 bbls Hauled 1150 bbls H2O from 6 mile lake for total=2950 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/19/2017 Drilling 12 1/4"hole f/3407'to 3749'(342')AROP 68.4'FPH 575 gpm, 1890 psi,5-10k wob,80 rpm,7k TQ. PU/SO/ROT 127/113/117 MW 9.3 vis 150, ECD 10.2 Start 5deg/100 build section @ 3500';Trouble shoot MWD issues.Stand back 1 stand. Restablish communication with mwd tools Run back to bottom.;Drilling 12 1/4"hole ft 3749'to 4200'(451')AROP 75'FPH 575 gpm, 1815 psi,5-10k wob,80 rpm,7k TQ. PU/SO/ROT 127/113/117 MW 9.3 vis 150, ECD 9.7 Lower Vis to 100 @ 4000';Drilling 12 1/4"hole f/4200'to 4351'(151')AROP 50.3'FPH 575 gpm, 1815 psi,5-15k wob,80 rpm,7k TQ. PU/SO/ROT 139/121/131 MW 9.2 vis 90, ECD 9.7;Back ream 2 stds f/4351'to 4223',retake survey due to magnetic interference @ Survey depth of 4186', good survey.Wash back to bttm pumping 300 gpm,630 psi.;Drilling 12 1/4"hole f/4351'to 4477'(126')AROP 50.4'FPH 575 gpm, 1800 psi,5-12k wob,80 rpm,8.2k TQ. PU/SO/ROT 140/121/132 MW 9.2 vis 90, ECD 9.8.;Drilling 12 1/4"hole f/4477'to 4803'(326')AROP 54.3'FPH 575 gpm,1850 psi, 10-19k wob,80 rpm,9.6k TQ. PU/SOIROT 144/114/127 MW 9.3 vis 105, ECD 9.9.;Both centrifuges running,adding water @ 20 bph Currently.7'below the line, 15.6'right of the line. 7.1 slide hrs,4.5 rotate hrs.;Daily losses to formation 0 bbls for total=0 bbls;Hauled 605 bbls to G&I for total=1790 bbls Hauled 1200 bbls H2O from 6 mile lake for total=4150 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/20/2017 Drilling 12 1/4"hole f/4803'to 5080'(277')AROP 46.2'FPH 575 gpm, 1905 psi, 10-19k wob,80 rpm, 10k TQ. PU/SO/ROT 140/109/119 MW 9.3 vis 105, ECD 9.9.;Drill Hard spot f/4987'to 5020',w/20-22K WOB.;Drilling 12 1/4"hole f/5080'to 5259'(179')AROP 71.6'FPH 575 gpm, 1905 psi,6-12k wob,80 rpm, 10k TQ. PU/SO/ROT 140/109/119 MW 9.3 vis 105, ECD 9.9.;Final Survey:5221'MD,87.87 INC,308.51 AZM,4428'TVD,2.9'Low,2.4'Left of plan.;Circulate and condition mud prior to BROOH reducing visc to 64 and YP to 26.Rotate 80 RPM @ 600 gpm. PU/SO/ROT 141/106/124.;Back ream OOH pumping 500 gpm, 1300 psi,60 rpm,7-10k tq.f/5259'to 4200',hole unloading.;Reciprocate and rotate 60 rpm pumping 500 gpm, 1250 psi,circulate hole clean.;Continue to back ream OOH pumping 500 gpm, 1200 psi,60 rpm,5-8k tq.f/4200'to 2764',Cleanup tight spots @ 4089',4070',3872',3073'.;Continue to back ream OOH pumping 500 gpm,850 psi,60 rpm f/2764'to 453'@ HWDP.Cleanup tight spot @ 2508'.;Attempt to pull on elevators f/453'with 15k over pull,pump out 320 gpm 400 psi f/453'to 300';Daily losses to formation 0 bbls for total=0 bbls;Hauled 636 bbls to G&I for total=2426 bbls Hauled 900 bbls H2O from 6 mile lake for total=5050 bbls Hauled 0 bbls to B-50 for total=0 bbls • • 3/21/2017 Continue to work BHA,set back WT Pipe.UD NMDC's Plug in to Down Load MWD Data.;Clean and Clear floor while down loading MWD Data.;Continue to UD MWD Tools Motor and Bit.. Bit was graded 2-5-BT-S-X-2-CT-TD and was 1/8"under gauge.;Pull wear bushing.Prep Pipe Shed and floor for running casing.;Service Rig.;Continue R/U to run Casing.R/D&UD short bails.Stage casing bails on floor.Install 9 5/8"bushings.;W/O Casing crews stuck behind Rig Move©Kuparuk Bridge.Clean up cellar.Adjust flow line to obtain accurate measurements for bell nipple mods.Start on Pit Cleaning.House keep through �.. out the rig.;Perform General maintenance handling equipment.Casing Crew on location©15:30 hrs.;PU&MU WOT Volant tool.PU&install long bails/single () vN joint elevators. R/U Weatherford 1450 double stack tongs for high tq connections.;PJSM on running Casing with crews.;M/U 80'shoe track(bakerlok). `�• °' Flashlight float equipment prior to makeup. Check floats(ok). Adjust double stack backups to pipe size.Tq 9-5/8"DWC/C connection to 32k.;Continue to run ( ',Ire 9 5/8'.40#.L-80, DWC/C Casing T/1511'MD.Break circulation and establish good returns to pits every 15 jts'.Tight spots© 400',421',486'.;Foul threads on jt#8. UD jt#8 and adjust tally. Run 14 total bow springs on first 19 jts.;Saw moderate returns of fine sand while washing down from 1100'to 1250'MD @ 5 bpm/90 psi. Continue RIH on elevators from 1250'to midnight depth of 1511'MD on elevators.;Continue to run 9 5/8',40#,L-80, DWC/C Casing F/1511'-T/ 3500'MD. Break circulation and establish good returns to pits every 15 jts+20 bbls. Stage up pumps to 5 BPM/110 psi;Hauled 695 bbls to G&I for total= 3121 bbls Hauled 147 bbls H2O from 6 mile lake for total=5197 bbls Hauled 0 bbls to B-50 for total=0 bbls 3/22/2017 Continue to run 9 5/8',40#, L-80, DWC/C Casing F/3500'-T/5139 'on elevators. Wash casing to bottom from 5193'to 5249', PU 200K,SO 154K.;Break circulation and establish good returns to pits every 15 jts+20 bbls. Stage up pumps to 5 BPM/110 psi.;Circulate and condition mud,stage pump from to 8 bpm/330 psi.lower YP to 18,vis to 55,working pipe 30'.PU 203K,SO 137K.;Park casing @ 5249',R/D volant tool,DSM witness loading plug in cement head,M/U cement head and lines.;PJSM with all parties involved for pumping 1st.;Pump 1st stage CMT:With cementers,pump 5 bbls water,pressure test lines to 800 psi low,4000 psi. Pump 60 bbls 10.5 ppg tunned spacer with red dye. lCL�' Drop bypass plug,load closing plug,;Mix and pump 500 sxs(220 bbls)Etenda Cem Lead Cement at 11.7 ppg. 1 J Mix and pump 210 sxs(43 bbls)Swift CemTail Cement at 15.8 ppg. w Drop Shut off Plug.;Displace cmt w/20 bbls RN f/Cmt Unit 5[x `0 Rig Pump 186.4 bbls,9.4 ppg mud Cmt Unit 80 bbls RN Rig Pump 105.3 bbls 9.2 ppg mud. Total Displacement @ 391.7 bbls;Bump plug with 500 psi over final circulating pressure.Check Floats. Floats held. CIP@18:00. Load Closing Plug.;lst Stage Details: / Lost 95 bbls during displacement. i/ Pump Cement @ 5 BPM Average. Pump Disp @ 5.5 BPM Average.Calculated Disp 391.7 bbl,Actual Disp 391 bbl. FCP 735 psi©2 BPM;Using rig pump,stage pressure up 3200 psi to open ES Cementer. 327 bbls circulated to see water returns©surface.;CBU through Stage tool staging up to 5 bpm,bringing 202 bbls contaminated Mud and 40 bbls green CMT to surface ,Over boarded Total of 242 bbls.Lost 95 bbls to hole.;lnject"Black Water"via annulus while taking cmt returns through stack and discarding overboard to cuttings boxes.;Shut down pumping. Disconnect knife valve. Flush stack and work annular with"Black Water'. Circulate"Black Water"through flowline jets and all surface lines.;Circulate and condition mud through ES cmtr @ 1913'MD. Pump @ 2 BPM/80 psi. Increase rate to 5 BPM periodically to minimize potential channeling.;Order 100 bbls additional lead cmt due to assumed washout from btms up©ES cmt stage tool(327 bbls Ann Cap/Surface to ES cmt tool).;Additional lead cmt on location©03:45 hrs. Rack in and rig up cmtrs. Continue circulating while racking in cmt equipment. Found"C"pump froze up on cmt unit. R/U heaters and thaw unit.;Hauled 745 bbls to G&I for total=3866 bbls Hauled 375 bbls H2O from 6 mile lake for total=5572 bbls Hauled 0 bbls to B-50 for total=0 bbls ROP notification sant via email a 05.4.5 hrs 1/23117 3/23/2017 PJSM on pumping 2nd stage cement.;Mix&pump 60 bbl 10.5 ppg. Mix and pump 450 sxs(432 bbls)Perm L Lead Cement at 10.7 ppg. •'u Mix and pump 275 sxs(56.6 bbls)Swift CemTail Cement at 15.8 ppg. Z r Drop Shut off Plug.;Displace cmt w/20 bbls FW f/Cmt Unit Rig Pump 125 bbls,9.4 ppg mud / Total Displacement @ 145 bbls Bump Plug @ 2 bpm,495 psi FCP Pressure up to 1900 psi&.close ESCMTR.Hold for 5 min.;2nd Stage Details: Full returns through out job. Pump Cement @ 5.5 BPM Average. Pump Disp @ 6 BPM Average.Calculated Disp 145.2 bbl,Actual Disp 145 bbl. FCP 500 psi @ 2 BPM;Pumped 130%Excess Lead,bringing 27 bbls green cmt to surface before going into Tail cement.Bring total of 201 bbls Green CMT to surface. Overboard all returns during 2nd Stage. CIP @ 10:00 hrs;Blow down cement line,Flush stack and all surface equipment with black water, R/D cement head and cementers.Fill stack w/blackwater and soak. Center up csg in wellhead.;RD Bell Nipple&raise same.RD Diverter Line.Bleed Down Koomey. Unbolt Diverter TEE.RD Turnbuckles.Hoist stack to set emergency slips.;Center up 9 5/8"Casing.Wellhead hand set slips on casing w 110K on slips. Rough cut casing and UD cut jt.Length=28.45'.;Lower stack and hot bolt diverter TEE.Lower bell nipple and R/U Same.UD CMT Head.Ready floor for surface equipment flush.M/U Wacker,flush equipment w/black water.;N/D diverter system. Open ram bodies and flush same.Inspect,grease rams and door seals. Close and tq doors. N/D Diverter"T"and remove from cellar. Rough cut 9-5/8"casing and dress same.;Continue working on pinion shaft seal-MP#1. Continue cleaning pits and prep for drillout.;lnstall 13-5/8"x 11"wellhead. Test packoff void"P"seals to 500/2450 psi w/5/10 min hold(test good).;N/U 11"5k spacer spool,13-5/8"x 11"5K DSA and 13-5/8"5K stack. Tq all flanges.Obtain measurements for pitcher and build same. Install pollution pan. Hook up koomey lines,choke and kill lines;Hook up hole fill and and flow line jets.;Hauled 1492 bbls to G&I for total=5358 bbls Hauled 900 bbls H2O from 6 mile lake for total=6472 bbls Hauled 0 bbls to B-50 for total=0 bbls • • 3/24/2017 Continue rig up BOP test equipment.Flood stack and choke Manifold.Obtain Shell test.;W/O Jeff Jones with AOGCC to arrive location for test witness. AOGCC on location @ 08:30.Prep Pipe shed for BHA and test run MP#1 while W/O AOGCC inspector.;With 5"Test jt,Test all Surface Equipment and choke manifold to 250/3000 psi as per AOGCC,with no failures.RD 5"Test Joint.Test Blinds.RU 4 1/2"Test Jt.Test Bag,TPR,LPR, t/250/3000 psi.;Test Gas Alarms,Test Koomey,Start 3000 psi,After closure 1550 psi,200 psi build 15 sec.Full recovery 72 sec. N2=6 @ 2340 psi average.;UD 4 1/2"Test joint.Blow Down/Drain surface equipment.;Set 10"ID wear bushing.Set Mouse hole,Prep floor and shed to PU BHA.;PU C/O BHA:8.5"RR Tricone Bit,Sperry mtr w/1.15 bend,3-NMFC,1 jt HWDP,Jar,7 jts HWDP.Total BHA Length 400.69';Service Rig;TIH P/U NC-50 DP from pipe shed from 400'to top of ESCMTR @ 1912'.;Drillout ES Cmt stage tool @ 1912'MD. 20 rpm,2.8k tq,350 gpm,515 spp,2-3k wob. Pull back above stage tool. Trip past with no rot or pump (clean). PT csg 1500 psi w/5 min hold(test good).;Continue single in out of shed F/1912'-T/4737'MD. P/U total 138 jts 5"DP.;TIH out of derrick Fl 4737'- T/5120'MD. Tagged green cmt @ 5120'MD. Pick up T/5,111'MD.;Fill pipe and break circulation @ 5,111'MD. R/U and test 9-5/8"casing. P/T casing to 3030 psi(4.5 bbls pumped)w/30 min hold. Chart and record same. Final psi 3000 psi(4.5 bbls bled back).;R/D test equipment. B/D lines.;Wash down F/ 5,111'-T/5120'MD. Drill green cmt F/5,120'-T/5,162'MD. Drill all shoe track equipment on depth Fl 5,162'-T/5248'MD. 20 rpm,2.8k tq,350 gpm,775 spp,54%flow,3-5k wob.;Drill 20'new formation F/5,259'-T/5,279'MD. Displace well on fly w/Baradril-N,8.8 ppg mud.;Hauled 171 bbls to G&I for total= 5529 bbls Hauled 450 bbls H2O from 6 mile lake for total=6922 bbls BOP Trip Drill @ 21:30 hrs w/45 sec resp time for well secure 3/25/2017 Work through shoe @ 5248'w/no issues. 148k up, 102k dn,123k rot. B/D TDS. Monitor well(moderate flow).;Circulate 2x's btm's up. 390 gpm,655 spp. Max gas @ btm's up 6700 units.;Increase mud wt F/8.8 to 9.4 ppg MW. Observe possible communication from B-29 injector. S/I B-29 and freeze protect same. BGG @ 400 units w/9.4 MW. 546 gpm, 1215 spp.;Monitor well(flow). 5-6 BPH flow w/9.4 MW.;Circ Btms up w/9.4 MW,max gas @ btms up 1830 units. Wt up active from 9.4 MW to 9.6 MW. Monitor well(static). Wt up F/9.6 to 10.0 MW for trip margin. Max gas 50 units @ btms up w/9.6 MW.;546 gpm, 1240 psi.;Monitor well(static). R/U and perform 12 ppg EMW FIT. Pump 10 ppg MW @ 1/2 bpm,pumped 2 bbls total w/max psi 460 psi. Shut dn and monitor 20 min with final psi 120. Bled back.5 bbls.;R/D test equipment. Blow down choke and kill lines.;Monitor well(static). Make wiper trip F/5,234'-T/ 3,165'MD. Trip back to btm. Hole took proper displacement.;CBU @ 5,235'MD. 430 gpm,850 psi.90 units max gas @ btms up;Monitor well(static). Pump dry job. POOH F/5,235'-T/BHA'(400'). 10 bbl loss for trip.;Monitor well @ BHA(static). POOH laying down BHA. Bumper jars would not close. B/O and UD jars. Flush and drain mtr/bit assy. B/O bit and UD same. Bit grade=4,3,BT,A,E,1,CT,BHA;Clean and clear rig floor. Stage drilling BHA on floor.;Hauled 342 bbls to G&I for total=5529 bbls Hauled 150 bbls water from 6 mile for total= 7072 bbls 2.4'low and 2.9'left of plan 3/26/2017 M/U 8.5"Geo-Pilot Assy. NOV long gauge PDC w/sleeve,7600 GP,MWD. Corrosion ring installed on top NM Flex DC. M/U new set drilling jars. (273.13' total length).;TIH w/BHA#3 F/273'-T/5,239'MD. Shallow pulse test @ 1025'(test good)515 gpm,1100 psi. Break in Geo-Pilot seals.;Cut and slip drilling line(57'line). Circ and condition mud offline while cut and slip. Circ @ 180 gpm,285 psi.;Rig Service.;Wash down F/5,239'-T/5279'MD. Work new PDC through shoe w/light wt. Break in bit pattern for first couple feet. Drill ahead as per Geo F/5279'-T/5494'MD.;550 gpm,1470 psi,80 rpm,12k tq,133k up, 98k dn, 118k rot,6-10k wob. 10.6 ECD's.;Cont Drlg Ahead F/5494'-T/6145'MD. 4-12k WOB,100-120 rpm,13k tq on,575 gpm, 1780 psi on, 1690 psi off,63%flow,2500 units bgg. 25 bbl sweep @ 5810'MD. lo wt/lo vis w/50%inc;Note:Top drive oil psi loss and VFD fault alarm. Troubleshoot,TDS lube pump still working. Contact NOV to address alarm.;Cont DrIg Ahead F/6145'-T/6811 'MD. 4-12k WOB,100-120 rpm,13k tq on,575 gpm, 1790 psi on,1700 psi off,63%flow,4400 units bgg. 25 bbl sweep @ 5321'MD. to wt/lo vis w/25%inc;.4 ppg gas cut mud. Inc MW Fl 9.95 ppg T/10.15-10.2 MW. SPR @ 6430'taken w/10.1 ppg MW.;Hauled 371 bbls to G&I for total=5900 bbls Hauled 150 bbls water from 6 mile for total= 7072 bbls Svv(c)6361'MD.89.67°Inc.313.77°Az,4417'TVD=In middle of target and 16.4'left of plan 3/27/2017 DrIg Ahead Fl 6811'-T/7430'619'@ 103 FPH Av 8-15k WOB,100 rpm, 14k tq on, 575 gpm, 1780 psi on,1700 psi off,63%flow.25 bbl sweep @ 7080' MD. lo wt/to vis w/50%inc.;Back ground gas @ 5000 units. No flow on connections. UP/DN/ROT 150K/71 K/111 K.;Drlg Ahead F/7430'-T/8165'@ 122 FPH Av 8-15k WOB,100 rpm, 14k tq on, 575 gpm,1780 psi on,1700 psi off,63%flow.;Drlg Ahead F/8165'-T/8780'@ 103 FPH Av 15-18k WOB,100 rpm, 19.5k tq on, 575 gpm,1970 psi on,1910 psi off,63%flow. ECD's 11.1.;20 bbl sweep @ 8200'(9 ppg,30 vis)w/20%inc Added.5%lubes by vol @ 8475'MD.;Drlg Ahead F/8780'-T/9417'@ 106 FPH Av 18-22k WOB,100 rpm,20k tq on, 575 gpm,2000 psi on, 1930 psi off,63%flow. ECD's 11.;166k up, 112k rot,lost dn wt @ 8,825'MD. 20 bbl sweep @ 8895'(9 ppg,30 vis)w/15%inc.Increase lubes by vol to 1%@ 8942'MD.;Hauled 364 bbls cutting to G&I for total=6264 bbls Hauled 700 bbls H2O from 6 mile lake for total=7772 bbls Last svy(a)9067'MD,90.84°Inc, 309.03°Az,4407'TVD=In zone,34'left of plan. 3/28/2017 DrIg Ahead Fl 9417'T/9655'238 @ 80 FPH Av 13k WOB,100 rpm,20-22k tq on, 575 gpm,2065 psi on,1930 psi off,63%flow.ECD's 11.;Drill concretion F/9955'T/9667'. Drill at reduced RPM Set tool to neutral&Stage up wt to 10-15K WOB,70RPM Broke through&drilled to 9672'.Showing 13.5 Deg DL @ 92 deg.;Pull up T/9644'&Ream out with tool set @ 180 F/9644'9672'three times. Dropped 13.5 DL T/9.9 DL. Back ground gas @ 150-200 during reaming with a 9.6 MW.;DrIg Ahead F/9672'T/9915'243'@ 54 FPH Av 13k WOB,100 rpm,20-22k tq on,575 gpm,1975 psi Drilled out of zone @ 9689'to 9915'.(226').;DrIg Ahead F/9915'T/10083'(168)@ 112 FPH Av(240 FPH On Btm)10-18k WOB,100 rpm,22-23k tq on,575 gpm, 1975 psi Max gas @ 5000 units.;Drlg Ahead F/10083'-T/10773'(690)@ 115 FPH Av(201 FPH On Btm)10-18k WOB,100 rpm,22k tq on,575 gpm,2200 psi Max gas @ 4300 units.;Drlg Ahead F/10773'-T/10933'(80)@ 115 FPH Av(144 FPH On Btm)15k WOB, 100 rpm,22k tq on,575 gpm,2175 psi Max gas @ 4166 units.183k up,111k rot,36k dn.;TD @ 10,933'MD/4408'TVD. Cir 3x's BU. 625 gpm,2410 psi,10.9 final ECD's,70 rpm,18k tq. Pump tandem sweeps (10/10&hi/hi)w/no increase in cuttings.;BGG @ 80. 178k up, 111k rot,36k dn.;Obtain final survey @ TD. Monitor well(17.8 BPH flow). Mud wt out 9.6 psi scale,9.2 non psi scale. Wt up F/9.6 to 9.8 MW. 575 gpm,2100 psi,64%flow,70 rpm,16.5k tq.;Hauled 285 bbls cutting to G&I for total=6549 bbls Hauled 640 bbls H2O from 6 mile lake for total=8412 bbls Daily losses to formation 207 bbls mud for total=351 bbls;Extrapolation to bit @ 10,933'=In zone and 35.9'Left of plan Last svy @ 10864'MD,89.6°,307.9°Az. • • 3/29/2017 Circulate and condition mud. Wt up F/9.6 to 9.8 MW. 575 gpm,2170 psi,63%flow,70 rpm, 16k tq. ECD's 10.8. 170k up,112k rot,36k dn. 30 BGG.;Monitor well(6 BPH static losses). BROOH Fl 10933'-T/5239'MD. 70 rpm,15.5k tq,500 gpm,1725 psi. No issues pulling in lateral or into shoe.5-6 BPH losses during backream operations.;Monitor well @ shoe(6 BPH static loss rate). Circ and cond©5239'MD. Pump 30 bbl hi vis sweep(minimal inc). 25%inc @ btm's up.Monitor well(6 bph static loss).Pump dry job,blow down TDS.;Pull out of hole laying down 5"DP Fl 5239'-T/3920'MD.;Continue TOH laying down 5"DP F/3,920'-T/273'MD. 10 bbl loss for total trip out.;B/O and UD all 8.5"lateral BHA F/273'-T/surface. Inspect,clean BHA. Download MWD. UD collars. Remove corrosion ring(see Mud Engineer).B/O bit,bit grade=2,4,BT,A,X,I,BU,TD.;CIean and clear rig floor. R/U WOT double stack 5.5 x 15 power tongs. R/U 4.5"100T elevators,air slips and size dog collar. Prep pipeshed and stage liner jewelry in place. 140 jts total in shed.;PJSM, Run 4.5", 13.5#,L-80 HTTC liner as per tally T/2419'MD.Top fill w/9.8 brine. Record disp every 10 jts. 9k M/U tq.;Use 4010 NM thread compound. 140 total jts in shed. Flashlight WIV jt(ok).WIV-2 pins @ 1088 psi.;Hauled 171 bbls cuttings to G&I for total=6720 bbls Hauled 260 bbls H2O from 6 mile lake for total=8672 bbls Daily losses 141 bbls for total=492 bbls mud • • Hilcorp Energy Company Composite Report Well Name: MP B-33 Field: Milne Point County/State: ,Alaska (LAT/LONG): avation(RKB): API#: Spud Date: Job Name: 1612656C MPB-33 Completion Contractor AFE#: AFE$: �.E Alctiurt....Q�ate.........::.:::::::::::,. ;:.�::::::::::::::.::....:::...::::::.:.::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::i� �::;�ummar..:::::::>::;::::>::::>::::::::::::::::::>::>::>::::::::::::::;::;::>::>:::::::::::::::::>::::::::::::»>::>::»..�.,.:::>::>::>::>::>.>.::<:>::>::>:::<:.;:>::::::><::.::>at:::_ 3/30/2017 PJSM,Run 4.5"liner as per tally F/2419 T/4280'.Top fill w/9.8 brine.Record disp every 10 jts. 9k M/U tq.Use 4010 NM thread compound.Flashlight WIV jt (ok).WIV-2 pins @ 1088 psi,Driller noticed ICD leaking brine from sleeve connection. Consulted Completion engineer&Halliburton.Decision made to continue running.RIH T/5173'. Completion Engineer decided to POOH to last ICD @ 4275 and have Halliburton Inspect. POOH UD 20 joints&swell packer. Haliburton on location.Found loose shroud protector.Tighten same.Still leaking.Decision made to baker loc connection. Baker loc same.,RIH F/ 4275'T/5173'. 116 joints 4.5 liner 7 ICDs,7 Swell packers total.Run joint 117& Set liner in tension.UD joint 117.,R/U baker false table&change handling equipment to 2 3/8 equipment.P/U slick stick&Rih with 2 3/8 PH6 T/5142'MD. 59k up,55k dn. Tag w/5k @ 5142'MD.,Spaceout w/2 pups.Final inner string set depth"no go"5'from landout @ 5137'MD. C/O elevators to 5". M/U"SLZXP"liner hanger.Mix pal mix and install.Total string wt w/liner-112k up, 102k dn.,Stage pumps up and circulate 1x's liner inner string volume. 2.5 BPM,940 psi. B/O TIW from safety jt. BOT rep-witness all rot and circ operations.,RIH w/liner on 5"DP out of derrick F/liner depth 5,211'to 8794'MD. Obtain rot tq @ 6910'MD-10/20/30 rpm=6.1 /7/7.3k Tq.,Circulate to condition mud in open hole @ 8,794'MD. Stage pumps up to 2.5 BPM,1075 psi,circ a total of 160 bbls. S/D and blowdown TDS.,Continue running in hole with liner on drill pipe. P/U a total of 55 stds 5"dp out of derrick,26 jts HWDP out of shed,and 13 more stds of 5"dp out of derrick. Total pipe-68 stds 5"dp, 13 stds 5"HWDP to put us on depth @ 10,277'MD. 8 bbl loss for trip.,Circulate and condition mud while emptying pits of excess mud. Stage Peak trucks and prep pits for displacement. Circ @ 2.5 BPM,1055 psi. 5-20 units BGG.,PJSM, Displace 9.8 ppg Baradril-N mud w/9.8 3%KCL Brine. Pump 3x's 40 bbl Sapp pills w/50 bbl brine between.Stage up to 3 BPM,1500 psi.,Hauled 169 bbls cutting to G&I for total=6889 bbls Hauled 130 bbls H2O from 6 mile lake for total=8802 bbls Daily losses 16 bbls for total 508 bbls 9.8 ppg mud lost to formation 3/31/2017 Displace to completion fluid @ 3 bpm 1495 psi.Pump final 30 bbl sap pill& chase with 918 bbl 9.8 brine dumping all returns. Shut down and drop Phenolic 1.25 ball.Pump down @ 3 bpm.Slow down to 2 bpm @ 70 bbl away.Ball on seat @ 75 bbl. Calculated @ 103 bbl.,Pressure up&see packer set @ 2600 psi.Hold for 5 min. Isolate MP&pressure with test pump.to 4100 psi. Good indication of tool releasing. Bleed down pressure. Brake out TD&blow down. Close annular and test back side to 1500. Bled down to 1420 in 20 min. Bumped up to 1600&hold for 30 min. Bled down 30 psi in 30 min.Good. Bleed down. Open annular. P/U&verify release running tool.Good.,Pull slick stick out of pack off. Pump 20 bbl sweep around @ 4.3 bpm 3500 psi.Circ 200 bbl total.4 Liner volumes. Shut down.Blow down TD. Monitor well.Static.,UD DP 28 joints5" &26 joint of HWDP T/8575.Stand back 5"Dp T/LRT @ 5095'. Inspect and UD Liner running tool. Good. change handling equipment to 2 3/8. 41 bbl losses for the tour. M/U safety joint for 2-3/8"PH6.,POOH laying down 2-3/8"inner string F/5095'-T/surface. B/O and UD Slick stick w/crossover. 10.6 bbl loss over calc displacement. Rebuild Geo-Skid and stage to replace during rig move.,R/D 2-3/8"handling equipment. Disconnect and stage power tongs out of critical path. R/U 5" handling equipment. R/D safety joint. 2 BPH static losses.,Service rig. Grease and inspect TDS,Blocks,Crown and Drawworks. Inspect tong hanging lines and sheaves.,M/U 5"Johnny Wacker and TIH out of derrick w/5"DP from surface to 3844'MD.,Hauled 1624 bbls to G&I for total=8513 bbls Hauled 0 bbls H2O for 6 mile lake for total=8802 bbls 4/1/2017 TIH F/3844'T/5064'with 5"Dp. Circ 9.8 3%KCL sweep around @ 14 bpm, Rot 10 RPM,580 psi dumping all returns.,Monitor well.Static.Blow down TD. UD 5"Dp F/5064'T/Surface. Break out Stack wash tool.,Drain stack.Attempt to pull WB. Having trouble getting in to profile. R/U stack wash tool and flush out profile.attempt to getting again.No go. Kelly up TD&ROT with 5K down @ 1800 tq.Found profile and pushed in.Rot in.R/D TD&Pull with tugger. Inspect wear bushing.Looked good other than slight edge.Send to wellhead rep to dress. UD 5"joint&running tool.,R/U 4.5 handling equipment. Conduct PJSM, M/U Floor valve and XO.,M/U 7"Seal assembly with 7.3 OD Mule shoe. Run 3 joints 4.5 Super Max 12.6#Tubing T/117'. M/U XN Nipple with pups, Run F/138'T/1998'Jt 58.P/U GLM with 3.813 Profile and 3.725 No go. RIH F/2024'T/5080'Jt 150. OPT TQ @ 3500# 1"GLM with 3500#shear valve set.Annular to tubing shear.,Unable to latch sidedoors on jt#85. No damage to pipe or elevators just very tight tolerances making it difficult.Replaced 100T sidedoors w/YC elevators to make latching elevators easier. Verify pipe OD(4.55"). Continue running pipe. BOP drill @ 21:20 hrs w/1 min 26 sec response for well secure.,Tag 16'in on jt#150(5080'MD).Saw seals engage liner top w/6k drag. Continue dn and landout @ 5089'MD w/5k set dn. POOH laying down jts#148-150. M/U spaceout pups(2.09',5.82',7.77',7.83'=23.51'). P/U jt 148. M/U XO pup,Hgr w/ pup and 5"landing joint.,Drain stack. RIH and landout w/a final set depth of 5087.08'(2.5'off no go) 71k dn w/4-6k drag from seals engaged. 88k up. Verify proper landout(ok). Fill stack. Mark landing jt. P/U 2'for hanger to clear wellhead profile.,Close annular and circ thru choke(ok). PT annulus T/500 psi w/5 min hold(ok). Chart and record same. Reduce annular psi to 825 psi. Bleed down annulus to 200 psi. Strip up to locate port(120k). P/U total 7-1/2'to dump psi and clear seal port from liner top for circulating.,Reverse circulate 120 bbls 9.8 corrosion inhibited brine followed by 167.4 bbls 9.8 brine. Stage up to 5 BPM,235 psi,40%flow. 23 bbl loss for total displacement.,Bleed off trapped psi. Open annular. S/O and land hanger on depth @ 5087.08'MD. RILDS. B/O landing joint and laydown same. 71k dn(35k string wt on hanger),B/D TDS. R/U and perform MIT 9-5/8"x 4.5"annulus. Psi up 3000 w/30 min hold, (ok). Chart and record same. Start psi 3050,final psi 3030 psi. Witness waived by AOGCC Chuck Scheve. Psi up after test to 3600 psi and shear GLM(ok). Verify circulation(ok).,Set TWC and begin nippling down BOP equipment.,Hauled 567 bbls cuttings to G&I for total=9080 bbls / k Hauled 0 bbls from 6 mile lake for total=8802 bbls tkt Daily losses to formation 54 bbls brine for total=54 bbls Brine Total mud losses to formation=555 bbls • 4/2/2017 N/D BOPs,Flush TD,Choke and kill lines with fresh water and blow down same. N/D Flow line, Pitcher Nipple. Pull Pitcher nipple. RID Catch can.N/D Choke and kill line. Bleed down Accumulator and rack back BOPs.N/D DSA and spacer spool.,N/U Adapter. Had to change out adapter due to longer neck on hanger than adapter. N/U dry hole Tree.Test hanger Void to 500/5000 psi for 15 min. Test tree to 250/5000 psi for 5 min.Good. Pull TWC. Install BPV.,R/U LRS to tubing. R/U returns to cellar. R/U vac truck to take returns. Pump 145 bbl @ 2 bpm down tubing taking returns to cellar and vac truck. Started getting diesel in returns. Lost 23 while circulating. Lined up little red down annulus and bullhead remaining diesel down back side.70 bbl. Final pressure 2000 psi. R/D little red and secure tree. Clear cellar for rig move.,Total losses of 9.8 bring 202 bbl. Total losses of 9.8 WBM 555.,Working on B-30 Report. Rig Released at 1800. S Hilcorp Alaska, LLC Milne Point M Pt B Pad MPU B-33 50-029-23573-00-00 Sperry Drilling Definitive Survey Report 03 April, 2017 HALLIBURTON Sperry Drilling • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 4 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well MPU B-33 Well Position +N/-S 0.00 usft Northing: 6,023,149.85 usft Latitude: 70°28'24.717 N +E/-W 0.00 usft Easting: 571,978.15 usft Longitude: 149°24'43.484 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.70 usft Wellbore MPU B-33 s4-.' A 1,4 Magnetics Model Name Sample Date Declination Dip Angle Field Strength 4 (°) (°) (nT) BGGM2016 3/20/2017 17.85 81.06 57,559 Design MPU B-33 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 26.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) I 26.00 0.00 0.00 314.00 I J Survey Program Date 4/3/2017 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 100.00 728.00 MPU B-33 SRG-SS(MPU B-33) SRG-SS Surface readout gyro single shot 03/08/2017 789.17 5,221.05 MPU B-33 MWD+IFR2+MS+sag(1)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 03/18/2017 5,292.82 10,863.92 MPU B-33 MWD+IFR2+MS+sag(2)(MP MWD+IFR2+MS+sag Fixed:v2:IIFR dec&3-axis correction+sag 03/27/2017 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 26.00 0.00 0.00 26.00 -22.70 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 UNDEFINED 100.00 0.40 159.44 100.00 51.30 -0.24 0.09 6,023,149.61 571,978.24 0.54 -0.23 SRG-SS(1) 165.00 0.22 68.61 165.00 116.30 -0.41 0.29 6,023,149.44 571,978.44 0.71 -0.49 SRG-SS(1) 228.00 0.42 108.61 228.00 179.30 -0.44 0.62 6,023,149.42 571,978.77 0.46 -0.75 SRG-SS(1) 290.00 0.94 56.96 289.99 241.29 -0.23 1.26 6,023,149.63 571,979.41 1.22 -1.07 SRG-SS(1) 352.00 2.25 34.28 351.97 303.27 1.05 2.37 6,023,150.92 571,980.51 2.31 -0.98 SRG-SS(1) 414.00 3.88 29.83 413.88 365.18 3.87 4.10 6,023,153.76 571,982.21 2.65 -0.26 SRG-SS(1) 476.00 4.94 25.61 475.69 426.99 8.10 6.30 6,023,158.01 571,984.37 1.79 1.10 SRG-SS(1) 539.00 6.17 25.09 538.40 489.70 13.61 8.91 6,023,163.55 571,986.92 1.95 3.05 SRG-SS(1) 602.00 6.15 28.08 601.03 552.33 19.66 11.93 6,023,169.62 571,989.89 0.51 5.07 SRG-SS(1) 665.00 6.17 22.47 663.67 614.97 25.76 14.81 6,023,175.75 571,992.71 0.96 7.24 SRG-SS(1) 728.00 6.36 22.81 726.29 677.59 32.11 17.46 6,023,182.12 571,995.30 0.31 9.74 SRG-SS(1) 4/3/2017 11:59:20AM Page 2 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: LLC Local Co-ordinate Reference: Well MPU B-- P Y� Hilcor P Alaska, 33 .. Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature ( Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA 'Survey Map Map Vertical MD Inc Azi TVD TVDSS +N1-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/1001 (ft) Survey Tool Name 789.17 6.66 22.81 787.07 738.37 38.50 20.15 6,023,188.54 571,997.92 0.49 12.25 MWD+IFR2+MS+sag(2) 851.97 6.26 6.31 849.48 800.78 45.26 21.94 6,023,195.32 571,999.65 3.01 15.66 MWD+IFR2+MS+sag(2) 914.92 6.64 353.53 912.03 863.33 52.29 21.90 6,023,202.35 571,999.54 2.35 20.57 MWD+IFR2+MS+sag(2) 977.28 7.40 342.95 973.93 925.23 59.71 20.32 6,023,209.75 571,997.89 2.40 26.86 MWD+IFR2+MS+sag(2) 1,040.25 8.65 332.25 1,036.28 987.58 67.78 16.93 6,023,217.79 571,994.42 3.09 34.91 MWD+IFR2+MS+sag(2) 1,103.54 9.99 321.38 1,098.74 1,050.04 76.28 11.28 6,023,226.23 571,988.69 3.49 44.87 MWD+IFR2+MS+sag(2) 1,166.35 10.95 318.85 1,160.50 1,111.80 85.03 3.96 6,023,234.91 571,981.28 1.69 56.22 MWD+IFR2+MS+sag(2) 1,229.56 11.82 313.90 1,222.47 1,173.77 94.04 -4.66 6,023,243.83 571,972.58 2.07 68.68 MWD+IFR2+MS+sag(2) 1,292.93 11.94 313.44 1,284.48 1,235.78 103.05 -14.10 6,023,252.75 571,963.06 0.24 81.72 MWD+IFR2+MS+sag(2) 1,355.16 11.73 313.54 1,345.39 1,296.69 111.83 -23.36 6,023,261.44 571,953.72 0.34 94.48 MWD+IFR2+MS+sag(2) 1,418.13 12.41 315.38 1,406.97 1,358.27 121.06 -32.75 6,023,270.58 571,944.24 1.24 107.65 MWD+IFR2+MS+sag(2) 1,480.94 11.44 312.14 1,468.42 1,419.72 130.04 -42.11 6,023,279.47 571,934.79 1.88 120.62 MWD+IFR2+MS+sag(2) 1,543.66 10.67 310.18 1,529.98 1,481.28 137.96 -51.16 6,023,287.30 571,925.67 1.37 132.63 MWD+IFR2+MS+sag(2) 1,606.58 10.74 309.83 1,591.80 1,543.10 145.48 -60.11 6,023,294.72 571,916.64 0.15 144.29 MWD+IFR2+MS+sag(2) 1,669.71 10,61 310.98 1,653.84 1,605.14 153.05 -69.01 6,023,302.22 571,907.67 0.40 155.96 MWD+IFR2+MS+sag(2) 1,732.36 10.66 310.41 1,715.41 1,666.71 160.59 -77.78 6,023,309.67 571,898.83 0.19 167.50 MWD+IFR2+MS+sag(2) 1,795.18 10.62 311.43 1,777.15 1,728.45 168.19 -86.54 6,023,317.18 571,889.99 0.31 179.09 MWD+IFR2+MS+sag(2) 1,857.92 10,80 314.50 1,838.80 1,790.10 176.14 -95.07 6,023,325.04 571,881.39 0.95 190.74 MWD+IFR2+MS+sag(2) 1,921.25 11.03 314.89 1,900.99 1,852.29 184.57 -103.60 6,023,333.39 571,872.78 0.38 202.73 MWD+IFR2+MS+sag(2) 1,984.31 10.67 313.48 1,962,92 1,914.22 192.84 -112.11 6,023,341.58 571,864.20 0.71 214.60 MWD+IFR2+MS+sag(2) 2,047.14 9.72 312.17 2,024.76 1,976.06 200.41 -120.26 6,023,349.07 571,855.97 1.56 225.72 MWD+IFR2+MS+sag(2) 2,109.97 10.02 312.51 2,086.66 2,037.96 207.66 -128.22 6,023,356.24 571,847.94 0.49 236.48 MWD+IFR2+MS+sag(2) 2,173.54 9.81 311.72 2,149.28 2,100.58 215.00 -136.34 6,023,363.50 571,839.75 0.39 247.42 MWD+IFR2+MS+sag(2) 2,235.95 9.99 313.19 2,210,76 2,162.06 222.25 -144.25 6,023,370.67 571,831.77 0.50 258.15 MWD+IFR2+MS+sag(2) 2,299.04 10.27 313.70 2,272.86 2,224.16 229.88 -152.31 6,023,378.22 571,823,64 0.47 269.24 MWD+IFR2+MS+sag(2) 2,361.65 10.50 314.14 2,334.45 2,285.75 237.71 -160.44 6,023,385.97 571,815.44 0.39 280.53 MWD+IFR2+MS+sag(2) 2,424.79 9.99 313.17 2,396.58 2,347.88 245.46 -168.56 6,023,393.65 571,807.24 0.85 291.76 MWD+IFR2+MS+sag(2) 2,487.57 10.55 312.86 2,458.35 2,409.65 253.09 -176.74 6,023,401.20 571,798.98 0.90 302.95 MWD+IFR2+MS+sag(2) 2,550.74 10.79 312.89 2,520.43 2,471.73 261.05 -185.32 6,023,409.07 571,790.34 0.38 314.64 MWD+IFR2+MS+sag(2) 2,613.68 9.61 313.03 2,582.38 2,533.68 268.65 -193.47 6,023,416.59 571,782.11 1.88 325.79 MWD+IFR2+MS+sag(2) 2,675.82 9.45 310.83 2,643.66 2,594.96 275.52 -201.12 6,023,423.39 571,774.39 0.64 336.07 MWD+IFR2+MS+sag(2) 2,739.39 9.82 312.67 2,706.33 2,657.63 282.61 -209.06 6,023,430.40 571,766.39 0.76 346.70 MWD+IFR2+MS+sag(2) 2,802.20 10.09 317.10 2,768.20 2,719.50 290.27 -216.74 6,023,437.98 571,758.63 1.29 357.55 MWD+IFR2+MS+sag(2) 2,865.27 9.89 316.11 2,830.31 2,781.61 298.22 -224.26 6,023,445.86 571,751.04 0.42 368.48 MWD+IFR2+MS+sag(2) 2,927.72 10.52 319.79 2,891.77 2,843.07 306.44 -231.66 6,023,454.01 571,743.56 1.45 379.51 MWD+IFR2+MS+sag(2) 2,991.01 10.85 319.99 2,953.97 2,905.27 315.41 -239.22 6,023,462.91 571,735.92 0.52 391.18 MWD+IFR2+MS+sag(2) 3,053.99 9.69 313.48 3,015,94 2,967.24 323.60 -246.87 6,023,471.02 571,728.18 2.60 402.38 MWD+IFR2+MS+sag(2) 3,117.13 9.44 312.42 3,078.20 3,029.50 330.75 -254.55 6,023,478.09 571,720.43 0.48 412.87 MWD+IFR2+MS+sag(2) 3,179.65 9.91 314.42 3,139.83 3,091.13 337.98 -262.18 6,023,485.24 571,712.74 0.92 423.37 MWD+IFR2+MS+sag(2) 3,242.77 10.22 315.74 3,201.98 3,153.28 345.79 -269.97 6,023,492.98 571,704.88 0.61 434.40 MWD+IFR2+MS+sag(2) 4/3/2017 11:59:20AM Page 3 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 3,305.61 10.12 315.00 3,263.83 3,215.13 353.68 -277.76 6,023,500.80 571,697.01 0.26 445.49 MWD+IFR2+MS+sag(2) 3,368.58 10.58 317.80 3,325.78 3,277.08 361.88 -285.56 6,023,508.92 571,689.13 1.08 456.79 MWD+IFR2+MS+sag(2) 3,431.35 10.60 318.71 3,387.48 3,338.78 370.48 -293.24 6,023,517.45 571,681.37 0.27 468.30 MWD+IFR2+MS+sag(2) 3,493.98 10.63 318.99 3,449.04 3,400.34 379.17 -300.83 6,023,526.06 571,673.70 0.10 479.79 MWD+IFR2+MS+sag(2) 3,556.99 12.85 318.41 3,510.73 3,462.03 388.80 -309.29 6,023,535.60 571,665.14 3.53 492.57 MWD+IFR2+MS+sag(2) 3,620.10 14.38 317.01 3,572.06 3,523.36 399.78 -319.30 6,023,546.49 571,655.03 2.48 507.39 MWD+IFR2+MS+sag(2) 3,682.54 17.07 316.75 3,632.16 3,583.46 412.13 -330.87 6,023,558.72 571,643.35 4.31 524.29 MWD+IFR2+MS+sag(2) 3,745.68 20.98 315.08 3,691.84 3,643.14 426.89 -345.20 6,023,573.34 571,628.87 6.25 544.86 MWD+IFR2+MS+sag(2) 3,808.79 24.40 314.37 3,750.06 3,701.36 444.01 -362.50 6,023,590.29 571,611.40 5.44 569.20 MWD+IFR2+MS+sag(2) 3,871.63 28.51 312.83 3,806.30 3,757.60 463.29 -382.79 6,023,609.37 571,590.93 6.63 597.18 MWD+IFR2+MS+sag(2) 3,934.88 31.40 312.85 3,861.10 3,812.40 484.76 -405.94 6,023,630.62 571,567.57 4.57 628.75 MWD+IFR2+MS+sag(2) 3,997.49 33.13 314.12 3,914.04 3,865.34 507.77 -430.19 6,023,653.39 571,543.11 2.97 662.17 MWD+IFR2+MS+sag(2) 4,060.51 36.50 313.79 3,965.77 3,917.07 532.73 -456.09 6,023,678.10 571,516.97 5.36 698.15 M1ND+IFR2+MS+sag(2) 4,123.76 39.46 313.31 4,015.62 3,966.92 559.55 -484.30 6,023,704.63 571,488.51 4.70 737.07 MWD+IFR2+MS+sag(2) 4,186.63 42.25 313.18 4,063.17 4,014.47 587.72 -514.25 6,023,732.51 571,458.28 4.44 778.18 MWD+IFR2+MS+sag(2) 4,249.66 46.84 313.86 4,108.08 4,059.38 618.16 -546.30 6,023,762.64 571,425.95 7.32 822.38 MWD+IFR2+MS+sag(2) 4,310.90 52.09 314.26 4,147.87 4,099.17 650.52 -579.73 6,023,794.67 571,392.21 8.59 868.91 MWD+IFR2+MS+sag(2) 4,375.80 53.38 315.75 4,187.16 4,138.46 687.05 -616.24 6,023,830.84 571,355.35 2.70 920.55 MWD+IFR2+MS+sag(2) 4,438.51 56.81 315.36 4,223.04 4,174.34 723.76 -652.25 6,023,867.20 571,318.99 5.49 971.95 MWD+IFR2+MS+sag(2) 4,501.59 57.97 315.58 4,257.04 4,208.34 761.64 -689.51 6,023,904.71 571,281.37 1.86 1,025.07 MWD+IFR2+MS+sag(2) 4,564.46 61.74 315.78 4,288.60 4,239.90 800.53 -727.49 6,023,943.23 571,243.02 6.00 1,079.40 MWD+IFR2+MS+sag(2) 4,627.07 64.31 315.26 4,317.00 4,268.30 840.33 -766.58 6,023,982.65 571,203.55 4.17 1,135.18 MWD+IFR2+MS+sag(2) 4,690.53 67.68 314.72 4,342.81 4,294.11 881.31 -807.58 6,024,023.23 571,162.16 5.37 1,193.13 MWD+IFR2+MS+sag(2) 4,753.00 71.43 313.53 4,364.63 4,315.93 922.05 -849.59 6,024,063.55 571,119.76 6.26 1,251.65 MWD+IFR2+MS+sag(2) 4,815.76 75.63 312.74 4,382.42 4,333.72 963.19 -893.50 6,024,104.26 571,075.46 6.80 1,311.82 MWD+IFR2+MS+sag(2) 4,878.72 78.85 311.35 4,396.33 4,347.63 1,004.30 -939.10 6,024,144.93 571,029.47 5.55 1,373.18 MWD+IFR2+MS+sag(2) 4,941.48 81.46 310.57 4,407.06 4,358.36 1,044.83 -985.79 6,024,185.00 570,982.39 4.34 1,434.92 MWD+IFR2+MS+sag(2) 5,004.15 85.43 310.43 4,414.21 4,365.51 1,085.26 -1,033.13 6,024,224.96 570,934.67 6.34 1,497.05 MWD+IFR2+MS+sag(2) 5,040.32 86.79 310.19 4,416.66 4,367.96 1,108.60 -1,060.65 6,024,248.04 570,906.93 3.82 1,533.06 MWD+IFR2+MS+sag(2) 5,067.17 86.13 311.06 4,418.32 4,369.62 1,126.05 -1,080.99 6,024,265.29 570,886.43 4.06 1,559.81 MWD+IFR2+MS+sag(2) 5,100.83 86.53 310.85 4,420.48 4,371.78 1,148.07 -1,106.35 6,024,287.06 570,860.85 1.34 1,593.36 MWD+IFR2+MS+sag(2) 5,130.21 85.68 311.11 4,422.47 4,373.77 1,167.29 -1,128.48 6,024,306.06 570,838.54 3.02 1,622.63 MWD+IFR2+MS+sag(2) 5,221.05 87.87 308.51 4,427.58 4,378.88 1,225.35 -1,198.14 6,024,363.44 570,768.33 3.74 1,713.07 MWD+IFR2+MS+sag(2) 5,292.82 87.32 315.49 4,430.60 4,381.90 1,273.30 -1,251.40 6,024,410.87 570,714.61 9.75 1,784.69 MWD+IFR2+MS+sag(3) 5,355.73 89.61 315.63 4,432.28 4,383.58 1,318.27 -1,295.35 6,024,455.41 570,670.23 3.68 1,847.54 MWD+IFR2+MS+sag(3) 5,418.33 92.26 316.18 4,431.26 4,382.56 1,363.30 -1,338.82 6,024,500.01 570,626.33 4.27 1,910.09 MWD+IFR2+MS+sag(3) 5,481.68 93.13 315.16 4,428.28 4,379.58 1,408.56 -1,383.04 6,024,544.84 570,581.68 2.11 1,973.34 MWD+IFR2+MS+sag(3) 5,543.98 91.77 314.97 4,425.62 4,376.92 1,452.62 -1,427.00 6,024,588.47 570,537.30 2.20 2,035.57 MWD+IFR2+MS+sag(3) 5,607.01 90.78 313.60 4,424.22 4,375.52 1,496.62 -1,472.11 6,024,632.02 570,491.77 2.68 2,098.59 MWD+IFR2+MS+sag(3) 5,670.17 90.23 311.98 4,423.66 4,374.96 1,539.52 -1,518.46 6,024,674.47 570,445.02 2.71 2,161.73 MWD+IFR2+MS+sag(3) 4/3/2017 11:59:20AM Page 4 COMPASS 5000.1 Build 81 • • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E/-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 5,732.80 90.90 310.99 4,423.04 4,374.34 1,581.01 -1,565.37 6,024,715.50 570,397.71 1.91 2,224.29 MWD+IFR2+MS+sag(3) 5,795.79 91.65 311.42 4,421.64 4,372.94 1,622.49 -1,612.75 6,024,756.52 570,349.94 1.37 2,287.19 MWD+IFR2+MS+sag(3) 5,858.83 91.71 311.44 4,419.79 4,371.09 1,664.19 -1,660.00 6,024,797.75 570,302.30 0.10 2,350.14 MWD+IFR2+MS+sag(3) 5,921.86 90.90 311.55 4,418.36 4,369.66 1,705.94 -1,707.19 6,024,839.04 570,254.70 1.30 2,413.09 MWD+IFR2+MS+sag(3) 5,984.62 90.16 311.68 4,417.78 4,369.08 1,747.62 -1,754.11 6,024,880.26 570,207.39 1.20 2,475.80 MWD+IFR2+MS+sag(3) 6,047.51 90.97 311.33 4,417,16 4,368.46 1,789.29 -1,801.21 6,024,921.47 570,159.89 1.40 2,538.62 MWD+IFR2+MS+sag(3) 6,110.44 90.16 312.03 4,416.54 4,367.84 1,831.13 -1,848.20 6,024,962.85 570,112.50 1.70 2,601.50 MWD+IFR2+MS+sag(3) 6,173.96 90.10 311.92 4,416.39 4,367.69 1,873.62 -1,895.43 6,025,004.87 570,064.87 0.20 2,664.98 MWD+IFR2+MS+sag(3) 6,236.09 89.86 312.25 4,416.41 4,367.71 1,915.26 -1,941.54 6,025,046.06 570,018.37 0.66 2,727.07 MWD+IFR2+MS+sag(3) 6,299.00 89.67 313.03 4,416.67 4,367.97 1,957.87 -1,987.81 6,025,088.22 569,971.68 1.28 2,789.96 MWD+IFR2+MS+sag(3) 6,361.66 89.67 313.77 4,417.03 4,368.33 2,000.92 -2,033.34 6,025,130.83 569,925.75 1.18 2,852.62 MWD+IFR2+MS+sag(3) 6,425.48 90.23 314.81 4,417.09 4,368.39 2,045.49 -2,079.02 6,025,174.94 569,879.64 1.85 2,916.44 MWD+IFR2+MS+sag(3) 6,488.02 90.23 316.22 4,416.84 4,368.14 2,090.10 -2,122.85 6,025,219.13 569,835.39 2.25 2,978.95 MWD+IFR2+MS+sag(3) 6,551.00 89.42 316.09 4,417.03 4,368.33 2,135.53 -2,166.47 6,025,264.12 569,791.33 1.30 3,041.89 MWD+IFR2+MS+sag(3) 6,613.62 89.73 317.43 4,417.49 4,368.79 2,181.14 -2,209.37 6,025,309.32 569,748.00 2.20 3,104.43 MWD+IFR2+MS+sag(3) 6,676.59 89.86 317.67 4,417.72 4,369.02 2,227.60 -2,251.87 6,025,355.36 569,705.06 0.43 3,167.28 MWD+IFR2+MS+sag(3) 6,739.66 90.23 318.19 4,417.67 4,368.97 2,274.42 -2,294.13 6,025,401.77 569,662.35 1.01 3,230.20 MWD+IFR2+MS+sag(3) 6,802.39 90.35 318.11 4,417.35 4,368.65 2,321.15 -2,335.98 6,025,448.08 569,620.05 0.23 3,292.77 MWD+IFR2+MS+sag(3) 6,865.38 90.35 317.21 4,416.97 4,368.27 2,367.71 -2,378.40 6,025,494.22 569,577.19 1.43 3,355.63 MWD+IFR2+MS+sag(3) 6,928.33 89.67 313.75 4,416.96 4,368.26 2,412.58 -2,422.53 6,025,538.67 569,532.63 5.60 3,418.55 MWD+IFR2+MS+sag(3) 6,991.29 89.48 312.42 4,417.42 4,368.72 2,455.59 -2,468.51 6,025,581.22 569,486.24 2.13 3,481.49 MWD+IFR2+MS+sag(3) 7,054.14 89.61 311.32 4,417.92 4,369.22 2,497.54 -2,515.31 6,025,622.71 569,439.04 1.76 3,544.30 MWD+IFR2+MS+sag(3) 7,116.83 89.86 311.17 4,418.21 4,369.51 2,538.87 -2,562.45 6,025,663.58 569,391.51 0.47 3,606.91 MWD+IFR2+MS+sag(3) 7,179.92 89.86 311.47 4,418.37 4,369.67 2,580.52 -2,609,83 6,025,704.77 569,343.73 0.48 3,669.94 MWD+IFR2+MS+sag(3) 7,242.84 89.98 310.52 4,418.46 4,369.76 2,621.80 -2,657.32 6,025,745.58 569,295.85 1.52 3,732.77 MWD+IFR2+MS+sag(3) 7,305.86 89.86 309.70 4,418.54 4,369.84 2,662.40 -2,705.52 6,025,785.71 569,247.27 1.32 3,795.64 MWD+IFR2+MS+sag(3) 7,368.63 90.10 308.74 4,418.56 4,369.86 2,702.09 -2,754.15 6,025,824.92 569,198.26 1.58 3,858.19 MWD+IFR2+MS+sag(3) 7,431.16 90.78 308.75 4,418.08 4,369.38 2,741.22 -2,802.92 6,025,863.58 569,149.12 1.09 3,920.46 MWD+IFR2+MS+sag(3) 7,494.24 91.09 307.98 4,417.06 4,368.36 2,780.37 -2,852.37 6,025,902.24 569,099.30 1.32 3,983.23 MWD+IFR2+MS+sag(3) 7,557.38 89.36 306.72 4,416.81 4,368.11 2,818.67 -2,902.56 6,025,940.05 569,048.74 3.39 4,045.94 MWD+IFR2+MS+sag(3) 7,620.13 89.42 305.13 4,417.48 4,368.78 2,855.48 -2,953.37 6,025,976.37 568,997.59 2.54 4,108.06 MVVD+IFR2+MS+sag(3) 7,683.60 89.61 305.64 4,418.01 4,369.31 2,892.23 -3,005.11 6,026,012.62 568,945.49 0.86 4,170.81 MWD+IFR2+MS+sag(3) 7,746.34 89.86 307.16 4,418.30 4,369.60 2,929.46 -3,055.61 6,026,049.35 568,894.64 2.46 4,233.00 MWD+IFR2+MS+sag(3) 7,809.26 90.10 307.53 4,418.33 4,369.63 2,967.63 -3,105.63 6,026,087.03 568,844.26 0.70 4,295.49 MWD+IFR2+MS+sag(3) 7,871.89 89.92 307.91 4,418.31 4,369.61 3,005.95 -3,155.17 6,026,124.86 568,794.36 0.67 4,357.75 MWD+IFR2+MS+sag(3) 7,934.96 90.16 308.04 4,418.27 4,369.57 3,044.76 -3,204.89 6,026,163.19 568,744.27 0.43 4,420.47 MWD+IFR2+MS+sag(3) 7,997.95 90.53 307.76 4,417.89 4,369.19 3,083.45 -3,254.59 6,026,201.39 568,694.20 0.74 4,483.10 MWD+IFR2+MS+sag(3) 8,060.82 91.15 306.99 4,416.97 4,368.27 3,121.61 -3,304.55 6,026,239.06 568,643.88 1.57 4,545.55 MWD+IFR2+MS+sag(3) 8,121.91 90.90 307.36 4,415.88 4,367.18 3,158.52 -3,353.21 6,026,275.50 568,594.86 0.73 4,606.19 MWD+IFR2+MS+sag(3) 8,184.88 90.66 307.83 4,415.02 4,366.32 3,196.93 -3,403.10 6,026,313.42 568,544.61 0.84 4,668.76 MWD+IFR2+MS+sag(3) 4/3201711:59:20AM Page 5 COMPASS 5000.1 Build 81 • i Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (8) (ft) (°1100') (ft) Survey Tool Name 8,249.00 90.53 307.79 4,414.35 4,365.65 3,236.24 -3,453.76 6,026,352.23 568,493.58 0.21 4,732.51 MWD+IFR2+MS+sag(3) 8,311.62 90.72 308.40 4,413.67 4,364.97 3,274.87 -3,503.04 6,026,390.38 568,443.94 1.02 4,794.79 MWD+IFR2+MS+sag(3) 8,377.60 90.41 308.99 4,413.02 4,364.32 3,316.12 -3,554.53 6,026,431.13 568,392.05 1.01 4,860.49 MWD+IFR2+MS+sag(3) 8,438.11 90.29 310.19 4,412,65 4,363.95 3,354.68 -3,601.16 6,026,469.23 568,345.06 1.99 4,920.81 MWD+IFR2+MS+sag(3) 8,501.45 90.41 310.57 4,412.26 4,363.56 3,395.71 -3,649.41 6,026,509.79 568,296.42 0.63 4,984.03 M1ND+IFR2+MS+sag(3) 8,564.69 91.65 312.03 4,411.13 4,362.43 3,437.44 -3,696.91 6,026,551.06 568,248.52 3.03 5,047.18 MWD+IFR2+MS+sag(3) 8,627.85 91.59 311.43 4,409.34 4,360.64 3,479.46 -3,744.02 6,026,592.62 568,201.01 0.95 5,110.27 MWD+IFR2+MS+sag(3) 8,690.62 91.52 311.99 4,407.64 4,358.94 3,521.21 -3,790.87 6,026,633.91 568,153.77 0.90 5,172.97 MWD+IFR2+MS+sag(3) 8,753.12 90.47 311.87 4,406.55 4,357.85 3,562.97 -3,837.36 6,026,675.21 568,106.88 1.69 5,235.41 MWD+IFR2+MS+sag(3) 8,816.21 90.29 312.28 4,406.13 4,357.43 3,605.25 -3,884.18 6,026,717.03 568,059.65 0.71 5,298.47 MWD+IFR2+MS+sag(3) 8,878.76 89.98 308.58 4,405.99 4,357.29 3,645.80 -3,931.79 6,026,757.12 568,011.66 5.94 5,360.88 MWD+IFR2+MS+sag(3) 8,942.00 88.62 305.08 4,406.76 4,358.06 3,683.70 -3,982.39 6,026,794.52 567,960.69 5.94 5,423.61 MWD+IFR2+MS+sag(3) 9,004.97 89.98 307.15 4,407.53 4,358.83 3,720.81 -4,033.26 6,026,831.14 567,909.48 3.93 5,485.98 MWD+IFR2+MS+sag(3) 9,066.90 90.84 309.03 4,407.08 4,358.38 3,759.01 -4,081.99 6,026,868.86 567,860.38 3.34 5,547.58 MWD+IFR2+MS+sag(3) 9,131.11 90.41 312.02 4,406.38 4,357.68 3,800.73 -4,130.79 6,026,910.10 567,811.19 4.70 5,611.66 MWD+IFR2+MS+sag(3) 9,193.31 90.78 314.29 4,405.74 4,357.04 3,843.27 -4,176.16 6,026,952.19 567,765.41 3.70 5,673.84 MWD+IFR2+MS+sag(3) 9,256.41 90.10 314.09 4,405.25 4,356.55 3,887.25 -4,221.41 6,026,995.73 567,719.75 1.12 5,736.94 MWD+IFR2+MS+sag(3) 9,319.41 90.23 313.38 4,405.07 4,356.37 3,930.80 -4,266.93 6,027,038.84 567,673.81 1.15 5,799.94 MWD+IFR2+MS+sag(3) 9,382.18 90.90 314.90 4,404.45 4,355.75 3,974.51 -4,311.97 6,027,082.10 567,628.35 2.65 5,862.70 MWD+IFR2+MS+sag(3) 9,445.30 91.03 315.32 4,403.39 4,354.69 4,019.22 -4,356.51 6,027,126.38 567,583.39 0.70 5,925.80 MWD+IFR2+MS+sag(3) 9,507.86 90.84 315.47 4,402.37 4,353.67 4,063.76 -4,400.43 6,027,170.48 567,539.04 0.39 5,988.34 MWD+IFR2+MS+sag(3) 9,570.67 90.16 314.08 4,401.82 4,353.12 4,107.99 -4,445.02 6,027,214.28 567,494.03 2.46 6,051.14 MWD+IFR2+MS+sag(3) 9,633.58 89.98 313.58 4,401.74 4,353.04 4,151.56 -4,490.40 6,027,257.40 567,448.24 0.84 6,114.05 MWD+IFR2+MS+sag(3) 9,696.85 91.52 315.60 4,400.92 4,352.22 4,195.97 -4,535.45 6,027,301.37 567,402.76 4.01 6,177.30 MWD+IFR2+MS+sag(3) 9,759.65 89.55 315.03 4,400.33 4,351.63 4,240.61 -4,579.61 6,027,345.58 567,358.18 3.27 6,240.08 MWD+IFR2+MS+sag(3) 9,822.62 88.81 314.06 4,401.23 4,352.53 4,284.78 -4,624.48 6,027,389.31 567,312.89 1.94 6,303.04 MWD+IFR2+MS+sag(3) 9,885.60 88.50 312.62 4,402.71 4,354.01 4,327.99 -4,670.27 6,027,432.07 567,266.68 2.34 6,365.99 MWD+IFR2+MS+sag(3) 9,948.28 88.50 309.96 4,404.35 4,355.65 4,369.34 -4,717.35 6,027,472.95 567,219.21 4.24 6,428.58 MWD+IFR2+MS+sag(3) 10,011.51 89.05 309.24 4,405.70 4,357.00 4,409.63 -4,766.06 6,027,512.77 567,170.12 1.43 6,491.61 MWD+IFR2+MS+sag(3) 10,074.80 89.42 310.06 4,406.55 4,357.85 4,450.01 -4,814.78 6,027,552.67 567,121.01 1.42 6,554.71 MWD+IFR2+MS+sag(3) 10,137.68 89.79 310.24 4,406.98 4,358.28 4,490.55 -4,862.84 6,027,592.75 567,072.57 0.65 6,617.44 MWD+IFR2+MS+sag(3) 10,200.54 89.48 310.96 4,407.38 4,358.68 4,531.46 -4,910.57 6,027,633.19 567,024.45 1.25 6,680.19 MWD+IFR2+MS+sag(3) 10,263.26 89.86 311.51 4,407.74 4,359.04 4,572.80 -4,957.74 6,027,674.07 566,976.89 1.07 6,742.84 MWD+IFR2+MS+sag(3) 10,326.53 89.98 312.21 4,407.83 4,359.13 4,615.02 -5,004.86 6,027,715.82 566,929.37 1.12 6,806.06 MWD+IFR2+MS+sag(3) 10,389.26 90.60 313.82 4,407.51 4,358.81 4,657.81 -5,050.72 6,027,758.17 566,883.10 2.75 6,868.78 MWD+IFR2+MS+sag(3) 10,452.31 90.60 314.74 4,406.85 4,358.15 4,701.83 -5,095.86 6,027,801.74 566,837.54 1.46 6,931.83 MWD+IFR2+MS+sag(3) 10,515.10 89.61 313.29 4,406.74 4,358.04 4,745.46 -5,141.01 6,027,844.93 566,791.97 2.80 6,994.61 MWD+IFR2+MS+sag(3) 10,577.99 90.10 312.10 4,406.90 4,358.20 4,788.10 -5,187.23 6,027,887.12 566,745.35 2.05 7,057.49 MWD+IFR2+MS+sag(3) 10,640.33 90.10 311.82 4,406.79 4,358.09 4,829.78 -5,233.59 6,027,928.34 566,698.59 0.45 7,119.79 MWD+IFR2+MS+sag(3) 10,704.13 90.04 310.21 4,406.71 4,358.01 4,871.65 -5281.73 6,027,969.74 566,650.06 2.53 7,183.50 MWD+IFR2+MS+sag(3) 4/3/2017 11:59:20AM Page 6 COMPASS 5000.1 Build 81 . • Halliburton Definitive Survey Report Company: Hilcorp Alaska,LLC Local Co-ordinate Reference: Well MPU B-33 Project: Milne Point TVD Reference: Actual:@ 48.70usft Site: M Pt B Pad MD Reference: Actual:@ 48.70usft Well: MPU B-33 North Reference: True Wellbore: MPU B-33 Survey Calculation Method: Minimum Curvature Design: MPU B-33 Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +E!-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 10,766.71 89.42 308.83 4,407.01 4,358.31 4,911.47 -5,330.00 6,028,009.09 566,601.41 2.42 7,245.88 MWD+IFR2+MS+sag(3) 10,830.00 89.48 308.07 4,407.61 4,358.91 4,950.83 -5,379.56 6,028,047.96 566,551.47 1.20 7,308.87 MWD+IFR2+MS+sag(3) 10,863.92 89.61 307.87 4,407.88 4,359.18 4,971.69 -5,406.30 6,028,068.56 566,524.53 0.70 7,342.61 MWD+IFR2+MS+sag(3) 10,933.00 89.61 307.87 4,408.35 4,359.65 5,014.10 -5,460.83 6,028,110.44 566,469.60 0.00 7,411.29 PROJECTED to TD mitchell.laird@halliburton.com benjaminhandehailiburtoncom Checked By: 2017.04.0310:20:30-08'00' Approved By: 2017.04.030¢x407-08'00• Date: 4/3/2017 4/3/2017 11:59:20AM Page 7 COMPASS 5000.1 Build 81 Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. MP B-33 Date Run 23-Mar-17 r County State Alaska Supv. J.Lott/S.Barber CASING RECORD j Surface 7. TD 5,259.00 Shoe Depth: 5,248.00 PBTD: 5,162.17 No.Jts.Delivered 124 No.Jts.Run 124 No.Jts.Returned Casing(Or Liner)Detail Setting Depths Jts. Component Size Wt. Grade THD Make Length Bottom Top Eccentric Shoe 10 40.0 DWC/C DHP 2.26 5,248.00 5,245.74 1 Casing 9 5/8 40.0 L-80 DWC/C Vam 40.34 5,245.74 5,205.40 Float Collar 10 40.0 _ DWC/C DHP 1.73 5,205.40 5,203.67 1 Casing 9 5/8 40.0 L-80 DWC/C Vam 39.90 5,203.67 5,163.77 Baffle Collar 10 DWC/C Halliburton 1.60 5,163.77 5,162.17 80 Casing 9 5/8 40.0 L-80 DWC/C Vam 3,247.03 5,162.17 1,915.14 ES Stage Tool 10 _ DWC/C Halliburton 3.10 1,915.14 1,912.04 ✓ 45 Casing 9 5/8 40.0 L-80 DWC/C Vam 1,857.50 1,912.04 0 Csg Wt.On Hook: 145,000 Type Float Collar: Conventional No.Hrs to Run: 18 Csg Wt.On Slips: 110,000 Type of Shoe: Eccentric Shoe/Down I Casing Crew: Weatherford Rotate Csg Yes X No Recip Csg X Yes No 40 Ft.Min. 9.4 PPG Fluid Description: Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes _No Liner hanger test pressure: Floats Held X Yes_ No Centralizer Placement: 2 ea on shoe jt,1 ea in ctr of jt#2 and jt#3. Every 80 from 125'to 890'MD. 3 ea above and 3 ea below ES stage tool. Total of 20 bow spring centralizers run. CEMENTING REPORT Shoe @ 5248 FC @ 5,203.67 Top of Liner Preflush(Spacer) Type: Tuned Spacer w/dye Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry Type: Extenda Cem Sacks: 500 Yield: 2.24 Density(ppg) 11.7 Volume pumped(BBLs) 220 Mixing/Pumping Rate(bpm): 5 Tail Slurry 5 r m Type: Swift Cem Sacks: 210 Yield: 1.15 / ¢ Density(ppg) 15.8 Volume pumped(BBLs) 43 Mixing/Pumping Rate(bpm): 5 4C4fr• F Post Flush(Spacer) z Type: Density(ppg) Rate(bpm): Volume: IT. Displacement: Type: Spud Mud Density(ppg) 9.4 Rate(bpm): 5.5 Volume(actual/calculated): 391/391.7 FCP(psi): 750 Pump used for disp: MP#2 Bump Plug? X Yes No Bump press 1250 Casing Rotated? Yes X No Reciprocated? X Yes _No %Returns during job 100 Cement returns to surface? X Yes _No Spacer returns? X Yes No Vol to Surf: 40 Cement In Place At: 18:00 Date: 3/22/2017 Estimated TOC: 1,912 Method Used To Determine TOC: Circ cmt out from ES stg tool Stage Collar @ 1912.04 Type ES Cmt stage too Closure OK ok Preflush(Spacer) Type: Tuned Spacer Density(ppg) 10.5 Volume pumped(BBLs) 60 Lead Slurry 1,09 Type: Perm L Lead Sacks: 450 Yield: 5.39 r-ikC?V Density(ppg) 10.7 Volume pumped(BBLs) 432 Mixing/Pumping Rate(bpm): 5 5' Tail Slurry cw7 Type: Swift Cem Sacks: 275 Yield: 1.15 y Density(ppg) 15.8 Volume pumped(BBLs) 56.6 Mixing/Pumping Rate(bpm): 5 z Post Flush(Spacer) o Type: Density(ppg) Rate(bpm): Volume: Si co Displacement: Type: Spud Mud Density(ppg) 9.5 Rate(bpm): 5.5 Volume(actual/calculated): 145/145 FCP(psi): 495 Pump used for disp: Rig Bump Plug? X Yes No Bump press 1900 Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 100 Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 228.6 d Cement In Place At: 10:00 Date: 3/23/2017 Estimated TOC: 0 Method Used To Determine TOC: Visual,Scale,Sample Post Job Calculations: Calculated Cmt Vol @ 0%excess: 292.3 Total Volume cmt Pumped: 751.6 Cmt returned to surface: 268.6 Calculated cement left in wellbore: 483 OH volume Calculated: 292.3 OH volume actual: 483 Actual%Washout: 65 www.wellez.net WellEz Information Management LLC ver_102716bf • • MPB-33 MW vs Depth 0 MPB-33 Plan 1000 MPB-33 Actual 2000 3000 4000 5000 $ 6000 s a 7000 3 c C G 8000 9000 10000 11000 12000 13000 14000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) 5/1/2017 411/ 1110 MPB-33 FINAL Days vs Depth 0 500 -MPB-33 Plan 1000 -MPB-33 Actual 1500 2000 2500 3000 3500 4000 4500 F5000 r v 5500 v 1 6000 0 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 0 5 10 15 20 25 Days 5/1/2017 410IP Wallace, Chris D (DOA) From: AK, GWO Well Integrity Engineer <AKGWOWellSiteEnginee@bp.com> Sent: Sunday, February 26, 2017 4:08 PM To: AK, GWO Projects Well Integrity;AK, GWO SUPT Well Integrity;AK, OPS GC2 OSM;AK, OPS GC2 Field O&M TL;AK, OPS GC2 Wellpad Lead;AK, OPS Prod Controllers;AK, OPS EOC Specialists;Cismoski, Doug A; Daniel, Ryan;AK, RES GPB West Wells Opt Engr;AK, RES GPB East Wells Opt Engr;AK, OPS Well Pad RJ;Wallace, Chris D (DOA) Cc: AK, GWO DHD Well Integrity;AK, GWO Completions Well Integrity;AK, OPS FF Well Ops Comp Rep; Rupert, C. Ryan; Schultz, Kirsten L; Hibbert, Michael;Janowski, Carrie; Montgomery,Travis J; Munk, Corey; Obrigewitch, Beau; Pettus,Whitney; Sternicki, Oliver R;Tempel,Troy;Worthington,Aras J; Regg,James B (DOA);AKIMS App User Subject: OPERABLE:Injector R-22A (PTD#2141640)Inner Annulus Repressurization on MI Mitigated All, Injector R-22A(PTD#2141640) passed an MIT-T& MIT-IA on 1/28/17, after Slickline set a Liner Top Packer.The passing tests confirm two competent well barriers. The well was brought online Under Evaluation and monitored for 26 days, with no further indication of Tubing x Inner Annulus communication. The well is classified as Operable. Work Completed/Plan Forward: 1. Wellhead: Positive Pressure Packoff Test-Tubing—Passed 09/09/16 2. Wellhead: PPPOT-IC—Failed 09/09/16; however Leak Path Evaluation indicated primary seal good 3. Fullbore:AOGCC MIT-IA to 3700 psi—Passed 09/13/16 4. Downhole Diagnostics: Monitor wellhead pressures—IA exhibited repressurization 10/6/16 5. Slickline/Fullbore:Caliper tubing, load tubing, set and test wireline-retrievable plug—Inconclusive 12/20/16 6. Slickline/Fullbore: Load tubing, set and test Liner Top Packer—MIT-T& MIT-IA to 3400 psi Passed 1/28/17 7. Operations: Bring well online Under Evaluation-Complete 8. Downhole Diagnostics: Monitor wellhead pressures-Complete Please reply if in conflict with proposed plan. Matt Ross (Alternate: Josh Stephens) Well Integrity Engineering Office 907-659-8110 Cell 907-980-0552 Harmony 4530 1 \0\�/77 9 THE STATE Alaska Oil and Gas ,t-�ys �y LA T Conservation Commission _ 333 West Seventh Avenue "��'`� - ! Anchorage, Alaska 99501-3572 �.T., GOVERNOR BILL WALKER g ," ' Main: 907.279.1433 C4'ALAS� Fax: 907.276.7542 www.aogcc.alaska.gov Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Schrader Bluff Oil Pool, MPU B-33 Hilcorp Alaska, Inc. Permit to Drill Number: 216-164 Surface Location: 4313' FEL, 27' FSL, SEC. 18, T13N, R11E, UM, AK Bottomhole Location: 95' FNL, 835' FWL, SEC. 13, T13N, R10E, UM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced service well. Per Statute AS 31.05.030(d)(2)(B)and Regulation 20 AAC 25.071,composite curves for well logs run must be submitted to the AOGCC within 90 days after completion,suspension or abandonment of this well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition,the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05,Title 20,Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair DATED this(/day of January, 2017. E. I. STATE OF ALASKA A OIL AND GAS CONSERVATION COMI1 11 OFC 0 2 2016 PERMIT TO DRILL t4 20 AAC 25.005 -A.22 t 1 iLy 1a.Type of Work: 1 b.Proposed Well Class: Exploratory-Gas ❑ Service- WAG ❑ Service-Disp 31 lc.Specify if well is proposed for: Drill ❑., ' Lateral ❑ Stratigraphic Test ❑ Development-Oil ❑ Service- Winj ❑✓ ' Single Zone I".Coalbed Gas ❑ Gas Hydrates ❑ Redrill❑ Reentry❑ Exploratory-Oil ❑ Development-Gas ❑ Service-Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket Q r Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 ' MPU B-33 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 MD: 10,933' • TVD: 4,399' i Milne Point Unit 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Schrader Bluff Oil Pool Surface: 4313'FEL,27'FSL,Sec 18,T13N,R11E,UM,AK • (SHL)ADL047438/(TPH/BHL)ADL047437. PL 4,1-)b Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1158'FSL,197'FEL,Sec 13,T13N,R10E,UM,AK N/A 2/11/2017 Total Depth: , 9.Acres in Property: 14.Distance to Nearest Property: 95'FNL,835'FWL,Sec 13,T13N,R10E,UM,AK 4344 5404'to nearest unit boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL(ft): 49.2 ' 15.Distance to Nearest Well Open Surface: x-571978 y- 6023149 Zone-4 ' GL Elevation above MSL(ft): 22.7 r to Same Pool: MPB-29 705' 16.Deviated wells: Kickoff depth: 254 feet i 17.Maximum Potential Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 90.26 degrees 4 Downhole: 1954 • Surface: 1512 • 18.Casing Program: Specifications Top - Setting Depth - Bottom ' Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD ND (including stage data) 42" 20" 78.6# A-53 Weld 80' Surface Surface 80' 80' 50 bbls from cement truck Stg 1 -1330 ft3 12-1/4" 9-5/8" 40# L-80 DWC/C 5,078' Surface Surface 5,078' 4,420' Stg 2-1690 ft3 8-1/2" 4-1/2" 13.5# L-80 VAM HTTC 6,033' 4,900' 4,400' 10,933' 4,399' Cementless Inj.Liner w/ICDs Lul - -'‘.4..o E.1:i.— Ptc.e} 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): Casing Length Size Cement Volume MD ND Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth ND(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program Q Time v.Depth Plot ❑✓ Shallow Hazard Analysis❑ Diverter Sketch ❑., Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements Q 21. Verbal Approval: Commission Representative: Date 22.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Email Ikellerahilcorp.com Printed Name Luk Keller Title Drilling Engineer Signature Phone 777-8395 Date 1 2--(6/20/6 Commission Use Only Permit to Drill API Number: Permit ApprovalI _ See cover letter for other Number: ,)!b— /6 1 50-(122i- 13573 — OQ —QQ Date: i I 1/)I Ii requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane gas hydrates,or gas contained in shales: Other: = 3 Ow5. / f--- Samples req'd: Yes❑ No NII Mud log req'd:Yes No T( 0/2,64_4.41- H2S measures: Yes V No❑ Directional svy req'd:Yes No iki-- ( L-t- ' - �+ y,., Spacing exception req'd: Yes❑ No V Inclination-only svy req'd:Yes❑ No AM 1-r- /4 , c c•iy,:4- Post initial injection MIT req'd:Yes CINo CI Al,'�L�.�'n,�, _ k,.�c_.t P_ /0 kt...•ra, 7in• /�°''€'4z .-) z J:�{[z.C.9 / APPROVED BY Approved by: .. COMMISSIONER THE COMMISSION Date:/- (p- l 7 i m, 1 /15 i1/ 5) � //Form 10-401(Revised 0 Rii ei.i4li��ol months from the date of approval(20 AAC 25.005(g)) Attachments in Duplicate/'L Luke Keller • Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Hilcorp Alaska,LLA, 12/2/2016 RECEIVED Commissioner Alaska Oil &Gas Conservation Commission DEC 02 2016 333 W. 7th Avenue Anchorage, Alaska 99501 AOGCC Re: MPB-33 # ► l� Dear Commissioner, MPU B-33 is a grassroots water injector planned to be drilled in the Schrader Bluff NC sand. B-33 is part of a (2)well pilot program targeting the NC sand. B-33 will be paired with a grassroots producer, B-32. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff NC sand. A lateral section will then be drilled in the reservoir. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately February 11th, 2017. The Hilcorp"Innovation"will be used to drill and complete the wellbore. If you have any questions, please don't hesitate to contact myself at 777-8395 or Paul Mazzolini at 777-8369. Sincerely, Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 101 • 0 r � l.0 Q m EV •! CO 0 NCO /( 0. O0. N• co MI m M / M I m, . • / \ 05 CO e / CO o M • / co %- 7 r • 44144%, m..... co 0 / m / `11 r / / / ' • . i 4 N /OQ .N ' -�� • m' CD /000 CI . c ‘41%vo \ . ' 17 s J /// C I / 0 J J U 2 13 mz 9 CO ` U`a(n o zopQ lW J l- v y mEo o QIZin - W Y`?1M i Q ^- Z yyO m LL ..-5c � La01it fi O O w a J c Lc2com C i Y8M 0 b 36 ry '1 ru ❑ 2fifil 20 HP 611) =1 1 mcmc„ 5 Sam F Area of ReIw — Proposed MPB-33 InjecPn Well Prior to completion of the MPB-33 Schrader Bluff NC injection well, an Area of Review (AOR) must be conducted. This AOR found 9 wells that enters the SB NC within 1/4 mile of MPB-33's proposed lateral. The tables below illustrate the wells within the AOR, the distance from MPB- 33, completion details and integrity conditions based on in-depth review of each well. . Table 1: Wells within AOR Well PTD NC Sand Shortest Annulus Integrity Name Depth Distance, Ft. 4851' MD 13-3/8" Casing set at 2,547'. Well drilled out to 8,300'then MPD-02 183-012 4466'TVD 1275' cemented with plugs @ 7,554'-8,300', 3,900'-4,250', 2,634' (PBTD) -2,800'. Kicked off of cement plug at 2,634'. Ran 7" casing to 9305'. Pump 925 sx of Class G cmt, and down squeezed with 400 sx 5073' MD of Coldset II and 180 bbl of Arctic Pack.TxIA MPD 02A 183-040 155' 4413'ND communication.Well secured with plug at 8476' and passing CMIT-TxIA to 2500 psi on 2/13/10 confirmed production casing integrity. 5967' MD 9-5/8" surface casing run to 6113'. Surface cement job MPB-19 185-230 4454'ND 610' pumped as 552 bbls of 12.3 ppg Perma E and 56 bbls of 15.8 ppg Class G. Cement to surface. 5375' MD 9-5/8" surface casing run to 5805'. Surface cement job MPB-08 185-063 4441'ND 370' pumped as 820 bbls of 12.2 ppg Coldset III and 58 bbls of 15.8 ppg Class G. Cement to surface. 5394' MD 9-5/8" surface casing run to 5789'. Surface cement job MPB-10 185-017 4394'ND 1180' pumped as 762 bbls of 12.2 ppg Arctic Set III and 106 bbls of 15.8 ppg Class G. Cement to surface. 9-5/8" surface casing run to 5346'. Surface cement job 4887' MD pumped as 750 bbls of 12 ppg Arctic Set III and 50 bbls of MPB-11 185-043 4423'ND 265' 15.8 ppg Class G. Lost returns 80 bbls into displacement, top job with 19 bbls of Arctic Set I cmt. 9-5/8" surface casing run to 5068'. Surface cement job 5023' MD pumped as 2 stage cmt job. Stg 1- 187 bbls of 11.7 ppg MPB-29 216-015 705' Class G and 40 bbls of 15.8 ppg Class G.Stg 2—226 bbls of 4416'ND 10.7 ppg Perma and 55.8 of 15.8 Class G. Cement circulated to surface for both stages. 4567' MD 9-5/8" surface casing run to 4787'. Surface cement job MPB-12 185-080 4457'ND 1090' pumped as 424 bbls of 12.3 ppg ColdSet III and 59 bbls of 15.8 ppg Class G. Cement to surface. 4659' MD 9-5/8" surface casing run to 5034'. Surface cement job MPB-20 186-005 4408'ND 1290' pumped as 456 bbls of 12.3 ppg Perma E and 56.3 bbls of 15.8 ppg Class G. Cement to surface. • • Hilcorp Alaska, LLC Milne Point Unit (MPU) B-33 Drilling Program Version 1 Oct 17th, 2016 • • Milne Point Drilling Procedure Hilcorp Energy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Casing Inspection 4 6.0 Internal Reporting Requirements 5 7.0 Planned Wellbore Schematic 6 8.0 Drilling/Completion Summary 7 9.0 Mandatory Regulatory Compliance/Notifications 8 10.0 R/U and Preparatory Work 10 11.0 N/U 13-5/8"5M Diverter System 11 12.0 Drill 12-1/4"Hole Section 13 13.0 Run 9-5/8" Surface Casing 18 14.0 Cement 9-5/8" Surface Casing 23 15.0 BOP N/U and Test 27 16.0 Drill 8-1/2"Hole Section 29 17.0 Run 4-1/2"Injection Liner 33 18.0 Run Injection Assembly 37 19.0 RDMO 37 20.0 Diverter Schematic 38 21.0 BOP Schematic 39 22.0 Wellhead Schematic 40 23.0 Days Vs Depth 41 24.0 Formation Tops 42 25.0 Anticipated Drilling Hazards 43 26.0 Innovation Rig Layout 45 27.0 FIT Procedure 46 28.0 Choke Manifold Schematic 47 29.0 Casing Design Information 48 30.0 8-1/2"Hole Section MASP 49 31.0 Spider Plot(NAD 27)(Governmental Sections) 50 32.0 Surface Plat(As Built)(NAD 27) 51 33.0 Offset MW vs TVD Chart 52 34.0 Drill Pipe Information 5" 19.5#S-135 DS-50 53 • • IEI Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 1.0 Well Summary Well MPU B-33 Pad Milne Point"B"Pad Planned Completion Type 4-1/2" Injection string Target Reservoir(s) Schrader Bluff "NC" Sand Planned Well TD,MD/TVD 10,933.3' MD/4,399.2' TVD PBTD, MD/TVD 10,925' MD/4,399' TVD Surface Location(Governmental) 4,313' FEL,27' FSL, Sec 18, T13N,R11E, UM,AK Surface Location(NAD 27—Zone 4) X=571,978.15, Y=6,023,149.85 Surface Location(NAD 83) Top of Productive Horizon (Governmental) 1158'FSL, 197'FEL, Sec 13, T13N, RI OE, UM,AK TPH Location(NAD 27) X= 570,871.77, Y=6,024,270.44 TPH Location(NAD 83) BHL(Governmental) 95'FNL, 835'FWL, Sec 13, T13N,R10E, UM,AK BHL(NAD 27) X= 566,585.29, Y=6,028,257.39 BHL(NAD 83) AFE Number 1612656D AFE Drilling Days 14 days AFE Completion Days 5 days AFE Drilling Amount $3,317,700 AFE Completion Amount $1,514,500 AFE Facility Amount $300,000.00 Maximum Anticipated Pressure (Surface) 1512 psi Maximum Anticipated Pressure (Downhole/Reservoir) 1954 psi Work String 5" 19.5# S-135 DS-50 (Weatherford Rental) KB Elevation above MSL: 26.5 ft+22.7 ft=49.2 ft GL Elevation above MSL: 22.7 ft BOP Equipment 13-5/8"x 5M Annular, (3)ea 13-5/8"x 5M Rams Page 2 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp F Connors Changes to Approved Permit to Drill Date: 10-25-2016 Subject: Changes to Approved Permit to Drill for MPU B-33 File#: MPU B-33 Drilling and Completion Program Any modifications to MPUB-33 Drilling& Completion Program will be documented and approved below. Changes to an approved APD will be communicated& approved by the AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared Drilling Engineer Date Page 3 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp /•'=\ Energy Company 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD (in) (#/ft) (psi) (psi) (k-lbs) Cond 20" 19.25" - - 78.6 A-53 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.235" 40 L-80 DWC/C 5,750 3,090 916 VAM 8-1/2" 4-1/2" 3.849" 3.75" 4.93" 13.5 L-80 HTTC 9,020 8,540 307 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn M/U M/U Tension Section (in) (in) (#/ft) (Min) (Max) (k-lbs) All 5" 4.276" 3.25" 6.625" 19.5 S-135 GPDS50 36,100 43,100 560k 5.0 Casing Inspection All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 1 Oct, 2016 • • 11 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 6.0 Internal Reporting Requirements 6.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to 6am • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area—this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. • Enter the MD and TVD depths EVERY DAY whether you are making hole or not. 6.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com , Ikeller@hilcorp.com and cdinger@hilcorp.com 6.3 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. 6.4 EHS Incident Reporting • Health and safety: Notify EHS field coordinator. • Environmental: Drilling Environmental coordinator • Notify Drlg Manager&Drlg Engineer • Submit Hilcorp Incident report to contacts above within 24 hrs 6.5 Casing Tally • Send final "As-Run"Casing tally to Ikeller@hilcorp.com and cdinger@hilcorp.com 6.6 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller(a,hilcorp.com and cdinger@hilcorp.com 6.7 Hilcorp Milne Point Contact List: Title Name Work Phone Cell Phone Email Drilling Manager Paul Mazzolini 907.777.8369 907.317.1275 pmazzolini@hilcorp.com Drilling Engineer Luke Keller 907.777.8395 832.247.3785 Ikeller@hilcorp.com Geologist Kevin Eastham 907.777.8316 907.360.5087 keastham@hilcorp.com Drlg Environmental Coord Keegan Fleming 907.777.8477 907.350.9439 kfleming@hilcorp.com EHS Coordinator Carl Jones 907.777.8327 907.382.4336 caiones@hilcorp.com Drilling Tech Cody Dinger 907.777.8389 509.768.8196 cdinger@hilcorp.com V Page 5 Version 1 Oct,2016 • II Milne Point Unit B-33 41,- i r x`" Drilling Procedure Hilcorp Energy Company 7.0 Planned Wellbore Schematic OrgKBEler-492'/GLElev.:22.7 TREE&WELLHEAD Tree Seaboard 4 1/16" 5M I ' ` Seaboard 13-5/8"5M x 11"5M Tbg Spool w/11"x 41/2"EUE Wellhead Top and Bottom;with 4"CIW"H"BPV profile.2ea 3/8"NPT control lines.4 1/2"EUE x Supermax x-over on pup OPEN HOLE/CEMENT DETAIL 20" 350 sx of Arcticset I(Approx) • •• 12-1/4"1st Stage 194 bbl 10.7#ArcticCEM,43 bbl 15.8#SwiftCEM 12-1/4"2nd Stage 245 bbl 10.7#ArcticCEM,56 bbl 15.8#SwiftCEM }. 8-1/2" Cementless Injection Liner in 8-1/2"hole ' CASING DETAIL 96.6*'ES' Size Type Wt/Grade/Conn Drift ID Top Btm BP1 Cementer 0 a; 20" Conductor 78.6/A-53/Weld N/A Surface 106.5' N/A 1,900 9-5/8" Surface 40/1-80/DWC/C 8.75" Surface 5,078' 0.0732 4-1/2" Liner 13.5/L-80/HTTC 3.833 4,900' 10,933' 0.0152 TUBING DETAIL 4-1/2" I Tubing I 12.6/l-80/Supermax I 3.833 1 Surf 14,900' 10.0152 h*. z- WELL INCLINATION DETAIL KOP @ 254' ' Max Hole Angle=90.26 deg , JEWELRY DETAIL 4�t No Depth Item ID s• I 1 3,000 3-1/2"SLB KBMG GIM w/1"pocket and a SBEK-2C latch.3500 psi shear 2 4,750' KN Nipple profile(No Go 3.72")3.813 Polish Bore 4>/z ,' 3 4,899' No-Go LocateroniTiebackAssy. 4 4,910' Tieback Shoe .. 5 4,900' 7"Liner Top Packer 6 10,925' WIV(Bali on Seat/Closed) - I ICD DETAIL 1, ,'13 "1�tk No Depth ICD Detail 1 5,300 4-1/2"17#DWC/C BxP,WOT ICD W/(9)1/8"nozzles 95/8 Iop ki-- - « $u7'r (sk- ) 2 5,800' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles 3 6,500' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles 4 7,200' 4-1/2"17#DWC/C BxP,WOT ICO w/(10)1/8"nozzles 5 7,800' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles j t61� o 6 8,400' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles 7 9,000' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles 8 9,600' 4-1/2"17#DWC/C BxP,WOT ICD w/(10)1/8"nozzles 9 10,200' 4-1/2"17#DWC/C BxP,WOT lCD w/(10)1/8"nozzles See ED Neal } 10 10,900' 4-1/2"17#DWC/C BxP,WOT lCD W/(10)1/8°nozzles • i S w c.-I,L-- 41/2GENERAL WELL INFO 6 TO=10,933'(MD)/TD=4,399'01.0) PBTD=10,925'(MD)/PBTD=4,399'(TVD) Page 6 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 8.0 Drilling / Completion Summary MPU B-33 is a grassroots water injector planned to be drilled in the Schrader Bluff NC sand. B-33 is part of a(2)well pilot program targeting the NC sand. B-33 will be paired with a grassroots producer, B-32. The directional plan is a catenary wellpath build with 9-5/8" surface casing set into the top of the Schrader Bluff NC sand. A lateral section will then be drilled in the reservoir. An injection liner will then be run with ICDs placed along the wellbore to optimize the water injection strategy. Drilling operations are expected to commence approximately February 11th, 2017. The Hilcorp"Innovation"will be used to drill and complete the wellbore. Surface casing will be run to 5,078' MD/4,420' TVD and cemented to surface via a 2 stage primary cement job. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. All waste & mud generated during drilling operations will be hauled to the Milne Point G&I facility located on`B"pad. / General sequence of operations: 1. MOB Rig to well site 2. N/U 13-5/8" BOP in conductor mode. N/U 16" diverter line. 3. Drill 12-1/4" hole to TD of surface hole section. Run and cmt 9-5/8" surface casing. 4. Remove 13-5/8" diverter"T",N/U &test tubing spool and 13-5/8" x 5M BOP. 5. Drill 8-1/2" lateral to well TD. Run 4-1/2" liner. 6. Run injection string. 7. N/D BOP,N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: No mud logging. On Site geologist. LWD: GR+Res 2. Production Hole: No mud logging. On site geologist. LWD: GR+Res J Page 7 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at(2) week intervals during the drilling and completion of MPU B-33. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/5 min(annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: t • A variance from regulation 20 AAC 25.412.b is requested: The Production packer will be set>200' MD from the closest injection control device. The current plan is to set the production packer—400 ft MD from the first ICD. Page 8 Version 1 Oct,2016 • • Iti Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 12-1/4" • 13-5/8"5M diverter w/16"diverter line Function Test Only • 13-5/8"x 5M Control Technology Inc Annular BOP • 13-5/8"x 5M Control Technology Inc Double Gate Initial Test:250/3000 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross w/3"x 5M side outlets 8-1/2" • 13-5/8"x 5M Control Technology Single ram • 3-1/8"x 5M Choke Line Subsequent Tests: • 3-1/8"x 5M Kill line 250/3000 • 3-1/8"x 5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc Primary closing unit: Control Technology Inc, 6 station, 20 bottle, 3000 psi, 220 gal EHPLC Primary & secondary closing hydraulics are provided by electrically driven triplex pumps. Emergency pressure is provided by bottled nitrogen. The remote closing operator panels are located in the doghouse and on accumulator unit. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email: guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: Victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Version 1 Oct, 2016 ! S Milne Point Unit B-33 Drilling Procedure Hilcorp Enemy Company 10.0 R/U and Preparatory Work 10.1 A new insulated conductor has been set for B-33, the surface location is to the North of the existing well, B-02. 10.2 Dig out and set impermeable cellar. 10.3 Ensure PTD and drilling program are posted in the rig office and on the rig floor. 10.4 Install Seaboard slip-on 13-5/85M j "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 10.5 Insure (2) 3"threaded nipples are installed on opposite sides of the conductor with ball valves on each nipple. These will be used to take cement returns to the cellar during the surface cmt job, and also to wash out the diverter and hanger in preparation for running the pack-off. 10.6 Level pad and ensure enough room for layout of rig footprint and R/U. 10.7 Confirm that the rig is over the appropriate well slot. 10.8 MIRU Hilcorp "Innovation". 10.9 Mud loggers WILL NOT be used on either hole section. 10.10 Mix spud mud for 12-1/4" surface hole section. Keep mud cool. 10.11 Set test plug in wellhead prior to N/U diverter to ensure nothing can fall into the wellbore if it is accidentally dropped. 10.12 Keep 5" liners in mud pumps. • White Star 1300 HP Quatro mud pumps are rated at 4097 psi, 380 gpm @ 140 spm @ 90% mechanical efficiency & 100%volumetric efficiency. Page 10 Version 1 Oct, 2016 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 11.0 N/U 13-5/8" 5M Diverter System 11.1 N/U 13-5/8" Control Technology 5M diverter System (Diverter Schematic at Sec 20 at back of program). • N/U 13-5/8" 5M diverter "T". • Install 16"knife gate and 16" diverter line. • Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). • Diverter line must be 75 ft from nearest ignition source. • Place drip berm at the end of diverter line. 11.2 Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. • Ensure all other Rams and both HCRs are disabled/not connected. The BOP is being used as a diverter, and there should be NO possible way to shut in the well inadvertently. 11.3 Ensure to set up a clearly marked "warning zone" is established on each side and ahead of the vent line tip. "Warning Zone" must include: • A prohibition on vehicle parking. • A prohibition on ignition sources or running equipment. • A prohibition on staged equipment or materials. • Restriction of traffic to essential foot or vehicle traffic only. 11.4 Set wearbushing in wellhead. Page 11 Version 1 Oct, 2016 • • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 11.5 Ri• and diverter orientation: I ,r1 I I L.:111 I I 197O4 ... , 1-- 1 T 1 I I , 1 ,..., ...4 I I ...t,/;;;;::•.., , 1 C140r4r. • OW /:',•,-;';?;;;/,''//;;:'i I plIt-l_il• Producer r-11111 ,„,•••: ••., //,•••.•,•:;,•,•;, 8—3r... t.c li P r c i L 1 r" Fli.PrtT ;%:;:.;.%, ',',.•:: ::,,f'''..- I ;/,',,;;;;•,,,,,, ,,,,,,,,, c- III t I ....-1" In lectcr •,_ ;;;',";;':2. ,'";":::•: ,".."'.:%.1 A 1 • ',//....,,,/,1,:/...r.:":',:',•:7''''''''i • 1 s './..,z,.>";:,;;';',/,',/*,,,/,;"':,;(,•%; 1 ‘. ,J. 1 ' `1- 1 1 T' 1 1 . ......2/.......5....,...;',.....,,.., ........,, . 1 , _ , :.1,.] Pr...ItilJt Fq- .7.77.7. .,: i ..... . . III 1.i.1-1 I t II I • •./..,7..,;..1 t et I '....;/ "..../... .71 -ii.M r_i li ..,„;„/„....„....,7.1 ,, 4, ___,., , T •-•.,..,..,,,-;;;;,,,..,....4.1 i.::?1111 , ....",',.: .•",;.;"..',1 „ .,...• ' 7-1111 Al I',CI]f'-'1' ''''•%, ''''////4,,,, /.':+'•4:...•7". ,../•'''..,•1 I 3111 ''''''7'''''''44 4'''''X'',.• i ''',.;':•;:.,4.;;;:',....',,,,,,;:';'; i.<4..::::1 , Page 12 Version 1 Oct,2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 11.5 Ri• and diverter orientation: -- �- I 411 co 1 to iii 1419 0704' ■- I I I I I (7,104.. . . NJ CA 9 1f`i" DivPrfPr I inP N NN// y , /,/e,,,,. -[4 (77 z_/7/ 4 I iTogr.Z1 7 011. raifigt0 M0� N''f ///// Igginli 7 al c. 610.0163' ra Ln N / ca / Ar r. do-, ,,, V' v Page 12 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 12.0 Drill 12-1/4" Hole Section 12.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Be sure to run a UBHO sub so that wireline orientation is possible if necessary. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Run a solid float in the surface hole section. 12.2 12-1/4" BHA (GR+ Res LWD and PWD planned in surface hole): COMPONENT DATA Item De r rag ID Stiff ID Gauge Weight To;) Length Total Location (in) (in) (in) (in) (lbpf) Connection (ft) (ft) (f1) Tricone 8.000 3.000 12.250 147.22 P 6-5/8"REG 1.10 ©8"SperryDrill Lobe 415-5.3 stg 8.000 5.000 5.000 103.09 B 6-5/8"REG 31.47 32.57 Stabilizer 12.125 4.28 ©Float Sub 8.000 2.880 2.880 149.10 B 6-5/8"REG 2.40 34.97 0 Stabilizer 8.000 3.000 3.000 10.250 147.22 B 6-5/8"REG 6.00 40.97 35.97 8"DM Collar(Directional) 8.000 3.500 3.544 147.40 B 6-5/8"REG 9.20 50.17 6 8"DGR Collar(Gamma) 8.000 1.920 4.997 142.70 B 6-5/8"REG 4.55 54.72 0 8"EWR-P4 Collar(Resistivity) - 8.000 1.985 5.205 151.00 B 6-5/8"REG 12.19 66.91 8 8"PWD(Pressure ECDs) 8.000 1.920 4.760 143.40 B 6-5/8"REG 4.44 71.35 9 8"HCIM Collar(Processor) 8.000 1.920 4.309 149.90 B 6-5/8"REG 4.97 76.32 10 8"POS PULSER(Telemetry) 8.000 4.000 4.257 145.20 B 6-5/8"REG 15.44 91.76 m Orienting Sub UBHO 8.000 2.875 3.000 149.18 B 6-5/8"REG 2.50 94.26 ®NM Flex Collar 8.000 2.813 150.13 B 6-5/8"REG 31.00 125.26 ®NM Flex Collar 8.000 2.813 150.13 B 6-5/8"REG 31.00 156.26 MI NM Flex Collar 8.000 2.813 150.12 B 6-5/8"REG 31.00 187.26 8jts x 5"X 3"HWDP#49.3-NC50(IF) 5.000 3.000 49.30 240.00 427.26 16 Jar 7.500 2.813 2.813 129.38 B 4-1/2"IF 35.00 462.26 12jts x 5"X 3"HWDP#49.3-NC50(IF) 5.000 3.000 49.30 360.00 822.26 822.26 Page 13 Version 1 Oct, 2016 • Milne Point Unit B-33 fit Drilling Procedure Hilcorp Energy Company 12.3 Primary Bit: \j„...'"\A i 12-1 /4 VMD-3 STEEL TOOTH BITS (311.2 mm) • Ultra-Abrasive Formation Cutting Structure Specifically engineered for ultra-abrasive formations This steel tooth cutting structure has extra-thick hardfacing to ensure teeth stay sharper forger and delver extended runs with 4.A} improved penetration rates. ../ . $ -.l w • Metal Face Seal&Bearing System t Longer bit life in high-RPM rrotor,and high-temperature drilling applications,up to 400'F ', (204°C).with the patented VM metal-to-metal sealing system. r idlh II • XL&LX Hardfacing Features A patented.strategically placed bead of hardfacing is added to key areas on specific teeth to retard tooth wear and improve tooth strength and durability. 1111, • Boss Stabilization System ilia These unique integrated stabilizers provide near six-point contact with the borehole wall for / unequaled stability and cutting structure protection. • STL Hardfacing Increased bit life and reliability with a precisely controlled appricatron of patented.highly wear- resistant STL-"'hardfacing that covers the entire shirttail and leg areas for superior protection from the potentially damaging effects of hole-wall contact • Center Jet(C) A fourth get is positioned in the center of the bit and utilized to prevent bit balling and the associated reduction in penetration rate. • Clean Sweep Hydraulics(CS2) Biased nozzle configuration directs fluid toward areas where bit balling occurs.The Clean Sweep high-velocity core strikes heel and adjacent heel area on the backside of the cone. PRODUCT SPECIFICATIONS: !ADC: 137 Bearing/Seal Package: Journal!Metal Cutting Structure: Inner Row: ST Heel Row: ST Gauge Row: ST Gauge Trimmers: NWA Tooth Hardfacing: XL/LX OD Hardfacing: STL Nozzle Type: Standard Center Jet Display: FK or VK Makeup Torque: 28.0-32.0 klbf-ft(38.0-43.4 kNrn) Connection: 6-5/8 REG API Approx. Shipping Weight: 235 lb(106.6 kg) Reference Part Number: H2187000 OPERATING RECOMMENDATIONS: * Weight On Bit: 20-50.0 klb(9-22 to or kdaN) Rotation Speed: For High Speed RotaryiMotor Applications Page 14 Version 1 Oct, 2016 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 12.4 5" Workstring, HWDP, and Jars will come from Weatherford. 12.5 Begin drilling out from 20" conductor at reduced flow rates to avoid broaching the conductor. 12.6 _ Drill 12-1/4"hole section to D per the geologist and drilling engineer. • Monitor the area around the conductor for any signs of broaching. If broaching is observed, Stop drilling (or circulating)immediately notify Drilling Engineer. • Hold a safety meeting with rig crews to discuss: • Conductor broaching ops and mitigation procedures. • Well control procedures and rig evacuation. • Flow rates, hole cleaning, mud cooling, etc. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Keep mud as cool as possible to keep from washing out permafrost. • Pump at 550 - 650 gpm. Ensure shaker screens are set up to handle this flowrate. • Keep swab and surge pressures low when tripping. • For producer wells only: • Ensure to leave a"Pump Tangent" section that is approx. 300' long in the directional plan. The ESP will need a straight section to sit. This will occur very near TD of the hole section. • Efforts should be made to minimize dog legs in the surface hole. ESP equipment can be damaged if run through high dog legs. Keep DLS < 6 deg/ 100. • Make wiper trips every 2000' unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section just into the target sand. Geologists and Drilling Engineers will help adjust well path to ensure well is landed correctly. • Take MWD surveys every stand drilled(95' intervals). • Be prepared for GAS HYDRATES below the base of the permafrost (2,185' TVD) and as deep as 3500' TVD. Previous wells have experienced hydrates on"B"pad. 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 mud products such as Lecithin to allow the gas to break out. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • Do not stop to circulate on wiper trips with bit across a slide interval, especially not in an area where DLS is>4. • Do not slide for 100' MD above the base of the permafrost(1700' TVD) or 100' below the base. We want to leave this transition as undisturbed as possible. • Plan a bit trip (if necessary) before penetrating the UGNU LA3 sand. This interval caused an unintentional sidetrack on L-48. Page 15 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 12.7 12-1/4" hole mud program summary: • Density: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system(1) ppg above highest anticipated MW. We will start with a simple gel+FW spud mud at 8.8 ppg. • PVT System: An electronic PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, and Toolpusher office. • Rheology: Aquagel and Barazan D+ should be used to maintain rheology. Begin system with a 75 YP but reduce this once clays are encountered. Maintain a minimum 25 YP at all times while drilling. Be prepared to increase the YP if hole cleaning becomes an issue. • Fluid Loss: DEXTRID and/or PAC L should be used for filtrate control. Background LCM (10 ppb total) BARACARBs/BAROFIBRE/STEELSEALs can be used in the system while drilling the surface interval to prevent losses and strengthen the wellbore. • Wellbore and mud stability: Additions of CON DET PRE-MIX/DRIL N SLIDE are recommended to reduce the incidence of bit balling and shaker blinding when penetrating the high-clay content sections of the Sagavanirktok and the heavy oil sections of the UGNU 4A. Maintain the pH in the 8.5 —9.0 range with caustic soda. Daily additions of ALDACIDE G/X-CIDE 207 MUST be made to control bacterial action. • Casing Running: Reduce system YP with DESCO as required for running casing as allowed (do not jeopardize hole conditions). Run casing carefully to minimize surge and swab pressures. Reduce the system rheology once the casing is landed to a YP <20 (check with the cementers to see what YP value they have targeted). System Type: 8.8-9.2 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths ..... ty Viscosity Plastic Viscosity Yield Point API FL pH Surface 8.8—9 85-250 20-40 25-75 <10 8.5—9.0 stem 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) Page 16 Version 1 Oct,2016 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 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 12.8 At TD; pump sweeps, CBU, and orient motor to high side. Pump out of the hole at full drilling rate, keeping motor high sided. Do not initiate back reaming unless absolutely necessary. 12.9 Should backreaming be necessary to get out of the hole: • Prior to initiating backreaming, ensure a few B/U have been circulated to get hole as clean as possible. • Pump at slightly reduced flow rate (approx 400 gpm), and reduced rpm (approx 40 rpm). • Pull slowly, 5 — 10 ft/minute. • Monitor well for any signs of packing off or losses. • Have the flowline jets hooked up and be ready to jet the flowline at the first sign of clay balling. • If flow rates are reduced to combat overloaded shakers/flowline, stop back reaming until parameters are restored. 12.10 TOH with the drilling assy, handle BHA as appropriate. 12.11 No open hole logging program planned. `J Page 17 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 13.0 Run 9-5/8" Surface Casing 13.1 R/U and pull wearbushing. 13.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" DWC/C x DS50 XO on rig floor and M/U to FOSV. • Use BOL 2000 thread compound. Dope pin end only w/paint brush. • Consider R/U of CRT if hole conditions require. • R/U a fill up tool to fill casing while running if the CRT is not used. • Ensure all casing has been drifted to 8.75" 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. 13.3 P/U shoe joint, visually verify no debris inside joint. 13.4 Continue M/U &thread locking shoe track assy consisting of: • (1) Shoe joint w/float shoe bucked on(thread locked). Install (2) centralizers on shoe joint over stop collars 10' from each end. • (1) Joint with float collar bucked on pin end &thread locked. Install (1) centralizer mid tube over a stop collar. • Ensure bypass baffle is correctly installed on top of float collar. Bypass Baffle This end up. 011,o•k kalt • (1)Joint with Halliburton bypass baffle adapter bucked on pin&threadlocked. Install (1) centralizer mid tube over a stop collar. • Ensure proper operation of float equipment while picking up. • Ensure to record S/N's of all float equipment and stage tool components. y` Page 18 Version 1 Oct, 2016 0 • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 13.5 Float equipment and Stage tool equipment drawings: mmy—^� Overall Length Type H ES Cementer B Part No. Mir.I D After Drillout 'hl--1 Ull SO No. C Max.Tool OD 1=111 D /More ES-II Running Order • I= Opening Sear ID AailClosing Sleeve No.Shear Pins MIN E Closing Seat ID -`D Opening Sleeve ( E C I I No.Shear Pins Plug Set 1 ': 1 ES-Il Cementer ES Cementer Part No. B Depth 1 SO No. hWIN Closing Plug MIMI WNW Nomii = Baffle Adapter{if used) OD MShut Off Plug ■ IDOpening Plug III i Depth OD Baffle Adapter OD a , -- II BypassID or Shut-off Baffle it 111 ` By-Pass Plug Depth IllrShut-off Plug r Illic 111 1Float Collar lirt_,j Depth " By Pass Baffle 1 T NM 1 OD Float Collar Ill r Float Shoe 1��c + Depth Bypass Plug (if used) Hole ID float Shoe "Reference Casing 0D Sales Manual Section 5 Page 19 Version 1 Oct,2016 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 13.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Break circulation prior to reaching the base of the permafrost if casing run indicates poor hole conditions. • Any packing off while running casing should be treated as a major problem. It is preferable to POH with casing and condition hole than to risk not getting cmt returns to surface. 13.7 Install the Halliburton Type H ES-II Stage tool so that it is positioned at 1900' MD/ 1882' TVD. This will position the stage collar comfortably below the permafrost. • Install centralizers over couplings on 3 joints below and above stage tool. • Do not place tongs on ES cementer,this can cause damage to the tool. • Ensure tool is pinned with 6 opening shear pins. There are 6 holes,the tool is normally sent with only 4 pins installed. This will allow the tool to open at 3300 psi. 9-5/8" 40#L-80 DWC/C Make Up Torques: Casing OD Min M/U Torque Max M/U Torque 9-5/8" 29,800 ft-lbs 34,800 ft-lbs 13.8 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slips. 13.10 P/U landing joint and M/U to string. Position the shoe as close to TD as possible. 13.11 Lower string and space out to ensure a coupling is not across the wellhead. 13.12 We will use slip type casing hanger to maximize annular clearance across wellhead and ensure an effective cement job. 13.13 R/U circulating equipment and circulate B/U. Reduce YP to<20 to help ensure success of cement job. Ensure adequate amounts of cold M/U water are available to achieve this. Page 20 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 13.6 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Install (1) centralizer every other joint for the first 15 joints. • Utilize a collar clamp until weight is sufficient to keep slips s- -properly. • Break circulation prior to reaching the base of the permafro: if casing run indicates poor hole conditions. • Any packing off while running casing should be treate' as a major problem. It is preferable to POH with casing and condition hole than to risk at getting cmt returns to surface. 13.7 Install the Halliburton Type H ES-II Stage tool so t .t it is positioned at 1900' MD/ 1882' TVD. This will position the stage collar comfortably bel, the permafrost. • Install centralizers over couplings on 3 join . below and above stage tool. • Do not place tongs on ES cementer, this c.n cause damage to the tool. • Ensure tool is pinned with 6 opening sh;.r pins. There are 6 holes, the tool is normally sent with only 4 pins installed. This will a ow the tool to open at 3300 psi. 9-5/8" 40#L-80 DWC Make Up Torques: Casing OD Mi Torque Max M/U Torque 9-5/8" 9,800 ft-lbs 34,800 ft-lbs 13.8 Watch displacement careful and avoid surging the hole. Slow down running speed if necessary. 13.9 Slow in and out of slip . 13.10 P/U casing hanger j mt and M/U to string. Casing hanger joint will come out to the rig with the landing joint alrea'y M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at(1) ft intervals to use as a reference when landing the hanger. 13.11 Lower strin and land out in wellhead. Confirm measurements indicate the hanger has correctly landed ou in the wellhead profile. 13.12 Have - ergency slips ready to go in the event we cannot land the hanger. Page 20 Version 1 Oct, 2016 s • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 13.13 R/U circulating equipment and circulate B/U. R-. ce YP to <20 to help ensure success of cement job. Ensure adequate amounts of co ' /U water are available to achieve this. Elevate hanger slightly above hang off point whit; circulating to avoid plugging the flutes. 13.14 After circulating, lower string and d hanger in wellhead again. Page 21 Version 1 Oct, 2016 S Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company Technical Specifications Connection Type: Size(O.D.): Weight (Wall): Grade: D'WC1C Casing 9-518 in 40.00 lb/ft(0.395 in) L-80 scancard Material A L-80 Grade 80.000 Minimum Yield Strength (psi) 11111111=1111110 S A 95.000 Minimum Ultimate Strength (psi) YAM USA 4424 W. Sam Houston Pkwy.Sue'? 150 Pipe Dimensions Houston,TX 77C41 Phone: 9-3200 9.625 Nominal Pipe Body O.D. (in) Fax.713-479-3234 8.835 Nominal Pipe Body I.D.(in) E-grail:VAMUSAsaiesi vam-usa_com 0.395 Nominal Wall Thickness (in) 40.00 Nominal Weight (lbs/ft) 38.97 Plain End Weight(lbs./ft) 11.454 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 916.000 Minimum Pipe Body Yield Strength (lbs) 3.090 Minimum Collapse Pressure (psi) 5.750 Minimum Internal Yield Pressure (psi) 5.300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.835 Connection I.D. (in) .- 8.750 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 11.454 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 916.000 Joint Strength (lbs) 16.360 Reference String Length (ft) 1.4 Design Factor 947.000 API Joint Strength (lbs) 916.000 Structural Compression Rating (lbs) 3.090 API Collapse Pressure Rating (psi) API Internal Pressure Resistance (psi) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft) Appoximated Field End Torque Values 29.800 Minimum Final Torque (ft-lbs) 34.800 Maximum Final Torque (ft-lbs) 39.800 Connection Yield Torque (ft-lbs) Page 22 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 14.0 Cement 9-5/8" Surface Casing 14.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud& water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. Ensure vac trucks are on standby and ready to assist. • Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. • Ensure adequate amounts of water for mix fluid is heated and available in the water tanks. • Positions and expectations of personnel involved with the cmt operation. • Review test reports and ensure pump times are acceptable. • Conduct visual inspection of all iron used to route slurry to rig floor. 14.2 Document efficiency of all possible displacement pumps prior to cement job. 14.3 Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cmt pump or treating iron will not be pumped downhole. 14.4 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 14.5 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.6 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.7 Drop bottom plug (flexible bypass plug). Mix and pump cmt per below calculations for the 1st stage. 14.8 Cement volume based on annular volume + 30% open hole excess. Job will consist of lead& tail, TOC brought to stage tool. Estimated Total Cement Volume: Section: Calculation: Vol(BBLS) Vol (ft3) 12-1/4" OH x 9-5/8" Casing (4578'- 1900') x .0558 bpf x 1.3 = 194 bbls 1090 ft3 5�. annulus: Total LEAD: 194 bbls 1090 ft3 .Z -5-13 12-1/4" OH x 9-5/8" Casing (5078'- 4578') x .0558 bpf x 1.3 = 36 202 annulus: 9-5/8" Shoe track: 90 x .0758 bpf = 6.8 38 Total TAIL: 43 bbls 240 ft3 rr ,�3G rer t.. Page 23 Version 1 Oct, 2016 • • Milne Point Unit B-33 14 Drilling Procedure Hilcorp Energy Company Cement Slurry Design (both 1st and 2nd stage cement jobs): Lead Slurry Tail Slurry System ArcticCEM TM System SwiftCEM TM System Density 10.7 lb/gal 15.8 lb/gal Yield 4.298 ft3/sk 1.16 ft3/sk Mixed 21.13 gal/sk 5.04 gal/sk Water 14.9 Attempt to reciprocate casing during cement pumping if hole conditions allow. If the hole gets "sticky", position the casing on depth and stop reciprocating. 14.10 After pumping cement, drop top plug (Shutoff plug) and displace cement with spud mud out of mud pits using rig pump. 14.11 To operate the stage tool hydraulically,the plug must be bumped. 14.12 Displacement calculation: (G l O(, 5000' x .0758 bpf= 379 bbls total (200 bbl mud+ 80 bbl water+ 99 bbl mud) —The 80 bbls of water must be left across stage tool to ensure proper operation once opened. 14.13 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Route cement returns to the cuttings tank, and have vac trucks/super suckers ready. Have some sx of sugar available to retard setting of cement. 14.14 If plug is not bumped at calculated strokes, double check volumes and calculations. Overdisplace by no more than 10 bbls before consulting with drilling engineer. 14.15 If plug is not bumped consult with drilling engineer. Ensure the free fall stage tool opening plug is available if needed. This is the back-up option to open the stage tool if the plugs are not bumped. 14.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. 14.17 Increase pressure to 3300 psi to open circulating ports in stage collar. Slightly higher pressure may be necessary if TOC is above the stage tool. CBU and record any spacer or cement returns to surface. Circulate until YP <20 again in preparation for the 2nd stage of the cement job. Page 24 Version 1 Oct, 2016 ! • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company Second Stage: 14.18 Prepare for the 2nd stage as necessary. Hold another pre job meeting if crew change has occurred. 14.19 Load ES cementer closing plug in cmt head. 14.20 Pump 5 bbls 10.5 ppg tuned spacer. Test surface cmt lines. 14.21 Pump remaining 55 bbls 10.5 ppg tuned spacer. 14.22 Mix and pump cmt per below recipe for the 2nd stage. 14.23 Cement volume based on annular volume+200% open hole excess. Job will consist of lead& tail, TOC brought to surface. However cmt will continue to be pumped until clean spacer is ,/ observed at surface. Estimated Total Cement Volume: .� 5—rAL Section: Calculation: Vol(BBLS) Vol (ft3) 20" Conductor x 9-5/8" (106.5') x .27 bpf x 1 = 29 bbls 163 ft3 casing annulus: 12-1/4" OH x 9-5/8" Casing (1400'- 110') x .0558 bpf x 3 = 216 bbls 1213 ft3 annulus: Total LEAD: 245 bbls 1376 ft3 12-1/4" OH x 9-5/8" Casing (1900'- 1400')x .0558 bpf x 2 = 56 314 annulus: Total TAIL: 56 bbls 314 ft3 14.24 Continue pumping lead until uncontaminated spacer is seen at surface, then switch to tail. 14.25 After pumping cement, drop ES Cementer closing plug and displace cement with spud mud out of mud pits. 14.26 Displacement calculation: 1900' x .0758 bpf= 144 bbls mud Page 25 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 14.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. Open wellhead side outlets to cellar if necessary to take returns. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 14.28 Decide ahead of time what will be done with cmt returns once they are at surface. We should get back approx. 150 bbls of cmt slurry. 14.29 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. Back out and L/D landing joint. Flush out wellhead with FW. 14.30 Lift BOP/Diverter and set slips. 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 lkeller@hilcorp.com and cdinger@hilcorp.corn This will be included with the EOW documentation that goes to the AOGCC. Page 25 Version 1 Oct,2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 14.27 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If ►.nger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be •repared to pump out fluid from cellar. Have some sx of sugar available to retard setting of ement. 14.28 Decide ahead of time what will be done with cmt returns once they are at s face. We should get back approx. 150 bbls of cmt slurry. 14.29 Land closing plug on stage collar and pressure up to 1000— 1500 ps''to ensure stage tool closes. Follow instructions of Halliburton personnel. Bleed off pressure ., d check to ensure stage tool has closed. Back out and L/D landing joint. Flush out wellhea•with FW. 14.30 M pack-of nni g tool and pack-off to bottom of Land' g joint. Set casing hanger packoff. Ru i in loc, downs .nd injec •las c packi : e e,s ent. 14.31 Lay ••wn landing j•' and pack-off running tool. Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(pp: • Cement slurry type, lead or tail, volume weight • Pump rate while mixing, bpm, note any . utdown during mixing operations with a duration a. Pump rate while displacing,note whet'er displacement by pump truck or mud pumps,weight&type of displacing fluid b. Note if casing is reciprocated or rot ted during the job c. Calculated volume of displaceme , 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 •turns at surface&volume f. Note time cement in place g. Note calculated top of ce ent h. Add any comments wh. h would describe the success or problems during the cement job Send final "As-Run" casing is ly & casing and cement report to lkeller(&,hilcorp.com and cdinger(a,hilcorp.com This w ll be included with the EOW documentation that Qoes to the AOGCC. Page 26 Version 1 Oct,2016 • • 11 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 15.0 BOP N/U and Test 15.1 N/D the diverter"T" &N/U 11" 5M tubing spool. 15.2 N/U 13-5/8"x 5M BOP as follows: • BOP configuration from Top down: 13-5/8"x 5M annular/ 13-5/8" x 5M Double gate / 13- 5/8" x 5M mud cross/ 13-5/8" Single gate • Double ram should be dressed with 2-7/8" x 5" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 5" Fixed rams • N/U bell nipple, install flowline. • Install (1) manual valve & (1) HCR valve on kill side of mud cross. (manual valve closest to mud cross). • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. ean 15.3 Run 5" BOP test assy, land out test plug (if not installed previously). IT y •A • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. � • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. • We will need to test on the following sizes: 5" (for 5" DP workstring) 4-1/2" (for 4-1/2"production liner&tubing) 15.4 R/D BOP test assy. 15.5 Dump and clean mud pits, send spud mud to G&I pad for injection. 15.6 Mix 8.9 ppg Baradrill-N fluid for production hole. 15.7 Set 10" ID wearbushing in wellhead. 15.8 Rack back as much 5" DP in derrick as possible to be used while drilling the hole section. 15.9 Keep 6" liners in mud pumps. 15.10 P/U used 8-1/2"mill tooth bit and clean out BHA and TIH to TOC. Shallow test MWD and LWD on trip in. 15.11 Note depth TOC tagged on AM report. Drill out stage tool as follows: • Do not exceed 75 rev/min rotation speed. A good range is 40 to 75 rpm. • Drilling with minimal WOB is recommended. Approx 2-5 k is enough. • Apply weight and allow it to drill off before applying more. Page 27 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company • After drilling out, chase any remaining debris to bottom with the drill bit. 15.12 TIH to TOC above the baffle adapter. Note depth TOC tagged on morning report. 15.13 R/U and test casing to 3000 psi/ 30 min. Ensure to record volume/pressure and plot on FIT graph. AOGCC reg is 50% of burst= 5750/2 =—2875 psi, but maximum test pressure on the well is 3000 psi. N 4) 15.14 Drill out shoe track and 20' of new formation. 15.15 CBU and condition mud for FIT. 15.16 Conduct FIT to 12 ppg EMW. 15.17 TOH with clean out assy for lateral drilling assy. Page 28 Version 1 Oct, 2016 • • Milne Point Unit B-33 II Drilling Procedure Hilcorp Energy Company 16.0 Drill 8-1/2" Hole Section 16.1 P/U 8-1/2" directional BHA. • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure MWD is R/U and operational. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 5" 19.5# S-135. • Install ported float in the BHA. 16.2 8-1/2" Rotary Steerable (Includes at bit GR, at bit incl, ADR for geosteering, PWD): COMPONENT DATA IIIII III Item OD ID Gauge Weight Top Length Cumulative Description dal Number # (in) (in) (in) (Ibpf) Connection (ft) Length (ft) 1 PDC-Long Gauge 6.360 2.250 8.500 94.72 P 4-112"REG 2.19 2.19 Stabilizer 8.469 -�- 2 Geo-Pilot 7600 XL 25KSI 7.625 1.490 8.375 113.00 B 4-112"IF 20.16 22.35 Ref Housing Stabilizer 8.375 _-IIIIIIIIII� 3 6-3/4'DriIIDOC(WOB,TOB) 7.100 2.000 108.41 B 4-112"IF 7 10 29.45 4 6-3/4`DGR(Gamma) i 6.750 1.920 97.80 B4-112"IF 8 43 37.88 5 6-3/4'PWD{Pressure) 6.750 1.920 96.30 B 4-1/2"IF 4 40 42.28 6 Inline Stabilizer(ILS) 6.750 1.920 8.250 112.09 B 4-112"IF 2.25 44.53 7 6-314"ADR Collar(Resistiv6i 6.750 1.920 109.40 11111M 24.30 68.83 8 6-3/4'DM Collar(Directional) 6.750 3.125 103.40 B 4-1/2"IF 9.20 78.03 9 6-3/4"TM Collar(Mud Pulse 6.750 3.250 M® B 4-112"IF 10.00 88.03 Telemet 10 6-314"Float Sub -, 6.750 2.250 108.40 B 4-112"IF 2.00 90.03 11 NMDC Slick 6.750 2.813 100.77 B 4-1/2"IF 3'.00 121.03 12 NMDC Slick 6.750 2.813 100.77 IMERE 31.00 152.03 13 NMDC S=ick 6.750 2.813 100.77 B 4-112" IIF 3' 00 183.03 izi lit x5"X3"HWDP#49.3-4.51F 5.000 3.000 49.30 31.00 214.03 15 Weatherford 6.25"Jar 6.250 2.250 91.01 B 4-1:2" IF 30.00 244.03 Es lit x 5"X 3"I-IWDP#49.3-4.51F 5.000 3.000 49.30 31.00 275.03 17 5'X 4.276'-19.5#6-5/8'X2-3,4"- 5.000 4.276 22.60 31.00 306.03 4.51F Total: 306.0 3 Page 29 Version 1 Oct, 2016 • • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 16.3 Primary Bit: NOYWellbore Technologies Design Specifications ir 40 Make up Length(ft): .92 Shank Bore(ins): 2.300 , Shank Diam(ins): 6.400 J t Ari Connection std: Y "', • r Vire Connection Size(ins): 4.500 • ` . t n - . Connection Type: Api Reg Pin i Make up Torque(ft-lbs). 20000 .I► IADC Code: M422 K" Diameter(ins) 8 "rr,' Body Material: Matrix HDK JSA(ir8 /" SK616M-J 1 D Facer'): 18.440 Face Volume:(in') 71.66 Normalised Face vol: 53.26% Design Features of this bit Seeker"'Directional Drill Bits Seeker'"'directional drill bits are designed to overcome directional drilling challenges for both motor or RSS tools;n a wide range of directional applications. Blade Oty: 6 Gauge Helios"''InfernoT"Cutters-Specialized cutter technology engineered for specific applications that Length(ins) 4.000 may require increased thermal resistance.,increased abrasion resistance or increased toughness. Gauge Geometry: Spiral-Trailing Each Helios""'Inferno"'cutter has a unique cutter index value indicating performance characteristics. Gauge Profile: SmoothSteer SmoothTorqueTse Torque Control Components-SrrxxYIhTorque""torque control components are Gauge Protection: TSP Tiled inserts placed between primary cutters to provide a predictable torque response to applied weight-on-bit and reduction in torque variance. Bit Profile: &ncrt Taper-Sls taeow cane SmoothSteer"Gauges-SmoothSteerTM gauges deliver maximum gauge contact.lowering resistance to steer by reducing torque.and leading to improved ROP and extended bit and tool life. Recommended Operating TSP Gauge Protection-Thermally stable product(TSP)tiles and welded hardmetal gauge Parameters protection give both a highly durable and ultra-smooth gauge. Max Operating WOB(klbs):38 Spiral Gauge-Stability is improved by increasing the circumferential contact of the bit gauge. Min TFA(in2): 0.2946 Improved stability enhances steerability and ROP. Max TFA(in2): 2.2272 Max Flow(gprn): 934 This bit/unit can accommodate BlackBoxt"HD drIling recorder. HSI: 2-7 This bodied PDC bit features computer aided cutter placement and hydraulics optimized by nozzle location to deliver high performance and longer bit life. Bit Breaker. Thick 1'r4' m same appYcaraans eas Pe is ran succesrA ny beyond Mese parameters Co nmol your NOV Reedeyrabp NeereserdaMm for recortvrended operates:parameters of yew AbOetcabn.NOV ReedNrca1b reserves tae'MN to revise Mese seer.Vkartons,based on advances and Mwrovnments In tedvnabOy. This report is va d for 30 days from 02-Sep-2015 Cutting Structure Nozzles&Ports Type Qty Location Diameter Shape O 11,11 ale Primary 31 FACE 16 err; CYLINDER 6 TNZ VARIABLE Primary 12 GAGE 13 mm CYLINDER Primary 6 BACK-ANGLE 13 mm CYLINDER TCC 6 FACE 11 mm DOME TOPPED Page 30 Version 1 Oct, 2016 s Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 16.4 8-1/2"hole section mud program summary: • Density: Weighting material to be used for the hole section will be calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. • Solids Concentration: It is imperative that the solids concentration be kept low while drilling the production hole section. Keep the shaker screen size optimized and fluid running to near the end of the shakers. It is okay if the shakers run slightly wet to ensure we are running the finest screens possible. • Rheology: Keep viscosifier additions to an absolute minimum (N-VIS). Data suggests excessive viscosifier concentrations can decrease return permeability. Do not pump high vis sweeps, instead use water or low vis sweeps. • Run the centrifuge continuously while drilling the production hole, this will help with solids removal. • Dump and dilute as necessary to keep drilled solids to an absolute minimum. • MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, & Toolpusher office. System Type: 8.9—9.2 ppg Baradrill-N drilling fluid Properties: JSection ensity Plastic Viscosity Yield Point Total Solids MBT HPHT pH Production 8.9-9.2 15-25 15-25 <10% <7 <11.0 8.5-9.5 System Formulation: Baradrill-N Product Concentration Water 0.955 bbl KCL 11 ppb KOH 0.1 ppb N-VIS 1.0— 1.5 ppb N-DRIL HT PLUS 5 ppb BARACARB 5 4 ppb BARACARB 25 4 ppb BARACARB 50 2 ppg BARACOR 700 1.0 ppb BARASCAV D 0.5 ppb X-CIDE 207 0.015 ppb Page 31 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 16.5 On-bottom staging technique: • Tag bottom and begin drilling with 100 - 120 rpms at bit. Allow WOB to stabilize at 5-8k. • Slowly begin bringing up rpms, monitoring stick slip and BHA vibrations pulsed up real time. • If BHA begins to show excessive vibrations/whirl/ stick slip, it may be necessary to P/U off bottom and restart on bottom staging technique. 16.6 Drill 8-1/2" hole section to section TD per Geologist and Drilling Engineer. • Pump at 550 - 650 gpm. • Ensure shaker screens are set up to handle this flowrate. Ensure shakers are running slightly wet to maximize solids removal efficiency. Check for holes in screens on every connection. • Pump water or other low vis sweeps to aid in hole cleaning. • Keep swab and surge pressures low when tripping. • Make wiper trips every 1500—2000 ft if necessary. • Take MWD surveys every stand drld. Surveys can be taken more frequently if deemed necessary. • Good drilling and tripping practices are vital for avoidance of differential sticking. Make every effort to keep the drill string moving whenever possible and avoid stopping with the BHA across the sand for any extended period of time. • Use ADR to stay in section. Ideally, we would like to stay in section 100% of the time and DO NOT want to serpentine between the upper and lower lobes. • Limit maximum instantaneous ROP to <200 fph. The sands will drill faster than this, but when concretions are hit when drilling this fast, cutter damage can occur. 16.7 Concretion drilling strategy: • Past experience has shown that no two hard streaks are the same. WOB and RPM may have to be constantly changed to drill effectively. • When a hard streak is encountered, first attempt to drill through it with low WOB (5k WOB, 150 RPMs at the bit). Gradually increase one or the other or both. Allow enough time to elapse after a parameter adjustment to make note of increased or decreased drilling efficiency. • DO NOT backream through concretions. This practice has been attributed to cutter damage in the past. • Normal backreaming can be done through soft/high ROP drilling areas. • Make all attempts at prolonging bit life when working through concretion intervals. Once the shoulder row of cutters has been chipped or damaged, the steerability and ROP will be significantly reduced. 16.8 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. Page 32 Version 1 Oct, 2016 i ! Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company • Orient TF to low side and dig a trough with high flowrates for the first 10 ft, working string back and forth. Trough for approx. 30 min. • Time drill at 4 to 6 feet per hour with high flow rates. Gradually increase ROP as the openhole sidetrack is achieved. 16.9 At TD; pump low vis sweeps, CBU at least 3 times at maximum circulation and rotation, and pull a wiper trip back to the 9-5/8" shoe. If backreaming is necessary: • Circulate at full drill rate (550—650 gpm). • Rotate at maximum rpm that can be sustained. • Limit pulling speed to 5 — 10 min/std (slip to slip time, not including connections). • If backreaming operations are commenced, continue backreaming to the shoe and circ at least a b/u once at the shoe. 16.10 TOH with the drilling assy, handle BHA as appropriate. Rabbit DP on TOH. 16.11 No open hole logs are planned for the production hole section. 17.0 Run 4-1/2" Injection Liner 17.1 Ensure VAM rep on location to assist with running the HTTC connection. 17.2 Well control preparedness: In the event of an influx of formation fluids while running the 4- 1/2" injection liner, the following well control response procedure SHALL be followed: • 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"ICD. • 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. 17.3 In the event of an influx of formation fluids while running the 2-7/8" inner string inside the 4- 1/2" injection liner: • P/U & M/U the 5" safety joint(with 4-1/2"x 2-7/8" triple connect crossover installed on bottom, TIW valve in open position on top, 2-7/8" handling joint above TIW). M/U 2-7/8" 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 of wash pipe. • 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. 17.4 R/U 4-1/2" casing running equipment. Page 33 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company • Ensure 4-1/2"HTTC x NC-50 crossover is on rig floor and M/U to FOSV. • Ensure appropriate safety joint is ready on the pipe rack(detailed above). • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 17.5 Run 4-1/2"production liner per completion tally. icp "/ Swr--- fes-5 • Use "Best 0 Life 4010NM"thread compound. Dope pin end only w/paint brush. • Utilize a collar clamp until weight is sufficient to keep slips set properly. • Install swell packers & ICDs as per Operations Engineer guidance. • Ensure all plastic packing is removed from swell pkr elements. • Do not place tongs or slips on pkr elements or ICDs. 4-1/2" HTTC M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 6,910 ft-lbs 9,350 ft-lbs 12,350 ft-lbs Page 34 Version 1 Oct, 2016 III II II Milne Point Unit B-33 Drilling Procedure Hilcorp >� y [I.V.Ica ori.a3 hot.2013 tJy lean-Goatfaurne ee5:d 14811.C4f77J71' DATA ARE ONSI-PO 101155 Connection Data Sheet BASED ON SI-PD 101156 OD Weight Wall Th. 1 Grade 1 API Drift Connection 41/2 In. I 13.50 lb/ft 0.210 in. LEO 3.795 in. VAN®HTTC PIPE PROPERTIES CONNECTION PROPERTIES Nominal OD 4.500 in. I 1Corinection Type Premium T&C Nominal ID 3.920 in. Connection OD(nom) 4.930 in. Nominal Cross Section Area 3.836 spin. Connection ID(nom) 3.849 in. Grade Type API 5CT Make-Up Loss 4.380 in. Mn.Yield Strength 80 ksi Coupling Length 9.917 in. IMax.Yield Strength 95 ksi Critical Cross Section 3.836 spin. inn.Ultimate Tensile Strength 95 ksi Tension Efficiency 100%of pipe :Tensile Yield Strength 307 klb Compression Efficiency 100%of pipe 'Compressive Yield Strength 307 klb Compression Efficiency with Sealability 80%of pipe Internal Yield Pressure 9,020 psi Internal Pressure Efficiency 100%of pipe 8,540 psi External Pressure Efficiency 100%of Pipe CONNECTION PERFORMANCES TORQUE VALUES 307 klb Mn.Make-up torque 6,910 R.Ib Compression Resistance 307 klb Opti.Make-up torque 8,130 ft.lb Compression with Sealability 246 klb Max.Make-up torque 9,350 Rib Internal Yield Pressure 9,020 psi Max.Torque with Sealability 12,350 ft.ib External Pressure Resistance 8,540 psi Max.Torsional Value 14,400 ft.ib Max.Bending 77°/100ft Max.Bending with Sealability 33 o/100ft Max.Load on Coupling Face 158 klb Do you need help on this product?-Remi.eber no one knows VAMr like VAN canadopyomlleidsenece.com ukt&vermilei erstotmm dtlwpiromfterdservicacom usapvem8.ldsenace.com dubatewamfdderrite.com bakupreinfiethhervice.cam mexlcotrveemhefdservue.cam nngerktevemleldsernte.com singspereprandhadmervice.cafn braztlevarrIteddsetvisre.com ongolepyemieldseawrce.wm ousbatfogovernfteldsonloccont Over 140 VAN®Specialists available worldwide 24/7 for Rig Site Assistance Caner COnnecttG,Data Secat:.are CTaII°°IC at WWIN.1..er4,<a:r°nf 17.4 Ensure to run enough liner to provide for approx 100' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 17.5 R/U false rotary and run 2-7/8" inner string. 17.6 Before picking up Baker ZXP liner hanger/packer assy, count the#of joints on the pipe deck to make sure it coincides with the pipe tally. 17.7 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 17.8 Note weight of liner. Run liner in the hole one stand and pump through liner hanger to ensure a clear flow path exists. 17.9 RIH w/liner on DP no faster than 1-1/2 min/stand. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. Page 35 Version 1 Oct, 2016 i S Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 17.10 DP should autofill. 17.11 Slow in and out of slips. Ensure accurate slack off data is gathered during RIH. Record shoe depth+ S/O depth every stand. Record torque value if it becomes necessary to rotate the string to bottom. 17.12 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 17.13 If any open hole sidetracks have been drilled, monitor sidetrack depths during run in and ensure shoe enters correct hole. 17.14 TIH deeper than planned setting depth. Last motion of the liner should be up to ensure it is set in tension. 17.15 Prior to setting the hanger and packer, double check all pipe tallies and record amount of drill pipe left on location. Ensure all numbers coincide with proper setting depth of liner hanger. 17.16 Rig up to pump down the work string with the rig pumps. 17.17 Break circulation and begin displacing wellbore to 8.9 ppg 2% KC1/NaC1 brine. Adjust brine weight to equal mud weight. Note the large OD on the swell packers. Begin circulating at—1 BPM and monitor pump pressures. Slowly bring rate up while circulating the lateral clean. 17.18 Monitor pump pressures closely and adjust pump rate if the well appears to be packing off at the swell packers. Note all losses. Catch mud for future use if feasible. 17.19 Displace entire wellbore to brine at 300 FPM annular velocity if possible (approximately 15 BPM). Monitor the returned fluids to ensure as much mud has been removed from the wellbore as possible. 17.20 Drop setting ball down the workstring and pump slowly (1-2 bpm). Slow pump before the ball seats. Do not allow ball to slam into ball seat. 17.21 Pressure up to 3000 psi and hold for 5-15 minutes to set SLZXP hanger packer. Continue pressuring up in 500 psi increments holding for 5 min each up to 4000 psi. 17.22 Bleed DP pressure to zero, close BOP and test annulus to 1500 psi for 30 min and chart record same. 17.23 Bleed off pressure and 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. 17.24 POOH, L/D and inspect running tools. If setting of liner hanger/packer proceeded as planned, LDDP on the TOH. Page 36 Version 1 Oct, 2016 • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 18.0 Run Injection Assembly ( 18.1 M/U injection assy and RIH to setting depth. • Ensure appropriate well control crossovers on rig floor and ready. • Monitor displacement from wellbore while RIH. 18.2 Land hanger, RILDs and test hanger. 18.3 Circulate freeze protect down IA, allow freeze protect to U-tube down tubing. 18.4 Set packer. Test annulus to 3000 psi f/30 min. / L0_S • Please fill out a 10-426 and send to cdinger@hilcorp.com and lkeller@hilcorp.com. i. http://doa.alaska.gov/ogc/forms/forms.html form located here. 18.5 Install BPV and N/D BOP. 18.6 N/U tree adapter and tree. Conduct pressure tests of same to 250/3000 psi. 18.7 Shut in well.+ j PI g-eLt C,BL- 'v=— 19.0 RDMO /`e .-✓' Page 37 Version 1 Oct, 2016 I • 11 Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 20.0 Diverter Schematic 1111 M irrr-rrn flit>I 3-5/8"5M Control Technology Annular BOP ] I 1 O is i• 1 1DEI --13-5/8"5M Control o p Technology Double Ram no d ,.r. ir" T �� C 3-1/8"Kill Line �� ] 41 `�. r �� -3 1/8"Choke Line ": I I OE O ! F_Kd ii F_ 13-5/8"5M Controls" I Technology Single Ram 13-5/8"x 5M 0 1 ------ '"'---16"Diverter Line I I / 13-5/8"x 5M -I %- D,'][' I 1 \-2-1/16"x 5M 20"Casing Page 38 Version 1 Oct, 2016 i 0 II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 21.0 BOP Schematic r m nUnii m mn "------13-5/8"5M Control Technology Annular BOP ° ® .ai Etli 1. EH II :-----EE -----`"-- 13-5/8"5M Control -o- 2 o Technology Double Ram 3-1/8"Kill Line �t I M. ./�^. J .10410 , '9iyx. -3-1/8"Choke Line c o —�� ;.; L4_3- 3 -----"-------13-5/8"5M Control Technology Single Ram 13-5/8"x 5M 11"x5M Oil JO\ 9-5/8"DBL DSeal--,,,,, 2-1/16"x 5M Casing Hanger � Il3-5/85M S-22 �''1 •-�tr,'][t.' 13-5/8"NOM 9-5/8"BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top 1 W/Primary Seal I 20"Casing 9-5/8"Casing Page 39 Version 1 Oct, 2016 • • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 22.0 Wellhead Schematic O HILCORP ALASKA MO-388 1,4,1 CI: II 1Ou. �.l " 47.3 ..10 iii... EST PliO ©1 , u ,j 4-1/16 SM W 11111. ,4) o , II ® o ©• °1 105.7 : -* O F EST u,u...1 1. ® � 4-1/16 5M QQ/ p HYDRAULIC ACTUATOR— ( 0 II �% o O 35.1 •I in us u. EST 56.4 — EST ...""7".."111. ..lel u... 0 to 411;4) 185.4 EST .441 r ; ADAPTER.SM-E-CLN "T7 : URI 11 SM X 4-1/16 SM .II �R:. ,_.11 SM TUBING HANGER 1 I SM-E-CL II X 4-1/2 ,m:'1* ■ 191 EU 8RD BTOP 9 - /1 4-1/2 API MOO BOX BTM ...,, - --__ ,. (��/) 7 a yy' 28.2 1EST I... II 1 61 ,4i:$1vl`, i Y1.1 — 1.1 —� L 2-1/16 sM 9-5/8 DBL Fs F 59.7 'f`. ,1t 13-5/8 5M (ST CASING HANGER I' i 5-22 e•rII ,! _ I1r i 13-5/8 X 9-5/8 31.5 C- 1'0.... • a ' _I . EST _ I �� al R_ZZ � L. ' [-Ij It jM IIvJL.1/41 v1% a_..._. ; I NI LOOT Q6-000ar 20 CASING— 9-5/8 CASING WEIR 4-1/2 TUBING--- - 5.000 PSI ESP WELLHEAD & TREE ASSEMBLY RM. 20 X 9-5/8 X 4-1/2 DIMENSIONS SHOWN ON THIS DRAWING ARE _...... -_T ESTIMATES ONLY AND CAN VARY SIGNIFICANTLY RESTRICTED CONFIDENTIAL DOCUMENT ...A DEPENDING CN RAW MATERIAL LENGTHS. .+•••��+ .e +K. ..w.a •' 35' 1:10 1..8/23/16 fta m wiMO s■OW*•61004103. r.w. NO GDARANIEE OT STAOIVP HOGHT IS IMPLIED. e. ,n gre 0...o No DIMENSIONS SHOWN SHOULD BE8 CON90EAE0 ..otit v w e....a...,mot.t. FOR REFERENCE PURPOSES aNI.r. '^'�'O11L ••w were...,^�-� • P-21548 Mdl O N..•I...R K Page 40 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 23.0 Days Vs Depth Days Vs Depth o — �B-032 —B-28 —B-29 2000 — 4000 - -- 6000 — q� r I � 3 ry 8000 10000 — 12000 14000 0 5 10 15 20 25 Days Page 41 Version 1 Oct,2016 • • Eli Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 24.0 Formation Tops MPU B-33 Projected Formation Tops Formation Top ND Bottom TVD SV1 2607 2627 Ugnu LA3 3900 3930 Schrader Bluff NA 4386 4400 ��c Schrader Bluff ND 4410 4430 W GENERALIZED GEOLOGICAL FORECAST SS GEOLOGICAL TVD FM LITH DESCRIPTION SUGGESTED MUD WT. All Geol. *. 8.5 910 9.5 10.0 10 Depths Gubik •� Unconsolidated coarse to medium Tvu Tolerance 606 . ^ sand and small gravel with minor ss MUD PPG t;_Inn . siltstone. Note:This is .� ........ Heavy gravel conglomerate to 1400'. ` a generic mud 1,000' E , • Wood fragments throughout tam-- i -weight chart. a ' ' ' permafrost zone. See individual ( well plan for • 1700' ------'I- ••• Base permafrost specific mud weights. 2,000' C _ _ _ _ Sagavanirktok L ' 9.2 to 9.3 ppg Predominantly clay to+1-3000' with A" - interbeds of sand.clays and silt• ■. stones with occasional shows of coal 94 , , , ■ around 2700'. Pebbley gravel(up to MINIMII 11111111111.11111 50%)down to 2700'. 3,000' INNIN Continued interbeds of sand,clays andimm o siltstones with heavy coal sections 2800-3200 KA: 3800- K-sands 3900 (-A B C,D) UGNU: Series of coarsening upward UGNU L-sands1111MII sands which are made up of: (from top MA: (-&8l to bottom)coarse sand,fine sand,silty 4070- M-sands shale and some coal. Better developed 4140 (-A,B,c) ■ams intervening shales as you progress into the L and M(deeper). 4,000' Possible hydrocarbon bearing sands - - NA: 'Schrader Bluff Sands 4300- N-Sands Continued layered coarsening upward sands as 4600' (-A.B,c.o, above except more condensed. Possible E.F) .drocarbon bearing and potentially productive OA: 0-Sands .,the"0"and"N"sands. Tend to be waterwst 4550- (-A_B,c. more than a mile to the east. 4800' O,E,F) 1 Primarily clay with some silty sandstone I I s. Page 42 Version 1 Oct,2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 25.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Gas Hydrates Remember that hydrate gas behave differently from a gas sand. Additional fluid density will not prevent influx of gas hydrates. Once a gas hydrate has been disturbed the gas will come out of the hole. Drill through the hydrate section as quickly as possible while minimizing gas belching. Minimize circulation time while drilling through the hydrate zone. Excessive circulation will accelerate formation thawing which can increase the amount of hydrates released into the wellbore. Keep the mud circulation temperature as cold as possible. Weigh mud with both a pressurized and non-pressurized mud scale. The non-pressurized scale will reflect the actual mud cut weight. Add 1.0—2.0 ppb DRILTREAT to the system to help thin the mud and release the gas. Isolate/dump contaminated fluid to remove hydrates from the system. Hole Cleaning: Maintain rheology of mud system. Sweep hole with high viscosity sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the hole. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Anti-Collison: There are a number of adjacent wells in the vicinity. Take directional surveys every stand, take additional surveys if necessary. Continuously monitor proximity to offset wellbores and record any close approaches on AM report. Discuss offset wellbores with production foreman and consider shutting in adjacent wells if necessary. Monitor drilling parameters for signs of collision with another well. Wellbore stability (Permafrost, running sands and gravel, conductor broaching): Washouts in the permafrost can be severe if the string is left circulating across it for extended periods of time. Keep mud as cool as possible by taking on cold water and diluting often. High TOH and RIH speeds can aggravate fragile shale/coal formations due to the pressure variations btwn surge and swab. Bring the pumps on slowly after connections. Monitor conductor for any signs of broaching. Maintain mud parameters and increase MW to combat running sands and gravel formations. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on this pad. 1. The AOGCC will be notified within 24 hours if H2S is encountered in excess of 20 ppm during drilling operations. Page 43 Version 1 Oct,2016 • • li Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 2. The rig will have fully functioning automatic H2S 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. 8-1/2" Hole Section: Hole Cleaning: Maintain rheology of mud system. Sweep hole with low-vis water sweeps. Ensure shakers are set up with appropriate screens to maximize solids removal efficiency. Run centrifuge continuously. Monitor ECDs to determine if additional circulation time is necessary. In a highly deviated wellbore, pipe rotation is critical for effective hole cleaning. Rotate at maximum RPMs when CBU, and keep pipe moving to avoid washing out a particular section of the wellbore. Ensure to clean the hole with rotation after slide intervals. Do not out drill our ability to clean the hole. Maintain circulation rate of> 500 gpm. Lost Circulation: Ensure adequate amounts of LCM are available. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of calcium carbonate. Faulting: There is at least(1) fault that will be crossed while drilling the well. There could be others and the throw of these faults is not well understood at this point in time. When a known fault is coming up, ensure to put a"ramp" in the wellbore to aid in kicking off(low siding) later. Once a fault is crossed, we'll need to either drill up or down to get a look at the LWD log and determine the throw and then replan the wellbore. H2S: Treat every hole section as though it has the potential for H2S. No H2S events have been documented on drill wells on"B"pad. 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 H2S 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: There are no abnormal pressures or temperatures observed on this pad. Page 44 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 26.0 Innovation Rig Layout —170'-3 " _ ",.....--,r II. . . "..1.:4+:1:.__r . _- I th _�•r•„• no T=I l4 , DKV • � I ■ " L r —� O i .O ;1-I i It La 0 '� 41 ' ' H if • a------- i 0 I I I - S' Il-ytp .1. r d V wrw �� 56'-4" - HAK 2 FOOT i.. .1, IIIII 171 PRINT Ua`'! -F 05/21/16 - - i,_ -"\; - - -----i- 11111111.11111 liotillia 113'-113" ■ I♦ U 36'-1 " Page 45 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 27.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 46 Version 1 Oct, 2016 • • t Milne Point Unit B-33 '" Drilling Procedure M. Hilcorp Energy Company 28.0 Choke Manifold Schematic 76, _, _,F,-,t,-.-::::--) a n � rf —ill 1 117:i U `�a_, ~b d a 0 a b a .11/13-111 /.` —SII zr1.-- - — 4 ,..,„ ____) ,_ _,. ,...,,,, „,..., 1 I la V ti s IN a r. a . a r' a I r n 2-9Itlertraiffi '''3 C? 8"5M BB209 22-9/16"SM BB208 r" uul Piper Ball Valves Piper Ball Valves jia Ll a ai rf rim li Ivv ,..1 I y • a K iK0 a a a i;.) aI ,I -14 Ta =el las 1 J Page 47 Version 1 Oct, 2016 • • Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 29.0 Casing Design Information Calculation & Casing Design Factors DATE: 10/2612016 WELL: MPU B-33 DESIGN BY:Luke Keller Design Criteria: Hole Size 8-1/2" Mud Density: 9.5 ppg Hole Size Mud Density: Hole Size Mud Density: Drilling Mode MASP: 1512 psi(see attached MASP determination &calculation) MASP: Production Mode MASP: 1512 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 Casing Section Calculation/Specification 1 2 3 4 Casing OD 9-5/8" - 4-1/2" Top(MD) 0 4.900 Top(TVD) 0 4.400 Bottom (MD) 5,078 10,933 Bottom (TVD) 4,420 4.399 Length 5,078 6.033 Weight(ppf) 40 13.5 Grade L-80 L-80 Connection DWC/C VAM HTTC Weight w/o Bouyancy Factor(lbs) 203.120 81,446 Tension at Top of Section (lbs) 203.120 , 81,446 Min strength Tension (1000 lbs) 916 307 Worst Case Safety Factor(Tension) 4.51 • 3.77 Collapse Pressure at bottom(Psi) 2,183 2.173 Collapse Resistance w/o tension(Psi) 3,090 8.540 Worst Case Safety Factor(Collapse) 1.42 3.93 MASP(psi) 1,512 1.512 Minimum Yield (psi) 5,750 9.020 Worst case safety factor(Burst) 3.80 5.97 -f Page 48 Version 1 Oct, 2016 ( • • i Milne Point Unit B-33 i Drilling Procedure 1 ,'- Hilcorp Energy Company 30.0 8-1/2" Hole Section MASP III Maximum Anticipated Surface Pressure Calculation 8-1/2"Hole Section H#Ic= MPU B-33 Milne Point Unit MD ND Planned Top: 5078 4420 Planned TD: 10933 4399 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Schrader Bluff NC Sand 4,420 1954 Oil/Wet 8.5 0.442 • Offset Well Mud Densities Well MW range Top(TVD) Bottom (ND) Date MPB- 11 9.5-9.6 Surface 4,500 1985 MPB- 12 9.0-9.8 Surface 4,500 1985 MPB-13 9.5-9.6 Surface 4,500 1985 MPB-14 9.1-9.4 Surface 4,500 1985 MPB- 15 8.6-9.8 Surface 4,500 1985 MPB- 16 8.9-9.6 Surface 4,500 1985 MPB- 17 8.6-9.7 Surface 4,500 1985 MPB-19 9.2-9.7 Surface 4,500 1985 MPB-21 9.3-10.1 Surface 4,500 1986 MPB-25 8.3-9.4 Surface 4,500 1997 MPB-28 9.0-9.4 Surface 4,435 2016 MPB-29 8,8-9.2 Surface 4,400 2016 Assumptions: L 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: 4420(ft)x 0.78(psi/ft)= 3448 psi 3448(psi)-[D.1(psi/ft)*4420(ft)]= 3006 psi MASP from pore pressure(complete evacuation of wellbore to gas from Schrader Bluff sand) 4420(ft)x 0.442(psi/ft)= 1954 psi 1954(psi)-0.1(psi/ft)*4420(ft)= 1512 psi Summary: 1. MASP while drilling 8-1/2"production hole is governed by pore pressure and evacuation of entire wellbore to gas at 0.1 psi/ft. Page 49 Version 1 Oct, 2016 • i Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 31.0 Spider Plot (NAD 27) (Governmental Sections) 00. 1 ' sec 7 ADL047433 sec ti Sec 12 / ADL392703 (6281 1 , , } - -• 4 I, , M73431) 1 �. .„ MPB-33 NC Inj_)3I II ' mss, , t.WC-24APe1 `' t� V •ii Sec 14 } SOC t3 1, (830) rave fe �� 4 � ,'' -_ `. \IPB-33 NC Inj_TPH � __-N11LNE POINT UNIT U013NO1OE \, . ' ,U013N011E Pic 22A o Is i*---/— MPB-33 NC kJ_SHL --, -,- .. '-,-;..ADL047437 _ - - - - �_a , ADLO47438 ., Y ♦' - yQ 'O. 7 .1PB.c;:- i IJ t rve:ot ' - -4 .A 31P81 - vV��+V4+�1 4 1 L WG fr /J 4 sec.19 — CMOS) ¢ Sec.24 i (833) ` IPE-19I11,11,8-66i I alfriDO , ` Q ` \1 < 1 I . .€ IPE„2<M� , / -01 i i • ... . \\ PAPE-26 '', iii - s 'Y ` -- -- -k ♦``\ i !argil P8 Irl '• Legend , k, i /4/,,,,f.,:MPSIMPB-33 NC Inj_SHL Other Surface Holes(SHL) \`Ci �,,p r' c !./----- 9 Ga 3 • Other Bottom Holes(BHL) .. MRUIE...-'— - - 4 MPB-33 NC In)_TPH a��''-- < IPB 22.PB?^PE 20 �_ -ADL028 ': •763.30 - Other Well Paths f ,`, - '• (gag) •.Pr'i3.,J' ►- MPB-33 NC Inj_BHL Q t s.,. `~� Q Oil and Gas Unit Boundary J .,. Pad Footprint I ~”- . \ �-�^- - - - - II Milne Point Unit �N MPB-33 Well 0 1,000 2,000 Map Dat.16,25,2016 Feet Page 50 Version 1 Oct, 2016 • !II - Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) / s N 2800 - -AiJ - • 1 / IS N U • .I 13-P4D 20• a •21 110MIN= . • ¢/m 180 •19 4 I A-A-4/ ' • • 4 Ili 24 { 79 • TO GRAVEL SI Ti_ _ 9• ■16 / CFP % .._ I /`E-PAD •15 `t. 1230•• 4B �1. 4 25 t 30 �� •'g• •22 Oft VICINITY MAP B-33_ .5A N.T.S. LEGEND: p5 •3 ATB 28 see Tg\ - AS-BUILT CONDUCTOR •Is •40 '' - • EXISTING CONDUCTOR § ,‘01.0%%114111 -"N 1000 '�'`��P'\�.0. A,(qs��,,� *r4 "...set /,0 El—PAD /.... OM Ve.•. ' othy F. Barnhart 10200 •• s 's,'1 'ESSICNA- %% NOTES: 1. ALASKA STATE PLANE COORDINATES ARE ZONE 4 NA027. SURVEYOR'S CERTIFICATE 2. GEODETIC COORDINATES ARE NA027. I HEREBY CERTIFY THAT I AM 3. HORIZONTAL AND VERTICAL CONTROL ARE BASED ON MP B-PAD PROPERLY REGISTERED AND LICENSED OPERATOR MONUMENTS 8-1 AND 8-2. TO PRACTICE LAND SURVEYING IN THE STAT OF ALASKA AND THAT 4. ELEVATIONS ARE MP B-PAD DA IUM, MEAN SEA LEVEL(U.S..). THIS AS-BUILT REPRESENTS A SURVEY MADE BY ME OR UNDER MY DIRECT 5. MEAN PAD SCALE FACTOR IS: 0.999905887 SUPERVISION AND THAT ALL 6. DATE OF SURVEY: SEPTEMBER 27-28, 2018. DIMENSIONS AND OTHER DETAILS ARE 7. REFERENCE FIELD BOOK: HC16-03, PGS. 24-33. CORRECT AS OF SEPTEMBER 28, 2016. LOCATED WITHIN PROTRACTED SEC. 18, T. 13 N., R. 11 E., UMIAT MERIDIAN, ALASKA WELL A.S.P. PLANT GEODETIC GEODETIC TOP OF SECTION BASE FLANGE NO. COORDINATES COORDINATES POSITION(DMS) POSITION(D.DD) CELLAR BOX OFFSETS ELEVATION Y=6,023,149.85 N 1498.68 70'28'24.717" 70.4735324' 27' FSL 8-33 X= 571,978.15 E 599.89 149'24'43.484" 149.4120789' 22.7 4,313' FEL NA NM. KLEIN •r•• Aco IJHilcorp Alaska e:a D011 10,S,1a 0.A B 4 MPS 24- MILNE POINT B-PAD sr:y' OB MU AS-BUILT CONDUCTOR LOCATION Op 10131111/SIM Ka 14,4'"'"110,4 4K" 1' ()' WELL 8-33 1 or 1 Q. DA . masa+ B•Ic.v,1 Page 51 Version 1 Oct,2016 • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 33.0 Offset MW vs TVD Chart 0 _ -B-21 (1986) -B-25 (1997) B-12(1985) 1000 -B-11 (1985) 1 -B-15 (1985) 1B-14(1985) 2000 • -B-13 (1985) -B-17(1985) ' llilltivr B-19 (1985) 3000 ` . B-16 (1985) 1 .4 Vi 4000 it. , . . 5000 ` )ik 6000 V::.\\\ ,1/4.41‘.. 7000 `., 8000 8.0 9.0 10.0 11.0 12.0 Mud Weight(PPG) Page 52 Version 1 Oct,2016 • • II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company 34.0 Drill Pipe Information 5" 19.5# S-135 DS-50 Drill Pipe Configuration Pice Body OD ,n<5.0C+CC 80%Inspection Class , Roe Body Wail Thickness in 0.362 Nominal Weight Designation 19.50 • Pice Body Grade 5-135 'Drill Pipe Approximate Length -. 31 5 Drial Pipe Length Range2 SrnoothEdge Height ,in,J3'32 Raised Connection GPDS50 Tool Joint SMYS •pzn 120,000 Tool Joint 00 6.625 Upset Type IEU i, I Tool Joint ID 1 n 3.250 Max Unset OD ;DTE) _:5 125 Pin Tong g Friction Factor 11.0 Box.Tor' ,.n.12 Note Torg:pace may include Marg.-aided ._.... _.... Drill Pipe Performance Drill-Pipe Length Range2 1 Best Estimates Nominal Performance of Drill Pipe with Pipe Body at ,.,_„,._�,.,, ,,,,�,,,.rd� � x .a<curaM1e; 80%Inspection Class &pied lase` Oftrat onal 41ax Tensick Drill Pipe Adi.ued*eight tr-nl 24.11 23.29 mom. {nuwi Torque 0.100, n:, =laid Disc icemen i;g rel,0.37 0.36 Tension Only 0 560.800 aid Disc acemerd a°o ftl p 0.0085 Maami.rr MU 43,100 Cornaned uoaarw 39.600 410.500 Fluid Capacity �uoL'rtt�D.71 0.70 0.72 Fluid Capacity eelons D.0169 0.0167 0.0172 36,100 Tension Only 0 560.800 Drift Size +Int 3.125 Mlrrrnum Nrur ccrnrineo Load'iQ 32.100 467,400 �,. re onto Or fold oartel equals 42 US Dillon:. Note.Doll ppe as:^_n Hy aal.I00 a e:,vanes and may oaty dt to IOPe bndy roll tolerance.Internal plastk co.WO.and ober 1.-Lr:. Connection Performance GPDS50 ( 6.625 i-nI OD X 3.250 tai ID ) 120,000 til? Appled Malue-up Terson at S,oalde- Tension a^.Ccrnector Tool Joint Dimensions Torque Separr.or Yell -....-.., ,rt-os) Ill's; lass, Balanced 40 nn16.435 Maximum Make-up Torque 43,100 Tensile Lulled 1,046,900 inn.-urn Tool Jont CO ror API 5.930 A nimum Make-up Torque 36,100 1202.500 1,250.000 Premium Coon ITS Note The maximum makeup toque should he applied alien "" posse,* Mtrernurn Tool Jant OD ier... 5.93 Note To maxlmite connection operaeonal tensile,a MUT liar.37,703 tit.lhs}should he applied t . !Tool Joint Torsional Strength eft de:, 71,800 Tool Joint Tensile Strength no 1.250.004 C4L1'1terGVfe on; Elevator Shoulder Information Elevator OD 3/32 Raised 6.812 f,, SmoothEdge Height Nominal Tool Joint Worn to Bevel Worn to Min TJ OD for 3132 Raised OD Diameter API Premium Class Box OD •,.•6.812 6.625 6.063 5.930 Elevator Capacity ,em.1,658.000 1.440,200 823.600 685,600 VJe Ele, r: ;..r E..-,re.ror wear factor.and contact saws or 1lO.lOCps: Assumed Elevator Bore Diameter ]5.219 i ..1,:re A raised e e,ar.1 00, .e,._. _r ca, ,n•moui aned0O make-up torque. Pipe Body Slip Crushing Capacity Pipe Body Confguration( 5 on) OD 0.362 coni Wall S-135) Nominal 80%Inspection Class API Premium Class IT?' Slip Crushing Capacity 396,500 396.500 Mote-Ste Owing 314r vu hino and is calculated elh tic spna+ertrurd ego.31ce Ton',,Wri Does Dsil Ppe Assumed Slip Length foul 16.5 oaf in re Shp Area'Norkl Ce,t939 for the ctO Impel and transverse and factor Moan and Is for reference Transverse Load Factor(Kl 4.2 „ ov dUp � c"' °e"e"'dnflenthe 4Odeaanand� ma dndentdmrmn bairg0 uvn N.P. p(e 00 and Md.'artatke and Otte 00CCI: Cd^GJ1'A/lh the sio Ina'415,t 01rx adaf°"al rrrrPdcn. Pipe Body Performance Pipe Body Configuration( 5 so OD 0.362 ieli Wall S-135) Nominal 80%Inspection Class API Premium Class Pipe Tensile Strength -itdl 712,100 560,800 560.800 Pipe Torsional Strength 74.100 58.`00 58.100 TJ/PipeBody Torsional Ratio 0.97 1.24 1.24 80%PipeTorsional Strength n-.r:.5 M _...,,,........._ I ..9 300 46.500 46.500 Burst ps1 17.105 15.638 15,638 Nle Nominal Burst Collapse p 15.672 10.029 10,029 gacutxled al 67 5',Raw per API Pipe OD n l 5.000 4.855 4.855 Wall Thickness 0.362 0.290 0.290 Nominal Pipe ID un1 4.276 4.276 4.276 Cross Sectional Area of Pipe Body i:in 21 5275 4.'=54 4.154 -Tr Cross Sectional Area of 00 hest 19.635 18.514 18.514 Cross Sectional Area of ID (m021 14.360 _14.360 14.360 • Section Modulus 0,03)5.708 4.476 4.476 dfiShPolar Section Ndodulus in^ai 11.415 8.953 8.953 _.._ Page 53 Version 1 Oct,2016 0 S II Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company Operational Limits of Drill Pipe Connection ]GPDS50 Tool Joint 00 ,,,16.625 Tool Joint ID ,n, 3.250 "ool Joint Specified M^im,.m 120.000 Yield Strength I=• Pipe Body %Inspection Class Pipe Body OD ,,,5 wall Thickness ,,,0.362 Pipe Body Grade S-135 Combined Loading for Drill Pipe at Combined Loading for Drill Pipe at 1 Maximum Make-up Torque= 43,100 rt-es, Minimum Make-up Torque= 36,100 :-•ns OOperaticna; Assembly Pipe Body coenecnmMax 0perat,ona Assembly Prix Body corneecacn MaxTorque + Tension Max Tension Te,mtm I Torque Max Tension ;AmTenrsaon Max Tension q in-is:, ins, lin:, rg.. --rx ii. abS nb,I 0 560.800 560,800 1.046.900 0 560.800 560.800 1.202.500 2,100 560.400 560,400 1.046,900 1.700 560.500 560.500 1,202,500 4,200 559.300 559,300 1.046.900 3.400 559.800 559.800 1,202,5r 6,300 557.500 557,500 1.046.900 5,100 558.600 558.600 —1202.500 ' 8,300 555.000 555,000 1.046.900 6 800 556.900 556.900 1.202,500 10,400 551.700 551,700 1.046.900 8 400 554 900 554.900 1,202.500 12,500 547,600 547,600 1.046.900 10 '00 552 200 552.200 1.202.500 14.600 542.800 542,800 1,046.900 11.800 549.100 549.100 1,202,500 16.700 537.100 537,100 1046.903 13.500 545.400 545.400 1,202,500 18,800 530.600 530,600 1.046.900 15.200 541.200 541.200 1,202500 20,800 523.600 523,600 1.046.900 16.900 536.500 536.500 1.202,500 22,900 515,400 515,400 1.046.900 18.600 531,300 531,300 1,202,500 25.000 506.200 506,200 1.046.900 20.300 525.400 525.400 1.202.501 27.100 496.100 496,100 1.046.900 22.000 519.000 519.000 1,202.500 29,200 484.800 484,800 1.046.900 23.700 512.000 512.000 1202.50: 31,300 472,500 472,500 1,046.900 25.300 504.800 504,800 1.202.500 33,300 459,600 459,600 1.046.900 27 000 496.600 496.600 1 202 50; 35,400 444.700 444,700 1.046.900 28.700 487.600 487.600 1,202,500 37.500 428.400 428,400 1.046.900 30.400 477 900 477 330 1 202.50=: 39.600 410.500 410,500 1.046.900 32.100 467.400 467.400 1.202.500 Operational drilling torque is limited by the Make-up Tcrque. Operational anlling torque is limited by the Make-up Torque. Connection Make-up Torque Range Make-up Torque Connection Max ,.,_,, Tension ,,.,, Min MUT 36,100 1,202,500 11, 36,900 37.700 37.700 1.243,600 —' 38,400 1,218,100 39.200 1,189,000 40.000 1,159,800 40.800 1,130,700 41,500 1,105,200 42.300 1,076,100 Max MUT 43,100 1,046,900 Page 54 Version 1 Oct, 2016 "� ! 0 :� Milne Point Unit B-33 Drilling Procedure Hilcorp Energy Company Connection Wear Table Connection GPDS50 Tcci.oint 00 1,,;16.625 !TodJoint ID 11,,,13250 I Tool Joiet Specified Minimum 120,000 Yield Strength Ic,1 Connection Wear _ TOOT Connection Max COIK9ecton Max Min MUT Connection Max Joint OD Torsional MUT Tension Tension New OD Strength I 1 6.625 71,800 43,100 1,046,900 35,900 1,195,900 f 6.562 71,800 43,100 1,034,900 35.900 1.208.700 6.499 71,800 43,100 1,022,600 35,900 1.222.400 IIMMI 6.435 71,800 43.100 1,009,800 35.900 1.237.50.0 6.372 71,200 42,700 1,008,100 35,600 1.245.200 6.309 68,000 40.800 1,057,300 34.000 1.207.700 6.246 64,800 38,900 1,104,800 32,400 1.169.800 • / 6.183 61,700 37.000 1.150,400 30.800 1.131.300 6.12 58,600 35,200 1,190,900 29,300 1.096.100 6.056 55,500 33,300 1,232.300 27.800 1.060.800 Worn OD 5.993 52,600 31,500 1,227,200 26,300 1,024.600 5.93 49,600 29,800 1,187,100 24,800 987.900 Pipe Body Combined Loading Table (Torque-Tension) Pipe Body 80%Inspection Class Pipe Body OD .1,, 5 Wail Thickness ,,.0.362 Pipe Body Grade S-135 Pipe Body Torque F0 5.300 0 600 5 500 21 100 26 400 31 700 37 000 42 300 47.500 52.800 58.100 Pipe Body Max Tension 50,800 558.400 551.400 539 600 522 50C 499 600 470 000 432 400 384 500 323.100 234.300 12.200 Page 55 Version 1 Oct, 2016 Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-33 Inj MPB-33 NC Inj Plan: MPB-33 wp03 Standard Proposal Report 24 October, 2016 HALLIBURTDN Sperry Drilling Services ! . 0 WALLIBURTON Project: Milne Point WELL DETAILS:FIm MPS-33 Iry NAD 1927(NADCON MINUS) Alaska Zone 04 sv.., y Ore.ryy Site: M Pt B Pad Ground Level 22.70 Well: Plan:MPB-33 Inj +N/.S +F/-W Northing Fasting Latittude Longitude Wellbore: MPB-33 NC Inj 0.00 0.00 6023149.85 57197815 70°28'24.717N l49°24'43.484W Design: MPB-33 wp03 SECTION DETAILS Sec MD Inc Azi ND +N/-S +E/-W Dleg TFace VSect Target 1 28.50 0.00 0.00 26.50 0.00 0.00 0.00 0.00 0.00 2 254.00 0.00 0.00 254.00 0.00 0.00 0.00 0.00 0.00 -887- 3 554.00 6.00 20.00 553.45 14.75 5.37 2.00 20.00 6.38 - 4 804.00 6.00 20.00 802.08 39.30 14.31 0.00 0.00 17.01 _ 5 1123.46 10.41 314.69 1118.78 75.37 -0.54 3.00 -99.59 52.74 6 3526.74 10.41 314.69 3482.50 380.77 -309.23 0.00 0,00 486.94 - A7 5078.59 88.00 313.48 4420.71 1131.35 -1095.59 5.00 -1.24 1574.00 8 . . . . - . . . 0- 9 52235178.7559 90.2688.00 313313.4848 44442244:8290 4244424.892012001231.1811 -1200.871168.11 50.0000 00.0000 17191673.0894 MPB-33 NC Heel Start Dir 2°/100':254'MD,254'TVD 10 10933.30 90.26 313.48 4399.20 5159.95 -5343,71 0.00 0.00 7428.34 MPB-33 BHL NC Toe f00___End Dir:554'MD,553.45'ND CASING DETAILS FORMATION TOP DETAILS 667- _ ___-Start Dir 3°/100':804'MD,802.08'TVD TVD TVDSS MD Size Name TVDPath TVDssPath MDPath Formation 4417.20 4368.00 5020.36 9-5/8 9 5/8" 1588.20 1539.00 1800.74 Base Permafrost _ 1000 4399.20 4350.00 10933.30 4-1/2 41/2" 2150.20 2101.00 2172.14 SV3 -__ 3908.20 3859.00 3988.87 UGNU LA3 End Dir :1123.46'MD,1118.78'ND - 4148.20 4099.00 4310.67 UGNU MA -E-1333- 4379.20 4330.00 4806.61 Schrader Bluff NA - 1500 4417.20 4388.00 5020.36 Schrader Bluff NC c - Base Permafrost -- - - p _ SURVEY PROGRAM ..2000- 2000 Date:2016-05-19700:00:00 Validated:Yes Version: n - 0 - Depth From Depth To Survey/Plan Tool SV3 26.50 600.00 MPB-33 wp03 SRG-SS - 250° 600.00 5020.00 MPB-33 wp03 MWD+IFR2+MS+sag e - 5020.00 10933.30 MPB-33 wp03 MWD+IFR2+MS+sag j 2687- _ Start Dir 5°/100':3526.74'MD,3482.5'ND F 3000 3333- - 3500 End Dir:5078.59'MD,4420.71'ND - - UGNU L.A3A°p0 ' Start Dir 5°/100':5178.59'MD,4424.2'ND Total Depth:10933.3'MD,4399.2'TVD 4000- UGNU MA oo End Dir :5223.75'MD,4424.89'ND - Schrader Bluff NA h -- z C G C O O O O O O N b, , 4887- Schrader Bluff NC o $ 0 0 0 0 0 0 o w MPB-33 wp03 9 SIB'I 14 1/2'{ - MPB-33 NC Heel MPB-33 BHL NC Toe 5333- i i i i i i i i i i i i i a i i i i i i i a i i I i i l i i i i r l i i i i l r r i r i r r r r r r r i i i i r i i i i i i r -887 0 - 887 1333 2000 2687 3333 4000 4667 5333 8000 8887 7333 :„' --- Vertical Section at 314.00°(1000 usft/in) ri I H. ,y r r. V • _ DETAILS: Plan:MPB-33 Inj ►. HALLI® Project: Milne Point Hilcorp Site: M Pt B Pad Ground Level: 22.70 Sperry Drittic,9 Well: Plan: MPB-33 Inj +000 +000 6023149.85[ 7197s15 70°28'24.717N149°Longitude Latittude 24'43.484W Wellbore: MPB-33 NC Inj Plan: MPB-33 wp03 REFERENCE INFORMATION Co-ordinate(NIE)Reference:Well Plan:MPB-33 Inj,True North Vertical(TVD)Reference:As-built Plan©49.20usft(Innovation) Measured Depth Reference:As-built Plan(B 49.20usft(Innovation) Calculation Method:Minimum Curvature SURVEY PROGRAM 7000— Date:2016-05-19T00:00:00 Validated:Yes Version: Depth From Depth To Survey/Plan Tool 26.50 600.00 MPB-33 wp03 SRG-SS 600.00 5020.00 MPB-33 wp03 MWD+IFR2+MS+sag – 5020.00 10933.30 MPB-33 wp03 MWD+IFR2+MS+sag 6500— CASING DETAILS 6000— TVD TVDSS MD Size Name 4417.20 4368.00 5020.36 9-5/8 9 5/8" 4399.20 4350.00 10933.30 4-1/2 4 1/2" MPB-33 wp03 5500— 4 1/2" COMPANY DETAILS: Hilcorp Energy Company IMP3-33 BHL NC Too Calculation Method: Minimum Curvature Error System: ISCWSA 5000— Scan Method: Closest Approach 3D Error Surface: Elliptical Conic Warning Method: Error Ratio 4500- 4000- 500-4000— Total Depth 10933.3'MD,43992'TVD 3500- 0 o + 3000— o ,: 2500— o rn 2000- - I MPB-33 NC Heeli 1500- - End Dir:5223.75'MD,4424.89'TVD 9 5/8" 1000— Start Dir 50/100':5178.59'MD,4424.2'TVD — 50 - ati End Dir:5078.59'MD,4420.71'TVD 500— ^,'`5 Start Dir 50/100':3526.74'MD,3482.5'TVD- End Dir:1123.46'MD,1118.78'TVD____ r000 0- -- Start Dir 3°/100':804'MD,802.08'TVD r End Dir:554'MD,553.45'TVD -500- - Start Dir 20/100:254'MD,254'TVD -1000— -6000 -5500 -5000 -4500 -4000 -3500 -3000 -2500 -2000 -1500 -1000 -500 0 500 1000 West(-)/East(+)(1000 usft/in) ! 1 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 Inj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Project Milne Point,ACT,MILNE POINT Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor i Site M Pt B Pad,TR-13-11 Site Position: Northing: 6,021,548.49 usft Latitude: 70°28'8.986 N From: Map Easting: 571,775.55 usft Longitude: 149°24'49.895 W: Position Uncertainty: 0.00 usft Slot Radius: 0" Grid Convergence: 0.55 ° Well Plan:MPB-33 Inj Well Position +N/-S 0.00 usft Northing: 6,023,149.85 usft Latitude: 70°28'24.717 N +E/-W 0.00 usft Easting: 571,978.15 usft Longitude: 149°24'43.484 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 22.70 usft Wellbore MPB-33 NC Inj Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2016 5/19/2016 18.34 81.07 57,570 Design MPB-33 wp03 Audit Notes: Version: Phase: PLAN Tie On Depth: 26.50 Vertical Section: Depth From(TVD) +N/-5 +E/-W Direction (usft) (usft) (usft) (0) 26.50 0.00 0.00 314.00 Plan Sections I Measured Vertical ND Dogleg Build Turn Depth Inclination Azimuth Depth System +NI-S +EI-W Rate Rate Rate Tool Face (usft) (°) (0) (usft) usft (usft) (usft) ("I100usft) 0100usft) ("N00usft) (0) 26.50 0.00 0.00 26.50 -22.70 0.00 0.00 0.00 0.00 0.00 0.00 254.00 0.00 0.00 254.00 204.80 0.00 0.00 0.00 0.00 0.00 0.00 554.00 6.00 20.00 553.45 504.25 14.75 5.37 2.00 2.00 0.00 20.00 804.00 6.00 20.00 802.08 752.88 39.30 14.31 0.00 0.00 0.00 0.00 1,123.46 10.41 314.69 1,118.78 1,069.58 75.37 -0.54 3.00 1.38 -20.44 -99.59 3,526.74 10.41 314.69 3,482.50 3,433.30 380.77 -309.23 0.00 0.00 0.00 0.00 5,078.59 88.00 313.48 4,420.71 4,371.51 1,131.35 -1,095.59 5.00 5.00 -0.08 -1.24 5,178.59 88.00 313.48 4,424.20 4,375.00 1,200.11 -1,168.11 0.00 0.00 0.00 0.00 5,223.75 90.26 313.48 4,424.89 4,375.69 1,231.18 -1,200.87 5.00 5.00 0.00 0.00 10,933.30 90.26 313.48 4,399.20 4,350.00 5,159.95 -5,343.71 0.00 0.00 0.00 0.00 10/24/2016 6:31:49PM Page 2 COMPASS 5000.1 Build 81 • 11110 Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 lnj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EI-W Northing Easting DLS Vert Section (usft) (°) (^) (usft) usft (usft) (usft) (usft) (usft) -22.70 26.50 0.00 0.00 26.50 -22.70 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 100.00 0.00 0.00 100.00 50.80 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 200.00 0.00 0.00 200.00 150.80 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 254.00 0.00 0.00 254.00 204.80 0.00 0.00 6,023,149.85 571,978.15 0.00 0.00 Start Dir 2°/100':254'MD,254'TVD 300.00 0.92 20.00 300.00 250.80 0.35 0.13 6,023,150.20 571,978.27 2.00 0.15 400.00 2.92 20.00 399.94 350.74 3.50 1.27 6,023,153.36 571,979.39 2.00 1.51 500.00 4.92 20.00 499.70 450.50 9.92 3.61 6,023,159.80 571,981.66 2.00 4.29 554.00 6.00 20.00 553.45 504.25 14.75 5.37 6,023,164.65 571,983.37 2.00 6.38 End Dir :554'MD,553.45'TVD 600.00 6.00 20.00 599.20 550.00 19.27 7.01 6,023,169.18 571,984.97 0.00 8.34 700.00 6.00 20.00 698.65 649.45 29.09 10.59 6,023,179.04 571,988.45 0.00 12.59 800.00 6.00 20.00 798.10 748.90 38.91 14.16 6,023,188.89 571,991.93 0.00 16.84 804.00 6.00 20.00 802.08 752.88 39.30 14.31 6,023,189.29 571,992.07 0.00 17.01 Start Dir 3°/100':804'MD,802.08'TVD 900.00 6.21 352.72 897.56 848.36 49.17 15.36 6,023,199.16 571,993.04 3.00 23.10 1,000.00 7.66 330.74 996.84 947.64 60.35 11.42 6,023,210.30 571,988.98 3.00 33.70 1,100.00 9.84 317.04 1,095.68 1,046.48 72.42 2.34 6,023,222.28 571,979.79 3.00 48.62 1,123.46 10.41 314.69 1,118.78 1,069.58 75.37 -0.54 6,023,225.21 571,976.89 3.00 52.74 End Dir :1123.46'MD,1118.78'TVD 1,200.00 10.41 314.69 1,194.06 1,144.86 85.10 -10.37 6,023,234.84 571,966.96 0.00 66.57 1,300.00 10.41 314.69 1,292.41 1,243.21 97.81 -23.21 6,023,247.42 571,954.00 0.00 84.64 1,400.00 10.41 314.69 1,390.77 1,341.57 110.52 -36.06 6,023,260.00 571,941.03 0.00 102.70 1,500.00 10.41 314.69 1,489.12 1,439.92 123.22 -48.90 6,023,272.58 571,928.06 0.00 120.77 1,600.00 10.41 314.69 1,587.47 1,538.27 135.93 -61.75 6,023,285.16 571,915.10 0.00 138.84 1,600.74 10.41 314.69 1,588.20 1,539.00 136.02 -61.84 6,023,285.26 571,915.00 0.00 138.97 Base Permafrost 1,700.00 10.41 314.69 1,685.83 1,636.63 148.64 -74.59 6,023,297.74 571,902.13 0.00 156.91 1,800.00 10.41 314.69 1,784.18 1,734.98 161.34 -87.43 6,023,310.33 571,889.17 0.00 174.97 1,900.00 10.41 314.69 1,882.54 1,833.34 174.05 -100.28 6,023,322.91 571,876.20 0.00 193.04 2,000.00 10.41 314.69 1,980.89 1,931.69 186.76 -113.12 6,023,335.49 571,863.24 0.00 211.11 2,100.00 10.41 314.69 2,079.24 2,030.04 199.47 -125.97 6,023,348.07 571,850.27 0.00 229.17 2,172.14 10.41 314.69 2,150.20 2,101.00 208.63 -135.24 6,023,357.15 571,840.92 0.00 242.21 SV3 2,200.00 10.41 314.69 2,177.60 2,128.40 212.17 -138.81 6,023,360.65 571,837.30 0.00 247.24 2,300.00 10.41 314.69 2,275.95 2,226.75 224.88 -151.66 6,023,373.23 571,824.34 0.00 265.31 2,400.00 10.41 314.69 2,374.31 2,325.11 237.59 -164.50 6,023,385.81 571,811.37 0.00 283.37 2,500.00 10.41 314.69 2,472.66 2,423.46 250.30 -177.35 6,023,398.40 571,798.41 0.00 301.44 2,600.00 10.41 314.69 2,571.02 2,521.82 263.00 -190.19 6,023,410.98 571,785.44 0.00 319.51 2,700.00 10.41 314.69 2,669.37 2,620.17 275.71 -203.04 6,023,423.56 571,772.48 0.00 337.57 2,800.00 10.41 314.69 2,767.72 2,718.52 288.42 -215.88 6,023,436.14 571,759.51 0.00 355.64 2,900.00 10.41 314.69 2,866.08 2,816.88 301.13 -228.73 6,023,448.72 571,746.54 0.00 373.71 3,000.00 10.41 314.69 2,964.43 2,915.23 313.83 -241.57 6,023,461.30 571,733.58 0.00 391.78 3,100.00 10.41 314.69 3,062.79 3,013.59 326.54 -254.42 6,023,473.88 571,720.61 0.00 409.84 3,200.00 10.41 314.69 3,161.14 3,111.94 339.25 -267.26 6,023,486.46 571,707.65 0.00 427.91 10/24/2016 6:31:49PM Page 3 COMPASS 5000.1 Build 81 • • Halliburton H,ALLIBURTOPJ Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 Inj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +El-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,210.29 3,300.00 10.41 314.69 3,259.49 3,210.29 351.95 -280.10 6,023,499.05 571,694.68 0.00 445.98 3,400.00 10.41 314.69 3,357.85 3,308.65 364.66 -292.95 6,023,511.63 571,681.72 0.00 464.04 3,500.00 10.41 314.69 3,456.20 3,407.00 377.37 -305.79 6,023,524.21 571,668.75 0.00 482.11 3,526.74 10.41 314.69 3,482.50 3,433.30 380.77 -309.23 6,023,527.57 571,665.28 0.00 486.94 Start Dir 5°/100':3526.74'MD,3482.5'TVD 3,600.00 14.07 314.37 3,554.09 3,504.89 391.65 -320.30 6,023,538.35 571,654.10 5.00 502.47 3,700.00 19.07 314.12 3,649.90 3,600.70 411.54 -340.74 6,023,558.04 571,633.48 5.00 530.98 3,800.00 24.07 313.97 3,742.87 3,693.67 437.09 -367.16 6,023,583.33 571,606.82 5.00 567.74 3,900.00 29.07 313.88 3,832.28 3,783.08 468.11 -399.37 6,023,614.03 571,574.31 5.00 612.45 3,988.87 33.51 313.81 3,908.20 3,859.00 500.07 -432.65 6,023,645.67 571,540.72 5.00 658.60 UGNU LA3 4,000.00 34.07 313.80 3,917.45 3,868.25 504.36 -437.12 6,023,649.91 571,536.21 5.00 664.79 4,100.00 39.07 313.75 3,997.74 3,948.54 545.57 -480.13 6,023,690.70 571,492.81 5.00 724.35 4,200.00 44.07 313.70 4,072.53 4,023.33 591.42 -528.06 6,023,736.08 571,444.44 5.00 790.69 4,300.00 49.07 313.67 4,141.25 4,092.05 641.56 -580.56 6,023,785.71 571,391.46 5.00 863.29 4,310.67 49.60 313.66 4,148.20 4,099.00 647.15 -586.42 6,023,791.23 571,385.56 5.00 871.38 UGNU MA 4,400.00 54.07 313.64 4,203.39 4,154.19 695.62 -637.23 6,023,839.21 571,334.28 5.00 941.60 4,500.00 59.07 313.61 4,258.46 4,209.26 753.17 -697.63 6,023,896.17 571,273.34 5.00 1,025.02 4,600.00 64.07 313.58 4,306.05 4,256.85 813.79 -761.30 6,023,956.17 571,209.09 5.00 1,112.94 4,700.00 69.07 313.56 4,345.80 4,296.60 877.01 -827.75 6,024,018.74 571,142.03 5.00 1,204.66 4,800.00 74.07 313.54 4,377.40 4,328.20 942.35 -896.50 6,024,083.40 571,072.67 5.00 1,299.50 4,806.61 74.40 313.54 4,379.20 4,330.00 946.74 -901.11 6,024,087.74 571,068.02 5.00 1,305.86 ISI Schrader Bluff NA 4,900.00 79.07 313.52 4,400.62 4,351.42 1,009.32 -967.00 6,024,149.68 571,001.53 5.00 1,396.73 5,000.00 84.07 313.50 4,415.28 4,366.08 1,077.40 -1,038.72 6,024,217.05 570,929.16 5.00 1,495.61 5,020.36 85.09 313-49, 4,417.20 4,368.00 1,091.35 -1,053.42 6,024,230.86 570,914.32 5.00 1,515.88 i chrader Bluff NC-9 5/8" / 313.48 4,420.71 4,371.51 1,131.34 -1,095.59 6,024,270.44 570,871.77 5.00 1,574.00 End Dir :5078.59'MD,4420.71'TVD 5,100.00 88.00 313.48 4,421.46 4,372.26 1,146.07 -1,111.12 6,024,285.01 570,856.11 0.00 1,595.39 5,178.59 88.00 313.48 4,424.20 4,375.00 1,200.11 -1,168.11 6,024,338.50 570,798.60 0.00 1,673.93 Start Dir 5°/100':5178.59'MD,4424.2'TVD 5,200.00 89.07 313.48 4,424.75 4,375.55 1,214.84 -1,183.64 6,024,353.07 570,782.93 5.00 1,695.33 5,223.75 90.26 313.48 4,424.89 4,375.69 1,231.18 -1,200.87 6,024,369.25 570,765.54 5.00 1,719.08 End Dir :5223.75'MD,4424.89'TVD 5,300.00 90.26 313.48 4,424.54 4,375.34 1,283.65 -1,256.20 6,024,421.17 570,709.72 0.00 1,795.33 5,400.00 90.26 313.48 4,424.09 4,374.89 1,352.46 -1,328.76 6,024,489.27 570,636.50 0.00 1,895.32 5,500.00 90.26 313.48 4,423.64 4,374.44 1,421.27 -1,401.32 6,024,557.37 570,563.29 0.00 1,995.32 5,600.00 90.26 313.48 4,423.19 4,373.99 1,490.08 -1,473.88 6,024,625.47 570,490.07 0.00 2,095.31 5,700.00 90.26 313.48 4,422.74 4,373.54 1,558.89 -1,546.43 6,024,693.57 570,416.86 0.00 2,195.31 5,800.00 90.26 313.48 4,422.29 4,373.09 1,627.70 -1,618.99 6,024,761.67 570,343.64 0.00 2,295.30 5,900.00 90.26 313.48 4,421.84 4,372.64 1,696.51 -1,691.55 6,024,829.77 570,270.43 0.00 2,395.30 6,000.00 90.26 313.48 4,421.39 4,372.19 1,765.32 -1,764.11 6,024,897.87 570,197.21 0.00 2,495.29 6,100.00 90.26 313.48 4,420.94 4,371.74 1,834.13 -1,836.67 6,024,965.96 570,124.00 0.00 2,595.29 10/24/2016 6:31:49PM Page 4 COMPASS 5000.1 Build 81 110 I Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 Inj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-S +E/-W Northing Easting DLS Vert Section (usft) (') (') (usft) usft (usft) (usft) (usft) (usft) 4,371.29 6,200.00 90.26 313.48 4,420.49 4,371.29 1,902.94 -1,909.23 6,025,034.06 570,050.78 0.00 2,695.28 6,300.00 90.26 313.48 4,420.04 4,370.84 1,971.75 -1,981.79 6,025,102.16 569,977.57 0.00 2,795.28 6,400.00 90.26 313.48 4,419.59 4,370.39 2,040.56 -2,054.35 6,025,170.26 569,904.35 0.00 2,895.27 I 6,500.00 90.26 313.48 4,419.14 4,369.94 2,109.38 -2,126.91 6,025,238.36 569,831.14 0.00 2,995.27 6,600.00 90.26 313.48 4,418.69 4,369.49 2,178.19 -2,199.47 6,025,306.46 569,757.92 0.00 3,095.26 6,700.00 90.26 313.48 4,418.25 4,369.05 2,247.00 -2,272.03 6,025,374.56 569,684.71 0.00 3,195.26 6,800.00 90.26 313.48 4,417.80 4,368.60 2,315.81 -2,344.59 6,025,442.66 569,611.49 0.00 3,295.25 6,900.00 90.26 313.48 4,417.35 4,368.15 2,384.62 -2,417.15 6,025,510.76 569,538.28 0.00 3,395.25 7,000.00 90.26 313.48 4,416.90 4,367.70 2,453.43 -2,489.71 6,025,578.86 569,465.06 0.00 3,495.24 7,100.00 90.26 313.48 4,416.45 4,367.25 2,522.24 -2,562.27 6,025,646.96 569,391.85 0.00 3,595.24 7,200.00 90.26 313.48 4,416.00 4,366.80 2,591.05 -2,634.83 6,025,715.05 569,318.63 0.00 3,695.23 7,300.00 90.26 313.48 4,415.55 4,366.35 2,659.86 -2,707.39 6,025,783.15 569,245.42 0.00 3,795.23 7,400.00 90.26 313.48 4,415.10 4,365.90 2,728.67 -2,779.95 6,025,851.25 569,172,20 0.00 3,895.22 7,500.00 90.26 313.48 4,414.65 4,365.45 2,797.48 -2,852.51 6,025,919.35 569,098.99 0.00 3,995.22 7,600.00 90.26 313.48 4,414.20 4,365.00 2,866.29 -2,925.07 6,025,987.45 569,025.77 0.00 4,095.21 7,700.00 90.26 313.48 4,413.75 4,364.55 2,935.10 -2,997.63 6,026,055.55 568,952.56 0.00 4,195.21 7,800.00 90.26 313.48 4,413.30 4,364.10 3,003.91 -3,070.19 6,026,123.65 568,879.34 0.00 4,295.20 7,900.00 90.26 313.48 4,412.85 4,363.65 3,072.72 -3,142.75 6,026,191.75 568,806.13 0.00 4,395.20 8,000.00 90.26 313.48 4,412.40 4,363.20 3,141.53 -3,215.31 6,026,259.85 568,732.91 0.00 4,495.19 8,100.00 90.26 313.48 4,411.95 4,362.75 3,210.34 -3,287.87 6,026,327.95 568,659.70 0.00 4,595.19 8,200.00 90.26 313.48 4,411.50 4,362.30 3,279.15 -3,360.43 6,026,396.05 568,586.49 0.00 4,695.18 8,300.00 90.26 313.48 4,411.05 4,361.85 3,347.96 -3,432.99 6,026,464.14 568,513.27 0.00 4,795.18 8,400.00 90.26 313.48 4,410.60 4,361.40 3,416.77 -3,505.55 6,026,532.24 568,440.06 0.00 4,895.17 8,500.00 90.26 313.48 4,410.15 4,360.95 3,485.58 -3,578.11 6,026,600.34 568,366.84 0.00 4,995.17 8,600.00 90.26 313.48 4,409.70 4,360.50 3,554.40 -3,650.67 6,026,668.44 568,293.63 0.00 5,095.16 8,700.00 90.26 313.48 4,409.25 4,360.05 3,623.21 -3,723.23 6,026,736.54 568,220.41 0.00 5,195.15 8,800.00 90.26 313.48 4,408.80 4,359.60 3,692.02 -3,795.79 6,026,804.64 568,147.20 0.00 5,295.15 8,900.00 90.26 313.48 4,408.35 4,359.15 3,760.83 -3,868.35 6,026,872.74 568,073.98 0.00 5,395.14 9,000.00 90.26 313.48 4,407.90 4,358.70 3,829.64 -3,940.91 6,026,940.84 568,000.77 0.00 5,495.14 9,100.00 90.26 313.48 4,407.45 4,358.25 3,898.45 -4,013.47 6,027,008.94 567,927.55 0.00 5,595.13 9,200.00 90.26 313.48 4,407.00 4,357.80 3,967.26 -4,086.03 6,027,077.04 567,854.34 0.00 5,695.13 9,300.00 90.26 313.48 4,406.55 4,357.35 4,036.07 -4,158.59 6,027,145.14 567,781.12 0.00 5,795.12 9,400.00 90.26 313.48 4,406.10 4,356.90 4,104.88 -4,231.15 6,027,213.23 567,707.91 0.00 5,895.12 9,500.00 90.26 313.48 4,405.65 4,356.45 4,173.69 -4,303.71 6,027,281.33 567,634.69 0.00 5,995.11 9,600.00 90.26 313.48 4,405.20 4,356.00 4,242.50 -4,376.26 6,027,349.43 567,561.48 0.00 6,095.11 9,700.00 90.26 313.48 4,404.75 4,355.55 4,311.31 -4,448.82 6,027,417.53 567,488.26 0.00 6,195.10 9,800.00 90.26 313.48 4,404.30 4,355.10 4,380.12 -4,521.38 6,027,485.63 567,415.05 0.00 6,295.10 9,900.00 90.26 313.48 4,403.85 4,354.65 4,448.93 -4,593.94 6,027,553.73 567,341.83 0.00 6,395.09 10,000.00 90.26 313.48 4,403.40 4,354.20 4,517.74 -4,666.50 6,027,621.83 567,268.62 0.00 6,495.09 10,100.00 90.26 313.48 4,402.95 4,353.75 4,586.55 -4,739.06 6,027,689.93 567,195.40 0.00 6,595.08 10,200.00 90.26 313.48 4,402.50 4,353.30 4,655.36 -4,811.62 6,027,758.03 567,122.19 0.00 6,695.08 10,300.00 90.26 313.48 4,402.05 4,352.85 4,724.17 -4,884.18 6,027,826.13 567,048.97 0.00 6,795.07 10,400.00 90.26 313.48 4,401.60 4,352.40 4,792.98 -4,956.74 6,027,894.23 566,975.76 0.00 6,895.07 10,500.00 90.26 313.48 4,401.15 4,351.95 4,861.79 -5,029.30 6,027,962.33 566,902.54 0.00 6,995.06 10,600.00 90.26 313.48 4,400.70 4,351.50 4,930.60 -5,101.86 6,028,030.42 566,829.33 0.00 7,095.06 10/24/2016 6:31:49PM Page 5 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTOI\I Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 Inj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 4,351.05 10,700.00 90.26 313.48 4,400.25 4,351.05 4,999.42 -5,174.42 6,028,098.52 566,756.11 0.00 7,195.05 10,800.00 90.26 313.48 4,399.80 4,350.60 5,068.23 -5,246.98 6,028,166.62 566,682.90 0.00 7,295.05 10,900.00 90.26 313.48 4,399.35 4,350.15 5,137.04 -5,319.54 6,028,234.72 566,609.68 0.00 7,395.04 10,933.30 90.26 313.48 4,399.20 4,350.00 5,159.95 -5,343.70 6,028,257.40 566,585.30 0.00 7,428.34 Total Depth:10933.3'MD,4399.2'TVD-4 1/2" Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) MPB-33 NC Heel 0.00 0.00 4,424.20 1,200.11 -1,168.11 6,024,338.50 570,798.60 -plan hits target center -Point MPB-33 BHL NC Toe 0.00 0.00 4,399.20 5,159.95 -5,343.71 6,028,257.40 566,585.30 -plan hits target center -Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 10,933.30 4,399.20 41/2" 4-1/2 8-1/2 5,020.36 4,417.20 9 5/8" 9-5/8 12-1/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 4,806.61 4,379.20 Schrader Bluff NA 4,310.67 4,148.20 UGNU MA 2,172.14 2,150.20 SV3 1,600.74 1,588.20 Base Permafrost 3,988.87 3,908.20 UGNU LA3 5,020.36 4,417.20 Schrader Bluff NC 10/24/2016 6:31:49PM Page 6 COMPASS 5000.1 Build 81 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well Plan:MPB-33 lnj Company: Hilcorp Energy Company TVD Reference: As-built Plan @ 49.20usft(Innovation) Project: Milne Point MD Reference: As-built Plan @ 49.20usft(Innovation) Site: M Pt B Pad North Reference: True Well: Plan:MPB-33 Inj Survey Calculation Method: Minimum Curvature Wellbore: MPB-33 NC Inj Design: MPB-33 wp03 Plan Annotations Measured Vertical Local Coordinates Depth Depth +NI-S +EI-W (usft) (usft) (usft) (usft) Comment 254.00 254.00 0.00 0.00 Start Dir 2°/100':254'MD,254'TVD 554.00 553.45 14.75 5.37 End Dir :554'MD,553.45'TVD 804.00 802.08 39.30 14.31 Start Dir 3°/100':804'MD,802.08'TVD 1,123.46 1,118.78 75.37 -0.54 End Dir :1123.46'MD,1118.78'TVD 3,526.74 3,482.50 380.77 -309.23 Start Dir 5°/100':3526.74'MD,3482.5'TVD 5,078.59 4,420.71 1,131.34 -1,095.59 End Dir :5078.59'MD,4420.71'TVD 5,178.59 4,424.20 1,200.11 -1,168.11 Start Dir 5°/100':5178.59'MD,4424.2'TVD 5,223.75 4,424.89 1,231.18 -1,200.87 End Dir :5223.75'MD,4424.89'TVD 10,933.30 4,399.20 5,159.95 -5,343.70 Total Depth:10933.3'MD,4399.2'TVD 10/24/2016 6:31:49PM Page 7 COMPASS 5000.1 Build 81 • • Hilcorp Energy Company Milne Point M Pt B Pad Plan: MPB-33 Inj MPB-33 NC Inj MPB-33 wp03 Sperry Drilling Services Clearance Summary Anticollision Report 24 October,2016 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-33 Inj-MPB-33 NC In)-MPB-33 wp03 Well Coordinates: 6,023,149.85 N,571,978.15 E(70"28'24.72"N,149°24'43.48"W) Datum Height: As-built Plan @ 49.20usft(Innovation) Scan Range: 0.00 to 10,933.30 usft.Measured Depth. Scan Radius is 1,290.68 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build:81 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 HALLIIBURTON Sperry Drilling Services • • HALLIBURTON Project: Milne Point REFERENCE INFORMATION WELL DETAILS:Plan:MPB-33Inj NAD 1927(NADCON CONO$) Akdm Zone 04 Site: M Pt B Pad Coordinate(N/E)Reference:Well Plan:MPB-33 hi True North Lound Level: 22.70 car .,.,.y p,,,0,,.,,,.1 Well: Plan:MPB-33 Int Vertical(TVD)Reference:As-bee Plan W 49.20usn(Innovation) +N/-$ +F/-W N Lstilmde Lo tole MeasuredDepthR Reference:An-coin Plan @49.2oeen(Innovation) 0.00 0.00 6023n 14985 57 15 70°28'24.717N la 4'43.404W Wellbore: MPB-33 NC Inj Cakulalion Method Minimum curvature j Plan: MPB-33 wp03 SURVEY PROGRAM GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference f h.(cor") .50 To 10933.30 Ladder/S.F. Plots Depth From Deptht To 016 Sursy/P n:00 Validn atel d:Yea Vernon:Version: CASING DETAILS 28.50 600.00 MPB-33 wp03 SRG-SS 600.00 5020.00 MPB-33 wp03 MWD+IFR2+MS*sag TVD TVDSS MD Size Name 5020.00 10933.30 MPB-33 wp03 MWD+IFR2+1AS+sa9 4417.20 4368.00 5020.36 9-5/8 95/8" 4399.20 4350.00 10933.30 4-1/2 4 1/2" c150.00 ..,,i!!1:01I M'12 •i.4. J j Ilf I_. �I �1,lit I 0120.00 Q 1 �JIi ci Ill 1,,' ! 1"' + 1 9 ih; 6 CO Ill , MPD-02A 90.00 .. 1;11; - II�II��: "- ilk 2 _ a) _ Ill�t/�l'l I �I� N 60.00 1 1I 27'trill PB-06 111 i IIIIIIIII v - j0 • 30.009 - 11, MPB-n i - 0.00 Ilii 1111111111111 1111 1111 illi 111111 . 11 1111 1111 1111 t1 1111 1111 1111 1111 111 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 10500 11250 12000 12750 Measured Depth(1500 usft/in) s.00 • 1 \-/ 4.50 Ilit . O t N LL c :..43.00Vilir / v a N co _-Collision Avoidance Rec. 1.50-No-Go Zone-Stop Drilling 0.00 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 III 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 Measured Depth • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-33 lnj -MPB-33 wp03 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-33 In)-MPB-33 NC In)-MPB-33 wp03 Scan Range: 0.00 to 10,933,30 usft.Measured Depth. Scan Radius is 1,290.68 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft M Pt B Pad MPB-02-MPB-02-MPB-02 26.50 30.55 26.50 29.74 23.30 37.966 Centre Distance Pass- MPB-02-MPB-02-MPB-02 275.00 31.10 275.00 28.27 271.71 10.999 Ellipse Separation Pass- MPB-02-MPB-02-MPB-02 525.00 41.91 525.00 36.61 521.32 7.913 Clearance Factor Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 50.00 30.55 50.00 29.67 46.79 34.927 Centre Distance Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 275.00 30.63 275.00 28.49 271.80 14.348 Ellipse Separation Pass- MPB-02-Plan MPB-02A-MPB-02Awp03 525.00 37.86 525.00 34.56 522.33 11.465 Clearance Factor Pass- MPB-03-MPB-03-MPB-03 26.50 241.94 26.50 241.24 35.98 344.299 Centre Distance Pass- MPB-03-MPB-03-MPB-03 625.00 243.65 625.00 236.23 633.16 32.826 Ellipse Separation Pass- MPB-03-MPB-03-MPB-03 3,925.00 686.50 3,925.00 636.78 3,961.83 13.806 Clearance Factor Pass- MPB-05-MPB-05-MPB-05 711.69 199.91 711.69 191.18 712.58 22.897 Centre Distance Pass- MPB-05-MPB-05-MPB-05 725.00 199.94 725.00 191.11 725.23 22.650 Ellipse Separation Pass- MPB-05-MPB-05-MPB-05 900.00 208.98 900.00 198.95 884.60 20.828 Clearance Factor Pass- MPB-05-MPB-05A-MPB-05A 711.69 199.91 711.69 191.18 712.58 22.897 Centre Distance Pass- MPB-05-MPB-05A-MPB-05A 725.00 199.94 725.00 191.11 725.23 22.650 Ellipse Separation Pass- MPB-05-MPB-05A-MPB-05A 900.00 208.98 900.00 198.95 884.60 20.828 Clearance Factor Pass- MPB-06-MPB-06-MPB-06 1,028.49 52.62 1,028.49 41.68 1,031.87 4.809 Ellipse Separation Pass- MPB-06-MPB-06-MPB-06 1,075.00 53.60 1,075.00 42.33 1,076.06 4.756 Clearance Factor Pass- MPB-08-MPB-08-MPB-08 6,592.72 367.18 6,592.72 124.02 5,299.90 1.510 Centre Distance Pass- MPB-08-MPB-08-MPB-08 6,625.00 367.98 6,625.00 122.46 5,320.91 1.499 Ellipse Separation Pass- MPB-08-MPB-08-MPB-08 6,650.00 369.68 6,650.00 123.01 5,337.09 1.499 Clearance Factor Pass- MPB-08-Plan MPB-08A-MPB-08A Wpb 6,592.72 367.18 6,592.72 124.17 5,314.00 1.511 Centre Distance Pass- MPB-08-Plan MPB-08A-MPB-08A Wpb 6,625.00 367.98 6,625.00 122.62 5,335.01 1.500 Ellipse Separation Pass- MPB-08-Plan MPB-08A-MPB-08A Wpb 6,650.00 369.68 6,650.00 123.17 5,351.19 1.500 Clearance Factor Pass- MPB-09-MPB-09-MPB-09 1,465.15 226.20 1,465.15 209.90 1,453.23 13.875 Centre Distance Pass- MPB-09-MPB-09-MPB-09 1,475.00 226.24 1,475.00 209.84 1,461.97 13.799 Ellipse Separation Pass- MPB-09-MPB-09-MPB-09 1,575.00 231.50 1,575.00 214.28 1,549.11 13.444 Clearance Factor Pass- MPB-10-MPB-10-MPB-10 738.21 199.22 738.21 192.46 732.86 29.476 Centre Distance Pass- MPB-10-MPB-10-MPB-t0 750.00 199.24 750.00 192.41 744.14 29.204 Ellipse Separation Pass- 24 October,2016- 18:50 Page 2 of 7 COMPASS 0 • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-33 lnj -MPB-33 wp03 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-33 In)-MPB-33 NC In)-MPB-33 wp03 Scan Range: 0.00 to 10,933.30 usft.Measured Depth. Scan Radius is 1,290.68 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-10-MPB-10-MPB-10 6,625.00 1,275.86 6,625.00 1,195.43 5,583.50 15.863 Clearance Factor Pass- MPB-it-MPB-11-MPB-11 2,768.80 216.15 2,768.80 189.46 2,730.97 8.101 Centre Distance Pass- MPB-11-MPB-11-MPB-11 5,200.00 263.06 5,200.00 125.13 4,869.27 1.907 Ellipse Separation Pass- MPB-11-MPB-11-MPB-11 5,225.00 266.80 5,225.00 126.29 4,887.57 1.899 Clearance Factor Pass- MPB-12-MPB-12-MPB-12 3,155.64 489.44 3,155.64 458.60 3,109.45 15.870 Centre Distance Pass- MPB-12-MPB-12-MPB-12 3,175.00 489.50 3,175.00 458.48 3,126.15 15.781 Ellipse Separation Pass- MPB-12-MPB-12-MPB-12 3,500.00 509.11 3,500.00 475.32 3,394.09 15.068 Clearance Factor Pass- MPB-13-MPB-13-MPB-13 1,712.39 292.40 1,712.39 273.30 1,737.52 15.310 Centre Distance Pass- MPB-13-MPB-13-MPB-13 1,725.00 292.49 1,725.00 273.19 1,747.70 15.153 Ellipse Separation Pass- MPB-13-MPB-13-MPB-13 1,850.00 303.14 1,850.00 282.03 1,844.17 14.360 Clearance Factor Pass- MPB-14-MPB-14-MPB-14 2,823.13 438.71 2,823.13 410.80 2,794.82 15.718 Centre Distance Pass- MPB-14-MPB-14-MPB-14 3,050.00 440.13 3,050.00 410.02 3,020.44 14.616 Ellipse Separation Pass- MPB-14-MPB-14-MPB-14 3,475.00 458.56 3,475.00 424.58 3,408.22 13.494 Clearance Factor Pass- MPB-15-MPB-15-MPB-15 1,206.46 196.68 1,206.46 186.77 1,225.38 19.839 Centre Distance Pass- MPB-15-MPB-15-MPB-15 1,225.00 196.80 1,225.00 186.76 1,243.01 19.609 Ellipse Separation Pass- MPB-15-MPB-15-MPB-15 1,375.00 206.74 1,375.00 195.72 1,383.15 18.761 Clearance Factor Pass- MPB-16-MPB-16-MPB-16 1,886.32 303.25 1,886.32 284.73 1,881.10 16.372 Centre Distance Pass- MPB-16-MPB-16-MPB-16 1,975.00 303.65 1,975.00 284.27 1,968.83 15.665 Ellipse Separation Pass- MPB-16-MPB-16-MPB-16 2,550.00 338.75 2,550.00 313.77 2,524.88 13.560 Clearance Factor Pass- MPB-17-MPB-17-MPB-17 130.18 139.14 130.18 137.27 134.48 74.257 Centre Distance Pass- MPB-17-MPB-17-MPB-17 275.00 140.08 275.00 136.48 278.38 38.939 Ellipse Separation Pass- MPB-17-MPB-17-MPB-17 1,275.00 233.15 1,275.00 220.15 1,272.02 17.938 Clearance Factor Pass- MPB-19-MPB-19-MPB-19 7,371.85 633.61 7,371.85 248.84 5,944.21 1.647 Centre Distance Pass- MPB-19-MPB-19-MPB-19 7,450.00 635.76 7,450.00 245.60 5,999.94 1.630 Ellipse Separation Pass- MPB-19-MPB-19-MPB-19 7,475.00 637.33 7,475.00 245.80 6,019.36 1.628 Clearance Factor Pass- MPB-20-MPB-20-MPB-20 3,855.42 143.22 3,855.42 96.33 3,924.16 3.054 Centre Distance Pass- MPB-20-MPB-20-MPB-20 3,875.00 144.25 3,875.00 96.14 3,934.97 2.998 Clearance Factor Pass- MPB-21-MPB-21-MPB-21 2,445.70 149.33 2,445.70 111.72 2,628.93 3.970 Centre Distance Pass- MPB-21-MPB-21-MPB-21 2,450.00 149.37 2,450.00 111.60 2,631.63 3.954 Ellipse Separation Pass- MPB-21-MPB-21-MPB-21 2,475.00 151.11 2,475.00 112.67 2,647.15 3.931 Clearance Factor Pass- 24 October,2016- 18:50 Page 3 of 7 COMPASS • • Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-33 Inj -MPB-33 wp03 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-33 Inj-MPB-33 NC Inj-MPB-33 wp03 Scan Range: 0.00 to 10,933.30 usft.Measured Depth. Scan Radius is 1,290.68 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft MPB-21-MPB-21PB1-MPB-21PB1 2,445.70 149.33 2,445.70 111.72 2,628.93 3.970 Centre Distance Pass- MPB-21-MPB-21PB1-MPB-21PB1 2,450.00 149.37 2,450.00 111.60 2,631.63 3.954 Ellipse Separation Pass- MPB-21-MPB-21PB1-MPB-21PB1 2,475.00 151.11 2,475,00 112.67 2,647.15 3.931 Clearance Factor Pass- MPB-22-MPB-22-MPB-22 1,140.23 120.37 1,140.23 107.69 1,171.09 9.494 Centre Distance Pass- MPB-22-MPB-22-MPB-22 1,150.00 120.42 1,150.00 107.62 1,180.34 9.406 Ellipse Separation Pass- MPB-22-MPB-22-MPB-22 1,250.00 126.27 1,250.00 112.15 1,274.56 8.944 Clearance Factor Pass- MPB-22-MPB-22A-MPB-22A 1,140.23 120.37 1,140.23 107.69 1,171.09 9.494 Centre Distance Pass- MPB-22-MPB-22A-MPB-22A 1,150.00 120.42 1,150.00 10762 1,180.34 9.406 Ellipse Separation Pass- MPB-22-MPB-22A-MPB-22A 1,250.00 126.27 1,250.00 112.15 1,274.56 8.944 Clearance Factor Pass- MPB-22-MPB-22APB1-MPB-22APB1 1,140.23 120.37 1,14023 107.69 1,171.09 9.494 Centre Distance Pass- MPB-22-MPB-22APB1-MPB-22APB1 1,150.00 120.42 1,150.00 107.62 1,180.34 9.406 Ellipse Separation Pass- MPB-22-MPB-22AP61-MPB-22APB1 1,250.00 126.27 1,250.00 112.15 1,274.56 8.944 Clearance Factor Pass- MPB-23-MPB-23-MPB-23 1,196.53 102.33 1,196.53 92.00 1,183.42 9.902 Centre Distance Pass- MPB-23-MPB-23-MPB-23 1,200.00 102.33 1,200.00 91.97 1,186.74 9.878 Ellipse Separation Pass- MPB-23-MPB-23-MPB-23 1,350.00 109.36 1,350.00 97.77 1,330.13 9.441 Clearance Factor Pass- MPB-25-MPB-25-MPB-25 100.00 170.56 100.00 169.39 104.60 146.220 Centre Distance Pass- MPB-25-MPB-25-MPB-25 225.00 170.93 225.00 168.93 228.55 85.522 Ellipse Separation Pass- MPB-25-MPB-25-MPB-25 1,550.00 338.31 1,550.00 327.51 1,490.92 31.331 Clearance Factor Pass- MPB-27-MPB-27-MPB-27 100.00 60.85 100.00 59.00 107.70 32.805 Centre Distance Pass- MPB-27-MPB-27-MPB-27 150.00 61.02 150.00 58.86 157.22 28.132 Ellipse Separation Pass- MPB-27-MPB-27-MPB-27 600.00 73.73 600.00 67.90 609.94 12.645 Clearance Factor Pass- MPB-28-MPB-28-MPB-28 26.50 200.55 26.50 199.48 34.39 187.257 Centre Distance Pass- MPB-28-MPB-28-MPB-28 175.00 201.23 175.00 199.07 180.59 93.045 Ellipse Separation Pass- MPB-28-MPB-28-MPB-28 900.00 288.20 900.00 278.67 884.14 30.233 Clearance Factor Pass- MPB-29-MPB-29-MPB-29 26.50 110.71 26.50 109.79 34.83 120.930 Centre Distance Pass- MPB-29-MPB-29-MPB-29 300.00 111.37 300.00 107.63 308.49 29.776 Ellipse Separation Pass- MPB-29-MPB-29-MPB-29 10,550.00 681.24 10,550.00 422.48 11,005.34 2.633 Clearance Factor Pass- MPB-50-MPB-50-MPB-50 890.63 285.10 890.63 278.20 918.15 41.315 Ellipse Separation Pass- MPB-50-MPB-50-MPB-50 1,950.00 455.18 1,950.00 440.22 1,922.16 30.429 Clearance Factor Pass- Plan:MPB-32 Prod-MPB-32 NC Prod-MPB-32 wp02 453.57 26.58 453.57 22.99 453.09 7.422 Ellipse Separation Pass- 24 October,2016- 18:50 Page 4 of 7 COMPASS • ! Hilcorp Energy Company HALLIBURTON Milne Point Anticollision Report for Plan: MPB-33 Inj -MPB-33 wp03 Closest Approach 30 Proximity Scan on Current Survey Data(Highside Reference) Reference Design: M Pt B Pad-Plan:MPB-33 In)-MPB-33 NC In)-MPB-33 wp03 Scan Range: 0.00 to 10,933.30 usft.Measured Depth. Scan Radius is 1,290.68 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Measured Minimum @Measured Ellipse @Measured Clearance Summary Based on Site Name Depth Distance Depth Separation Depth Factor Minimum Separation Warning Comparison Well Name-Wellbore Name-Design (usft) (usft) (usft) (usft) usft Plan:MPB-32 Prod-MPB-32 NC Prod-MPB-32 wp02 500.00 27.90 500.00 23.99 498.33 7.142 Clearance Factor Pass- MPtDPad a' 3 MPD-02-MPD-02A-MPD-02A •i 117k MIME 5,181.14 0.638 Ellipse Separation FAIL- MPD-02-MPD-02A-MPD-02A - 1411. =EAO - 5,193.80 0.635 Clearance Factor FAIL- MPD-02-MPD-02A-MPD-02A 1 IIID" WOO ® lir 5,203.10 0.760 Centre Distance FAIL- Survey fool program From To Survey/Plan Survey Tool (usft) (usft) 26.50 600.00 MPB-33 wp03 SRG-SS 600.00 5,020.00 MPB-33 wp03 MWD+IFR2+MS+sag 5,020.00 10,933.30 MPB-33 wp03 MWD+IFR2+MS+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 24 October,2016- 18:50 Page 5 of 7 COMPASS • • Schwartz, Guy L (DOA) From: Cody Dinger <cdinger@hilcorp.com> Sent: Thursday,January 05,2017 2:33 PM To: Luke Keller;Schwartz,Guy L(DOA) Cc: Bettis, Patricia K(DOA) Subject: RE: B-33 MPU injector. (PTD 216-164) Guy, See comments below based on our phone call. The NC sand is no more than 1-10' thick anywhere in the field. / All B Pad wells within the AOR have surface casing set below the bottom of the NC Sand and have cement across the NC sand. The MPD-02 was drilled to 8,300'then P&A'd with 3 cement plugs(7544'-8300',3900-4250',2634'-2800' MDs).There is /no cement across the NC sand(4,851' MD) in that wellbore. However the MPD-02A 8-1/2" open hole sidetrack, kicked ✓ off @ 2,634' MD, isolated the abandoned MPD-02 wellbore. 7" casing was run and cemented w/925 sks of Class G (cement across NC Sand based on calc.TOC @ "3,200' MD)followed by a downsqueeze of 400 sks of Coldset II and 180 bbls of Arctic Pack. I will use the format you sent me on the next one. Let me know if I can provide any further information. Thanks, Cody Dinger Hilcorp Alaska, LLC Drilling Technician cdinger@hilcorp.com Direct: 907-777-8389 From: Luke Keller Sent:Thursday,January 05,2017 6:53 AM To:'Schwartz,Guy L(DOA)'<guy.schwartz@alaska.gov>; Cody Dinger<cdinger@hilcorp.com> Cc: Bettis, Patricia K(DOA)<patricia.bettis@alaska.gov> Subject: RE: B-33 MPU injector. (PTD 216-164) Guy, Answers to your questions below in red. Sorry for the delayed reply on this... Cody—please give Guy a call to answer his question concerning the AOR. Luke 1 • • From: Schwartz, Guy L(DOA) [mailto:guv.schwartz@)alaska.gov] Sent: Tuesday, January 03, 2017 5:21 PM To: Luke Keller Cc: Bettis, Patricia K(DOA) Subject: B-33 MPU injector. (PTD 216-164) Luke, A couple of questions on this PTD: 1) The wellhead/tree sketch on page 40 does not appear to be correct. Your procedure indicates using a casing hanger mandrel where this looks like the casing is cut and slips set in the wellhead. Ne have begun to get away from the mandrel hangers due to pack-off issues encountered during the surface casing cement jobs. The base plan would be to install slip type hangers to alleviate this issue and allow for better cement jobs. Wording is fixed in attached drilling program. 2) On page 12 the diverter sketch shows the line exiting the rig at an odd place. Something happened with my autocad drawing... Diverter line did not move with the rig. It is fixed and also included in attached program. 3) In the anti collision data MPU D-02A is very close..what are your mitigation plans for this well while drilling by? MPU D-02A is a shut in Kuparuk producer. We will monitor drilling parameters and also monitor MWD for signs of interference while drilling. 4) ON the AOR chart you provided is the NC sand depth given the top of the formation? It is a little difficult to determine if there is cement across the NC sand on the offset wells the way you presented the data. Call me to discuss. II have Cody call you to discuss. He put the AOR together tor this well. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:'i his e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.00v). Hilcorp Energy Company's new address is 1111 Travis, Houston, TX 77002. 2 • • Bettis, Patricia K (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Monday, December 12, 2016 10:26 AM To: Bettis, Patricia K (DOA) Subject: RE: MPU B-33 (PTD 216-164): Permit to Drill Application Patricia, Sorry, I must have missed this email last week. No—we do not plan to pre-produce MPU B-33. Thank you for following up! Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Monday, December 12, 2016 10:23 AM To: Luke Keller Subject: FW: MPU B-33 (PTD 216-164): Permit to Drill Application Good morning Luke, Have you received this email? From: Bettis, Patricia K(DOA) Sent:Wednesday, December 07, 2016 3:07 PM To: Luke Keller(Ikeller@hilcorp.com) <Ikeller@hilcorp.com> Subject: MPU B-33 (PTD 216-164): Permit to Drill Application Good afternoon Luke, Quick question: Does Hilcorp plan to pre-produce the MPU B-33; and if so, for what duration? Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 1 Tel: (907)793-1238 • • CONFIDENTIALITY NOTICE:This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Patricia Bettis at(907)793-1238 or patricia.bettis(?alaska.gov. 2 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • • TRANSMITTAL LETTER CHECKLIST WELL NAME: /Th U. _B-33 PTD: 026 -161/ Development /Service _Exploratory Stratigraphic Test _Non-Conventional FIELD: ft/• 6/14.. fl n� POOL: 411J)0 P1J &A,1-510 Cr,/ Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. 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