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Home My WebLink About2018-11-21_318-518STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 NOV 2 1 2018 ,AOCCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑✓ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑J Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 218-109 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-029-23612-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O. 432D Will planned perforations require a spacing exception? Yes ❑ No Q MPU L-55 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025509 / ADL355017 Milne Point Field / Kuparuk Oil Pool 11 . PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12,079' 7,481' 11,907' 7,318' 3,394 N/A N/A Casing Length Size MD TVD Burst Collapse Conductor 80' 20" 80' 80' N/A N/A Surface 8,406' 9-5/8" 8,440' 4,759' 5,750psi 3,090psi Intermediate 11,432' 7" 11,464' 6,899' 7,240psi 5,410psi Liner 761' 4-1/2" 12,034' 7,438' 8,430psi 7,500psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): i See Schematic See Schematic 4-1/2" 12.6# / L-80 / TXP 11,281' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4.5" x 7" AHC & LTP Packers and N/A 11,139 MD/ 6,594 TVD & 11,273 MD / 6,719 TVD and N/A 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑Q Exploratory ❑ Stratigraphic ❑ Development Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 11/30/2018 OIL WINJ 11 WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. `�, Authorized Name: Bo York Contact Name: Taylor Wellman Authorized Title: Operations Manager Contact Email: twellmanOfticorip.com Contact Phone: 777-8449 2c�\`v Authorized Signature: Date: u COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: I I 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: l GI AvLdate Submit Form and Form 10-403 Revised 4/2017 Approved applicatios al ot of approval. Attachments in Duplicate November 21, 2018 Hollis S. French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RIE: Hydraulic Fracturing Application, Milne Point Unit, MP L-55 Dear Commissioner French, Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Paul Chan Senior Operations Engineer (907)777-8333 Hilcorp Alaska, LLC ("Hil_corp"), as Operator of the Milne Point T1nit, herein submits its application to fracture stimul-ate MP L-55. Please do not hesitate to contact Taylor Wellman at 907-777-8449 should you have any questions regarding this application. Sincerely, Bo, Operations Manager LCORP ALASKA, LLC Enclosures: Form 10-403 Sundry Attachments 20 AAC 25.283 (a)(1) Affidavit Affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided a notice of operations that is in compliance with 20 AAC 25.283 (a)(1) VERIFICATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MP L-55 I, PAUL CHAN, Hilcorp Alaska, LLC, ("Hilcorp") do hereby verify the following: I am acquainted with Hilcorp Alaska, LLC's application for sundry approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MP L-55 well via hydraulic fracturing. Pursuant to 20 AAC 25.283(a)(1), I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska, LLC's proposed operations. rd DATED at Anchorage, Alaska this 0O w day of N0V61_/Lgg&-7F_ 2018. Paul than, Sr."'Operations Engineer Hilcorp Alaska, LLC STATE OF ALAKSA THIRD JUDICIAL DISTRICT SUBSCRIBED TO AND SWORN before me this 2-63" day of 2018 STATE OF ALASXAA=.b NOTARY PUBLC NOTARY PUBLIC IN SND FOR MMVW W, Sehoet _ THE STATE OF ALSKA My Comm WW EViree Feb 28, 2MM My Commission expires: 20 AAC 25.283 (a)(2) A Plat (A) Showing The Well Location; (B) Identifying each Water Well, if any, Located within a One -Half Mile Radius of the Well's Surface Location; and TF-73AP61 ,F-57APB1 b F-62 I I `\ I ( I t /) / / �� F,89 / / �: 7 / 1 > tIi 1 IF_331 l J l /ll ! /(01 10 � V��as�sutA 4� it Di f L-2.1 AL355018 Sec`32 Sec.,I 31 L-,sb 0:14N01 DE ADL355017 (22) L -z4 �t r'♦,� 491 2 ,. C-4311 MPU L-55 BIT -t i ' If f / ( r — / IMPU L 55 FracZone L -16A L L-41PB1 \ •.� AV �� \ (�/Ili; ; / ,' i �L-051 ( / / 04j1�/ % t/ .♦ ( , '/ / f .M/ L-07 NIt -13 'i ` �� `;•; II� / E I +//f�/`� .' i .43PB1 Sec. 4 ri L-06 ` � � •� ,\\��\a� x}'(62.5;)' �! - �l� i i ► ;' ! � ! , % / a � ,#I 1MILNE' j / / c-17 POINT UNIT' / 0: F-82PB_1 F-21 PB.1 / a ADL047434 AW -0:2,5506 t L 03t WELLSYMBOL ` ` \ •; i\ t i / 1 DRY HOLE i \ Ar,• oz`F-21� y 1 / U013N010E l INJECTOR MPU L -55 -SHL 1 F=99 L-02APB2,•1 o2APM ,, i� f PLUG BACK F 9,9PB-1 r i` v / , r111 UX s >lr ,� L -02A 2, ,1 ,G36 OTHER ,Sec 7 L oza �L1.6Ac1 Y Sec.. 8� I I 10 OIL -ACTIVE (628)' /�� i % L:01A I ` 00 \ C OSA < Legend • MPU L-55 Surface Hole Location ��I�� 1/2 Mile Radius -Well Bore Oil and Gas Lease ®ADL315848 Ai3L315348 • MPU L-55 Top of Frac Zone �I,i 1/2 Mile Radius -Frac Zone - ADL025509 ®ADL355117 • MPU L-55 Base of Frac Zone Well Trajectory MPL-55 ADL025515 ® ADI -3550181 Sec. 16 10 — - Other Well Trajectories __; ADL047434 MPU L-55 Bottom Hole Location ?Pad Footprint J Milne Point Unit Petra Well Database- HAK MPL-55 Well MPL-55 Definitive SurveyT� Hikorp , Suit: L1�J 3800 Centerpoinl int Dr,Dr, Suite 1400 Plat depicting all Well types 0 1,000 2,000 YI Anchorage, AK, 99503 within 1/2 mile of MPL-55 Feet Map Dale: 11/20/2018 ADL355018 Sec. 31 (622) Legend i MPU L-55 Surface Hole Location • MPU L-55 Top of Frac Zone MPU L-55 Base of Frac Zone MPU L-55 Bottom Hole Location Well Trajectory MPL-55 Dioio 1/2 Mile Radius from SHL Pad Footprint NP L: F U014NO10E ADL355017 MPU L-55 BHL Sec. 32 . MPU L-55] I Frac Zone Sec. 6 Se c. 5 (625) j U013N01 i m MPU L-55�SHL` Sec. 7t ♦ (628) I Si=c�8 v � a ® � t � I MIILNE POINT UNIT Sec. 33 Sec. 4 AD L047434 Sec.9 Petra Well Database - HAK Milne Point Unit MPL-55 Definitive Survey MPL-55 Well No Water Wells Within 1/2 Mile tiilcorp A1 -k., fA,C N 3800 centerpolnt Dr, s,na 1400 Plat depicting no water wells 0 500 1,000 1,500 Anchorage, AK, 99503 g Feet Map Date 11/2W2018 within 1/2 mile of the MPL-55 SHL (C) Identifying for all Well Types each Well Penetration Well API PTD POOL Type Status MPL-01A 50029210680100 2030640 KR 1 -OIL Shut In MPL-02A 50029219980100 2091470 KR 1 -OIL Producing MPL-03 50029219990000 1900070 KR 1 -OIL Producing MPL-04 50029220290000 1900380 KR 1 -OIL Producing MPL-05 50029220300000 1900390 KR 1 -OIL Producing MPL-06 50029220030000 1900100 KR SUSP Suspended MPL-07 50029220280000 1900370 KR 1 -OIL Producing MPL-08 50029220740000 1901000 KR WAG Shut In MPL-09A 50029220750100 2131870 KR WAG Shut In MPL-10 50029220760000 1901020 KR WAG Shut In MPL-11 50029223360000 1930130 KR 1 -OIL Producing MPL-12 50029223340000 1930110 KR 1 -OIL Producing MPL-13 50029223350000 1930120 KR 1 -OIL Shut In MPL-14 50029224790000 1940680 KR 1 -OIL Producing MPL-15 50029224730000 1940620 KR WAG Injecting MPL-16A 50029225660100 1990900 KR WAG Injecting MPL-17 50029225390000 1941690 KR 1 -OIL Shut In MPL-20 50029227900000 1971360 KR 1 -OIL Shut In MPL-21 50029226290000 1951910 KR WAG Shut In MPL-24 50029225600000 1950700 KR WAG Shut In MPL-25 50029226210000 1951800 KR 1 -OIL Producing MPL-28A 50029228590100 1982470 KR 1 -OIL Producing MPL-29 50029225430000 1950090 KR 1 -OIL Producing MPL-32 50029227580000 1970650 KR WAG Shut In MPL-33 50029227740000 1971050 KR WAG Injecting MPL-34 50029227660000 1970800 KR SUSP Suspended MPL-35A 50029227680100 2011090 KR SUSP Suspended MPL-36 50029227940000 1971480 KR 1 -OIL Producing MPL-37A 50029228640100 1980560 SB 1 -OIL Shut In MPL-39 50029227860000 1971280 KR 1 -OIL Shut In MPL-40 50029228550000 1980100 KR 1 -OIL Producing MPL-41 50029236110000 2181040 KR 1 -OIL Producing MPL-42 50029228620000 1980180 KR WAG Shut In MPL-43 50029231900000 2032240 KR 1 -OIL Producing MPL-45 50029229130000 1981690 KR P&A P&A MPL-46 50029235510000 2151180 SB 1 -OIL Producing MPL-47 50029235500001 2151170 SB 1 -OIL Producing MPL-48 50029235520000 2151200 SB PWI Injecting MPL-49 50029235450000 2150990 SB PWI Shut In Well API PTD POOL Type Status MPL-50 50029235550000 2151320 SB PWI Injecting MPL-51 50029235870000 2171510 SB PWI Shut In MPL-52 50029235900000 2171740 SB PWI Shut In MPL-53 50029235860000 2171440 SB PWI Shut In MPL-54 50029236070000 2180660 SB 1 -OIL Producing MPL-56 50029236040000 2180500 SB 1 -OIL Producing MPL-57 50029236090000 2180720 SB 1 -OIL Producing 20 AAC 25.283 (a)(3) Identification of Freshwater Aquifers There are no underground sources of drinking water within a one-half mile radius of the current wellbore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exemption Order 2 (AEO-2). See the Conclusion of AEO-2, which states that "The portions of freshwater aquifers lying directly below Milne Point Unit qualify as exempt freshwater aquifers under 20 AAC 25.440." 20 AAC 25.283 (a)(4) Baseline Water Well Sampling There are no water wells located within one-half mile radius of the current wellbore trajectory. A water sampling program is not required. 20 AAC 25.283 (a)(5) Detailed Casing and Cementing Information 9-5/8" 40#/ft L-80 TXP-SR surface casing set at 8,440' MD with ESIPC (stage tool/ECP) at 2,765' MD. First stage cemented with 785 sxs / 329 bbls of ExtendaCem 12 ppg cement followed by 400 sxs / 82 bbls of 15.8 ppg Class G cement. Squeeze 56 bbls 15.8 ppg Class G cement through stage tool with no returns. Top job performed with 150 sxs / 115 bbls of 10.7 ppg PermaFrost L cement with cement returns to surface. 7" 26#/ft L-80 TXP-SR production casing shoe set at 11,463' MD and cemented. Pumped 40 bbls Clean Spacer III followed by 180 sxs / 37 bbls of 15.8 ppg Premium G cement with 88 — 94% losses during the job. Bumped plug and floats held. 4-1/2" 12.6#/ft L-80 TXP-SR production liner shoe set at 12,034' MD and cemented. Pumped 15 bbls 13.5 ppg Tuned Spacer followed by —130 sxs / 20 bbls of 15.8 ppg Premium G cement. Detailed Casing Information Size Type Wt/ Grade/ Conn Pipe Body Yield (Ibs) Collapse Pressure (psi) Internal Yield Pressure (psi) Conductor N/A N/A N/A N/A 9-5/8" Surface 40# / L-80 / TXP-SR 916,000 3,090 5,750 7" Production 26# / L-80 / TXP-SR 604,000 5,410 7,240 4-1/2" Liner 12.6# / L-80 / TXP-SR 288,000 7,500 8,430 Detailed Tubing Information 4-'/2" Tubing 12.6 / L-80 / TXP-SR 288,000 7,500 8,430 20 AAC 25.283 (a)(6) Assessment of Each Casing and Cementing Operation Performed to Construct or Repair the Well The 9-5/8" surface casing was set below the base of the Schrader Bluff sands. The first stage cement job was started by pumping 60 bbls of 10 ppg Clean Spacer with red dye followed by 785 sxs / 329 bbls of 12 ppg ExtendaCem lead cement and 400 sxs / 82 bbls of 15.8 ppg Premium G tail cement at 2 BPM. Displaced cement by pumping at 9 BPM until caught cement and then reduced rate to 3 BPM at 1900 strokes; Increased pump rate from 3 BPM (1900 strokes) to 8 BPM (3900 strokes); and then reduced rate to 6 BPM at 5800 strokes before bumping plug at 6015 strokes. Lost 114 bbls while displacing cement. Casing was rotated and reciprocated during the first stage cement job until the pipe became sticky 220 bbls into the job. Attempt to inflate the ESIPC and establish circulation without success for the second stage cement job. Squeeze 56 bbls 15.8 ppg Class G cement through stage tool with no returns. Close stage tool at 2,765' MD. Abort planned second stage cement job. RIH with 1.66" "spaghetti" string in the conductor x 9- 5/8" annulus to 589' MD. Performed top job with 150 sxs / 115 bbls of 10.1 ppg PermaFrost L cement with cement returns to surface. The 9-5/8" casing is adequately cemented. The 7" production casing was set in the Upper Kalubik formation and cemented. Pumped 40 bbls of 10.5 ppg Clean Spacer III followed by 180 sxs / 37 bbls of 15.8 ppg Premium G cement at 5 BPM rate before slowing down to 1 BPM as the pump pressure increased. 88% - 94% loss rate during the cement job. The 7" casing was not rotated or reciprocated during the cement job. Lift pressure may have been seen during cement job but is difficult to calculate due to the pressure increase seen during the cement job. Bumped plug and floats held. The 7" casing is adequately cemented. The 4-1/2" production liner shoe was set across the Kuparuk River formation and cemented with a single stage cement job. A 15 bbls 13.5 ppg Tuned Spacer was followed by —130 sxs / 20.0 bbls of 15.8 ppg Premium G cement at 2 BPM average rate. The liner was not rotated/reciprocated. Floats held. Bumped plug and attempt to set liner hanger. Liner hanger not holding. Mechanically release from liner hanger. No indication liner top packer set. POOH and test liner lap — liner lap did not test. RIH and set liner top packer with rotating dog sub. Pressure tested 4-1/2" liner lap to 3500 psi for 30 minutes. The 4-1/2" CBL/VDL log will be submitted after completing the logging run post -rig. 20 AAC 25.283 (a)(7) Plans to Pressure -Test the Casings and Tubing Installed in the Well The 9-5/8" casing pressure tested to 2500 psi for 30 minutes on October 31, 2018. The 7" casing pressure tested to 3500 psi for 30 minutes on November 15, 2018. The 4-%" liner pressure tested to 3500 psi for 10 minutes on November 15, 2018. The 4-%" tubing was pressure tested to 5000 psi for 30 minutes on November 19, 2018. The 4-1/2" x 7" annulus pressure tested to 3500 psi for 30 minutes on November 19, 2018 20 AAC 25.283 (a)(8) Pressure Ratings and Schematics for the Wellbore, Wellhead, BOPE, and Treating Head Size Weight #/ft Grade API Collapse Pressure (psi) API Internal Yield Pressure (psi) 9-5/8" 40 L-80 3,090 5,750 7" 26 L-80 5,410 7,240 4-1/2" 12.6 L-80 7,500 8,430 Treating Head 15M Wellhead 5M ROPE N/A Hileorp Alaska, LLC Orig. KB Elev.: 33.7'/ GL Elev.: 16.9 Shoe 12,034' TD =12,079' (MD) / TD = 7,481' (TVD) PBTD =11,907 (MD) / PBTD= 7,318' (TVD) Milne Point Unit Well: MPL-55 Last Completed: 11/17/18 PTD: 218-109 TREE & WELLHEAD Tree 5M 4-1/16" Wellhead I 5M FMC Gen IV OPEN HOLE / CEMENT DETAIL Conductor Driven 12-1/4" Stg 11,853 ft3/464 ft3, Stg 2 316 ft3, Top Job 650 ft3 9-7/8"x 8-1/2" 207 ft3 6-1/8" 112 ft3 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm BPF 20" Conductor 164 / A53B / Weld N/A Surface 80' N/A 9-5/8" Surface 40 / L-80 / TXP 8.835 Surface 8,440' 0.0758 7" Intermediate 26 / L-80 / TXP 6.276 Surface 11,464' 0.0383 4-1/2" Liner 12.6 / L-80 / TXP 3.958 11,273' 12,034' 0.0152 TUBING DETAIL 4-1/2" Tubing 12.6 / L-80 / TXP 1 3.958 1 Surface 1 11,281' 1 0.0152 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle 58 deg JEWELRY DETAIL No. Top MD Item ID 1 11,139' 4-1/2" x 7" AHC Packer (Cut to Release) 3.880 2 11,144' 4-1/2" XN Nipple - No-go = 3.725" 3.725 3 11,272' Mule Shoe— Bottom @ 11,281' 3.958 4 11,273' Liner Top Packer 4.340 GENERAL WELL INFO API : 50-029-23612-00-00 Cased by Doyon 14:11/13/2018 Revised By: TDF 11/20/2018 jjj OIL ' STATES Energy Services (Canada) Inc. Maximum Allowable Pumping Rates PROPOSAL: Casing Isolation Tool EMT CSG ID 2.280 .. 3,760 RATE m'/min 10 Wimin 112" Big Sore 1.760 2.760 6 m9/min _3 2 718" & 3 112" 1,438 2.380 4 m31min. 231811 1.000 '1.900 2 m'/min 3 1116 & 4 1116 with tapered mandrel 2.750 4.000 16 m3imin 4'1116 X Tool Mandrel 3.610 4.760 24 m'lmin OPEN POSMON VM9 ua, wVP4 V1Wk1V4) FA wuvttuo WID �mnsuRmw lr�' ! ,iiAVN�Ck WEM1�YNYF � } r am br, :. ,/MmmR VOIEIGEFO iFttrENf v.uns aotrc+ 15M Treating Head CLOSED POSITION tk%wnt wswfoj www.StingerCanada.com lMlN WEM1�YNYF +YEIUfiM� 1 } am br, h C« .i.. MND PACK r A{FEANt1 p �Ut�C Ml 1tAfNy Y www.StingerCanada.com 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B) the geological name of each zone; (C) the measured depth and true vertical depth of each zone; (D) the measured thickness and true vertical thickness of each zone; and (E) the estimated fracture pressure for each zone; The Kuparuk formation is a Cretaceous -aged, fine-grained marine sandstone. The productive Kuparuk interval in the L-55 area is made up of 5 sand members, whose top, base and true vertical thickness are listed in the table below. The estimated fracture gradient for the Kuparuk interval is 0.61-0.68 psi/ft. Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 KUP—C 11679 -7052 7102 8 Top Kuparuk C L-55 KUP_B6 11688 -7060 7110 78 Top Kuparuk B / Base Kuparuk C L-55 KUP_A3 11771 -7138 7188 19 Top Kuparuk A3 / Base Kuparuk B L-55 KUP A2 11791 -7157 7207 26 Top Kuparuk A2 / Base Kuparuk A3 L-55 KUP Al 11818 -7183 7233 55 Top Kuparuk Al / Base Kuparuk A2 L-55 KUP A BASE 11876 -7239 7289 Base Kuparuk Al The overlying confining zone consists of 2315' TVT of Kuparuk D, Kalubik, HRZ, and Colville siltstones and shales, whose top, base and true vertical thickness are listed in the table below. The estimated fracture gradient for the overlying confining zone is 0.75-0.82 psi/ft. Well Formation Depth MD Depth TVDSS Depth TVD True Vertical Thickness L-55 Colville 8499 -4737 4787 2016 Top Colville L-55 HRZ 11361 -6753 6803 18 Top HRZ/ Base Colville L-55 KLB 11381 -6771 6821 160 Top Kalubik/ Base HRZ L-55 KUP_D 11551 -6931 6981 121 Top Kuparuk D / Base Kalubik L-55 KUP_C 11679 -7052 7102 Top Kuparuk C / Base Kuparuk D The underlying confining zone consists of more than 2000 ft TVD of Milluveach shales. The top of the Milluveach shales is 11876' MD / 7289' TVD. The estimated fracture gradient for the Milluveach shales is 0.78-082 psi/ft. 20 AAC 25.283 (a)(10) The Location, the Orientation, and a Report on the Mechanical Condition of Each Well that May Transect the Confining Zones MP L-11: 7" casing set across the Kuparuk sands and cemented with 67 bbls / 302 sxs of 15.8 ppg Class G cement with partial returns during job. Bump plug and floats held. CBL log noted TOC low so the well was perforated and squeeze cemented at 10,992' MD with 135 sxs / 28 bbls of 15.8 ppg Class G cement. MP L-14: 7" casing set across the Kuparuk sands and cemented with 44 bbls / 215 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. MP L -16A: 4-1/2" liner set across the Kuparuk sands and cemented with 35 bbls of 15.8 ppg Class G cement. Bump plug with 3500 psi. Good cement from 11,900'— 13,345' PBTD from CBL. MP L-21: 7" casing set across the Kuparuk sands and cemented with 51 bbls / 250 sxs of 15.8 ppg Class G cement with 30% returns during job. Bump plug with 3500 psi. Estimated TOC from CBL is —12,000' M D. MP L-41PB: Cemented 4-1/2" liner. Unable to release from 4-1/2" liner. Commence plug back operations. Spot balanced plug inside 7" production casing and tagged at 9,590' MD. Pressure tested 7" casing and cement plug to 2000 psi. Set retainer set at 7,833' MD and tested good to 2000 psi. Cut and pull 7" casing down to 7,667' MD. Spot balanced cement plug from top of retainer at 7,883' MID to 7,267' MD. Note 9-5/8" casing shoe at 7,366' MD. Kick off well at 7,392' MD. MP L-41: 7" casing set across the Kuparuk sands. First stage cement job: 52.7 bbls / 255 sxs of 15.8 ppg Class G cement with 100% losses during the first stage cement job. 590 psi lift pressure observed during cement job. Second stage cement job: 34.1 bbls / 165 sxs of 15.8 ppg Class G cement with 100% losses. 300 psi lift pressure observed during cement job. 20 AAC 25.283 (a)(11) The Location of, Orientation of, and Geological Data for Each Known or Suspected Fault or Fracture that May Transect the Confining Zones L-21 -7,184 -a5 Jf_d .138 (7 -7 615'/� ► 1 uA r, 05 L -44tr 167 -71220 i 7 11 a 1200 ft L-07 -7,105 18 HILCORP ALASKA LLC AMilne POW KL9" Al S.4 seuw.na,a �ro:rcaaervass w.xt� eccvea wEu, a+,rn The map above shows the structure at the top of the Kuparuk A3 Sand interval. All faults shown are inferred from seismic data. The L-55 well is located at a distance between 610 - 920 ft from nearby faults. Horizontal principal stress from well data indicate that the fracture should propagate approximately NW -SE (SHmax is NW -SE, SHmin is NE -SW). Based on current mapping, the fracture wings should not extend into the nearby faults. 20 AAC 25.283 (a)(12) Proposed Hydraulic Fracturing Program 1. RU e -line and PCE. PT to 4000 psi (MPSP is 3394 psi / estimated Kuparuk River reservoir pressure). 2. Perforate the Kuparuk A sand formation from ±11,791 - ±11,796' MD. Final depths may be adjusted and be in either the Kuparuk A2 or A3 sands. 3. RDMO a -line. 4. MIRU frac fleet. MIRU frac and slop tanks. MIRU all ancillary support equipment. 5. Fill frac tanks with water. Heat water as needed. 6. Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. Monitor 7" x 4-1/2" annulus pressure during DFIT and fracture stimulation. RU flowmeter if performing forced closure on tank return line. 7. RU hardline from 9-5/8" x 7" annulus to tank and shall be left open to atmosphere during the stimulation job. 8. RU 15K tree saver and hard line. 9. Pressure test all high pressure treating lines to 8000 psi. 10. Set the GORV (gas operated relief valve) at ±7300 psi. Set the staggered pump kickouts between 6800 psi and 6400 psi. 11. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. 12. Prepare frac fleet to pump. 13. Pump Kuparuk A sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 14. Fracture stimulate Kuparuk A sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 15. Displace with freeze protect fluid. Underdisplace by ±3 bbls. Do not over displace. 16. Shut well in. Perform forced closure (optional) 17. RD tree saver. 18. MIRU CTU, portable test separator and associated equipment. 19. RU CTU BOPE and PT to 4000 psi. RIH and cleanout frac sand/frac fluid to PBTD. Flowback well to portable test separator with 2% KCI/NaCl kill weight brine and N2 as needed to clean up frac. 20. Sand back 4-1/2" liner to ±11,730' MD. 21. RU e -line and PCE. PT to 4000 psi. 22. Perforate the Kuparuk C sand formation from ±11,682 - ±11,687' MD. Final depths to be determined from OH logs. 23. RDMO a -line. 24. RU 15K tree saver and hard line. 25. Pressure test all high pressure treating lines to 8000 psi. 26. Set the GORV (gas operated relief valve) at ±7300 psi. Set the staggered pump kickouts between 6800 psi and 6400 psi. 27. Pressurize annulus to 3000 psi. Set annular PRV at 3500 psi. 28. Prepare frac fleet to pump. 29. Pump Kuparuk C sand DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 30. Fracture stimulate Kuparuk C sand with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule" for proposed design. 31. Displace with freeze protect fluid. Underdisplace by ±3 bbls. Do not over displace. 32. Shut well in. Perform forced closure (optional) 33. RD tree saver. 34. Contingency (Pending WO rig availability). MIRU CTU, portable test separator and associated equipment. 35. Contingency (Pending WO rig availability). RU CTU BOPE and PT to 3500 psi. RIH and cleanout frac sand/frac fluid to PBTD. Flowback well to portable test separator with 2% KCI/NaCl kill weight brine and N2 as needed to clean up frac. 36. Turn well over to operations. 20 AAC 25.283 (a)(12) (A) Estimated Total Volumes Planned 20 AAC 25.283 (a)(12) (B) Trade Name, Generic Name, and Purpose of each Base Fluid and Additive to be Used; 20 AAC 25.283 (a)(12) (C) Chemical Ingredient Name of, and the Chemical Abstracts Service (CAS) Registry Number Assigned to, each Base Fluid and Additive to be used; 20 AAC 25.283 (a)(12) (D) Estimated Weight or Volume of each Inert Substance, including a Proppant or other Substance injected OneStilli'm YF130FIexD,WF130,Y 105,546 Gal F125FlexD,WF125 Client: Hilcorp Alaska, LLC Well: MPU L-55 Basin/Field: _ Breaker State: Alaska County/Parish: North Slope Borough Case: 495.0 Lb Disclosure Type: Pre -Job Well Completed: 12/4/2018 Date Prepared: 11/16/2018 3:53 PM Report ID: RPT -58499 Additive F103 Description Surfactant 1.1 Gal/ 1000 Gal 115.0 Gal - �- _._._._.._.. __ Methanol _ Breaker 1.9 Lb / 1000 Gal 200.0 Lb - J475 _ -- Breaker _ _ 4.7 Lb / 1000 Gal 495.0 Lb J580 Gelling Agent 28.6 Lb / 1000 Gal 3,020.0 Lb _ J604 Crosslinker 2.1 Gal / 1000 Gal225.0 - _ Gal _ �L071 LTCA Clay Control Agent LTCA 2.1 Gal / 1000 Gal 1.6 Gal / 1000 Gal 225.0 Gal 165.0 Gal M002 M275 5526-1620 Additive Bactericide Propping Agent 1.2 Lb / 1000 Gal 0.5 Lb / 1000 Gal j varied concentrations 125.0 Lb 54.0 Lb 245,200.0 Lb The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. 66402-68-4 F,7 -AR -1 Water (Including Mix Water Supplied by Client)* Ceramic materials and wares, chemicals Guar gum _ 2-hvdroxv-N.N.N-trimethvlethanaminium chloride 1319-33-1Ulexite T -_- - < 0.1 % _ - ----- 67-56-1_------- �- _._._._.._.. __ Methanol < 0.1 % 7727-54-0 Diammonium peroxidisulphate <0.1 % 107-21-1 Ethylene Glycol < 0.1 % 68131-40-8 Alcohols, c11 -15 -secondary, ethoxylated <0.1 % 67-63-0 Propan-2-ol < 0.1 % 111-76-2 2-butoxyethanol -_ -� _--- ----_.-__<0.1 % ___--- - 34398-01-1 1310-73-2 1303-96-4 _-`.--_ _.- Ethoxylated C11 Alcohol Sodium hydroxide Sodium Tetraborate Decahydrate <0.1 % < 0.01 % 68131-39-5 Ethox lated Alcohol < 0.01 % 25038-72-6 Vinylidene chloride/methylacrylate copolymer < 0.01 % 25322-68-3_ Poly(oxy-1,2-ethanediyl),a-hydro-w-hydroxy- Ethane -1,2 -dial, ethoxylated _ < 0.01 % _ _ 91053-39-3 Diatomaceous earth, calcined - - < 0.01 % --- _ --_ 110-17_8 - _ but-2Tenedioicacid- -_ - _<0.01_% -_ 112-42-5 _ U_ndecanol__ _ < 0.01 % _ _ 7631-86-9 ----_ _ _ Non -crystalline silica (impurity) - --- _ - <0.00_1 % - --_ 10377-60-3 - - ---` Magnesium nitrate <0.001 % 26172-55-4 5-chloro-2-methyl- 2h-isothiazolol-3-one <0.001 % _ 7_786-30-3 14807-96-6 _ Magnesium chloride Magnesium silicate hydrate (talc) <0.001 % < 0.001 % - 125005-87-0 Diutan gum <0.001 595585-15-2 Diutan _< 0.001 % 9002-84-0 _ _ _ --_,-poly(tetrafluoroeth leve) - -_, <0.001 % _ - ---- 2682-20-4 2-methyl-2h-isothiazol-3-one <0.0001 % 14808-60-7 Quartz, Crystalline silica < 0.0001 % _ 14464-46-1 Cristobalite <0.0001 % 127-08-2__ Acetic acid, potassium salt <0.0001 % Acetic acid (impurity) Total <0.0001 % 100% *Mix water is supplied by the client. OneStim has performed no analysis of the water and cannot provide a breakdown of components that may have been added to the water by third -parties. *The evaluation of attached document Is performed based on the composition of the identified products to the extent that such compositional information was known to GRC-Chemicals as of the dote of the document was produced. Any new updates will not be reflected In this document. D OneStim 2018. Used by Hilcorp Alaska, LLC by permission. Page: 1 / 1 20 AAC 25.283 (a)(12) (E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Hydraulic Fracturing Program. The 4-% "production tubing tested to 5000 psi for 30 minutes, 4-% "production liner tested to 3500 psi for 10 minutes, and the 7" production casing tested to 3500 psi for 30 minutes prior to the fracture stimulation. The maximum surface differential pressure the tubing will be subjected to will be 4300 psi (7300 psi GORV maximum pressure setting - 3000 psi of pressure on the casing x tubing annulus). The calculated maximum treating pressure is 5,335 psi for the Kuparuk A sand and 4,943 psi for the Kuparuk C sand fracture stimulations. 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: Kuparuk A Sand: 11,791' MD / 7,207' TVD BKB Kuparuk C Sand: 11,679' MD / 7,101' TVD BKB (ii) a description of each method and assumption used to determine designed fracture height and length: The MP L-55 fracture stimulation was modeled using the FracCADE program. Kuparuk A Sand propped half length: 359.7' Kuparuk C Sand propped half length: 306.6' Note — The TVD depths in FracCADE are BKB. S0 KlAkIllmho" umulnuorclep FracCADE* STIMULATION PROPOSAL Operator Hilcorp Alaska Well MPL-55 Field Milne Point Formation KuparukA/e- WellLocation Milne Point County North Slope State Alaska Country United States Prepared for Almas Aitkulov Service Point Prudhna Bay Proposal No. 2 Business Phone Date Prepared 111-20-2018 FAX No. Prepared by Gunther Rutzinger Phone 907 273 1788 E -Mail Address grutzinger@slb.com *Mark of Dziclairner NcUe. This information is presented in good feii'Ji, but no warranty is given by and SWumbiarger assahmas no fiabZty for adince or recowneridinionis spade toniciersirg results to be obtained from the use of any produc, cr servics. The resuftsgivan are estimates based on ca9cui produced by a tonwurtaternDdel on tae "nell, reservc r and treatment" The resins depend vii input data provided by the Operator and estirr-wiss as to urAomm. 4m and can be no nvie aocuTate fRan the nndel, "E, assumptions and such input data. The information Presented is schlumbarger's best ssfimate of the atbal results that awry be arbiew-0 and sAwId be used for COMPBTS00, purposes rather than absolute values. The Quality of input data, and hence resuhs, may he improved through the use Of CaTonblLam TIM Procedufas vgtkh S&Nlanbeqar can assat in selecting. Tie Operator has superior knowledge of the wed, me reservoir, the field and conditions affect nig ftm. tf 1he Opwstcir is aware rf m- ccnill6crris%T4 c ftneby a wVlhborm weds might beaffected bythe treatment proposed Fricesquoted areestmatesonlyand are good for 30 days from the date of issue. Actual cfiargesnnq vary depanding u,,w imr eqx.;�rrem &M material ultmalsk zequirad up pe-fcrT these services. Freedom froin infringement of patents of S-, HLrnberger or others is not to be ir'arred. Schlumberger -Private Ckent Hi|corpAJaaka Well K8PL,55 Formation Kupar kA&C o|amct Prudhoe Bay Cv"mm United States Section 1: Zone Data SchlumhPlep Formation Mechanical Prope ies Zone Name Top TO (ft) Zone Height Fra c Grad. Insitu Stress Young's Modulus Poisson's Ratio Toughness (psiJnO.5) Kalubik 6820.8 160.1 0,784 5410 1.308E+6 0.35 2000 Kup D 6980.9 120.3 0.784 5520 1.847E+6 0.35 2000 Kup C 7101.2 8.5 0.660 4690 1.847E+6 0.25 800 Kup B6 7109.7 9.5 0,640 4553 1.733E+6 0.28 2000 Kup B 7119.1 11.4 0.660 4702 1.733E+6 0.28 2000 Kup B 7130.5 18.9 0.700 4998 1.729E+6 0.32 2000 Kup B 7149.4 26.5 0.720 5157 1.729E+6 0.32 2000 Kup B 71M9 12.3 0.750 5387 1 1,729E+6 1 0.32 2000 Kup A3 7188.2 10.5 0.610 4388 1.729E+6 0.25 2000 Kup A3 71983 8.5 0.700 5042 1.729E+6 0,25 2000 Kup A2 7207.2 11.4 0.610 4400 1.729E+6 0.28 2000 Kup A2 7218.6 14.3 0.700 5058 1.729E+6 0.32 2000 Kup All 7232.9 7.7 0.630 4559 1.729E+6 0.32 2000 Kup Al 7240.6 47.7 0.670 4867 1.729E+6 0,32 2000 Miluveach 7288.3 100.0 0.780 5724 4.494E+6 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) Net Height Perm (aid) Porosity Res. Pressure Gas Sat Oil Sat. N Water Sat. Kalubik 6820.8 1.0 0.001 1.0 3596 0.0 80.0 20.0 Kup 136 71093 9.4 30.000 10.0 3749 0.0 80.0 20.0 Kup A3 7188,2 10.4 40.000 210 3790 0.0 80.0 20.0 KupA3 7198.7 TO 5.000 22.0 3796 0.0 80.0 20.0 Kup A2 7207.2 11.4 40.000 22.0 3800 0.0 80.0 20.0 Kup All 7232.9 5.7 20.000 13.0 3814 0.0 80.0 20.0 Kup All 7240.6 15.0 1.000 13.0 3818 0.0 80.0 20.0 Miluveach 7288.3 1.0 0.001 1.0 3843 0.0 80.0 , 20.0 -,r Hilcorp Alaska Vjel : MPL-55 Forme i cn KLIPaTUK A& Diylrt, Prudhoe Bay RUA flame United States It I lt� L m0mr, (k m --- ON - gul Section 2: Propped Fracture Schedule — "A" Frac PoIrIff, 9 pilm, Schedule The 'I L !cw`ng is 1-e P,,imp,qg Sched7j�a to a pre. Aped, ffacture half-leng:h jXff) of 3593 ft-twith 8,0 amivrage cDrftict',,ity Krvv) of 7927 md.ft. Fluid Totalm Soo bbl Df Y -FE, I.Ie )eD, 173,bbl of WIRSO RrOppant Totals 127107 77 civr-b, o&n�d Lite I BiTO Pad'PIETCe,r,i,ta;ges % PAD Clean 22.2 PAD 10,irty 3 Schlumberger -Private Job Desvfip-.hDn Step N,E:T—n 8 Pump Rate !�t n 1;rT (ip) RUA flame Step flum W,4mme ON) Gel Ce ,.C. �,Wmgal) NOP. Type and Mash PFOP. CDnC. JPPA) PAD 35.0 YFI30FJex,,D 2DO.6 30.0 0.00 1.s0 PPA 311'0 Y-Fl-nR-Ex'D Im.10MID CBThD8;,ond Lite I&W 1.09 2." FPA 3D.10 YFIlIT"'ReAD 11@10 32JO Carter BDnd Lite IWZ) 209 3.2 PPA ZIO W11,13712XI) IOD.10 210.0 CaTboftnd Lfte IWZ) 3.09 4,0 PPA 3H IKF!1-3NIRi D, 11OU70 .7110 D'aft8and date ISM, 4.100 5.0 RPA 3016 YF13xD IWO 39.13 aBond Lite IWM 5.80 5:0 PRA 20.0 IV'FW3IT9ItP-m3 50.0 calbo&fld U'�,e W20 GOO 7Z PPA 30.10 X-0 Lite 16M TM 1H PPA 33.0 Carbr)Ron,,d Lite 116M &M J.,O PPA 30.10 'YFOORex"a mo 39.0 CaftBwd 'Lite IWM 9.09 1,10 PPA 30.10 YF13CReAD 2.0 30.0 Carba&md Lite 16//2,0 1 10.10 RIsh M.0 WFIZO 'I III 3C:2 2 1 am Fluid Totalm Soo bbl Df Y -FE, I.Ie )eD, 173,bbl of WIRSO RrOppant Totals 127107 77 civr-b, o&n�d Lite I BiTO Pad'PIETCe,r,i,ta;ges % PAD Clean 22.2 PAD 10,irty 3 Schlumberger -Private Client Hi|oorpA|auka Well MPL-55 Formation Kupor kA8C District Prudhoe Bay Country United States SAIMPIOP Schlumberger -Private Step Name Step Fluid Volume Cum. Fluid Volume (bbl) Ste p Slurry Volume Cum. Slurry Volume Ste p Prop (lb) Cum. Prnp. flb) Avq Surface pressure Step Time hin) Cum. Time (min) PAD 200.0 200.0 200.0 200,0 0 D 5251 5.7 53 1.0 PPA 100.0 30H 104.6 304.6 42M 420D 5274 3.5 9.2 2.0 PPA 1 OH 400.0 1091 41H 8400 1263,0 5220 3.6 12.8 3.0 PPA 100.0 500.0 1118 527,7 12603 25203 4792 18 16.6 4.0 PPA 100.0 60H 118.4 �45.1 16800 42CDO 4810 3.9 20.6 5.0 PPA 100.0 70M 11210 769,11 21000 8300 4347 4,1 24.7 6.0 PPA 50.0 750.0 63.8 B33,0 12600 7HOD 4889 21 26.8 7.0 PPA 50.0 800.0 66.1 8991 14700 90300 4,950 2.2 29.0 8.0 PPA 50.0 85H 68A _I 96T5 1BBOD I 071,DO 5053 1 2.3 1 31.3 9.0 PPA 25.0 875.0 35.4 10,02,9 S450 M550 5139 1.2 32.5 10.0 PPA 25.0 900.0 36.5 1039,4 1MO 127050 5211 1.2 33.7 Flush 173.1 1073,1 1711 1212,5 0 127M 4436 5.8 1 39.5 Schlumberger -Private Cbelit Hilcorp Alaska rJail MPL-55 schlumbepp, P Fbaration Kupardk A &,C Dimict Prudhoe Bay Cairivy United States Section 3: Propped Fracture Simulation Results — "A" Frac JI) ACLFracture Profile and PrDppanvCoin v3nITaIjoT.i PIDI HII.,p Ala- F.rac,CADE' MPL-55 KupAJA 11.20-2018 AOL Fracture Pmffle and Pmppa,t C—antrall— I (2) Treating Plot — Botionnhole Pres re ------ Surface Presque Total Inj. Rate ... ... EOJ 6000 40 50001..� ......... .. . ............ .... 130 4000 .................. ............ .. ....... . ..... .................. ................ ... ........... .. .. .... ... . ........ ................ ............. .... ... 120 3000 ... . .... ......... ................... . .... I ............. ................ ... .. .... .... .. ....................................... 10 1. ---------------------- 2000' .............. .......... ..... . ........ .. ................. ------- 1000 0 10 20 30 40 50 60 70 80 Treatment Time -min 5 Schlumberger -Private umvll Hi|corpA|aoko wmm � MPL��5 ��=��"��" Famrattw KupairlkA&C osmct Prudhoe Bay Country United States Section 4: Propped Fracture Simulation — "A" Frac The foflovving aire the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-0 VarticaY mcdaL Effective Conductivity and Effective Fcd are calculated based on perforatediflierva|avvdh pootixenot heights. Initial Fracture Top TVD ------------------------- 72O7.2 ft InibmFracture Bottom TO ----------------- �72Q8.Gft Propped Fracture Half -Length _- EQJHydBeightutVVo|L---- AvormgaPrmppodVVidth___—. Net Pressure ------------------------------ Efficiency ___------'Gfficiency --------EffmodvaFcd Max Surface Pressure ------ 359Jft 153.0 ft 0.164 in --------- 93Opsi --_0.525 --------- .l2380mdjt _--�� ---- 5335psi Simulation Results by Fracture Segment iF,rom To (ft) Prop. Conc. at End of Propped Width Propped Height Fra c. Prop. Frac Gel C on c. Fracture cDndurtivilty D'O 89.9 8.7 0.223 74.8 1.92 3010 11827 8,9.9 179.8 6.3 0.198 1203 1.76 351.1 9758 ��a�oObNi Pmmppantpacked ot35S r in step O client Hilcorp Alaska Welt MPL-55 Format on Kuparuk A& C ffistrict Prudhoe Bay country United States A -LF L 8111monp Schlumberger -Private Fracture Geometry Data Per Zone for Production Prediction Zone Name Top MD (ft) Top TVI) )ft') Gross Height )ft) Net Height Fracture Width (in) Fracture Length (ft) Fracture Conductivity (md.ft) Kalubik 11381.0 68203 160.1 1.0 0.000 .0 0 Kup D 11551.0 6.980.9 120.3 LO 0.000 .'0 0 Kup C 11679.0 7101.2 8.5 8.5 0.000 .0 0 Kup B6 11688.0 711093 M 9.4 0.000 .0 0 Kup B 11698.0 7119.1 11.4 9.0 0.000 .0 0 Kup B 11710,0 7130.5 18.9 6.0 '0.000 19.9 0 Kup B 11730.0 7149.4 26.5 8.0 0.013 141.8 651 Kup B 11758.0 7175,9 12.3 5.0 0.078 301.4 3671 Kup A3 11771.0 71882 10.5 10.4 0.193 340.9 9042 Kup A3 11782.0 7198.7 8.5 7.0 D.238 358.1 11072 Kup A2 11791.0 720.2 11.4 11.4 0.267 359.7 12390 Kup A2 11803.0 7218,.6 14.3 5,0 0.223 359.5 10301 Kup Al 11818.0 7232.9 7.7 5.7 0.227 353.5 10465 Kup Al 11826.0 7240.6 47.7 15.0 10.149 337.4 68713 Miluveach 11876.0 72883 100.0 1.0 0.020 236.9 974 Schlumberger -Private Client Hilcorp Alaska Well MPL-55 Formation Ku pariuk A& C Distr!c'. Prudhoe Bay Pump Rate (bbl/m4 United States schl'umbopp Section 5: Propped Fracture Schedule - "C" Frac Pumping Sch,,O u, I e The following is the Pumping Schedule to acNieve a propped fracture half-length (Xi) of 30H ft With sin avarage ronductiv4 (Kfw) of 8911 md.ft Fluid Totals 850 bbl of 'YIFI 25Raxl] 171 bbi of WF125 Proppant Totals 118700 lb of CarboBond Lite 116120 Pad Percentages ctl PAD Clean 17.6 % PAD Dirty 1153 Job Descripfilon Job Execution Step Name Pump Rate (bbl/m4 Fluid Name Step Fluid Volume (bbl) Bel,P Conc. (lb/m gal) Type and Mesh Prop. Conc. ffA) PAD 35.0 YF125RexD 11511.0 25,0 PAID HO 1.0 PPA 30.0 YF125Raxl) 159'0 2E0 Carbo&:md Lite16,,,420 1.`00 2.0 PPA 30.0 YF125FIexD 100.0 25.0 CarboBond Lite 16120 2.00 H PPA 30,0 YF125He)O 7.15.0 25.0 CarbuSond Lite 15120 3.00 4.0 PPA 30.0 YF125FIBXD 75.0 25.0 CarboBord Lite 16/20 13.2 5.0 PPA 30.0 YF125FIex51 75.0 25.0 Carbo&ond Lte'JIV,20 5.00 6.0 PPA 30.0 YF125FIexD 75.0 25.0 CarbriBond Lite 16129 6.00 7.0 PPA 30.0 YFI25RexD 75.0 25,0 CarboBond Jbite 16120 TO 8.0 PPA 30.0 1 YFI25RexD 75;0 1 25.,,0 CarboBond Lite 116120 1 HO Flush 310 1 WF125 171,4 1 25.0 95,7 1 D.00 Fluid Totals 850 bbl of 'YIFI 25Raxl] 171 bbi of WF125 Proppant Totals 118700 lb of CarboBond Lite 116120 Pad Percentages ctl PAD Clean 17.6 % PAD Dirty 1153 Schlumberger -Private Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry volurn, e Ibbl) cum Slurry VDIurne (bbl) Step Prop )lb) cum. Prop- jib) Avg. SuffUB PTeSSUTS (,psi) Step Tine (min) Cum. Time IminI PAID 150.0 150.0 150.0 150.0 0 '0 4907 4,3 43 1.0 PPA 150.0 32,10 156.9 306.9 6300 6300 4932 5,2 9.5 2.0 PPA 100"0 4009.00 109.2 416.1 8400 1 14700 4551 16 13.2 3.0 PFA 75.0 475.0 85.4 501,5 9450 24150 4402 2,8 16.0 4.0 PPA 75.0 550.0 98.8 5903 12600 36759 4328 3.0 19.0 5.0 PPA 75.0 625.0 92,3 6816 15750 52500 4330 3.1 22.0 6.0 PPA 75.0 700.0 95,7 779,3 18900 71400 4382 12 25.2 M PPA 75.0 775.0 99.2 877.5 22050 '93450 4470 3.3 28.5 &0 PPA 75.0 850.0 1023 M.2 25200 118650 1 4590 3.4 32,0 Flush 171.4 1021.4 171.4 1151,6 0 118650 1 4176 5.7 37.7 Schlumberger -Private C9eTtt Hilcorp Alaska l "Well MPL-55 Ylh { ge! Foraa;atiwi Kuparuk A& c Dlstfict Prudhoe Bay countal United States Section 6: Propped Fracture Simulation Results — "C" Frac 19) ACL Fracture Profile anal Proppant Comentraborl Piot FTazCAD MPL-HilW sAln9a KupC JA 1120-2018 ACL Fracture Profile and P,ppant Concentration -0.0 Ib/ft2 M 0.0-0.5 IN42 0.5 -1.1 Ib/02 1.1 - i.b lb'02 1.6-2.216"'2 2.2-21IbM2 � 2.7 -3.3122 M 3.3-3.616/ft2 3.6-4A IN02 14.41bIR2 1-- p''I rrvLViFfF&a rtli'/t.KY:'i«:-3,.r F—c WN -91h-11 12) Treatinrg Plat Eottomhole Pressure ------ Surface Pressure ..""" Total Inj. Rate ....... EOJ Mid'. 0 10 20 30 40 50 60 70 80 90 100 110 120 130 14 Treatment Time -min 9 Schlumberger -Private Client Hilcorp Alaska Well MPL-55 Formation Kuparuk A&C District Prudhoe Bay Country United States Section 7: Propped Fracture Simulation — "C" Frac schInkplep The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD------------------------- 7101.2 ft Initial Fracture Bottom TVO-------------------- 7109.7 ft Propped Fracture Half -Length ---------------- 306.6ft EOJ Hyd Height at Weil ----------- -------------- 162.6 ft Average Propped Width ---------------- -------- 0.220 in Net Pressure---------------------------------------- 1052 psi Efficiency-------------------------------- ------------ 0.573 Effective Conductivity_ --------_ ...............11086 md.ft Effective Fed -----------------------------------------7.2 0.363 Max Surface Pressure --------------------- ----- 4943 psi Simulation Results by Fractilre Segment From (ft) To (ft) Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (Ib/ft2) Frac. Gel Cone. (lb/rngal) Fracture Conductivity (md.ft) 0.0 76.7 6.6 0.363 121,2 3.21 237.6 16395 76.7 1 153.3 5.2 0.256 95.3 2.22 322.2 12412 153.3 230.0 4.2 0.205 78.4 1.82 387.1 75D4 230.0 306.6 1.6 0.071 62.1 0.58 728.1 20'33 Proppant bridged at 299 ft after 74 bbl in step 3 10 Schlumberger -Private Can ' Hi|oo/pAJaoka We�l MPL,55 Formation KuparukA@C District Prudhoe Bay Country United States 1I Schlumberger -Private Fracture GeometryData Per Zone for PrDduclion FiredictiDn Zone Name Top MID �ft� Top TVD Gross Height N at Maight Firact.,u re Width fra"C'U've Length fracture Conductivity up 19 11551..o MIM 1203 1.0 2..116 2641 4377 KUP 86 1111888,C) 71 C9,.7 9.5 R A DM7 M5 14423 Kup 6 111710.0 71130.5 M9 &0 0-392 3016,16 11367 Kup B 11117 3,0.0 7149.4 26,5 8-0 0.167 263,7 Kup B 111759.0 71759 12-3 5.0 ain-"o 99.9 2668 Kup A3 111771.0 71 S&I M.5 I'DA C.P38 48.0 1740 Kup A2 11791.0 7207.2 1 L4 11A "0 Kup A2 118010 72TZ6 143 5.0 ID Kup Al 11818,0 723Z9 7.7 5.7 .0 0 Mfluvearh 11876,0 1 72a,.3 100.0 1.0 am 1I Schlumberger -Private 20 AAC 25.283 (a)(13) Description of the Plan for Post -Fracture Wellbore Cleanup and Fluid Recovery through to Production Operations The well will be cleaned up through a portable separation system before turning the well over to Production. Initial returns will be taken to the permitted Milne Point G&I facility for disposal. <19§k4 Z �'I a a m fL a STANDARD WELL PROCEDURE IlileorpAlaska, LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre -Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4 -gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1