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Home My WebLink About213-199Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Wednesday, March 01, 2017 1:28 PM To: Luke Keller Cc: Schwartz, Guy L (DOA); Bettis, Patricia K (DOA) Subject: PTD 213-199, Granite Point St 18742 37A Hello Luke, Permit to Drill 213-199, for Granite Point St 18742 37A, issued 31 December 2013, has expired under Regulation 20 AAC 25.005 . The PTD will be marked expired in the AOGCC database. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. THE STATE o1A .1 1. LASKA GOVERNOR SEAN PARNELL Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Alaska Oil and Gas r:.lt14,..1'��•tl'�li 1 .$1�1` 131 �ii1�11 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276,7542 Re: Granite Point Field, Hemlock Undefined Oil Pool, Granite PT ST 18742 37A (AN 37A) Hilcorp Alaska, LLC Permit No: 213-199 Surface Location: 789' FNL, 601' FEL, SEC. 12, T1ON, R12W, SM, AK Bottomhole Location: 2288' FNL, 1116' FEL, SEC. 1, T1ON, R12W, SM, AK Dear Mr. Keller: Enclosed is the approved application for permit to re -drill the above referenced development 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 a AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, G Cathy P Foerster Chair S� DATED this day of December, 2013. RECEIVED DEC 20 2013 STATE OF ALASKA A jKA OIL AND GAS CONSERVATION COMM ON PERMIT TO DRILL 20 AAC 25.005 l v� n (**, 1a. Type of Work: Drill ❑ Lateral ❑ Redrill ❑✓ • Reentry ElExploratory 1 b. Proposed Well Class: Development -Oil ❑✓ • Service - Winj ❑ Single Zone ❑ Stratigraphic Test ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ El Service - WAG ❑ Service - Disp El 1c. Specify if well is proposed for: Coalbed Gas ❑ Gas Hydrates ❑❑ Geothermal ❑ Shale Gas 2. Operator Name: Hilcorp Alaska, LLC 5. Bond: Blanket ❑ Single Well ❑ Bond No. 02235244, 11. Well Name and Number: Granite PT ST 18742 37A (AN-37A) , 3. Address: 3800 Centerpoint Drive, Suite 100, Anchorage, AK 99503 6. Proposed Depth: MD: 13,500' TVD: 11 ,685' • 12. Field/Pool(s): Granite Point bIrnY Hemlock 9441eef II 41JA � �' 1 4a. Location of Well (Governmental Section): Surface: 789' FNL, 601' FEL, Sec 12, T10N, R12W, SM, AK Top of Productive Horizon: 1357' FSL, 6' FWL, Sec 6, T1ON, R11 W, SM, AK Total Depth: 2288' FNL, 1116' FEL, Sec 1, T10N, R12W, SM, AK 7. Property Designation (Lease Number): ADLO18742 Cook Inlet Basin, GP, Anna, Offshore 8. Land Use Permit: NA 13. Approximate Spud Date: 1/26/2014 9. Acres in Property: 5060 - 14. Distance to Nearest Property: 1373.00 4b. Location of Well (State Base Plane Coordinates - NAD 27): Surface: x-266849.467 y-2551352.254 Zone-4 10. KB Elevation above MSL: 4-2+ lal feet GL Elevation above MSL:N/A feet 15. Distance to Nearest Well Open to Same Pool: 5218' 16. Deviated wells: Kickoff depth: 2500 feet Maximum Hole Angle: 67.97 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 7000 , Surface: 3898 - 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 12 1/4 9 5/8 47 I-80 DWC/C 9,200' Surf Surf 9,200' 8,933' See below 12 1/4 9 5/8 47 P-110 DWC/C 1,400' 9,200' 8,933' 10,600' 10,218' 558.5 bbl / 3135 ft3 /&- 8 1/2 7 29 P-110 DWC/C 3,100' 10,400' 10,058' 13,500' 11,684' 117.9 bbl / 662ft3 / 497 sks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Structural 268' 30", 320#, Weld Driven 268' 268' Conductor 571' 20", 133#, K55 1308 sx 615' 615' Surface 3,522' 13-3/8", 68#, N80 2543 sx 3,522' 3,266' Intermediate 10,150' 9 5/8", 53.5#, N80 1250 sx 10,150' 9,389' Production 790' 7 5/8", 39#, C95 300 sx 10,687' 9,886' Liner 1,204' 5", 18#, L80 768 sx 11,644' 10,804' Perforation Depth MD (ft): Please see Operational Shutdown Schematic Perforation Depth TVD (ft): Please see Operational Shutdown Schematic 20. Attachments: Property Plat ❑ 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 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Email Printed Name Luke Keller Title Drilling Engineer Signature Phone 907- 777-8395 Date 12/20/2013 Commission Use Only Permit to Dri p Number: n 13 d CJ r API Number: Sp -� - a�3� y -01 — 01O 733 2�394-@1 Permit Appro a Date: �\ \� See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed meth ne, gas hydrates, or gas contained in shales[✓ Other: OpO �� ; L //Z �L tiQN0Samples req'd: Yes ❑ No� Mud log req'd: Ye❑ N© 3 �� 7 C"/ HZS measures: Yes ❑ No� Directional svy req'd: Ye[j N❑ (L?5"0gP cing exception req'd: Yes ❑ Noy Inclination -only svy req'd: Ye❑ No APPROVED BY Approved bya4. —_ COMMISSIONER THE COMMISSION Date: i2 5S rlk6 4_6A-U{ib �Z" 3a j JJ Submit Form and Form 10-401 evised 10/2012) Thi()rRiyvGi f jrRqo th[ from the date of approval AAC 25.005(g)) Attachments in Duplicate Hilcorp Energy Company 12/20/2013 Luke Keller Drilling Engineer Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Granite PT ST 18742 37A (AN-37A) Dear Commissioner, Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8369 Email Ikeller@hilcorp.com REC DEC 2p 20 AOGCC Enclosed for review and approval is the 10-401 "Permit to Drill" for the Granite PT ST 18742 37A (AN- 37A). This well is a "re -drill" of the Granite PT ST 18742 37 (AN-37) wellbore. AN-37A is a development oil well planned to be re -drilled in a Northerly direction from leg #2 (East Corner), Slot #8 utilizing the existing casing program down to 2500' MD. The base plan is to sidetrack the well out of the 12-1/4" window cut in the 13-3/8" casing at 2500' MD. The 12-1/4" hole section will be drilled to 10,600' MD / 10,218' TVD and a string of 9-5/8" casing will be set. An 8-1/2" hole section will be drilled to TD at 13,500' MD / 11,685' TVD and a 7" production liner run and cemented. The well will be completed with a dual string of 3-1/2" production tubing. Drilling operations are expected to commence immediately following the slot recovery operations. Slot recovery operations are expected to begin 1-5-2014 and forecasted to last approx 21 days. Operations conducted during the slot recovery of Anna #37: 1. Kill well, Remove tree, N/U & test BOP. — 3oao (5; 2. Pull 3-1/2" kill string. 3. P&A wellbore with cement. p,P 4. Set & test CIBP at 3650' MD. �vs 5. Cut and pull 9-5/8" casing to 2500' MD. �6. Clean out run with 12-1/4" clean out assy. 7. Run and set Whipstock, mill 12-1/4" window at 2500', FIT to 12ppg. General sequence of operations pertaining to this 10-401 APD: 1. Drill 12-1/4" hole section to 10,600' MD utilizing a 2%KCl/Clayseal/GEM drilling fluid system at 9.2 to 9.6 ppg. Obtain LWD logging data. 2. Run and cement 9-5/8" production casing. ---V- TS f" f-?a ►'O - .5--010 w 5" 3. Test 9-5/8" casing to 4000 psi / 30 min. Drill out & conduct FIT to 15 ppg. 4. Drill 8-1/2" hole section to 13,500' MD. 5. Run and cement 7" production liner. 6. TIH w/ clean out assy. Clean out to landing collar and displace to filtered inlet water. A separate Completion program will be submitted that includes: 1. RIH w/ TCP assy, perforate well. 2. Run dual string 3-1/2" production tubing. Install BPV. 3. N/D BOP, N/U Tree. 4. Produce well. Hilcorp Alaska, LLC Page 1 of 2 Pursuant to 20 AAC 25.055(a)(3), a spacing exception is not required to produce Anna 37A. 1. The Anna 37A will be the only Hemlock well capable of producing in the SE quarter section of section 12. 2. The Hemlock perforations are more than 500' (1,631') from nearest lease line. 3. Hemlock perforations are more than 1,000' (3,554') from a well (GP 11-13RD) producing from the Hemlock. A map is included at the end of the drilling program that depicts all adjacent Hemlock penetrations. Pursuant to 20 AAC 25.005 (c) & (d), the following is included: 1. Diagram & description of blowout prevention equipment. 2. Information on drilling hazards. a. The Tyonek & Hemlock are potential hydrocarbon bearing throughout the section. MASP calculations are attached per 20 AAC 25.005 (c)(4)(A) b. Potential target reservoirs and their predicted pore pressures are indicated in attached Drilling Program. 3. Formation integrity test procedure. 4. Planned casing & cement program is included in at!�ched Drilling Program. 5. Diverter system will not be used. 13-5/8" 5M BOP equipment will be used throughout the f well program. 6. Drilling fluid program 7. Tabulation of predicted depths with equivalent formation pressures. 8. Requirements of 20 AAC 25.025 have been met. a. Blanket bond issued for the inlet, bond no. 22035244. 9. Copy of Drilling Program attached. 10. General description of waste disposal. Operator does not wish to request authorization under 20 AAC 25.080 for an annular disposal operation in the well. a. Qualified drilling waste will be discharged in accordance with NPDES permit AKG-31-5019. 11. Requirements of 20 AAC 25.050(b) have been met. a. Plat showing path of proposed wellbore including all adjacent wellbores within 200' is attached. b. All wellbores within 200' of proposed wellbore are owned by Hilcorp. 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 2 of 2 Po0 to Sea Lr el (MLW) =127 KE3 33.4 it 'j 29' @ 613' a 33S0 133/8 - 352Z - ' 2 16' 1✓Tool .. CMr BSKr 35,B'-10,159 1g4t9 A 7&8'-19,68T C-5 Tap of RI 11,25Z C-7 C-7 5"- 11 614" PBTD=11,575' TD=11,741' MAX HOLE ANGLE = 31 C& 8200' DOGLEGS: 4.1"@ 1400' Size Type WT Grade CONN ID Top BTM Hole Size Cement Sacks Top Top 30" Structural 320 STIR Weld Surf 268' Driven 20" Conductor 133 X56 19" 44' 615 26" 1308 sx Surf 13-3/8 Sur Pipe 68 N80 Buttress 12.415 Surf 3522' 17.5" 2543 sx Surf 9-5/8 Sur CSG 53.5 N80 Buttress 8.535 Surf 10,150' 1 12.25" 1 1250 sx 7-5/8 CSG 39 C-95 FL4S 6.625 9897' 10,687' 8.5" 300 sx 5 Liner 18 L80 Buttress 4.276 1 10,440 11,644' 7" 768 sx 3.5" Plastic Coated Tubing Tubing 9.2 L80 Buttress 2.942 Surf 5814' # Depth ID Jewelry Description Approximate Depths 1 33.40' Hanger 2 34.4' 2.942 5814' 3-1/2" N80 9.2# Buttress Kill String" 3 DATE INTERVAL MD INTERVAL TVD DESCRIPTION ZONE 03/14/88 11225' - 11237' 10,398' - 10,477' 3.375" 4 SPF @ 90D, 48 C-7 11,307 - 11346 10,477' - 10,515' 3.375" 4 SPF @ 90D 156 C-7 11,380' - 11,446' 10,548' - 9,913' 3.375" 4SPF @ 90D 164 C-7 05/04/88 10,716' - 10,784' 9,913' - 9,977' 3.375" 4 -.500 SPF @ 90D 272 C-5 10,798' - 10,882" 9,991' - 10,070' 3.375" 4 -.500 SPF @ 90D 336 C-5 08/31/96 10,714' - 10,784' 9,911' - 9,977' 2-1/8" Enerjet @ 6 SPF @ 90D C-5 10,798 - 10,882' 9,991' - 10,070' 2-1/8" Enerjet @ 6 SPF @ 90D C-5 11,076' - 11,091' 10,254' - 10,269' 2-1/8" Enerjet @ 6 SPF @ 90D C-6 11,154' - 11,176' 10,329' - 10,351' 2-1/8" Enerjet @ 6 SPF @ 90D C-7 11,225' - 11,236' 10,398' - 10,409' 2-1/8" Enerjet @ 6 SPF @ 90D C-7 Fish In Hole A. 11,282' APRS Jet Cutter String Inside 2-7/8" Tubing (Fish Length = 199.48) GHOST: 10,787': BHA Assembly: 192' Fish, off of side track bore WBD An-37 6 27 2008 Kill String Page 1 of 1 JRN 6 27 2008 Hilcorp Alaska, LLC Anna 37A Drilling Program Anna Platform Rig 428 Granite Point Field Revision 0 Dec 16t", 2013 Contents Anna #37A Drilling & Completion Procedure 1.0 Well Summary.................................................................................................................................2 2.0 Tubular Program: ........................................................................................................................... 3 3.0 Internal Reporting Requirements..................................................................................................4 4.0 Planned Wellbore Schematic..........................................................................................................5 5.0 Drilling / Completion Summary.....................................................................................................6 6.0 Mandatory Regulatory Compliance / Notifications.....................................................................7 7.0 Drilling 12-1/4" Hole Section..........................................................................................................9 8.0 Running 9-5/8" Production Casing..............................................................................................15 9.0 Cement 9-5/8" Casing...................................................................................................................18 10.0 Drilling 8-1/2" Hole Section..........................................................................................................21 11.0 Running 7" Production Liner......................................................................................................25 12.0 Cementing 7" Production Liner...................................................................................................28 13.0 Wellbore Clean Up & Displacement............................................................................................31 14.0 Complete well................................................................................................................................32 15.0 BOP Schematic..............................................................................................................................33 16.0 Wellhead Schematic......................................................................................................................34 17.0 Days Vs Depth...............................................................................................................................35 18.0 Geo-Prog........................................................................................................................................36 19.0 Formation Tops/ Pressures...........................................................................................................37 20.0 Anticipated Drlg Hazards.............................................................................................................38 21.0 FIT Procedure...............................................................................................................................39 22.0 Choke Manifold Schematic..........................................................................................................40 23.0 Casing Design Information...........................................................................................................41 24.0 12-1/4" Hole Section MASP..........................................................................................................42 25.0 8-1/2" Hole Section MASP............................................................................................................43 26.0 Directional Program (P4).............................................................................................................44 27.0 Directional Plan View(XY)..........................................................................................................47 28.0 Plan View (VS / TVD)...................................................................................................................48 29.0 Spider Plot (Governmental Sections)..........................................................................................49 30.0 Offset MWs vs TVD plots.............................................................................................................50 31.0 Anti -Collision Calculations...........................................................................................................51 32.0 5-1/2" Drill Pipe Specifications....................................................................................................58 Anna #37A Drilling & Completion Procedure 1.0 Well Summary Well Granite PT ST 18742 37 (AN-37A) Anna Leg & Slot designation Leg #2 (East Corner), Slot #8 Planned Completion Type: Dual 3-1/2" production tubing Target Reservoir (s): Hemlock Oil Pool ✓ Planned Well TD, MD / TVD: 13,500' MD / 11,685' TVD PBTD, MD / TVD: 13,400' MD / 11,647' TVD Surface Location (Governmental) 789' FNL, 601' FEL, Sec 12, T10N, R12W, SM, AK Surface Location (NAD 27) X= 266849, Y= 2551352 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 1357' FSL, 6' FWL, Sec 6, T10N, RI 1 W, SM, AK TPH Location (NAD 27) X=267499, Y=2553486 TPH Location (NAD 83) BHL (Governmental) 2288' FNL, 11 16'FEL, Sec 1, T10N, R12W, SM, AK BHL (NAD 27) X= 266410, Y= 2555143 BHL (NAD 83) PTD # TBD API Number 50-733-20394-01 AFE Number TBD AFE Drilling Days 32 Days from Spud AFE Completion Days 11 Days AFE Drilling Amount $11,100,566 AFE Completion Amount $2,452,400 Work String: 5-1/2" 24.7# 5-135 HT-55 (Rental string from Weatherford) RKB — MSL: 121' AMSL RKB — THF: 43' Water Depth 71' Drilling Contractor/Rig Name: Inlet Drilling / Rig 428 Page 2 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 2.0 Tubular Program: { Hole Section OD (in) ID (in) Drift in Conn OD (in) Wt #( /ft)(psi)(psi) Grade Conn Burst Collapse Tension k-Ibs 12-1/4" 9-5/8" 8.681" 8.525 10.625 47 L-80 DWCHT/C 6870�` 4760 1086 12-1/4" 9-5/8" 8.681" 8.525 10.625 47 P-110 DWCHT/C 9440 5300 1493 8-1/2" 7" 6.184" 6.059 7.656 29 P-110 DWC/C HT 11220 8530 929 Drill Pipe Information: Hole Section O !D n) ID (in) TJ ID in)_ TJ OD in Wt #/ft Grade : _ .,.. ,... Conn ....:._ _(psi) Burst Collapse (psi) Tension k-Ibs All 5-1/2" 4.67' 4" 7" 24.7 S-135 HT-55 16,298 11,177 704k Page 3 Revision 0 Dee, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy company 3.0 Internal Reporting Requirements 3.1 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. 3.2 Afternoon Updates • Submit a short operations update each work day to pmazzolinighilcorp.com , Ikeller@hilcorp.com and ibarrett@hilco!p.com 3.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a username to login with. 3.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: 0: (907) 777-6726 C: (907) 227-3189 b. Mark Tomai: 0: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: 0: (907) 777-8317 C: (907) 602-5178 2. Spills: Kate Kaufman: 0:907-777-8329 C:907-244-8292 • Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 • Submit Hilcorp Incident report to contacts above within 24 hrs 3.5 Casing Tally • Send final "As -Run" Casing tally to lkeller@hilcorp.com and ibarrett=,hilcorp.com 3.6 Casing and Cmt report • Send casing and cement report for each string of casing to Ikeller@hilcoip.com and bad rrett@hilcorp.com Page 4 Revision 0 Dec, 2013 S e,Z 4.0 Planned Wellbore Schematic I I.:>. -": ' I If PBTD = 13,400' ?AID111,647' -n-D TD=13,500' XID / 11,685' Tt D Anna #37A Drilling & Completion Procedure Anna Platform PlannedAnna llo. An-37A Planned WBD 12-16-2013 CASING DETAIL WT" GRADE CONN 10 TOP STf,R. 320 STR Weld Surf 265' 133 x-56 19 Surf 615' 68 N-80 STC 12.415 Surf . - 47P L-SC DWC/C HT 8.681 surf 9,20C' 47R Pdi2 DWC/CHT 8.681 9.2Cs7° 10.640' 29P P-130 DWC/C HT 1 6.184 10ACC' 1 1350C' TUBING 9.29 L-80 2.992` Surface 30,354' 3-1/2` 9.2# L-80 2.992' Surface 1 10 520' 7 JEWELRY DETAIL NO. Depth OD Item 1 10,320' 35' X Profile Ni k 2 10,350' K08E Cr�� 3 10ASS, 35" P Profile Nipple 4 10,600' 35' Sdilin Stee�v 5 1 M620' 7.0' Pxker 6 iC,640' 35- Ported Sub 7 1C,b83"- 11,257' 4-118" PerfGurs PLANNED PERFORATIONS Zane TOP (MO) TOP (TVD) H K-1 H K-2 HK-2 Re o= HK-1 Re rat Page 5 Revision 0 Dec, 2013 4J/ N lads.-.' 2H6oil Anna #37A Drilling & Completion Procedure Hilcorp 5.0 Drilling / Completion Summary Anna 37A is a development oil well planned to be re -drilled in a Northerly direction from leg #2 (East Corner), Slot #8 utilizing the existing casing program down to 2500' MD. The base plan is to sidetrack the well out of the 12-1/4" window cut in the 13-3/8" casing at 2500' MD. The 12- 1/4" hole section will be drilled to 10,600' MD / 10,218' TVD and a string of 9-5/8" casing will be set. An 8-1/2" hole section will be drilled to TD at 13,500' MD / 11,685' TVD and a 7" production liner run and cemented. The well will be completed with a dual string of 3-1/2" production tubing. Drilling operations are expected to commence immediately following the slot recovery operations. Slot recovery operations are expected to begin 1-5-2014 and forecasted to last approx 21 days. Operations conducted during the slot recovery of Anna #37: /STY s 1. Kill well, Remove tree, N/U & test BOP. ---7 3d6l 2. Pull 3-1/2" kill string. 3. P&A wellbore with cement. 4. Set & test CIBP at 3650' MD. 5. Cut and pull 9-5/8" casing to 2500' MD. 6. Clean out run with 12-1/4" clean out assy. 7. Run and set Whipstock, mill 12-1/4" window at 2500', FIT to 12ppg. General sequence of operations pertaining to this 10-401 APD: r�U 1. Drill 12-1/4" hole section to 10,600' MD utilizing a 2%KCl/Clayseal/GEM drilling fluid system at 9.2 to 9.6 ppg. Obtain LWD logging data. 2. Run and cement 9-5/8" production casing. u f 49-P ,SBoa p S; 3. Test 9-5/8" casing to 4000 psi / 30 min. Drill out & conduct FIT to 15 ppg. 4. Drill 8-1/2" hole section to 13,500' MD. 5. Run and cement 7" production liner. 6. TIH w/ clean out assy. Clean out to landing collar and displace to filtered inlet water. A separate Completion program will be submitted that includes: 1. RIH w/ TCP assy, perforate well. 2. Run dual string 3-1/2" production tubing. Install BPV. 3. N/D BOP, N/U Tree. 4. Produce well. Page 6 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 6.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC and BLM regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drlg Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of Anna 37A. Ensure to provide AOGCC 24 hrs notice. • BOP tests conducted while drilling the 12-1/4" hole section 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. • BOP tests conducted while drilling the 8-1/2" hole section will be to 250/5000 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. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 13-5/8" Shaffer 5M annular • 13-5/8" 5M Schaffer LXT Double gate 12-1/4" Tests: o Top Cavity: 3-1 /2" x 5-1 /2" VBR 250/3000 o Btm Cavity: Blind Ram (Annular 2500 psi) • Mud cross 12-1 /4" & 8-1 /2" . 13-5/8" 5M Cameron U single gate o 2-7/8" x 5-1 /2" VBR or casing ram • 3-1 /16" 5M Choke Manifold 8-1 /2" Tests: Standpipe, floor valves, etc 250/5000 (Annular 2500 psi) • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Secondary back-up is an air pump, and tertiary emergency pressure is provided by bottled nitrogen. Page 7 Revision 0 Dee, 2013 Anna #37A Drilling & Completion Procedure 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): 907-276-7542 / Email: guy.schwartz@alaska.goy Victoria Ferguson / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.fergusonkalaska.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 8 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilmTEnergy company 7.0 Drilling 12-1/4" Hole Section 7.1 BOP configuration should be annular / 3-1/2" x 5-1/2" VBR / blind ram / 2-7/8" x 5-1/2" VBR. 7.2 BOP tests conducted while drilling the 12-1/4" hole section 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. 7.3 Set wearbushing in wellhead if not done previously. 7.4 Mix mud for drilling 12-1/4" hole section. 12-1/4" hole mud program summary: 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. Canrig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.2 — 9.6 ppg 2% KCl / Clayseal / GEM drilling fluid Pronerties: Densit Viscosi Plastic Viscosity Yield Point HTHP pH 9.2-9.6 40-53 6 - 15 13 - 24 <9 8.5-9.5 Svstem Formulation: 2% KCl/ CLAYSEAL/ GEM GP Product Concentration Water 0.905 bbl KCI 7 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.0 ppb (as required 18 YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial .15 ppb) CLAYSEAL 4 ppb (Initial build 1 ppb) ALDACIDE G 0.1 ppb GEM GP 1.0% by volume BARACARB 50 10 ppb BAROID 41 58 ppb as needed to 9.6 1. Mud weight: Maintain the density at 9.2 - 9.6 ppg or as directed; use solids control and whole mud dilution. Increase density as required for hole stability/coal sloughing. Maximize solids control usage. 2. Rheology: Maintain a YP between 13 and 20. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). Page 9 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilmiT Energy Company 3. Lubricity: With the expected INC. of 21 deg, torque should not be a problem. TORQ-TRIM II or BARO-LUBE GOLDSEAL are the only lubricants available for use while discharging overboard. Combined lubricant levels must stay <1 % to achieve NPDES compliance. 4. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. LCM (BARACARBs 5/25/50, STEELSEAL 50/100/400) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. 7.5 M/U the below kick off directional drilling assy: • 12-1 /4" Mill Tooth Bit (Smith XR+) • Mud motor (1.5 deg) • NM IB stabilizer (12-1/8") • Telescope-825 MWD • NM IB Stabilizer (12-1 /8") • NM Bottleneck crossover • (2) NM DC (7-1/4") • NM IB stabilizer (8-3/8") • NM DC (7-1/4") • Saver/Float Sub • 5-1/2" HWDP (7 joints) • 6.5" Drlg Jar (Weatherford) • 5-1/2" HWDP (13 joints) • 5-1/2" DP to surface. 7.6 Ensure BHA components have been inspected previously. 7.7 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 7.8 Ensure TF offset is measured accurately and entered correctly into the MWD software. 7.9 Confirm Bit TFA = 0.8 — 0.85 in2. Have the DD run independent hydraulic calculations to ensure optimum TFA. 7.10 TIH to 30' above Whipstock. Orient toolface so that bend/bit faces away from Whipstock face. Avoid rotating BHA with bit or stabilizers across Whipstock face. 7.11 Lower string and begin sliding to initiate sidetrack. Page 10 Revision 0 Dec, 2013 ff Hilcorp Enema Company (311.15 MM) tADC:117 Xplorer Expanded bit.- are specifically, designed to drill. -oft formations with exceptional ROP and reliability. With the proven Gemini Twin Seal .-; item and the ultra durable MIC2 hardmetal, these bits deliver maximum ROP and long run times in a wide range of application.-. Bearing Type Spinodal"' 2 Bearing w/Silver Plated Component- Seal Type Gemini— Twin Seal Srtem Bit Connection Type 6-518" API Reg. _. Rows Total:7 Inner 4 Gage:3 Insertstfeeth Total: 65 Inner. 33 Gaae: 32 Weight on Bit 10.000 To 55,000 (lbs) 4.545 To 24,998 (daN) _ __ 4 To 25 (Tonnes) Rotary Speed (RPM) 280 To 50 Operating parameters are typical range.-. Please contact ;your Smith Bit^ representative for recommendations for -,tour individual welt, Anna #37A Drilling & Completion Procedure SMITH BITS A Schlumberger Company FEATURES ■ Premium hardmatal material reduce.- wear, provide.- .-uperior durability and ensure.- that a full gauge hole i.- drilled. ■ The Gemini tvwin seat .-y.-tem consists of a primary -.eat which protects the bearing and a secondary seal that protects the primary seal. This dual seat .-;,.-tem will perform reliably for extended periods of time in high RPM. heavier WOB. high mud weight and severe dogleg applications. ■ Spinodal 2 bearing en:ures longer runs at higher ROP. This proprietary material offers maximum wear resistance and withstands extreme load forces for longer period.- than conventional bearing materials. Page 11 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp sn�y co�r�r 7.12 Drill along approved directional plan using motor BHA until bit or hole dictates a change is needed. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 9 • Take formation samples every 30 ft. 7.13 CBU prior to TOH for RSS BHA. 7.14 Cease rotation and circulation prior to BHA being pulled across the Whipstock face. 7.15 TOH w/ kick off BHA. Lay down MM & Bit. 7.16 M/U 12-1/4" rotary steerable assy as follows: • 12-1/4" PDC bit (Smith MDSi716) • PDX5-900 12-1/4" Stab CC GR+D&I • NM PDX5 Receiver • NM PDX5 Flex Collar / • ARC-8 LWD (Gamma Ray + Resistivity) ✓ • NM IB Stabilizer (12-1 /8") • NM Bottleneck crossover • (2) NM DC (7-1/4") • NM IB stabilizer (8-3/8") • NM DC (7-1/4") • Saver/Float Sub • 5-1/2" HWDP (7 joints) • 6.5" Drlg Jar (Weatherford) • 5-1/2" HWDP (13 joints) • 5-1/2" DP to surface. Page 12 Revision 0 Dec, 2013 UMEdWiTUT 111MVA�� (311.15 mm) iD:64533D0001 The Smith High Abrasion Resistance Configuration (SHARC) bits are designed with the durability to withstand the demands of highly abrasive formations without sacrificing ROP. Speciftations Total Cutters _ 113 Cutter Size 16mm (518 in) Face Cutters (57)16mm Gauge Cutters (7)16mm Badc-Up Cutters (49) 16mm Blade Count 7 _...._.__..__._.-_ Nozzles ---- .._.__...____..__��.__�______�___� 9 Standard Series 60N Bit Connection _6 518 Reg Junk Slot Area. in2 25271_._ Gauge Length_: 5" Protection: Options Available Length _ Make -Up: 12.94m Overall 17.878mm Fishing Neck Diameter. 8 Length: 3.229 Operating Parameters Rotary Speed Rotary Speed Suitable for Rotary & PDM } _ Weight -on -Bit 6.000 To 40.000 (lb f) 2.727 To 18.180 (daN) _ 3 To 18 (Tonnes) V^ Flow Rate galUslmin 500 To 1200 Hydraulic Horsepower. HSI 1 To 6 Recommended Make-up Torque 47.300 To 47.800 ftAbe Operating parameters are typical ranges. Please contact your Smith Bits representative for recommendations for your individual well. Page 13 Revision 0 Anna #37A Drilling & Completion Procedure SMITH BITS A Schitimbeiger Ctunpaiiy FEATURES IS Bit design and performance have been certified through the validation process prescribed by IDEAS simulation technology. ■ The PX feature place -- thermally stable diamond inserts (TSP)on the gauge to maximize gauge retention and extend bit life- ® Bit design is available with ONYX cutters for improved i= thermal stability in harder. more abrasive formations. M resulting in greater wear resistance, cutters remaining sharp longer, more footage drilled, and faster ROP. ttt Limited Torque -Blade tops "` are raised so that the maximum depth of cut is limited by the engagement of the blade tops into the formation. This limits the torque that the bit can produce which is very useful for directional applications which utilize a rteerable motor assembly. ■ Higher nozzle counts enhance bit cleaning. cooling and cuttings evacuation, and allow; for higher flow rates with minimal increases in pump pressure. This improved bottomhole cleaning maximizes ROP. Dec, 2013 Anna #37A Drilling & Completion Procedure 7.17 Ensure BHA components have been inspected previously. 7.18 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 7.19 Ensure to follow Schlumberger source installation procedures. 7.20 Confirm Bit TFA = 0.7 — 0.75 in2. Have the DD run independent hydraulic calculations to ensure optimum TFA. 7.21 TIH with RSS BHA. 7.22 Drill 12-1/4" hole section along approved directional wellpath to section TD. Section TD is planned at 10,600' MD / 10,218' TVD. The objective of the 9-5/8" casing is to isolate anv potentially depleted sands in the Tyonek from the MW that will be required in the 8- U " ole '9 section. • Begin drilling with light WOB to initiate a new PDC bottom hole pattern. • Work pipe through coal seams as req'd. Avoid excessive backreaming. Backreaming & surging the coals has an adverse effect on the quality of the wellbore. • Utilize formation type log to identify coal seams and plan directional work accordingly. • Pump sweeps as required for additional hole cleaning. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. Keep API fluid loss < 9 • Pull wiper trips as hole conditions dictate. A good rule of thumb is to start with wiper trips every 500'. • Take formation samples every 30'. 7.23 At 10,600', sweep hole & CBU. Pull a wiper trip back to the 13-3/8" window. TOH & handle BHA as appropriate. • Note any tight spots or hole problems on AM report. 7.24 No open hole logs are planned for Anna 37A. / Page 14 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Company 8.0 Running 9-5/8" Production Casing 8.1 Pull wear bushing. C16 Q 41> J f k G 0 8.2 R/U Weatherford 9-5/8" 47#I L�-80 DWC/C casing running equipment. • 9-5/8" CRT c/w elevator positioning system. • 14-50 Weatherford High Torque tongs. • Flush mounted spider & adapter bushing. • Back up tongs (rig provided) for 9-5/8" casing. • Ensure all casing has been drifted on the pipe rack prior to running. • Be sure to count the total # of joints on the rig before running. • Keep hole covered as much as possible while R/U casing tools. -� —?,L5 o / s • Monitor wellbore on trip tank. • Record OD's, ID's, lengths, S/N's of all shoe track components & the stage collar. • Ensure 9-5/8" DWC/C x 5" HT-55 crossover on rig floor and M/U to FOSV. 8.3 P/U the reamer shoe joint. Visually verify there is no debris inside joint. 8.4 M/U and thread lock shoe track assy consisting of: • (1) Shoe joint with reamer shoe bucked on (thread locked). Install centralizers at 10' from each end btwn stop collars. • (1) Joint with coupling thread locked (Bakerlocked joint). Install centralizer mid tube btwn stop collars. • (1) Joint with float collar bucked on pin end & thread locked. Install centralizer mid tube btwn stop collars. • Ensure proper operation of float equipment. 8.5 Continue running 9-5/8" intermediate casing. • Use "API Modified" thread compound. Dope pin end only using a paint brush. • Install centralizers every 3rd joint. Leave centralizers free floating so they are free to slide up and down the joint unrestricted. • No centralizers required above 4000'. • Utilize the CRT to fill the string while running. • Run P-110 casing from 10,600' to 9,200'. L-80 casing from 9,200' to surface. 8.6 If trouble is encountered, the CRT can be utilized to rotate the string. Torque is limited by the top drive (30k ft-lbs). Page 15 Revision 0 Dec, 2013 Connection Type: DWC/C Casing standard Anna #37A Drilling & Completion Procedure Technical Specifications Size(O.D.): Weight (Wall): 9-5/8 in 47.00 lb/ft (0.472 in) Material L-80 Grade 80,000 Minimum Yield Strength (psi) 95,000 Minimum Ultimate Strength (psi) Pipe Dimensions 9.625 Nominal Pipe Body O.D. (in) 8.681 Nominal Pipe Body I.D.(in) 0.472 Nominal Wall Thickness (in) 47.00 Nominal Weight pbs/ft) 46.18 Plain End Weight (lbsfft) 13.572 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 1.086,000 Minimum Pipe Body Yield Strength (Ibs) 4,750 Minimum Collapse Pressure (psi) 6,870 Minimum Internal Yield Pressure (psi) 6,300 Hydrostatic Test Pressure (psi) Connection Dimensions 10.625 Connection O.D. (in) 8.681 Connection I.D. (in) 8.525 Connection Drift Diameter (in) 4.81 Make-up Loss (in) 13.572 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 1,086,000 Joint Strength (ibs) 16,500 Reference String Length (ft) 1.4 Design Factor 1,122,000 API Joint Strength pbs) 543,000 Compression Rating (Ibs) 4,750 API Collapse Pressure Rating (psi) 6,870 API Internal Pressure Resistance (ps) 19.0 Maximum Uniaxial Bend Rating [degrees/100 ft] Appoximated Field End Torque Values 40,000 Minimum Final Torque (ft-Ibs) 50,000 Maximum Final Torque (ft-Ibs) 59,400 Connection Yield Torque (ft-Ibs) Grade: L-80 "law �'U SA VAM-USA 4424 W. Sam Houston Pkwy. Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713479.3234 E-mail: YtUuAri?tesna va's,roc Corr Page 16 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilcOIp Energy Company 8.7 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 8.8 Slow in and out of slips. 8.9 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe +/- 20' from TD when landed. Strap the landing joints while on the pipe deck and mark the joints to use as a reference when landing the hanger. 8.10 Lower string and land out in wellhead. Confirm measurements indicate hanger has correctly landed out in the wellhead profile. 8.11 Estimated P/U weight at TD is 650k. Page 17 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilmTEncW Company 9.0 Cement 9-5/8" Casing 9.1 Hold a pre job safety meeting over the upcoming curt operations. Ensure adequate mud volume available for displacement in the event of lost returns while cementing. Ensure enough M/U water is warmed up and ready. Ensure to cover the following during the PJSM: • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. 9.2 R/U cmt head (if not done previously). Ensure top and bottom plugs have been loaded correctly. Ensure top and bottom plugs are PDC drillable. Test surface curt lines to 4500 psi. 9.3 Circ until MW is conditioned properly for cmt operations. Add M/U water to reduce viscosity and gel strength. Ensure not to allow MW to decrease. Pump at 6 — 8 bpm. 9.4 Cement volume is based on annular volume + 30% open hole excess. Cement from shoe to 500' below 13-3/8" window. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol ft3) LEAD: (10,100' — 3,000') x .0558 bpf x 515 bbls 2891 ft3 12-1/4" OH x 9-5/8" csg 1.3 = annulus: Total LEAD: 515 bbls 2891 ft3 TAIL: (10,600'-10,100') x .0558 bpf x 37 bbls 208 ft3 12-1/4" OH x 9-5/8" csg 1.3 = annulus: TAIL: 90 x .073 bpf = 6.5 bbls 37 ft3 10-3/4" Shoe track: Total TAIL: 43.5 bbls 244 ft3 Page 18 Revision 0 Dec, 2013 t19, s'`s 1?S SXS HilmiT Energy Company Anna #37A Drilling & Completion Procedure Cement Slurry Design: Lead Slurry (10,100' to 3,000' MD) Tai I Slurry (10,600' to 10,100' MD) System Extended Lead 15.3 EASYBLOK Density 12 ppg 15.3 lb/gal Yield 2.45 ft3/sk 1.39 ft3/sk Mixed Water 14.373 gal/sk 6.214 gal/sk Mixed Fluid 14.523 gal/sk 6.233 gal/sk Expected Thickening 100 Bc at 6:30 hr:mn 100 Bc at 05:30 hr:mn Expected ISO/API Fluid Loss < 200 mL < 60 mL Code Description Concentration Code Description Concentration D046 Antifoam 0.2% BWOC D046 Antifoam 0.2% BWOC D020 Extender 3.0%BWOC D202 Dispersant 1.5% BWOC Additives D079 Extender 2%BWOC D400 Gas Migration 0.8% BWOC D110 Retarder 0.15 al/sk D154 Extender 8%BWOC D174 Expanding Agent 1.5% bWOC D198 Retarder 0.4%BWOC 9.5 Pump 5 bbls 10.5 ppg spacer. Test surface cmt lines to 4000 psi. 9.6 Pump remaining 35 bbls 10 ppg spacer. 9.7 Drop bottom plug and pump 12 ppg lead followed by 15.3 ppg tail cmt. 9.8 Drop top plug and displace with mud in pits at 6 — 8 bpm. Estimated displacement volume: (10,600' — 20' — 90') = 10,490 * 0.0732 = 768 bbls. If surface volume allows, displace with mud that will be used for the next hole section (12.9 ppg). 9.9 Monitor returns closely while displacing cmt. Adjust pump rate if necessary. Bump plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. 9.10 R/D surface cement equipment. 9.11 Back out and L/D landing joint. 9.12 M/U flush tool and wash out area btwn hanger neck and wellhead in preparation for running seal assy. Page 19 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Company 9.13 M/U packoff & setting assy to landing joints. Run and set packoff. Test packoff to 3000 psi / 30 min through test port on side of wellhead. 9.14 L/D landing joint. Run and set wearbushing in wellhead. 9.15 RIH w/ 1000' of 5" DP out of derrick. M/U RTTS for 9-5/8" 47# casing. Hang off RTTS at 500'. Test above RTTS to 1500 psi / 10 min. 9.16 N/D BOP. Install and test new 13-5/8" 3M x 11" 5M tubing head. Test void to 5000 psi / 10 min. 9.17 N/U & test BOP. T y4 Sbzr� 1:�,u 7 ",eff 9.18 Recover RTTS and stand back DP in derrick. Page 20 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Company 10.0 Drilling 8-1/2" Hole Section 10.1 Remove 9-5/8" casing rams from lmyer ram cavity. Install and test 5-1/2" x 2-7/8" VBRs. MASP for this hole section is 3898 psi so (2) sets of rams sized to fit the 5-1/2" workstring is required by the AOGCC. 5000 $L 86Ya j-.� 10.2 Run and set wear bushing in wellhead. 10.3 M/U 8-1/2" directional drilling assy as follows: • 8-1/2" PDC bit (Smith MSi716) (TFA:.70 in2) • PDX5 675 w/ 8.375" stabilizer (Gamma Ray + D&I) • ARC-675 LWD (GR + Res) • Telescope-675 MWD (D&I — GR) / J • ADN — 675 8-1/4" stab (Density -Neutron) • NM IB Stabilizer 8-3/8" • (2) NM Drill Collar 7-1/4" • NM IB stabilizer 8-3/8" • NM Drill collar 7-1/4" • Saver/float sub • 5-1/2" HWDP (7 joints) • Daily Jar • 5-1/2" HWDP (13 joints) • 5-1/2" Drill Pipe 10.4 TIH w/ RSS BHA to estimated TOC. 10.5 CBU and test casing to 4000 psi / 30 min. O 10.6 Drill out shoe track + rat hole + 20' new formation. 10.7 CBU and condition MW for FIT. 10.8 Conduct FIT to 15 ppg. Projected FIT test data: • 10,218' TVD, 12.9 ppg MW, 1115 psi surface pressure. • Anticipated fracture gradient at the 9-5/8" casing shoe (10,218' TVD) is expected to be btwn 17 and 18 ppg EMW based on offset wellbores. • An FIT of 15 ppg was chosen to allow for a (2.1 ppg) kick margin while drilling with a 12.9 ppg fluid density. 10.9 Displace well to 12.9 ppg if not done previously. Page 21 Revision 0 Dec, 2013 Hilm7Enema Company Anna #37A Drilling & Completion Procedure 8-1/2" hole mud program summary: 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. Camig PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. The starting MW of 12.9 ppg was chose after careful review of the offset wellbores. MW ranges of 12.6 to 13.4 ppg were utilized. System Type: 12.9 ppg 2% KCl / Clayseal / GEM drilling fluid Properties: Density Viscosit Plastic Viscosity Yield Point HTHP pH 6 - 15 13 - 24 <9 8.5-9.5 y 12.9 40-53 System Formulation: 2% KCl/ CLAYSEAL/ GEM GP Product Concentration Water 0.905 bbl KCI 7 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.0 ppb (as required 18 YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial .15 ppb) CLAYSEAL 4 ppb (Initial build 1 ppb) ALDACIDE G 0.1 ppb GEM GP 1.0% by volume BARACARB 50 10 ppb BAROID 41 58 ppb as needed to 12.9 1. Mud weight: Maintain the density at 12.9 ppg or as directed; use solids control and whole mud dilution. Increase density as required for hole stability/coal sloughing. Maximize solids control usage. 2. Rheology: Maintain a YP between 13 and 24. Pump high viscosity sweeps throughout the interval as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). 3. Lubricity: TORQ-TRIM II or BARO-LUBE GOLDSEAL are the only lubricants available for use while discharging overboard. Combined lubricant levels must stay <1 % to achieve NPDES compliance. 4. Other issues: The use of good drilling practices to minimize excessive swab and surge pressure should be employed to minimize the chances for losses and differential sticking. LCM (BARACARBs 5/25/50, STEELSEAL 50/100/400) should be maintained at elevated concentrations while drilling coals to help strengthen the wellbore. Page 22 Revision 0 Dec, 2013 ff Hilcorp Energy Company Anna #37A Drilling & Completion Procedure 10.10 Begin drilling 8-1/2" hole section along approved directional plan. • Begin with light WOB to establish a new bottom hole pattern with the PDC bit. • Work pipe through coal seams as req'd. • Utilize formation type log to identify coal seams and plan directional work accordingly. • Pump sweeps as required for additional hole cleaning. • Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 8 • Pull wiper trips as hole conditions dictate. A good rule of thumb is to start with wiper trips every 500'. • Take formation samples every 30' 10.11 Drill to TD at 13,500' MD / 11,685' TVD. • Exact TD will be determined based on LWD log and casing tally. 10.12 CBU and pull a wiper trip back to the 9-5/8" casing shoe. 10.13 TOH, drop drift on trip out of hole. Handle BHA as appropriate on trip out of hole. • Record torque at 9-5/8" shoe at 20, 30, 40 rpm. Note on AM report. Page 23 Revision 0 Dec, 2013 Hilcorp Energy Company (215.9 mm) ID:64356130101 ER:25337 The Smith High Abrasion Resistance Configuration (SHARC) bits are designed with the durability to withstand the demands of highly abrasive formations without sacrificing ROP. Specificabons Total Cutters Cutter Size 55 16mm (518 in) Face Cutters (34)16mm - Gauge Cutters rda Cone Cutters (6)16rnm Back -Up Cutters (15)16mm _ Blade Count 7 Nozzles Bit Connection Junk Sot Area. W2 Gauge 3 Standard Series 60N. 4 Standard Series 40N 41 /2 Reg 9.392 _ Length: 2' Protection: Options Available Make Up: 9.087 Overa/:13.275 Fishing Neck _ Diameter: 6 Length: 3273 Operallitig Parameters Rotary Speed Rotary Steerable BHA & Downhole Motors Weight -on -Bit 4.000 To 35.000 (lbf) 1.818 To 15.908 (daN) 2 To 16 (Tonnes) Flow Rate galUsimin _ 300 To 800 Hydraulic Horsepower. HSI 1 To 6 Operating parameters are typical ranges. Please contact your Smith Bits representative for recommendations for your individual well- Page 24 Revision 0 Anna #37A Drilling & Completion Procedure SMITH BITS A Schlumberger Company FEATURES ■ Bit design and performance have been certified through the validation process prescribed by IDEAS simulation technology. ■ Bit design is available with ONYX cutters for improved P, rj thermal stability in harder, more abrasive formations. resulting in greater wear161— resistance, cutters remaining sharp longer. more footage drilled. and faster ROP. ■ Limited Torque -Blade tops are raised so that the maximum depth of cut is limited by the engagement of the blade tops into the formation. This limits the torque that the bit can produce which is very useful for directional applications which utilize a steerable motor assembly. ■ The PX feature places thermally stable diamond inserts (TSP)on the gauge to maximize gauge retention and extend bit life. Dec, 2013 Anna #37A Drilling & Completion Procedure Hilco p Energy Company 11.0 Running 7" Production Liner 11.1 Install and test 7" casing ram in lower ram cavity. Test should be to 250/5000 psi for 515 min. 11.2 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure dart will pass through components. • Confirm largest OD of packer assy will pass through wear bushing. 11.3 R/U Weatherford 7" casing running equipment. • Ensure 7" DWC/C HT x 5-1/2" HT-55 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • 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 shoe track components. 11.4 P/U shoe joint, visually verify no debris inside joint. 11.5 Continue M/U & thread locking shoe track assy consisting of: • (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). • (1) Baker Locked joint • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). • (1) Joint with landing collar installed INSIDE pin end. • Solid body centralizers will be pre -installed on shoe joint & FC joint. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe. 11.6 Continue running 7" prod liner • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every joint across the entire open hole section. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 7" DWC/C MX torques Casing OD Minimum Maximum Yield Torque 7" 24,300 ft-lbs 28,200 ft-lbs 32,200 ft-lbs Page 25 Revision 0 Dec, 2013 Connection Type: DWC/C Casing 2012 API Spec 5CT Coupling O.D. Anna #37A Drilling & Completion Procedure Technical Specifications Size(O.D.): Weight (Wall): Grade: 7 in 29.00 Ib/ft (0.408 in) P-110 Material P-110 Grade 110,000 Minimum Yield Strength (psi) 125,000 Minimum Ultimate Strength (psi) Pipe Dimensions 7.000 Nominal Pipe Body O.D. (in) 6.184 Nominal Pipe Body I.D.(in) 0.408 Nominal Wall Thickness (in) 29.00 Nominal Weight (Ibs/ft) 28.75 Plain End Weight (Ibs/ft) 8,449 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 929,000 Minimum Pipe Body Yield Strength (Ibs) 8,530 Minimum Collapse Pressure (psi) 11,220 Minimum Internal Yield Pressure (psi) 10,300 Hydrostatic Test Pressure (psi) Connection Dimensions 7.875 Connection O.D. (in) 6.184 Connection I.D. (in) 6.125 Connection Drift Diameter (in) 4.50 Make-up Loss (in) 8.449 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 929,000 Joint Strength (Ibs) 22,880 Reference String Length (ft) 1.4 Design Factor 955,000 API Joint Strength (Ibs) 465,000 Compression Rating (Ibs) 8,530 API Collapse Pressure Rating (psi) 11,220 API Internal Pressure Resistance (psi) 36.0 Maximum Uniaxial Bend Rating (degrees/100 ft) Appoximated Field End Torque Values 24,300 Minimum Final Torque (ft-Ibs) 28,200 Maximum Final Torque (ft-Ibs) 32,200 Connection Yield Torque (ft-lbs) lam t�USA VAtA-USA 4424 W. Sam Houston Plnry Suite 150 Houston, TX 77041 Phone: 713-479-3200 Fax: 713.479-3234 E-maik VAMU GIs ns.vattour acorn Page 26 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilmTEnergy Company 11.7 Ensure to run enough liner to provide for approx 200' overlap inside 9-5/8" casing. Ensure hanger/pkr will not be set in a 9-5/8" connection. 11.8 Before picking up liner hanger, count the # of joints on the pipe deck to make sure it coincides with the pipe tally. 11.9 M/U Baker SDD hydraulic set liner hanger. 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. 11.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 11.11 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. 11.12 M/U top drive and fill pipe while lowering string every 10 stands. 11.13 Slow in and out of slips. 11.14 Circulate 1-1/2 drill pipe and liner volume at 7-5/8" shoe prior to going into open hole. Stage pumps up slowly and monitor for losses. Do not exceed 60% of the nominal liner hanger setting pressure. Nominal liner hanger setting pressure is 2500 psi. 60% of this value is 1500 psi 11.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 11.16 Maximum torque while running the 7" liner is 32k + 70% torque obtained at shoe on previous trip out of the hole. A spreadsheet will be developed after these values have been obtained on the last trip out of the hole. 11.17 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill the drill pipe. 11.18 P/U the cmt stand and tag bottom with the liner shoe. P/U 2' off bottom. Note slack -off and pick-up weights. Record rotating torque values at 10, 20, & 30 rpm. 11.19 Stage pump rates up slowly to circulating rate without exceeding 60% of the liner hanger setting pressure (1500 psi). Circ and condition mud with the liner on bottom. Reduce the low end rheology of the drilling fluid by adding water and thinners. 11.20 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 27 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 12.0 Cementing 7" Production Liner 12.1 Hold a pre job safety meeting over the upcoming cmt operations. 12.2 Attempt to reciprocate & rotate the liner during cmt operations. 12.3 Cement volume is based on annular volume + 50% open hole excess. Job will be a single stage design. Cement from shoe to TOL. 12.4 Pump 5 bbls 12 ppg MUDPUSH II spacer. 12.5 Test surface cmt lines to 4500 psi. 12.6 Pump remaining 25 bbls 12 ppg MUDPUSH II spacer. 12.7 Mix and pump 15.6 ppg class "G" EASYBLOCK cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 50% OH excess.... Cement Calculations 9-5/8" x 5-1/2 DP" Overlap: 200' x 0.0489 = 9.8 bbls 9-5/8" x 7" Liner Overlap: 200' x 0.0256 = 5.2 bbls 8-1/2" OH x 7" Liner: (13,500—10,600') x 0.0226 x 1.50 = 98.3 bbls Shoe Track: 120' x 0.038 = 4.6 bbl Total Volume (bbls): 9.8 + 5.2 + 98.3 + 4.6 = 117.9 bbls Total Volume (ft3): 117.9 bbls x 5.615 ft3/bb1= 662 ft3 Total Volume (sx): 662 ft3 / 1.33 ft3/sk = �sx Page 28 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Slurry Information: System EASYBLOCK Density 15.6 lb/gal Yield 1.33 ft3/sk ✓ Mixed Water 5.776 gal/sk Mixed Fluid 5.776 gal/sk Expected Thickening 100 Bc at 06:00 hr:mn Expected ISO/API 15 mL in 30.0 min at 175degF / 1000 psi Fluid Loss Code Description Concentration G Cement 94 lb/sk D202 Dispersant 1.5% BWOC Additives D400 Gas Control Agent 0.8% BWOC D154 Extender 8.0 % BWOC D174 Expanding Agent 1.5% BWOC D198 Retarder 0.4% BWOC 12.8 Drop DP dart and displace with drilling fluid in mud pits. Reciprocate and rotate liner if hole conditions allow. 12.9 Reduce pump rate to 3 bpm prior to latching DP dart into liner wiper plug. Note plug departure from liner hanger running tool and resume pumping at full displacement rate. Displacement volume can be re -zeroed at this point. 12.10 If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 12.11 Bump the plug and pressure up as required by Baker procedure to set the liner hanger (20% above nominal setting pressure. 2500 psi is nominal setting pressure. Pressure up to 3000 psi to confirm hanger setting. 12.12 Slack off total liner weight plus 20k to confirm hanger set. 12.13 Do not overdisplace by more than % shoe track. Shoe track volume is 4.6 bbls. 12.14 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. Page 29 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Company 12.15 Bleed pressure to zero to check float equipment. 12.16 P/U and verify setting tool is released. 12.17 Pressure up to 500 psi down DP and pick up to remove the RS packoff bushing from the RS nipple. Bump up pressure as req'd to maintain 500 psi DP pressure while moving pipe until the pressure drops off rapidly, indicating pack -off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 12.18 Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 12.19 Pick up to the high -rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re -tag the liner top, and circulate the well clean. 12.20 Watch for cement returns and record the estimated volume. Rotate & circulate to clear curt from DP. 12.21 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 12.22 If the HRD-E tool still does not release hydraulically, left-hand (counterclockwise) torque will have to be applied to the tool. This torque acts to shear brass screws. Bleed off pump pressure and ensure that the tool is in the neutral position. Apply left-hand torque as required to shear screws. 12.23 NOTE: Some hole conditions may require movement of the drillpipe to "work" the torque down to the setting tool. 12.24 After screws have sheared, the top sub and body of the setting tool will turn 1/4 turn. Then proceed slacking off set -down weight to shear second set of shear screws. The top sub will drop 1-3/4 inches. At this point, the bottom sub no longer supports the collet fingers. Pick straight up with workstring to release collet from the profile. 12.25 If trouble is encountered with the Primary Release — ENGAGE office support immediately! This includes liner hanger company support as well as Hilcorp support. There may be valuable insight that can be brought to bear on the situation immediately. Page 30 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Company 13.0 Packer Setting Procedure / Wellbore Clean Up & Displacement 13.1 Remove 7" casing ram. Install and test 2-7/8" x 5-1/2" VBR for coverage of the 4" clean out string. Ensure to test on 4" test joint. i/ 13.2 M/U PBR polish mill assy and TIH. Polish PBR per BOT representative instructions. Note any curt encountered on AM report. 13.3 M/U ZXP liner top packer c/w seal assy and TIH. Ensure to run enough weight above the packer to allow proper setting. TIH and set ZXP liner top packer. Note depth of element and Top of assy on AM report. 13.4 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 6" bit or mill • Casing scraper & brush for 7" 29# casing (MI Swaco - Multiback) • +/- 3000' x 4" HT-38 workstring. • Crossover (No PBR Polish Mills) • Casing scraper & brush for 9-5/8" 47# casing (MI Swaco - Multiback) • (5500') 5-1/2" DP • Casing scraper & brush for 9-5/8" 474 casing (MI Swaco - Multiback) • 5-1/2" HT-55 to surface. 13.5 TIH & clean out well to landing collar (+/- 13,400 MD). • Circulate as needed on trip in if string begins to take weight. • Circulate hi-vis sweeps as necessary to carry debris out of wellbore. • Ensure 6" bit is worked down to the landing collar. • Space out the cleanout BHA so that the 6" bit reaches the 7" landing collar when crossover is +/- 30' above the 9-5/8" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 13.6 After wellbore has been cleaned out satisfactorily using mud, test casing to 4000 psi / 30 min. 13.7 Displace drilling fluid in wellbore with a hi-vis pill followed by FIW. • Circulate 3 to 4 B/U until clean-up is satisfactory with water. Do not recirculate fluid, pump and dump. • Pump as fast as feasible. Slow circulating rates will string out the interface and cause a much longer clean up phase. • Short trip the assy to bring the upper 9-5/8" multi -back assy to surface. • RIH again & tag landing collar w/ 6" bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Target NTUs are 80 - 100. Page 31 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilmix Energy Company 13.8 After sufficient circulations with filtered inlet water, displace the wellbore to 6% KCl completion fluid. 13.9 TOH w/ clean out assy. LDDP & 4" workstring on the trip out. Note any abnormal wear on the clean out assy components. 13.10 Make CBL logging passes. Log both the 7" prod liner and 9-5/8" casing. 14.0 Complete well • A separate sundry will be submitted that details the sequence of operations to perforate the / wellbore and run the dual string. Page 32 Revision 0 Dec, 2013 0 Me =Energy Company Anna #37A Drilling & Completion Procedure 15.0 BOP Schematic Stack up on right will be used to drill 12-1/4" hole section. Stack up on left will be used to drill 8-1/2" hole section. Fed w `qa.7 aW'u :it9 i+3 s;.spar: Page 33 Revision 0 Dec, 2013 16.0 Wellhead Schematic An-37RD 20X 133/8X95/8X 3 '/2 BHTA, Bowen, 3 1/8 10M FE X 3" Bowen quick union Valve, lower master, CIW-FC, 3 1/8 10M FE, HWO, FF trim Void test good 250/5000 6/10/2010 Tubing head, CIW-DCB, 13 5/8 5M X 11 5M, w/ 2- 2 1/16 5M SSO, X-bottom prep � Fg Casing spool, OCT-22, 21'/42MX 135/85M, w/ 2- 2 1/16 5M EFO, 00 bottom prep Casing head, OCT-22, 21 '% 2M X SOW, w/ 2- 2 1/16 2M EFO Page 34 Revision 0 Anna #37A Drilling & Completion Procedure Tubing hanger, CIW-DCB- FBB, 11 X 3'/2 EUE IiftX 3'/2 BTC susp, w/ 3" type H BPV profile, 1/8" non -continuous control line port Adapter, CIW, 11 5M FE X 3 1/16 10M Stdd, 6%slick neck pocket,'/2' control outlet Valve, CIW-F, 2 1/16 5M FE, HWO Qty 2 -Void test good 250/2500 6/10/2010 OCT-20, 2 1/163M ) FE, HWO Void test good 250/1000psi 6/10/2010 Valve, OCT-20, 2 1/16 2M FE, HWO Dec, 2013 17.0 Days Vs Depth 0 Anna #37A Drilling & Completion Procedure Anna 37A Days Vs Depth 10 20 30 40 50 60 70 Days Page 35 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy Co -Pent' 18.0 Geo-Prog _ WELL NAME SURFACE v . _ tPRS'ED TD. l3E0L00/CAt PROGNOSIS _ `Nlkot na 37A FIELD Granite Point xg2a6d18 t BOTTOM HOLE x=286419 AFE -..,.. ` MD 111684' TYQ EST KS 12 4_ APL EST GL 0" Objecbire Side tr irk an azlstmg well to ate a deviated development well to 13500 mdr 1 68A' tvd to the Hemlock sand updip from current Hemlock producers Integrated subsuAace and 3-D 000109kai kite retatronss to oonjucbon with sut>surlaq a v3ous producx+on daW InQkates Utat o3 reserve remain the Hemlock satM at GPF, Two downdi wells have sticcesN!y oompleted the Hemlock of GPF wrth each _ _ovenr.9 over 1 MMSO. These reservesµ itGpo5umm : _ _ i are booked and not recoverable in existing weiibwes. Casing will need to be set Just above the toDof the Hemlock at -106W This well is a hockey stick stile plan with a max rndination of 68 deSrees w+th build nogreater than 3 degreeer 100 DrUig Txne Dcitlinq times resod to Anchorage office by fax daffy to Jacob Dunston (907)777 8510� Mud Lc it Gas detection ord ✓ _ ; Casing., sz wautDa"JO" i z s c�bcu�Lue Hru} m tzt m u C,rxcsat al tOA�c _ _ O Hole Service MIND GAMMA RES from KO to casing pt S a r MWD - Triple comtiofrom casing point toTD OFFICE NO. CELL ` Jaccb t3tin§ton t 907.777�8373 Geobgra _ Operations E 907-777-8319 Reservoir Ertg 907.777-8375 907.250.5081 _. Dtilirng Eng 907-777-8520 832-247-3785 qan TaAor Reid Edwards Luke Keller >� t EEw.-,».,,_..1- _ L Page 36 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 19.0 Formation Tops/ Pressures MD TVD MD TVD Pressure NID TVD Pressure COAL 3,581 3,522 COAL 8,5S2 8,277 COAL 10,982 10,429 COAL 3,738 3,671 COAL 8,S67 8,292 COAL 11,208 10,S60 COAL 3,789 3,720 C-1 SAND 8,568 8,293 WET 3967 HPSAND 11,490 10,694 WET 7000 COAL 3,916 3,842 COAL 8,739 8,456 GP-HK-1 11,620 10,744 OIL 7000 COAL 3,%7 3,891 C-2A SAND, 8,568 8,293 WET/SWEPT GP-HK-2 11,87S 10,828 OIL 7000 COAL 4,027 3,939 COAL 8,779 8,495 WF_MKR 12,400 10,998 WET 7000 COAL 4,088 4,007 C-28 SAND 8,568 8,293 WET/SWEPT WF-REPEA 12,600 11,063 WET 7000 COAL 4,354 4,262 COAL 8,828 8,542 GP-HK2-RE 13,100 11,225 OIL 7000 COAL 4,445 4,349 COAL 8,893 8,603 GP-HKI-RE 13,277 11,282 OIL 7000 COAL 4,580 4,479 G-4 SAND 8,568 8,293 WETISWEPT 2156 TO -13400 11,322 COAL 4,674 4,569 COAL 8,984 8,690 C-5ASAND 9,028 8,733 WET/SWEPT COAL 9,107 8,808 C-58 SAND 9,119 8,820 WET/SWEPT COAL 9,210 8,907 C-6 SAND 9,236 8,932 OIL COAL 9,347 9,038 ICOAL 1 9,390 9,079 jC7AT SANE 9,436 9,123 OIL ICOAL 9,464 9,150 IC78-UPPEI 9,475 9,160 OIL ICOAL 9,514 9.197 jC7CT SANE 9,523 9,206 OIL ICOAL 9,614 9,293 jC7DT 9,62S 9,305 OIL COAL 9,663 9,340 UET 9,685 9,360 OIL COAL 9,688 9,364 COAL 9,706 9,381 C-88 9,741 9.414 OIL COAL 9,813 9,482 C•8C 9,840 9,500 OIL COAL 9,875 9,540 C-80 9,890 9,560 OIL COAL 9,970 9,628 COAL 10,010 9,664 COAL 10,115 9,759 C-9A 10,171 9,808 OIL C-98 10,230 9,860 OIL C-9C 10,330 9,945 OIL C-10 10,540 10,116 04l CASING P 10,650 10,200 1816 183S 2322 2372 2382 2394 2419 2434 2448 2470 2486 25SO 2S64 4200 4200 COAL 4,748 4,639 COAL 4,918 4,802 COAL 5,062 4,940 COAL 5,186 SAS9 COAL 5,310 5,177 COAL 5,443 5,304 COAL 15,50915,367 COAL 5,630 5,493 COAL 5,745 5,592 COAL 5,827 5,671 COAL 5,909 5,749 COAL 6,086 5,919 COAL 6,344 6,266 COAL 6,S37 6,350 COAL 6,73E 6,S40 COAL 6,837 6,637 COAL 6,933 6,729 COAL 7,092 6,881 COAL 7,171 6,957 COAL 17,232, 7,015 COAL 17,31717,097 COAL 7,390 7,166 COAL 7,468 7,240 COAL 7,540 7,310 COAL 7,623 7,388 COAL 7,688 7,451 COAL 7,762 7,S22 COAL 7,827 7,S84 COAL 7,879 7,634 COAL 8,061 7,808 COAL 9,128 7,872 COAL 8,198 7,938 COAL 8,268 8,006 COAL 9,304 8,040 COAL 18,367 8,100 Page 37 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcrp En-u.2 20.0 Anticipated Drlg Hazards 12-1/4" & 8-1/2" Hole Sections: Lost Circulation: Ensure 500 Ibs of BaroFibre (Fibrous Cellulosic Material), 500 Ibs SteelSeal (Angular, dual -composition carbon -based material), & 500 Ibs different sizes of Calcium Carbonate are available on the rig to mix LCM pills at moderate product concentrations. Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal while drilling both intervals to control any seepage losses. Hole Cleaning: Maintain a YP between 13 and 20. Pump high viscosity sweeps throughout the intervals as needed, particularly prior to POH for casing. Optimized mud rheology and flow rate will be the primary mechanisms for achieving hole cleaning in this deviated wellbore. Maximize pipe rotation (ideally > 100 RPM). BARAZAN-D should be used to maintain rheological properties. Wellbore stability: Maintain 1 Oppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. In the 12-1 /4" hole section, maintain MW @ 9.2 - 9.6 ppg using additions of Barite. For the 8-1 /2" hole section, maintain the MW at 12.9 ppg. HTHP in the <9 range is required. Maintain additions of PAC L / Dextrid LT to maintain API fluid loss of <9. Maintain 2% KCI in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams. Ensure these additives can be discharged prior to use. • An increase in fluid density does not positively effect a running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. • Avoid backreaming hole sections if possible. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 38 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 21.0 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. drillpipe 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 39 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hil=Ens. �m 22.0 Choke Manifold Schematic 01 c� 8 1 [CY LU << ! E L 441. a A P { p€ VW J ! ( i t (wv T4� Y u "F $ 3� q Z h 1' •� 2 �' R �f K S Q sU-u �i`tzt�ivi Z Q y , ( a W a^i N f IV N N� N N d tv ' t�P ri a wi !q N n V ._ {may �S N I'i �t 1e) O�.N. � Page 40 Revision 0 Dec, 2013 Hilcorp Energy Compmy Anna #37A Drilling & Completion Procedure 23.0 Casing Design Information Calculation & Casing Design Factors Cook Inlet, Alaska DATE: 1211712013 WELL: Anna 37A FIELD: Granite Point DESIGN BY:Luke Keller Design Criteria: Hole Size 12-114" Mud Density: 9.5 ppg Hole Size 8-1/2' Mud Density: 12.9 ppg Hole Size Mud Density: Drilling Mode MASP(sec 1): 1341 psi (see attached MASP determination & calculation) MASP(sec 2, 3, 4): 3898 psi (see attached MASP determination & calculation) Production Mode MASP: 5932 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1, 2, 3 Normal gradient external stress (0.494 psi/ft) and the casing evacuated for the internal stress 4 Overpressured Hemlock external stress (0.671 psi/ft) and the casing evacuated for the internal stress. Casing Section Calculation/Specification 1 2 3 4 Casing OD 13-3/8" 9-5/8" 9-518" 7" To MD 0 0 9200 10400 Top (TVD) 0 0 8933 10058 Bottom MD 2,500 9200 10600 13500 Bottom (TVD) 2,432 8,933 10218 11684 Length 2.500 9,200 1,400 3,100 Weight 68 47 47 29 Grade L-80 L-80 P-110 P-110 Connection BTC DWC/C DWC1C DWC/C Weight w/o Bouyancy Factor Ibs 170.000 432.400 65.800 89,900 Tension at Top of Section Ibs 170,000 498,200 65,800 89,900 Min strength Tension (1000 Ibs) 1661 1086 1493 929 Worst Case Safety Factor(Tension) 9.77 2.18 22.69 10.33 Collapse Pressure at bottom Psi 1,201 4,413 5,048 7,640 Collapse Resistance w/o tension (Psi) 4,760 5300 8530 Worst Case Safety Factor (Collapse) 0.00 1.08 1.05 1.09 MASP si 1,341 1 3,898 1 3898 3900 Yield psi 6,870 9440 11220 F�--Minimum Worst case safety factor Burst 0.00 1 1.76 2.42 2.88 Page 41 Revision 0 Dee, 2013 Anna #37A Drilling & Completion Procedure 24.0 12-1/41' Hole Section MASP 14 Maximum Anticipated Surface Pressure Calculation 12-1/4" Hole Section Hilcor� Anna 37A Cook Inlet, Alaska MD TVD Planned Top: 2500 2423 Planned TD: 10600 10218 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad GP -CI 8,159 40W Wet 9.4 0.490 C-4 8,544 2200 Gas 5.0 0.257 C-5A 8,659 1800 Gas 4.0 0.208 C-513 8,729 1800 Gas 4.0 0.206 VAT 9,039 2200 Gas 4.7 0.243 C7CT 9,109 2200 Gas 4.6 0.242 C7DT 9,178 2200 Gas 4.6 0.240 C-8A 9,278 2200 Gas 4.6 0.237 C-86 9,359 2200 Gas 4.5 0.235 C-8C 9,413 2200 Gas 4.5 0.234 C-9A 9,689 2200 Gas 4.4 0.227 C-9C 9,751 4200 Wet 8.3 0.431 Offset Well Mud Densities Well Max MW Ton (TVDI Bottom (TVD) Date Anna 17 9 ppg 3,500 10,020 1977 GP 13.11 RD 9.8 ppg 3,975 10,100 1992 GP # 50 9.4 ppg 3,880 9,851 1992 Anna 03 RD 10.5 ppg 7,755 10,219 1994 Assumptions: 1. Wet formation fluid gradient estimated at 8.5 ppg (0.442 psi/ft) 2. Fracture gradient at 2,500' MD / 2423' TVD is estimated at 0.85 psi / ft based on field test data. Fracture Pressure at 13-3/8" shoe considering a full column of gas from shoe to surface: 2423 (ft) x 0.85(psi/ft)= 2059 psi 20S9(psi) - (0.1(psi/ft)'2423(ft))= 1817 psi MASP from pore pressure (wellbore evacuated to gas from C4) 8544(ft) x 0.257(psi/ft)= 2195 psi 2195(psi) - l0.1(p,i/ft)'8544(ft))=r 1341 psi MASP from pore pressure (weilbore evacuated to water from GP-Cl): 8159(ft) x 0.490(psi/ft)= 4000 psi 4000(psi) - [0.442(psi/ft)"8159(ft))= 394 psi Summary: 1. MASP while drilling 12-1/4" production hole is governed by SIBHP - gas gradient to surface from the C4 sand (1341 psi). Page 42 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure 25.0 8-1/2" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 11 8-1/2" Hole Section H�ilcar Anna 37A Cook Inlet, Alaska MD TVD Planned Top: 10,600 10,218 Planned TD: 13,500 11,685 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad WET SAND 10,617 7100 Wet 12.9 0.669 HK-1* 10,683 7000 Oil/Wet 12.6 0.655 HK-2* 10,734 7000 Oil/Wet 12.5 0.652 HK-2-REPEAT 11,117 7000 Oil/Wet 12.1 0.630 HK-I-REPEAT 11,405 7000 Oil/Wet 11.8 0.614 WET SAND 11,471 7700 Oil/Wet 12.9 0.671 Offset Well Mud Densities Well Max MW Top (TVD) Bottom (TVD) Date GP 13-11 RD 13.5 ppg 10,100 11,407 1992 GP q 50 13.4 ppg 9,851 11,818 1 1992 Anna 03 RD 12.9 ppg 10,219 11,930 1 1994 Assumptions: 1. Fluid gradient from wet formations estimated at 8.5 ppg (0.442 psi/ft) 2. Fracture gradient at 10,700' MD / 10,237' TVD is estimated at 0.936 psi / it based on field test data. 3. 8.1/2" Hole section mud density planned at 12.9 ppg (0.6708 psi/ft) rCalculations assume Hemlock reservoir contains 100% gas (worst case). Production data indicates the eservoir contains 90 - 95 % water, 4% oil, and the remaining 1% a mixture of gas + oil. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 10218 (ft) x 0.936(psi/ft)= 9564 psi 9,564 (psi) - (0.1(ps1/ft)* 10,218(ft)j= 8542 psi Drilling Mode MASP MASP from pore pressure (2/3 wellbore evacuated to gas from top of Hemlock) 10,683(ft) x 0.655(psi/ft)= 7000 psi 7000(psi) - ((0.1(psi/ft)*10,683(ft)*2/3]+(0.671(psi/ft)*10,683(ft)*1/3))= 3$98 psi %' T&% r rf µ,—U Production Mode MASP o `3 MASP from pore pressure (wellbore evacuated to gas from HK-1): 10683(ft) x 0.6SS(psi/ft)= 7000 psi 7000(psi) - (0.1(psi/ft)* 10683(ft))= 5932 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from the HK-1 formation. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from the HK-1 formation. oo,� l�. C'4 '0 S •I Page 43 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp Energy campamy 26.0 Directional Program (P4) Hilc45 AN-37A (P8) Proposal Geodetic Report (Def Plan) it: Hkorp Energy Company Vertical Section Azimuth: 345,286 '(True North) 1: Granite Point Unit Vertical Section Origin: 0.000 ft.. 0,000 ft cture I Slot: Anna I log 2 slot 8 TVD Reference Datum: Rotary Table AN-37 TVD Reference Elevation: 124.000 ft above MSL !hole: AN37A Ground Elevation: 77.000 ft betaN MSL 507332037601 Magnetic Declination: 17,093' ey Name: AN-37A (P8) Total Gravity Field Strength: 1001.3649mgn (9 80665 Based) ey Date: December 09, 2013 Gravity Model: DOX I AHO I DDI I ERD 129.122 ' 14776,491 ft 15.853 I0 409 Total Magnetic Field 55558.170 nT ,dinato Reference NAD27 Alaska State Piano, Zane 04. US Feel Magnetic Dip Angle: 73 843' dion Let I Long: N 60' SW 36,96661'. W 151' 18' 45.29693' Declination Date: January20. 2014 lion Grid WE YIX: N 2551352254 fiUS, E 266849,461 ttUS Magnetic Declination Model: 8GGM 2013 Grid Convergence -1.1478 ` North Reference: True North Scale Facto: 0.99996185 Total Corr Mag NorthaTruo 0,0000' Ion I Patch: 2 T998 0 Total Corr Mag aGrid North: 17,0932 ° Local Coord Referenced To: Well Head MD Incl Azim True TVDSS TVD VSEC NS EW Ti OLS Directional Exclusion Exclusion Zone Easting Northing Comments (ft) {') (') (ft) (ft) ift► (ft) (n) C! ('it00ft) Difficulty Zone Alert Angie (ftus) (ftus) Index 0.00 0,00 0 00 -124 00 0,00 000 Ono 000 Om WA 000 1616 266849.47 2551352 25 1900. "0 0.00 .105 00 1900. 000 000 000 262,63%1 000 000 1616 M849 47 2551352.25 119.00 0.17 262.63 -5.00 119.00 002 .0.02 -0.15 241,71 M 017 0.00 16 23 266849.32 2551352 24 Writer 201.00 0.72 24371 7700 201,00 0,00 •0,10 -0.41 240.7M 0.10 0.00 16.31 266849.06 255135216 AAW0111c 219,00 0,23 240.70 95,00 219.00 -0.01 -0.14 -0,47 24.12M 0.10 0.00 16.32 266849,00 2551352.13 319 00 0.8$ 24.12 19500 319.00 051 0.44 -0 34 25 77LI 104 019 1531 266849A 3 2551352.70 419.00 300 25,77 294,93 41893 308 348 1,10 24.12M 215 120 1320 266850.64 2551355 71 519.00 3,43 24,12 394,78 51878 740 856 146 25.65M 0,44 1.80 12.76 266853.10 2561360,75 619.00 3.62 25.65 494.59 618.59 12.14 14.14 6.05 29.01M 021 1,83 QZ9 266855.80 2551366,27 20' 634.00 3,75 29,01 509.56 633.56 12,85 1&00 6.49 439M 1,68 1.88 12,51 266856.26 2551367,12 719,00 4.68 43,90 594.33 718,33 16.67 19.93 10.24 65,13M 1-68 2.13 12.16 266MA1 2551371.97 819.00 5.13 65A3 693.97 SiT97 1958. 24.75 17.13 71.38M 1.66 2.39 13..27 266867.09 2551376,65 919.00 5..95 71,38 793,50 917,50 2072. 28.28 26.10 85.42M 1,02 2.56 13.55 266876.13 2551380.00 1019.00 6.12 85,42 89295 101695 2014 3036 36.32 82 9M 1,48 272 1499 266886 39 2551381 88 1119.00 7.32 82.90 99227 111627 1836 3157 47.96 77.35M 124 2.66 14,71 266898,05 2551342.86 1219.00 8.82 77.35 1091,27 121527 17,24 3404 6176 2971. 169 3,01 1400 266911,90 2551395,05 1319.00 12.15 76.53 1189.59 131359 1673 38.17 79.48 6,37R 3,33 320 14.36 266929,69 2551388.82 1419,00 16.28 78.17 1286.51 1410,51 1580 43.50 10345 5.6R 4.15 3,40 16.32 266953,76 2561393,67 1519.00 18.53 78.97 1381.82 1505,82 1405 49.48 13309 8.31R 266 3,55 17.99 266983,52 2551399.05 1619.00 20,62 7987 1475.92 1599,92 11.66 5574 166,34 3.92R 1,71 367 1925 267016 88 2551404.65 1719.00 2048 79,72 156943 169343 894 6208 201,20 101371. 026 375 1943 267051,86 2551410.29 1819,00 20,83 79,00 166288 176668 641 6865 236.18 13 43R 026 3.82 1921 267086 97 2551416.16 19if)W 20,98 79.10 175629 1880.29 4.07 75,43 271.22 127991. 015 3,86 1934 267122,13 25514223 2019.00 20.85 78.63 1849,71 1973.71 1.84 82.32 30624 6.61R 021 3,94 19,12 267157.28 2551428A2 211900 21.13 78.72 1%1107 2067,07 -028 89.35 341_36 107All. 028 3,99 19.34 267192.54 255143475 2219.00 21.07 78.17 2036.37 2160,37 -226 96,57 376A3 177.151. 021 4.03 19.15 267227.94 2651441.25 2319,00 20,37 78.07 2129.90 2253,90 -4.01 10385 41l 26 154 081. 0.70 4.08 18,66 267262,70 2551447.84 Tie-in Survey 2419.00 20,32 78,00 2223.66 234T66 �5 68 111.06 44527 161.75R 0.06 4.12 18.61 267296.85 2551454 36 Top Wh�pstock 25W OO 20.13 78.19 2299,66 2423,66 -7.05 116,83 47267 45L 025 4,15 1853 267324.36 2551459,59 Base 2516.00 21,52 74,48 731462 243862 -7.15 118.18 47819 HS 1200 418 1846 267329.91 255146083 Whipstock cry 31100 2536,00 21.52 74.48 2333.23 2457.23 -7.05 120.15 48526 113.31- 0 00 4.19 1846 267337.02 2561462,66 26WOO 20.84 69,52 2392.91 251691 -5,74 127.27 507.24 10867L 3.00 4.23 1666 267359A3 25514%33 270000 20.07 6121 2486.62 261062 022 141.76 53894 100 89L 3.00 4,30 1390 267391.12 255148318 2800,00 19.71 52A5 258068 2704.68 1094 16030 56736 92 64L 3,00 4.36 1126 267419.90 2551501,15 2900.00 19.80 43,57 2674,81 279881 2639 182.66 59241 84 28L 300 442 8 85 26744540 2551523 20 3000.00 20.31 34.94 2768.77 289277 46.53 209.36 614,02 76.1SL 300 4.48 6.91 267467,53 2551549.26 3056.97 20.78 30.26 2822.12 294GA2 60,08 226.19 624.78 71.79L Ion 4.51 Enter Alen 620 267478,62 2551565.87 3100.00 21.22 26.87 2862.30 2986.30 71.31 23973 63214 68.621. 3,00 4.53 Alert 5.93 267486.26 2551579.26 End Cry 3165.19 22.00 22,00 2922,91 304691 89 92 261.57 64205 HS 300 4,56 Alen 605 267496.60 2551600.90 3200,00 22.00 72,00 295519 3079 19 10037 27366 646 93 HS 000 457 Aled 605 261501,72 2551612 89 Page 44 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcgy orp EnerCompany 3300.00 2200 22.00 3047,90 3171,90 13040 30SAU 66096 HS 0,00 4.59 Alert 6,05 267516AS 2551647,34 3400.00 22,00 22.00 3140,62 3264-62 160.43 343.13 675,00 HS 0.00 4.61 Alert 6,05 267531,17 2551681,78 MOM 22,00 22.00 3233,34 3357.34 190.46 377.86 689.03 HS 0.00 4,63 Alert 6.05 267545,90 2551716,22 3600.00 22.00 22.00 3326.06 3460.06 22OA9 41259 70306 HS 000 4.65 Alert 6.05 267560.62 25Si750.67 3700.00 22.00 22.00 3418.78 354218 250.52 447.33 717.10 HS 0.00 4.67 Alert 6.05 267575.35 2551785AII 3800.00 22.00 22.00 3511,50 363S$0 280.55 482.06 731,13 HS 0.00 4.69 Alert 6.05 267590.08 2651819.55 3900.00 22,00 22,00 3604,21 372821 310.58 516,79 745.16 HS 0,00 4.70 Alert 6,06 267604,80 255185400 4000.00 22,00 22.OD 369693 3820,93 34061 55153 759,19 HS 0,00 4,72 Alert 606 2676M53 25518NA4 4100,00 22.00 2200 3789,65 3913,65 370.64 586.26 77323 HS 0.00 4.74 Alert 6,06 26763425 2551922.88 4200.00 22.00 22.00 3882.37 4006.37 400.67 620.99 78726 HIS O.DO 4,75 Alert 6.06 267648.98 2551957,33 4300.00 22.OD 22.00 3975,09 4099,09 430,70 655.72 801,29 HS 0,00 4.76 Alert 6.06 267663,70 2551991.77 440000 22.00 22.00 4067,81 4191.81 460.73 690.46 815.33 HS 0,00 4.78 Alert 6,06 26767SA3 2552026.21 4500.00 22.00 22.00 4160,52 4284.52 400.76 125.19 829.36 HS 0100 4.79 Alert 6.06 26769115 2652060.66 460000 22,00 22,00 426324 437724 520.79 769.92 843-39 HIS 0.00 4.81 Alert 6,06 267707,08 25S2095.10 Cry 31100 4665.19 22.00 22.00 4313,68 4437,68 S40 36 702.57 85254 176.47L 0.00 4,81 Alert 6,06 267717A8 2552117,55 4700,00 20,96 21.92 4346.08 4470,08 550-59 794.39 857,31 170AL 3,00 4,83 Alert 5,04 26772248 255212928 4731.47 20.01 21.85 4375,56 4499,66 559,43 804.61 861,41 178.33L 3,00 4.84 Este' Fell 4.13 267726.79 2552139.41 4800.00 17.96 21,65 444036 456436 577.36 825.31 869,67 178.151. 3.00 4.86 Fell 224 267735,46 2552159.95 49000D 14.96 21.28 4536,25 466025 600.22 861,67 880,05 177.79L 300 4.90 Fat 1.64 267746.36 25521186.09 4994.57 12.12 20.75 462818 4752.18 618.19 872.34 MOO 177,281. 3.00 4,93 Exri Fag 4A3 267754.72 2562206,69 5000.00 11.96 20.72 4633A9 4767,49 619.11 873AO 888AO 17124L 3,00 4,93 Alert 428 267MAS 2562207,65 5085.61 10.00 20.17 4697.89 4621,89 629.32 88510 892,77 176,71L 3100 4,95 Ex4Alan 6,20 267759.75 255221926 510D,00 8,97 19.79 4731A2 4855.02 633.96 89043 894,70 176131. 300 4,96 7,21 267761.79 2552224.54 5200,OD 5,98 17.95 483096 4954,96 644.79 902.71 890.95 174,51L 300 4,98 1018 267766.28 2552236,74 End Cry 5200,18 5,97 17,94 4831.14 4965,14 64480 902.73 $98.95 HS 3,00 4.98 10,19 26776629 2552236,76 5300.00 5,97 17.94 4930.41 5054,41 653.54 912.61 902,15 HS 000 4,98 10.19 267769,68 2552246.57 5400,00 597 17.94 5029,87 5153.87 662.30 92251 905,36 HS 0.00 4,99 1019 267773,08 2552256,40 550000 5.97 17.94 5129.33 5253.33 671,06 932AO 908.56 HS 0.00 4,99 IlOA9 267776A8 255226623 6600.00 5.97 17.94 5228.79 5352.79 67942 942.30 91116 HS 0.00 4,99 10,19 267779,89 2552276.06 5700.00 5.97 17.04 632824 545224 688,57 952,19 914,97 HS 0.00 4.99 10.19 26779329 2552285.89 S800.00 SW 17.94 5427.70 5551.70 $97,33 96209 918,17 HS 0.00 5.00 10.19 267786,69 2552295.72 MOM 547 17.94 6527.16 5651.16 706,09 971,98 921,38 HS 0.00 5.00 10,19 267190,09 2552305,55 6000,00 5,97 17.94 5626,62 5750,62 714,85 981.88 924,58 HS 0OD 5100 10,19 267793.49 2552315,38 6100,00 5,97 17.94 572607 585007 723,60 991,78 927,78 HS 000 501 10,19 26779649 25S232521 6200.00 517 17.94 5825.53 5949,53 732,36 1001.67 93029 HS OM 5,01 10.19 267800,30 2552335.04 8300.00 5,97 17.94 5924.99 6048.99 741.12 1011,57 934.19 HS 0.00 5.01 10,19 267803.70 2552344.87 6400.00 5.97 17.94 6024.45 6148AS 749.87 1021A6 937AO HS 0.00 6.01 10.19 267807.10 2552354.69 6SOO.00 6,97 17.94 6123.9D 6247,90 758.63 1031.36 940.60 HS 0.00 S42 1019 267810,50 255236CS2 6600.00 5.97 17.94 6223.36 6347.36 76739 104125 943.80 HIS 000 6.02 1019 26781190 255237435 6700.00 5,97 1744 6322,42 6446,62 776,15 105115 94701 HS 0.00 5,02 1019 267817.30 2552364.18 6800.00 5,97 17.94 6422,28 654628 784.90 1D61.05 950.21 HS 0,00 5.02 10,19 267820.70 2552394,01 6900.00 5,97 17,94 652114 664514 793.66 1070.94 953A2 HS 0.00 5,03 1019 267824.11 2552403.84 7000.OD 5,97 17.94 6621A9 6745.19 802,42 1080.84 956.62 HS 0.00 5.03 10.19 267827,51 2552413.67 7100,00 5.97 17.94 6720AS 6844.65 811,18 1090.73 959.83 HS 0.00 5.03 1019 267830.91 2652423.50 7200,00 547 17.94 682011 6944.11 819.93 1100.63 963.03 HS 0,00 6.03 10.19 267834,31 25S243133 7300.01) 5.97 1744 6919,57 7043.57 828,69 111042 966.23 HS 0.00 5.04 1019 267837.71 2552443.16 7400.00 5,97 17,94 7019,02 7143,02 037,45 112OA2 969A4 HS 0.00 5,04 1019 267841.11 2552452,99 7500,00 5,97 17.94 7116.48 7242,40 $46.21 113032 972,64 HS 0.00 5,04 10.19 267844.52 2552462,82 7600,00 5,97 17,94 7217.94 7341,94 854.96 114021 976,85 HS 0.00 5,04 1019 267847,92 2552472.64 7700.00 547 17,94 7317.40 7441AO $63,72 1150.11 979.05 HS 0.00 5,05 10.19 26?851.32 2552482.47 7800.00 6,97 17.94 7416,85 7540AS 872AS 1160.00 902.25 HS 0.00 5.05 1019 267854.72 2552492,30 MOM 5.97 17.94 7616.31 7640.31 981.24 116940 985A6 HS 0.00 6.05 10,19 267868,12 2652502.13 800000 5.97 17.94 7615,77 7739.77 889.99 1179.79 988.66 HS 0.00 5,05 10.19 267861.52 2552511.96 8100.00 5,97 17.94 7715,23 1839,23 89815 1189A9 991AT HS 000 5,06 10.19 26786d.92 2552521.79 820000 5.97 17.94 7814,68 793868 907.51 1199.59 995.07 HS 000 506 10.19 2678WL33 2552531.62 830000 5,97 17,94 7914,14 8038,14 91627 1209AS 9"27 HS 0.00 5.06 10,19 267871,73 2552541AS 8400.00 5.97 17.94 801160 8137.60 925.02 1219.38 1001.48 HS 0.00 506 10.18 267875.13 2552551.28 8500.00 5,97 17.94 8113,06 8237.06 93178 122927 100418 HS ODD 5.07 101B 267878.63 2652561.11 8600.00 5.97 17.94 8212.61 $336.51 942.54 1239,17 1007.89 HS O00 6.07 10.18 267881.93 2S52570.94 8700.00 6.97 17.94 8311.97 WSW 96129 1249.06 1011.09 HS 0.00 SW 10.18 267885.33 2652580.77 8800.00 $17 17,94 $411.43 8535A3 96005 1258,96 101429 HS 0,00 6.07 10,18 267888,74 2552590.59 89D0.00 5,97 17.94 851089 $63489 96841 1268,86 1017.50 HS 0,00 5.08 10,18 267892.14 2552600,42 9000.00 5.97 17,94 8610.34 6734,34 97757 1278.75 1020.70 HS 0.00 5,08 10.18 267895,54 255261025 9100.00 597 17.94 8709.80 8833,80 986,32 1288.65 1023,91 HS 0.00 5,08 10.18 26789894 2552620.08 9200.0D 517 17.94 880926 893326 995,08 1298.S4 1027.11 HS OM 5.08 1018 26790234 2552629.91 9300,00 5.97 17.94 8908.72 903212 1003.84 1308A4 1030.32 HS 0.00 5,09 10.18 267905.74 2552639.74 Cry 31100 9355.32 5.97 17.94 8963.74 9087.74 1008.68 1313.91 1032.09 54.39L 0.00 5.09 1018 267907.63 2552645.18 9400,00 6.84 8,76 900814 9132.14 101348 1318.76 1033,21 45,26L 300 5.10 9," 267908.84 2552649.99 9500,00 9.20 355.30 9107,16 $231,16 102641 1332.61 1033,46 31,941. 3.00 5,12 8,33 267909,37 2552663.84 "WOO 11.85 347,55 9205.48 9329AB 1D44,55 1350,60 1030,59 24,32L 3100 5,14 821 267906,06 2552681,89 970000 14.64 342.66 930281 9426,81 1067.43 137289 102461 19.55L 3,00 5,17 9.13 26790123 2552704.09 9800,OD 17A9 339.32 9398,90 9522,90 1095,01 139842 1015.54 16.341. 3,00 5,19 10.83 267892,78 2552730.39 9900.00 20.39 336.90 9493.48 9617.48 1127A9 1428.90 1003.39 14.051. 300 521 13.00 267881.24 2552760.72 10000.00 23.31 335.06 9586.29 971029 1163.90 1462,87 98821 12,34L 100 524 iSAS 267866.75 2552794.98 10100.00 26.2$ 333.61 967707 9801.07 120S03 1500.62 970.04 11,02L 3,00 5,26 1&06 267849.33 2562833.09 1020000 2920 332.43 9765,59 9889,59 1250A7 1542,06 948.92 9.981. 3,00 $29 20,77 267829,04 255287494 1030000 32,15 331.46 985158 9975,58 1300.10 1567,07 924,91 9.14L 3.00 5,31 2155 267805.94 2552920.41 10400.00 3512 330.63 9934,83 10058,83 135178 1635.52 $98.08 8.451. 3.00 5,34 26.38 267780.09 2552969.39 End Cry 10486,93 3710 330.00 10004.79 10128.79 1403,62 168034 872.52 HS 3,00 5,36 28,86 267755.43 2553014.71 9-&'81 10500.00 37.70 330.00 1001513 10139.13 1411,33 168726 868,52 HS 0.00 5.36 2846 267751.58 2553021.71 10576.93 37.70 330.00 10076.00 10200,00 1456.71 1728,00 845,00 HS 0.00 5,37 28,86 267728,88 2553062.91 Cry 1.8/t0O 10S96.93 37.70 330.00 10091.82 10215.82 1468,51 1738.59 838.88 2.24R 0,00 5,37 28.86 261722.98 2553073.62 10600.00 37.76 330.00 10094,25 10218,25 1470,32 174022 837.95 2,24R 1.80 6,31 28.91 267722,07 2553015.27 10700,00 3955 330.11 10172,34 1029634 1530,59 1794.34 806.77 215R 1,60 5.39 30,52 267691,99 255313000 10800.00 41,35 330.22 10248,43 1037243 159322 185063 77449 207R 1,80 5A1 32.15 267660,84 2553186,92 10900.00 43.15 330.31 10322.44 10446.44 1658.16 1909,01 741,14 2R 180 5,43 33.80 267628.67 255324596 11000.00 44.95 330.40 10394,31 10518.31 172515 1969,44 706,75 1.94R 1,80 5,46 35.46 267595.50 2553307.06 Page 45 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure HilmiT Energy Company 11100.00 46.75 330.48 10463.95 10587.95 1794.71 2031.86 671.36 1.88R 1,80 5.48 37.13 267561.36 2SS3370.17 11200,00 48.56 330.56 10531.31 10655.31 1866.17 2096.20 634.99 /.83R IA0 5,50 38,81 26762620 2553435.23 IxIPn 11276.11 49.92 330,62 10581.00 10705.00 1921.93 2146.42 NCO 18,55L 1.80 5.51 40.10 267499,00 2563486.00 11300,00 50.33 330.44 10696,32 1072032 1939.67 2162.38 597.66 18.43L 1,80 5.52 40,53 267490.30 2553502.14 11400,00 52.04 329.72 10658,99 10782,99 2014,65 2229.91 558.80 17,98L 1,80 534 4233 267452,80 2553570.43 115W00 53.76 329.03 10719,31 10843,31 2091,55 2298.54 518,16 17,57L 180 5,56 44.13 267413.55 2553639.86 11600.00 55A7 328.37 1077722 10901,22 2169.68 2368.19 475,81 17.18L 1.80 5.58 45,93 267372,60 2553710.35 11700.00 57.20 327.74 10832.65 10956AS 2249,17 2438.81 431.77 16.831. 1.80 5.60 47.73 267329,98 2553781.63 11800.00 58.02 327.13 10885.56 11009,56 2329.94 2510.32 386,09 16.51L 110 5,62 49.53 267285.75 2553854.24 11900.00 60.65 326.54 10935.88 11059.88 2411.90 258266 338.62 1822L 1,80 SAM 51.33 267239.94 2S53927.50 12000,00 62.38 325,98 10963,68 11107.58 2494.99 2665.74 290.01 15.95L 1,80 5,66 53.13 267192,60 2554001,54 12100.00 64,11 325.43 11028,60 11152.60 2579.11 272950 239,69 15.7L 1,80 5.67 54.93 26714317 255407629 12200,00 65,64 324.89 11070.90 11194,90 2664.18 2803,66 187.92 15,47L 1,80 5.69 56,73 26709151 2554151,68 12300,00 67.58 324.37 11110.44 11234,44 2750,13 287816 134.76 15.27L 1,80 5.71 58.53 267041.86 2554227.62 End Cr.. 12322,47 67.97 324,26 11118.94 11242.94 2769.55 2895.66 12263 HS 1.80 5.72 58,93 267030.07 2554244,76 12400,00 67.97 32426 11148.02 11272.02 2836.63 2963.99 80.65 HS 0,00 5.73 58,93 26698927 2554303.92 12487.91 67.97 324.26 11181.00 11305M 2912.70 3020.14 33.05 HS 0.00 6,74 68.03 266943.00 2554371.00 12500,00 67.97 324.26 11185,53 11309,53 2923,16 3029.23 26.50 HS 0.00 6,74 68.93 266936,64 2554380,22 12600.00 67,97 324.26 11223.05 11347.05 3009.68 3104,47 -27AS HS 0,00 5,75 58,93 266684.01 2554456.53 12700,00 67.97 32426 11260.56 11384.56 3096.21 317911 .8119 HS 0,00 5,76 58.93 266831,39 255453283 12800,00 6717 324.26 11298,07 11422,07 3182,73 3254,95-135.94 HS 000 578 58.93 266778,76 2554609.14 12900.00 67.97 324.26 11335.59 11459.59 326926 3330,19-190,08 HS 0,00 5.79 68.93 266726.13 2554685A5 13000.00 67.97 324.26 11373.10 11497.10 3355.78 3405A3-244.23 HS 0.00 5.80 58,93 266673.51 2554761.75 13100.00 67.97 324.26 11410.61 11534.61 3442.31 3480.66-298,38 HS 0.00 5.81 58.93 266620.88 2554838.06 13200.00 67,97 324.26 11448.12 11572.12 3528,83 3555.90-352.52 HS 0,00 5.82 S8.93 26656826 2554914.36 13300.00 67,97 324,26 11485,64 11609,64 3615,36 3631,14 .406,67 HS 0.00 583 58.93 266515.63 2554990,67 13400.00 67.97 $24.26 1152315 1164715 3 IA$ 3706.38-460.82 HS 0.00 5.84 5893 20463.00 255506697 To 13500.00 67.97 324.26 11560.66 11684,66 3788,40 3781.62-514,96 0,00 5,85 5893 266410 38 2555143 28 Page 46 Revision 0 Dec, 2013 Hilcorp Energy Company 27.0 Directional Plan View (XY) VIEST (ft) EAST Anna #37A Drilling & Completion Procedure Page 47 Revision 0 Dec, 2013 Hi1COIp Energy CO-P-Y 28.0 Plan View (VS / TVD) Vertical Section Plane (0.00 ft N, 0.00 ft E) s` 345.29° Anna #37A Drilling & Completion Procedure Vertical Section (ft) -3500 0 35DO 7000 Page 48 Revision 0 Dec, 2013 Anna #37A Drilling & Completion Procedure Hilcorp EneW Cximrwy 29.0 Spider Plot (Governmental Sections) M A104ROST28HI. 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Wph 4659 2$ 256 &) $3037 "OC 06F 160 OW,91 U22 06 L4"P*0-SF 5673(4 2V4 44 $40067 631 " '!W4 011110 811,410 1611111 WFI-0-sr 6227.50 232, 11 $772,39 Se 95' 5 OSF I so 10062 15 976790 TO W4369WSAW 1 14" N It Wt 1444,34 �141071 �'I OSF 160 241900 230,66 mrp" 42670 16,,874 40601 4110 0,V 150 $72397 $4760 UrPt."F AM" 1053 40WI 47 4618 OSF 150 643319 616146 k4ript-W e41500 MeAD 62" 2b 6204 3tt 06f 160 911310 Ox 0 Unpt-osf 647595 27054 6206 23 62OS36 3603 OSF i So 9t7S40 89A74 21t TO Page 57 Revision 0 Dec, 2013 32.0 5-1/211 Drill Pipe Specifications avtn.ti(?'s*-CvmCira?Cf'r.},:o Phaoc •". C2'Lt}878CA7?3 Drill Pipe Configuration Pipe Body OD k', 5.500 Pipe Body Walt ThiOneag 0.415 Pipe Body Grade S-135 Drill Pipe Length Ranue2 Connection KT55 Too] Joint OD Ov 7.000 Tool Joint ID (n 4.000 Pin Tong 10 Box Tong tfi, 15 Drill Pipe Performance Anna #37A Drilling 8, Completion Procedure Rig Drill Pipe Performance Sheet 80 % Inspection Class NOmetat ht nation 24.70 Drill Pipe Approximate Loth thi 31.8 SmoothEdge HeIgtd tn13132 Raised Tool Joint SMYS ($ `} 120.000 1.1wiType tEU Max Upset DD (DTE) friction Factor 1.0 for Tarr) spov a maY'-V O .xang ce of Drill Pipe with Pipe Body at Best Estimates 80 % Inspectlon Class 1-1-mcw*v I ... Opel a, Ir1ax Tatassan 0011 Poe Adiusted Weight om t` 29.01 Tortxta to i iias.L fluid Dis lacernent taarrn 0.0106 Tension Only 0 704.300 FW Capacitytea 0.0203 0.0202 � L 41.900 1599,600 Drift size )'n, 3.875 38,600 Tangy ant o ... 1704.300 conibtrvadt.ae N 33.900 1637.600 4kd. Thw ftu -up axvw shm" ba DPiA»d v nvt N rtr; P" Bod Burst dPeO 16 Pipe Body Collapse tPsi> 11,177 Connection Wear Table No* oA Ikid tnrnat *qO* 42 US gold" W" Dot pipe aseemth vok" are treat eMmatea ad may vary due to pipe body WO lotion, Oft"W PAMW motrtg, W4 t#vx boom. wctn. Ur6^re3gad eoomcacns L."" be abi* to raid Wrw ssmd pipe prtuums.. cOnntcians O"h a "till to &* IA a ia4 S" O"t d'A pin naaa. ddKtljuiad wM an `U' in V* t&ai,.. art gVeo a pteatrre ratfttp. Connection NT55 Tooi Joint qD 7.00� Toct Joint ID ;,,; 4.t1J0 Toot leant $ .� a ht;nagxsrn 120,000 Yce,d St�an�cn ice+: Tool Joint OD Max MUT Cortn Mon Marc Tension 7 46,300 992,700 6.957 46,300 982,400 6.915 145,600 993,400 6,872 144,000 1.030.900 6.83 42,500 1,064,400 6.787 41,000 1,096,400 6.745 39,500 1,127.700 6.702 38.000 1.157,300 6.66 36,500 1,186,200 6.617 35,100 1,210.400 6.575 33,600 132,200 1,2361700 6.532 11,225.900 Min MUT t" 4as1 Comnsbon Max Tension tabs` 38.600 1.240,800 38,600 1,227.900 38,000 11.233,400 36,700 1,228,900 35,400 1,201,000 34.100 1,173.400 32,900 1,148,700 31,700 1,124,200 V.500 1.099,200 29.200 1,070,800 28,000 1,045,600 2b,80o 1,020.300 Page 58 Revision 0 Dec, 2013 �I I 1 IVY TLI LaE T TER CHEA C LIST WELL DAME: �- AA) t-ik PT Si 1 Vq Z- 3?A r�TD: � 5 ✓ I)e%elopiuent _ Scn icc I ploratory Strati<'rahllic Test Non-C'omciitioual FIELD: POOL: U'14'nJ 611 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-- (lf 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 locus 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 ennit). 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 pennafrost 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. In addition to the well logging program proposed by (CompaU Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after com letion, suspension or abandonment of this well. Revised 5/2013 WELL PERMIT CHECKLIST Field & Pool GRANITE PT, HEMLOCK UNDEF OIL - 280152 PTD#: 2131990 Company HILCORP ALASKA LLC Initial Class/Type Well Name: GRANITE PT ST 18742 37A Program DEV Well bore seg DEV / PEND GeoArea 820 Unit 00000 On/Off Shore Off Annular Disposal Administration 1 Permit fee attached NA 2 Lease number appropriate Yes ADL0018742. ENTIRE WELLBORE 3 Unique well name and number Yes Granite PT ST 18742-37A 4 Well located in a defined pool No GRANITE PT. HEMLOCK UNDEF OIL - 280152 5 Well located proper distance from drilling unit boundary Yes 6 Well located proper distance from other wells Yes 7 Sufficient acreage available in drilling unit Yes 8 If deviated, is wellbore plat included Yes 9 Operator only affected party Yes Wellbore will be more than 500' from an external property liner where ownership or landownership changes. 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order Yes Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes PKB 12/26/2013 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.030(j.1.A).(j.2.A-D) NA 18 Conductor string provided NA Conductor set in AN -37 Engineering 19 Surface casing protects all known USDWs NA No aquifers... offshore. 20 CMT vol adequate to circulate on conductor & surf csg NA Surface casing cemented in place. 21 CMT vol adequate to tie-in long string to surf csg Yes 9 5/8" will be tied back to surface and cemented to within 500ft of 13 3/8" window 22 CMT will cover all known productive horizons Yes (cut and pull 9 5/8" from 2500 ft md) 23 Casing designs adequate for C, T, B & permafrost Yes BTC calculations are provided and meet industry accepted standards. 24 Adequate tankage or reserve pit Yes Drilling waste will be disposed of as permitted by ADEC . 25 If a re -drill, has a 10-403 for abandonment been approved Yes 313-614 - sidetrack out of 13 3/8" casing at 2500 ft. 26 Adequate wellbore separation proposed Yes Proximity analysis performed.. No issues. 27 If diverter required, does it meet regulations NA Wellhead in place .. BOPE will be used. Changing out tubing head. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press=7000 psi (12.6 ppg EMW) May be higher presurres in Wet sand lobes.. 12.9 ppg. 29 BOPEs, do they meet regulation Yes Rig 428 has 13 5/8" 5000 psi BOPE. (Drilling 8.5" OH section wiwth 12.9ppg mud) 30 BOPE press rating appropriate; test to (put psig in comments) Yes MASP = 3898psi will test BOPE to 5000 psi (alternate MASP calc approved 2/3 gas evac) 31 Choke manifold complies w/API RP-53 (May 84) Yes 32 Work will occur without operation shutdown Yes 33 Is presence of H2S gas probable No H2S not expected .Rig has sensors and alarms. 34 Mechanical condition of wells within AOR verified (For service well only) NA 35 Permit can be issued w/o hydrogen sulfide measures Yes H2S not expected. Geology 36 Data presented on potential overpressure zones Yes Expected reservoir pressure is 11.54 ppg EMW; reservoir section will be drilled using 12.9 ppg mud. Appr Date 37 Seismic analysis of shallow gas zones NA 9 5/8" csg will be set to isolate any potentially depleted sands in Tyonek prior to drilling production intery PKB 12/26/2013 38 Seabed condition survey (if off -shore) NA Development well off Anna Platform 39 Contact name/phone for weekly progress reports [exploratory only] NA Geologic Engineering Public Sidetrack of well AN-37 out of 13 3/8" surface casing at 2500' md. Will target Hemlock reserves north of current BHL. GIs Commissioner: Date: miss, er: Date C i i ner Date