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213-028
STATE OF ALASKA • ALA.. .1 OIL AND GAS CONSERVATION COMP. _4ION WELL COMPLETION OR RECOMPLETION REPORT AND LOG la.Well Status: at P 4idas ❑ SPLUG ❑ Other ❑ Abandoned ❑ . Suspended❑ lb.Well Class: 2OAAC 25105 2OAAc 25.110 Development ❑✓ . Exploratory ❑ GINJ ❑ WINJ❑ WAG ❑ WDSPL❑ No.of Completions: _0 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12.Permit to Drill Number: Hilcorp Alaska,LLC ' (Aband.: 12/23/2014 ` ' 213-028/314-620 3.Address: 6.Date Forded: 13.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK,99503 5/6/2013 50-133-10109-02-00 ' 4a.Location of Wel(Governmental Section): 7.Date TD Reached: 14.Well Name and Number. Surface: 961'FNL,1127'FEL,Sec 4,T7N,R9W,SM,AK ' 5/16/2013 SCU 41A-04< Top of Productive Horizon: 8.KB(ft above MSL): 192.3- 15.Field/Pool(s): GL(ft above MSL): 173.7. Swanson River Field/ Total Depth: 9.Plug Back Depth(MD+TVD): Hemlock Oil Pool . 1257'FNL,1016'FEL,Sec 4,T7N,R9W,SM,AK •9,086'MD/9,086'TVD• 4b. Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface: x- 346506.3 • y- 2460223.8 • Zone- 4 • . 10,807'MD/10,75T TVD . A028997 • TPI: x- y- Zone- 11.SSSV Depth(MD+ND): 17.Land Use Permit: Total Depth: x- 346599.1 y-2459919.2 Zone- 4 N/A N/A 18.Directional Survey: Yes ❑✓ No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-driI/Lateral Top VMrdow MD/TVD: N/A N/A 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOOM HOLE SIZE CEMENTING RECORD PULLED 22" ' Surf 22' Surf 22' 13-3/8" 54.5# J-55 Surf 3,000' Surf 3,000' 7" 23291E N-80 Surf 9,591' Surf 9,590' 4-1/2" 12.6# L-80 9,383 10,790 9,382' 10,747 6" 294 sx Q 15.3 ppg 24.Open to production or injection? Yes ❑ No 0 25. TUBING RECORD If Yes, list each interval open(MD+TVD of Top and Bottom;Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): N/A N/A N/A "- ' 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. � Math��t . ri I ZL)AI ,1/44 RECEIVED Was hydraulic fracturing used during completion? Yes❑ No Q (�„} DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED ,JAN 1 6 2015 AOGCC 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): N/A Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: N/A Test Period Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate ...► 28. CORE DATA Conventional Core(s)Acquired? Yes❑ No Q Sidewall Cores Acquired? Yes❑ No 0 If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. sCNNNE® i`moi', , 1) - ±1`; Form 10-407 Revised 10/20127 p ' /3-CONTI�LED Q )4.0S ,> / „t r5- RBDMS V aJANonly 6 20154 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes 0 No If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form, if Permafrost-Top needed,and submit detailed test information per 20 AAC 25.071. Permafrost-Base Formation at total depth: 31. List of Attachments: Operations Summary,Schematic 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Stan Porhola Email: Sporholaa.hiIcorp.com Printed Name: Stan Porhola Title: Operations Engineer� Signature: `/�' Phone: %o1— 7 1 7 -ref IL Date: 14()/ INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift, Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 ,i4 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 12/14/14 12/23/14 Daily Operations: 12/14/2014-Sunday Rig down on well SCU 21C-04, move all rig modules off location. Felt, liner on well SCU 41A-04 (SCU 41B-04), spot sub, set draw works, derrick, gen sets, pump houses, 1 pit section. Start hooking up utility lines, prep derrick for raising. 12/15/2014- Monday Drop travel beam out of sub, hang windwalls, spot top drive on rigfloor, spot pumps, pits, boilers and rig up he same. Put down felt and containment for pipe shed. Change out cylinder on derrick and raise same. Spot catwalk with choke house, pipe sheds and hook up same, steam, electrical, Hyd. Cut and slip 136' of drilling line, prep derrick to be raised, pick up torque tube and telescope the derrick up. Put top drive in blocks and install kelly hose. 12/16/2014-Tuesday Continue to R/U on SCU 41A-04. R/U hydraulic and steam lines. Spot gen 3, Halliburton trailers. Replace gate seals in pits. Replace broken bolts on iron ruffneck face plate. Perform 125 day inspection on draw works. Check air operation to rig floor motor. C/O swivel packing. Install saver sub, bails. Function test top drive. Install 2" bleeder valve and lines. R/U tongs, replace riser cables in pits. R/U fuel lines to boilers. Fill pits with 359 bbls of produced water. Change bed rubbers on #1 shaker. R/U centrifuge, gas buster line. Install cuttings box chute. Prime and pressure test mud pump and lines. Install Gas buster hose and choke hose from catwalk to I/A, install hose from stand pipe to tree valve to kill well. Pressure test lines to 500 psi. Note: tubing 240 psi, IA 125 psi. PJSM, Kill well pumping 8.4 ppg produced water down tubing at 5 bpm, 50 psi, taking returns thru choke and gas buster, as fluid started up the annulus the tubing pressure increased to 1,500 psi with 40 psi on the casing. Hole capacity is 215 bbls and we pumped a total of 280 bbls with no returns. Flow Check while hauling produced water, no flow. Accept rig @ 06:00. Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 12/14/14 12/23/14 Daily Operations: 12/14/2014-Sunday Rig down on well SCU 21C-04, move all rig modules off location. Felt, liner on well SCU 41A-04 (SCU 41B-04), spot sub, set draw works, derrick, gen sets, pump houses, 1 pit section. Start hooking up utility lines, prep derrick for raising. 12/15/2014-Monday Drop travel beam out of sub, hang windwalls, spot top drive on rigfloor,spot pumps, pits, boilers and rig up he same. Put down felt and containment for pipe shed. Change out cylinder on derrick and raise same. Spot catwalk with choke house, pipe sheds and hook up same, steam, electrical, Hyd. Cut and slip 136' of drilling line, prep derrick to be raised, pick up torque tube and telescope the derrick up. Put top drive in blocks and install kelly hose. 12/16/2014-Tuesday Continue to R/U on SCU 41A-04. R/U hydraulic and steam lines. Spot gen 3, Halliburton trailers. Replace gate seals in pits. Replace broken bolts on iron ruffneck face plate. Perform 125 day inspection on draw works. Check air operation to rig floor motor. C/O swivel packing. Install saver sub, bails. Function test top drive. Install 2" bleeder valve and lines. R/U tongs, replace riser cables in pits. R/U fuel lines to boilers. Fill pits with 359 bbls of produced water. Change bed rubbers on #1 shaker. R/U centrifuge, gas buster line. Install cuttings box chute. Prime and pressure test mud pump and lines. Install Gas buster hose and choke hose from catwalk to I/A, install hose from stand pipe to tree valve to kill well. Pressure test lines to 500 psi. Note: tubing 240 psi, IA 125 psi. PJSM, Kill well pumping 8.4 ppg produced water down tubing at 5 bpm, 50 psi, taking returns thru choke and gas buster, as fluid started up the annulus the tubing pressure increased to 1,500 psi with 40 psi on the casing. Hole capacity is 215 bbls and we pumped a total of 280 bbls with no returns. Flow Check while hauling produced water, no flow. Accept rig @ 06:00. 12/17/2014-Wednesday Continue to test BOPE with water. Pull BPV, install TWC.Test upper pipe 2-7/8"VBR ram with 4-1/2" and 2-7/8"test jts,test lower 2-3/8" ram with 2-3/8"test jt, blind ram, HCR kill and kill valve, HCR, 3" manual valve, FOSV, Dart valve, upper and lower IBOP to 250psi low/3,500_psi highi 10 minutes ea.Test annular with 2-3/8" and 4-1/2"test jts to 250psi low/2,500 ps highi 10 minutes ea. Chart all tests. Perform accumulator draw down test. R/D test equipment, blow down choke and gas buster. PJSM, R/U Weatherford power tongs and 2-7/8" handling equipment. M/U landing jt and top drive. Close annular, line up to closed choke. Back out LDS per cameron rep. Pull 80k to unseat hanger, P/U 2'. Open choke, pump 8.4 ppg produced water down tbg 5 bpm, pump 91 bbls before seeing tbg pressure, continue to pump 5 bpm, 1,450 psi. See returns out gas buster @ 180 bbls pumped. shut down pump,well on vac.Open annular, close choke. Pull 90k, packer sheared at 15k over string wt. pull hanger to rig floor @ 10,237'. Establish loss rate @ 140 bph, pump down backside using rig pump @ 3 bpm keeping hole full. L/D landing jt and hanger. Blow down choke,gas buster and top drive. POOH from 10,237'to 5,171' L/D 2-7/8" production string filling backside @ 70 bph with 8.4 ppg produced water. Current losses to well: 531 bbls of produced water. 12/19/2014- Friday Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 12/14/14 12/23/14 Daily Operations: Trip out lying down the 2-7/8" casing F/5,000'to 966'.Wipe down each jt and put protectors on each end. Continue tripping out with the 2-3/8"tubing F/966'to the packer and entry sub, lay down same. PJSM,Close blind ram. R/D Bell nipple, N/U lubricator. R/U Priority e-line. M/U 12.6#4 1/2"CIBP, Baker#10 setting tool, 3 1/8"CCL with quick change, pressure test lubricator to 250psi low/3,000 psi high 10 min ea. Open blind ram.TIH with e-line, locate 4-1/2" collar @ 10,359'. Set 4-1/2" CIBP @ 10,367' (CIBP set 8' below 4-1/2" collar and 50' above top perf). POH with setting tools. Fill wellbore, 38 bbls. Well is static. R/U test equipment,close blind ram, Monitor 0/A.Attempt to test bridge plug, pressure up using mud pump to 1,500 psi w/no further pressure increase, 5 bbls pumped,shut off pump. Pressure bled to 0 psi. Check surface equipment. Attempt to re-test with same results. Open blind rams. R/D test equipment,well remains static. M/U 3"x 40' bailer,3-1/2"CCL and XOs, load w/12 gallons of 16.6 ppg cement. RIH,tag CIBP on depth @ 10,367', bail cement. POH, Load bailer w/12 gallons of cmt, RIH to 10,349'and bail remaining cmt to 10,332' (35'of cmt on top of plug) POH. Load 12 gallon barite slurry in bailer. RIH to 10,332', bail 14 ppg barite slurry on top of cmt plug. POH, L/D tools. R/D wire line. Last 24 hrs well took 606 bbls of produced water.Total losses 1,137 bbls of produced water. 12/20/2014-Saturday Nipple down the wire line lubricator and install flow nipple. Install wear bushing with a 6-3/8"ID,Service rig and topdrive. Mobe drill pipe and strap same. M/U 6" bit- MX-18HDX Tricone bit with 3 x 14 jets, 7"csg scaper, bit sub,xo=7.79',Static loss rate @ 21 bph. Drift and single in the hole w/4-1/2" drill pipe scraping 7"casing to 4,500'. Fill pipe every 2,500'. Continue to single in the hole with 4-1/2" drill pipe from 4,500'to 9,379'just above 4-1/2" liner top @ 9,383'. Fill pipe every 2,500', use continuous hole fill on trip in, hole took 200 bbls on TIH. M/U top drive, Break circulation, pump 500 stks,shut down pump. Establish loss rate-continues @ 21 bph. Blow down top drive. POH with 7"scraper assy from 9,379'to 3,400', use continuous hole fill on trip out. Last 24 hrs well took 438 bbls of produced water.Total losses 1,575 bbls of produced water. 12/21/2014-Sunday Continue to POH with 7" casing scraper from 3,400', L/D casing scraper assembly. PJSM, R/U Weatherford tongs and handling equipment. M/U Halliburton 4-1/2" RTTS assembly.Single in the hole with 2-7/8"drill pipe to 1,000'. RIH with 4-1/2"drill pipe in derrick from 1,000'to 9,422',84' below 4-1/2"TOL. P/U 148K,S/O 148K. Note: lost 87 bbls on trip in the hole. Set RTTS @ 9,422',attempt to pressure up on CIBP, leaking by RTTS, release RTTS. RIH and re-set RTTS @ 9,495', pressure up on plug, RTTS holding but leaking past CIBP. Close annular, monitor 0/A. Pressure up on backside to 2,600 psi, lost 50 psi in 5 minutes, good test. Bleed off pressure,open annulus. Release RTTS. RIH from 9,495'to 10,278'. P/U 162K,5/0 161K.Set RTTS @ 10,278',attempt to test CIBP, leaking by plug. Close annular, monitor 0/A. Pressure up on backside to 2,600 psi, bleed off 50 psi in 10 minutes. Good test on I/A to surface. Confirm CIBP not holding. Bleed off pressure, open annular. Release RTTS. Blow down top drive, POH from 10,278'to 1,000'. R/U power tongs and 2-7/8" handling equip. POH from 1,000' L/D 32 jts 2-7/8" drill pipe. L/D RTTS.Trip out of the hole took 110 bbls over calculated displacement. Last 24 hrs well took 287 bbls of produced water.Total losses for SCU 41A-04 1,862 bbls of produced water. 12/22/2014-Monday Hi corp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 12/14/14 12/23/14 Daily Operations: R/D Weatherford tongs and power unit. PJSM, R/U Priority e-line and lubricator. Pressure test lubricator to 250psi low/ 3,000psi high 5 min ea. Open blind ram. RIH and set 4-1/2"CIBP @ 10,297', POH.Close blind ram, monitor 0/A,attempt to test CIBP, pressure up to 2,300 psi, leaking by plug. Open blind ram. Rig service,grease crown sheaves,drawworks,change oil in drawworks transmission.Wait on Halliburton 4-1/2" EZ Drill plug. Pressure test lubricator to 250psi low/3,000psi high 5 min ea. RIH and set 4-1/2" EZ drill plug @ 10,275', POH. Close blind ram, monitor 0/A,test EZ drill plug to 2,600 psi for 30 charted minutes. No pressure loss.Good test. Bleed off pressure, open blind ram. M/U 3"x 40' bailer, 3-1/2"CCL and XOs, load w/12 gallons of 16.6 ppg cement. RIH,tag 4-1/2" EZ drill plug on depth @ 10,275', bail cement. POH, load bailer w/12 gallons of cmt, RIH to 10,256'and bail remaining cmt to 10,240' (35'of cmt on top of plug) POH. L/D bailer assembly. R/U 7" CIBP and CCL tools, RIH,set C113.13.@ 9,086' (5' above collar @ 9,091'). POH, R/D e-line. Remove X0 flange for lubricator. M/U bell nipple and lines, pull 6-3/8"wear bushing, install test plug.With 3 barriers in place,C/O lower 2-3/8" pipe ram, install 2- 7/8"x 5-1/2"VBR. Last 24 hrs well took 113 bbls of produced water.Total losses for SCU 41A-04 1,975 bbls of produced water. 12/23/2014-Tuesday Cont NU flow riser and button up ram doors after ram change.Test 2-7/8"x 5-1/2"VBR to 250/3,500 psi at 10 minutes each on chart. R/D test equipment. Rack and Tally Baker whipstock/milling tools. M/U BHA. BTM trip anchor,WS slide, 6"window mill, 5-7/8"WMM, Flex jt, 6"WMM,float sub, UBHO sub,xo.Single in the hole with 30 jts 4-1/2" HWDP=964.74'.TIH from 964'to 9,044'at 1-2 min per stand. Easy in and out of the slips. Fill pipe, R/U Pollard e-line with Gyro tools and side entry sub. M/U 1 stand and top drive. P/U 160k,S/0 160k. RIH with Gyro on e-line to 9,000' @ UBHO sub. Latch gyro in UBHO sub,with tool face of 354 deg,work pipe down in 10' intervals 3 times.Check tool face,338 deg.Turn pipe 1/8 turn to right,work torque down in 10' intervals 3 times. Check tool face @ 0.52 deg, P/U e-line 30', RIH and retag UBHO sub. Check tool face @ 2.2 deg. POH with e-line. L/D side entry sub and gyro tools. R/D e-line.Set top drive torque @ 12.5K. M/U stand and top drive. RIH and tag CIBP @ 9,073' MD.Set down 20K and set anchor. P/U 10K over to verify anchor set. Set down 40K and shear whipstock bolt. P/U 5'TO 9,050'. Whipstock orientation is at 2.2 deg as per version#3 of directional plan. Displace with 9.8 - ppg drilling mud pumping 5 bpm, 1,800 psi. P/U 160K,S/0 160K, ROT 160K,95 RPM,torque off 4,300#. Mill window as per Baker Rep.Time mill 6"window from 9,055'to 9,062' pumping 355 gpm, 1,970 psi, 1.5-2K wt on mill, 95 RPM,average torque @ 4-7K. Ditch magnets and catch pans in place,start seeing metal @ shaker after 2' of window milled.Total losses for SCU 41A-04 1,975 bbls of produced water. Swanson River Unit Well: SCU 41A-04 5/27/2013 ACTUAL SCHEMATIC Completion Ran: PTD: 213-028 Hilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL 22"J Size Type Conductor Wt Grade Conn. ID Top Btm 22" Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' DV Collar 29 N-80 BIC 6.184" Surf 304' • 2,002' 26 N-80 BIC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' `' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' TUBING J S la) Ll L JEWELRY DETAIL 0 No. Depth ID _ OD Item Ilar 1 9,086' - 3.9" Bridge Plug(Set for whipstock) 1 `� 2 10,275' 3.9" Bridge Plug(Capped w/35'of cement);Test to 2,600 psi(OK) 3 10,297' - 3.9" Bridge Plug;Failed Press Test 4 10,367' - 3.9" Bridge Plug(Capped w/35'of cement);Failed Press Test 1 5 10,777' - CIBP I ,: )))2A9 ‘,..,..? • 0 ' - �0, 1 5p- •iPhA, ,1l 1 , _` � Y+ 7" Y a6O`�p)- Gg ilotPERFORATIONS Zone _ Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date * ',t H4 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 2 .4.' 1 H5 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 H7 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 Failed H9 10,668' 10,681' 10,626' 10,639' 13' 6 1-11/16"strip _ 09/29/13 3 •ressure H10 10,710' 10,730' 10,666' 10,685' 20' 6 1-11/16"strip 04/07/14 loomed Pi Test •4+ Failed 4 yk .•ressure it, Test H4 j :-.-.n iH5 11 H7 "4si : H9 -= H10 k �t r, z ik* Fill Tagged @ 10,742'SLM 5 , 1.75"Bailer(8/24/14) 4-1/2" , Pi 6"Hole TD=10,807'MD-10,758'ND Max Deviation 19°@ 10,516' PBTD=10,777'MD-10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Revised: 12/23/14 Updated by STP 1/14/15 Image Project Well History File Cover Page XI-IVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. p21 3_ QQ,$ Well History File Identifier Organizing(done) 'wo-sided III IIEIIIIII liii ❑ Rescan Needed III II11II1 I III III 1 RE AN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: eyscale Items: ❑ Other, No/Type: ❑ Other Items Scannable by VV✓✓ a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non-Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: , BY: Date:3/411 /s/ Project Proofing III I II IIIII 11111 BY: Date: 3/41/If. /s/ Scanning Preparation (0 x 30 = / ESQ + a% _ = TOTAL PAGES (Count does not include cover eet) BY: Maria 4 Date: 3 1 /s/ Y V 11 Production Scanning I Stage 1 Page Count from Scanned File: ad 7 (Count does include cover et) Pa•e Count Matches Number in Scanning Preparation: YES NO BY: an, Date:3/141 I LL- /s/ r Stage 1 If NO in stage 1, page(s)discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III IllIllIllIl II III ReScanned I 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked III I 12/22/2011 Well History File Cover Pape.doc • STATE OF ALASKA Mr.__ A OIL AND GAS CONSERVATION COMM10010N REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well Lf Plug Perforations U Perforate U OtherU Pull Capstring Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well E 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ I 213-028 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 4 50-133-10109-02 7.Property Designation(Lease Number): 8.Well Name and Number: • A028997 s Soldotna Creek Unit(SCU)41A-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A • Swanson River Field/Hemlock Oil 11.Present Well Condition Summary: 1 RECE VEC Total Depth measured • 10,807 feet Plugs measured 10,777 feet true vertical 10,757 feet Junk measured N/A feet MAY 0 7 2014 Effective Depth measured 10,777 feet Packer measured 10,244 feet ."lOGCC true vertical 10,730 feet true vertical 10,226 feet Casing Length Size MD ND Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' •3,800"---- -~. 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic SCANNED 1\A NY 2 °u Mil 2-7/8" 6.5#/L-80 9,304'MD 9,304'ND Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,270'MD 10,250'ND Tri-Point Packers and SSSV(type,measured and true vertical depth) Hydraulic Pkr-N/A 10,244'MD 10,226'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A , Intervals treated(measured): N/A RBDM5'-? MAY 17 2014 Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 47 1 212 1180 180 - Subsequent to operation: 26 62 489 1230 180 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development 0 i Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil J Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 314-125 Contact Stan Porhola Email sporhola cl.hilcorp.com Printed Name di-- Stan Porhola Title Operations Engineer Signature k,..,p � Phone 907-777-8412 Date S 7 Form 10-404 Revised 10/2012 /, /,� Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/7/14 4/7/14 Daily Operations: 04/07/2014- Monday MIRU Pollard E-line. Rig up. PT Lubricator 250/3,000 psi -test OK. PU GR/CCL. RIH and tag PBTD at 10,735' WLM. POOH. PU 20' of 1-11/16" Owen Shogun Strip Gun @ 6 spf. RIH and correlate using GR/CCL. Correlate to Tie-in log Baker LWD dated 5-07-13. SITP = 185 psi. Perforate 10,7101-10,730'. No change in tubing pressure. POOH. Rig down. Swanson River Unit Well: ACTUAL SCHEMATIC• CompletionSCU41A-045/Ran: 27/2013 PTD: 213-028 Hilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 22" 2 22" Conductor Surf22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' DV Collar 29 N-80 BTC 6.184" Surf 304' • 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 3 f 0 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' �F TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' , JEWELRY DETAIL No. Depth ID OD Item DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT 6 944' 2 20' 2.441" 4.250" XO 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice 4 k }I 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' 2.313" 3.625" X-Nipple 7 9,304' 1.995" 2.875" X0 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 10 10,254' 1.875" 3.000" X-Nipple 5 0 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 12 10,777' - CIBP 6 X 7 , Capillary String Plan to Re-Install at new depth 3/8" 2205 Stainless Steel 211/8 I e qMD Top0' Bottom 0' L_ TVD 0' 0' lb I II ".' 9 41: , PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10© H4 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 H5 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 11—... H7 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 I H9 10,668' 10,681' 10,626' 10,639' 13' 6 1-11/16"strip 09/29/13 'li H10 10,710' 10,730' 10,666' 10,685' 20' 6 1-11/16"strip 04/07/14 -r GLV Port Temp @ E H4 # Size Depth TCF PSC PSO PTRO Description 4 16 105:0.904 1805 2000 2190 IPOR-1/IPOC-1/PPOR-1 ; r. f H5 3 16 140 0.841 1763 1885 2080 IPOR-1/IPOC-1/PPOR-1 H�� 2 16 170 0.794 1714 1786 2000 IPOR-1/IPOC-1/PPOR-1 s H9 1 20 185 0.773 ORIFICE-1 tiil�ti�ti:ti�s� H10 ,.?;:yar;:. r' Fill Tagged @ 10,735'RKB 12 . ,;r•r-r-r-1 1.75"GR(4/07/14) rJI, 6"Hole TD=10,807'MD—10,758'TVD Max Deviation 19°@ 10,516' PBTD=10,777'MD—10,730'TVD Max Dogleg 6.5°/100'@ 9,831' Downhole Revised:4/07/14 Updated by STP 05/07/14 •••••'"'•••"Y'CL]YCW45WI5YYi'i1 WIIT�a.iTm "^"+Y'"".;yroe..iWM•Yw/rYwtl'...._."i YIW""S.a,i3tiv.• W M'u. .. ..a.u.wdiw xmiu-=m^r..aw... Yfurro �w����1 1/7 ,N i Fit .S 1 A I L d-i J i, min a.:_, P .' /1 @ \ \, i s t = :533 W(3.i Seventh Avenue Anchorage, Alaska 99501 3572 wr "'� Main. 907 279 1433 SCANNE° AUG 0 2V14 Stan Porhola q Operations Engineer ( 3' 0 d- Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 41A-04 Sundry Number: 314-125 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, or f-; t, 'V-r't—' Cat y P. oerster Chair DATED this7ay of March, 2014. Encl. . . RECEIVED V t► STATE OF ALASKA MAR 0 4 4014 ALASKA OIL AND GAS CONSERVATION COMMISSION OTS �3 - /g. APPLICATION FOR SUNDRY APPROVALS AOCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Wale Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate Q ' Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter Casing❑ Other. Pull Capstring Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC - Exploratory IllDevelopment Q • 213-028 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service ❑ 6.API Number: • Anchorage,Alaska 99503 50-133-10109-02 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B Sddotna Creek Unit(SCU)41A-04 - Will planned perforations require a spacing exception? Yes ❑ No 0❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997 Swanson River Field/Hemlock Oil 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 10,807' ' 10,757' ' 10,777' 10,730' 10,77T N/A Casing Length Size MD TVVD Burst Collapse Structural Conductor 22' 22" 22' 22 Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8"/2-3/8" L-80/L-80 9,304'/10,270' Packers and SSSV Type: Packers and SSSV MD(t)and TVD(ft): Tri-Point Hydraulic Packer/N/A 10,244'MD/10,226'ND/N/A/N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphicn Development n Service n 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 03/10/14 Oil Q • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Email sDorhola( hilcorD.con) Printed Name Stan PorholalaTitle Operations Engineer Signature ✓"�'"X-- Phone 907-777-8412 Date • / �f f J/4 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: `l-l._ �j�! Plug Integrity ❑ BOP Test Li Mechanical Integrity Test ❑ Location Clearance p ` Other: R8DMS MAY 10 2014 Spacing Exception Required? Yes ❑ No j 1 Subsequent Form Required: /0_ 1./64,./ APPROVED BY Approved by: 9ail, 0&014_,‘____ COMMISSIONER THE COMMISSION Date: 3 - 7. / il, Form 10-403(Revised 10/2012) App o gaep i4 I IIL>b 12 months fr4he date of approval. Attachments in Duplicate ip_t nt Well Prognosis Well: SCU 41A-04 Hilcorp Alaska,Lb Date:3/04/2014 Well Name: SCU 41A-04 API Number: 50-133-10109-02 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: March 10th, 2014 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 213-028 First Call Engineer: Stan Porhola (907)777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: 1,986 psi @ 10,519' ND Based on June 2013 static survey at top of the Hemlock H-10. Maximum Expected BHP: 1,986 psi @ 10,519'ND Based on June 2013 static survey at top of the Hemlock H-10. Max.Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 5,361 ft. ND. Brief Well Summary This well was drilled and completed with the Doyon Arctic Fox in May 2013. The well is currently producing approximately 55 bbls of oil and 200 bbls of water per day on gas lift completion. A capillary string was run in July 2013 to aid dealing with downhole emulsions. Perforations were added to the Hemlock H-11 and the 3/8" ✓ capillary string re-ran to a deeper depth in September/October 2013. Notes Regarding Wellbore Condition New completion ran in May 2013.Capstring run in July 2013. • Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 2. POOH w/3/8" capillary string that was set at 10,160'. 3. Store capillary string spool on pad for re-installation. 4. Rig down Cap String Truck. 5. Turn well over to production. E-line Procedure: 6. MIRU E-line, PT lubricator to 3,000 psi Hi, 250 psi Low. 7. RIH w/1.75"gauge ring to 10,777'. POOH. 8. RIH and perforate Hemlock H-10 w/1-11/16" strip gun from 10,688'to 10,744' (56'). POOH. a. Hole angle at perfs is+/- 19°. 9. RD E-line. 10. Turn well over to production. Capstring Procedure: • , • Well Prognosis Well: SCU 41A-04 Hilcorp Alaska,LL Date:3/04/2014 11. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 12. PU 3/8"capillary string. RIH and set at+/-10,250'. 13. Set spool of remaining line near well. 14. Rig down Cap String Truck. 15. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic . • ll Swanson River Unit • Well: SCU 41A-04 ACTUAL SCHEMATIC Completion Ran:5/27/2013 PTD: 213-028 Llilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL V 1 LSize Type Wt Grade Conn. ID Top Btm 22"41 0 2 Ma 0 22" Conductor - - - Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' s29 N-80 BTC 6.184" Surf 304' i DV Collar 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' �# b 7" Production Casing 26 _ N-80 _ BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' . 6,489' II 26 N-80 LTC 6.276" 6,489' 9,346' 11 29 N-80 LTC 6.184" 9,346' 9,591' 3 lit 1 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' I:'4 JEWELRY DETAIL No. Depth ID OD Item DV Collar lip 1 18' 2.992" _ 6.184" Tubing Hanger 3-1/2"IBT Mr' 6,944' 2 20' _ 2.441" 4.250" XO 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SF0-1,8RD,Orifice k 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice 4 5 8,899' _ 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' _ 2.313" 3.625" X-Nipple .'" ' 7 9,304' 1.995" 2.875" X0 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SF0-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 10 10,254' 1.875" 3.000" X-Nipple 5 Alt ' 11 10,270' _ 1.995" 2.375" Wireline Re-Entry Guide II . } 12 10,777' CIBP Ir 6 El V J 7 a Capillary String Installed on 10/02/2013 3/8" 2205 Stainless Steel 8 Top Bottom p, MD 0' 10,160' Il TVD 0' 10,146' 9 PERFORATIONS A Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10 © H6 10,417' 10,426' • 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 f"1' H7-H9 10,442' 10,530' • 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 11 H10 10,553' 10,598' •_ 10,518' 10,560 45' 6 2-3/4"TCP 05/26/13 H11 10,668' 10,681' . 10,626' 10,639' 13' 6 1-11/16"strip 09/29/13 GLV Port Temp @ # TVD MD Size Depth TCF PSC PSO PTRO Description 4200 4200 16 105 0.904 1805 2000 2190 IPOR-1/IPOC-1/PPOR-1 7000 7000 16 140 0.841 1763 1885 2080 IPOR-1/IPOC-1/PPOR-1 «. H6 8900 8900 16 170 0.794 1714 1786 2000 IPOR-1/IPOC-1/PPOR-1 +°, 10180 10180 20 185 0.773 ORIFICE-1 {s,- H7-H9 4 liE H10 i• 12 < H11 4-1/2" *% 6"Hole TD=10,807'MD-10,758'ND Max Deviation 19°@ 10,516' PBTD=10,777'MD—10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Revised: 10/02/13 Updated by STP 3/02/14 1H Swanson River Unit 4 Well: SCU 41A-04 PROPOSED SCHEMATIC Completion Ran:5/27/2013 PTD: 213-028 Hilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' l CASING DETAIL tm 22"J 2 .A L� 22" Condp f 6 or Wt Grade Conn. ID Top Surf 22' J 13-3/8" Surf.Csg 54.5 1-55 STC 12.615" Surf 3,000' ' r�, DV Collar 29 N-80 BTC 6.184" Surf 304' n, 2,002' 26 N-80 BTC 6.276" 304' 1,235' 4'P. 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 3 ED) 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' • 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' A. JEWELRY DETAIL No. Depth ID OD Item ' I DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT 6,944' 2 20' 2.441" 4.250" XO 3-1/2"IBT Box x 2-7/8"8rd Pin ' 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice kay 4 CD) 1 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice ;� 6 9,297' 2.313" 3.625" X-Nipple ril V 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin tT 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice • 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer *" 10 10,254' 1.875" 3.000" X-Nipple 5 i .A 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 12 10,777' - CIBP 6 > 7 Capillary String Plan to Re-Install at new depth 3/8" 2205 Stainless Steel — Top Bottom 2, 8 "�pP `► MD 0' lei.'°r, IF : TVD 0' ly.'it 9 -w i9 PERFORATIONS • + , Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date , 10 0 H4 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 H5 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 g- 11• H7 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 ,y+' H9 10,668' _ 10,681' 10,626' 10,639' 13' 6 1-11/16"strip 09/29/13 ; H10 10,688' ' 10,744' - 10,645' 10,698' 56' 6 1-11/16"strip Proposed , t . GLV Port Temp @ 46 = Ha # TVD MD Size Depth TCF PSC PSO PTRO Description ' 4 4200 4200 16 105 0.904 1805 2000 2190 IPOR-1/IPOC-1/PPOR-1 V' - H5 3 7000 7000 16 140 0.841 1763 1885 2080 IPOR-1/IPOC-1/PPOR-1 H7 2 8900 8900 16 170 0.794 1714 1786 2000 IPOR-1/IPOC-1/PPOR-1 1 10180 10180 20 185 0.773 ORIFICE-1 ems, A „' 12 4-1/2"` a. ro•J '`� 6"Hole TD=10,807'MD–10,758'ND Max Deviation 19°@ 10,516' PBTD=10,777'MD–10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Proposed Updated by STP 03/04/14 iI ! 7 M o 1 O I o (NJ 0 0 N rn I z O 0 0 0 0 0 N o V. 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Ce H j1 JJ W co W co d p it To 0 Y M M U d�+ .Q Q N N 7 p p I W N Q N N N Z Ut a 0.13 Q . D o O N J a c 1 co J 7 a 1I a m CL O u) c U U c M c d H G co 11 O N_ a !. O ~ c Q II n V U Z a) �j o co )E>- >- >- n J o i c , o no a E U I— v c r F- M N D i I IN N ■ a7 N C Z, a: M Y N ate+ p N E j W U C 0 II 'I Q , �I Z r m (.3 s• o, II, . CO O f0 U) .0 a> co c H o 4 G p c D ` Q -J c m I co D. C •U N ' Q a li U L O z p • U _ 0 E 0 5 2 0 i_ -tom ea z M M _ co as a) / Ip p Q O O O _� _� o z n 1, �I or, m N >- >- >- N 1 Q Q j u7 M j I O p € O ' ) c J II m o , N 1. C f0 Q. H j o rn co W E a O II w N 8 W .d e- N d Ill >C a w = E E z N m Y W m , cc L 3 O I▪ W y Z C z c m 0 H a) • I U O Q o a < o 0 c ar f 0 6 o 0 0 U g '� g H 71 a d .c D o a H E a m Q` o cLL 2 a O o a G H o 1 o p jp 0 ? i 0 0 0 0 0 a 9 a W w RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION OCT 2 8 2013 REPORT OF SUNDRY WELL OPERATIONS OGCC 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U - •Other ✓ Change Capstrings Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension p Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 111 Exploratory p 213-028 , 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service p 6.API Number: Anchorage,Alaska 99504 50-133-10109-02 . 7.Property Designation(Lease Number): 8.Well Name and Number: A028997• Soldotna Creek Unit(SCU)41A-04 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil • 11.Present Well Condition Summary: Total Depth measured 10,807 feet Plugs measured 10,777 feet true vertical 10,757 feet Junk measured N/A feet Effective Depth measured 10,777 feet Packer measured 10,244 feet true vertical 10,730 feet true vertical 10,226 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 9,304'MD 9,304'TVD Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,270'MD 10,250'TVD Tri-Point Packers and SSSV(type,measured and true vertical depth) Hydraulic Pkr-N/A 10,244'MD 10,226'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 82 22 246 1100 150 Subsequent to operation: 89 1 570 1300 180 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory p Development 0 . Service ❑ Stratigraphic p Daily Report of Well Operations X 16.Well Status after work: Oil Is . Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-498 Contact Stan Porhola Email sporholaCp�hilcora.com Printed Name Stan Porhola Title Operations Engineer / Signature tv Phone 907-777-8412 Date �o/ 2-/ Form 10-404 Revised 10/2012 //lc--/3 Submit Original Only Swanson River Unit Well: SCU 41A-04 ACTUAL SCHEMATIC Completion Ran:5/27/2013 PTD: 213-028 Ililcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL J 1 Size Type Wt Grade Conn. ID Top Btm 22" 2 22" Conductor Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' DV Collar 29 N-80 BTC 6.184" Surf 304' 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 3 ED) 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' 4 TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' is ,, . JEWELRY DETAIL No. Depth ID OD Item ' ' DV Collar 1 18' 20' 2.992" 6.184" Tubing Hanger 3-1/2"IBT 6 944' 2 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice 4 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' 2.313 3.625 X-Nipple 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 10 10,254' 1.875" 3.000" X-Nipple 5 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 12 10,777' CIBP L 6 ) 7 Capillary String Installed on 10/02/2013 3/8" 2205 Stainless Steel 8 Top Bottom z-- ) 11 r• MD 0' 10,160' TVD 0' 10,146' Iltlil 't• 9 . PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10© , H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 11• H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 H11 10,668' 10,681' 10,626' 10,639' 13' 6 1-11/16"strip 09/29/13 -.N ;N 04 • +,1 = H6 s H7-H9 H10 12 = H11 41/2". ',° 6"Hole TD=10,807'MD—10,758'TVD Max Deviation 19°@ 10,516' PBTD=10,777'MD—10,730'TVD Max Dogleg 6.5°/100'@ 9,831' Down hole Revised: 10/02/13 Updated by STP 10/25/13 Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 9/29/13 10/3/13 Daily Operations: 09/26/2013 -Sunday MIRU EL,Tested lub and TIH w/ 1-11/16" shotgun 13' to 10,750'. Made correlation pass. Correlated to HEC Gamma Ray/CCL. In position fire gun, perf from 10,668'-10,681'. Pressure increased 20psi. PU to and recorded pressure for 40 mins. POOH. RDMO EL. 09/29/2013 -Sunday MIRU EL,Tested lub and TIH w/ 1-11/16" shotgun 13'to 10,750'. Made correlation pass. Correlated to HEC Gamma Ray/CCL. In position fire gun, perf from 10,668'-10,681'. Pressure increased 20psi. PU to and recorded pressure for 40 mins. POOH. RDMO EL. 10/03/2013 -Thursday Rig Up Cap String Truck. Rig up lubricator and adapter. Test to 3,000 psi. RIH w/3/8" capillary string. Set capillary string @ 10,X00'. RDMO Cap String Truck. Schwartz, Guy L (DOA) From: Schwartz,Guy L(DOA) Sent Friday, September 27, 2013 12:14 PM To: 'Stan Porhola' Subject: RE:Change to Approved Sundry(313-498) SCU 41A-04(PTD 213-028) Stan, You have verbal approval to change pert interval to H11 bench as proposed. The wellwork should be reported under sundry 313-498 with a 10-404. You are changing the scope of work somewhat but this doesn't warrant a new sundry. Guy Schwartz Senior Petroleum Engineer AOGCC 907-444-3433 cell 907-793-1226 office From: Stan Porhola [mailto:sporhola@-)hilcorp.com] Sent: Wednesday, September 25, 2013 8:07 PM To: Schwartz, Guy L(DOA) Subject: Change to Approved Sundry(313-498)SCU 41A-04(PTD 213-028) Guy, We are requesting a change to the approved sundry(313-498)for the proposed workover of SCU 41A-04(PTD 213-028). Our new plans are to defer the rig workover and defer the additions of the Hemlock H-1 and H-2 intervals.This is based on our recent results from the perforating of the Hemlock H-2 in well SCU 12B-09(PTD 213-062).After perforating the Hemlock H-2,the well has produced at a rate of 5.0 MMCF/D of gas with no oil and a few barrels of water.Similar results are anticipated in this interval in the SCU 41A-04 well. Attached are the proposed changes to the procedure and proposed schematic to instead perforate the Hemlock H-11 thru-tubing.This well currently has a capillary string that will be pulled ahead of the planned e-line perforating and a longer capillary string will be installed after the perforating. Let me know if you have any questions. Regards, Stan Porhola Operations Engineer North Kenai Asset Team Hilcorp Alaska, LLC sporliola @hilcorp,rom Office: (907) 777-8412 Mobile: (907) 331-8228 1 r II Swanson River Unit PROPOSED SCHEMATIC Well:CompletonRan:::5/27/2013 PTD: 213-028 Hileorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL 22 2 LJ 22" Conductor Wt Grade Conn. Surf 22' - -13-3/8" Surf.Csg 54.5 i-55 STC 12.615" Surf 3,000' Dv Collar 29 N-80 BTC 6.184" Surf 304' 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 3 1.---0 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' 1I JEWELRY DETAIL No. Depth OD Item ' U DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT 6 944' 2 20' 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice 4 I 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' 2.313" 3.625" X-Nipple 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 10 10,254' 1.875" 3.000" X-Nipple 5 I— bi 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 12 10,777' - CIBP 6 } 7 Capillary String Plan to re-install after 9/28/2013 3/8" 2205 Stainless Steel g Top Bottom MD 0' 10,250' TVD 0' 10,231' 9 PERFORATIONS Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10E H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 11- H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 1 = H6 H7-H9 H10 12 4-1/2"��`p 6"Hole TD=10,807'MD–10,758'TVD Max Deviation 19°@ 10,516' PBTD=10,777 MD–10,730'TVD Max Dogleg 6.57100'@ 9,831' Downhole Proposed Updated by STP 09/25/13 Well Prognosis Well: SCU 41A-04 Hilcorp Alaska. Date:9/25/2013 Well Name: SCU 41A-04 API Number: 50-133-10109-02 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: September 28th,2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 213-028 First Call Engineer: Stan Porhola (907)777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405(0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: 1,986 psi @ 10,519'TVD Based on June 2013 static survey at top of the Hemlock H-10. Maximum Expected BHP: 1,986 psi© 10,519'TVD Based on June 2013 static survey at top of the Hemlock H-10. Max.Allowable Surface Pressure: -0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 5,361 ft. ND. Brief Well Summary This well was drilled and completed with the Doyon Arctic Fox in May 2013. The well is currently producing approximately 100 bbls of oil and 200 bbls of water per day on gas lift completion. A capillary string was run in July 2013 to aid dealing with downhole emulsions. Plan is to add perforations to the Hemlock H-11 and re-run a 3/8"capillary string to a deeper depth. Notes Regarding Wellbore Condition New completion ran in May 2013.Capstring run in July 2013. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 2. POOH w/3/8"capillary string that was set at 8,900'. 3. Store capillary string spool in Hilcorp inventory. 4. Rig down Cap String Truck. 5. Turn well over to production. E-line Procedure: 6. MIRU E-line, PT lubricator to 3,000 psi Hi,250 psi Low. 7. RIH w/1.75"gauge ring to 10,777'. POOH. 8. RIH and perforate Hemlock H-11 w/1-11/16"strip from 10,668'to 10,681'(13'). POOH. a. Hole angle at perfs is+/-19°. 9. RD E-line. 10. Turn well over to production. Capstring Procedure: 0,t",\ 1//77,s, THE STATE Alaska Oil and Gas , + ofl 1LAS Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue vo 0,p; �� Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 41A-04 Sundry Number: 313-498 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. oerster Chair, Commissioner DATED this 7)¢-d of September, 2013. Encl. ( •1r . . {I � EC V w.i STATE OF ALASKA Oki/ EP 1 7 1 ALASKA OIL AND GAS CONSERVATION COMMISSION pA S 4l APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate 0 ' Pull Tubing0 ' Time Extension❑ Operations Shutdowl❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter casing❑ I Other❑ 2.Operator Name: r. Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development is . 213-028 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic El Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-10109-02 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123B Soldotna Creek Unit(SCU)41A-04 • Will planned perforations require a spacing exception? Yes ❑ No El 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997 Swanson River Field/Hemlock Oil • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 10,807' 10,757' . 10,777' 10,730' 10,777' WA Casing Length I Size MD ND Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8"/2-3/8" L-80/L-80 9,304'/10,270' Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): Tri-Point Hydraulic Packer/N/A 10,244'MD/10,226'ND/N/A/N/A 12.Attachments: Description Summary of Proposal Is 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 11 Exploratory [1 Stratigraphit❑ Development pi ervice ❑ 14.Estimated Date for 15.Well Status after proFosed work: Operations: 09/28/13 Commencing Oil g O p is Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Email soorhola( hilcorD.com Printed Name Stan Porhola Title Operations Engineer // Signature ...,),..4.46-r--- /?v1(J___ Phone 907-777-8412 Date Ct/ 7 5 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: V3 — 4-EC(y6 _ Plug Integrity ❑ BOP Test E( Mechanical Integrity Test ❑ Location Clearance ❑ Other: Y .36W s L 150 P zs-r RBLi /MS OCT 1 0 20131 Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0 —L/011 11 APPROVED BY C/� Approved by: COMMISSIONER THE COMMISSION Date: "- — 7 3 A ' � 7.23-/.� Submit Form and FA 'l Form 10-403(Revised 10/2012) Appro Rc�t64v�l�f f gmonth feI rom the date of approval. s in Duplicate I.1 Well Prognosis Well: SCU 41A-04 Hilcorp Alaska,LL Date:9/16/2013 Well Name: SCU 41A-04 API Number: 50-133-10109-02 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: September 28th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 213-028 First Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: 1,986 psi @ 10,519'ND Based on June 2013 static survey at top of the Hemlock H-10. Maximum Expected BHP: 1,986 psi @ 10,519'ND Based on June 2013 static survey at top of the Hemlock H-10. Max. Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 5,361 ft. ND. Brief Well Summary This well was drilled and completed with the Doyon Arctic Fox in May 2013. The well is currently producing approximately 100 bbls of oil and 200 bbls of water per day on gas lift completion. A capillary string was run in July 2013 to aid dealing with downhole emulsions. Notes Regarding Wellbore Condition New completion ran in May 2013. Capstring run in July 2013. WO Rig Procedure: CAP S J " 1. MIRU Moncla#405 WO Rig(formerly Williams#405). 2. Set TWC in tubing hanger, ND tree, NU 7-1/16" BOPE and test to 250psi low/310O0psi high, annular to 250psi low/1,500psi high (hold each valve and test for 10-min). Record accumulator pre-charge pressures. PA"r- a. Notify AOGCC 24 hrs in advance to witness. b. Notify BLM 48 hrs in advance of BOP test. ' c. Crew will be working 12hr shifts and well will be secured nightly with TIW valves and BOPE. 3. Release test pressure, pull TWC and install handling sub in hanger. 4. Back out tbg hanger hold down pins and pick up on hanger. 5. RU to pull tubing hanger and unseat Tri-Point Hydraulic packer at 10,243' (straight-pull release)and SOOH with 2-7/8" EUE 8RD production tubing from 9,304' and 2-3/8" EUE 8RD production tubing from 10,270'. a. Lay down 3 joints of 2-3/8"tubing. 6. MIRU E-line, PT lubricator to 3,000 psi Hi,250 psi Low. 7. RIH w/3.50"gauge ring to 10,777'. POOH. 8. RIH and perforate Hemlock H-2 w/3-1/8" HC from 10,270'to 10,283' (13'). POOH. a. Hole angle at perfs is+/- 19°. Well Prognosis Well: SCU 41A-04 Hiicorp Alaska,LL Date:9/16/2013 9. RIH and perforate Hemlock H-1 w/3-1/8" HC from 10,224'to 10,258' (34'). POOH. ./ a. Hole angle at perfs is+/- 19°. 10. RD E-line. 11. PU new hydraulic packer. 12. RIH and set packer at+/- 10,153' MD. a. Leave tubing tail at least 30' above Hemlock H-1 perfs at 10,224'. b. Pre-load lower X-profile with RHCP plug. c. Space out Gaslift Mandrels as previous completion. d. Run live valves in Gaslift Mandrels. 13. Drop RHCP prong and pressure up to 2,500 psi and set hydraulic packer. 14. Test tubing to 3,500 psi. 1 , 5 f- L4 fio 15. ND BOPE. NU Tree and test to 5,000 psi. 16. RD Moncla#405 WO Rig and move off location. 17. Turn well over to production. Slickline Procedure: 18. MIRU Slickline, PT lubricator to 3,000 psi Hi, 250 psi Low. 19. RIH and pull RHCP prong and plug. 20. RD Slickline. 21. Turn well over to production. Capstring Procedure: 22. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 23. PU 3/8"capillary string. RIH and set at+/-10,160'. 24. Set spool of remaining line near well. 25. Rig down Cap String Truck. 26. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. BOPE Schematic Swanson River Unit Well: SCU 41A-04 ACTUAL SCHEMATIC Completion Ran:5/27/2013 PTD: 213-028 Ililcorp Alaska,LLC API: 50-133-10109-02 K B-TH F: 17.83' CASING DETAIL 1 Size Type Wt Grade Conn. ID Top Btm 22' 2 22" Conductor Surf 22' 13-3/8" Surf.Csg 54.5 1 55 N-80 SIC 12.615" Surf 3,000 DV Collar 29 BTC 6.184" Surf 304' 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' 3 i TUBING 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' JEWELRY DETAIL No. Depth ID OD Item DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT ' I 6 944' 2 20' 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice 4 i 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' 2.313" 3.625" X-Nipple ' 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer ✓ 10 10,254' 1.875" 3.000" X-Nipple 5 i' 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 12 10,777' - CIBP 6 X i 7 n Capillary String Installed on 8/13/2013 3/8" 2205 Stainless Steel 8I !i Top Bottom MD 0' 8 8,900' I._ TVD 0' 8,900' 9 PERFORATIONS " "1 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date i i 10 X ,;; H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 "" H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 } 11 H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 t. , H6 i" r H7-H9 a„ H10 12 4 1/2"", , 6"Hole TD=10,807'MD—10,758'ND Max Deviation 19°@ 10,516' PBTD=10,777 MD—10,730'ND Max Dogleg 6.S°/100'@ 9,831' Downhole Revised:8/13/13 Updated by STP 08/15/13 Swanson River Unit II Well: SCU 41A-04 PROPOSED SCH E MATT C Completion Ran:5/27/2013 PTD: 213-028 Ililcor')Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL a i Size Type Wt Grade Conn. ID Top Btm 22" 2 2. r� 22" Conductor Surf 22' iP 13-3/8" Surf.Csg 54.5 1-55 STC 12.615" Surf 3,000' ;, DV Collar 29 N-80 BTC 6.184" Surf 304' +� 2,002' 26 N-80 BTC 6.276" 304' 1,235' ' �,' 23 N-80 BTC 6.366" 1,235' 4,229' r»' *: 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" r 29 N-80 LTC 6.184" 4,527' 6,489' i ' 26 N-80 LTC 6.276" 6,489' 9,346' 4 'c 29 N-80 LTC 6.184" 9,346' 9,591' ' y.i 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' i 3 l■i ,w TUBING 1 4 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 41 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,180' e JEWELRY DETAIL ,.. r No. Depth ID OD Item w, 4. DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT ►` 2 20' 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin 6,944' �� ■ y.% 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice c y' 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice .1 4 AB i 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice - rt' 6 9,297' 2.313" 3.625" X-Nipple Y, ` 4 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 64 8 10,105' 1.995" 3.688" GLM#1,2-3/8"SF0-1,8RD,Orifice 9 10,153' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer •/ `M 10 10,164' 1.875" 3.000" X-Nipple 5 III P I 11 10,180' 1.995" 2.375" Wireline Re-Entry Guide s4 as r 12 10,777' - CIBP 6 s: a`, i1 E w' 04 7 II y■ Capillary String Proposed Re-Install ■■ Top of Liner 3/8" 2205 Stainless Steel AR II_ it Hanger @ 9,383' Top Bottom T . MD 0' 10,160' I •' TVD 0' 10,146' i • L'' 4 II 7 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10 0 • H1 10,224' 10,258' 10,207' 10,239' 34' 6 3-3/8"HC Proposed S. • H2 10,270' 10,283' 10,250' 10,263' 13' 6 3-3/8"HC Proposed 11 3r - H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 5. • H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 .0 Hl H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 'i!'' - - H2 o H6 H7-H9 aH sE H10 A• yt 12 ;4 glIMPli/i 6"Hole 4-1/2" TD=10,807'MD-10,758'ND Max Deviation 19°@ 10,516' PBTD=10,777 MD—10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Proposed Updated by STP 09/10/13 ... 11 Swanson River 2013 Moncla Rig#405 �iaki,rn:►i,�.k._lit Knight Oil Tools BOP Mk ois I_1 Il lil lil ill Ill lil Ill 2.57' \ / Shaffer 7 1/16 5000 ,_ (ffil fffil rtfi it y, ry 1I-� 4JJ _ / 1 2 3/8-3%variable CAMERON r 3.68' H [• I i H ": ?� _ [ Blind H I 7 1/16 5000 [ io r I lil ill iii 1 Choke and Kill valves are 2 1/16 10M IIIi!11!1'l!Pl i iOijvi 1.56' ' � .1500 ,_ �r .• •l- :I lii.lil.11l�lil.l 1 t �I'-_, o� � V V RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AUG 2 7 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon U Repair Well U Plug Perforations Li Perforate U Other U Run Short Capstring Performed: Alter Casing ❑ Pull Tubing el Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development El Exploratory U 213-028 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-10109-02• 7.Property Designation(Lease Number): 8.Well Name and Number: A028997 Soldotna Creek Unit(SCU)41A-04 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil ' 11.Present Well Condition Summary: Total Depth measured 10,807 feet • Plugs measured 10,777 feet true vertical 10,757 feet Junk measured N/A feet Effective Depth measured 10,777 feet Packer measured 10,244 feet true vertical 10,730 feet true vertical 10,226 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 9,303'MD 9,303'TVD Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,270'MD 10,250'TVD Tri-Point Packers and SSSV(type,measured and true vertical depth) Hydraulic Pkr-N/A 10,244'MD 10,226'TVD N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 99 274 279 1200 150 Subsequent to operation: 99 166 264 1180 160 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development El . Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil is• Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG p 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: N/A Contact Stan Porhola Email sporhola(c�hilcorD.com Printed Name Stan Porhola Title Operations Engineer Signature ✓U v4 Phone 907-777-8412 Date L�+ 3 9.1;./5 RBDM S P -4 20P Form 10-404 Revised 10/2012 ...0C �l( Submit Original Only / l Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 8/12/13 8/13/13 Daily Operations: 08/12/2013 - Monday Rig Up Cap String Truck. Rig up lubricator and adapter. Test to 3,000 psi. POOH w/3/8" capillary string from 9,250'. RDMO Cap String Truck. Move to SRU 331-27. 08/13/2013 -Tuesday Rig Up Cap String Truck. Rig up lubricator and adapter. Test to 3,000 psi. RIH w/ 3/8" capillary string. Set capillary string @ 8,900'. RDMO Cap String Truck. ° Swanson River Unit Well: SCU 41A-04 ACTUAL SCHEMATIC ompletionRan:5/27/2013 PTD: 213-028 Hilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL Co' 1 T Size Type Wt Grade Conn. ID Top Btm 22"J 2 l f� 1� 22" Conductor Surf 22' 13 3/8" Surf.Csg 54.5 1 55 STC 12.615" Surf 3,000' r, ;, DV Collar 29 N-80 BTC 6.184" Surf 304' 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' a 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" l ' 29 N-80 LTC 6.184" 4,527' 6,489' 9t t, t, y; 26 N-80 LTC 6.276" 6,489' 9,346' r 29 N-80 LTC 6.184" 9,346' 9,591' 4-1/2" Production Liner 12.6 L-80 DWC/C-HT 3.958" 9,383' 10,790' 3 • I t• TUBING aA;) ,"I 2-7/8" Production Tubing _ 6.5 L-80 8RD 2.441 Surf 9,304' V 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' iv JEWELRY DETAIL ''. No. Depth ID OD Item• 404 4 tip DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT '� 2 20' 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin 6,944' 4� 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice a? 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SFO-1,8RD,Orifice r 4 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 4 Y' 6 9,297' 2.313" 3.625" X-Nipple i; ,4 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer P 10 10,254' 1.875" 3.000" X-Nipple ;' 5 AID 1 * 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide III a.` 12 10,777 CIBP 4.4� 6 �. a S 7i Capillary String Installed on 8/13/2013 it 3/8" 2205 Stainless Steel 8 Top Bottom 7" .4MD 0' 8,900' •A TVD 0' 8,900' 9 di II s 11 PERFORATIONS 111 «4 Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10 CI H6 10,417' _ 10,426' 10,389' 10,398' _ 9' 6 _ 2-3/4"TCP 05/26/13 `,'a ? H7-H9 10,442' _ 10,530' 10,413' 10,496' 88' 6 _ 2-3/4"TCP 05/26/13 g;I 11 ' H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 N1 '5 :4-t ill mar H6 H7-H9 V4 NE H10 • 12 4-1/2" 6"Hole TD=10,807'MD-10,758'TVD Max Deviation 19°@ 10,516' PBTD=10,777 MD—10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Revised:8/13/13 Updated by STP 08/15/13 Landon Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 ei Hatevrrp %64,1A J Fax: 907 777-8510 REC E-mail: lellison @hilcorp.com SEP 12 2p13 DATE 09/11/2013 PO"''GG To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTA SCU 41A-04 Well Samples BOX NUMBERISAMPLE INTERVAL' 1 9,600-10,400 2 I 10,400-10,800 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Rec '' d Date:1,3 0)■..1 3 -. V �� RECEIVED STATE OF ALASKA AL...K(A OIL AND GAS CONSERVATION COMM-010N .JUL 19 2013 REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Lf Repair Well U Plug Perforations ❑ Perforate U Other U Install Capillary Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Strinq Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development El Exploratory ❑ 213-028 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99504 50-133-10109-02 7.Property Designation(Lease Number): 8.Well Name and Number: A028997 Soldotna Creek Unit(SCU)41A-04 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Swanson River Field/Hemlock Oil 11.Present Well Condition Summary: Total Depth measured 10,807 feet Plugs measured 10,777 feet true vertical 10,757 feet Junk measured N/A feet Effective Depth measured 10,777 feet Packer measured 10,244 feet true vertical 10,730 feet true vertical 10,226 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-7/8" 6.5#/L-80 9,303'MD 9,303'ND Tubing(size,grade,measured and true vertical depth) 2-3/8" 4.7#/L-80 10,270'MD 10,250'ND Tri-Point Packers and SSSV(type,measured and true vertical depth) Hydraulic Pkr-N/A 10,244'MD 10,226'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 109 1190 232 1515 165 Subsequent to operation: 105 1415 235 1490 180 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development El Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-359 Contact Stan Porhola Email sporhola(ahiIcorp.com Printed Name Stan Porhola Title Operations Engineer Signature ,,d%L/u ti "\ Phone 907-777-8412 Date '7 q1 1] RBDMS JUL 2 4 2044 Form 10-404 Revised 10/2012 2-7 t'S Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 7/9/13 7/9/13 Daily Operations: 07/09/2013-Tuesday Rig Up Cap String Truck.Rig up lubricator and adapter.Test to 3,000 psi.RIH w/3/8"capillary string.Set capillary string @ 9,250'.RDMO Cap String Truck. Swanson River Unit , . WeU A 4 ACTUAL SCHEMATIC Completion ll: 41 Ran-0:5/27/2013 P TD: 213-028 SC Hilcorp Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL J i 1 "� Size Type Wt Grade Conn. ID Top Btm 1� `A 22" 2 22" Conductor Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' en 29 N-80 BTC 6.184" Surf 304' _u DV 00' i�+ 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" ' 29 N-80 LTC 6.184" 4,527' 6,489' iot 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 4-1/2" Production Liner 12.6 L-80 DWC/C HT 3.958" 9,383' 10,790' 4 3 I i0 TUBING ►,1 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' 2 JEWELRY DETAIL No. Depth ID OD Item r.' 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT i °' ti DV Collar 6,944' 2 20' 2.441" 4.250" XO 3-1/2"IBT Box x 2-7/8"8rd Pin 4' 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SF0-1,8RD,Orifice 4 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 41 6 9,297' 2.313" 3.625" X-Nipple '' is 7 9,304' 1.995" 2.875" X0 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer m 10 10,254' 1.875" 3.000" X-Nipple 5 ■ 144 1 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide II 12 10,777' - CIBP 6 ++a vi B P 7 .i. q Capillary String Installed on 7/09/2013 3/8" 2205 Stainless Steel 8 Top Bottom 2-- a ,I MD 0' 9,250' I TVD 0' 9,250' 9 , PERFORATIONS I Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date 10 + H6 10,417' , 10,426' 10,389' , 10,398' 9' 6 2-3/4"TCP 05/26/13 I H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 11 H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 I H6 H7-H9 • l, H10 1` EEE+ 12 M l''6 "Hole 4-1/2"'' ' TD=10,807'MD—10,758'TVD Max Deviation 19°@ 10,516' PBTD=10,777 MD—10,730'ND Max Dogleg 6.5°/100'@ 9,831' Downhole Revised:7/09/13 Updated by STP 07/15/13 or T THE STATE ti „17,\ 177,',v Alaska Gil and Gas fri ° onservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF y,P Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Stan Porhola Operations Engineer Hilcorp Alaska, LLC � I _��C�' 3800 Centerpoint Drive Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, Soldotna Creek Unit 41A-04 Sundry Number: 313-359 Dear Mr. Porhola: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely,12;€-(47 Cathy . Foerster Chair DATED this 12- day of July, 2013. Encl. 5 • .. 4,, RECEIVED STATE OF ALASKA 4k' JUL 0 9 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ACGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redril ❑ Perforate New Pod ❑ Repair Wel❑ Change Approved Program❑ Suspend❑ Plug Perforations ❑ Perforate❑ Pull TubinJ Time Extension❑ Operations Shutdowi❑ Re-enter Susp.Wel ❑ Stimulate❑ Alter Casing Other. Install Capillary String 0 2.Operator Name: r. Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number. Exploratory ❑ Development Ei• 213-028 - 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service El 6.API Number: Anchorage,Alaska 99503 50-133-10109-02 - 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123A Soldotna Creek Unit(SCU)41A-04 - Will planned perforations require a spacing exception? Yes ❑ No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997 - Swanson River Field/Hemlock Oil - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 10,807' 4 10,757' - 10,777' 10,730' 10,777' N/A Casing Length I Size MD ND Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3,000' 13-3/8" 3,000' 3,000' 2,730 psi 1,130 psi Intermediate Production 9,591' 7" 9,591' 9,591' 6,340 psi 3,830 psi Liner 1,407' 4-1/2" 10,790' 10,741' 8,430 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 2-7/8"/2-3/8" L-80/L-80 9,304'/10,270' Packers and SSSV Type: Packers and SSSV MD(t)and ND(ft): Tri-Point Hydraulic Packer/N/A 10,244'MD/10,226'ND/N/A/N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program n BOP Sketch n Exploratory n Stratigraphidi Development n Service n 14.Estimated Date for 15.Well Status after prorosed work: Commencing Operations: 07/10/13 Oil 0 Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhda Email,sDorhola( hiIcorD.cortl Printed Name Stan Porhola Title Operations Engineer , Signature Pi pct Phone 907-777-8412 Date ,/V� / L COMMISSION USE ONLY l Conditions of approval: Notify Commission so that a representative may witness Sundry Number: I —� Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ 1 Other: RBDMS JUL 13 20:'Ni Spacing Exception Required? Yes ❑ No Subsequent Form Required: /O_ c./0 i( APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: 7. /243 I A 7�/�� Submit Form and i., \■� Form 10-403(Revised 10/2012) Apr I i Nacl2 mon s from the date of approvalr�./ttachments in Duplicate Well Prognosis Well: SCU 41A-04 Ililcorp Alaska,LL, Date:7/09/2013 Well Name: SCU 41A-04 API Number: 50-133-10109-02 Current Status: Gaslifted Oil Producer Leg: N/A Estimated Start Date: July 10th, 2013 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 213-028 First Call Engineer: Stan Porhola (907)777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: 1,986 psi @ 10,519' TVD Based on June 2013 static survey at top of the Hemlock H-10. Maximum Expected BHP: 1,986 psi @ 10,519'TVD Based on June 2013 static survey at . top of the Hemlock H-10. Max. Allowable Surface Pressure: —0 psi (Based on actual reservoir conditions and min water cut of 50% (0.385psi/ft) will balance reservoir pressure at 5,361 ft. ND. Brief Well Summary This well was drilled and completed with the Doyon Arctic Fox in May 2013. The well is currently producing approximately 100 bbls of oil and 200 bbls of water per day on gas lift completion. Notes Regarding Wellbore Condition ,( 7 ,,? New completion ran in May 2013. Completion procedure: 1. MIRU Cap String Truck, PT lubricator to 3,000 psi Hi 250 Low. 2. PU 3/8" capillary string. RIH and set at+/-10,300'. 3. Set spool of remaining line near well. 4. Rig down Cap String Truck. 5. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 1116 II Swanson River Unit Well: SCU 41A 04 ACTUAL SCHEMATIC Actual Actual Completion: PTD: 213-028 llilcor'►Alaska,LLC API: 50-133-10109-02 KB-THF: 17.83' CASING DETAIL 1 Size _ Type Wt Grade Conn. ID Top Btm „"del 2 22" Conductor Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' DV Collar 29 N-80 BTC 6.184" Surf 304' 2,002' 26 N-80 BTC 6.276" 304' . 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" 29 N-80 LTC 6.184" 4,527' 6,489' 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 3 I N 4-1/2" Production Liner 12.6 L-80 DWC/C HT 3.958" 9,383' 10,790' TUBING 2-7/8" _ Production Tubing 6.5 _ L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' • JEWELRY DETAIL No. Depth ID OD Item ' I DV Collar 6,944' 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT 2 20' 2.441" 4.250" XO 3-1/2"IBT Box x 2-7/8"8rd Pin 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 L b 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SF0-1,8RD,Orifice ' 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SFO-1,8RD,Orifice 6 9,297' 2.313" 3.625" X-Nipple 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin • 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SFO-1,8RD,Orifice 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 5 I d 10 10,254' 1.875" 3.000" X-Nipple ,--i 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide 6 X , 12 10,777' - CIBP • 7 \_/ PERFORATIONS 7, 2198I p Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 9 H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 2-3/4"TCP 05/26/13 . ; H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 111 -8 I 3M! = H6 H7-H9 H10 12 " �C 6"Hole Max hole deviation=19° 4-1/2". 4 'r '. ' TD=10,807'MD—10,758'ND PBTD=10,777 MD—10,730'ND Down hole Revised:05/27/2013 Updated by STP 07/09/13 I. 111 II Swanson River Unit PROPOSED SCHEMATIC Well:ProposedSCU Comple41A-04 tion PTD: 213-028 Hilcorp Alaska,LLC API: 50-133-10109-02 KB-TH F: 17.83' CASING DETAIL 1 141 Size Type Wt Grade Conn. ID Top Btm 22" 2 SE 1� 22" Conductor Surf 22' 13-3/8" Surf.Csg 54.5 J-55 STC 12.615" Surf 3,000' M , DV Collar 29 N-80 BTC 6.184" Surf 304' -'� 2,002' 26 N-80 BTC 6.276" 304' 1,235' 23 N-80 BTC 6.366" 1,235' 4,229' * ,. 7" Production Casing 26 N-80 BTC 6.276" 4,229' 4,527' 13-3/8" :; 29 N-80 LTC 6.184" 4,527' 6,489' 3 in I 26 N-80 LTC 6.276" 6,489' 9,346' 29 N-80 LTC 6.184" 9,346' 9,591' 4-1/2" Production Liner 12.6 L-80 DWC/C HT 3.958" 9,383' 10,790' 4 io TUBING ►, 2-7/8" Production Tubing 6.5 L-80 8RD 2.441 Surf 9,304' 2-3/8" Production Tubing 4.7 L-80 8RD 1.995 9,304 10,270' a, 4a JEWELRY DETAIL No. Depth ID OD Item + DV Collar 1 18' 2.992" 6.184" Tubing Hanger 3-1/2"IBT ltd 1 6,944' 2 20' 2.441" 4.250" X0 3-1/2"IBT Box x 2-7/8"8rd Pin ki 3 4,193' 2.441" 4.625" GLM#4,2-7/8"SFO-1,8RD,Orifice 4 GB i 1 4 7,007' 2.441" 4.625" GLM#3,2-7/8"SF0-1,8RD,Orifice sP 5 8,899' 2.441" 4.625" GLM#2,2-7/8"SF0-1,8RD,Orifice >'l ''40 6 9,297' 2.313" 3.625" X-Nipple 7 9,304' 1.995" 2.875" XO 2-7/8"8rd Box x 2-3/8"8rd Pin 8 10,195' 1.995" 3.688" GLM#1,2-3/8"SF0-1,8RD,Orifice "J Pl, 9 10,243' 1.995" 3.500" 4-1/2"Tri-Point Hydraulic Packer 1 5 �t �i 10 10,254' 1.875" 3.000" X-Nipple 4 11 10,270' 1.995" 2.375" Wireline Re-Entry Guide tl 6 II 12 10,777' - CIBP tl 7 II I 8 1! PERFORATIONS T h Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Amt spf Comments Date rit H6 10,417' 10,426' 10,389' 10,398' 9' 6 2-3/4"TCP 05/26/13 g H7-H9 10,442' 10,530' 10,413' 10,496' 88' 6 , 2-3/4"TCP 05/26/13 , I b H10 10,553' 10,598' 10,518' 10,560' 45' 6 2-3/4"TCP 05/26/13 as1101It it,,( * 11 :c ' Capillary String Proposed Install 3/8" 2205 Stainless Steel ; STATE OF ALASKA ALAJr\A OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a.Well Status: Oil El . Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1b.Well Class: 20AAC 25.105 20AAC 25.110 Development Ei • Exploratory ❑ GINJ ❑ WINJ❑ WAG ❑ WDSPL❑ No.of Completions: _1 Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.,or , 12.Permit to Drill Number: Hilcorp Alaska,LLC • Aband.: 5/27/2013 213-028 . . 3.Address: 6.Date Spudded: 13.API Number: 3800 Centerpoint Drive,Suite 100,Anchorage,AK,99503 5/6/2013 50-133-10109-02-00 4a.Location of Well(Governmental Section): 7.Date TD Reached: 14.Well Name and Number: Surface: 961'FNL, 1127'FEL,Sec 4,T7N,R9W,SM,AK . 5/16/2013 SCU-41A-04 _ , Top of Productive Horizon: 8.KB(ft above MSL): 192.3• 15.Field/Pool(s): 1079'FNL,1099'FEL,Sec 4,T7N,R9W,SM,AK GL(ft above MSL): • 173.7' Swanson River Field/ Total Depth: • 9.Plug Back Depth(MD+TVD): Hemlock Oil Pool - 1257'FNL,1016'FEL,Sec 4,T7N,R9W,SM,AK 10,777'MD/10,730'TVD• 4b. Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16.Property Designation: Surface: x- 346506.3 • y- 2460223.8 • Zone- 4 10,807 MD/10,757'TVD•• A028997 TPI: x- 346518.1 y- 2460098.5 - Zone- 4 11.SSSV Depth(MD+TVD): 17.Land Use Permit: Total Depth: x- 346599.1 y-2459919.2 Zone- 4 N/A N/A 18. Directional Survey: Yes 0 No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) N/A (ft MSL) N/A 21. Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drillLateral Top Window MD/TVD: GR,Resistivity,Density,Neutron 9591' 23. CASING,UNER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 4 1/2" 12.6# L-80 9383 10790 9383 10741 6" 294 sx @ 15.3 ppg 24.Open to production or injection? Yes is No ❑ 25. TUBING RECORD If Yes, list each interval open(MD+TVD of Top and Bottom;Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 2 3/8,4.7#,L-80,8RD 10269.81' 10243.51 MD/10227.5 ND to.yl7 %t>`lZ(�, MD See attached Wellbore Schematic. /d 4r{ ,_ /0 530'44 p 2 7/8,6.4#,N-80,8RD 9304.43' /05-S-3'_ /c S'-S'Mj) 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. ....ii.....�-___ L'Q1,IiirLEiTQtt Was hydraulic fracturing used during completion? Yes❑ No Ill i I itina , l'lt DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED At " y 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 6/4/2013 Gas Lift Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 6/13/2013 24 Hr's Test Period -209 277 328 3 inch spool 1325 Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): `� Press. 240 160 24-Hour Rate - 209 277 328 In Progress 2•"1. 5 Qd`1 28. CORE DATA Conventional Core(s)Acquired? Yes❑ No IS Sidewall Cores Acquired? Yes ❑ No If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. G RBnMS JUL - 2 2013) ,?) Form 10-407 Revised 10/2012 CONTINUED ON REVERSE 73b .13 Submit original only 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? ❑ Yes -/ NO If yes,list intervals and formations tested, briefly summarizing test results.Attach separate sheets to this form,if needed, Permafrost-Top and submit detailed test information per 20 AAC 25.071. Permafrost-Base Tyonek G2 10170 10155 Top Hemlock 10253 10234 Hemlock H2 10300 10279 H3 10335 10312 H6 10417 10389 H7 10442 10413 H10 10553 10518 • H11 10668 10626 H13 10751 10705 Formation at total depth: Hemlock 10807 10758 31. List of Attachments: Definitive Surveys,As drilled wellbore schematic,All casing tallies,All casing and cement reports, Days vs Depth,MW vs depth,Morning Report summaries Logs obtained,Mud log 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Janise Barrett Email: jbarrett@hilcorp.com Printed Name: Luke Keller Title: Drilling Engineer Signature: Phone: 007) 777- S'39-5 Date: /2Sj2oi3 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 ut Hilcorp Alaska, LLC - Post office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage,AK 99503 Phone: 907/777-8300 July 1, 2013 Fax: 907/777.-8301 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage,Alaska 99501 Re: Swanson River Field SCU 41A-04 Update to Form 10-407 Swanson River Field SRU 24-15 Update to Form 10-407 Dear Commissioner: This letter is to update the Well Completion Form 10-407 for the SCU 41A-04 and SRU 24-15. Our Oil Gravity API tests are now complete.The Oil Gravity API for SCU 41A-04 is 27.58, specific gravity is 0.8895.The Oil Gravity API for SRU 24-15 is 28.05 and the specific gravity is 0.8869. Please do not hesitate to contact me should you have any questions or need additional information. Sincerely, HILCORP ALAS LLC ) Janise Barrett Drilling Technician jsb 10-407 cc: Luke Keller ini Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 1 ,'. ., 'F.. 3800 Centerpoint Drive Suite 100 Anchorage,AK 99503 Phone: 907/777-8300 June 25, 2013 ,-- t -',"..y I'1 Fax: 907/777.-8301 Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage,Alaska 99501 Re: Swanson River Field SCU 41A-04 Form 10-407 Dear Commissioner: Please find enclosed the Well Completion Form 10-407 for the SCU-41A-04.Our Oil Gravity API test is still in progress;we expect to have the results back in the next few weeks and will update the AOGCC with this data point. Please do not hesitate to contact me should you have any questions or need additional information. Sincerely, HILCORP ALASKA,LLC Janise Barrett Drilling Technician jsb 10-407 cc: Luke Keller Swanson River Unit Well SCU 41A-04 Actual Actual WBD Ili!carp Alaska,I.LC C A S I N G & T U B I N G Drift Size Type Wt Grade Conn. ID Top Btm 1 1 22" Conductor- 22" Driven to Set - - - - Surf 22' 1 Depth ril ii 13- Surf.Csg 54.5 - - 12.459" Surf 3,000' a 3/8" "' 7" Intermediate 29 N-80 BTC 6.05" Surface 304' 13-3/8" `` 1f 7" Intermediate 26 N-80 BTC 6.151" 304' 1,235' A ill `. 2 m i 7" Intermediate 23 N-80 BTC 6.25" 1,235' 4,229' it 7" Intermediate 26 N-80 BTC 6.151" 4,229' 4,527' I 7" Intermediate 29 N-80 LTC 6.05" 4,527' 6,489' 3 , 7" Intermediate 26 P-110 LTC 6.151" 6,489' 9,346' 7" Intermediate 29 P-110 LTC 6.05" 9,344' 9,591' 4-1/2" Prod Lnr 12.6 L-80 D HT/C 3.958" 9,383' 10,790' r. 4 Tubing '* 2-7/8" Prod Tbg 6.4 L-80 8RD 2.347" 17.83' 9304' `kt pr 1 2-3/8" Prod Tbg 4.7 L-80 8RD 1.901" 9304' 10269.8' li 6 Ior 5 Albs A JEWELRY DETAIL No. Depth ID OD Item 1 17.83' 2.441" 2.875" Hanger,LDS to PUP 2 4,193.03' 2.441" 4.625" GLM#4,2 7/8 5F0-1,8RD,Orfice w., 7 11111111 I 3 7,006.76' 2.441" 4.625" GLM#3,2 7/8 SFO-1,8RD,Orfice *; 1 4 8,899.44' 2.441" 4.625" GLM#2,2 7/8 SFO-1,8RD,Orfice 1 I ,. I 8 ;7t.!„ _ u- 5 9,297.23' 2.441" 3.625" X Nipple 1 9 * 6 9,304.43' 1.995" 2.875" XO 2 7/8 X 2 3/8 8RD EUE W. 10 7 10,195.21' 1.995" 3.6875" GLM#1,2 3/8 SFO-1,8RD,Orfice 7" t iltv 8 10,243.51' 1.995" 5.5" Tri-Point Hydraulic Packer ii 9 10,254.16' 1.995" 2.375" X-Nipple 10 10,269.8' 1.995" 2.375" WLEG r 11 10,777' - - CIBP 4. L i il PERFORATIONS Zone Top Btm Top Btm Amt spf Comments Date 11 (MD) (MD) (TVD) (TVD) ;404 4 H6 10,417' 10,426' 10,389' 10,398' 9 6 2.75"TCP 5/26/13 ' H7-9 10,442' 10,530' 10,413' 10,496' 88 6 2.75"TCP 5/26/13 H10 10,553' 10,598' 10,518' 10,560' 45 6 2.75"TCP 5/26/13 1l i 4-1/2" ., re. ' ' TD=10,807'/TVD=10,758' Updated by JSB 6/10/2013 CASING RUN IN TALLY WELL NAME: SCU 41A-04 DATE: 05/19/13 CASING SIZE 4.500 WEIGHT 12.60 CASING ID 3.958 GRADE L-80 THREAI DWC/C-HT Casing (Buttress Casing) CAPACITY 0.0152 bbls/ft TORQUE - MAXIMUM=6,500 MIN=5,800 DISPLACEMENT 0.0046 bbls/ft SHOE DEPTH 10790.0 feet Coupling OD 5.00, Drift 3.833, ID 3.958 HOLE TD 10807.0 feet Foremen: Pederson/Grubb I MUD WT 11.10 ppg Joint Running Joint Depth BOUY FACTOR 0.82 Joint# Joint# Length _ Total Bottom Top REMARKS Bouyant Capacit)Displmt on Rack I in hole feet feet feet feet weight bbls bbls I Off Bottom 17.00 ( Block Weight = 25,000 Hobbs Reamer Shoe, A 2.13 2.13 10790.00 10787.87 OD-5.07, SN-53958-4 25,022 0.0 0.0 BakerLocked Joint 4.5" 56 41.16 43.29 10787.87 10746.71 DWC w/Centralizer#1 25,449 0.7 0.2 BakerLocked Joint 4.5" 55 41.43 84.72 10746.71 10705.28 DWC w/Centralizer#2 25,880 1.3 0.4 Hobbs Float Collar, B 1.69 86.41 10705.28 10703.59 '`D 5.07", SN-53958-1 25,897 1.3 0.4 BakerLocked Joint 4.5" 54 41.11 127.52 10703.59 10662.48 DWC w/Centralizer#3 26,324 1.9 0.6 Hobbs Landing Collar, C 1.23 128.75 10662.48 10661.25 OD 5.07", SN-53424-3 26,337 2.0 0.6 Joint 5"DWC 53 41.81 170.56 10661.25 10619.44 w/Centralizer#4 26,771 2.6 0.8 52 5 41.79 212.35 10619.44 10577.65 Jt 5"DWC w/cent#5 27,205 3.2 1.0 51 6 40.85 253.20 10577.65 10536.80 Jt 5" DWC w/cent#6 27,629 3.9 1.2 50 7 41.24 294.44 10536.80 10495.56 Jt 5"DWC w/cent#7 28,057 4.5 1.3 49 8 41.76 336.20 10495.56 10453.80 Jt 5"DWC w/cent#8 28,491 5.1 1.5 48 _ 9 41.79 377.99 10453.80 10412.01 Jt 5"DWC w/cent#9 28,924 5.8 1.7 47 10 41.60 419.59 10412.01 10370.41 Jt 5" DWC w/cent#10 29,356 6.4 1.9 46 11 41.40 460.99 10370.41 10329.01 Jt 5" DWC w/cent#11 29,786 7.0 2.1 45 12 41.31 502.30 10329.01 10287.70 Jt 5" DWC w/cent#12 30,215 7.6 2.3 44 13 41.58 543.88 10287.70 10246.12 Jt 5"DWC w/cent#13 30,647 8.3 2.5 43 14 41.85 585.73 10246.12 10204.27 Jt 5" DWC w/cent#14 31,081 8.9 2.7 42 15 41.44 627.17 10204.27 10162.83 Jt 5"DWC w/cent#15 31,512 9.5 2.9 41 16 41.87 669.04 10162.83 10120.96 Jt 5" DWC w/cent#16 31,946 10.2 3.1 40 17 41.24 710.28 10120.96 10079.72 Jt 5"DWC w/cent#17 32,374 10.8 3.3 39 18 41.82 752.10 10079.72 10037.90 Jt 5" DWC w/cent#18 32,809 11.4 3.4 38 19 41.53 793.63 10037.90 9996.37 Jt 5"DWC w/cent#19 33,240 12.1 3.6 37 20 41.30 834.93 9996.37 9955.07 Jt 5" DWC w/cent#20 33,669 12.7 3.8 36 21 41.50 876.43 99.55.07 9913.57 Jt 5"DWC w/cent#21 34,099 13.3 4.0 35 22 41.45 917.88 9913.57 9872.12 Jt 5" DWC w/cent#22 34,530 14.0 4.2 34 23 41.74 959.62 9872.12 9830.38 Jt 5"DWC w/cent#23 34,963 14.6 4.4 33 24 41.37 1000.99 9830.38 9789.01 Jt 5" DWC w/cent#24 35,393 15.2 4.6 32 25 41.79 1042.78 9789.01 9747.22 Jt 5" DWC w/cent#25 35,827 15.9 4.8 31 26 41.40 1084.18 9747.22 9705.82 Jt 5" DWC w/cent#26 36,256 16.5 5.0 30 27 41.87 1126.05 9705.82 9663.95 Jt 5" DWC w/cent#27 36,691 17.1 5.2 29 28 41.44 1167.49 9663.95 _ 9622.51 Jt 5" DWC w/cent#28 37,121 17.8 5.3 28 29 41.16 1208.65 9622.51 9581.35 Jt 5" DWC 37,549 18.4 5.5 27 30 41.83 1250.48 9581.35 9.539.52 Jt 5" DWC 37,983 19.0 5.7 26 31 41.53 1292.01 9539.52 9497.99 Jt 5" DWC 38,414 19.7 5.9 25 32 41.80 1333.81 9497.99 _ 9456.19 Jt 5" DWC 38,848 20.3 6.1 24 33 41.82 1375.63 9456.19 9414.37 Jt 5" DWC 39,282 20.9 6.3 208' XO,Flex-Lock Liner Hanger,XO,RS Packoff Overla Seal Nipple Jt,HRD ZXP p 30.60 1406.23 9414.37 9383.77 Packer,PBR. 39,600 21.4 6.4 Joint Run Joint Depth BOU kCTOR 0.82 Joint# Joint# Length Total Bottom Top REMARKS Bouyant Capacit)Displmt on Rack in hole feet feet feet feet weight bbls bbls 5.42 1411.65 9383.77 9378.35 Running Tool 39,656 21.5 6.5 AV,11 1-JO.A J 11G 11 2.21 1413.86 9378.35 9376.14 (BxP) 39,679 21.5 6.5 545.79 1959.65 9376.14 8830.35 (18) IIWDP 45,346 29.8 9.0 8835.85 10795.50 8830.35 -5.50 (std# 140.5), Dp to surface 137,083 164.3 49.4 Make up 20' Pup&XO to bottom of Cement Head. Make up 10' Pup to top 20' Pup 20.00 10815.50 -5.50 -25.50 and stage on Pipe Skate 137,291 164.6 49.5 Top Joint of 4.5" DWC to center of Hanger=8.0'- (9403) Top Joint of 4.5" DWC to center of Packer= 13.5'- (9397.5, 7" Casing couplings @ 9322',9364'and 9404' Extra Joints 41.78 41 .82 39.47 41 .81 40.07 41 .43 41 .81 41 .16 41 .83 41 .82 41 .52 41 .81 41 .49 41 .81 41 .57 41 .78 41 .81 41.38 41.81 41.45 41.46 41.55 41.04 Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. SCU 41A-04 Date 20-May-13 County Kenai Peninsula Burough State Alaska Supv. Rance Pederson/Joe Grubb CASING RECORD TD 10807'MD/10757'TVD Shoe Depth: 10790'MD/10,741'TVD PBTD: 10,777'MD/10,730'TVD Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 41/2 STL HRS 2.13 10,790.00 10,787.87 0 2 41/2 12.6 L-80 DWC/C-HT 82.59 10,787.87 10,705.28 F.Collar 41/2 STL HFC 1.69 10,705.28 10,703.59 1 41/2 12.6 L-80 DWC/C-HT 41.11 10,703.59 10,702.48 Land CLR 4 1/2 STL 1.23 10,702.48 10,701.25 30 41/2 12.6 L-80 DWC/C-HT 1,286.88 10,701.25 9,414.37 Hng./Packer Baker 30.60 9,414.37 9,383.77 Running tool Baker 5.52 9,383.77 9,378.25 Totals , Csg Wt.On Hook: 150000 Type Float Collar: Hobbs Float Collar No.Hrs to Run: 20 hrs Csg Wt.On Slips: 0 Type of Shoe: Hobbs Reamer Shoe Casing Crew: Wfd Fluid Description: 11.1 ppg / 6%KCL/PHPA Mud/ PV=12 YP=22 HTHP=11.4 Liner hanger Info(Make/Model): Flex lock hanger,ZXP Packer Liner top Packer?: x Yes _No Liner hanger test pressure: 2100 Centralizer Placement: Soild centralizers on each joint in shoe track,every joint F/10616'T/9660' CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 12 Volume pumped(BBLs) 35 BBLS Lead Slurry Type: Yield: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry Type: Easy Block Cement Yield: 1.34 ft3/sk Density(ppg) 15.3 ppg Vol pumped(BBLs/sx) 70 bbls/294sx Mixing/Pumping Rate(bpm): 4.2 N Post Flush(Spacer) co Type: Density(ppg) Rate(bpm): Volume: c I/ Displacement: Type: 6%KCUPHPA Density(ppg) 11.1 Rate(bpm): 5.0+ Volume(actual/calculated): 118 bbls/118.5 bbls FCP(psi): 1200 Pump used for disp: SLB Cement Plug Bumped? X Yes No Bump press 1700 Casing Rotated? X Yes No Reciprocated? x Yes No %Returns during job 85% Cement returns to surface? X Yes No Spacer returns? X Yes No Vol to Surf: 30 bbls cement r// Cement In Place At: 21:30 Date: 5/19/2013 Estimated TOC: 9,383 Method Used To Determine TOC: Pulled out with running tool and circulated out cement Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: a Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): (0 Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: w Displacement: • co Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _No Reciprocated? Yes No %Returns during job Cement returns to surface? Yes No Spacer returns? Yes No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type SMB-22 Serial No. H245745 Size 16 3/4 x 11 W.P.3000/5000 Test Head To 3000 PSIG 10 MIN X OK Remarks: IITubular Tally Tubular Information: Tubular Size: 2 7/8" x 2 3/8" AFE Number: 1310631 Well: 41A-04 Start Date: 5/27/13 Field: Swanson River Start Time: Platform: Date Landed: Foreman: Pederson / Greco Time Landed: Rig: Arctic Fox Up-Weight: Completion Fluid Weight (PPG): 8.9 Slack-off : Completion Fluid Type: 6% KCL Weight set on Slips/HGR: Wellhead Make: Cameron Current Rig KB Elevation: 17.10' Original Rig KB Elevation: 19.18' Item Jt Description ID" OD" LENGTH Total TOP BTM. (in) (in) (ft) Length (ft) (ft) WLEG 1.995 2.375 0.49 0.49 10,269.32 10,269.81 PUP-2 3/8,6.4#,I,-80,8RD 1.995 2.375 10.17 10.66 10,259.15 10,269.32 PUP-2 3/8,6.4#,L-80,8R1) 1.995 2.375 3.69 14.35 10,255.46 10,259.15 X-Nipple(run with Plug) .99S 2.375 1.30 15.65 10,254.16 10,255.46 l'UP-2 3/8,6.4#,1-80,8RD 1.995 2.375 4.80 20.45 10,249.36 10,254.16 '11(1 Point Hydraulic Packer 1.995 5.50r 5.85 26.30 10,243.51 10,249.36 PUP-2 3/8,6.4#,L-80,8RD 1.995 2.375 6.18 32.48 10,237.33 10,243.51 29 1 1 .74,1:80. 31.75 64.23 10,205.58 10,237.33 PUP-2 3/8,6.4#,L-80,8RD 1.995 3.125 4.03 68.26 10,201.55 10.205.58 GLM ,2 3/8 S170-1,8RD,Orrice 1.995 3.688 6.34 74.60 10,195.21 10,201.55 PIP-2 3/8,6.4#,L-80,8RD 1.995 3.125 3.68 78.28 10,191.53 10,195.21 28 _ 2 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.79 110.07 10,159.74 10,191.53 27 3 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 30.68 140.75 10,129.06 10,159.74 26 4 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.00 171.75 10,098.06 10,129.06 25 5 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.73 203.48 10,066.33 10,098.06 24 6 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.78 235.26 10,034.55 10,066.33 23 7 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.80 267.06 10,002.75 10,034.55 22 8 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.84 298.90 9,970.91 10,002.75 21 9 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 30.57 329.47 9,940.34 9,970.91 20 _ 10 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.23 360.70 9,909.11 9,940.34 _ 19 11 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.80 392.50 9,877.31 9,909.11 18 12 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.79 424.29 9,845.52 9,877.31 17 13 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.78 456.07 9,813.74 9,845.52 16 14 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.70 487.77 9,782.04 9,813.74 15 15 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.68 519.45 9,750.36 9,782.04 14 16 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.79 551.24 9,718.57 9,750.36 13 17 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.74 582.98 9,686.83 9,718.57 12 18 .loint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.80 614.78 9,655.03 9,686.83 11 19 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.77 646.55 9,623.26 9,655.03 10 20 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.82 678.37 9,591.44 9,623.26 9 21 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.76 710.13 9,559.68 9,591.44 8 22 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.80 741.93 9,527.88 9,559.68 7 23 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.69 773.62 9,496.19 9,527.88 6 24 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.77 805.39 9,464.42 9,496.19 5 25 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2.375 31.83 837.22 9,432.59 9,464.42 4 26 _ Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.81 869.03 9,400.78 9,432.59 3 27 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.82 900.85 9,368.96 9,400.78 2 28 Joint 2 3/8,4.7#,L-80,8RD Tubing 1.995 2375 31.74 932.59 9,337.22 9,368.96 1 29 Joint 2 3/8.4.7#,1,80,8RD Tubing 1.995 2.375 31.78 964.37 9,305.44 9,337.22 .995 2.875 1.01 965.38 9,304.43 9,305.44 PUP-2 7/8,6.4#,1-80,8R1) 2.441 2.875 6.20 971.58 9,298.23 9,304.43 apple 2.441 3.625 1.00 972.58 9,297.23 9,298.23 PUP-2 7/8,6.4#,1-80,8R1) 2.875 4.30 976.88 9,292.93 9,297.23 292 1 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 1,008.70 9,261.11 9,292.93 291 2 _ Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 1,040.70 9,229.11 9,261.11 290 3 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 1,072.46 9,197.35 9,229.11 4 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 1,104.47 9,165.34 9,197.35 5 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.46 1,135.93 9,133.88 9,165.34 6 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 1,168.32 9,101.49 9,133.88 7 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 1,200.10 9,069.71 9,101.49 8 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 1,232.12 9,037.69 9,069.71 9 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 1,264.13 9,005.68 9,037.69 10 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.91 1,296.04 8,973.77 9,005.68 11 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 1,327.54 8,942.27 8,973.77 281 12 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 1,359.05 8,910.76 8,942.27 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 4.21 1,363.26 8,906.55 8,910.76 GLM#2,2 7/8 SF0-1,8RD,Orficc 2.441 4.625 7.11 1,370.37 8,899.44 8,906.55 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 3.74 1,374.11 8,895.70 8,899.44 280 13 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 1,406.10 8,863.71 8,895.70 14 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 1,437.60 8,832.21 8,863.71 15 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 1,469.59 8,800.22 8,832.21 16 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.58 1,501.17 8,768.64 8,800.22 17 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 1,532.97 8,736.84 8,768.64 18 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.32 1,564.29 8,705.52 8,736.84 19 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 1,596.29 8,673.52 8,705.52 20 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 1,628.31 8,641.50 8,673.52 21 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.38 1,659.69 8,610.12 8,641.50 22 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 1,691.48 8,578.33 8,610.12 270 23 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 1,723.49 8,546.32 8,578.33 24 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 1,755.29 8,514.52 8,546.32 25 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.34 1,787.63 8,482.18 8,514.52 26 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.32 1,819.95 8,449.86 8,482.18 27 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 1,851.45 8,418.36 8,449.86 28 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.31 1,883.76 8,386.05 8,418.36 29 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.53 1,915.29 8,354.52 8,386.05 30 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 1,947.08 8,322.73 8,354.52 31 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 1,979.46 8,290.35 8,322.73 32 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 2,011.28 8,258.53 8,290.35 260 33 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 2,043.07 8,226.74 8,258.53 34 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.18 2,073.25 8,196.56 8,226.74 35 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 2,104.79 8,165.02 8,196.56 36 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.98 2,136.77 8,133.04 8,165.02 37 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 2,168.29 8,101.52 8,133.04 38 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 2,200.66 8,069.15 8,101.52 39 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.49 2,232.15 8,037.66 8,069.15 40 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.29 2,264.44 8,005.37 8,037.66 41 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 2,295.96 7,973.85 8,005.37 42 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 2,327.73 7,942.08 7,973.85 250 43 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.71 2,359.44 7,910.37 7,942.08 44 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.43 2,391.87 7,877.94 7,910.37 45 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 2,423.66 7,846.15 7,877.94 46 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 2,455.48 7.81433 7,846.15 47 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.41 2,486.89 7,782.92 7,814.33 48 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 2,518.40 7,751.41 7,782.92 49 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 2,550.21 7,719.60 7,751.41 50 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 2,581.71 7,688.10 7,719.60 51 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 2,613.70 7,656.11 7,688.10 52 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.56 2,645.26 7,624.55 7,656.11 240 53 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 2,677.02 7,592.79 7,624.55 54 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 2,708.53 7,561.28 7,592.79 55 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 2,740.91 7,528.90 7,561.28 56 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.06 2,772.97 7,496.84 7,528.90 57 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 2,804.79 7,465.02 7,496.84 58 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.30 2,836.09 7,433.72 7,465.02 59 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.48 2,867.57 7,402.24 7,433.72 60 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.43 2,900.00 7,369.81 7,402.24 61 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 2,932.39 7,337.42 7,369.81 62 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 2,964.19 7,305.62 7,337.42 230 63 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 2,995.69 7,274.12 7,305.62 64 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 3,027.20 7,242.61 7,274.12 65 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 3,059.56 7,210.25 7,242.61 66 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 3,091.07 7,178.74 7,210.25 67 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 3,123.44 7,146.37 7,178.74 68 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 3,155.21 7,114.60 7,146.37 69 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 3,186.99 7,082.82 7,114.60 70 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 3,154.95 7,114.86 7,146.37 71 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 3,186.95 7,082.86 7,1 14.86 72 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.32 3,219.27 7,050.54 7,082.86 220 73 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 3,251.64 7,018.17 7,050.54 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 4.31 3,255.95 7,013.86 7,018.17 GLM#3,2 7/8 SF0-1,8RD,Orficc 2.441 4.625 7.10 3,263.05 7,006.76 7,013.86 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 3.87 3,266.92 7,002.89 7,006.76 219 74 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 3,298.72 6,971.09 7,002.89 75 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 3,330.49 6,939.32 6,971.09 76 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 3,362.03 6,907.78 6,939.32 77 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 3,393.77 6,876.04 6,907.78 78 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 3,425.54 6,844.27 6,876.04 79 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 3,457.06 6,812.75 6,844.27 80 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 3,489.44 6,780.37 6,812.75 81 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 3,520.96 6,748.85 6,780.37 82 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 3,552.76 6,717.05 6,748.85 210 83 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.56 3,584.32 6,685.49 6,717.05 84 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.45 3,615.77 6,654.04 6,685.49 85 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 3,647.57 6,622.24 6,654.04 86 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 3,679.09 6,590.72 6,622.24 87 Joint 2 7/8,6.4#,N-80,8RD Tubing _ 2.441 2.875 30.36 3,709.45 6,560.36 6,590.72 88 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.42 3,741.87 6,527.94 6,560.36 89 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 3,773.66 6,496.15 6,527.94 90 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 3,806.04 6,463.77 6,496.15 91 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.68 3,836.72 6,433.09 6,463.77 92 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.56 3,868.28 6,401.53 6,433.09 200 93 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 3,899.82 6,369.99 6,401.53 94 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 3,931.82 6,337.99 6,369.99 95 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 3,963.61 6,306.20 6,337.99 96 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 3,995.43 6,274.38 6,306.20 97 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 4,027.24 6,242.57 6,274.38 98 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 4,059.25 6,210.56 6,242.57 99 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.53 4,090.78 6,179.03 6,210.56 100 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.42 4,122.20 6,147.61 6,179.03 101 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.55 4,153.75 6,116.06 6,147.61 102 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 4,186.14 6,083.67 6,116.06 190 103 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 4,218.15 6,051.66 6,083.67 104 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.03 4,250.18 6,019.63 6,051.66 105 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 4,282.57 5,987.24 6,019.63 106 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.98 4,314.55 5,955.26 5,987.24 107 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 4,346.54 5,923.27 5,955.26 108 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.32 4,378.86 5,890.95 5,923.27 109 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 4,410.62 5,859.19 5,890.95 110 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 4,442.43 5,827.38 5,859.19 111 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.35 4,473.78 5,796.03 5,827.38 112 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 4,505.80 5,764.01 5,796.03 180 113 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 4,537.34 5,732.47 5,764.01 114 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.03 4,569.37 5,700.44 5,732.47 115 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.42 4,601.79 5,668.02 5,700.44 116 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.70 4,632.49 5,637.32 5,668.02 117 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 4,664.87 5,604.94 5,637.32 118 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 4,696.64 5,573.17 5,604.94 119 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 4,728.42 5,541.39 5,573.17 120 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 4,760.21 5,509.60 5,541.39 121 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 4,792.01 5,477.80 5,509.60 122 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 4,823.78 5,446.03 5,477.80 170 123 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.91 4,855.69 5,414.12 5,446.03 124 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.87 4,887.56 5,382.25 5,414.12 125 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.71 4,918.27 5,351.54 5,382.25 126 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 4,949.79 5,320.02 5,351.54 127 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.40 4,982.19 5,287.62 5,320.02 128 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.44 5,013.63 5,256.18 5,287.62 129 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 5,046.01 5,223.80 5,256.18 130 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.59 5,077.60 5,192.21 5,223.80 131 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 5,109.39 5,160.42 5,192.21 132 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 5,141.17 5,128.64 5,160.42 160 133 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 5,173.53 5,096.28 5,128.64 134 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 5,205.91 5,063.90 5,096.28 135 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 5,237.70 5,032.11 5,063.90 136 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 5,269.46 5,000.35 5,032.11 137 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 5,301.46 4,968.35 5,000.35 138 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 5,332.98 4,936.83 4,968.35 139 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.53 5,364.51 4,905.30 4,936.83 140 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 5,396.30 4,873.51 4,905.30 141 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 37.03 5,433.33 4,836.48 4,873.51 142 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 5,465.72 4,804.09 4,836.48 150 143 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 5,497.24 4,772.57 4,804.09 144 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 5,529.01 4,740.80 4,772.57 145 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 5,560.79 4,709.02 4,740.80 146 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.01 5,592.80 4,677.01 4,709.02 147 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.78 5,623.58 4,646.23 4,677.01 148 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 5,655.38 4,614.43 4,646.23 149 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.81 5,687.19 4,582.62 4,614.43 150 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 5,718.69 4,551.12 4,582.62 151 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 5,750.71 4,519.10 4,551.12 152 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 5,782.22 4,487.59 4,519.10 140 153 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.98 5,814.20 4,455.61 4,487.59 154 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.53 5,845.73 4,424.08 4,455.61 155 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.77 5,876.50 4,393.31 • 4,424.08 156 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 5,908.25 4,361.56 i 4,393.31 157 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 5,939.77 4,330.04 4,361.56 158 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.34 5,972.11 4,297.70 ' 4,330.04 159 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.69 6,002.80 4,267.01 4,297.70 133 160 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 6,034.30 4,235.51 4,267.01 132 161 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 6,065.81 4,204.00 4,235.51 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 3.87 6,069.68 4,200.13 4,204.00 GLM#4,2 7/8 SFO-1,8RD,Orfice 2.441 4.625 7.10 6,076.78 4,193.03 4,200.13 PUP-2 7/8,6.4#,L-80,8RD 2.441 2.875 4.31 6,081.09 4,188.72 4,193.03 131 162 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 6,113.08 4,156.73 4,188.72 130 163 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 6,145.46 4,124.35 4,156.73 164 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 6,177.46 4,092.35 4,124.35 165 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 6,209.24 4,060.57 4,092.35 166 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.31 6,241.55 4,028.26 4,060.57 167 Joint 2 7/8;6.4#,N-80,8RD Tubing 2.441 2.875 31.52 6,273.07 3,996.74 4,028.26 168 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.99 6,305.06 3,964.75 _ 3,996.74 169 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 6,336.81 3,933.00 3,964.75 170 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 6,368.33 3,901.48 3,933.00 171 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.70 6,399.03 3,870.78 3,901.48 172 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 6,431.41 3,838.40 3,870.78 120 173 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 6,463.43 3,806.38 3,838.40 174 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 6,495.21 3,774.60 3,806.38 175 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.38 6,526.59 3,743.22 3,774.60 176 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 6,558.36 3,711.45 3,743.22 177 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 6,590.15 3,679.66 3,711.45 178 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.35 6,622.50 3,647.31 3,679.66 179 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 6,654.50 3,615.31 _ 3,647.31 180 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.35 6,686.85 3,582.96 3,615.31 181 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 6,718.62 3,551.19 3,582.96 182 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 6,750.40 3,519.41 3,551.19 110 183 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.57 6,781.97 3,487.84 3,519.41 184 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.36 6,813.33 3,456.48 3,487.84 185 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.75 6,845.08 3,424.73 3,456.48 186 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 6,876.92 3,392.89 3,424.73 187 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.35 6,909.27 3,360.54 3,392.89 188 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 6,941.29 3,328.52 3,360.54 189 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.32 6,973.61 3,296.20 3,328.52 190 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.38 7,004.99 3,264.82 3,296.20 191 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 7,036.76 3,233.05 3,264.82 192 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 7,068.26 3,201.55 3,233.05 100 193 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 7,100.03 3,169.78 3,201.55 194 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.30 7,132.33 3,137.48 3,169.78 195 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 7,163.84 3,105.97 3,137.48 196 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.65 7,195.49 3,074.32 3,105.97 197 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.84 7,227.33 3,042.48 3,074.32 198 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 7,259.13 3,010.68 3,042.48 199 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.70 7,289.83 2,979.98 3,010.68 200 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 7,321.65 2,948.16 2,979.98 201 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 7,353.16 2,916.65 2,948.16 202 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 7,384.66 2,885.15 2,916.65 90 203 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.31 7,416.97 2,852.84 2,885.15 204 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 7,448.47 2,821.34 2,852.84 205 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.31 7,480.78 2,789.03 2,821.34 206 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 7,512.29 2,757.52 2,789.03 207 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.55 7,543.84 2,725.97 2,757.52 208 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.30 7,576.14 2,693.67 2,725.97 209 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 7,607.66 2,662.15 2,693.67 210 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 7,639.44 2,630.37 2,662.15 211 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 7,671.46 2,598.35 2,630.37 212 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 7,703.83 2,565.98 2,598.35 80 213 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 7,735.83 2,533.98 2,565.98 214 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 7,767.34 2,502.47 2,533.98 215 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.49 7,798.83 2,470.98 2,502.47 216 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.74 7,829.57 2,440.24 2,470.98 217 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 7,861.35 2,408.46 2,440.24 218 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.35 7,893.70 2,376.11 2,408.46 219 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 7,926.06 2,343.75 2,376.11 220 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 7,957.86 2,311.95 2,343.75 221 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.97 7,989.83 2,279.98 2,311.95 222 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 8,021.35 2,248.46 2,279.98 70 223 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 8,053.13 2,216.68 2,248.46 224 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 8,085.13 2,184.68 2,216.68 225 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.35 8,117.48 2,152.33 2,184.68 226 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.56 8,149.04 2,120.77 2,152.33 227 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 8,180.82 2,088.99 2,120.77 228 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 8,212.32 2,057.49 2,088.99 229 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.66 8,243.98 2,025.83 2,057.49 230 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 8,276.34 1,993.47 2,025.83 231 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.30 8,308.64 1,961.17 1,993.47 232 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 8,341.02 1,928.79 1,961.17 60 233 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 8,372.78 1,897.03 1,928.79 234 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.98 8,404.76 1,865.05 1,897.03 235 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.00 8,436.76 1,833.05 1,865.05 236 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 8,468.28 1,801.53 1,833.05 237 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.28 8,500.56 1,769.25 1,801.53 238 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.47 8,532.03 1,737.78 1,769.25 239 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 8,563.57 1,706.24 ' 1,737.78 240 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 8,595.07 1,674.74 1,706.24 241 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.26 8,626.33 1,643.48 1,674.74 242 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.48 8,657.81 1,612.00 1,643.48 50 243 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 8,690.19 1,579.62 1,612.00 244 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 8,721.93 1,547.88 1,579.62 245 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.31 8,754.24 1,515.57 1,547.88 246 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 8,785.74 1,484.07 1,515.57 247 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.35 8,817.09 1,452.72 1,484.07 248 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 8,848.59 1,421.22 1,452.72 249 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 8,880.95 1,388.86 1,421.22 250 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 8,913.32 1,356.49 1,388.86 251 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.82 8,945.14 1,324.67 1,356.49 252 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.38 8,977.52 1,292.29 1,324.67 40 253 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.36 9,009.88 1,259.93 1,292.29 254 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.50 9,041.38 1,228.43 1,259.93 255 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 9,073.17 1,196.64 1,228.43 256 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.40 9,105.57 1,164.24 1,196.64 257 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 9,137.94 1,131.87 1,164.24 258 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 9,169.72 1,100.09 1,131.87 259 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.48 9,201.20 1,068.61 1,100.09 260 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.40 9,233.60 1,036.21 1,068.61 261 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 9,265.12 1,004.69 1,036.21 262 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 9,297.51 972.30 1,004.69 30 263 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.34 9,329.85 939.96 972.30 264 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 9,361.62 908.19 939.96 265 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.02 9,393.64 876.17 908.19 266 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.55 9,425.19 844.62 876.17 267 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 9,456.97 812.84 844.62 268 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.74 9,488.71 781.10 812.84 269 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 9,520.50 749.31 781.10 270 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 9,552.30 717.51 749.31 271 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 9,584.07 685.74 717.51 272 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.76 9,615.83 653.98 685.74 20 273 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.34 9,648.17 621.64 653.98 274 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.37 9,680.54 589.27 621.64 275 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.80 9,712.34 557.47 589.27 276 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.51 9,743.85 525.96 557.47 277 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.87.5 30.70 9,774.55 495.26 525.96 278 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.71 9,805.26 464.55 495.26 279 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 30.72 9,835.98 433.83 464.55 280 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 9,868.37 401.44 433.83 281 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.79 9,900.16 369.65 401.44 282 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.52 9,931.68 338.13 369.65 10 283 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.54 9,963.22 306.59 338.13 9 284 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.40 9,995.62 274.19 306.59 8 285 .loint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.42 10,027.04 242.77 274.19 7 286 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.78 10,058.82 210.99 242.77 6 287 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.57 10,090.39 179.42 210.99 5 288 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 10,122.78 147.03 179.42 4 289 .loint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.49 10,154.27 115.54 147.03 3 290 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 32.39 10,186.66 83.15 1 15.54 2 291 Joint 2 7/8,6.4#,N-80,8RD Tubing 2.441 2.875 31.77 10,218.43 51.38 83.15 1 292 .loint 2 7/8,6.4#,N-80,8121)Tubing 2.441 2.875 30.70 10,249.13 20.68 51.38 XO PUP 3 1/2 IBT X 2 7/8 8rd(BxP) 2.441 2.875 0.97 10,250.10 19.71 20.68 XO PUP 3 1/2 1BT x 3 1/2 IB(PxP) 2.441 2.875 1.38 10.251.48 18.33 19.71 Hanger,LDS to PI'P 2.441 2.875 0.50 10,251.98 17.83 18.33 17.83'RR,; 17.83 10,269.81 (0.00) 17.83 SCU 41A-04 MW Vs Depth 0 500 - 1000 1500 2000 2500 3000 3500 4000 4500 — MW vs Depth 5000 EL 5500 a 6000 — U, 6500 7000 7500 8000 8500 9000 9500 10000 10500 11000 11500 8 9 10 11 12 13 14 Mud Density(ppg) SCU 41A-04 Days Vs Depth 9000 9500 10000 SCU 41A-04 10500 a v a a v - ra v i) 11000 11500 12000 12500 0 5 10 15 20 25 30 35 Days Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 ' i 3.3 -/o/ v9.oa ;2/3 d28' 4/30/13 c,Y/, 3 Daily Operations: 04/30/2013-Tuesday Rig down, and move, pipe houses, motor houses, gen sets, pump houses and pits. Load out mats, misc equip, unstring blocks. Finish final grade @ 41A-04. Scope top section of derrick down and LD derrick, prep derrick for removal . Lay felt and liner on 41A-04 well. 05/01/2013-Wednesday Continue to Rig down and transport loads from 24-15 to 41A-04. Crane Derrick and Drawworks off of Sub Structure. Move Water Tank and Crane Sub off of Pony Subs. Inspect liner f/hydrocarbons. Cut,fold & dispose of same. Load and transport Rig Mats to 41A-04. Set Mats and prep for rig up. Crane Sub onto Pony Subs and center over Well. Set Drawworks and install Derrick. Set Water Tank and first Pit Module. Install & secure Shakers,set pump houses, set motor houses, boiler houses, string up blocks, raise derrick, lay liner and lay mats for pipe houses. 05/02/2013-Thursday Continue moving rig from 24-15 to 41A-04. Set Gas Buster, DD &Canrig shacks. Set SLB cement pump building and Silo. Set Pipe Shed Modules. RD Office Trailers. Move and R/U both office trailers and tanks. R/U Envirovac& Break Room. Hook up Generator and plumbing. Install Top Drive & Service Loop. Set cuttings tank. Install Wind Walls w/Crane. Continue rigging up Service Lines & Rig Equipment, change liners in pumps t/4", haul 4" Dp and final equipment f/24-15 pad. Repair failed valves in Mud Pits. Function test TD and Rock Washer(good). Start Boiler and circ steam throughout. Terminate electrical. Change out Kill HCR t/different style. Fill Rig Water Tank. Take on water in pits and test Pit valves. Hook up Gas Buster. Hook up Kelly Hose and set C.O.M. 05/03/2013- Friday Continue to R/U Arctic Fox onto SCU 41A-04. Finish changing Liners to 4". Begin transporting 11.4 ppg mud from storage @ G&I. Change Saver Sub and test run Top Drive. Fill out "Rig Acceptance" check list. RIG ACCEPTED @ 09:00. Remove Temp Well Cap. N/U BOP: XO Spool, Sgl Gate w/4" Ram Mud Cross, Dbl Gate w/Blinds in btm, VBRs in Top Cavity&Annular Preventer. Make up Choke and Kill Lines. Install Flow Nipple and Drip Pan. Quadco Rep setting up Rig Watch system. Dilute 11.4 ppg mud to 10.5 and adjust properties. Load Pipe Shed with 4" Dp and SLM same. Torque Flange connections with Hydraulic Wrench. Open Ram doors and remove debris from cavities. Inspect Rams &grease seals. Finish closing Ram doors. Pull Test Plug and inspect. M/U Test joint and R/U test equipment. Fill Stack with clean water. Pre-test BOP components. Tighten leak between XO flange and Single Gate. Tighten Bonnet Flange on Choke manual Valve and service Choke HCR. Continue mixing Mud and loading pipe shed with DP & HWDP. 05/04/2013 -Saturday Continue with pre-test of BOP while waiting on AOGCC Rep.to arrive.Test BOPs and related equipment to 250L/4,000H. Test Annular to 250L/2,500H. All tests held for 10 min &chart recorded. Perform Accumulator Pre-charge test. Main test conducted on 4"Test Jt.Tested VBRs on 4" &4-1/2"test its. FP on CMVs#10,#11 and Hydraulic Choke. Serviced Valves and overhauled Choke. Found small amount of scale and worn Teflon Seals in Choke. Reassembled and retested with good results. AOGCC BOB NOBLE witness bop test. Rig down testing equip, Blow down all lines,set wear bushing, (ID 6 1/8). Make up clean out assembly and pick up hwdp. Pick up 4" drill pipe and single in hole from 586'to 5,750'. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 St)-/33 10/09 0a c2/3...e<..7by 4/30/13 6/ Daily Operations: t ;. 05/05/2013-Sunday Continue to single in the hole with 4" Dp from 5,750'. Tag CIBP @ 9,631'. Fill pipe& Break circulation. Rig up to Test Csg. Purge air from lines. Pressure test 7" Casing to 3,000 psi for 30 min. Chart record test. 0 psi bleed in 30 min. Bleed pressure & R/D test equipment. P/U Sgl and park Bit @ 9,629'. PJSM. Displace Well Bore to 10.5 ppg 6% KCL/PHPA Drilling Fluid @ 6 bpm, 720 psi. POOH for WhipStock f/9,631'. Rack back DP& HWDP. L/D Jars. Inspect Mill & Bit. Clear Rig Floor of slip/trip hazards and stage BHA Components. Pick up Whipstock assembly,orient UBHO to Whipstock,and RIH with hwdp T/642'. Weight of bha 40#. PJSM,Trip in hole F/642'T/894'. Service TD& DW. Trip in hole w/whipstock on 4"drill pipe F/894' T/6,850'. Injected 547 bbls drilling fluids,and 154 bbls water. 05/06/2013-Monday TIH with Whipstock assy from 6,850'to 9,606'. Fill pipe every 2,500'. PJSM. Rig up Pollard E-line and Sheaves. RIH with �J/L Gyrodata tools on Pollard E-line to UBHO sub @ 9,511'. Gyro survey indicated Whipstock oriented @ 197 deg. Rotate pipe, // �I and then stroke 15'to orient Whipstock @ 160 deg. Perform check shot w/Gyro. Orientation confirmed @ 158 deg. POOH and R/D Pollard/Gyro tools. Slack off to land 22'tail Pipe onto CIBP. Set Anchor with 17k do wt. Pull 10k over UP wt to verify Anchor set. Set down and shear off of Whipstock w/35k. Break circulation and record parameters. UP 150k, DN 15 cam, ROT 150k, 1.5k Tq @ 60 RPM, 1,370 psi @ 6 bpm. Mill Window f/9,591'to 9,605', drill new hole F/9,605'T/9,628'. Circ 20 bbl sweep @ 6 bpm, 1,320 psi, 1.6k torq. 107 lbs metal shavings recovered. Perform FIT test @ 13.5 ppg EMW(1,502 PSI). Test good. Trip out of hole F/9,625'T/Mill assembly, p/u 152k,s/o 149k. 59(1: 05/07/2013-Tuesday Break inspect and LD Window Mills. Starter mill was 1/16" under gauge. Upper Mill was in gauge. Clear floor of slip/trip hazards. Make up Wash Tool. Flush Well Head and BOP to remove possible metal shavings. Make up BHA#3: M/U HCC 505 PDC, .81 deg Motor, Stab, Pony Clrs, MWD and LWD. Orient&Calc offset. Up Load LWD. Load RA Source. M/U NMDCs and (2)stds HWDP. Surface test LWD and MWD. (good test) P/U Jars &TIH w/remaining HWDP. Single in the hole with (50) joints of 4' Dp. Drift ea jt w/2.35 drift. Continue to TIH with Stands f/2,415'to Window @ 9,605'. M/U TD&fill pipe. Ream under guage hole F/9,608'to 9,628'-20 rpm, 1,800 ft/lb tq, 200 gpm. Circulate bottoms up, 7,200 stks @ 250 gpm and 20 rpm @ 1,800 ft/lb. Break off topdrive,stand back stand#141 and P/U single for drilling. P/U and install side entry sub in drillstring, P/U Gyro on wire line and run in to the UBHO sub, Seat Gyro in UBHO sub and test. Drill F/9,628'to 9,656'. Hilcorp Alaska LLC s Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 Daily Operations: 5/8/2013-Wednesday Slide drill to build angle from 9,656'to 9,704'. Gyro survey to steer. Re-initiate Gyro every hour to verify orientation. Rack back(2) stds. POOH w/E-line and Gyro. Well showing slight flow. Brk& lay dn Side-entry sub and Gyro tools. Flow from Well increasing. MU (2) stds and Brk circ @ 9,704'. (14.4 bbl gain since pumps off @ 11:00) Drill from 9,704'to 9,720'. B/U gas increasing. P/U & monitor Well. 13:53, Shut in Well due to Gas entrained in mud getting to pits. 2572 units max. Line up to Gas Buster and circulate influx out. Mud returns @ BU was water cut to 8.5 ppg. Chlorides dropped from 30,000 to 6,000 ppm. Hold 400 psi on Choke to prevent additional influx while increasing MW f/10.5 ppg t/10.8 ppg, 10.8 ppg in, 10.7+out: Shut dn pumps and open Annular Preventer. Well static. Directional Drill 6" hole f/9,720'to 9,832' to build angle. Back ground Gas 15 units, but connection Gas spiking @ 1,768 units. Drill F/9,832'to 9,868' while weighting up to 11.0 ppg,flow rate 4 bbls/hr. Drilling F/9,868'to 9,957', flow rate during connection @ 5 bbls/hr with connection gas spike @ 1,338 units. Weight up to 11.2 ppg. After weighting up the well is still flowing during connections @ 1.7 bbls/hr and connection gas spikes have dropped to 0 units. Drill ahead. 5/9/2013 -Thursday Directional drill f/9,957't/10,048'. Build angle &turn t/planned Well path UP 170k, DN 160k, RT 162k,TO 2200 @ 40 RPM, 5k WOB. 1,950 psi @ 6 bpm. Continue to drill 6" Production Hole f/10,048 t/10,182. Limit penitration rate during drilling breaks to 50'/hr as per Geologist. Driller had Drlg Brk @ 10,177& increase in Tq. He picked off bottom @ 10,182. Full loss of returns. Attempts to fill hole failed. POOH to Casing Shoe @ 9,605. Pump 26 bbl LCM Pill dn Annulus via Kill Line while POOH. Displace pill in Ann. Mix and pump 50 bbl LCM @ 20 ppb down Dp. Displace out of Drill String. Mix and pump 42 bbl LCM @ 80 ppb down Annulus and top fill to displace. 50 bbl pill stood up Well, but losing @ 4 bpm. 26 bbl Ann pill slowed losses to 50 bph. Circ across top of hole while building volume. 42 bbl LCM pill @ 80 ppb reaches loss circulation zone @ 10,182'. Close hydrill and squeeze 5 bbls of LCM pill into formation, pressure broke down @ 617 psi bleeding back to 190 psi. Squeeze 5 more bbls, pressure broke down @ 724 psi. Bleed back to 340 psi. Squeeze 5 more bbls, pressure broke down @ 950 psi. With 16.5 bbls of 80 ppb pill squeezed away formation holding 1,075 psi. A total of 20 bbls squeezed into the formation holding 1,125 psi for EMW of 13.25 ppg. Bleed pressure and open Hydrill,The remaining 24 bbls of the 80 ppb LCM pill remains in open hole while we build new mud. Monitor well bore,slight flow, close hydrill and and hold pressure. Open Hydril. Tripping in one stand putting the bit @ 9,635', 30' below the whipstock. and circulate a bottoms up to ensure we have 11.0 ppg mud in the well bore. BU Gas peaked @ 846 units.Total losses during the last 24 hrs= 655 bbls. 05:45,TIH to 10,182. 5/10/2013 - Friday Finish TIH to 10,182'. Break circulation. (Est 20 bbls of 80 ppb LCM Pill in OH) Drill from 10,182'to 10,192'. No returns, but hole staying full. P/U above loss zone and monitor Well. (static losses @ 48 bph) Pump 48 bbl LCM Pill @ 25 ppb. Displace Pill out bit (zero returns) POOH t/Csg Window. Static loss rate now @ 12.6 bph. Top Squeeze 85 bbls in 5 bbl increments in attempt to build formation integrity. Max psi developed =440. Loss rate diminished to 6 bph. Build 11.2 ppg surface volume. TIH to 10,130'. Break circ. Load pipe with 27 bbl LCM Pill @ 25 ppb. Drill from 10,192't/10,228'. 4.8 bpm, 1,250 psi, 3,200 tq @ 40 RPM. Initial loss rate 1 bpm. Loss rate increased slowly until no returns after drilling 32 ft. Max Gas = 154 units. Mud Loggers reported clean Sand samples. Pump 47 bbl LCM Pill @ 25 ppb and attempt to displace out bit, but cut short due to low surface volume. POOH to Shoe to build additional volume. Top fill annulus via Kill Line until full and then switch to Trip Tank. Monitor Well on Trip Tank while building volume. Losses @ 40 bbl/hr. Mix up another LCM pill @ 25 ppb and pump 48 bbls down drill pipe with 65 stks and 470 psi.Chase LCM pill with 35 bbls 10.9 ppg mud. 83 bbls pumped 27 bbl loss Monitor losses with trip tank, 24 bbls/hr loss. Attempt squeezing LCM in formation to slow losses, no success, losses 40 BBL/Hr. Mix and spot 40 bbl 60 ppb LCM pill on the back side (BaraSeal Steal Seal). Monitor well @ 27 bbl/hr losses while mixing new mud at 10.8 ppg. 5/11/2013-Saturday Monitor Well on Trip tank @ Casing Window. Top fill to work 40 bbl LCM Pill down to Loss zone. Currently losing 24 bpm. Apply squeeze pressure when Pill reached loss zone to build formation integrity. Pump in 5 bbl increments. Max psi of 800psi bled to 30psi. Monitor Well (3.6 bph loss rate.) POOH 5 stds t/place bit above LCM Pill. Attempt to CBU, but Drill String plugged. Attempts to gain circulation with pressure and pipe surge failed. POOH for BHA change from 9,280'to BHA @ 782'. Well initially taking 3.6 bph and then zero losses to hole. Well began flowing slightly while POOH and increasing in rate near BHA. Decision made to M/U Circ Sub and TIH t/Window. M/U XO &Circ Sub on top of HWDP. Drop Opening Ball & open Sub w/1280 psi. Circ thru ports to verify flow path. TIH from 906 to 3,500. Pump 26 bbls of 11.0 ppg mud into Dp and continue in Service Rig and topdrive while monitoring the well bore. Trip in F/6,883'to 9,100',getting flow back due to under balance mud. Pump 60 bbls of 11.0 ppg down drillstring to stop flow. Continue trip in to 9,588' Up wt= 165k Dn wt = 160k. Circulate and condition weighting up to 11.0 ppg attempting to kill water flow. Pumping 11.0 ppg mud down the drillstring and getting 10.8 ppg returns. At 6,000 stks water cut mud started coming across the top of the hole. Got 85 bbls clean 8.5 ppg fresh water to surface. Take returns to rockwasher. Take returns back to pit system when mud weight got back to 10.3 ppg. Weight up mud in pit system to 11.2 ppg. Max Gas while circulating 800 units. 5/12/2013-Sunday Circulate 11.0 ppg mud do Drill String. Returns 10.4 ppg diluted. Shut in Well. Increase MW in surface volume t/11.2 ppg and increase LCM concentration t/15 ppb;Shut in DPP= 110 psi. (11.24 EMW). Displace Well f/11.0 ppg to 11.2 ppg while holding 250 psi back pressure Choke Maintain 550 psi on Dp once 11.2 ppg exited circ sub. Zero losses to formation. Monitor Well for 30 min. Fluid dropped in Riser 4 ft (.9 bph loss rate). Pump 26.5 bbl LCM Pill (50 ppb baracarb) and displace to balance @ Circ Sub. POOH for BHA change from 9,588'to BHA @ 756'. PJSM-POOH with HWDP to BHA#3, Pull sources from MWD tool and download. Continue laying down BHA#3, UBHO sub, Filter sub,Stop sub, SCN-LWD, BCPM, MWD Ontrak, 2-Non mag pony DC, Motor and bit. Motor and Bit plugged with LCM, MWD tools in good shape, download went well. Clear and clean rig floor, Pull wear bushing, install test plug and test jt. Function test: Upper and lower pipe rams,Test Annular 250 psi low F/5 min 2,500 psi high F/5 min, R/D test equip, pull test plug, install wear bushing. Function test Blind rams, ready rig floor to pick up BHA#4. P/U BHA#4, Rerun bit, new motor, MWD, Circ sub and jars, Losses 0 Static. 5/13/2013- Monday M/U and test BHA. No Pulse from BCPM. Pull up & check filter sub. Found Polymer& LCM in filter sub. Clean Pump Suction Screens (80% blinded) Open bleed valves. Circulate Suction Pit thru bleeders and clean screens every 10 min to remove LCM and Polymer. Re-test MWD with good results. TIH w/HWDP and Jars. M/U Circ Sub, drop Opening Ball and cycle closed w/2,150psi. Continue pumping to verify flow path thru Bit. TIH w/remainder of HWDP. TIH with Dp from 776. Well giving calc. displacment from Dp. Driller reported lost returns @ 3,200'. Suspect Float had possibly failed allowing fluid to U-tube. (0 losses to formation) (3) attempts necessary to communicate with BCPM. Confirm good signal @ 310, 250&210 GPM. Continue TIH f/3,200't/Window @ 9,605'. Fill pipe every 1,800' &confirm MWD signal, 210 gpm, 1,500psi, Good PulseUp- 154k Dn-148k. PJSM, Service rig and topdrive. Cut and slip 140' drilling line. Calibrate Blocks. Trip in F/9,580'to 9,832' Uwt- 162k Sow-156k. Circulate B/U, at bottoms strokes 2,173 units of gas with 10.8 ppg mud, had water influx in mud, mud wt. still 10.8 ppg. Trip in F/9,835' encountering tight hole at 9,948'. Wash and ream down to bottom @ 10,228' pumping 128 gpm with 890psi,40 rpm and 2500 ft/lb Tq. Reaming showed a few tightg spots but mostly LCM. 0 losses while reaming. Drill F/10,228'to 10,288' @ 185 gpm, 1,590 psi, 40 bbl/hr losses while drilling. At 10,240' had a formation change from sand to Tuffaceous Siltstone. 5/14/2013 -Tuesday Drill from 10,288 to 10,355'. 5.3 bpm, 1975 psi, losses ranging 40 to 50 bph. Mud Logger reported good Oil show starting @ 10,250'. CBU at 216 gpm-1,730psi, 40 rpm. Fluid loss decreased to 25 bph. Dropped 1.76" ball to open circ sub, chase w/1,500 strokes, seated ball, opened sub fully w/2,466psi. Dropped 1.698" ball,gave it 5 minutes to fall and pumped 20 bbls of 50 ppb LCM pill. Chased pill with 100 bbls 11.2 mud to spot pill. Fluid loss decreased to 18 bph. POOH slowly f/10,355'to 9,549'. Pulled 13 stnds. Calculated hole fill 4.8 bbls, actual hole fill 11.7 bbls. Pipe pulled dry entire 13 stnds. Monitored static fluid loss at 9,549'. Loss rate at 18 bph. Close annular, line up dwn drill string and attempt to squeeze LCM pill into loss zone in 250psi increments,allowing 10 to 15 minutes between squeezes. Pumped a total of 33 bbls over 2-1/2 hrs in 2 to 4 bbl increments. Highest psi attained was 415 psi before psi broke over. PSI bled to 47 psi each attempt. Monitored well on trip tank f/30 minutes. Fluid loss at 15 bph. RIH f/9,549'to 10,335'. Pump an additional 20 bbls LCM pill at 50 ppb,followed with 100 bbls 11.2 mud to spot pill. Pill was pumped and displaced @ 2 bbl/min and 330 psi. Trip out F/10,355'to 9,580' Uwt-166kDwt-162k. Monitor well for 1 hr, loss rate static is 12 bbls/hr. Sqeeze LCM into the formation, highest pressure observed, 1,125psi. Monitor well,fill hole with hole fill, losses 12 bbls hr mix LCM pill @ 80 ppg. Trip in and spot 40 bbls of 80 ppb LCM pill, 50 ppb BaraSeal, 30 ppb Cal Carb. Trip out F/10,355'to 9,580' Uwt-166kDwt-162k. Monitor losses keeping hole full with the trip tank, 15 bph losses. Squeeze Lcm into formation and monitor,still showing 15 bph losses. Trip up to window and mix 75 ppb BaraSeal, BaraCarb and BaraFiber pill. Trip back in to open hole putting circ sub 300' below whipstock. Pump LCM pill and spot in open hole. Monitor wellbore while drilling mud is mixed due to being low. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 6/4/..7, Daily Operations: "'yam' 05/15/2013-Wednesday No activity to report. 05/16/2013-Thursday No activity to report. 05/17/2013-Friday No activity to report. 05/18/2013-Saturday MU 4 1/2" DWC/C-HT(buttress casing) 12.6#, L-80,Liner Shoe Track and float equipment. Check floats(ok),Cont RIH MU toque 6,200 ft/lbs optimum,installing free floating stand off centralizers on the first 28 jts. Run a total of 33 jts. P/U liner hanger assembly, Mix POW and pour inside hanger,let set for 30 min. P/U first Stand of HWDP, Make up topdrive and circulate liner volume. Trip in with the 4-1/2" liner and hanger assembly. Fill casing on the fly with the fill up hose and make up topdrive every 10 stands to ensure its full. Trip in slow due to losses. Hole taking 4 bbls/hr. 05/19/2013-Sunday Cont trip in hole with 4-1/2" 12.6#DWC L-80 Liner on 4" DP f/6,365'to 9,508'at 90 seconds per stand. MU topdrive and circulated 1-1/2" pipe volumes at 80 gpm-340 psi. MU Baker cement head with 10'on top and 20' pups below. Have 28' 4.S stickup(to allow for safety off packer)with shoe 20'off bottom. Circ and condition mud for cementing at 10,787'. SLB ,{- pumped 5 bbls water to purge lines,tested lines at 1,000 and 5,000 psi f/5 minutes(ok). SLB started batch mixing while rig circulated. Rig pumped 35 bbls 12 ppg MudPush II and chased with 5 bbls mud. SLB pumped 70 bbls(294 sx) 15.3 ppg Z.t A" EasyBlok cement w/1 ppb cemnet at 3 to 4 bpm. Baker dropped wiper dart and SLB pumped 5 bbls water for spacer. SLB displaced with 110 bbls 11.1 ppg mud at 5 bpm with psi ranging from 175 psi to 800 psi. Displace with 118.5 bbls and plug 1/ bumped. Held 500 psi over(1700) FCP of 1200 psi for 5 minutes and bled back 1.5 bbls. Floats held. CIP at 21:30 on 5-19- 13. Set the Flex-Lock Hanger. Set HRD-ZXP liner top packer. Pick up to free travel and test liner lap to 2,100 psi for 5 min (Test Good). Pressure up T/1,000 psi,pick up until pressure drop is seen. Bring pumps up to circulating rate and circulate cement out of well bore. 30 bbls cement returns to surface. Drop nerf ball down drill pipe and circulate 1.5 pipe volume cleaning cement from pipe. Trip out F/9,372'to 9,058', Pump dry job and continue trip out. 05/20/2013-Monday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 i 'y f,2, Daily Operations:' Cont POOH f/9,058'to 1,641'racking back in derrick. Cont POOH LD DP and HWDP f/1,641'. LD liner run tool. Dog ring was shifted indicating good weight transfer to set packer. Clear rig floor, PU cement head and break off pup jnts. LD cement head and pups. Drift 45 jts 2-7/8", RU Weatherford tongs. CO handling equipment. MU 3.75"bit,bit sub and XO. PU and single in hole with 45 jts 2-7/8"SLH90 work string(1,411'total length). RD Weatherford tongs,CO handling equipment,MU 2-7/8"x 3-1/2" IF XO and 3-1/2"x 4" HT-38 XO. Stabbed first stand of 4" DP and upon torque up of connection,the 2-7/8" joint in slips broke off clean at base of box end(left 2-1/2"section of box above bottle neck). Call out Baker Fishing with 1- 1/2"spear,wait on Baker,Baker on location at 17:30. MU spear and XO's on single 4"jt. Installed spear and raised 2-7/8" jnt 2'to accommodate elevators. RD Baker Fishing and released. Wait on Weatherford tong hand. U tongs,CO handling equipment. eatherford on location at 19:00. POOH LD all 45 jts 2-7/8"workstring(to be replaced with new string of 2- 7/8"). Wait on new string of 2-7/8"SLH tubing(clean up,service topdrive and draw works,grease crown). Off load 2-7/8" SLH-90 tubing to pipe shed,strap and drift same. M/U Bit,bit sub and cross over to bottom of first Jt. Trip in picking up a total of 45 jts of 2-7/8"tubing to the depth of 1,418'. Continue tripping in running 4" HT-38 drill pipe from derrick F/1,418' to the top of the liner @ 9,383'. Rig up and test casing and liner lap T/3,000 psi for 30 min on chart. 05/21/2013`-Tuesday Test casing at 3,000 psi f/30 minutes on chart.. Good test. RD test equipment, blow down cement line. Cont RIH f/9,339', entered liner hanger top at 9,383'and saw no fluctuation on weight indicator. RIH to 10,540'and obtained rotating and pump rate parameters. 160 gpm-885 psi,20 rpm=1600 ft/Ibs,30 rpm=1700 ft/lbs,60 rpm=1900 ft/lbs,up wt 155K,down wt 150K,rot wt=154K. Ease down f/10,540'and tagged landing collar at 10,664'md. Pumping at 109 gpm-700 psi. 1-2K wob. Drilled out landing collar,41'cement,tagged top of float collar at 10,707'. Drilled out float collar and cement down to 10,723'. Made connection at 10,723'and had no bit weight beyond that. Stopped rotation and slowed pump to 80 gpm. Still no bit weight down to 10,777'(10'above top of shoe). CBU at 160 gpm-921 psi. Rotate and reciprocate 50 rpm. Have some show of cement on shakers using phenylphalene. POOH rack back one stand. RU test equipment. With rig injection pump,pumped down DP and kill line attempting to test casing at 3,000 psi. At 2,650 psi pressure broke over and started bleeding off. Pressure bled from 2,463 to 1,450 in 20 minutes. Verified no leaks. Notified Drilling Engineer, made second attempt at test. Increased pump rate on injection pump and at 2,880 pressure broke over and started bleeding off. Notified Drilling Engineer and bled well to 0 psi. Opened rams, RD test eqipment. Monitored well 15 minutes. Well static. Decision made to POOH to run CIBP on e-line. POOH rack back 4" DP from 10,777'to 1,418'. RU Weatherford tubing tongs, CO handling equipment. Cont POOH rack back 22 stands 2-7/8"pipe from 1,418'. LD last single and 3 3/4" bit. Spot Pollard e-line truck and RU same,MU Halliburton CIBP,CCL and weight bars. Unable to reach setting depth of 10,777',wire line stopped @ 10,765', POOH with wire line. Install gama tools above CIBP&TIH to 10,758',lost communication with tool, POOH,troubleshoot electrical problem,CO weight bar(short in weight bar). Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 c/y// Daily Operations: 05/22/2013-Wednesday CO weight bar on tool string (electrical short in weight bar), Pollard RIH with 12.3' CIBP and Gamma Tool string to 10,747'. Made 5 attempts to get string deeper. Last attempt we had increased overpull. Set down one more time placing top of tool at 10,747', discussed with Geo and Engineer. Decision made to pull up hole 1' and set CIBP. PU and set CIBP top at 10,746' WLM. Pollard POOH with e-line. RU test equipment on rig floor. Test casing at 3,000 psi for 30 minutes on chart. Good test. RD test equipment. CBL tools and lubricator on location at 10:30. RU Pollard lubricator and secure in annular. MU CBL tools and RIH to 10,746'. Log up hole at 30'/minute to 9,290'. RIH to 10,746' and applied 1,000 psi to well bore. Pollard logged up hole at 30'/minute to 9,290'. Pollard POOH, LD tools and RD, released. RU Weatherford tongs and hadling equipment, PJSM, MU 3-3/4" bit, bit sub,4-1/2"Swaco multiback combo tool and XO on single 2-7/8"jt. Cont RIH with 2-7/8" workstring from derrick (22 stnds)total length of 2-7/8"workstring= 1,394.54'. RD Weatherford tongs. CO handling equipment. MU XO's and 7" multiback combo tool, cont RIH with 4" DP from derrick(74 stnds), MU upper 7" multiback combo, cont RIH with 4" DP from derrick(74 stnds +single) and tagged at 10,777' drill pipe measurement. This places bottom of lower 7" multicombo tool 3' above top of liner hanger. Displace 11.1 ppg mud with spacer followed by fresh water at 5 bpm-1,874 psi. Rotate and reciprocate, 10 rpm-1,000 ft/lbs torque, up wt 163K, dwn wt 156K rot wt 160K. POOH wiping both strings of casing to 9,357' (short trip to upper multiback combo tool). Injected 442 bbls drilling fluids, 131 bbls water. 05/23/2013-Thursday Cont POOH wiping both casing strings from 9,357' to upper 7" multiback combo tool at 6,080'. Clean magnet. Slip and cut 50' drill line,service rig and topdrive. Trip back to bottom 74 stands+single, had no tag up when bit/scraper entered liner top. Commence second 500 bbl fresh water displacement at 3.5 bpm-625 psi, rotating 20 rpm-1,000 ft/lbs torque, up wt 167K, dwn wt 163K. Pumped the casing wash pill as follows: 45 bbls Caustic followed with 5 bbls fresh water to clear mud lines, 60 bbls of 5% Baraklean FL and 45 bbls of Hi-Vis Barazan. Displaced pill train w/500 bbls 6% KCL(filtered at 25 micron) at 3.5 bpm. Had 119 NTU's at shut down from flowfine. Drained hoses, blew down circ lines and topdrive. POOH f/10,777' LD 149 jts 4" DP, upper 7" Swaco combo tool and 148 more jts 4" DP. LD lower 7" Swaco combo tool. CO 4" handling equipment, RU Weatherford tongs and LD 33 jts 2-7/8" SLH pipe. 05/24/2013 Friday Cont POOH from 697', LD remaining 2-7/8"workstring, 4.5" combo tool and 3-3/4" bit. Clean and clear rig floor. Halliburton loggers on location. Spot logging unit, RU sheaves, MU 30'tool consisting of pulse,gamma, ccl, qpc,temp and cfsm. RIH to 7,400' and start logging down hole at 30' per minute. Tagged bottom at 10,753'WLM. Start logging up hole at 15' per minute to 7,400', cont POOH. LD tool, RD sheaves. Received first load 2-7/8"tbg at 13:00. Rig crew cleaning,flushing lines, applying primer for painting. Rack and tally 2-7/8" tbg in pipeshed. Second load of 2-7/8", 2-3/8" tbg, guns and associated TCP equipment on location at 19:00. Pull wear ring, &test BOP'S (upper rams and annular @ 250/4000 psi f/5 min ea). Cont rack and tally 2-7/8" and 2-3/8"tbg. Stage 2-3/4" guns, blanks, DCI sub in shed. 05/25/2013-Saturday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 (-/fir/R Daily Operations: PU and RIH with 10 sections of 273/4"guns and associated equipment. Total length = 229.99'. PU RIH with 34 jts 2-3/8" 8 RND tubing. Top filled tubing with 6% KCL. Tubing length= 1,077.65'. PU and MU Halliburton 7" Champ IV Packer, CO handling equipment to 2-7/8", MU RA sub and XO's. PU RIH with 292 jnts& 10' pup, 2-7/8" 8 RD tubing. Added 21 bbls 6% KCL into 2-7/8"tubing at 10,622.89', then ran remaining tubing dry. Rig up wire line, RIH and correlate TCP guns. Send log to Geologist. Pollard POOH. LD 10' pup to position guns up hole 7' (bottom shot at 10,568'-top shot at 10,387'). 05/26/2013-Sunday RIH Pollard e-line CCL/gamma tool and coorelate gun depth via RA sub at 9,226'. Send log to wellsite Geologist. Guns verified on depth (top shot at 10,417'-bottom shot at 10,568'), Pollard POOH and RD released. Rotate string 2 turns to the right and set Champ packer at 9,264'. Slack off to 40K and set slips in rotary table. MU XO+TIW+headpin +swing and 1502 "T". Install sonic depth recorder. Took two fluid level shots in the 2-7/8" tbg. Fluid level at 7,294'. Close annular, line up on kill line, install Halliburton shot recorder on tubing stump, pressure up annulus to 2,200 psi (firing head activates at 1,800 psi), wait 6 minutes and guns fired. Halliburton shot recorder indicated guns fired. Opened bleeder valve on surface equipment. Had air flow for first 10 minutes indicating fluid entering 2-7/8"tubing,then tapered off. Monitored 120 minutes. Relay fluid depth information to completion Engineer. RD sonic tool, swing and 1502 "T". Top fill 2-7/8"tubing with fill up hose 20 bbls through TIW valve. MU topdrive, reduce annular psi to 300, pressure up on annulus to 500 psi through kill line. Strip up hole 3' and open bypass valve on Champ packer. Saw pressure drop on annulus indicating bypass valve opened on packer. Opened kill line to bleed any trapped pressure, opened annular, cont PU on string and released packer as per Halliburton Rep. Fluid level dropped out of sight in wellbore. Start CBU down 2-7/8"tubing with 6% KCL. Took 13.6 bbls to fill hole and get returns at flowline. Losing 16.8 bbl/hr at 3 bpm-485 psi. At 7,900 strokes started to gain fluid and getting oil and gas at surface. Shut down pump, closed annular and lined up on choke manifold taking returns through degasser. Cont circ through full open choke/degasser at 2 bpm losing 12 bph, until well past bottoms up. Shut down pump, monitored well via degasser line at shakers. Had no flow. Opened annular and resumed pumping for a total of 1-1/2 circulations. 3.5 bpm-550 psi, losing 7.8 bbl/hr. Shut down pump, monitor well at surface for 30 minutes. Fluid dropping in well bore. POOH slow to reduce chance of swabbing with packer. POOH rack back 2-7/8" in derrick from 10,584'to 1,322'. Caculated hole fill= 22.2 bbls, Actual hole fill =46 bbls. LD 7" PKR, change out handling equipment,stand back 14 stds 2-3/8" tubing. 05/27/2013 -Monday Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 (I y/,3 Daily Operations: LD 10 sections of 2-3/4"guns. All guns fired. CO handling equipment. Clean rig floor, load completion equipment in pipe shed,verify completion run tally with Engineer. PU and MU WLEG, 10' pup, MU on bottom of 4-1/2"Tri-Point hydraulic packer assembly with plug in X nipple, MU one jt 2-3/8"tbg, MU 1st 2-3/8" GLM with live valve (will sit at 10,195'), cont RIH 14 stnds 2-3/8" 4.7# L-80 8RD tbg from derrick. MU XO assembly with X nipple, cont RIH with 292 jnts 2-7/8" 6.4# L-80 8RD tbg from derrick. Three 2-7/8" GLM's with live valves will sit at 8,899', 7,006' and 4,193'. MU 8' x 3-1/2" OD Mod Butt tbg hanger on jt 292, MU 3-1/2" IBT to 2-7/8"XO on hanger top, MU 2-7/8" 8RD landing jt. Land hanger in tbg head. Up wt= 83kK dwn wt= 79K. RILD's. Test tubing hanger, test no good, pull hanger to floor and inspect, mark hanger and land, close annular, Psi up to 2500 psi on hanger, psi bleed off 1,000 psi, re-tighten LDS, psi up to 2,500 psi still bleeding off, check hanger through annulas valves no sign of leaking by hanger, PSI up to 2,500#, psi bleed down 100#, Cameron called test good. Drop packer setting ball. RU chart recorder and circ line on landing jt, ensure tbg is full, allow ball to seat in packer, pessure up on tbg to 3,000 psi to test tbg and set packer. Hold test for 30 minutes. Bleed tbg to zero. RU circ line on annulus and ensure annulus is full taking returns up tbg. Pressure up on annulus (communicates to through GLM valves) and tbg to 2,500 psi and hold for 30 minutes on chart. Bleed tbg and annulus to zero, RD chart sensor and circ lines, LD landing jt, install BPV in hanger. Total losses to well since perforating 143 bbls 6% KCL. 05/28/2013-Tuesday MU stack wash tool and use to flush Well Head/BOP. Circ soapy water thru Choke manifold and Gas Buster to clean all lines. Open gas buster and pressure wash out bottom, remove drilling tools from Rig Floor. Clean under Pipe Rack. Transport SLB Cement Silo and Pump to staging area. Clean Pits. Transport excess mud product to staging area. Continue to flush surface lines and clean pits. Pressure Wash BOP and prep for Nipple Down. ND BOP: Open Doors on Upper, Center and Lower Rams. Remove all Rams and pressure wash Cavities. Lube and close Doors. ND Flow Line and Flow Nipple. RD Choke and Kill Lines. ND and remove from Cellar-Single Gate, Mud Cross, Double Gate and Annular Preventer. Lube all Ring Grooves and prep for Transport. NU tree,test tubing hanger @ 5,000 psi f/30 min,test tree @ 5,000 psi f/30 min. Continue cleaning pits, mud lines, etc. Prep mud pumps for stack out, start rigging down top drive. Release Doyon Rig from SCU 41A-04 @ 06:00, 5-29-13. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 6/4/13 Daily Operations: 05/29/2013-Wednesday RD Doyon Arctic Fox& prep for demobe from field. Remove Traction Motor from Top Drive for service. Pressure wash under Pipe Skate. Continue to clean Mud Pits. Remove Liners,Valves &Seats from Mud Pumps. Clean and prep BOPs for transport. Remove Extend link Arm from Top Drive and load TD in Cradle. Weld pad-eyes onto Rotary Table and prep for removal. Clean Cellar area. Load &transport misc equipment to Peak Yard. Continue cleaning wind walls around rig floor, Finish rigging down mud pumps. Drain boilers and start cleaning boilers. Injected 305 bbls drilling waste, and 154 bbls water. 05/30/2013-Thursday Continue to clean Rig and prep loads for transport out of field. RD and load out Top Drive. Clean and remove Windwall Panels from pits. Clean and prep Pipe Sheds for Transport. R/D Service Loop to TD. L/D lower section of Torque Tube. Open and inspect#1 Boiler, (found fire damage to Shell on rear end of Boiler). Pump out Hot Well Tank. Clean and load out Top Drive Power Pack& Gas Buster. Clean and inspect BOPs. Load BOPs and transport to Anchorage for inspection. Pressure wash Auger and Rock Washer. Pressure wash Drawworks and Cellar area. Transport all Doyon and Hilcorp Drilling equipment staged on North end of field to Tyler Pad for load out. Prepare and deliver Well File to Production for records, scope derrick down, unstring blocks, lay derrick down, continue to clean rig modules. Note: All components are inspected by Tool Pusher prior to leaving location to verify everything has been satisfactorily cleaned and is free of any contaminates that may have been generated from this Drilling Program. 05/31/2013- Friday Prep derrick for removal. Continue cleaning on Pipe Sheds. Move (3) Pipe Sheds off location and transport to Peak Yard. Crane Derrick off Sub-structure and set on Sills. Split Derrick and stage on containment for steam cleaning. Continue to prep and secure loads for transport to Peak Yard. Steam clean derrick,start steam cleaning sub base, rig floor and off driller side wind walls, prep dog house for removal. 06/01/2013 -Saturday Finish cleaning Derrick sections with Steam On Wheels crew. Remove Dog House from Water Tank stand. Clean out Water Tank with Vac Truck. Crane Drawworks skid off of sub and onto containment for steam cleaning. Transport both Derrick sections to Epperhiermer Painting. Set Pipe Skate in containment for Steam cleaning. Crane Sub off of Well and onto Containment. Pressure wash Pony subs and load on trailer w/Auger. Move both Pit modules off of Matts and prep to remove shakers, remove shakers, pressure wash shakers, pit modules, and wind walls, load wind walls in tubs for transportation. 06/02/2013-Sunday Prep loads for transport out of field. Pressure wash outside of Mud Tanks. Clean solids from suction lines. Vac residual mud from tank bottoms. Pressure wash Shakers and Shaker supports. Load Wind Walls into Pipe Bunks and secure same. Finish cleaning Sub and then move off location. Pressure wash Pump Rooms. Continue pressure washing pump houses, Gen set, motor room and boiler house, clean liner around well, pick up liner and felt and dispose it. Continue loading misc, in pipe tubs. All loads inspected by Tool Pushers to verify clean of all contaminates. Hilcorp Alaska, LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SCU 41A-04 50-133-10109-02 213-028 4/30/13 6/4/13 Daily Operations: 06/03/2013- Monday Prep loads for transport out of field. Wash and dispose of Liner and Felt underlayment. Pump out Well Cellar&shovel out all debris to cement bottom. Load out final equipment from Well site and perform final clean-up. Production on location atempting to install Flowlines. Take Flowline to Fab shop to re-fit. Move in and rig up Pollard Wireline Service. Rig up Lubricator and make up 1.25 Tool String. RIH and pull Prong from RCP Plug in X-Nipple @ 10,255' (10,295' WL depth). POOH and Re-tool. RIH with GS and pull Plug from X-Nipple @ 10,255' (tagged @ 10,295'WL measurements). Rig down PWLS and secure Well. Palletize materials around shop and prep shop to be scoped down. Production bringing SRU 24-15 on line. Currently producing 700 bpd with 75/25 cut (Water/Oil). 06/04/2013-Tuesday Prep Doyon Shop and equipment for demobe from field. Load out Shop and miscellaneous equipment and then transport to Peak yard. Production connected Flowline and Gas supply line to 41A-04 and tested same. Started bringing Well on line @ 17:00. 41A-04 375 bpd, 7%oil 24-15 1,600 bpd, 20%oil & lmmsfd Gas. Final Report for SCU 41A-04. 1 r a } p re c E 9 7 co M f O ✓ 0 3 z >'' o y Dm o 'm a o ^' e. A P. 2 _ mm mm^1 0. O E— W 2,71 WA'V 2 1-qq 2 N W ;m.01 y O O 1 .1 NNNNpAA2:2 S VISa V t O O 7`.N N 7 O W W W W pp 0 0 0 N M N 0 0 7 _ >V1uNNNNNNt�I8881+)171+l101001t 6t9 8 v V 'I O C E". 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E a ;. E F- ay d J" 000 « d p O VV 080888g$g8888888888 (� « d V 1;1;u. ��W _OpOp p 7 _O 1p 1pQ_ a aa 11pp•e N e. d i0aa.��. • 3.E vi J,__.0' t_m0 W y7U �`OTNN10110 Q$$ v�toO C'1 W 1n�AV00 • a`w a — o a . D —W c N w mmw gg a 0028280281'8 0 ¢H in3333ingUOw NLLw i Landon Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8339 r i1,ali ka,TLC Fax: 907 777-8510 ri " ° t>' rW.. E-mail: lellison @hilcorp.com o 06/20/2013 To: Alaska Oil & Gas Conservation Commission / - Q 27 Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 G' 7 Anchorage, AK 99501 DATA TRANSMITTAL e,t �- SRU 41A-04 (�//? /It 4,77 Prints L/ �� � 7 Multi Prop Res Comp Neut Por Comp Bulk Density Sin MD/TVD Multi Prop Res Comp Neut Por Comp Bulk Density tin MD/TVD 7. / (3 CD: MWD/LWD log data Please include current contact information if different from above. Please acknowledg recei t by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: / Da e: Landon Ellison Hilcorp Alaska, LLC GeoTech II 3800 Centerpoint Drive, Suite 100 Anchorage,AK 99503 Tele: 907 777-8339 T iksurp:ti ii ka,1.1d: Fax: 907 777-8510 E-mail: lellison @hilcorp.com % • DATE 06/20/2013 ( r To: Alaska Oil & Gas Conservation Commission Makana Bender 1 3 i 227 Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL 01 S2 SCU 41A-04 e- 1 t -4c . c.14) Prints: �4/s Final Well report / • 2"/100' Formation Log(MD/TVD) /,S [ �� `��� 5"/100' Formation Log(MD) 7 2"/100' Drilling Dynamics Log(MD/TVD) p� 2"/100' LWD Combo Log(MD/TVD) 2"/100' Gas Ratio Log(MD/TVD) Final Well Data: CD (please see cd) Please include current contact information if different from above. Please acknowledg ce'pt by signinc and returning one copy of this transmittal or FAX to 907 777.8510 Received By• Date: • I%% s9 THE STATE Oil an s Gas � ofl L SKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue 94'ALAS/ P Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 _ 0 Re: Swanson River Field, Hemlock Oil Pools, SCU 41A-04 Sundry Number: 313-259 Dear Mr. Keller: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. F erster Chair DATED this ,-)/111A-- DATED of May, 2013. Encl. RECEIVED • STATE OF ALASKA MAY 2 3 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations ❑ Perforate 0 • Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well 0 Stimulate ❑ Alter Casing❑ Other.Complete ' 0 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development Q 213-028 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Suite 100,Anchorage,AK,99503 50-133-10109-02-00 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 123A SCU 41A-04 Will planned perforations require a spacing exception? Yes ❑ No 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997 • Swanson River Field/Hemlock Oil Pool . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 10,807' 10,758' 10,777' 10,728' None None Casing Length Size MD TVD Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3000 13-3/8" 3000 3000 2730 1130 Intermediate 9,591' 7" 9,591' 9,591' 8160 7030 Production Liner 1,407 4-1/2" 10,790' 10,740' 8430 7500 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A N/A N/A N/A Packers and SSSV Type: None Packers and SSSV MD(ft)and TVD(ft): None 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development el Service ❑ 14.Estimated Date for 5/23/2013 15.Well Status after proposed work: Commencing Operations: Oil 12 Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Email Printed Name Luke Keller Title Drilling Engineer / Signature / zz Phone (907)777-8395 Date ••5f26/201 A• .5/23 20/3 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3( - 2.5 vl n Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS MAY 2 8 20M Spacing Exception Required? Yes ❑ No Ef Subsequent Form Required: JO — ¢0. �� // APPROVED BY Approved by(,/ / ✓i1ti.._ COMMISSIONER THE COMMISSION Date: s 2,q_ 1..� 112 Submit Form ?k Form 10-403(Re ised 10/2012) /Apps°RtG t onths from the d f a al. Attachments in Duplicate 4. / Hilcorp Luke Keller Hilcorp Alaska, LLC Energy Company Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8385 5/23/2013 Email Ikeller @hilcorp.com RECCommissioner EIVE D Alaska Oil & Gas Conservation Commission MAY 2 3 2013 333 W. 7th Avenue Anchorage, Alaska 99501 AOGCC Re: Soldotna Creek Unit 41A-04(Redrill of SCU 42-04). Dear Commissioner, Enclosed for review and approval is the 10-403 Sundry for the completion of SCU 41A-04. Drilling operations have been completed. A 6" production hole section was drilled from 9,591' MD to 10,807' MD. A 4-1/2" production liner has successfully been run/cemented/tested from 9,383' MD to 10,790' MD as approved in PTD#213-028. Well bore clean out operations are currently underway(5-23-2013). The purpose of this sundry is to notify the AOGCC of our intent to complete the well using the Doyon Arctic Fox instead of the Swanson River workover rig (as briefly mentioned in the APD). Details of the completion are specified on attached completion procedure. Also attached is the . planned wellbore schematic. If you have any questions, please don't hesitate to contact the Operations Engineer, Chad Helgeson at Y Yq p p 9 9 777-8405, or myself at 777-8395. Sincerely, ILf Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 Well Prognosis Well: SCU 41A-04 Hilcora Alaska,LLC Date:5/23/13 Well Name: SCU 41A-04 API Number: 50-133-10109-02-00 Current Status: Production Liner Run, Leg: N/A cmt'd,and tested Current Depth(PBTD) 10,777' Rig: Doyon Rig 1 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz Permit to Drill Number: 213-028 First Call Engineer: Chad Helgeson (907)777-8405 (0) Second Call Engineer: Luke Keller (907)777-8395 (0) AFE Number: 1310631 Brief Well Summary SCU 41A-04 is a sidetrack of the parent wellbore,SCU 42-04. Drilling operations have been completed. A 6" production hole section was drilled from 9,591' MD to 10,807' MD. A 4-1/2" production liner has successfully been run/cemented/tested from 9,383' MD to 10,790' MD. Well bore clean out operations are currently underway(5-20-2013). The following operations will be done with the Doyon Arctic Fox. There is no change to the BOP configuration and all MASP+Reservoir pressure calculations submitted to the AOGCC in the 10-401 PTD are still valid. Brief Procedure: 1. Run CBL log on 4-1/2" production liner via e-line. 2. Run RST cased hole via e-line. 3. Test VBRs and annular on 2-7/8"test joint to 250/4000 psi (annular to 250/2500 psi). Hold tests for 5 min. 4. PU TCP completion a. Ensure a good strap/tally on all pipe and TCP equipment RIH. b. Lay out all guns in order from the bottom to the top. 5. Run TCP completion, 2-3/4" TCP guns (192ft total perfs (proposed), 354ft overall length), Firing head, 35 joints of 2-3/8" tubing, below packer vent, (fill tubing as RIH) 7" champ packer, Annular pressure XO, Big John Jars, 2ea joints of 2-7/8"workstring, RA marker sub,and 2-7/8" workstring to surface. a. RIH with annular pressure crossover closed b. Fill workstring to desired underbalanced pressure as RIH, (2,520 psi=5,770 ft of 6%brine in tubing) 6. Once close to depth, RU E-line to correlate guns on depth with gamma ray logs and RA sub. 7. RD E-line and reposition guns 8. Set Halliburton champ packer,Shoot fluid level with a sonic depth recorder on tubing 9. RU surface equipment(kelly valve, pump-in sub, pressure gauge and shot recorder) 10. Close Annular and pressure up on the annulus to fire guns and open vent. 11. Release pressure from annulus and monitor well. a. After 30 minutes shoot fluid level on well (if fluid level changed from prior to firing guns, wait 15 minutes and shoot FL again.) b. If fluid level is not rising.Strip through annular with work string to open the by-pass on the champ packer. Pressure will drop in annulus when bypass opens. c. Monitor fluid level and pressure for another 30 minutes,ensure fluid level is stagnant. Continue to monitor until fluid in tubing and annulus is stable. 14 Well Prognosis • Well: SCU 41A-04 Hilcorp Alaska,LLC Date:5/23/13 i. if well is flowing and well needs to be killed, MU necessary KW fluid. ii. Reverse out to fill tubing and kill well. 12. After ensuring no flow,TOH, laydown 2-7/8"workstring and necessary 2-3/8"tubing and TCP assembly a. Ensure all guns fired 13. RIH w/completion on new 2-7/8"8rd EUE tubing and 2-3/8"tubing(hydraulic packer and gas lift valves),set packer at approx.9,300ft. Ensure that RHCP plug is set in the X Nipple below the packer before running in the hole (run GL Mandrels with live valves. a. Land tubing in hanger. Close the lockdown pins. b. Set packer ball by dropping prong. c. Pressure up tubing to 3,000 psi to set packer(chart for 30 min). If packer doesn't set, pressure up until the packer sets. Once packer is set,test casing pressure to 2,100 psi (chart 30 min). 14. Set BPV, ND BOP, NU Tree test(5,000 psi). 15. RDMO Doyon rig 16. Turn well over to production 17. N/U piping and flowlines. 18. Gas lift well, unloading fluid from well,SI well leaving gas lift pressure on well. 19. R/U slickline, PT lubricator to 250/3000 psi. 20. RIH and pull RHCP prong and plug. 21. R/D slickline. 22. Start production. 23. Notify AOGCC of SSV testing within 5 days of bringing well online. 24. Notify BLM of start of production within 5 days of production. Attachments: 1. Proposed Wellbore Schematic , . 14 Planned Swanson River Unit Well SCU 41A-04 Planned WBD na,,,ri,,4.t,...ka.l.i.t: Casing & Tubing Drift 1 >� Size Type Wt Grade Conn. ID Top Btm 22" , ` Conductor- ;' 22" Driven to Set - - - - Surf 22' Depth y 13-3/8" Surf.Csg 54.5 - - 12.459" Surf 3,000' n, 7" Intermediate 29 N-80 BTC 6.05 Surface 304' 13-3/8" L 7" Intermediate 26 N-80 BTC 6.151 304' 1,235' ++ 7" Intermediate 23 N-80 BTC 6.25 1,235' 4,229' 7" Intermediate 26 N-80 BTC 6.151 4,229' 4,527' !, 7" Intermediate 29 N-80 LTC 6.05 4,527' 6,489' a 7" Intermediate 26 P-110 LTC 6.151 6,489' 9,346' g.' 2 M 1', t1' 7" Intermediate 29 P-110 LTC 6.05 9,344' 9,600' . 4-1/2" Prod Lnr 12.6 L-80 D WC 3.958"3.958" 9,383' 10,950' Tubing `. 2-7/8" Production 6.5 L-80 8RD 2.441 Surf 9,300' 2-3/8" Production 4.6 L-80 8RD 1.995 9,310' 10,255' e Pi 5 ,'1 JEWELRY DETAIL 3 11I `7,' No. Depth ID OD Item . r1 !e Y4 e ' 1 18.7' 2.44" - Tubing Hanger V P. 2 ±4,200' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD .' ik 3 ±7,000' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD 4 ±8,900' 2.44" 4.750" 2-7/8"SF0-1 Mandrel 8RD y is 5 ±9,300' 2.313" 3.5" X-Nipple • E+ 4 Mk;i 1 6 ±9,310' 1.90" XO 2-3/8"x 2-7/8"8RD EUE III ,y. ±10,200' 1.90" 3.750" 2-3/8"GLM 8rd,T-1 Latch Mandrel fi 5/6 7 8 ±10,230' 1.995" Hydraulic Packer■ 7" y� 9 ±10,245' 1.875" 2.5" Y X-Nipple 10 ±10,255' 1.995" WL Entry Guide `;, ' 7 11 10,777' - - HES CIBP 1 s AIL : 8 '' i 1' 9/10 i 1 .-F. 1 +' PROPOSED PERFORATIONS 4r r Zone Top(MD) Btm(MD) Top(TVD) Btm(TVD) Notes • H-6 10,417 10,426 TCP 2-3/4"6spf 60 deg ii I H-7/9 10,442 10,530 TCP 2-3/4"6spf 60 deg 11 H-10 10,553 10,598 TCP 2-3/4"6spf 60 deg 4-1/2" G A• I-7., ,. TD=10,950'/TVD=10,891' PBTD=10,770' Updated by CAH 5/22/2013 • II RECEIVED ? ` STATE OF ALASKA ;V1r,Y 1 6 2°13 • ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS r 2CC 20 MC 25.280 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Change Approved Program El • Suspend❑ Plug Perforations ❑ Perforate ❑ Pull Tubing❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate❑ Alter Casing❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development 213-028 ' 3.Address: Stratigraphic ❑ Service El 6.API Number. 3800 Centerpoint Drive,Suite 100,Anchorage,AK,99503 50-133-10109-02-00 • 7.If perforating: N/A 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? SCU 41A-04 Will planned perforations require a spacing exception? Yes ❑ No ❑ 9.Property Designation(Lease Number): 10.Field/Pool(s): A028997 " Swanson River Field/Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): P gs(me. u'-d): Junk(measured): 10,392 10,370 10,392 10,37k V None None Casing Length Size MD �40 Burst Collapse Structural Conductor 22' 22" 22' 22' Surface 3000 13-3/8" 3000 4 3'10 0 2730 1130 Intermediate 10,168' 7" 10,168' I ' 10 •. 8160 7030 Production 1 Liner ` 1 Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: ` 5" g Grade: Tubing MD(ft): N/A N/A ,.i N/A N/A Packers and SSSV Type: None 11 Packers d SSSV MD(ft)and TVD(ft): None 12.Attachments: Description Summary of Proposal !n► 0 13.W Class after proposed work: Detailed Operations Program ❑ BOP Sket IE x lorato ❑ Stratigraphic❑ Development 0 Service ❑ 14.Estimated Date for 5/ 0/20: / \ 15.Well Sta s after proposed work: Commencing Operations: it El • Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ El WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and corr: t to the best of my knowledge. Contact Email Printed Name Luke Keller Title Drilling Engineer Signature "0" Phone (907)777-8395 Date 5/16/2013 COMMISSION USE ONLY Conditions of approval: Notify Com •-sion so that a representative may witness Sundry Number: �1 Z -(8' Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No [ Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and }/ `29 Form 10-403(Revised 10/2012) ApprOl RliI41jd) r 12 months from the date of approval. Att is Du irate Well Prognosis • Well: SCU 41A-04 Hilcorp Alaska,LU Date:5/16/13 Well Name: SCU 41A-04 API Number: 50-133-10109-02-00 Current Status: Sidetrack In Progress Leg: N/A Current Depth 10,392 Rig: Doyon Rig 1 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Luke Keller Permit to Drill Number: 213-028 First Call Engineer: Luke Keller (907)777-8395 (0) Second Call Engineer: Paul Mazzolini (907) 777-8369 (0) AFE Number: 1310631 Brief Well Summary SCU 41A-04 is a sidetrack of the parent wellbore,SCU 42-04. Drilling operations are in progress, latest depth is 10,392' MD/10,370'ND. The well was originally permitted to a total depth of 10,950' MD/10,891'ND. A subsequent notification was provided from Hilcorp to AOGCC& BLM requesting permission to deepen the well to 11,350' MD/11,266'ND. • Due to ongoing wellbore integrity issues that have required an excessive amount of LCM squeezing, Hilcorp has decided to abandon an attempt at reaching the 11,350' MD target with the current, 6" hole section. Instead, the plan has been modified as follows: Brief Procedure: 1. Drill to 6" hole section TD at 10,830' MD/10,781'ND. • 2. Run and cmt 4-1/2" liner as planned. 3. Test BOPs to pressures specified on APD (test on 2-7/8" and 4"test joints). 4. M/U 3-3/4" drilling assy and TIH. Test casing to 3500 psi/30 min. 5. Drill out from 4-1/2" shoe and to 10,850' MD, conduct FIT to 13.5 ppg EMW. 6. Drill 3-3/4"x 4-1/8" hole from 10,850'to 11,550' MD/ 11,463'ND. ^b ; 7. Run slim hole wireline logs. % � ' 8. Wiper trip. Lc s 9. Run and cmt 2-7/8"Vam STL production liner. 10. Polish PBR, run liner top packer. Test wellbore to 3500 psi/30 min. 11. Displace well to completion fluid. TOH. 12. N/D BOP, N/U dry hole tree. 13. RDMO Doyon Rig#1. Attachments: 1. Planned Wellbore Schematic 2. Planned Drilling BHA 3. 2-7/8"Specification Sheet 4. Revised Cmt calculations 4.5" Production Liner Cement Calculations 7"x 4 DP"Overlap: 200' x 0.021 = 4.3 bbls 7"x 4.5"Liner Overlap: 200' x 0.017 = 3.4 bbls 6"OH x 4-1/2"Liner: (10,830' —9,600')x 0.015 x 2 = 37 bbls Shoe Track: 120' x 0.015 = 1.8 bbl Total Volume(bbls): 4.3 +3.4 +37+ 1.8 = 46.5 bbls Total Volume(ft3): 46.5 bbls x 5.615 ft3/bbl= 261 ft3 Total Volume(sx): 261 ft3 / 1.35 ft3/sk= 193 sx Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 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 D198 Retarder 0.4% BWOC Additives D046 Anti Foam 0.2%BWOC D202 Dispersant 1.5%BWOC D400 Gas Control Agent 0.8%BWOC D154 Extender 8.0 % BWOC D174 Expanding Agent 1.5%BWOC 2-7/8" Production Liner Cement Calculations 4-1/2"x 2-7/8"DP Overlap: 200' x 0.007= 1.4 bbls 4-1/2"x 2-7/8"Liner 200' x 0.007 — 1.4 bbls Overlap: 4-1/8"OH x 2-7/8"Liner: (11,550' — 10,830)x 0.009 x 2 = 13 bbls Shoe Track: 90' x 0.005 = 0.5 bbls Total Volume(bbls): 1.4 + 1.4 + 13 + 0.5 = 16.3 bbls Total Volume(ft3): 16.3 bbls x 5.615 ft3/bbl= 91 ft3 Total Volume(sx): 91 ft3 / 1.35 ft3/sk= 67 sx Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 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 D198 Retarder 0.4%BWOC Additives D046 Anti Foam 0.2% BWOC D202 Dispersant 1.5%BWOC D400 Gas Control Agent 0.8%BWOC D154 Extender 8.0 % BWOC D174 Expanding Agent 1.5%BWOC . Swanson River Unit Well SCU 41A-04 Planned Planned WBD Ililcorp Alaska.LLC C a s i n g & T u b i n g Size Type Wt Grade Conn. Drift Top Btm 22- Li x: Conductor—Driven - - -" 22 to Set Depth Surf 22' 21. 13-3/8" Surf.Csg 55 - - 12.459" Surf 3,000' 14 7" Intermediate 29 N-80 BTC 6.05 Surface 304' 3 7" Intermediate 26 N-80 BTC 6.151 304' 1,235' 13-38" G 7" Intermediate 23 N-80 BTC 6.25 1,235' 4,229' 41 kg 7" Intermediate 26 N-80 BTC 6.151 4,229' 4,527' 7" Intermediate 29 N-80 LTC 6.05 4,527' 6,489' 7" Intermediate 26 P-110 LTC 6.151 6,489' 9,346' ,I 7" Intermediate 29 P-110 LTC 6.05 9,344' 9,600' 4-1/2" Prod Lnr 13 L-80 DWC/C HT 3.958" 9,400' 10,830' 6 a1 2-7/8" Prod Lnr 6.5 L-80 ST-L 2.377" 10,680 11,550' I I< Tubing I itl 3-1/2" Production 9.2 L-80 IBT IBT 2.441 Surf 9,300' 7 I11 i M 8 i 'r I JEWELRY DETAIL No. Depth ID OD Item 9 i 1 20' 2.44" Tubing Hanger 10 2 1,300' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port I I ', 3 2,400' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port '' 4 3,500' 2.44" 4.750" 3-1/2"SFO 1 Mandrel 8RD 12 port 11 ! 5 4,600' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port r 12 C` 6 . 5,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port * 7 6,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 8 6,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 9 7,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port vi 10 9,260' 2.000" 6.5" On/Off Tool w/X Nipple .p 11 9,280' 1.978" 4.140" Arrowset Mechanical Packer t : 12 9,300' - - WL Entry Guide w/X Nipple 4-1/2" t l- C 2 t M . 2-7/8' " -!t# TD=11,550'/TVD=11,463' Updated by LEK 5/16/2013 Schwartz, Guy L (DOA) From: Luke Keller <Ikeller @hilcorp.com> Sent: Friday, May 17, 2013 11:02 AM To: Miller, Justin T; Schwartz, Guy L (DOA) Cc: Rance Pederson - (C); Paul Mazzolini Subject: SCU 41A-04 Change to Procedure '7-i-D Justin/Guy, Please disregard the previous sundry concerning the latest change. We encountered yet another lost returns event and will be completing the well at 10,807' MD. We will not deepen the well further than this. Our forward plan is to run/cmt the 4-1/2" liner as planned. Then continue on with wellbore clean up procedures. After this well,we will release the Doyon Arctic Fox. We will use the Saxon rig# 169 instead to drill the SCU 12B-09. Please call or email if there is any clarification required on this. co/31 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 9 LIr �� g 907-777-8395 '1 313' 5./7.(3 t S Cc t 4-03,--04- P 213010 Regg, James B (DOA) From: Mike Leslie [gleslie @hilcorp.com] Sent: Monday, May 13, 2013 11:12 AM C 13 To: BLM_AK_AKSO_EnergySection_Notifications @blm.gov; Brooks, Phoebe L(DOA); DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Luke Keller; Rance Pederson -(C); Joe Grubb - (C); Jimmy Greco-(C) Subject: SCU 41A-04 Annular Preventer Test Attachments: Annular test, Post Shut-in. .pdf; Notification for use of Blowout Equipment 05-08-13 .docx To All, We tested our Annular Preventer on a 4"Test Joint to 250L/2500H while out of the hole this morning for a BHA change. We also functioned tested the Upper, Lower and Blind Rams. Regards, { Q O a/vl eui,(GJ_ (Nee-c t C red Mike Leslie Drilling Foreman 194 7,e) ' 2S-.Ci �)A u)cc) Hilcorp Alaska gleslie @hilcorp.com Swanson River 907-776-6776 1 --, , ... ,--------- „---- — - --- fp 7":", .---,----' _:_ A000j------, --___-Th___ ' --....„:-. ,- ,c-------. 7----7---- Ailk .. -NN. , ,..----,*Pirkk---,..,-, s. ,4i,v,„ .: 000 -__----_--_ -_- --------f-_-_ ---- .--7----,----- N , „..... . ...„-4.4., .,,,,,N.,. ..vd.0\ ,,, ,,,,,.. opo _ -...-......... .... '=•-.......... ....■, -"W. ............=.............. .=...,... ....,. - 4 W.,,,_, • N%W'' 1'OW \ x /,-;-.;000 ' 'k" "■■•'- \ °"50 ° 2, ,,- ------;,---, , N. ,.?\ 0 / • /'. ' - ' - --- ' 024 ___.---- atit *4 ...'■ % ' ". t5'() N \\% \t‘ Txif.r.:"*"1:::::75b\* 1.4 Ili'll::::1111:01111 cc:20o Himmi!Ili anilliiiiiill111111111:1\\r'''r 'I :: ", / / / /, °4°'.,.' 0 -------- - ,_-‘174:**ft. %/C) %ft is°1 :•°‘' N\, '. O g wiltill / 0 0 up, , ,,,,? , 141447 I/ \• \lettripla1311.1111 "stiatittitillan a ollon 1 , iont4ETER IIIIIIN pm INUMNIIIIIII[1111" tink., 0 A tot PUT 1.1 ,' stISS,us.. \\OCA,110:1(s , ,,41•K„k__---------/ ''IA* _,Ison 818 0 , ' 111111koi , Allti WA .11ark\ ‘ ----- ----mli4 ' a'(----. /"I'lliP11111841114118)114 I 111 \ „tA Pmam----- -ikrfer 61,,,I- IA / I widitiriiip g 1 47, WO itta%lt ' St/ II, 8 It it \ \* \ \‘'. 00 •..,,kk-‘.4.--......,==.... ..0‘ ./, ii ifi /1# e` ...............„ 000 „......,......:„...„.......--=....___---_—,„,_,,,,, I' ,_.._ _......, .......„, ,,...,.. .._, ...„.._,...„.., ......=, 00...0„, ,...- , ...„,, ...,,........_ __„.„....,.....--0,--,----........„-0 4, .,......„...._,....„„,,,,,,,....,.. ..■.....■".. .1:: ,,...,, ft s"........•■• „„,_.____ ......•=.■-••• ■•••• ■. „, ".--..,....,.......„.........„...:1,...„...„„ •'•-•"2" . ....j==== rt:,,,. ..". ,...--- 02 -------..- -- __----- -- ----- ------___ c'Cc.4(a--(2 pit) Zt3OZ$o Regg, James B (DOA) From: Mike Leslie [gleslie @hilcorp.com] Sent: Wednesday, May08, 2013 10:45 PM 7 SLZ�1 To: BLM_AK_AKSO_EnergySection_Notifications @blm.gov; Brooks, Phoebe L (DOA); DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Luke Keller; Joe Grubb- (C); Rance Pederson -(C); Jimmy Greco-(C) Subject: Notification for use of Blowout Equipment 05-08-13 .docx Attachments: Notification for use of Blowout Equipment 05-08-13 .docx 1 Notification for use of Blowout Equipment Date: 05-08-13 Shut In Time: 13:53 Location: Swanson River,SCU 41A-04 PTD#: 213-028 Rig: Doyon Rig#1, Arctic Fox Drilling Foremen: Mike Leslie &Joe Grubb, Hilcorp Alaska BOP used: 11" 5M, Annular Preventer Reason: Gas entrained in mud registering @ Mud Pit LEL gas detector. Casing Window depth: 9605 Summary:We had drilled to a depth of 9705,while utilizing Gyro-data tools on E-line for steering.The pumps had been off while rigging down E-Line and Gyro tools. We had gone back to bottom and finished drilling the remainder of the last stand to a depth of 9720. We began getting a gas increase prior to Bottoms Up, so picked up off bottom.As the gas units increased, we began getting a gas reading of 10 ppm at the Shakers.The pumps were shut down and the Annular Preventer closed, so returns could be routed through the Gas Buster.There was no flow down the Flow Line when the pumps were shut down, but gas was percolating in the Well Bore. The final reading from the Mud Logger was 2572 units of Gas.There was no shut in pressure on the Dp., but the Casing gauge registered 110 psi.The Pit Watcher reported a 14.4 bbl gain to the mud system while the pumps were off during R/D of Pollard E-Line and Gyro. The Influx was circulated from the Well @ 3 bpm,while holding 400 psi of back pressure with the Choke to prevent additional influx.The MW was increased from 10.5 ppg to 10.8 ppg. Once 10.7+ MW returned to surface,the well was opened and monitored.The Well was static, so drilling resumed. Back ground gas now consistent @ 15 units. Last BOP test date: 05-04-13 The Annular Preventer will be re-tested on the next trip out of the hole, prior to re-entry. Current Depth: 9838' @ 22:25. Mike Leslie, Drilling Foreman Hilcorp Alaska gleslie@hilcorp.com, 907-776-6776 Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday, May 08, 2013 2:53 PM To: 'Miller,Justin'; Luke Keller; 'Davies, Stephen F(DOA) (steve.davies @alaska.gov)' Cc: Paul Mazzolini; Kate Kaufman; Sharon Yarawsky(syarawsk @blm.gov); Mike Leslie;Joe Grubb - (C) Subject: RE:SCU 41A-04 (PTD#:213-028) Change to Approved Procedure Luke, AOGCC has no issues either(<500 ft from permitted TD per 20 AAC 25.015 (a)(1)) ... Steve is out till Friday so he can take a look also at any spacing issues. As far as name change that is a bit more complicated but I agree with Justin that maybe wait to see if the lower section is actually productive before diving into the name change quagmire. Regards, L`", Guy Schwartz ' Senior Petroleum Engineer � y--/� - 6� AOGCC 907-444-3433 cell 907-793-1226 office /1 Ape L 1 From: Miller, Justin [mailto tmillercnblm�ov] ' �J Sent: Wednesday, May 08, 2013 2:09 PM To: Luke Keller Cc: Schwartz, Guy L(DOA); Paul Mazzolini; Kate Kaufman; Sharon Yarawsky(syarawsk(crblm.gov); Mike Leslie; Joe Grubb - (C) Subject: Re: SCU 41A-04 (PTD#: 213-028) Change to Approved Procedure Luke, This will need to come in as a Change of Plans Sundry Notice, which in our WIS system should come up as a 'Change to Original APD'type. We shouldn't have a problem approving this change in time for the weekend. As for the change to the well name, I'd say let's approach that after you've gotten to the location you want to be at and decide it's productive. You can change the well name easily by filing a separate sundry notice. Sincerely, JUSTIN T. MILLER PETROLEUM ENGINEER BLM-ALASKA STATE OFFICE - BRANCH OF ENERGY AND MINERALS OFFICE: (907) 271-3406; BLACKBERRY: (907) 717-4039; FAX: (907) 271-3933 1 JTMILLER(a BLM.GOV SPE A �G a. MEMBER On Wed, May 8, 2013 at 1:56 PM, Luke Keller<lkeller(hilcon, (',„ >wrote: Guy/Justin, There has been some new information uncovered which encourages us to drill approx 400' deeper(MD) on the SCU 41 A-04. Hilcorp Alaska, LLC respectfully requests AOGCC and BLM approval to extend TD on the SRU 41A-04 to 11,350' MD/ 11,266' TVD. Permitted depth is 10,950' MD / 10,891'. This change has been made to take the opportunity to look at the H13 & H15 sands that may potentially contain hydrocarbons in commercial quantity. The new BHL resides in the 4/2 quarter section of section 4, which will also prompt the need for a name change should the well be successfully drilled and completed in this new BHL. The new well name will be SCU 42A- 04. Please note that all attached documents reference this new well name. Attached are the following revised documents: 1. Wellbore diagram 2. Cement calculations 3. Casing design 4. MASP calculations 5. Geo-prog 6. Directional Plan 7. Structure map 2 Please let me know how each of you would like for us to proceed in regaras to formal approvals or sundries. Regarding operations at the rig site—we just began drilling the 6"hole section at 9628' MD this morning. We estimate reaching the permitted depth of 10,950' MD this Saturday/Sunday. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 3 Modifications to SRU 41A-04 (PTD#: 213-028) Hilcorp Alaska, LLC respectfully requests AOGCC and BIM approval to extend TD on the SRU 41A-04 to 11,350' MD/11,266'ND. Permitted depth is 10,950'MD/10,891'. This change has been made to take the opportunity to look at the H13& H15 sands that may potentially contain hydrocarbons in commercial quantity. The new BHL resides in the 4/2 quarter section of section 4,which will also prompt the need for a name change should the well reach and be completed at its intended location. The new well name will be SCU 42A-04. Attached are the following revised documents: 1. Wellbore diagram 2. Cement calculations 3. Casing design 4. MASP calculations 5. Geo-prog 6. Directional Plan 7. Structure map Swanson River Unit • Well SCU 42A-04 Planned Planned WBD Ilikorp Alo,kn.LLC Casing & Tubing I 1 Size Type Wt Grade Conn. Drift Top Btm 22" �` Conductor- 's' r° 22" Driven to Set - - - - Surf 22' 21 bl Depth '' 13-3/8" Surf.Csg 54.5 - - 12.459" Surf 3,000' 7" Intermediate 29 N-80 BTC 6.05 Surface 304' 31 13-3/8" L 7" Intermediate 26 N-80 BTC 6.151 304' 1,235' 7" Intermediate 23 N-80 BTC 6.25 1,235' 4,229' 4 i- 0 7" Intermediate 26 N-80 BTC 6.151 4,229' 4,527' I 7" Intermediate 29 N-80 LTC 6.05 4,527' 6,489' 7" Intermediate 26 P-110 LTC 6.151 6,489' 9,346' Si 7" Intermediate 29 P-110 LTC 6.05 9,344' 9,600' D W C/C 4-1/2" Prod Lnr 12.6 L-80 RT 3.958" 9,400' 11,350' 61 LI ' Tubing 3-1/2" Production I 9.2 L-80 IBT IBT 2.441 Surf 9,300' 11 111 JEWELRY DETAIL No. Depth ID OD Item sr ii] ;1 1 20' 2.44" - Tubing Hanger 2 1,300' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port `, 9 1, 3 2,400' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 4 3,500' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 10 5 4,600' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port '! 6 5,200' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 11 MN ;N 7 6,200' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 7„ 2,1! 12 8 6,900' 2.44" 4.750" 3-1/2"SF0-1 Mandrel 8RD 12 port 9 7,900' 2.44" 4.750" 3-1/2"SFO-1 Mandrel 8RD 12 port 10 9,260' 2.000" 6.5" On/Off Tool w/X Nipple I•` 11 9,280' 1.978" 4.140" Arrowset Mechanical Packer A 1;1 12 9,300' - WL Entry Guide w/X Nipple � � t, y, ty i ,i V y S 7 N� , N r I i:. yrTl 4-1 ! /2 " ' TD=11,350'/'1'VD=11,266' Updated by LEK 5/7/2013 1.0 Cement 4.5" Production Liner 1.1 Hold a pre job safety meeting over the upcoming cmt operations. 1.2 Attempt to rotate&reciprocate the liner during cmt operations. 1.3 Pump 5 bbls 12 ppg MUDPUSH II spacer. 1.4 Test surface cmt lines to 4500 psi. 1.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 1.6 Mix and pump 15.3 ppg class"G"cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100%OH excess. Cement Calculations 7"x 4 DP"Overlap: 200' x 0.021 = 4.3 bbls 7"x 4.5"Liner Overlap: 200' x 0.017= 3.4 bbls 6"OH x 4-1/2"Liner: (11,350'—9,600') x 0.015 x 2= 52.5 bbls Shoe Track: 120' x 0.015= 1.8 bbI Total Volume(bbls): 4.3+3.4+52.5+ 1.8= 62 bbls . Total Volume(ft3): 62 bbls x 5.615 ft3/bbl= 348 ft3 Total Volume(sx): 348 ft3 / 1.35 ft3/sk= 257 sx Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 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 D198 Retarder 0.4%BWOC Additives D046 Anti Foam 0.2%BWOC D202 Dispersant 1.5%BWOC D400 Gas Control Agent 0.8%BWOC D154 Extender 8.0 %BWOC D174 Expanding Agent 1.5%BWOC 1.7 Drop DP dart and displace with 10.5 ppg drilling fluid. 1.8 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. 1.9 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. 1.10 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. 1.11 Slack off total liner weight plus 20k to confirm hanger set. 1.12 Do not overdisplace by more than %2 shoe track. Shoe track volume is 1.8 bbls. 1.13 Pressure up to 4200 psi to release the running tool(HRD-E)from the liner. j _ o (C) Me- mC- I)liN- N- 0 O1 COM � COCAtO � N111 CO r' NM Cl* LO CD N- 000M 0) 000 00C 000 e- e- e- .-- e- .- e- e- e- I i Q1*I 000 O 00'000 MMM MMM`MMM 2tl -2..,� + + + + + + + + + co. N M (O 0) Co,in M a- 0 a- h M a- CD e-1 N- U) to V 4 0 'ct e- 0) u) I- N,1, e- n 0 C � -I 0. °O O O O O ,0) 0 O -1 m 0 1 G) CO (O CO (O O U) U) 111 U) N Y n. C.) 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J ozi D F- F- O J W O Q Q - O CV ri ocn co U co Q CO 1 I v Calculation & Casing Design Factors Kenai Peninsula,AK DATE: 5/7/2013 WELL: SCU 42A-04(Sidetrack of SCU 42-04) FIELD: Swanson River DESIGN BY:Luke Keller Design Criteria: Hole Size: 6" Mud Density: 10.5 ppg MASP(Drilling): 1357 psi(see attached MASP determination &calculation) MASP(Prod): 3023 psi(see attached MASP determination &calculation) Collapse pressure for section 1 &2 is calculated; Overpressured Tyonek water Collapse Calculation: flow external stress(0.604 psi/ft)and the casing evacuated for the internal stress. Casing Section Calculation/Specification 1 2 3 4 Casing OD 7" 4-1/2" Top(MD) 0 9,400 Top(TVD) 0 9,400 Bottom (MD) 9,600 11,350 Bottom(ND) 9,600 11,266 Length 9,600 1,950 Weight(p_pf)_ 29 12.6 Grade P-110 L-80 Connection LTC DWC/C HT Weight w/o Bouyancy Factor(lbs) 278,400 24,570 Tension at Top of Section (lbs) 278,400 24,570 Min strength Tension (1000 Ibs) 797 288 Worst Case Safety Factor(Tension) 2.86 11.72 Collapse Pressure at bottom (Psi) 5,798 6,805 Collapse Resistance w/o tension (Psi) 7030 7,500 Worst Case SafetyFactor(Collapse) 1.21 1.10 MASP(psi) 1,357 1,357 Minimum Yield(psi) 8,160 8,400 Worst case safety factor(Burst) 6.01 6.19 , nMaximum Anticipated Surface Pressure Calculation Hil corp .1jR°° °. Soldotna Creek Unit 42A-04 Kenai Peninsula,Alaska MD ND Planned Top: 9,600 9,600 Planned TD: 11,350 11,266 Anticipated Formations and Pressures: Formation TVD Est Pressure Expected Fluid PPG Grad G2 10,166 2000 OIL 3.8 0.197 HKT 10,250 1000 OIL/Gas 1.9 0.098 H3 10,313 1000 OIL/Gas 1.9 0.097 H7 10,430 3000 OIL/Gas 5.5 0.288 H10 10,528 3000 OIL/Gas 5.5 0.285 H12 10,653 3000 Wet 5.4 0.282 I-113 10,711 4150 Oil/Water 7.5 0.387 H15 10,804 4150 Oil/Water 7.4 0.384 WFD 10,924 4150 Oil/Water 7.3 0.380 TD 11,266 4150 7.1 0.368 Offset Information Well Date Hemlock Pressure TVD Grad SRU 331-27 March, 2012 3140 10600 0.296 SRU 13-27 2013 H-13: 4150 psi 11266 0.368 SCU-341-04 1960 11.8- 12.6 ppg MW used Assumptions: 1. Based on offset drilling&well test data, Hemlock pore pressure is anticipated at 4150 psi 2. Fracture gradient at 9,600' is estimated at 0.728 psi/ft based on field test data. Fracture Pressure at 7"window considering a full column of gas from window to surface: For 7" window at 9600'TVD: 9600(ft)x 0.728(psi/ft)= 6989 psi 6,989(psi)- [0.1(psi/ft)*9,600(ft)]= 6029 psi MASP from pore pressure(TD at 11,266'TVD) MASP (2/3 of wellbore evacuated to gas column) 11,266(ft)x 0.368(psi/ft)= 4150 psi 4,150(psi)- [[0.1(psi/ft)*11,266(ft)*2/3]+[0.546(psi/ft)*11,266(ft)*1/3]]= 1348.6 psi MASP from pore pressure(communication with lower tyonek water flow): MASP (wellbore evacuated to formation water gradient): 9600(ft)x 0.573(psi/ft)= 5500 psi 5500(psi)- [0.4316(psi/ft)*9,600(ft)]= 1357 psi MASP from pore pressure(TD at 11,266'): MASP (wellbore evacuated to gas): 11,266(ft)x 0.368(psi/ft)= 4150 psi 4150(psi) - [0.1(psi/ft)*11,266(ft)]= 3023 psi Summary: 1. MASP while drilling 6" production hole is governed by SIBHP-2/3 of wellbore evacuated to gas 2. MASP during production life is governed by SIBHP-gas gradient to surface. 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G 5 E x c z a Q] F - i 7> U y ' v{ O ¢ w x •+ Z R N (i) Hilcorp Alaska, LLC ��� Location: Cook Inlet,Alaska(Kenai Peninsula) Field: Soldotna Creek Unit Slot: SCU 341-04 Well: SCU 42-04 BAKER II Facility: SCU 341-04 Pad Wellbore: SCU 42A-04 HUGHES IIiburp.&ht8ku,LLC Plot reference wellpath is SCU 42A-04 Version#3 — True vertical depths are referenced to Arctic Fox(RTE) Grid System:NAD27/TM Alaska SP,Zone 4(5004).US feel Measured depths are referenced to Arctic Fox(RTE) North Reference:True north Arctic Fox(RTE)to mean sea level:192.3 feet Scale:True distance mean sea level to Mud line(At Slot:SCU 341-04):0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by:jonethoh on 08-May-13 t n1d0 Q$00 s . . -s� Eastiny(ft) Scale -L•' - 7a :A tt9. :,A WA SCU 34 L04 Tie On(Revised wlG '• SCU 42A-04 QQ Tie On(Revised w/Gyro) SCU 332-04 M a4A G2 °) 3.00 1l100h Ens of Build j MN G2 o..M Target SCU41A-04 117 Tat: 18--i..-13 N End of Build O HKT 405 fl1 v H3 H10 Tgt Horizon N SCU41A-04 H10 eb-13 OZ -- SCU 42-04 ,, 4.0 .- N 2 H7 Target H SCU41A-04 H7 Tgt: 18-Feb-13 IOW x H 11 Tgt Horizo SCU41 A-04 1110 Tgt 18-Feb-13 H-13b I 1G0 �_ H12 H-15 ' H-13 -$00.0 U N 1O$00 H-15 yS�' WFT 9 GJ 01 6 WFT 1000 tNQQ ,4111.5 1140 Revised TD 7-May-13• Revised TD 7-May-1 • ' -404 1100 160 r 160 ..r •.. ?.■ ?; Vertica ection( Scab,NC$-)UOW1n Azimuth 159.76'with reference 0.00 N,0.00 E y*v\����j/j�s THE STATE Alaska Oil and Gas 44, �f ALASKA Conservation Commission l *h GOVERNOR SEAN PARNELL 333 West Seventh Avenue P Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Swanson River Field, Hemlock Oil Pool, SCU 41A-04 Hilcorp Alaska, LLC Permit No: 213-028 Surface Location: 961' FNL, 1127' FEL, SEC. 4, T7N, R9W, SM, AK Bottomhole Location: 1291' FNL, 986' FEL, SEC. 4, T7N, R9W, SM, AK Dear Mr. Keller: Enclosed is the approved application for permit to re-drill the above referenced development 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 Commission 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 Commission 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 Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy P oerster �� Chair DATED this / y of March, 2013. HtetiVtU STATE OF ALASKA FEB 2 5 2013 AL A OIL AND GAS CONSERVATION COMMI, N PERMIT TO DRILL i3 qn 20 AAC 25.005 t)r ry O`�^�+'✓ la.Type of Work: 1 b.Proposed Well Class: Development-Oil 0 • Service- Winj ❑ Single Zone �] lc.Specify if well is proposed for: Drill ❑ Lateral El Stratigraphic Test El Development-Gas El Service-Supply ❑ Multiple Zone El Coalbed Gas El Gas Hydrates El Redni 0• Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket al Single le W 11.Well Name and Number: Hilcorp Alaska,LLC Bond No.Z 35-2-161 22 7 � z. -, (5 SCU 41A-04 - 3.Address: 6.Proposed Depth: '' 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 100,Anchorage,AK,99503 MD: 10,950' ' ND: 10,891' ' Swanson River Field/ 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Hemlock Oil Pool Surface: 961'FNL, 1127'FEL,Sec 4,T7N,R9W,SM,AK A028997 - Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1034'FNL,1082'FEL,Sec 4,T7N,R9W,SM,AK N/A April 12th,2013 ' Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1291'FNL,986'FEL,Sec 4,T7N,R9W,SM,AK 2560 acres 6,287' 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 192.3 feet 15.Distance to Nearest Well Open Surface: x-346506.3 • y-2460223.8 - Zone-4 GL Elevation above MSL: 173.7 feet to Same Pool: 1370'(SCU 332-04) 16.Deviated wells: Kickoff depth: 9600 feet 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 21 degrees Downhole: 5500 psig ' 'Surface: 2131 psig 18.Casing Program: _ Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD _ ND (including stage data) 6" 4-1/2" 12.6# L-80 DWC/C HT 1550 9400 9400 10950 10891 50 bbls 15.4 ppg -?0$5xs 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth ND(ft): Plugs(measured): Effect.Depth MD(ft): Effect.Depth ND(ft): Junk(measured): 10,901' 10,379' 10,898' 10,898' 10,379' None Casing Length Size Cement Volume MD ND Conductor/Structural 22 22 - 22 22 Surface 3000 13-3/8 - 3000 3000 Intermediate 10168 7" - 10168 10168 Production Liner 831 3-1/2" - 10898 10379 Perforation Depth MD(ft): Slotted liner f/10,095'to 10,898'MD. Perforation Depth ND(ft): Slotted liner f/10,095'to 10,379'ND 20. Attachments: Property Plat 0 BOP Sketch SI Drilling Program IS Time v.Depth Plot IS Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program SI 20 AAC 25.050 requirements El 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Email Printed Name Luke -Iler Title Drilling Engineer i Signature Phone 907-777-8395 Date 2/19/2013 Commission Use Only Permit to Drill z r?�, c�2, API Number: / -/ /c Permit Approval �I '' +I n See cover letter for other Number: 50 Z•C°r`/Date: (.� requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methan ,gas hydrates,or gas contained in shales: Other: - I-1000 /c C. [36 F 1 y Samples req'd: Yes❑ No ' Mud log req'd:Yes❑ ND[� �-- HZS measures: Yes❑ No Directional svy req'd:Yes Ef NOD Sr,� /2 S. /4hn --f S Spacing exception req'd: Yes❑ No[21 Inclination-only svy req'd:Yes❑ [v]a No f — poa psi- as -, fe.r �_ APPROVED BY Approved by: (:,,,y �[,7(�{/� COMMISSIONER THE COMMISSION Date: �/ /- //�� m&cl 3'f a '�3 Submn Fops at d o��i2� This permit Is valid for 24 months fro he date of approval(20 AAC 25.005(8 � ttachments in Duplicate ll Hilcorp Paul Mazzolini Hilcorp Alaska, LLC En«aCompanr Drilling Manager P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8369 2/19/2013 Email pmazzolini @hilcorp.com Commissioner RECEIVED Alaska Oil &Gas Conservation Commission 333 W. 7th Avenue FEB 2 5 2013 Anchorage, Alaska 99501 n n AOGCC Re: Soldotna Creek Unit 41A-04(Redrill of SCU 42-04). Dear Commissioner, Enclosed for review and approval is the application for the Permit to Drill the Soldotna Creek Unit 41A- 04. SCU 41A-04 is a development oil well planned to be re-drilled in an Southerly direction from the parent wellbore SCU 42-04 utilizing the existing casing program down to 9,600' MD/9,600'ND. SCU 42-04 is currently on production. Daily production is 564 bid water&24 bopd oil. SCU 42-04 has been identified as a candidate for re-drilling. The new wellbore will utilize the existing casing program down to 9600' MD/TVD. The well will be sidetracked at 9600', and target the Hemlock formation to the South. The new well will be called SCU 41A-04. At 9,600' MD the parent wellbore will be sidetracked and a 6"x 1350' hole section drilled to a total depth of 10,950' MD/ 10,891'ND. SCU 41A-04 is a slightly deviated wellbore reaching a maximum inclination of 21 degrees. Drilling operations are expected to commence approximately April 12th, 2013 depending on the progress of ongoing wellwork at Swanson River. Prior to the commencement of drilling operations, the Williams Pulling Unit will be mobilized and conduct wellbore preparation operations for the sidetrack operation. A 10-403 is attached and covers the below operations: 1. Kill well. 2. Removing the existing production tree. 3. Pulling the existing 4-1/2"tubing. 4. Plug and abandon wellbore. 5. Cleaning out wellbore. 6. Set a CIBP @ 9625'&test casing to 2100 psi/30 min. A spacing exception is not required for SCU 41A-04. Only one well is currently completed in the Hemlock formation in the same quarter section. Pursuant to 20 AAC 25.005(c)&(d), the following is included: 1. Plat identifying the property on which the well will be drilled. 2. Diagram&description of blowout prevention equipment. 3. Information on drilling hazards. Hilcorp Alaska, LLC Page 1 of 2 a. The Hemlock is potentially 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 4. Formation integrity test procedure. 5. Planned casing &cement program 6. Diverter system will not be used. An 11" 5M BOP (3 ram &annular)will be used while drilling and completing SCU 41A-04. BOP schematic is attached. 7. Drilling fluid program. 8. Tabulation of predicted depths with equivalent formation pressures. 9. Requirements of 20 AAC 25.025 have been met. a. Blanket bond issued for Swanson River, bond no. 22035257 10. Copy of Drilling Program 11. 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. Drilling waste (cuttings and water based drilling fluids) will be injected into waste disposal well SCU 43-04 WD. 12. 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 777-8369 or Luke Keller at 777- 8395. Sincerely, Paul Mazzolini Drilling Manager Hilcorp Alaska,LLC Page 2 of 2 Hilcorp Alaska, LLC SCU 41A-04 Drilling & Completion Program Swanson River Revision 0 Feb, 2013 Soldotna Cr0eek 4 Unit 41 A- Hilcorp Drilling Procedure Enemgy Company Contents 1.0 Well Summary 2 2.0 Management of Change Information 3 3.0 Tubular Program: 4 4.0 Drill Pipe Information: 4 5.0 Planned Wellbore Schematic 5 6.0 Drilling/Completion Summary 6 7.0 Mandatory Regulatory Compliance/Notifications 7 8.0 R/U and Preparatory Work 10 9.0 BOP N/U and Test 11 10.0 Mud Program and Density Selection Criteria 12 11.0 Whipstock Running Procedure 14 12.0 Whipstock Setting Procedure. 16 13.0 Drill 6"Hole Section 18 14.0 Run 4.5"Production Liner 21 15.0 Cement 4.5"Production Liner 24 16.0 Wellbore Clean Up& Displacement 27 17.0 RDMO 28 18.0 BOP Schematic 29 19.0 Wellhead Schematic 30 20.0 Days vs Depth 31 21.0 Geo-Prog 32 22.0 Anticipated Drilling Hazards 33 23.0 Rig Layout 34 24.0 FIT Procedure 35 25.0 Arctic Fox Choke Manifold Schematic 36 26.0 Casing Design Information 37 27.0 6"Hole Section MASP 38 28.0 Directional Program (P1) 39 29.0 Directional Plan View(Plot) 42 30.0 Plot(NAD 27)(Governmental Sections) 43 31.0 Spider Plot(NAD 83)(Governmental Sections) 44 32.0 Surface Plat(As Built)(NAD 27) 45 33.0 Surface Plat(As Built)(NAD 83) 46 34.0 MW,PP,FG vs Depth 47 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 1.0 Well Summary Well SCU 41A-04 Pad& Old Well Designation Sidetrack of existing well SCU 42-04 ' li Planned Completion Type Gas lift on 3-1/2" IBT production tubing Target Reservoir(s) Hemlock Planned Well TD, MD/TVD 10,950' MD/ 10,891' TVD PBTD, MD/TVD 10,800' MD/ 10,751' TVD Surface Location(Governmental) 961' FNL, 1127' FEL, Sec 4, T7N, R9W, SM, AK Surface Location(NAD 27) X=346506.3, Y=2460223.8 Surface Location(NAD 83) X=1486529.1, Y=2459985 Top of Productive Horizon (Governmental) 1034' FNL, 1082' FEL, Sec 4, T7N, R9W, SM,AK TPH Location(NAD 27) X=346535.42, Y=2460143.02 TPH Location(NAD 83) X= 1486558,Y=2459904 BHL(Governmental) 1291' FNL, 986' FEL, Sec 4, T7N, R9W, SM,AK BHL(NAD 27) X=346628.71, Y=2459884.42 BHL(NAD 83) X= 1486651,Y=2459645 AFE Number Pending AFE Drilling Days 18 AFE Completion Days 6 AFE Drilling Amount Pending AFE Completion Amount Pending Work String 4" 14# S-135 HT-38 (Rental string from Weatherford) RKB—GL 18.6' Ground Elevation 173.7' AMSL(NAVD88) BOP Equipment 11" 5M Schaffer Annular BOP 11" 5M Schaffer Double Ram 11" 5M Schaffer Single Ram Page 2 Revision 0 Feb, 2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 2.0 Management of Change Information Hilcorp Alaska, LLC Hilcorp Changes to Approved Permit to Drill Date: Feb 19. 2012 Subject: Changes to Approved Permit to Drill for SCU 41A-04 File#: SCU 41A-04 Drilling and Completion Program Any modifications to the Drilling&Completion Program will be documented and approved below. Changes to an approved APD will be communicated to the AOGCC &BLM Section Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared: Drilling Engineer Date Page 3 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp COY 3.0 Tubular Program: Hole OD (in) ID (in) Drift Conn Wt Grade Conn Burst Collapse Tension Section (in) OD(in) (#/ft) (psi) (psi) (k-lbs) F 6" 4-1/2" DWCT 3.918 3.833 4.729 12.6 L-80 8430 7500 192 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) 6" 4" 3.34 2-9/16" 4-7/8" 14 S-135 HT-38 18,400 13,800 403k All casing will be new, PSL 1 (100%mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Revision 0 Feb, 2013 11 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hi lcorp Planned Wellbore Schematic ,.Swanson River Unit Well SCU 41A 04 Plarnied Planned WBD 11ab."r 1c..►.,1.1,. C a s i n g & T u b i n g Drift 1 :: !I _ ,-T ��' - Type 'ar�rr Grade Conn, ID Top Btm 1 :_onductor- Z2 DriwntoSet • - - - Surf 22 _r-----0 Depth 13.3.3 Surf.Cs; 54.5 - - 12.459' Surf 3,CCC' 31-8 7' Intermediate 29 N-CC 3T 5.05 Surface 304' ty,}� ., T Intermediate 26 N-9C STC 5.151 304' 1,235' T Intermediate Z3 N-9C 510 6.2.5 1.235' 4,229' t 7 Intermediate 25 N-9C 8T' 6.151 4229' 4,527' r y e T Intermediate 29 N-9C LT 6.05 4,527' 8,469' ..� 7' Intermediate 25 P-110 LT 6.151 5469' 9,346' V , 1. 7' Intermediate 23 P-110 LT 6.05 3.344' 9,600' 1-1/2' Prod Lnr _2: L-90 D HT'` 3:959' ;42: 10.950' .1- 61 CJ Tubing lo 5-1/2" I Production 19 2 11-8016T I 151 I 2.-__ Surf 19,3CC' JEWELRY DETAIL Depth IC OD Rem 3['6 _ 20' 2.44' - Tubing danger 1,500' 2.44 4.750" 3-1/2"'SPO-1 Mandrel BRD 12 port 2.400' 2.44' 4.750" 3-1J2'"SF0-1 Mandrel SRO 12 port � I 4 3,500' 2.44 4.750" 3-1/2'SFO-1 Mandrel BRD 12 port 11 4,600' 2.44 4.750" 3-1/2"5F0-1 Mandrel BRD 12 port 11E1M E a ; • . , 5 5.200' 2.44' 4.750" 3-1/2"SFO-1 Mandrel BRD 12 port 11 ! 7 5,200' 2 44' 4.750" 5-1/2`SFO-1 Mandrel 3RD 1.2 port . ) r I µ/I� q VG 3 6.900' 2.44' 4.150" 5.1/2SFO-1 Mandrel BRD 12 port l....4 3 7,300 2.44 4.750" 3-1/2"SFO-1 Mandrel BRD 12 port 4' S' 1•• 10 9,260' 2.000' 6.5' On/Off Tool w/x Nipple 11 9,260' 1.973 4.140' Mechanical Packer - 12 9,300' - • WL envy Guide wJ X Nipple t • Ir 4: 1 I (, ' r . Li cur 111.110,1110'/TPD=10,891' Page 5 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling& Completion Procedure Hilcorp Energy Company 6.0 Drilling / Completion Summary SCU 41A-04 is a development oil well to be re-drilled in a Southerly direction from the existing well SCU 42-04. The new well will utilize the existing casing program down to 9600' MD. Integrated subsurface and 3-D geological interpretations, in conjunction with previous production data indicates that stranded oil reserves remain in the Hemlock 1-10 benches south of the E fault. High on structure,the H7/8 &H10 are the primary targets. Reserves aren't recoverable in existing wellbores due to lack of take-points or mechanical condition of other existing wellbores in the fault block. The base plan is a slightly deviated wellbore reaching a maximum inclination of 21 deg and a 360' vertical separation at TD. Drilling operations are expected to commence approximately April 12th,2013. The Doyon Arctic Fox will be used to drill and partially complete the wellbore. The Williams rig or AWS #1 will be used to perforate the liner and run the 3-1/2"production tubing. All waste & mud generated while drilling SCU 41A-04 will be injected into waste disposal well SCU 43-04 WD. °l(o A separate sundry notice will be submitted to cover P&A and wellbore preparation for the sidetrack. 3t3�0 General sequence of operations pertaining to this approved drilling procedure: 1. MOB Doyon Arctic Fox to well site 2. N/U & test BOP. 3. Make drift run& P/U 4" DP to 9625'. ��� 4. Run and set Whipstock, displace to 6% KCL/PHPA drilling fluid at 9.5 ppg. Initiate sidetrack. Conduct FIT to 13.5 ppg. 5. Drill 6"production hole section to TD. Make wireline logging passes. Run and cmt 4.5" <<<`'"'1 production liner. s Ca s; 3cao�ps,; rr D 6. TIH w/clean out assy, clean out liner to landing collar. Displace mud to 6%KC1 filtered completion fluid. 7. TOH, LDDP 8. Run 1200' of 3-1/2"production tubing. Land tubing hanger. Set BPV. 9. N/D BOP,N/U temp abandonment cap, RDMO C5i-ni4 ; 3•, •/3 Page 6 Revision 0 Feb,2013 ini Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 7.0 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 Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of SCU 41A-04. Ensure to provide AOGCC & BLM 48 hrs notice prior to testing BOPs. • The initial test of BOP equipment will be to 250/4000 psi & subsequent tests of the BOP equipment will be to 250/4000 psi for 10/10 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" • All Federal regulations within BLM"Onshore Oil and Gas Order#1" • Ensure both AOGCC & BLM approved drilling permits are posted on the rig floor and in Co Man office. Variance Requests: • Onshore Oil and Gas Order No. 1, Section III. D. 3. C. (L /4.. o Hilcorp requests approval to install a 3-1/8" 5M HCR valve on kill line inlllieu of a check valve. Operator suspects a freeze plug risk associated with installation of a check valve in the kill line. o Hilcorp requests approval to utilize flexible choke and kill lines in lieu of hard piping. Page 7 Revision 0 Feb, 2013 11 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Cm,pmy Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) • 11"x 5M Hydril GK Annular BOP • 11"x 5M Hydril Double Ram Initial Test:250/4000 o Blind ram in btm cavity (Annular 2500 psi) 6" • Mud cross • 11"x 5M Hydril Single Ram Subsequent Tests: • 3-1/16"5M Choke Manifold 250/4000 • Standpipe,floor valves,etc (Annular 2500 psi) • Primary closing unit: 1 ea. —Olio, 6 station, 3000 psi, 180-gallon accumulator unit, with a remote control panel in the doghouse. • 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. 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. • 48 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Required BLM Notifications: • 48 hours before spud. Follow up with actual spud date and time. • 48 hours before casing running and cmt operations • 48 hours before BOPE tests • 48 hours before logging, coring, & testing • Any other notifications required in APD. Additional requirements may be stipulated on APD. Page 8 Revision 0 Feb, 2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Ram comp, Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg(a1alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-276-7542/Email:guy.schwartz @alaska.gov Victoria Ferguson/Petroleum Engineer/(0): 907-793-1247/Email:Victoria.ferguson @alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors @ alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.htm1 Notification/Emergency Phone: 907-793-1236(During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) BLM Tom Zelenka/BLM Petroleum Engineer/(0): 907-271-4224 (C): 907-301-8972 Justin Miller/BLM Petroleum Engineer/ (0): 907-271-3406 (C): 907-717-4039 Use the below email address for BOP notifications to the BLM: BLM_AK_AKSO_EnergySection_Notifications@b1m.gov • Page 9 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling& Completion Procedure Hilcorp EliaBY Com Pony 8.0 R/U and Preparatory Work 8.1 A separate sundry will be submitted that will include the following: • MIRU Williams pulling unit. • Set BPV, remove tree. • N/U and test BOP. • Pull existing production tubing. Plug back well with cmt. • Tag &pressure test cmt plug. • Run and set a CIBP at 9625' MD. • RDMO Williams pulling unit. 8.2 Level pad and ensure enough room for layout of rig footprint and R/U. 8.3 Layout Herculite on pad to extend beyond footprint of rig. 8.4 R/U Doyon Arctic Fox, spot service company shacks, spot& R/U company man &toolpusher offices. 8.5 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 8.6 Mix mud for 6" hole section. 8.7 Set test Plug in wellhead prior to N/U conductor riser to ensure nothing can fall into the wellbore if it is accidentally dropped during N/U of BOP. 8.8 Install 4" liners in mud pumps. PZH pumps are rated at 5000 psi and 144 gpm @ 110 spm with the 4" liners. Page 10 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 9.0 BOP N/U and Test 9.1 N/U 11" x 5M Hydril BOP as follows: • BOP configuration from Top down: 11"x 5M Hydril GK annular BOP/11" x 5M Hydril double ram/11"x 5M mud cross/Hydril single ram. • Double ram should be dressed with 2-7/8" x 5" VBR in top cavity, blind ram in btm cavity. • Single ram should be dressed with 4" fixed ram. V • N/U bell nipple, install flowline. 9.2 Run BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/4000 psi for 10/10 min. Test annular to 250/2500 psi for 10/10 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 9.3 R/D BOP test assy. 9.4 Continue mixing mud for 6" hole section. 9.5 Set wearbushing in wellhead. Ensure ID of wearbushing> 6". Page 11 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy ennivmy 10.0 Mud Program and Density Selection Criteria 10.1 6" Production 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. MD Totco PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5ppg 6%KCI/PHPA fresh water based drilling fluid. Properties: Depths Density Viscosity Plastic Viscosity Yield Point HTHP FL pH 9600'-10,950 9.5 60- 100 15-30 20-30 <9 8.5-9.5 System Formulation: 6% KCI/ PHPA Product Concentration Water 0.905 bbl KCI 22 ppb Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.1 ppb (as required 18+YP) DEXTRID LT 1-2 ppb EZ MUD DP 0.5 ppb (initial.15 ppb) ALDACIDE G 0.1 ppb BAROID 41 208 ppb (as needed to desired MW) 10.2 Program mud weights are generated by reviewing data from producing & shut in offset wells, . estimated BHP's from formations capable of producing fluids or gas and formations which could require mud weights for hole stabilization. 10.3 A guiding philosophy will be that it is less risky to weight up a lower weight mud than be overbalanced and have the challenge to mitigate lost circulation while drilling ahead. 10.4 9.5 ppg was chosen as the starting MW for SCU 41A-04 to stay as close as possible to formation pressure (which is expected to be 5.4 - 5.5 ppg) but still allow for adequate suspension of cuttings and LCM. Wellbore instability is not perceived to be an issue at 9.5 ppg. 10.5 The only formation that exceeds a 9.5 ppg gradient would be the lower Tyonek water sands. These formations are expected to occur from 8700' to 9,000' TVD, so it is not expected • Page 12 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Snow Company that we will have communication with these formations with 7" window at 9,600' TVD. The ✓ lower Tyonek water flow has been observed with gradients as high as 13.1 ppg EMW. 10.6 Differential sticking of the drill string and the production casing significantly increases with increasing mud weights. The differential pressure across the H10 interval (10,528' TVD) with a 9.5 ppg MW is 2209 psi however increasing the mud weight to 12.8 ppg would increase the differential pressure to 4058 psi, an increase of greater than 80%. Page 13 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 11.0 Whipstock Running Procedure 11.1 M/U window milling assembly and TIH w/4" DP off pipe rack. • Use a 6"taper mill (or 6" mill tooth bit) and a 6" string mill above to ensure CIBP & Whipstock assy will pass freely. • Ensure BHA components have been inspected previously. • Caliper and drift all BHA components before running them in the hole. • Drift DP prior to RIH. • Lightly wash and ream any tight spots noted. 11.2 TIH to CIBP(9625' MD). Keep up with the # of joints picked up so we know where we are. 11.3 CBU & circ at least(1) hi-vis sweep to remove any debris created by the clean out run. Anything left in the wellbore could affect the setting of the Whipstock. 3000 3•!2-•13 11.4 Pressure test casing to 21.00-psf'/30 min. Chart record casing test& keep track of the amount of fluid pumped. Stage up to 2-1-06-psi in 500 psi increments. 306L> 11.5 TOH. 11.6 Make up mills on a joint of HWDP. 11.7 RIH& set in slips. 11.8 Make up float sub, install float. 11.9 Make up MWD &UBHO sub. 11.10 Orient Gyro MWD & UBHO to starter mill. 11.11 RIH& test Gyro MWD. Ensure telemetry information functioning correctly. 11.12 Back out top drive and pull out of hole. 11.13 Leave assembly hanging in the elevators, and stand back on floor. 11.14 Bring Whipstock to rig floor on the pipe skate. Do not slam into bottom of Whipstock with pipe skate. 11.15 Pick up Whipstock per Baker rep using the Baker Whipstock handling system using air hoist. Allow assy to hang while Baker Rep inspects and removes shear screws as needed and any safety screws. Page 14 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company Note: Anchor should be pinned with 6 shear screws initially. Shear screws are rated for 6,630 lbs each. REMOVE 3 screws for a set down shear of 6,630 x 3=19,890 lbs. Note: Attach mills to Whipstock with (1)35k mill shear bolt. 11.16 If needed, open BOP Blinds. 11.17 Run the Whipstock in the hole, install safety clamp as per Baker Rep, and install hole cover wrap. 11.18 Release pick up system at this point, Make up mills. 11.19 With the top drive, pick the assembly and position the starting mill to align with the hole in the slide. The Baker Rep will instruct the driller when the slot is lined up, the shear bolt then can be made up by the Baker Rep. 11.20 The assembly can now be picked up to ensure that the shear bolt is tight. 11.21 Remove the handlin g system. stem. 11.22 Slowly run in the hole as per Baker Rep. run extremely slow through the BOP & wear bushing. 11.23 Run in hole at 1 '/2 to 2 minutes per stand. 11.24 Fill every 30 stands or as needed, do not rotate or work the string unnecessarily. 11.25 Call for Baker Rep. 15 — 10 stands before being to bottom. 11.26 Orient at least 30' —45' above the CIBP. Ensure to have gyro personnel and equipment as well as a wireline unit on standby in the event of an MWD failure. WindowMaster G2 System on TorqueMaster BTA BHA #1 Connection Length O.D. BOTTOM TRIP ANCHOR 3 '/" IF-B X Anchor 3.21' 5.680 WINDOWMASTER G2 WHIPSTOCK 3 '/2 IF-P X 35K Shear bolt 18.5 5.500 WINDOW MILL 3 '/2 REG-P X MILL 1.38 6" NEW LOWER WATERMELON MILL 3 '/2 IF-B X 3 '/2 IF-P 5.50 6' FLEX JOINT 3 '/2 IF-B X 3 'h IF-P 6.55 4.750 UPPER WATERMELON MILL 3 '/2' IF-B X 3 %" IF-P 5.83 6" 1jt - HWDP 3 '/2' IF-B X 3 1/2" IF-P 30 4.750 FLOAT SUB 3 %2' IF-B X 3 'A" IF-P 3 4.750 MWD 3 1/2' IF-B X 3 '/2" IF-P 30 4.750 UBHO 3 %2" IF-B X 3 1/2" IF-P 4 4.750 X-O sub + 30 jts-HWDP 4" HT-38 4" HT-38 B X 4" HT-38-P 900' 4.750 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY Page 15 Revision 0 Feb,2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 12.0 Whipstock Setting Procedure: 12.1 With the bottom of the Whipstock 30—45' above the CIBP, measure and record P/U and S/O weights. Run gyro survey to orient Whipstock face if the MWD is not operational. 12.2 Orient Whipstock to desired direction by turning DP in 1/4 round increments. P/U and S/O on DP to work all torque out(Being careful not to set BTA). Whipstock Orientation Diagram: 140 deg 180 deg Desired orientation of the Whipstock face is 140 — 180 degrees. Hole Angle at window interval (9,600') is < 1 deg. Planned wellbore azimuth is 160 degrees. 12.3 Slack off to bottom while monitoring Whipstock face direction with MWD. If Whipstock is in desired direction, slack off and tag CIBP to set Bottom Trip Anchor. 12.4 Set down 18-25K on anchor to trip, P/U 5-7K maximum overpull to verify anchor is set. The window mill can then be sheared off by slacking off weight on the Whipstock shear bolt. (35k shear value). 12.5 P/U 5-10' above top of Whipstock. 12.6 Displace to 9.5 ppg 6% KC1/PHPA drilling fluid. 12.7 Record P/U, S/O weights, and free rotation. Slack off to top of Whipstock and with light weight and low torque. Mill window. Utilize 4 ditch magnets on the surface to catch metal cuttings. 12.8 Install catch trays in shaker underflow chute to help catch iron. 12.9 Keep iron in separate bbls. Record weight of iron recovered on ditch magnets. Page 16 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Cern PanY 12.10 Estimated metal cuttings volume from cutting window: 7" 29#P-110 Cuttings Weight Window Length Casing Weight Min (Ibs) Avg(Ibs) Max(Ibs) 16 29# 60 85 115 12.11 Drill approx. 20' rat hole to accommodate the drilling assembly. Ream window as needed to assure there is little or no drag. After reaming, shut off pumps and rotary (if hole conditions allow) and pass through window checking for drag. 12.12 Circulate Bottoms Up until MW in=MW out. 12.13 Conduct FIT to 13.5 ppg EMW. • (13.5 —9.5) * 0.052 * 9600' tvd= 1996 psi Note: Offset field test :a a predicts • • 'as ten s .• e 7"window to be bwtn 14.4 ppg and 15.4 ppg. A 13.5 ppg FIT results in a 44 pick margin while drilling the interval with a 9.5 ppg fluid density. It will also allow room for a MW increase if communication is observed with the lower tyonek waterflow. 12.14 Slug pipe and POOH. Gauge Mills for wear. 12.15 Should a second run be required pick up the following BHA. Back Up Mills Connection Length O.D. WINDOW MILL 3 '/ REG-P X MILL 1.38 6" NEW LOWER WATERMELON MILL 3 % IF-B X 3 %2 IF-P 5.50 6' FLEX JOINT 3 '/ IF-B X 3 % IF-P 6.55 4.750 UPPER WATERMELON MILL 3 '/" IF-B X 3 '/" IF-P 5.83 6" FLOAT SUB 3 '/" IF-B X 3 '/2' IF-P 3 4.750 X-O sub 30 jts-HWDP 4" HT-38 4" HT-38 B X 4" HT-38-P 900' 4.750 CONNECTIONS ON TUBULARS ARE SUBJECT TO CHANGE. BHA'S SHOW SPECIFIC CONNECTIONS AS AN EXAMPLE ONLY! Page 17 Revision 0 Feb,2013 11 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 13.0 Drill 6" Hole Section 13.1 P/U 6" directional drilling assy consisting of: • 6" PDC bit (Baker Hughes QD505X). • Mud Motor(1.18 deg) • Non-Mag Stab (5-7/8" OD) • NMPC • NaviGamma(D&I, + Gamma Ray) • (3)Non-Mag Flex collars • XO • (5) 4" HWDP • Dailey Jar • (21) 4" HWDP • 4"DP to surface. 13.2 Ensure BHA Components have been inspected previously. 13.3 Drift& caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 13.4 Ensure TF offset is measured accurately and entered correctly into the MWD software. 13.5 Confirm that the bit is dressed with a TFA of 0.52—0.57 sqin. Have DD run hydraulics models to ensure optimum TFA. We want to pump at 300 gpm. 13.6 Motor AKO should be set at 1.18 deg 13.7 Primary bit will be the Baker Hughes QD505X. Spec sheet attached on next page. Ensure to have a few back up insert bits (IADC 517) and mill tooth bits (IADC 117) available on location. Page 18 Revision 0 Feb,2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company mall 6" TSO5X TM BAKER t f1 m) Talon HUGHES / • DART Approved The well balanced and experienced Drilling Application Review Team(PART)carefully analyze the application to propose the right solution for your needs.The Network Behind the Solution_ 'talon Optimized Blade Profile Optimized blade profiles improve drilling dynamics and efficiency,promoting a smooth cutting action. • Polished Cutters Baker Ilghes patented polished cutters improve drilling efficiency by reducing balling.Polishing eliminates buildup on the cutter face,enhancing cutting action and cuttings removal From the face of the bit.The industry's only polished cutters. • Optimized Hydraulle Efficiency Optimized junk slot geometries,face volumes and increased blade standoff provide hydraulic efficiency in low-HSI applications.Use of newly advanced Computational Fluid Dynamic(CFD)techniques ensure flow field in each junk slot, maximizing cuttings evacuation and minimizing hit balling and nozzle plugging. II Reference Photo: 6 in.(152,4mm)T505X I'mciuit`ltu'ciiiiatu.its IAlx': N13'_3 Number of Blades 5 Cutter Quantity l Total.tl.I'acel: 2s. lb � .° Primay Cutter Size .625 in[15.8 mm) '°rt Number of Nozzle,: 5 Nozzle Type: Micro SP Fixed TFA 0 in-(0,0 mar) Gauge Length 2 in(50.8 mm) l +' • Junk Slot Alva 6.575 in I-12.4 cm=) -' Bit Breaker: C Connection: 3-1.2 API REG Makeup Torque: 4 I'8"Bit Sub 5.2-5.7 k11-1617.1-7.7 kNm) 4 1;4"Bit Sub 6.3-7.0 kR-lb(8.5-9.5 kNm) 4 1:2"t Bit Sub 7.7.8.5 kR-lb 1 10,4.11.5 kNm) Reference Part Number_ X17695 III Operating Recommendations*: Hydraulic Flow Rate: 200-450 gpm(750-1700 1pm) Rotation Speed: For Rotary and Motor Applications Max.Weight On Bit: 17 klb(7 In or kdaN) 'The ranges of bit weight and RPM shown an repo senIatrvc urtypical operating paratnet n.but will nut necessarily yield opummn hut life ur laves(drilling cunt.It is Vi Ve Vu,baakerlluj*.Iles.coll1 not recommended that Me upper limits of both weight and RPM be run simuhaneutisly t'2012 Hakel Hughes Ineuxparated.All rights ie.crscd, Contact your MK al Hughes Christensen representative for rerumna rndatiun.in your area Page 19 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 13.8 TIH to window. Shallow test MWD on trip in. 13.9 TIH through window, ensure Baker service rep on rig floor during this operation. • Do not rotate string while bit is across face of Whipstock. 13.10 Drill 6"hole to 10,950 MD using above motor assembly. • 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. • See attached mud program for hole cleaning and LCM strategies. • 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. • Ensure mud engineer set up to perform HTHP fluid loss. • Maintain HTHP fluid loss <9. • Take MWD surveys every stand drilled. J 13.11 Hilcorp Geologists will follow LWD log closely to determine exact TD. Plan on drilling to a maximum of 10,950' MD/ 10,891' TVD. 13.12 At TD; pump sweeps, CBU, and pull a wiper trip back to the 7"window. 13.13 TOH with drilling assy, handle BHA as appropriate. Drop drift on trip out. Page 20 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 14.0 Run 4.5" Production Liner 14.1 M/U and rack cement stand in derrick. • Ensure to drift components prior to M/U. Ensure DP wiper dart will pass through components. • Confirm largest OD of packer assy will pass through wear bushing. 14.2 Install 2-7/8" x 5"VBR in lower cavity if not done previously. Test on 4" and 4-1/2"test joints. 14.3 R/U Weatherford 4.5" casing running equipment. • Ensure 4.5" DWC/C HT x 4" HT-38 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 components w/vendor& model info. 14.4 P/U shoe joint, visually verify no debris inside joint. 14.5 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. 14.6 Continue running 4.5"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 to 10,100' MD. Leave the centralizers free floating. • Install them every other joint thereafter to the 7"window. • Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 21 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 4.5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 4.5" 5,800 ft-lbs 6,500 ft-lbs 8,400 ft-lbs Technical Specifications Connection Type: Slze(O.D.): Weight(Wall): Grade: DWC/C•HT Tubing 4-1/2 in 12.60 lb/ft(0.271 in) 1-80 Standard 14- Material Grade :• - ' 80,000 Minimum Yield Strength(psi) USA 95,000 Minimum Ultimate Strength(psi) VAnn-USA 4424 W.Sam Houston Pkwy.Sate 150 Pipe Dimensions Houston,Tx 7/041 4.500 Nominal Pipe Body O.D. (in) Phone:y1a-4y�234 3.958 Nominal Pipe Body I.D.(in) E-mail:VAN.W+satosdQna.vatigurec.cocn 0.271 Nominal Wall Thickness(in) 12.60 Nominal Weight(Ibstft) 12.25 Plain End Weight(Ibs/ft) 3.600 Nominal Pipe Body Area(sq in) • Pipe Body Performance Properties 288,000 Minimum Pipe Body Yield Strength(Ibs) 7,500 Minimum Collapse Pressure(psi) 8,430 Minimum Internal Yield Pressure(psi) - 7,700 Hydrostatic Test Pressure(psi) ; Connection Dimensions 5.000 Connection O.D. (in) t' 3.958 Connection I.D.(in) 3.833 Connection Drift Diameter(in) 3.94 Make-up Loss(in) 3.600 Critical Area(sq in) (' 100.0 Joint Efficiency(%) Connection Performance Properties 288,000 Joint Strength(Ibs) I . 14,290 Reference Siring Length(ft) 1.6 Design Factor 314,000 API Joint Strength(Ibs) 288,000 Compression Rating(Ibs) 7,500 API Collapse Pressure Rating(psi) 8,430 API Internal Pressure Resistance(psi) 81.5 Maximum Uniaxial Bend Rating[degrees/100 ft3 • Appoximated Field End Torque Values 5,800 Minimum Final Torque(ft-Ibs) 6,500 Maximum Final Torque(ft-Ibs) 8,400 Connection Yield Torque(ft-Ibs) 18.7 Ensure to run enough liner to provide for approx 200' overlap inside 7" casing. Ensure hanger/pkr will not be set in a 7" connection. Page 22 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 18.8 Before picking up Baker ZXP liner hanger/packer assy, count the# of joints on the pipe deck to make sure it coincides with the pipe tally. 18.9 M/U Baker ZXP liner top packer. Fill liner tieback sleeve with"Pal mix", ensure mixture is thin enough to travel past the HRD tool and down to the packoff. Wait 30 min for mixture to set up. 18.10 RIH one stand and circulate a minimum of one liner volume. Note weight of liner. 18.11 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. 18.12 M/U top drive and fill pipe while lowering string every 10 stands. 18.13 Slow in and out of slips. 18.14 Circulate 1-1/2 drill pipe and liner volume at 7"window 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 18.15 Obtain up and down weights of the liner before entering open hole. Record rotating torque at 10, 20, & 30 rpm. 18.16 Continue to fill the DP every stand down using fill up line on rig floor. Do not stop to fill casing. 18.17 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. 18.18 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. 18.19 Reciprocate & rotate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 23 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling &Completion Procedure Hilcorp &Keay company 15.0 Cement 4.5" Production Liner 15.1 Hold a pre job safety meeting over the upcoming cmt operations. 15.2 Attempt to rotate &reciprocate the liner during cmt operations. 15.3 Pump 5 bbls 12 ppg MUDPUSH II spacer. 15.4 Test surface cmt lines to 4500 psi. 15.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 15.6 Mix and pump 15.3 ppg class "G"cmt per below recipe. Ensure cmt is pumped at designed weight. Job is designed to pump 100% OH excess. Cement Calculations 7"x 4 DP"Overlap: 200' x 0.021 = 4.3 bbls 7"x 4.5"Liner Overlap: 200' x 0.017 = 3.4 bbls 6"OH x 4-1/2"Liner: (10,950—9,600')x 0.015 x 2 = 40.5 bbls Shoe Track: 120' x 0.015 = 1.8 bbl Total Volume(bbls): 4.3 +3.4 +40.5 + 1.8 = 50 bbls Total Volume(ft3): 50 bbls x 5.615 ft3/bbl= 281 ft3 Total Volume(sx): 281 ft3 / 1.35 ft3/sk= 208 sx Page 24 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Hum Con MY Slurry Information: System Conventional Density 15.3 lb/gal Yield 1.35 ft3/sk Mixed Water 5.912 gal/sk Mixed Fluid 5.962 gal/sk Expected Thickening 100 Bc at 05:57 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 D198 Retarder 0.4%BWOC Additives D046 Anti Foam 0.2%BWOC D202 Dispersant 1.5%BWOC D400 Gas Control Agent 0.8% BWOC D154 Extender 8.0 % BWOC D174 Expanding Agent 1.5% BWOC 15.7 Drop DP dart and displace with 9.5 ppg drilling fluid. 15.8 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. 15.9 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. 15.10 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. 15.11 Slack off total liner weight plus 20k to confirm hanger set. 15.12 Do not overdisplace by more than %z shoe track. Shoe track volume is 1.8 bbls. 15.13 Pressure up to 4200 psi to release the running tool (HRD-E) from the liner. Page 25 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling& Completion Procedure Hilcorp Energy Company 15.14 Bleed pressure to zero to check float equipment. 15.15 P/U, verify setting tool is released, and expose setting dogs on top of tieback sleeve. 15.16 Rotate slowly and slack off 50k downhole to set the ZXPN liner top packer. 15.17 P/U to P/U weight plus 1 ft. 15.18 Close annular and test 4" DP x 7"annulus to 2100 psi/ 5 min to test liner top packer. 15.19 Bleed off pressure, open up annular. 15.20 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). 15.21 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. 15.22 Pick up to the high-rate circulation point above the tieback extension, mark the pipe for p g P � pp reciprocation, do not re-tag the liner top, and circulate the well clean. 15.23 Watch for cement returns and record the estimated volume. Rotate& circulate to clear cmt from DP. 15.24 POOH, verify the liner top packer received the required setting force by inspecting the rotating dog sub. Backup release from liner hanger: 15.25 If the HRD-E tool still does not release hydraulically, left-hand(counterclockwise)torque will have e 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. 15.26 NOTE: Some hole conditions may require movement of the drillpipe to"work"the torque down to the setting tool. 15.27 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. Page 26 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling&Completion Procedure Hilcorp ram Company Ensure to report the following on wellez: • Pre flush type,volume(bbls)&weight(ppg) • Cement slurry type, lead or tail,volume&weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration • Pump rate while displacing,note whether displacement by pump truck or mud pumps,weight&type of displacing fluid • Note if casing is reciprocated or rotated during the job • Calculated volume of displacement, actual displacement volume,whether plug bumped&bump pressure,do floats hold • Percent mud returns during job, if intermittent note timing during pumping ofjob. Final circulating pressure • Note if pre flush or cement returns at surface&volume • Note time cement in place • Note calculated top of cement • Add any comments which would describe the success or problems during the cement job Note: Send Csg& cmt report+ "As-Run"liner tally to lkeller@hilcorp.com hilcorp.com 16.0 Wellbore Clean Up & Displacement 16.1 M/U casing clean out assy complete with casing scraper assys for each size casing in the hole. • 3-3/4"bit or mill • Casing scraper& brush for 4.5" 12.6#casing (MI Swaco - Multiback) • +/- 1500' 2-7/8"workstring. • Crossover(No PBR Polish Mills). • Casing scraper&brush for 7" 29#casing (MI Swaco - Multiback) • (5000') 4" HT-38 DP. • Casing scraper&brush for 7" 29#casing (MI Swaco - Multiback) • 4" HT-38 DP to surface. 16.2 TIH & clean out well to landing collar(+/- 10,800' 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 3-3/4"bit is worked down to the landing collar. • Space out the cleanout BHA so that the 3-3/4"bit reaches the 4.5"landing collar when crossover is+/- 30' above the 4.5" liner top. • The primary objective of the clean out run is to ensure the TCP assy will reach intended depth. 3o°` 195 16.3 After wellbore has been cleaned out satisfactorily using mud, test casing to)1.00-psi/30 min. 16.4 Displace drilling fluid in wellbore with a hi-vis pill followed by fresh water. Page 27 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling& Completion Procedure Hilcorp • Catch drilling fluid in rain-for-rent tanks for use on a future well. • Circulate fresh water into wellbore until clean up is satisfactory. Do not recirculate fluid, • After a couple circulations using FW, short trip the assy to bring the upper 7"multi-back assy to surface. • RIH again&tag landing collar w/3-3/4"bit. Continue circulation as necessary until fluid cleans up. Make another short trip if necessary. • Pump a chemical train followed by 6% KC1 after fluid has cleaned up satisfactorily. Target NTUs are 80 - 100. 16.5 TOH w/clean out assy. LDDP on the trip out. Note any abnormal wear on the mill assy. 17.0 RDMO 21.1 Run 1200' of 3-1/2"production tubing. Install tubing hanger&back pressure valve. N/D BOP. • A waiver is requested from the AOGCC to omit the testing and installation of 3-1/2"rams due to the fact that a wellbore influx at this point is highly unlikely as the well will be cased +cemented+pressure tested. • In the event of an influx, a crossover could be M/U to the 3-1/2"production tubing and RIH to position the 4"DP across rams before shutting in the well. - - '' t/(�K � 21.2 N/U temp abandonment cap. Nso 21.3 RDMO Arctic Fox. 21.4 After rig has departed, run CBL to determine TOC behind 4.5"production liner. Page 28 Revision 0 Feb,2013 Soldotna Creek Unit 41A-04 Drilling& Completion Procedure Hilcorp Energy Compsay 18.0 BOP Schematic Sr. 4k 'a Hyr1111 Doyai Driling 11"5M Hydri1 V BOP + + + ".I �+ 'l nytr �7/" `� k r tS 31r =1 . . -- IZ/" 3-11"3AtF L VA, � - V , ,11.• 1.1- I T Line ■ `-tCe 11. lAng `�I 1 -i., 1.1 Ill l�l li, 3.1 5'•.IaS. Hydrli V Lt 11 l i l P I I i l I I I Crc.c.e.nwr Spnri 11 5M X I 1:1(1 5M t.I III I I. ,I I •I 1, III 6111101 ik } lip 411I 1 U •• Page 29 Revision 0 Feb,2013 11 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 19.0 Wellhead Schematic B►4 A, Bowen, 3 V8 5M FE M Valve,swab,VG-M, ...paw"`; a Valve,Wing,SSV, 3 1/8 5M FE,HWO Valve. YV+ng, VG-M, VG-M, 3 118 5M FE � ., •'10 3 118 5M FE, HWO w,�htalliburtM ,r Qty 2 Hydraulic operator Valve.Wing, VG-M. o `,_•2 1116 5M FE, HWO i t l 1 Re of m ( II.. 01,93, Valve,upper master, * ` 1 VG-M, 31/8 5M FE. HWO Valve,master, VG-M. 3 118 5M FE,HWO _ li Adapter, Seaboard SM-E-CLN 7 1/16 5M stdd X 3 1/8 5M stdd top,w.+%npt control line exit ............ Tbg head,Seaboard,S-8, __ '� Ground level 135/83MX71/16"5M, w12-21/16 5M SSO r I r P 'MT 1 1 Mel , , I. ']] Valve, Seaboard, ( ; .' , ,. ,"l M 1 7 1 ;6 5M FE. HWO,Qty 2 a . .... is, _ � ur , . Valve Seaboard,2" LPO 8 ) 11111 MI- ;0).11.i. ill i Page 30 Revision 0 Feb,2013 11 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 20.0 Days vs Depth Days Vs Depth 9000 8500 9000 r 9500 a ij 10000 ! I 10500 11000 • • • • • • • 1 • 11500 — — — — 0 5 10 15 20 25 30 Days is Page 31 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 21.0 Geo-frog GEOLOGICAL PROGNOSIS WELL NAME: SCU 41A-04 FIELD: Swanson River SURFACE: X=346506.271 LONG:-150 8571(SCU 42-04 well STATE: Alaska Y=2460223.814 LAf:60.7312873 BOTTOM HOL X=346631.1 LONG.-150.8567811 TVD REF DATU KB 18.6'-Arctic Fox KB Y=2459886.4 ILAT:60.7303687 ND REF ELEV 192.3 COORD REF. —.-SYSTEM NAD27 GROUND ELEV 173.7 PROPOSED T r 10.950'MD/10.891'TVD Objective: Drill deviated sidetrack Hemlock well Gas Lift completion targeting H6.10 sands by sidetracking out of SCU 42-041341-04 wellbore(7"casing). This is the first follow up well to the success seen at Geo Summary/ Integrated subsurface and 3-D geological interpretations,in conjuction with previous production data Justification: indicates that stranded oil reserves remain in the Hemlock 1-10 benches south of the E fault High on structure,the H718&H10 are the primary targets.Reserves aren't recoverable in existing wellbores due to lack of takepoints or mechanical condition of other existing wellbores in the fault ANTICIPATED FORMATION TOPS&GEONAZARDS jtXPECTED Intersection Points TOP TOP NAME FORMATION FLUID TVD(FT) TVDSS fFT2 Est.Pressure X Y ±!- frjQ_ SICK OFF POINT 9.600 -9 408 same as Surface Loc 9,600 G2 Tyonek G Oil OIL 10,166 -9.974 2000 psi . 346537.1 2460141.8 F.-30' 10,175- HKT Top Hemlock Oil OIUGAS 10.250 -10.058 1000 psi 346547,6 2460117.5 +1-30' 10.263' H3 Hemlock Oil OIUGAS 10,313 -10,121 1000 psi 346554.5 2460093.3 +1-30' 10,331 H7 Hemlock Oil OIUGAS 10,430 -10238 2500-3000 psi 346568.4 2460051.6 +1-30' 10,456 • H10 Lower Hemlock OIUGAS 10.528 -10,336 2500-3000 psi 346582.3 2460016.9 +1-30' 10.561 1112 Laver Hemlock Wet 10,653 -10,461 2500-3000 psi 346599.6 2459971.8 +1-30' 10,695 TD 10,891 -10,699 2500-3000 psi See Bottom Hole Loc 10,950 =Primary Objective =Secondary Objective T•R T ••II 75 FT DATA COLLECTION REQUIREMENTS: Mud Logging. Mudloggers on site for entire sidetrack. Start collecting 10'samples for OFT2 analysis at–10,000'MD ✓ I WD Data: Baker L'WD GR E-Line Lo• Data Eline OH Quad Combo and Formation Prossure data COMPLETION TYPE Gas fft ANTICIPATED RATES 500-1000 BOED ARTIFICIAL LIFT EQUIPMENT TUBING SIZE 2-718" OTHER COMMENTS --- -------- 1.The kickoff point of 9600'litres chosen to avoid the high pressure water sand at 8,877'MD in SCU 341-04 12.We expect to sidetrack below most,if not all,of the Tyonek coals. 3. We do not anticipate crossing any significant faults that would pose drilling problems. '4. Wells of concern for anticoilision purposes are SCU 341-04,SCU 42-04 and SCU 332-04 4. 3D Time seismic data exists over the Swanson River Field • • Page 32 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 22.0 Anticipated Drilling Hazards Overpressured Lower Tyonek Waterflow: (V Communication with the lower tyonek waterflow is not anticipated, but is always a possibility. Ensure to have enough barite on location to get started weighting up the system to 12.5 ppg if communication with this zone is encountered. H2S: H2S is not present in this hole section.' Abnormal Temperatures: No abnormal temperatures are present in this hole section. Lost Circulation: Ensure 500 lbs of BaroFibre (Fibrous Cellulosic Material), 500 lbs SteelSeal (Angular, dual-composition carbon-based material), & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Maintain l Oppb total of BaraCarbs/Barofibre/Steelseal while drilling the interval to control any seepage losses. Hole Cleaning: Maintain rheology w/Aquagel & Barazan D+. Sweep hole w/20 bbls Barazan D as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 13 - 20 to optimize hole cleaning and control ECD. Wellbore Stability: Maintain 10ppb total of BaraCarbs/Barofibre/Steelseal to strengthen wellbore. Maintain MW as necessary using additions of Barite. I-ITHP control in the <5 range is required. Maintain additions of PAC L /Dextrid LT to maintain API fluid loss of<5. Maintain 6%KC1 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 (BARO-TROL PLUS 4 ppb). • Increase fluid density as required to control the running coal. • Emphasize good hole cleaning through hydraulics, ROP and system rheology. 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. Page 33 Revision 0 Feb, 2013 Soldotn41 a A-04 Creek Unit Drilling & Completion Procedure Hilcorp Energy Company 23.0 Rig Layout $S-10"(76.16m) - s3'-3 1.16. I 4'2 ZE A g Qr E a 114 G072 U f �m 0 Z IG-- K Ll R Cr 7. (r - ai l ,f' 1 •..'_I �.— —_-- ... rr Li A rk AM c Imil ii=llllllllllI-1�■ "_ - =-lma—��...��+.��.∎num I IIIIIIIIIIIII p,;;.•';i, r.' .,.1 ,� 1I:u.= 1 -I F''U',i\�'� •1 i:.•1 IM ■.1••∎∎ ii••■uunnuu_I∎=m T 2)7- I I ! 4 �� i ._ • —r. wi a+_.r� l,v.L ' -- -- ill!r Pn mar mm�-I� D ." •' Ire. o�iu$ o MI �:' M7� II =-Imsi3f; ■g Ft. F11 i - A _ 9/10c7:1 . =_..4 .. rill=agll lii 1 -- t m Mit . 7aaaa . r r I PJII mtis 1 6 r. SA 73 7 moor-1 —.-gi gyp. c''.., lI. i" _ t ti c�I GS�'re ua —ice. pD G — �' ri n Z IrM- y• I..: N. n i `1 \`1 r'1 v ',F c.,.-. r rC AA'' [: ! r 8 I11 rr u = r r SA W t: . �• y u• tyl C A 64'.13-:1:4.brtrr -, Page 34 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 24.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 35 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 25.0 Arctic Fox Choke Manifold Schematic LEDGEND OP A KI TA JV 0 (-1-) White Handle Valves Normally Open 4.00 111 Red Handle Valves 4 0 Normally Closed 637 To FLAg p Ts 3 M Bop STACK 4 4 ER° 1 ° 5 * r 1 f, To FLAO V l I ITS I - 4 10 B t� . n o DEGASSeg MATERIAL LIST r T Item Description A 3-1116"10M Remote Operated r Hydraulic Choke B 3-118"5M Adjustable Choke .: 1 2-1116"5M Manual Gate Valve ) 2-14 3-118"5M Manual Gate Valve 1 • N jsacnc FOX • Page 36 Revision 0 Feb, 2013 • Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 26.0 Casing Design Information Calculation & Casing Design Factors Kenai Peninsula,AK DATE:2/19/2013 WELL: SCU 41A-04(Sidetrack of SCU 42-04) FIELD: Swanson River DESIGN BY:Luke Keller Design Criteria: Hole Size: 6" Mud Density: 9.5 ppg MASP: 2131 psi (see attached MASP determination&calculation) Collapse Calculation: Collapse pressure for section 1 &2 is calculated; Overpressured Tyonek water flow external stress (0.604 psi/ft)and the casing evacuated for the internal stress. Casing Section Calculation/Specification 1 2 3 4 Casing OD 7" 4-1/2" Top(MD) 0 9,400 Top(TVD) 0 9.400 Bottom(MD) 9,600 10,950 Bottom(TVD) 9,600 10,891 Length 9,600 1,550 Weight(ppf) 29 12.6 _ Grade P-110 L-80 Connection LTC DWC/C HT Weight w/o Bouyancy Factor(Ibs) 278.400 19,530 Tension at Top of Section (Ibs) 278,400 19,530 Min strength Tension(1000 Ibs) 797 288 Worst Case Safety Factor(Tension) 2.86 14.75 • Collapse Pressure at bottom (Psi) 5,798 6,578 Collapse Resistance w/o tension(Psi) 7030 7.500 Worst Case Safety Factor(Collapse) 1.21 1.14 • MASP(psi) 2,131 2,131 Minimum Yield (psi) 8,160 8,400 Worst case safety factor(Burst) 3.83 3.94 • • Page 37 Revision 0 Feb, 2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 27.0 6" Hole Section MASP titMaximum Anticipated Surface Pressure Calculation Hilcor Soldotna Creek Unit 42-04 Kenai Peninsula, Alaska Offset Information Well Date Hemlock Pressure TVD Grad SRU 331 27 March, 2012 3140 1.)6Dt0 0.296 Assumptions: 1. Based on offset drilling & well test data, Hemlock pore pressure is anticipated at 2800 - 3200 psi. 2. 3200 psi @ 10,653' =0.300 psi/ft 2. Fracture gradient at 9,600' is estimated at 0.728 psi / It based on field test data. f' I-2P 14/On Fracture Pressure at 7" window considering a full column of gas from window to surface: For 1" window at 9600'TVD: 9600(ft) x 0.728(psi/ft)= 6989 psi 6,989(psi) - [0.1(psi/ft)*9,600(ft)]= 6029 psi MASP from pore pressure (Hemlock H12 at 10,653'TVD) MASP (Wellbore evacuated to gas column) 10,653(ft) x 0.300(psi/ft)= 3196 psi V SIBHP gas gradient to surface: 3196(psi) - [0.1(psi/ft)'"10,653(ft)]= 2131 psi MASP from pore pressure (communication with lower tyonek water flow): MASP (wellbore evacuated to formation water gradient): 9600(ft) x 0.573(psi/ft)= 5500 psi 5500(psi) - [0A316(psi/ft)*9,600(ft))= 1357 psi Summary: 1. MASP while drilling 6" production hole is governed by SIBHP - gas gradient to surface. 2. MASP during production life is governed by SIBHP -gas gradient to surface. Page 38 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcor Energy 28.0 Directional Pl Program g (P1) II Planned Wellpath Report VPI SCU 41A-04 Version#1 BAKER Fay 1�f 3 HUGHES ,,,,,,„r u:,,k:..ta, REFERENCE WELLP.ITH IDENTIFICATION [Operator IHilcorp Alaska,LLC Slot SCU 341-04 !Area !Cook Inlet,Alaska(Kenai Peninsula) Well I SCU 41A-04 !Field lSoldotna Creek Unit ! ellbore SCU 41A-04 Facility !SCU 41-04 Pad !Sidetrack from 'SCU 341-04 at 9600.00 MD REPORT SETUP INFORM Projection System NAD27/TM Alaska SP,Zone 4(5004),US feet Soths ar•System .dl rchitecrC 3.0.9 !North Reference True i!•er Joncihuh !Scale 0.999927 Report Generated 18-Feb-13 at 12:08155 {Convergence at slot 0.75°West I) !abase Source file ,SS ellArchitectDRISCI 41A-04.xml WELLPATII LOCATION I Local coordinates Grid coordinates Geographic coordinates Northlfti EastlfiI : EastingIUS RI Norlhin8iUS RI Latitude Longitude Slot Location -944.87 -1111,25 346506.27 2460223.81 60°43'52.634"N 150'51'27.(110"W !, Facility Reference Pt 34762939 2461154.12 60°44'01.939"N 150°51'04.664"W Field Reference Pt 1 347568.07 2455882.99 60°43'10.024"N 150°51'04.527"W WELLPATH DATUM 'Calculation method Minimum curvature Arctic I or(RTIJ to Facility Vertical Datum 192.3011 - 1 lori.'ontal ReFrcnee Pt Slot Arctic I u\1 R I] I[■mean sea le\.l 19230ft Vertical Reference Pt Arctic Fox(RTE) Arctic Fos t I(f l i to\1ntd1 tine at Slot IS('11 141-04) 19230ft MD Reference Pt Arctic Fox(RTE) Section Origin N 0.00,E 0.00 ft Field Vertical Reference mean sea loci . Section Ainnutli 159.41' J Page 39 Revision 0 Feb, 2013 Ili Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcor Baggy Report ath FAR Planned Well P P Re ��� � SCU 41A-04 Version#1 BAKER Page 2 of± HUGHES 11;14,11.III REFERENCE WELLPATI1 WI N I I l I( \I II IN 1lper11or 'Hilcnrp Alaska.I.1.0 Slot SCU 341-04 \rcu Cook inlet.:\laska(Kenai Peninsula) Well SCU4IA-14 hold Sold ntnil('reek l nil Wellbore SCU 4IA-04 1;6:11 ill SC( 41-114 Pad Sidetrack from SCU 341-04 at 9600.00 MD 142E l.LPA't'H I)A't'A(22 stations) t-intcrpolulcdiesIrupululcd slemn 111) in iinalion A,imuth 7111 I S 11 from Sort Nett North L10 Grid halt (;rid North Latitude Longitude 01.8 ('ommenle 1171 I-I I°i 1111 lId8cr(II-I 0171 181 1(ti it K111 115nl riourii 1111 9611:1(41 (I(1(81 159111 9604100 9-0. II ft Olt 11)111'. 11141 34651)6!'. .'161^101,--6(1"43'52.634"N 150=51'2"010'18 1100 I;e(1i ----- (1481 159.111 969995 9507.65 2.62 4� 6.9 97(4(0418 - - � - 0.92 3465117.16 2461)221 61111'52611"N 150 51'2ti.992"N' 31x1 9801.0 Nit 61881 159.414 9799 61 9611733 10.46 -9.79 3.68 346509,8 46)2_1 1 __ 60 43'52<111 N 150'5126.936"W 31111 9941:8.11 '1(1141 109.414 ')19177 970647 23.51 .22111 11_27 346514.25 -46)'016) 6114. 2417'4 180°5176.844"W 3.(111 10000 Nit 12.000 159.414 9997,08 91504.711E - 4 -39.07 n1 14652E43 2460154.55 0°43 52.249"N t_ .00 1nl,o Ot 15.000 159.414 14109431 99(12.ill 65.05 -6(1.92 22.88; 14652435 2 2461162.60 61143.52134"N 15(151'26 05(1W 3 010 111174.941 17.248 159.414 1(11(0 11 9974 11) x5.09 -X11411 10.20 146535.42 2480143.02 6(1.43'51 842'N 11111"51'26.403"N 1.1111({2 --_ i o'.00 Imo IS(10(1 189 411 101`01 S '199100 914x -57.51 12.7r 5.8 _ 74651'9`11 2460135.89 MN43'S1 i.i'N l till°51'26.349"11 ;On I O261 578 194117 159,414 111251t 3)1 10115s 00 114.12 11683 41113 74654-".111 2460116.47 611.43'51 58_'4 150 51'26_203"11' 3.00 11181 _ 103111.008 21.000 159.414 10284.43 10092.13 126.85 -118.75 44.60 346549.32 2460104.50 60°43'51.465"N 150'5126.113"W 101U7 81 21.184 159414 1(1287115 111/9475 127.x6 -119.66 44.96 141,949.St, 2460101 53 61)41'51 455'N I5(1'51'26.106"\\ 3.011 I4x111'Build 0I:.)1194+ 21.1184 159111 01:1 31i1 111!111 13795 1:'91' 785:' 316553 I)) `461119113 (41.19'51 162'N 150°51'26.034"41 0.(4111: - 10400.00t 211184 159.414 10377,74 1110544 16_2.$2 -15243 5'.25 346561 52 2461070.66 60°43'51.133"N 150°51'25.859"W' 0_01 10.15611 21 054 159 111 10430301 111'9$1n 1x3.09 -171.411 64.38 346568.4U 24 01x1 ir Iurga i0500 00t 21.084 159.414 10471.04 10278.74 198.80 -186.10 69,90 346573.73 2460036.82 60°43'50.801"N` 150°51'25,604"W' 0.00 10561.16 21.4194 159.414 1(19`81(12 111331,.10 2211.07 -2 116.77 7761, 746551,22 2460016.116 6043'511.59$N 15(151'25.448,11' 0 0 11111 1g?11orlton -- I1:x,,NI(81ti 21061 15,)III 1056.1 15 II,17,115 ,31 7 '19.74 5_`55 - ;465:,5 91 216)1;02 99 h0 43'50470'4 1511 51'25 3511'1\' nun Inl93 ait 21684 159.414 10653 30 111461.I11, 269-I17 251.88 94.61 346597 58 2459970 73 61143.51-154'N 1501 I'_5.1n1'1A' 11.1111112 _ 10'11(1.(417 21.1114 15)).414 1.4637 63 114651` 27i,7 4 -251.46 9S.:SI 346591'.15 2439969 15 60143'5(1.118'N 151`51'25.(196'11 11 1111 1(1800.(108 21.084 159414 10750.96 1055866 306,72 -287,13 107,85 346610.35 24.59935,32 60'43'49.806"N 150°51'24.841"W 0,00 IiIWli.ljllt 2111,44 159.414 111944.27 10651')? 342.69 .1211.81 '2(1.511 346622 56 2459911.40 611"43'49.475'N 150 51'24.587 000111 r. .,, 11.1951.41 281111 159.414 11891.30, 1(8,'09.6) 380.838 :'_6.1"• }46620.71 2459084.1_' 60'43'49.311("N� ISfT51'24.459"1\' 016)'117 Page 40 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company Planned Wellpath Report V I SC11 41A-114 Version#1 BAKER I'a:!c ;01 llilrrxr.Ua4a.LIA: HUGHES REF'ERLIICE N ELLI':AIll lDE:N I II it'VI ION operr.tr,r llilcarp Si tcka.I.L(' Slut SC1'341-(4 'Arca Cook Inlet.Alaska(Kenai Peninsula) Well SCU 41A-04 l'ie':: Sokol TM('ruck t nil 1\'cllhorr rSCU 41A-04 I aeii ir) SC 41-04 Pad Soictrack from SCl 341-04 at 9600.011 VII/ ,TARGETS some NM 'I'VI) North East (:rid I:.,t Grit North I Latitude Longitude Shape Ittl 101 101 Ito Itsul it s tti 1)SCU41A-04 H7 TO:18-Feb-13 10456.33 10430.30 -171.40 64.38 346568.40 2460051.60 60°43'50.946"N 150°51'25.715"W circle 2)SCU4IA-04 1110'1gI:l&Feb 113 Itr."'t.3u ]ll<A? 78.73 346582_\11 2460016.90 60 13'511.61x,"\ 150-51'25.427"W circle SURVEY PROGRAM- Ref Wellbore:S('U 41A-04 Net\S(llpath:SCI 41'1-04 Version N1 Stan MI) End VD 1'n+itional I nccrlainl■ Model Lon Name'('Om rnent 5%ellhnre 101 9600.00 1011 192.30 9600.00(BIind Drillml: 5('1 341-04 10950.41 1Kaei(mklh1al._(oiri i('U11:1W - I Page 41 Revision 0 Feb, 2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 29.0 Directional Plan View (Plot) II Hilcorp Alaska, LLC Frail lo1.L/Gn Cook Inal NaHU liana Pori-...,.; Slat SCU 1e 1.CC Feld SMldors Croak Una tValt SCU 4tA-Oa Fart SCU„-01�, mot,„A t” HUGHES I Iikverp.I Iaxlte.MI: Plat reference wsapath is SCO 41A-04 Version#1 True vertical depths are referenced to Arctic Fox(RTE) Gnd System-NAD27.TM Alaska SP,Zone 4(S034),GS feet Measured depths are referenced to Arctic Fox(RTE) North Reference:True north Arctic Fox(RTE)to mean sea level:192.3 feet Scab TWO distance mean sea level to Mud tine(At Slat:SCU 341-04 0 feet Depths are in feet Coordinates are in feet rohrertoed to Slot _Created by pnetloh on 18-Feb-13 ....K. ., Eaeting On MI Sal 41AAe To On a k 2 E I..x Alt 110 3 CO'■100,1 j ,- MT,,,,,,es ..414,04 H7 TOC 1BFeb.13 T a 0? INN,- Hat n,^0 Ta Hoe,,, 'W 1A-01 H10 Tpl 16 cnratMan H3 E IIIIIIIIIIIIIIIIIIIIIIII. 4M Minn p p n,7 V i s.ki -- ISM %Iksi"': o s ----1 ltd .{. 4:km Ih•Vl ,... . . •i, r r.iwP,n-rw{flit/]n]r pider Page 42 Revision 0 Feb, 2013 11 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 30.0 Plot (NAD 27) (Governmental Sections) j SCU 13-34 BHL I r ./ r I. y ri,- I I / • in A028399 SCU:9-33 BHL rf r' S008N009W 4026990 rr _--- `J r • i SRU 24.33 OHt,. SCU 24-34 BHL SCU_44-33 prop BHL •` i 1 SCU 21A434 8HL l J tl - :SCU 21.Q4-aft SCU 41,E-114 � Top of Production Horizon • SCU 4? ,,, '� '1 SCU 41 A-04 Surface Hole Location ,r i Bottom Hole Location(TI)) F :SCU 42-04 Btu SCU 124-03 8111 . SCU 12-09 8HL i SCU 332.04 15-L SCU 22-04 BHL scu 22.04PB BHL SCU 238-03 BHC- SCU 234-03 BHL 4 © SCU 23-03 BHL S007N009W A028997 5CU-l3-04 B.-q. -- - • SL.0 4:lA-04 4HL SCU'1 1)3 0141 r SCU 44-04 BH_ Legend • SCU 4204 SHL SOU 114-;:3 IHL''•R X SCU 41A-04 TPH i SCU 41A-04 TD • Other Surface Well Locations Other Bottom Hole Locations_ ---- Well Paths © SCU 418-09 BHL cm SRF Unit Boundary SCU41-09BHL<- •1A-09 041 ' II 0 1 000 2 000 Soldotna Creek Unit Fit SCU 4 1+I A Alaska Slate Plane Lone 4.NA02 1I I..„-p u:,.t. Itt tap Date.2192013 lA Page 43 Revision 0 Feb,2013 11 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcoor Fara 31.0 Spider Plot (NAD 83) (Governmental Sections) 1 SCU 13.34 BHL 1 r1 1 r A✓ 1� t A028399 SCU 33-33 BHL •j'f J' 03 SOO8N009W �'f P028990 ---__ SRU 24-33 BHtr SCU 24-34 BHL SCU 44.33 prop BHL C- SCU 21A,04 BHL _ SCU 21-04-SHL -- - SCU 41A-04 N.�.- Top of Production Horizon] • SCU 42-04 ' SCU 41A-04 Surface Hole Location !■, Bolton I Ink Location(TI)) ✓` SCU 42.04 BHL SCU t2A-03 BHL SCU 12-09 BHL 1 SCU 332-04 BHL SCU 22-04 BHI,t SCU 22.04P8 eHl SCU 238-03 8141• SCU 23A-03 BHL 4 ;r l SCU 23-03 BHL SOO7N009W A02899V 4 SCU 43-04 BHL--• - •• SCU 43A-04 BHL- SCU 13.03 BHL SCU 4404 BHL.--. Legend • SCU 42.04 SHL SOU 314-03 8H1 .' X SCU 41A-04 TPH 4 SCU 41A-04 TD • Other Surface Well Locations • Other Bottom Hole Locations ---- Well Paths t t 0 SCU 418-09 BM ©SRF Unit Boundary SCU 41-09 BHL KS-U 41A-09 8•.. ' H tam Feet accn Soldotna Creek Unit SCU 41 A-04 ANSK Pl d Stale ane Lone 4.NAC 83 ll1Iru.p 11.4.o.I i I. Map Dole.2;1920,3 Page 44 Revision 0 Feb, 2013 Soldotna Creek Unit 41A-04 ✓ Drilling & Completion Procedure Hilcorp Energy Company 32.0 Surface Plat (As Built) (NAD 27) ._a SECTION CORNER(:o4PUTED NORTH FROM CA 568 43 C81C°..1.1:54. ..'=•+ilbro 33 34 '`--" A 3 N 2461154.123 C 3e729 51K} AS-BUILT LOCATION WELL SCU 42-4 N.2460223.814 E-346506 271 %%%%%1111 * • LAT 80'43'52.834'N ��or A4�a it 7+ S, LONG.150-51'21.010'W + s,• J \ ASP ZONE 4 NAD21 �A.p',. ' // --- \\ uZ. FEL 1127' ••* 49I . *.•0 FNL-991' \\ ELEV=173,r(NAV0881 • ) r. 5 ` SECTION 4, i VI A. NaAtE. T7N.R9W,SAI,AK // 4837-S 4 h , 1.deb Il ,/ \ fEL 112T 1 I \ \ \ 1 1 , — \ \ \ \ \ \ \ \ \ \ \ \ NOTES 1)BASIS OF COORDINATES.NOS OPUS SOLUTION FROM COBS '2AN1','TBON'AND TSEA'ALASKA STATE PLANE ZONE 4 NA083 EPOCH 2003. 2)BASIS OF ELEVATION NOS BM 079 RESET 1991 NAW88 3)SECTION LINE OFFSETS COMPUTED FROM BIM CORNERS FOUND ALONG NORTH BOUNDARY OF 54 USED TO COMPUTE `EAST BOUNDARY OF 54 SHO4A4. SCU 42-4 AS-BUILT SURFACE LOCATION (NAD27) SWANSON RIVER FIELD LOCATION: SECTION 4. TOWNSHIP 7 NORTH, ENGINEERING-TESTING RANGE 9 WEST,SEWARD MERIDIAN ALASKA SURVEYING-MAPPING P.O.BOX 468 IIilrorp Ala ku.1.1,1 SOLDOTNA,AK 99669 JOB NO, 133008 VOICE.(907)283-4218 FAX:(997)283.3265 DWG Cowan.leg WWW_MCLANECG.COM 133008 I Date-2)1112013 FIGURE: 2 Page 45 Revision 0 Feb, 2013 1 Soldotna Creek Unit 41A-04 Drilling & Completion Procedure Hilcorp Energy Company 33.0 Surface Plat (As Built) (NAD 83) .'V 4■_. SECTION CORNER COMPUTED NORTH FROMCX S48 '+4 ' — 33 34 4 3 N 2160816.$1!4 f i4N.r:v*Aim AS-BUILT LOCATION WELL SCU 42-4 N:2459985.048 E:1486529.131 i...„:001111111 111 LAT:60'43'50.606'N o At f + N * LONG•15011'34 998'w .."ps - !4s, f -"I ASP ZONE 4 NAM �Ao ej1•— FELa112T r*:ggIli *0 FNL=961' r_ .♦ NN, ELEV.173.7(NAVD881 i'N.- )Medina, ` ' SECTION 4. •, STAN A.McLAtE T7N,R9w.SM.,Ut 4637-5 1 \ \ *ill 1 / FEL 1127 1 if f- ir/ 1 1 1 11 r (;:- NOTES Ii BASIS OF COORDINATES:NOS OPUS SOLUTION FROM COBS `ZANY,•BCN'AM)TSEA'ALASKA STATE PLANE ZOOE 4 NAO9.3 EPOCH 2003, 2yBA515 OF ELEVATION NOS BM 079 RESET 1991 NAVV68 3)SECTION LINE OFFSETS COMPUTED FROM BLM CORNERS FOUND ALONG NORTH BOUNDARY OF S4 USED TO C0P 1iTE ` EAST BOUNDARY OF 64 SH(1WN SCU 42-4 AS-BUILT SURFACE LOCATION (NAD83) SWANSON RIVER FIELD LOCATION: SECTION 4. TOWNSHIP 7 NORTH, ENGINEERING-TESTING RANGE 9 WEST. SEWARD MERIDIAN ALASKA \,,, SURVEYING-MAPPING P.0_BOX 468 I liliv�l p.11u�6u.W. �1 50LDOTNA,AK 99t'J69 J�NO. 133008 ` VOICE:(907)283-4218 FAX(907)283-3285 llilrekw WWW-MCLANECG.COM 1 3 { �m 3008 I Date-2(1112013 FIGURE: 1 Page 46 Revision 0 Feb,2013 Soldotna Creek Unit 41 A-04 Drilling & Completion Procedure Hilcorp Energy Company 34.0 MW, PP, FG vs Depth SRU 41A-04 MW, PP, FG vs Depth 8000 8500 — MW vs Depth —FG vs Depth —PPvs Depth 9000 - 9500 8 5 10500 11000 11500 12000 —1.0 3.0 5.0 7.0 9.0 11.0 13.0 15.0 17.0 19.0 EMW{ppg) Page 47 Revision 0 Feb, 2013 Hiloorp Alaska,LI.1', Surface Use Plan Swanson River Unit Well SCU 41A-04 Surface Location Anticipated: 961' FNL, 1127' FEL, Sec 4,T7N, R9W, SM, AK Existing Road: The proposed SCU 41A-04 is within the unit boundaries of the Swanson River Field. The roads in the field are suitable for transportation of the drilling rig and support equipment. The road leading into Swanson Field is within the boundaries of the Kenai National Wildlife Refuge and is also suitable for rig transport. Sterling, Alaska is the nearest town to the site and is approximately 25 miles south of the well site. A map showing the location of the proposed well site and access route to the site is included in Figure 1. New or Constructed Access Roads: The well will be drilled from existing pad SCU 41-04. There will be no new roads or road upgrades required for the drilling of this well. Location of Existing Wells: SCU 42B-04 will be sidetracked from existing wellbore SCU 42- 04. SCU 42-04 is currently producing. The well will be shut in and lower zones abandoned prior to sidetracking the well. The Williams pulling unit will complete the well P&A operations. A map showing all known wells within a one-mile radius of the proposed SCU 41A-04 is included in Figure 3. Location of Existing and/or Proposed Production Facilities: Proposed well SCU 41A-04 is currently producing and is tied into production facilities. No facility modifications will be required for the new well. Figure 2 shows the proposed location of the well on pad 41-04 and existing facility flowlines. Location and Types of Water Supply: Existing water sources in Swanson River Field will be utilized. Available sources include Alaska Department of Natural Resources (ADNR) permitted water wells at 14-22 and TS 1-33. All water use will be tracked in compliance with applicable permits. Water will be transported via vacuum truck from water wells to the rig location. Construction Materials: No road upgrades will be needed to allow for rig access. Stockpiled clean gravel picked up from roads within Swanson River Field will be used to level the pad if needed. Methods for Handling Waste: Drilling muds and cuttings: Excess mud and cuttings will be xr hauled from the rig pit system or storage tanks to a Grind and Inject facility at Swanson River Pad 243-04. Wastes will be disposed of in AOGCC approved well SCU 43-04 WD. An ADEC temporary waste storage permit is in effect for any interim drilling'Iluid storage in Swanson River. Brines& Completion Fluids: Eligible fluids will be hauled to a permitted Class II disposal well in Swanson River Field for disposal. Garbage: All household and approved industrial garbage will be segregated and transported to the Kenai Borough Central Peninsula Landfill for disposal. Chemicals: Unused chemicals will be returned to vendors or utilized in future operations. Sewage: All sanitary waste will be contained on-site and hauled off-site by a designated contractor. Ancillary Facilities: A trailer will be staged on the pad to house various supervisory personnel and a minimum number of support personnel. The remainder of the drilling crew will be housed at a temporary camp staged at nearby pad 221-27. Well Site Layout: Attached Figure 2 shows the existing pad, the access road to the location and the proposed well location. There will be no reserve pit on location. A plan view layout of the Doyon Arctic Fox is provided in Figure 4. Plans for Surface Reclamation: No surface disturbances are required for drilling this well. Access will be on existing roads within Swanson River Field, and the well will be drilled from an existing pad. No pad expansion will be required. Approval for final abandonment of the well and location will be obtained from the BLM and U.S. Fish and Wildlife Service prior to any reclamation work. Surface Ownership: The surface lands of the Swanson River Field and the roads leading into the field are within the Kenai National Wildlife Refuge, and are managed by the U.S. Fish and Wildlife Service. Other Information: The Doyon Arctic Fox rig will be used to drill the well. A plan view layout of the rig is provided in Figure 4. -1..., . 1 illt i 4 / S _I 2 1 i ■ 1 I SRU 212-1p Pad ; 121 7 8 9 1 10 1 11 12 i 1 let Ave SRU 14-09 lad\ii SRU 34-10 Pad / SRU 211-15 P. SRU 21-15 Pad MU 41-15 Pad- '- 1 18 17 16 15\1 14 13 1--$110 23-15 vat! A 1 1 _.... SRU 43 15 Pad ; U WS 1-5111.1 234.15 Pad I SR Pad 1 SRU 21 22 Pad-4; SRU 22 23 Pad SRU 32 22 Pad SRU 412 22 Pad di. i ad S 1 08N01 OW SOO8N009W 21 dikSRU 222 21 P 22 23 24 19 20 1 st Ave SRO 14 22 Pad SRU 331 27 Pad - SRU 223 28 Pad ii"--------- - SRU 12 27 Pad SRU 31 27 Pad 2' 30 29 28 .1143 28 Pad 27 26 25 gill SRU 34-28 Pad 3)1., ft)? ISRU 414311.4 SRU 21 14 Pad sae 21 33 Pad ""...d.„ vr••••••••••- o—•••I; ./ .... —eel ■,.. SRU 32 33 Pad SR°;;,.P.4 36 31 32 33 34 35 36 ‘i SRU 23-3 P411,, 042 3343 Pad P i is c u 43.13 Pad SCU 1st Ave 14-34 Pad.1" SCU 41A-04 scu 34-33 Pad — —di Proposed SCU 21-04 P.O Pad SCU 2143 Pad SCU 3.5 Pad I 24nd 4 A.ve .....7,144,1.144„ it SC112-03 Pad 1 6 sc 0 12 0, 01 3 50112.3 P. 2 CU 4.5 Pad A, scui(3p pp p:U 43 04,rpad s 1- ; 1-- SCU 34-0 Pad SCU 1.4 P. SCU 24344 P. ; 1 09 P. 1-. 1, „,,,,,„3"""'''''' KU 21-05 P. 1. B St r , scu SOON 009W/ SCU 3248 Pad r, j• ( .0.2:3..1 d2 09 Pad i 8 U 43 08 Pad. 4I; / 10 11 / ) SCU 24.0 P. )„ .1 S5 AV:c u 7:., i—; r r I t ( --- --- SCU 1409 Pad SCU 34.25 Pad 1 ( SCU 34 05 Pad i ..11.. 1 ■ _, P" SCU 27 is 0.4a 1---- ._._. N -.. . 11 18 17 15 16 *„,_, 14 13 (7' 11 Swanson River Field Figure 1 0 Map Scale 1:32,000 Alaska State Plane 4 NAD 1927 1 2 Meal.AI.ok..LL4 Miles . „.„:. ,A• vif,-• .. . . k , -. .---..' ''. v. :, '.... . .it.7.444011: jil'''':-A r, .4%, ,. . . ,. r‘iSf‘.7** lit'..,it...:.'iiiirit,s. ',Cll. .• -,,, 'c .4 ' 74 '''N ..tv' " 4,,.4 :"*'' . 4":.-t. i, .,,,r. !,..:-.44....1..„.7.;,1.14.,. .. „.... . ,,,...„..t, . -, — _ , d; ,...!,, ,, . ., . 7.4 A474..s 4i4: A ',7' '',; 4,• ,;0-."." - ' ' . • lir. ',.-.....i• • ...., • . ..., • ,., 4L... :4,, ..: 4 411' • • :• ;,., iil '' t, •• 4 ' .. '' . p ° •° , ' • t ,•f •' Y tir.J y. TN d, v ,. /4 ,,re F-1, ... . . • cC °a ^ SCU 41A-04 r Proposed Location , '/ 0 .$a Pgrn rir.!r. ,,k.., c,,,,k,y/ r s ' r 1OP • . t ,wir • . # U �'��. : , . zt SRF Field j .'`, . Overview ' /, i,it,: ..,ea!I.., .%.' ., * AllibilL . . Iii Legend N SCU 41A-04 Proposed Well 1 inch=50 feet A SCU 41A-04 Proposed Location SCU 41-04 Well Pad "`" "" Figure 2 Feet Map Date.7212013 • Other Surface Well Locations 0 50 100 n� ,a„_, q y k+ Y , SF7A,: Y�..: itio) "�. S.#'''.‘,:r � a PBS YARD;,• y .: -:If iY-r Fr"c * '`.--.- .4, . ,4.'' rimimfgl �rif { U:Tr parr m ?Fi r i l s � FrY mu rr. Farr 19tf AT Fre K tf€Fr Mt 'Fre mr leTATTTarse,w rAre4T r/.7;TFrY rrFF;4,~,Frerarm' ctf F. Pre >T r ce-k1Y•Frf4 mrsr + RVf€ Mr gr-Cr FFf. SCU 41A-04 NSnry�rn Proposed Location •F riF'.m Mitern,F€e r ne tr S rtr rnx„ ~i c• rssm rsFxr %rrrFr'f q'i+tf7,fn > 1,rtFFre air 5wK'r FErr 't+re. itIP•rn fr;l l+r.s (,rar...vrmie.r-gt ✓4,arfk'.fRP7fiee.r' MT MO Mrk(i?M 'm71 7.fr1.=1,g,(41 i ted.40 t< F�'(+rYE:04r, mr ga.,q- iera.!x=Mtr^-(X'Fre rrt-f�rFre r,17:.rF Fri' :ir Fr frrsprrr mrFi! mr l; f!r-6;/.Frrr r rg7 'f `* mrI.rfi7'Fr e "; tn t r.•f!.", rsSFr'", g, ' wAresa-ti,wr!v r •-rot^!-ffFrf ,t wrsrArt-Mr!si4fr F. lr r� F•r-e r FYI rrrFrY anti€F::%T r&FXk" •-- f;;.-TiAr Fr r SRF Field r rF1∎{47 FrY �-(t(7. 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F LCi .I1I i r. ai NlC .:;iiiii�aai •s■I :'�ZTI =11 - -I Iw44'Z0 2-,it, Avon I JIIII1I =— :- -_ ,- `Lj,_. VIII III p `�� 6 Wilma,W._ ='i ,0 rjr_I ir; — i[ `® ...1120.._ ► — Iw£4'41.9-41, h� � ML�71\I■■Ir1e\ _ ∎i•_nnmum�s 7�__., .` � ; I_ _ = I[ ' Jw000).0– I pu I , &F.,—. I � I ,', ! .: oCmL IIIIIIiiiiiiii_ 111111111 ∎ir ua�alaaa�r– I – _! III111111111=11�-1 -� ■_Ra_--.■IWI , lik......-.......ill -iiii..,, 11,—_, 11 int 11izi IwSVL1.6-.EZ j�&i – ► —Iw94 L1„9-,4Z 'wi�v�� Q E z E g e N O 01 N r N Ou co N O O r N 7 p N 0 V Davies, Stephen F (DOA) From: Luke Keller[Ikeller @hilcorp.com] Sent: Tuesday, February 26, 2013 4:19 PM To: Davies, Stephen F (DOA) Subject: RE: SCU 41A-04 Surface Location Attachments: SCU 42-4 (NAD27).pdf Steve, We had McLane Consulting, Inc resurvey the well recently and this is the new survey data that was given to us: 961' FNL, 1127' FEL,S. 4, 7N, 9W, SM. It is different from what we had on file as well. Attached is the survey from McLane. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Davies, Stephen F (DOA) [mailto:steve.davies@ alaska.gov] Sent: Tuesday, February 26, 2013 3:05 PM To: Luke Keller Subject: SCU 41A-04 Surface Location Luke, Could you please check the surface location of 41A-04 for me? Hilcorp's permit to drill lists the location of the parent wellbore SCU 42-04 as being 961' FNL, 1127' FEL, S.4, 7N, 9W,SM. AOGCC's database and the well completion report for SCU 42-04 list this same surface location as 1000' FNL, 1170' FEL, S. 4, 7N, 9W, SM. Thanks, Steve Davies AOGCC 907-793-1224 1 0 100 200 I SCALE I ............----............---=-11 I I N SECTION CORNER COMPUTED NORTH FROM CY.,S5&WCMC S33/S4 1111 11 H l 33 34 J----/- 4 3 N 2461154.123 E 347629.593 AS-BUILT LOCATION WELL SCU 42-4 N:2460223.814 E:346506.271 - `NNNA.1,%1I LAT:60°43'52.634"N ��OF A4q Ili m LONG:150°51'27.010"W S J \ m ASP ZONE 4 NAD27 _ COQ. ��� '•.9II \ z FEL=1127' - *:'4911:1 i. ..*II \ =96 %\ ELEV=17 3. (NAVD88) I JA� lir e 1 SECTION 4, 10,), STAN A. McLANE ,. N T7N,R9W,SM,AK II . 4637—S 1 /7/ \\ N i��'I \ ` �� /// \ , FEL 1127' / / I \ / / I ( I \ _ \ \ — \ \ \ NOTES 1)BASIS OF COORDINATES:NGS OPUS SOLUTION FROM CORS "ZAN1","TBON"AND"TSEA"ALASKA STATE PLANE ZONE 4 NAD83 EPOCH 2003. 2)BASIS OF ELEVATION:NGS BM Q79 RESET 1991 NAVD88. 3)SECTION LINE OFFSETS COMPUTED FROM BLM CORNERS FOUND ALONG NORTH BOUNDARY OF S4 USED TO COMPUTE EAST BOUNDARY OF S4 SHOWN. J SCU 42-4 AS-BUILT SURFACE LOCATION (NAD27) SWANSON RIVER FIELD II LOCATION: SECTION 4, TOWNSHIP 7 NORTH, / ENGINEERING-TESTING SURVEYING-MAPPING RANGE 9 WEST, SEWARD MERIDIAN ALASKA / P.O.BOX 468 1Iik orp :%1zx'k.IAA: me SOLDOTNA,AK.99669 JOB NO. 133008 VOICE:(907)283-4218 FAX:(907)283-3265 DWG. Consulting Inc WWW.MCLANECG.COM 133008 Date: 2/11/2013 FIGURE: 2 TRANSMITTAL LETTER CHECKLIST WELL NAME __id L c/7 r CDC/4 PTD# 2'l I/ Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD: ��� '` z -e • POOL: e'e"` ` Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for(name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. 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No special effort has been made to chronologically organize this category of information. 1 22°x52 a 13- 021 . a 1.,...,,..,- ,:,. . , II JUN 202013 AOGCC Ililcorp Alaska, LLC Hilcorp Alaska, LLC SCU 41A-04 III t. r _go ,, ,V-: = ifilearp Alaska,LLC SCU 41A-04 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT& CREW 2 1.1 Equipment Summary 2 1.2 Crew 2 2 WELL DETAILS 3 2.1 Well Summary 3 2.2 Hole Data 3 2.3 Well Synopsis. 3 2.4 Daily Activity Summary 4 3 GEOLOGICAL DATA 9 3.1 Lithostratigraphy 9 3.2 Lithologic Details 10 3.3 Connection Gases 12 3.4 Trip Gases 12 3.5 Sampling Program/Sample Dispatch 13 4 DRILLING DATA 14 4.1 Directional Survey Data 14 4.2 Bit Record 15 4.3 Mud Record 16 5 DAILY REPORTS 17 6 SHOW REPORTS 18 Enclosures: 2"/100' Formation Log (MD/TVD) 5"/100' Formation Log (MD/TVD) 2"/100' Drilling Dynamics Log (MD/TVD) 2"/100' LWD Combo Log(MD/TVD) 2"i 100'Gas Ratio Loa (MD/TVD) Final Data CD 1 CAN 4G Hiloorp Alaska,LLC SCU 41A-04 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type/Position Total Comments Downtime Mudlogging Unit Canrig: 3 HP Compaq Workstations 0 Computer System (DML, RigWatch,and Sample Catcher) Canrig: (2) QGM Gas Traps (with High RPM Ditch Gas Electric-Powered Agitators) 0 Canrig: E-Series Hydrogen Flame Gas Analysis and Chromatography. TOTCO RigSense All Drilling Parameters -0- Intermittent loss of signal throughout job. Block Height/ Depth Totco WITS Feed -0- Hookload/WOB Totco WITS Feed -0- RPM Totco WITS Feed -0- Torque Totco WITS Feed -0- Return Flow Totco WITS Feed -0- Pit Volumes Totco WITS Feed -0- Mud Gain/Loss Totco WITS Feed -0- Pump Pressure Totco WITS Feed -0- Pump Strokes Totco WITS Feed -0- Rate of Penetration Calculated from Block Position tracking -0- Mud Flow In Calculated from Pump Output/Rate tracking -0- 1.2 Crew Unit Number : ML030 Unit Type : Arctic Steel Skid Unit Mudloggers Years* Days*2 Sample Catchers Years Days*2 Technician Days Larry Resch 13 18 John Farrell 1 15 ML Michael Sherry 1 16 Jane Grundin Trainee 13 *1 Years experience as Mudlogger. .2 Days at well site. 2 CANRIG Moo.p Alanka.LLC SCU 41A-04 2 WELL DETAILS 2.1 Well Summary, Well: SCU 41A-04 API Number: 50-133-10109-02-00 Field: Swanson River Field Surface Co-Ordinates: 961' FNL, 1127' FEL Sec 4 T7N R9W SM Borough: Kenai Borough Primary Target Depth: Hemlock H3 10313'TVD State: Alaska TD Depth: 10807'MD/ 10757'TVD Rig Name/Type: Arctic Fox/ Double Suspension Date: N/A Primary Target: Hemlock Formation Permit to Drill: 213028 Spud Date: May 07, 2013 Ground Elevation: 173.7'AMSL Completion Status: Run 4-1/2" liner RKB Elevation: 192.3'AMSL Classification: Development Oil Secondary Target: Hemlock H7 10 Depth: 10456'MD/ 10430'TVD TD Formation: Hemlock Formation TD Date: May 17, 2013 Days Drilling: 11 Days Testing: N/A 2.2 Hole Data Maximum Depth Mud Shoe Depth FIT Hole TD Dev. Casing/ Section MD TVDSS Formation Wt rinc) Liner MD TVDSS (ft) (ft) (ppg) (ft) (ft) (ppg) Tyonek 0.32 7" 9600' -9407 13.4 6" 10807 -10566 Lower 11.1 19.82 4-1/2" 10786 -10546 n/a Hemlock 2.3 Well Synopsis. SCU 41A-04 is the seventh in a series of wells drilled by Hilcorp during the 2012-2013 drilling season. A sidetrack of the parent well SCU 332-04, SCU 41 A-04 deviated from a window cut through existing 7"casing at 9591'MD targeting the Lower Tyonek G2 sand and the Hemlock H1-3 sands. Secondary production objectives include the Hemlock H7, H10 and lower Hemlock sands. It was also planned to drill approximately 365' measured footage of the top of the West Foreland Formation. Within several hundred foot of drilling out of the window high pressure fresh water (8.6 PPG, 6000 ppm Chlorides)was encountered. Current belief is that this is not connected to the high pressure Tyonek water as 11.3 ppg mud weight was able to kill this flow. Lost circulation zones were encountered at 10182'MD and 10807'MD. Drilling, MWD logging and obtaining quality cuttings samples was necessarily problematic with instances of partial or complete loss of returns and significant LCM(Barofiber,Steelseal,Baracarb)in the mud system. Additionally, LCM (nut plug) was encountered in cutting samples intermittently from 10220'MD to 10410'MD and interpreted to have come from lost returns remediation while drilling the parent well. In consideration of the current borehole condition the decision was made to TD before drilling into the West Foreland. There was no significant lost circulation while running 4-1/2"production liner or during the cement job. 3 CANRIG e, nom,LLC SCU 41A-04 2.4 Daily Activity Summary May 05,2013: Canrig representative Larry Resch completes rig up operations. Continue tripping in hole with 4"drill pipe from 1500 ft to top of cement at 9631 ft;pressure test casing to 3000 psi for 30 minutes;circulate through kill and drill pipe, shut top rams, HCR-KILL and 2"low torque to isolate for test—good test; monitor outer annulus during test;blow down associated equipment;pick up joint#288 and run in hole to 9629'MD; pump at 6.5 BPM to displace brine with 10.50 ppg EZ-Mud with 6%KCI;surface to bit 3490 stks,bit to surface 6981 stks, surface to surface 10471 stks, 392 psi increasing to 1180 psi at end of displacement;trip out of hole from 9625 ft to surface; pick up/ make up whipstock assembly per Baker Rep and HWDP to 642 ft. Currently servicing rig at report time. May 06,2013: Continue to trip in from 1594' MD to 9606' MD. Rig up wire line to orient whipstock;run gyro data down string to latch into UBHO.Orient string to 158°.Confirm orientation of whipstock,wireline/gyro data POOH;rig down wireline. Run wireline logs;confirm orientation of whipstock;R/D wireliners.Set whipstock @ 9591'; drill window from 9591' to 9602'; continue milling window from 9602' to 9628'. Circulate 19.5 BBL sweep STS 11400 stks;245 GPM; Rig up and FIT to 13.5 EQ MW;rig down;1502 PSI chart;5 min;good test. POOH from 9625'to 9000' UWT 152k; SOW 149k May 07, 2013: Blow down kill line; monitor well. Continue pulling out of hole from 9000' MD to 8100' MD; POW= 151k;SOW =136k. Monitor well;pump dry job; 19 BBLS of 11.7 PPG. Continue trip out of hole from 8100' MD to 97' MD; POW = 138k; SOW 136k. Break down BHA according to Baker hand;window mill = 1/16"under gauge;upper and lower string mill in full gauge.Jet stack;pull out of hole;function BOPs;jet stack second time. Calibrate blocks for rig sense; re-calibrate with Baker-MW D. R/U to pick up BHA. Pick up BHA as per DD;TQ and scribed to UBHO;POW=30k. Download tool;set 2 nuke sources;UWT 44k;SOW 44k; shallow well test;208 GPM @ 730 PSI;to 781'MD. Single in the hole from pipe shed;50 JTS;from 781'MD to 1574' MD; UWT 67k;SOW 64k; Fill pipe;220 strokes to fill. RIH 1574'MD to 6000'MD; UWT 113k;SOW 108k. RIH from 6000' MD to 9585' MD; UWT 166k;SOW 160k; ROT 156k. Reaming out under gauge hole from 9608'MD to 9628'MD; 1.8 TQ;20 RPM;1400 PSI;166k;.Circulate BUS 7200+. Rack back ST 141;P/U single not in tally.Wireline logs;R/U side entry sub;M/U wireline sheave and side entry sub per wireliners;run tool to bottom. May 08, 2013: Run gyro data to orient string; establish tool face @ 218*. Put plug in port of wire line entry sub;pressure test to 250 GPM;1880 PSI.Kelly up stand 141;start sliding from 9627'MD to 9633'MD;GPM= 210;pump pressure off= 1460;pump pressure on= 1580;WOB=2-4; PUW= 165k;SOW= 159k; POW= 155k. Re-initiate gyro every hour-pick up 5'off bottom and turn pumps off;continue drilling from 9633'MD to 9655' MD. Continue drilling per DD from 9655' MD to 9704' MD; PUW = 166k; SOW = 155k; POW = 159k; GPM=240;pump pressure on=1866;pump pressure off=1820;WOB 2-5k;bit=6 hrs;motor=3.2 hrs;jars =0;AST=6 hrs;ADT=6 hrs;ART=0 hrs.Trip out from 9704'MD to 9613'MD;PUW=166k;SOW=155k; rack back stand 142 & 141. POOH with gyro; R/D wireliners. Drill from 9704' MD to 9715' MD; shut well in. Circulate through choke; weight up mud to 10.8 lbs/gal both ways; 3 BBUmin 870 PSI W 400 PSI back pressure at start;200 PSI back pressure at end of STS strokes. Drill from 9715'MD to 9755'MD;250 GPM @ 1933 PSI off;2140 PSI on;5k on bit;40 RPM;UWT 166k;SOW 162k;ROT 158k.Continue drilling from 9755' MD to 9868' MD; UWT= 168k; 162k SOW; 158 ROT;242 GPM; 1850 PSI off;2080 PSI on; ROT 40 RPM; 1.9 TQ off. 4 CANRIG Hlkor,Alaska,LLC SCU 41A-04 May 09,2013: Continue drilling from 9869'MD to 9938'MD;PUW=168k;SOW=158k; RTW=155k;GPM =254; pump pressure on = 2120; pump pressure off= 1980; WOB=2-5k; RPM 40;TQ on =3k;TQ off= 1.9k. Well was flowing at 5 BBLS/hr, increase MW from 11.0 to 11.2. Continue drilling from 9938' MD to 10048' MD; PUW = 171k; SOW = 159k; RTW = 158k; GPM = 250k; pump pressure on = 2340; pump pressure off=1950;WOB=5k; RPM=40;TQ on=3.2k;TQ off=2.2k;Continue drilling from 10048'MD to 10156'MD; UWT= 168k;SOW=160k; ROT=157k;TQ off=1.9;TQ on=3.3;GPM=250;pump pressure on =2250; pump pressure off= 1950. Continue drilling ahead from 10156' MD to 10182'MD; UWT= 170k; SOW= 162k;ROT=157k;GPM=250;pump pressure on=2350;pump pressure off=1950;40 RPM. Lost circulation; POOH to shoe at 9572'MD;pump LCM pill through kill line;chased with 14 BBL good mud.Pump 20 Ib/BBL LCM pill down DP;chased with 102 BBL mud to spot pill of bit;filled backside with trip tank. Fill hole with TT;build volume;squeeze 16.62 BBL into formation;bag closed;pumped through kill line.ADT=4.4 hrs; ART= 1.3 hrs;AST=3.1 hrs; BIT=23.5 hrs;JAR =3.6 hrs; MOTOR=38.7 hrs. 656 BBL lost. May 10,2013: Continue squeezing LCM down back side;pump and additional 30 STKS to maintain 1100 PSI on ANN.; continue batching mud to 11 PPG—390 barrels built. Bleed pressure; open up and monitor TT- gained 3.2 BBLS while monitoring. Shut in ann.-line up to squeeze on back side—33 STKS to pressure up- maintain 1100 PSI on back side while continuing to batch up an additional 100 BBLS of 11 PPG mud.Trip in one stand from 9580' MD to 9641' MD; stage pumps up to 160 GPM; pump pressure = 960 PSI; @ 7500 STKS pump pressure = 1060 PSI; PUW = 160k; SOW 155k; downtime gas observed =846 units @ 7500 STKS.Trip in hole from 9641'MD to 10153'MD;PUW=158k;SOW=152k. Kelly up stand 150;continue trip from 10153'MD to 10171'MD;set 10k on bit;pick up and wash down to 10182'MD; RPM=20;GPM=160; pump pressure = 1440; TQ = 4.4k; continue drilling from 10182' MD to 10192' MD; stage pumps up to 17 GPM;pumped 3055 STKS=88 BBLS; lost 68 BBLS to hole while pumping on it.Turn off rotary and pumps; P/U of bottom and line up TT; establish loss rate with hole fill pump = 1 BBUmin; work pipe to keep from sticking;continue conditioning and batching 11 PPG mud. Pump 48 BBLS of 25 Ibs/BBL LCM pill;stage out of bit 5392 total STKS pumped; 3718 STKS to chase out of string;@ 1.8 BPM pump pressure=350 PSI;@ 3 BPM pressure=510 PSI,increased to 950 PSI as returns were established.Trip out of hole from 10192'MD to 9579' MD; PUW=173k; .8 BBLS lost during trip. Monitor static loss with hole fill; 2.9 BBLS to fill in 10 minutes;shut ann.;Line up to pump down backside. Pumping 5 BBLS at a time-squeezed 85 BBL away;Max pressure=450 PSI. Bleed pressure and open up well; Line up to TT and get a loss rate of 6 BBUmin; Max gas observed=846 units;380 BBLS lost from 00:00 to 12:00. Monitor well;check loss rate every 5 minutes. Place bit out of window;9615' MD;pump 2 BBUmin; 50%loss. POOH to shoe;circulate over the top of well with hole fill;build volume and LCM pill;trips RIH from 9582'MD to 10150'MD;UWT=170;SOW=160;ROT 160;200 GPM @ PSI off 1980;PSI on 2250;TO off 2.0;TQ on 3.4. Drill from 10192'MD to 10228'MD; UWT =174k;SOW=163k; ROT 160k;TQ on 3.2k;off 2.1k;240 GPM;POOH from 10228'MD to 9588'MD;pulled good. Build volume;chase 42 BBL pill;chase with 35 BBL; monitor loss. Squeeze 5 BBL into formation at a time;wait 5 minutes between; highest PSI observed =546 PSI; building 80 Ib/BBL LCM pill. May 11, 2012: Pump 40 BBL, 60 PPB LCM (Baraseal, Steal Seal) pill through kill line; SIMOPS; build 130 BBL batches to 10.8 PPG PHPA 6%KCL drilling fluid.Continue to fill hole via trip tank,monitoring losses;28.8 BPH initial loss rate.Close annular preventer,squeeze 20 BBL of 25 BBL LCM pill into formation,initial break down PSI: 530 PSI, final-760 PSI,wait 5 mins, PSI up- break down @ 530 PSI. Continue to fill hole via trip tank monitoring losses,28.8 BPH initial loss rate.Close annular preventer,squeeze 20 BBLS of 25 BBL LCM pill into formation,initial break down PSI:530 PSI, Final:760 PSI,wait 5 mins, PSI up—break down at @ PSI. Continue to fill hole via trip tank monitoring losses,28.8 BPH initial loss rate;final loss rate 12.6 BPH,160 BBL loss from 00:00; continue to build 130 BBL batches 10.8 PPG PHPA 6% KCL drilling fluid. Close annular preventer, Squeeze 18 BBLS with 300 PSI staging up to 800 PSI break down PSI, open annular preventer. Continue to fill hole via trip tank monitoring losses, 18 BPH initial loss rate;final loss rate 7.2 BPH (15.7 BBL loss).Close annular preventer,squeeze 17 BBLS with 300 PSI staging up to 600 PSI,open annular preventer. Continue to fill hole via trip tank monitoring losses, 10.8 BPH initial loss rate;final loss rate 3.6 BPH. POOH from 9582'MD to 8640'U-155 D-150. monitor well;well flowing 5 BBL/Hr:tried pumping;pressure up;bled off PSI; UWT 155 K; POOH from 8640' MD to 781' MD; UWT 44K;gain of 30 BBL while tripping; add circ sub and 2 XO's per Baker rep RIH with 2 STDS of DP;drop ball open circ sub;opened @ 1281 PSI.RIH from 900' MD to 6883' MD; UWT= 126K; SOW = 122K. Service TD; DW; grease wash pipe, monitor well. 5 ANRIG Hikurp Alaska,LLC SCU 41A-04 May 12,2013: RIH from 6883'MD to 9100'(pipe out of balance). K/U;circulate 60 BBL 11.0 PPG mud @ 80 GPM 660 PSI ICP;280 PSI FCP. RIH from 9100' MD to 9537'MD; K/U TD; RIH to 9588'MD U- 165, D-160. Circulate @ 9588' MD bit depth; 8794' MD circ. sub depth. @ 160 GPM 40 PSI WT up to 11.0 PPG; clean H2O returns @ 6000 STKS(85 BBL total)with 45 BBL diluted mud dumped to R/W;returns to pits with 10.2 PPG mud;continue WT up to 11.0 PPG @ 80 GPM 40 PSI;Max gas 865 units.Close annular preventer;hold 300 PSI on DP and CSG; bleed off to 115 PSI on DP, 30 PSI on CSG;WT up surface mud system to 11.2 PPG. Circulate through choke with 11.2 PPG kill WT mud @ 80 GPM, 560 PSI, 250 back PSI. Continue circulating through choke until 11.2 PPG mud around; open up the well. Monitor well; Build and spot pill outside of circ.sub;3577 STKS.TOOH from 9588'MD to 5545'MD; UWT=156k;SOW=152k;TOOH from 9588' MD to 5545' MD; UWT= 156k; SOW = 152k;trip from 9588' MD to 5650' MD; UWT= 106k; SOW = 102k. POOH from 5560' MD to 757' MD; UWT = 44k; SOW = 44k. POOH with HWDP jar; T smart tools; retrieve nukes; UD BHA per baker rep;download MWD;depth 111.89' MD. May 13,2013: Continue to UD BHA#3:UBHO,filter sub,stop sub,SDN-LWD,BCPM,MWD-ONTRAK,stop sub, 2- PNY NMFC, motor, bit; all jets on bit plugged with LCM, could not turn bit sub on motor, not able to drain.Clear and clean rig floor;pull wear bushing;install test plug&4"test JT;R/U to test BOP.Function test: blind rams,top pipe rams and lower pipe rams,test:annular with 4"test JT @ 250 PSI/5 min,2500 PSI/5 min; R/D test equipment; set wear ring 6.125" ID. M/U BHA#4: bit, 0.8 deg motor, stab, 2-PONY NMFC, MWD, BCPM,stop sub,filter sub;orient motor to MWD,clean and dress all T2 connections. Plug in to MWD,obtain surface electronic test. RIH with NMFC from FRK,3 STDS of HWDP from DRK.Attempt to shallow pulse test @ 210 GPM-to 310 GPM (no pulse). POOH, RK BK 3 SIDS HWDP&NMFC. Break filter sub and inspect, plug in to MWD CK communication(good);M/U filter sub;RIH with NMFC;M/U to drive;clear mud pumps of LCM/polymer.Shallow pulse test @ 240 GPM 775 PSI,300 GPM 1140 PSI;30 RPM;0.4 TQ.M/U BHA;place well commander circ. sub after jar stand; RIH with all HWT DP to 77'MD; UWT 402k;SOW 42k.TIH in hole from 776' MD to 3220' MD. Fill DP; 252 GPM; 1230 PSI; BHA pulsing; no communication with smart tools; repeat at 310 GPM, 1695 PSI (working);cycle pumps;208 GPM,915 PSI(everything ok).RIH from 3220'MD to 4400' MD; UWT 86k;SOW 82k. RIH from 4400'MD to 9580'MD;fill every 1800';fill DP @ 9580'MD,210 GPM, 1500 PSI;UWT 154k;SOW 148k;MWD pulse test;210 GPM(good pulse,good coms).Change oil and service DW;service TD and grease wash pipe.Cut and slip drilling line;cut 140'of drilling line.Calibrate block heights for MWD;RIH from 9580'MD to 9832'MD;UWT=162k;SOW 152k.Circ.BUS;214 GPM;1540 PSI. May 14,2013: Continue circulate B/U STKS @ 214 GPM, 1540 PSI;max gas @ 217 Units. RIH from 9835'to 9948'(tight),wash DN to 10228'at 128 GPM 890 PSI,40 RPM,2.5k;TRQ(no fill on BTM). Drill from 10228' to 10286'@ 186 GPM PSI:on-1650 off-1425;40 RPM;TRQ:on-2.6 off-2.3;WOB-2-4k;flow-20%;U-174k D- 163k;RT-171 k;D-163 RT-170;ADT-2.4 TR-1.7 TS-.7; 151 BBL loss. Drill from 10286'to 10355'@ 224 GPM PSI:on-2100 off-1830;40 RPM;TRQ:on-3.2 off-2.5;WOB-3-5k;flow-23%; U-175k D-164k; RT-171 k ADT- 3.0 TR-1.8 TS-1.2;221 BBL loss. Circulate B/U STKS @ 216 GPM 1730 PSI;40 RPM,2.2k TRQ. Break out T/D,drop 1.75"ball, pump DN @ 80 GPM to 1546 STKS,seat ball, PSI to 1000 PSI wait 30 seconds; PSI to 2466 PSI shear circular valve,confirm open; ICP-540;PSI FCP-360 PSI,circulate through circular sub;Drop 1.698"isolation ball, let drop 5 mins.Tour loss=405 BBL.Break connection;drop 1.698"black ball;pump 20 BBL 50 LB/BBL LCM pill chased with 100 BBL mud to spot LCM; 2 BBUmin 360 PSI; 3 BBUmin 510 PSI. POOH from 10355'to 9580'; UWT 172k;SOW 166k. Circulate over top of well;check loss rate; 18 BBUhr. Shut bag;squeeze LCM pill into formation;highest PSI observed 424 PSI;build volume in pits.RIH from 9580' to 10355'; 175k UWT; 168k SOW. Pump 20 BBL 50 LB/BBL LCM pill;spot out of circular sub. POOH from 10355'to 9580'; UWT 166k;SOW 162k.Monitor well for 1 hour;Get loss rate; 12.5 BBUhr.Squeeze LCM pill into formation;highest PSI observed 1123. Monitor well;fill hole with holefill and track losses;build 80 LB/BBL LCM pill; RIH from 9580' to 10355'. Pump 40 BBL LCM pill, 80 LB/BBL LCM pill; spot out of circ. Sub by chasing with 100 BBL mud;3460 STK; 2 BBUmin, 400PSI. Tour loss =232.2 BBL. 6 CANRIG Hi burp AI.ek.,LLC SCU 41A-04 May 15,2013: Continue pump 45 BBL of 80 PPB LCM pill(30 PPB Baracarb 50,25 PPB Steel Seal,25 PPB Barafiber),chase with 100 BBL 11.2 PPG mud @ 80 GPM,240 PSI. POOH from 10334'to 9574'U-160K D- 156k. Monitor losses via trip tank, 19 BBL/hr loss. Close annular preventer, squeeze 20 BBL @ 300 PSI staging to 700 PSI, open annular preventer monitor losses via trip tank, 16 BBUhr loss. RIH from 9574'to 10203' U-173 D-162. Build 50 BBL 70 PPB pill (Baracarb 50 40 PPB, Baraseal 15 PPB, Barafiber 20 PPB), pump pill and chase with 99 BBL 11.2 PPG mud. POOH from 10203'to 9574'.Monitor losses via trip tank, 10 BPH loss; SIMOPS; build 11.0 PPG 6% KCL PHPA mud. Close annular preventer, squeeze 7 BBL @ 3000 PSI staging to 500 PSI, open annular preventer. Monitor losses via trip tank, 8.6 BPH loss. Close annular preventer, squeeze 7 BBL @ 3000 PSI staging to 1000 PSI, open annular preventer monitor losses via trip tank,8.4 BPH loss.Close annular preventer;squeeze 7 BBLS @ 3000 PSI staging to 1000 PSI,open annular preventer. Monitor losses via trip tank,8.4 BPH loss;SIMOPS;build 11.0 PPG 6%KCL PHPA mud.Continue monitor well for losses; build volume in pits; losing 6 BBL/Hr. Circulate drill string volume; due to gas increasing pump bus;7200+;2 BBUmin @ 285 PSI. Lubricate rig;service TD;DW.Circulate,drop 1.75 ball to close circular sub(ball#5)80 gal per min,close @ 2427 PSI on circular sub. Monitor well; RIH from 9580'to 10355'; UWT 156k SOW 152k; Drill from 10355'to 10362'; UWT 175k;SOW 166k;ROT 171k 40 RPM; 183 GPM; 4k WOB; 1260 PSI off; 1370 on; 2.1 to off; 2.6 on. TD lost power;troubleshoot TD; PLC down;work pipe; pump 80 GPM;560 PSI. May 16,2013: Troubleshoot MWD pulsar. Drill from 10362'to 10395'@ 255 GPM PSI on-2120 off- RPM-0 TRQ-0 WOB-1.2k flow-28% U-175 D-164 RT-170 ADT- 1.1 TR- 1.1 TS-0.Continue drilling from 10412'to 10585'; UWT 178k; 165k; 168k; 2.2k off; 5-8K WOB;250 GPM 2070 PSI off;2420 on. Continue drilling from 10585'to 10XXX'; UWT= 184k; SOW 166k ROT 168k;262 GPM @ 2100 off PSI; 2400 on; 5-8k on bit; 50 RPM. May 17,2013: Drill from 10800'to 10807.8', hit drilling break @ 10806'; return flow loss from 28%to 3%. Monitor well on TT, obtain loss rate @ 75.5 BPH. Drop 1.75"close/open ball pump DN 2 80 GPM 490 PSI, ball seat @ 1407 STKS, PSI up to 1000PSI wait 30 sec, PSI to 2278 PSI shear circ sub open, 310 PSI open, drop 1.698 isolation ball. Monitor well on TT, obtain loss rate @ 51 BPH, build LCM pill. Pump 43 BBL 80 PPB LCM pill (Stealseal 400-20PPB, Barafiber-25PPB, Baracarb 5-53PPB) chase with 102 BBL 11.1 PPG mud @ 80 GPM 300 PSI. POOH from 10807'to 9575' U-164 D-157. Monitor well on TT, initial loss rate 30 BPH;final loss rate 20.5 BPH, build 11.1 PPG 6% KCL PHPA mud, build LCM pill. Pump 43 BBL 80 PPB LCM pill (Stealseal 400-20 PPB, Barafiber-25 PPB, Baracarb 5-53 PPB) chase with 60 BBL 11.1 PPG mud @ 80 GPM 300 PSI.. RIH from 9575'to 10778'. Displace LCM pill with 55 BBL 11.1 PPG mud @ 80 GPM 345 PSI. POOH from 10778'to 9570'. Monitor well on TT, loss rate 6.4 BBUhr, continue to build 11.1 PPG 6% KCL PHPA mud, close annular and squeeze periodically @ 300 and 500 PSI. Bleed off pressure, open annular; monitor with TT, 1 BBUhr loss rate. Close annular, squeeze periodically @ 300 to 800 PSI. Monitor well on TT in between. Continue to build 11.1 PPG 6% KCL mud. Circulate B/U through circular sub. Pumping @ 1.9 BBUmin @ 200-310 PSI. Attempt to get 11.1 PPG mud in and out. Out WT won't come up past 10.9 PPG. Drop steel ball to close circular sub. Circulate through BHA to ensure that it's clear. All good, sleeve closed @ 2400 PSI. RIH W/4" HT-38 DP. From 9570'to 10778'. No tight spots. UW=183k, DW=165k. CBU @ 2.7 BBUmin, @ 800 PSI. 11.1 PPG MW. Monitor well for 5 minutes, dropping slowly. POOH from 10778'to 9570'. Monitor well at window for 30 minutes on TT; 15 BBUhr loss rate. Pump dry job; 12.6 PPG. 7 CANRIG Hilcorp Alaska,LLC SCU 41A-04 May 18,2013: Monitor well;15 BPH loss;drop 2.38"drift on 80'wire(STD 140). POOH from 9577'to 776'U- 42k D-42k; monitor well;7.2 BBUhr loss;recover wired drift at first JT HWDP,calc-57.1 ACT-88.5 Toss-31.4 (SIMOPS:test choke manifold 250-4000 PSI). Continue POOH, RK BK 9 STDS HWDP, UD: Commander Sub, X/O's, JARS, 1 JT HWDP. UD BHA#4: 2- NMFC,filter sub. Plug in, download MWD; monitor well on TT. Rinse and drain BHA;continue UD BHA#4:MWD,2 NMFC, STAB, motor, bit. Clear and clean rig floor; send out all Bakers subs and bits;pull wear bushing. R/U to test BOPE, M/U FOSV, DART to 4"test JT;M/U rocket launcher to saver sub; R/U test equipment.Test annular preventer to 250 PSI/5 min,2500 PSI/5 min, 4000 PSI/5 min: TPR, HCR choke, HCR kill, FOSV. Tour loss = 100.5 BBLS. Continue to test BOPs, 250 PSI/low,4000 psi/high;test top pipes, man kill, man choke, DART valve;test top pipes,3 1/8"kill,valve 1 on choke, lower IBOP; test top pipes, upper IBOP; test lower pipes on 4" test JT, perform Koomy test; build blinds;test bag on 4 1/2"test JT 250/2500;test top pipes on 4 1/2"test JT. R/D test equipment; break TIW & DART valve apart;break XO on top of 4 1/2"test JT;clean up rig floor;install wear bushing 6.125"ID.R/U CSG equipment; P/U handling tools; ID elevators and slips; P/U power tongs& hang; rig up CSG;fill up line; P/U centralizers. Run liner assembly; Baker LOK& M/U shoe track, blank JT, float collar, & landing collar; CK floats;continue RIH with total of 33 JTS of 4 1"liner. P/U liner hanger assembly; mix POW mix, pour in, let stand for 30 mins. P/U first STD of 4"HWDP;make up TD&CIRC liner volume.Continue RIH with HWDP& 4" DP;fill every 10 STDS;drift HWDP W/2"drift. May 19,2013: RIH from 2586'to 6365'with 4"DP from DRK @ 90 sec/STD;fill pipe every 10 STDS via T/D. Continue RIH from 6365'to 9508'with 4" DP from DRK @ 90 sec/STD;fill pipe every 10 STDS via T/D; U- 146k, D-145k, ACT-36.6, CALC-65.9, LOSS-29.3. Circulate @ window 1.5X liner and drill string volume; pumping @ 80 GPM @ 340 PSI, max gas observed = 258 units. Continue RIH with 4" DP from 9575' to 10795'. UD top single off of STD 141; P/U CMT head, M/U to TD and string. CBU @ 10795'; max gas observed = 1811 units; pumping @ 100 GPM with 450 PSI; TQ=2-2.5k. PJSM: Cementing; SLB pump 5 BBLS of water.PT lines to 5000 PSI;bleed down,SLB start batching up;pump 35 BBLS of mud push with rig pumps;SLB pump 70 BBLS of 15.3 PPG easy block CMT,with 1 PPB CEM/NET;drop wiper dart;SLB chase with 5 BBLS of water, then 113.5 BBLS of rig mud; dart latched @ 98 BBLS away; plug bumped @ 118.5 BBLS away; increase PSI 500 over FCP, hold for 5 min; check floats. 1.5 BBLS bled back; pressure up to 3000 and hold, slack off to 100k; pressure up to 4700, slack off to 90k; pulled free. UD CMT head and equipment.Set liner packer and hanger;R/U test chart,pressure up backside to 2100 PSI for 5 min.Un-sting from hanger; circulate mud push and CMT out of hole, 30 BBLS of CMT back to surface. May 20, 2013: Drop nerf ball; CIRC DP VOL x 1.5 @130 GPM, 580 PSI, flow check (static). POOH from 9372'to 9058', pump 15 BBL 12.3 PPG dry job; continue POOH from 9058' to 1641' U-52 D-51; Continue POOH from 1641';UD DP in pipe shed;UD X/O,liner hanger running tool.Clear and clean rig floor;P/U CMT head from pipe shed;break all pups,X/O and UD same;drift 45 JTS 2 7/8"SLH-90; R/D M/U rig tongs; R/U Weatherford double stack power tongs;bring to floor via beaver slide: 2 7/8"elevators, slips, FOSV, DART valve. Break 3.65"bit,bit sub,X/O off 2.875"scraper;M/U bit;bit sub;X/O to 1 JT 2.875"SLH-90 DP.Single in hole with 45 JTS of 2 7/8" work string. Put 2 7/8" x 3 Y" if XO on top of last JT in slips, and TQ with Weatherford tongs; R/D Weatherford equipment; change elevators; hang rig tongs back up. Latched up 1s` STD of 4"DP;put 3'/z"if X HT-38 XO on BTM of STD and spin up on other XO in stump;went to TQ 3'/z' IF connection, got to about 9000 ft/lbs and the 2 7/8"stump broke off @ the hard band; it was partially rusted through.Wait on Baker fishing tools; P/U JT of 4"DP;install 3'/2"IF x HT-38 XO on BTM of JT.M/U spear on BTM of 4"JT hanging; M/U spear to broke stump in slips; P/U string and set slips higher and secure string. Wait on Weatherford to UD all 45 JTS of 2 7/8"work string. UD 45 JTS of 2 7/8"work string in pipe shed; break out bit, bit sub&XO together.Wait for new string of 2 7/8"Weatherford pipe;SIMOPS;clean;service DW,TD, blocks,crown, &cleaning mud pits. Offload truck with new 2 7/8"work string;strap and drift in pipe shed. RIH;single in with 2 7/8"SLH-90; M/U bit, bit sub&XO to bottom of 1st JT;Continue picking up 2 7/8" work string. May 21, 2013: Continue to run in hole with 2-7/8" SLH-90 drill pipe from 623 ft to 1418 ft; make up crossovers; rig down Weatherford power tongs and change out elevators; continue to RIH from 1418 ft to 9338 ft with 4"drill pipe; rig up head pin,tee,chicksen,sensator,cement hose and test casing to 3000 psi for 30 minutes—good test. CANRIG released from responsibilities at 0800 hrs. 8 CANRIG H Hilcorp Alaeka,LLC SCU 41A-04 3 GEOLOGICAL DATA 3.1 Lithostratiaraphy Prognosed tops were provided by Hilcorp geologist Kevin Eastham. PROGNOSED OBSERVED FORMATION MD TVD SSTVD MD TVD SSTVD (ft) (ft) (ft) (ft) (ft) (ft) Tyonek G2 10175 10166 -9974 10,170 10,155 -9,963 HKT 10263 10250 -10058 10,253 10,234 -10,042 Hemlock H3 10331 10313 -10121 10,335 10,312 -10,120 H6T -- -- -- 10,417 10,389 -10,197 Hemlock H7 10456 10430 -10238 10,442 10,413 -10,221 Hemlock H10 10561 10528 -10336 10,553 10,518 -10,326 H11ST -- -- -- 10,668 10,626 -10,434 Hemlock H12 10695 10653 -10461 -- -- -- Hemlock H13 10757 10711 -10519 10,751 10,705 -10,513 Hemlock H15 10857 10804 -10612 -- -- -- West Foreland 10985 10924 -10732 -- -- -- TD 10350 11266 -11074 -- -- -- 9 CANRIG Hiloorp Alaska,LLC SCU 41A-04 3.2 Litholooic Details Tuffaceous Claystone(9595'-9660') = medium light gray to light gray;soft;poor induration; mushy, pasty; pulverulent in part;no definable fracture or cuttings habit;dull;non to slightly gritty and abrasive with increased lower very fine sand; sand locally abundant; grades towards a very arenaceous claystone/ argillaceous sandstone;trace thinly interbedded carbonaceous shale/sublithic coal. Tuffaceous Sandstone,Sandstone(9660'-9720')=light gray to very light gray,grayish white;very fine grain; bimodal subrounded to rounded,well indurated in tuffaceous/ash matrix;subrounded to subangular in cleaner sandstone; 60-80%quartz;secondary components of feldspars, mafic minerals,greenstones; note pebble/ cobble fragments at bottom of interval; NSOFC. Tuffaceous Siltstone, Tuffaceous Sandstone / Sand (9720'-9810') = tuffaceous siltstone: moderate yellowish brown to brownish gray;poor to moderate induration;crumbly;smooth to silty texture;waxy luster; tuffaceous sandstone / sand: light gray to medium light gray; lower medium to upper medium grains; subangular to subrounded; well sorted; poorly consolidated; tuff matrix supported; 90% quartz, trace greenstones and lithics; sand content increases at bottom. Tuffaceous Siltstone(9810'-9840')=light gray to medium light gray;soft;poorly indurated;crumbly tenacity; smooth to gritty;waxy to dull luster. Tuffaceous Sandstone, Sandy Tuff (9840'-9900') = very light gray to medium gray with white tuff hues; lower very fine to upper fine grains; low to moderate sphericity; angular to subrounded; moderately sorted; poorly to moderately consolidated;tuff matrix supported;tuffaceous sandstone grains fine toward bottom and loose sands decrease. Tuffaceous Sandstone (9900'-10020') = light gray to very light gray generally with grayish white to white matrix;very fine grain;subrounded,subangular in part;subdiscoidal,rarely subprismoidal;moderate to locally well sorted; varies from grain supported to matrix supported with tuffaceous, ashy, devitrified component; quartz dominant with locally abundant medium dark gray to grayish black lithics creating a slightly salt and pepper appearance;greenstones more common in more coarse conglomeratic sands;locally abundant mafic minerals; generally no visible porosity, less than 10% of sandstone with fair porosity; note localized well rounded pebbles/cobble fragments with high impact fracture; NSOFC. Tuffaceous Sandstone,Occasional Conglomeratic Sand,Conglomerate(10020'-10120')=medium light gray to light gray with grayish white to white ash component; dominantly upper fine to lower medium grain, upper medium grain common;subrounded to subangular;subprismoidal and subdiscoidal;fair to moderate sorting; poorly consolidated with abundant ash matrix, occasionally well cemented; siliceous to slightly calcareous;fair porosity in part,decreasing proportionately with increase matrix component;dominantly white to very light gray opaque,translucent to transparent quartz;dark gray to grayish black,feldspars,greenstone lithics;note localized pebble/cobble fragments;NO VISIBLE STAIN;NO ODOR;TRACE UP TO 30%DULL YELLOW ORANGE TO BRIGHT YELLOW WHITE FLUORESCENCE;IMMEDIATE MILKY WHITE CUT;NO VISIBLE CUT OR RESIDUAL RING;WHITE TO MILKY WHITE FLUORESCENT RING. Sand (10130'-10220') = unconsolidated; upper very fine grain; angular to subangular; prismoidal;very well sorted; 95% translucent to transparent quartz and volcanic glass clasts; minor secondary mafic minerals; overall sample appears dark pale orange to light pale yellowish brown; 95% sand, 5% conglomerate and pebble fragments; NSOFC. 10 CANRIG Her ni,aka,LL SCU 41A-04 Tuffaceous Sandstone,Sand,Tuffaceous Siltstone(10220'-10370')=medium light gray to light gray with grayish white to white matrix;upper to lower very fine grain;subrounded;subdiscoidal;moderate sorting;60- 70% milky white to translucent quartz, with abundant dark gray to grayish black clasts, minor mafics, rare greenstone;very ashy/argillaceous matrix;poor visible porosity;sublithic arenite to arenaceous'ash-stone'; note thinly interbedded/ interfingered dark grayish orange to light brown medium grain subrounded subprismoidal/ subdiscoidal loose clasts(?) becoming dominant by 10310'md; NO STAIN OR ODOR; LOCALLY ABUNDANT BRIGHT YELLOW TO YELLOWISH WHITE SAMPLE FLUORESCENCE; IMMEDIATE BURST WITH FAST STREAM MILKY WHITE FLUORESCENT CUT; MILKY WHITE FLUORESCENT RESIDUAL RING; NO VISIBLE RESIDUE RING. Tuffaceous Sandstone, Loose Sand (10370'-10530') =overall very light gray to light gray with abundant grayish white to white tuffaceous/ash matrix; predominantly lower very fine, upper very fine grain common; subrounded;subdiscoidal;well to moderate sorting;interval varies 40-70%poorly consolidated/60-30%loose or disaggregated sand; noncalcareous; matrix is tuff to devitrified volcanics, ash, occasional vitreous components; dominantly translucent and transparent quartz, volcanic glass clasts, feldspars and locally abundant mafic minerals; note localized very fine glass shards; note occasional light gray subwaxy tuff; interval varies from a sublithic arenite to an'ash-stone'with significant quartz component;no visible porosity; NO OIL STAIN;SLIGHT HYDROCARBON ODOR AND SHEEN ON UNPROCESSED SAMPLES AT 10460' AND BEYOND;YELLOW ORANGE TO YELLOW SAMPLE FLUORESCENCE;SAMPLES BRIGHTEN WITH MODERATE LIGHT MILKY TO YELLOW STREAM CUT; MILKY TO WHITE FLUORESCENT RING; NO VISIBLE RESIDUE. Tuffaceous Sandstone (10530'-10570') = medium light gray to light gray with grayish white to white ash matrix;upper very fine grain;subrounded;subdiscoidal;well sorted;quartz dominant sublithic arenite to'ash- stone';very soft; no visible porosity; noncalcareous; note localized pebble fragments; NSOFC. Sand(10570'-10630')=very light gray to light gray and white translucent and opaque loose grains;upper fine to upper coarse;very low to high sphericity; subrounded to angular; very poorly sorted;dominated by 85% quartz grains; minor tuffaceous sandstone and tuffaceous siltstone with trace conglomerate; OIL SHEEN SEEN AT SHAKERS;NO STAIN;MODERATE TO STRONG ODOR;DULL ORANGE TO YELLOW SAMPLE FLUORESCENCE; IMMEDIATE STRONG MILKY-WHITE TO MILKY-YELLOW CUT FLUORESCENCE; ORANGE TO YELLOW FLUORESCENT RING; NO VISIBLE RESIDUAL RING. Tuffaceous Siltstone(10630'-10660')=medium light gray and medium gray to brownish gray;soft to easily friable;brittle; silty to gritty; earthy to greasy luster; mushy to pasty. Sand (10660'-10680') = very light gray to light gray translucent grains; lower fine to lower medium; high sphericity; rounded to subrounded; well sorted; 90% quartz grains with minor tuff; NO STAIN; NO ODOR; ORANGE TO YELLOW ORANGE SAMPLE FLUORESCENCE; MODERATE STRONG YELLOW-WHITE CUT FLUORESCENCE;YELLOW-WHITE FLUORESCENT RING; NO VISIBLE RESIDUAL RING. Tuffaceous Sandstone (10660'-10807') = interval varies from 10-40% loose sand, 90-60% poorly consolidated sandstone;overall grayish white to white,very light to medium light gray; upper very fine grain, rounded to subrounded;subdiscoidal;well to moderate sorting;translucent and transparent quartz dominant, prominent mafic minerals,localized medium dark gray to grayish black lithics;note occasional biotite;vitreous and devitrified ash and altered tuff matrix; note abundant volcanic glass clasts and very fine glass shards; grains suspended and well entrained as a sublithic arenite to an 'ash-stone'; NO VISIBLE OIL STAIN; NO ODOR; <5% TO 95% BRIGHT YELLOW TO YELLOWISH ORANGE FLUORESCENCE; VERY SLOW, WEAK PALE YELLOW FLUORESCENT CUT; FEINT WHITE FLUORESCENT RING; NO VISIBLE RESIDUE. 11 CANRIG H Hikorp Aleeka,LLC SCU 41A-04 3.3 Connection Gases 50 units =1%Methane Equivalent Measured Subsea Total Gas over Measured Subsea Total Gas over Depth Vertical Depth background Depth Vertical Depth background (feet) (feet) (units) (feet) (feet) (units) 9772 -9578 1290 10397 -10178 308 9835 -9641 1514 10461 -10239 277 9899 -9703 1337 10524 -10298 197 9962 -9764 155 10585 -10356 368 10025 -9825 285 10648 -10449 277 10088 -9885 330 10712 -10476 252 10333 -10118 379 10775 -10538 260 3.4 Trip Gases, 50 units =1%Methane E.uivalent Measured Subsea Total Trip to Maximum Pumps Off Depth Vertical Depth (feet) Gas Time (feet) (feet) (Units) (hours) 9625 -9432 Surface-Bit Trip 133 23.1 9704 -9511 Down time *as 2572 2.8 9719 -9526 Down time gas 366 0.2 10151 -9945 Down time gas 864 4.8 10216 -10007 Short trip to top BHA 866 28.6 10228 -10018 Surface-Bit Trip 2173 27.7 10276 -10064 Down time gas 438 4.8 10302 -10088 Down time *as 91 0.4 10386 -10168 Down time gas 405 0.2 10807 -10566 _ Trip in with 4-1/2"liner 1811 50.7 12 CANRIG Hikarp Marko,LLC SCU 41A-04 3.5 Semolina Program/Sample Dispatch Set Type/Purpose Frequency* Interval Dispatched to Hilcorp Alaska LLC 3800 Centerpoint Drive A Washed and dried 30 ft 9000 ft—9990 ft Suite #100 reference samples 10 ft 9990 ft—10807 ft Anchorage AK 99503 Attn.: Debra Oudean (907)777-8337 Hilcorp Alaska LLC 3800 Centerpoint Drive B Washed and dried 30 ft 9000 ft—9990 ft Suite #100 reference samples 10 ft 9990 ft—10807 ft Anchorage AK 99503 Attn.:Debra Oudean (907)777-8337 3 CAN 1G H Hiloorp Alaska,LLC SCU 41A-04 4 DRILLING DATA 4.1 Directional Survey Data Measured Incl. Azim. True Northing Easting Vertical Dogleg Depth (°) (°) Vertical (ft) (ft) Section Rate (ft) Depth (ft,) (ft) (°/100ft) TI 9591.00 0.36 288.49 9590.50 -9.46 6.38 9770.00 7.84 215.35 9768.93 -19.25 -1.23 17.62 4.33 9831.00 10.60 197.32 9829.15 -28.01 -5.31 24.41 6.50 9896.00 13.35 184.80 9892.74 -41.20 -7.72 35.93 5.80 9956.00 14.52 176.12 9950.98 -55.60 -7.79 49.42 3.99 10020.00 16.08 168.53 10012.72 -72.30 -5.49 65.87 3.96 10081.00 17.84 162.71 10071.07 -89.50 -1.03 83.55 4.01 10141.00 18.66 156.57 10128.05 -107.09 5.52 102.31 3.48 10203.00 18.45 155.96 10186.83 -125.15 13.46 122.01 0.46 10265.00 18.75 155.68 10245.59 -143.19 21.56 141.74 0.50 10334.00 18.76 155.47 10310.95 -163.34 30.71 163.82 0.15 10393.00 19.29 154.36 10366.74 -180.72 38.85 182.94 1.22 10454.00 19.15 154.01 10424.33 -198.80 47.59 202.93 __0.30 10516.00 19.35 153.91 10482.87 -217.16 56.57 223.27 0.33 10579.00 19.18 154.75 10542.34 -235.90 65.57 243.97 0.52 10643.00 19.23 154.82 10602.78 -254.94 74.54 264.95 0.09 10706.00 18.92 155.43 10662.32 -273.62 83.20 285.47 0.59 p. 10807.00 18.92 155.43 p. 10757.86 -304.09 97.14 318.92 0.89 14 CANRIG LU I M 5 z 0 I- 6 g )L IL z a`0i 0 V T X X C'3 IL¢° v z � U o U r N '1a N 0 d Q O Q N N ri)2 rn < CC N 'NS m y Q 0Y ° LCi 6a L In CO 9 O t CO CO Q CC w W M 4 rn CO G N N et al a p y aQ' pro 1 lC d CO O) e-U 0 •L COO ..,..� R u) 8 i Q. 7 b 0 0 0 Q O N Si O N a) O co N Q CA O) O 0 0 0 Q COO ref r.1- 7 ~ co O Cn 0 In O � r C XO x(O LL Ll T 0.Z OD Or Or- >y 0 1 co an co I- C7I 0N . O N. Y 0 0 0 cc 0 0 0 2 I I I a L o m 0) 'CO CO CO CO CC r _ CO . N m m N N 4 CO Al J 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 V LA OD OD CO �OODNCOCDCONNNOOO J 0000000000000000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 co O N 0 0 0 0 0 0 0 0 0 0 0 0 0 0 E r C,.) 0 0 O) O O 0) r ca j) N O N N O ... M M M cc:F\ M N M N M N M M M M '— O O O LO O O O Ln 0 0 0 L0 O O ll) Y r r r r r r L() cc i3 N r r r M 0 C Q d O O O O O O O O O O O O O O O O .5 N N 0_ C 22 o 1 _ Tr 1\ O up O O U0 00 N f� f� Th O O O O 0)w cs C. 0060) 0) 0) 0) COO) 0) 60060000O) CO } II = II cc 11 0- O as m .0 t 0000000000000000 } � U 2 C, d CV N N N N N N N N N N N N N N N .... o LO LO LC) LO L() LO LC) LO L0 LO LO 0 0 L() LL) L() CI) e r N N r r r N N N N N L[) LO N N N `-' 0000000000000000 >, N CO - COCOCO000Lf) L() 000000 O C O O O O 00 f� O CO CO I� N N N y *' co co 00 co co co co co co co co co co co co co 5 cs cn R 0 c 0000000000000000 00 - 0000000000000000 'p1- •- , CZ •o W ... O r r r N I� CO N CO CO CO CO CO CO f� 0 C No co co co O T Oj O r r r 0 0 0 0 0 0 II �� t►� 0 y Q o u 0 Y iX ? U J Cj M0000000NOr00N (OCOMCO 00 82 T tq co N- 0) I. T T r 00 CO 00 N. p Zo d CO OO CD CO CO 0 — — 1- CO I- LO V to 000) 0) •— 00MLoLo - -- Cl) 0) CO It) N- L[) Lf) It) co r, r- CEO CD L() L() L() ; J C 0 0) N U CL 00 CO 0) r 0) O d• O O M M 0) CO CO N 0) c >- T r r N r N N N N N N r r r N r 11- as II LL u) II it N r N Ll7 co I• CO M N N r N r cn J -0 Cl. r T T N > U- CD N a 't CO 't N L\ CO CO r CO 0) CO CO L() LO 1- O U co O O O O O O O O O O O co O O r up up Ln O N 00 O N N N r r r r CO Y M Q 000 � ro 0r �_ ED' a) m `� CO Cn (0 O 7 j .0 N a) co a) co up L() co 1- N- L\ N ++ 0) -_ w' .-. Ln Lf) CO co N N N N In LC) N O O O O ,0(NI C-w N N N N M M 00 00 00 00 > O 0 mW f� v OM00000000000000 i II � II '' P. N j o O 0 Q200 U ca T co co C) CO CO CO) CO CO C") CO) CO CO CO CO CO CO 41 03 I— CC 15 -C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 7; N N N N N N N N N N N N N N N N 3 U2 ci L0 CON CO 001- NM � LOCON000) 0 C 0 O O_ O 0 . . . . . . T T T T N c LO Ln LO LC) Ln LO LO LO LO LO LO Ln LO LO LO 10 co Hilcorp Alaska,LLC SCU 24-15 5 DAILY REPORTS 17 CANRIG H Hilcorp Alamka,LLC SCU 24-15 6 SHOW REPORTS 18 CANRIG Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 cA1JRIG REPORT FOR:Lesli,Greco,Grubb, Pederson DATE: May 5,2013 DEPTH 9625' PRESENT OPERATION: RIH w/whipstock TIME: 2359 hrs YESTERDAY 9625' 24 HOUR FOOTAGE 0' CASING INFORMATION 7"@ 9625' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ AMPS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH 9625'MD/9625'TVD MW 10.50 VIS 44 PV 12 YP 18 Gels 6/7/8 FL 4.8 CL- 31000 FC 1/2 SOL 8.0 SD 0.15 OIL 0.0/89.6 MBT 2.0 pH 8.4 Ca+ 400 CCI 0.10 MWD SUMMARY INTERVAL TO TOOLS No MWD tools in hole this period. GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) @ @ CONNECTION GAS HIGH ETHANE(C-2) @ @ CONNECTION GAS:AVG PROPANE(C-3) @ @ CONNECTION GAS:CURRENT BUTANE(C-4) @ @ CURRENT AVG BACKGROUND PENTANE(C-5) @ @ HYDROCARBON SHOWS No new footage drilled this period. INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY No new footage drilled this period. PRESENT LITHOLOGY May 05,2013:Canrig representative Larry Resch completes rig up operations.Continue tripping in hole with 4"drill pipe from 1500 ft to top of cement at 9631 ft;pressure test casing to 3000 psi for 30 minutes;circulate through kill and DAILY drill pipe,shut top rams,HCR-KILL and 2"low torque to isolate for test—good test;monitor outer annulus during test; ACTIVITY blow down associated equipment;pick up joint#288 and run in hole to 9629`MD;pump at 6.5 BPM to displace brine SUMMARY with 10.50 ppg EZ-Mud with 6%KCI;surface to bit 3490 stks,bit to surface 6981 stks,surface to surface 10471 stks, 392 psi increasing to 1180 psi at end of displacement;trip out of hole from 9625 ft to surface;pick up/make up whipstock assembly per Baker Rep and HWDP to 642 ft.Currently servicing rig at report time. CANRIG PERSONNEL ON BOARD: Resch, Farrell_DAILY COST: $2460 REPORT BY: Larry Resch Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT x SCU 41A-04 GA1iIG REPORT FOR:Leslie,Grubb,Greco, Pederson DATE: May 06,2013 DEPTH 9625' PRESENT OPERATION: POOH with mill casing cutter TIME: 2359 hrs YESTERDAY 9591' 24 HOUR FOOTAGE 34' CASING INFORMATION 7"@ 9591' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED Mill#1 6" Mill casing cutter 10127231 9591' 9625' 34' 7.6 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 18.4 @ 9618 1.7 @ 9595 7.0 13.3 FT/HR SURFACE TORQUE 5922 @ 9610 2799 @ 9622 4309.2 3842 AMPS WEIGHT ON BIT 25 @ 9619 6 @ 9593 18.2 24.80000 KLBS ROTARY RPM 89 @ 9605 77 @ 9594 81.4 86 RPM PUMP PRESSURE 1519 @ 9617 1227 @ 9597 1325.3 1472 PSI DRILLING FLUIDS REPORT DEPTH 9625/9625 MW 10.50 VIS 46 PV 11 YP 19 Gels 5/6/7 FL 4.8 CL- 32000 FC 1/2 SOL 8.1 SD 0.25 OIL 0.0/89.4 MBT 2.0 pH 8.7 Ca+ 400 CCI 0.1 MWD SUMMARY INTERVAL TO TOOLS No smart iron in hole this period. GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 6 @ 9619 0 @ 3.4 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 143 @ 9593 0 @ 0 4.2 CONNECTION GAS HIGH ETHANE(C-2) 0 @ @ CONNECTION GAS:AVG PROPANE(C-3) 0 @ @ CONNECTION GAS:CURRENT BUTANE(C-4) 0 @ @ CURRENT AVG BACKGROUND n/a PENTANE(C-5) 0 @ @ HYDROCARBON SHOWS None INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY PRESENT LITHOLOGY May 06,2013:Continue to trip in from 1594'MD to 9606'MD. Rig up wire line to orient whipstock;run gyro data down DAILY string to latch into UBHO.Orient string to 158*.Confirm orientation of whipstock,wireline/gyro data POOH;rig down ACTIVITY wireline.Run wireline logs;confirm orientation of whipstock;R/D wireliners.Set whipstock @ 9591';drill window from SUMMARY 9591'to 9602';continue milling window from 9602'to 9628'.Circulate 19.5 BBL sweep STS 11400 stks;245 GPM; Rig up and FIT to 13.5 EQ MW;rig down; 1502 PSI chart;5 min;good test. POOH from 9625'to 9000' UWT 152k; SOW 149k CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Larry Resch Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT 41A-04 RIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 07,2013 DEPTH 9627' PRESENT OPERATION: R/U wireline and orient tool face TIME: 2359 hrs YESTERDAY 9625' 24 HOUR FOOTAGE 2' CASING INFORMATION 7"@ 9591' SURVEY DATA DEPTH INCLINATION AZIMUTH VERTICAL DEPTH BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6 DP505FX/HCC 70287861 5x11 9625' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 117.4 @ 9627' 13.4 @ 9625' 65.4 117.4 FT/HR SURFACE TORQUE 3842 @ 9625' 1841 @ 9626' 3882.5 2082 AMPS WEIGHT ON BIT 24 @ 9625' 2 @ 9626' 15.2 3.4 KLBS ROTARY RPM 86 @ 9625' 20 @ 9627' 65.5 20 RPM PUMP PRESSURE 1472 @ 9625' 1317 @ 9626' 2076.5 1364 PSI DRILLING FLUIDS REPORT DEPTH 9627'/9627' MW 10.5 VIS 44 PV 12 YP 19 Gels 7/8/9 FL 4.6 CL- 30000 FC 1/2 SOL 8.1 SD 0.25 OIL 0.0/89.6 MBT 2.0 pH 9.9 Ca+ 360 CCI 0.4 MWD SUMMARY INTERVAL 9625' TO 9627' TOOLS Gamma, ECD, Resistivity, Directional, Density,Caliper,Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 136 @ 9626' 6 @ 9625' 84.7 TRIP GAS 136 U CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 20529 @ 9626' 20529 @ 9626' 10264.5 CONNECTION GAS HIGH ETHANE(C-2) 48 @ 9626' 48 @ 9626' 24.0 CONNECTION GAS:AVG PROPANE(C-3) @ @ CONNECTION GAS:CURRENT BUTANE(C-4) @ @ CURRENT AVG BACKGROUND 6 U PENTANE(C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Claystone,Tuffaceous Sandstone,Minor Tuffaceous Siltstone. PRESENT LITHOLOGY Tuffaceous Sandstone Blow down kill line;monitor well.Continue pulling out of hole from 9000'MD to 8100'MD;POW=151k;SOW= 136k. Monitor well;pump dry job; 19 BBLS of 11.7 PPG.Continue trip out of hole from 8100'MD to 97'MD;POW=138k; SOW 136k.Break down BHA according to Baker hand;window mill=1/16"under gauge;upper and lower string mill in full gauge.Jet stack;pull out of hole;function BOPs;jet stack second time.Calibrate blocks for rig sense;re-calibrate DAILY with Baker-MWD. R/U to pick up BHA. Pick up BHA as per DD;TO and scribed to UBHO;POW=30k. Download tool; ACTIVITY set 2 nuke sources;UWT 44k;SOW 44k;shallow well test;208 GPM @ 730 PSI;to 781'MD.Single in the hole from SUMMARY pipe shed;50 JTS;from 781'MD to 1574'MD;UWT 67k;SOW 64k;Fill pipe;220 strokes to fill. RIH 1574'MD to 6000' MD;UWT 113k;SOW 108k. RIH from 6000'MD to 9585'MD;UWT 166k;SOW 160k;ROT 156k.Reaming out under gauge hole from 9608'MD to 9628'MD; 1.8 TQ;20 RPM; 1400 PSI; 166k;.Circulate BUS 7200+. Rack back ST 141; P/U single not in tally.Wireline logs;R/U side entry sub;M/U wireline sheave and side entry sub per wireliners;run tool to bottom. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell _DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska, LLC Swanson River Field DAILY WELLSITE REPORT ANR1G SCU 41A-04 REPORT FOR:Leslie,Grubb,Greco, Prederson DATE: May 08,2013 DEPTH 9868' PRESENT OPERATION: Drilling ahead TIME: 2359 hrs YESTERDAY 9627' 24 HOUR FOOTAGE 241' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA 9770' 7.84 215.35 9768.93 BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11 9625' 243' 12.1 hrs DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 302.9 @ 9715' 0.4 @ 9629' 42.3 48.10833 FT/HR SURFACE TORQUE 4922 @ 9771' 80 @ 9805' 1053.1 0.00000 AMPS WEIGHT ON BIT 21 @ 9671' 3 @ 9627' 11.4 10.50000 KLBS ROTARY RPM 45 @ 9706' 1 @ 9818' 11.1 0.00000 RPM PUMP PRESSURE 2253 @ 9770' 1364 @ 9627' 1880.1 2023.00000 PSI DRILLING FLUIDS REPORT DEPTH 9868' MW 11.0 VIS 44 PV 14 YP 21 Gels 5/6/7 FL 4.8 CL- 30,000 FC 1/2 SOL 10.1 SD 0.15 OIL 0.0/87.6 MBT 2.0 pH 9.5 Ca+ 440 CCI 0.15 MWD SUMMARY INTERVAL 9625' TO 9868' TOOLS Gamma,ECD, Resistivity, Directional,Density,Caliper,Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 2576 @ 9704' 0 @ 9685' 62.7 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY 16u METHANE(C-1) 503954 @ 9704' 71 @ 9685' 11579.8 CONNECTION GAS HIGH 2500u ETHANE(C-2) 1257 @ 9704' 0 @ 9825' 39.6 CONNECTION GAS:AVG 1768u PROPANE(C-3) 414 @ 9704' 0 @ 9722' 8.7 CONNECTION GAS:CURRENT 1500u BUTANE(C-4) 41 @ 9720' 0 @ 9722' 0.6 CURRENT AVG BACKGROUND 10u PENTANE(C-5) 0 @ 9868' 0 @ 9868' 0.0 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Silstone,Tuffaceous Claystone,and Sand PRESENT LITHOLOGY Tuffaceous Sandstone and loose Sands Run gyro data to orient string;establish tool face @ 218*.Put plug in port of wire line entry sub;pressure test to 250 GPM;1880 PSI.Kelly up stand 141;start sliding from 9627'MD to 9633'MD;GPM=210;pump pressure off=1460; pump pressure on= 1580;WOB=2-4;PUW=165k;SOW=159k; POW=155k.Re-initiate gyro every hour-pick up 5' off bottom and turn pumps off;continue drilling from 9633'MD to 9655'MD.Continue drilling per DD from 9655'MD to DAILY 9704'MD;PUW=166k;SOW=155k;POW=159k;GPM=240;pump pressure on=1866;pump pressure off=1820; ACTIVITY WOB 2-5k;bit=6 hrs;motor=3.2 hrs;jars=0;AST=6 hrs;ADT=6 hrs;ART=0 hrs.Trip out from 9704'MD to 9613' SUMMARY MD;PUW=166k;SOW=155k;rack back stand 142&141.POOH with gyro;R/D wireliners.Drill from 9704'MD to 9715'MD;shut well in.Circulate through choke;weight up mud to 10.8 lbs/gal both ways;3 BBUmin 870 PSI W 400 PSI back pressure at start;200 PSI back pressure at end of STS strokes. Drill from 9715'MD to 9755'MD;250 GPM @ 1933 PSI off;2140 PSI on;5k on bit;40 RPM;UWT 166k;SOW 162k;ROT 158k.Continue drilling from 9755'MD to 9868'MD; UWT= 168k; 162k SOW;158 ROT;242 GPM; 1850 PSI off;2080 PSI on;ROT 40 RPM; 1.9 TQ off. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 09,2013 DEPTH 10181' PRESENT OPERATION: Lost circulation;building mud volume TIME: 2359 hrs YESTERDAY 9868' 24 HOUR FOOTAGE 313' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 9896' 13.35 184.80 9892.74' SURVEY DATA 9956' 14.52 176.12 9950.98' 10020' 16.08 168.53 10012.71' 10081' 17.84 162.71 10071.06' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11 9625' 556' 23.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 369.8 @ 9878' 0.5 @ 10045' 43.3 39 FT/HR SURFACE TORQUE 6853 @ 10180' 5 @ 9984' 1791.8 3780 AMPS WEIGHT ON BIT 19 @ 9873' 2 @ 10156' 8.5 8.1 KLBS ROTARY RPM 56 @ 10170' 2 @ 9955' 20.4 50 RPM PUMP PRESSURE 2698 @ 10079' 1568 @ 10181' 2192.4 1568 PSI DRILLING FLUIDS REPORT DEPTH 10181' MW 11.2 VIS 42 PV 15 YP 19 Gels 5/6/7 FL 4.8 FC 1/2 SOL 11.2 NAF/W 0.0/86.6 SD 0.15 MBT 2.0 pH 9.0 ALK 0.10 Cl- 29,000 Ca+ 400 MWD SUMMARY INTERVAL 9625' TO 10181' TOOLS Gamma, ECD, Resistivity,Directional, Density,Caliper, Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 75 @ 9899' 0 @ 9947' 10.1 TRIP GAS N/A CUTTING GAS @ @ WIPER GAS N/A CHROMATOGRAPHY(ppm) SURVEY N/A METHANE(C-1) 14608 @ 9899' 10 @ 9947' 1660.5 CONNECTION GAS HIGH 1337 ETHANE(C-2) 1291 @ 10149' 0 @ 9947' 48.9 CONNECTION GAS:AVG 527 PROPANE(C-3) 365 @ 10149' 0 @ 9947' 23.1 CONNECTION GAS:CURRENT 0 BUTANE(C-4) 354 @ 10117' 0 @ 10024' 19.4 CURRENT AVG BACKGROUND 10 PENTANE(C-5) 172 @ 10125' 0 @ 10056' 8.7 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone, minor Tuff and Coal PRESENT LITHOLOGY N/A-Lost circulation Continue drilling from 9869'MD to 9938'MD;PUW=168k;SOW=158k;RTW= 155k;GPM=254;pump pressure on= 2120;pump pressure off=1980;WOB=2-5k;RPM 40;TQ on=3k;TQ off=1.9k.Well was flowing at 5 BBLS/hr,increase MW from 11.0 to 11.2.Continue drilling from 9938'MD to 10048'MD;PUW=171k;SOW=159k;RTW=158k;GPM= 250k;pump pressure on=2340;pump pressure off=1950;WOB=5k;RPM=40;TQ on=3.2k;TO off=2.2k;Continue DAILY drilling from 10048'MD to 10156'MD;UWT=168k;SOW=160k;ROT= 157k;TQ off=1.9;TQ on=3.3;GPM=250; ACTIVITY pump pressure on=2250;pump pressure off= 1950.Continue drilling ahead from 10156'MD to 10182'MD;UWT=170k; SUMMARY SOW=162k;ROT=157k;GPM=250;pump pressure on=2350;pump pressure off=1950;40 RPM.Lost circulation; POOH to shoe at 9572'MD;pump LCM pill through kill line;chased with 14 BBL good mud.Pump 20 lb/BBL LCM pill down DP;chased with 102 BBL mud to spot pill of bit;filled backside with trip tank. Fill hole with TT;build volume;squeeze 16.62 BBL into formation;bag closed;pumped through kill line.ADT=4.4 hrs;ART=1.3 hrs;AST=3.1 hrs;BIT=23.5 hrs;JAR =3.6 hrs;MOTOR=38.7 hrs.656 BBL lost. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANRIG REPORT FOR:Leslie,Grubb,Greco, Pederson DATE: May 10,2013 DEPTH 10229' PRESENT OPERATION: Building mud volume TIME: 2359 hrs YESTERDAY 10181' 24 HOUR FOOTAGE 48' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11 /0.464 9625' 604' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 203.0 @ 10186' 1.2 @ 10228' 71.3 23.5 FT/HR SURFACE TORQUE 7619 @ 10190' 2473 @ 10228' 4292.0 3327 FT-LBS WEIGHT ON BIT 19 @ 10218' 2 @ 10193' 6.6 2.6 KLBS ROTARY RPM 50 @ 10181' 33 @ 10216' 40.7 42 RPM PUMP PRESSURE 2139 @ 10190' 1267 @ 10182' 1804.1 1415 PSI DRILLING FLUIDS REPORT DEPTH MD/TVD 10229'/10,211' MW 10.8 VIS 47 PV 14 YP 20 Gels 5/6/7 FL 5.2 FC 1/2 SOL 9.7 NAF/W 0.0/88.0 SD 0.15 MBT 2.0 pH 9.0 ALK 0.1 CI- 30,000 Ca+ 400 MWD SUMMARY INTERVAL 9625' TO 10229' TOOLS PDC bit on mud motor with Gamma, ECD,Resistivity,Directional, Directional, Density,Caliper,Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 846 @ 10182' 0 @ 10192' 51.7 TRIP GAS N/A CUTTING GAS @ @ WIPER GAS N/A CHROMATOGRAPHY(ppm) SURVEY N/A METHANE(C-1) 99492 @ 10182' 6 @ 10184' 8396.1 CONNECTION GAS HIGH N/A ETHANE(C-2) 3611 @ 10182' 0 @ 10192' 87.5 CONNECTION GAS:AVG N/A PROPANE(C-3) 23 @ 10210' 0 @ 10200' 3.0 CONNECTION GAS:CURRENT N/A BUTANE(C-4) 2486 @ 10182' 0 @ 10192' 52.3 CURRENT AVG BACKGROUND 8 PENTANE(C-5) 1184 @ 10182' 0 @ 10192' 24.9 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor Tuff and Coal PRESENT LITHOLOGY Sand Continue squeezing LCM down back side;pump and additional 30 STKS to maintain 1100 PSI on ANN.;continue batching mud to 11 PPG-390 barrels built.Bleed pressure;open up and monitor TT-gained 3.2 BBLS while monitoring.Shut in ann.-line up to squeeze on back side-33 STKS to pressure up-maintain 1100 PSI on back side while continuing to batch up an additional 100 BBLS of 11 PPG mud.Trip in one stand from 9580'MD to 9641'MD; stage pumps up to 160 GPM;pump pressure=960 PSI;@ 7500 STKS pump pressure=1060 PSI;PUW=160k;SOW 155k;downtime gas observed=846 units @ 7500 STKS.Trip in hole from 9641'MD to 10153'MD;PUW=158k;SOW = 152k.Kelly up stand 150;continue trip from 10153'MD to 10171'MD;set 10k on bit;pick up and wash down to 10182' DAILY MD;RPM=20;GPM=160;pump pressure=1440;TQ=4.4k;continue drilling from 10182'MD to 10192'MD;stage ACTIVITY pumps up to 17 GPM;pumped 3055 STKS=88 BBLS;lost 68 BBLS to hole while pumping on it.Turn off rotary and SUMMARY pumps;P/U of bottom and line up TT;establish loss rate with hole fill pump=1 BBL/min;work pipe to keep from sticking; continue conditioning and batching 11 PPG mud. Pump 48 BBLS of 25 lbs/BBL LCM pill;stage out of bit 5392 total STKS pumped;3718 STKS to chase out of string;@ 1.8 BPM pump pressure=350 PSI;@ 3 BPM pressure=510 PSI, increased to 950 PSI as returns were established.Trip out of hole from 10192'MD to 9579'MD;PUW=173k;.8 BBLS lost during trip.Monitor static loss with hole fill;2.9 BBLS to fill in 10 minutes;shut ann.;Line up to pump down backside. Pumping 5 BBLS at a time-squeezed 85 BBL away;Max pressure=450 PSI. Bleed pressure and open up well;Line up to TT and get a loss rate of 6 BBL/min;Bit=23.7 hrs;Jars=3.7 hrs;Motor=41.6 hrs;ADT=.2 hrs;AST=0 hrs;Max gas observed=846 units;380 BBLS lost from 00:00 to 12:00. Monitor well;check loss rate every 5 minutes. Place bit out of window;9615'MD;pump 2 BBL/min;50%loss. POOH to shoe;circulate over the top of well with hole fill;build volume and LCM pill;trips RIH from 9582'MD to 10150'MD; UWT=170;SOW=160;ROT 160;200 GPM @ PSI off 1980;PSI on 2250;TO off 2.0;TO on 3.4. Drill from 10192'MD to 10228'MD;UWT= 174k;SOW=163k;ROT 160k; TQ on 3.2k;off 2.1k;240 GPM;POOH from 10228'MD to 9588'MD;pulled good.Build volume;chase 42 BBL pill; chase with 35 BBL;monitor loss.Squeeze 5 BBL into formation at a time;wait 5 minutes between;highest PSI observed =546 PSI;building 80 Ib/BBL LCM pill. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell _DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 11,2013 DEPTH 10229' PRESENT OPERATION: RIH with circulating sub TIME:2359 hrs YESTERDAY 10229' 24 HOUR FOOTAGE 0' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA none taken BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11 /0.464 9625' 604' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION N/A @ @ FT/HR SURFACE TORQUE N/A @ @ FT-LBS WEIGHT ON BIT N/A @ @ KLBS ROTARY RPM N/A @ @ RPM PUMP PRESSURE N/A @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11 VIS 58 PV 13 YP 24 Gels 6/8/10 FL 5 FC 1/2 SOL 10.7 NAF/W 0.0/87 SD 0.25 MBT 2.0 pH 8.5 ALK 0.1 Cl- 30,000 Ca+ 220 MWD SUMMARY INTERVAL 9625' TO 10229' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with Gamma,ECD,Resistivity,Directional,Directional, Denisty,Caliper,Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS N/A @ @ TRIP GAS N/A CUTTING GAS N/A @ @ WIPER GAS N/A CHROMATOGRAPHY(ppm) SURVEY N/A METHANE(C-1) N/A @ @ CONNECTION GAS HIGH N/A ETHANE(C-2) N/A @ @ CONNECTION GAS:AVG N/A PROPANE(C-3) N/A @ @ CONNECTION GAS:CURRENT N/A BUTANE(C-4) N/A @ @ CURRENT AVG BACKGROUND 4 U PENTANE(C-5) N/A @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor tuff and coal PRESENT LITHOLOGY Sand Pump 40 BBL,60 PPB LCM(Baraseal,Steal Seal)pill through kill line;SIMOPS;build 130 BBL batches to 10.8 PPG PHPA 6% KCL drilling fluid.Continue to fill hole via trip tank,monitoring losses;28.8 BPH initial loss rate.Close annular preventer, squeeze 20 BBL of 25 BBL LCM pill into formation,initial break down PSI:530 PSI,final-760 PSI,wait 5 mins,PSI up-break down @ 530 PSI.Continue to fill hole via trip tank monitoring losses,28.8 BPH initial loss rate.Close annular preventer, squeeze 20 BBLS of 25 BBL LCM pill into formation,initial break down PSI:530 PSI,Final:760 PSI,wait 5 mins, PSI up— DAILY break down at @ PSI.Continue to fill hole via trip tank monitoring losses,28.8 BPH initial loss rate;final loss rate 12.6 BPH, ACTIVITY 160 BBL loss from 00:00;continue to build 130 BBL batches 10.8 PPG PHPA 6%KCL drilling fluid.Close annular preventer, SUMMARY Squeeze 18 BBLS with 300 PSI staging up to 800 PSI break down PSI,open annular preventer.Continue to fill hole via trip tank monitoring losses,18 BPH initial loss rate;final loss rate 7.2 BPH(15.7 BBL loss).Close annular preventer,squeeze 17 BBLS with 300 PSI staging up to 600 PSI,open annular preventer.Continue to fill hole via trip tank monitoring losses,10.8 BPH initial loss rate;final loss rate 3.6 BPH.POOH from 9582'MD to 8640'U-155 D-150.monitor well;well flowing 5 BBL/Hr: tried pumping;pressure up;bled off PSI;UWT 155 K;POOH from 8640'MD to 781'MD;UWT 44K;gain of 30 BBL while tripping.add circ sub and 2 XO's per baker rep RIH with 2 STDS of DP;drop ball open circ sub;opened @ 1281 PSI.RIH from 900'to 6883';UWT=126K;SOW=122K.Service TD;DW;grease wash pipe,monitor well CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3,260 REPORT BY:John Farrell Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 AJRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 12,2013 DEPTH 10229' PRESENT OPERATION: Breaking down BHA TIME: 23:59 hrs YESTERDAY 10229' 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@ 9551' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA none taken BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11 /0.464 9625' 604' 24.33 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION N/A @ @ FT/HR SURFACE TORQUE N/A @ @ FT-LBS WEIGHT ON BIT N/A @ @ KLBS ROTARY RPM N/A @ @ RPM PUMP PRESSURE N/A @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11.20 VIS 58 PV 17 YP 20 Gels 7/9/10 FL 5.1 FC 1/2 SOL 11.8 NAF/W 0.0/86.0 SD 0.25 MBT 2.0 pH 9.8 ALK 0.55 Cl- 29,000 Ca+ 160 MWD SUMMARY INTERVAL 9625' TO 10229' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with Gamma, ECD, Resistivity,Directional,Density, Caliper, Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS N/A @ @ TRIP GAS N/A CUTTING GAS N/A @ @ WIPER GAS N/A CHROMATOGRAPHY(ppm) SURVEY N/A METHANE(C-1) N/A @ @ CONNECTION GAS HIGH N/A ETHANE(C-2) N/A @ @ CONNECTION GAS:AVG N/A PROPANE(C-3) N/A @ @ CONNECTION GAS:CURRENT N/A BUTANE(C-4) N/A @ @ CURRENT AVG BACKGROUND N/A PENTANE(C-5) N/A @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor Tuff and Coal PRESENT LITHOLOGY Sand RIH from 6883'MD to 9100'(pipe out of balance).K/U;circulate 60 BBL 11.0 PPG mud @ 80 GPM 660 PSI ICP;280 PSI FCP.RIH from 9100'MD to 9537'MD;K/U TD;RIH to 9588'MD U-165,D-160.Circulate @ 9588'MD bit depth;8794'MD circ.sub depth.@ 160 GPM 40 PSI WT up to 11.0 PPG;clean H2O returns @ 6000 STKS(85 BBL total)with 45 BBL diluted mud dumped to R/W;returns to pits with 10.2 PPG mud;continue WT up to 11.0 PPG @ 80 GPM 40 PSI;Max gas DAILY 865 units.Close annular preventer;hold 300 PSI on DP and CSG;bleed off to 115 PSI on DP,30 PSI on CSG;WT up ACTIVITY surface mud system to 11.2 PPG.Circulate through choke with 11.2 PPG kill WT mud @ 80 GPM,560 PSI,250 back PSI. SUMMARY Continue circulating through choke until 11.2 PPG mud around;open up the well.Monitor well;Build and spot pill outside of circ.sub;3577 STKS.TOOH from 9588'MD to 5545'MD;UWT=156k;SOW= 152k;TOOH from 9588'MD to 5545'MD; UWT=156k;SOW=152k;trip from 9588'MD to 5650'MD;UWT=106k;SOW=102k. POOH from 5560'MD to 757'MD; UWT=44k;SOW=44k. POOH with HWDP jar;T smart tools;retrieve nukes;L/D BHA per baker rep;download MWD; depth 111.89'MD. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3,260 REPORT BY:John Farrell Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 13,2013 DEPTH 10229' PRESENT OPERATION:Circulate BU @ 9800' TIME:2359 hrs YESTERDAY 10229' 24 HOUR FOOTAGE 0 CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9625' 604' 24.33 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION N/A @ @ FT/HR SURFACE TORQUE N/A @ @ FT-LBS WEIGHT ON BIT N/A @ @ KLBS ROTARY RPM N/A @ @ RPM PUMP PRESSURE N/A @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD 10229'/10,211' MW 11.2 VIS 51 PV 13 YP 20 Gels 7/9/11 FL 4.8 FC 1/2 SOL 11.2 NAF/W 0.0/86.5 SD 0.25 MBT 2.0 pH 9.2 ALK 0.30 Cl- 31,000 Ca+ 160 MWD SUMMARY INTERVAL 9625' TO 10229' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with Gamma,ECD,Resistivity,Directional,Density,Caliper,Porosity GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS N/A @ @ TRIP GAS N/A CUTTING GAS N/A @ @ WIPER GAS N/A CHROMATOGRAPHY(ppm) SURVEY N/A METHANE(C-1) N/A @ @ CONNECTION GAS HIGH N/A ETHANE(C-2) N/A @ @ CONNECTION GAS:AVG N/A PROPANE(C-3) N/A @ @ CONNECTION GAS:CURRENT N/A BUTANE(C-4) N/A @ @ CURRENT AVG BACKGROUND N/A PENTANE(C-5) N/A @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor Tuff and Coal PRESENT LITHOLOGY Sand Continue to L/D BHA#3:UBHO,filter sub,stop sub,SDN-LWD,BCPM,MWD-ONTRAK,stop sub,2-PNY NMFC,motor,bit;all jets on bit plugged with LCM,could not turn bit sub on motor,not able to drain.Clear and clean rig floor;pull wear bushing;install test plug&4"test JT;R/U to test BOP.Function test:blind rams,top pipe rams and lower pipe rams,test:annular with 4"test JT @ 250 PSI/5 min,2500 PSI/5 min;R/D test equipment;set wear ring 6.125"ID.M/U BHA#4:bit,0.8 deg motor,stab,2-PONY NMFC,MWD,BCPM,stop sub,filter sub;orient motor to MWD, clean and dress all T2 connections.Plug in to MWD,obtain surface electronic test.RIH with NMFC from FRK,3 STDS of HWDP from DRK. DAILY Attempt to shallow pulse test @ 210 GPM-to 310 GPM(no pulse).POOH,RK BK 3 STDS HWDP&NMFC.Break filter sub and inspect,plug in to ACTIVITY MWD CK communication(good);M/U filter sub;RIH with NMFC;M/U to drive;clear mud pumps of LCM/polymer.Shallow pulse test @ 240 GPM SUMMARY 775 PSI,300 GPM 1140 PSI;30 RPM;0.4 TO.M/U BHA;place well commander circ.sub after jar stand;RIH with all HWT DP to 77'MD;UWT 402k;SOW 42k.TIH in hole from 776'MD to 3220'MD.Fill DP;252 GPM;1230 PSI;BHA pulsing;no communication with smart tools;repeat at 310 GPM,1695 PSI(working);cycle pumps;208 GPM,915 PSI(everything ok).RIH from 3220'MD to 4400'MD;UWT 86k;SOW 82k.RIH from 4400'MD to 9580'MD;fill every 1800';fill DP @ 9580'MD,210 GPM,1500 PSI;UWT 154k;SOW 148k;MWD pulse test;210 GPM(good pulse, good corns).Change oil and service DW;service TD and grease wash pipe.Cut and slip drilling line;cut 140'of drilling line.Calibrate block heights for MWD;RIH from 9580'MD to 9832'MD;UWT=162k;SOW 152k.Circ.BUS;214 GPM;1540 PSI. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANJRAG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 14,2013 DEPTH 10355' PRESENT OPERATION: Circulating LCM pills TIME: 2359 hrs YESTERDAY 10229' 24 HOUR FOOTAGE 126' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9265' 730' 29.68 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 310.7 @ 10335' 1.0 @ 10237' 31.8 0.0 FT/HR SURFACE TORQUE 6550 @ 10314' 1 @ 10341' 3192.2 0.0 FT-LBS WEIGHT ON BIT 23 @ 10298' 2 @ 10351' 9.2 6.8 KLBS ROTARY RPM 57 @ 10330' 7 @ 10285' 36.6 0.0 RPM PUMP PRESSURE 2558 @ 10337' 1415 @ 10229' 1830.6 1723 PSI DRILLING FLUIDS REPORT DEPTH MD/TVD 10355/10330' MW 11.2 VIS 58 PV 14 YP 23 Gels 7/10/11 FL 5.2 FC 11.0 SOL 11.3 NAF/W 00/86.5 SD 0.25 MBT 2.0 pH 8.7 ALK 0.2 CI- 29000 Ca+ 160 MWD SUMMARY INTERVAL 10229' TO 10355' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with ECD,Gamma,Resistivity,and Directional GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 137 @ 10355' 5 @ 10229' 38.2 TRIP GAS 2173u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 18960 @ 10275' 882 @ 10229' 5266.7 CONNECTION GAS HIGH 379u ETHANE(C-2) 672 @ 10301' 14 @ 10229' 234.5 CONNECTION GAS:AVG 231u PROPANE(C-3) 659 @ 10298' 12 @ 10229' 276.2 CONNECTION GAS:CURRENT BUTANE(C-4) 393 @ 10307' 10 @ 10229' 175.1 CURRENT AVG BACKGROUND 10u PENTANE(C-5) 193 @ 10230' 11 @ 10245' 75.9 HYDROCARBON Fair to poor show from 10100'-10160'.Fair show from 10250'-10300'. SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 1:10100'-10160'has 1:Top 20'of interval is mainly tuffaceous sandstone and sand, 1:Gas peak of 1:No odor,trace up to 30%dull yellow orange to fair to poor shows.2: lower 40'is tuffaceous sandstone,tuffaceous siltstone and 79u at coal seam. bright yellow white fluorescence,immediate milky 10250-10300'has fair tuffaceous siltstone;20'coal seam at bottom of interval.Porosity 2:Gas peak of white cut,no visible cut or residual ring,white to shows. and permeability is likely poor due to tuffaceous matrix.2:Mainly 129u 10276';gas milky white fluorescent ring.2:No stain,very tuffaceous sandstone with tuffaceous siltstone and some average of 15u- slight to no odor,bright yellow to tellow white tuffaceous claystone toward bottom of interval.Porosity and 20u before and sample fluorescence,immediate fast streaming permeability is likely poor due to tuffaceous matrix. after peak. fluorescent cut,no visible ring,milky white fluorescent ring. LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor Tuff and Coal PRESENT LITHOLOGY Sand Continue circulate B/U STKS @ 214 GPM,1540 PSI;max gas @ 217 Units.RIH from 9835'to 9948'(tight),wash DN to 10228'at 128 GPM 890 PSI,40 RPM,2.5k;TRQ(no fill on BTM).Drill from 10228'to 10286'@ 186 GPM PSI:on-1650 off-1425;40 RPM;TRQ:on-2.6 off-2.3;WOB-2- 4k;flow-20%;U-174k D-163k;RT-171 k;D-163 RT-170;ADT-2.4 TR-1.7 TS-.7;151 BBL loss.Drill from 10286'to 10355'@ 224 GPM PSI:on- 2100 off-1830;40 RPM;TRQ:on-3.2 off-2.5;WOB-3-5k;flow-23%;U-175k D-164k;RT-171 k ADT-3.0 TR-1.8 TS-1.2;221 BBL loss.Circulate B/U STKS @ 216 GPM 1730 PSI;40 RPM,2.2k TRQ.Break out T/D,drop 1.75"ball,pump DN @ 80 GPM to 1546 STKS,seat ball,PSI to 1000 PSI DAILY wait 30 seconds;PSI to 2466 PSI shear circular valve,confirm open;ICP-540;PSI FCP-360 PSI,circulate through circular sub;Drop 1.698" ACTIVITY isolation ball,let drop 5 mins.Tour loss=405 BBL.Break connection;drop 1.698"black ball;pump 20 BBL 50 LB/BBL LCM pill chased with 100 SUMMARY BBL mud to spot LCM;2 BBUmin 360 PSI;3 BBUmin 510 PSI.POOH from 10355'to 9580';UWT 172k;SOW 166k.Circulate over top of well; check loss rate;18 BBUhr.Shut bag;squeeze LCM pill into formation;highest PSI observed 424 PSI;build volume in pits.RIH from 9580'to 10355';175k UWT;168k SOW.Pump 20 BBL 50 LB/BBL LCM pill;spot out of circular sub.POOH from 10355'to 9580';UWT 166k;SOW 162k. Monitor well for 1 hour;Get loss rate;12.5 BBUhr.Squeeze LCM pill into formation;highest PSI observed 1123.Monitor well;fill hole with holefill and track losses;build 80 LB/BBL LCM pill;RIH from 9580'to 10355'.Pump 40 BBL LCM pill,80 LB/BBL LCM pill;spot out of circ.Sub by chasing with 100 BBL mud;3460 STK;2 BBUmin,400PSI.Tour loss=232.2 BBL. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT CAN SCU 41A-04 ANRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 15,2013 DEPTH 10355' PRESENT OPERATION:Top drive broken;preparing to slide TIME:2359 hrs YESTERDAY 10362' 24 HOUR FOOTAGE 7' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA none taken BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9265' 730' 30.06 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION N/A @ @ FT/HR SURFACE TORQUE N/A @ @ FT-LBS WEIGHT ON BIT N/A @ @ KLBS ROTARY RPM N/A @ @ RPM PUMP PRESSURE N/A @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11.10 VIS 49 PV 13 YP 23 Gels 6/8/10 FL 4.6 FC 1/2 SOL 10.6 NAF/W 0.0/87.0 SD 0.25 MBT 2.0 pH 8.7 ALK 0.20 Cl- 32000 Ca+ 120 MWD SUMMARY INTERVAL 10229' TO 10362' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with ECD,Gamma,Resistivity,and Directional GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 43 @ 10356' 30 @ 10362' 37 TRIP GAS 545 u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 8673 @ 10360' 7140 @ 10358' 7907 CONNECTION GAS HIGH ETHANE(C-2) 84 @ 10360' 48 @ 10358' 66 CONNECTION GAS:AVG PROPANE(C-3) 120 @ 10360' 57 @ 10358' 89 CONNECTION GAS:CURRENT BUTANE(C-4) 27 @ 10360' 0 @ 10358' 14 CURRENT AVG BACKGROUND 25 u PENTANE(C-5) 66 @ 10358' 0 @ 10360' 33 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Tuffaceous Claystone,Sand,minor Tuff and Coal PRESENT LITHOLOGY Sand Continue pump 45 BBL of 80 PPB LCM pill(30 PPB Baracarb 50,25 PPB Steel Seal,25 PPB Barafiber),chase with 100 BBL 11.2 PPG mud @ 80 GPM,240 PSI.POOH from 10334'to 9574'U-160K D-156k.Monitor losses via trip tank,19 BBUhr loss.Close annular preventer,squeeze 20 BBL @ 300 PSI staging to 700 PSI,open annular preventer monitor losses via trip tank,16 BBUhr loss.RIH from 9574'to 10203'U-173 D-162. Build 50 BBL 70 PPB pill(Baracarb 50 40 PPB,Baraseal 15 PPB,Barafiber 20 PPB),pump pill and chase with 99 BBL 11.2 PPG mud.POOH from 10203'to 9574'.Monitor losses via trip tank,10 BPH loss;SIMOPS;build 11.0 PPG 6%KCL PHPA mud.Close annular preventer,squeeze 7 DAILY BBL @ 3000 PSI staging to 500 PSI,open annular preventer.Monitor losses via trip tank,8.6 BPH loss.Close annular preventer,squeeze 7 BBL ACTIVITY @ 3000 PSI staging to 1000 PSI,open annular preventer monitor losses via trip tank,8.4 BPH loss.Close annular preventer;squeeze 7 BBLS @ SUMMARY 3000 PSI staging to 1000 PSI,open annular preventer.Monitor losses via trip tank,8.4 BPH loss;SIMOPS;build 11.0 PPG 6%KCL PHPA mud. Continue monitor well for losses;build volume in pits;losing 6 BBL/Hr.Circulate drill string volume;due to gas increasing pump bus;7200+;2 BBL/min @ 285 PSI.Lubricate rig;service TD;DW.Circulate,drop 1.75 ball to close circular sub(ball#5)80 gal per min,close @ 2427 PSI on circular sub.Monitor well;RIH from 9580'to 10355';UWT 156k SOW 152k;Drill from 10355'to 10362';UWT 175k;SOW 166k;ROT 171k 40 RPM;183 GPM;4k WOB;1260 PSI off;1370 on;2.1 to off;2.6 on.TD lost power;troubleshoot TD;PLC down;work pipe;pump 80 GPM;560 PSI. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell DAILY COST: $3260 REPORT BY: John Farrell Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 A1JRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 16,2013 DEPTH 10799' PRESENT OPERATION: Drill ahead to 10835'to set casing TIME:2359 hrs YESTERDAY 10362' 24 HOUR FOOTAGE 437' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH 10454' 19.15 154.01 10424.33' 10516' 19.35 153.91 10482.87' SURVEY DATA 10579' 19.18 154.75 10542.34' 10643' 19.23 154.82 10602.78' 10706' 18.92 155.43 10662.32' BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9625' 1174' 45.5 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 13941.2 @ 10780' 0.9 @ 10385' 79.5 25.4 FT/HR SURFACE TORQUE 5315 @ 10766' 2531 @ 10362' 3446.3 3592 FT-LBS WEIGHT ON BIT 18 @ 10525' 0 @ 10720' 5.0 3.7 KLBS ROTARY RPM 56 @ 10487' 37 @ 10396' 44.4 47 RPM PUMP PRESSURE 2634 @ 10736' 1008 @ 10362' 2207.4 2345 PSI DRILLING FLUIDS REPORT DEPTH MD/TVD 10807'/10760' MW 11.1 VIS 43 PV 12 YP 19 Gels 6/8/10 FL 4.6 FC 1/2 SOL 10.8 NAF/W 0.0/87.0 SD 0.50 MBT 2.0 pH 8.4 ALK 0.15 Cl- 29000 Ca+ 120 MWD SUMMARY INTERVAL 10229' TO 10799' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with ECD,Gamma,Resistivity,Directional GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 368 @ 10587' 2 @ 10396' 72.9 TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 39655 @ 10776' 237 @ 10796' 8812.9 CONNECTION GAS HIGH 368u ETHANE(C-2) 1868 @ 10587' 4 @ 10390' 404.5 CONNECTION GAS:AVG 272u PROPANE(C-3) 3223 @ 10587' 2 @ 10792' 547.4 CONNECTION GAS:CURRENT 260u BUTANE(C-4) 2136 @ 10587' 3 @ 10390' 351.5 CURRENT AVG BACKGROUND 25u PENTANE(C-5) 983 @ 10587' 2 @ 10390' 161.4 HYDROCARBON Significantly fair show from 10450'-10530'.Fair shows from 10570'-10600'and 10670'-10680'.Poor shows from 10710'-10720'and SHOWS 10770'-10780'. INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION 1:10450'-10530'2: 1:Loose sand with tuffaceous sandstone and 1:Gas peak of 159u; 1:Oily sheen in pits,no stain,very slight odor,yellow to bright 10570'-10600'3: minor tuff at top 30'of interval,bottom 30' fluctuating from 19u yellow sample fluorescence,samples brighten with mud,light 10670'-10680'4: becomes more dominated by tuffaceous low to 145u.2:Gas milky-yellow stream cut,milky white fluorescence ring,no visible 10710'-10720'5: sandstone.2:Loose sands with minor tuffaceous peak of 195u; residual ring.2:Oily sheen in pits,no stain,moderate to strong 10770'-10780' sandstone and tuffaceous siltstone,trace average gas around odor,dull orange to yellow sample fluorescence,no staining, conglomerate.3:Loose sand dominated,with peak is 120u.3.Gas immediate strong milky white to milky-yellow cut fluorescence, tuffaceous sandstone,tuffaceous siltstone and peak of 85u;average orange to yellow-orange residual ring fluorescence,3:No stain, tuff.4:Loose sand dominated,with tuffaceous of 49u 4.Gas peak of no odor,orange to yellow-orange sample fluorescence, sandstone and minor tuffaceous siltstone.5: 107u;average of 80u. moderate to strong yellow-white fluorescence cut,yellow-white Loose sand dominated,with tuffaceous 5.Gas peak distorted fluorescence ring,no visible residual ring.4:No odor,no stain, sandstone and minor to trace conglomerate. by connection gas. yellow to bright yellow sample fluorescence,slow moderate yellow-white fluorescence cut,faint white residual ring fluorescence,no visible residual ring.5:No odor,no stain,dull yellow to yellow orange sample fluorescence,very slow weak pale yellow fluorescence cut,yellow residual ring fluorescence, no visible residual ring. LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Sand,Tuffaceous Claystone,minor Tuff and Coal PRESENT LITHOLOGY Sand,Tuffaceous Sandstone,minor Conglomerate/Conglomeratic Sand DAILY Troubleshoot MWD pulser.Drill from 10362'to 10395'@ 255 GPM PSI on-2120 off-RPM-0 TRQ-0 WOB-1.2k flow-28%U-175 D-164 RT-170 ACTIVITY ADT-1.1 TR-1.1 TS-0.Continue drilling from 10412'to 10585';UWT 178k;165k;168k;2.2k off;5-8K WOB;250 GPM 2070 PSI off;2420 on. SUMMARY Continue drilling from 10585'to 10XXX';UWT=184k;SOW 166k ROT 168k;262 GPM @ 2100 off PSI;2400 on;5-8k on bit;50 RPM. CANRIG PERSONNEL ON BOARD: Resch, Sherry. Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 cA1RIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 17,2013 DEPTH 10807' PRESENT OPERATION: Pumping dry job,preparing to POOH TIME:2359 hrs YESTERDAY 10799' 24 HOUR FOOTAGE 8' CASING INFORMATION 7"@ 9591 DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA none taken BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9625' 1182' 45.75 DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION 35.8 @ 10800' 25.4 @ 10799' 7.6 FT/HR SURFACE TORQUE 3592 @ 10799' 3398 @ 10800' 873.8 FT-LBS WEIGHT ON BIT 3 @ 10800' 3 @ 10799' 0.9 KLBS ROTARY RPM 54 @ 10800' 47 @ 10799' 12.6 RPM PUMP PRESSURE 2345 @ 10799' 2274 @ 10800' 577.4 PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11.1 VIS 46 PV 12 YP 18 Gels 5/7/8 FL 5.3 FC 1/2 SOL 10.6 NAF/W 0.0/87.0 SD 0.5 MBT 2.0 pH 8.0 ALK 0.1 Cl- 31,000 Ca+ 120 MWD SUMMARY INTERVAL 10229' TO 10807' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with ECD,Gamma,Resistivity,Directional GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS 11 @ 10799' 10 @ 10800' 2.7 TRIP GAS CUTTING GAS 0 @ 10807' 0 @ 10807' 0.0 WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) 730 @ 10800' 575 @ 10799' 163.1 CONNECTION GAS HIGH ETHANE(C-2) 0 @ 10807' 0 @ 10807' 0.0 CONNECTION GAS:AVG PROPANE(C-3) 45 @ 10800' 32 @ 10799' 9.6 CONNECTION GAS:CURRENT BUTANE(C-4) 19 @ 10800' 16 @ 10799' 4.5 CURRENT AVG BACKGROUND 10u PENTANE(C-5) 42 @ 10800' 37 @ 10799' 9.9 HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Sand,Tuffaceous Claystone,minor Tuff and Coal PRESENT LITHOLOGY Sand,Tuffaceous Sandstone,minor Conglomerate/Conglomeratic Sand Drill from 10800'to 10807.8',hit drilling break @ 10806';return flow loss from 28%to 3%.Monitor well on TT,obtain loss rate @ 75.5 BPH.Drop 1.75"close/open ball pump DN 2 80 GPM 490 PSI,ball seat @ 1407 STKS,PSI up to 1000PSI wait 30 sec,PSI to 2278 PSI shear circ sub open, 310 PSI open,drop 1.698 isolation ball.Monitor well on TT,obtain loss rate @ 51 BPH,build LCM pill.Pump 43 BBL 80 PPB LCM pill(Stealseal 400-20PPB,Barafiber-25PPB,Baracarb 5-53PPB)chase with 102 BBL 11.1 PPG mud @ 80 GPM 300 PSI.POOH from 10807'to 9575'U-164 D- 157.Monitor well on TT,initial loss rate 30 BPH;final loss rate 20.5 BPH,build 11.1 PPG 6%KCL PHPA mud,build LCM pill.Pump 43 BBL 80 DAILY PPB LCM pill(Stealseal 400-20 PPB,Barafiber-25 PPB,Baracarb 5-53 PPB)chase with 60 BBL 11.1 PPG mud @ 80 GPM 300 PSI..RIH from ACTIVITY 9575'to 10778'.Displace LCM pill with 55 BBL 11.1 PPG mud @ 80 GPM 345 PSI.POOH from 10778'to 9570'.Monitor well on TT,loss rate 6.4 SUMMARY BBUhr,continue to build 11.1 PPG 6%KCL PHPA mud,close annular and squeeze periodically @ 300 and 500 PSI.Bleed off pressure,open annular;monitor with TT,1 BBUhr loss rate.Close annular,squeeze periodically @ 300 to 800 PSI.Monitor well on TT in between.Continue to build 11.1 PPG 6%KCL mud.Circulate B/U through circular sub.Pumping @ 1.9 BBL/min @ 200-310 PSI.Attempt to get 11.1 PPG mud in and out.Out WT won't come up past 10.9 PPG.Drop steel ball to close circular sub.Circulate through BHA to ensure that it's clear.All good,sleeve closed @ 2400 PSI.RIH W/4"HT-38 DP.From 9570'to 10778'.No tight spots.UW=183k,DW=165k.CBU @ 2.7 BBUmin,@ 800 PSI.11.1 PPG MW.Monitor well for 5 minutes,dropping slowly.POOH from 10778'to 9570'.Monitor well at window for 30 minutes on TT;15 BBUhr loss rate. Pump dry job;12.6 PPG. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: John Farrell Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 cANRIG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 18,2013 DEPTH 10807' PRESENT OPERATION: RIH with 4.5"casing TIME: 2359 hrs YESTERDAY 10807' 24 HOUR FOOTAGE 0' CASING INFORMATION 7"@ 9591' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 2 6" DP505FX/HCC 70287861 5x11/0.464 9625' 10807' 1182' 46.3 2-1-CT-N-X-I-WT-TD TD DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11.1 VIS 45 PV 11 YP 16 Gels 5/6/8 FL 4.8 FC 1/2 SOL 10.6 NAF/W 0.0/87.0 SD 0.25 MBT 2.0 pH 8.0 ALK 0.1 Cl- 32000 Ca+ 100 MWD SUMMARY INTERVAL 10229' TO 10807' TOOLS Well Commander Circulating Sub and PDC bit on mud motor with ECD,Gamma,Resistivity,Directional GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) @ @ CONNECTION GAS HIGH ETHANE(C-2) @ @ CONNECTION GAS:AVG PROPANE(C-3) @ @ CONNECTION GAS:CURRENT BUTANE(C-4) @ @ CURRENT AVG BACKGROUND PENTANE(C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Sand,Tuffaceous Claystone,minor Tuff and Coal PRESENT LITHOLOGY Sand Monitor well;15 BPH loss;drop 2.38"drift on 80'wire(STD 140).POOH from 9577'to 776'U-42k D-42k;monitor well;7.2 BBL/hr loss;recover wired drift at first JT HWDP,calc-57.1 ACT-88.5 loss-31.4(SIMOPS:test choke manifold 250-4000 PSI).Continue POOH,RK BK 9 STDS HWDP, L/D:Commander Sub,X/O's,JARS,1 JT HWDP.L/D BHA#4:2-NMFC,filter sub.Plug in,download MWD;monitor well on TT.Rinse and drain BHA;continue L/D BHA#4:MWD,2 NMFC,STAB,motor,bit.Clear and clean rig floor;send out all Bakers subs and bits;pull wear bushing.R/U to test BOPE,M/U FOSV,DART to 4"test JT;M/U rocket launcher to saver sub;R/U test equipment.Test annular preventer to 250 PSI/5 min, DAILY 2500 PSI/5 min,4000 PSI/5 min:TPR,HCR choke,HCR kill,FOSV.Tour loss=100.5 BBLS.Continue to test BOPS,250 PSI/low,4000 psi/high; ACTIVITY test top pipes,man kill,man choke,DART valve;test top pipes,3 1/8"kill,valve 1 on choke,lower IBOP;test top pipes,upper IBOP;test lower SUMMARY pipes on 4"test JT,perform koomy test;build blinds;test bag on 4 Y"test JT 250/2500;test top pipes on 41/2"test JT.R/D test equipment;break TIW&DART valve apart;break XO on top of 4 1/2"test JT;clean up rig floor;install wear bushing 6.125"ID.R/U CSG equipment;P/U handling tools;ID elevators and slips;P/U power tongs&hang;rig up CSG;fill up line;P/U centralizers.Run liner assembly;Baker LOK&M/U shoe track, blank JT,float collar,&landing collar;CK floats;continue RIH with total of 33 JTS of 4 1/2"liner.P/U liner hanger assembly;mix POW mix,pour in, let stand for 30 mins.P/U first STD of 4"HWDP;make up TD&CIRC liner volume.Continue RIH with HWDP&4"DP;fill every 10 STDS;drift HWDP W/2"drift. CANRIG PERSONNEL ON BOARD: Resch, Sherry, Grundin, Farrell_DAILY COST: $3260 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT SCU 41A-04 CANRAG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 19,2013 DEPTH 10807' PRESENT OPERATION: Preparing to pull 4"drill pipe from casing TIME:2359 hrs YESTERDAY 10807' 24 HOUR FOOTAGE 0' CASING INFORMATION 7"@ 9591'4.5"@ 10787' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD 10807'/10760' MW 11.1 VIS 45 PV 12 YP 22 Gels 5/7/8 FL 5.0 FC 1/2 SOL 10.6 NAF/W 0.0/87.0 SD 0.25 MBT 2.0 pH 9.0 ALK 0.35 Cl- 32000 Ca+ 100 MWD SUMMARY INTERVAL TO TOOLS NO TOOLS IN HOLE GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS 1811u CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) @ @ CONNECTION GAS HIGH ETHANE(C-2) @ @ CONNECTION GAS:AVG PROPANE(C-3) @ @ CONNECTION GAS:CURRENT BUTANE(C-4) @ @ CURRENT AVG BACKGROUND 4u PENTANE(C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Sand,Tuffaceous Claystone,minor Tuff and Coal PRESENT LITHOLOGY Sand RIH from 2586'to 6365'with 4"DP from DRK @ 90 sec/STD;fill pipe every 10 STDS via T/D.Continue RIH from 6365'to 9508'with 4"DP from DRK @ 90 sec/STD;fill pipe every 10 STDS via T/D;U-146k,D-145k,ACT-36.6,CALC-65.9,LOSS-29.3.Circulate @ window 1.5X liner and drill string volume;pumping @ 80 GPM @ 340 PSI,max gas observed=258 units.Continue RIH with 4"DP from 9575'to 10795'.L/D top single off of DAILY STD 141;P/U CMT head,M/U to TD and string.CBU @ 10795';max gas observed=1811 units;pumping @ 100 GPM with 450 PSI;TQ=2-2.5k. ACTIVITY PJSM:Cementing;SLB pump 5 BBLS of water.PT lines to 5000 PSI;bleed down,SLB start batching up;pump 35 BBLS of mud push with rig SUMMARY pumps;SLB pump 70 BBLS of 15.3 PPG easy block CMT,with 1 PPB CEM/NET;drop wiper dart;SLB chase with 5 BBLS of water,then 113.5 BBLS of rig mud;dart latched @ 98 BBLS away;plug bumped @ 118.5 BBLS away;increase PSI 500 over FCP,hold for 5 min;check floats.1.5 BBLS bled back;pressure up to 3000 and hold,slack off to 100k;pressure up to 4700,slack off to 90k;pulled free.L/D CMT head and equipment. Set liner packer and hanger;R/U test chart,pressure up backside to 2100 PSI for 5 min.Unsting from hanger;circulate mud push and CMT out of hole,30 BBLS of CMT back to surface. CANRIG PERSONNEL ON BOARD: Resch, Sherry DAILY COST: $2460 REPORT BY: Mike Sherry Hilcorp Alaska,LLC Swanson River Field DAILY WELLSITE REPORT CAN SCU 41A-04 RAG REPORT FOR:Leslie,Grubb,Greco,Pederson DATE: May 20,2013 DEPTH 10807' PRESENT OPERATION: RIH with 2.875"mill TIME:2359 hrs YESTERDAY 10807' 24 HOUR FOOTAGE 0' CASING INFORMATION 7"@ 9591'4.5"@ 10795' DEPTH INCLINATION AZIMUTH VERTICAL DEPTH SURVEY DATA NONE TAKEN BIT INFORMATION INTERVAL CONDITION REASON NO. SIZE TYPE S/N JETS/TFA IN OUT FOOTAGE HOURS T/B/C PULLED 3 2.875" HDBS/FX45s TFA:1.000 10807' DRILLING PARAMETERS HIGH LOW AVERAGE CURRENT AVG RATE OF PENETRATION @ @ FT/HR SURFACE TORQUE @ @ FT-LBS WEIGHT ON BIT @ @ KLBS ROTARY RPM @ @ RPM PUMP PRESSURE @ @ PSI DRILLING FLUIDS REPORT DEPTH MD/TVD MW 11.1 VIS 57 PV 11 YP 19 Gels 4/5/7 FL 5.0 FC 1/2 SOL 10.7 NAF/W 0.0/87.0 SD 0.25 MBT 2.0 pH 8.0 ALK 0.01 Cl- 30000 Ca+ 100 MWD SUMMARY INTERVAL TO TOOLS NO TOOLS IN HOLE GAS SUMMARY(units) HIGH LOW AVERAGE DITCH GAS @ @ TRIP GAS CUTTING GAS @ @ WIPER GAS CHROMATOGRAPHY(ppm) SURVEY METHANE(C-1) @ @ CONNECTION GAS HIGH ETHANE(C-2) @ @ CONNECTION GAS:AVG PROPANE(C-3) @ @ CONNECTION GAS:CURRENT BUTANE(C-4) @ @ CURRENT AVG BACKGROUND 8u PENTANE(C-5) @ @ HYDROCARBON SHOWS INTERVAL LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY Tuffaceous Sandstone,Tuffaceous Siltstone,Sand,Tuffaceous Claystone,minor Tuff and Coal PRESENT LITHOLOGY Sand Drop nerf ball;CIRC DP VOL x 1.5 @130 GPM,580 PSI,flow check(static).POOH from 9372'to 9058',pump 15 BBL 12.3 PPG dry job;continue POOH from 9058'to 1641'U-52 D-51;Continue POOH from 1641';UD DP in pipe shed;L/D X/O,liner hanger running tool.Clear and clean rig floor;P/U CMT head from pipe shed;break all pups,X/O and UD same;drift 45 JTS 2 7/8"SLH-90;R/D M/U rig tongs;R/U Weatherford double stack power tongs;bring to floor via beaver slide:2 7/8"elevators,slips,FOSV,DART valve.Break 3.65"bit,bit sub,X/O off 2.875"scraper;M/U DAILY bit;bit sub;X/O to 1 JT 2.875"SLH-90 DP.Single in hole with 45 JTS of 2 7/8"work string.Put 2 7/8"x 3 Y2"if XO on top of last JT in slips,and TO ACTIVITY with Weatherford tongs;R/D Weatherford equipment;change elevators;hang rig tongs back up.Latched up 1st STD of 4"DP;put 3 1/2"if X HT-38 SUMMARY XO on BTM of STD and spin up on other XO in stump;went to TQ 3 1/2"IF connection,got to about 9000 ft/lbs and the 2 7/8"stump broke off @ the hard band;it was partially rusted through.Wait on Baker fishing tools;P/U JT of 4"DP;install 3 1/2"IF x HT-38 XO on BTM of JT.M/U spear on BTM of 4"JT hanging;M/U spear to broke stump in slips;P/U string and set slips higher and secure string.Wait on Weatherford to UD all 45 JTS of 2 7/8"work string.UD 45 JTS of 2 7/8"work string in pipe shed;break out bit,bit sub&XO together.Wait for new string of 2 7/8"Weatherford pipe;SIMOPS;clean;service DW,TD,blocks,crown,&cleaning mud pits.Offload truck with new 2 7/8"work string;strap and drift in pipe shed. RIH;single in with 2 7/8"SLH-90;M/U bit,bit sub&XO to bottom of 1st JT;Continue picking up 2 7/8"work string. CANRIG PERSONNEL ON BOARD: Resch, Sherry_DAILY COST: $2460 REPORT BY: Mike Sherry CANRIG Dsu.I I s.t.TrcH,n,R,.:r°. Hydrocarbon Show Report # 1 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 Field: Swanson River Date: 5/14/2013 Rig: Doyon Arctic Fox Time: 0437 hrs County: Kenai Borough Depth Start End State: Alaska 10170' MD 10249' MD Country: USA 10155' TVD 10229' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 45 51 26 203 10000 - - C WOB 6 3 4 19 _ RPM 56 44 39 56 1000 Mud Weight 11.00 11.15 11.15 • Chloride 28,500 28,500 28,500 • 6� a 100, Total Gas 10 36 51 66 ...10 •- •- Cl (ppm) 1,445 6,079 7,516 11,435 -•- , olL -- -- - C2(ppm) 148 75 393 1,149 - — C3(ppm) 26 16 380 285 1 C4(ppm) 45 45 229 230 C,C2 C.C3 Cl/CA C,� C5(ppm) 19 29 61 93 Lithology Samples could not be obtained from 10170'-10182'due to loss of circulation. Sand (10130'-10220') = unconsolidated; upper very fine grain; angular to sub-angular;prismoidal;very well sorted; 95%translucent to transparent quartz and volcanic glass clasts; minor secondary mafic minerals;overall sample appears dark pale orange to light pale yellowish brown;95%sand, 5%conglomerate and pebble fragments. From 10220'-10249', interval becomes dominated by tuffaceous sandstone with lesser amounts of sand and tuffaceous siltstone.Tuffaceous sandstone,sand,tuffaceous siltstone (10220'-10249') =medium light gray to light gray with grayish white to white matrix; upper to lower very fine grain;subrounded; sub-discoidal; moderate sorting;60-70% milky white to translucent quartz,with abundant dark gray to grayish black clasts, minor mafics and trace carbonaceous shale. Cuttings Analysis Odor INone Fluorescence Cut Fluorescence Residual Cut Stain Amount Tr to 60% Type Fast Amount None Amount None Distribution Patchy Intensity Bright Color Color Intensity Bright Color Milky- Residual Fluorescence Cut Color Yel-Yel Wh _ White Intensity Strong — Color I _ - Color Milky White Oil Show Rating 11.2 Free Oil in Mud None Comments Very poor sample quality due to loss of returns from 10170'-10182';abundant LCM in the mud system. Last 10'of interval shows signs of oil show: no odor, no stain,trace to 60%patchy bright yellow to yellow-white sample fluorescence,fast bright milky-white cut fluorescence, stong milky-white residual fluorescence ring, no visible residual ring. Report by: Larry Resch, Michael Sherry n^� Hilcorp Alaska, LLC CA RIG SCU 41 A-04 Ratio Plot #1 May 14, 2013 Tyonek G2 10170'MD to 10249'MD 10155'TVD to 10229'TVD 10000 - - 1000 • • • • • • • DRY GAS • • • • 100 • • • • •• • • • • • / 10 / • • • - s- • • • 1 NON PRODUCTIVE- 1 2 3 4 01/02 C1/C3 Cl/C4 Cl/C5 CANRIG i,„„,,‘,,Tr,Fa„∎", Hydrocarbon Show Report # 2 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 Field: Swanson River Date: 5/14/2013 Rig: Doyon Arctic Fox Time: 0846 hrs County: Kenai Borough Depth Start End State: Alaska 10253' MD 10316' MD Country: USA 10234' TVD 10293' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 35 39 40 125 10000 WOB 4 8 8 23 RPM 41 46 46 54 100p , Mud Wei g ht 11.15 11.15 11.15 _ Chloride 28,500 28,500 28,500 —_ DRY Gas ---- ' GAS E 100 _ Total Gas 20 51 28 129 -Cl - (ppm) 3,738 6,937 3,849 18,960 10 —_-- -_ - C2(ppm) 140 321 190 672 NON PRODUCTIVE C3(ppm) 126 378 238 659 1 1 C4(ppm) 71 234 178 393 01 CUP 0 „C4 Cl/C5 C5(ppm) 32 88 82 179 Lithology Tuffaceous sandstone, sand, tuffaceous siltstone (10220'-10370') =medium light gray to light gray with grayish white to white matrix; upper to lower very fine grain;subrounded;sub-discoidal; moderate sorting; 60-70%milky white to translucent quartz,with abundant dark gray to grayish black clasts, minor mafics, rare greenstone;very ashy/argillaceous matrix; poor visible porosity; sublithic arenite to arenaceous'ash- stone'; note thinly interbedded/interfingered dark grayish orange to light brown medium grain sub-rounded subprismoidal/subdiscoidal loose clasts(?) becoming dominant by 10310'.At 10300', sand content increases from 30%to 100%by 10315'. Cuttings Analysis Odor 'Very Slight Fluorescence Cut Fluorescence Residual Cut Stain Amount 20-100% _ Type Instant Amount None Amount None Distribution Patchy Intensity Mod-Strg Color Color Intensity Mod-Strong Color Milky Wh Residual Fluorescence Cut Color Bright Yel _ Intensity Mod-Strong _ Color Color Milky White Oil Show Rating 2.3 Free Oil in Mud None Comments Besides average sample fluorescence of -60%, best signs of an oil show are from 10250'-10260': no odor, no stain, locally abundant bright yellow to yellow-white sample fluorescence, immediate burst with fast streaming milky white cut fluorescence, milky white residual ring fluorescence, no visible residual ring. Report by: Larry Resch, Michael Sherry A�' Hilcorp Alaska, LLC CA RIG SCU 41A-04 uxu.uaa recuvou wv Lru. Ratio Plot #2 May 14, 2013 Hemlock H1/2 10253'MD to 10316'MD 10234'TV D to 10293'TV D 10000 1000 • 0I • • • • DRY GAS • • • • 100 • • • • • • • - - • • • 10 • OIL • 1 NON PRODUCTIVE 2 3 4 C1/C2 C1/C3 C1/C4 C1/C5 CANRIG °x,,,,,°Tr,�„,, ,t.Y,.11,. Hydrocarbon Show Report # 3 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 _ Field: Swanson River Date: 5/14/2013 Rig: Doyon Arctic Fox Time: 0909 hrs County: Kenai Borough Depth Start End State: Alaska 10333' MD 10410' MD Country: USA 10310' TVD 10383' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 40 17 12 311 _ WOB 8 5 9 19 RPM 46 8 45 45 1000 , __ Mud Weight 11.20 11.05 11.05 .- Chloride 30,500 30,500 30,500 a 100 -lC Total Gas 28 21 4 137 —�"�"—,, Cl (ppm) 3,849 3,706 783 2,455 C2(ppm) 190 76 55 467 i _•3 E C3(ppm) 238 105 35 527 1 1 C4(ppm) 178 52 - 319 0102 C3 c+iu 0, C5 C5(ppm) 82 28 - 152 Lithology The top 35'of this interval is dominated by sand, reaching 100%sand from 10340'to 10360'. Very little sample data is avalable to to significant loss of returns and contamination by LCM products. Cuttings Analysis Odor ]None Fluorescence Cut Fluorescence Residual Cut Stain _ Amount None Type None Amount None Amount None Distribution Intensity Color Color Intensity Color Residual Fluorescence Cut Color _ Intensity _ Colors Color Oil Show Rating 0 Free Oil in Mud None Comments Very poor sample quality due to intermittent loss of returns and abundant LCM in the mud system. No visible signs of an oil show were observed through this interval. Report by: Larry resch, Michael Sherry A A' Hilcorp Alaska, LLC CA RIG SCU 41 A-04 Ratio Plot #3 May 14, 2013 Hemlock H3-5 10333'MD to 10410'MD 10310'TV D to 10383'TV D 10000 1000 • • • • • i • DRY GAS • • • 100 • • • • • • • • • • 10 • • • • • • • • 1 NON ,PRO_DUCTIVE 1 2 3 4 C1/C2 Cl/C3 Cl/C4 Cl/C5 li CANRIG ��H❑,IM. F(HStl(N:T1:1, Hydrocarbon Show Report # 4 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 Field: Swanson River Date: 5/16/2013 Rig: Doyon Arctic Fox Time: 1717 hrs County: Kenai Borough Depth Start End State: Alaska 10417' MD 10538' MD Country: USA _ 10389' TVD 10504' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 12 38 29 161 10000 WOB 9 3 6 18 RPM 45 52 50 56 1000 __- Mud Weight 11.05 11.10 11.10 -- Chloride 30,000 30,000 30,000 _ E °° G' ___ "may.,,S__-_,i... -�L° Total Gas 4 83 113 159 _ _= �"�� C1 (ppm) 783 9,009 11,074 20,076 0 _ - --- _ C2(ppm) 55 643 955 1,181 N•N PRODUCTIVE C3(ppm) 35 879 1,201 1,807 1 . 2 C4(ppm) - 547 753 1,830 Cl/C2 C3 0,�CA 0„C5 C5(ppm) - 213 328 470 Lithology Interval is dominated by tuffaceous siltstone and tuffaceous claystone until 10440'where tuffaceous sandstone and sand become prevalent and signs of oil begin.Tuffaceous sandstone, loose sand (10440'- 10530')=overall very light gray to light gray with abundant grayish white to white tuffaceous/ash matrix; predominantly lower very fine, upper very fine grain common; subrounded;subdiscoidal;well to moderate sorting;interval varies 40-70%poorly consolidated/60-30% loose or disaggregated sand; noncalcareous; matrix is tuff to devitrified volcanics, ash, occasional vitreous components;dominantly translucent and transparent quartz,volcanic glass clasts,feldspars and locally abundant mafic minerals; note localized very fine glass shards; note occasional light gray subwaxy tuff; interval varies from a sublithic arenite to an'ash- stone'with significant quartz component; no visible porosity Cuttings Analysis Odor (Very Slight Fluorescence Cut Fluorescence Residual Cut Stain Amount 100% Type_Burst Amount None Amount None Distribution Even Intensity Moderate Color Color Intensity Mod-Strong Color Light Residual Fluorescence Cut Color Bright Yel- Milky-Yel Intensity Strong Color Color Milky-white Oil Show Rating 2.5 Free Oil in Mud I None Comments Possible cavings from 10420'-10440'. Oily sheen at shakers, no stain,very slight odor, 100%yellow to bright yellow sample fluorescence from 10460'-10530',with light milky yellow streaming fluorescence cut, milky-white residual fluorescence ring, and no visible residual ring. Zero sample fluorescence seen in last 10'of interval. Report by: Larry Resch, Michael Sherry /� Hilcorp Alaska, LLC CA N RIG SCU 41 A-04 Ratio Plot #4 May 16, 2013 Hemlock H6-8 10417'MD to 10538'MD 10389'TV D to 10504'TV D 10000 1000 • • • • • • DRYG-AS - r • • 100 • • • • • Y • 10 • OIL . - 1 NON PRO UCTIVE 1 2 3 4 C1/C2 C1/C3 C1/C4 C1/C5 CANRIG Dk,,,,.<:TFI:FIV,R(H.1I.,,'. Hydrocarbon Show Report # 5 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 Field: Swanson River Date: 5/16/2013 Rig: Doyon Arctic Fox Time: 2003 hrs County: Kenai Borough Depth Start End State: Alaska 10553' MD 10639' MD Country: USA 10518' TVD 10599' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 29 63 99 112 10000 WOB 6 5 6 9 RPM 50 50 50 56 1000 , - Mud Weight 11.10 11.10 11.10 Chloride 29,000 29,000 29,000 ''' E Total Gas 113 121 99 291 .--"— Cl (ppm) 11,074 15,762 12,496 37,784 10 - ---4111111--- - �°®®_--- C2(ppm) 955 563 432 1,869 E C3(ppm) 1,201 254 598 3,223 1 C4(ppm) 753 447 356 2,136 1 2 3 4 cvcz c,res cvcn cuts C5(ppm) 328 203 180 983 Lithology Beginning of interval is a mix of tuffaceous sandstone,tuffaceous siltstone,tuffaceous claystone;by 10570' there is minor tuffaceous sandstone and tuffaceous siltstone with increasingly dominant loose sands. Sand (10570'-10630') =very light gray to light gray and white translucent and opaque loose grains;upper fine to upper coarse;very low to high sphericity; subrounded to angular;very poorly sorted;dominated by 85% quartz grains;trace conglomerate toward middle of oil show interval. Lower 10'of interval becomes dominated by tuffaceous siltstone. Cuttings Analysis Odor None Fluorescence Cut Fluorescence Residual Cut Stain Amount 50+% Type Fast Amount None _ Amount None Distribution Scattered Intensity Mod-Strg Color Color Intensity Moderate Color Yellow- Residual Fluorescence Cut Color Yel-Org Bright Yel Intensity Moderate Color Color Bright Yel-Org Oil Show Rating _2.5 Free Oil in Mud None Comments Oil sheen at shakers from 10570'-10600',accompanied by moderate to strong odor, 60-100%yellow- orange sample fluorescence and fast, moderate to strong milky yellow-white cut fluorescence with yellow- orange residual fluorescence ring. No more odor by 10610', and cut fluorescence becomes very weak. Average of 40%bright yellow sample fluorescence from 10610'to end of interval. Report by: Larry Resch, Michael Sherry /� Hilcorp Alaska, LLC CA N RIG SCU 41A-04 Ratio Plot #5 May 16, 2013 Hemlock H10 10553'MD to 10639'MD 10518'TVD to 10599'TVD 10000 1000 • • • • • • • DRY OAS- • • • • 100 • • • * • • - - _• ; �- - 0 • • • 10 - • •• • • OIL • - - � 1 - 1VON ,PRO6UCTIVE 1 2 3 4 C1/C2 C1/C3 C1/C4 C1/C5 CANRIG ..„,,.,.TEUN]U1,, Hydrocarbon Show Report # 6 Operator: Hilcorp Alaska, LLC Well: SCU 41A-04 API Number:50-133-10109-02-00 Field: Swanson River Date: 5/17/2013 Rig: Doyon Arctic Fox Time: 0204 hrs County: Kenai Borough Depth Start End State: Alaska 10668' MD 10800' MD Country: USA 10626' TVD 10751' TVD Averages Before During After Maximum Pixley Plot ROP(fph) 99 36 120 10000 WOB 6 _ 4 15 RPM 50 54 56 1000 Mud Weight 11.10 11.10 Chloride 29,000 29,000 E - 00 Total Gas 99 51 260 "4:111111� Cl (ppm) 12,595 6,161 39,655 10 '_ '_•1 (ppm) _ C2 m 433 194 1,005 - f; .-.=Tfi:i —•C3(ppm) 598 263 1,352 1 C4(ppm) 356 224 1,334 0, C,C3 Cl/CA C,C5 C5(ppm) 180 137 751 Lithology Tuffaceous sandstone (10660'-10800') = Interval varies from 10-40%loose sand, 90-60%poorly consolidated sandstone;overall grayish white to white,very light to medium light gray; upper very fine grain, rounded to subrounded; subdiscoidal;well to moderate sorting;translucent and transparent quartz dominant, prominent mafic minerals, localized medium dark gray to grayish black lithics; note occasional biotite;vitreous and devitrified ash and altered tuff matrix; note abundant volcanic glass clasts and very fine glass shards;grains suspended and well entrained as a sublithic arenite to an'ash-stone'. Cuttings Analysis Odor None Fluorescence Cut Fluorescence Residual Cut Stain Amount 40% Type Slow Amount None Amount-None on Distribution Scattered Intensity Wk-Mod Color Color Intensity Dull Color Light Yel- Residual Fluorescence Cut Color Yel-Yel/Org Bright Yel Intensity Yel to Yel-Wh Color Color Oil Show Rating 2.1 Free Oil in Mud None Comments NOTE: LOSE 100% RETURNS WHEN DRILLING THROUGH 10800 FT. No odor, stain, or visible cut through entire interval. Even 85-95%sample fluorescence from 10670'-10680'accompanied by moderate to strong milky yellow-white fluorscence cut and orange to yellow-orange residual ring fluorescence. Shows from 10670'-1680', 10710'-10720', and 10770'-10780'appear much stronger than the rest of the interval. Report by: Larry Resch, Michael Sherry A A' Hilcorp Alaska, LLC CA RIG SCU 41A-04 Uxiw.in'e,Tvii i,ww x�i Lru. Ratio Plot #6 May 17, 2013 Hemlock H11-13 10668'MD to 10800'MD 10626'TV D to 10751'TV D 10000 1000 - - • • • • • • DRY GAS • • • • • 100 • • • • / / • 10 /• NON PRODUCTIVE 1 2 3 4 C1/C2 C1/C3 C1/C4 C1/C5
