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Home My WebLink About168-043STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS CDEIVD SEP 30 2014 1. Operations Abandon ❑ Repair Well ❑ Plug Perforations ❑ Perforate ❑ Other 2 Gpmpl2td Performed: Alter Casing ❑ Pull Tubing[] Stimulate - Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat. Shutdown❑ Stimulate - Other ❑ Re-enter Suspended WeII❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑ Exploratory ❑ Stratigraphic❑ Service Q 168-043 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-733-20115-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0017594 Trading Bay Unit / G-11 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): McArthur River Field / Hemlock Oil, Middle Kenai G Oil 11. Present Well Condition Summary: Total Depth measured 10,846 feet Plugs measured N/A feet true vertical 9,860 feet Junk measured See Schematic feet Effective Depth measured 10,444 feet Packer measured See Schematic feet true vertical 9,512 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Structural Conductor 694' 16" 694' 694' 2,630 psi 1,020 psi Surface 3,081' 13-3/8" 3,081' 2,934' 3,090 psi 1,540 psi Intermediate Production 10,835' 9-5/8" 10,833' 9,869' 5,750 psi 3,090 psi Liner Perforation depth Measured depth 9,709-10,700 feet True Vertical depth 8,850-9,752 feet SrANNED OCT 16. 2014 Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3 / L-80 9,675' (MD) 8,812' (TVD) Packers and SSSV (type, measured and true vertical depth) See Schematic 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 2603 2150 2150 Subsequent to operation: 0 0 0 112 0 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory[] Development[-] Service Q Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas ❑ WDSPL❑ IGSTOR ❑ WINJ 21 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: 1313-453 Contact Dan Taylor Email dtaylor2hilcorp.com Printed Name Dan Taylor Title Operations Engineer Signature Phone (907) 777-8319 Date 9/30/2014 Form 10-404 Revised 10/2012 Submit Original Only 201 Hilcorp Alaska, LLC RKB to TBG Hngr = 42.95' Tree connection: 4-1/2" 8RD Top TD = 10,835' ETD = 10,790' 3 McArthur River Field Well: G-11 Completed: 08/31/2014 CASING DETAIL SIZE WT (#/ft) GRADE CONN ID (in) MDP MD BTM (ft) 16" 75 J-55 Butt 3.00 3.5in T2 On/Off Tool Surf. 694 13-3/8" 61 J-55 Butt 5 Surf 3,081 9-5/8" 47 N-80 Seal Lock 8.681 Surf 76 9-5/8" 40 N-80 Seal Lock 8.835 76 4,956 9-5/8" 43.5 N-80 Seal Lock 8.755 4,956 7,208 9-5/8" 47 N-80 Seal Lock 8.681 7208, 8,290 9-5/8" 47 P-110 Seal Lock 8.681 8,290 10,833 D,236 D,266 9,329 TUBING DETAIL 122/26/1975 HB -1 3-1/2" 9.3 L-80 TPL 4040 2.67 42.95 9,675' JEWELRY DETAIL NO. Depth (ft) ID (in) Item Hangar 42.95 11" X3-1/2" Tubing Hanger 1 6,615 5.00 9-5/8in Hyd Perm Packer(TriPoint) 2 6,691 3.00 3.5in T2 On/Off Tool 3 9,622 5.00 9-5/8in Hyd Perm Packer (TriPoint) 4 9,667 1 2.313 XLanding Nipple 5 9,675 1 3.25013-1/2" WLEG PERFORATIONS Interval rop M D (ft) 3trn M D (ft) Top TVD (ft) Btm M D (ft) SPF Date G-1 9,709 9,736 8,850 8,875 5 6/28/2014 G-2 9,759 9,780 8,896 8,95 5 6/28/2043 G-3 9,821 9,857 8,952 8,985 5 6/28/2014 GA 9,868 9,925 8,995 9,047 5 6/28/2014 G-4 9,931 9,958 9,052 9,076 5 6/28/2041 G-5 10,05 10,079 9,28 9,116 5 6/28/2041 HB -1 11,223 9270 9,317 9,360 7/3/1968 HB -1 D,236 D,266 9,329 9,356 122/26/1975 HB -1 D,230 13,260 9,324 9,351 4/6/1176 HB -1 10,228 13,268 9,322 9,358 8/0/1980 HB -1 10,228 0,268 9,322 9,358 5/11984 HB -1 10,225 1),265 9,319 9,355 9/19/1388 1-113-2 D,290 13,375 9,378 9,456 7/3/1968 HB -2 10,290 0,330 9,378 9,45 12/26/1975 HB -2 13,355 0,385 9,438 9,465 4/26/075 HB -2 13,290 10,340 9,378 9,424 4/6/1376 HB -2 0,290 10,375 9,378 9,456 15/1977 HB -2 0,290 0,370 9,378 9,451 8/16/080 HB -2 0,290 10,370 9,378 9,451 5/1084 1-113-2 10,295 0,370 9,383 9,451 8/19/1988 HB -2 0,352 10,372 9,435 9,453 3/16/2008 HB -3 13,400 10,435 9,479 9,511 12/26/1975 HB -3 0,396 10,436 9,475 9,511 4/6/1976 HB -3 0,400 D,440 9,479 9,55 8/0/1980 HB -3 13,398 10,40 9,477 9,495 3/5/2008 HB -3&4 0,395 10,590 9,474 9,652 7/3/1968 HB -4 13,476 10,491 9,548 9,562 12/26/075 HB -4 0,502 0,537 9,572 9,604 4/26/1975 HB -4 13,460 10,520 9,533 9,588 4/6/1976 HB -4 0,550 1),575 9.5sl 9,638 4/6/1976 HB -4 0,460 0,490 9,533 9,561 8/8/080 HB -4 10,501 10,521 9,571 9,589 8/'1/080 HB -4 13,540 0,560 9,606 9,625 8/19/080 HBA D,466 1),491 9,539 9,562 9/19/088 HB -5 10,613 10,700 9,670 9,752 7/3/068 Fish in Well MAX HOLE ANGLE = 30.7° p@ 5,900' Fish No. 1 Unknown length of wire and 1-11/16" X 13.3 long GR/CCL tool string at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel @10,655' 2.83' long, Max OD 5.5" (3/26/76) Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3-1/2" tubing 18.15' Left in hole (8/80) Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 1 5/24/14 8/31/14 Daily Operations: 05/24/14 - Saturday Rigging up. 05/25/14 —Sunday Rigging up. 05/26/14 - Monday Mix LCM pill. Rigging up circ lines to tree, change out tree cap, pump tbg capacity of 88 bbls FIW, filled tbg w/ 66 bbls, before seeing pressure. Shut down pump pressure bleed to "0" in seconds and went on vacuum. Pump 20 bbls nw 50 Icm pill and displace w/ 78 bbls FIW at 2 bpm w/ 1975 psi, on tbg and 2200 psi on csg. Shut down pump, pressure bleed 1,975 psi to 890 psi in 30 minutes. Monitor well for 30 minutes. Rigged up return line to well. Clean tank filled hole w/ 37 bbls of FIW, got clean water back, shut down monitor well for 1 hr. Filled hole w/ 1 bbl FIW. Set BPV, nipple down head, remove same for well room, prep head, nipple up bops. 05/27/14 -Tuesday Rig up test jt. x7 x/o's, TIW. IBOP, &function bop's from remote, Installing floor plates & clean floor of excess equipment, lay down rig up lines, Rig up 2" line from choke manifold to gas buster- rig up bleed line from pump pop off valve to return tank, fill bops' with FIW attempt to test ;annular & Ibop, IBOP leaking, Rig down TIW & IBOP, change out Ibop & rig up test equipment, test no 2 had slow bleed off grease & work choke manifold valves, test # 3 OK, test #4 chart recorder failed to work, change out chart recorder, continue testing bop's and surface equipment to 250 low & 3000 psi hi, with FIW, held each test for 5 minutes on chart preform Koomey drill. Test witness was waived on 5-23-14 at 15:30 hrs by Mr. Jim Regg w/AOGCC. R/Up E -line, test lubricator to 500 psi. RIH w/ 1-9/16" tbg punch & log on depth, punch holes at 10,105't 10,108'. Pooh. RIH w/ 2" RCT cutter and log on depth & cut tbg at 10,108' WLM. Pooh rig down cutter. Brk out lubricator jt. and tongs. Make up BHA #1 with spear, Engage spear, unseated hanger at 60k, working pipe f/ 60k to 120k attempting to free same. 05/28/14 - Wednesday Working pipe f/ 60k to 130k attempting to free same. Lost weight, pooh to check grapple. Had hanger on spear, lay down hanger & pups. Pooh lay down fish, recovered (hanger, x/o, 5 pups, 6 full jts of 3.5" 9.3#, buttress modified, L-80, SC production. Total fish recovered =254.07'. Waiting on fishing tools. Made up 8-1/8 overshot dressed w/ 3-7/8 grapple, x/over, bumper jar, oil jar, (6) 4-3/4 drill collars, x/o). Rih w/ 3 jts 3.5 ph -6 work string, attempt to engage fish, unable to catch same. Pooh inspect and cut lip guide had marks 3" up inside lip of guide. RIH w/ 8-1/8 overshot dressed w/ 3-7/8 grapple, x/over, bumper jar, oil jar,6 4-3/4 drill collars, x/o) Rih w/ 3 jts 3.5 ph -6 work string, attempt to engage fish, unable to catch same. R/d Kelly hose, pooh. Lay down cur lip guide. Riggi S_up to run wash pipe. P/u BHA Out side cutter, 3 jts of 8-1/8 wash pipe, top sub, oil jar bumper jar, (6) 4-3/4 drill collars, x/o. P/u power swivel, locate collar, make cut on fish. Rig down power swivel. Pooh. Lay do 1 ft fish 32.64, cut was made in middle of tool jt, inspect cutter found slips on cutter was broke. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 168-043 1 5/24/14 8/31/14 Datl�r Op�ra�ltons 05/29/14 - Thursday Make up 8-1/8 wash pipe. Made external cutter, tin w/ same. Rig up power swivel, pick up and locate collar, made cut at 382'. Rig down power swivel. Pooh w/ work string, shuck fish, recovered 95.23 ft of fish. Cut was made in middle of tool jt. Made up over shot and RIH latch onto fish. Rig up sheaves, perform stretch readings pick up to 110k, wt dropped off to 105k, pick up to 110 k wt dropped off to 100k and continue picking up pipe free. Pooh work string and shuck overshot. Pooh laying down 3.5 buttress 9.3# L-80 production tbg. Fluid u -tubing reverse 1 tbg volume. Pooh Laying down 3.5, buttress, 9.3, L-80 production tbg. 152 jts laid down at rpt time 4758 ft. 05/30/14 - Friday Pooh laying down 251 jts of 3.5, 9.3#, Buttress Modified, L-80, SC, Production tbg, fish laid down = 7854.35'. Total fish laid down 8278.29'. Est TOF 82_79', leaving 58 jts, pup and seals in hole. Total fish in hole 1881'. Cleaning floor and gathering BHA. P/up BHA #5 (8-1/2 Bit, bit sub, X -over, Bumper jar, Oil Jar, (6) 4-3/4 drill collar, Acc Jars, x/over, = 223.72' ) TIH w/ 5 stds out of derrick. TIH Picking up 3.5 ph -6 tbg tagged the top scab liner packer at 6640'. Circ hole clean. Rig down circ hose. Pooh. 05/31/14 - Saturday Pooh w/ work string, lay out bit, x/o's. Waiting x/o from town, the one sent out was to big for ID of scab liner. Making up BHA, mechanical, inside cutter, x/o, bumper jar, oil, (6) 4-3/4 drill collars, acc jar, x/o = 268.11') Trip in hole w/ work string, picking up 8 jts 3.5 ph 6 off deck. Rigging up power swivel and space out same, making cut on 7" scab liner @ 6896'. Rig down power swivel. Start pooh, work string wet, rig up circ hoses, attempt to unplug. Unable to unplug. Continue pooh w/ workstring, pulling a wet string. Laying down plug BHA. Clean floor. 06/01/14 - Sunday Cleaning rig floor and unplugging BHA. Made up mule shoe, This w/ same with 11 stds of 3.5 ph -6 work string. Continue TIH to 8233' picking up 52 jts 3.5 pipe off the deck. Spot 20 bbls of NW 50 LCM pill. Pooh w/ 4 stds pipe to 8109', circ and weight up fluid from .5 ppg to 9.6+ ppg. 06/02/14 - Monday Circ at 2 bpm weighting up to 9.6 ppg taking returns to well clean out tank. Circ taking returns to pits, continue circulating weighting up. Pooh w/ work string, laid down mule shoe. Pick up BHA (slick bore packer retrieving spear 2-7/8 prt, packer mill, sub, canfield bushing, skirted junk basket, bit sub, magnet, x/over, bumper jar, oil jar, (4) 4-3/4 drill collars, acc, jar, x/ over = (185.26 ). Trip in hole with work string tagging packer at 6640'. Rig up power swivel, attempt to circ, pipe was plug, surge same, and unplug same. Milling on packer f/ 6640'- 6643'. 06/03/14 - Tuesday Continue milling on packer at 6643' dpm, circ and cond fluid at 6643' dpm at 2.5 bpm had 20% gas on btm up. Circ out same, pump dry job. Pooh had 20 k over pull for 70' then back to normal up drag. Rigging up test equipment and filling up stack and flushing lines. Testing bops and related surface equipment to 250 low and 3000 psi high. Had no failures. Mr. Johnny Hill with AOGCC on board to witness test. Pick up BHA 6" Grapple, w/ spear, oil jar, bumper jar, (4) 4-3/4 drill collars, acc jar, x/o = 164.96' ). Engage fish at 6642', jarring on fish at 50k over. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 1 5/24/14 8/31/14 Daily Operatonsr 06/04/14 - Wednesday Jarring on stuck fish at 150k _pulling up to 210k, fish pulled free. Lay down pup jt. and started to POOH, fish stuck, ETOF at 6610'. Jarring on fish f/ 190k pulling up to 235k, working back down to 60k. Shuck spear to be able to space out to pick up Vibrator. Space out with pups, clearing equipment on deck to spot power pack. Continue to jar on fish at 190k pulling up to 235k working back down to 60k had no movement on fish. Rigging up vibrator and making up subs, working fish vibrating same f/ 80k down to 180k up. Hold fish intension then working fish back down trying different weights, pumping at 4.5 bpm. Circ out gas 33% no fluid cut. Had slight movement at one time then stop, rig down vibrator and hoses & inspect draw works and derrick, crown. Release spear, Pooh. L/d spear, slip and cut drill line. 06/05/14 - Thursday Slip and cut drill line. Service rig. PU 7" mechanical cutter, TIH to 6706'. RU power swivel. Function test power swivel. Make cut at 6706', pumping 1/2 bpm with 30 rpm for 1 hour. RD power swivel, POOH. PU MU 7" spear, 7" spear pack off, 4 3/4 jars, 4 3/4 drill collars. TIH to spear 7" scab liner. 06/06/14 - Friday 7" spear and spear pickoff, 4 3/4 bumper, oil, (4) 4 3/4 drill collars, 4 3/4 intensifier, crossover to 3 1/2 PH-6 work string. Engaged in 7" 29# scab liner top at 6610'. Begin jarring and overpull to 250K. Work with no movement up and 7' movement down. Pump 2 bpm with no pressure and full returns. Released spear assembly. POOH, spear pack off cup had piece missing. Spear grapple good. Break out lay down. PU 7" mechanical cutter, 6" OD non rotating stabilizer, crossover to 3 1/2 work string. TIH to 6686' RU power swivel. Make cut. RD power swivel. POOH, Finish POOH. Break out 7" mechanical cutter. Lay down. Bottom nut of mechanical cutter was missing. 5 3/4" OD x 8" long. Good wear pattern on knives. Begin picking up 6 1/4 OD drilling jars, (10) 4 3/4 drill collars, 6 1/4 OD intensifier. crossover to 3 1/2 work string now. 06/07/14-Saturday TIH with 7" spear/spear packoff, 6 1/4 drilling jars, (10) 4 3/4 drill collars, 6 1/4 intensifier xover to workstring. TIH to 6610' TOF 7" scab liner. Engage and begin working and jarring 60K down to 235K up. After 1 hour fish came free. Pulled 2 stands and rigged up pump. Pumped at 3 bpm while working pipe. POOH. Recovered 6 joints 7" scab liner and Baker FB anchor latch. Broke out and laid down in singles. PU 6 1/4" Drilling jar and break out spear, spear packoff, crossovers. PU packer retrieving tool, junk baskets, and inline magnets, 4 3/4 bumper, oil, (6) 4 3/4 drill collars, 4 3/4 intensifier, xover to work string. TIH with packer retrieving assembly to 6769' tagged obstruction. Set up to 30K down. No go. POOH. Will PU 8 3/8 tapered mill, 8 3/8 string mill, jars, drill collars. Will send in Test Witness notification to AOGCC for BOPE test for Tuesday. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 -` a — F 7�Pi�i� ;` �� ` ih� = Qal�y 0(3atlOn�. 4 � � �� «. 06/08/14 - Sunday Cont. POOH w/ packer retrieving assembly. L/d BHA, P/U taper milling assembly. BHA # 15, taper mill 8 3/8", bit sub, watermelon mill 8 1/2", string magnet, drilling jar, xo, 6-4 3/4" dc, xo=238'. Tih w/3 1/2 ph -6 wk string t/6760' up wt 108, do wt 82. P/u power swivel, tag tight spot @ 6769'. Wash & ream t/6774' breaking through obstruction, circ @ 3.5bpm, 45 psi, rot wt, 95k. Cont wash t/ 6793' clean. Rev. cbu x2 @ 3.5 bpm bringing back scale. L/d swivel & tih t/tag top of packer @ 6895'. POOH & I/d taper mill assy. String magnet full of metal shavings. P/U packer retrieving assembly, BHA # 14 run 2, packer retrieving tool, junk basket, bit sub, string magnet, xo, bumper jar, oil jar, 6-4 3/4 DC, xo= 230'. Tih t/ 6879', up wt 108, do wt 84. P/u swivel. Circ @ 140gpm, 40 psi, tag @ 6896' wk pipe unable to fall in packer w/6" spear mill. P/u, no signs of overpull or drag. Rot @ 40 rpm tq off 4k, on 4-5, tool not falling in (should have 7' travel in spear assembly past top of packer). L/d swivel. Start POOH. 06/09/14 - Monday Cont. POOH w/ packer retrieval assy. L/D BHA, nose of spear assy polished. R/U w/l, p/u 2.5 magnet on 5.5" cent. Tih t/6877', wlm. POOH, retrieving a 2" x 1/2" piece of metal & shavings. Re -run bringing back shavings. Rih w/2" drive bailer no recovery and no downward movement. Run 5" & 3.71 LIB's w/no distinctive pics. R/D w/I prep t/ p/u BHA. Clean & clear floor, rig maintenance while waiting for shoe f/beach. P/U BHA# 17, 8 1/2 packer shoe & bushing, DP sub, junk basket, bit sub, string magnet, xo, bumper jar, oil jar, 6- 4 3/4" DC, xo= 230'. Tih t/6878', up wt 108, do wt 84. P/u swivel, RIH t/tag @ 6896', pump 3.5 bpm, 30 psi, rot 60 rpm, rot wt 94, tq 4k off, 4.5k on. Mill packer f/ 6896't/6899', broke free, pushed down t/ 6909'. R/d swivel, POOH. 06/10/14 -Tuesday Cont. POOH I/d BHA, recover 30 lbs metal shavings & coal f/ magnets & boot basket. Clear floor, m/u 3 1/2 test jt. Rih set test plug. Fill stack & valve manifolds. Test BOPE as per Hilcorp & AOGCC regulations, witness waived by AOGCC Jim Regg on 6-8-14 @ 9:40. Test BOPE 250 low, 3000 high, test Annular 250 low, 2500 high. Test with 3 1/2" tj, all good. Pull test plug, set wear bushing, I/d test jt. P/U BHA, overshot w/ 6 3/4 grapple, xo, bumper jar, oil jar, 6- 4 3/4 DC, xo=212'. TIH t/ 6922' up wt.104, do wt 78. Cont tih t/ 7295' had drag of 6k going down, pu w/ 30k op falling off, rev CBU x2 @ 3.5 bpm, 110psi. Cont tih tag @ 8118', set down 20k. P/u dragging 30-45k over pull. Cont. POOH t/7974' w/drag 20-40k, Rev CBU x2, 3.5 bpm, 75 psi, POOH dragging t/742'. 06/11/14 - Wednesday Cont. POOH & L/D BHA retrieving FA packer. P/U BHA 19, 8 1/8" shoe w/bushing, xo, bumper jar, oil jar, (6) 4 3/4" DC, xo = 216'. TIH t/ 8,101', up wt 125, do wt 85, P/U swivel, Rev circ @ 3.5 bpm, 150 psi, rot 40 rpm, rot wt 104, tq off 3-4, on 4-5. Tag @ 8,118', wash & ream t/8,224'. CBU, clean before connection. Cont. wash & ream t/8,242' stop making headway. P/U set back down, lost 4', wk several times before getting past obstruction and back down to 8,242'. L/D swivel & start POOH. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 Daily Opeeations:d 06/12/14 - Thursday Cont. POOH. L/D C/O assy. No recovery in shoe trap, recovered pieces of slips from milled packer in jars. Clean & clear floor. Service rig. R/U W/L, run 2.5" magnet on 5.5" stab. t/ 8,222' wlm. Retrieve 10" x 4"x 3/16" peeled metal & 3/4" band 20" long. Re-ran magnet recovering 6"x3" 3/16" metal. Re-run magnet retrieving 5 3/4" nut from cutter. Re-run magnet 2 more times recovering fine shavings. Run 6.5" LIB had 2 dimples 3/4" diam. R/D W/L. P/U BHA #20, 8 1/2" bladed junk mill, boot basket, bit sub, string magnet, xo, bumperjar, oil jar, 6- 4 3/4" DC, xo=223'. TIH t/8,020' tag tight spot. P/U swivel, circ. 140 gpm, 90 psi, rot 60 rpm, tq off 4200, on 4-6, wk t/8,025'- tight stalling. L/D swivel POOH t/543'. 06/13/14 - Friday Cont. POOH L/D BHA. Mill had markings on outside leading edge. P/U BHA 21, taper mill 8 3/8", bit sub, watermelon mill 8 1/2", string magnet, xo, bumper jar, oil jar, xo, 6-4 3/4" dc, xo=227'. TIH t/7,988' up wt 125, do wt 85. P/U swivel. Wash & ream f/8,019' t/ 8,028', circ 3.5 bpm, 140 psi, rot wt 100, tq off 4k on 4.5-5k. L/D swivel. TIH t/ 8,236' good, cub @ 3.5 bpm, 145 psi. POOH, L/D taper mill BHA assy. P/U BHA #22, 8 1/2" bladed junk mill, boot basket, bit sub, string magnet, xo, bumper jar, oil jar, 6- 4 3/4" DC, xo=223'. TIH t/ 8,233'. P/U power swivel, broke circulation, mill on fish fr/ 8,238' to 8,243' mill 5', rot/wt 108 K, RPM 65, P/U wt 124 K, S/O wt 95K, PP 100 psi, @ 185 gpm. Close Annular & reverse out 2 - tubing volume @ 8,243'. 125 psi @ 185 gpm. POOH w/ 8 1/2" bladed junk mill. 06/14/14 - Saturday POOH W/ 8 1/2" 4- blade junk mill & L/D same. P/U BHA 8 1/2" OD packer type shoe, 3 - jts 8 1/8" OD wash pipe, canfield bushing 4 1/2" IF X 8 1/8" KHT, XO 3 1/2" IF box X 4 1/2" IF pin, Bumper jar, Oil jar, 6 - 4 3/4" DC & XO =305'. TIH W/ BHA & 3 1/2" work string t/869', stopped moving, tried to push through no go. POOH found scrape marks on upper part of upper W/P jt. L/D jt. M/U bushing. TIH W/ 2 JTS W/P BHA & 3 1/2" work string T/ 869', stop moving, tried to push through made about 30' no go. POOH L/D upper W/P jt. L/D jt. M/U bushing. TIH W/ 1jt W/P BHA & 3 1/2" work string, tag top fish @ 8,243'. 8 1/2" OD packer type shoe, 1jt 8 1/8" OD wash pipe, canfield bushing, 4 1/2" IF X 8 1/8" KHT, KO 3 1/2" IF box X 4 1/2" IF pin, bumper jar, oil jar,6 - 4 3/4" DC, XO = 247'. P/U power swivel, Line up to reverse circulate, Wash over fish F/ 8,243' to 8,278' ( 35'). St/wt 120K, S/O 94K, P/U 124K, Rot. 108K, 100 SPM, 100 PSI @ 185 GPM. Reverse circulate 2 - tubing volume @ 8,278'. L/D power swivel & 1jt 3 1/2" work string. POOH F/ 8,278' to BHA. L/D jars, canfield bushing, wash pipe, 8 1/2" OD packer type shoe & OX sub. Clear rig floor . Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 168-043 1 5/24/14 8/31/14 'Daily Operations. s 06/15/14 - Sunday P/U & TIH W/ 6 1/2" Over -shot W/ 3 1/2" Grapple, BHA & 3 1/2" W/S to top fish @ 8,243'. 6 1/2" OD over -shot D/W 3 1/2" grapple, drilling jar, XO sub 3 1/2" IF X 4 1/2" IF, 10 - 4 3/4" OD drill collars 3 1/2" IF, XO 3 1/2" PH -6 X 3 1/2" IF. P/U swivel, Latch on to fish @ 8,243', pull fish free. P/U wt. 134K, S/0 wt. 94K. Free 210K, 168 - 180K drag. falling off t/ 136k. L/D power swivel, POOH W/ fish. L/D jar. POOH Breaking out & L/D 6 1/2" over shot & 3jts + cut jt fish. Total fish L/D 123.09'. P/U 5 1/2" Bladed junk mill, TIH W/ BHA & 3 1/2" work string tag fill @ 8,275'. 5 1/2" Bladed junk mill, bit sub 4 1/2" Reg X 4 1/2" IF, drilling jar, XO sub 3 1/2" IF X 4 1/2" IF, 10 - 4 3/4" drill collars 3 1/2" IF, XO sub PH -6 X 3 1/2" IF. P/U Power swivel broke circulation washing F/ 8,275' to top fish @ 8,375'. Chase fish from 8,375' to 8,380'. Attempting to dress of top fish @ 8,380'. P/U wt. 138K, S/0 wt. 94K, P/S 100 spm, P/P 175 psi @ 185 gpm. P/U close annular & reverse out 2 - tubing volume. 100 spm, P/P 175 @ 185 gpm. L/D swivel & POOH W/ 5 1/2" bladed junk mill. 06/16/14 - Monday POOH W/ 8 1/2" Bladed junk mill BHA & L/D same. P/U BHA, 8 1/8" overshot w/3 1/2" grapple, drilling jar, xo, 10 -4 3/4" DC, xo =350'. TIH W/over shot, BHA, to 8,362'. P/U power swivel, break circulation, reverse circulate & washing F/ 8,362' to 8,446'. Engage fish @ 8,446', P/U t/ 8,425' 12K above normal drag. 146K - 158K, CBU 145 GPM, 146 PSI. L/D Power swivel. POOH F/8,425' to the drilling jars. L/D drilling jars, POOH breaking out & L/D 8 1/8" over shot + 1,665.11' fish. (52 jts + 15.15' cut jt). Clearing rig floor. 06/17/14 -Tuesday Cont. clean floor & drill deck. M/U 3 1/2" Test jt. RIH pull wear ring, set test plug, fill stack & valve manifold. Test BOPE as per Hilcorp & AOGCC regulations, Witness waived by Jim Regg on 6 -16-14. Test BOPE & valves 250 low & 3000 high. Good. Attempt to test annular 250 low & 2500 high test failed. L/D test jt, close & lock down blind ram. R/D rig floor, Pull bell nipple. Change annular preventer element. Install bell nipple, floor, dresser sleeve & flow line. P/U test jt, close annular test 250 low 2500 high each test 5 min on chart, good. L/D test plug, set wear bushing & L/D test jt. P/U BHA, 8 1/8" overshot w/3 1/2" grapple, drilling jar, xo, 10 -4 3/4" DC, xo =350'. TIH W/ 8 1/8" OD overshot, BHA & 3 1/2" W/S to 8,112'. Hung block & slip & cut 200' 11/8" drill line. 06/18/14 - Wednesday Finish cutting drill line. Cont. TIH from 8,112't/ 8,739' start P/U singles TIH t/tag fill @ 10,032'. P/U power swivel. Wash F/ 10,032' to top fish @ 10,108'. Tag TOF @10,108'. Close annular & reverse circulate hole clean. Wk string t/ engage fish. P/U w/40k op falling off t/6k. L/D power swivel. Fluid U - tubing. Pump 23 bbls 9.9ppg slug, POOH to 6,401'. Cont. POOH slow F/ 6,401' to drilling jars. L/D drilling jar, 8 1/8" over shot w/ fish. 06/19/14 - Thursday Cont. L/D fish, 3 1/2" cut jt, pup jt, 15' seal assy, 3 1/2" jt, x nipple, 3 1/2" jt, mule shoe. Clear floor. P/U BHA # 27, packer retrieval spear w/ext., 8 1/2" packer mill, bushing, xo, xo, mud motor, xo, double pin sub, junk mill, bit sub, string magnet, xo, bumperjar, oil jar, 6- 4 3/4" dc, xo =270'. TIH t/ 300', test mud motor, good. Cont. TIH t/ 6,794'. Trouble shoot drawworks w/ mechanic. Found input shaft on drawwork broken. Pull out same. Waiting on new shaft & bearing. Housekeeping & rig maintenance. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 168-043 5/24/14 8/31/14 - 06/20/14 - Friday Parts in transit for D/W repair. Performed housekeeping and general equipment maintenance while waiting on parts. Attempt to take fish out of over shot & failed. 06/21/14 - Saturday Rig service. P/U secondary shaft w/ crane. Set in place @ 16:45. Installing shaft, chains sprockets, chains, chain guards & add oil to chains guards. P/U tools test run empty block up & down w/ mechanic checking out draw works. OK. Prepared to TIH, Foster tongs not working. Mechanic checked out the hydraulic pump on engine, not pumping in full capacity, switch to the power pack unit, blew a hose. Repaired lines on power pack. TIH F/ 6,794' to 7,538', tight hole @ 7,538'. P/U power swivel @ 7,538', attempt to wash tight spot @ 7,538'W/ 8 1/2" packer head mill & mud motor, stalling mud motor. L/D power swivel. 06/22/14 - Sunday POOH L/D packer mill/retrieval BHA. C/O Hyd pump on rig skid. P/U BHA 28, taper mill 8 3/8", bit sub, watermelon mill 8 1/2", string magnet, X0, bumperjar, oil jar, XO, 6-4 3/4" DC, XO=227'. TIH t/ 8,567' tight hole 19:30. P/U power swivel, ream through tight hole @ 8,567', P/U 136K, S/0 94K, Rot 112, 200 psi, 3 1/2 bbls min. L/D power swivel. TIH F/ 8,615' to 8,741'. Wash & ream tight spot @ 8,741', 8,896', 9,647', 9,704', 9,741'. P/U 138K, S/0 96K, Rot 126K, Free torque 6K, 200 psi, 3 1/2 bbls min. Close annular @ 9,741' & reverse circulate 2 - tubing volume @ 3 1/2 bbls min, 200 psi. L/D Power swivel. TIH F/ 9,741' to 10,110'. P/U Power swivel, wash & ream F/ 10,110' to 10,115'. P/U 138K, S/0 96K, Rot 126K, Free torque 6K, 200 psi, 3 1/2 bbls min. Close annular, reverse circulate @ 10,115', 1 - tubing volume @ 3 1/2 bbls min. 200 psi. Wash & ream F/ 10,115' to 10,127' top of packer. Close annular & reverse out @ 10,127'. 06/23/14 - Monday Cont. CBU clean @ 3.5 BPM, 240 PSI. L/D swivel. POOH t/ 7,526'. Wash & ream f/ 7,526'-7,557' @ 3.5 BPM, tq 4-4.5. L/D swivel. POOH t/ 6,720'. P/U swivel. Wash & ream f/ 6,720'- 6,751' @ 3.5 BPM, tq 4. L/D swivel. Cont. POOH W/ 8 1/2" Taper/string mill BHA & L/D same. P/U BHA # 29, packer retrieval spear w/ext., 8 1/2" packer mill, bushing, xo, xo, mud motor, double pin sub, junk basket, junk basket, bit sub, bumper jar, oil jar, 6- 4 3/4" dc, xo, string magnet, xo, xo =275'. TIH W/ BHA # 29 & 3 1/2" WS to 9,649'. Tight hole. P/U Power swivel. Wash & ream f/ 9,632' to 9,649', tight hole @ 3.5 BPM, 144K, 94K. L/D Power swivel & P/U mud bucket. POOH W/ 8 1/2" packer mill. 06/24/14-Tuesday Cont. POOH W/ 8 1/2" packer mill & L/D BHA # 29. Clean rig floor. Pull wear bushing. Land test plug. Fill BOP W/ filter water. Test BOPE as per Hilcorp & AOGCC regulations, Witness waived by Jim Regg on 6 -23-14 @ 10:41. Test BOPE & valves 250 low & 3000 high, Annular 250 low & 2500 high, Good. Pull test plug & landed wear bushing. Spot E-Line. Held JSA. R/U E-line w/ 40 arm caliber. Ran in hole w/ 40 arm caliber log to 10,113' wire line depth. Log up f/ 10,113' to surface @ 50' min. R/D E-Line & lubricator. P/U BHA 30, taper mill 8 1/2", bit sub, XO, string mill 8 1/2", XO, XO, string magnet 4 7/8", X0, bumper jar, oil jar, XO, 6-4 3/4" DC, XC=231'. TIH W/ BHA & 3 1/2" tubing. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 gaily Clper-atilion 06/25/14 - Wednesday Con. TIH W/ 8 1/2" taper mill & 3 1/2" tubing to 9,720'. Tight hole. Pull up to 9,682'. Pump out 141 bbls f/ pits to production. Clean pits. Mix 120 bbls 3% kcl, wt up t/ 9.4 w/ o/f salt, displacing hole w/ 9.4 ppg brine @ 3 bbls min. 450 psi.. POOH W/ 8 1/2" taper/string mill BHA & L/D same. P/U & breaking down packer plucker & L/D same. Clear rig floor. P/U 9 5/8" RTTS tool. TIH W/ same. 06/26/14 - Thursday Finis-h TIH to 6659' with 9 5/8" test packer. Pressure to 2500 psi. Leak off 250 psi in 15 minutes. Bleed off and release packer and pull up to 6,597', attempt to retest, no luck. Pull up to 6,561' retest no luck. Check all surface equipment. All good. Check chart recorder. Noticed vibration on chart recorder so repositioned and placed rubber matt under recorder. Retested good at 2500 psi for 30 minutes good. TIH to 6,659' retested 2500 psi for 30 minutes tested good. Bleed off and POOH with test packer. Finish POOH, break out test packer. TIH with 5 stands 4 3/4" drill collars, 3 stands 3 1/2" ph-6 tubing, test packer to 200'. Set packer, release from packer POOH. Test packer, no test. Check all surface equipment, all good. Reset packer and retest, no luck. Order new test packer. Wait on packer. 06/27/14 - Friday PU MU to drill collars. TIH to 200'. Attempt to test packer. No luck. Found 9 5/8" casing valve leak. Removed 2" hose, installed bull plug. Tested good 2500 psi 30 minutes charted. POOH with 3 stands tubing. Rack back. Remove rig floor. ND BOP/riser and hang off under floor structure. ND tubing wellhead. Clean and prepare for new tubing head. Install new . tubing head. Test to 3000 psi. Test good but secondary seal had rolled over top of 9 5/8" casing stub. Pull tubing head and redress with new seals. Used R-57 ring gasket instead of RX 57 to make head sit 1/4" lower. Test tubing head to 3000 psi, test good, seals stayed in place. NU riser/BOP. Test tubing head on chart 3000 psi for 30 minutes. Test good. Install drip pan and floor. 06/28/14 - Saturday Finish NU BOP riser/drip pan. TIH release test packer. POOH. Lay down packer. Lay down (9) 4 3/4" drill collars in singles. Change slip inserts. Install wear bushing. Hold JSA on perforating. PU TCP guns, LSDS sub, 2 7/8" 8 RD tubing crossover to 3 1/2" PH-6 work string. Drop drift through tubing on each stand. TIH to 10,114.50'. Tagged packer 13' high with TCP BHA. RU Eline GR/CCL. TIH and log 8,750'- 9,650'. Log showed guns were 5' high. Discussed with Engineer and Geologist. Decision made to shoot guns at current depth 5' high. POOH with Eline. RD. Drop bar and monitor well. Reverse circulate well one tubing volume. Took 7 bbls to get circulation. Begin POOH. Well U-tubing. Mix 40 bbl 9.9 salt pill. Pump pill down tubing. Continue POOH laying down workstring in singles. 06/29/14-Sunday POOH with 3 1/2" PH-6 work string laying down in singles. Continue POOH with work string and perf guns. Laying out in singles. Load perf guns in basket. All shots fired. Rig down rig tongs. RU Weatherford tongs. Remove wear bushing. Move completion equipment in place. Strap first bundle of 20 joints 3 1/2" TPL 4040 tubing. Begin PU WLEg, one joint tubing, X nipple and pup joint and RIH. Hole took 78 bbls fluid. Mix 120 bbl 3% KCL 9.4 fluid. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 06/30/14 - Monday Hold JSA with crew on running completion packers and tubing. PU WLEG, 3-1/2" EUE tubing, packer, 2,982'3-1/2" TPL 4040 tubing, 2nd packer 3-1/2" Tubing RIH at 30 seconds per joint, 1 hour per bundle of 20 jts. tubing. Drifting every joint using stabbing guide. At 5,094' EOT/5,019.5' bottom packer depth we stopped suddenly. Begin working from string weight of 45K to 95K in 10K increments slowly. Worked for 11/2 hours. Pressured up on casing to 500 psi. Held pressure with no bleed off. Bleed off pressure. RU slick line with JS tool. TIH and retrieved plug 5060 in X nipple. POOH. Recovered plug. RD slick line. MU Kelly hose, pressure up again to 500 psi on 9 5/8" casing, held pressure. Bleed off. RU Eline unit. TIH with free point indicator. Make readings to 200' below top packer at 2,031.5'. Top packer shows to be stuck or preset. POOH with Eline. Will discuss options with Anchorage office. 07/01/14-Tuesday TIH with free point indicator, top packer at 2,031.79' showed no movement. POOH. TIH with hole punch to 2,006'. TIH with 2" OD radial torch cutter. Detonate cutter at 2,006', (1) crossover, xo pup joint and 10" above packer. POOH. Pull and attempt to pull free. Work cut up to 45K over. Begin getting 8" of movement at 35K over. Would move up and down. TIH with free point indicator. Pipe shows no movement below top packer. POOH, PU MU 2nd RTC TIH to 2,008'. Fire cutter. PU no indication of cut. POOH. Work pipe. Could not part at cut. Continue to work pipe. Wait on 2 1/2" OD jet cutter to be flown out. Arrived at 5:30 am. Will run 2 1/2 gauge run, then jet cutter. 07/02/14 - Wednesday RU 2.5 OD gauge on eline. TIH to 2,046'. Gauge went good. POOH, MU 2.5 OD Spectra jet cutter. TIH to 2,010'. Fill well with 9.4 fluid 38 bbls. Fire cutter. Had good indications at surface. POOH. Pull on pipe no cut. Work pipe from 15K to 25K with RH torque. Worked pipe up to 80K. No luck. MU tubing swivel and Y block. TIH with string shot to 2,018'. Torque pipe to the right. Put left hand torque and fire string shot. Back off pipe. POOH RD Eline. Move Eline unit and tubing from pipe racks. Adjust draworks brake. POOH with 3 1/2 TPL 4040 tubing laying down in singles. No indication of penetration from (2) RTC cuts. Jet cut had bulged pipe from 3 1/2" to 4 3/16". RD Weatherford tongs and hoses. RU Foster tongs and change out dies. MU 8 1/8" overshot with 5" grapple, 4 3/4" bumper, oil, (6) 4 3/4" drill collars, 4 3/4" intensifier, xo to 3 1/2" PH-6 work string. Picking up in singles tallying. Tagged fish at 2,018' and attempt to engage. No luck. POOH. Rechecked dimensions on completion schematic. Markings on stop ring show 4 1/4" OD. Coupling looking up should be 4 1/4". Changed grapple to 4 1/4" OD. currently TIH. 07/03/14 - Thursday TIH to 2,010' engage 4 1/4" coupling with 8 1/8" overshot. Jar for 2 hours with no movement. Release overshot, POOH. PU 5 3/4" overshot with 8 1/2" flat bottom shoe, 8 1/8" wash pipe extension, JB busing, 1 joint 8 1/8" wash pipe, 4 3/4" bumper, oil jars, (6) 4 3/4" drill collars, 4 3/4" intensifier. TIH hitting tight spot at 600'. Work through tight spot. TIH to 2,010'. PU power swivel. Engage 5 3/4" overshot to 3 1/2" TPL 4040 coupling. Take pull 10K over. Un "J" from JB Bushing lower to 6' above packer. Tight spot in 9 5/8" casing. Ream and fell through 3'. Power swivel went down. Power pack would not restart. RU. Begin milling tight spot 2 1/2' above packer at 2,011.5'. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 168-043 5/24/14 8/31/14 07/04/14 - Friday TIH with 8 1/2" shoe, J bushing, (1) joint 8 1/8" washpipe, 5 3/4" overshot with 4 1/4" grapple. TIH to 2,010'. PU power swivel, engage overshot, take over pull of 40K. Un "J" from J bushing lower down with shoe to 2,007' hit tight spot, reamed and fell through 3'. Continue to 11/2' above packer. Tagged again. Spinning no torque. Lugs 4 3/4" ID spinning on 5" crossover coupling. POOH. Changed packer retriever assy. BHA adding one joint of 8 1/8" washpipe below J bushing and adding one joint 4 3/4" drill internally as extension. TIH to 907' hit tight spot, worked thru. TIH to 2,010'. PU power swivel, engage overshot take overpull of 40K. Un "J" for J bushing lower down 27' to top of packer. Turn on pump and pressured up. Work shoe and get circulation. Begin milling on packer. 2-3K weight, 2 1/2 bpm, 2-3 torque, 70-80 RPM. Turn on pump. Reverse circulating. Pressuring up. Work shoe get circulation. Begin milling. 80 RPM, 2-3K weight, 3 bpm. 2-3K torque. Mill making no headway. Maybe 1-2 inches. No cuttings coming back. Pick swivel back up and begin milling. PU to check depths and measurements again. Overshot had released. Change out swivel. Will re-engage overshot. 07/05/14 - Saturday Milling on 9 5/8" Stimtop packer at 2,031'. Not making progress. Release overshot and POOH with packer milling assembly. Break out and lay down. Test BOPE to 250 low / 3000 psi high. Annular to 250 low / 2500 psi high. No failures. Test waived by Jim Regg, AOGCC. PU MU 8 1/8" overshot with 4 1/4" grapple, crossover to 3 1/2" PH -6 work string. TIH to 2,011' engage 3 1/2" TPL 4040 coupling 4 1/4" OD. RU slickline TIH with 2.313 plug. Could not get past 2,011'. Plug stuck. Pulled shear out sub loosens. TIH with retrieving tool. Engage and pull 2.313 plug free. POOH. TIH with 2.27 Od swage. Stopped at 2,011'. POOH. TIH with 13/4 OD swage to 2,033'. Could not go further. POOH. Order 1" tool string. RU Kelly hose. Fill up 9 5/8" casing. Fill up tubing. Attempt to pressure up to 3500 psi open ended to set packers. Made multiple attempts to reach 3500 psi. Pressured up to 2300 psi maximum. Ordered 10 sacks sand. Will attempt to pump foam balls and dump 30' of sand to create sand bridge to pressure up against. 07/06/14 - Sunday Decision made to set both packers. Attempt to pressure up on tubing to 3500 psi._ Reached 2200 osi.Qp1K,, Waiting on sand. Pumped (2) small foam balls at 1200 strokes at average 650 psi. Dumped 17 gallons of sand in tubing. Wait 45 minutes. Pressure up on workstring to 3500 psi and 4200 psi. RU slick line TIH and tag top of sand at 1,970', 40' above top of completion tubing stub where overshot is latched. Too high. Release overshot and POOH. No sand left in tubing. TIH with new 4 1/4" grapple, 8 1/8" overshot and engage tubing coupling. Pumped one small foam ball and (2) tennis balls. Had 1300 to 1600 psi while pumping 950 strokes. Shut down pump and dumped 15 gallons sand. Wait 45 minutes. Pressured up to 2500 psi. 2nd attempt blew sand and balls out of end of tail pipe. Called and discussed with Engineer to get 1 1/4" CS Hydril tubing, 2 1/8" mud motor, 2.50 tapered mill to clean out to X nipple. Called to organize tubing, handling tools, BOPE. Currently waiting on tools. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 Daily Operations: 07/07/14 - Monday RU power swivel. Release 8 1/8" overshot from 4 1/4" crossover coupling. POOH BO LD overshot. PU MU 8 1/2" flat bottom shoe, (2) 9' washpipe extensions, top bushing, jars, (8) 4 3/4" drill collars, intensifier, xo to 3 1/2" PH -6 work string. TIH to 2,011'. PU power swivel. Adjust torque limiter to 7600 ft. lbs. Lower down over tubing top at 2,011'. Break circulation at 3 bpm, 50 psi, 85 RPMs, 2300 ft. lbs torque, rotating weight 46K. Begin torqueing at 2,019'. Getting hard torque spikes. Power swivel stalling out. PU and try to fan at high rpm's. Lost 1.5' of hole. Could only rotate to get 1.5' of hole back. Sticking. Jarred free at 55K over. Free BHA. Attempt to mill with almost no weight. Continue to attempt to mill down to packer top. Changing pump, RPMs, weight. No luck. POOH. Lay down power swivel. POOH. 07/08/14 - Tuesday Finish POOH with 8 1/2" flat bottom shoe. Shoe was worn on ID from 6 3/4" to 6 7/8" ID. No wear on bottom and minimum wear on OD. Flat bottom pads were cracked and flared out to 8 5/8" OD. Obstruction at 2,019'. PU MU 8 1/8" overshot with 5" grapple with 4 1/2" ID welded bead at top of grapple for stop. (2) overshot extension, jars, (8) 4 3/4" drill collars, intensifiers. TIH to 2,011'. PU power swivel. Lower over tubing top to 2,015'. Make multiple attempts to back off tubing crossovers. Grapple would hold up to 40K up pull but not left hand torque. POOH with overshot assembly. Grapple control had markings but grapple showed no markings. Change out mill control and grapple. TIH to 2,011', lower over top of tubing stub to 2,015', engage 5" OD crossover coupling. Take overpull. Work right hand torque in work string. Attempt left hand back off. Work string backed off approximate 4,500'. screwed back together. Torque tubing to 7500 ft. lbs. to the right with power swivel. Attempt left hand back off. Work string backed off approximately 2,300'. Could not screw back together. RD power swivel. POOH with workstring. Ordered another overshot. PU MU overshot. TIH. Engage workstring. Release lower overshot. POOH. BO/LD overshot assembly. Picking up 8 1/2" milling assembly. 8 1/2" smooth OD flat bottom mill, 7" OD boot basket, Inline magnet, bit sub, 4 3/4" bumper, oil jars, (8) 4 3/4" drill collars, 4 3/4" intensifier, crossover to 3 1/2" PH - 6 workstring. 07/09/14 - Wednesday Picking up 8 1/2" milling assembly. 8 1/2" smooth OD flat bottom mill, 7" OD boot basket, Inline magnet, bit sub, 4 3/4" bumper, oil jars, (8) 4 3/4" drill collars, 4 3/4" intensifier, crossover to 3 1/2" PH -6 workstring. TIH to 2,011'. PU power swivel. Begin taking parameters. PU RU KOT power swivel. Begin milling at 2,011'. Using water flood pumping to Trading Bay, 7 bpm, 70 RPM, 1250 psi, 3-4K weight on mill. Made 13' so far. Currently at 2,024'. Milling has slowed. Continue milling. 07/10/14 - Thursday Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 paily;Op-F mow __. Hold Safety meeting with Daylight crew. Continue milling while circulating with waterflood take returns to Trading Bay. Milled to 2,024', making no hole . Rig down swivel. Start pooh with workstring. Lay down BHA. Emptied boot basket and clean magnet, nothing in boot basket but fine cutting on magnet. Make up 8-1/2" concave mill, 3 boot baskets, 8-3/8" Stabilizer and inline magnet and Bumper and oil jars. TIH with drill collars, picked up accelerators jar and TIH with work string. Rigged up power swivel. Pumped 40 bbls out of pit to Trading Bay. Hold Safety meeting with night crew. Tag fish @ 2,024', Start milling on fish 4.7 bbls/min at 77 ft/min annular velocity. Milled down to 2,027' packer released shut down swivel. TIH to 2,051', no tag. Monitor well while rigging down swivel and laying out work string to Talley and continue TIH to bottom, tag fish @2,254' set 20,000# down pick up no overpull. Decided to pooh and pick up spear. Out of hole with mill. Start breaking out BHA. Lay out magnets and boot baskets including mill with minimal wear on mill. Start making up spear with 4.961 grapple. Start TIH with spear, tag fish @ 2,254'48,000# pick up weight 42,000# slack off weight. Latch fish. Pick up to 70,000# and let jars go off, fish not free. Continue jarring on fish, slack off to 30,000# and picking up to 120,000 and letting jars go off. 07/11/14- Friday Hold Safety meeting with daylight crew. Continue jarring on fish @150,000#, no movement and jars were no longer working. Decided to release spear. Pooh with workstring, lay down accelerator jar and rack back drill collars. Lay down bumper sub, oil jar and spear. Repair lugs on packer retrieve J bushing. Weld stop on spear and spaceout packer retriever assembly on deck and verify spaceout. Pick up bumper and oil jar, made up packer retrieving assembly and shoe. TIH with 2 stands of drill collars. Hold Safety meeting with night crew. Continue make up Bha and TIH to top of fish. Tag tight spot at 622' rotate with tongs to get through tight spot continue TIH to fish 2,225'. Rig up swivel. Lower swivel and tag top of fish at 2,254', try to latch fish, having hard time, decided to turn to left and fish was latched. Close annular and start reverse circulation 5bbls/min 260 psi. Start rotating down minimum torqueing seen. Tag hard at 2,257'. Pipe weight without rotation 51,000# up, 46,000 # down Pipe weight while rotating and pumping 46,000# up, 46,000# down. Start milling on packer down to 2,258.5.4.5" from fish top to current depth. No torque seen, decided to release spear. Rig down swivel and start pooh with work string and spear. Out of hole with spear, all indication show we were over packer 2-1/2', also found packing element, packing ring and bundle of metal shavings. 07/12/14 - Saturday Hold Safety meeting with daylight crew. TIH with overshot. Dress 8-1/8" overshot with 6-3/4" grapple make up over shot and TIH with workstring torqueing each connection to BJ tongs to 6000 ft/lbs. Reverse circulate 2 tubing volumes and latch fish @ 2,258'. Rig up Eline and make 2 runs with 2-1/4" magnet tagging at 2,264' getting minimal shavings back. Make one run with 1-1/2" gauge ring and tag same at 2,264'. Rigged down Eline. RU power swivel, apply left hand torque and make backoff gain 27,000 # pipe weight. RD power swivel. POOH, Hold Safety meeting with night crew. Overshot at rig floor, lay down overshot and packer mandrel. Continue POOH with Polycore tubing and also pulling wet. 69 joints of fish out of hole, tubing stop pulling wet. Mark joint # 69 saying there is a obstruction in joint, continue POOH with fish. Out of the hole, pulled 99 joint of 3-1/2" Polycore tubing and 1 TPL 4040 collar. PU overshot and release packer mandrel out of overshot and lay down same. Remove rig floor and remove annular cap to change out element. Torque annular cap. Pull wear bushing and prepare to test ROPE. Talked with Lou Grimaldi per telephone this morning and witness waived. 07/13/14- Sunday Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 DailypratlC) _ '' Hold Safety meeting with daylight crew. Finish torqueing up annular cap. Install pollution pan. Rig up test joint, drain stack and make up test plug and run in and pull wear bushing. Invert and set test plug, fill stack with filtered inlet water. Started test bops, found leak on pipe ram bonnet seal, tighten bolts, still leaking. Pull test plug and change out door seal, set test plug and fill stack. Attempt to test but opposite door seal is leaking, tighten door and leak stopped. Test all BOPS and associated components according to test procedure. Rams 250 psi low/3000 psi high. Annular 250 psi low/2500 psi high. Valves 250 psi low/3000 psi high. Witness of test waived by Lou Grimaldi, AOGCC. Hold Safety meeting with night crew. Pull test plug and set wear bushing. Lay down test joint. Rig up dress sleeve and hoses to bell nipple. Make up BHA. Make up 8-1/2" burning shoe with 1 joint of wash pipe extension bumper and oil jars, 4 stands of drill collars with accelerators and continue run with milling assembly. Tag tight spot @ 622' rotate through continue running in hole. Begin picking up pipe from pipe rack tallying and drifting same. Rig up swivel and spot power pack. Pick up weight 93,000# and slack off weight 68,000#. Tag packer 5,239' start reverse circulating, got returns 5 bbls/min @ 1000psi. Start milling pipe weight while milling and pumping 79,000# pick up and 70,000# slackoff. 07/14/14 - Monday Hold Safety meeting with daylight crew. Continue milling of packer 5,239'. Continue milling packer from 5,239' to 5,242' making no improvement. Decided to pooh and inspect burning shoe. Rig down power swivel and start pooh with burning shoe. Start breaking down Bha. Shows wear 2'4" on the ID of the shoe and about 10' on the OD of the shoe. Make up 3- 1/2" grapple in a 8-1/8" overshot with 4 strand drill collars, bumper and oil jars including accelerators jars and start TIH with overshot. Pipe weight 86,000# pick up and Slack off 66,000# down. Tag top of fish @ 5,243' set down 20,000# and pick up to 110,000, jars when off and pipe weight fell back to 86,000# Slack off to 5,258'. Start pooh with fish. 07/15/14-Tuesday Hold Safety meeting with day light crew. Continue POOH with workstring. Lay down accelerator, oil and bumper jars. Rack back drill collars and pull overshot to rig floor No Recovery. Decided to tih with same assembly to 5,260'. Continue tih with overshot while tallying and drifting 3-1/2" PH-6 from the deck. Hold safety meeting with night crew. Continue drifting and tallying workstring from deck. Tagged @ 7,435' jar on tubing came free, pull and rack back 1 stand. Move equipment and spot tubing swivel. Rig up power swivel and hoses. Pick up 1 single joint and make up to swivel. Circulate down slowly incase of engaging fish, washing down just fine with no tag. Continue pick up tubing and making up with swivel. Rig down power swivel. 252 joints in well 7,498' in hole 160,000# pick up weight, 268 joint in well 8,618' 180,000# pick up weight, 293 joints in well 9,396' Pick up weight is in excess of 220,000#. Tight spot. Rig up swivel. Start pumping 4 bbls/min 400 psi and try to circulate free. Having to circulate while pooh out of the hole due the increased drag, also unable to rotate pick up weight is from 170,000# to 230,000#. 290 joints in hole 9,302', 287 joints in hole 9,208' in well pulling without pump. Pick up weight is 170,000# to 200,000# still dragging up the hole. Rig down swivel and continue pooh with overshot. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 1 5/24/14 8/31/14 Daily Operations: 07/16/14 - Wednesday Hold safety meeting for daylight crew. Weight up fluid in pits to 9.4 to balance well. Move pipe from pipe rack and lower rack to start pulling tubing. Start pooh with workstring dragging up the hole to 190,000#. Circulate bottoms up. Continue pooh lay down 3-1/2 PH-6. Hold safety meeting with night crew. Continue laying down 3-1/2" tubing. Change out hydraulic hose on tongs due to wear. Rack back 15 stands for kill string. Continue pooh with 3-1/2" PH-6 workstring. At rig floor with drill collars and lay down same. At floor with overshot, recovered fish. Lay out (2) crossover pups, packer, 2- joints 3-1/2" 8rd tubing with 2.313 nipple and Wireline entry guide. Pick up oil and bumper jars with overshot and break down same. Run 990' kill string. PU hanger. Landing now. 07/17/14 - Thursday Hold safety meeting with daylight crew. Continue tih with 3 1/2" 12.95# P-110 kill string tL.070'. Install hanger with BPV. Land hanger and run in pins. Lay down landing joints, removed floor plates and dresser sleeve, nipple down bell nipple and bolt on lift plates. Rig down scaffolding. Rig down bops and hang under the rig. N/D riser and N/U tree. Tested tree & void to 5000 each f/30 min good. Installed floor plates. Hold safety meeting. Mix bleach with fluid in tanks to cut to viscosity. Disconnect all electrical lines including PVT System and gas alarms. Remove front lower wind wall. Consolidate solids in one cutting box for transportation. Install jacks for skidding master skid. Continue disconnecting hose from substructure and start pumping to Trading Bay. Remove rear lower wind walls and start loosing master skid clamps. Move off driller side dog house. 08/13/14 - Wednesday Rigging up. 08/14/14 - Thursday Rigging up. 08/15/14 - Friday Filled pit with 120 bbls FIW. Weighted up to 3% KCL/9.4 ppg. Spot power swivel, connected hydraulic lines to substructure, finished welding padeye for power swivel torque line. Remove pollution pan, set BPV, nipple down tree, nipple up riser/BOP'S. Set up scaffolding around BOP's. Pre-test test pump. Bleeding off 100 psi in 5 minutes. Leave message for Jeff Jones that we are working on test pump, BOPE will be delayed. Work on test pump. Bleeding off 100 psi in 5 minutes. Borrowed test pump from King Salmon. RU new test pump. Received call from Jeff Jones that he will not be able to come until the next morning. NU bell nipple and install flow line. Set pollution pan. RU dressing sleeve. Pull BPV. PU/MU test joint, set 2 way check valve, fill stack, close blinds. Test pump was tripping breaker. Change out breaker. RU flowline to shaker. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 Daily bper`ations � "' 08/16/14 - Saturday Service rig and equipment. Waiting on AOGCC rep. to begin BOPE test. Test annular 250 low / 2500 high. Test pipe rams 250 low / 3000 high. Performed accumulator test. (1) air pump would not work, the other air pump had a drip leak on the discharge line. Pulled test joint and test blinds. 250/3000. Test PVT sensors, Flow out sensor not working. Attempt to troubleshoot no luck. Repaired accumulator leak and air pump. Performed bump test on H2S/LEL sensors. All good. BOPE test witnessed by Jeff Jones, AOGCC. Retest accumulator pressure build up. 3 minutes 30 seconds. Test good. Check and recharge all nitrogen bottles. Offload equipment from top of pipe rack. PU on pipe rack and move production connex. Reset pipe rack and disconnect accumulator lines. Move accumulator under pipe rack. Reconnect accumulator lines. Quadco arrive, work on flow out sensor. Move change locker building next to accumulator. Pull test joint / MU pup joint. Quadco goes over sensors and computer software with driller and Toolpusher. B/O TIW, IBOP, crossovers. MU TIW valve to testjoint. B/O hold down pins. Unseat hanger, B/O test joint, LD hanger and test joint. POOH with 3 1/2 PH-6 kill string racking back. 995.83'.Currently PU MU BHA # 1 consist of 8 1/2 tapered mill, 8 1/2 string mill, 9 5/8 casing brush, (6) 4 3/4 drill collars, 4 3/4 bumper/oil jars. 08/17/14 - Sunday Continue PU 4 3/4 drill collars and BHA #1. 8 1/2 tapered mill, 9 5/8 casing brush, xover, (6) 4 3/4 drill collars, xover to 3 1/2 PH-6 work string. TIH to 854' tagged tight spot. Begin milling until full drift with 2500 - 4000K torque, 200 psi @ 4 bpm with 4-5K weight, 80-90 rpm. Mill and ream to 877'. PU above 854' to begin again. Tagged at 857', milling hard again. POOH. BO tapered mill and add 8 1/2 smooth OD string mill to BHA. 8 1/2 tapered mill, 8 1/2 string mill, xover, 9 5/8 casing brush, xover to (6) 4 3/4 drill collars, xover to 3 1/2 PH-6 work string. TIH to 866' tagged and begin milling. Milled, reamed with 2500 - 4000K torque, 200 psi @ 4 bpm with 4-5K weight, 80-90 rpm. Each time milled until free below 877' and PU above 857', same results, begin milling again. Ordered 8 1/2 lead impression block. POOH. Rack back DC's /jars. MU 8 1/2 lead block on 3 1/2 PH-6 tubing. Currently TIH to 854'. 08/18/14 - Monday TIH with 8 1/2 OD lead impression block to 971'. Did not see tight spot in 9 5/8 casing. POOH, did not see it coming out. PU 8 1/2 tapered mill, 8 1/2 string mill, xover to (6) 4 3/4 drill collars, xover to 3 1/2 PH-6 work string., TIH to 865'. PU power swivel and begin milling/reaming to 870'. Reamed until smooth. RD power swivel. Continue TIH picking up singles and tallying/running tubing drift. TIH to 6,818'. Tagged at 6,818', PU power swivel begin milling tight spot. Started getting gas back. Shut down swivel. Circulated gas out @ 500 / 5 bpm reversing out. 103 units. Begin reaming again from 6,818' - 6,835'. PU single, ream from 6,835'- 6,866'. RD power swivel. Continue TIH picking up singles, tallying/drifting to 8,934'. Tagged tight spot. PU swivel, begin reaming. Currently milling/reaming tight spot at 8,934'. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 Dailyperaions _ G 08/19/14 -Tuesday Continue TIH to 8,934'. Tagged tight spot begin milling /reaming. Could not make any progress. Torque smooth. POOH. Rack back drill collars. BHA was broken at bumper sub mandrel. Left 8 1/2 tapered mill, 8 1/2 string mill, xover and bottom sub of bumper jar in hole. PU MU 9 5/8 RTTS test packer. Function packer and bypass valve. PU additional (6) 4 3/4 drill collars for a total of (12) 4 3/4 drill collars for weight to set packer. TIH to 450'. Set packer with 18K. Fill 9 5/8 casing, pressure to 500 psi, hold for10 minutes. Bleed off, cont TIH. TIH to 920'w/ 20K. Pressure to 1500 psi on chart. Leaked from 1500 to 1000 psi in 7 minutes 15 seconds. Establish injection rate. Pumped 34 strokes, reached 1500 psi. No pressure indication on 13 3/8 casing annulus. Release packer. POOH. Lay down (6) drill collars. B/O lay down test packer. Prepare to set RTTS packer and squeeze Poly Plug into leak. 08/20/14 - Wednesday PU MU RTTS tool and (6) drill collars for a total of (12) 4 3/ DC's. TIH to 929'. Clean mixing tank. Wait on Poly Plug materials. Change out 4 way valve on accumulator. Service rig. Annular will not close. Remove hoses, test accumulator, OK. Begin pumping 19 bbls FIW in mixing tank. Changed out butterfly valve. Mix 20 bbl poly Plug pill. Set test packer, test packer with 1000 psi, bleed off pressure. Open bypass and begin pumping, bypass open and working good. Reverse to spot pill with open bypass. Close bypass and pipe rams. Pump and pressure up to 1500 psi, let bleed off in hole to 1000 psi, pump/pressure up to 1500 psi alternating until 10 bbis pumped away through leak. Initially bleeding off in 10 - 15 minutes then taking 20 - 30 minutes to bleed off from 1500 psi to 1000 psi. Open bypass and reverse balance of plug and 2 tubing volumes. PU one stand and wait 4 hours. Will then TIH to 929', reset packer and test casing to 1500 psi. 08/21/14 - Thursday Spot 20 bbl Poly Plug pill @ 929' and wait on poly plug to set 4 hours. Pressure up to 1500 psi. Leaking, no test. Pulled one stand, set packer, pressured up to 1500 psi for 15 minutes. Packer setting good. Released packer, TIH one stand, set packer, opened bypass, establish circulation. Mix 10 bbl poly plug pill, hopper plugged, unplugged hopper, continue mixing pill. Spot PP pill at packer. Close bypass, pumped 1 bbl pressured up to 1500 psi, pressure bled off to 1350, pressured up to 1500 psi. Casing held pressure on chart 20 minutes at 1500 psi. Test good. Open bypass, reverse out 3 tubing volumes. Pumped fluid from pill pit to active pit, cleaned pill pit. RU to Trading Bay. Pumped approximate 200 bbls to Trading Bay. Filled active pit with clean FIW. Build fluid weight to 9.4 ppg 3% KCL. RD TIW valve and hose. Release packer, POOH, lay down (6) 4 3/4 DC's, test packer. Change out annular rubber and function test. Test good. Picking up overshot, jars and DC's now. 08/22/14 - Friday PU 8 1/8 overshot, 4 3/4 jars, (6) 4 3/4 drill collars. TIH to 8,934' engage fish, jarred 5 times at 60-70K fish came free. POOH. 19 stands out stuck again. Jarred free. Continue POOH. Mills had good wear. Taper on tapered mill had wear down to nose. BO/LD fish. PU 8 1/2 tapered mill, xover, 8 1/2 string mill, 9 5/8 casing brush, 4 3/4 bumper/oil jar, (6) drill collars. TIH to 863'. Tagged tight spot again. POOH, remove casing brush, trip back in hole. Tagged tight spot at 863'. PU power swivel begin milling. Currently milling. 3 bpm, 2500-3500 torque, 200 psi, 3-4K weight. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 5/24/14 8/31/14 08/23/14-Saturday Continue reaming tight spot from 853'- 862'. RD power swivel. TIH to 7,533'. RU power swivel. Mill @ 7,533', stuck pipe, jar free, slack off to 7,572'. Did not tag obstruction. RD power swivel. TIH to 7,841, tag obstruction. RU power swivel. Milled 71841'- 7,872'. Milled from 7,872'- 7,883'. RD power swivel. TIH tagged obstruction @ 8,028'. RU power swivel. Begin milling @ 8,028'. 08/24/14 - Sunday Continue reaming to 8,040'. RD power swivel. TIH with 14 stands from derrick. Begin picking up singles from deck. Pick up (1) single tagged at 8,891'. PU power swivel, milled to 8,899' broke through. Continue RIH tagged @ 9,642'. Milling obstruction at 9,642'. RPM 35, added (1) bbl of CFS-520 but did not see any significant hole friction reduction. Decision made to POOH. Will move completion packers up hole 40'. RD power swivel. POOH. Pulled 20K over @ 9,366'. RU power swivel. Begin reaming while picking up and POOH 9,366'- 9,345'. RD power swivel. POOH to 9,121'. Hung up. RU swivel, attempt to back ream. No luck. LD swivel. Change to heavy duty elevators. Begin jarring, jarred at 70K over. Pulled free. POOH. Hung up @ 9,002'. PU swivel. Back ream to 8,971'- 8,940'. Laying down joints in singles. Continue to POOH, @ 8,815' now. 08/25/14 - Monday Finish POOH with milling BHA. Mills were 20% worn. Marks were on top of tapered mill blade showing something was wearing or riding out on this part of the mill. Perform BOPE test. Attempt test on Annular. No test. Change out annular rubber. Test good. Test annular 250 low / 2500 high, rams, choke manifold, surface valves, Kill and choke valves 250 low / 3000 high. Test good. Witness of test waived by Jim Regg, AOGCC. Break out TIW/IBOP valves, pull test joint and test plug. Lay down. Begin PU 9 5/8 hydraulic packer, WLEG, 3 1/2 EUE pup joint, X nipple, crossover, (1) joint 3 1/2 EUE tubing, 3 1/2 EUE pup joint. 08/26/14-Tuesday PU MU 9 5/8 hydraulic packer assembly. TIH with 3 1/2 PH-6 work string slowly, ran 146 stands from derrick. Picked up 16 singles and (2) 10' pup joints. Packer depth 9,622'. Pump 30 bbls to Trading Bay. Reverse circulate well until balanced, dropped ball and wait for 15 minutes. Pressure up to 3500 psi, holding pressure. Bleed off pressure. Release from packer. RU tubing tongs and power pack. Displace hole volume 662 bbls while adding 1.5% CRW-132 @ 3.5 bpm. Slip and cut drill line. POOH with 3 1/2 PH-6 work string. 08/27/14 - Wednesday Finish POOH with packer setting tools. Break out lay down same. RD Rig foster tongs. RU Weatherford tongs. Hold JSA. PU MU seal assembly. TIH picking up 3 1/2 TPL 4040 Poly Core tubing in singles. TIH with 97 joints. 2,908.40'. MU crossover, on/off tool, ran 1 joint of 3 1/2 PH-6 tubing. RD Weatherford tongs, RU Foster tongs. Start TIH with 3 1/2 PH-6 tubing from derrick to 9,622'. PU single and sting into Tie back sleeve with seals assembly. PU tension and Back off from on/off tool. POOH with workstring. PU MU (2) joints of 3 1/2 Poly Core, on/off tool, 9 5/8" hydraulic set packer. Currently tripping with packer assembly @ 3,514'. Top of 3 1/2 TPL 4040 tubing in hole @ 6,691.91' Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 1 168-043 1 5/24/14 8/31/14 r - Daily Operations: y " 08/28/14 - Thursday Cont. TIH t/632' up wt 96, do wt 76. Cont. RIH t/ tag @ 6,692', tag top of on/off tool, set 15k dn, p/u wk t/ 20k over verifying latch. Drop dart, let fall 30 min, pressure up t/ 3500 psi set packer @ 6,615'. R/u pressure test annulus t/ 2500 psi, bled down 60 psi in 20 min, pressure up t/2500, double block valves t/ pump, hold 2500 for 30 min good. R/u W/L, RIH t/ 9,651' wlm retrieve ball & rod dart. M/u 2.5 GS RIH t/9,652'unable to latch plug. POOH, dogs unseated on tool. RIH w/GS t/9,656' unable to latch. POOH, pins sheared on tool. Re -pin w/steel pins. RIH t/ 9,656'wlm, unable t/ latch. POOH, tool not sheared. RIH w/ GS w/knuckle jt., latch plug, pull 4 jar licks @ 800 op tool coming free. Found fill in nose of tool. POOH no plug, partial shear. RIH w/GS had small op, no latch. POOH found rubber strip under sleeve. RIH w/2.26 fluted cent. w. 1.35 digging tool t/ 9,656', POOH. RIH w/ 2.25 pump bailer w/mule shoe btm retrieving 3 cups fill w/ up t/ 1" pieces. RIH w/GS tool t/ 9,660' wlm, latch plug, hit several jar licks w/ 1500. Tool coming off. POOH, went on vac. RIH w/ GS tool, latch, jar several times POOH. No plug, not sheared. RIH w/ 2.25 pump bailer t/ 9,656' got hung up pulled 1700 w/ 6, jar hits t/free. POOH recover 2 cups fill. 08/29/14 - Friday RIH w/2.25 bailer, recover 1 cup fill. RIH w/ bailer, recover no fill. RIH w/1.5 KJ & GS tool, t/ 9,656' latch plug, hit 6 jar licks @ 1700 came free. POOH, recover plug. RIH w/ 2" GR t/ tag @ 9,762' wlm. POOH. RIH w/10k Tri -Gauges t/9,762' @ 60' min, 15 min btm hole stop. POOH @ 60'/ min. R/D W/L. P/U string t/neutral 96k, rot 12 turns rt t/ release f/ packer. POOH f/6,615' t/6,431', up wt 92k. PTSM crew change. Secure well. C/O tugger line & sheave on ods tugger. P/U Anchor seal assy. TIH. P/U 100 its 3 1/2 TLP -4040 9.94# L-80 polycore completion tubi t/3,115'. 08/30/14 - Saturday Cont. TIH f/ 3,115't/ 9,590', up wt 66, do wt 54. R/U t/ reverse, circ @ 2 bpm 45 psi. Ease down watch f/pressure increase. Pressure increase t/ 85. Mark pipe, p/u space out. Pull 8 jts. L/D jt # 301. P/u jt # 310. RIH w/ 8 jts. P/u 3.13 pup. M/U hanger & landing jt. Land hanger. P/u 20k over, verify anchor seal latched, land out hanger, run in I/d pins. R/U pressure up annulus t/ 2500 lost 180 psi 30 min, bleed off. install secondary isolation valve t/ pump, pressure up t/2500 isolate f/ pump remove line f/behind isolation valve, valve leaking, bleed down c/o valve. Pressure up ann t/2500 psi bleed down 120 psi in 30 min, check surface valves good, bleed off. Install landing jt, drain fluid from top of hanger, pressure up t/ 2500 fill landing jt w/water, monitor hanger top & landing jt. Pressure bleeding down, found water leaking from tubing. Consult w/engineer discuss options. Decide t/ release anchor seal assy re -set & re -test. R/u t/ rotate string & work pipe. Back out I/d pins, p/u string set tq on fosters t/ 1700, attempt t/ rot pipe unable, increase tq t/ 2000, rot pipe working string f/ 80k - 58k working turns down till released from latch. P/u hanger t/ floor inspect seals, re -land hanger. Run in I/d pins. R/u pressure test ann t/2500, fill landing t & monitor. Good test w/ no water from tubing. House keeping. Maintenance & prep f/ rig move while waiting f/ w/I crew to make gauge run before n/d. Hilcorp Alaska LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date G-11 50-733-20115-00 168-043 1 5/24/14 8/31/14 Daily gperations: 08/31/14 - Sunday PTSM, service rig. Pull BPV. M/u landing jt. R/U W/L, RIH w/2" GR t/ 6,664', clear. POOH R/D W/L. Install BPV, remove floor panels, rot beams, dresser sleeve, drip pan, flow line, bell nipple, break down scaffolding. N/D BOP & hang off in cellar. Pull riser, R/D PVT system & gas detection. N/U tree, re -orientate valves, install manumatic & choke, test void on tree t/ 5000 good, test tree t/ 5000 good. R/U lines & start pumping fluid t/ Trading Bay f/pits. Housekeeping & clearing decks for rig move. THE STATE ®fId A." A es I, ` GOVERNOR SEAN PARNELL September 10, 2014 Mr. Stan Golis Hilcorp Alaska LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: Notice of Violation dated August 29, 2014 Moncla Rig 301 Dear Mr. Golis: J-.y;Cc s�J&'a z la aiirir tii s4 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 SCUM OCT OC20114 Hilcorp Alaska LLC (Hilcorp) responded — by letter dated September 9, 2014 — to a notice of violation for a late test of blowout prevention equipment on Moncla Rig 301. Hilcorp was performing well workover operations at the time of the violation on Trading Bay Unit G-11. In response, Hilcorp performed a review of the work history and a cause and effect analysis. Corrective actions implemented by Hilcorp include clearly documenting the due dates for blowout prevention equipment on daily reports, and refresher training for well site managers addressing the requirements and expectation associated with blowout prevention equipment testing. The Alaska Oil and Gas Conservation Commission accepts these corrective actions as addressing the identified regulatory concerns and deems this notice of violation closed. Sincerely, Cathy P. oerster Chair, Commissioner cc: AOGCC Inspectors (via email) Hilcorp Alaska, LLC September 9, 2014 Daniel T. Seamount, Jr. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Re: Notice of Violation — Failure to Test BOPE Moncla Rig 301 Trading Bay Unit G-1 1 (PTD 1680430) Dear Commissioner Seamount: RECEIVED SEP 0 9 2014 AOGCC � (-4.. `6 - o `-"3 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907/777-8300 Fax: 907/777.-8301 My name is Stan Golis, Operations Manager overseeing the work -over program on the Grayling platform in the Cook Inlet. I am responding to the letter written to Mr. John Barnes, August 29, 2014 stating the Notice of Violation on the Moncla 301 rig. We have reviewed the work history on the Grayling platform G-11 work over NOV — Failure to Test BOPE, discussed the causes, the effects, and the steps necessary to prevent its recurrence. Hilcorp Alaska recognizes the extensive importance of well control and how it rests on the knowledge and experience of our people and the integrity our BOPE. We regret having gone beyond the 7 day test cycle and, we are learning from this mistake. Moving forward we will have any anticipated upcoming BOPE test dates posted on the morning report and discussed on morning calls. This will increase visibility of the test schedule and stimulate more conversation on the importance of well control and well control equipment integrity. All of our Well Site Managers (WSM) have Alaska based experience and have been coached on BOPE testing regulations. Each WSM will have a refresher course on the requirements and expectations of the AOGCC. Thank you and we look forward to continuing to work closely with the AOGCC to ensure that we have safe and efficient operations in the Cook Inlet. Sincerely, HILCORP ALASKA, LLC 54, C�) (' �- �_ Stan Golis Cook Inlet Offshore — Operations Manager THE STATE G0VERN0R SEAN PARN?ELI_ August 29, 2014 CERTIFIED MAIL — RETURN RECEIPT REQUESTER 7009 2250 0004 3911 3491 Mr. John Barnes Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Notice of Violation — Failure to Test BOPE Moncla Rig 301 Trading Bay Unit G-11 (PTD 1680430) Dear Mr. Barnes: 333 West Seventh Avenue Anchorage, Aicska 99501-3572 NA,oin' 907.?79.1433 .< 7 Hilcorp Alaska LLC (Hilcorp) is performing workover operations on Grayling Platform, Trading Bay Unit Well G-11 pursuant to sundry permit 313-453, approved on August 28, 2013. During workover operations testing of blowout prevention equipment (BOPE) must be completed at intervals not to exceed 7 days. 20 AAC 25.285. Failure to test BOPE within 7 days is a violation of the Alaska Oil and Gas Conservation Commission (AOGCC) regulations. After moving to TBU G-11, Hilcorp tested the Moncla 301 BOPE on August 16, 2014 (witnessed by the AOGCC) and again on August 25, 2014. Nine days elapsed between tests in violation of 20 AAC 25.285(f)(1). The BOPE test was required to be completed by August 23. Hilcorp's first notice of its intent to test was provided to AOGCC on August 24, 2014. The test itself was supposed to start August 25. Hilcorp's notice was inconsistent with the clarification provided in AOGCC Industry Guidance Bulletin 10-01 A: "For activities that have a remote location from the nearest AOGCC office, you are requested to provide 48 hours advance notice." Hilcorp notified AOGCC at approximately 8 am on August 25 that the work string was stuck downhole, further delaying an already late BOPE test. An email to the Moncla 301 Well Site Manager later that morning advised of the apparent testing noncompliance, instructed him to test BOPE when the milling assembly was out of the hole, and to provide daily drilling reports beginning August 22, 2014. At no time did AOGCC waive witness of the BOPE test. ■ Complete items 1, 2, and 3. Also complete Item 4 if Restricted Delivery is desired. t Print your name and address on the reverse so that we can return the card to you. It Attach this card to the back of the mailpiece, or on the front if space permits. t. Article Addressed to: Mr. John Barnes Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524-4027 2. A C i PS f X A' LJ Agentff , ❑ Addressee 13. Rec hreF1 by IflVed ) C. Date o ebivpry L/ ,. If YES, enter delivery address below: 3. Service Type ❑ Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. _ .. ❑ Yes is J, uvii�w.rt: noumti netxipat ff 02-[01=1540. postal MAILT11 RECEIPTCERTIFIED Mail Only; No Insurance C overage Provided) (Domestic I a— = rq r -q 0^ Postage $ m Certified Fee postmark -r Q Return Receipt Fee (Endorsement Required) Here E3 c3 Restricted Delivery Fee (Endorsement Required) Ln ru Total Postage & Fees ru Mr. John Barnes To Alaska, LLC Hilcorp OetN.post Office Box 244027®O LSent Box No.r`; side: iiP+a ......""_""" AK 99524-4027 Anchorage, Mr. John Barnes August 29, 2014 Page 2 of 2 The Well Site Manager provided a table with unlabeled columns that summarize work activities between August 22 and mid-day August 25. According to the daily activity summaries provided, Hilcorp had several opportunities to perform a full BOPE performance test to remain in compliance with the required August 23, 2014 due date: - On August 22, 2014, Moncla Rig 301 crew changed out the annular preventer rubber sealing element and performed a function test of the annular preventer only; - On August 23, 2014, Moncla Rig 301 tripped to surface and re -ran into the well twice as part of the workover activities. Within fourteen (14) days of receipt of this letter (next business day if the due date falls on a weekend), Hilcorp is requested to provide AOGCC with an explanation of what steps Hilcorp has or plans to take to prevent any future violation of AAC 25.285 on Hilcorp operated rigs in Alaska. This request is made pursuant to 20 AAC 25.300. The AOGCC reserves the right to pursue enforcement action in connection with these BOPE testing violations. Questions regarding this letter should be directed to Jim Regg at 907-793- 1236. cc: AOGCC Inspectors Sincerely, Daniel T. Seamount, J Commissioner i RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. THE STATE Awake Oil amL Gas oil 7 GOVERNOR SEAN PARNELL August 29, 2014 CERTIFIED MAIL — RETURN RECEIPT REQUESTED 7009 2250 0004 3911 3491 Mr. John Barnes Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Notice of Violation — Failure to Test BOPE Moncla Rig 301 Trading Bay Unit G-11 (PTD 1680430) Dear Mr. Barnes: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Pain: 907.279.1433 rcr.: 907.276.7542 Hilcorp Alaska LLC (Hilcorp) is performing workover operations on Grayling Platform, Trading Bay Unit Well G-11 pursuant to sundry permit 313-453, approved on August 28, 2013. During workover operations testing of blowout prevention equipment (BOPE) must be completed at intervals not to exceed 7 days. 20 AAC 25.285. Failure to test BOPE within 7 days is a violation of the Alaska Oil and Gas Conservation Commission (AOGCC) regulations. After moving to TBU G-11, Hilcorp tested the Moncla 301 BOPE on August 16, 2014 (witnessed by the AOGCC) and again on August 25, 2014. Nine days elapsed between tests in violation of 20 AAC 25.285(f)(1). The BOPE test was required to be completed by August 23. Hilcorp's first notice of its intent to test was provided to AOGCC on August 24, 2014. The test itself was supposed to start August 25. Hilcorp's notice was inconsistent with the clarification provided in AOGCC Industry Guidance Bulletin 10-01 A: "For activities that have a remote location from the nearest AOGCC office, you are requested to provide 48 hours advance notice." Hilcorp notified AOGCC at approximately 8 am on August 25 that the work string was stuck downhole, further delaying an already late BOPE test. An email to the Moncla 301 Well Site Manager later that morning advised of the apparent testing noncompliance, instructed him to test BOPE when the milling assembly was out of the hole, and to provide daily drilling reports beginning August 22, 2014. At no time did AOGCC waive witness of the BOPE test. Mr. John Barnes August 29, 2014 Page 2 of 2 The Well Site Manager provided a table with unlabeled columns that summarize work activities between August 22 and mid-day August 25. According to the daily activity summaries provided, Hilcorp had several opportunities to perform a full BOPE performance test to remain in compliance with the required August 23, 2014 due date: - On August 22, 2014, Moncla Rig 301 crew changed out the annular preventer rubber sealing element and performed a function test of the annular preventer only; - On August 23, 2014, Moncla Rig 301 tripped to surface and re -ran into the well twice as part of the workover activities. Within fourteen (14) days of receipt of this letter (next business day if the due date falls on a weekend), Hilcorp is requested to provide AOGCC with an explanation of what steps Hilcorp has or plans to take to prevent any future violation of AAC 25.285 on Hilcorp operated rigs in Alaska. This request is made pursuant to 20 AAC 25.300. The AOGCC reserves the right to pursue enforcement action in connection with these BOPE testing violations. Questions regarding this letter should be directed to Jim Regg at 907-793- 1236. cc: AOGCC Inspectors Sincerely, Daniel T. Seamount, J Commissioner / RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Regg, James B (DOA) pt From: Regg, James B (DOA)f Sent: Friday, August 29, 2014 3:49 PMI (In�� To: 'Bob Finch - (C)' Cc: Juanita Lovett; Brooks, Phoebe L (DOA) Subject: RE: BOPE Test Report Attachments: BOP Moncla301 8-25-14.xlsx Several things: 1) Under MISC. INSPECTIONS, item titled "Rig" cannot be "NA" (you are working with a rig). This item addresses the general mechanical condition of the rig/structure/derrick, safety railings, stairs, winterization (as appropriate), etc. 2) Annular Preventer test result should be "FP"; from the Daily Reports sent earlier the Annular was reported as replaced and function tested (not performance tested) on 8/22, making this a second failure of the Annular Preventer in 4 days. Explain. 3) Number of Failures should be 1 4) Added to Remarks that the test was late (due 8/23); notice was also late 5) Witness was not waived by AOGCC. Revised report attached. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Bob Finch - (C) [mailto:bfinch@hilcorp.com] --M' Sent: Wednesday, August 27, 2014 9:08 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Juanita Lovett Subject: FW: BOPE Test Report Please see corrected date on BOPE test form. SCWZ) OCT 2 6 2A Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 From: Bob Finch - (C) Sent: Wednesday, August 27, 2014 6:32 AM To: 'jim.regg@alaska.gov'; 'AOGCC.Inspectors@alaska.gov'; 'phoebe.brooks@alaska.gov' 1 Cc: Juanita Lovett Subject: BOPE Test Report Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 STATE OF ALASKA n OIL AND GAS CONSERVATION COMMISSIONaj,.� BOPS T t R rt V W-1 epo Submit to: jim.repg(a�alaska.gov AOGCC.InspectorsCc�alaska.gov Phoebe. brooks at?alaska.gov Contractor: Moncla Rig No.: 301 DATE: 8/25/14 Rig Rep.: Jerry Guidry Rig Phone: 907-776-6751 Operator: Hilcorp Alaska LLC Op. Phone: 907-776-6754 Rep.: Bob Finch E -Mail bfinchtc'7.hilcorp.com Well Name: TBU G-11 PTD # 1680430 Sundry #- 313-453 Operation: Test: Test Pressure (psi): Drilling: Initial: Rams: 250/3000 Workover: Weekly: Annular: X Explor.: X Bi -Weekly: 250/2500 Valves: 250/3000 MASP: 0 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. P Well Sign P Upper Kelly 0 NA Housekeeping P Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. NA Ball Type 1 P nding Order Posted P Misc. NA Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 135/8 FP Pit Level Indicators P P #1 Rams 1 2 3/8 x 3 1/2 P Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 31/8 P Inside Reel valves 0 NA HCR Valves 2 31/8 P Kill Line Valves 2 31/821/16 P Check Valve 1 P ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3000 P CHOKE MANIFOLD: Pressure After Closure (psi) 1800 P Quantity Test Result 200 psi Attained (sec) 41 P No. Valves 11 P Full Pressure Attained (sec) 175 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P Nitgn. Bottles Avg. (# and psi): 4 @ 2200 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 1 Test Time: 12.0 Hours Repair or replacement of equipment will be made within 1 days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: Annular did not test. Installed new annular rubber. Tested good. MASP calculation based on alternate pressure gradient as approved in Sundry 313-453 Test #2 Pen cartridge skipping. Begin test again. [Note per J. Regg, AOGCC Inspection Supv. - test notice and test were late (test due 8/23/14); also test witness was not waived by AOGCC Inspection 24 hr Notice Yes Date/Time 3/24/2014 9:10 AM Waived By Test Start Date/Time: 8/25/2014 15:30 (date) (time) Witness Test Finish Date/Time: 8/26/2014 3:30 Form 10-424 (Revised 06/2014) BOP Moncla301 8-25-14.xlsx r 000 00. f SMP I' u C,, cn sQ Ci� /r w f() - 25 i Val 0 00 -1'� to�apliictt"Ikreoii t jr J! o o . '� .!CHART N0. MC MP -5000 -IHR til 1 3 4,3 + 'METER —-- t � l CHART PUT ON T 4r,� • - � , ,_ J � LOCA TION I/.17 //flI {7 /� a REMARK.: p O I O BlLS/zol i� _ O Q �---- — OOSZ� 02 0 (51 rIV 0 \, Regg, James B (DOA) From: Bob Finch - (C) <bfinch@hilcorp.com> Sent: Tuesday, August 26, 2014 6:07 AM To: Regg, James B (DOA) Subject: RE: Moncla rig 301 Grayling Platform well TBU G-11 Mr. Regg, We tested BOPE beginning yesterday afternoon when we got out of the hole with the milling assembly. But, I did not get a witness waived from you. I am now wondering what I should have done. Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, August 25, 2014 11:34 AM To: Bob Finch - (C) Subject: RE: Moncla rig 301 Grayling Platform well TBU G-11 TBU G-11 PTD 1680430 Mr. Finch — BOPE test was due 8/23/14 (last tested 8/16/14, witnessed by AOGCC). You notified AOGCC on 8/24/14 at 910am (late) of BOPE test scheduled for 8/25/14 (short notice). There was no request with justification for approval to delay the ROPE test. You must test BOPE when out of the hole with the milling assembly. Please provide daily reports beginning 8/22/14 for Moncla 301 well workover operations on TBU G-11. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Bob Finch - (C) [mailtotfinch hilcor m] Sent: Monday, August 25, 2014 8:14 AM Regg, James B (DOA) From: Bob Finch - (C) <bfinch@hilcorp.com> Sent: Monday, August 25, 2014 11:41 AM To: Regg, James B (DOA) Subject: RE: Moncla rig 301 Grayling Platform well TBU G-11 Attachments: Moncla Rig 301 TBU G-11 Daily Report 8-22 thru 8-25.xlsx See attached daily report for well operations on the G-11. Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, August 25, 2014 11:34 AM To: Bob Finch - (C) Subject: RE: Moncla rig 301 Grayling Platform well TBU G-11 TBU G-11 PTD 1680430 Mr. Finch — BOPE test was due 8/23/14 (last tested 8/16/14, witnessed by AOGCC). You notified AOGCC on 8/24/14 at 910am (late) of BOPE test scheduled for 8/25/14 (short notice). There was no request with justification for approval to delay the ROPE test. You must test BOPE when out of the hole with the milling assembly. Please provide daily reports beginning 8/22/14 for Moncla 301 well workover operations on TBU G-11. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or lim.regg@alaska.gov. From: Bob Finch - (C) [mailto:bfinch@hilcorp.com] Sent: Monday, August 25, 2014 8:14 AM To: Regg, James B (DOA) Subject: Moncla rig 301 Grayling Platform well TBU G-11 Mr. Regg, We are still trying to get out of the hole with a milling assembly that is stuck. I will update as we progress. Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform WSM 907-776-6754 Spot 20 bbl Poly Plug pill @ 929' and wait on poly plug to set 4 hours., Pressure up to 1500 psi. Leaking, no test. Pulled one PU 81/8 overshot, 4 3/4jars, (6) 4 3/4 drill collars.TIH to 8934' engage fish, jarred 5 times at 60-70K fish came free. POOH. BOB 19 stands out stuck again. Jarred free. Continue POOH. Mills had good wear. Taper on tapered mill had wear down to FINCH nose., BO/LD fish. PU 81/2 tapered mill, xover, 81/2 string mill, 9 5/8 casing brush, 4 3/4 bumper/oil jar, (6) drill collars. /HAROLD TIH to 863'. Tagged tight spot again. POOH, remove casing brush, trip back in hole. Tagged tight spot at 863'. PU power 8/23/2014 8/22/2014 SOULD Recover mill BHA swivel begin milling. Currently milling. 3 bpm, 2500-3500 torque, 200 psi, 3-4K wwight. Continue reaming tight spot from 8S3'- 862'., RD power swivel, TIH to 7533'. RU power swivel. Mill @ 7533', stuck pipe, jar BOB free, slack off to 7572'. did not tag obstruction., RD power swivel., TIH to 7841, tag obstruction„ RU power swivel., Swivel FINCH power pack would not start, work on swivel, Power swivel working. Milled 7841'- 7872', Power swivel quit working. Work /HAROLD on power swivel., Started swivel again.Milled from 7872'- 7883'., RD power swivel., TIH tagged obstruction @ 8028'., RU 8/24/2014 8/23/2014 SOULD TIH with milling BHA power swivel., Begin milling @ 8028'. Continue reaming to 8040'., RD power swivel., TIH with 14 stands from derrick. begin picking up singles from deck., Pick up (1) single tagged at 8891'., PU power swivel, milled to 8899' broke through. Contnue RIH tagged @ 9642'., Milling obstruction at 9642'. RPM 35, added (1) bbl of CFS -520 but did not see any significant hole friction reduction., Decision made to POOH. Will move completion packers up hole 40'. RD power swivel., POOH. Pulled 20K over @ 9366'., RU power BOB swivel., gin reaming while picking up and POOH. 9366'- 9345'., RD power swivel., POOH to 9121'. Hung up. RU swivel, FINCH attempt to back ream. No luck. LD swivel. Change to heavy duty elevators. Begin jarring, jarred at 70K over. Pulled free. /HAROLD POOH. Hung up @ 9002'. PU swivel. Back ream to 8971'- 8940'. Laying down joints in singles. Continue to POOH, @ 8815 8/25/2014 8/24/2014 SOULD TIH reaming to 9642' now. stand, set packer, pressured up to 1500 psi for 15 minutes. Packer setting good., Released packer, TIH one stand, set packer, opened bypass, establish circulation., Mix 10 bbl poly plug pill, hopper plugged, unplugged hopper, continue mixing pill., Spot PP pill at packer. Close bypass, pumped 1 bbl pressured up to 1500 psi, pressure bled off to 1350, pressured up to 1500 psi. Casing held pressure on chart 20 minutes at 1500 psi. Test good. Open bypass, reverse out 3 BOB tubing volumes, Pumped fluid from pill pit to active pit, cleaned pill pit, RU to Trading Bay., Pumped approximate 200 bbls FINCH to Trading Bay. Filled active pit with clean FIW. Build fluid weight to 9.4 ppg 3% KCL., RD TIW valve and hose. Release /HAROLD packer, POOH, lay down (6) 4 3/4 DC's, test packer., Change out annular rubber and function test. Test good. Picking up 8/22/2014 8/21/2014 SOULD Spot Poly Plug Pill overshot, jars and DC's now. PU 81/8 overshot, 4 3/4jars, (6) 4 3/4 drill collars.TIH to 8934' engage fish, jarred 5 times at 60-70K fish came free. POOH. BOB 19 stands out stuck again. Jarred free. Continue POOH. Mills had good wear. Taper on tapered mill had wear down to FINCH nose., BO/LD fish. PU 81/2 tapered mill, xover, 81/2 string mill, 9 5/8 casing brush, 4 3/4 bumper/oil jar, (6) drill collars. /HAROLD TIH to 863'. Tagged tight spot again. POOH, remove casing brush, trip back in hole. Tagged tight spot at 863'. PU power 8/23/2014 8/22/2014 SOULD Recover mill BHA swivel begin milling. Currently milling. 3 bpm, 2500-3500 torque, 200 psi, 3-4K wwight. Continue reaming tight spot from 8S3'- 862'., RD power swivel, TIH to 7533'. RU power swivel. Mill @ 7533', stuck pipe, jar BOB free, slack off to 7572'. did not tag obstruction., RD power swivel., TIH to 7841, tag obstruction„ RU power swivel., Swivel FINCH power pack would not start, work on swivel, Power swivel working. Milled 7841'- 7872', Power swivel quit working. Work /HAROLD on power swivel., Started swivel again.Milled from 7872'- 7883'., RD power swivel., TIH tagged obstruction @ 8028'., RU 8/24/2014 8/23/2014 SOULD TIH with milling BHA power swivel., Begin milling @ 8028'. Continue reaming to 8040'., RD power swivel., TIH with 14 stands from derrick. begin picking up singles from deck., Pick up (1) single tagged at 8891'., PU power swivel, milled to 8899' broke through. Contnue RIH tagged @ 9642'., Milling obstruction at 9642'. RPM 35, added (1) bbl of CFS -520 but did not see any significant hole friction reduction., Decision made to POOH. Will move completion packers up hole 40'. RD power swivel., POOH. Pulled 20K over @ 9366'., RU power BOB swivel., gin reaming while picking up and POOH. 9366'- 9345'., RD power swivel., POOH to 9121'. Hung up. RU swivel, FINCH attempt to back ream. No luck. LD swivel. Change to heavy duty elevators. Begin jarring, jarred at 70K over. Pulled free. /HAROLD POOH. Hung up @ 9002'. PU swivel. Back ream to 8971'- 8940'. Laying down joints in singles. Continue to POOH, @ 8815 8/25/2014 8/24/2014 SOULD TIH reaming to 9642' now. Schwartz, Guy L (DOA) From: Daniel Taylor <dtaylor@hilcorp.com> Sent: Wednesday, August 13, 2014 5:03 PM To: Schwartz, Guy L (DOA) Subject: RE: G-11, PTD: 168-043, Sundry:313-453 Guy, I want to inform you that we have just moved off of the G-15RD and have returned to the G-11. We are planning to be nippling up BOP'S and testing by 8-15-14 which will be one month after getting off of the well. Thank you sir. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. O: 907-777-8319 C: 907-947-8051 From: Schwartz, Guy L (DOA)[Lai lto:guy.schwa rtz(cbalaska.gov) Sent: Tuesday, July 15, 2014 9:10 AM To: Daniel Taylor Subject: RE: G-11, PTD: 168-043, Sundry:313-453 Daniel, You have approval to run kill string and come back later. If you are not back on well within 30days submit a 10-404 report for work done and also another 10-403 may be needed to finish the wellwork.. Otherwise you can stay on the same sundry. Contact me if it goes over 30 days.. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Daniel Taylor [ o:dtaylor(-@hilcorp.com] Sent: Tuesday, July 15, 2014 8:25 AM To: Schwartz, Guy L (DOA) SWNED OCT 16, 2014 Subject: G-11, PTD: 168-043, Sundry:313-453 Guy, The arrival of our completion equipment for the G-11 is behind schedule. We would like to hang a kill string off in G-11, and return after completing the other wells on schedule for this leg (G-15: ESP Completion, G-29: Injector). Do we have permission to move forward? Thank you. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. O: 907-777-8319 C: 907-947-8051 --1-6uG-Ii Pnb (X30 43G Regg, James B (DOA) I6v k -3a ( `3& -*s--T- 7t5((4 From: Bob Finch - (C) <bfinch@hilcorp.com> Sent: Saturday, July 12, 2014 7:05 AM �Orj 1/14114 To: Regg, James B (DOA) Cc: Brooks, Phoebe L (DOA); Ted Kramer; Juanita Lovett Subject: FW: BOPE Test Report Moncla 301 Well G-11 7-5-2014 Attachments: BOP Moncla301 7-5-14.xlsx Mr. Regg, Thank you for the clarification on the MASP. That is clearer now. The blinds test failure on the test chart is the test plug seal failure. We pulled the test plug and replaced the seal. Retested good. I will make sure and note any discrepancies in the future. Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform 907-776-6630 From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, July 11, 2014 2:45 PM To: Bob Finch - (C) Cc: Brooks, Phoebe L (DOA) Subject: RE: BOPE Test Report Moncla 301 Well G-11 7-5-2014 s(MOW TBU G-11 PTD 1680430 BOPE Test 7-5-14 I have sent a similar message to several others in Hilcorp, so apologiz/und Iready seen this: Thank you for using the new test report form. Please note that we hoblem with the form since you submitted this report; form has been corrected and posted on our worms) Appears that many of the workover BOPE tests are going to re 9yre some additional explanation for the MASP, especially wells that are incapable of unassisted flow to surf e (that is the case for many Hilcorp wells in Cook Inlet) researched sundry approval 313-453 for this well and fouO the calculation that gives MASP=Opsi that you report. AOGCC regulation 20 AAC 25.280(b)(4) requires calc ,tion of MASP using a 0.1 psi per foot pressure gradient for each foot of true vertical depth, "unless the commissio approves a different pressure gradient...". Appears from this Sundry approval that an alternate pressure gradient is eing allowed (0.435psi/foot). In this case, it is ok to show MASP =0 on ROPE Test Report but you should include a s tement in Remarks similar to the following — "MASP calculation based on alternate pressure gradient as approved i Sundry 313-453". Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, July 11, 2014 2:45 PM / To: 'Bob Finch - (C)' Cc: Brooks, Phoebe L (DOA) ((( Subject: RE: BOPE Test Report Moncla 301 Well G-11 7-5-2014 Attachments: BOP Moncla301 7-5-14.xlsx TBU G-11 PTD 1680430 BOPE Test 7-5-14 I have sent a similar message to several others in Hilcorp, so apologize if you have already seen this: Thank you for using the new test report form. Please note that we have found a problem with the form since you submitted this report; form has been corrected and posted on our webpage (link: Forms) Appears that many of the workover ROPE tests are going to require some additional explanation for the MASP, especially wells that are incapable of unassisted flow to surface (that is the case for many Hilcorp wells in Cook Inlet) researched sundry approval 313-453 for this well and found the calculation that gives MASP=Opsi that you report. AOGCC regulation 20 AAC 25.280(b)(4) requires calculation of MASP using a 0.1 psi per foot pressure gradient for each foot of true vertical depth, "unless the commission approves a different pressure gradient...". Appears from this Sundry approval that an alternate pressure gradient is being allowed (0.435psi/foot). In this case, it is ok to show MASP =0 on BOPE Test Report but you should include a statement in Remarks similar to the following — "MASP calculation based on alternate pressure gradient as approved in Sundry 313-453". Attached is a revised report form that includes the statement about MASP in the Remarks and a couple other minor edits - changed miscellaneous components to NA. I need an explanation for the apparent Blind Ram failure (based on my review of test chart). 1 also suggest that you annotate the chart when there is a failure or some discrepancy. Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.regg@alaska.gov. From: Bob Finch - (C) [mailto:bfinch@hilcorp.com] Sent: Monday, July 07, 2014 6:53 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Juanita Lovett Subject: BOPE Test Report Moncla 301 Well G-11 7-5-2014 Comments box will not let you put comments in it. It is linked to email address. Jim.regg@alaska.gov and opens new email. Bob Finch WSM (C) Hilcorp Alaska Cell 832-578-2246 Grayling Platform 907-776-6630 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: lim.reggt7a.alaska.gov AOGCC. InspectorSCa.alaska.gov Phoebe. brooks cDalaska.aov Contractor: Moncla Rig No.: 301 DATE: 7/5/14 Rig Rep.: Jerry Guidry Rig Phone: 907-776-6754 Operator: Hilcorp Alaska LLC Op. Phone: 907-776-6751 Rep.: Bob Finch E -Mail bfinchCc_hilcorp.com Well Name: TBU G-11 PTD # 1680430 Sundry #- 313-453 Operation: Test: Test Pressure (psi): Drilling: Initial: Rams: 250/3000 Workover: X Weekly: X Annular: 250/2500 Explor.: Bi -Weekly: Valves: 250/3000 MASP: 0 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: NA Test Result Test Result P Quantity Test Result Location Gen. P Well Sign P Upper Kelly 0 NA Housekeeping P Rig NA Lower Kelly 1 P PTD On Location P Hazard Sec. NA Ball Type 1 P nding Order Posted P Misc. NA Inside BOP 1 P P P #4 Rams FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 13 5/8" P Pit Level Indicators P P #1 Rams 1 2 7/8" x 5" P ✓ Flow Indicator P P #2 Rams 1 Blinds P Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 31/8 P Inside Reel valves 0 NA HCR Valves 2 31/8 P Kill Line Valves 2 31/821/16 P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3200 P CHOKE MANIFOLD: Pressure After Closure (psi) 1700 P Quantity Test Result 200 psi Attained (sec) 46 P No. Valves 11 P Full Pressure Attained (sec) 183 P Manual Chokes I P Blind Switch Covers: All stations Yes Hydraulic Chokes I P Nitgn. Bottles Avg. (# and psi): 4 @ 2100 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 1 Test Time: 7.0 Hours Repair or replacement of equipment will be made within 0 days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: MASP calculation based on alternate pressure gradient as approved in Sundry 313-453 q 14k -S. �D��'��/l °c 3 OF-SOF 454- p� issue AOGCC Inspection 24 hr Notice Yes Date/Time 07/212014 7:10 Waived By Jim Regg Test Start Date/Time: 7/5/2014 14:30 (date) (time) Witness Test Finish Date/Time: 7/512014 21:30 Form 10-424 (Revised 06/2014) BOP Moncla301 7-5-14.xlsx lip Std G- I t �kvv-VL 30 - 7151 Ill PoLc-� PF�T� - 7(sl14 _Az 1, -s _ ,.r f A&YkcV,� 30 P' U l (,bo oo P� ��-3 S , i i ,.r f A&YkcV,� 30 P' U l (,bo oo P� ��-3 Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Thursday, May 22, 2014 2:53 PM To: 'Daniel Taylor' Cc: Roby, David S (DOA) Subject: RE: Grayling Platform, G-11, PTD: 168-043, Sundry: 313-453 Dan, You have approval to modify sundry 313-453 as per your attached procedure. CIBP may be left out and hemlock reperfed. Allocation of water injection to the different pools must be done using injection spinner surveys. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.gov). From: Daniel Taylor [mailto:dtaylor@hilcorp.con] Sent: Thursday, May 22, 2014 2:30 PM To: Schwartz, Guy L (DOA) Cc: Roby, David S (DOA) Subject: RE: Grayling Platform, G-11, PTD: 168-043, Sundry: 313-453 Guy, We will run a spinner survey to determine what the individual pools are taking and allocate accordingly. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. 0:907-777-8319 C: 907-947-8051 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.govI Sent: Thursday, May 22, 2014 2:20 PM To: Daniel Taylor Cc: Roby, David S (DOA) Subject: RE: Grayling Platform, G-11, PTD: 168-043, Sundry: 313-453 Daniel, How do you plan to allocate injection between the two pools? Hemlock and Kenai G .. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv.schwartz@alaska.gov). From: Daniel Taylor [ "ailto:dtavlornhilcorp.com] Sent: Thursday, May 22, 2014 1:51 PM To: Schwartz, Guy L (DOA) Subject: RE: Grayling Platform, G-11, PTD: 168-043, Sundry: 313-453 Guy, We will be starting the work on this well tonight as per the approved Sundry application. Please let me know your thoughts on the below request of not setting a cement plug above the Hemlock and re -perforating the Hemlock. Thank you Guy. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. O: 907-777-8319 C: 907-947-8051 From: Daniel Taylor Sent: Monday, May 19, 2014 10:03 AM To: 'Schwartz, Guy L (DOA)' Subject: Grayling Platform, G-11, PTD: 168-043, Sundry: 313-453 Guy, The attached Sundry was approved on 8-28-13. Please see the attached revision to the procedure. This revision removes the step of placing a cement retainer over the Hemlock and increases the perforation depths to the previously perforated Hemlock zones. Changes are outlined in red. Attached to the procedure is the current, and proposed diagrams. Also attached is the Moncla 301 BOP stack in use on the Grayling platform. We are currently on G-13. The plan forward is to move to G-11 and then G-15RD. Please let me know if we may proceed as planned. Thank you sir. Regards, Dan Taylor Operations Engineer Hilcorp Alaska, LLC. O: 907-777-8319 C: 907-947-8051 1h6wr %64.k. 1.14 Revised Procedure Grayling Well: G-11 PTD: 168-043 Sundry: 313-453 1. Skid Williams Rig 404 over well G-11 2. Plumb filtered inlet water (FIW) lines to circulate down the annulus and up the tubing, or vice versa, through the tree, make sure there is no gas in the tubing or annulus. 3. Notify AOGCC 24 hrs before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3,000 psi HIGH. 4. PU landing joint and make-up to tubing hanger. Pull hanger up to floor height by unstinging from packer at 10,127'. If unable to remove push below the top of Hemlock perfs. 5. POOH with completion tubing. LD same, check for NORM. 6. PU scab liner milling assembly. Mill scab liner packers and retrieve same. 7. Mill and remove packer at 10,127'. 8. MaKe a tuu gauge mul and scraper to +i- i u,JbU . 9. Set a Gement Fetainw just a the uemlerk ee.fs at 10,21 r 10. RU E -line and run a casing inspection log (USIT or multi -arm caliper) in 9-5/8" casing from new PBD to surface, or run an RTTS to find the bottom hole and top hole in the 9-5/8" casing. 11. Set storm packer at 200', change out tubinghead. POOH. 12. RU Perforating company. PU and RIH with TCP guns according to perforating program. Confirm guns are on depth, Fire guns. Pull up hole to clear pert guns from new perforations. Monitor well shooting fluid level shots to confirm well is static. POOH with pert guns. 13. Losses are likely to occur following the re -perforation event until the well finds its stable point again. There is no need to circulate the hole, following re -perforation. After detonation, monitor well by shooting a fluid level and/or noting any flow. Once the well is determined to be static, POOH. 14. POOH with guns. LD same. Confirm that all charges fired. 15. PU RIH with injection straddle packers on new injection tubing. Treat backside with FIW with corrosion inhibitor, circulate around. Land tubing hanger 16. RU and set plug in X -Nipple to set packers, pressure up backside to confirm packer is set. Conduct WO MIT by testing backside to 2500 psi for 30 minutes with a 2 -pen recorder. NU tree, test same. Provide Larry Greenstein with the pressure test results as well as the completed 10-426 form for the MIT. 17. Set BPV. ND BOPE and NU tree. Test tree. 18. Turn well over to Production for restart of injection. 19. Within 2 weeks of stable injection, schedule an Initial MIT to test upper packer with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10-426 are to be provided to Larry Greenstein immediately following the test. Run a baseline temp survey to confirm integrity of lower packer. Attachments: 1. Current Schematic 2. Sundry Proposed Schematic 3. Proposed Schematic (5-19-14) 4. Grayling: Moncla 301 BOP H JJik." .U-ka. Lu OV( at 4,12 Colo casii 6,76 RKB to TBG Hngr = 42.95' Tree connection: 4-1/2" 8RD Top TD = 10,836' ETD = 10,790' MAX HOLE ANGLE = 30.7° @ 5,900' 2 3 4 -5 Revised Procedure G-11 Schematic As Completed: 10/2/00 As Perfed: 3/84 CASING DETAIL Grayling Well: G-11 PTD: 168-043 Sundry: 313-453 TUBING DETAIL 3-1/2" 1 9.3 N-80 I lmp.Buttspc 1 2.992" 1 42.95 1 10,210' JEWELRY DETAIL NO. Depth GRADE CONN ID MD TOP MD BTM. 16" 75 1-55 Butt Baker 9-5/8" x 6" ID" FA packer Surf. 694' 13-3/8" 61 J-55 Butt 3.875" Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8" 40 N-80 Seal Lock 8.835" 76' 4,956' 9-5/8" 43.5 N-80 Seal Lock 8.755" 4,956' 7,208' 9-5/8" 47 N-80 Seal Lock 8.681" 7,208' 8,290' 9-5/8" 47 P-110 Seal Lock 8.681" 8,290' 10,833' 7" Scab 29" N-80 Butt 6.181" 6,640' 6,900' TUBING DETAIL 3-1/2" 1 9.3 N-80 I lmp.Buttspc 1 2.992" 1 42.95 1 10,210' JEWELRY DETAIL NO. Depth ID Item Hangar 42.95' 10,223' Cameron 11" DC-FBB Tbg Hanger, 4-1/2"EUE Top x4-1/2" Butt Btm. 1A 6,640' 6,181" Baker 9-5/8" x 6" ID" FA packer 1B 6,900' 6.181" Baker 9-5/8" x 6" ID FA packer 2 10,125' 3.875" Baker Locator Type Seal Assy, w/ 1S' of seals, 4-3/4" X 2.992" 3 10,127' 4.750" Baker Model"D" Packer(DIL Depth) 4 10,175' 2.813" 3-1/2" "X" Nipple 5 10,210' 2.992" Baker Muleshoe PERFORATIONS Interval From To Last Date Remarks HB -1 10,223' 10,272' Mar -84 4spf HB -2 10,290' 10,390' Mar -84 4spf HB -3/4 10,395' 10,590' Jul -68 4spf HB -3 10,396' 10,436' Aug -80 4spf HB -4 10,460' 10,520' Aug -80 4spf HB -4 10,550' 1 10,575' Aug -80 4spf HB -5 10,610' 1 10,700' Jul -68 4spf Fish in Well Fish No. 1 Unknown length of wire and 1-11/16" X 13.3 long GR/CCL tool string at 10,493' (9/19/88) Fish No. 2 Bottom section of CX Mandrel @10,655' 2.83' long, Max OD 5.5" (3/26/76) Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3-1/2" tubing 18.15' Left in hole (8/80) Ilii -p AInA.. LLA DVc at 4,12 Colla casir 6,76' RKB to TBG Hngr = 42.95' Tree connection: 4-1/2" 81RD Top TD = 10,835' ETD =10,790' MAX HOLE ANGLE = 30.7° @ 5,900' 3 v) 1 2 3 4 5 Revised Procedure PROPOSED Grayling Well: G-11 PTD: 168-043 Sundry: 313-453 CASING DETAIL McArthur River Field Well: G-11 Completed: Future SIZE WT GRADE CONN ID MD TOP MD BTM. 16" 75 1-55 Butt Lower Straddle Packer Surf. 694' 13-3/8" 61 1-55 Butt 5 Surf 3,081' 9-S/8" 47 N-80 Seal lock 8.681" Surf 76' 9-5/8" 40 N-80 Seal Lock 8.835" 76' 4,956' 9-5/8" 43.5 N-80 Seal Lock 8.755" 4,956' 7,208' 9-S/8" 47 N-80 Seal Lock 8.681" 7,208' 8,290' 9-5/8" 47 P-110 Seal Lock 8.681" 8,290' 10,833' 7" Scab 29" N-80 Butt 6.181" 6,640' 6,900' TUBING DETAIL 3-1/2" 1 9.94 1 L-80 IBT 2.50" 1 42.95 NO. Depth ID Item Hangar 42.95' 11" X 3-1/2" Tubing Hanger 1 ±6600' Upper Straddle Packer 2 ±9550' Lower Straddle Packer 3 ±9590' X Nipple 4 ±9591' 3-1/2" Tubing Tail, WLEG 5 ±10,210' Cement Retainer PFRFORATIONS Interval Top (MD) Btm (MD) Top (TVD) Btm (TVD) SPF Date Comment G-1 ±9,714' ±9,741' ±8,855' ±8,879' 5 Future G-2 ±9,764' ±9,785' ±8,900' ±8,920' 5 Future G-3 ±9,826' ±9,862' ±8,957' ±8,990' 5 Future G-4 ±9,873' ±9,930' ±9,000' ±9,051' 5 Futurt: G-4 ±9,936' ±9,963' ±9,057' ±9,081' 5 Future G-5 ±10,020' ±10,084' ±9, ±9 5 Future HB -1 9,475' 9,500' 8,630' 8,653' 5 7/22/2012 Isolated HB -2 9,508' 9,548' 8,660' 8,697' 5 7/22/2012 Isolated HB -3/4 9,562' 9,602' 8,709' 8,746' 5 7/22/2012 Isolated HB -3/4 9,638' 9,708' 8.778' 8.842' 5 7/22/2012 Isolated HB -4 9,752' 9,848' 8.882' 8.970' 5 7/22/2012 Isolated HB -4 9,995' 10,020' 9,103' 9,125' 5 7/22/2012 Isolated HB -4 10,160' 10,192' 9.253' 9.282' 5 7/22/2012 Isolated 1-113-5 10,205' 10,315' 9,294' 9,394' 5 7/22/2012 Isolated [1"h In wen Fish No. 1 Unknown length of wire and 1-11/16"X13.3 long GR/CCL tool string at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel @10,655'2.83' long, Max OD S.5" (3/26/76) Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3-1/2" tubing 18.15' Left in hole (8/80) DVc at 4,12 colle casir 6,76' RKB to TBG Hngr = 42.95' Tree connection: 4-1/2" 8RD Top TD = 10,836' ETD = 10,790' MAX HOLE ANGLE = 30.7° @ 5,900' 4 V) 1 2 3 4 5 Grayling Well: G-11 Revised ProcedurePTD: 168-043 Sundry: 313-453 McArthur River Field PROPOSED (5-19-14) Well: G-11 Completed: Future CASING DETAIL SIZE WT GRADE CONN ID MD TOP MD BTM. 16' 75 J-55 Butt 5 Lower Straddle Packer Surf. 694' 13-3/8" 61 J-55 Butt 38,920' Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8" 40 N-80 Seal Lock 8.835" 76' 4,956' 9-5/8" 43.5 N-80 Seal Lock 8.755" 4,956' 7,208' 9-5/8' 47 N-80 Seal Lock 8.681' 7,208' 8,290' 9-5/8' 47 P-110 Seal Lock 8.681' 8,290' 10,833' 9,500' SAW SAW. TUBING DETAIL 7/2212012 Isolated HB -1 3-1/2" 9.3 L-80 I TPL 4040 1 2.50" 42.95 19,591' JEWELRY DETAIL NO. Depth ID (in) Itern Hangar 42.95' 11"X3-1/2"Tubing Hanger 1 ±6,600' 5 Upper Straddle Packer 2 ±9,600' 5 Lower Straddle Packer 3 ±9,637' 2.313 XNipple 4 ±9,668' 1 2.99213-1/2- Tubing Tail, WLEG PERFORATIONS Interval Top (M D) Btm (M D) Top (TVD) Btm (TVD) SPF Date Comment G-1 39,714' 19,741 ±8,855' 38,879' 5 Future 'Jew G-2 39,764' ±9,785' 113,900' 38,920' 5 G-3 39,826' 19,862' 0,957' 38,990' 5 G4 39,873' ±9930' 39,000' 39,051 5 Fut, G4 39,936' 19,057' 39,081 5 Future +ew G-5 30,020' 39,92' ±9,130' 5 Future New 14e-1 9,475 9,500' SAW SAW. 5 7/2212012 Isolated HB -1 9,475' 9,500' 8,630' 8,653' Future New HB -2 9AW 9,548' SAW 8,69T 5 7/22/204 Isolated 118-2 9,508' 9,548' 8,660' 8,697' Future HB -3/4 9,582' 9,802' 8,709' 8,748' 5 7/22/2012 Isolated HB -3/4 9,562' 9,602' 8,709' 8,746' Future New HB -3/4 9,838' 9,708' 8,775 8,842' 5 7/22/2012 Isolated HB -3/4 9,638' 9,708' 8,778' 8,842' Future New HB -4 9,752' 9AW 8,882' 8,970' 5 7122/202 Isolated HB -4 9,71, 9,848' 8,882' 8,970' Future New HB -4 9,995' Op20' 9,133' 7/22/204 Isolated H84 9,995' 10,020' 9,03' Future New HB4 10,180' 70,92' 9253' 7/22/2012 Isolated HB4 1D,Ti0' D,192' '�+3' g9,125' Future New HB4 10205' 0,315' 9,294' 7/22/20/2 Isolated HB -5 10205' 10,315' 9294' Future New Fish in Well Fish No. 1 Unknown length of wire and 1-11/16" X 13.3 long GR/CCL tool string at 10,493' (9/19/88) Fish No. 2 Bottom section of CX Mandrel @10,655' 2.83' long, Max 00 5.5" (3/26/76) Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3-1/2" tubing 18.15' Left in hole (8/80) 08/20/13 by JLL Revised Procedure Grayling Platform 2014 Workovers BOP Drawing Moncla Grayling Well: G-11 PTD: 168-043 Sundry: 313-453 • illr■■■■•■ •■•■•■•■■ w�\\I%% s� THE STATE Alaska Oil and Gas ofl 1L1 1VKA Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF Q. Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Dan Marlowe S A04E� 3 Operations Engineer �" rrl Hilcorp Alaska, LLC b V 3800 Centerpoint Drive, Suite 100 Anchorage,e, AK 99503 Re: McArthur River Field, Hemlock Oil &Middle Kenai G Pools, TBU G-11 Sundry Number: 313-453 Dear Mr. Marlowe: 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 DATED this ZS day of August, 2013. Encl. .' • illite-. .tip' RECEIVED STATE OF ALASKA "V AUG 21 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 29 MC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pod❑' Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations 0 b Perforate❑ PuN Tubing 0• Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Atter Casing❑ Other. Complete Sc. 2.Operator Name: 4.Current WeN Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development ❑ 168-043" 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic ❑ Service 6.API Number Anchorage,AK 99503 50-733-20115-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception? Yes ❑ No 0 Trading Bay Unit G-11 - (C�(J raj L:-..) P( P,. ) 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0017594' McArthur River Field/Hemlock Oil&Middle Kenai G 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): '10,846 , 9,860 ■ 10,453 '9,519 N/A See Schematic - Casing Length Size MD TVD Burst Collapse Structural Conductor 629' 16" 694' 694' 2,630 psi 1,020 psi Surface 3,081' 13-3/8" 3,081' 2,934' 3,090 psi 1,540 psi Intermediate Production 10,835' 9-5/8" 10,833' 9,869' 5,750 psi 3,090 psi Scab Liner 260' 7" 6,640'-6,900' 6,087'-6,314' 8,160 psi 7,120 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Schematic • See Schematic 3-1/2" N-80 10,210 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker D Packer and N/A 10,127'(MD)9,220'(ND)and N/A 1 '12.Attachments: Description Summary of Proposal p ' 13.Well Class after proposed work: '( Detailed Operations Program ❑ BOP Sketch G • Exploratory ❑ Stratigraphic❑ Development❑ Service 14.Estimated Date for 15.Well Status after proposed work: 9/15/2013 Commencing Operations: Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ G • 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 Dan Marlowe Email dmarlowe @hilcorp.com Printed Name Dan Marlowe Title Operations Engineer Signatur. R phone (907)283-1329 Date 8/20/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 316._� ^ Plug Integrity ❑ BOP Test I� Mec anical Integrity Test Location Clearance ❑ /� Other: 43- M.r-r—IA(Lip es) 7L7 (bar re? . 2 rA--• / > / ...,,, �p�,r�, p 2c A4 - C�) la, ��1"�r Q ,4 7CS� 3600 s:, D pp �p Spacing Exception Required? Yes'❑ No Subsequent Form Required: /0 —y '/ RBF,Nk OCT 1 0 2 APPROVED BY Approved by: /9 COMMISSIONER THE COMMISSION Date: z 43— 13 g•zT•3 pp pp Submit Form and 1�1. '1�+J Form 10-403(Revised 10/2012) A rov 4 allo nths from th date of approval. Attachments in Duplicate ( �V • • Well Work Prognosis Well: G-11 Hilcorp Alaska,PLC Date: 08/20/13 Well Name: G-11 API Number: 50-733-20115-00 Current Status: SI Injector _ Leg: Leg#4 (SW corner) Estimated Start Date: September 15,2013 Rig: William Rig 404 Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 168-043 First Call Engineer: Ted Kramer (907)777-8420 (0) (985)867-0665 (M) Second Call Engineer: Dan Marlowe (907)283-1329 (0) (907) 398-9904(M) AFE Number: Budgeted Cost: The well is currently injecting about 1500 bwipd. When the well is shut-in periodically, pressure bleeds down to 0 psi within a short time and fluid level falls below surface. The estimated bottomhole pressures are based on previous static surveys, fluid level shots, and observations of surrounding wells. Current BHP: —4,000 psi @ 9,471' TVD/10400' MD .42 psi/ft, (8.1 ppg) at mid pert of Hemlock Max. Expected BHP: —3,500 psi @ 9,200' TVD .38 psi/ft G-zone is also de-pressured Max. Possible SP: 0 psi Using 0.435psi/ft SW gradient to surface Brief Well Summary G-11 is a Hemlock injector with communication between the tubing and casing annulus and fill over much of the Hemlock zone. It has been injecting about 1,500 bwpd at a choked pressure of 2,150 psi to limit the pressure on the casing annulus. As a Hemlock injector it is in a poor location, as it is too close to several wells including G-02RD and D-42. If converted to G-zone injection, it would allow for a larger sweep area from G-22, and better support of G-zone offtake at G-02RD and G-03RD. The objective of this rig workover is to pull the existing production packer (which is across the G-zone), isolate the Hemlock, perforate the G-zone, and run a new completion. To remove the old 9-5/8" packer, the scab liner must be removed. The well is expected to inject approximately 1,500—2,000 bwpd into the G-Zone. a Notes Regarding Current Wellbore Condition • Communication between tubing and the tubing X casing annulus • Scab liner must be removed to remove the production packer • • Hemlock perfs are to be abandoned. Fill over perfs will not be removed. Procedure: 1. Skid Williams Rig 404 over well G-11 2. Plumb filtered inlet water(FIW) lines to circulate down the annulus and up the tubing, or vice versa, through the tree, make sure there is no gas in the tubing or annulus. 3. Notify AOGCC 24 hrs before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3,000 psi HIGH., 4. PU landing joint and make-up to tubing hanger. Pull hanger up to floor height by unstinging from packer at 10,127'. If unable to remove push below the top of Hemlock perfs. 5. POOH with completion tubing. LD same, check for NORM. 6. PU scab liner milling assembly. Mill scab liner packers and retrieve same. 7. Mill and remove packer at 10,127'. 1t `D' • • Well Work Prognosis Well: G-11 Hilcorp Alaska,PLC Date: 08/20/13 8. Make a full gauge mill and scraper run to the top of Hemlock perforations at 10,223'. 9. Set a cement retainer just above the Hemlock perfs at 10,210'. 10. RU E-line and run a casing inspection log(USIT or multi-arm caliper) in 9-5/8" casing from new PBD to surface, or run an RTTS to find the bottom hole and top hole in the 9-5/8" casing. 11. Set storm packer at 200', change out tubinghead. POOH. 12. RU Perforating company. PU and RIH with TCP guns according to perforating program. Confirm guns are on depth, Fire guns. Pull up hole to clear perf guns from new perforations. Monitor well shooting fluid level shots to confirm well is static. POOH with p erf guns. 13. Losses are likely to occur following the re-perforation event until the well finds its stable point again. There is no need to circulate the hole,following re-perforation. After detonation, monitor well by shooting a fluid level and/or noting any flow. Once the well is determined to be static, POOH. 14. POOH with guns. LD same. Confirm that all charges fired. 15. PU RIH with injection straddle packers on new injection tubing. Treat backside with FIW with corrosion inhibitor, circulate around. Land tubing hanger 16. RU and set plug in X-Nipple to set packers, pressure up backside to confirm packer is set. Conduct WO MIT by testing backside to 2500 psi for 30 minutes with a 2-pen recorder. NU tree,test same. Provide Larry Greenstein with the pressure test results as well as the completed 10-426 form for the MIT. 17. Set BPV. ND BOPE and NU tree. Test tree. 1345 44- Dr X 51144-7 .. r 18. Turn well over to Production for restart of injection. Q T 19. Within 2 weeks of stable injection,schedule an Initial MIT to test upper packer with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and cmpleted 10-426 are to be provided to Larry Greenstein immediately following the test. Run a besetie temp survey to confirm integrity of lower packer. `{ J' ' M!T- IA --ems' Attachments: 1-v'`� 2 Rolling BOP test procedure V As-built(Old)Wellbore Schematic Proposed(New)Wellbore Schematic As-Built(Old)Wellhead Diagram Proposed (NEW)Wellhead Diagram BOP Drawing ., ini • • G-11 Schematic As Completed: 10/2/00 Hik orp Alaska,LLC As Perfed: 3/84 CASING DETAIL RKB to TBG Hngr=42.95' SIZE WT GRADE CONN ID MD TOP MD Tree connection:4-1/2"8RD Top BTM. .1 j [I... 16" 75 J-55 Butt Surf. 694' 13-3/8" 61 1-55 Butt Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8" 40 N-80 Seal Lock 8.835" 76' 4,956' 9-5/8" 43.5 N-80 Seal Lock 8.755" 4,956' 7,208' 9-5/8" 47 N-80 Seal Lock 8.681" 7,208' 8,290' 9-5/8" 47 P-110 Seal Lock 8.681" 8,290' 10,833' 7"Scab 29" N-80 Butt 6.181" 6,640' 6,900' TUBING DETAIL 3-1/2" 9.3 N-80 Imp.Butt spc 2.992" 42.95 10,210' DV collar at JEWELRY DETAIL 4,128'MD NO. Depth ID Item Cameron 11"DC-FBB Tbg Hanger,4-1/2"EUE Hangar 42.95' Top x 4-1/2"Butt Btm. 1:(1 1A 6,640' 6.181" Baker 9-5/8"x 6"ID"FA packer 1A 16 6,900' 6.181" Baker 9-5/8"x 6"ID FA packer Collapsed �'" Baker Locator Type Seal Assy, w/15' of casing at 2 10,125' 3.875" 6,767'MD seals,4-3/4"X 2.992 16 ,/, 3 10,127' 4.750" Baker Model"D"Packer(DIL Depth) - 4 10,175' 2.813" 3-1/2" "X"Nipple 5 10,210' 2.992" Baker Mule shoe PERFORATIONS Interval From To Last Date Remarks HB-1 10,223' 10,272' Mar-84 4spf < HB-2 10,290' 10,390' Mar-84 4spf Vi r � HB -3/4 10,395' 10,590' Jul-68 4spf 2 iiii/ , c P 3 Il=r HB-3 10,396' 10,436' Aug 80 4spf HB-4 10,460' 10,520' Aug-80 4spf 4 ■ • HB-4 10,550' 10,575' Aug-80 4spf C HB-5 10,610' 10,700' Jul-68 4spf 5 HB-1 HB-2 Fish in Well Fish No.1 Unknown length of wire and 1-11/16"X 13.3 long GR/CCL tool string at 10,493' (9/19/88) Fish No.2 Bottom section of CX Mandrel @10,655'2.83'long, Max OD 5.5"(3/26/76) FIB-3 Fish No.3 Mule shoe.72',Q nipple 1.7',cut 3-1/2"tubing 18.15'Left in hole(8/80) Top of fill 10,444'9/8/2011 HB-4 9v ` HB-5 / TD=10,835' ETD=10,790' MAX HOLE ANGLE=30.7°@ 5,900' G-11 WBS 09.30.00.doc Revised 6/28/12 by TDF McArthur River Field ., 11. • •PROPOSED Well: G-11 Hilcorp Alaska,LLC Completed: Future CASING DETAIL RKB to TBG Hngr=42.95' SIZE WT GRADE CONN ID MD TOP MD Tree connection:4-1/2"8RD Top BTM. i] 16" 75 1-55 Butt Surf. 694' 13-3/8" LL 61 J 55 Butt Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8" 40 N-80 Seal Lock 8.835" 76' 4,956' 9-5/8" 43.5 N-80 Seal Lock 8.755" 4,956' 7,208' 9-5/8" 47 N-80 Seal Lock 8.681" 7,208' 8,290' 9-5/8" 47 P-110 Seal Lock 8.681" 8,290' 10,833' 7"Scab 29" N-80 Butt 6.181" 6,640' 6,900' TUBING DETAIL 3-1/2" 9.94 L-80 IBT 2.50" 42.95 ±9591' DV collar 4,128'MD • JEWELRY DETAIL v tjo-An r'i NO. Depth ID Item 660° 1 A Hangar 42.95' 11"X 3-1/2"Tubing Hanger 10- 1 ±6600' Upper Straddle Packer Imp p"‘` 2 ±9550' Lower Straddle Packer Collapsed 3 ±9590' X Nipple casing at 6,767'MD 4 ±9591' 3-1/2" Tubing Tail,WLEG 5 ±10,210' Cement Retainer PERFORATIONS Interval Top Btm Top Btm SPF Date Comment /51oI 2 (MD) (MD) (TVD) (TVD) G-1 ±9,714' ±9,741' ±8,855' ±8,879' 5 Future x 3 Future 4 G-2 ±9,764' ±9,785' ±8,900' ±8,920' 5 G-3 ±9,826' ±9,862' ±8,957' ±8,990' 5 Future G-4 ±9,873' ±9,930' ±9,000' ±9,051' 5 Future G-4 ±9,936' ±9,963' ±9,057' ±9,081' 5 Future G - one G-5 ±10,020' ±10,084' ±9,132' ±9,190' 5 Future Perfs HB-1 9,475' 9,500' 8,630' 8,653' 5 7/22/2012 Isolated (New) 5 = HB-2 9,508' 9,548' 8,660' 8,697' 5 7/22/2012 Isolated '- HB-3/4 9,562' 9,602' 8,709' 8,746' 5 7/22/2012 Isolated HB-1 HB-3/4 9,638' 9,708' 8,778' 8,842' 5 7/22/2012 Isolated \n I(S ----- HB-2 HB-4 9,752' 9,848' 8,882' 8,970' 5 7/22/2012 Isolated e" HB-4 9,995' 10,020' 9,103' 9,125' 5 7/22/2012 Isolated HB-3 HB-4 10,160' 10,192' 9,253' 9,282' 5 7/22/2012 Isolated To.of fill 10 444 9 8 ' HB-5 10,205' 10,315' 9,294' 9,394' 5 7/22/2012 Isolated � s *, "�s `' ,� HB-4 *� ,e1 ^ , HB-5 Fish in Well art N. s p y ' .,r ,� ,,� ;� „�v Fish No 1 Unknown length of wire and 1-11/16"X 13.3 long GR/CCL tool string at 10,493'(9/19/88) 3,(a. < ?c.r.' .,:' ',. Fish No.2 Bottom section of CX Mandrel @10,655'2.83'long, Max OD 5.5"(3/26/76) Fish No.3 Mule shoe.72',Q nipple 1.7',cut 3-1/2"tubing 18.15'Left in hole(8/80) TD=10,835' ETD=10,790' MAX HOLE ANGLE=30.7°@ 5,900' Revised: 08/20/13 by AL Grayling Platform • • Williams Rig BOP (rental) 1/18/2013 Flil+vlrp %Lean ILIA. Grayling Platform 2013 Workovers BOP Drawing(Williams) it rrq S tiolitlitariti 3.42' Shaffer lil,ii Ill III It III ICI I/I.iii III 4.54' —1 �. _ _ e � _ „._11 :Ill Booster bon ets on botto _. Iio 41 lit III III dt ; Kill Side 2 1/16 5M w/check valve A ICI milt tit.In Choke side 2.00' "W { } A`4 { - } it 2 1116 5M w/HCR and and Unibolt line , �,II, . II,�.,.-I 1:0b1; ; connection lit 414141 Iil Unibolt line connection 1.00'to 2.00' III III III III III Drill deck Riser 11 5M FE X 16.00' 11 5M FE Ill il1101III III'lop I11 III Spacer spool 3.00' 11 5M FE X 11 5M FE Ill lit 441 lit Ill 14 • • Williams Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska LLC. BOP Test Procedure: Williams Rig 404, Grayling WO Program—Oil Producers, Water Injectors Pre Rig Move 1) Blow down well, bleed gas to Well Clean Tank that is vented thru flare to atmosphere 2) Load well with FIW to kill well. • Note: Fluid level will fall to a depth that balances with reservoir pressure. 3) Shoot fluid level at least 24 hours before moving on well. 4) Shoot fluid level again, right before ND/NU. Confirm that well is static. Initial Test(i.e.Tubing Hanger is in the Wellhead) If BPV profile is good 1) Set BPV. ND Tree. NU BOP. 2) MU landing joint. Pull BPV. Set 2-way check in hanger. 3) Space out test joint so end of tubing(EOT) is just above the blind rams. 4) Set slips, mark same. Test BOPE per standard test procedure. If BPV profile is eroded and/or corroded and BPV cannot be set with tree on, Profile and/or landing threads must be prepped while tree is off. Worst Case: BPV profile and landing threads are bad. Conduct Rolling Test. 1) Attempt to set BPV through tree. If unsuccessful, shoot fluid level. 2) If fluid level is static from previous fluid level shots, notify Hilcorp Anchorage office that the well is static and the tree must be removed with no BPV.As approved in the sundry, proceed as follows: a) ND tree with no BPV b) Inspect and prepare BPV profile to accept a 2-way valve,or prepare lift-threads to accept landing joint to hold pressure. If well is a producer and the culprit is scale,attempt to clean profile with Muriatic acid and a wire brush or wheel. c) Set 2-way check valve by hand,or MU landing(test)joint to lift-threads d) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test, notify office via e-mail that neither profile will allow for a test of the BOP.As outlined and approved in the sundry, proceed as follows: a) Nipple Up BOPE b) With stack out of the test path,test choke manifold per standard procedure c) Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor the surface equipment for leaks to ensure that the fluid is going down-hole and not leaking anywhere at surface.) • S Williams Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 d) Hold a constant pressure on the equipment and monitor the fluid/pump rate into the well. Record the pumping rate and pressure. e) Once the BOP ram and annular tests are completed,test the remainder of the system following the normal test procedure (floor valves,gas detection,etc.) f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile wouldn't hold pressure and rolling test was performed on BOP Equipment and list items, pressures and rates. 4) Pull hanger to surface. (Requires tubing cuts as necessary to free tubing). CBU to displace annulus and tubing with kill weight fluid. 5) If a rolling test was conducted, remove the old hanger, MU new hanger or test plug to the completion tubing. Re-land hanger(or test plug) in tubing head. Test BOPE per standard procedure. Subsequent Tests(i.e.Test Plug can be set in the Tubing-head) 1) Remove Wear bushing. a) Use inverted test plug to pull wear busing. MU to 1 jt.of tubing. b) Thread into wear bushing c) Back out hold down pins d) Pull and retrieve wear bushing. 2) Break off test plug and invert same,and RIH on 1 joint of tubing. Install a closed TIW or lower Kelly valve in top of test joint. 3) Break joint off test plug and pull up to space the bottom of tool joint above blind rams. 4) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack with rig pump and install chart recorder on the stack side of the pump manifold. 2) Note: When testing, pressure up with pump to desired pressure,close valve on pump manifold to trap pressure and read same with chart recorder. 3) Referencing the attached schematics test rams and valves as follows. a) Close C-1(inside gate valve on choke side of mud cross) and close the annular preventer. Pressure test to 200 psi for 5 minutes and 1,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open annular. b) Close Pipe Rams. Test to 200 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open pipe rams. c) Test Dual Rams. If the well has dual tubing,and dual rams are installed in the stack,test the dual rams by picking up two test joints with dual elevators and lowering them into stack and position them properly in the dual rams. Close rams. Test to 200 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off back to tank and open rams. d) Open C-1. Flow through the choke manifold and purge air. Test the choke manifold starting with the outer most valves,to 250 psi low and 3,000 psi high,for 5 minutes each,as follows: (Valve numbers are in reference to Diagram B) i) Valves 1,2, 10. After test,open same. • • Williams Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 ii) Valves, 3,4,9. After test, open valves 3&4. Leave 9 closed. iii) Valves 5,6,9. After test,open valves 5&6, leave 9 closed. iv) Valves,7, 8,9. After test,open all valves. e) Close C-2. This is the HCR(the hydraulic controlled remote)valve just outside C-1 on choke side of mud cross. Test to 250 psi low and 3,000 psi high. After test,open HCR, close C-1. f) Blind Rams. Make sure test joint is above the blind rams. Close blind rams. Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. Bleed down pressure. g) Bleed off all pressure. Line up pumps to pump down tubing. h) Test K-1, K-2, and K-3 on the kill (pump-in)side by pressuring up on tubing.Test to 200 psi Low for 5 minutes and 3,000 psi High for 5 minutes. i) Test floor valves TIW(or Lower Kelly Valve)and IBOP. STANDARD TEST PROCEDURE OF CLOSING UNIT(ACCUMULATOR) 1) This is a test of stored energy. Shut off all power to electric and pneumatic pumps. 2) Record "Accumulator Pressure". It should be+/-3,000 psi. 3) Close Annular Preventer,the Pipe Rams, and HCR. Close 2nd set of pipe rams if installed (e.g. dual pipe rams). Open the lower pipe rams to simulate the closing volume on the blinds. 4) Allow pressures to stabilize. 5) While stabilizing: Record pressure values of each Nitrogen bottle and average over the number of bottles. (i.e. Report might read "10 bottles at 2,150 psi"). 6) After accumulator has stabilized, record accumulator pressure again. This represents the pressure and volume remaining after all preventers are closed. (The stabilized pressure must be at least 200 psi above the pre-charge pressure of 1,000 psi). 7) Turn on the pump and record the amount of time it takes to build an additional 200 psi on the accumulator gauge. This is usually+/-30 seconds. 8) Once 200 psi pressure build is reached,turn on the pneumatic pumps and record the time it takes for the pumps to automatically shut-off after the pressure to builds back to original pressure (+/-3,000 psi). Note: Make sure the electric pump is turned to "Auto", not "Manual" so the pumps will kick-off automatically. 9) Open all rams and annular and close HCR to place BOPE back into operating position for well work. 10) Fill out AOGCC report. FINAL STEP, FINAL CHECK 1) Test Gas Alarms 2) Double check all rams and valves,for correct operating position 3) Fill out the AOGCC BOPE Test Form (10-424) in Excel Format and e-mail to AOGCC and Juanita Lovett. • • Williams Rig 404 BOP Test Procedure it,� �I,t ,11,,k,_ Attachment#1 Diagram A-1: Grayling BOP stack and Riser Arrangement—Typical for Single Completion Grayling Platform 2013 Workovers BOP Drawing(Williams) i iii III 1 3.42' 111 111 111 111 111 4.54' _g all Booster bo is on _. 111 iii Iii lii Kill Side Choke side 21/16 5M w/check valve A 1 •1 �'!"!""""!' and Unibolt line 2.00 )1 { } ' �; { ' } - t1l 2 1/16 5M w/HCR and connection I'• II' ll' 1 ''lit!il,ii iil.il' 1' ` °11'4'1 ` Unibolt line connection 1.00'to 2.00' 111 111111 11;111 Drill deck Riser 11 5M FE X 16.00' 11 5M FE lil hil lil Ill lit 111 111111 III 111 Spacer spool 3.00' 11 5M FE X 11 5M FE lir'il lil Iii lit • •• Williams Rig 404 BOP Test Procedure HileorpAla6ka,I,r.l Attachment#1 Diagram A-2: Grayling BOP stack and Riser Arrangement—Typical for Dual Completion Williams Workover Rig Grayling Platform BOP 2012 .L=f-'M - _111 1.44 •1 Ii 19 II' 13 5/8 5M Spacer spoil 2 00 1. al 111 0 7 IIId11 I' - - Weeth.rford Rental BOP Width 4.16 3.74' Shaffer to SIB OA III III III lil iii � S13MB _-_-_ 13 6/8 6M LWS t36/8 6/8 6 5M , _ dimensions ® :c � r Length 7 73 a 3'00' Width across body 2.72' Width 'across flanged n =I= 7 outlets �=1 n 111 1111 +{ eN�• 3: IiMr,N}1I +e-.4.3 III : -} 1.74 K 3 -1 1.. ..,-..... 1 1 1 K-2 K-1 C-1 C-2"HCR' Mud Cross r Riser above drill deek This number will vary front well to well Drill Deck 13 5/8 6M Riser 86001bs 135/8 5M X -•,� 15.00' 3 1155M EFO 1!1 111 maw III I11 l Spac er Sp000 1365 a Spacer 13 f 6M 195' 18001bs III 111 AIIII III III Crossover Spool 136/86M X115M 18001bs 2.82 III MI III Top of Wellhead II • i Williams Rig 404 BOP Test Procedure Hilrnrp nlackn.l.LC Attachment#1 Diagram B: Grayling Choke Manifold To Gas Buster All National type To Panic line 2 1/16 5M 1502 Union ball valves *11111 22y t �T 1111i1 III WiNt 111 I"' Chokes are 90 degrees off ` in drawing in order to show / 11 detail imut _ i! AIM :: 1 ' 1111 IN 111 '604 i 11"1161 7 01 AL I lillaC - - III - - ISwaco Alll II I:: E. i I , a� 6 i III 1,i --- II, III ftwt ifs ; :1. 1,lu.r From Bop Choke Line 2 1/16 5M Unibolt Flange Valve Type #1 National Ball Valve B3260, 3 1/4" Ball port, 6000psi working pressure #2 National Ball Valve B3260, 3'A" Ball port,6000psi working pressure #3 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #4 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #5 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #6 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #7 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #8 National Ball Valve B2650, 2 9/16" Ball port, 5000psi working pressure #9 National Ball Valve B3260, 3 1/4" Ball port,6000psi working pressure #10 National Ball Valve B1560, 1 'A" Ball port,6000psi working pressure • • Williams Rig 404 BOP Test Procedure Hi!carp Alaska,1.1.1. Attachment#1 u 1 t Pg fJK I C.1 T `..,w a � :.: r N jY } i ,i,;1 h '..0 m iii ill s i a_ EE G co Q co .w oS s A m 0 z m 9 :o ___ la_ °u_-- Z - - Q g � aOU I— p ¢ d `-LIJLJO � ,- d __Thi 0 2 a IX ri=1 ,....:5 cz ___i 0.7.] iii J O z w M a LI- Z 1= a Q J D U CC U • • Williams Rig 404 BOP Test Procedure Hileorp Alaska,ii.c Attachment#1 u a� V 4 2 — :11 r d t VI' Z t .1 U I' F Z N 1 1 r ID- r r r1 1 103 C TiT -.. N a a c. 2 a III 0 r U j.. .„ • 7,... (0 , < 1 ,__, .__, J J D a Z Z O :o Z 0 o o vQZU _ II Do 0 `—Lc t � wzc� u) 0_ — Z • O ° cO • LL cL 7� W V w J a J 0 J V J .. VI l-1- ZO 0 Z Q J D U CC 0 • • Grayling Platform G-11 Current 02/15/2012 Hilrurp %laAka.1.11. Grayling 11 Tubing hanger, CIW- 133/8X95/8X41/2 DCB, 11X4'/2EUE 8rd lift and 4'h IBT susp,w/4"type H BPV profile, 7" EN, '/o" non continuous control line BHTA, CIW,4 1/16 5M FE X Internal Acme knockup undIS , III Choke, adj, Cortec, _l_ 4 1/16 5M FE X FE '.i• r d � Tree, Block, CIW-F, 11 5M 1I. FE X 4 1/16 5M, single a master and swab,w/7" _ __ '• FBB pocket, 1/2 control line O exit, EE trim �. `;0 • O - / Void test good in 250/5000psi er 2/15/2012 :.iI • ■ I;i.: Tubing head, CIW-DCB, 1II I 11l 13 5/8 3M X 11 5M, w/ Valve, WKM-M, 2 1/16 5M -` 9 FE, HWO,AA 2-2 1/16 5M SSO,X- •. , °,, �' .i,j,. bottom prep, iI � � �� ' 1 '/2 VR profile - in /_; Void test failed Casing head, ilk �' 2/15/2012 Shaffer KD, ®_ 135/83MX ilk ` Ill 13 3/8 SOW,w/2-2" LPO, cur 11111 I 041. IaI-L 2"LP ball valve ow or,. • • • Grayling Platform G-11 Proposed 08/21/2013 II lrurp %la+La.ILL( Grayling 11 Tubing hanger,SME-CL,11 X 133/8X95/8X41/2 4%EUE lift and 4Y2TC-2 susp,w/4"Type H BPV profile,2-3/8 CCL,6 extended neck,17-4PH stainless steel BHTA,Bowen,4 1/16 5M FE X 7"-Ssa Bowen top,full stainless steel III ! n Pig Valve,swab,WKM-M, co 4 1/16 5M FE,HWO, r ", a' Valve,Wing,WKM-M,4 1/16 T-26 O 0 0 5M FE,w/15"Safeco operator,T-26 MI I!1 Tee,stdd,4 1/16 5M X N / . 4 1/16 5M Full Stainless Steel ;f Q Valve,lower master, PAiir \WKM-M,4 1/16 5M FE, Adapter,Seaboard,11 5M FE HWO,T-26 0 0 0 X 4 1/16 5M,w/6%pocket, "' 2-%CCL exits,Full Stainless Steel is�. �_ =.iIi r . rril iii■= Tubing head,5-8,13 5/8 3M x 11 5M,w/2-2 1/16 5M !- Jr= 1 Casing head, r Shaffer KD, lei 13 5/8 3M X ; 2"LP ball valve 13 3/8 SOW,w/2-2" III Imo la ? •b LPO, • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe @hilcorp.com> Sent: Monday,August 26, 2013 10:35 AM To: Schwartz,Guy L(DOA);Ted Kramer Cc: Roby, David S(DOA); Bettis, Patricia K(DOA) Subject: RE:G-11 Injector workover(PTD 168-043) Attachments: Grayling Injection Well Repair; RE:Grayling Injection Well Repair Guy A couple weeks ago we discussed two wells on the grayling with this completion design. Refer to attached my original email and your reply. G-11 (PTD 168-043) G-19 (PTD 169-017) Sundry to be submitted today Our intent is to complete both with a straddle packer design to isolate bad spots in the 9-5/8" casing. The upper packers will be tested with standard MIT's every 4 years. The lower packers will be monitored with temperature surveys every 2 years. We intend to establish a baseline and file for Administrative Approval on both wells for the high set packer(more than 200' above the zone) and the two year temp survey to verify zone isolation with the lower straddle packer, Let me know what else you need sir thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Fax 907-283-1315 Email DMarlowe cx hilcorp.corn Hilcorp A Company Built on Energy , From: Schwartz, Gu From: Guy L(DOA ) [(ilailLO:gtlir schwa rC`dala5,. ,c,''-1`J] Sent: Friday, August 23, 2013 3:24 PM To: Dan Marlowe Cc: Roby, David S (DOA); Bettis, Patricia K(DOA) Subject: G-11 Injector workover(PTD 168-043) Dan, Your proposal to workover G-11 includes setting a straddle packer over a bad casing section at about 6600-6900 ft. In this case the upper monitor-able annulus is well over 3000 ft from the injection zone . By regulation(20 AAC 25.412(b)), the packer must be within 200 ft of the injection zone unless the Commission approves something different. Can you provide any backup as to why this arrangement will isolate injection into the target zones? Also how it can be monitored effectively to ensure UIC conformance?You will need to request a variance to the 20 AAC 25.412 also. 1 • • Guy Schwartz Senior Petroleum Engineer AUGCC 907-444-3433 cell 9 07-793-1226 office 2 • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe @hilcorp.com> Sent: Wednesday,August 28, 2013 7:54 AM To: Schwartz, Guy L(DOA) Cc: Juanita Lovett;Ted Kramer Subject: Grayling G-11 PTD 168-043 Attachments: G11 AOR MAP.pdf;G-02RD Schematic 4.25.2012.doc;G-34(PTD 170-023).pdf Guy Here is the AOR information we initially supplied for the G-11 workover prior to revising our completion design to isolate the casing damage Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Fax 907-283-1315 Email DMarlowe(c hiicorp corn Hilcorp A Company Built on Energy From: Larry Greenstein Sent:Thursday,July 05, 2012 4:14 PM To: Victoria Ferguson @ AOGCC Subject: Area of Review for recompleting G-11 to a G-Zone only injector Hi Victoria, Two wells penetrate the G-Zone within the %mile radius Area of Review(AOR)for the new G-Zone perfs proposed for G- 11 (as shown on the attached map), G-2RD and G-34. For the G-02RD well (a Hemlock only Oil well), I've attached the wellbore schematic and a scan of the G-Zone area of the CBL(G-Zone-9640'-10153'). The G-34 well has been abandoned and re-drilled as G-34RD which lies entirely outside of the 1/4 mile radius AOR. See the attached pdf of the abandonment info(with 350 sacks of cement across the G-Zone, I sure hope this old penetration is isolated). The WO of the G-11 well is currently planned to follow the WO of the G-14ARD well which starts next week. Let me know if you need anything else. Larry 1 1. • G-33 / '.9- G-1ORD h 41,620 •. 5'72 136 e / �• w6 s G-02 - '' 49 woo \• G-07 0 *t_G-06RD \\G-34RD .-\S 497 2,370 ro° a,-., ..,<.P -14 G-21RD yti' 4-G-06 •�' •$773 613 6y'.16 0 • •8'2 ••• 06 A-0 °,299 ••• .••. ••9• •93,266 •' 684 i•• •••• G24 29 G-21 .^ • •0 • cb A° i ryp • Proposed •• G-30 • Perforation ` •B 6AO a. i1 boo • Interval \y_ 8,729 ■ •�' �y \ �' ^ �Ca > 9,205' 9' • $521.90 \ 347 •9^� • 9ry G-14ARD 9.177 jo • 6j . 457 • ^ •-9,16,094 9• -0 • nri ?S �6 RD2 r G 1 G 02E2D \ G-03PB2 G-08RD G-22 •• .... :• •-8,570 \ 1_HLCORP ALASKA,LLC ii G-34 a1 0-08 MCARTHUR RIVER FIELD•�D-40RD ii -_.3 --G-0351 •s' M-31A_prop ,• s-42 •.• •-9,049 — Wei Ate D-28•••• .. • ...... .. 9�0 9011 6210 167 .-9�? �+_7Rp, D�0 • •' •a' 8.523 FEET • 225 �9, 83 �6Z3 G-26RD 7'446�G-23RD c, POSTED wELL DATA • 91291 471 -' D-30RD D-07RD " • • • wpaL.l»t ■ ~8669 666 / 'O91\-,f. •.., I \ G-23 \ \ FMTOPS Grone toiJwaIN LSS) D-07 9-36 FMTOPS-HKT(MASTRJ(SS D-11 6 at D-07 RD 720 Tau GZN-CUM OILIOPR(MEO) 86 86 / 9 6VI TEL GZN CUR NJW(MEW) D-47 �D-01 °O." D-30RD2 •7)O 14,848 ,1 •¢A WELL SYMBOLS 64 gps •a' 247 • Oil w l tEr.SB '9 61. Gas Wel •,p 9 c• Dry Hole 4, 47070 •./ •\ t Injection Wea s' 312 067 9:155'‘ ® WeN Type Not Listed D-29 •" '50'' Pugged 8 Abandoned 011W es86 2 G 36DPN s9' • * Pugged 8 Abandoned GasW , ,0' Abandoned Well Converted Water Input Wet D-26RD •19 . Abandoned Water Injector D-27 Shut-in oaweo 5 846---41D-31 RD 371' p� G 12RD sb hot-in Water Injector 295 •e� D 26 sus G-12 Jane zT.zotz 8A, _-_ PFTRA R(770017 7 n5 4R PM Schwartz, Guy L (DOA) 10 Y "OY 3 From: Juanita Lovett <jlovett@hilcorp.com> Sent: Tuesday, July 16, 2013 3:08 PM To: Schwartz, Guy L (DOA) Subject: Withdraw Sundry # 312-244 - Grayling G-11 (PTD 168-043) Guy, Please withdraw the above mentioned sundry. We will resubmit at a later date. Thank you, Juanita Lovett Sr. Operations/Regulatory Tech Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Office: (907) 777-8332 Email: ilovett@hilcorp.com 1 SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMl►IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Mike D. Dunn ff tt Sr. Reservoir Engineer 1 ( — 3 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: McArthur River Field, Middle Kenai G Oil Pool, Trading Bay Unit G -11 Sundry Number: 312 -244 WOOED JUL 18 Z01`4 Dear Mr. Dunn: 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, t ior / Cathy Foerster Chair DATED this 1( day of July, 2012. Encl. STATE OF ALASKA br ` " ALASKA OIL AND GAS CONSERVATION COMMISSION 4 , \ APPLICATION FOR SUNDRY APPROVALS 20 MC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool E • Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations 1 `)Z Perforate El Stimulate Tubing Time Extension El Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Recomplete 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Development ❑ Exploratory ❑ 168 -043 . 3. Address: Stratigraphic ❑ Service El . 6. API Number: 3800 Centerpoint Drive, STE 100, Anchorage, AK 99503 50 -733- 20115 -00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: RECEIVED property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No In Trading Bay Unit G -11 • JU G � ryniz 9. Property Designation (Lease Number): 10. Field / Pool(s): /14 ti i (,L_ K y - _ net . ,i..--&_e }� McArthur River Field /,IjgmlecK6in A - ..- 7 - > ADL (V' ' / 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): /C l c 1 , ' ,10;83 ''( ..97973 10,453 9,519 N/A See Schematic Casing r,? "Length Size MD TVD Burst Collapse Structural Conductor 629' 16" 694' 694' 2,630 psi 1,020 psi Surface 3,081' 13 -3/8" 3,081' 2,934' 3,090 psi 1,540 psi Intermediate Production 10,835' 9 -5/8' 10,833' 9,869' 5,750 psi 3,090 psi Scab Liner 260' 7" 6,640' - 6,900' 6.087' - 6,314' 8,160 psi 7,120 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attachment #1 See Attachment #1 3 -1/2" N -80 10,210' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker D Packer and N/A 10,127' (MD)9,220' (TVD) and N/A 12. Attachments: Description Summary of Proposal is 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch el Exploratory ❑ Development ❑ Service © , 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 7/8/2012 Oil ❑ Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: N/A WINJ IO ' GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Printed Name Mike D. Dunn Title Sr. Reservoir Engineer Signature ��r , j ` G� ---- I Phone (907) 777 -8382 Date 7/3/12/2012 r ! /.., 4 `, CO MMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: �) /' ' . L (.4 Plug Integrity ❑ BOP Test I/ Mechanical Integrity Test Location Clearance ❑ Other: / ` J- ` f / I ' L / k1 S ') G' '' c t 'C °' fat p res f`� L, , , . ti t z? !! , c1 /kid i (i4 tr C1 ' Subsequent Form Required: 1e - 4c ;' APPROVED BY 1 Approved by: "' / COMMISSIONER THE COMMISSION Date: 7 l/ 1 = ®„�3 . 12 c � �' � z-0 R 1 G 1 N A L 4/ p � � t7 ` +� �; Le p� 7/ q/ Submit in Duplicate � 2: Hilcorp Alaska, LLC Attachment #1 G -11 Perforation Data 07 -03 -12 Zone MD TVD HB -1 10,223' — 10,272' 9,310'- 9,355' HB -2 10,290' — 10,390' 9,371'- 9,462' HB -3/4 10,395' — 10,590' 9,467'- 9,645' HB -3 10,396' — 10,436' 9,468'- 9,504' HB -4 10,460' — 10,520' 9,526'- 9,581' HB -4 10,550' — 10,575' 9,608'- 9,631' HB -5 10,610' — 10,700' 9,663'- 9,745' Well Work Prognosis Well: G -11 Hilcorp Alaska, LLC Date: 07/02/2012 Well Name: G -11 API Number: 50- 733 - 20115 -00 Current Status: SI Injector Leg: Leg #4 (SW corner) Estimated Start Date: July 09, 2012 Rig: William Rig 404 Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 168 -043 First Call Engineer: Mike Dunn (907) 777 -8382 (0) (907) 351 -4191 (M) Second Call Engineer: Ted Kramer (907) 777 -8420 (0) (985) 867 -0665 AFE Number: Budgeted Cost: The well is currently injecting about 1500 bwipd. When the well is shut -in periodically, pressure bleeds down to 0 psi within a short time and fluid level falls below surface. The estimated bottomhole pressures are based on previous static surveys, fluid level shots, and observations of surrounding wells. Current BHP: — 4,000 psi @ 9,471' TVD /10400' MD .42 psi /ft, (8.1 ppg) at mid pert of Hemlock Max. Expected BHP: — 3,500 psi @ 9,200' TVD .38 psi /ft G -zone is also de- pressured Max. Possible SP: 0 psi Using 0.435psi /ft SW gradient to surface Brief Well Summary G -11 is a Hemlock injector with communication between the tubing and casing annulus and fill over much of the Hemlock zone. It has been injecting about 1,500 bwpd at a choked pressure of 2,150 psi to limit the pressure on the casing annulus. As a Hemlock injector it is in a poor location, as it is too close to several wells ✓ including G -02RD and D -42. If converted to G -zone injection, it would allow for a larger sweep area from G -22, and better support of G -zone offtake at G -02RD and G -03RD. The objective of this rig workover is to pull the existing production packer (which is across the G- zone), isolate the Hemlock, perforate the G -zone, and run a new completion. To remove the old 9 -5/8" packer, the scab liner must be removed. The well is expected to inject approximately 1,500 — 2,000 bwpd into the G -Zone. _kW "f, v ,t _s . ,r, 4 , . cz Notes Regarding Current Wellbore Condition coon ' . Offscr ffoducets q, • Communication between tubing and the tubing X casing annulus / Gwo ^' / ess 1-4 /Od 001 Ii • Scab liner must be removed to remove the production packer • Hemlock perfs are to be abandoned. Fill over perfs will not be removed �`r r h C��Cefs 1�$� rk /5 70 k r , e d h r &#'t' ev 4 Procedure: a +njtCti0 f " 1. Skid Williams Rig 404 over well G -11 I ° h f wL��, � 2. Plumb filtered inlet water (FIW) lines to circulate down the annulus and up the tubing, or vice versa, through the tree, make sure there is no gas in the tubing or annulus. 3. Notify AOGCC 24 hrs before pending BOPE test. Set BPV, ND tree, NU BOPE. Test all BOP equipment per AOGCC guidelines to 250 psi LOW and 3,000 psi HIGH. 4. - PU landing joint and make -up to tubing hanger. Pull hanger up to floor height by unstinging from packer at 10,127'. Install stripper rubber. Circulate at least 2 bottoms up to adequately clean hole. 5. POOH with completion tubing. LD same, check for NORM. 6. PU scab liner milling assembly. Mill scab liner packers and retrieve same. If losses are too high to circulate fill and /or metal shavings, pump pills as necessary to reduce fluid losses. 14 Well Work Prognosis Well: G -11 Hilcorp Alaska, Lac Date: 07/02/2012 7. Mill and remove packer at 10,127'. 8. Make a full gauge mill and scraper run to the top of Hemlock perforations at 10,223'. 9. Set a cement retainer just above the Hemlock perfs at 10,210'. 10. RU E -line and run a casing inspection log (USIT or multi -arm caliper) in 9 -5/8" casing from new PBD to surface, or run an RTTS to find the bottom hole and top hole in the 9 -5/8" casing. Order liner material and plan to extend the new scab liner 80' below the deepest deficiency or hole, and 80 above the shallowest deficiency or hole, or at least 80 below and 80 above the old scab packer setting depths. 11. Set storm packer at 200', change out tubinghead. POOH. ! 12. Perforate G -Zone with SLB PURE (Dynamic Underbalance) TCP guns /packer per perf design from 9762' — 10085'. Do not pump salt or polymer pill after perforating. Pull guns and packer. Zone Interval Feet G - 2 9,762' — 9,785' 23 G - 3 9,825' — 9,862' 37 G - 4 9,878' — 9,930' 52 G - 4 9,936' — 9,964' 28 G - 5 10,020' — 10,085' 65 Total: 205 13. Losses are likely to occur following the re- perforation event until the well finds its stable point again. There is no need to circulate the hole, following re- perforation. After detonation, monitor well by shooting a fluid level and /or noting any flow. Once the well is determined to be static, POOH. 14. POOH with guns. LD same. Confirm that all charges fired. 15. Provide a minimum 24 hour notice to AOGCC prior to the workover MIT test 16. PU 3 -1/2 X 9 -5/8" mechanical set retrievable packer and RIH on workstring. Set same at approximately 9,600'. 17. MU scab liner assembly and run across bad spots in 9 -5/8" casing as found in step 10. 18. PU 3 -1/2" tubing with seal assembly. RIH and sting into packer. Land the tubing hanger, and pressure up backside to confirm packer is set. Hold 2,500 psi for 30 minutes for the casing MIT test. If the pressure does not decline more than 200 psi in 30 minutes, the well has passed the Workover MIT. Provide Larry Greenstein with the pressure test results as well as the completed 10 -426 form for the MIT. 19. Set BPV. ND BOPE and NU tree. Test tree. 20. Turn well over to Production Supervision (TOPS) for restart of injection. 21. Within 2 weeks of stable injection, schedule an Initial MIT with AOGCC. Provide the AOGCC 24 hour notice prior to the MIT test. All pressure test results and completed 10 -426 are to be provided to Larry Greenstein immediately following the test. III • II • cArthur River Field, TBU SCHEMATIC e Well: G -11 IIileorp Alaska, 1.1.(: As Completed: 10/2/00 CASING DETAIL RKB to TBG Hngr= 42.95' SIZE WT GRADE CONN ID MD TOP MD Tree connection: 4 -1/2" 8RD Top BTM. -I] 16" 75 J -55 Butt Surf. 694' L 13 -3/8" 61 J-55 Butt Surf 3,081' 9 -5/8" 47 NJ-80 Seal Lock 8.681" Surf 76' 9 -5/8" 40 N -80 Seal Lock 8.835" 76' 4,956' 9 -5/8" 43.5 N -80 Seal Lock 8.755" 4,956' 7,208' 9 -5/8" 47 N -80 Seal Lock 8.681" 7,208' 8,290' 9 -5/8" 47 P -110 Seal Lock 8.681" 8,290' 10,833' 7" Scab 29" N -80 Butt 6.181" 6,640' 6,900' TUBING DETAIL 3 -1/2" 9.3 N -80 I Imp.Butt spc 2.992" 42.95 10,210' DV collar at JEWELRY DETAIL 4,128'MD NO. Depth ID Item Cameron 11" DC -FBB Tbg Hanger, 4- 1 /2 "EUE Hangar 42.95' Top x 4 -1/2" Butt Btm. 1A 6,640' 6.181" Baker 9 -5/8" x 6" ID" FA packer 1A 1B 6,900' 6.181" Baker 9 -5/8" x 6" ID FA packer Collapsed rvi i / I Baker Locator Type Seal Assy, w/ 15' of casing at 2 10,125' 3.875" 6,767'MD seals, 4 -3/4" X 2.992" 16 3 10,127' 4.750" Baker Model "D" Packer (DIL Depth) 4 10,175' 2.813" 3 -1/2" "X" Nipple 5 10,210' 2.992" Baker Mule shoe PERFORATIONS Interval From To Last Date Remarks HB -1 10,223' 10,272' Mar -84 4spf HB -2 10,290' 10,390' Mar -84 4spf 2 HB -3/4 10,395' 10,590' Jul -68 4spf 3 NM 11'' , / / HB -3 10,396' 10,436' Aug -80 4spf INN 4■ • HB -4 10,460' 10,520' Aug -80 4spf HB -4 10,550' 10,575' Aug -80 4spf C HB -5 10,610' 10,700' Jul -68 4spf 5 HB -1 Fish in Well HB - Fish No. 1 Unknown length of wire and 1- 11/16" X 13.3 long GR /CCL tool string at 10,493' (9/19/88) Fish No. 2 Bottom section of CX Mandrel @10,655' 2.83' long, Max OD 5.5" (3/26/76) HB-3 Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3 -1/2" tubing 18.15' Left in hole (8/80) To • of fill 10 444' 9 8 2011 F," ?1 k HB-4 �~ HB-5 TD = 10,835' ETD = 10,790' MAX HOLE ANGLE = 30.7° @ 5,900' G -11 WBS 09.30.00.doc Revised 6/28/12 by TDF II • cArthur River Field, TBU PROPOSED Well: G -11 Hilemp Alaska, LLC Proposed: 7/2/12 CASING DETAIL RKB to TBG Hngr= 42.95' SIZE WT GRADE CONN ID MD TOP MD Tree connection: 4 -1/2" 8RD Top BTM. -I] _ 16" 75 J -55 Butt Surf. 694' 1 3 -3/8" [L 61 J -55 Butt Surf 3,081' 9 -5/8" 47 N -80 Seal Lock 8.681" Surf 76' 9 -5/8" 40 N -80 Seal Lock 8.835" 76' 4,956' 9 -5/8" 43.5 N -80 Seal Lock 8.755" 4,956' 7,208' 9 -5/8" 47 N -80 Seal Lock 8.681" 7,208' 8,290' 9 -5/8" 47 P -110 Seal Lock 8.681" 8,290' 10,833' 7" Scab 29" N -80 Butt 6.181" 6,600' 7,000' TUBING D ' "AIL 3 - 1/2" 9.3 N -80 Imp.Butt spc 2.992" 42.95 10,210' DV collar at • • 4,128'MD JEWELRY DETAIL NO. Depth ID Item Cameron 11" DC -FBB Tbg Hanger, 4- Hangar 42.95' 1 /2 "EUE Top x 4 -1/2" Butt Btm. 1A ±6,600' 6.00" Weatherford slips and packer I S 1A X 1B ±7,000' 6.00" Weatherford slips and packer Collapsed casing at 2 ±9,600' 2.875" Weatherfod Packer 6,767'MD 3 ±9,630' 2.875" XN Nipple X 1B X 4 ±9,640' 2.875" Wireline Entry Guide 5 ±10,210' 8.681" Cement Retainer PERFORATIONS Interval From To Last Date Remarks G -2 9762 9785' Proposed 5 spf 2 till. 94,00 G -3 9825' 9862' Proposed 5 spf 3 G -4 9878' 9930' Proposed 5 spf C G4 9936' 9964' Proposed 5 spf 4 i 710 Z G -5 10,020 10,085' Proposed 5 spf G zone / 1 5 Z /P? — HB-1 HB - 2 Fish in Well = Fish No. 1 Unknown length of wire and 1- 11/16" X 13.3 long GR /CCL tool string at 10,493' — HB -3 (9/19/88) Top of fill 10,444'9 /8/2011 HB -4 Fish No. 2 Bottom section of CX Mandrel @10,655' 2.83' long, Max OD 5.5" (3/26/76) FE Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3 -1/2" tubing 18.15' Left in hole (8/80) 0 = HB -5 A es a te . 7 TD = 10,835' ETD = 10,790' MAX HOLE ANGLE = 30.7° @ 5,900' Revised 7/03/12 by TDF • • II Well Work Prognosis Well: G -11 Hilcorp Alaska, LLC Date: 07/02/2012 Williams Workover Rig t III Grayling Platform v a BOP 2012 IUi Weatherford Rental BOP Width 4.16' 3.74' Weight 13,100# Shaffer 13 5/8 5M lil Iii it 111 lil MP e S Total BOP height above drill deck 135/85M LWS _ 1 ' 9.48' min dimensions 1 1.48'maX Length 7.73' - - �— 3.00 Width across body 2.72' Width across flanged outlets 4.00' ' — _ — Weight95001bs ,I_ "`— 9.00' 111 111 ili lil Iil 1 I. Mud Cross H ! 2850Ibs w/ vlves Q ]qj ' _ r a Ill lil Iii Ill Ill '� m ui Riser above drill deck III ' III This number will vary from well to well 1.00' to 3.00' T Drill Deck 13 5/8 5M Riser 85001bs 15.00' i 1 Spacer Spool 135/85M X 135/85M 1.95' 1800lbs 11I I1I MINI . 111 , II Crossover Spool 135/85M X115M 1800Ibs 2.83' 111 111 Top of Wellhead • • Ferguson, Victoria L (DOA) From: Ted Kramer [tkramer @hilcorp.com] Sent: Wednesday, July 11, 2012 10:41 AM To: Ferguson, Victoria L (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: TBU G -11 (Sundry 312 -244) Victoria, In our analysis of injection wells changed out in the past and the age of the completion, the tubing heads sometimes exhibit signs of corrosion. Therefore since we will have the well apart, we felt it would be prudent to plan to change out the tubing head at this time ( if needed). We are taking the position that it is a small incremental preventive maintenance cost to set the well up for the next 15 years of injection. Please let me know if you have any other questions, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907 - 777 -8420 C 985 - 867 -0665 From: Ferguson, Victoria L (DOA) J mailto :victoria.ferguson@alaska.govl Sent: Monday, July 09, 2012 3:39 PM To: Ted Kramer Cc: Schwartz, Guy L (DOA) Subject: TBU G -11 (Sundry 312 -244) Ted, In the procedure for this well, why are you changing out the tubinghead? Thanx, Victoria Victoria Ferguson Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave, Ste 100 Anchorage, AK 99501 Work: (907)793 -1247 victoria.ferquson a(�alaska.gov 1 5L/A)O,ZY 31Z - 24"j Ferguson, Victoria L (DOA) From: Larry Greenstein [Ireenstein @hilcorp.com] Sent: Thursday, July 05, 2012 4:15 PM To: Ferguson, Victoria L (DOA) Subject: Area of Review for recompleting G -11 to a G -Zone only injector Attachments: G11_AOR_MAP.pdf; G -02RD Schematic 4.25.2012.doc; G -34 (PTD 170- 023).pdf Hi Victoria, Two wells penetrate the G -Zone within the'/ mile radius Area of Review (AOR) for the new G -Zone perfs proposed for G- 11 (as shown on the attached map), G -2RD and G -34. For the G -02RD well (a Hemlock only Oil well), I've attached the�crvellbore schematic and a scan of the G -Zone area of the CBL (G -Zone — 9640' — 10153'). ✓/ The G -34 well has been abandoned and re- drilled as G -34RD which lies entirely outside of the 'A mile radius AOR. See the attached pdf of the abandonment info (with 350 sacks of cement across the G -Zone, I sure hope this old penetration is isolated). The WO of the G -11 well is currently planned to follow the WO of the G -14ARD well which starts next week. Let me know if you need anything else. Larry 1 G -33 G -34 - 11 -. N`- •- 1ORD h�� 6 1,620 8 'SF < 4b, - 8 �1_ g ,6 a9 . r 6 4. o G-02 843 a 4,,ta G -07 0 * - G -06RD G -34RD • o g 2, , � 0, -C *W . m 'c,C1 -14 1 �,. G -21 RD • y ti' G -06 s 4.-' �� 9 2 • o s. •. ...... Oah � 4 ,5b' 299 • •'. •9 3,266 11 / 684 • ••• • i N ` 9 G -24 O j y 9 G 40 • 9 ° G - �° Proposed NI 3O 'b Perforation ` • O 4', 640 s ow \ s - 6. S - ,- 8,724 nterval ■ • • .s,2"..90 ' ,� ��o i -9. O G -14ARD 9. + -8 >6> -...__ -9.205 .457 347 s' 9, � • v � • . s,ts,o94 ..9: G -03RD2 . � � s G 1 rb G -0 G -08RD • • •: - 0- G -03PB2 G-22 i/' • • -657 - D-42 .• G-08 if HILCORP ALASKA, LLC •• • • 0 i G -34 A G -08 MCARTHUR RNER FIELD 5 D-40RD G -03 •' M -31 A_prop •'• • 0-11 Aoli #D 28 p 0 500 S .. .. D 3 • 90EO • . 9 01 �62�` /67 19 • G-26 � . a.s23 FEET / 225 ID ; • 86 73 G -26RD ,----- ' 44 G -23RD ' 2 h 5 A POSTED WELL DATA 271 � — 'D -30RD D -07RD W' • ..9 s .9. I I Ozone top Well Label Ike 68g 666 9 ° 6, p 1 46, G -23 wnwRL RFI0 t 83) D -11 • a 96 D- 07R D-07 720 F M TOPS - Tao GZN- CUUM(��OI 6 LLL)IO � D-47 • D 14,646 o L 6 ° J. 1 TBD_GZN - CUM INJW (MEW1 ' � OD_01 64 D -30RD2 v 1 A2 •� WELL SYMBOLS • 06 �, 247 • • Oil Well - •5' B '' 1 Well t Gasw O . Dry Hole 470 •,9O \ •� !election WeA 312 6 41110 7 t ✓7 . 8,\ • WeA Type Not Listed • D -29 •'O ; Plugged & Abandoned OIl W 21 85 88 G-36DPN .- 9 ' *- Plugged & Abandoned Gas h 1 •C7 Abandoned Well Converted Water -Input We! D -26RD • .D-27 19 Abandoned Water Injector '� j_______71 � � 7 ? G -12RD Shutdn WaterI njector 5 -- �D - 31RD Bhutan waterl Well 295 � D-26 G-12 June 27, 2012 PFTRA 0/77/7017 1'eA' PM 1 S Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, September 28, 2011 1:21 PM To: 'Lambert, Steve A' Cc: Brooks, Phoebe L (DOA); Greenstein, Larry P; Greenstein, Larry P; Cole, David A Subject: RE: G -11 (PTD 168 -043) MIT Temp Survey Steve, et al, I concur with your assessment. The curves indicate that the injected water is being contained as required. The difference in the absolute temperatures also reflects the 3+ months SI time prior to the survey in July 2009. Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com) Sent: Wednesday, September 28, 2011 10:50 AM To: Maunder, Thomas E (DOA) Cc: Brooks, Phoebe L (DOA); Greenstein, Larry P; Greenstein, Larry P; Cole, David A Subject: G -11 (PTD 168-043) MIT Temp Survey An MIT temperature survey was run in well G -11 (PTD 168 -043; AIO 5.009) on September 9, 2011. As the attached data confirms, all injected fluids are exiting the wellbore at the perforations. This survey should fulfill the requirements to submit a biennial temperature survey under AIO 5.009, which was approved on December 15,2005. Based on the survey results, this well will remain on injection. If you have any questions please contact me. • • Pressure (psia) 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 r ....: %... .. 1000 - - - --- 2000 -Id I i 1 3000 4000 - - 1111111. k G) - 5000 — - 0 2 . Q 6000 _. G) - 3 7000 8000 9000 10000 _ -- - - 1 \ 11000 ■ I I I I i I ■ I 1 60 70 80 90 100 110 120 130 140 150 160 170 Temperature (Deg. F) - 9 -9 -11 Pressure - Perfs 13 -3/8 9 -5/8 - 7 TBG 9 -9 -11 Temp -7-8-09 Temp • • Pressure (psia) 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 0 � _ 1000 11141114 - - -4 2000 3000 4000 L , 15 c ' 1111111 5000 I— s a a) in 6000 7000 - - - - 8000 - 1 9000 -- ..1. ir.......... \ C i 10000 I I 1 I 1 I I I I 60 70 80 90 100 110 120 130 140 150 160 170 Temperature (Deg. F) 9 -9 -11 Pressure — Perfs 13 -3/8 9 -5/8 -- 7 TBG 9 -9 -11 Temp —7-8-09 Temp Page 1 of 4 Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp @chevron.com] Sent: Wednesday, August 04, 2010 8:48 AM To: Maunder, Thomas E (DOA) Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke Tom, I agree, we both want accurate numbers to be generated and reported. We rely on these numbers in many ways, reservoir management, regulatory reporting, monthly well integrity reports, etc. Found out there is no consistency for water wells at the different platforms /fields. SRF & Happy Valley have theirs on an annual calibration for instance, Grayling only checks when something seems out of whack (kind of like what happened recently) just like the King who looks at the production meters annually, but not the injection meters (most common schedule). This recent event has Grayling proposing a semi - annual PM schedule for their instrument tech to verify accuracy /performance. Every day there is a general balance between what the pump puts out and what goes into each well, but any smaller errors could easily be lost in the overall volume of injection. Those platforms that are on the edge of losing all waterflood due to losing enough injection volume that the pump has to be shut down are watching their wells closest. But that is still comparing one day to the next and totaling up to make sure the pump output agrees with the what the wells are taking. The monthly reporting I do on the failed MIT wells provides another cross -check on the accuracy of the meters /gauges. They may be false alarms, but if something looks awry, we are going to respond as if it is real. Meters and pressure gauges go bad, they drift off of accurate, they corrode, they break, etc. We catch them being wrong and we fix them. The engineers in the office check their production and injection wells on a regular basis for abnormal conditions and respond accordingly. The biggest issue seems to be bad data entry/typos so that what looks like pressure spikes aren't even real. We find and correct lots of these each week. Sure wish we had a fully instrumented electronic oil field to build PLC logic monitoring into all of the various flow streams, but that's not going to happen. We have the operators catching everything they can and some other cross- checks and back -ups to help them. We'd rather respond to a few extra false alarms, than miss a real event by ignoring indications of problems with a well. The fewer false alarms the better is everyone's goal. I'm sure you understand where we are at. Larry 4.401410f4) APR 8 nri From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, August 03, 2010 10:57 AM To: Greenstein, Larry P Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke Thanks Larry and Steve. I think we both want the same goal here. From: Greenstein, Larry P [mailto :Greensteinlp @chevron.com] Sent: Tuesday, August 03, 2010 10:30 AM To: Maunder, Thomas E (DOA) Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke 4/8/2011 Page 2 of 4 • Fully understand and fully agree, Tom. Our reservoir management requires accuracy on not only what comes out of the ground, but also what goes into the ground. My reference to not 'too extensive' is in comparison to custody transfer type metering installations. Our flow measurement people handle all of those types of meters and the field personnel handle their own non - custody transfer meters, such as the waterflood wells. I'm getting a copy of one of their work orders to see what they do and how often as a part of their routine maintenance. This particular well metering problem may have gone undiscovered much longer except for the operations placards that we developed for each platform. This well showed an injection volume that was suddenly right at the max allowable range for the well and the operator called in to ask for a change. That brought the issue to light and initiated the admittedly proper reactions. Eventually it was determined that the meter was in error, but not before we had already shut -in the well and notified you. I'll get some more info and get back with you. Thanks Larry From: Maunder, Thomas E (DOA) [mailto:tom.maunder @ alaska.gov] Sent: Tuesday, August 03, 2010 10:12 AM To: Greenstein, Larry P Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke Larry, I'd agree that while there aren't royalty and sales concerns, incorrect measurement on any level introduces problems /issues. We have this example where you all are chasing replacement chokes, possibly performing slick line interventions (plugs, temperature surveys) and shutting in the well with the domino effect of loosing reservoir support and possibly not having sufficient well capacity to keep the water flood running at all (maybe that the King or Dolly water floods). We also had that "double counting" issue a few years back where if I remember correctly the "under measurement/allocation" was over 20 million barrels. That could have affected the regulatory cost charge Unocal is responsible for. It is my opinion that if you are employing sensing devices (measurement/pressure /temperature) which are required by the regulations, then they need to be working properly and Unocal /Chevron needs to have confidence that is so. Even without royalty and sales concerns, real costs result when proper reactions are taken to incorrect information. Tom Maunder, PE AOGCC From: Greenstein, Larry P [ mailto :Greensteinlp @chevron.com] Sent: Tuesday, August 03, 2010 9:58 AM To: Maunder, Thomas E (DOA) Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke I'll find out what field maintenance is in place for these types of meters, Tom. I don't expect it is too extensive as there isn't any royalty or sales involved in the waterflood arena. Larry From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, August 03, 2010 9:51 AM To: Greenstein, Larry P Cc: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke 4/8/2011 Page 3 of 4 • Larry and Steve, What is the preventative maintenance schedule for the flow measurement instruments as well as other sensors (pressure /temperature) on injection wells? If I remember correctly, this is not the first time we've seen this. I'd expect there is some PM schedule out there, but I don't know. It would seem, based on what you've /we've encountered that PM could prevent us jumping through hoops and unnecessarily shutting in wells. I look forward to your comments. Tom Maunder, PE AOGCC From: Greenstein, Larry P [ mailto :Greensteinlp @chevron.com] Sent: Tuesday, August 03, 2010 9:42 AM To: Maunder, Thomas E (DOA) Subject: RE: G -11 (PTD 168 -043) Injection choke Thanks Tom... it does look like all is `as expected'. Larry From: Maunder, Thomas E (DOA) [mailto:tom.maunder @ alaska.gov] Sent: Tuesday, August 03, 2010 7:13 AM To: Lambert, Steve A Cc: Greenstein, Larry P Subject: RE: G -11 (PTD 168 -043) Injection choke Steve and Larry, It does appear that the present performance is in the "normal" operating envelope. It is acceptable to keep the well in operation closely monitoring its performance as you plan. Call or message with any questions. Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Monday, August 02, 2010 2:39 PM To: Maunder, Thomas E (DOA) Cc: Greenstein, Larry P Subject: RE: G -11 (PTD 168 -043) Injection choke Tom the attached graph shows the pressure and rate performance for injection well G -11 (PTD 168 -043) on the Grayling platform. The well is being returned to injection slowly, and all rate and pressure data seems to be consistent with the well's historic long term performance. The well's current performance appears to confirm that the anomalous rate data that was seen on June 15 was a metering error and not a change in performance. With your permission, we plan to keep the well on injection and will continue to closely monitor its performance. Steve Lambert Senior Advising Petroleum Engineer Chevron North America Exploration and Production 3800 Center Point Suite 100 Tel 907 263 7658 salambert @chevron.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] 4/8/2011 Page 4 of 4 • • Sent: Monday, July 26, 2010 8:11 AM To: Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Injection choke Steve, It is acceptable to resume the injection test. I look forward to additional information as it is available. Call or message with any questions. Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Monday, July 26, 2010 7:30 AM To: Maunder, Thomas E (DOA) Subject: G -11 (PTD 168 -043) Injection choke Tom we have received the new surface injection choke for Grayling well G -11 and we would like to reaffirm our request to return the well to injection. As I detailed in my previous e-mail, the 6 hour injection test performed on June 18th appeared to confirm that the issues with the Scada software had been fixed and the injection rates and pressures were in line with historic performance. With your permission we would like to return the well to continuous injection. We will continue to monitor the injection rates and pressures to insure that the well performance is consistent with past performance. Steve Lambert Senior Advising Petroleum Engineer Chevron North America Exploration and Production 3800 Center Point Suite 100 Tel 907 263 7658 salambert@chevron.com From: Lambert, Steve A Sent: Tuesday, June 29, 2010 4:26 PM To: Thomas Maunder Cc: Agler, Brit G; Greenstein, Larry P; Cole, David A Subject: G -11 (PTD 168 -043) Follow up Tom I apologize for not following up after our 6 hour injection test on well G -11 (PTD168 -043). As you recall we shut the well in on June 15th when we saw a dramatic increase in rate with a corresponding decline in injection pressure. We subsequently determined that an error in the Scada software was giving false data on this well. You permitted us to perform a short term test to confirm the actual rates and pressures for this well. We were able to install a new choke on this well and perform a 6 hour injection test on June 18 The data from the test is attached. The test confirmed that the previously reported rates and pressures had been in error. Unfortunately the surface choke failed on this well after the test was completed, so the well could not be returned to injection. We are in the process of obtaining a new surface choke and should be capable of returning the well to injection shortly. We would like to ask your consent to attempt a longer term injection test to confirm that in fact the well does have casing integrity and is capable of return to long term injection. 4/8/2011 G -11 Pressure Observations 2500 ,; . 2500 • 2000 ours 2000 ubing ' S/8" 3 3/8" 1500 ate 1500 a 3 ++ F. 2 a ` 1000 1000 • 500 500 0 0 05/12/10 05/17/10 05/22/10 05/27/10 06/01/10 Time 06/06/10 06/11/10 06/16/10 06/21/10 06/26/10 Printed on 4/8/2011 at 3:19 PM G -11 Pressure Data 2010 06 14 BA (3) (3).xlsx g -11 Pressure Observations 2500 2500 • 2000 ours Men 2000 4 . 1 •"T •ing I■IP 5 • . 13 3 :' • 20" 1500 Rate 1500 a, z 4: cc 1000 • 1000 • 500 500 ■o 0 0 04/12/10 05/02/10 05/22/10 06Yql2f10 07/01/10 07/21/10 08/10/10 Printed on 4/8/2011 at 3:17 PM Pressure Data following restart (2).xlsm Page 1 of 3 • • Maunder, Thomas E (DOA) From: Greenstein, Larry P [Greensteinlp ©chevron.com] Sent: Thursday, June 17, 2010 5:06 PM To: Maunder, Thomas E (DOA) Cc: Agler, Brit G; Cole, David A; Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Performance anomaly Tom, Further update. The available replacement choke on the Grayling wouldn't work for this well, so they have one coming out from the valve shop. This means we won't have the new choke installed until at best this weekend and won't be bringing this well on until after then. Whenever it does happen, we will be taking hot sheet data to confirm the integrity of the well and will communicate the readings and results to you quickly. Larry From: Greenstein, Larry P Sent: Wednesday, June 16, 2010 5:16 PM To: Maunder, Thomas E (DOA) Cc: Agler, Brit G; Cole, David A; Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Performance anomaly Tom, Due to some choke problems that could be fixed as early as tomorrow, the G -11 well was not returned to injection today. We will try to get it going tomorrow and collect the data we need to prove up its integrity then. Thanks for the quick responses and hope to have some good news for you tomorrow. Automatic alarming for rate increases would be very difficult with our present system. We do have both rate and pressure guidance placards at each facility as well as thresholds built into the data entry screens to aid in the identification of potential integrity problems, but these are not automated systems. The flow transmitter was the culprit here, not the meter itself. It just got knocked out of calibration somehow and wasn't caught until we did some further investigating. This is not a common occurrence, so it caught us by surprise. Talk to you tomorrow. Larry From: a • - , N. • •I -s E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Wednesday, June 16, • I =. To: Greenstein, Larry P Cc: Agler, Brit G; Cole, David A; Lambert, Steve A 6/18/2010 • • From: Maunder, Thomas E (DOA) Sent: Wednesday, June 16, 2010 9:35 AM To: 'Greenstein, Larry P' Cc: Agler, Brit G; Cole, David.A, Lambert, Steve A Subject: RE: G-11 (PTD 168 -043) Performance anomaly Larry, et al, Troubleshooting the instrumentation was a good move. Based on this information, it is acceptable to bring the well back on to verify the flow rates. Please keep me informed. What is the PM interval on the flow meters? Is there a capability to have some sort of automatic alarm when "rates increase" so trouble shooting can be done? Thanks in advance, Tom Maunder, PE AOGCC From: Greenstein, Larry P [mailto:Greensteinlp @chevron.com] Sent: Wednesday, June 16, 2010 9:12 AM To: Maunder, Thomas E (DOA) Cc: Agler, Brit G; Cole, David A; Lambert, Steve A Subject: RE: G -11 (PTD 168 -043) Performance anomaly Tom, Here is the note from the guys on the Grayling. It appears, once again, what looks like a secondary failure is merely a false alarm explained by meter error (see below). We feel certain the well is still within the AA compliance guidelines of rates and pressures and did not have a rate increase while showing an injection pressure decrease. If you approve, we would like to bring this well back on injection for hopefully just a few hours to confirm the actual flow rates and pressures are consistent with previous levels and do not exhibit the rate increase shown on the previously sent plot. Larry From: Liebenthal, John W Sent: Wednesday, June 16, 2010 8:22 AM To: Agler, Brit G Cc: Waters, Brian; St John, Bob; Bartlett, Jeffery M; Simpson, Dan W; Owen, Claude D Subject: G -11 Brit, After Steve called the state and had us shut in G -11, we had our IT go down to verify the flow transmitter on G -11. He found that the zero had shifted so the transmitter was indicating approximately 1500 bbls /day high. This means that the well was actually flowing at a rate of 500 bbls /day and would account for the lower tubing psi and thus the anomaly that was reported to the state resulting in us shutting in the well. The transmitter has been recalibrated and will function properly now. We are sorry for the confusion and do have an explanation for the zero shift in the transmitter. Please advice on how to proceed. Jon Liebenthal Lead Operator Page 1 of 1 • Maunder, Thomas E (DOA) From: Lambert, Steve A [salambert @chevron.com] Sent: Tuesday, June 15, 2010 5:50 PM To: Maunder, Thomas E (DOA) Subject: RE: G -11 (PTD 168 -43) Performance anomaly Yes, we just became aware of the change in injection in well G - 11 today. Steve Lambert Senior Advising Petroleum Engineer Chevron North America Exploration and Production 3800 Center Point Suite 100 Tel 907 263 7658 salambert@chevron.com From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, June 15, 2010 4:34 PM To: Lambert, Steve A Cc: Greenstein, Larry P; Agler, Brit G; Cole, David A Subject: RE: G -11 (PTD 168-43) Performance anomaly Importance: High Steve, et al, Thanks for reporting the injection anomaly. Were you just notified of the pressure /rate change? This type of pressure /rate relationship would indicate that a flow resistance has been "removed" from the injection well system. It appears that the pressure has dropped —25% and the daily rate has increased nearly 50 %. Running a temperature survey as soon as possible is appropriate. However I do not believe it advisable to keep the well in service. The well should be safely shut in as required by Rule 5 of AIO 5.009 pending an analysis of the temperature survey. Call or message with any questions. Tom Maunder, PE AOGCC From: Lambert, Steve A [mailto:salambert@chevron.com] Sent: Tuesday, June 15, 2010 4:16 PM To: Maunder, Thomas E (DOA) Cc: Greenstein, Larry P; Agler, Brit G; Cole, David A Subject: G -11 (PTD 168 -43) Performance anomaly Tom, well G- 11(PTD 168 -43) is a Hemlock injector operating on the Grayling platform. The well developed tubing and casing communication and was granted administrative approval for continued injection in December 2005. Temperature surveys run in June 2007 and in July 2009 confirmed that all fluid was exiting the welibore at the perforations. Upon reviewing the well's performance today (see attached performance data), it appears that operating conditions have changed with increased injection and reduced injection pressures starting June 10 of this year. Due to the change in well performance, it is planned to activate a wireline crew as soon as possible to run a static temperature survey in this well. We expect to run the survey within the next 7 days. It is requested that we be allowed to continue injection until the temperature survey has been run in this well. Since the change in production characteristics has been apparent for only a short period of time, continued injection will improve our chances of seeing temperature anomalies on a temperature survey. I will be out of the office starting tomorrow, but Larry Greenstein and Brit Agler will continue to monitor this well's performance and will be available for consultation with you if needed. We will provide you with the temperature log data as soon as it is collected and we will shut -in the well if the temperature survey indicates an anomaly which would indicate fluid is leaving the welibore in any location other than the perforations. 6/16/2010 s • INJDATE HRS_ON TBGPRESS CSGPRESS2 CSGPRESS3 CSGPRESS5 MEASVOL 06/14/10 24 1550 1550 70 118 2032 507332011500 06/13/10 24 1550 1550 70 116 2046 507332011500 06/12/10 24 1550 1550 70 116 2069 507332011500 06/11/10 24 1700 1700 70 118 2302 507332011500 06/10/10 22 1700 1700 70 118 1817 507332011500 06/09/10 24 2000 2050 70 118 1583 507332011500 06/08/10 24 2000 2050 70 118 1587 507332011500 06/07/10 24 2000 2050 70 118 1583 507332011500 06/06/10 24 2000 2050 70 118 1583 507332011500 06/05/10 24 2000 2050 70 118 1553 507332011500 06/04/10 24 1950 2000 70 118 1535 507332011500 06/03/10 24 1950 2000 70 118 1484 507332011500 06/02/10 17 1950 2000 70 118 1002 507332011500 06/01/10 14 0 50 62 112 787 507332011500 05/31/10 24 2050 2100 70 112 1368 507332011500 05/30/10 24 2040 2050 70 123 1346 507332011500 05/29/10 24 2040 2050 70 123 1356 507332011500 05/28/10 24 2050 2060 70 123 1394 507332011500 05/27/10 24 2050 2060 70 123 1396 507332011500 05/26/10 24 2050 2060 70 123 1409 507332011500 05/25/10 24 2100 2100 64 121 1439 507332011500 05/24/10 24 2100 2100 64 121 1443 507332011500 05/23/10 24 2100 2100 64 121 1433 507332011500 05/22/10 24 2150 2150 66 118 1361 507332011500 05/21/10 15 2150 2150 66 118 971 507332011500 05/20/10 0 100 50 62 120 0 507332011500 05/19/10 0 100 50 62 120 0 507332011500 05/18/10 0 100 50 62 120 0 507332011500 05/17/10 11 100 50 62 120 719 507332011500 05/16/10 24 2050 2000 60 121 1565 507332011500 05/15/10 24 2050 2000 60 121 1534 507332011500 G -11 Pressure Observations 2500 . - 2500 '''"'" 4 1 2000 2000 -,rs `�1 • Tu • ng .95'" • 13 8" • 1500 Rat:- 1500 2 L 4) vi as ce a 1 .......... 1000 1000 500 500 0 0 05/12/10 05/17/10 05/22/10 05/27/10 Time 06/01/10 06/06/10 06/11/10 06/16/10 Printed on 6/15/2010 at 4:34 PM G -11 Pressure Data 2010 06 14.xlsx ~ ~ Page 1 of 1 Regg, James B (DOA) ~ ~~`~-~3 From: Regg, James B(DOA) 7~(~ I~~ Sent: Thursday, July 16, 2009 10:00 AM 1~1 To: Greenstein, Larry P Cc: Aubert, Winton G(DOA); Schwartz, Guy L(DOA) Subject: Mechanical Integrity Determinations - Grayling Wells During our phone conversation 7/15/2009, you requested clarification about timing of inechanical integrity determintations for several wells on TBU Grayling Platform. Temperature surveys for TBU G-29RD (PTD 192- 052; AIO 5.007) and G-11 (PTD 168-043; AIO 5.009) and were performed on 2/20/2009 and 7/8/2009 , respectively. You questioned if these temp surveys - performed up to 7 months early - can be used to satisfy the requirements of administrative approvals. Both surveys will be considered by the Commission as satisfying compliance with the administrative ap~rovals; please note that testing early will not reset the due date for temperature surveys; next temperature surveys will be due as follows: TBU G-11 due 12/15/2011 TBU G-29RD due 9/23/2011 You also mentioned that the standard MIT (pressure test) for TBU G-14ARD (PTD 191-099) was due April 6, 2009 but platform production and injection has been SI due to Redoubt volcano eruptions. Delaying the MIT until the G-14ARD was put back on injection was discussed and agreed to previously (refer to June 12, 2009 email). You indicated that Union is assessing restarting Grayling production and injection in August - please notify us when injection recommences and to arrange for a witnessed MIT. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 r..~''~:>~3YS::.~,% u ~~t _. ._ (-4JG~ 7/16/2009 • • Page 1 of 1 Regg, James B (DOA) I ~~- ~~ ~ ~ ;~ l ~Q _ pCf ~ From: Lambert, Steve A [salambert@chevron.com] Sent: Wednesday, July 15, 2009 2:58 PM To: Regg, James B (DOA) Cc: Greenstein, Larry P Subject: G-11 Temp Survey Attachments: 7-09 Temp Survey.zip Jim attached are the results of a temperature survey that was recently run on well G-11. We would like to request that the survey be used to fulfill the requirement to perform a temperature survey on the well prior to the 12/15/09 anniversary date of the Administrative Approval. The plot confirms that all fluid is being injected within the zones of interest. 7/16/2009 Chevron Well: G-11 Field: Grayling 07-08-2009 I Pressure (psia) 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 0 - Pressure-Temperature Profile ~ 1 . Going in hole { 1000 2. Shut-Ire 2000 - -- -- 3000 4000 - - ~w 5000 - - - -- C +s+ 6000 - Q O 7000 -- - 8000 -- 9000 ----- --- 10000 - - 11000 60 70 80 90 100 110 120 130 140 150 160 _ Temperature (Deg. F) 7-8-09 Pressure - Perfs 13-3/8 9-5/8 ~ 7 TBG 7-8-09 Temp 6-25-07 Temp Report date: 12/15/2009 Chevron Well: G-11 Field: Grayling 07-08-2009 Pressure (psia) 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 0 Pressure-Temperature Profile 1 Going in hole TVD 2. Well Shut-In 1000 - 2000 - - --- 3000 - - .-. 4000 - D ~ 5000 - H t ~ 6000 - - - 7000 ----- 8000 - 9000 -- - - - 10000 60 70 80 90 100 110 120 130 140 150 160 Temperature (Deg. F) 7-8-09 Pressure - Perfs 13-3/8 9-5/8 7 TBG 7-9-09 Temp 6-25-07 Temp Report date: 12/15/2009 ' STATE OF ALASKA '' `~"'° ~~'''' ~ " ALA OIL AND GAS CONSERVATION COM~ION ~;4,~~~ '~ 2008 REPORT OF SUNDRY WELL OPERATIONS AlBslc~ ~;~ ;:~~~: ~~ns. Commiss~pp 1. Operations Abandon Repair Well Plug Perforations Stimulate Ottyggj ~~~ Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Change Approved Program ^ Operat. Shutdown ^ Perforate ~ ~ Re-enter Suspended Well ^ 2. Operator Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number: Name: Development ^ Exploratory^ 68-43 - 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic^ Service 0- 6. API Number: 5c~ - 733 • Lo //S az~ 5 - . /, a 7. KB Elevation (ft): 9. Well Name and Number: RKB to tbg hanger 42.95' / RT 99' to MSL r G-11 8. Property Designation: ~ 0. Field/Pool(s): Grayling Platform/ ADL 17594 McArthur River/Hemlock 11. Present Well Condition Summary: Total Depth measured 10,835' feet Effective Depth Casing Structural Conductor Surface Intermediate Production Liner true vertical 9973' feet measured 10,453' feet true vertical 9519' feet Length Size 629' 16" 3081' 13-3/8" 10835' 9-518" i Pertoration depth: Measured depth: See Schematic True Vertical depth: MD 694' 3081' Plugs (measured) n/a Junk (measured) See Schematic TVD 694' 2934' Burst 2630 psi 3090 psi 5750 psi 10,835' 9869' ~v~ APR 1200$ Tubing: (size, grade, and measured depth) 3-1/2" N-80 10,210' Packers and SSSV (type and measured depth) Baker D Pkr 10,12T (DIL) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: n/a Representative Daily Average Production or injection Data Collapse 1020 psi 1540 psi 3090 psi - - Prior to well operation: 1395 1650 psi 1750 psi Subsequent to operation: 1351 1750 psi 1800 psi 14. Attachments: 15. Well Class after proposed work: :Copies of Logs and Surveys Run Exploratory^ Development ^ Service ~~ Daily Report of Well Operations X 16. Well Status after proposed work: Oil^ Gas ^ WAG ^ GINJ ^ WINJ Q' WDSPL ^ 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 Steve Tvler 263-7649 Printed Name Timothy C. Brandenburg ~, "' Signature "'~` Form 10-404 Title Drilling Manager Phone 907-276-7600 .f Date 3/20/2008 Ci Submit Original Only Chevron ~ Chevron -Alaska Daily Operations Summary Well Name G-11 Fleld Name MCARTHUR APUUWI 507332011500 Lease/Serial ADL0017594 Orig KB Elev (ftKB) Water Depth (ft) Primary Job Type Perforating Primary Wellbore Affected Main Hole Jobs AFE No: 'QC Eng R-8020-FJCP Daily Operations 3/10/2008 00:00 - 3/1 Ran GR and dummy guns and tag fill at 10,453' RKB (slm) 3/16/2008 00:00 - 3/17/2008 00:00 RIH and Perforate from 10,410'-10,430'; 10,398'-10.418' and 10,352'-10,372' with 2-1 /2" uNQ~`® ~ Trading Bay Unit • Well # G-11 Revised 3-18-08 rtKts to i esta nngr = a~.y~• Tree connection: 4-1/2" 8RD Top DV 412 Coll< cash 6761 SIZE WT CASING AND TUBING DETAIL GRADE CONK ID MD TOP J1D BTSI. 16" 75 J-55 Butt Surf. 694' 13-3/8" 61 J-55 Butt Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8 40 N-80 Seal Lock 8.835" 76' 4956' 9-5/8 43.5 N-80 Seal Lock 8.755" 4956' 7208' 9-5/8 47 N-80 Seal Lock 8.681" 7208' 8290' 9-5/8" 47 P-110 Seal Lock 8.681" 8290' 10833' 7" Scab 29" N-80 Butt 6.181" 6,640' 6,900' Tubing: 3-1/2" 9.3 N-80 Imp.Butt 2.992" 42.95 10,210' spc NO. Depth JEWELRY DETAIL TVD ID Item 42.95' Cameron 11" DC-FBB Tbg Hanger , 4-1/2"EUE Top x 4-112" Butt Btm. 1 10,125' 3.875" Baker Locator Type Seal Assy, w/ 15' of seals, 4- 3/4" X 2.992" 2 10,127' 4.750" Baker Model "D" Packer (DIL Depth) 3 10,175' 2.813" 3-1/2" "Y" Nipplc 4 10,210' 2.992" Baker Mule shoe Casing Scab: 5 6,640' 6.181" Baker 9-5/8" x 6" ID" FA packer 6,900' 6.181" Baker 9-5/8" z 6" ID FA packer Fish in Well Fish No. 1 Unknown length of wire and 1-11/16" X 13.3 long GR/CCL tool string at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel @ 10,655' 2.83' long, Max OD 5.5" (3/26/76) Fish No. 3 Mule shoe .72', Q nipple 1.7', cut 3-1/2" tubing 18.15' Left in hole (8/80) PERFORATION DATA Interval From To Last Date Remarks HB-1 10223' 10272' 3/84 4spf, 4spf, 4spf HB-2 10290' 10390' 3/08 4spf, 4spf, 4spf, 4spf, 4spf HB-3/4 10395' 10590' 7/68 4spf,4spf, 4spf HB-3 10396' 10436' 3/08 4spf, 4spf, 4spf HB-4 10460' 10520' 8/80 4spf, 4spf,4spf HB-4 10550' 10575' 8/80 4spf,4spf HB-5 10610' 10700' 7/68 4spf 1 2 -3 -5 REVISED: 3/18/08 DRAWN BY: NM TD =10,835' ETD =10,790' MAX HOLE ANGLE = 30.7° @ 5900' Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, December 26, 2007 5:23 PM To: 'Greenstein, Larry P' Cc: Maunder, Thomas E (DOA) • ~~ .~% ~--a ~' Subject: RE: Wefl with Questions on Determining the Anniversary Dates for Compliance Temp Surveys Larry -Each of the listed admin approvals did not establish a formal anniversary date for determining when to perform compliance temperature surveys. There has been same confusion that has resulted. Based on what I have read below and our conversation earlier today, I believe using the effective date (signature date) of the administrative approvals is consistent with your request far nearly all wells accomplishes what you are after (efficiency}. The wells you reference below are (with a due date for the next temp survey): Granite Pt State (Anna) 19 - AIO 6.008 {3!29/2005); next temp survey due 3/29/2009 Granite Pt State (Anna} 21 - AIO 6.009 (3/29/2005); next temp survey due 3/29/2009 TSU G-11 - AIO 5.049 (12115/05}; next temp survey due 12/15!2009 (you suggested 912009) TBU G-22 - AIO 5.006 (9114/2005); next temp survey due 9/14/2009 TBU G-23RD - AIO 5.004 {6/30/2005); next temp survey due 6/30/2009 (;you suggested 312009) TBU G-27 - AIO 5.003 (3/29/2005); next temp survey due 3/29/2009 TBU G-29RD - AIO 5.047 (9!2312005}; next temp survey due 9/23/2009 TBU G-40 - AIO 5.002 (3/29(2005}; next temp survey due 3!29/2009 TBU i<-11 - AIO 5.011 (2/6/06); next temp survey due 2!6!2010 TBU K-24RD2 - A10 5.010 (2/6/06); next temp survey due 2/612010 There is nothing preventing Chevron from testing earlier (as you have proposed for 2 of these weds). This does not affect any admin approvals that have anniversary dates specificaliy Fisted in the conditions. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Wednesday, December 26, 2007 10:45 AM To: Regg, James B (DOA) Subject: Well with Questions on Determining the Anniversary Dates for Compliance Temp Surveys Thanks for the conversation on this anniversary date topic Jim. It gets real confusing for me to keep the different basis for the anniversary dates separate for each well. The wells in question are: An-19 - AA signed 3!29105 - last compliance temp survey 1013/06. ~Nould Pike to slide 10108 temp survey to 3109 to get on AA anniversary date cycle. An-21 - AA signed 3!29105 -fast compliance temp survey 1014106. V1/ould ike to siide 10/08 temp survey to 3/09 for the AA date reason. i<-11 - AA signed 2(6;06 -last compliance temp survey 12;'11107 (lust seat to you). Would like to slide 12109 temp survey to 2110 for the AA date reason. 12/26/2007 K-24RD2 - AA signed 2x6/06 - last c ance temp survey 12i21f0! {will send to, soon). Would like to slide 12199 temp survey to 2/10 far the AA date reason. The Grayling wells have some other things going on. We have wells with AA anniversary dates in every quarter. !sure would like to get the number of logging visits down to just twice a year instead of four times a year. Maybe slide G-23RD forward from June to March and G-11 forward from December to September. This way only two wells get off the AA anniversary date cycle and we'll have three wells due for temp surveys each visit. G-11 - AA signed 12115/05 -fast compliance temp survey 6125107. Would like to slide to 6f09 temp survey to 09!99 for efficiency. G-22 - AA signed 9f14.f05 -last compliance temp survey 4f26I07. Would like to slide 4109 temp survey to 9f09 for the AA date reason. G-23RD - AA signed 6130f05 -last compliance temp Survey 4!19/07. Would like to slide 4109 temp survey to 3109 for efficiency. G-27 - AA signed 3129`05 -last compliance temp survey 9/21 /06, Would like to slide 9108 temp survey to 3109 for the AA date reason. G-29RL~ - AA signed 9;23/05 -last compliance temp survey 6f24t07. Mould like to slide 6;'09 temp survey to 9109 for AA date reason. G-40 - AA signed 3!29f05 -last compliance temp survey 9/21x'06. Would (ike to slide 9108 temp s:~~rvey to 3109 for AA date reason. I hope there aren't any more hiding out there. Surely next year I'I! find one or two, but for now this fist looks Pike aft of them. Thanks again for your consideration Jim. Call me if you want to discuss some more. Larry 263-7661 12/26/2007 ---, ~~~~~~~ l~~i/~~~~ 2-Year Temperature Survey Timing Requirements Granite Point Field and Trading Bay Unit Administrative Approvals for these wells did not include specific anniversary dates for determining when to perform compliance temperature surveys (alternate mechanical Background Info: integrity determinations in lieu of MITs). Clarification was requested by Chevron (L. Greenstein; 907-263-7661) on 12/26/2007. The following table summarizes admin approval info, anniversary date options, and the Commission's decision. Well PTD AA Anniversary Date AA Date Last Surve GP State An-19 168-006 6.008 3/29/2005 10/3/2006 GP State An-21 176-049 6.009 3!29/2005 10/4!2006 TBU G-11 168-043 5.009 12/15/2005 6/25/2007 TBU G-22 175-016 5.006 9!14!2005 4126!2007 TBU G-23RD 179-014 5.004 6/30/2005 4/19/2007 TBU G-27 178-070 5.003 3/29!2005 9/21/2006 TBU G-29RD 192-052 5.007 9/23/2005 6/24/2007 TBU G-40 190-003 5.002 3/29!2005 9/20/2006 TBU K-11 168-083 5.011 2/6/2006 12/11/2007 TBU K-24RD2 201-141 5.010 2/6/2006 12/21/2007 GP State An Granite Point Field, Anna Platform TBU G Trading Bay Unit, Grayling Platform TBU K Trading Bay Unit, King Salmon Platform AA Administrative Approval (AIO 5 and AIO 6, Rule 9) Options Next Tem Surve Due, Based on AA Date1 AA Date2 Last Survey 3/29/2007 3/29/2009 10/3/2008 3129!2007 3!29/2009 10!412008 12/15/2007 12/15/2009 6/25/2009 9!14/2007 9/14!2009 4/26/2009 6/30/2007 6/30/2009 4/19/2009 3/2912007 3/29/2009 9121 /2008 9/23/2007 9/23/2009 6/24/2009 3/29/2007 3/29/2009 9/20/2008 2/6/2008 2/6/2010 12/11/2009 2/6/2008 2/6/2010 12/21 /2009 last update: 12/26/2007 Next Survey Due (Chevron Proposed) Next Survey Due (AOGCC) Which Option? 3/29/2009 3/29!2009 AA Date 3/29/2009 3/29/2009 AA Date 9/30/2009 12/45/2009 AA Date 9/30/2009 9/1412009 AA Date 3/30/2009 6130/2009 AA Date 3/30/2009 3/29/2009 AA Date 9/30/2009 9/23/2009 AA Date 3/30/2009 3/29!2009 AA Date 2/28/2010 2/6!2010 AA Date 2/28!2010 2/6/2010 AA Date • • G-ll Compliance Temperature Survey . Page 1 of 1 . Maunder, Thomas E (DOA) From: Lambert, Steve A [salambert@chevron.com] Sent: Monday, July 02, 20074: 11 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Cc: Greenstein, Larry P Subject: G-11 Compliance Temperature Survey Attachments: 6-25-07 survey.zip G-11 Admin Approval Temperature Suvey \<o~-a~ S> Jim, Tom Well G-11 (PTD 168-043)was granted Administrative Approval (AIO 5.009) on December 15,2005. As required under the approval, a follow-up temperature survey was run on 6-25-07. The survey (see attached) is consistent with the survey run on 12-3-2005. The current survey confirms that all injected fluids are being contained within the zones of injection. Please contact me if you have any questions concerning the survey. «6-25-07 survey.zip» ~ JUL 0 t) 2007 7/2/2007 1000 2000 3000 o 4000 5000 6000 1000 8000 9000 10000 Pressure - Perfs Report date: 112/2001 J j - 1 _- _s FRAMK H. MURKOWSKi, GOVERNOR AD>yIINISTRATIVE APPROVAL AIO x.009 1.VIr. Steve Lambert Unocal Alaska P.O. Box 196247 Anchorage, AK 99519-6247 333 W. T" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ~~r~~ SAN a ~ 2008 RE: TBU G-1 1 (PTD 168-043) Request for Administrative ,Approval __..._,~,~ ~~~.,~. Dear i~1r. Lambert: Per Rule 9 of Area Injection Order ~, the Alaska Oil and Gas Conservation Commission ("AOGCC") hereby grants Unocal Alaska ("Unocal")'s December l I, 2005 request for administrative approval to inject water in Trading Bay Unit ('`TBU"} G-11. Unocal notified the Commission on October 4, 2005 that TBU G-1 1 exhibits tubing- casing pressure communication; the well w-as shut in at that time. Approval to continue injection for the purpose of performing well integrity diagnostics was granted by sundry number 305-321 on October 24, 2005. Unocal has elected to perform no corrective action at this time on TBU G-11. Temperature sur~~eys performed as part of the diagnostic testing confirm the injected fluids are exiting the well at the perforations. Accordingly, the Commission believes that the well's condition does not compromise overall well integrity so as to threaten the environment or human safety. The Commission's administrative approval to inject in TBU G-i 1 is conditioned upon the following: I . Injection is Limited to WATER O~+LY; 2. Unocal shall monitor and record tubing, inner annulus, and outer annulus pressures and injection rate daily; 3. Unocal shall submit to the Commission a monthly report of well pressures and injection rates; 4. Unocal shall perform a temperature surrey every 2 years in lieu of the mechanical integrity test as outlined in Rule ~ of AIO 5 to demonstrate continued production casing integrity: ti1r. Steve Rossberg December t ~, 2005 Page 2 of 2 ~. Unocal shall immediately shut in the well and notify- the Commission if there is any change in the well's mechanical condition; and 6. after well shut in due to a change in the well's mechanical condition, Commission approval shall be required to restart injection. As provided in AS 31.4.080, 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 rehearing. A request for rehearing is considered timely if it is received by 4:30 Piv1 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. e, Alaska and dated December 1 ~, 2005. l~n K. Chairman ~,.~ ~ Daniel T. Seamount, Jr Commissioner _~ ~ ®~ y~ ~ ;~ >~ , ~~ p 5. ,.- ~ `7s~i~ i%' ' t ~ / '~ ~ '. - - '. . .. ` .?4 ~> - - ~ ~F' ` ~~~ '`~ ~, ~ ,~~' ~~ ~F _~ Cathy oerster Com issioner (~", V~!ß:\ Tfi: r-r '\,' i: ,{¡II\ i,l, ¡ b W'\ if IiI', l' '~ . ' I ¡: ;:\ ::1 : ; '"",: \-.¿ U \\:d i ) rTIl' '~. ~. :t !;~ ~ ~1r:; Œ\"" ',,' "'¡~" i :, " " ,'\:~ I " '1 '\" '\:l U i, i ,,' .t, ' 'ß' , ; i ! ! : : / :1~ \ t l j ;Í~ ""<\ :!" ! ! " \. ! ' ! ¡ ¡ , , U \ : I ¡:WI \ '\.,,! ¡, :1 J ' \ . " ' I , , \ ' L l -;-,', !?-:' 1 : : '\ . \ 10 LJ ljlt~ [¡ \.h0 J ~ lru I / .I / FRANK H. MURKOWSK/, GOVERNOR A.I~A.S&A. OIL AND GAS CONSERVATION COMMISSION 333 W. pH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Steve Lambert Reservoir Engineer Union Oil Company of California P.O; Box 196247 Anchorage, AK 99519 \ iO~ -'Û¥ Re: Tyonek GjHemlock G-11 Sundry Number: 305-321 :ØNNED OC1 3 1 Z005 Dear Mr. Lambert: 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). 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 rehearing. A request for rehearing 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. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED ili.i4ay of October, 2005 Enc!. --- J)Ø .RECEIVE~ ) STATE OF ALASKA ) /b/2-4 /5 OCT 2 0 Z005 ,,' ALASKA OIL AND GAS CONSERVATION COMMISSION '~\9ð~ APPLICATION FOR SUNDRY APPROVALS Alaska Oil & Gas Cons. CommissÎon 20 AAC 25.280 Anchoraøe 1. Type of Request: Abandon U Suspend U Operational shutdown U Perforate U Waiver U Other U Alter casing D Repair well D Plug Perforations D Stimulate D Time Extension D Change approved program 0 Pull Tubing D Perforate New Pool D Re-enter Suspended Well D 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development D Exploratory D 68-43 3. Address: Stratigraphic D Service 0 6. API Number: P.O. Box 196247 Anchorage, Alaska 99519 7. KB Elevation (ft): 99' above MS L 8. Property Designation: 50-733-20115 9. Well Name and Number: G-11 10. Field/Pools(s): McArthur River Field, Tyonek G/Hemlock PRESENT WELL CONDITION SUMMARY 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Lambert 263-7658 Printed Name Steve ~bert Title Reservoir Engineer Signature ~ ,-^~~r--.. Phone ê.c..:'.t(.~A. Date COMMISSION USE ONLY D Mechanical Integrity Test D Location Clearance D -. \c M: "'::. \Iê:~~ ",. ÇI \a..~J0 , .\0\ \<:>"-.)\.J~ \<c: \'V.. \Xfu~~ '>\)"\ Q c.c""~\~~~ \o'i \~r\ 10 ç- " .. y \~8DMS BFL 0 Cï 2 5 2005 \- \-~\~ \.'\ ~~ Trading Bay Unit ADL 17594 11. Total Depth MD (ft): 10,835 Total Depth TVD (ft): 9,868 Effective Depth MD (ft): 1 0,493 Casing Length Structural 374' 26" Conductor 694' 16" Surface 3,081' 13 3/8" Intermediate 10,835' 95/8" Production 260' 7" Size 374' 694' 3,081' 1 0,835' 6,640-6,900' Liner Perforation Depth MD (ft): 10223-1 0272. 10290-10390, 1 0395-1 0590.1 0396-1 0436, 10460-10520. 10550-1 0575, 10610-10700 Perforation Depth TVD (ft): 9298-9341,9359-9450,9454- 9633, 9455-9504, 9525-9581 , 9608-9631,9651-9693 Tubing Size: Packers and SSSV Type: Baker model "0" perm packer 12. Attachments: Description Summary of Proposal ~ Detailed Operations Program D BOP Sketch 0 14. Estimated Date for Commencing Operations: Date: Conditions of approval: Notify Commission so that a representative may witness Plug Integrity D BOP Test Other: o.¿' ~ W C¡" \ l \-0 Effective Depth TVD (ft): 9,556 Junk (measured): 1 0,493 Collapse Plugs (measured): MD TVD Burst 374' 694' 2,929' 9,680' 6,086-6,314' 2,630 3,090 5,750 8,160 1,020 1,540 3,090 7,020 31/2 " Tubing Grade: 9.3# N-80 Tubing MD (ft): 10,210 Packers and SSSV MD (ft): Packer- 10,127' 13. Well Class after proposed work: Exploratory D Development D Service 0 15. Well Status after proposed work: Oil D Gas D Plugged D Abandoned D WAG D GINJ D WINJ 0 WDSPL D 10/18/2005 SUndryNUmber:~5 - 3bL\ \ N I'\tMISSIONER APPROVED BY THE COMMISSION Date: ~¿~ ) ') Chevron III Steve Lambert Reservoir Engineer Union Oil Company of California P,O. Box 196247 Anchorage, AK 99519-6247 Tel 907 263 7658 Fax 907 263 7847 Email salambert@chevron.com October 18, 2005 Tom Maunder Alaska Oil and Gas Conservation Commission 333 W 7th Ave # 100 Anchorage, Alaska 99501-3539 RETURN TO INJECTION GRAYLING PLATFORM WELL NO.11 MCARTHUR RIVER FIELD Dear Tom: Unocal is proposing to return well G-11 to injection. Enclosed is form 10-403. Well G-11 experienced pressure on the tubing casing annulus and was shut-in on October 2. The well is a critical component of the efforts to maintain productivity and improve recovery from the Hemlock reservoir. Following is the proposed procedure for bringing this well back on injection. 1) Obtain permission to inject. 2) Baseline temperature survey 3) Inject until the well has stabilized (approximately 1 month). 4) Follow-up temperature survey. 5) Obtain variance to inject. 6) Monitor well daily and repeat temperature surveys every two years. Please let me know if you require additional information. ~&\~ Steve Lam bert SAUjll Enclosure Union Oil Company of California I A Chevron Company http://www.chevron.com [Fwd: RE: G-Il tbg-csg communication] ) ) . ... .. . ... . . . Subject: [Fwd:RE:G~lltbg:-csg coinn1l.1J:l~catìQÍ1]' FrolÏl:' Tl1ort¡as .Ma~D.4er <tc)rri~m~lllldeF@a.<i11iìº. st~té·flk·us> Då~~7I~~~g49~t~005,l q:~g:~P~9:~.egi': i~~~:~~': ~,~~wªm~it:~tªt~)~~J -------- Original Message -------- Subject: RE: G-ll tbg-csg communication Date: Tue, 04 Oct 2005 10:16:29 -0800 From: G re en s t e in , Larry P 5:.9.E.~,~.:0.:.§..~.,~.~:.~..~.E~?~~!.~.S?s.:.9.:.~...:...S:..S?~.:?.: To: Thomas Maunder <torn maunder@admin.state.ak.us:> CC: Cole, David A <dcole@unocal. com:>, Dolan, Jeff J .:::..ª.S?~..9.:.~j.j,~~~~~g.~.?:,,~...:...s:..S?~.:?.:, L arnbe rt, Steve A < sa 1. artl:b·e·r.:'t:·Q~)l:ir):c)··ë:··ä:I"":"·Ò·ë)rÏl·;"''''' Here you go Tom. All looked well, until just recently. Larry «G-ll Pressure Observations 2005 10 03.xls» *From: * Lambert, Steve A *Sent: * Tuesday, October 04, 2005 9:45 AM *To: * Thomas Maunder *Cc: * Cole, David Ai Greenstein, Larry Pi Dolan, Jeff J *Subject: * G-ll tbg-csg communication Well G-ll csg pressure was observed at 2350 psi on Sunday October 2. The pressure was bled off to 800 psi and it pressured back up to 2350 psi. The tubing pressure was 3100 psi. The well was shut-in at 2:00 a.m. on Sunday morning. Larry Greenstein will supply you with the recent pressure history. Content-Type: application/vnd.ms-excel G-ll Pressure Observations 2005 10 03.xls Content-Encoding: base64 I of 1 10/24/2005 10:24 AM 7000 6000 5000 4000 3000 2000 1000 G-ll Pressure Observations 9 5/8 133/8 ') ) \~~'-OL\'~ HECHANICAL INTEGRITY REPORT' ....... ~?UD DA!::: - \ ----\ '\l- ~ OPER & FIELD ()riOC()., \...) w"'ELL NUHBER G - \ \ . :~ I G R E L E ;... S ::: # .:...:"':ìe'!': qS/~ ~~ TD: 'o~~~i-m.. 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C) "">~-«~ 0."> ~ ~ I Cement Bond Log (Yes or No) '(CéS. ; In AOGCC Fíle~o ß~l) ~~'> ~CL~,--,~~ " C\_ ' CBL :Ö:v2.luation, ~one above perfs -Ø'û~\ v-...c...~ \t+\r..Q.:. \>~~~\\-..'\ '-' .'0t.()... \ p ro.... ~ t'-':, '> '\cæ-~\f'<~' .~ I.)Q\ \\\-\ \ "> ~Ð ,....... ~ ~ '\ 1\..1.t...~ \ ).., . ,J ~ "\S150' Pro¿u~tion Log: Type ¡Evaluation ' . i I CONCLUSIONS: ' . ? ar t n : \J\ \\-ü..s ~£dc<VCrÇ,,~ , lC>v....)q-~( \\ -+ \A. Cl"\~ ((L~ 1t¡'1Î. ?ar:: ;2: \-\rì."':>,\,,~tC-~~ .. 'I n11ftd ~ .I<JJ-- ~lOf-r4.-o '\ Jih --;'7 rT--. w Retarder STRING Vol. of cement Type of cement Additive-- Date Run No. Depth - Driller ~ Depth - Logger '~Btm. Log Interval Top Log Interval Open Hole Size CASI NG REC. Surface String Proto String Prod. String Liner PRIMARY CEMENTING DATA Surface Protection Production N.H, Line c¡ ~¿¡ ~~ ~1-~1/ ON I;' JosiJ ~CJðO Not to i'~o¿;1 ..: It;' ð (/ Id4; Size Wt / Ft 7b" Permanent Datum: M $" ( Log Measured From ),(8. 9.f Drilling, Measured From )(8'. Ft. , Elev. 0 Above Perm. Datum z >- 0 ....10..- Z 0.... :::>'"t]<C:j O~UUJ u&1:9~ >- Z <C a.. ~ o u LOCATION API Serial No [»o/tl. Ð ci/ LEt; '~ ) BOJ-S I IV 4- / I{ S' ¿ / t1/ I.'J F ~ E. C!?,f. Sec. ~'1 Twp. 'IIV' Rge. /J¿¿/ Other Services: F/ELJ} l)fiII r ) t }J fJ JV )) }'(ì ¿/ Elev. ) YlN/O'N all CðMjlIJ/VY CIlLIPI/,f/l¡ II WELL 1/ff}/) IJV~ ¡¡flY 0'llìlç G- /1 FIELD-11 0 /I 1ft 1:1 tlR /(/L/¡Ç/? /' 'é'¿'UNTY )(F N ~ J STATE !I/ 115 J(¡g of ) Grade Type Drill Fluid Fluid Level Max. Rec. Temp. Est. Cement Top Equip. I Location Recorded By Witnessed By. I ype JOint ..)'tI')( r '\? J~? J¡ t·-/. 7 \.)PYMðu!l ~j{ U/1Jf;.)"p¡V - ~op B_~aom OF 7 ij i+- K.B.~. D.F._,_.. G. L._,_-;- ..: Q) E ~ :;) u Q) -£ >-. ..c ""0 Q) ...c .!!! E :;) ..... Q) ~ 3: o ã ""0 Q) u r::: ~ Q) ~ Q) o ...c Q) o ..c ""0 r::: o r::: .2 Õ u o Q)~ E o r::: Q) ~ Q) ...c f- . +- m c 0) 0 Q) O...J E ...J ~ -o-g c: 0 0) () 0 co -0 .~ ~ co +- -0 Q) 0.... V) +- c . 3 0.... 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Q) >->- .. c g>3; .- 0 0....-0 E ::> 0) 0...2 O)Q.. c: '- ..¡: 2 ::>....... ""0 0 -0 -0 Q.) Q) - - o 0 u u o 0 .... '- Q..Q.. 'ü 'ü Q) Q.) '- .... Q.) Q) Q..Q.. i:l:i:l: .... vi ..!2 ..!2 '- Q) NVI .:= ...c: 0- ,-Q.. +-Q.) ~o U ~~~~~~\h .::t... ,,~~ t".5 ~ ......... ~ "-" QQ ~~ ~ <i.. ~ ~,~ ~~~ ~ -...J~~ ~~ lI) ~ ~ ~~ <r,'. ~~\,,!) Q) . ~~ "vt) .... ó . 0 ó~v, ~ Z ~ z zoz~Z' .... .-. UJ Z t"?Io.. o· > >. >. ~ - Q.) ""'-- Z 0.. :E _:t:: a.. ~ t: -g :g _ Z Q) '-' .!:.~ ê S 0 0 0 ó 0 ~ t: .~ ã) 0 2 2 C o..uU?Zo.. 0 00 >0 c.E: UJ uuu Eo..u.... Q).- ._ ._ ._ - --I +- /" ceca" Q.) ,c ....o..u oooO:::<~~Q) 000:::0- V)U?U?U<vuU I-Uua::: 'I '_ E o '- ...... o ""0_ Q.) C () 0 0.- V) ~ 0)0 cU . õ) Q.) 0) E o .- ...J.... Q Z ot/) =!:; o (.0> z:3 V:;~ c:::t: '-' ,~ ...~ ~ t:>C't> E o Z o ... Z c:: 'Ë .... Q.) VI ..c ...c: u- +-0... OQ.) tio V) I I .Â . C) Z u <:( a.. >- t/) t:: V"\ z....... ~f1J ~ ....oJ QQ t/) « 0 - Z Q::: 0 ~ ~ t/) o a:: U ~ o I.() -~ 0"" I -~ ~ I '- -- """" .,. o o """" UI o o """" Ø) o o - t I - ,-- ~ ----- ,_ I -~ . _____-: --t ' f- . . - - - :-- ---1 -- : .j. ----~-- >- ~ MEMORANDUM TO: ) R.yq +/ 'Z1j¿>; Jim Regg P.I. Supervisor FROM: Lou Grimaldi Petroleum Inspector Well Name: TRADING BAY UNIT G-11 Insp Num: mitLG050407061939 Rei Insp Num: Packer State of Alaska Alaska Oil and Gas Conservation Comm; DATE: Thursday, April 07, 2005 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA G-Il TRADING BAY UNIT G-ll Src: Inspector NON-CONFIDENTIAL API Well Number: 50-733-20115-00-00 Permit Number: 168-043-0 r (' J,' 11' A# \\U~ Reviewed By: 'ÍJ7 t' ~ P.I. Suprv~ Comm Inspector Name: Lou Grimaldi Inspection Date: 4/6/2005 Well G-ll ¡Type Inj. S TVD 9217 IA 450 P.T. 1680430 TypeTest I SPT Test psi 2304.25 OA I 20 Interval 4YRTST P/F P Tubing 3400 Notes: Tested while onboard for SVS tests. IA checked for fluid to surfsce. Good test. Initial 15 Min. 30 Min. 45 Min. 60 Min. 2390 2390 2390 25 25 25 3400 3400 3400 Thursday, April 07, 2005 Depth Pretest SCANNEr) MAY :1 12005 Page 1 of 1 ) MEMORANDUM State of Alaska ') Alaska Oil and Gas Conservation Commission DATE: Thursday, December 02, 2004 SUBJECT: Mechanical Integrity Tests UNION OIL CO OF CALIFORNIA G-ll TRADING BAY UNIT G-ll TO: Jim Regg P.I. Supervisor FROM: Jeff Jones Petroleum Inspector Src: Inspector Well Name: TRADING BAY UNIT G-ll Insp Num: mitJJ041129161325 Rei Insp Num: NON-CONFIDENTIAL API Well Number: 50-733-20115-00-00 Permit Number: 168-043-0 \~tb<l1'¥'3 Reviewed By: .. I zl :~();f- P.I. Suprv!'TB~ . ì Comm Inspector Name: Jeff Jones Inspection Date: 11123/2004 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well G-ll Type Inj. S TVD 9266 IA 150 2400 2380 2380 P.T. 1680430 TypeTest SPT Test psi 2316.5 OA 5 10 10 10 Interval 4YRTST P/F P Tubing 3400 3400 3400 3400 Notes: Good test. Please cc test report to Larry P. Greenstein (Unocal) ~C'A~iNED DEG 1. 4 2004 ~...4 . .~~ Thursday, December 02, 2004 Page 1 of 1 STATE OF ALASKA ALASKA -AND GAS CONSERVATION ,JMMISSION REPORT OF SUNDRY WELL OPERATIONS 10peral~ons performed Operation shutdown Sl~mulate Plugging Perforate Pull tubing Alter camng Repa, r well X Other X (convert to water rejector) 2. Name of Operator 5 Type of Well 6 Datum elevabon (DF or KB) Umon Od Company of Cal,fom,a (UNOCAL) Development RT 99' to MSL feet 3 Address Exploratory 7 Umt or Property name Strabgraph~c P O Box 196247, Anchorage, Alaska Service X Trading Bay Umt 4 Local~on of well at surface Grayhng Leg 4 Conductor No 21 8 Well number 1688'FSL, 1390' FEL, Sec 29, T9N, R13W, SM TBUS G-11 At top of productive ~nterval 9 Permit number/approval number 1684', FEL, 2069' FNL, Sec 32, T9N, R13W, SM 68-43 At effectn/e depth 10 APl number 1745' FEL, 2295' FEL, Sec 32, T9N, R13W, SM 50-133-20115 At total depth 11 F~eld/Pool 1751' FEL, 2318' FNL, Sec 32, T9N, R13W, SM McArthur R~ver F~eld/Hernlock 12 Present well condition summary Total depth measured 10846' feet Plugs (measured) true vertical 9973' feetORIGINAL Effecbve depth measured 10,790' feet Junk (measured) 10,493' (w~rehne fish) true verbcal 9950' feet Casing Length S~ze Cemented Measured depth True verbcal depth Structural Conductor 629' 16" 1300 sx 694' 694' Surface 3081' 13-3/8" 2400 sx 3081' 2934' Intermediate Production 10835' 9-5/8" 2500 sx 10835' 9869' L~ner Perforabon depth measured See attachment true vertical Tubing (s~ze, grade, and measured depth) Single 3-1/2"9 3 Ib/ft L-80 IMP Butt at 10,210 Packers and SSSV (type and measured depth) Baker Model "D" packer set at 10,127' 13 Stimulation or cement squeeze summary ............ ,' ,-,,~. Anchorage Intervals treated (measured) Treatment descnpbon ~nclud~ng volumes used and final pressure 14 Representative Daily Average Production or Injecbon Data Od-BBL Gas-Mcr Water-Bbl Casing Pressure Tubing Pressure Pnor to well operation Idle Producer 500 ps~ 150 psi Subsequent to operation 10/29/2000 5,300 BPD 760 ps~ (Maintained) 1850 15 Attachments 16 Status of well classlficabon as Copies of Logs and Surveys run Da~ly Report of Well Operabons X Od Gas Suspended Service Water Injector 17 I hereby certify that the foregmng ~s true and correct to the best of my knowledge Slgned(~~ ~ ~ Title Drllhng Manager Date Form 10-404 Rev 06/15/88 SUBMIT IN DUPLICATE Grayling G-11 Workover Summary of Operations Well work was required on G-11 to convert this idle HK producer into an IlIK injector. The well was shut in 5/98 due to marginally economic production rates and multiple mechanical problems. The existing single completion was recovered after three fishing attempts. Following fishing runs seals were run and stabbed into the lowermost packer and the production casing above was pressure tested to the MIT test pressure of 2400 psi. A slickline nm indicated a need for clean-out below the packer and a mud motor was nm and the well was cleaned out to expose the Hemlock Bench 1 through 4. Upon pulling out of the hole with the mud motor assembly the defective tubing spool was changed out and tested. A 3- 1/2" injection string was nm into the well and landed. The annulus was pressure tested to 2400 psi to confirm well bore integrity and the BOP's were nippled down and the tree was installed. Subsequently a MIT was conducted (MIT form attached) on 27 October 2000 which indicated mechanical integrity and the well was placed on injection. A~aska Oil & Gas Cons. Commission Anchorage f Grayling G-11 Perforation Interval (Current 10-3-00) Interval (MD) Interval (TVD) Status Formation 10223-10272' 9310-9355' Open for Injection HB-1 10290-10390' 9371-9462' Open for Injection HB-2 10395-10590' 9467-9645' Open for Injection HB-3/4 10610-10700' 9663-9745' Covered with Fill HB-5 Oil & Gas Cons. Commission Grayling G-11 Workover Daily Operations Summary 9-22-00 Oil & Gas Cons. Commission Commence operations at 12:00 hrs 22 September 2000. Skid to G-11 well slot. Commence rig up. 9-23-00 Bullhead tubing with 3% KCL/FIW. Fill tubing annulus with 3% KCL/FIW. RU APRS for tubing punch. 9-24-00 Perform tubing punch at 9088-9090'. Circulate well. Install BPV and ND trbe. NU BOP's 9-25-00 NU and test BOP's. Pull tubing free and POOH. Found tubing parted at 8940'. 9-26-00 RIH picking up 3-1/2" drill pipe. Engage fish with rolling dog overshot. POOH 9-27-00 POOH with single 3-1/2" tubing coupling. RIH with overshot and and engage fish. POOH laying down tubing fish. MU 4-3/4" seal assembly and RIH 9-28-00 Continue RIH with 4-3/4" seal assembly. Sting into packer at 10,127' Pressure test casing to 2400 psi- OK. RIH with tubing end locator and establish depth of fill below packer. 10,160' WLM. RD slickline and POOH with seal assembly 9-29-00 Make up mud motor assembly and RIH. Clean out fill to 10,500'. Circulate out 5 bbls sand/scale. POOH and PU storm packer. 9-30-00 Pull storm packer and finish LDDP. Run 4-3/4" tubing seals and completion tubing. 10-1-00 Stab seals into packer, test annulus to 2400 psi. PU and pump corrosion inhibitor in annulus. Space out and land hanger with 17K down. Pressure test annulus to 2400 psi. ND BOP. 10-2-00 Install and test tree. Commence RD operations. UNOCAL Trading Bay Unit Well # G-11 As Built 9-30-00 RKB to TBG Hngr = 42.95' Tree connection: 4-112" 8RD Top 1 ~llarat MD · II ,sed ~ at 5 2 \ 4 __ I Top offill 10,500' i _~ I- CTM 9/29/00 F .. ~F DV 412~ Colla casing 67{ HB-1 HB-2 HB-3 HB-4 HB-5 'I'D -- 10,835' £TD" 10,790' MAX HOLE ANGLE = 30.7° @ 5900' SIZE WY CASING AND TUBING DETAIL GRADE CONN ID MD TOP MD BTM. 16" 75 J-55 Butt Surf. 13-3/8' 61 J-55 Butt Surf 9-5/8' 47 N-80 Seal Lock 8.681" Surf 9-5/8 40 N-80 Seal Lock 8.835" 76' 9-5/8 43.5 N-80 Seal Lock 8.755" 4956' 9-5/8 47 N-80 Seal Lock 8.681" 7208' 9-5/8" 47 P-110 Seal Lock 8.681" 8290' 7" Scab 29" N-80 Butt 6.181" 6,640' Tubing: 3-1/2" 9.3 N-80 Imp. Butt 2.992" 42.95 spc 694' 3,081 ' 76' 4956' 7208' 8290' 10833' 6,900' 10,210' JEWELRY DETAIL NO. Depth TVD ID Item 42.95' 1 10,125' 3.875" 2 10,127' 4.750" 3 10,175' 2.813" 4 10,210' 2.992" Casing Scab: 5 6,640' 6.181" 6,900' 6.181" Cameron 11" DC-FBB Tbg Hanger, 4-1/2"EUE Top x 4-1/2" Butt Btm. Baker Locator Type Seal Assy, w/15' of seals, 4-3/4" X 2.992" Baker Model "D" Packer (])IL Depth) 3-1/2" "X" Nipple Baker Mule shoe Baker 9-5/8" x 6" ID" FA packer Baker 9-5/8" x 6" ID FA packer Fish in Well Fish No. 1 Unknown length ofw~re and 1-11/16" X 13 3 long GR/CCL tool stnng at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel ~10,655' 2 83' long, Max OD 5 5" (3/26/76) Fish No. 3 Mule shoe 72', Q topple 1 7', cut 3-1/2" tubing 18 15' Left m hole (8/80) PERFORATION DATA Interval From To Last Date HB-1 10223' 10272' 3/84 HB-2 10290' 10390' 3/84 HB-3/4 10395' 10590' 7/68 HB-3 10396' 10436' 8/80 HB-4 10460' 10520' 8/80 HB-4 10550' 10575' 8/80 HB-5 10610' 10700' 7/68 Remarks 4spf, 4spf, 4spf 4spf, 4spf, 4spf, 4spf 4spf,4spf, 4spf 4spf, 4spf 4spf, 4spf,4spf 4sp£,4spf 4spf REVISED. 10/2/00 DRAWN BY: NM STATE OF ALASKA L AND GAS CONSERVATION COMMIS~ FIELD IuNrtr I PAD:. ~..R¢~/?~~~ .~......~ DATE: ........ / ,,E¢.'7,~ r, G-lf .~:~MMENT8: ~QMMENT$: ~OMM~NTS: TUBING iNJECTI~ON FLUID: ~ = PRODUCED WATER INJ :~ -'* ~AL7~ WATER tNJ ~= Mt~CtBLE ~NJ - ]NgECT~ON ~f '- NOT !NJ~-CTING ANNULAR F:LU1D,* P,.P,G, G:ra~. 'VtCELL TEST: SALT WATER ..I. E,~' Werkover ....................... DRfLUNG MUD AOGCC REP SIGNATURE . '. OPERATOR REP ,~GNATU~ AgAa Oil & 6as Cons. Commission Anchorage (~ ~°v Oil & Gas Cons. Commi~on An~or~e Unocal Corporation 909 W. 9th Avenue Anchorage, AK 99501 907-263-7660 UNOCAL ) Dan Williamson Dnlhng Manager Thursday, September 21, 2000 Mr. Dan Seamount Commissioner Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, Ak 99501-3192 Dear Mr. Seamount: This letter is formally advise you of our contingency plan for the upcoming Grayling G-11 workover. The original 403 submitted and approved 14 September called for this idle producer to converted into an injector. Thers is a possibility due to the uncertainty of the production casing integrity in this well that we may alter our work plan and convert this well into a gas producer in the shallower D3A and C1 sands sequences. Further to verbal discussions between Neil Magee (Unocal Drilling Engineer) and Blair Wondzell concerning this possibility, we have provided a 403 to cover this contingency. UNOCAL plans to commence this well work 24 September. Please contact the undersigned with any questions regarding this application. Sincerely, Don Byrne Acting Drilling Manager enclosure RECEIVED SEP ? 1 2000 & ,gas Cons. g;0mmisslo~ AlaskeO~:; *" "' ' ' Anchorage STATE OF ALASKA ( ALASKA L AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1 Type of Request Abandon X Suspend Operabon shutdown Re-enter suspended well' Alter casing. Repar well Plugging T~me extensmn: Sbmulate Change approved program Pull tubing Vanance Perforate Other X 2 Name of Operator 5 Type of well' 6 Datum elevation (DF or KB) Umon Oil Company of Cahfoma (UNOCAL) Development X RT 99' above MSL feet 3 Address Exploratory 7 Umt or Property name Strabgraphm Trading Bay Umt P O Box 196247 Anchorage, Alaska 99519-6247 Service 4 Local]on of well at surface Grayhng Leg 4, Conductor No 21 8 Well number 1688' FSL, 1390' FEL, Sec 29, TDN, R13W, S M G-11 At top of producbve ~nterval 9 Permit number 1684' FEL, 2069' FNL, Sec 32, TDN, R13W S M 68-43 At effecbve depth 10 APl number 1745' FEL, 2295' FNL, Sec 32, TDN, R13W, S M 50-133-20115 At total depth 11 F~eld/Pool 1751' FEL, 2318' FNL, Sec 32, TDN, R13W S M McArthur R~ver F~eld/Hemlock 12 Present well cond~bon summary Total depth, measured 10846' feet Plugs (measured) true verbcal 9873' feet Effective depth, measured 10790' feet Junk(measured) 10493' (w,rehne fish)ORIGINAL true vertical 9950 feet Casing Length S~ze Cemented Measured depth True vertical depth Structural Conductor 694' 16" 1300 sx 629' 629' Surface 3081' 13-3/8" 2400 sx 3081' 2934' Intermediate Producbon 10835' 9-5/8" 2500 sx 10835' 9869' L~ner Perforatmn depth measured (See attachment) true verticalRECEIVED Tub,ng(s,ze, grade, and measured depth) 3-1/2"921b/ftN-S0at6471-10178',4-1/2"1261b/ftN-80at 38'-6471' SEP 71 ; 000 Packers and SSSV (type and measured depth) Baker Model D at 10127', Ohs SCSSSV at 227' Alaska OJ; & Gas Cons. C0mmis,, 13 Attachments Descnpt~on summary of proposal X Detaded operabons program BOP sketch X 14 Esbmated date for commencing operabon 15 Status of well class~flcabon as 9/25/2OOO 16 If proposal well verbally approved Od Gas Suspended Name of approver Date approved Service Convert to GGS Gas Well (Conbngency) 17 I hereby c_.,e.~fy that the forego,l~g ~s true and correct to the best of my kn. owledge ~,gne(~. ~~:3,~.~ T,tle gr, lhng Manager Date ~ I ~ FOR COMMISSION USE ONLY Cond,t, ons of approval Not,fy Comm,ss,on so representat, ve may w,tness - "-"" IAppro~ Plug ~ntegnty. ~" BOP Test v" Locabon clearance '" Mechanical Integnty Test Subsequent form required 10- ~.~'~ ORIGINAL SIGNED, ~¥ D Taylor Seamount Approved by order of the Comm,ss,oner Comm,ss,oner Date Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE Grayling G-11 Summary of Work Program (Contingency) The Grayling G-11 workover is proposed in order to convert a shut in producer to an injector. Grayling G-11 has a tubing fish consisting of a 18' strip gun which has eluded recover by slickline/braided line attempts. Subsequently the well has been shut in pending a workover. The proposed workover is to recover the existing tubing string. Verify the pressure integrity of the 9-5/8" production casing and 7" casing patch, attempt to clean out fill below the lowermost packer and re-complete the well as an injector in the existing Hemlock formation. In short the workover will entail the following steps: · Remove all the existing tubing in the well and uppermost packer. · Conduct a casing integrity investigation with a RTTS test packer If the test indicates significant casing damage exists above the lowermost packer but below the scab 7" liner the following contingency plan will be in effect in order to convert this well into a gas completion in the Grayling C-1 and D-3a sand sequences: · RIH and sting into lowermost packer and pump approximately 45 bbls of cement to abandon the Hemlock perforations in the well. · Set a 9-5/8" bridge plug above the upper scab liner at approximately 6600'. · Run a 2-7/8" gas completion and complete the well in C-1 and D-3A Grayling sand sequences RECEIVED SEP ? 1 2000 Alaska Oi.i & Gas Cons. ~mm~ss~on An~omge ' UNOCJLLe RKB to TBG Hngr = 38.00' Tree connection: 4-1/2" 8RD Top 1 41ar~t ~4D · · ----~c Collapsed ~ casing at 6767'MD DV coil; 412l 2 ;-1 ~-3,~ 5 4 2 HB-1 HB-2 HB-3 HB-4 HB-5 TD = 10,835' ETD = 10,790' G- 11~~ ~Ee_-l~.°~c@ $900, Trading Bay Unit Well # G-Il Proposed Gas Well SIZE WT CASING AND TUBING DETAIL GRADE CONN ID MD TOP MD BTM. 16" 75 J-55 Butt Surf. 13-3/8" 61 J-55 Butt Surf 9-5/8" 47 N-80 Seal Lock 8.681" Surf 9-5/8 40 N-80 Seal Lock 8.835" 76' 9-5/8 43.5 N-80 Seal Lock 8.755" 4956' 9-5/8 47 N-80 Seal Lock 8.681" 7208' 9-5/8' 47 P-110 Seal Lock 8.681" 8290' 7" Scab 29" N-80 Butt 6.181" 6,640' Tubing: 3-1/2" 9.3 N-80 Imp. Butt 2.992" 36 694' 3,081' 76' 4956' 7208' 8290' 10833' 6,900' 10,196' JEWELRY DETAIL NO. Depth ID Item 36' I 300' 2 4130' 3.875" 3 4200 2.813" 4 10,127' 4.750" 5 10,166' 2.813" 4 10,196' 2.992" Casing Scab: 5 6,640' 6.181" 6,900' 6.181" Cameron 11' DC-FBB Tbg Hanger, 4-1/2"EUE Top x 4-1/2" Butt Btm. SSSV Baker K-22 Anchor Type Seal Assy, w/1' and Baker permanent packer 3-1/2" "X' nipple Baker Model "D" Packer (DIL Depth) Baker Mule shoe Baker 9-5/8" x 6" ID" FA packer Baker 9-5/8" x 6" ID FA packer Fish in Well Fish No. 1 Approximately 10' of w~re and 1-11/16" X 13 3 long GR/CCL tool stnng at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel ~10,655' 2 83' long, Max OD 5 5" (3/26/76) PERFORATION DATA Interval From To Last Date Remarks HB-1 10223' 10272' 3/84 Abandoned HB-1 10230' 10260' 3/84 Abandoned HB-2 10290' 10390' 3/84 Abandoned HB-3 10395' 10590' 7/68 Abandoned HB-3 10396' 10436' 8/80 Abandoned HB-4 10460' 10520' 8/80 Abandoned HB-4 10540' 10575' 8/80 Abandoned HB-5 10610' 10700' 7/68 Abandoned REVISED: 9/21/00 DRAWN BY: NM Grayling G-11 Perforation Interval (Current 8-31-00) Interval (MD) Interval (TVD) Status Formation 10223-10272' 9310-9355' Open for Production HB-1 10290-10390' 9371-9462' Open for Production HB-2 10395-10590' 9467-9645' Open for Production HB-3/4 10610-10700' 9663-9745' Open for Production HB-5 Grayling G-11 BHP and Proposed Workover Fluid Static BHP Static BHP Hemlock: 4039 psi at 9400 TVD Proposed Workover Fluid Maximum Pressure Gradient: Workover Fluid: .42 psi/ti (Hemlock Bench 2) .45 psi/ii (Formation Inlet Water + 3% KCL) Overbalance Workover Fluid - BHP Hemlock 4252 psi- 4039 psi = 252 psi · ! .( "- '~ FLOWL[NE · · · ' r_..j I n _I · ~- ~u,~:,: ·~ ' r~,~ , ~~ 4- ~u v~.v~ · . i: ~, , · ... ' ,. ",,, i~ ' ,~ q~"'. 'i · ' : 13-5/8" 5~ ~~E · PIPE RAMS' · iiii ~NGLE ¢.,k~ 5M ' 13-5/8" 5U' FLANGE: C~EEON 5U SPOt., RECEIVED · · SEP 06 2:00'0 Na~ka O~ & Gas Cons. Comm~ ~P~3= 13-5/8" BOPE 5U SI'ACK ' GRAYLIN(] PLATFORM · · 4~ .( . i. · 1/16" · · · i BBLS · · MlXlN~ Prr 40 BELLS .' SEP 06 2000' .~, · 185 EIi~LS VOLUME PIT 1B5 BBES SUCTION i · · 125BBL$ '..67 BELLS' -,250 BElL ' S~J(ER SHN(ER · · · · · · · · · · · · RESERVE PIT ~75 BBLS . '- TItE 5'Y~E:M WILL DE EQUIPPED WITH A Dfl~LINO PIT LEVEL. INDIP*.,kTOR WITH AUDIO.ac Vj~iUAL WARNING DEVICES. · · ' · · · i ii ! i i _ 11 ii ii _ · , , ,, ,, , EQUIPMENT LIST 11 R£SERVE PIT DEO,~SSER · .3) (~) SH~K~s 4) Pm LEVEL, JNm~TO~ · (VlSUN. ~ AUDIO), 5 ~UID ~~ S~SOR ~ TANK : " Pff AG~ATORS : DES~TER CE~~UgE . lO) MIXING. P~ e UNOCAL ~RAYI.JNO MUD PIT SCH£MATI[ DRAWN f~f'r DAI3 APP~Df d~S~ DAT£1 11--30--/19 STATE OF ALASKA ALASKA Of L AND GAS CONSERVATION (f.,OMMISSION APPLICATION FOR SUNDRY APPROVALS 1 Type of Request Abandon Suspend Operabon shutdown Re-enter suspended well Alter cas,ng. Repair well: X Plugging T~me extensmn Sbmulate Change approved program Pull tubing Vanance Perforate Other X 2 Name of Operator 5 Type of well' 6 Datum elevation (DF or KB) Union Od Company of Callfoma (UNOCAL) Development ~ RT 99' above MSL feet 3 Address Exploratory 7 Unit or Property name Strabgraph~c iTrading Bay Unit P O Box 196247 Anchorage, Alaska 99519-6247 Service ~ 4 Localmn of well at surface Grayhng Leg 4, Conductor No 21 8. Well number 1688' FSL, 1390' FEL, Sec 29, T9N, R13W, S M G-11 At top of producbve interval 9 Permit number 1684' FEL, 2069' FNL, Sec 32, T9N, R13W S M 68-43 At effective depth 10 APl number 1745' FEL, 2295' FNL, Sec 32, T9N, R13W, S M ORIGINAL 50-133-20115 At total depth 11 F~eld/Pool 1751' FEL, 2318' FNL, Sec 32, T9N, R13W S M McArthur R~ver F~eld/Hemlock 12 Present well cond~l]on summary Total depth measured 10846' feet Plugs (measured) true vertical 9873' feet Effecbve depth measured 10790' feet Junk (measured) 10493' (w~rehne fish) true vertical 9950 feet Ah;~4,'-';,'" .... , '""* ' Casing Length Size Cemented Measured depth True~;~lOc~epth Structural Conductor 694' 16" 1300 sx 629' 629' Surface 3081' 13-3/8" 2400 sx 3081' 2934' Intermediate Production 10835' 9-5/8" 2500 sx 10835' 9869' L~ner Perforation depth measured (See attachment) true vertical Tubing (s~ze, grade, and measured depth) 3-1/2" 9 2 Ib/ft N-80 at 6471- 10178', 4-1/2" 12 6 Ib/ft N-80 at 38' - 6471' Packers and SSSV (type and measured depth) Baker Model D at 10127', Otto SCSSSV at 227' 13 Attachments Descnpbon summary of proposal X Detailed operations program BOP sketch X 14 Estimated date for commencing operabon 15 ~classlficabon ae* ~ ~ 9/15/2000 16 If proposal well verbally approved Od Gas Suspended' Name of approver Date approved Service Convert to Water Injector 17 I hereby~eu-~ ¥ that the for_ego~Gg ~s true and correct to the best of my knowledge Signed ~ ?~~~' Title Drllhng Manager Date FOR COMMISSION USE ONLY Conditions of approval Notify Commission so representative may witnessI ~)~)lApprOval No O Plug ,ntegr, ty BOP Test ~ Locat, on clearance . Mechamcal Integrity Test /-"' Subsequent form required 10- ORIGINAL SIGNED BYD Taylor Seamount C-- Approved by order of the Commissioner Commissioner Date / Form 10-403 Rev 06/15/88 SUBMIT IN TRIPLICATE Grayling G-11 Summary of Work Program The Grayhng G-11 workover is proposed in order to convert a shut in producer to an injector. Grayhng G-11 has a tubing fish consisting of a 18' strip gun which has eluded recover by shckhne/braided line attempts. Subsequently the well has been shut in pending a workover. The proposed workover is to recover the existing tubing string. Verify the pressure integrity of the 9-5/8" production casing and 7" casing patch, attempt to clean out fill below the lowermost packer and re-complete the well as an injector in the existing Hemlock formation. In short the workover will entail the following steps: · Remove all the existing tubing in the well and uppermost packer. · Conduct a casing integrity investigation with a RTTS test packer. · Attempt to clean out the well past the fish obstructing access to the lower portion of Hemlock Bench 4 and all of Hemlock Bench 5. · Re-complete the well as a Hemlock injector. · Carry out a MIT test to demonstrate the tubing/packer integrity. Grayling G-11 Perforation Interval (Current 8-31-00) Interval (MD) Interval (TVD) Status Formation 10223-10272' 9310-9355' Open for Production HB-1 10290-10390' 9371-9462' Open for Production HB-2 10395-10590' 9467-9645' Open for Production HB-3/4 10610-10700' 9663-9745' Open for Production HB-5 UNOCAL RKB to TBG Hngr = 38.00' Tree connection: 4-112" 8RD Top 1 )liar ~t MD I I-.3 · 2 sea ~ / 3 ~D i 4 21' 5 -:---Iq lop o~fill 10,510' --" -= H 7/27187 =1~ ~~= I~ .... .. DV, 41: Colla casin 6767'MD 11 HB-1 HB-2 HB-3 HB-4 HB-5 TD -- 10,835' ETD = 10,790' MAX HOLE ANGLE = 30.7° @ 5900' G-11 Drawing Current.doc Trading Bay Unit Well # G-Il Current Status 8-23-00 SIZE CASING AND TUBING DETAIL GRADE CONN ID MD TOP 16,, 75 13-3/8'' 61 9-5/8'' 47 9-5/8 40 9-5/8 43.5 9-5/8 47 9-5/8'' 47 7" Scab 29" Tubing: 4-1/2,, 12.6 3-1/2" 9.2 J-55 Butt Surf. 694' J-55 Butt Surf 3,081' N-80 Seal Lock 8.681'' Surf 76' N-80 Seal Lock 76' 4956' N-80 Seal lock 4956' 7208' N-80 Seal lock 7208' 8290' P-110 Seal Lock 8290' 10833' N-80 Butt 6.181'' 6,640' 6,900' N-80 Butt 36 6471' N-80 Butt 2.992 6471' 10,178' NO. Depth TVD 36.00' 1 227' 2 Camco KBUG (1-8) Gas #1 1887' 02 3750' 03 545' ' 04 6432' 05 7457' 06 8059' #7 8397' #8 8734' #9 9065' 010 9402' #11 9,439' 012 9988' 3 6471' 4 10,059' 5 10,125' 6 10,127' 7 10,176' 8 10,178 Casing Patch 9 6,640' 6,900' JEWELRY DETAIL ID Item Cameron 11,, DC-FBB Tbg Hanger, 4-1/2'EUE Top x Butt Btm. 2.75 Otis SCSSV Ball Valve Lift Mandrels 2.75 3.00 4.75 2.625 2.992 4-1/2'' GLM 4-1/2,, GLM 4-1/2" GLM 4-1/2'' GLM 3-1/2' GLM 3-1/2" GLM 3-1/2" GLM 3-1/2' GLM 3-1/2" GLM 3-1/2" GLM 3-1/2" GLM 3-1/2' GLM X-over 3-1/2' Butt Box x 4-1/2" Butt Pin 3-1/2" Otis "XA' Sliding Sleeve Locator Seal Assy, w/20.3' of seals, 4-3/4" X 3.00,, Baker Model "D' Packer 3-1/2" "Q' Nipple Baker Mule shoe Baker 9-5/8" x 6" ID" FA packer Baker 9-5/8" x 6,, ID FA packer Fish in Well Fish No. 1 18' 2-1/8" stop gun at 9128' (9/18/88) Fish No. 2 Unknown length ofw~re and 1-11/16" X 13 3 long GR/CCL tool stnng at 10,493'(9/19/88) Fish No. 3 Bottom sect]on of CX Mandrel ~10,655' 2 83' long, Max OD 5 5" (3/26/76) PERFORATION DATA Interval From To Last Date Remarks HB-1 10223' 10272' 3/84 4spf, 4spf, 4spf HB-1 10230' 10260' 3/84 4spf, 4spf, 4spf, 4spf HB-2 10290' 10390' 3/84 4spf, 4spf, 4spf, 4spf HB-3 10395' 10590' 7/68 4spf,4spf, 4spf HB-3 10396' 10436' 8/80 4spf, 4spf HB-4 10460' 10520' 8/80 4spf, 4spf,4spf HB-4 10540' 10575' 8/80 4spf,4spf HB-5 10610' 10700' 7/68 4spf REVISED: 8/22/00 DRAWN BY: NM UNOCAL ) RKB to TBG Hngr = 38 00' Tree connection 4-1/2" 8RD Top DV collar 4128'MD Collapsed casing at 6767'MD = HB-1 -- [ HB-2 ---= HB-3 = HB-4 :- HB-5 TD = 10,835' ETD = 10,790' Trading Bay Unit ( Well # G-Il Proposed CASING AND TUBING DETAIL SIZE WT GRADE CONN ID MD TOP MD BTM. 16" 75 J-55 Butt Surf. 694' 13-3/8" 61 J-55 Butt Surf 3,081' 9-5/8" 47 N-80 Seal Lock 8.681" Surf 76' 9-5/8 40 N-80 Seal Lock 76' 4956' 9-5/8 43.5 N-80 Seal lock 4956' 7208' 9-5/8 47 N-80 Seal lock 7208' 8290' 9-5/8" 47 P-I 10 Seal Lock 8290' 10833' 7" Scab 29" N-80 Butt 6.181" 6,640' 6,900' Tubing: 3-1/2" 9.3 N-80 Imp. Butt 2.992" 36 10,178' JEWELRY DETAIL NO. Depth TVD ID Item -- 36.00' 1 10,125' 3.875" 2 ! 0,127' 4.750" 3 10,176' 2.813" 4 10,178' 2.992" Casing Scab: 5 6,640' 6.181" 6,900' 6.181" Cameron 11" DC-FBB Tbg Hanger, 4-1/2"EUE Top x 3-1/2" Butt Btm. Locator Seal Assy, w/20.3' of seals, 4-3/4" X 3.00" Baker Model "D' Packer (DIL Depth) 3-1/2" "X' Nipple Baker Mule shoe Baker 9-5/8' x 6" ID" FA packer Baker 9-5/8" x 6" ID FA packer Fish in Well Fish No. 1 Unknown length ofw~rc and 1-11/16" X 13 3 long GR/CCL tool stnng at 10,493'(9/19/88) Fish No. 2 Bottom section of CX Mandrel ~10,655' 2 83' long, Max OD 5 5" (3/26/76) PERFORATION DATA Interval From To Last Date HB-1 10223' 10272' 3/84 HB-1 10230' 10260' 3/84 HB-2 10290' 10390' 3/84 HB-3 10395' 10590' 7/68 HB-3 10396' 10436' 8/80 HB-4 10460' 10520' 8/80 HB-4 10540' 10575' 8/80 HB-5 10610' 10700' 7/68 Remarks 4spf, 4spf, 4spf 4spf, 4spf, 4spf, 4spf 4spf, 4spf, 4spf, 4spf 4spf,4spf, 4spf 4spf, 4spf 4spf, 4spf,4spf 4spf,4spf 4spf REVISED: 9/1/00 DRAWN BY: NM ( Grayling G-11 BHP and Proposed Workover Fluid Static BHP Static BHP Hemlock: 4039 psi at 9400 TVD Proposed Workover Fluid Maximum Pressure Gradient: Workover Fluid: .42 psi/t~ (Hemlock Bench 2) .45 psi/t~ (Formation Inlet Water + 3% KCL) Overbalance Workover Fluid - BHP Hemlock 4252 psi- 4039 psi = 252 psi .! *' I ~" Kg.J.: LiNE V/ITH TWO 3" ~kl VALVE~ KiLL LINE FROM MUD P~ &: CE3UENT UNIT · i i jr _ · i i .['P~E RA~.S 1 ! FLOWL[NE FLANGE DOUBLE GATE 13-5/8" 5U CHOKE: LINE WITH ONE RE:~ '~ a~ i · SINGLE GATE ~3-5/a" 5u FLANG~ · · RISER , · i O" 5~ x 13-5/8" ADAPTER · 13-5/8" B(~PE SM SI'ACK ' · I · GRAYLING PLATF'OR~ · ,~F~WN: OAC APP.: G~ SCALE NON[ ,I. · I i I e· · TO OG'-~i~ YEN? WELL 1/lS" · AUTOMATIC C"HOKE CH O. KE ~,NIFOLD GRA~ING PLATFORM · UNION OIL COMPANY OF CALIFORNIA (dbcz UNOC~) I O~WN: OAC APP'a: G~ o~ ~1/~/~ AUTOMA11C CHOKE .~-~1,~- 3-V,~" /~ 3-,/,s- ~-~/,~" ' V~~ UF~~ 0g ~OKES '~ 10,000 P~ ~ ~E V~S'O~~~ ~ ~OK~ ~E 5.000 P~ ~ ~E ·UIXINO PIT IS A ONE: LEV~ BELOW THE JJMIXINg PIT' i ~0 BBLS ], ^CTN£SYST~... lg5 BELLS VOLUME PIT · TRIP TANK J ~ SUCTION PIT 125 BBLS -67 BBLS' · 2'1.0 BBLS ' I , , SI-IAI(ER. SI-IAI(ER ' "' E RESERVE PiT 4-75 BBLS . EQUIPMENT LIST 1) RESERVE PIT 2) DEGASS£R a) (2) S~Ud(ERS ' · 4) PIT LEVEL INDIP-.AToR · (vmua. ~ 5) FLUID FLOW SENSOR · 6) TRIP TANK · . PIT AGITATORS' ' DESILTER ~) CENTRIFUGE 10) MIXING PIT ' . ii UNOCAL · HOTE: THE 5Y:STEU WILL DE EQUIPPED WffH A DRILLIHO PIT LEVEL IHDIP-ATOR WITH AUDIO.a: VISUAL WARNINO DEVICE~i. ' -- ,~ 11 i i ........ , GRA'YI. ING MUD PIT SCHEblATIC DRAWN BYt DAC APP'D: 5CALEI NONE DATEI 1 1--~O--a9 i .... Alaska I:lec~on A~ri! Z6, 1990 Alaska Oil & Gas Conservation Commission 3001 Porcupine Dr. Anchorage, AK 99504 At,n: Ms. Elaine Johnson Dear Ms. Johnson: - I have attached surface survey locations of the "Legs" and conductors for the four platforms in the Trading Bay Unit as well as t~he Union Oil-operated Monopod and Granite Point Platforms. I was unable to locate any plats from a registered surveyor but I hope this will meet your needs. Yours very truly, Regional Drilling Manager GSB / lew CONDUCTOR GRAYLING DISTANCE & DIRECTIONS FROM SE CORNER SEC. 29, TgN, R13W LEG #3: LAT : 60o50, 22.569" LONG :151°36' 46.519" "Y" COORD. 2,502,352.30 "X" COORD. WELL # FSL · 212,272.70 1804 1 2 3 4 5 6 7 8 9 lO 11 12 LEG #4: LAT: 60050, 22.832" LONG :151°36' 48. 042" 2,502,346.65 2,502,350.14 2,502,354.64 2,502,358.05 2,502,358.77 2,502,356.46 2,502,352.20 2,502,347.99 2,502,345.80 2,502,350.83 2,502,354.60 2,502,351.47 2,502,380.80 FEL 1409 212,269.32 G-22 1789 1413 212,266.48 G-21 1802 1415 212,266.55 G-26 1806 1415 212,269.49 G-25 1810 1412 212,273.94' G-24 1810 1408 212,277.80 G-20 1808 1404 212,279.28 1804 1402 212,277.68 G-36 1800 1'404 212,273.75 G-34 & RD 1798 1408 212,270.89 G-23 & RD 1803 1411 212,272.33 G-33 1806 1409 212,274.88 G-27 & 28 1803 1407 13 14 15 16 17 18 19 20 21 22 23 24 LEG #1: LAT: 60050, 23.575" LONG :151°36' 47.505" LEG //2: LAT: 60050, 23.313" LONG =151°36' 45.982" 2,502,374.34 2,502,376.65 2,502,380.90 2,502,385.11 2,502,387.30 2,502,386.45 2,502,382.96 2,502,378.46 2,502,375.05 2,502,378.50 2,502,381.63 2,502,382.27 2,502,455.60 2,502,427. l0 212,197.90 1831 1486 212,196.66 G-14A 1825 212,192.79 G-19 1827 212,191.32 G-13 1831 212,192.92 G-15 1835 212,196.85 G-5 1838 212,201.28 1837 212,204.12 G-3 1833 212,204.05 G-2 1829 212,201.11 G-11 1825 212,198.27 G-lO 1829 212,195.72 G-17 & RD 1832 212,199.71 G-7 1832 1487 1491 1493 1491 1487 1483 1480 1480 1486 1483 1488 1484 212,226.40 1906 1458 37 38 39 40 41 42 43 44 45 46 47 48 (Reserved for Compressors) 212,301.20 1880 2,502,421.45 2,502,424.94 2.502,429.45 2,502,432.85 2,502,433.57 2,502,431.26 2.502,42?.00 2,502,422.80 2,502,420.60 2,502,425.63 2,502,429.40 2,502,426.27 1383 212,297.82 G-12, RD & 2 1874 1386 212,294.98 G-31 1878 1389 212,295.05 G-4 1882 1389 212,297.99 G-1 1886 1386 212,302.44 G-9 1886 1 382 212,306.31 G-18 1884 1378 212,307.78 G-14 1880 1 376 212,306.18 ....... G-30 1876 .1378 .... 212,302.25 G-8 & J~D 1874 1382 212,299.39 G-6 1879 1385 212,300.83 G-32 1882 1383 212,303.38 G-16 1879 1381 A ('~ .,ALA_ STATE OF ALASKA ( OIL AND GAS CONSERVATION COM MI~,,, .._)N REPORT OF SUNDRY WELL OPERATIONS 1 Operations performed Operat,on shutdown __ Stimulate __ Plugging __ Pedorate m Pull tub, ng ._. Alter casmg m Repar well m Pull tul:,ng __ Other 2 Name of Operator ! 5. Type of Well Union Oil Company of California (UNOqAL) D~evel.opm. ent~ / ,-xp~ratory 3 Address / Strat~graphtc P.O. BOX 190247, Anch, AK., 99519-0217 Serv,ce 4 Loca/~on o~ weUat suflace uona. ;~z, Leg 4, 1825' N & 1486' W of SE cot., Sec. 29, 6 Datum elevation (DF or KB) 99' RT above NSL feet 7 Un,t or...Prop.e;ty name /raa].ng Day Unit 8 Well n~_!~r 9 1W SM At to ~ o~o~u~Lc~vg;I nterva, 3896' S & 404' W from surface location At effective depth 4080'S & 273'W of surface location At total depth 4124'S & 485'W of surface locatlon 9 Permltb~_m4b_~J~.._l~~' number 10 APl number 50-- 733-20115 11 Field/Pool Hemlock 12 Present well cond~bon summary Total depth: measured true verbcal Effective depth measured true verbcal ,835' feet 1~,860' ~et ,655' ~m 1~'699' feet Plugs(measured) Junk(measured) Casing Length Size Cemented Measured depth Structural 374' 26" Driven 374' Conductor 694' 16" 1300 SX 694' Sudace 7670' 13 3/8" 2400 SX 3081' Intermediate 10835' 9 5/8" 2900 sx 10835' Production 260' 7" 6640' - 6900' Liner Perforabon depth measured 10223' - 10270'; 10290'- 10385'; 10395' - 10590'; 10610' - 10655' trbe ve~ical 9298' - 9341'; 9359' - 9445'; 9454' - 9633'; 9651' - 9693' ~ueve~caldepth 374' 694' 2929' 9680' Tub,ng (s,ze. grade, and measured depth) 3 1/2", 9.2¢~ 3619'; 4 1/2", 12.6¢; 6397' Packers and SSSV (type and measured depth) Baker "D" pkr $10127'; 4 1/2" Otis Ball ~ 227' RECEIVED 13 Sbmulabon or cement squeeze summary Intervals treated (measured) Treatment descnpbon including volumes used and final pressure JAN 2 ig e Oil & Gas Cons. Commissii "~" ~chorage 14. Representative Oady Average Production or Injection Data Od-Bbl Gas-Md Water-Bbl Casing Pressure Tubing Pressure Prior to well operation 170 483 2135 1400 psi 190 psi Subsequent to operation 319 410 2659 15. Attachments J 16. Status of well clasmflcation as Cop~es of Logs and Surveys run __ I Dady Report of Well Operabons __ Oil ~ Gas __ Suspended __ "i 7. I hereby certify that the foregoing ~s true and correct to the best of my knowledge. RoOerts/t-~.~-_ -z. ~/~r~--'Envi~ental Engineer SlgnedROy Form 10-404 Rev 06/15/88' /-"~' f--~'"~'/ 1400 psi 145 psi Service Da~e- t/19/89 SUBMIT IN DUPLICATE -'F 'M lEaSE -,-~,_,w $/22/~ UNION OIL CO. OF CALIFORNIA DRILLING RECORD i PAGE ND, __ ~' ~ LS ,BMC ArThur River ?,ay b~it ~t~' = _ jo-.. . .... ' ~ W..LI N -- _ , ..... ~ET'A~Ls OF OrrZATIONS, DESCRiPTiONS ~ RES ~5k~d =~g ~55 ov~ g-Il (L~ t~). Pig up My~s w~L~n~ u~t ~nd mak~ ~p ,].75" gauge cutle~. P:es~. ~ %e~[ [ub._~ato. ~o 2500 ps~, ok Ran in hole with g~uge cu~e~ to ~aI] ,.,,~ive hippie at 227', Puiled ou~ o~ hole. Eon ~n hole wlth pdii~ng Loot, ~ngage bail wlve~ unabIe -3 pull. PuIied o~ hoie. Spo~ f~ve ~aii~n~ H~L dow~ [Jb:ic~[;~ and soak fi= one h:)u=. Ean in hole wilt] ;d]i{na tool and pulle& Dail valve succes~:u!2 Rio down Myers wireline. i ~igged up Otis 1-1/~" coiled 5gbing unit. Make up 2-~/8" mud motor w~th 2.70" flat D3ttam mill. Pressure test unit, BOP5 to ~OgO T~i~ ok. Ran ho~e C!ean~ng tubing to th~ tail st 10~178' (K3 restr~c~.Lon encounter at ",Q" nipple I.D. 2.6~5" near tail.) Continu~ to ~un in hu!e arid beg~n cleaning out fill from !0,~8' to 10~507'~ tight hole. ____..p~l]~ out cf hole Made up and ran in hole 2 25" wash nozzle and clean out to i0~510' unable to make an~ noie PulIed oJt of hole. Ma~e uD 1.7~" mud motor ho._. Mud motor coninues to stall out %.80" tapered mill an~ ran in ~ndicating unable to : ~ ' ~ '' p.rne~ra~e oDscruc~on. Pullef out cf hole. I Ran in hole with Otis Hyd~o-B!ast tool using nine ~ets (iD = .0~' each). B~gin clean tubing (!s~ pass) from crossover st 6472' to ~u_xng tzll at 10,178~. Shut ~own pump for ons hou~ to index t~al. Pu!!a5 out of hole c'~eaning the tubing to the surface (2nd psss). ' ~mp!eted tnLrd an~ ~,~-~h, ~. p~ss~s to tuDing tail and b~.ck to surface. Rig up Myers wireIine p~essu~e =asr !ub~icator to 2500 osi, ok 'Ran in nole with 2,7~5" ' , * wi~h ~.75" gauge ~ing [o :~'~ (c:ossow: 4-~/2" ~ - ~ '" _~.. >-~/2 ). Pulled out of , ~._ ,- . _ , lowjet charges ~nd p~r, or~_~ 4 ~r ,~om _~,Z_.. -~0,.6~ , 10,2~ -lJ,~70 ; 10,465'-10,491 DiL. ''- ' ~ = ' _u=+. in ~h_ hole ~ ~ SE-CCh tO~! (!3.~'), TOF ~_ ~t !0.~5'. ~_ ~' v,. ' ' ? ~/q,, ~-~,- ,.~4~ con_.is%s of =.' shot s~rip, maonet~ ! i I I ALAS A OIL AND GAS CONSERVATION COM ,oSlON APPLICATION FOR SUNDRY APPROVALS 1 Type of Request Abandon ~ Suspend ~_ Operahon Shutdown ~ Re-enter suspended well -- Alter casing T~me extension '- Change approved program .~ Plugging- Shmulate ~ Pull tubing ~- Amend order ~ Perforate 2 Name of Operator Union 0il Company of California (UNOCAL) 3 Address P.O. Box 190247, Anch, Ak., 99519-0247 4 Location of well at surface Conductor #2[, Leg #4, 1825'N & 1486'W from SE Cot. Sec T9N, R13W, SR At top of productive ~nterval 3896'S & 404'W from surface location At effective depth 4080'S & 273'W of surface location At total depth 4124' S & 485'W of surface location 5 Datum elevation (DF or KB) 99' RT above HSL 6 Unit or Property name TBU :~9 ~Well number G-11 8 Permit number 68 -43 9 APl number 50-- 133-20115 10 Pool Hemlock feet 11 Present well condition summary Total depth measured true vertical Effective depth measured true vertical 10,835' feet Plugs (measured) 9,860' feet 10,655' feet Junk (measured) 9,699 feet Casing Structural Conductor Surface Intermediate Production L~ner Perforabon depth Length 374' 694' 3081' Size Cemented Measured depth Rue Vertical depth 26" Driven 374' 374' 16" 1300 sx 694' 694' 13 3/8" 2400 SX 3081' 2929' 10,835' 260' 9 5/8" 2900 sx 10,835 9860' 7" 6,640- 6,900' measured true vertical 10,223-10,270'; 10,290'-10,385'; 10,395'-10,590'; 10,610'-10,655' 9298'-9341'; 9359'-9445'; 9454'-9633'; 9651'-9693' Tub,ng (s,ze, grade and measured depth) 3 1/2", 9.2# 3,619' 4 1/2", 12.6 # 6379' Packers and SSSV (type and measured depth) II Il I Baker D Dkr ~ 10,127 ; 4 1/2" Otis Bali 12 Attachments Description summary of pro~s"l'a~er~_,t~ I~alled operations program - BOP sketch 13 Estimated date for commencing operation 14 If proposal was verbally approved Name of approver 5-01-88 Date approved 15 I hereby cerbfy that/~he foregoing ~s ~rup~nd correct, to the best of my knowledge ~gnea~ ,/,¢ ~Rnv D. Rht1~.-r:l-_~ Ht~e Fnvirnnm~nfal qpec: ~ ' ~/ Commission Use Only Conditions of approval Not~fy commission so representative may w~tness Approval [] Plug ntegnty [] BOP Test [] Locat on clearance Date 04/28/88 No. 9 ~_ ~/~ Approved Copy ~¢ ~........~//~.//~/~¢.,f//~.,¢//' ,~._._~_ ~fReturnedby order of Approved by the commission Date G-il PERFORATIONPROCEDURE 1. Rig up E-Line Unit. Pressure test lubricator to 2500 psi. · 0° phasing Perforate 2 RIH with 2 1/8" perforating guns, 4 SPF, . underbalanced or flowing as follows' B-1 B-2 B-4 B-4 10,223'-10,270' DIL 10,290'-10,375' DIL 10,460'-10,520' DIL 10,550'-10,575' DIL 3. Rig down E-Line Unit. 4. Flow well to test separator· ( ( v vi vii WELL TBUS G-11 WORKOVER 18 HB'I HB'2 ~ _ l HB-3 ~ ,, HB-4 =~-'~- HB-5 ~ VIII ._IT CASING & ABANDONMENT DETAIL I.) Rotary' Table Measurement at 0.00' I!.) ClW Tubing Hanger at 38.00' !11.) 16', 75+, J-55 Casing at 694' IV.) 13 3/8', 61,~, J-55 Casing at 3081' V.) 9 5/8' x 7 1/2" Baker 'FA" Packer at 6640' VI.) 7", 29e, N-80 Casing from 6640' to 6900' VII.) 9 5/8' x 7 1/2' Baker 'FA" Packer at 6900' VIII,) 9 5/8', 47v., N-80 Casing at 10,835' 3 1/2 , 1.) 4 2.) 4 3.) 4 4.) 4 5.) 4 6.) 3 7.) 3 8.) 3 9.) 3 lO.) 3 11.) 3 12.) 3 13.) 3 14.) 3 15.) 3 16.) 17.) 183 19.) 20.) TUBING DETAIL 9.2#, & 4 1/2", 12.6#, N-80 TUBING 1/2' Otis Ball Valve at 227.41' 1/2' Camco 'MMG' Gas L,ft Mandrel at 1887.06' 1/2' Camco 'MMG' Gas Ldt Mandrel at 3750.81' 1/2' Camco 'MMG' Gas Lift Mandrel at 5345.69' Camco 'MMG' Gas Ldt Mandrel at 6432.58' x 4 1/2' Box-Pm Crossover at 6471.98' 'KBUG' Gas Lift Mandrel at 7457.34' 1/2' 1/2' 1/2' Camco 1/2" Camco 1/2' Camco 1/2' Camco 1/2' Camco 1/2' Camco 1/2' Camco 1/2' Camco 'KBUG' 'KBUG' 'KBUG' "KBUG' Gas Lift Mandrel at 8059.93' Gas L,ft Mandrel at 8397.72' Gas Lift Mandrel at 8734.58' Gas LIft Mandrel at 9065.81' 'KBUG' Gas Lift Mandrel at 9402.56' 'KBUG Gas L~ft Mandrel at 9439.55' 'KBUG' Gas Lift Mandrel at 9988.48' 1/2' Camco 'KBUG' Gas Lift Mandrel at 10,053.04 3 1/2' Otis 'XA' Sleeve at 10,059.48' Baker Locator Sub at 10,125.98' Baker Model 'D' Packer w~th Seal Assembly from 10,127.01' to 10,147.31' 3 112' 'Q' N~pple at 10,176.01' Bottom of Baker Mule Shoe at 10,178.43' PERFORATION RECORD DA TE 7/02/68 7/03/68 4/16176 INTERVAL CONDITION 10610'- 10700' HB.~5 Prod. 10395'-10590' HB,~3 Prod. 10290'-10375' HB+2 Prod. 10223'-10270' HB+ 1 Prod. 10550"-10575' HB+4 Prod. 10460°-10520, HB+4 Prod. 10396'-10436' HB+3 Prod. 10230'-10260' HB+I Prod. WELL TBUS G-11 WORKOVER WELL SCHEMATIC UNION OIL COMPANY OF CALIFORNIA S( STATE OF ALASKA ( ALA A OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 1. Type of Request. Abandon ~ Suspend *" Operahon Shutdown '-; Re-enter suspended welt -- Alter casing ~' T~me extension '- Change approved program ~ Pluggm§ ~ Stimulate '-' Pull tubing '-' Amend order '--' Perforate [ Other Name of Operator Union Oil Company of California (UNOCAL) Address R.O. Box 190247, Anch, Ak., 99519-0247 Loca_t~on of well at surface C_oDguc~t.o.r, #Zl.., Leg #4, 1825'N & 1486 /YN, llJ..2W, ~ At top of productive ~nterval 3896'S & 404'W from surface locatlon At effectwe depth 4080'S & 273'W of surface location At total depth 4124' S & 485' W of surface location from SE Cor. Sec 5 Datum elevation (DF or KB) 99' RT above 1,4SL 6 Unit or Property name TBU feet 7. Welt number 29, G-11 8. Permit number 68-43 9. APl number 50-- 133-20115 10 Pool 11 Present well condition summary Total depth, measured true vertical Effective depth' measured true vertical ,835' feet Plugs (measured) 860 ' feet 10,655' feet Junk (measured) 699 feet Hemlock Casing Structural Conductor Surface Intermediate Production L~ner Perforation depth' Length 374' 694' 3081' S~ze Cemented Measured depth 26" Driven 374' 16" 1300 SX 694' 13 3/8" 2400 SX 3081' Rue Vertical depth 374' 694' 2929' 10,835' 260' 9 5/8" 2900 SX 10,835 7" 6,640- 6,900' 9860' measured true vertical 10,223-10,270'; 10,290'-10,385'; 10,395'-10,590'; 10,610'-10,655' 9298'-9341'; 9359'-9445'; 9454'-9633'; 9651'-9693' Tub,ng (size, grade and measured depth) 3 1/2", 9.2# 3,619' 4 1/2", 12.6 # 6379' Packers and SSSV (type and measured depth) Baker "D" pkr 8 10,127'; 4 1/2" Otis Ball - 12 Attachments Descrlpt,on summary of pro~s']'a~ ,P-'~_~ i~tTalted operations program -- BOP sketch - 13 Est;mated date for commencing operahon 14 If proposal was verbally approved , Name of approver ~-01-88 Date approved 15 I hereby certify that/the foregoing ~s true ~nd correct to the best of my knowledge S,gned ~/.-,'~--~'~4~ gL. /~'~,~' ~,'~z ~ %~ ..' /ITle ~ ~/-~ ~Rny D. R~-~t~ Fnvirnnm~nfnl qpeC: ~ ~ Commission Use Only Date 04./28/88 Conditions of approval Notify commission so representative may w~tness Fi Plug integrity [] BOP Test [] Locahon clearance Approved by r .... ~. d'~! '.FTERTON -~pproved Copy Return,ed Commissioner IAppr°val N°' by order of the comm,ss,on Date ~'-~:.'.~-' Form 10-403 Rev 12-1-85 Submit ~n triplicate G-il PERFORATION PROCEDURE 1. Rig up E-Line Unit. Pressure test lubricator to 2500 psi. 2. RiH with 2 1/8" perforating guns, 4 SPF, 0° phasing. Perforate underbalanced or flowing as follows- B-1 B-2 B-4 B-fl 10,223'-10,270' DIL 10,290'-10,375' DIL 10,460'-10,520' DIL 10,550'-10,575' DIL 3. Rig down E-Line Unit. 4. Flow well to test separator. / / ( .// WELL TBUS G-11 WORKOVER HB'I HS'~ '=- HB-3- '=- HB-4 = HB-5 vi VII ,j c CASING & ABANDONMENT DETAIL i.) Rotary Table Measurement at 0.00' II.) ClW Tubing Hanger at 38.00' III) 16', 75,~, J-55 Casing al 694' IV.) 13 3/8°, 61+, J-55 Casing at 3081' V.) 9 5/8' x 7 1/2° Baker 'FA' Packer at 6640' VI.) 7°, 29'~, N-80 Casing from 6640' to 6900' VII.) 9 5/8° x 7 1/2° Baker 'FA' Packer at 6900' VIII,) 9 5/8°, 47+, N-BO Casing at 10,835' 3 1/2, 1.) 4 2.) 4 3.) 4 4.) 4 5.) 4 6.) 3 7.) 3 83 3 93 3 lo.) 3 11.) 3 12.) 3 13.) 3 14.) 3 15.) 3 16.) 3 17.) 18.) 19.) 20.) TUBING DETAIL 9.2#, & 4 1/2", I2.6#, N-80 TUBING 112' Ot,s Ball VaNe at 227.41' 1/2' Camco 'MMG° Gas L~f! Mandrel at 1B87.06' 112' Camco 'MMG' Gas Lift Mandrel at 3750.81' 112' Camco 'MMG' Gas Lift Mandrel at 5345.69' 112' Camco 'MMG' Gas Lift Mandrel at 6432.58' 1/2' x 4 112' Box-Pm Crossover at 647 1.98' 1/2' 1/2" 1/2' 1/2" 1/2" 1/2" 1/2' 1/2" 1/2" 1/2' Camco 'KBUG" Gas Lift Mandrel at 7457.34' Camco 'KBUG" Gas L~ft Mandrel at 8059.93' Camco 'KBUG" Gas L,ft Mandrel at 8397.72' Camco 'KBUG" Gas Ldt Mandrel a;t 8734.58' Camco 'KBUG" Gas Lift Mandrel at 9065.81' Camco 'KBUG' Gas Lift Mandrel at 9402.56' Camco 'KBUG Gas Lift Mandrel at 9439.55' 6amco 'KBUG" Gas Lift Mandrel at 9988.48' Camco 'KBUG" Gas Llft Mandrel at 10,053.04 Otis 'XA" Sleeve at 10.059.48' Baker Locator Sub at 10,125.98' Baker Model 'D" Packer with Seal Assembly from 10,127.01' to 10,147'.31' 3 1/2" 'Q° N~pple at 10,176.01' Bottom of Baker Mule Shoe at 10,178.43' PERFORATION RECORD DA TE 7/02/68 7/03/68 4/16/76 INTERVAL CONDITION 10610'-10700' HBo-5 Prod. 10395'-10590' HBo3 Prod. 10290'-10375' HB+2 Prod. I0223'-10270' HB~I Prod. 10550'-10575' HB+4 Prod. 10460'-10520' HB+4 Prod. 10396'-10436' HB+3 Prod 10230"-10260' HB+I Prod. WELL TBUS G-I1 WORK OVER WELL SCHEMATIC UNION OIL COMPANY OF CALIFORNIA ,, STATE OF ALASKA ALAS OIL AND GAS CONSERVATION~,.OMMISSION SUNDRY NOTICES AND REPORTS ON WELLS 1 DRILLING WELL [] COMPLETED WELL OTHER 2 Name of Operator UNION 0IL COMPANY OF CALZFORNIA 3 Address PO BOX 6247 ANCHORAGE AK 99502 4 Location of Well Conductor #21, Leg #4, 1825'N & 1486'W from SE corner, Section 29, TgN, R13W, SM. 5 Elevation m feet (~nd~cate KB, DF, etc ) 99' RT above MSL 12 I 6 Lease Designation and Serial No ADL 187:50 7 Permit No 68-004:5 8 APl Number 50733-20115 9 Umt or Lease Name TRADING BAY UNIT 10 Well Number TBUS G-ii 11 FIeld and Pool McARTHUR RIVER FIELD HEMLOCK POOL Check Appropriate Box To Indmate Nature of Not~ce, Report, or Other Data NOTICE OF INTENTION TO SUBSEQUENT REPORT OF (Submit m Tnphcate) (Submit ~n Duplicate) Perforate [] Alter Casing [] Perforanons ~ Altering Casing [] Stimulate [] Abandon [] Sumulat~on [] Abandonment [] Repair Well [] Change Plans [] Repairs Made [] Other [] Pull Tubing [] Other [] Pulling Tubing [] (Note Report multiple completions on Form 10-407 w~th a submitted Form 10-407 for each completion ) 13 Describe Proposed or Completed Operations (Clearlv state all pertinent detads and g~ve pertinent dates, ~nclud~ng estimated date of starting any proposed work, for Abandonment see 20 AAC 25 105-170) The well was reperforated at 4 HPF at the following intervals: Perforations Bench ' i0,22B-10,2~8' 1 10,290-10,:570' 2 RECEIVED MAY 1 4 ]984 Alaska 0il & (~as Cons. Commission Anchorage 14 Iher~a ~l~oregomgls true and correct to the best of my knowledge S,gned~ '4~L~~/~ "'~,.V_____~~ T,tle District Engineer The space below for Commission use CondItions of Approval, ~f any Date 5/11/84 __ ~,- ~--' / - ~---/ By Order of Approved by COMMISSIONER the Commission Date Form 10-403 Rev 7-1-80 Submit "Intentions" ~n Triplicate and "Subsequent Reports" ~n Duplicate 2. Name of Operator UNION OIL COMPANY OF CALIFORNIA 3 Address PO BOX 6247 ALAS OILANDGAS CONSERVATION oMMISSION SUNDRY NOTICES AND REPORTS ON WELLS DRILLING WELL [] COMPLETED WELL ~ OTHER 7. Permit No ~PANY OF C~ LII ORNIA 68-0043 8. APl Number ANCHORAGE AK 99502 50-733-20115 4 Location of Well Conductor #21, Leg #4, 1825'N & 1486'W from SE corner, Section 29, TgN, R13W, SM. 9. Unit or Lease Name TRADING BAY UNIT 10. Well Number TBUS G-Ii 11. Field and Pool NcARTHUR RIVER FIELD HEMLOCK POOL 5 Elevation in feet (indicate KB, DF, etc.) 6 Lease Designation and Serial No 99' RT above MSL ADL 18730 Check Appropriate Box To Indicate Nature of Not~ce, Report, or Other Data NOTICE OF INTENTION TO' SUBSEQUENT REPORT OF' (Submit m Tr~phcate) (Submit m Duplicate) Perforate ~] Alter Casing [] ' Perforations [] Altering Casing Stimulate [] Abandon [] Stimulation [] Abandonment Repmr Well [] Change Plans [] Repairs Made [] Other [] Other [] Pulhng Tubing [] Pull Tubing 12 (Note Report multiple completions on Form 10-407 w~th a submitted Form 10407 for each completion ) 13 Describe Proposed or Completed Operations (Clearly state all pertinent detads and give pertinent dates, including estimated date of starting any proposed work, for Abandonment see 20 AAC 25 105-170). It is proposed to reperforate the following intervals: Per forations Bench 10,22-8-1 O' 268 ' 1- 10,290-10,370' 2 Subsequent Work Beported ,~.,Form No./i~ -qO~.. _ Dated ~ff__//!__/-~-? 14 I her~ at the foregoing ,s true and correct to the best of my knowledge ~.J2.gk,~ ~"~ii ["2 ~i::y ¢. ;~5. E m i~~O?j~,,,lSS,,.q~ S,gned ~-- ~ T,tle District Engineer Date 415/84 The space below for Commission use Cond,Bons of Approval, ~f any IRIGINAL $1GN£D BT LBNNI[ I:. SMITH Approved Cop~, Returned By Order of COMMISSIONER the Commission Approved by_ Form 10403 Rev 7-1-80 Submit "Intentions" in Triplicate and "Subsequent Reports" in Duplicate Form 10-4 U'3 REV. 1-10-73 Submit "Intentions" in Triplicate & "Sul~equent Reports" in Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE i5. APl NUMERICAL CODE 50-133-2011 5 SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) ]" OIL ~ GAS r-I WELLI~I WELLI I OTHER 2. NAME OF OPERATOR / Union 0il Company of £alifnrnia 3. ADDRESS OF OPERATOR P. 0. Box 6247, Anchorage, AK 99502 4. LOCATION OF WELL At surface Conductor #21, Leg 4' SE Corner Section 29' 1825 N' & 1486' W from the T9N, R13W, S.M. 13, ELEVATIONS (Show whether DF, RT, GR, etc.) 14. Check Appropriate Box To Indicate Nature of Notice, Re 6. LEASE DESIGNATION AND SERIAL NO. ADL-17594 7. IF INDIAN, ALLOTTEE OR TRIBE NAME 8. UNIT, FARM OR LEASE NAME Tradinq Bay Unit 9. WELL NO. G-11 (32-32) 10. FIELD AND POOL, OR WILDCAT McArthur River Field - Hemlock 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Section 32' T9N, R13W, S.M. 12. PERMIT NO. 68-43 3orr, or Other Data NOTICE OF INTENTION TO: FRACTURE TREAT MULTIPLE COMPLETE SHOOT OR ACIDIZE ABANDON* REPAIR WELL CHANGE PLANS (Other) ReBuff nra t.~ ~ i c t.i nn 'i n~-~v,v~ 1 c SUBSEQUENT REPORT OF: FRACTURE TREATMENT ALTERING CASING SNOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTEz Report results of multiple completion on Well Completion or Recompletion Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting any proposed work. We propose to reperforate the following intervals- B-1 B-2 B-3 B-4 B-5 10,228-268 10,290-370 10,400-440 10,460-490 10,501-521 10,540- 580 10,611-646 16. I hereby certify that the foregoing is true and correct SIGNED C.H. ~ TITLE District Enoin~_mr DATE, (This space for State of~) CONDITIONS OF A~ROVAL, IF AN~.'X'J '~Y O~DEH OF THE COMMISSION See Instructions On Reverse Side DATE Approved Copy Returned Un~on Od and Gas I~ don Western Region Un~on Od Company of Cahforn~a P O Box 6247, Anchorage, Alaska 99502 Telephone (907) 276-7600 unlln March 4, 1977 Mr. Hoyle Hamilton Division of Oil & Gas 3001 Porcupine Anchorage, Alaska 99504 Dear Mr. Hamilton. Enclosed for your approval is the Sundry Notices and Reports on Wells form for TBUS G-11. Sincerely yours, J ~'m~.R. Ca 11 ender Dist. Drlg. Supt. Form 10-403 REV. 1-10-73 Submit "Intentions" in Triplicate & "Subsequent Reports" tn Duplicate STATE OF ALASKA OIL AND GAS CONSERVATION COMM',TTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to drill or to deepen Use "APPLICATION FOR PERMIT--" for such proposals.) 5. APl NUMERICAL CODE 50-133-201 I5 6. LEASE DESIGNATION AND SERIAL NO. ADL-17594 OIL r-~ GAS I"-"'l ?. IF INDIAN, ALLOT'I-EEOR1 RIDE NAME WELLt '~ WELLL.J OTHER NAME OF OPERATOR 8. UNIT, FARM OR LEASE NAME Union Oil Company of California Tradin9 Bay Unit ADDRESS OF OPERATOR 9. WELL NO. P.O. Box 62q7, Anchorage, Alaska 99~;02 State G-11 (32-32) 1825' N & 1486' W from the T9N, R13W, S.M. 4. LOCATION OF WELL At surface Conductor #21, Leg /4: SE corner Section 29: 13. ELEVATIONS (Show wi~ether DF, RT, GR, etc.) Check Appropriate Box To Indicate Nature of Notice, Re 14. 10. FIELD AND POOL, OR WILDCAT McArthur River Field-Hemlock 11. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Section 32. TgN, R13W, S.M. 12. PERMIT NO. 68-43 3orr, or O[her Data NOT ICE OF INTENTION TO: TEST WATER SHUT-OFF FRACTURE TREAI SFIOOT OR ACID~2E REPAIR WELL (Other) PULL OR ALTER CASING MULTIPLE COMPLE~ E ABANDON* CHANGE PLANS SUBSEQUENT REPORt OF: WATER SHUT-OFF ~ REPAIRING WELL FRACTURE tREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recompletlon Report and Log form ) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent cletalls, and give pertinent dates, ~nclud~ng est;mated clate of starting any proposed work. PLAN OF PROCEDURE 1. Pull safety valve. 2. Rig up Dowell. 3. Pump 2,000 gal 50-50 D.A.D. P-20-15% HC! Pump 5,250 gal 25-75 D.A.D. P-20-12/10 UMA. 5. Pump 1,850 gal 50-50 D.A.D. P-20-7 1/2% HCi 6. Pump 900 gal 50-50 D.A.D. P-20-7 1/2% HC! with 900# OS90 Unibeads. 7. Pump 2,775 gal 50-50 D.A.D. P-20-7 1/2% HCI. 8. Repeat steps q thru 7 twice. 9. Pump 5,250 gal 25-75 D.A.D. P-20-12/10 UMA. 10. Pump 1,850 gal 50-50 D.A.D. P-20-7 1/2% HCI. 11. Displace with 131 barrels of diesel to top of perfs. 12. Immediately return the well to production. 13. Rig down Dowell. 14. Rerun safety valve. Estimated starting date: March 21, 1977. 16. I hereby certify that the foregoing Is true and correct S,~NED. ~:? //--~'~/~'~ ~;,~:.~'~"~ .... T,TLE District Engineer DATE March 3, 1977 See Instructions On Reverse Side DATE Approved Copy Returned Dear Mr. Hamilton: Union Oil and Gas ['(' sion: Western Region Union Oil Company of California P.O. Box 6247, Anchorage, Alaska 99502 Telephone: (907) 279-7681 union June 8, 1976 99504 Mr. Hoyle Hamilton Division of Oil & Gas State of Alaska 3001 Porcupine Dr. Anchorage, Alaska RE: TBUS G-II (WO) GRAYLING PLATFORM Enclosed for your files are two (2) copies of the Well History for the above captioned workover. Very truly yours, · Callender District Drlg. Supt. sk Encl. (2) cc: Marathon Oil Co. Atlantic Richfield Co, Amoco Production Co. Skelly Oil Co. Phillips Petroleum Co. Standard Oil Co. USGS-Rodney Smith UnionOilandGas( sion: Western Region~~ Union Oil Company of California P.O. Box 6247, Anchorage, Alaska 99502 Telephone: (907)279-7681 Mr. Hoyle Hamilton Division of Oil & Gas Stste of Alsska 3001 Porcupine Drive Anchors~e, Alssk~ 99504 Dear Mr. Hamilton: Enclosed for your files are two (2) copies each of the following monthly and completion reports for operations during the month of April. TBUS G-Il (32-32)-Grayling WO P-4 & 10-403 TBUS G-24 (14-32)-Grayling Drlg. P-4 TBUS D-7 (14-33)-Dolly WO P-4 & 10-403 TBUS D-28 (23-32)-Dolly Drlg. P-4 V~truly yours, David A. Johnson Drlg. Engineer sk Encl. (12) CC: Marathon Oil Co. Atlantic Richfield Co. Amoco Production Co. Phillips Petroleum Co. Skelly Oil Co. Standard Oil Co. Rodney Smith-USGS Form I 0-403 REV. 5ubml t "I nten [ & "Subsequent Reports" In Duplicate STATE o( _~SKA OIL AND GAS CONSERVATION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not use this form for proposals to (Jrlll or to cleeDen Use "APPLICATION FOR PERMIT--" for ~ucl~ DrODosals.) Ow~LLL['~WELLGAS r-~ OTHER NAME OF OPERATOR UNION OIL CO. OF CALIF. ~. ADDRESS OF OPERATOR P. O. Box 6247, Anchorage, Alaska 99502 4. LOCATION OF WELL Atsurface Conductor #21, Leg 4: 1825lN & 1486'W from the SE corner. Section 29: TgN, R13W, S. M. ELEVATIONS (Show whether DF, RT, GR, etc.) 14. Check Appropriate Box To Indicate Nature of Notice, Re NUMERICAL CODE 50~133-20115 6. LEASE DESIGNATION AND SERIAL ADL-17594 7. IF INDIAN, ALLOTTEE OR TRIBE NAME ,8. UNIT, FARM OR LEASE NAME Trading Bay Unit 9. WELL NO. State G-Il (32-32) 10. FIELD AND POOL, OR WILDCAT McArthur River Field-Hemlock ll. SEC., T., R., M., (BOTTOM HOLE OBJECTIVE) Section 32: T9N, R13W, S.M. 12. PERMIT NO. 68-43 )ort, or Other Data NOTICE OF INTENTION TO; TEST WATER SHUT-OFF FRACTURE TREAT SHOOT OR AClDIZE REPAIR WELL (Other) PULL OR ALTER CASING MULTIPLE COMPLETE ABANDON* CHANGE PLANS SUBSEQUENT REPORT OF: WATER SHUT-OFF ~ REPAIRING WELL FRACTURE TREATMENT ALTERING CASING SHOOTING OR ACIDIZING ABANDONMENT* (Other) (NOTE: Report results of multiple completion on Well Completion or Recomplet~on Report and Log form.) 15. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state all pertinent details, and g~ve pertinent dates, mcluchng estimated clate of starting any proposed work. PLAN OF PROCEDURE: (Work completed @ 12:00 Midnite, 4/2/76) L. Killed well w/ Dril-S completion fluid. ~. Removed x-mas tree. Installed & tested BOPE. ~. CO tbg. to 10,104'. Chased hyd. pkr. to 10,688'DPM w/ top of tbg. stub @ 10,655'. Unable to retrieve pkr. [. Sqz'd. damaged 9 5/8" csg. from 6767'-6774' w/ 650 sx. of cmt. i. CO 9 5/8" csg. to top of tbg. fish @ 10,655'. ' ,. Set 9 5/8" X 4 3/4" perm. prod. pkr. @ 10,120'. '. Straddled 9 '5/8" damaged csg. w/ 7" 39# N-80 scab liner w/ 9 5/8" X 7 1/2" perm. pkrs. @ 6900' & 6640'. I. Ran 4 1/2" X 3 1/2" gas lift production string & stabbed into perm. pkr. @ 10,120'. Removed BOPE. Installed & tested x-mas tree. '. Returned well to production. 16. I hereby certify that the foregoing I$ true anti correct TITLE Dist. Drlg. Supt, DATE- 5/14/76 {This space for State office use) APPROVED BY CONDITIONS OF APPROVAL, IF ANY= TITLE DATE See Instructions On Reverse Side l~rm N'o ~ 3-1-70 STATE OF ALASKA OIL AND GAS CONSERVATION COMMITTEE SUBMIT I~ DUPLICATE: MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS NAME OF OP~.ATOR UNION OIL CO. OF CALIF. P. O. Box 6247, Anchorage, Alaska 99502 4 LOCATION OF W~r-~ Conductor #21, Leg 4: 1825'N & 1486'W from the SE corner. Section 29: T9N, R13W, S. M. AP1 NU~(ER1CAL CODE 50-133-20115 LEASE DESiGNA.'r'ION A~D SERIAL NO ADL-17594 IF II~DIA~ ALO~ iE~ OR TRIBE NAME 8 L"~IT FA.R~ OR LEASE N.z~ME Trading Bay Unit 9 w~ NO State G-il (32-32) 10 FIF~,D AND POOL OR WILDCAT McArthur River Field-Hemlock IX SEC T R M (BO"I~OM HOLE O~ Section 32: T9N, R13W, S. M. 12 P~q.MIT N'O 68-43 13 REPORT TOTAL DEI:~FH AT END OF MONTH CHA~'~GES IN HOLE SIZE. CA,lNG AND CEMEN~'FING JOBS INCLUDING DEPTH SET ~ VOL~ US~ P~O~TIONS. ~TS ~ ~SUL~ FISHING JO~ JL~K ~ HO~ AND SIDE-~CKED HO~ ~D ~Y O~R SIGNIFIC~T ~G~ ~ HO~ ~ITIONS L6 17 4/1/76 4/2/76 10,846'TD 10,655'ETD top of fish 100846'TD 10,655'ETD top of fish (Footage 0') RIH w/ 9 5/8" X 7 1/2" Baker Model "FA" pkr. w/ 7" 29# N-80 csg. stinger on btm. Stabbed into Baker 9 5/8" X 7 1/2" FA pkr. @ 6900' & set top Baker FA pkr. @ 6640'. Pooh w/ setting tool. RU to run 4 1/2" X 3 1/2" gas lift production string. (Footage 0') Ran 4 1/2" X 3 1/2" production string w/ Camco side pocket gas lift valves as programed. Stabbed into Baker 9 5/8" X 4 3/4" Model "D" pkr. @ 10,120'DIL (10,127' tbg. meas.) & tested w/ 500 psi-ok. Spaced out & landed tbg. Installed BPV. Removed BOPE. Installed & tested x-mas tree. Removed BPV. RU slickline unit. Opened "CA" sleeve @ 10,090'. Displ. 72#/cu. ft. Dril-S WO fluid w/ inhibited filtered Inlet wtr. Closed "XA" sleeve © 10,090'. Placed well on gas lift. Released Rig #55 @ 12:00 Midnite, 4/2/76. Commenced deactivation on Rig #55 & activation of Rig #54 over Leg Room #3. Gas lifting well & prep. to test. FINAL REPORT oil ..d g.$ con~erv~on ¢o~iHee by the 15lb of t~e succeeding mon#~, u~l~ Ot~¢rm$~ d~r~c~ed. io P P --, ?;; ...._-,._ · .0 ~00 700 ..... /o0 -- 7~ £ ......... Union Oil and Gas~ ision: Western Region Union Oil Company of California P.O. Box 6247, Anchorage, Alaska 99502 Telephone: (907) 279-7681 union · April 12, 1976 Dear Mr. Hamilton: Mr. Hoyle Hamilton Division of Oil & Gas State of Alaska 3001 Porcupine Drive Anchorage, Alaska 99504 RE: TBUS D-15 (32-1) Enclosed for you files are the Monthly Report of Drilling & WO Operations (Form P-4) for both of the above captioned workovers and the Sundry Notice & Reports on Wells (Form 10-403) for TBUS D- 15. sk Encl. Very truly yours, District Drlg. Supt. cc: Marathon Oil Co. Atlantic Richfield Co. Phillips Petroleum Amoco Production Skelly Oil Co. Standard Oil Co. USGS-Rodney Smith ~c)rm No P--4 ~ &- I-?0 ( STATE OF ALASKA OIL AND GAS CONSERVATION COMMI'Iq'EE SUBMIT IN DI/PLICATE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS AP1 NIJ~ERICAL CODE 50-133-20115 LEASE DESiG]qATXON AND SERIAL NO ADL-17594 wELL WELL OTHER NAME OF OP~t.ATOR UNION OIL COMPANY OF CALIFORNIA P. O. Box 6247, Anchoral~e, Alaska 99502 LOCATION OF W~ Conductor 21, Leg 4: 1825'N & 1486'W from the SE corner. Section 29: T9N, R13W, S. M. 8 L,~IT FARM OR LEASE NAME Trading Bay Unit g WEI. J~ NO State G-Il (32-32) 10 i'{i~_~D A-ND POOL OR WILDCAT McArthur River Field-Hemlock ,~ s~c T, ~t, ~ (~o~o~ HoLE Section 32: T9N, R13W, S. M. 12 PEP.MIT 1~0 68-43 '13 REPORT TOTAL DEPTH AT lEND OF MONTH, CHANGES IN HOLE SIZE. CASING AND CEMENTING JOBS INCLUDING DEPTH SET AND VOLI/MI~ USED PERFORATIONS TESTS AND HESULTS FISHING JOBS JU'NK IN HOLE AND SIDE-TRACKED HOLE AND ANY OTHER SIGNIFICANT CHANGES IN HOLE CONDITIONS Mixed 72#/cu. ft. Dril-S NaC1 WO fluid. Pulled gas lift valves & opened circ. sleeve @ 10,056'. Well press, recorded @ 2400 psi on tbg. & 2425 psi on csg. Displ. tbg. w/ WO fluid. Unable to get returns on csg. annulus. Production perfs, from 10,223'-10,700' taking fluid. Set 4 1/2" Baker bridge plug & tbg. @ 10,122' below 9 5/8" Baker Model F-1 Hyd. pkr. @ 10,091'. Press. tbg. to 1700 psi & bled csg. press, to 1100 psi, bridge & csg. annulus broke loose & established circ. Circ. gas out of csg. annulus & killed well w/ 72# WO fluid. 3/17/76 10,846'TD (Footage 0') Commenced WO operations on TBUS G-Il WO @ 12:01 am, 10,790'ETD 3/17/76. Installed BPV in tbg. hgr. Removed x-mas tree. Installed FC BOPE. 3/18/76 10,846'TD 6171'ETD tbg. fish (Footage 0') Completed installing BOPE & tested to UOCO specs. PU on 4 1/2" tbg. & worked Cameron "DCB" hgt. free-tbg, stuck. RU Go-Int'l. & ran tbg. free pt. indicator. Tbg. 100% free @ 6214'- 100% stuck @ 6490'. Ran tbg. cutter & cut tbg. @ 6171'. (10' below btm. of CX Mandrel 6155'-6161'), Circ. btms. up. Pooh laying dwn. 4 1/2" tbg. 3/19/76 10,846'TD (Footage 0') Changed pipe rams to 5" & tested to UOCO specs. Ran 6295'ETD OS w/ hallow mill control & 4 1/2" grapple picking up 5" DP. Tagged top of fish up on top of fish @ 6284'. (Note; top of fish was left @ 6171' tbg. meas.-fish moved dwn. hole 113'. Est. top of pkr. to be @ 10,207' & tbg. tail @ 10,248'). Engaged fish @ 6284' w/ OS. RU Go-Iht'l. Logged top of fish @ 6295'WLM. Unable to get circ. gun below perf. in tbg. @ 10,096'-10,109' & had indication of fill getting above gun & 14 I hereby ~e~t the~ foreg~ing ~jgru~ ~ correct sm~r~ ~~-~ Dist. Drle. Supt, ..~ 4/10/76 NOT~--Re~ort on this f~ is re0uired for ~ calendar ~th~ regardless of the status of o~eratio~, and must ~ filed In dupli~ate with t~e oil and gas conlervotbn commi~ee bythe IS~ of the euecNding mn~, ~le~ otherwise d~rected. BUS G-11 (WO) (32-32) iONTHLY REPORT OF OPERATIONS -2- April 10, 1976 trying to stick. Pooh w/ circ. gun. Worked fish w/ 160 M over string weight, unable to work fish free. 3/20/76 10,846'TD (Footage 0') RU Dialog & ran free pt. Tbg. free to top of fill in tbg. 10,104'ETD @ 10,105'TM. Cut off 4 1/2" tbg. @ 10,104'TM (6' below perf. tbg.) top of fish Circ. btms. up. Recovered sand & gas cut W@ fluid. Pooh & laid dwn. 4 1/2" tbg. (top of fish @ 10,104', fish left in hole 144'). Ran 8 1/2" impression block in hole. Tagged up @ 6767'. Pooh. Had impression of collapsed or swedged in csg. 3/21/76 10,846'TD (Footage 0') Ran 4 3/4" X 7 3/8" tapered mill. Dressed out 9 5/8" 10,104'ETD csg. from 6767', rough milling to 6774' & mill fell free. Backreamed ok. top of' ~ish CO to 6794'. Circ. out metal cuttings. Pooh. PU 8 1/2" OD water- melon mill above 7 3/8" OD tapered mill. 3/22/76 10,846'TD (Footage 0') RIH w/ 7 3/8" OD tapered mill & 8 1/2" OD watermelon 10,371'TD mill in tandem. Dressed out 9 5/8" csg. to 8 1/2" from 6767'-6774'. top of fish Worked thru sand bridge from 8039'-8047'. Cont. RIH w/ mills. Tag- ged top of fish @ 10,294'. Fish moved dwn. hole to 10,371'. Circ. btms. up. Pooh. PU 8 1/8" W@ pipe. 3/23/76 10,846'TD (Footage 0') RIH w/ 8 1/2" OD wash pipe to 10,371'. Tagged fish. 10,582'ETD Fish moved dwn. hole. Washed from 10,371'-10,646'. Fish stopped @ 10,646'. Unable to tell if on top of fish or on top of pkr. Circ. hi-vis, pill to clean hole. Pooh w/ W@ pipe. RIH w/ OS w/hollow mill control & 4 1/2" grapple. Tagged top of fish @ 10,582'. (meas. indicated that wash pipe stopped on top of pkr. w/ wash pipe). Engaged fish w/ OS. Unable to jar free. Released OS & Pooh. RIH w/ 8 1/2" OD W@ pipe. Worked over top of fish @ 10,582' (top of pkr.) Circ. hole clean. 3/24/76 10,846'TD (Footage 0') Circ. hole clean on top of Baker 9 5/8" hyd. pkr. @ 10,582'ETD 10,688'. Pooh w/ W@ pipe. RIH w/ 7 5/8" OS w/ 8 1/2" grapple. top of fish Engaged fish @ 10,582'-unable to jar free. Released OS. Pooh. RU Schl. Ran CBL-VDL-GR Log from 8000'-2500'. Had good cmt. from btm. stage of primary job up to 7550'. Ratty cmt. to 7420'. No cmt. above 7420'. CBL showed csg. collapsed from 6761 1/2' to 6767'DIL meas. DIL Log showed an@really from 6761'-6767'. Reported to be Bentonite bed. (Note: DIL meas. 6' high to DP meas.) Had good bonding from top stage primary job from 4200'-2800'. (Note: DV stage cmt. tool @ 4128'). Ran CNL-GR-CL Log from 9400'. 3/25/76 10,846'TD (Footage 0') Ran CNL-GR Log from 9400'-3500'. RIH w/ 7 5/8" OS 10,582'ETD w/ 4 1/2" grapple & engaged top of fish @ 10,582'. RU Go-Int'l. top of fish RIH w/ 4 1/2" DP cutter ( 3 7/16"OD) Unable to work cutter thru 5" S-135 DP tool jts. RD Go-Int'l. Released OS. Pooh. PU BUS G-Il (WO) (32-32) iONTHLY REPORT OF OPERATIONS -3- April 10, 1976 Dialog circ. sub. RIH & engaged fish @ 10,582'. RIH w/ WL spud bar. Worked thru fill bridge @ top of fish @ 10,582'. CO to 10,647'. Pooh w/ WL wash dwn. tool. Washed dwn. from 10,647'-10,651'. Unable to wash inside fish dwn. below 10,651'. Pooh w/ wash dwn. tool. 3/26/76 10,846'TD (Footage 0') Backed off fish & Pooh. Rec. cut off piece 4 1/2" tbg. 10,655'ETD plus 2 jts. 4 1/2" tbg. & top section of "CX" Mandrel. Left 74' of top of fish fish in hole. Top of fish @ 10,655'. Fish left in hole: Top of fish @ 10,655'DPM Btm. section of Otis "CX" Mandrel - 2.83' *See drawing in Project File. 1 - it. 4 1/2" 12.6# Buttress Tbg. - 30.29' 1 - 9 5/8" Baker Model F-1 Hydro pkr. - 8.58' 1 - 4 1/2" Otis "X" Nipple - 1.51' I - Jr. 4 1/2" 12.6# Buttress Tbg. - 29.06' 1 - 4 1/2" Baker Trip Sub. - 1.42' Btm. of fish @ 10,729'DPM Note: DPM are 6' low to DIL meas. - top of fish @ 10,649'DIL meas. (Bench #5 perfs, from 10,610'-10,700'). Ran OEDP to 7401' (47# 9 5/8" csg. @ 7209') & set cmt. plug w/ 73 sx. Class "G" cmt. w/ .75%D-31, .6%D-9 & .1%D-6 w/ 10% sand. Displ. cmt. w/ 72# WO fluid. CIP @ 12:00 Noon. Pulled OEDP to 6660' & rev. circ. WOC. 3/27/76 10,846'TD (Footage 0') Total WOC time - 12 hrs. Ran OEDP to 7314'-no indica- 10,655'ETD tion of cmt. circ. out. Had sand in WO fluid but no positive indica- top of fish tion of cmt. Hung off OEDP @ 7401' & set second plug w/ 91 sx. Class "G" cmt-.75% D-31, .6% D-9, .1% D-6 & 10% sand w/ 1.1% · . CaC12 in mixing H_O. CIP @ 5:00 am Pulled OEDP to 6660' ,& rev. circ. WOC ~ hrs. Pooh. PU k 1/2" bit & TIH to 7386 . No indication of cmt. after 8 hrs, from CIP. Circ. out. Rec. approx- imately 20 bbls of Mud contaminated green cmt. Note: BJ lab test showed 2 hrs. 50 rains, set time on cmt. sample from rig. Slurry samples caught during cement mixing of both plugs never set up on surface. Washed dwn. & CO 9 5/8" csg. to 10,184'-circ. & cond. WO fluid. Rec. green cmt. globs in WO fluid. Cmt. not set after +36 hrs. Cmt. is not greatly effecting WO fluid properties other t~an Ph. & increased CA++. BUS G-11 (WO) (32-32) ONTHLY REPORT OF OPERATIOi~S -4- April 10, 1976 3/28/76 10,846'TD 7274'ETD Est. cmt. on top of (Footage 0') Ran in &tagged top of fish @10,655'. Circ. btms. up. Rec. traces of green cmt. Pooh. Ru Go-Int'l. Ran 8 1/2" gauge ring & junk basket. Unable to work thru bad csg. @ 6773'. RD Go-Int'l. Ran 9 5/8" Howco EZ drill cmt. ret. on DP & set @ 7412'. Laid 50 sx. of Class "G" cmt. on top of ret. Pooh. Ran Baker 9 5/8" squeeze tool & set @ 6473'. Test annulus to 2000 psi & surface lines to 4500 psi. 3/29/76 10,846'TD 7300'ETD Cmt. Plug (Footage 0') Set Baker 9 5/8" squeeze tool @ 6473' to squeeze off damaged csg. @ 6767' to 6774'. Broke dwn. rm. @ 1500 psi. PI 20 cfm @ 1550 psi. Fro. held 600 psi w/ pumps off. Mixed 650 sx. cmt. Class "G" w/ .75% D-31 to llS#/cu, ft. Squeezed 650 sc. below tool w/ a final pumping rate of 8 cfm @ 2500 psi. Squeeze job held 2050 psi w/ pumps off. WOC. Pooh w/ 9 5/8" squeeze tool. TIH w/ 8 1/2" bit. Tagged top of cmt. @ 6726'. CO firm. cmt. to 6772' & ratty cmt. to 6800'. CO & dressed off cmt. plug to 7300'. Circ. & cond. mud. Pooh. RU Go-Int'l. 3/30/76 10,846'TD (Footage 0') Ran Go-Int'l. CBL Log from ETD, cmt. plug @ 7300' to 10,655'ETD 4000' to check cmt. backing from sqz. on collapsed csg. @ 6767-6774'. top of fish Had fair cmt. from 7300'-6800' & good cmt. from 6800'-4650'. RD WL unit. Ran 7 3/8" tapered mill in tandem w/ 8 3/8" watermelon mill. Dressed out csg. from 6767'-6774'-ok. Pooh. Reran 7 3/8" tapered mill in tandem w/8 3/8" watermelon mill in tandem w/ 8 1/2"+watermelon mill. Redressed csg, @ 6767'-6774'. Pooh. Ran 8 1/2" bit. CO cmt. from 7300' to Howco cmt. ret. @ 7412'. Drilled cmt. ret. & CO to top of fish @ 10,655'. Circ. btms. up. 3/31/76 10,846'TD (Footage 0') Circ. & cond. W@ fluid. Pooh. RU Go-Int'l. RIH w/ 10,655'ETD gauge ring (8.45"OD) & junk basket. Tools stopped @ 7310'. Pooh-rec. top of fish rubber from cmt. ret. Ran gauge ring (8.125"OD) to 10,200'. Ran & set Baker 9 5/8" X 4 3/4" Model "D" (8.125"OD) pkr. @ 10,120". Ran Baker 9 5/8" X 7 1/2" Model FA pkr. (8.438"OD) @ 6900'. PU Baker 7 1/2" X 6" seal assy. & 6 its. of 7" 29# N-80 Buttress csg. on Baker 9 5/8" X 7 1/2" Model FA pkr. i, AR 9 - I976 Dear Mr. Hamilton: Union Oil and Gas Divi[," n: Western Region Union Oil Company of California I ~ ~ ', . P.O. Box 6247, Anchorage, Alaska 99502 j--:~ ~-: '. -? , , Telephone: (907) 279-7681 [~ j ,_ · . ,,, , Ufll,en Ma~rch 5, 1976 Mr. Hoyle Hamilton Division of Oil & Gas State of Alaska 3001 Porcupine Drive Anchorage, Alaska 99504 TBUS G-12 Rd, (34-33) GRAYLING PLATFORM Enclosed for your approval are three (3) copies each of the Sundry Notice & Reports on Wells for the above captioned Grayling workovers. Very truly yours, J~~m R Callender District Drlg. Supt. sk Encl. (6) cc: Marathon Oil Co. Atlantic Richfield Co. Amoco Production Co. Phillips Petroleum Co. Skelly Oil Co. Standard Oil Co. USGS-Rodney Smith / &-';~UD$OCIuent ReDOrt$" In DL;)ll¢ite STATE OF~r '~KA OIL AND GAS CONSERVe,, i ION COMMITTEE SUNDRY NOTICES AND REPORTS ON WELLS (Do not u~e this form for DrOOOSalS to ¢lrlll or to OeeDen Use '*APPLICATION FOR PERMIT--" for Such DrODosals.) L WELL OTHER ~.. NAME OF OPERATOR UNION OIL COMPANY OF CALIF. ADDRESS OF OPERATOR P. O. Box 6247, Anchorage, Alaska 4. LOCATION OF WELL 99502 At,~,,ace Conductor 21 Leg 4: 1825'N & 1486'W from the SE corner. Section 29: TgN, R13W, S. M. ELEVATIONS (Show whether DF, RT, GR, etc.) 99' RT above MSL 14. ~ JMER ICAL CODE 50-'133-20115 LEASE DESIGNATION AND SERIAL NO. ADL- 17 5 9 4 7. IF INDIAN, ALLOTTEE OR TRIBEN~ME 8. UNIT. FARM OR LEASE NAM Trading Bay Unit 9. WELL NO. State G-Il (32-32) 10. FIELD AND POOL. OR WILDCAT McArthur River Field-Hemlock ]]. SEC., T.. R.. M.. (BOTTOM HOLE OBJECTIVE) Section 32: T9N, R13W, S. M. 12. PERMIT NO. 68-43 Check Appropriate Box To Indicate Nature of Notice, Report, or Other Data SUBSEQUENT REPORT OF: WATERSHUT.OFF ~ FRACTURETREATMENT SHOOTING OR ACIDIZING (Other) NOTICE OF INTENTION TO: TEST WATER SHUT-OFF ~ PULL OR ALTER CASING FRACTURE TREAT ~ MULTIPLE COMPLETE SHOOT OR AClDIZE ~ ABANDON* REPAIR W~ELL ~ CHANGE PLAN5 (Other) liepair 9 5/gU--csg. damage REPAIRING WELL ALTERING CASING ABANDONMENT* (NOTE: ReDort results of mult~olecompletlon on Well Comoletton or Recomr)letion RePort ancl Log form.) 35. DESCRIBE PROPOSED OR COMPLETED OPERATIONS (Clearly state aH Pertinent cletalls, and 9,ve pertinent 0ares, mcluaing estimate0 Cate of ~tartlng any propose0 work. To repair suspected 9 5/8" csg. damage in Trading Bay Unit State Well G-Ii, a Hemlock Development Producer. It is proposed to pull tubing, locate the gas entry and repair suspected damaged 9 5/8" csg.w/ a possible change in production string from 4 1/2" to 3 1/2" assuming a scab liner has to be set. PLAN OF PROCEDURE: 1. Kill well w/ Dril-S completion fluid. ' 2. Remove x-mas tree. Install & test BOPE. 3. Pull & laid dwn. 4 1/2" tbg. & accessories. 4. RIH w/ 9 5/8" RBP & retrievable pkr. Locate source of gas entry. Run a csg. inspection log if determined necessary. 5. Depending upon type of damage, repair 9 5/8" csg. 6. Complete well w/ gas lift string & return to production. E__STIMATED OPERATING TIME: Twelve (12) Days. SIONE~~ · ~ Jim ii. Caiiender . - District Dr] .]~~U_p_t' TITLE DATE 3___3/~7 6 APPROVED BY_ / ~, .... CONDITIONS OF ~,,~O'VAL I' ' /'~-' ~'~'' - TITLE '" ~ ' ',' ~ ~ . F A~, ~ DATE ~pro~8 Cop~ Ee~med ~ '~tructions On Revere Side Form P--3 ( Stat)mit "Intentions" in Triplicate I~.EV 9-30-69 & 'Subsequent Reports" m Duphcatek_ STATE OF AL~KA ' '! Di'R ' ~r,,,~ OIL AND GAS CONSERVATION CO/WVU'I'[EE -"-~' GEO( ['~P~' SUNDRY NOTICES AND REPORTS ON ~.~WRI ~-'[ ] ENG ~/ (Do mot use this form £or proposaIs ~ d] HI oT to ~ee~e --- m ~ ~ Use ~[~A~ZON ~O~ P~Ir--" ~o~ such ~ ) _. I ~ OiL ~ OAS ~ WELL WgLL OTHER 2 NAME OF OPERATOR Union 0il Company of California 3 ADDRESS OF OPERATOR 909 IV. 9th Avenue, Anchorage, Alaska 99501 4 LOCATION OF WELL ^tsu. face Conductor 21, leg 4, 1825'N ~ 1486'W SE corner Section 29, TSN, R15W, SM. 13 ELEVATIONS (Show whether DF, RT, OR, eec 99' RT above biSL 14 LEASE DESIGNATION A.ND SERIAL NO ~DL 17594 : '" ; ' '/ IF INDIA_N, ALLOTTEE OR T~BE N~ ] 4 ~'~ Trading hy Unit 2 GEOL ~. ~L NO '-'[~ GEOL J~ State G-II (32-32) I~AFT J _ECI I J FILE, Check Appropriate Box To Indicate Nature of I~[otice, Re 10 F!~.Lr~ A~X[D POOL, OR WILDCAT Hc~thur River - Hemlock 11 SEC , T , R , M , (BOTTOM HOLE OBJECTIVE) Sec. 32, T9N, R13W, ~ert, or Other Data NOTICE OF INTENTION TO: TEST WATER SHUT-OFF i I PULL OR ALTER CASINO FBACTLRE TREAT MULTIPLE COMP! RTE SHOOT OR ACIDIZE ABANDONS REPAIR V~ ELL CHANGE PLANS ,Other) imtall new g~ lift ~sem. SUBSEQUENT REPORT OF: WATER SIIUT-OFF REPAIRINO WELL FRACTURE TREATMENT ALTERING CASI~O SHOOTINO OR ACIDI~.INO ABANDON MEETS (Other) (NOTE' Report results of multiple completion on Well Completion or Recompletion Report and Log form ) 15 D[ SCRIBE PROPOSED OR COMPLETED OPERATIO.NS (Clearly state all pertinent details, and give pertinent dates, including estimated date of starting an) proposed work. :RBASON FOR t~)IAL REPAIR: TBU State G-Il currently produces from the Hemlock Zone 5900 net B/D. The well is equipped with nine gas lift valves with the bottom valve positioned at 8640'. Due to the change in bottom hole pressure and fluid gradiemt, the present downhole gas lift assembly is not operating at maximum efficiency. It is proposed to kill the well w/invermul, pull tbg, change the gas lift valves, respace the present mandrels, and add additional valves and mandrels. An 800 BOPD production increase is anticipated. ESTIHATED STARTING DATE: 16 , hereby certify 7~ 8ION"ED ._ i1~ I~_ J_ I.~ z t~ iaA/ey) (This space for State ~U~) APPROVED BY 1. Hove over well. Kill w/68# invermul. Remove tree, ~ install BOE. 2. Pull tbg. Re-run same 4-1/2" tbg string w/respaced mandrels, additional mandrels, and equipped w/type "CF" valves. 5. Remove BOB, install tree, chng over to diesel oil, ~ set ~.. f, ~ !\/? ~ D 4. Return well to production, via gas lift. g/2o/71 DiVlSIOt~ OF O';t~ / ND GAS ANCI-iORAGB correct TITLE Dist. Drlg. Supt. 8/12/71 See I,n,s~ructions On Reverse Side Approved Cop~' Returned UNION OIL CO. OF CALIFORNIA AI.,\SkA PiSi F~ICI' T]'ans:,,it t al State of ^laska DATE* August 12, 1968 FROM' Union Oil Co. of Calif. WELL NA~'IE' Trading Bay Unit 6-11 Trans,n;.tted hcrcv,'ith are thc follo:,ing' Run No. final Sepia Blue Scale I 1 2~ Induction Electrical Log Dual Induction Laterolog B}IC Sonic/Caliper Log BI!C Sonic/Gamma Ray B}tC Soni6/ Caliper/Gamma Ray Log Formation Sonic Log (Fs) Density-Gamma l,og Formation Density Log (Fd) Neutron I,og Formation Neutron I,.o~7 (Fn) CDSI or Iligh Resolution Dil,meter CDH Safety Print CDbi or Printout CDrI o:' Pc, ly¥<~g Plot CI~M Polar Plots , Proxir, tity-~licrole2/Cal iper Log Gamma Ray-Neutron Gaf, ma Ray Co!iav Leg Cement Bond Log blfidlog Core Descriptions, Conventional, No. Core Descriptions, Side~all Core Core Chips Drill 5tc'~ 'Fe~ Form. No P---4 ( STATE OF ALA~SKA O~L AND GAS CONSERVATION COMMITTEE SUBMIT I2N' DEPLICATE /VIONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS WELL WELL ~ OTHER 2 NAME OF OPERATOR Union Oil Company of California 3 ADDRESS OF OPERATOR 507 W. Northern Li~lhts Blvd. t Anchorage, Alaska 4 LOCA/qON OF WTM 1825'N & 1486'W from SE corner Section 29, T9N, R13W, SM 99503 AP1 NL~iE~CAL CODE 50-133-20115 6 LE~kSE DESiGNAiION AND SERIAL NO ADL-17594 7 IF INDiIN, %L~DTTEE OR TRIBE NAME 8 L.'~'IT,F.~qA! OR LEASE NA-%IE Tradtn_e BaY Unit 9 WELL NO s~-~- G-11 (32-32) 10 Fr~Ln ~N'D P~L OR WI~C~T McArthur River - Hemlock i1 SEC, T, R, M I BO/'TOM HOLE O~~ Sec. 32, T9N, R13W, SM 12 P~IRIVIIT NO 68-43 13 REPORT TOTAL DEPTH AT END OF MONTH, CH.A.NGES IN HOLE SIZE, CASING AND CLWIENTING JOBS INCLUDING DEPTH SET A_NrD VOLU/V~S USED, PF. RFORATIONS, ~STS ~NrD I~ESULTS FISHING JOBS JI/NK LN HOLE ~D SIDE-/-FLACKED HOLE AND A-NY OTHER SIGNIFICANT CH.A~G~ IN HOLIi: CONDITIONS TRADING BAY UNIT STATE G-11. (32-32), JULY 1968 Ran 262 Jts 9-5/8" casing. Hung with shoe @ 10,835', DV @ 4128'. Cemented thru shoe w/1500 sx class "G" and thru DV w/1400 sx. Ran 327 Jts of 4-1/2" 12.6# N-80 buttress tubing. Hung with tail @ 10135' And Baker FI packer @ 10074'. Ran Schlumberger G-R Correlation log. Perforated 4-1/2" hpf: 10223-10270; 10290-10375'; 10395-10590'; 10610-10700' Well on production. RIG RELEASED 6:00 AM 7/3/68 RECEIVED DIVISION OF MINEs & MINERALS ANCHoP~GE 14 I hereby certffy.~th~r~ll%g is true and correct - //~/f //~.~/J Dist. Drilling Superintendent 8/5/68 SIGNED ....... /~,s~ ~ TITLE DA'i E , , K."l'rs '['.~-I i~ -- ~ ~ NOTE--Report on;hiS form is required for each calendar month, regardless of the status of operations, and must be filed m duplicate with the Division of ~ines & Minerals by the 15th of the succeeding month, unless otherwise d~rected Form P--7 STATE OF ALASKA SUBMIT IN DUP ,,'E* {See other ln- ~t ructloils Oil revez se side §0L133-20115 ~ ~LEA~E---D~Id~'~IOIq AI~,D SF--,PJ.A.L NO 'ADi,-17594 OIL AND GAS CONSERVATION COMMITTEE IIII II I m WELL cOMPLETION OR RECOMPLETION REPORT AND LOG* ii ,,. TYP-. oF W-.LL: o,.~ ,,. © " [] X% ELL WELL ' Dar Other IF ~, ~~ OR ~BE N~ b TYPE OF COMPL~ON: ~zw ~ wonx ~ DEZP-~ PL~ ~ m~, tt ELL OI ~a E~ nXCK ~ESVR Other 8. ~,F~ OR ~SE 2. S,=~ Or Oe,ai~oa , Trading, Bay Unit Union Oil C~y qf California 3. ~ei'ss om o,ze~a -: 'State G~l (32-32) 507 g. gorthe~ Lights* Blvd.. ~cho~a~e. ~a~ 99503 ~. ~c*~0s 0~ wgc~,{R~pori ]O~t~ cld~rl~ a~d ia accord~aoe with ~ay ~t~ requtreme~t~)* it.u~ace Conducto~ 21~ Leg'i~ i825'~ ~ 1486'~ from SE corner I~ ~god: 10223'~1 3896'S & 404'W fr~ surface location At trial ~p~ SeC. 32, T9N, R13W, SM Bo~C~ Hole: 10846'~; 4124"S & 485'W of surface location 5a9168 ~ [ 6/28/6S [,, 7}3/68 , R~ to ocean floor12~5.60, IRT to MiL 99 · ' ~ , [ ~ ~Y* ~ ROTARY TO0~ _~}~_ff~ __ ~ CABLE TOOLS ~ P~DU~i~G ~T~V~{~), ;OF ~S ~M~Z0~, ~~, N~E (~ ~D ~)* 1~ W~ DI~ON~ ' t " I I I SURVEY ~ADE H~ck: 1G12~10270 ~ (93~-9351 ~); 10395-10590 ~ (9~70-9637,D) Zone ~0290-103'75t~ (9372-9453'VD); ,10610-10700'~ (9655-9738 ~), {I Yes ~ ~E ~CT~C,~D OT~ ~S E~ ~:' Sc~lunbg~ger - DIL, Sonic ~ .Density, ~ ~ G~a ~y Correlation log. il) ;'7 16~ / ' 75~ 1.J~55. I ~ , 1300 sx "G" - [, I 2,00 .x Sx "[' - Nn.~ , 4-1/2" 1~13 10094 , . 28 pE~O~TIONS OP~ TO PRODU~ON (Inte~al, szze and~umbe~) 29 ACID, S~!OT, F~'~E, C~HENT SQUE~E, 10223-10270 ~-1/2" holes/fi 10610 10700 ; " " Ill m m m T 111 EDU~ON DATE,7 / 4~RST/6~ P~ODUC~ON , [ ~ODUC~ONF10~nsMETHOD (Flowu~g, ga~ hf~Ypumpmg--szze and type of p~p) P 714168 , t" 24 i196/64 s,~ 5219 ] 1237 ~ I' t~'a°Ua ~ ,[ . 2S5 ' ~00 ~T ~ 52!9 . 1[~ 1237 Fuel 10. rr~.~ A~D POOL, OH W~T McAxthur River - Hemlock 111 SlDC , T , R, M , (BOTTOM HOLE OBJECTIVE) ! 33 I hereby. ,certifY tha)~.~.~ ~for n ~ nd attached information is complete and correct as determined from all-available records SIGNED ' TITLE ,Dist, .... ~ Drilling SuperintendentvAT~: 7/12/68 ,,, B.E; Taller/' , -';' , , *(Se,9/Instructions and Spaces for Additional Data on Reverse Side) I WELL STATUS (Producing or ~,~,~t-,~,) Producing WATER-~BBL [ GAS-O~ ~O I t WA~B~ OIL GEAVITY-~ CC~.) J 37 34.2° ] TEST WITNESSED Robert Smith ,aMouwr ;U~D KINI)4)~- MATE~IAL USED INSTRUCTIONS General Th~s form is designed for subm~ttmng a complete and correct well completion report end log on all types of lands and leases in Alaska Item: 16: Indicate which elevation ~s used as reference (where not otherwise shown) for depth measure- mentsg~ven ~n ether spaces on th~s form and ~n any attachments _' Items 20, and 22:: If th~s well ~s completed for separate production from more than one ~nterval zone (multiple completion), so state ~n ~tem 20, and ~n ~teq) 22 show the prcduc~ng ~nterval, or ~ntervals, top(s), bottom(s) and name (s) (~f any) for only the ~nterval reported ~n ~tem 30 Submit a separate report (paoe) on th~s form, adequately ~dent~f~ed for each adcb(~onal ~nte~val to be separately produced, show- ,ng t,he aclld~t~onal data pertinent to such ~nterval It®m26: "Sacks Cement" Attached supplemental records for th~s well should show the details of any mul- tiple stage cementing and the location of the cementing ,tool Item 28: Submit a separate completion report on this form for each ~nterval to be separately produced (See ~nstruct~on for items 20 and 22 above) "34 -qUMMA}{Y OF~ F'OH. MATION TF2~'I'S IN( LUI)IN(, INTEFLV^L FESFEI) PI{ESS~]F~£ DATA A.N'D RF_~OVERIF~S OF OIL (]AS , '~5 GI~D, LOGIC WATFAX AND MUD i ii NAM~ MEAS D~-'PTM ~ None Hemlock 10223 ' ~ ,, ~ ( OIIE DA I'A Ag'I'A( Il IIIIIE~ D~SCItIPI~ONq C)F I I rTIOLC)GY POI1OSI'IY FllAC~II~ APP~NT DIP~ AND [)LIE, C'I'~I) ~IIOW5 OF' OIL G~S OIL WAIEI{ I II _ None ~.].ease Date ,,, 8-3-7o State of Alaska Department of Natural Resources DIVISION OF MINES AND MINERALS Petroleum Branch INDIVIDUAL WELL RECORD Sec. (29) 32 T. 9N R. 1'4I; Meridian . Permit No. 68-43 Issued 5-14-68 Cond. 21 Le~ 4 , .~_ Operator Union 0il Co. of Calif. Location (Surface)is/5, F_~_ ~ase No. ~L 1759~ or ~er.~ading Bay ~tt ~c. (Bot~m) 2300',,, .,~ _&,,,2000', ,, F~, Sec. 32 Well No. ~-11 (32-32) kea . Spud Date,. 5~29-68 __ Drilling ceased Suspended Abandoned Total Depth ~ Elevation 99' RT IP _ .5910 B/D, Gray 34..2 ._API Cut. Completed (F~q~ .... 7-3-68 __ Gas~ 12.3,] ~ _ MCF/D, Bean~ 196; /64 CP~ 1.00. _psi, TP.. ,2_55 ~ _psi Casing: Size ... 10 ,395 ' -590, ; !0 , .610 ' ~' 700 9 5/8"'40,43.5 GEOLOGIC FORMATIONS Surface Lowest Tested ,, ~emlock Name ' ' PRODU TIV aoRlzoss Contents Hemlock :~ ~ !0.223-10.700~ ,' Oil. Year Jan Feb Mar Apr WELL STATUS May ...... June July Aug Sept Oct Nov -Dec . . UNiC Oil CO. Of califo ia DRILLING RECORD SHEET PAGE NO. LEASE TRADING BAY UNIT STATEWELL NO. G-11 FIELD MC ARTHUR RIVER LOCATION Conductor 21, Grayling Platform, Leg 4, N1825', W1486' from S/E corner Section 29~ T9Nt R13Wt SM PERMIT NO. 68-43 SERIA/~ NO. ADL-17594 T.D. T.V.D. DEVIATION (B.H.L.) SPUD DATE 5/29/68 COMP. DATE 7/3/68 CONTRACTOR WODECO RIG NO. 55 TYPE UNIT . National 1320 UE DRILL PIPE DESCRIPTION 5" Hughes X hole ELEVATIONS: WATER DEPTH R.T. TO OCEAN FLOOR B.T. TO MLLW R.T. TO DRILL DECK R.T. TO PRODUCTI( 125.00 235.60 110.60 19.30 42.60 COMPANY ENGINEER APPROVED: BIT RECORD BIT JET DEPTH~T VERTICAL [] DATE DEPTH NO. SIZE MAKE TYP. E SIZE OUT FE~T HOURS ANN. DIRECTIONAL [] 5/29/68 374 1 15" Reed YT3A - 720 346 6-1/2 - - 30 374 HO1 22" ServccExpand - 720 346 8 30 72,0 1RR 15" Reed IYT3A - 990 270 4 Drill out cmt and shoe... 31 990 1RR 15" Reed '!YT3A 24 1486 766 6.-3/4 90 - Dynadrill 6/1/68 1486 2 15" HTC 0SC3A 16 1931 445 2-1/2 90 Pulled to .change BHA 1 1931 2Rl~ 15" HTC 0SC3A 16 2143 212 4 100 435 1 2143 3 15" HTC 0SC3A 16 3100 957 ill 100 435 2 3100 H02 18" Servcc Exp. Open 695 - iWould r~ot c]iose.}'0H w/60-80,0001/ draz. 2 3100 H03 18" " " " 2003 1306 i9 75 - One arm sheared 3 3100 }I04 18" " " " 2040 Re-reau,ed f~om 1077 to 2040 3 3100 H05 18" " " " 3098 1058 111-1/2 75 - _ 4 Ran 13-3/8" csg 5 3100 4RR 12-1/4" Reed ST1AG Open 3135 35 1 130 - Bit from G-9 ~/40 5 3135 5 " HTC 0SC3A 14 3703 568. 8 130 470 Drilling 12-1/4" hole 6 3703 6 " Smith )GHJ 14 4325 622 8 130 470 " " " 7 4325 7 " " " 14 4880 555 8 130 470 " " " 7 4880 8 " Globe SST3G 14 5366 486 1.1-1/2 130 470 " " " 8 5366 9 " " " 14 5790 424 9-1/2 130 470 " " " , 8 5790 10 -" - J Sm-ttS-0TH$ .... -14 - - 6110 320 11 130 470 " " 9 6~0 ~1 " " " 14 6412 302 9-1/2 130 470 " " " 10 64~2 12 " " " 14 66§2 280 8 130 470 " " " 10 6662 13 " " " 14 68~4 ,152 9 130 470 " " " - . 11 6814 14 " Sec. S4TGJ 14 7066 252 10-1/2 130 470 " " " - 1 2 7066 15 " HTC ODG 14 7225 159 9 1 30 470 " " " 12 7225 16 " Smith DCHJ 14 7453 228 7 130 470 " " " ~2 7453 17 " " " ],4 7668 215 7-1/2 130 4~0 " " " 1 q 7668 1 8 " 14TC ODC, 14 7814 146 9 130 460 " " " _ 14 7R14 19 " Smith DCH 14 8114 300 12-1/2 130 460 " " " 15 8114 20 " Smith DCH 8288 174 10-1/2 130 460 " " " 15 8~88 2]. " " " 8503 215 9 130 368 " " " 16 8503 22 " " " 8720 217 12 130 368 " " " 17 8720 2.3 " " " 3-16 8966 246 17 112 31~ " " " lg 8966 24 " Sam S4TG 3-16 9094 128 ~-1/2 112 315 " '" " ~8 9094 25 " " " 3-16 9256 162 11 112 315 " " " .. '19 925§ 2§ " " " 3-16 939.5 139 13 . 112 315 " " " 20 9395 27 " Smith DGHJ 3-16 9500 105 7 112 315 " " " 21 9500 28 " " " 3-16 9615 115 10 112 315 " " " 22 q615 29 " HTC ODV 3-16 9789 174 !4-1/2 1~2 315 " " " 22 9789 30 " " 0DG 3-16 9928 139 !_1-1/2 112 315 " " " 23 9928 31 " S~ th DGH3 3-16 10057 129 9-I/2 112 315 " " " 23 10057 32 " HTC ODV 3-16 l~155 98 il0 112 3].5 " " " 24 10155 33 " " " 3-16 10279 124 [16 !112 315 " " " - 27 10718 36 " " XDR 3-16 i10,79~ 77 8-1/2 112 315 " " 28 10795 37 " " ODV 3-16 108.46 51 8-1/2 112 315 " " 29 10846 37RR " " " Open Cond~ tion f or 9-5/ 8"- c~ sing. '7-1-68' 10846 38RR 8-1/2 Reed ST1AG Open Scrapper rum in 9- 5/8" asg. RR P58 from G-9 . , __ , UNIGJ OIL CO. OF CALIF IA MUD RECORD SHEET B PAGE NOi LEASE TRADING BAY UNIT STATE WELL NO. G-Il FIELD MC ARTHUR RIVER TYPE DISTRIBUTOR IMC ~ DEPTH ~EIGHT[ ¥ISC. W.L. PH SALT OIL SAND SOLIDS REMARKS 5-29-68i 600 82 42 5.4 8.3 500 6 1 15 31 900. 81 38 6.2 10.5 550 6 1 14 Drld. 60' cement - treated for sa,, 6-1-68 19,00 82 48 7.7 10 600 6 1/2 16 DYnadrillins 2 2937 83 45 5.2 9 600 5 1-1/2 16 3 3100 84 46 4.9 9 550 6 1 16 Openin§ .15" hole to 18". 4 3~00 82 45 4,3 9 600 6 3/4 15 Opng. hole and rng 13-3/8" csg. 6 3573 81 40 5,0 9.5 500 3 1 11 Drilling 12-1/4" hole 7 4684 79 50 4,2 9.6 550 3 3/4 11 " " " ~ 5366 79 40 4.0 9.3 500 2 1/2 10 " " " 9 6021 82 53 3.3 9.8 550 2 3/4 13 " " '" 10 6449 82 55 3.3 9.6 600 2 1/2 14 " " " 11 6814 82 50 3,0 , 9.4 450 2 1/2 13 " " " ]2 7165 80 50 3.0 9.3 450 2 1/2 13 " " " 13 7500 82 57 3.4 9.8 450 1/2 1 16 " " " 14 7810 R1 50 3.0 9.8 450 1/2 1 16 " " " 1 5 8200 81 53 ~.0 10 550 2 1 17 " " " ,. 16 8493 81 50 3; 0 10 500 2 1/2 15 " " " 17 8758 82 50 3.0 9.8 600 2 1 16 " " " 1 ~ q~A6 82 50 2.9 9.8 550 2 3/4 16 " " " ]9 q2~,2 82 58 2.8 9.6 500 2 3~/4 16 " " " 20 9&~ R'~_% &~ 2.6 9.5 500 1 314 17 " " " 21 q61 5 82 61 2.8 9.8 500 1 3/4 16 " " " 22 qR~O 82_ 5 59 2.9 9.7 500 Tr 3/4 17 " " " 2~ ~0035 81.5 57 2.6 9.8 550 -0- 3/4 16 " " " ii 2&. 1 ~1 5c, R1 59 2.4 9.6 500 -0- 1/2 16 " " " 25 1~q7_. R? ~2 2 .R q .7 500 -0- 1/2 17 " " " 26 1~4~2 82 50 3,0 9.4 500 -0- 1/4 15 " " " ?~- ' 1~qsq1 84 65 2.9 9.5 600 -0- 1-1/~ 21 " " " 28 !nTR~, R2 50 2:8 q. 5 550 -0- 3/4 16 " " " 29 1054& 82 50 2: q q _'5 500 -0- 1/2 16 Logging 30 !nRAk 81 5 AR 2.q q.4 550 -0- 1/2 16 Ran 9-5/8" csg. , . __ , · __ __ __ __ __ __ __ , LEASE UNION OiL CO. OF CaLiFORNiA · WELL RECORD i, · TRADING BAY UNIT STATE WELL NO. G-Ii FIELD McArthur River SHEET C PAGE NO., CASING & TUBING RECORD MIME WEIGHT THREAD GRADE DEPTH ltEMAltKS 16" 75 Butt & 8rd J-55 694 See Drill~no record for details 13-3/8" 61 Buttress J-55 3081 " ~" " 9-5/8" 47#, 43. 5 N-80 10835 " " " 40 Seal Lock P-110 4-1/2" 12.60 Buttress N-80 10135 " " " , PERFORATING RECORD J~ATE INT£1~VA.L £.T.D. I~EASON PRESENT COI~DITIOI~ -2-68 10610-10700 10790 Prod. -3-68 10395-10590 . , 10290-10375 10223-10270 · , INITIAL PRODUCTION 'PATE INTERVAL NET OIL CUT GRAV. C.P. T.P. CHOKE MCF GOR I REMARKS ~-4-68 10223-10700 5219 0.7% 34.2' 255# 196/64 1237 237 24 hr rate WELL HEAD ASSEMBLY TYPE: CASING HEAD: Shaffer K.D. 12" 900 Series x 13-3/8" S.O.W. CASING HANGER:. Shaffer 12" nominal - 9-5/8" Model KD. KS CASING SPOOL: TUBING HEAD: Cameron DC-B12 12" 3000# x 10" 5000# w/5000-"~ studded outlet TUBING HANGER: DC.-FBB 10" nominal 4-1/2" Buttress Bottom x 4-1/2" EUE top TUBING HEAD TOP: Single string solid block log type Cameron bottom flange to 5000# w/ 7" OD seal pocket MASTER VALVES: I II I Ill I UNION OIL CO. OF CALIFORNIA DRiLLiNG RECORD SHEET D PAGE NO.- LEASE Trading Bay Unit State W-ELL NO. G- 11 FIELD HcArthur River DATE 5-28-68 5-29-68 5-30-68 5-31-68 6-1-68 6-2-68 6-3-68 6-4-68 E. T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS · 720' 720 ' 1486' 2498' 3100' 3100' 3100' Started moving from G-10 @ 1700. Rigging up. Finished rigging up. Spudded at 0730.. Drilled 1S" hole to 720'. Opened hole to 22" to 660'. · Finished opening hole to 22" to 720'. Ran 17-3/4" mill to TD without difficulty. Ran 12" casing as follows: 16" Casing Detail Jts. 16" Baker Flexiflow Shoe -- 16" 75# JSS Buttress 15 X-over L6" 75# JSS 8RD X Butt. 16" 75# JSS 8RD 2 Landing Joint below RT 2.35' 694.44 692.09 598.89 692.09 93.20 21.44 93.20 71.76 56.36 71.76 15.40 15.40 15.40 0 17 694.44' Cemented above with 1300 sx. Class "G" cement w/2% CaC12. Bumped plug on baffle plate at 653' with 400 psi at 0830. W.O.C. Nippled up 20" hydril and picked up drilling assembly. Drilled out baffle plate, 60' cement & shoe. Drilled 1S" hole to 990'. Dyna drilled from 990' to 1486'. Drilled 15" hole from 1486' to 1931'. POH for drilling assembly change. Continued drilling to 2498'. Drilled 15" hole from 2498' to 3100'. RI w/Sowco 18" expandable hole opener. Opened hole to 695'. 18" hole opener would not close. Pulled out of hole w/60, to 80,000# drag. Opened 1S" hole to 18" from 695 to 1827'. Pulled for H.O. change found one arm sheared. Re-opened hole from 1077' to 1825'. Opened IS" hole to 18" from 1825' to 2830'. · Completed opening IS" hole to 18" to 3098'. Ran ~ cemented 73 its. 13- 3/8" 61# J-SS buttress csg. with shoe landed @ 3081'. Cemented k/900 sx. "G" cement with 10% gel, 1% CFR-2 and 2% CaC12 added; followed w/900 sx "G" neat cement ~ 600 sx. Class "G" with 2% C~CI~ added. Displaced with 721 cu. ft. and had cement returns to surface wxth only 1611 cut. ft. cement around shoe - Some 495 cu. ft.~less than the capacity of a perfect hole. Continued displacing with mud. Bumped plug with 1650 psi. Released pressure. Floats held O.K. ,C.I.P. 4'30 P.M. 6-4-68. W.O.C. Cut off 16" 13-3/8"/Casing Detail Jts. 13-3/8" HO;~CO float shoe · 13-3/8" 61# J-SS Buttress csg. 13-3/8" HOWCO diff. collar 13-3/8" 61# J-SS Buttress. csg. Landed below zero 2.03' 1 43.05 2.04 72 2996.65 57.00 3080.77 - 3078.74 3078.74 - 3035.69 3035.69 - 3033.65 3033.6S - 37.00 37.00 - -0- 73 3080.77' I! I I II I I I I UNION OIL CO. OF CALIFOrN'iA DRILLING RECORD II I I SHEET D PAGE NO LEASE Trading Bay Unit State I~ELL NO.. G- 11 FIELD. McArthur River DATE E. T. D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 6-5-68 6-6-68 Fo 6-27-68 6-28-68 6-29-68 6-30-68 7-1-68 7-2-68 3256' Installed & welded Shaffer K.D. head. Tested same with 3000 psi for 15 mins. - O.K. Nippled up B.O.E. & riser system. Tested blind rams with 1500 psi - 10 mins. - O.K. Ran into collar @ 3033'. Tested pipe rams ~ hydril with 1500 psi - 10 mins.' - O.K. Drilled out collar & shoe. Drilled 12-1/4" hole to 3135.'. P.O.H. Locked up drilling assembly. Drilled & surveyed 12-1/4" hole to 3256'. 10,741' Drilled & surveyed 12-1/4" hole from 3256' to 10,741'. 10,846' Drilled & surveyed 12-1/4" hole from 10,741' to 10,846'. Conditioned hole for electric logs. 10,846' Schlumberger ran DIL, Sonic, Density ~ HRD. 10,846' Completed Logging. Conditioned hole for casing. Ran ~ cemented 262 its. 9-5/8" csg. Shoe landed at 10,835'. Cemented through shoe with 1SO0 sx. CFR-2 mixed with fresh water. Bumped plug with 1850 psi. Released pressure. Floats held O.K. C.I.P. 11:45 P.M. 6-30-68 Opened D.V. collar with 800 psi. 10,846' Cemented through D.V. Collar with 1,000 sx. CFR-2 followed with 400 sx. Class "G" mixed with sea water. Closed D.V. collar with 2200 psi. ~.I~P~ 1:45 A.M. -7~1-68. Set 9-5/8" csg. slips with 170,000#. Cut off 9-5/8" csg. Installed Cameron tubing head. Tested pack-offs with 3000 psi - 15 mins. - O.K. Nippled up. Tested blind ~ pipe rams with 1500 psi - 10 mins. - O.K. Drilled out D.V. Collar, differential collar ~ cement to top of float collar @ 10,790'. Displaced mud with sea water & sea water with diesel (32,515 gals.j 9-5/8" Casing Detail Jts. 9-5/8" HOWCO float shoe 9-S/8" 47# P-110 Seal Lock Csg, 9-S/8" HOWCO Float Collar 9-S/8" 47# 'P-ll0 Seal Lock Csg, 9-5/8" HO$fCO Dill, Fill Collar 9-S/8" 47# P-110 Seal Lock Csg. 9-S/8" 47# N-80 Seal Lock Csg, 9-S/8" 43,5# N-80 Seal Lock Csg, 9-S/8" 40# N-80 Seal Lock Csg, 9-5/8" ttOWCO D,V, Collar 9-$/8" 40# N-80 Seal Lock Csg, 9-S/8" 47# N-80 Seal Lock Csg, Landed below zero 60 26 55 20 I 98 1 2.10 10,835.43 - 10,833.33 41.33 10,792.00 1.76 10,790.24 37.35 ' 10,752.89 2.09 10,750.80 2460.36 8,290.44 1081.72 7~208.72 2252.58 4,956.14 825.80 4,130.34 2.17 4,128.17 4051.48 76.69 39.69 57.00 37.00 -0- 262 10.,835.43' 10,790' Ran 327 jts. 4-1/2" 12.60# N-80 buttress tubing with Baker 9-5/8" Type F-1 Hydro Packer ~ 10 Otis CX' sleeves. (See tubing detail) Set pkr. with 1,000 psi - Sheared trip sub with 1800 psi. Pressure tested pkr. with 2,000 psi. Nippled down B.O.P.'s 5 riser system. Installed Cameron X-mas tree. Tested same. Rigged up Schlumberger ~ ran Gamma Ray correlation log. Commenced perforating. Perforated with Scallop 'guns with 4 shots/ft, from 10,610 to 10,700. UNION OiL CO. OF CaLiFOrNIa DRILLING RECORD SHEET D PAGE NO LEASE Trading Bay Unit State WELL NO G-11 FIELD. McArthur River DATE 7-2-68 7-3-68 E.T.D. DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 10,790 ' 10,790 ' Tubing Detail Jts, 4-1/2" Baker Trip Sub 4-1/2" 12.60# N-80 Butt. Tubing 4-1/2" Otis X-Nipple 9-S/8" Baker F-1 Hydro Pkr. 4-1/2" 12.60# N-80 Butt. Tbg. Otis CX Sleeve 4-1/2" 12.60# N-80 Butt. Tbg. Otis CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing CX Sleeve 4-1/2" 12.60# N-80 Butt. Tubing B.V. Nipple 4-1/2" 12.60# N-80 Butt. Tubing CI~ Tubing ttanger Landed Below Zero 1.42 10,134.74 - 10,133.32 1 29.06 10,104.26 1.S1 10,102.73 8.58 10,094.17 I 30.29 10,063.88 6.12 10,057.76 46 1410.94 8,646.82 6.12 8,640.70 13 396.56 8,244.14 6.12 8,238.02 13 401.14 7,836.88 6.12 7,830.76 12 367.67 7,463.09 6.12 7,456.97 18 534.19 6,902.78 6.12 6,896.66 24 735,53 6.161.13 6.12 6,155.01 32 985.35 5,169.66 6.12 5,163.54 40 1226.98 3,936.56 6.12 3,930.44 60 1835.80 2,094.64 6.12 2,088.52 58 1771.37 317.15 3.10 314.05 9 275.05 39.00 1.O0 38.00 38.00 -0- 327 10,134.74 Continued perforating from 10,395' to 10,590, 10,290 to 10,375 and 10,223 to 10,270'. Rigged down Schlumberger. Released rig @ 0600, 7-3-68. Total time spud to release, 34 days, 23 hrs. Form Do1001°A UNION OIL CO. OF CALIFORNIA REPAIR RECORI~~ SHEET A PAGE NO. LEASE TRADING BAY UNIT STATE wELL NO. G-Il CONTRACTOR Parker Drilling Co. FIELD McArthur River Field TYPE UNIT N~tfonnl_ !3_~0 EIJE BEGAN: 3/17/76 COMPLETED. 4/2/76 ELEVATIONS: GROUND PERMIT NO. §8-43 SERIAL NO. ADL-17594 CASING HEAD. COMPANY ENGinEER XS~atson/Wester AFE #361413 TUBING HEAD. · ~,~ APPROVED t>~,~,~ ~ ~/r_~_~,{/_~_/~_;_,,_~7~_ _,~ ROTARY DRIVE BUSHING ' ~" J~m 1<. Callender CASING ~ TUBING RECORD · SIZE DEPTH. . WEXGHT GRADE REMARKS 16" 694' 75# 3-55 Cmt'd. w/ 1300 sx. "G" w/ 2% CaC12 13 3/8 3081' 61# J-55 Cmt'd. w/ 2400 sx. "G" w/ CaC12 9 5/8" 10,835' 47# N-80 Cmt'd w/ 2500 sx CFR-2 & 400 sx. "G". 7" 6900' 29# N-80 7" Csg. patch - Top @ 6640'. 4 1/2" 6379' 12.6# N-80 3 1/2" 3619' 9.2# N-80 Single String Producer PERFORATING RECORD -~ATE INTERVAL E.T.D. REASON PRESENT CONDITION 7/2/68 10,610-10,703 10,790' Production Bench #5 - Open for production. 7/3/68 10,395-10,593 " " Bench #4 - Open for production. 7/3/68 10,290-10,375 " " Bench #3 - Open for production. 7/3/68 10,223-10,273 " " Bench #3 - Open for production. 4/16/76 10,575-10,553 10,655' Production Bench #4 - Open for production. 4/16/76 10,520-10,460 " " Bench #4 - Open for production. 4/16/76 10,436-10,395 " " Bench #3 - Open for production. 4/16/76 10,260-10,230 " " Bench #3 - Open for production. INITIAL PROE DATE INTERVAL NET OIL CUT GRAV. C.P. T.P. CHOKE MCF GOR REMARKS 4/7/76 Hemlock 1524 1.0% 34.2° 620 100 196 688 4/8/76 Hemlock 1425 0.1% 34.3° 820 300 48 1101 772 Restricted product 4/9/76 Hemlock 1518 1.4% 34.4° 880 300 48 403 594 to increase flowin 4/13/76 Hemlock 1651 1.0% 34.0° 900 300 48 591 358 btm. hole' press. WELL HISTORY p]RIOR TO REPAIR COMPLETION DATE: 7/3/68 LAST COMPLETION NO.. 1 PRODUCING INTERVAL: Hemlock INITIAL PRODUCTION: July 68 LAST REGULAR PROD. & DATE: 3/5/76 3548/3448 3177/2821 CUMULATIVE PRODUCTION: 9,503.917 bbls oil REASON FOR REPAIR. Repair damaged 9 5/8" csg. @ 6767' MD. Form D-IO01-S UNION OIL CO. OF C/~LIFORNIA REPAIR RECOR~ SHEET B PAGE NO LEASE TRADING BAY UNIT STATE COMPLETION DATE: DATE 4/2/76 TYPE: Shaffer / Cam er on WELL NO. G-Il FIELD McARTHUR RIVER FIELD APPROVED Jim R. Callender DETAILS OF OPERATIONSf DESCRIPTIONS 8[ RESULTS ~lr~T.T. ~-]~A.D ASSEMBLY CASING HEAD:. Shaffer KD 12" 900 Series X 13 3/8" SOW CASING HANGER: CASING SPOOL:, TUBING HEAD: Shaffer 12" Nominal 9 5/8" Model KD KS Cameron DC-B12 12" 3000# X 10" 5000# w/ 5000# studded outlet DC-FBB 10" nominal 4 1/2" Butt. Btm. X 4 1/2" EUE top. TUBING HANGER: TUBING HEAD TOP' Single string solid block log type Cameron Btm. Flange to 5000# w/ 7" OD seal pocket. MASTER VALVES: CHRISTMAS TREE TOP CONN.:,, 4 1/2" EUE tlffl 0IL COHPNN CF CAL! '"NIA }FN_L I _C0RD TRADING BAY UNIT STATE N0, , -11 (wo) FIELD McARTHUR RIVER FIELD DATE ETD DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 1 3/17/76 2 3/18/76 3 3/19/76 4 3/20/76 5 3/21/76 6 3/22/76 7 3/23/76 10,846'TD 10,790'ETD FC 10,846'TD 6171'ETD tbg. fish 10,846'TD 6295'ETD top of fish 10,846'TD 10,104'ETD top of fish 10,846'TD 10,104'ETD top of fish 10,846'TD 10,371'TD top of fish 10,846'TD 10,582'ETD top of fish Mxxed 72#/cu. ft. Drxl-S NaC1 W@ flmd. Pulled gas hft valves & opened cxrc. sleeve @ 10,056'. Well press, recorded @ 2400 pst on tl & 2425 psi on csg. D~spl. tbg. w/ W@ flmd. Unable to get returns ~ csg. annulus. Productmn perfs, from 10,223'-10,700' takmg flmd. Set 4 1/2" Baker bmdge plug & tbg. @ 10,122' below 9 5/8" Baker Model F-1 Hyd. pkr. @ 10,091'. Press. tbg. to 1700 ps~ & bled csg. press, to 1100 pst, bridge & csg. annulus broke loose & estabhshed circ. Circ. gas out of csg. annulus & killed well w/ 72# W@ fluid. (Footage 0') Commenced W@ operatxons on TBUS G-il W@ @ 12:01 ar 3/17/76. Installed BPV in tbg. hgr. Removed x-mas tree. Installe¢ BOPE. (Footage 0') Completed xnstalling BOPE & tested to UOCO specs. PU 4 1/2" tbg. & worked Cameron "DCB" hgt. free-tbg, stuck. RU Go-Int'l. & ran tbg. free pt. indicator. Tbg. 100% free @ 6214'- 100% stuck @ 6490'. Ran tbg. cutter & cut tbg. @ 6171'. (10' below btm. of CX Mandrel 6155'-6161'). Circ. btms. up. Pooh layxng dwn 4 1/2" tbg. (Footage 0') Changed pipe rams to 5" & tested to UOCO specz. Ran OS w/ Hallow mill control & 4 1/2" grapple p~cking up 5" DP. Tagg. up on top of fish @ 6284'. (Note; top of fish was left @ 6171' tbg. meas.-fish moved dwn. hole 113' Est. top of pkr. to be @ 10,207' tbg. ta~l @ 10,248'). Engaged fish @ 6284' w/ OS. RU Go-Int'l. Logged top of fish @ 6295'WLM. Unable to get circ. gun below perf. tbg. @ 10,096'-10,109' & had ~ndlcat~on of fill getttng above gun & trying to stick. Pooh w/ cxrc. gun. Worked fish w/ 160 M over string weight, unable to work fish free. (Footage 0') RU Dialog & ran free pt. Tbg. free to top of fill in tb1 @ 10,105'TM. Cut off 4 1/2" tbg. @ 10,104'TM (6' below pert. tbg.) Circ. btms. up. Recovered sand & gas cut W@ flmd. Pooh & lard dwr 4 1/2" tbg. (top of fish @ 10,104', hsh left ~n hole 144'). Ran 8 1/2 ~mpress~on block in hole. Tagged up @ 6767'. Pooh. Had ~mpresst( of collapsed or swedged ~n csg. (Footage 0') Ran 4 3/4" X 7 3/8" tapered mxll. Dressed out 9 5/8" csg. from 6767', rough mxlhng to 6774' & mill fell free. Backreamed ok. CO to 6794'. Circ. out metal cutttngs. Pooh. PU 8 1/2" OD watermelon mill above 7 3/8" OD tapered m~ll. (Footage 0') RIH w/ 7 3/8" OD tapered mill & 8 1/2" OD ~atermelon mill xn tandem. Dressed out 9 5/8" csg. to 8 1/2" from 6707'-6774'. Worked thru sand bmdge from 8039'-8047'. Cont. RIH w/ mtlls. Ta[ ged top of fish @ 10,294' Fish moved dwn. hole to 10,371'. C~rc. btms. up. Pooh. PU 8 1/8" W@ p~pe. (Footage 0') RIH w/ 8 1/2" OD wash p~pe to 10,371' Tagged f~sh. Fish moved dwn. hole. Washed from 10,371'-10,646' t:~sh ~topp~.d @ 10,646'. Unable to tell ~f on top of fish or on top of pkr. C~rc. h~-v~s, p~ll to clean hole. Pooh w/ W@ ptpe. RIIt w/ OS ~/hollow mtll control & 4 1/2" grapple. Tagged top of fish @ 10,582'. (moas. indtcated that wash p~pe stopped on top of pkr. w/ ~vash p,pe). Engaged fish w/ OS. Unable to jar free. Released ()S & Ih~()}~. RIII I tION 0IL CfftPANY OF CALI PRNIA ;ELL I CORD LEASE TRADING BAY UNIT STATE ~'~ll N0. G-11 (wO) FIELD McARTHUR RIVER FIELD DATE ETD DETAILS OF OPERATIONS, DESCRIPTICfflS & RESULTS 8 3/24/76 9 3/25/76 10 3/26/76 11 3/27/76 10,846'TD 10,582'ETD top of fish 10,846'TD 10,582'ETD top of fish 10,846'TD 10,655'ETD top of hsh 10,846'TD 10,655'ETD top of fish w/8 1/2" OD WO pipe. Worked over top of fish @ 10,582' (top of pkr.) Circ. hole clean. (Footage 0') C~rc. hole clean on top of Baker 9 5/8" hyd. pkr. @ 10,688'. Pooh w/ W@ pipe. RIH w/ 7 5/8" OS w/ 8 1/2" grapple. Engaged fish @ 10,582'-unable to jar free. Released OS. Pooh. RU' Schl. Ran CBL-VDL-GR Log from 8000'-2500'. Had good cmt. from btm. stage of pmmary job up to 7550'. Ratty cmt. to 7420'. No cmt. above 7420'. CBL showed csg. collapsed from 6761 1/2' to 6767'DIL meas. DIL Log showed an@really from 6761'-6767' Reporter to be Bentonite bed. (Note: DIL meas. 6' high to DP meas.) Had good bondxng from top stage pmmary job from 4200'-2800'. (Note: DV stage cmt. tool @ 4128'). Ran CNL-GR-CL Log from 9400'. (Footage 0') Ran CNL-GR Log from 9400'-3500' RIH w/ 7 5/8" OS w/ 4 1/2" grapple & engaged top of hsh @ 10,582'. RU Go-Int'l. R.IH w/ 4 1/2" DP cutter ( 3 7/16"OD) Unable to work cutter thru 5" S-135 DP tool jts. RD Go-Int'l. Released OS. Pooh. PU Dialog circ. sub. RIH & engaged hsh @ 10,582'. RIH w/ WL spud bar. Worked thru fill bridge @ top of fish @ 10,582'. CO to 10,647'. Pooh w/ WL wash dwn. tool. Washed dwn. from 10,647'-10,651'. Unable to wash inside fish dwn. below 10,651' Pooh w/ wash dwn. tool. (Footage 0') Backed off fish & Pooh. Rec. cut off piece 4 1/2" tbg. plus 2 jts. 4 1/2" tbg. & top sectmn of "CX" Mandrel. Left 74' of fish in hole. Top of hsh @ 10,655'. Fish left m hole: Top of fish @ 10,655'DPM Btm. section of Otis "CX" Mandrel - 2.83' *See drawing ~n ProJect F~le. 1 - jt. 4 1/2" 12.6# Buttress Tbg. - 30.29' 1 - 9 5/8" Baker Model F-1 Hydro pkr. - 8.58' 1 - 4 1/2" Otis "X" Nipple- 1.51' 1 - Jr. 4 1/2" 12.6# Buttress Tbg. - 29.06' 1 - 4 1/2" Baker Trip Sub. - 1.42' Btm. of fish @ 10,729'DPM Note: DPM are 6' low to DIL meas. - top of hsh @ 10,649'DIL meas. (Bench #5 perfs, from 10,610'-10,700'). Ran @EDP to 7401' (47# 9 5/8" csg. 07209') & set cmt. plug v~ ' 73 sx. Class "G" cmt. w/ .75%D-31, .6%D-9 & .1%D-6 w/ 10%sand. Dlspl. cmt. w/ 72# W@ fluid. CIP @ 12:00 Noon. Pulled @EDP to 6600' & rev. circ. WOC. (Footage 0') Total WOC t~me - 12 hrs. Ran @EDP to 731-1'-no ~n¢llca- t~on of cmt. circ. out. Had sand in W@ iluid but no po.',ltl,.e ~nrllca- tlon of cmt. }tung off @EDP @ 7401' & set second plug Class "G" cmt-.75% D-31, .6% D-9, .1% D-6 & 10% sand w~ 1. CaC12 m mixing II20. CIP (ri 5:00 am. Pulled OEI)P to 6hh0' rev. c~rc. WOC 4 hrs. Pooh. PU 8 1/2" bit & Till to '~86'. No UNI0 i 0IL Cff'PANY OF CAL[r- ;IA 'ELL IE. CORD LE/GE TRADINC BAY UNIT STATE I' LL NO, (wo) FIELD McARTI-IUR RIVER FIELD DATE ETD DETAILS OF OPERATIONS, DESCRIPTIO[IS & RESULTS 12 3/28/?6 13 3/29/76 14 3/30/76 15 3/31/76 16 4/1/76 17, 4/2/76 10,846'TD 7274'ETD Est. cmt. on top of ret. !0,846'TD 7300'ETD Cmt.Plug 10,846'TD 10,655'ETD top of fish 10,846'TD 10,655'ETD top of fish 10,846'TD 10,655'ETD top of fish 10,846'TD 10,655'ETD top of fish indication of cmt. after 8 hrs. from CIP. Circ. out. Rec. approx- imately 20 bbls of Mud contaminated green cmt. Note: BJ lab test showed 2 hrs. 50 m~ns. set time on cmt. sample from Jig. Slurry samples caught dqmng cement mixing o: both plugs never set up on surface. Washed dxvn. & CO 9 5/8" csg. to 10,184'-circ. & cond. W@ fluid. Rec. green cmt. globs m W@ fluid. Cmt. not set after +36 hrs. Cmt. ~s not greatly effecting W@ flmd properties other t~'an Ph. & increased CA++. (Footage 0') Ran in &taggedtop ofhsh @10,655'. Circ. btms. up. Rec. traces of green cmt. Pooh. RU Go-Int'l. Ran 8 1/2" gauge ring & junk basket. Unable to work thru bad csg. @ 6773'. RD Go-Int'l. Ran 9 5/8" Howco EZ drill cmt. ret. on DP & set @ 7412'. Laid 50 sx. of Class "G" cmt. on top of ret. Pooh. Ran Baker 9 5/8" squeeze tool & set @ 6473'. Test annulus to 2000 psi & surface lines to 4500 psi. (Footage 0') Set Baker 9 5/8" squeeze tool @ 6473' to squeeze off damaged csg. @ 6767' to 6774'. Broke dwn. fro. @ 1500 ps~. PI 20 cfm @ 1550 psi. Fm. held 600 psi w/ pumps off. M~xed 650 sx. cml Class "G" w/ .75% D-31 to ll5#/cu, ft. Squeezed 650 sx. below tool w/a final pumping rate of 8 cfm @ 2500 psi. Squeeze job held 2050 psi w/pumps off. WOC. Pooh w/ 9 5/8" squeeze tool. TIH w/ 8 1/2" bit. Tagged top of cmt. @ 6726'. CO firm. cmt. to 6772' & ratty cmt. to 6800'. CO & dressed off cmt. plug to 7300'. Circ. & cond. mud. Pooh. RU Go-Int'l. (Footage 0') Ran Go-Int'l. CBL Log from ETD, cmt. plug @ 7300' to 4000' to check cmt. backing from sqz. on collapsed csg. @ 6767-6774 Had fair cmt. from 7300'-6800' & good cmt. from 6800'-4650'. RD WI_ unit. Ran 7 3/8" tapered m~ll in tandem w/ 8 3/8' watermelon m~ll. Dressed out csg. from 6767'-6774'-ok. Pooh. Reran 7 3~8" tapered mlll~n tandem w/ 8 3/8" watermelon mill in tandem xx ~ 8 1'2 +water- melon m~ll. Redressed csg. @6767'-6774'. Pooh. Ran 8 1 2 bit. CO cmt. from 7300' to Howco cmt. ret. @7412'. Dmlled cmt. ret. & CO to top of fish @ 10,655' Circ. btms. up. (Footage 0') Circ. & cond. W@ flmd. Pooh. RU Go-Int'l. RIH w/ gauge rang (8.45"OD) & junk basket. Tools stopped @ 7310'. Pooh- rec. rubber from cmt. ret. Ran gauge ring (8.125"OD) to 10,200'. Ran & set Baker 9 5/8" X 4 3/4" .Model "D" (8.125"OD) pkr. @ 10,120'. Ran Baker 9 5/8" X 7 1/2' Model FA pkr. (8.438 OD) 0 6900'~ PU Baker 7 1/2" X 6" seal assy. & 6 jts. of 7" 20~ N-SO Buttress csg. on Baker 9 5/8" X 7 1/2" Model FA pkr. (Footage 0') Rill w/ 9 5/8" X 7 1/2" Baker Model "FA" pi<:', x~,' 7" 2955 N-80 csg. stinger on btm. Stabbed into Baker 9 5'8 X 7 1/~ FA pkr. @ 6900' & set top Baker FA pkr. @ 6640'. Pooh x~ ,settling tool. RU to run 4 1/2" X 3 1/2" gas lift production str~ng. (Footage 0') Ran 4 1/2" X 3 1/2" proctuct~on string '~/ Camco pocket gas l~ft valves as programed. Stab})ect into Bakt'~ '~ ;'g' 4 3/4" Model "D" pkr. (si 10,120'DII, (10,127' tbg. w/ 500 ps~-ok. Spaced out & landed tbg. lnsh~llc(t ( OIL Cff / IY OF LII II^ I', LL I CORD LEASE TRADING BAY UNIT STATE~.~LL []0, G-11 (WO) FIELD McARTHUR RIVER FIELD DATE Ell) DETAILS OF OPEPATIONSo DESCRIPTIO~IS g RESULTS 18 4/6/76 4/7/76 10,846'TD 10,655'ETD top of fish 10,846'TD 10,655'ETD top of fish unit. Opened "CA" sleeve @ 10,090'. Dlspl. 72#'cu. ft. Drfl-S WO flmd w/ ~nh~bited filtered Inlet wtr. Closed "XA' sleeve ~ 10,090'., Placed well on gas hft. Released R~g -~55 @ 12'00 .M~dmte, 4/2/76. Commenced deactivation on R'~g #55 & activation of R~g #54 over Leg Room #3. Gas hftmg well & prep. to test. (Footage 0')) RU Schl. & reperf, the folloxwng Hemlock Benches. BENCH INTERVALS FOOTAGE #4 10,575'-10,550' 25' 10,520'-10,460' 60' #3 10,436'- 10,396' 40' 10,260'-10,230' 30' Completed reper£. RD Schl. (Footage 0') Production Test 4/7/76: Avg. Rate: GROSS CUT NET INJ.GAS FM. GAS GOR GLR GRAVITY 1728 0.8% 1714 2042 977 570 1747 33.7~ TBG. PRESS. CSG. PRESS. 100 600 Ran Gas Lift Survey & found well to be hftxng otf btm. GL valve @ 10,060'+. BHP=940 psi. AVG. Rate: GROSS CUT NET INJ.GAS FM.GAS GOR GLR GRAVITY 1824 0.1% 1822 'i'967-" 1051 576 1~54 34 0° TBG. PRESS. CSG. PRESS. 130 620 LEASE ( UNIO~i OIL CO'~A~h' CF CALIFUI~IlA ¥,~J.L IECORD TRADING BAY UNIT STATE I'~ELL N0, G-Il (wo) PAGE No, FIELD McARTHUR RIVER FIELD DATE ETD DETAILS OF OPERATIONS, DESCRIPTI~IS & RESULTS JTS. 7" CASING PATCH DETAIL DESCRIPTION LENGTH BOTTO.ki 9 5/8" X 7 1/2" Baker "FA" Pkr. 2.55 7" 29# N-80 Butt. Csg. 253.97 7 1/2" X 6" Seal Assy. 1.35 9 5/8" X 7 1/2" Baker "FA" Pkr. 3.05 TOTAL 260.92 6901.28 6898.73 6644.76 6643.41 TOP 6898.73 6644.76 6643.41 6640.36 LE E UNION OIL COHPAI'iY CALI)%,dlA I;FJ.L i CORD TRADING BAY UNIT STATE I'~LL [~), G-Il PAGE Ih, 8 FIELD McARTHUR RIVER FIELD D~TE ETD DETAILS OF OPERATIONS, DESCRIPTI~IS & RESULTS JTS. 11 11 11 11 11 2O 33 35 51 600 54 · DESCRIPTION TUBING DETAIL Baker Mule Shoe 4.125"OD 2.992"ID Otis 3 1/2" Q N~pple 3.75"OD, 2.625"ID 3 1/2" 9.2# N-80 Tbg. Baker seal assy 190-47 4.75OD 3 ID Baker locator sub 4.875 OD 3 ID 3 1/2" 9.2# N-80 Tbg. Otis 3 1/2" XA sleeve 4.28"OD 2.75"ID 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #1 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #2 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #3 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #4 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #5 3 1/2" 9.2# N-80 Tbg. Camco 3 1/2" KBUG #6 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #7 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #8 3 1/2" 9.2# N-80 Butt. Tbg. Camco 3 1/2" KBUG #9 3 1/2" 9.2# N-80 Butt. Tbg. 3 1/2" X 4 1/2" Box-Pm X-over 5.25"OD, 2.992"ID. 4 1/2" 12.6# N-80 Butt. Tbg. Camco 4 1/2" ~{MG Mandrel Butt. #10 4 1/2" 12.6# N-80 Butt. Tbg. Camco 4 1/2" MMG .Mandrel #11 8rd X Butt. 4 1/2" 12.6# N-80 Butt. Tbg. Camco 4 1/2" MMG Mandrel #12 8rd X Butt. 4 1/2" 12.6# N-80 Butt. Tbg. Camco 4 1/2" MMG Mandrel #13 8rd X Butt. 4 1/2" 12.6# N-80 Butt. Tbg. Otto 4 1/2" ball valve mandrel 4 1/2" 12.6# N-80 Butt. Tbg. 4 1/2" 12.6# Butt. N-80 Pup 4 1/2" 12.6# N-80 Butt. Pup Carnet-on Tbg. Hgt. Elevation LENGTH BOTTOM TOP .72 1.70 28.70 20.30 1.03 31.10 4.20 31.10 6.54 58.02 6.54 242.39 6.54 330.45 6 54 330 21 6 54 324 69 6 54 330 32 6 54 331 25 6 54 596.05 6.54 984.76 10,178 10,177 10,176 10,147 10,127 10,125 10,094 10,090 10,059 10,053 9,995 02 9,988 48 9,746 09 9,439 55 9,409 ]0 9,402 56 9,072 35 9,065 81 8,741 12 8,734.58 8,404.26 8,397.72 8,066.47 8,05o.93 7,463.88 7,457.34 43 10 177.7] 71 10 176.0] O1 10 147.31 31 10 127.01 O1 10 125.96 98 10 094.86 88 10 090.66 68 10 059 56 58 10,053 04 04 9,995 O~ 9,988 46 9,746 0c, 9,739 5_~ 9,409 1£ q, 402 5( 9,072 3~ 9,065 81 8,741 12 8,734 58 8,404 2~ 8 397 72 8 066 47 8 059 9~ 7 463 88 7 457 34 6 472 58 30 8 1076 .60 .95 .45 .84 6,472.58 6,471.98 6,471.98 6,441.03 6,441.03 6,432.58 6,432.58 5,355.74 10.05 1584.83 5,355.74 5,345.69 5,345.6~ 3,760.86 10.05 1853.70 3,760.86 3,750.81 3,753.70 1,897.11 10 1656 3 175 6 5 1 38 05 I ,8o7.1 I I ,887.06 58 1,887 0, 230.48 07 230 a8 227.41 79 227.41 51.62 06 51.t,2 45.56 94 45 ~h 3'). 62 00 ~,o. h2 38.62 62 38. (,2 0- 121 Total Its. ot 3 1/2" 9.2# N-80 Tbg. But(,ess 13 3/8" 61# @ 3081' 9 5/8" X 7 1/2" Baker "FA" Pkr. @ 6640' 6jts. 7" 29# N-80 Csg. 9 5/8" X 7 1/2" Baker "FA" Pk~. @ 690C 9 5/8" 47# @ 10,835' Collapsed 9 5/8" Csg. L . 1,.. 11 i iii i ! i i I i i i i il i .11 . . = ..... i i ii ii i i L I I ItE~. DA~E . DL~kWN. CICa. =_._._.._._ , TRADING BAY UNIT STATE G-Il (WO) ' -- 7" CSG. PATCH DETAIL , ................. '" ' 1.1 i UNION OIL COMPANY OF CALIFORNIA "Z_., ..... _" '.-']', , ,, ,, . ..... - -mt,i~, i,,,~,, 10. . Otis 4 1/2" ball valve mandrel @ 227.41'. · Camco 4 1/2" MMG Mandrel @ 1887· 06' · Camco 4 1/2" MMO Mandrel @. 3750.81'. · Camco 4 1/2" MMG Mandrel @ 5345.69'. , · Camco 4 1/2" MMG Mandrel @ · 6432.58'. .. 3 1/2" X 4 1/2" Box-Pin X-over 5.25"OD X 2.992"ID @ 6471.98'. · Camco 3 1/2" KBUG gas lift Mandrel @ 7457.34'. · Camco 3 1/2" KBUG gas lift Mandrel @ 8059.93'. · Camco 3 1/2" KBUG gas lift Mandrel @ 8397.72'. 0. Camco 3 1/2" KBUG gas lift Mandrel @ 8734.58'. 1. Camco 3 1/2" KBUG gas lift Mandrel @ 9065.81'. 2. Camco 3 1/2" KBUG gas lift Mandrel @ 9402.56'. 3. Camco 3 1/2" KBUG gas lift Mandrel @ 9739.55'. ~. Camco 3 1/2" KBUG gas lift Mandrel @ 9988.48'. 5. Camco 3 1/2" KBUG gas lift mandrel @ 10,053.04'. 6. 3 1/2" Otis 'JXA" sleeve 4.28"OD X 2.75"ID @ 10,090.68'. 7. Baker locator sub 4. 875 "OD X 3"ID w/ seal assy. 190-47 OD-4.75", ID-3" @ 10,125.98'. 8. 3 1/2" Otis Q nipple 3.75"OD X 2.625"ID @ 10,176.01'. 9. Baker mule shoe 4.125"OD X 2'992" ID @ 10,177.71'. L o Total its. 3 1/2" 9.2# N-80 Butt. Tbg. - 121 jts. Total its. 4 1/2" 12.6# N-80 Butt. Tbg. - 207 its. DATE .t 241 |NLW ", bb~ TRADING BAY UNIT STATE G-Il (WO) WELL COMPLETION SCHEMATIC Started 3/17/76 Completed 4/2/76 UNION OIL COMPANY OF CALIFORNIA D~WI,I Aff'D. SC. ALE ~ATi: CKD. SH£LI$ I ~H[[I JOB NO ..... REPORT and PLAN RECEIVED AUG 5 1968 DIVISION OF MINF~ & MINEI?,AL~ ,ANCHORAGE of SUB-SURFACE SURVEY UNION OIL COMPANY T.B.U. G-II COOK INLET, ALASKA JUNE 1968 DRILLING CONTROL CORPORATION LONG BEACH, CALIFORNIA DRILLING CONTROL CORP. SHeeT NO.. i ,. flUKVZY DATA COMPANY Union Oil Crappy DATE,, Jtme 1968 Jos NO., WELL. T,~.U. G-Ii FIELD Cook Inle% COUNTY .... STATE Alaska TRUE RECTANGULAR COORDINATES MEASURED DRIFT DEVIATION DRIFT VER~CAL REMARKS DEPTH ANGLE COURSE DIRF~ON DEPTH NORTH SOUTH EAST WEST 374 374 00 ~SSU~ D V~R~ICAL 5]8 0° 00' 518 00 7?0 0° !5' 720 00 89 S 40° E 68 57 9q0 0° 30' 990 00 2 35 S 83° E 96 2 91 10q7 ]o 30' 1036 99 1 23 S 45° E 1 83 3 7S 1162 2° 30' 1161 96 5 45 S 19° W 6 99 2 00 1223 4° 00' ].222 71 4 26 S 25° W 10 86 2~ ]254 5° 00' 1253 59 2 70 S 34° W 13 ]0 I 31 ]317 6° 30' 1316 19 7 13 S 25° W 19 56 ~ 37 1412 9° 00' 1410 02 14 86 S 12° W 34 09 7 41 15~9 ]3° 30' 1582 13 41 32 S 03~ W 75 35 9 5~ 1931 26° 30' 1888 19 152 60 S 05° W 227 37 22 2060 28° 30' 2001 56 61 56 S 05~ W 288 70 28 25 2]43 28° 00' 2074 84 38 )7 S 06~ W 327 45 32 32 249~ 26° 45' 2391 85 159 79 S 03° W 487 02 40 68 3100 24° 00' 2941 78 244 83 S 04° W 731 26 57 77 3238 24° 15' 3067 61 56 68 S 04° W 787 80 61 73 3425 24° 45' -3237 43 78 29 S 03° W 865 98 65 83 3703 24° 00t 3491 39 113 07 S 04° W 978 7S 73 72 4022 23° 45' 3783 37 128 48 S 01° W 1107 24 75 96 4325 , 24° 00' 4060 17 123 23 S 03~ W 1230 30 8~ 40 4508 25° 00' 4226 02 77 34 SOUTH 1307 64 82 4817 28° 15' 4498 22 146 25 SOUTH 1453 89 ~2 40 4880 29° 30~' 4553 05 31 D2 S 01~ W 1484 90 82 94 5178 30S 00~ 4811 02 149 )0 S 02~ E 1633 81 77 74 , , ,, DRILLING CONTROL CORP. 6HEET NO ..... 2 flU~VEY DATA BHEET COMPANY ., Union Oil Cc~, ~ny DATE ~me 196~ JOB NO .... WELL m.~.lT. C-] 1 FIELD Cook Inlet COUNTY ....... STATE ~lask.~ ,, .... TRUE I~TANGULAfl COORDINATES MEASURED DRIFT DEVIATION DRIFT VERTICAL REMARKS DEPTH ANGLE COURSE DI~ON DEPTH NORTH SOUTH EAST V~T -- ~"' 53~6 30° 0~' 4973 83 94 00 SOUTH 1727 81 77 74 5522 30° h0' 5]09 03 78 00 S 03° E 1805 70 73 66 5790 -~° 15' 5340 53 135 02 SOUT~ 1940 72 73 66 ~1]_0 3~° 15~ 5616 95 161 22 S 01° W 2101 90 76 47 6412 29° 45' 5879 15 149 85 S 02° W 2251 66 81 70 6662 29° 00' 6097 80 121 20 S 02° W 2372 79 85 93 6814 29° h0' 6230 74 73 69 S 03° W 2446 38 89 78 7066 28° 00' 6453 23 118 31 S 05° W 2564 24 ]00 ~0 7225 27° 15' 5594 58 72 80 S 06° W 2636 65 107 7] '~53 27° 0~' 5797 73 103 51 S 08° W 2739116 122 12 7~9 26° ~' ~99~ 97 94 26 S 09° W 2832 26 ]36 ~6 7~14 ~5o 45' 7122 47 63 42 S 10° W 2894 7]. 147 ~7 qt14 2~ 00' 7396 52 ]_22 01 S 11° W 3014 48 ]71 ~5 ~288 25° 00' 7554 22 73 53 $ 10° W 3086 89 183 92 %., ~503 ?7° ~5' 77~4 49 100 10 S 14° W 3184:02 208 13 S720 27° 45' 7936 53 101 S4 S 14° W 3282 06 232 57 8966 26° 00' ~157 63 107 85 S 14° W 3386 70 258 66 9094 ~6° 00' '8272 68 56 11 S 14° W 3441 15 272 24 9256 25° 00' 8419 50 68 46 S 16° W 3506 96 291 11 9396 23° 0~' 8548 37 54 70 S 17° W 3559 27 307 10 9500 · ~4° 45' 8642 81 43 54 S 16° W 3601 12 319 10 I 9789 ~4° i5' 8905 68 71 46 S 15° W 3717 08 350 9928 25° 30' 9031 14 59 84 S 17° W 3774 30 367 68 10,~57 26° 00' 9147 09 56 55 S 17° W 3828 38 384 21 · , .... DRILLING CONTROL CORP. S~EET NO., ~ , BUItVEY DATA BHEET COMPANY Union Oil Comp, any DATE .... J,~.u~e 1968 Jos NO .... WELl T.B.U. G-11 FIELD.. Cook Inlet COUNTY STATE, A~_pska_ .... , , ~ ~AS~ DB~ ~ D~A~ON D~ ~~GU~R C~~A~ D~ ANG~ VER~CAL CO~ D~ON .-- RE~~ DE~ NO~ SOU~ ~ST ~T 10,155 25° 15' 9235 ~73 41 80 S 18° W 3868 13 3~7 13 10,289 24° 15' 9357 91 55 03 S 19° W ' 3920 16 4]5 05 10,432 25° 15' 9487 25 61 00 S 18° W 3978 17 433 90 10,718 22° 45' 9751 00 110 60 S 20° W 4082 ~10 471 73 10,846 22° 00' 9869 68 47 95 S 20° W 4127 ~16 488 13 ~~ 4154.42' S 06° 45' W , D~RECT~ONAL SURVEY R~PORT FOR '¢YPE OF SURVEY: .... ~[roscoFic SURVEY DEPTH: FROM, L~ 0 T~U LEA.~E:~ McArthur River ~IEL~., FT. TO . lPl!!~ WELL NO. O-11 COUNTY/PARISH~, ~enai Pcminsula STATE A l a s k a DATE OF SURVEY *JOB NO. ~2SU]-16032 Anch ora Fe OFFICE: ,,, SP 13SC UNION OIL COHPANY OF CALIFORNIA T,B,U, G-11 qCARTHUR RIVER ALASKA SPERRY-SUN WELL SURVEYING COMPANY ANCHORAGE, ALASKA- - COMPUTATION DATE NOVEHBER 8t 1975 PAGE 1 DATE OF SURVEY NOVEHBER 7, 1975 SURWEL GYROSCOP[C HULTISHOT SURVEY .dOB NU~iBER SU3-16032 - KELLY ~USHIN6 ELEV, = 99,00 FT, TRUE MEASURED VERTICAL DEPTH' DEPTH SUB-SEA COURSE cOURSE DOG-LEG TOTAL VERTXCAL INCLINATION DIRECT[ON SEVERITY RECTANGULAR cOORDZNATES DEPTH ...... DEG MIN DEGREES DEG/IO0 NORTH/SOUTH EAST/WEST 0 ~~00 200 ~00 -~qO0 500 600 800 9O0 -~-1000 1[00 2200 ~300--~ 1~00 1600~- 1700 1800 '~1900 .... 2000 2100 2200~' 2300 2400 ~2500~ 2600 2700 2900 3000 0.00 -99.00 99.99~ 0.99 199.99 100.99 299.99 200.99 399.99 ...... 300.99 499.99 ~00.'99 599.99 500.99 699.99 ..... .&00.99 .... 799.99 7~0.~9 899~98 800.98- .... 999.97 ...... 900.97 ...... 1199.7~ 1100.75 1299.2q .... 120092~ 2398.30 1299.30 1496.66 1397.66 1688.70 1589.70 1781.09 1682.09 1957.97 1658.97 20~5.87 19q6.87" 223q.q2 ...... 2035.q2--- 2223,ql 212q,~1 2312.60 2213.&0 2q02,12~ 2303,12 ..... 2q91,9~ 2392.9~ 2582,02 '2483,02 2572.~~- 2575,#q 2763.09 285#,12 2755.12 0 0 S O. 0 E 0.00 0.00 · 16 S 39,18 E 0.27-- 0.18 S 0 16 $ 11.80 E 0,13 0.58 S 0 15 S 86.39 E 0.31 0.8~ S 0 20- $ 55.~2 E- -- 0.18-- 1.00 S 0 17 N 88,60 E 0.20 1.16 S 0 17 S 52,85 E 0,19 1.31 S 0 2~- 'S .80.752-- 0.17 0' 15 S 80.12 E 0.10 0 16 $ 55.96 E 0.11 I:-18'-- S 35. 5 2 25 S 6,50 ~ 20 S 22.95 W 2.52 6 ~1- S 1~.$6 W ..... 2,q8 .1,50 S 1.59 S '1,76 S 2.82 S 5,8~ S 11,~1 $ 20.55 S 9 5 S 2.qO W 2.89 34,06 S 11 q,O -S 2.60 E 2,75 52,05 S 16 11 - S O, I E ....... q.55 76.10 S 20 6 S 1,9~+ W 3,96 107.22 S 2~ 50 S 2.79 W q.7~ 1~5.39 S 28 'q5 S 3,6q W-~ 3.96- 190.38 S 28 50 S 3.16 ~ 0.25 238.~6 S 28 7 S 2,67 W 0.75 286.07 S 27-16 ...... S- 2,~1 Y .... 0,86--- 332,50 S 2Y 0 .S 2.~2 W 0.27 376.06 S 26 q6 S 2.2~ M- 0,25, q23,2~ S 26- 10 .... $ - 2.60 ~ 0,62 q67.77 S 26 0 S 2.93 ~ 0,22 511.69 S 25 28 S 2.99 ~ 0.5~ 555.05 S 25-- 6 .... S ~.q9 ~ ..... 0,~2--- 597.69 S 2~ 50 S q. 6 W 0.36 639.81 S 2~ 5 S 3.61 W 0,77 681.11 S VERTICAL SECTION 0.00 0.00 0.14 E 0.17 0.~ E 0.56 0.60 E 0.79 1.06 E 0.9~ 1.55 E 1.07 1.99 E 1.19 2,~9 E '-' 1.36 - 5.01 E 1.q2 ~.~1 E 1.56 q.26 E 2,57 .... 5.15 E 5.5~ 3.91 E 11.17 1.00 E 20,qq - 0.77 ~ ~.05 0.6~ W 52.00 0.18 W 75.98 -- 0.76 W 107.09 2.36 W 1~5,28 #,91 ~ - 190.55 7.77 W 238.51 10,20 W 286,19 12.22 W 332.65 1#.10 W 578.25 15.9~ W q23.~6 17.82 W #68.02 19,9q W 511,99 · 22.18 W 555.~1 2~.59 W--' 598.1~ 27.37 W 30.1~ W 681.72 ....... UNION OIL COMPANY OF CALIFORNIA T,B.U, G'12 ~CARTHUR RIVER ALASKA SPERRY-SUN WELL SURVEYING COMPANY ANCHORAGE. ALASKA ......... COMPUTATION OATE NOVENBER 8e 1975 PAGE 2 DATE OF SURVEY NOVERBER 75 1975 SURWEL GYNOSCOPIC_MULTISHOT SURVEY dOB NUHEER SU$-16032 KELLY BUSHING ELEV, = 99,00 FT. PIEASURED DEPTH 3100 3200 3300 5400 .... 3500 3600 3700 3800 3900 qO00 TRUE VERTICAL DEPTH .... DEPTH ..... DES SUB-SEA COURSE cOURSE DOG-LEG TOTAL VERTICAL. INCLINATION DIRECTION SEVERITY RECTANGULAR COORDINATES q100 q200 q300 qq00--- 4500 ~600 q700--- ~800 qgO0 ---5000--- 5100 5200 ...... 5300~ 5qO0 DEGREES 29q5,52 28q6,52 23 3036,93-- 2937.93 ....... 3128.1# 3029,1~ 3219.29 3120,29 33i0,56 .... 3211.56 .... 3q01.98 3302.98 23 3~93.61 339q,61 23 25 S 0.27 3585,q2--- 3q86.~2 ......... 3677.15 3578.15 23 37 S 0,19 3768,82 3669,82 DEG/IO0 NORTH/SOUTH 0,61 0,32- -- 0.08 0,30 0,33 0.48 0.29 0,23 5500 5100,q7 5001,q7 ~5600~ 5186.87 .... 5087.87--~ 5700 5800 ~5900" 6000 6100 3951.9I 3852.91 23 55 ~0q2.99 ~9q3.99 2~ 50 413q,0~- ~035,0q .... 2~ - ~225,03 ~126,03 25 0 q315,58 ~216.58 25 13 qqOS,ql .... ~306.qI 26 52 q~93.90 q39~.90 28 38 ~581,30 ~q82.30 29 30 4667,9q ..... q568.gq ..... ~75ff,23 #655,23 q8~0.76 ~7~1,76 q927.q2 ..... ~828.~2 5015.95 ~91#,95 '0.86 E ..... 0.26 1. 8 E 0.19 O.q3 E 0.95 0.23 E ..... 0.82 0,52 E 0,99 0,10 E 0.28 0,12 E ....... 1.65 1.8q 0,87 0,92 0,22 0,22 - 0,17 S 1.2q £ S 1.50 E $0 25 .... S 1.77 E-- 30 18 S 2.15 E 29 52 S 2.59 E 30-- 0 ..... $ 2.2q E 30 10 $ 2,32 E 721.61 S 762.13 S 803.10-$ 8qq.20 S 885,05 S 925.55 S 965.60 S 1005.2~ S 10#5,05 S 1085.02 S 1125.09 S 1165.~9 S 1206.76 S 12~6.10 S 1289.58 S 1332,02 S 1375.91 S lq22.q6 S lq71.03 S 1520.9~ $ 1571,#6 S 1621.5~ S 1671,39 S 17~1.~8 $ 1771.56 S 1821,86 S 1872,27 S 1922.96 S 197q,09 $ '' 16.00 202~.91 S lq,99 2075.21 S 15,90 ~0 0 S 2.66 E 0.2~ 30- 28 ..... $ 2, 5 £ 0.56 5273.22 517q.22 30 7 S 1.92 E 0.36 5359,q0 5260oq0 30 50 S 2.16 E 0,72 5q~5,~5--- 53q6,3~ .... 30- q~ - '$ 1,18 E ..... 0,52 5531.qq 5q32,#q 30 2q S 1, a E 0,30 5617,86 5518.86 30 I S 1,q2 E O,q2 EAST/~EST 32,24 33.82 35.31 ~6.78 38.10 ~9.03 ~9,~7 38.9~ 37,70 37,16 36.92 ~6.65 36,q2 36.3~ 35.77 3~.61 33,18 31.~5 29.38 27,28 25.29 23.11 21.0q 19.29 17.~9 VERTICAL SECTION 722.27 762.82 803.80 8qq.92 885.78 926.27 966.27 1005.85 10~5.58 1085.q6 1125.qq- 1165,73 1206.90 12q8.17 1289.56 1331.91 1375.73 - 1422.17 lq70.59 1520,3q- 1570.67 1620.55 1670.21 1720.09 1769.97 1820.07 1870.30 1920.80 1971,76~ 2022.~& 2072.59 UNION OIL CO~PANY OF CALIFORNIA T.B.U. G-11 MCARTHUR RIVER-- ALASKA TRUE ~EASURED VERTICAL DEPTH DEPTH 6200 570q.46 -~-6500'---- 5791.I7- 6~00 5677.95 6500 596~,82 6600 6051,95- 6700 6139.35 6500 6227.02 -----6900 ..... 631~.91-- 7000 6t~03.16 7100 6~91,66 SP&REy-SUN WELL SURVEYING CO~PA.NY ' PAGE ANCHORAGE, ALASKA OATE OF SURVEY NOVENBER 7, 1975 cOHPUTATION DATE SUR~EL GYROSCOPIC ~ULTISHOT SURVEY NOVEMBER 8, 1975 ~OB NUMBER SU3-16032 KELLY BUSHING ELEV. = 99.00 FT. SUB-SEA COURSE COURSE DoG-LEG TOTAL VERTICAL INCLINATION DIRECT[ON.. SEVERITY RECTANGULAR cOORDINATES DEPTH ..... D£G ~IN DEGREES DEG/IO0 NORTH/SOUTH EAST/~EST 5605,46 30 0 5692.17 -- 29 ~5 5778,95 29 50 5665,82 29 $~ 5952,93 ..... 29~ 16 6040.35 28 50 6128102 28 qO 6215.91 ...... 28 20 .630~.16 6392.66 S 0.81 $ 0.6~ $ 0.11 S O. 6 S '0.75 S 1.13 S 0.62 S 1.69 27 4§~' -S 2.50 27 q5 S' 0.50 2125.21 S 12.92 0.26 2175.02 S 12.29 0.28 222~,70 S 11.97 0.29 227~,25 S 11,95 0,~3 2323.53 S 12.28 0,#7 2371,88 S 13,07 0,29 2419,98 S 15,81 0,61 2467.68 S 14.76 0,69 251~,66 $ 16,~& 0,27 2561.1& S 18,75 0,71 2607.13 S 21,~5 0,50 2652,~7 S 2~,77 0.~9 ~697.57 S 26.91 0,15 27~2.~2 S 33,51 0,57 2786.72 S 38,17 0.85 2829.92 S 42.79 0,70- 2872.13 S 47.90 0.58 2915.56 S 53,~7 .0.31 295~.28 S 59.09 -0,65 299q.26 S 64.7~ 0,70 30~4.15 S 70,76 1.33 ~075.18 S 78,00 1,56 3117.99 S 86.26 1.63 3163.10 S 94,#2 0,28 $209,67 S 102.15 0.81 ...... 3255.50 S 109.86 1.02 3500.54 S 117.89 0,~0 ~3~.18 S 126.12 0.39 $~50o15 S 1~1,52 0.7~ 3472,05 S 149.~1 -- VERTICAL SECTION- 2122.#5 2172.1# 2221.72 2271.18 2320.21 2368.73 2416.78 246~.~6 - 2511.~6 2558.02 -~'7200- ..... 6580.q3-'~ 7500 7~00 7500 ..... 7600 7700 .... 7800 ..... 79O0 8000 ~--8100~- 8200 8500 8500 8600 ~8700~ 8800 8900 ---"--90-00~ 9100 9200 6669.50 6570.50 6758,65 6659.65 68~7,91 .... 67~8.91- ~ 6937,q~ 683814~ 27' 5 $ 3,65 bi 27 0 S ~.73 Id 26 52 S 5.78 ~ 26 q~- S 5.93 bl- * 26 10 S 6. 6 Id 7027,50 6928,50 25 20 S 6,17 Id 7118,01-- 7019.0I ...... 25~- 0--- S 7,6~ bi- 7208.85 7109.85 2~ 25 S 7.68 M 7300,01 7201,01 2~ 8 7391,~9 7292.~9---- 23 30-- 7~82.99 7383,99 2~ 5 7575.90 747~.90 25 10 7663.88--- 756~.88 26 7752.7~ 7655.7~ 28 S 8, 2W S 6, 8-W S 9. 6 Id S 10.92 W S 10.93 W- S 9.60 W 7840.90 7741,90 7929.28~' 7850.28~-- 8018135 7919,55 8107.95 8008.95 8197.79~- 8287.86 8188.86 8378.52 8279.52 28 17 S 9.25 27- 30 .... S 9.73 26 3ff S 10.66 26"' 10 S 10.69 25' 55'- S 9.82'bi 25 35 $ 10.29 ~ 52 S 10.78 260~.07 26~9.52 269~.79 2739.83 275~132 2827.71 2870,15 291[.83 2952.81 2993.05 3033.22 3074.59 3117,80 3163.31 ~256.75 3301.86 33~5.91 $389,#6 3432.62 5~7~,90 - . SPERRY-SUN WELL SURVEYING COMPANY .................................. ANCHORAGE, ALASKA ' - UN[ON OIL COMPANY OF CALIFORNIA T.B.U. G-11 COMPUTATION DATE MCARTHUR RIVER NOVEMBER 8, 1975 ......... ALASKA . PAGE 4. DATE OF SURVEY NOVEHBER 7, 1975- SURWEL ~YROSCOPIC MULTISHOT SURVEY dOB NUMBER SUE-l&052 KELLY BUSHING ELEV. m 99.00 FT, TRUE MEASURED VERTICAL DEPTH DEPTH ..... DEPTH .... DEG MIN DEGREES* DE6/IO0 NORTH/SOUTH SUB-SEA COURSE cOURSE DOG-LEG TOTAL VERTICAL INCLINATION DIRECTION SEVERITY RECTANGULAR COORDINATES EAST/WEST 9~00 84~69~51 8570.51 25 55 S ~10,82 W 1.28 5512.55 S 157.00 --9400--- 6561,56-~- 8462.3& ..... 25 0 S 11.'77 W- 0.69 3551.15 S 164.74 9500 8652.77 8555.77 24 48 $ 10,61W 1.86 5590.87 S 172.59 9600 8745.65 8644.6~ 24 55 S 10. 0 W 0.55 $631.97 S 180.06 .... 9700 ....... 8854.77 8755.'77-- 24 0 .S 10. I W 0.58 3672.48 S 187.21 9800 8926.06 8827.06 24 12 S 10.89 W 0.~I ~712.65 S 194.61 9900 9016.88 8917.88 ~5 15 S 10.85 ~ 1,05 ~753.71S 202.50 .... 10000 9107.1~- 9008.13 ..... 25 ' 47 S 11.69 ~ 0,6~ 5795.95 S 210,92 10100 9197.7~ 9098.7~ 2~ 15 S 11.66 ~ 1.53 3657.56 S 219.48~ 220.77 10115 g211,42 9112.42 2~ 10- S 12.47 W~- 2.29 3845,37 S HORIZONTAL D~SPLACE~ENT = 5849.71 FEET AT SOUTH~ 3 DES. 17 ~ZN. ~EST AT ~D = 10115 VERTICAL SECT/O~ 551~.58 3554.75 5&77.17 5717.68 3759.14 5801,80 3843.63 3~49.71 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE DIMENSIONAL RADIUS OF CURVATURE METHOD, SPERRY-SUN WELL S~RVEYING cOmPANY .................... ANCHORAGE, ALASKA ..... uNION OIL COMPANY OF CALIFORNIA' T.B.U. G-11 CONPUTATZON DATE qCARTHUR~RIVER ....... NOVEMBER 8~ 1975 ....... ALASKA ALASKA-- PAGE 5 DATE OF SURVEY NOVEEBER 7, 1975 SURWEL GYROSCOPIC NULTISHOT SURVEY JOB NU~-~BER SU$-16052 KELLY bUSHING ELEV. = 99.00 FT. KELLY BUSHIN$ ELEV, = 99.00 FT. - INTERPOLATED- VALUES FOR EVEN 1000 FEET OF MEASURED DEPTH TRUE SUB-SEA ~EASUREb ...... VERTICAL VERT[CAL DEPTH DEPTH DEPTH - 0 -0.00 ..... -99.00 1000 999.97 900,97 TOTAL RECTANGULAR COORDINATES- MD-TVD .... NORTH/SOUTH EAST/WEST DIFFERENCE 0o00 2.82 S 2000 1957.97 1858.97 2~8.N6 ..... 3000 ....... 2854.12 '- 2755.12 ....... 6~1.11 ~000 5768°82 3669.82, 1085,02 5000 q667,9~ ~568.9q- 1520°9~ .... 6000 ...... 55~1.q~-- 5~2.~ 7000 6~05.16 650~.16 8000 7500o01 7201.01 ~9000 ..... 8197,79 6098,79 - 10000 9107.1~ 900~o1~ 10115 9211,~2 9112.#2 VERTICAL CORRECTION 251~,66 S 295~o28 S 5587,58 $ 5795,95 S 56~.~7 S 0.00 .... 0.00 -- N.26 E 0.02 0,02 7.77 W q2°02 ~1,99 50.1~ ~ .... 145.87 103,85 58,93 ~ - 2~1.17 35.1~ ~ ~2.0~- 100,87 1~.99 W"- 468.55- 1~6,#9 16°~8 W 596,85 128.27 59,09 ~ 699.98 ½03.15 135,9~ W 802.20 102,21 210.92 W 892.86 90.66 220.77 ~ 905.58 10.71 THE CALCULATION PROCEDURES ARE BASED ON THE USE OF THREE DIMENSIONAL RADIUS OF CURVATURE EETHOD. dNiON OIL COMPANY OF CALIFORNIA T,B,U, G-11 qCARTHUH RIVER' ALASKA SPERRY-SUN WELL SURVEYING CORPANY - ANCHORAGE, ALASKA - CORPUTAT[ON DATE NOVERBER 8, 1975 PAGE 6 DATE OF SURVEY NOVEr4BER 7, [975 SURWEL GYMOS¢OPIC MULT[SHOT SURVEY dOB NUMDER SU5-[6032 KELLY BUSHING ELEV. = 99.00 INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH 9EASURED 3EPTH TRUE ....... SUB-SEA VERTICAL VERTICAL DEPTH OEPTH ........... TOTAL .......................... RECTANGULAR COORDINATES MD-TVD NORTH/SOUTH EAST/WEST OIFFERENCE 0 0.00 -99.00 99 99.00 0.00 .... 199------199.00 ...... 100,00 299 299,00 200.00 599 399.00 ~00,00 ~--499~-' ~99.00 -'- 400,00 ........ 599 599,00 500,00 699 699,00 600.00 0.00 0.17 S 0.58 $ 0,82 S 1,00 S 1,16 S- 1,30 S 1.50 S 799 ...... 799.00 899 ~99,00 ~00.00 999 999.00 900.00 .... 1099 ..... 1099,00 - 1000.00 .... 1199 1199.00 1100.00 1299 1299.00 1200.00 ---1400 ..... 1~99.00 .... 1300,00' 1502 1~99.00 1~00.00 1605 1599.00 1500.00 1710 ...... 1699.00 1600.00 .... 1819 1799.00 1700.00 700.00 .......... 1.59 1.76 2,80 5.50 11,56 20.50 34,17 52.55 77.68 111,08 153,81 0.00 0.00 0.1~ E 0.00 0.~4 K ...... 0,00 0,60 £ 0,00 1.05 K 0.00 1,5~ K .... 0,00 -- 1,99 E 0.00 2.#8 E: 0.00 $,00 K 0.01- '- ~,41 K 0.01 4.2~ K 0.02 5.14 E 0,08 3,9~ E 0,26 1,00 K 0.75 0,77 W ......... 1.70 - 0.62 W 0,18 W 6.55 0.90 W ..... 11.99 -' 2.79 W ~0,79 VERTICAL cORREcTION 0,00 0.00 0,00 0,00 0.00 0,00 0,00- 0,00 0000 0,01 0,05 0,18 0.48 0.95 1.68 5.46 8.80 UNION OIL COMPANY OF CALIFORNIA T,B,U, G-l[ qCAR1HUR RIVER' ALASKA SPERRY-SUN WELL SURVEYING COMPANY ANCHORAGEe ALASKA ...... COMPUTATION DATE NOVEf~BER 8, 1975 PAGE 7 DATE OF SURVEY NOVEr~BER 7e 1975 SURWEL GYROSCOPIC MULTISHOT SLJRVEY dOB NUr~BER SU3-16032 KELLY BUSHING ELEV, INTERPOLATED VALUES FOR EVEN [00 FEET OF SUB-SEA DEPTH SUB-SEA ......... TOTAE ........................... VERTICAL RECTANGULAR COORDINATES ~D-TVD DEPTH NORTH/SOUTH EAST/WEST ~[FFERENCE '-- TRUE ~.qEASURED VERTICAL DEPTH DEPTH i932 i899,00 1800,00 20~6 1999,00 1900,00 .... 2160 ..........2099,00 2000.00~ 227~ 2~99,00 2~00,00 2~8~ 2299.00 2200,00 '2~96 2399,00- 2300.00 2607 2499.00 2~00,00 2718 2599,00 2500.00 206,07 S 5,91 W 3~,68 260.96 S 9,00 W ~7,80 31~,26 $ 11,~8 W 61,15 - ~65.6~ S 1~,57 W 73,59 ~16,39 S 15,67 W 85.75 q~S,2q S' 17,75 W -- 97,51 515,13 S 20,1~ ~ 108,~5 563,12 S. 22,60 W 119,80 610,11 S - 25,55 W- - 130.5~' 656,58 S 28,55 ~ 1~0,56 701,11 S ~1,36 W 150,1~ 7~5,19 S 33,18 W 159.~ 789,9~ S $~,85 W 169.0i 835°06 S 36,~5 ~ 178.73 879.90 S 37.95 ~ 188.3~ 92q.23 S 39,01 ~ 197.73 967,9~ S $9.~8 ~ 206,86 lo11,09 S '-- 39.39W 215.78 105q,60 S 59,20 W 22~,83 2829 ...... 2939 30~9 5158--- 5268 3377 3596 ~705 2699,00- - 2300,00 2799.00 2700,00 2899.00 2800.00 2999.00 2900,00-- ~099.00 3000.00 3299.00 3100.00 3299.00 .... 3200,00 3399.00 $300.00 3~99.00 S~O0.O0 ~§99,00 .... S500,00 .... VERTICAL CORRECTION 12.q~ 12,1& 11.75 11.33 10.95 10,52 10,2& 9,58 9,30 9,56 9,72 9.60 8,91 9,05 UNION OIL COMPANY OF CALIFORNIA T,BeU, G-11 HCARTHUR RIVER ................... ALASKA SPERRY-SUN WELL SURVEYING COHpANY ANCHORAGE, ALASKA--- COMPUTATION DATC NOVEMBER 8, 1975 PAGE 8 DATE OF SURVEY NOVEMBER 7, 1975 SURWEL GYROSCOPIC RULT[SHOT SURVEY dOB NUMBER $U3-16032 KELLY BUSHING ELEV. = 99,00 FT, ~NTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH TRUE ..... SUB-SEA- ~EASURE. D VERTICAL VERTICAL DEPTH DEPTH DEPTH TOTAL RECTANGULAR COORDINATES HD-TVD NORTH/SOUTH EAST/WEST DIFFER£NCE ~032 5799.00 ~1~2 3899.00 ...... ~25i .... 3999.00 ~361 ~099.00 ~71 ~199.00 -----~581 ...... ~299.00'- ~692 ~599.00 4805 q~99,00 3700,00 1098olq $ 3800.00 11q2.06 S 3900,00--- 1186.q7 S ~000.00 1232.~9 S ~100.00 1277.~5 S ~200,00 ...... 1~2~.21 S ~300.00 1372,66 S ~00.00 Z~25.2~ S ~92-0- .... ~599,00 '-- qSO0.O0 ...... 1~81,0~ S' 5036 ~699.00 4600,00 5151 ~799.00 qTO0,O0 5267 .... ~899,00 - ~800,00 --- 5382 ~999.00 ~900,00 5~98 5099,00 5000,00 ..... 561~ ...... 5199,00 ~ 5100,00 ..... 5729 5299,00 5200,00 58q6 5399,00 5300,00 ---5962 .... 5q99;00~- 5q00.00~--- 6078 5599.00 5500,00 1559.17 S 1557,55 S 1655.00 S 1712.80 S 1770.70 S 1828.99 $- 1887,2E S 19~6,57 $ 2005,87 206~.31 38,77 W 233.90 38.13 W 2~3,12 57,3~ W '- 252,55 36.99 W 262065 36,76 W 272.28 36.~ W -' 282,67 36,3~-W 293,80.' . 35,71 W 306,8~ 32,62 ~ 537,01 30,~5 ~ 55~,82 27,92 ~ 368,18 25,6~ ~ 383,71 23,15 W 599,29 20,79 W ~15,06 18.79 W 16,62 W ~7,11 15,35 W 1~,17 ~ q79.21 VERTICAL cORkECTION 9,06 9,22 9,#2 10,06 9,6~ 10,39 11,13 12,99 1~,52 15.68 15,81 15,52 35,58 15,77 15,7& 16,30 16,27 15,8~ SPERRY-SUN WELL SURVEYING CO~IPANY .............................. ANCHORAGE~ ALASKA UNION OIL COMPANY OF CALIFORNIA T,B,U, G-11 ~iCARTHUR RIVER ALASKA PAGE 9 COMPUTATION DATE NOVEMBER 8, 1975- DATE OF SURVEY NOVEI~BER 7, 1975 SUR~EL GYROSCOPIC MULTISHOT SURVEY JOB NUMBER $U3-16052 KELLY BUSHING ELEV. = 99.00 FT. INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH ;~EASURED 3EPTH --TRUE -- SUB-SEA TOTAL ............................ VERTICAL VERTICAL RECTANGULAR COORDINATES RD-TVD VERTICAL DEPTH DEPTH NORTH/SOUTH EAST/NEST DIFFERENCE cORRECTION 6193 6509 6559 6655 6881 6995 7108---- 7220 7557 7668 --7779 .... 7889 7998 8108---- 8217 5699.00 5799.00 5899.00- 5999.00 6099,00 _ 6199.00 6A99.00 6~99.00 5600.00 2122,06 5700.00 ~179.q9 5800.00-- 22~6,77 5900.00 229~,61 6000,00 2~9.6q 6100.00 ...... 2~0~o65 6200.00 6~00.00 2512.~7 ~6~99,00 -- ~00.00 - 6599.00 6500,00 6699,00 6600,00 6799.00 6700.00 6~99.00 6800,00 6999,00 6900,00 7099,00 7000,00 7199.00 7100,00 7299,00 7200,00 7~99.00 7~99.00 2565.02 S- 2616.60 $ 2667.~5 2717.90 S 2767.92 S 2816.50 S 2863.3~ S- 2909.12 S 2953,85 $ 7500,00 ...... 2997.69 S' 7~00.00 $0~1.21 S 12.97 W q9~,69 15,~8 12,2~ W 510,01 15,32 11,9~ W 525.26- 15,2~ 11,97 W 5~0,28 15,02 12,6~ ~ 55~,92 1~.6q ~ 569.05--~ 1~,I$ lq,51 N 582,92- 15,86 16,38 N 596.2~ 18.95 ~ 609.26 12,99 22.05 N 621.85 12.56 26.01 ~ 65~.~1 ~2.25 50,98 ~ 6#6,22 12,11 56,~7 ~ 658,16 11,95 ~1,~ W 669.~6 11,29 q6.72 ~-- 680.01- 10.55 52.87 W 690.17 10,15 59,02 ~ 699.88 9.71 65,20 ~ 709.18 71.88 N 718o58 UNION OIL COMPANY OF CALIFORNIA T,B.U. G-11 MCARTHUR RIVER ALASKA SPERRY-SUN WILL SURVEYING CONPANY ANCHORAGEe ALASKA CO~IPUTATION DATE NOVEMBER 8e 1975 PAGE 10 DATE OF SURVEY NOVEMGER 7, 1975 SURWEL GYi~OSCOPIC ~ULTISHOT SURVEY dOB NUMBER SU5-16032 KELLY BUSHING ELEV. = 99.00 FT. MEASURED DEPTH INTERPOLATED VALUES FOR EVEN 100 FEET OF SUB-SEA DEPTH , -TRUE .... SUB-SEA TOTAL' ' ....... VERTICAL VERTICAL RECTANGULAR COORDINATES PqD-TVO DEPTH DEPTH NORTH/SOUTH EAST/WEST DIFFERENCE 8327 7599.00 7500.00 8q59 7699.00 7600.00 ------8552 8655 8778 8590 9001 9112 9222 9332 9440 $086.76 3135.20 5187.45 7899.00 7800.00 3240.27 7999.00 7900.00 3291.02 8099.00 8000.00 ....... ~359,85 8199.00 8100.00 5387,9§ 6299.00 8200.00 ~5.40 8399,00 - 8300,00 ....... 3481.46 8499.00 8400.00 5525.00 8599,00 8500,00 3566.78 9550-- 8699.00 8600.00 .... ~611.84 S 9660 8799.00 8700.00 $65~.79 S 9770 6899,00 8800,00 5700.69 S "'~9880----8999.00-- 8900,00 ........ 3745.q2 S - 9990 9099.00 9000.00 3792.10 S 10101 9199.00 9100.00 3~37.91S 10115 ..... 9211.~2-- VERTICAL -.,~, COFREcTION*. 9112.~2 .... ~843,37 $ ' - 220.77'W 80.25 W 728.75 10.20 89.59 W 740.24 11.51 98,5i-W-' 753.42- 1~,17 107.19 W 766,85 116.10 ~ 779.56 12.50' 125.31 W 791,02 11,66 154.0~ W 802.3~ 11.31 142.47 W 813.5~ 11.00 151,10 W 825,78 159.42 W 855.17 9.38 168.00 W 841.89 8.72 176.49 W- 851.91 -- 10,01 184.4~ W 861.8~ 9,92 192.~2 W 871.~3 9,49 200.91W 881.2~ 9,88 210.1~ ~ 891.97 219.60 ~ 90~.$8 90~.58 1.19 THE CALCULATION PROCEDURES USE A LINEAR INTERPOLATION BETWEEN THE NEAREST 20 FOOT MD (FRO~ RADIUS OF CURVATURE) POINTS D RECTIONAL suRW¥ FOR REPORT ,TJNIO.T' ,,gII, COHPANY ..... TANG k:NT [ A L ~YPE OF SURVEY:__ ~ Gyros,c. opic SURVEY DEPTH: FROM , 0 LEASE: T BU Mc Arthur River FIELD: , ,.,FT. TO =. 10]]5 Fr. - -WELL NO._ ,O,11 .... COUNTY/PARISH_ yenai Peninsula DaT~ OF SURVEY 13.-?-75 OFFICE: ~ n .ch ora .ge JOB NO. STATF Alask~ ST]3-1603 2 UD,JION OrL cor<PANY OF CALIFORNIA T.R.U. G-11 D~CARTHUR RIVER FIELD ALASKA P4GE 1 NOVF~RER 7, 1975 SURVEY DATE VFRTICAL SECTION COMPUTED ALONG cmOSURE SPERRY-SUN WELL SURVEYING COMPANY ~U3-16052 RECORD OF SURVEY TRUE HFARURFD VERTICAL SUB-SEA DEPTH DEPTH DEPTH INCLINATION DEG r4IN DIRECTION DOG'LEG SFVFRITY VFRTICAL DEG MIN DFG/100 SECTION RECTANGULAR COORDINATES O. 0.00 '99,00 100. 99,99 0,99 200. 199,99 100,99 ORIGIN AT SURFACE 0 16 S $9.~8 F 0 16 ~ 11.80 F 0.00 0.54 0.12 0.79 0,00 N 0,36 S 0,81 S 0,00 W 0,29 E 0,38 E 300. 299.99 200,99 400. 399.99 300,99 500. q99.99 400,99 0 15 S 8~.39 0 20 s 55.42 0 17 N 86.60 0.51 0.79 0.84 S 0.82 0.!7 1.09 1.17 S 1.30 0.19 1.05 1.16 S 1.79 GO0. 599.99 500,99 700. 699.99 600,99 800. 799.98 700.98 0 17 S 52,85 0 21 s 80,75 0 15 ~ 80.12 0.~8 1,33 1,46 S 2,19 E 0.16 1.39 1,55 S 2.79 E 0,10 1.44 1.63 S 3.22 E 900. 899.98 800.98 )000. 999.96 900,96 1100. 1099.87 1000,87 0 16 S 55,96 I 18 ~ 35, 5 2 25 S 6.50 0.10 1.68 1.05 1.41 7.61 1.89 S 3,75 S 7.9~ 3.61 4,91 5.39 ]200. 1199,5B 1100,58 1300. 1298.90 1199,90 1400. 1397.65 1298,65 4 20 S 22.95 W 6 41 S 1~.36 W 9 5 ~ ~.40 W 2.52 ~ 14.73 3~,89 S 2,~ ~ 2,48 96.15 2~.17 S 0.4~ W 2.~9 ~1.93 41.94 S 1.10 W ~500. 1~95.58 1396.58 1600. 1591.62 1492,6~ 1700. 1685.53 1586,53 11 40 S ~.60 ~ 20 6 S 1.94 W 2.73 A2.05 62.14 S 0.18 W 4.55 ~9.87 gO,O1S 0,18 W 3.96 1~4.23 12~.36 S 1.34 W 1500. 1776.28 1677.28 1900. 1863.96 1764,96 2000. 1951.56 1852,56 24 50 S P,79 W 28 ~5 S ~.64 W 28 50 S 3,16 W 4.74 1A6.22 36A.31S 3.38 W 3.93 2~4.32 P14.31S 6.~ W 0,2~ 2R2,55 262,~6 S 9.10 W 2100. 2039.76 1940.76 2200. 2128,65 2029,65 2300. 2217,75 2118,75 28 7 S 2.67 W 27 16 S 2.31W 27 0 S P.42 W 0.75 3n9.67 309.54 S 11.29 W 0.86 355.~8 555,31S 13.14 W 0,27 400.~7 400,67 S 15.05 W U~JION OIL COEPANY CF CALIFORNIA PAGE 2 T.~.U. G-11 NOVFRRER 7, 1975 SURVEY DATE PiCARTHIlR RIVER FIELD VFRTICAL SEcTTON COMPUTED ALOA~G CLOSURE ALASKA SPERRY-SUN ~ELL gURVEYING COMPANY SU3-16032 TRUE MEARURED VERTICAL SUB-SEA DEPTH DEPTH DEPTH 2qO0. 2307,03 2208,05 250fl. 2396.78 2297,78 2600. 2q86.66 2587,66 2700. 2576.95 2~77.95 2800. 2667.50 2568,50 2900. 2758.26 2659.26 5000. 2849,55 2750.55 3100. 29~1,07 2B~2.07 ~200. 3032.37 2933.37 3500~ 3~23.50 302~,50 3~00. 52~q.67 3115,67 ~500. 3306.03 5207,03 3600. 3397.52 3298,52 ~700. 3g~9.29 5390,29 3800~ 3581,13 5~82,13 ~900. 3672.76 3573.76 ~000. ~76q,q6 3665.~6 ~100. 3855.99 3756.99 ~300. ~038.16 3939,1~ ~500. q220,15 ~121.15 ~00. ~310.60 ~211.60 a700. ~399.81 ~500.81 RECORD OF SURVFY INCLINATION DEG MIN OIRECTION DOG~.LEG SEVERITY VFRTICAL DEG MIN DEG/iO0 SECTION 26 ~6 26 10 26 0 ~ p.2q W O.~q ~5.90 S ~.60 W 0.62 S 2,95 W 0.22 555.85 25 28 25 2~ 50 S ~.99 W 0.55 576.85 S 3,~9 W 0.#2 R19.25 S q. 6 W 0.55 AA1.2~ 2~ 5 25 ~6 2% 5 3.61W 0.77 702.05 2.31W 0.~1 2,16 W 0.32 2~ 19 2% 15 2~ 0 25 ~8 23 25 23 18 2. 2 W 0.~ ~. 6 W 0.06 ~65.37 1.6% W 0,30 qO6.0~ ~,99 W 0,27 W 0.#7 0.39 ~ 0.26 ~0~5.50 23 50 0,19 E 0.52 10R5.~9 0.68 F 0.22 1105.~6 0.86 E 0.26 11~5.~5 25 55 2~ 50 S 1. 8 [ O.lB 11~5.~5 ~ O.q3 F 0.95 1~7.76 S 0.25 E 0.82 ~268.58 25 0 26 52 0.52 F 0.99 1510.55 0.10 F 0.28 i~S5.08 0.12 [ 1.65 1398.19 RECTANGUI AR COORDINATES ~q5,67 S ~89.75 S 533.51 S 576.~5 S 61~,79 S 660.68 S 701 ,~1 S 7~1,68 S 782.q5 S 823.61 905.31 9~5,66 985.~0 102~,95 106§.01S 110~,88 S 11~5,15 S 1185.69 S 1~27.68 S 1P68,58 S 1310.6# S 135%.25 S 16,A1 W 1B.81 W 21.0& W 23.30 W 25.86 W 28.a5 W 31.~2 W 33.05 W 3~.59 W 36.0~ W 57.51W 38.A8 W 39.37 W 39,56 W 39.~9 W 39.1A W 38.69 W 38.08 W 37.32 W 37.00 W 36,8q W 36,~6 W 36,38 W 36,29 W U;dTON OTL COMPANY OF CALIFORNIA T.F.U. 6-11 PiCARTHIIR RIVER FIELD ALASKA PAGF NOVF~RER 7, 1975 SURVEY DATE VERTICAL SECTTON COMPUTED ALONG CmOSURE SPERRY-SUN ~ELL RURVEYING COMPANY SU3-16052 RECORD OF SURVEY TRUE MEARURED VERTICAL SUB-SEA DEPTH DEPTH DEPTH INCLINATION DEG MIN DIRECTION DOG-lES SEVERITY VFRTICAL DEG MIN DEG/100 SF£TION RECTANGULAR COORDINATES 4300. 4487,56 N588,58 4900. 457q.62 4475,62 5000. N660.85 4561,85 28 38 30 25 1.2~ E 1.8~ 1~5,95 1.50 F 0.87 1~95.02 1.77 [ 0.92 15~5.45 1495.57 S 35,25 W 33.96 W 32.4O W 5100. ~7~7.19 4648,19 5200. ~833,91 ~734,91 5300. 4920.51 ~821,5~ $0 18 29 52 3O 0 S ~.15 F 0.22 1~95.~7 ~ 2.59 F 0.48 1G~5.20 ~ ~.24 £ 0.21 169~.97 159G,GO S 1~46.3~ S 30,50 W 28,25 W 26,30 W 5400. 5006.97 ~907,97 5500. 5093.57 499~,57 ~600. 5179,76 5080,76 30 10 30 0 30 28 S a.32 F 0.17 17~q.97 S ~.66 F 0.25 179~.70 S 2. 5 F 0.55 1A~5.18 17q~.52 S 179~,46 S 1~7,13 S 24.26 W 21,9~ W 20.13 W 5700. 5266,26 5167,26 5800. 5352.13 5253,13 5900. 5438,12 5339,12 30 7 30 50 30 ~2 ],92 E 0.35 1A95.15 ~,16 F 0.72 1,18 E 0,51 ]997.06 1897.28 $ 19~,50 S 1999,5~ S 18,45 W 16,5~ W 1§,47 W ~000~ 5524,37 5425,37 RIO0. 5610.96 5511,9& A200. 5697.56 5598,55 30 2q 30 30 0 1, 8 r 0.30 .: ~D~7.51 1,~2 F 0.~1 ~97.37 0.81 F 0.30 P1~7.~ 2050,1~ S 2100.15 S 2150,1~ S 14,51 13,27 12,57 ~300. 5784.38 5685.38 RqO0. 5871.15 5772.13 ~500. 5958.12 5859.12 29 45 29 50 29 33 0.6~ 0,11 O. 6 0.26 e196.7~ 2199.76 S 12.01 W 0.27 PP~6.40 2e49.51 S 11,92 W 0.29 2295.6~ 2298,83 S 11.97 W ~GO0. 6045.35 5946,35 ~700. 6132.96 6033.96 ABO0. 6220.70 6121,70 29 16 28 50 28 ~0 0,7:~ W 1.13 w 0.62 W 0.#3 P34~.47 23q7,71 S 12.59 W 0.~7 2392.~6 2395.93 S 13.5~ W 0.29 ~0.5~ 24~.90 S 1#.06 ~ kgO0. 6308.72 6209.7~ 7000. 6397.22 6298.22 7100. 6q85.72 6386,72 28 20 27 45 27 45 S 2.50 W S 3, 8 k 0.60 2q88.02 2~91.33 $ 15.~6 W O.A9 P53~.58 2537.85 S 17,~g W 0.27 P~l.lq 2584,35 S 19.99 W UNION O)L COMPANY OF CALIFORNIA T.R.U. G-11 ~£ARTHIJR RIVER FIELD ALASKA PnGE 4 NOVE~RER 7, 1975 SURVEY DATE VFRT~CAL SE£T?ON CODqPUTFD ALONG clOSURE SPERRY-SUN WELL ~URVEYIh. G COMPANY SU3-16052 RECORD OF SURVEY TRUE MFARURED VERTICAL SUB-SEA DEPTH DEPTH DEPTH INCLINATION DEG DIRECTION ~OG-iEG SEVERITY VFPTICAL DEG MIN DEG/IO0 SFCTION RECTANGULAR COORDINATES 7200. 657~.75 6475.75 7300. 6663,85 6564,85 7400. 6755.06 6654,06 27 5 27 0 26 52 3.65 W 0.71 2626.67 4.73 W O.a9 2~72.05 5,78 W 0.49 P7~7.~0 2629,78 2675,05 S 2719,99 S 22,89 W 26,63 W 51,19 W 7500. 6842.~7 6745,37 7600. 69~2.12 68~3,19 7700. 7022,50 6923.50 26 ~4 26 10 25 20 5.93 W 0.14 ~762.14 ~. 6 W 0,56 ~06.19 4.17 W 0.83 P~48.92 276~.73 S 2~08.58 S 2A51.12 S 35,83 W 40.~9 W g5.09 W 7800. 7113.13 701~.13 7900. 7204.19 7105,19 RO00. 7295.45 7196,~5 25 0 24 25 24 8 7.64 W 0.70 2R91.07 7,68 W 0.58 p9~2.28 ~. 2 W 0.31 ~973.03 2893.01 S 2933,98 S 50,71 W 56,~5 W 61,95 W ~100. 7587.16 7288.16 ~200. 7478.45 7379,45 ~300. 7568.96 7~69,96 23 30 24 5 25 10 g ~. 8 W 0.63 3012.77 S 9, 6 W 0.70 3053.37 S lo,92 W 1.53 3095.53 3013.94 S 30~,24 S 3095,99 $ 67.5~ W 73,97 W 82.02 W 8400. 7658.45 7559.43 ~500. 7746,68 76~7,68 ~600. 783~.74 7735.74 26 52 28 3 28 17 10.93 W 1.56_ 3139.81 9,60 W 1.~3 ~1~6.55 g.25 W 0.28 3233.68 3139.86 S 3232,99 S 90.g9 W 98,33 W 105.95 W 8700. 7923.44 782#.44 ~800. 8012.88 7913.88 ~900. 8102.64 8003,6~ 27 30 26 34 26 10 9,75 W 0.81 3279.57 10.66 W 1.02 33~3.93 10.69 W 0.40 3367.66 5278.50 S 113.75 W 3322,45 S 122,03 W 3365,78 S e* 130,~1 W 9000. 8192,58 8093,5A 9100. 8282,77 8183.77 9200. 8373.50 8274,50 25 55 25 35 2# 52 9.82 W 0.45 34~1.09 10.29 W 0.~9 ~53.g5 10.78 W 0.7~ 3~g5.&5 3q 08.85 S 3q9~. 65 $ 137.66 W 1 ~5.37 W 153,P.~ W 9300. 8465.15 8366,15 g~O0. 8557.20 8459.20 9500. 8647.98 8548,98 23 35 23 0 24 ~8 10.82 W 1.28 3535.32 11.77 W 0.~9 3573.97 10,61 W 1.~6 3&15.57 3531,94 S 3570.20 S 3611.42 S 160.75 W 168.72 W Uh'ION OIL COMPANY OF CALIFORNIA T.~.U. MCARTHtJR RIVER FIELD ALASKA PaGE 5 NOVEMRER 7, 1975 SURVEY DATE VERTICAL SECTTON COMPUTF~ ALONG cmO~URE SPERRY-SUN WELL AURVEYI~G COMPANY SU3-16O32 RECORD Of SURVEY TRUE MEARURED VERTICAL SUB-SEA nEPTH DEPTH DEPTH INCLINATIOH DEG MIN DIRECTION DOGJLE$ SEVERITY VERTICAL CEA MIN DEG/IO0 SECTION RECTANGULAR COORDINATES g600. 8738.92 8639,92 2g 35 $ 10. 0 ~ 0.35 3~56.89 3~5~,39 9700. 8830.27 8731,27 2~ 0 ~ 10, 1 W 0.58 3A97.29 369P.~5 9800. 8921.q8 8822,48 2~ 12 S 10.89 W 0.~1 3737.95 3732,70 183.67 W 190.7~ W 198.~8 W ~900. 9011.93 8912.9~ 25 15 $ lo.85 k 1.05 ~7R0.22 377~.60 S 10000. 9101.97 9002,97 25 ~7 S 11.69 W 0.~ 3R~$.25 3817,19 S 10100. 9193.15 909~.15 2~ 15 ~ il.G6 W 1.53 ~8A3.89 3857.~2 S 206.51 W ~15o33 W 225.63 W 10115. 9206.85 9107,85 2~ 10 S 1P.~7 W 2.~8 ~&69.96 $865.~1 S 22~.95 W **** THF CALCULATION PROCEDURES ARE BASFD ON THE IJSF OF THE TANGFNT~AL OR CHORD MFTHOn HORIZONTAL DISPLACEMENT = ~869.96 FEET AT AOUTH 3 DFG. i9 MIN, WEST{TRUE~ UNION OIL COMPANY OF CALIFORNIA TBU G-11 MCARTHUR 'RIVER FIELD JOB NO. SU3-16032 NOVEMBER~ 7, 1975 Union Oil Company ~P"lallfornla ;IR}5 Denali 8tre~, &l~chorage, ^la;kn 99503 Telephone (907) 277,146t Division of L~dl Anchorage, Alaska unlln' In icco~d!ce wt~h ~hO prlvtsions ~0'~ ~ho' ipPti~ed Oil Ind tho O~ayling~Pla~Eom located on $~ete Lepso ADh '17594 Was spudded on ~a~ 29, 1968. ~e proposed bo~to~ hole loc~ion 0'~ s~id well is 8pproximatel~ 2,S00' 8ouCh ~nd ~,~000' Wa~t ~Foa NE co.er 60ctton !2, TgN~ R13W, ~,M. , ]~.~ ~ r~' < ( Form No P~4 ~EV ~,-:~o-r~ STATE OF ALASKA O~L AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS ( SUBMIT IN DEPLICATE ~ API NL~.IEKICAL CODE 50-133-20115 LEASE DESIGNATION A\-D SERIAL NO ADL-17594 WELL WELL OTHER 2 NAi~E OF OPgRATOR Union 0tl Comnanv of California 3 ADDRESS OF OPEP..AT(YR 507 W. Northern Lights Blvd., Anchorage, Alaska 99503 4 LO'CATION OF 1825'N & 1486'W from SE corner Section 29, T9N, R13W, SM 8 L~'IT,F.~q_M OR LEASE N~XlE Trading Bay Unit 9 WELL NO State G-il (32-32) 10 FTEI.r~ AND POOL OR WILDCAT McArthur River - Hemlock 11 SEC, T, R M (BO'rToM HOLE O~~ Section 32, T9N, 1LI3W, SM 12 PEP.MIT NO 68-43 13 REPORT TOTAL DEPTH AT END OF MONTH, CHANGES IN HOLE SI~E, CASING AND CLWIENTING JOBS INCLUDING DEPTH SRT Ai~D VOL~ USED, PEP~FORATIONS, ~ESTS AICD RESULTS, FISHING JOBS, JUNK IN HOLE A_ND SlDE-TI~ACKED HOLE AND ANY O~I-IER SIGNIFICAA~T CIrlAJ~IGES IN HOL]~ CONDITIONS TRADING BAY U~IT STATE G-11 {32-3,2}, JUNE 19,,68 Drilled 15" directional hole to 3100'. Opened hole to 18" to 3098'. Ran 73 Jts 13-3/8" 61# J-55 buttress casing w/shoe @ 3081'. Cemented w/900 sx class "G" cement premixed w/10I gel, 11 CFR-2, 2% CaUl2 followed w/l$00 sx class "G" w/2l CaC12. Good cement returns to surface. Installed BOE. Drilled 12-1/4" directional hole to 10,846'TD Ran Schlumberger DIL, Sonic, Density and HRD logs. Now conditioning hole for casing. RECEIVED JUL 5- 1968 DIVISION OF MINES & MINER, ALS ANCHORAGE . 14 I hereby certl£~ ~ th~ i~r~g ~s tr~e a_nzi ~ ...... , ~ __ ~ SIG~ 1~[/ /~ District Drilling ~uperxncenaenc _ - - - ~r~ vi,,~ 7/3/68 w~th the D~v~s~on of M~ es & M~nerals by the 15th of the succeeding month, unless other,se d~rected STATE OF ALASKA O~L AND GAS CONSERVATION COMMITTEE MONTHLY REPORT OF DRILLING AND WORKOVER OPERATIONS i OIL ,~, GAS ~ WELL WW-LL OTHER SUBMIT IN DEPLICATE 2 NAME OF OPEP,2kTOR Union Oil Company of California 3 ADDRESS OF OPEI~ATOR 507 W. Northern Lights Boulevard, Anchorage. Alaska 9950~ 4 MCA~ON ~ ~ 1825'N and 1486'W from SE corner Section 29, T9N, R13W, SM ~ Alii NUA.{EKICAL CODE AP1 50-133-20115 LEASE DESiGNAiION AXD SEEIAL NC) ADL-17594 ? IF II%-DI iN %iXDTT~ OR TRIBE 8 LrNIT,FA/:LM OR LEASE Trading Bay Unit 9 WELJ~ NO State G-11 (32-32) 10 FTFJ,r) AND POOL OR WILDCAT McArthur River - Hemlock 11 SEC. T, R. M (BO~'TOM HOI~E Section 32~ T9N, R13W, SM 12 P]~R/~IT NO 68-43 /:;,Al 13 REPORT TOTAL DEPTH AT ElqD OF MONTH, CHANG~ IN HOLE SI~-E, CASING AND CEMENTING JOBS INCLUDING DEPTH SET ~ VOLUI~ USET), PF~OHATIONS, ~-F~TS ~ RESULTS FISHING JOBS. JLrNK IN HOLE ~ND SIDE-/q~CKED HOLE AND ANY O~{ER SIGNIFIC~kNT C~F~ IN HOI~ COI~ITIONS TRADING BAY UNt~ STATE G-11.....(32-32), MAY 19,68 Spudded 5/29/68 , 7:00 AM Drilled 15" hole to 720' and opened to 22". Ran 694' 16" 75# J-55 casing. Cemented thru shoe @ 694' w/2% CaC12. Installed 20" hydrill, tested - OK. Drilled 15" hole to 967'. Now drilling. w/1300 sx neat cement DIVISION OF ~Ni~S & MINERALS -- ~CHO~GE ~/~ ~ !l true and correct · /{](Il / IlIllll/ District Drilling Superintendent May 31 1968 SIGN-ED _ _ ~ _ ~_ J,q'&'~'WlF TITLE DA'ii NOT£--Report on th~$ f~m ~s reqmred ior each calendar month, regardless of the stat..$ of operations, anti re.st be fried m d~phcate w~th the D~wsmn of Mines &VMmera[$ by the 15th of the s.cceedmg month, ~n[ess otherwise d~rected Un~on Oil Company{Ir California 2805 Denal~ Street, Anchorage, Alaska 99503 Telephone (907) 277-1481 Robert T. Anderson D~stnct Land Manager unl In · May 27, 1968 RECEIVED hlAY $1968 DIVISION OF MINES & MINERAL8 /kNCHOP-AGE Division of Mines & Minerals Petroleum Branch 3001 Porcupine Drive Anchorage, Alaska 99504 TRADING BAY UNIT Cook Inlet, Alaska Permits to Drill Trading Bay Unit State G-11 (32-32) API 50-133-20115 Trading Bay Unit State G-12 (34-33) API 50-133-20116 Gentlemen: Please alter the subject Permits to Drill to show the following corrected information' G-11 No. of Acres in Lease: 5116 G-12 Lease Designation & Serial No.' ADL 18730 All other information on said Permits remains unchanged. Please indicate your approval of the above changes on the attached copy of this letter and return same to this office. Very truly yours, WSM:jb Approved this ~ day of May, 1968. ~-~ C-,~ Tit 1 e ,; s ~,na~. ~~-~'~ -- -'orm 401 ANC-A (New 7/67) 1968 thtton Oil Coupm~ of Caltforuta, Opera,or Dear Sir: Very tr~Xy yeur~, ~ar~, Jr. Supervisor FORM SA lB 1'25 5M 8/67 MEMORANDUM TO: r State of Alaska FROM: DATE : SUBJECT: FORM SA- I B 125 5M 8/67 MEMORANDUM TO: F" FROM: ( State of Alaska DATE SUBJECT: Form P--1 REV reverse side) STATE OF ALASKA MAY 1 4 196. OiL AND GAS CONSERVATIIJ~tV~iJ~iF~j'$ ~ ~~ APPLICATION FOR PERMIT TO DRILL, DEEPE RI~.UG BACK la. TYPE OF WORK DRILL [] DEEPEN [] PLUG BACK [] b. TYPE OF WELL OIL ~ O&8 ~] SINGLE [~] MLLTIPLE [--] WELL WELL OTHER ZONE ZONE 2 NAME OF OPERATOR Union Oil Company of California 3 ADDRESS (~F OPERA~R 2805 Denali Street, Anchorage, Alaska 99503 LOCATION O~ WF~L Atsurface Conductor 21, Leg 4, 1825'N & 1486'W from SE corner Section 29, T9N, R13W, S.M. Atpropo~dp~d zone Top Hemlock, 1980'S, 1980'W, NE corner Section 32, T9N, R13W, S.M. 13 DISTANCE IN MIL~ AND DIRECTION F2OM NEAREST TOWN OR POST OFFIC~ 23 air miles NW of Kenai, Alaska API 50-133-2&115 5. $ LEASE DESIGNATION AND SI~L NO ADL 17594 IF INDIAN. A/J_~'z-r~:,: OR TREBE NAME 8 UNIT~ FARM OR LEASE NAME Trading Bay Unit 9 V~ELL NO State G-ii (32-32) 10 FIELD AND POOL, OR WILDCAT McArthur River - Hemlock 11 SEC , T, R , M , (BOTTOM HOLE OBJECTIVE) Section 32, T9N, R13W, SM BOND INFORMATION Statewide $100,000.00 TYPE Aznount United Pacific Insurance Company B-55372 Surety and/or No i l8 NO. OF ACRES IN LEASE 98o, J ~ Jig PROPOSED IDEPTI-~ ! [10825~MD & 9900~VD DISTANCE FROM PROPOSED* LOCATION TO NEAREST PROPERTY OR LEASE LINE, FT (Also to nearest drag, unit, ~£ any) 18 DISTANCE FROM PROPOSED LOCATION* TO NEAREST WELL DRILLING, COMPLETED. OR APPLIED FOR, FT 2100' 21 ELEVATIONS (Show whether DF, RT, C-R, etc ) 99' RT above MSL 23 PROPOSED CASING AND CEMENTING PROGRAM 17 NO ACRES ASSIGNED TO THiS WELL 160 20 ROTARY OR CABLE TOOLS Rotary 22. APPROX DATE WORK WILL START* May 25, 1968 SIZE OF HOLE SIZE OF CASING WEIGHT PER FOOT GRAD~ [ I S~"FITNG DEPT~I QUANTIT~ -- ~ ..... 22,, 16" 75 J-SS 600 ' 1200 sacks 18" 15-5/8" 61 J-55 5000' 2000 " 12-1/4" 9-5/8" ,40~45.5~ 47 N~P 10p10q' 2000 .... 8-1/2" 7" .... 29 'NJ'80 10~825' 400 " Cement 16" casing in 22" hole at 600'. Install 2000t Hydrill. Cement 13-3/8" casing in 18" directional hole at 3,000'. Install BOPE. Drill 12-1/4" directional hole to 10,100'. Run electric logs. Cement 9-5/8" casing. Drill 8-1/2" directional hole to 10,825'. Run electric logs. Cement 7" liner. Complete for production. Bottom Hole Location: Approximately 2300'S & 2000'W from NE corner Section 32~ T9N, R13W, S.M. IAI ABOVE SPACE DESCP,/BE PROPOSED PROGRAM If proposal is to deepen or plug back, give data on present productive zone and proposed new productxve zone If proposal ~s to drill or deepen d~reet_onally, give pertinent data on mibsurface lc~atmns and measured and true vertical depths Gxve blowout preventer program 24 I hereby certify that t~.~Foregomg is True and Cprreet j~o ~ ~ ...... May 13 1968 (This space for State office use) CONDitIONS OF APPROVAL, IF ANY: District Land Manager SA1VIPLES AND CORE CHIPS REQUII~ YES ~ NO DIRECTIONAL SURVEY KEQUIRED ~ YES [] NO OTHER REQUIREMENTS A P I NIIMERICAL CODE APPROVAL DATE MARSHALL THOMAS / *See Instructions O./~~,~e~o~ DATE G-lO (14-29) UNION-MAEATHON ADL- 17594 G-5 _2.9 (34- 29) 1 6 (14-21) 2J PROP TOP H EMLDCK TMD 10,150' /I TVD 9270' /, O-II 0 PROP 8. H.LO¢ (32-32) TMD I0, 825' ,~_-~ TVD 9900' D-I ~ ( 34 - 22) / / / / / / / / RECEIV O MAY 14 19Bl "- G-8 '0 (32-3~) T9N- RI3W UNION -MARATHON ADL 18730 pI¥1,SK3~N OF MINES & MINEiu.~ - ANC].,IORAGE $-9 .._....-.---'0' (32-27) TMD 15, I00' TVD I0,270' D-2 22-5) ~V UN ION OIL COMPANY OF CALIFORNIA ALASKA DISTRICT WELL LOCATION MAP UNION OIL CO. OPERATOR UNION TRADING BAY STATE UNIT G-II DATE APRIL 1968 SCALE I"= 2000' ~) I000' ZOO0' I i i i ! I ! [ I I J