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201-046
• STATE OF ALASKA RECEIVED 411,SKA OIL AND GAS CONSERVATION CC*SSION REPORT OF SUNDRY WELL OPERATIONS APR 2 ' 2018 1.Operations Abandon ❑ Plug Perforations 0 Fracture Stimulate ❑ Pull Tubing Elo s eu- u., ❑ Performed: Suspend CI 0 Other Stimulate ❑ Alter Casing 0 Change pproves •rogram 0 Plug for Redrill 0 Perforate New Pool ❑ Repair Well 0 Re-enter Susp Well❑ Other:Run Kill String CI 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory❑ 201-046 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service 0 6.API Number: Anchorage,AK 99503 50-733-20157-02-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018722 Trading Bay Unit K-13RD2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 15,485 feet Plugs measured N/A feet true vertical 9,738 feet Junk measured 8,235 feet Effective Depth measured 8,235 feet Packer measured See Schematic feet true vertical 6,770 feet true vertical See Schematic feet Casing Length Size MD TVD Burst Collapse Surface 5,011' 13-3/8" 5,011' 4,183' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,164' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,659' 8,160 psi 7,030 psi Liner 3,748' 4-1/2" 12,320' 9,600' 8,430 psi 7,500 psi Liner 1,459' 4-1/2" 13,779' 9,772' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"slotted 15,385' 9,742' slotted slotted 12,520-13,675 Perforation depth Measured depth 13,779-15,385 slotted feet 9,701 -9,776 True Vertical depth 9,772-9,742 slotted feet 4-1/2" 12.75#/L-80 1,517(MD) 1,502(TVD) Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.75#/L-80 8,262(MD) 6,792(TVD) Packers and SSSV(type,measured and true vertical depth) See Schematic 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 38 Subsequent to operation: 0 0 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory ❑ Development9 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 WAG ❑ GINJ❑ 3USP0 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: 318-027 Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: ��Opeer�rations�Mannager Contact Email: dmarlowe hilcorp.com Authorized Signature: 56, — `-' Date: d'L 1 1.4 i t$ Contact Phone: (907)283-1329 74 5.1.1q Form 10-404 Revised 4/2017 RBDMS�� APR 3 0 2018 Submit Original Only Trading Bay Unit n • SCHEMATIC • Wel :Salmon K 13RD2atform PTD:201-046 50-733-20157-02 Ililcarp Alaska,LLC Completed: 03/27/18 RKBtoTbgHanger=33.77' CASING DETAIL Size T Grade Conn ID Top Btm 13-3/8" W 61 J-55 BTC 12.415" Surf 2,509' 68 1-55 BTC 12.415" 2,509' 5,011' 9 5/8„ 47 N-80 BTC 8.681" Surf 4,749' 13-3/8" 47 5 95 BTC 8.681" 4,749' 8,707'(T.O.W.) 7"Liner 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Tie Back Liner 12.75 L-80 Hydril 503 3.958" 8,572' 12,320' 4-1/2"Liner 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' **4-1/2"Slotted Liner 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' _ **2-1/2"x 1/8"slots,16 slots/ft Casing TUBING DETAIL damage 1,517' •@8184' 4-1/2" 12.75 L-80 Hydril 503 3.958" Surf Kill String 6.293" 4-1/2" 12.75 L-80 Hydril 503 3.958" 8,235' 8,262' restriction TCF azss I TUBING JEWELRY DETAIL No Depth Depth ID OD Item 41. (MD) (ND) 33.50' 33.50' Hanger 1 8,262' 6,792' N/A 5.620 Bolt-On Discharge 8,262' 6,792' N/A 5.620 Pump(x2)49 Stage,SK15500 8,306' 6,828' N/A 5.620 Gas Separator/Intake M4 21 1 8,307' 6,829' N/A 5.130 Tandem Seals 9-5/8" C 2 (Q1 8,325' 6,844' N/A 5.620 Motor(x2)562,500 HP,KMSUT&KMSLT . Go�I _ 8,392' 6,899' N/A 5.620 Gauge/Centralizer/Bullnose Anode LINER JEWELRY DETAIL Casing leak2 8,572' 7,049' 5.000 5.980 Tie Back Receptacle w/3.6'sealbore 8'977 $'�� 8,576' 7,053' 4.000 5.880 Packer-Hydraulic Permanent 3 12,308' 9,594' 3.812 5.580 X-Nipple 4 12,320' 9,600' 4.280 5.230 Seal Assembly w/5.70"No-Go 12,320' 9,600' 5.250 5.780 Baker ZXP Tie Back Sleeve 5 12,334' 9,608' 4.276 5.880 Baker ZXP Packer 12,339' 9,610' 4.385 5.820 Baker HMC Liner Hanger 6 13,696' 9,775' 3.875 - ECP Packer(Inflated w/Mud) 7 13,779' 9,772' 3.875 4.500 Top of Slotted Liner 8 15,348' 9,743' 2.00 4.500 Baker Pack-off Bushing ':: 9 15,383' 9,742' N/A 4.500 Baker Type"V"Set Shoe w/Float IS X 4 EI 5 41 6 7' Perforation Detail mm I-K-1 m Zone Top Btm Top Btm.... tFT SPF Date Comments HK-2 (MD) (MD) (ND) (TVD) s HK 1-2 12,520' 13,675' 9,701' 9,776' 1,155' 6 05/31/2016 Open 6 cz23 HK-2 12,580' 12,600' 9,726' 9,733' 20' 6 05/09/2006 Open II HK-2 13,779' 15,385' 9,772' 9,742' 1,606' *16 06/19/2001 *Slotted Liner I I hK-2 I I Fish/Other Information: Lost 1 roller 2.6"dia.X.25"thick off of Schlumberger roller stem 4-1/2" Note: Slotted Liner at Near-Horizontal in HB-2 Al l 8,9 PBTD:15,383' TD:15,485' 90 Deg Section at 13,000'MD MAX HOLE ANGLE=94.75°@ 13,413' Updated By:JLL 04/19/18 ' • • Hilcorp Alaska, LL_ �N��|| Operations Summary ' ' ~'' Well Name Rig API Number Well Permit Number Start Date End Date K'13RD2 Moncla 404 58-733'20157'02 201'046 3/8/18 3/28/17 03/08/18-Thursday Assisted production breaking lines and removing SSV from tree- N/D tree. NOS checked hanger threads and M/U 4 1/2" IBT x blank LHR test sub. Installed rubber ring gasket and stacked 13 5/8" 5M BOPE equipment (spool w/ hub adapter, riser, spool, mud cross w/2 1/16" hyd and manual valve on each side, double gate w/ blind and 2 7/8" x 5" VBR and annular). Finished torquing all valves and bop components with hydraulic torque wrench. Raised derrick and penned to A-Frame. Off driller's side pen pocket would not line up. Moncla mechanic worked on the pen pocket 2 hrs. Attempted to scope up derrick-wind gusts 40 to 45 mph (reported by crane op). Decision was made to wait till winds decreased. Installed drill line to draw works-connected all accumulator lines to components. Installed steps from the pipe rack to the driller's shack- hooked up power cable to remote koomey controls in driller shack, hooked up heater trunks to the BOPs and under rig carrier. 03/0q/18- Friday Mounted rig floor w/supports. Installed wind walls and wrapped BOP stack with herculiner, ran heat truck to stack. Ran heat to choke house, driller's shack and accumulator unit. Ran hose from WF to rig tank. Loaded rig floor with handling tools and McCoy tongs. K4/U41/Z" test jte/ LHR sub onbtm' pumpin, SV, |BOP, 1SU2ontop. Wrapped K. 3 w/insulation and setup test pump w/chart recorder. Welder fabed cover for super choke and break water tank. Checked all nitrogen and accumulator bottles and recorded pressures. Continued setting up for pre-test. Began BOPE pre-test (250-3000 PSI) working thru leaks: (1) backed out test jt w/hanger connector and reworked w/ thread tape and dope (2) had to tighten door seal on blind ram body(3) leak on HCR valve (4) leaking safety valve. Continuing thru pretest. 03/10/18 Saturday Continued pretesting BOPE working thru leaks. Performed successful (pre) koomey drawdown test.Tested all BOPE to 250 psi low 3000 psi high as per Sundry in accordance with Hilcorp &AOGCC requirements. Performed successful koomey draw down test tested w/4 1/2" tb only. Checked PVT system on rig tank- production personnel tested gas alarm systems. All tests were witnessed by Matthew Herrera/AOGCC. One FP on manual wing valve-corrected by greasing. Onloaded Summit pulling equipment from M/V Titon during test. R/D test jt after pulling blanked LHR test sub from hanger threads- pulled BPV- backed out HD pins while M/U 4 1/2" IBT landing jt w/SV installed. Screwed into hanger. P/U on string and hanger moved off seat at 100k- pulled up to 180k w/o pipe moving free. Worked pipe from 105k to 180k while discussing plans with engineering. Called for Pollard ELine crew and equipment will capability to FP &cut or perf. Continued periodically working pipe as before while waiting on crew& equipment. Pressured up to 1000 psi down tb in attempts to circ but had no fluid movement- released pressure- continued working pipe as before. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Daily Operations: �� 03/11/18-Sunday Worked production string from 105k to 180k periodically while waiting on Pollard ELine crew to arrive. Pressured up down tb in attempts to circ but had no fluid movement- bled off pressure. Continued working as before. ELine crew arrived. Held PJSM w/ Pollard and rig crew prior to R/U. Welder arrived to modify beaver slide in order make laying down tb easier. Pollard reheaded their unit. R/U Pollard Eline unit- hung sheave in derrick and M/U 1 3/8" free point tool w/ bow springs set at 4 3/8". Prior to running in hole, stretch readings were taken at surface- worked pipe from 110k to 150k getting 14" of stretch which equates to "possible" stuck point at 4,000' (deviated wells make this type of freepoint reading inaccurate). RIH w/ FP to 3,010' and took stretch reading- 100%free there. Continued in hole and tagged at 3,230'-could not get deeper(no reading taken). Discussed plan forward with Eng-directed to make gauge run. RIH w/ 1 11/16" wt bar and collar locator to top of ESP pump assy-tagged @ 8,262' (ELM). POOH. Discussed plan forward with Eng-directed to standby for orders. Rig crew continued organizing and cleaning. 03/12/18- Monday Continued working prod string while waiting on Pollard tools to arrive. Rig crew cleaning and organizing. M/U 1 7/16" Motorized FP tool w/ 1- 5' 1 7/16" Wt bar and ccl. TIH to 2,520' and setup tool- 100%free readings @ 3,350' & 3,850', 30%free reading @ 4,500', 0%free reading at 5,000'. Worked uphole taking reading: 0%free at 4,750', 30- 45%free from 4,315' to 4,100'-tool would not repeat 100%free reading @ 3,850' (no confidence in tool). Conferred with Eng- POOH. Run #2 M/U 1 7/16" spring-type freepoint w/ 1 11/16" tungsten wt bar. TIH to 2,000' and setup tool- 100%free readings from 3,350'to 7,400'. 70%free reading @ 7,450', 10%free reading at 7,508, 7,608'-0%free. POOH. M/U string shot loaded w/240 grains of primacord. P/U string weight to 185k and set on slips. RIH w/string shot to 8,242' and fired shot, POOH and rigged EL to side. Worked prod string for 30 mins-did not pull free. M/U 2nd 240 grn stringshot and TIH to same depth-fired shot and POOH-worked string with same results. M/U 3rd 240 grn stringshot and TIH to 7,525'-fired shot with 185k sitting on slips- POOH and rigged EL to side. Worked pipe from 105k to 185k-tb did not pull free. Continued working prod string while Pollard M/U 1 9/16" EHC Idd 3' 4 SPF with circulation charges (Owen Tb puncher 453/.41 hole).TIH w/ perf gun tagging at 8,262' (top of ESP assy)- pulled CCL strip and fired gun perfing 8,235-38' (no surface indication). POOH and rigged EL to side. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 03/13/18-Tuesday Lined up to pump down tb in efforts to break circulation- pressured up to 1000 psi and pressure bled back- keep pump pressure near 1000 @ 1/2 bpm and began getting returns. Pressure dropped so pump rate was increased to 2.5 bpm @ 600 w/full returns. Stopped pumping and worked pipe from 105k to 185k-could not pull ESP assy loose. Stopped working pipe and set same on slips at 185k. Began pumping again LW at 1.3 bpm 1400 psi- reversed fluid flow briefly then began pumping LW again at 3.3 bpm 600 psi. Received CFS-520 from M/V Titon (but it was frozen). Continued circ while thawing friction reducer.Trickled CFS-520 into rig tank at suction while circulating. Adjusted annular from 1400 psi to 650 psi and began working production string while circulating 3 bpm 550 psi LW. Continue adding friction reducer while working prod string (total of 2 drums added). No success in pulling ESP assy. Stopped circulating and attempted to bullhead down casing (past esp)- pressured up to 1400 psi w/ no bleed down- work pipe w/ no pressure loss. Lined up and began circulating LW again with increased pressure at reduced rate. Conferred with Eng- decision was made to cut tubing. R/U Pollard eline unit- M/U 2.5" radial torch cutter- RIH/with cutter t/8,238' (pulled strip and positioned cutter at btm of tb perfs)-cut tubing @ 8,238 (indication of cut but no separation)- POOH. Rigged ELine to side- worked pipe as before but could not pull cut- relayed info to Eng. Decision was made to cut above called freepoint @ 7,400'. 03/14/18-:Wednesday TIH w/2 1/2" RTC to 7,450'. Pulled ccl strip and position cutter at 7,380' -set anchor tool and fired cutter w/ 155k sitting. Logged back thru and observed separation at cut depth. POOH. B/D spent RTC- latched & picked up pipe off slips to check weight- now weighing 95k(155k set on set prior to cut). Pollard M/U 2"jet cutter and TIH to 7,380'- fired cutter in separation at RTC cut in attempt to sever/weaken ESP flatpack cable and 1/4" control lines. POOH and R/D ELine. Lined up to reverse hole clean-circulated 15,000 strokes (542 bbls FIW) around at 3.5 bpm 160 psi- minimal solids (hand full of gravel and fine sand in possum belly) in returns during circulation. R/D ELine and moved Summit pulling equipment into position. Pulled hanger to floor with string weighting 100k and B/D same. Held tailgate meeting with rig and crane crew, Summit, Karson and JC. Pulled enough cable to R/U Summit. POOH w/ RTC cut production string laying down singles in flying pipe racks (strapping recovery)- Pumped 3 bbls FIW (displacement) every 16 jts. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date • K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Dail"Operations 03/15/18-Thursday Finished POOH w/partial production string cut at 7,380' (ELM)- pumping 3 bbls FIW (displacement) every 16 jts laid down. Laid down 238 jts plus 1-cut piece, hanger and hanger pup-with elevation total recovery= 7,369.07' (strap). ESP cable 9' longer than EOT-flatpack cable 41' longer than EOT. Recovered 121 clamps (none missing). R/D & move Summit pulling equipment. Clear& clean rig floor. Moved recovered prod tb to M/V- brought workstring onboard- P/U BJs. Swapped out Moncla heaters. M/U WFT BHA#1-8 1/8" overshot Idd w/4 1/2" basket grapple plus upper ext and top sub, tightened to specs. Laid down BJs. P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars, 6-4 3/4" x 2 1/4" (Hilcorp) DCs, 4 3/4" x 2 1/4" Acc jar, 4 3/4" x 2 11/16" xover sub= 226.11'.TIH picking up 3 1/2" 12.75# P-110 PH-6 workstring-strapping, drifting and torqueing to 6000 FPT. Stopped at 5,375' and R/U hose - established circ rate @ 3 bpm 250 PSI-circ 1 1/2 tb volumns (37 bbls) SW. Continued TIH picking up 3 1/2" 12.75# P-110 PH-6 workstring-strapping, drifting and torqueing to 6000 FPT. Stopped at 6,590' and R/U hose-established circ rate @ 2 .6 bpm 235 psi-circ 1 1/2 tb volumns (45 bbls) SW. Continue TIH picking up 3 1/2" 12.75# P-110 PH-6 workstring-strapping, drifting and torqueing to 6000 FPT. RIH a total of 229 jts+ BHA= 7,336'. Began N/U stripping head. 03/16/18 Friday Finished N/U 7 1/16" stripping head on top of 11" x 13 5/8" 5m spool (after removing 2' 13 5/8" 5m spool). P/U swivel. BOPE testing error was identified by Mr. Quick (failure to test w/3 1/2" tb prior to RIH) -call was made to notify Mr. Regg/AOGCC. His directions allow us to test immediately by landing test plug, w/3 1/2" &4 1/2" tb, one day early, witness waived. Laid down swivel. N/D stripping head w/adapter spool- N/U 13 5/8" 5M spool- pulled single#229 from well. M/U test plug on 3 1/21 jt of PH-6.Tested all BOPE to 250 psi low 3000 psi high as per Sundry in accordance with Hilcorp &AOGCC requirements. Performed successful koomey draw down test-tested w/4 1/2" and 3 1/2" tb. Checked PVT system on rig tank- production personnel tested gas alarm systems. Witness waved by Jim Regg/AOGCC. R/D test equipment and pulled test plug- B/D same. P/U jt#229 and RIH to 7,336'. N/D spool N/U stripping head w/adapter. P/U power swivel w/single #230- installed stripping rubber- M/U to string and landed rubber. PUW 85k SOW 59k-eased down to 7,378'- broke circ SW at 3 bpm 350 psi and flushed well clean from last circ at 6,590'. S/D pump. M/U 18.64' of pups on swivel -eased down while circ LW and tagged fish at 7,378' (PM). Latched fish and pulled pipe uphole 2' (weight reported at 88k). B/O L/D power swivel. R/U Pollard Eline- RIH w/ 1.83"jet cutter and attempted to go thru TOF but failed. POOH and re-rigged ELine sheave in derrick.TBI and worked thru TOF- RIH to cut depth @ 8,238' (but could not go past cut depth). Presently attempting to determine if pipe has moved uphole before firing jet cutter to cut/damage ESP cable &control line before pulling on pipe. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Daily Operations; , :;, � , 03/17/18-Saturday Continued attempting to record collar locator strips in order to determine if fish moves when pipe is picked up (being mindful not to P/U pipe high enough to break ESP cable or control lines prior to firing cutter at previous RTC depth-8,238').While attempting to work ELine back inside overshot/fishing assy CCL began to fail. POOH w/ ELine- Supervisor determined that line was shorted —8,000'. Called for unit. Decision was made to check ovs latch. P/U string 6' w/2k weight gain -slacked down to B jar closure. R/U swivel and P/U 6'-started rotating string slowly at 2000 FPT-eased down to just above jar closure and torque increased "' 200 FP. Kept applying slight weight down but could not get deeper-torque would increase slightly but no stall out (max torque seen was 2500 FPT). Attempted to latch while circ LW. NoGo. Discussed situation w/ Eng-decision was made to POOH. R/D swivel- N/D stripping head- N/U 2'13 5/8" spool. POOH to BHA. M/V Titan arrived-onloaded replacement ELine unit from Pollard -offloaded unit w/shorted line. B/D WFT BHA#1- no sign of fish entering grapple, minor metal in teeth of mill control pkr, overshot guide not deformed in any way.Asked WFT to build an ocean wave shoe, SOD necked down to 4 1/2". Shoe was delivered to heliport at 22:00 hrs-OSK heliport on weather hold-decision was made to add mill guide on overshot and TIH. M/U WFT BHA#2-8 1/8" overshot Idd w/4 1/2" basket grapple-guide is dressed to 4 1/2" ID plus upper ext and top sub, tightened to specs. Laid down BJs. P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars, 6-4 3/4" x 2 1/4" (Hilcorp) DCs, 4 3/4" x 2 1/4" Acc jar, 4 3/4" x 2 11/16" xover sub = 226.17.TIH w/ WFT BHA#2 on 3 1/2" 12.75# P-110 PH-6 workstring to 7,367' (115 stands+ BHA). N/D 13 5/8" spool. N/U stripping head w/adapter. 03/18/18-Sunday Finished N/U stripping head & DSA w/ 11" x 13 5/8" adapter spool. P/U power swivel and added pups- installed rubber and M/U to string- landed rubber. Broke circ SW at 2.5 bpm 200 psi- began turning power swivel at 30 rpms 2000 FPT- PUW 83k SOW 60k. Eased down tagging at 7,378'- rotated for 40 mins gradually added more weight w/ torque increasing to 3000 FPT. Had to stop operation for 25 mins while repairing chain drive on rig pump oiler. Continued rotating &circ as before for 60 mins- unable to engage TOF (no hole made). Contacted Op Engs and discussed details and plan forward. Made another attempt to latch fish by working bumper jar in efforts to drive overshot over TOF-was able to get overpull but could not maintain it (probably due to wedging beside junk/wire or cutting into TOF). Circ btms up-fine metal shavings on magnetic in possum belly- no solids. R/D swivel- Laid out pups- had to circulate 3000 stks SW to stabilize well. N/D stripping head w/adapter spool- N/U 13 5/8" spool. POOH w/WFT BHA#2 pumping 5 bbls FIW every 20 stands and std back 4 3/4" D.0 and L/D WFT over shot w/small pieces of junk tubing stuck in over shot guide. No damage to cut-lip guide on overshot. Clean up floor and R/U pollard eline w/ccl, 7 FT wb and 6" LIB rih t/7374' w/elm set down 2 times and POOH. 4 1/2" tubing half moon mark on face of tool. R/D eline unit. M/U WFT BHA#3-8 1/2" sod x tapered 4 1/2" ID ocean wave shoe, and 8 1/8'top sub,tightened to specs- laid down Bis P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars, 6-4 3/4" x 2 1/4" (Hilcorp) DCs,4 3/4" x 2 1/4" Acc jar, 4 3/4" x 2 11/16" xover sub= 224.60'.TIH w/WFT BHA#3 on 3 1/2" 12.75# P- 110 PH-6 workstring to 7365.48 (115 stands+ BHA). N/D 2' 13 5/8" 5M spool N/U 7 1/16" stripping head w/ DSA & 11" x 13 5/8" adapter spool. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Daily Operatk ns "; 03/19/18- Monday Finshed N/U 7 1/16" stripping head. P/U power swivel and M/U pups. Installed rubber and M/U to string- landed rubber. PUW 84k SOW 60k, Rot Wt 70k, 3000 FPT @ 60 RPMs, initial circ rate SW @ 2.5 bpm 220 psi. Began milling- when 4 1/2" section of shoe went over fish, pressure increased to 1700 psi @ .5 bpm-turned fluid and started circ LW at .5 bpm 700 psi. Milled from 7,378' to 7,379.5' in 3.5 hrs- no hole made in the last 1 1/2 hr.Jarred down slightly in efforts to make additional hole- no go. Picked up off fish and circulated hole clean SW at 3 bpm 340 psi. L/D swivel- N/D stripping head on DSA w/adapter spool- N/U 2' 13 5/8" spool. Pulled and L/D pup jts. POOH w/ WFT BHA#3 pumping 5 bbls FIW every 20 stands- B/D BHA. All indications shows that the 4 1/2'tubing was inside the wave shoe. M/U WFT BHA#4- Itco flush type spear dressed w/3.947 grapple, xo sub, dps, 8 1/2" sod ows,tcts, xo sub,tightened to specs. Laid down Ills. P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars, 6-4 3/4" x 2 1/4" (Hilcorp) DCs, 4 3/4" x 2 1/4" Acc jar,4 3/4" x 2 11/16" xover sub = 225.10'.TIH w/WFT BHA#4 on 3 1/2" 12.75# P-110 PH- 6 workstring to 7,366' (115 stands+ BHA). N/U 7 1/16" stripping head - P/U power swivel and M/U pups- installed rubber and M/U to string- landed rubber. 03/20/18-Tuesday P/U swivel- M/U pups- installed rubber on pups- M/U to string and land rubber. PUW 84k SOW 60k-eased down and tagged at 7,381'. Continued slacking off on string- @ 10k down spear started entering TOF- 13k down spear bottomed out in fish. P/U to 90k then set back down to 35k. R/D swivel-worked string hitting jars at 135k then pulling up to 185k. At 22 jars, we lost latch or something parted-could not relatch (2" of movement/stretch measured during jarring operation). L/D swivel breaking off xovers &valve (broke pin in carriage and 1- die set- repaired Gill tong). N/D stripping head N/U 2' 13 5/8" spool-cleared floor of all unnecessary equipment. POOH w/ WFT BHA#4 pumping 5 bbls FIW every 20 stands. 1415 hrs held trip drill-securing well, shuting down rig engine and heaters in 35 secs, derrick man down in + 13 secs. Finished POOH to BHA. L/D spear and 4.1' piece of 4 1/2" tubing. Discussed plan forward and BHA with Engineers. M/U WFT BHA#5 8 1/2" SOD x 4 1/2" tapered ID, 8 1/8" xo bushing, 8 1/8" bowen ovs bowl Idd w/4 1/2" basket grapple, 8 1/8" upper ext and top sub, tightened to specs. Laid down Ws P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars, 6-4 3/4" x 2 1/4" (Hilcorp) DCs, 4 3/4" x 2 1/4" Acc jar, 4 3/4" x 2 11/16" xover sub = 231.24.TIH w/WFT BHA#5 on 3 1/2" 12.75# P-110 PH-6 workstring to 7,372' (115 stands & BHA) @ 2330 hrs held trip drill securing well, shuting down rig engine and heaters in 48 secs, derrick man down in + 20 secs. N/D 2' 13 5/8" 5M spool N/U 7 1/16" stripping head on 11" DSA w/ 11" x 13 5/8" spool. P/U swivel M/U pups installed rubber. M/U to string and landed rubber. PUW 81k SOW 62k- slacked off and tag fish @ 7,385'-stopped @ 7,388'-changed out pups for full jt of workstring. Eased down and covered 10.5' of fish w/ovs assy. Pulled 10k and reset grapple. R/D swivel (before jarring on fish). R/U to circ while working pipe. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Daily Operationsi ! .; 03/21/18-Wednesday Finished R/D swivel. Changed out elevators.Added pup w/side pumpin. Broke circulation at .1 bpm 900 psi LW. Worked pipe from 135k hitting jars then pulling up to 185k-on jar#93 circulation rate increased to 2.5 bpm 400 psi &fish broke free weighing 120k- moved 3' uphole.Slacked down low enough to R/U ELine. Continued circulating while waiting on ELine. Stopped circulating- no fines, metal or solids in returns. Reconfigured circ assy to facilitate working pipe while Eline was in the hole. R/U Pollard's top sheave in the derrick. Pollard M/U Run #1 (2" swedge on 1 1/2" spang jars w/ 1 11/16" CCL and 7' 1 7/16" wt bar and rope socket). TIH and set down at TOF (7,385') on 1st attempt. Went 7' inside fish next 3 attempts (did not set down). POOH, M/U Run #2 (1.83" Jet cutter w/CCL&wt bar)- RIH to 8,238' and tagged (RTC cut depth)- logged CCL strip and attempted to move pipe 3' uphole but pipe was stuck. POOH w/ ELine- R/U hose to break circulation and worked pipe briefly to free same- moved pipe uphole 3'. TBI w/ 1.83" cutter and tagged 1' higher at 8,237'- logged strip again and found that pipe had moved uphole 1'. Pulled pipe uphole another 1' (after breaking circ to free same) and relogged collars- btm &collars moved uphole 1' (could not log separation at RT cut). Pulled pipe uphole another 1' (same sticking issue) and relogged collars- btm & collars moved uphole 1' (could not log separation at RT cut). Informed Ops Eng and decision was made to POOH & R/D ELine. Started POOH having to circulate LW at 1 bpm 50-150 psi with overpull to 150k- LID 13 singles (403') before being able to pull pipe without circulating. Pulled 6-stands and N/D stripping head N/U 13 5/8" spool. POOH w/WFT BHA#5 pumping 5 bbls FIW every 20 stands- 36 stands OOH (6,006'). 03/22/18-Thursday Finished POOH to WFT BHA#5. B/D BHA- laid out overshot/shoe assy w/18.47' of 4 1/2" 12.75# L-80 503 Hydril prod tb. POOH L/D 27 full jts 4 1/2" 503 tb+2-cut pieces= 853.43' (top cut piece = 18.47, btm cut= 6.57') . New TOF after prod string recovery= 8,238'- ESP cable and control lines were folded over at 1st clamp under TOF-cable & control lines were broken at last clamp on tb- possible 6' of cable and control lines sticking above fish top at 8,238'- 19 clamps and 2- pieces of metal .095" thick recovered. Cleared and cleaned rig floor of all ESP pulling equipment-set back McCoy tongs and P/U BJs. B/D old BHA shucking fish- M/U new BHA(same as#5) (8 1/2" SOD x 4 1/2" tapered ID Ocean Wave shoe, 8 1/8" xo bushing, 8 1/8" bowen ovs bowl Idd w/4 1/2" basket grapple, 8 1/8" upper ext and top sub, tightened to specs- laid down BJs P/U Gill tongs. M/U 4 3/4" x 2 1/4" B&O jars(fresh oil jar), 6-4 3/4" x 2 1/4" (Hilcorp) DCs,4 3/4"x 2 1/4" Acc jar,4 3/4" x 2 11/16" xover sub= 231.24). RIH w/BHA#6 on 3 1/2" PH6 workstring to 6,969' (108 stands). N/U 2' 13 5/8" 5M spool N/U 7 1/16" stripping head on 11" DSA w/11" x 13 5/8" spool. R/U 13 singles to 7,372'-circ hole clean SW at 3.4 bpm 370 psi. Continued in hole picking up singles stopping at 7,465', 7,553', 7,651' and 7,745' circulating hole clean SW at same rate. P/U swivel M/U single#243 installed stripping rubber-screwed into string and landed rubber. Broke circulation then slacked off to 7,776'-circ hole clean SW at 3.3 bpm 360 psi. • S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 Dail O erations .. ' Y p •. `s�ra"�sA......i. ? � � wr�l , ;. .`. .,a 03/23/18- Friday Finished circulating hole clean SW @ 3.3 bpm 360 psi. Set back power swivel and N/D stripping head (but did not lift it over stub-well overbalanced on tb side). Circulated 2000+ 2000+ 1000 strokes LW to settle well. Removed stripping head and pulled single#243 from well. M/U test plug w/xovers on 3 1/2" tb then screwed into string- landed plug and M/U pumpin, SV& IBOP on top. Filled stack and shell tested to 3000 psi.Tested all BOPE to 250 psi low 3000 psi high as per Sundry in accordance with Hilcorp &AOGCC requirements. Performed successful koomey draw down test-tested w/4 1/2" and 3 1/2" tb. Checked PVT system on rig tank- production personnel tested gas alarm systems. Witness waived by Jim Regg/AOGCC 1535 hrs 22Mar18 (by email). Slipped and cut 130' of drill line (with test plug in hole). Pulled test plug and B/D test jt. N/U stripping head and p/u power swivel. PUW 97k SOW 69k-washed down SW @ 3 bpm 350 psi- P/U R/I singles from 7,776' to 8,049' circ 1. 1/2 tubing vols every joint- taking samples every 100'- heavy returns starting at 8.055' of sand, coal chips and possible mud products. Continued washing down experiencing slight plugging issues-taking 2-3 tubing volume to clean up. CHC @ 8,210' at report time. 03/24/18-Saturday M/U single#258 and break circ SW at 3.3 bpm 370 psi (8,210')-washed/rotated down to 8,229' in 1 hr 25 mins- began having plugging issues again. Rocked fluid back and forth but could not lose plug (rotating and dropping pipe) (circ .5 bpm 950 psi). Shutdown pump to check surface lines-found quarter size rocks in gooseneck on swivel. Cleared swivel gooseneck and began circ SW 3.3 bpm 360 psi. Flushed tb clean w/2000 strokes then began washing down from 8,229' to 8,231'. Continued having plugging issues- rocking fluid back&forth would usually clear plug. 1300 hrs pressure increased to 1200 psi (SW) and blew stripping rubber. Stopped pump, P/U and changed out rubber, B/O swivel and checked gooseneck(clear)-found plug in return line going to tank (seeing more quarter size rocks in returns). Changed out plugged lines and continued washing/rotating down from 8,232' circ LW at 2.4 bpm 600 psi (rev would pressure up). Began seeing torque at 8,235' (PM). Attempted to P/U and rev hole clean but pulled weight-slacked off to 50k and pulled 20k over string weight (100k) allowing jars to hit- P/U to 150k. Set back swivel, M/U SV and P/U HYC elevators. 1430 hrs began jarring at 150k picking up to 180k-worked 4' of travel in string occasionally losing travel. R/U hose and broke circulation LW-could move fish/BHA uphole with no trouble- shutdown pump and could not move uphole (2-3k weight gain). Discussed plan forward with Ops Eng-decision made to POOH. Pulled 2-singles while circulating w/20k-40k overpull- pulled 3rd single without pumping no overpull- R/D hose. POOH slow standing back workstring-at 10 stands out N/D stripping head N/U 2' spool- changed elevators. POOH w/WFT BHA#6 pumping 5 bbls FIW every 20 stands. B/D BHA#6-found 7" ball of compacted ESP cable & control line inside shoe-grapple untouched-one gallon of 1/2 dollar size rocks above ball of cable. Continued B/D BHA. 0 bbls fluid loss at this point in job-8 bbls of solids recovered: 80%sand, 15%coal, 5% rocks-the deeper we get the bigger the rocks get and the coarser the sand gets. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50'733'20157'02 201'846 3/8/18 3/28/17 03/25/18-Sunday Mill BHA#7 (8l/Z" SOD x63/4" RID flat btmshoe, 81/8" triple bushing, 61/4" x21]/16" XoverSub, 43/4" x2 1/4" B&Ojars, 6'43/4" x21/4" (Hi|corp) DCs,43/4" xZ1/4" Accjar,43/4" x2l1/16" xoversub = 2I4.S9'). Used EUoto tighten 8 1/8" connection-Gill tongs for remainder of BHA.TIH w/BHA on 3 1/2" 12.75# P'118 PH-6 workstring to8,173' (l28stands)' P/UR/| 1'single to8,204' N/DZ' 13S/8" 5Mspool- N/U71/l6" on11" DSA on 11" x 13 5/8" 5M spool. P/U swivel and M/U single#258- installed stripping rubber and WU to string- landed rubber. PUW 97k SOW 68K- Eased down w/#258 to 8,234' M/Upups and tagged at8,I3S'' P/U3' and established circ SVVat2.Sbpm 3UOpsi, swivel @5URPMs 3SUOFRT, RotVV8Ok. Milled/washed from 8,23S'tn8,238'- pressured up to 1050 psi-could not break circ either direction-checked surface lines and found no plug. Pressured up down tb to 2000 psi but could not jar plug loose. While bleeding pressure crew member heard plug/rocks moving thru manifold- lined up SW and established circ at 2.3 bpm 500 psi-circ 1 1/2 tb volumns 1' off tb stub. Washed down from 8,238 to 8,239'- (with minor plugging) circulated hole clean SW before L/D swivel. B/0 swivel and backed off pups'setbackswive|' N/DstrippingheadN/U2' spoo|, POOHw/VVFTBHA#7pumpingdisp|ucementevery2U stands. L/D shoe and ext and recover ball of esp cable and chunk ofrubber. K4/UBHA#8 (8l/8" over shot w/ hollow mill guide dressed to41/I', 81/8" top ext, 61/4" xI13/16" XoverSub, 43/4" xZ1/4'' B&Ojars, 6-43/4" x21/4'' (Hi|corp) D[s,43/4" xZ1/4" Accjar,43/4" xJ1l/16" xoversub= 2Z6.l7'). Used B]stntighten 81/8" connection-Gill tongs for remainder of BHA.TIH w/ BHA on 3 1/2" 12.75# P'118 PH-6 workstring to 5,812' (90 stands) at report time. 0 bbls fluid loss at this point in job-8 1/4 bbls of solids recovered: 80%sand, 15%coal, 5% rocks-the deeper we get the bigger the rocks get and the coarser the sand gets. 03/26/18- Monday Continued R|Hw/VVFTBHA#8 (81/8" over shot w/ hollow mill guide dressed tu4l/I" ID, 81/8" top ext, 61/4" xZ 13/16" XoverSub, 43/4"x21/4" B&'Ojars, 6'43/4" x2l/4" (Hi|oorp) DCs,43/4" x21/4" Accjar,43/4" x2 11/16" xoversub= ZI6.17'). PUVV92kSOW 66k'tagged TOFat8,Z35''slacked down toS0kwatching overshot cover fish. Pulled 20k over fishing string wt and slacked back to 50k-jarred on tb at 135k then pulling to 180k- attempted to circ LW- pressured up to~800#s while working pipe. Jarred for 45 mins then rig crew inspected derrick. Continued jarring-something turned loose at 18th jar- lost all pressure (~750 psi).Attempted to relatch fish but no indication of going back over fish-2-3k overpulled at P/U. Laid out pups and tb was standing full- rigged up mud bucket-changed out Gill tongs and power pack (had to replumb hoses for power pack). POOH w/WFT BHA#8 pumping 5 bbl FIW displacement every 20 stands. B/D BHA#8. Grapple in overshot was damaged. Discussed plan forward with Ops Eng-decision was made to suspend cleanout operation on well. RIH w/WFT BHA- B/D L/0 all fishing tools. RIH w/ 129 stands (8,004') of 3 1/2" PH-6 workstring. POOH laying down workstring pumping displacement every 40 jts.0 bbls fluid loss at this point in job-8 1/4 bbls of solids recovered: 80%sand, 15% coal, 5% rocks. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 3/8/18 3/28/17 03/27/18-Tuesday Finished POOH laying down 3 1/2" PH-6 workstring. Broke subs off power swivel and packed up same for transport to Grayling. Worked M/V Titan off loading all vendor and un-needed equipment to be sent to OSK- P/U 4 1/2" elevators and slips- prepped floor to run in kill string. M/U 6.3' cut-piece of 4 1/2" 12.75# L-80 Hydril 503 tb on btm of 1st full jt of kill string. Ran in 48 full jts. P/U and RIH W/48 joints of 4.5" kill string to 1,517.06' (w/ hanger, pup & elevation). M/U hanger- installed BPV then M/U landing jt-attempted to land hanger but had difficulty working thru annular(rubber damaged). Landed hanger on seat- B/O L/D landing jt. Cleared and R/D floor-scoped down and laid over derrick. N/D 13 5/8" 5M BOP stack.Viewed hanger in tb head and observed that both seals were rolled/cut off of hanger. Contacted Ops Eng who contacted Mr. Schwartz/AOGCC and received verbal approval (at 5:44 AM)to lift hanger and make repair without N/U BOPE. 0 bbls fluid loss during job-8 1/4 bbls of solids recovered: 80%sand, 15%coal, 5% rocks. 03/28/18-Wednesday Placed new body seals on top of hanger-screwed 4 1/2" IBT landing jt into hanger threads using crane to handle jt. P/U 18k and pulled hanger above tb head. Changed out seals and lowered hanger down to seat. No damage to seals.Verbal and email confirmation received from Mr. Schwartz/AOGCC prior to replacing seals (email in well file). Changed orings on hanger neck- lowered tree into position and installed clamp. Bolted blind flanges on wing section of tree. Continued prepping W/O package to be moved to Grayling. Offloaded annular preventer on to M/V Resolution to be sent to OSK for Weatherford to repair and send back to Grayling.Vacuumed drilling mud from rig tank into cutting boxes. Tied onto derrick with crane and unpinned same- loaded same on M/V Titan. Loaded draw works and A-frame. NOS rep tested hanger void to 500#s f/5 mins 5000#s f/ 15 mins. Pulled BPV and installed 2- way check-visually shell tested tree to 1500#s (because of pressure rating on blind flange). Loaded rig carrier, load connex, load out Moncla crew on boat, rig supervisors and crane crew to Grayling via helicopter. Arrived on Grayling and held PJSA with production crew and had safety orientation. Moncla crew began unloading boat and making up rig beams. Closed K-13RD2 Report @ Midnight. • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday, March 28, 2018 6:08 AM To: Schwartz, Guy L(DOA) Cc: Juanita Lovett; Michael Quick;S -• . 's Subject: RE: K-13RD2 PTD 201-04. "undry 318-02 Guy as discussed this morning, We landed the kill string last night in K-13rd2, nippled down the BOPE equipment and found rolled hanger seals that need changed. The well is static and has been static the entire 21 day workover as it is plugged up downhole. We have had 1500 psi on it with no gains or losses. From a well control standpoint we are effectively isolated from the reservoir. We have two options 1. Spend 30 hours nippling up BOPs to change the seals. exposed the entire time. We would then have to pull the leaking hanger to install a test plug or conduct a rolling test. 2. Lift the kill string off seat and have the seals changed within the hour. As discussed we feel the prudent course of action is to simply lift the hanger and swap the seals Per your verbal approval this morning at 05:44,that is how we will proceed. Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowe@hilcorp.com Hilcorp A Company Built on Energy From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday, March 27,2018 9:06 AM To: Dan Marlowe<dmarlowe@hilcorp.com> Cc:Juanita Lovett<jlovett@hilcorp.com>; Michael Quick<mquick@hilcorp.com> Subject: RE: K-13RD2 PTD 201-046 Sundry 318-027 Dan, Thanks for the update. Go ahead and close out the sundry with a 10-404 report. No issues with leaving well with kill string coming up with new plan later. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 1 • • 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: Dan Marlowe<dmarlowe@hilcorp.com> Sent:Tuesday, March 27,2018 8:17 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Juanita Lovett<jlovett@hilcorp.com>; Michael Quick<mquick@hilcorp.com> Subject: FW: K-13RD2 PTD 201-046 Sundry 318-027 Guy We have been unable to pull the stuck pump in K-13rd2. We will be running a kill string in the well today and moving off the well. Revised proposed schematic attached Let me know if you have any questions/concerns Thanks Dan From: Dan Marlowe Sent:Tuesday, March 06,2018 6:29 AM To:Schwartz,Guy(guy.schwartz@alaska.gov)<guy.schwartz(a@alaska.gov> Cc:Juanita Lovett<ilovett@hilcorp.com>; Michael Quick(mquick@hilcorp.com)<mquick@hilcorp.com> Subject: K-13RD2 PTD 201-046 Sundry 318-027 Guy A slight modification on this one In Phase I of the program step 7, instead of using a retrievable packer,we now intend to use a set of seals spacing out and stabbing into the top of the scab liner—see attached revised schematic Thanks Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowehilcorp.com Hilcorp A Company Built on Energy 2 • Ati OF ? • �w �\I% s THE STATE Alaska Oil and Gas __�'►-"'����, of LASKA Conservation Commission Wetut " 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ain: 907.279.1433 ®A ALA`s�� MFax: 907.276.7542 www.aogcc.alaska.gov April 9, 2018 Mr. Stan Golis Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: OTH-18-021 ' Notice of Violation—Failure to Test BOPE Moncla Rig 404 Trading Bay Unit K-13RD2 (PTD 2010460) Dear Mr. Golis: The Alaska Oil and Gas Conservation Commission (AOGCC) reviewed Hilcorp Alaska LLC (Hilcorp)'s April 3, 2018 explanation regarding the failure to test blowout prevention equipment on all pipe sizes used for workover operations at Trading Bay Unit K-13RD2. The actions taken by Hilcorp address the procedural concerns identified in the violation. We appreciate Hilcorp's effort to share the findings of its internal review with its Alaska-based operations engineers and field supervisors involved with blowout prevention equipment operations. The AOGCC does not intend to pursue any further enforcement action regarding the testing violation. Sincerely, da>ft---1 -- Hollis S. French Chair, Commissioner cc: AOGCC Inspectors (via email) ! • iti Hilcorp Alaska, LLC Post Office Box 244027 Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 April 3, 2018 Hollis French RECEIVED Chair, Commissioner Alaska Oil and Gas Conservation Commission APR o 3 2�1$ 333 West Seventh Avenue Anchorage, AK 99501-3572 AOGCC Re: Docket Number OTH-18-021 �l v Notice of Violation—Failure to Test BOPE Trading Bay Unit K-13RD2 (PTD 2010460) Dear Chair French: On March 16, 2018, Hilcorp Alaska, LLC ("Hilcorp Alaska")reported to the AOGCC that a 3- 1/2"workstring was run into Trading Bay Unit("TBU") King Salmon Platform K-13RD2 (PTD 2010460) (the "Well") without having tested the 2-7/8"to 5"VBR rams on the 3-1/2"pipe size. On March 10, 2018, Hilcorp Alaska commenced a workover operation to replace the failed ESP pump in the Well under Sundry 318-027. On that date, an AOGCC inspector witnessed a full BOP test after the initial rig up operations of the Moncla Rig 404. Hilcorp Alaska was unable to move the tubing string due to what appeared to be a stuck ESP pump assembly. After punching the 4-1/2"tubing just above the ESP pump at+/- 8235' to gain circulation,the 4-1/2"tubing was cut at+/-8238', but could not be pulled free. A second cut was made in the 4-1/2"tubing at+/- 7380', and the tubing string was pulled out of the hole and laid down on March 15. A 3-1/2" workstring with a stronger connection than the production tubing's connection, along with fishing tools, were mobilized to the platform. On the afternoon of March 15,the fishing BHA and 3-1/2"workstring were run into the hole. During the March 16 morning review of the daily report for the prior day, while the rig was continuing to trip in the hole, Hilcorp Alaska identified that the 3-1/2" size was not tested in the VBR rams during the March 10 BOPE test, and notified the AOGCC accordingly. Hilcorp Alaska was in process of hanging off the workstring to test the VBR rams on the 3-1/2" workstring when Mr. Regg authorized and waived AOGCC witness on a full BOP test, which was then completed on both 4-1/2"and 3-1/2"test sizes in the VBR rams, with no failures. The AOGCC test report was submitted electronically to the Commission on March 17. The Well is a no flow well as tested on June 15, 2016. The wellbore maintained a full column of fluid and took correct fill volumes when pulling the 4-1/2"tubing and again while tripping back in the hole. The Hilcorp Alaska onsite supervisors have worked in Alaska for several years for Hilcorp Alaska, and are familiar with the BOPE testing requirements and regulations. ! • Chair Hollis French Re: Docket Number: OTH-18-021 April 3,2018 Page 2 of 2 As with most incidents,there were several key failures that led to this violation. The running of the 3-1/2"workstring was an unplanned event, due to the stuck production tubing and ESP pump. In the course of sourcing and mobilizing the workstring and fishing tools,no one on the rig site noted the change in pipe size that necessitated the VBR testing on the 3-1/2"workstring. The BHA submitted to Hilcorp Alaska engineers on March 15 included the fishing BHA details, however it did not include the workstring diameter. This event started with the on-site leadership failing to identify the need to test the 3-1/2"tubing in the VBRs, and the Anchorage support team did not identify the failure until after the workstring was already being tripped in the hole. Hilcorp Alaska began mitigation measures to prevent reoccurrence immediately, prior to receiving the NOV letter from the AOGCC, by implementing a Hilcorp Alaska best practice that the complete BHA be sent to and approved by engineering prior to the BHA being run in the hole. The lead Hilcorp Alaska onsite supervisor was disciplined as part of the resolution of this matter. Additionally, Hilcorp Alaska will share the details of the NOV with all the Alaska based operations engineers at their monthly meeting on April 16, 2018, and the attached Safety Alert of the incident and learnings will be distributed to all field supervisors that work with a BOP installed. Hilcorp Alaska is available at the Commission's convenience to discuss this matter. Should you have any additional questions,please contact Michael Quick at 907-777-8442. Sincerely, David W' kins Senior Vice President cc: Stan Golis Chad Helgeson Bo York Larry Greenstein I March 2018 IIHilcorp Alaska, LLC SAFETY ALERT KING SALMON PLATFORM - BOPE TESTING FAILURE 3/16/2018-CIO BOPE TESTING FAILURE During workover operations on the King Salmon Platform, a planned ESP change out on well K-13RD2, a 3-1/2" workstring was ran in the hole without the 3-1/2" tubing first being tested in the 2-7/8" to 5" Variable Bore Rams (VBR's), as is required by the AOGCC regulation 20 AAC 25.285. The AOGCC regulation 20 AAC 25.285 (f)(4) states "variable bore rams must be function pressure tested to the required pressure on the smallest outside diameter (OD) and the largest outside diameter (OD) tubulars that may be used during that test cycle..." During the initial AOGCC witnessed BOP test on 3/10/18, only 4-1/2" tubing was tested in the VBR's. After the BOP test, it was determined that the ESP was stuck and could not be pulled. The 4-1/2"tubing was cut above the ESP and pulled out of the hole. Fishing tools, including a 3-1/2" workstring with a stronger connection than the 4-1/2" tubing, were mobilized to the platform. The fishing BHA was made up and tripped in the hole on the afternoon of 3/15/18, on a 3-1/2" workstring. Hilcorp employees identified the error in tripping in the hole without having tested the 3-1/2" tubing in the VBR's after reviewing morning reports on 3/16/18, and the AOGCC was immediately notified. Hilcorp began the procedure to hang off the workstring to test the 3-1/2" tubing in the VBR's when the AOGCC gave approval to perform a full BOPE test, without witness, one day early. Investigation Findings: g g The Hilcorp onsite supervisors have worked in Alaska for several years for Hilcorp, and are familiar with the BOPE testing requirements and regulations. In the course of sourcing and mobilizing the workstring and fishing tools, no one on the rig noted the change in pipe size that necessitated the VBR testing on the 3-1/2" workstring. > The BHA submitted to Hilcorp engineers on March 15th included the fishing BHA details, however, it did not include the workstring information. Prevention • Implementation of a bestpractice that the complete BHA be sent to and approved p p pp by engineering prior to the BHA being ran in the hole. ➢ This testing failure will be shared with all Hilcorp field supervisors that work with BOP equipment installed. > Hilcorp will share the details of this failure and the Notice of Violation issued by the AOGCC with all the Alaska based operations engineers at their monthly meeting on April 16, 2018. • Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, March 29, 2018 12:48 PM To: 'Michael Quick' Cc: Larry Greenstein;Juanita Lovett Subject: RE: OTH-18-021 Response Mike, Hilcorp's request for an extension is approved.Hilcorp's response is due by April 11,2018. Thank you, Samantha Carlisle Executive Secretary III Alaska Oil and.Gas Conservation.Commission 333 West 7th Avenue Anchorage, AK 99501. (907)793-1223 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 jor 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 Samantha Carlisle at(907) 793-1223 or Samantha.Carlisleit,alasisa.goy. From: Michael Quick<mquick@hilcorp.com> Sent:Thursday, March 29, 2018 10:51 AM To:Carlisle,Samantha J (DOA)<samantha.carlisle@alaska.gov> Cc: Larry Greenstein<Igreenstein@hilcorp.com>;Juanita Lovett<jlovett@hilcorp.com> Subject:OTH-18-021 Response Samantha— Due to key personnel being out on leave, Hilcorp Alaska respectfully requests a 7 day extension to the due date of our response to the NOV issued as OTH-18-021, Failure to Test BOPE on Moncla Rig 404 on the K-13RD2 well (PTD 201-046). The NOV letter was received by Hilcorp on March 21, 2018,and Hilcorp would appreciate the 7 day extension to submit our response by April 11, 2018. Regards, Mike Michael Quick Hilcorp Alaska, LLC Operations Engineer Office 907-777-8442 Cell 907-317-2969 Email mouick(c�hilcorp.com 1 . • Hilcorp A Company Built on Energy 2 M• • Carlisle, Samantha J (DOA) From: Michael Quick <mquick@hilcorp.com> Sent: Thursday, 29, March 2018 10:51 AM To: Carlisle, Samantha J (DOA) Cc: Larry Greenstein;Juanita Lovett Subject: OTH-18-021 Response Samantha— Due to key personnel being out on leave, Hilcorp Alaska respectfully requests a 7 day extension to the due date of our response to the NOV issued as OTH-18-021, Failure to Test BOPE on Moncla Rig 404 on the K-13RD2 well (PTD 201-046). The NOV letter was received by Hilcorp on March 21, 2018,and Hilcorp would appreciate the 7 day extension to submit our response by April 11, 2018. Regards, Mike Michael Quick Hilcorp Alaska, LLC Operations Engineer Office 907-777-8442 Cell 907-317-2969 Email mquick(c�hilcorp.com Hilcorp A Company Built on Energy 1 OF Thr ,v THE STATE Alaska Oil and Gas 4? ,s • of LAsKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OFfi,,, Main: 907.279.1433 ALAS Fax: 907.276.7542 March 19, 2018 www.aogcc.alaska.gov CERTIFIED MAIL— RETURN RECEIPT REQUESTED 7015 0640 0006 0779 5104 Mr. Stan Golis Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 Re: Docket Number: OTH-18-021 Notice of Violation—Failure to Test BOPE Moncla Rig 404 Trading Bay Unit K-13RD2 (PTD 2010460) Dear Mr. Golis: Hilcorp Alaska LLC (Hilcorp) is performing workover operations on King Salmon Platform, Trading Bay Unit Well K-13RD2 pursuant to sundry permit 318-027, approved on January 30, 2018. The workover is being performed using Moncla Rig 404. Blowout prevention equipment (BOPE) was initially tested on March 10, 2018 and witnessed by an Alaska Oil and Gas Conservation Commission (AOGCC) Inspector. The BOPE stack included the following preventers: Annular, Variable Bore Ram (VBR), and Blind Ram. The VBR was noted to be equipped for pipe sizes ranging from 27/8 inches to 5 inches and tested (on March 10) with a 4'/2- inch test joint. Hilcorp notified AOGCC on March 16, 2018 that a 3'/2-inch workstring was run in the well without first testing the VBR on that size pipe. Hilcorp noted that the next full BOPE test is scheduled for March 17,2018.1 Failing to function-pressure test the VBR on the smallest outside diameter and largest outside diameter tubulars that may be used during the test cycle is a violation of State regulations. 20 AAC 25.285. In subsequent communications, Hilcorp noted that use of the 3'/2-inch workstring was not a planned activity for this workover and recognized — after the fact—the error in not retesting the VBR. Downhole activities with the 3'/2-inch workstring commenced March 15. They also noted that Moncla 404 will perform a full BOPE test on March 16,2018,one day early. AOGCC waived its opportunity to witness the test. Within fourteen days of receipt of this letter(next business day if the due date falls on a weekend), Hilcorp is requested to provide AOGCC with a written response describing the steps that have been or will be taken to prevent recurrence on Hilcorp operated rigs in Alaska. 'BOPE tests for workover operations on Moncla Rig 404 are required at intervals not to exceed 7 days. Hilcorp notified AOGCC of the upcoming BOPE test March 15,2018;there was no mention of the 3'A-inch workstring. s U.S. Postal Service- CERTIFIED MAIL° RECEIPT Domestic Mail Only 1-3 For delivery information,visit our website at www.usps.com" LI Certified Mail Fee N $ ra Services&Fees(check box,add fee as appropriate) 0 Return Receipt(hardcopy) $ ...0 0 Return Receipt(electronic) $ Postmark O 0 Certified Mail Restricted Delivery $ _ Here 0 Adult Signature Required $ _ ❑Adult Signature Restricted Delivery$ 0 Postage =— o Mr. Stan Golis „i Hilcorp Alaska, LLC '- '� P.O Box 244027 N Anchorage, AK 99524-4027 PS Form 3800,April 2015 PSN 7530-02-000-9047 See Reverse for Instructions • S Docket Number:OTH-18-021 March 19,2018 Page 2 of 2 The information request is made pursuant to 20 AAC 25.300. Failure to comply with this request will be an additional violation. The AOGCC reserves the right to pursue an enforcement action in this matter according to 20 AAC 25.535. Questions regarding this letter should be directed to Jim Regg at 907-793-1236. Sincerely, d:33 Hollis S. French Chair, Commissioner cc: AOGCC Inspectors 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. • 0 M v o C) VI N a Q Q Q >? Q Q Q a !a Q Q a a Q a Q Q Cl _ 2 ) ) co Cl 0 0 nin . E F- J co 0 coD o Z >, U— O a) U 0 - - Cl Z o a 0 cu> >> a)0 (/) c < 0� ° u) Q U) U m E L E W 0 n 1-2 o > a) n * O a) u) > .L o cn 3 Y o 0) �6 J D ( D 0) N c`o - c 0 a o a- 0 5E cn > E a L L Q Q U a) U CO� CO m 4' co c c C p 0 -0 a a) C C7 > Q F- c Q > a) C o L a _ Y o n� •C 1 .5 i6 o o c o_ cu o a) w U -a a u) 0) D C C a) m C > E > o) o.. O o 5 5 a) U - O O ` o D N o T a) O co >, Cl) 5 O w a cn D Q m 0 0 iL cN E z 0 > cc LL F- m N ;�,,, E a) 7 O a) LC O o c6 a a) u _ E Y _ C 0 2 NI o >.. a cn QQ Q < < 0_ a. fl.. O..Q o o. o CL Q a Q a 0 Z C C Z Z Z Z Z Z Z p M 0 o C o +� a) z F- c6 O N :'= O O V) 0 0 0 0 03 0 F- Q W N W c O 0 o U U c6 oI �' f/)F- O -.= 0 ..a(-) 0 L Q) @ W Z CO - a) J — C O C > co c/) 0 C c/) a) (1) C Ll 0 . 06 m 2 S Z R. Q) C E L O O C7 u) a) u N > O a F- OU •� a) ° 0 o u) mU > > o a) o C U ( o O W n ; 0 ( Q (6 0 (0 > O o C C a) ct °) dE cn a D C a) = O C66 O Q >" L COLC V) > 0 0 Cl o1 Q a) a' C J O U) a) m a-1 .> C LL a U U C) CMZ o) 2 o 0 c oC L o a) = a O GCj o O o 0 0 _E 0 0 ° D i6 U) con o a Y a) C L c6 u) a) a°)i U o cO Z )3 a) co o '5 CC C7 u) N 0 U m c6 0 � ,_ 0 ca - CO o Q ~ E W -o o) co u) E o u°)) Q >, 8 a) @ cn Q N J O 2) O N u) O D co a) co c6 C a) a) O 0 . 0 a E E. 1 0 cn C7 Q U D F- Y LL 0 C7 = Y 0 co Q m (Ni (/) Z Q L L J CO a) O Q L N N O CD = E O 2 Q a Q a Q Q a O., a a Q Q. 0..Z z Q O.. a Q Q , (1) O N C Da) 0 0 CD co O m Cem U moo Z o aL) O c6 c6 Q Y p Q U) < 0 LL I- O O O YF- u) C J 0) � a � � = I- CI-� � m NCC U) WE. F- v) o — U C U z u) C C (� CO w -o L L cn cn '= o a) cn O O 2 F- d U O cn ) > U L u) a) O o N C a W W cn 0 O O > o ? N O Ti) U L L N N u) a) C a) F- a) c6 O C Z C� c6 a O C > Q J ai '' D, 2 0 'd o o 0) m CL m - 0,Q _1 a) m c6 > = cn •_Q O ) o J 2 Q o m i� ct a) a) > o m Z o O N O Q O 0>» Q a) Q O O c Q.E UO (06 J@ 0 N U C 0 0 aW. 0 0 0 U- U EcLO 'SO � � Q � m3cn0YF- ILLDLL0 a 1 or Ty • • _'' THE STATE _ Alaska Oil and Gas 7, —s=���—' Of/` /, J( /� Conservation Commission F -Oritt CA 1r1 1� X1'1 333 West Seventh Avenue - r- GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 a771Vc, Main: 907.279.1433 °F ALA91°' Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager scot* `° 4 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-13RD2 Permit to Drill Number: 201-046 Sundry Number: 318-027 Dear Mr. Golis: 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, Hollis S. French 4-C Chair DATED this day of January, 2018. RED ,MS Lc— Fr:3 - 1 2u18 RECEIVED • • r JAN 1 018 t� STATE OF ALASKA 00,-.5 ALASKA OIL AND GAS CONSERVATION COMMISSION . CC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown El Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing 0' Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well 0 Alter Casing E] Other CT Clean-out w/N2& 0 Run new ESP 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development 0' 201-046 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number Anchorage,AK 99503 50-733-20157-02-00 ' 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A . Will planned perforations require a spacing exception? Yes 0 No 0 / Trading Bay Unit K-13RD2 , 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018722 McArthur River Field/Hemlock Oil Pool , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): 6 6 Plugs(MD): Junk(MD): 15,485 • 9,737 ' 15,383 • • 9,742 3,9Siefsi S jrP N/A —13,720 Casing Length Size MD TVD Burst Collapse Surface 5,011' 13-3/8" 5,011' 4,183' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,164' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,659' 8,160 psi 7,030 psi Liner 3,748' 4-1/2" 12,320' 9,600' 8,430 psi 7,500 psi Liner 1,459' 4-1/2" 13,779' 9,772' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"slotted 15,385' 9,742' slotted slotted Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 12,520-13,675 '. 9,701-9,776 4-1/2" 12.75/L-80 8,262 13,779-15,385 slotted 9,772-9,742 slotted Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): See Schematic See Schematic - 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory 0 Stratigraphic❑ Development 0 ' Service 0 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 3/1/2018 OIL 0 • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmariowe@hilcorp.com _1 Authorized Signature: �....�- I'LL.... Date: t f 3. J tB COMMISSION USE ONLY Contact Phone: (907)283-1329 Conditions of approval: Notify Commission so hat a representative may witness Sundry Number. c�; 5- -w/�i 315 - 02.R- _Plug Integrity 0 a BOP Test L ' MechanicalicIntegrity Test 0 Location Clearance ❑ �a /� Other: At 3 oc is„ .i 'c"f' (:5 4- ( ''b ) le 4 -; 11.45/' c t-Cc.. -.4,-.r )i 6- 11(;)0 s : . - c c-,i iid-J ft-E4— Z-6 44c Z--S-76 S jL 1)(A Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No 2' Subsequent Form Required: fu--110 4-1 1'rl"s 2 ^C 18 APPROVED BY Approved by: (4A2ON, COMMISSIONER THE COMMISSION Date: 1 76 1I€) htLAL /,-_,8 SubmitForm and Form 10-403 Revised 4/2017 Approved application is vali OrRIO O tapproval. Attachments in Duplicate s Well Prognosis Well: K-13rd2 ililcorp Alaska,LL' Well Name: K-13rd2 API Number: 50-733-20157-02 Current Status: Oil producer(ESP) Leg: Leg#2 (SE) Estimated Start Date: 03/01/2018 Rig: Moncla 404/SLB Coil Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 201-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Mike Quick (907) 777-8442 (0) (907) 317-2969 (M) Current Bottom Hole Pressure: 4,069 psi @ 9,701'TVD 0.419 lbs/ft(8.07 ppg)based on ESP Gauge Maximum Expected BHP: 4,069 psi @ 9,701'TVD 0.419 lbs/ft(8.07 ppg)based on ESP Gauge Maximum Potential Surface Pressure:**3,099 psi Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) *"Note-This is a No-Flow Well as of 06/15/2016.Current SITP is 65 psig ALTERNATE MPSP calculation requested per 20 AAC 25.280(b)(4)to use Moncla 404 BOPE system w/3 preventers Last Casing Test: 10/04/2017 tested casing at 9,700'to 1,500 psig for 30 minutes on chart. Brief Well Summary The K-13rd2 well is currently completed with an ESP installed in October 2017 that has failed.This work over will pull the failed pump, cleanout the well with coil tubing, then run a new ESP completion. / Brief Procedure: n Phase I f�%ct t 58/ /c`'`am` .1 r 1. MIRU Moncla Rig#404. 2. Kill well and circulate Hydrocarbon off of well through ESP.Work over fluid to be FIW. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test all BOP equipment per AOGCC guidelines to 250 psi low/3 tlispsi high/1,500 psi Annular. 4. BOP's will be closed as needed to circulate the well. 73'` 5. Monitor well to ensure it is static. P fSe 6. Unseat hanger and POOH with completion. 0 1)6.— 4.1,(3._ 7. RIH with production tubing and retrievable packer-spacing out to top of 4-1/2" scab liner and land Fir "L,c, tubing hanger. (IA MITIA not required as this string for cleanout velocity only) 8. Set BPV. NU tree,test same. 9. Rig Down Moncla Rig#404 Phase IIS, 1. MIRU Schlumberger CTU 2. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test all BOP equipment per AOGCC guidelines to 250 psi low/ ,500 psi high. 3. RIH and cleanout well to±15,345' and circulate clean " 4. POOH to±12,300'. ( CT 5. Unload well to production header with Nitrogen. ( 1c 4 1.-.:•1-r 6. RIH to±15,345' checking for fill. / j z- o W C t' +✓.3 7. POOH. �� w 8. Rig down coil unit • Well Prognosis Well: K-13rd2 Hilcorp Alaska,LLQ Phase III jZ #? /4"- ESP 1. MIRU Moncla Rig#404. 2. Kill well and circulate Hydrocarbon off of well.Work over fluid to be FIW. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test all BOP equipment per AOGCC guidelines to 250psi low/3si high/ 1,500 psi Annular. 4. BOP's will be closed as needed to circulate the well. 3°Ly 5. Monitor well to ensure it is static. 4Lei) 6. Unseat hanger and POOH with production tubing. ( Q✓�ric�./7 ' 7. MU and RIH with ESP completion. 8. Set BPV. NU tree,test same. 9. Turn well over to production. 10. Conduct SVS test(s) and no-flow per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Intermediate (for Coil cleanout) 3. Well Schematic Proposed 4. Wellhead Schematic Current/ Proposed (Same) 5. BOP Drawing—Moncla 404 6. BOP Drawing—Schlumberger CTU 7. Fluid Flow Diagrams—Moncla 404 8. Fluid Flow Diagrams—Schlumberger CTU 9. RWO Sundry Revision Change Form 11 0 Trading Bay Unit King Salmon Platform SCHEMATIC Well: K-13RD2 PTD: 201-046 Iiilcorp Alaska,LLC 50-733-20157-02 Completed: 10/08/17 CASING DETAIL RKB to Tbg Hanger=33.77' Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 68 J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 13-3/8 47 S-95 BTC 8.681" 4,749' 8,707'(T.O.W.) 7"Liner 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Tie Back Liner 12.75 L-80 Hydril 503 3.958" 8,572' 12,320' 4-1/2"Liner 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' **4-1/2"Slotted Liner 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' **2-1/2"x 1/8"slots,16 slots/ft TUBING DETAIL 4-1/2" 12.75 L-80 Hydril 503 3.958" Surf 8,262' TUBING JEWELRY DETAIL 111 No Depth Depth ID OD Item (MD) (ND) 33.70' 33.70' Hanger 1 8,262' 6,792' N/A 5.620 Bolt-On Discharge 8,262' 6,792' N/A 5.620 Pump(x2)49 Stage,SK15500 8,306' 6,828' N/A 5.620 Gas Separator/Intake Nor AL 1 8,307' 6,829' N/A 5.130 Tandem Seals 9-5/8" Nr 2 8,325' 6,844' N/A 5.620 Motor(x2)562,500 HP,KMSUT&KMSLT a IL 8,362' 6,874' N/A 5.620 Bullnose Anode LINER JEWELRY DETAIL Casing leak 8,572' 7,049' 4.000 5.980 Tie Back Receptacle 8,977 8,987 2 8,576' 7,053' 4.000 5.880 Packer-Hydraulic Permanent 3 12,308' 9,594' 3.812 5.580 X-Nipple 4 12,320' 9,600' 4.280 5.230 Seal Assembly w/5.70"No-Go 12,320' 9,600' 5.250 5.780 Baker ZXP Tie Back Sleeve 5 12,334' 9,608' 4.276 5.880 BakerZXP Packer 12,339' 9,610' 4.385 5.820 Baker HMC Liner Hanger 6 13,696' 9,775' 3.875 - ECP Packer(Inflated w/Mud) 7 13,779' 9,772' 3.875 4.500 Top of Slotted Liner 8 15,348' 9,743' 2.00 4.500 Baker Pack-off Bushing 9 15,383' 9,742' N/A 4.500 Baker Type"V"Set Shoe w/Float ,. 3 �Q X 4 ( Z 5 - I 7' Perforation Detail = HK-1 Top Btm Top Btm Zone (MD) (MD) (TVD) (TVD) FT SPF Date Comments HK-2 - HK 1-2 12,520' 13,675' 9,701' 9,776' 1,155' 6 05/31/2016 Open 6 cE 0 HK-2 12,580' 12,600' 9,726' 9,733' 20' 6 05/09/2006 Open 7 e I I HK-2 13,779' 15,385' 9,772' 9,742' 1,606' *16 06/19/2001 *Slotted Liner I I HK-2 II Fish/Other Information: Lost 1 roller 2.6"dia.X.25"thick off of Schlumberger roller stem 41/2„J l g g Note: Slotted Liner at Near-Horizontal in HB-2 PBTD:15,383' TD:15,485' 90 Deg Section at 13,000'MD MAX HOLE ANGLE=94.75°@ 13,413' Updated By:JLL 01/18/18 • Trading Bay Unit Proposed • King Salmon Platform Well: K-13RD2 Cleanout String PTD:201-046 Hilcorp Alaska,LLC 50-733-20157-02 Completed: FUTURE RKB to Tbg Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 9 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 1-55 BTC 12.415" 2,509' 5,011' 9 5/8" 47 N-80 BTC 8.681" Surf 4,749' 13-3/8" 47 S-95 BTC 8.681" 4,749' 8,707'(T.O.W.) 7"Liner 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Tie Back Liner 12.75 L-80 Hydril 503 3.958" 8,572' 12,320' 4-1/2"Liner 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' **4-1/2"Slotted Liner 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' **2-1/2"x 1/8"slots,16 slots/ft TUBING DETAIL 4-1/2" 112,75 L-80 I Hydril 503 3.958" Surf ±8,550' TUBING JEWELRY DETAIL No Depth Depth ID OD Item (MD) (ND) 33.70' 33.70' Hanger 1 Y'I�• I 1 ±8,450' ±6,947' Packer-Hydraulic Retrievable ±8,550' ±7,031' Tubing Tail 9-5/8° I 2 Z A I. LINER JEWELRY DETAIL Casing leak 8,572' 7,049' 4.000 5.980 Tie Back Receptacle 8'977 $'987 8,576' 7,053' 4.000 5.880 Packer-Hydraulic Permanent 3 12,308' 9,594' 3.812 5.580 X-Nipple 4 12,320' 9,600' 4.280 5.230 Seal Assembly w/5.70"No-Go 12,320' 9,600' 5.250 5.780 Baker ZXP Tie Back Sleeve 5 12,334' 9,608' 4.276 5.880 BakerZXP Packer 12,339' 9,610' 4.385 5.820 Baker HMC Liner Hanger 6 13,696' 9,775' 3.875 - ECP Packer(Inflated w/Mud) 7 13,779' 9,772' 3.875 4.500 Top of Slotted Liner 8 15,348' 9,743' 2.00 4.500 Baker Pack-off Bushing 9 15,383' 9,742' N/A 4.500 Baker Type"V"Set Shoe w/Float 3 X_ 4 Z] 5 A Perforation Detail = HK-1 Top Btm Top Btm Zone (MD) (MD) (TVD) (ND) FT SPF Date Comments HK-2 HK 1-2 12,520' 13,675' 9,701' 9,776' 1,155' 6 05/31/2016 Open 6 EE g.iHK-2 12,580' 12,600' 9,726' 9,733' 20' 6 05/09/2006 Open 7 HK-2 13,779' 15,385' 9,772' 9,742' 1,606' *16 06/19/2001 *Slotted Liner HK-2 IFish/Other Information: 4-1/2" Lost 1 roller 2.6"dia.X.25"thick off of Schlumberger roller stem A l 8,9 Note: Slotted Liner at Near-Horizontal in HB-2 PBTD:15,383' TD:15,485' 90 Deg Section at 13,000'MD MAX HOLE ANGLE=94.75°@ 13,413' Updated By:JLL 01/18/18 11 • • Trading Bay Unit King Salmon Platform PROPOSED Well: K-13RD2 PTD: 201-046 Hilcorp Alaska,LLC 50-733-20157-02 Completed: Future RKB to Tbg Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 68 1-55 BTC 12.415" 2,509' 5,011' .!- [ 9-5/r 47 N-80 BTC 8.681" Surf 4,749' 13-3/8 47 5-95 BTC 8.681" 4,749' 8,707'(T.O.W.) 7"Liner 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Tie Back Liner 12.75 L-80 Hydril 503 3.958" 8,572' 12,320' 4-1/2"Liner 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' **4-1/2"Slotted Liner 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' **2-1/2"x 1/8"slots,16 slots/ft TUBING DETAIL 4-1/2" 12.75 L-80 Hydril 503 3.958" Surf ±8,260' TUBING JEWELRY DETAIL r 1 No Depth Depth ID OD Item ri (MD) (ND) 33.70' 33.70' Hanger 1 ±8,260' ±6,790' N/A 5.620 Bolt-On Discharge Pump Gas Separator/Intake 1 2 M Tandem Seals 9-5/8" c 2 vEj Motor a 1 ±8,365' ±6,877' N/A 5.620 Bullnose Anode LINER JEWELRY DETAIL Casing leak 8,572' 7,049' 4.000 5.980 Tie Back Receptacle -1.‘"8,977-8,987 8,576' 7,053' 4.000 5.880 Packer-Hydraulic Permanent 3 12,308' 9,594' 3.812 5.580 X-Nipple 4 12,320' 9,600' 4.280 5.230 Seal Assembly w/5.70"No-Go 12,320' 9,600' 5.250 5.780 Baker ZXP Tie Back Sleeve 5 12,334' 9,608' 4.276 5.880 BakerZXP Packer 12,339' 9,610' 4.385 5.820 Baker HMC Liner Hanger 6 13,696' 9,775' 3.875 - ECP Packer(Inflated w/Mud) - 7 13,779' 9,772' 3.875 4.500 Top of Slotted Liner 8 15,348' 9,743' 2.00 4.500 Baker Pack-off Bushing 9 15,383' 9,742' N/A 4.500 Baker Type"V"Set Shoe w/Float ti' 3 X 4 P Z 5 1 = Perforation Detail HK-1 Top Btm Top Btm Zone (MD) (MD) (TVD) (TVD) FT SPF Date Comments x HK-2 HK 1-2 12,520' 13,675' 9,701' 9,776' 1,155' 6 05/31/2016 Open 6 IS HK-2 12,580' 12,600' 9,726' 9,733' 20' 6 05/09/2006 Open 7 II HK-2 13,779' 15,385' 9,772' 9,742' 1,606' *16 06/19/2001 *Slotted Liner I HK-2 I AP I Fish/Other Information: Lost 1 roller 2.6"dia.X.25"thick off of Schlumberger roller stem 41/2" 1/2 J l8' Note: Slotted Liner at Near-Horizontal in HB-2 PBTD:15,383' TO:15,485' 90 Deg Section at 13,004 MD MAX HOLE ANGLE=94.75°@ 13,413' Updated By:JLL 01/19/18 • 0 II King Salmon Platform K-13 Current 01/18/2016 Hilcnrp Alawka_1.1.0 King Salmon Tbg hanger,OCT-UH-TC-1A- K-13 ESP,13 X 4%:BTC lift and 24X133/8X95/8X4% susp,w/4"TypeH BPV profile,3/8 cont control line port BHTA,B-11-A0,4 1/16 5M FE (c' A Y Valve,SFE, WO EEtrim 1/16 SM rt--o-- *z' 20 41116t5x\1., �'l Me\5O Valve,Wing,Vetco,2 1/16 5M FE, N /- HWO,AAtrim 1 I ; O ■ �_ 1 ii OO _ I LP i Pit_1�i 7 U ;' Valve,Master,OCT-75,4 1/16 5M `p. �Ot -mi.; FE,HWO,EE trim f*� m'0,00 lloiniiiiiii-v. Bad Ring Groove Petromec Ring Gasket Only Valve,Wing,OCT-20,4 1/16 5M FE, HWO,EE trim st A Adapter,OCT-A5-ESP,13 5/8 5M API hub 0 --W _/111 1 X 4 1/16 5M stdd top,w/2-%control Q line exits,prepped w/OCT 400-4 pocket s�. ? : ØL 111 i"i$I L1 Tol ill II- .,,s tit. 'k .. All unihead annular valves,2 Unihead,OCT type 3,13 5/8 5M API . II 17 '? 1/16 5M FE OCT-20,HWO hub top X 13 3/8 BTC casing bottom, : I Ia ,,,,%/11 4* w/1-2 1/16 5M SSO on lower r - , I section,1-2 1/16 5M SSO on middle _'_"," pl1 I' section,3-2 1/16 5M SSO on upper - section,IP internal lockpin assy111;÷.;' ; III -mieXtipsokr `�'11�2° Valve,OCT-20,3 1/8 2M FE, Starting head,OCT,21 Y.2M FE X ,� Iii 24OfullWO-II 24" 13 3/8" 9 5/8" - 4'/:" a • • II King Salmon Platform BOP Stack(Moncla) Hilrnrp Alaska..1,1A: • 111.111 III 111 111 III II_ I1III 3.74' Shaffer 13 5/8 SM III Ill Ill III III 1-141t-Lli[-Iii I i sit Clw-U 1 �- Variable 7 7/8-5 =—.1-111 -° 0 gum 4.67' e- it 135/8-5000 I �=Blind Rams 1I Iii Iii Iii ill Iii t _ A Choke and Kill Valves E+ 21/16 SM w/Unibolt connections for hoses 111 III III III 1i1 2.00' �,, ; 'i, 1. ! � •�' ' •8 'i 1i ! `. — - is p 'Ural III 11!111*III 746, 1 III III l!l 111 III Riser,13 5/8 5M FE X 13 5/8 SM API#13 hub 13.70' • 0 COIL TUBING BOP ihic." th,L... f.I.i Lubricator to injection head ,____J > 0 f 1 f "_' 1/16 10 -a . ,' J.IuIi Blind/Shear nd/Shear • Milk BliI mot, 1 Anil iiiM =Mk; 1 III*Blind/Shea rBlind/ShearLl.l■1 1 460: C•I,I,) Slip i- ■ Slip 1.1.11 11)■I,I,I Pipe511.1 =Ems Pipe LLI■ L. 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N , � �� �` ��� 0 z CD (n N /� Er W CL o DC O Li? a 0.( I moo• =' r LO ,I;_1■I J..,[[I,!, I _ 7 -I �■fa�l 0 ev,CD a • Q < ^ Nc CO D NiiI 1 6 rTi an--Ifti1 C _ M ��; • - 2 C CD 1=1i�11�'11A • • �� eft T -.-- - E' o IN:nkt 2 • cn 'v y� C Q o I oistat 1 0 a.:!All-- ---.*.' 01"Z a 6 a) o- - < 3 -0 m ! 1 O , m 3 a (D C 0 -8. X I D Q n r n r w CA CA III-. 'D ? c .D O3 O 7 (D 2, 8 <. -h 0; (D to +C G fD (C (n N N N I N 7 O ^' o (p N < m P. ? o I iL .-1- ,.„ x S• ai ,G U> m < m = O * f4 1 o c a e m N `cd (8-: (1 = 3(fl 02 - N N • • STANDARD WELL PROCEDURE tliteorpAlaska.LLC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Facility Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Nitrogen Tank. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure supplier has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Tank. 09/23/2016 FINAL v-offshore Page 1 of 1 • • Moncla Rig 404 BOP Test Procedure Hileorp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, 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 the tubing hanger won't pressure test due to either a penetrator leak or the 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. 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) For ESP wells-Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks,notify Operations Engineer(Hilcorp), Mr.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. As /tlL outlined and approved in the sundry, proceed as follows: 01� ' 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.) 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.) • • Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator 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 joint 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-RIH with test plug on joint of tubing. Install a pump-in sub w/test line plus an open TIW or lower Kelly valve in top of test joint w/open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump-install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 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(test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1st valve on standpipe manifold,close valves 1, 2, 10 on choke manifold and close the annular preventer,open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer,close safety valve and open IBOP on test joint,close outside valve on kill side of mud cross,open 1St valve of standpipe,close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. 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 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross, close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to^'1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. (At f) Close HCR(outside valve on choke side of mud cross), open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. • • 11 Moncla Rig 404 BOP Test Procedure Hilcurp Alaska,LLC Attachment#1 g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off-open pipe rams and pull test joint leaving test plug/2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold,close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves(TIW or Lower Kelly Valve)and IBOPs as necessary. 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. Document both the rolling test and the follow up tests. 0 0 0 - > Cl) > > @ Cl) k 2 0 0 § 7 ) w 0 CD B ° / « 2 CO C - ® E i m 9 k \ / / n 2 co' k k / CD CD ° IN 9 A 0 3 \ n E f ■ 0 2 f ■ 2 7 n g < � Bei m ¢ 0 . CD � � ■ _ . Cl) xi Ca E /s.. § �. a § CO \ t 0 CD C / / 2 \ 0 22 C 0 C gi 2 Co cm > = ƒ c of 0 CD 0 CD / \ � §, ƒ \ Ca �a k -• / 0 _ _ CD / / v Q. 7• ¥ o % » / 6 m<2M / = � O 0 � � 32JCO 0, ■ & mo « « % w %' § / f g -0 _ / a EPI:�/ k / CL rn a E § CD 0_ > k / K = = (T) a: § 7 2 7 m an 3 2 ] D o § 220 yR J R § $ § 0 / = 735 J Qo. ( k CD ■ Z 2 - a • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Monday,January 29, 2018 10:33 AM To: Schwartz, Guy L(DOA) Cc: Rixse, Melvin G (DOA);Juanita Lovett Subject: RE: K-13RD2 RWO (PTD 201-046) Follow Up Flag: Follow up Flag Status: Flagged Guy 1. Our request for an alternate MASP calculation is based on an observed maximum SITP of 65 psig 2. Correct, during Phase II,the main purpose of the N2 lift will be to pull the well down as much as possible to see if more solids influx occurs.Step 6 has checking for additional fill 3. Good catch, If the well is not static,we will have to add eline perforations to establish a circulation path prior to pulling the hanger 4. We last passed a witnessed no-flow on 6/15/2016. We haven't cleaned out across perforations or stimulated the well since that time so haven't triggered a regulatory retest yet, although we did verify recently that the well will still bleed down.This workover will trigger the need to have a new witnessed no flow test Let me know if you have any other questions/concerns Dan Marlowe Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 Cell 907-398-9904 Email DMarlowe(c hilcorp.com Hilcorp A Company Built on Energy From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Thursday,January 25, 2018 10:44 AM To: Dan Marlowe<dmarlowe@hilcorp.com> Cc: Rixse, Melvin G(DOA)<melvin.rixse@alaska.gov> Subject: K-13RD2 RWO(PTD 201-046) Dan, Questions on sundry: 1. You requested an alternate MASP calculation for the well but did not submit the actual data. Can you forward your proposed MASP pressure and calculations . 2. CT FCO: Phase II after the initial cleanout is it your intent to flow well with CT in the well as artificial lift(N2)to check for solids influx. Then recheck with the tag and possibly do another FCO if needed? 3. How are you are going to circulate fluid before you pull the work string? (Phase III step 2) No circ path in tubing x IA that I can see. Step 4 doesn't make sense if you haven't pulled the hanger yet. 4. Has this well passed a no flow recently? After last workover? 1 • Regards, Guy Schwartz Sr. 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). 2 RE 1cJ t STATE OF ALASKA OCT 3 0 2017 ALO OIL AND GAS CONSERVATION COM ION , i1 '41 REPORT OF SUNDRY WELL OPERATIONS AOC C. 1.Operations Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Pull Tubing 0 Operations shutdown 0 Performed: Suspend 0 Perforate 0 Other Stimulate 0 Alter Casing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool 0 Repair Well 0 Re-enter Susp Well❑ Other:Replace ESP/Install Liner 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory❑ 201-046 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20157-02 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018722 Trading Bay Unit K-13RD2 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 15,485 feet Plugs measured N/A feet true vertical 9,737 feet Junk measured —13,720 feet Effective Depth measured 15,485 feet Packer measured N/A feet true vertical 9,737 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Surface 5,011' 13-3/8" 5,011' 4,183' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,164' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,659' 8,160 psi 7,030 psi Liner 3,748' 4-1/2" 12,320' 9,600' 8,430 psi 7,500 psi Liner 1,459' 4-1/2" 13,779' 9,772' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"slotted 15,385' 9,742' slotted slotted Perforation depth Measured depth 12,520-13,675/ feet 13,779-1 tt 4385 %AN ED JAN 1 1 L.0:G. True Vertical depth 9,701-9,776/ feet 9.772-9.742(slotted) Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.75/L-80 8,262(MD) 6,792(TVD) Packers and SSSV(type,measured and true vertical depth) N/A&N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 58 61 Subsequent to operation: 0 76 6167 90 86 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory 0 Development0 Service El Stratlgraphic 0 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 0 Gas 0 WDSPL❑ Printed and Electronic Fracture Stimulation Data 0 GSTOR 0 WINJ 0 WAG El GINJ 0 5USP0 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: 317-329 ✓ Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager6'04.4; Contact Email: dmarlowe@hilcorp.com t e')+5c(Zd1 907 283-1329 Authorized Signature: Date: / I � Contact Phone: ( ) Form 10-404 Revised 4/2017 RBDirS V' / iu v - 2 217 Submit Original Only (/77 f(.ic-i1 Trading Bay Unit , t, King Salmon Platform (��i itl2-pi° Well: K-13RD2 SCHEMATIC II • • !'i"� PT .20±='11T 20��D�-� 50-[:733-20157-02 II it""`°Alaska,LLC Completed: 10/08/17 RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2" 12.75 L-80 Hydril 503 3.958" 8,572' 12,320' 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2"Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' L , TUBING DETAIL 4-1/2" 12.75 L-80 Hydril 503 3.958" Surf 8,262' 111 JEWELRY DETAIL No Depth Depth OD ID Item I 1 (MD) (TVD) `- 33.70' 33.70' Hanger 8,262' 6,792' 5.620 N/A Bolt-On Discharge / \/ 8,262' 6,792' 5.620 N/A Pump(x2)49 Stage,SK15500 /\ /� 8,306' 6,828' 5.620 N/A Gas Separator/Intake /IL E LZ / 1 8,307' 6,829' 5.130 N/A Tandem Seals 8,325' 6,844' 5.620 N/A Motor(x2)562,500 HP,KMSUT&KMSLT 9-5/8"Window 8,362' 6,874' 5.620 N/A Bullnose Anode @ 8707'MD, easing leak 2 12,320' 9,600' 4-1/2"Liner top(ZXP Packer) 30°Hole Angle 8'977 -8'987 Perforation Detail Top Zone (MD) Btm(MD) Top(ND) Btm(TVD) Date Comments HK 1-2 12,520' 13,675' 9,701' 9,776' 05/31/2016 Open HK-2 13,779' 15,385' 9,772' 9,742' 06/19/2001 Slotted Liner L12 2 it,___ 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME 4-1/2"J-55, 11.6#Tubing 20" - 119 hrs 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"- 229 hrs 13,779 MD-15,348' MD 9-5/8"-259.5 hrs 7"- 99.5 hrs _._._._._._._._._._._._._._._._._._.L ly G ECP (inflated with mud) at 13696' MD (9774'ND) 90 Deg Section at 13,000' MD WI blank 4-1/2" above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD= 15485' MD/9736'ND Revised By:JLL 10/26/17 i i Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/04/2017- Monday Prepping and organizing Moncla 404 W/O package for movement to King Salmon K-13RD2. General cleanup of platform deck while waiting on M/V Resolution. Back load M/V w/derrick, draw works,A-frame, carrier, koomey unit, mud box w/koomey hoses, driller's shack, 2-connexs, choke house, 1-carrier walkway, assorted stairs and walkways. Boat departed for King Salmon. Transported Moncla day crew, crane crew and WSM to King Salmon platform. Worked M/V Resolution unloading 1st load of W/O package. Positioned upper beams and welded same in place (while off loading boat).Transported Moncla Nite crew to King Salmon platform @ 18:00 PM. Worked M/V Resolution unloading 2nd load of W/O package. Off loaded carrier and welded front carrier beam in place then spotted carrier. Installed off driller side walkway. Secured carrier to beams. Install draw works A-frame and derrick. Finished off loading equipment from Graying platform. Send M/V Resolution back to the Grayling for the last load. Continued organizing deck and conex and equipment on rig. Installed drive shaft-torqued up bolts- hooked up air lines from control panel to draw works. 09/05/2017-Tuesday Continued setting up W/O package-welder cut— 1 1/2' off front skid beam in order to seal Ruston AC room- replaced panels on wall. Worked 3rd and final load of W/O package from M/V Resolution-spotting equipment as needed. Checked well-annulus side on vacuum-tb side w/slight pressure (oil). Sucked fluid down in tree and set BPV. Assisted production B/D tree hook ups- NOS void tested hanger to 3500 psi- removed clamp and lifted tree from well room. NOS cleaned and prepped tb head and control lines-worked hold down pins and M/U LH test sub. N/U 13 5/8" hub type riser on well head, 2' adapter spool and mud cross w/manual & HCRs. Set drill line spool on skid beam- off loaded M/V Titon receiving 40' catwalk, stairway to driller's shack, 2-cutting boxes, 7 5/8" test jt, Knight tools and single gate dressed f/7 5/8" rams and thread protectors f/4 1/2" Hydril 563 tb. Wind speeds 45-65 mph- crane work haulted.Assisted production in cleaning up production well bay#2. Laid out koomey lines- performed general organizing, cleaning and maintenance. Caught a break in the wind and finished stacking up BOPE (double gate, single gate and annular). Wind speed back up- haulted crane work again. Running pump and electrical lines. 09/06/2017-Wednesday Continued running pump, koomey and electrical lines and torqueing BOP bolts. Prepped derrick to be raised- raised and scoped out derrick, securing all guy lines. Spooled drill line on draw works- R/U both air hoists- hooked up control panel for driller's shack- mounted rig floor w/supports and hand rails. Finished torqueing bop bolts, hooked up all koomey lines to bop stack. Assisted welder with building walkway from pipe rack to rig floor. Repositioned active tank and mud pump- moved test pump- hooked up kill line and choke lines-electrician wired in bang box for rig power. Worked M/V Resolution unloading Summit ESP equipment. Installed walkway from pipe rack to driller shack- r/u lights on rig floor- hooked up all camlock hoses to rig- loaded rig floor w/handling tools and McCoy tongs. Crane crew continued organizing decks. M/U 4 1/2" test jt w/ LH sub on btm- pumpin, Sv& IBOP on top. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: ftv, F 09/07/2017-Thursday Finished M/U 4 1/2" test jt w/ LH sub on btm, pumpin, SV& IBOP on top-screwed onto LH sub and filled system 6�)f G with FIW-shelled tested to 3500 psi. Worked out one leak in test hose.Tested all BPSOas Sudry per nin accordance `y with Hilcorp and AOGCC requirements- performed successful koomey draw down test. Tested with 3 1/2" &4 1/2" tb. Witness waived by Mr. Regg 9:09 AM 9/7/17. Platform electrician set up and tested LEL& H2S alarm system- Quadco set up PVT, pit gas, hook load and rig pump sensors. Built railing on driller side of rig carrier to block gap between Ruston AC room and carrier. Positioned catwalk and beaver slide then welder added hand rails where needed. Installed 2' 13 5/8" spool on top of annular. Modified base of rig floor supports for a more secure attachment to racking mat. NOS rep checked for pressure under BPV then pulled same. M/U 4 1/2" IBT landing jt and screwed into hanger. BOLDS- picked up and unseated hanger then pulled up 16' @ 135K. Worked M/V receiving 3 1/2" PH-6 workstring. Hooked up circulating hose and closed annular- pumped LW @ 2.5 BPM 395 psi (pumped tb volume to settle tb side) taking returns through ckoke manifold to rig tank- no fluid loss. Pulled hanger to floor and disconnect ESP cable from hanger- laid down hanger and landing jt. R/U Summit to POOH. 09/08/2017- Friday Be arLPOOH w/ ESP production string laying down 4 1/2" 12.75# L-80 Hydril 533 tb- pumping displacement every (4,3110e 30 joints. Laid down 31 jts (7,324') and pumped displacement. M/U SV and Kelly hose-attempted to circulated with annular closed on cable &flat pack- Nogo. Summit cut lines- lowered string down and closed annular- circulated hole volume LW at 3.6 BPM 880 psi (600 bbls total). Cleaned up spill while circulating. Shutdown pump and B/O Kelly hose. Pulled one jt and used ropes to restring ESP cable and flat pack. Continued POOH w/ ESP production string. Changed out Summit ESP spool @ splice with 101 jts laid down (5,109'). Cleaned up working platform and BOP stack. Continued POOH w/ ESP production string laying down tb- 220 of 262 jts laid down at report time = 1,470'. 09/09/2017-Saturday Continued POOH from 1,470' laying down 4 1/2" 12.75# L-80 Hydril 533 tb. Drill line kinked at breakover while pulling pipe-slipped and cut 135' of drill line. Finished POOH to Summit ESP assy laying down tb. B/D ESP assy- found metal flakes around base of discharge and bolt heads- pump to intake shaft was rough to turn and had excessive wobble- intake shaft was badly worn. Protector top seal was damaged and the top protector did not drain any fluid- btm of LT protector drained clean oil. Motors were low resistance phase to ground but balanced and were full of clean oil. Cleared and cleaned rig floor and BOP stack, prepped Summit equipment to be shipped out. Laid out and strapped 3 1/2 " PH-6 workstring on pipe deck. M/U BHA#1 w/8 1/2" Rock bit, 9 5/8" casing scraper, bit sub,xo t/3 1/2" work string= 7.04'.TIH P/U 3 1/2" 12.95# P-110 PH-6 work-string-drifting then M/U to 6000 FPT. 220 jts+ BHA= 6,827.04' at report time. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/10/2017-Sunday Continued RIH w/8 1/2" rock bit w/scraper for 9 5/8" casing picking up 3 1/2" 12.95# P-110 PH-6 work string- strapping, drifting,torqueing to 6000 FPT. Checked weights at#274- PUW 116 SOW 58k.Tagged 5' in on #275 = 8,506' (PM). P/U to connection (8,496') and broke off single. M/U SV w/hose. Attempted to circulate SW but plugged-turned fluid around and pressured up to 3500 psi (LW)-could not estb circ. Checked to make sure nothing on surface was plugged-attempted several more times working tb but could not unplug pipe. R/U to pull wet. POOH wet filling hole every 20 stands. B/D bit&scraper-found — 10' plug of calcium carbonate & scale inside last jt of workstring.Cleared and cleaned rig floor.Tripoint M/U 9 5/8" test tool (BHA#2). RIH w/test pkr on 3 1/2" PH-6 work-string to 4,968'. Rigged up and broke circulation @ 1 bbl min w/50 psi (PUW 60k SOW 42k).Tested casing at this depth-good test- released tool. Continued RIH to 6,958'. Rigged up and broke circulation LW @ 1 bbl min 85 psi (PUW 88k SOW 52k). Continued RIH to 8,318' (134 stands). M/U SV and hose- broke circulation LW then turned fluid around (SW)- pressured up. Turned fluid around again-circulating (LW) @ 2.83 BPM 450 PSI at report time. 09/11/2017- Monday Stopped circ LW and turned fluid around (SW)-attempted to circ but pressured up (8,318').Turned fluid around and broke circ LW. Shutdown pump. Pulled 2-stands and set test pkr at 8,135'-pressured annulus to 1550 psi and held f/30 mins on chart-good test. Released pressure and test tool. Broke circ down tb then lined up to rev- could not reverse- began trouble shooting lines again. Found that we could pump thru stand pipe and Kelly hose one way but not the other- bypassed Kelly hose and stand pipe. Reverse circulated 300 bbls FIW at 3 BPM 500 psi. B/O hose and SV- RIH w/5-stands of workstring to 8,470'. Reversed 2-tb volumes @ 3 BPM 500 psi-shut down pump and set test pkr. Pressured annulus to 1600 psi and held on chart f/30 mins-solid test. Released pressure and pkr. POOH w/ 9 5/8" test pkr pumping disp every 20 stands. B/D Tripoint 9 5/8" test pkr- cleaned up rig floor. M/U BHA#3 w/6" rock bit, bit sub, 4-4 3/4" DCs, workstring xo = 127.56'. RIH on 3 1/2" PH-6 workstring to 8,466' (140 stands+single). N/U 7 1/6" x 13 5/8" stripping head-changed out Kelly hose. 09/12/2017-Tuesday Changed out Kelly hose and rebuilt gate valve on circ manifold. M/U Kelly hose on single#270- broke circ SW at 3 BPM 550 psi-eased down to 8,497' and circ tb volume. Shut down pump. B/O hose and ran in next stand-tagged up at top of liner(8,506' PM)-attempted to rotate into liner but nogo- broke off/racked back stand then P/U power swivel w/single#271. Broke circulation and stripping rubber leaked- pulled rubber and centered derrick over well. Attempted to reverse circ @ 1 bbl min- pressured up to 500 psi-shut down pump- bleed off pressure. Rotated @ 20 rpm, surged and worked pipe from 8,470' to 8,490' a few times- regained circ @ 3.5 BPM 525 psi. Reversed btms up @ 3.5 bbls min 525 psi @ 7" liner top (8,506')- pearl scale in returns. Continued P/U 3 1/2" PH-6 work string singles cleaning out 7" liner- pumping @ 3.5 BPM 525 psi (PUW 116 SOW 64 RotW 84k @ 30 RPMs Torq 3000-3500 FPT WOB 1-3k)-from 8,506' to 8,839' at report time (— 6 bbls of solids recovered- 9 bbls of fluid loss). • 111 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/13/2017-Wednesday Continued washing/rotating down from 8,830' (PUW 116 SOW 64 RotW 84k @ 30 RPMs Torq 3000-3500 FPT WOB 1-3k). Changed blown out stripping rubber at 0815 hrs on jt#283 = 8,901'. Replaced rubber and finished 15 min circ. Washed/rotated to 9,087' (#289) (below hole in casing @ 8,977-87') circulated 3-tb volumes. Shutdown pump and cleaned out possum belly. M/U #290 on swivel- broke circ SW (3 BPM 440 psi) and rotated/washed down to 9,119'- rotated and washed #291 & 292 down same way to 9,182'-still getting pearl scale in returns. M/U #293- cleaned out to 9,190' and hole began taking fluid at 40 bbls/hr rate, pump pressure fell from 400 psi to 140 psi and bit began torqueing and bouncing on something hard- unable to make hole. Circulated hole clean and shut down pump. Pulled stripping rubber- B/O L/D swivel- N/D 7 1/16" x 13 5/8" stripping head- laid down 5-singles. Total of 6 bbls of solids (pearl scale) recovered during last 10 hrs, for a total recovery of 12 bbls since 7" cleaning out started. POOH to BHA standing back 3 1/2" PH-6 work string. Racked back 2-stands of collars and B/O bit. No identifying marks on bit. Cleaned up floor and organized tools for the weekly BOP test. M/U 3 1/2" test jt and set test plug-filled system w/ FIW and shell tested to 3500 psi. Began testing BOPE 250 low 3500 high as per Sundry- witness waived by Mr. Regg 11:43 AM 9/13/17. 09/14/2017-Thursday Finished testing all BOPE 250 psi low 3500 psi high as per Sundry in accordance with Hilcorp and AOGCC requirements.Tested w/3 1/2" &4 1/2" tb- performed successful koomey draw down test. Witness waived by Mr. Regg 11:43 AM 9/13/17. Pulled test plug- B/D test equipment and M/U KOTs BHA(#4) (6" x 1 1/2" taper mill,4 3/4" x 1 1/2" bit sub, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub = 152.03'). TIH w/ tapered mill assy on 3 1/2" 12.95# P410 PH-6 workstring to 9,175'. N/U stripping head- P/U power swivel w/single #292- installed rubber and M/U to string- landed rubber. Broke circulation SW @ 3.5 BPM 175 psi- loss rate @ 2 bbls min (SOW 64, PUW 120, ROT WT 98). Eased down to 9,189' & plugged off. P/U and worked pipe to clear plug- loss rate now @ 2.5 BPM- laid down single#292 (EOT @ 9,175'). Worked pipe slowly while pumping 1 BPM with very little returns. Conferred w/ Eng and Halb concerning salt pill. R/U mixing tank and built 60 bbl salt pill w/202 sacks of oilfield salt. Spotted salt pill at EOT and let sit for 15 mins. M/U single#292 on swivel- lined up to pump down tb at slow rate while attempting to get by obstruction or determine what it is. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/15/2017- Friday Established parameters: PUW 120k, SOW 68k, RotW 88k, RotFT 4500 FPs, 3.5 BPM 600 psi (LW). Milled from 9,190' to 9,196' (milling torque 7000-75000 FPs) then torque dropped off-washed/rotated to EOJ at 9,206'. Picked up to 9,175' and turned fluid around (SW)- began circulating at 3.12 BPM 250 psi losing—60 BPH. Slacked down to EOJ and circulated btms up to check for solids or shavings. Small amount of metal, cement &coal in returns. Shutdown pump and M/U single #293- broke circ SW at 3.6 BPM 270 psi then washed/rotated to 9,221'-shutdown pump and swivel and slacked off to EOJ at 9,236'. Brought pump on line and pipe was plugged. Worked pipe to clear plug. P/U and washed/rotated to EOJ (9,267')fighting to maintain circulation-decision was made to pump sized salt pill. Mixed 50 bbl sized salt pill w/88 sks oilfield salt, 1/2 bucket Baradefoam HP,4 sks Barazan D Plus,4 sxs Dexrid LT, 28 sxs Baraplug 20, 26 sxs Baraplug 50. Pumped 50 bbl pill-chased w/48 bbls FIW then shut down and let soak for 1 hr. Established parameters: PUW 126k, SOW 76k, RotW 90k, RotFT 4500 FPs, 3.5 BPM 435 psi S/W. Continued washing/reaming from 9,267' to 9361'-fluid loss rate "20 BPH when pumping. Troubleshot surface manifold due to return line plug off. B/D and flushed through surface lines-checked out all good (static loss rate 8 BPH). Continue washing and reaming from 9,361' to 9,454' (parameters running the same)-occasionally stalling out, having to hit jars to get loose. Solids in returns are sparse-as though ID of casing is mostly open-we are able to make hole sometimes without rotating and pumping. Decision was made to circ hole clean and POOH to remove tapered mill and P/U rock bit. Circulating hole clean (SW) at 3.62 BPM 380 psi 20 BPH loss rate. 3 bbls of solids from returns last 12 hrs (mostly pearl scale). 09/16/2017-Saturday Finished laying down swivel- N/D stripping head. POOH w/ KOTs 6" tapered mill assy (BHA#4) pumping 8 bbls FIW every 20 stands. B/D KOTs tapered mill assy-all TC worn from end of mill-3" from end of mill has noticeable wear markings- no heavy markings elsewhere on mill to 6" OD. M/U KOTs 6" rock bit BHA (#5) (6" x 1 3/4"Varel rock bit, 4 3/4" x 1 1/2" bit sub,4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 147.97'). Changed dies in tb tong heads. TIH running BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 9450' w/no issue (PUW118k SOW 70k). N/U stripping head- P/U power swivel with single #301 installed rubber and M/U to string- landed rubber-changed out cuttings box. Established parameters: PUW 120k, SOW 64k, RotW 88k, RotFT 4000 FPs, 3.5 BPM 200 psi (SW).Tagged at 9,454'then washed/rotated to 9,459'- bit began bouncing (as on metal)- no additional hole made in 30 mins w/2-4k on bit. P/U to 9450' & CBU (SW) @ 3.75 BPM 260 psi (losses' 52 BPH pumping 225 BPH). L/D swivel- N/D stripping head. POOH to BHA- pumping 8 bbls FIW every 20 stands. B/D BHA- B/0 6" Varel rock bit- bit is in 'as run in' condition. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/17/2017 Sunday M/U BHA#6 (6" x 2 1/4" KOT bladed junk mill, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x- over sub = 147.74').TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 9,450'- no trouble going thru TOL(8,506' PM) or tight spot (9,190-96'). N/U 7 1/6" 5M x 13 5/8" 5M stripping head and adapter spool. P/U swivel w/single #301- installed rubber and M/U to string- landed rubber. Broke circulation in rev at 3.4 BPM-shutdown pump to tighten up plates on swabs. Broke circulation in rev at 3.4 BPM 290 psi (PUW 118k SOW 70k RotW 88k FT 4000 FPs). Eased down and torqued thru something at 9,459' washed/rotated down to EOJ at 9,480'- pressure increased to 360 psi-circulated for 10 mins then M/U #302. Washed/rotated down to 9,483' and pressure increased to 410 psi. Circulated btms up to check returns- pearl scale, small rocks, shale &sand. Continued in to EOJ at 9,511'. Continued cleaning out 7" casing from 9,511' to 9,605'-turned on junk from 9,605' to 9,635'-4 to 6K WOB- pump pressure 400-700 psi-tq 3500-8000 FPs. Dumped 1-drum of CFS 520 into active tank. Continued cleaning out 7" casing from 9,635' to 9,977' washing/rotating through mostly sand, small rocks and shale @ 3.5 BPM 420 psi (PUW 120k SOW 76k RotW 90k 30 RPM Tq 3500 FPs). Loss rate when pumping 57bbls hr. Shut down to repair the oiler on mud pump drive shaft-static loss rate 8 BPH. Continued cleaning out 7" casing from 9,977' to 10,133' at report time. 3 bbls of solids recovered in last 24 hrs for a total of 21 bbls total recovery. Fluid losses running around 60 BPH while pumping. 09/18/2017- Monday Continued C/O 7" liner from 10,133' w/6" KOTs junk mill (6" x 2 1/4" KOT bladed junk mill, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 147.74') (PUW 120k SOW 70k RotW 88k FT 4000 FPs) - washed/rotated to 10,506'. Changed out stripping rubber. Continued washing/rotating from 10,506' to 11,625' at report time. Fluid loss rate at 60 BPH (while pumping)-2.5 bbls of solids recovered last 24 hrs (total recovery of 23.5 bbls of pearl scale, small rocks, shale and sand during cleanout). 09/19/2017-Tuesday Continued cleaning out 7" liner from 11,625' w/6" KOTs junk mill (6" x 2 1/4" KOT bladed mill,4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 147.74') (PUW 120k SOW 70k RotW 88k FT 4000 FPs)- washed/rotated to 12,295' (21' in on #392). Hung up and swivel stalled- lost circulation while attempting to pull free- hit jars at 200k to pull free- (according to diagram TOL is at 12,320'). Parameters at 12,295': PUW 167k, SOW 84k, RotW 110k, FTorq 7000 FP, 3.45 BPM 400 psi (SW). Circulated tb volume x 2 (SW). B/O L/D swivel and N/D stripping head. POOH standing back 3 1/2" PH-6 workstring- pumping 8 bbls FIW every 20 stands. B/D BHA- laid down KOTs bladed junk mill- mill was 50%worn-two small pieces of steel found in ports of mill. M/U BHA#7 Baker'TBR' dress & polish assy(5.180" x 2.69" PBR mill,4.79" x 2.04" spacer subs x 2, 5.76" x 2.70" top mill,4 3/4" x 2.54" pup, 4 3/4" x 2 1/4" (KOT) B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 165.69).TIH w/polishing mill on 3 1/2" 12.95# P-110 PH-6 workstring to 1,898' (28 stands in) at report time. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/20/2017-Wednesday Continued in hole w/ Baker'TBR' dress & polish assy(BHA#7) (5.180" x 2.69" PBR mill, 4.79" x 2.04" spacer subs x 2, 5.76" x 2.70" top mill, 4 3/4" x 2.54" pup, 4 3/4" x 2 1/4" (NOV) B&O jars,4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub = 165.69) from 1,898'to 12,261'. N/U 7 1/16" x 13 5/8" stripping head- installed rubber on single #391 and M/U to string. Landed rubber and eased down to 12,290'. P/U swivel w/ 14' of pups-established parameters: PUW 158k, SOW 84k, RotW 112k, FT 6600 FPs, 3.5 BPM 330 PSI-tagged at 12,292'. Continued adding wt to 8k down-gained weight back and eased down to 12,307' (end of pups). Plugged up once-turned fluid around to regain circulation. B/O pups and added single#392- broke circ LW then turned fluid around. Continued washing/rotating from 12,307' to EOJ at 12,323'. Shut down pump and added 14' of pups (2). Continued washing/rotating down to 12,335'-set down 6k WOB and turned for 15 mins. Checked this several times with no torque or new hole made. Determined that we should be on TOL with (upper) tattletale mill (5 3/4"). Worked pipe while CBU x 2 (SW) @ 3.8 BPM 415 PSI. L/D power swivel and N/D 7 1/16" x 13 5/8" stripping head. POOH to 11,200' standing back 3 1/2" PH-6 workstring pumping 8 bbls FIW every 20 stands. Link in right angle to draw- works. Drive chain broke- repaired same. Continued POOH w/ Baker polishing mill assy. 121 of 196 stands OOH at report time =4,818'. 09/21/2017-Thursday Finished POOH w/Baker TBR polishing mill assy (BHA#7)from 4,818' to BHA. B/D BHA racking back collars and laying down jars. 5 3/4"Tattletale mill (10' above polishing mill) had marks indicating that it btm'd out on top of liner(determined to be successful tie-back receptacle clean-out run)- no unexpected marks on polishing mill. L/D Baker polishing mill assy. M/U 3 1/2" test jt w/test plug on btm, pumpin, SV& IBOP on top- had to pressure up on stack to land test plug fully. Filled system with FIW and shell tested to 3500 psi-worked thru leaks in surface subs and around hold down pins at tb head.Tested all BOPE to 250 psi low 3500 psi high as per Sundry in accordance to Hilcorp &AOGCC requirements. Performed successful koomey draw down test-tested w/3 1/2" &4 1/2" tb. Witness waived by Mr. Regg 2:09 PM 9/20/17. R/D test equipment then RIH & laid down DCs&jars. Prepped to run 4 1/2" liner. Strapped 4 1/2" 12.75# L-80 Hydril 503 liner(previously used as production string). P/U Tripoint 7" pkr then B/O X-O pup (to be used in string)- laid down pkr.Tripoint rep P/U Baker 5.23" 10.87' seal assy then M/U 3.813" X-nipple assy on top w/x-over pups= 37'. Changed from Gill to McCoy power tongs. P/U 4 1/2" 12.75# L-80 Hydril 503 liner-strapping, drifting w/3.83" drift then torqueing to 4600 FPT. At 2,294' we began running into pipe that would not drift due to scale. Pipe that was in upper part of production string was cleaner so crane operator moved top bundles to get to upper tb. Continued P/U RIH w/4 1/2" liner- 2,511' at report time. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/22/2017 Friday Continued P/U 4 1/2" 12.75# L-80 Hydril 503 liner-strapping, drifting w/3.83" drift then torqueing to 4600 FPT- from 2,511' to 3,888'. Tripoint Rep P/U 9 5/8" 40-47# Permanent Hydraulic Isolation (liner hanger) packer. M/U to string w/4 3/4" bumper jar. R/D McCoy tongs- P/U Gill tongs.TIH w/isolation assembly on 3 1/2" 12.95# P-110 PH- 6 workstring running 2 mins/stand-sat down w/ EOTs at 9,138' (pkr depth is 5,242')-set 6k down before stopping- picked up to 125k with no movement (previous P/U was 94k). B/O single#169. Conferred with Engineer and Tripoint concerning situation. R/U safety valve w/ Kelly hose-attempted to pump down annulus @ 1.5 BPM but pressured up to 1000 psi with no bleed off- released pressure-worked pipe from 40k to 200K with no movement. Lined up L/W- pumped down tubing @ 1.5 BPM 290 psi with no returns-continued working string with no success in freeing same. Decision was made to release from 9 5/8" liner hanger pkr. Picked up to 70k (neutral weight at bumper sub)- rotated 12 turns to the right and released from pkr @ 5,242'. POOH w/Tripoint hydraulic setting tool pumping 8 bbls FIW every 20 stands. B/O L/D setting tool. Received KOTs fishing hand and Itco spearing assy via helicopter- onloaded KOT fishing tools from M/V Titan. Strapped and calipered spear assy for 3.958" ID catch (below pkr). M/U BHA#9 (Itco spear to catch 4 1/2" pup below pkr, 4 3/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, w/ workstring XO).TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring- 39 stands in at report time = 2,580' 09/23/2017-Saturday Continued RIH w/ KOTs Itco spear assy(BHA#9) (3 1/4" x 3/4" Itco spear dressed w/3.947" grapple, 13.48' of 3 1/8" x 1" spear extensions,4 3/4 x 1" X-over sub,4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs,4 3/4" x 2 1/4" WS X-over sub = 164.86')from 2,580' to 5,217'. P/U single and went thru top of TBR at 5,236'. PUW 60k SOW 48k. Speared into 4 1/2" pup below TBR/pkr assy(engagement depth = 5,249.') and worked pipe from 40k to 160k, hitting jars at 110k- no movement at pkr- released spear with RHT. POOH to BHA pumping displacement every 20 stands. B/D KOTs spear assy then M/U KOTs pkr burning assy(BHA#10) (8 1/2" x 7" pkr type burning shoe, 8 1/8" x 7 1/4" WP ext, 8" x 3 1/8" triple bushing, 6 1/2" x 2 1/4" DP sub, 6" x 2" bit sub, 4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub = 163.88).TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 5216'. N/U 7 1/6" 5M x 13 5/8" 5M stripping head and adapter spool- P/U swivel- made up single#164. Established parameters: PUW 64k, SOW 50k, ROT 56k, pump rate @ 3.5 BPM 253 PSI-eased down and tagged top of TBR at 5,236'. Began milling on 8" TBR w/2k on shoe (@ 5,236') w/torque running 1500-5500 FPs. At 2' in (5,238') torque smoothed out to —2000 FPs- no additional footage made in 1 hr. CBU x 2 @ 3.5 BPM 268 PSI. L/D power swivel and N/D 7 1/16" x 13 5/8" stripping head. POOH standing back 3 1/2" PH-6 workstring to BHA- pumping 8 bbls FIW every 20 stands. B/D BHA and checked shoe- 1/8" ring on OD of shoe wore down to metal (which stopped shoe)- 70%of carbide still on face. M/U new 8 1/2" x 7" pkr type shoe on same BHA-complete BHA in hole at report time. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/24/2017-Sunday TIH w/ BHA#11 (8 1/2" x 7" pkr type burning shoe, 8 1/8" x 7 1/4" WP ext, 8" x 3 1/8" triple bushing, 6 1/2" x 2 1/4" DP sub, 6" x 2" bit sub, 4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 164.37')to 5,216'. N/U 7 1/16" stripping head w/13 5/8" adapter spool. P/U swivel, M/U single#164, installed rubber and M/U to string, landed rubber. Established parameters: PUW 64k, SOW 50k, ROT 56k, pump rate @ 3.5 BPM 270 PSI (SW). Began milling on TBR at 5,237' (took 45 mins to cut back over 1' of previous hole made on 1st shoe run). Made 6" of new hole in 4 hrs 15 mins- new TD= 5,238.5'. B/O L/D swivel- L/D single#164 & 163- N/D stripping head. POOH to BHA pumping displacement every 20 stands. B/D BHA and checked shoe-60%of carbide still on face. L/D w/o ext and shoe. M/U new 8 1/2" 6-bladed junk mill on BHA# 12-Tot 153.23'.TIH w/ BHA#12 (8 1/2" 6- bladed junk mill), 6 1/2" x 2 1/4" DP sub, 6" x 2" bit sub,4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 153.23') to 5,236'. N/U 7 1/16" stripping head w/ 13 5/8" adapter spool. P/U swivel, M/U single#165, installed rubber and M/U to string, landed rubber. Established parameters: PUW 60k, SOW 52k, ROT 56k, pump rate @ 2.5 BPM 204 PSI (SW). Began milling on top of TBR at 5,236'-torque running 2500-5500 lb @ 75 rpm. 4' of hole made at report time, putting new depth at 5,240' (still cutting). Fluid losses 24 BPH. 09/25/2017- Monday Continued milling @ 5,240' w/8 1/2" junk mill (8 1/2" x 2 1/4" 6- bladed junk mill, 6 1/2" x 2 1/4" DP sub, 6" x 2" bit sub,4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub = 153.23'). At 9 AM we began having plugging issues due to metal returns-current depth is 5,241.5' (— 1' in milling on pkr).Turned fluid around numerous times to regain full circulation. Checked and cleared surface lines several times but each time we went back to milling pressure climbed again-could not get rid of partial plug- 1230 hrs conferred with Engineer and decision was made to POOH to remove metal cuttings from pipe ID. L/D swivel- had to tighten x-over sub on swivel before setting it back- pulled rubber& N/D stripping head. POOH to BHA pumping displacement. B/D BHA and checked junk mill- 60%of carbide still on face- no metal shavings or plugging in mill or pipe. M/U BHA #13 (8 1/2" x 2 1/4" 6-bladed junk mill, 6" x 2" bit sub, 4 3/4" x 2 1/4" B&O jars,4-4 3/4" x 2 1/4" DCs,4 3/4" x 2 1/4" WS x-over sub= 151.31').TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 5,232' (rabbiting all pipe). N/U 7 1/16" stripping head w/13 5/8" adapter spool. P/U swivel, M/U single#165, installed rubber and M/U to string, landed rubber. Established parameters: PUW 60k, SOW 50k, ROT 56k, pump rate @ 3.4 BPM 325 PSI (SW). Had to clean up metal shavings @ 5,239' to 5,241.5'. Began milling on 9 5/8" pkr at 5,241.5'. Fluid losses running 24 BPH- 1/3 of a drum of metal shavings recovered during pkr milling operations.TD at report time = 5,242.5' (mill spinning on pkr components). 411 410 Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/26/2017 Tuesday Continued milling on pkr w/8 1/2" bladed junk mill at 5,242.5'. 0845 hrs lost all torque and weight picked up-eased down to EOJ at 5,265' w/o tagging. Circulated btms up x 2 (SW) at 3.45 BPM 270 PSI. L/D swivel and N/U stripping head. Eased down hole and located top of pkr at 8,419' (top expected to be found at 8,421' if seal assembly stung in completely at 4 1/2" liner top). N/U stripping head and P/U swivel- dressed off top of pkr assy and circ btms up x 2 (rev). L/D swivel and N/D stripping head. POOH to BHA pumping displacement every 20 stands. B/D BHA and checked junk mill-75%of carbide remaining on mill-3 pieces of pkr rubber in mill ports. M/U BHA #14 (Itco spear dressed w/3.947 grapple, 11.82' of 3 1/8" x 1" spear extensions, 3"x 1" x 8" stop sub, 4 3/4" x 1" X-over sub, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub = 161.13') (pictures in 0-drive of mill).TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 8,407' (133 stands). P/U single#267 and tagged TOF at 8,419'- attempted to spear into fish (top of pkr) with no success. M/U Kelly hose to use circulation to aid in latching. Presently attempting to establish circulation-tb plugged. 09/27/2017-Wednesday Continued trying to estb circ alternating directions and working pipe- nogo. Closed annular and pumped at 3.5 bpm 1050 psi for 15 mins (no returns)-shut down pump, opened annular and eased down setting 3k on TOF. Closed annular and began injecting again at 3.4 bpm 960 psi for 15 mins. Shut down pump and opened annular-attempted again to stab into top of fish w/spear, setting 10k down while trying to work in - nogo. POOH to BHA pumping displacement. B/D BHA and B/O spear assy-—2' of fine metal shavings and gunk jammed inside spear and lowest spear extension. Unplugged assembly and ran water thru jars and 1" IDs of 3 1/8" extension assy. M/U BHA#15 (3 3/4" x 1" Piranha mill, 13.48' of 3 1/8" x 1" extensions, 8" x 3" x 1" stop assy,4 3/4" x 1"X-over sub, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4" x 2 1/4" DCs, 4 3/4" x 2 1/4" WS x-over sub= 166.02). TIH w/ milling BHA on 3 1/2" PH-6 workstring to 1,712' (25 stands in)- pumped tb capacity LW. Cut and slipped 120' of drilling line-serviced rig. Continued RIH to 8,410' pumping tb capacity LW every 25 stands. N/U 7 1/16" stripping head w/ 13 5/8" adapter spool- P/U swivel- M/U single#267 and installed rubber- M/U to string and landed rubber. Established parameters: PUW 110 k, SOW 78k, RotW 88k,4.25 BPM 1050 PSI (LW). Cleaned out top of pkr from 8,419' to 8,436'. Pumped 60 bbl high visc salt pill (L/W) and chased w/ FIW @ 4.33 BPM 1080 PSI- P/U out of pkr assy once pill came around end- continued rotating string slowly while pumping. Fluid losses—24 BPH. 110 • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/28/2017 -Thursday Finished circulating hi-visc salt pill OOH-diverted pill into pit under shaker-some metal in returns. Eased down and re-entered ID of cleaned out pkr bore 17' (w/pump on) w/ no trouble-shutdown pump and re-entered again with no trouble. Pulled and L/D single#167- L/D swivel and N/D stripping head w/spool. POOH to BHA pumping 8 bbls FIW every 20 stands. B/D BHA- left B&O jars together w/3 1/8" extensions plus 8" stop. Minor marks on face of 3 3/4" mill. M/U test plug on btm of 3 1/2" test jt- pumpin, SV, !BOP on top- landed plug. Filled system w/ FIW and pressured up for shell test-four hold down pins on tb head leaked. Backed out pins 1/8" from OD of head and ran in smaller alien set screws until resistance was felt. Pressured up again with same leak. Called for NOS wellhead rep to come out while rig crew repacked pins- next shell test held- NOS changed one pin and repacked same. Pulled test plug and changed seal- relanded test plug and performed solid shell test to 3500 psi. Rig crew flushed and cleaned out pit system.Tested all BOPE to 250 psi low 3500 psi high as per Sundry in accordance to Hilcorp &AOGCC requirements. Performed successful koomey draw down test-tested w/3 1/2" &4 1/2" tb. Witness waived by Mr. Regg 5:39 PM 9/27/17 by email. B/D test equipment and cleared floor. M/U BHA#16 (Itco spear dressed w/3.947 grapple, 11.82' of 3 1/8" x 1" spear extensions, 3"x 1" x 8" stop sub, 4 3/4" x 1" X-over sub, 4 3/4" x 2 1/4" B&O jars, 4-4 3/4"x 2 1/4" DCs, 4 3/4 x 2 1/4" WS x-over sub= 161.13 ),TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 591'- pumped tb capacity LW at 3.5 bpm 455 psi. Continued in hole to 4,250' and pumped tb capacity at 3.3 bpm 650 psi LW. Continued in hole. 6,546' (103 stands) at report time. 09/29/2017- Friday Continued in hole w/ Itco spear assy(3.947" nominal catch grapple) to 8,406' P/U 110k SOW 68k). M/U Kelly hose and circulated tb capacity prior to engaging fish @ 3.2 bpm 760 psi. Eased down while circ (LW) at 1 bpm 105 psi and speared into fish (top of fish = 8,419') (grapple depth = 8,432'). P/U to 140k and allowed oil jars to open- picked up to 210k and seals pulled loose from TBR in liner pkr at 12,320'. B/O Kelly hose and laid down single (moving uphole at 168k). POOH to BHA pumping displacement. B/O L/D drill collars and KOTs jars- R/U BJs and B/D spear/milled over pkr assy. With 3,888' of 4 1/2" liner in hole- R/U and circulated tb capacity x 2 (Rev) @ 3.75 bpm 250 psi. L/D 4 1/2" 12.75# L-80 Hydril 503 liner checking pins and doping box ends- 125 total jts laid down- no damage found with liner. L/D 5.25" seal assembly and pups w/X-nipple-while B/0 seal assembly, broken up 9 5/8" pkr parts fell out on rig floor(slips and cone chunks)- 1 seal missing on bottom set on seals. M/U Tripoint 7" test pkr = 12.07' (BHA#17).TIH on 3 1/2" 12.95# P-110 PH-6 workstring to 4,101' (66 stands)- reversed tb capacity @ 2.5 bpm 160 psi. Continued in hole to 84 stands in hole (5,217') at report time. Had to stop briefly to repair rig radiator hose. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 09/30/2017 -Saturday Finished repairs on rig radiator hose-topped off antifreeze and check ran motor. Continued in hole from 5,217' to 8,504' (2' above liner top- PM)- M/U stand #138 then eased down tagging at 18' in = 8,524'. B/O stood back stand and P/U single w/valve and Kelly hose- installed stripping head to avoid wear on annular- began pumping SW at 3.5 bpm 450 psi-from 8,504' eased down washing and tagged in same spot (8,524')-worked tool in efforts to get deeper- nogo.Turned fluid around and began pumping at 2.75 bpm 420 psi-attempted to wash thru obstruction with no success. Schematic shows 7" liner top at 8,487'- 10 Sep17 tagged w/8 1/2" bit at 8,506' (unable to circ)-we have not tagged on 7" liner top during any runs in hole.Attempted to set test pkr 3 times but no set (possibility of being above 7" liner). Placed end of tool 1/2' above tag (2nd time at 3' above tag) and circ (LW) at 4 bpm 530 psi f/ 20 mins-shutdown pump and attempted to get deeper-could not get deeper. N/D stripping head, POOH to 7" test tool pumping displacement. L/D pkr(no damage visible at surface-functioned pkr w/no problems). M/U BHA#18 w/5" x 2" bladed mill,4 3/4 x 2 1/8" X-over sub, 6" x 2 1/4" string mill, 4 3/4" x 2 1/4" B/O jars, 2 -4 3/4" x 2 1/4" DCs, 4 3/4"x 2 1/4" = 94.46'.TIH w/ BHA on 3 1/2" 12.95# P-110 PH-6 workstring to 450'- flow checked LW at 3.5 bpm 186 psi. Flow checked again at 4,600'. Continued in hole to 8495'. N/U stripping head. Established parameters: PUW 100 k, SOW 70k, 3.75 bpm 688 psi (LW). Washed down through top of 7" liner from 8,506'to 8,526' w/ no problems- R/D hose and RIH to 8,588' w/ no problems. R/U hose and circ tb capacity x 2 (SW) @ 3.5 bpm 400- R/D hose. Continued RIH from 8,588'-tagged at 9,550'. Presently R/U circulating hose. 10/01/2017-Sunday (TIH w/ KOTs 5" x 6" tandem mill assy w/jars &collars)Tagged at 9,550'-set back stand- N/U stripping head and P/U power swivel- M/U single#305 w/ rubber-screwed into string and landed rubber. Established parameters (PUW 110k SOW 94k RotW 84k FT 3500 fps, circ 3.2 bpm 370 psi)-washed/milled from 9,518' to 9,706' (last jt went down w/o circ or rotation). Circ btms up (SW) at 3.3 bpm 410 psi. R/D swivel and N/D stripping head. Began running stands out of derrick from 9,706' to 12,314' (197 stands total in hole)-tagged @ 12,314'. R/U Kelly hose on single and began circ (SW) at 3.5 bpm 400 psi-attempted to wash down from 12,314'- nogo- R/D hose and single. N/U stripping head and P/U swivel w/single#395- installed rubber and screwed into string- landed rubber in head. Established parameters: PUW 162k, SOW 80k, RotW 100k, FT 6000 fps, circ 3.5 bpm 800 psi-washed/milled from 12,314 to 12,331'. Worked pipe in efforts to make last 2' of hole- nogo (this gives us 6' of clean TBR to stab 3' of seals into). Circulated btms up x 2 (SW) at 3.5 bpm 531 psi- (once inside the tie back sleeve and once outside of the tie back sleeve)-spotted 1 drum of CFS-520 friction reducer in 7" casing due to PUW. R/D swivel and N/D stripping head- laid down pups used to wash/mill down with. POOH standing back workstring pumping 8 bbls FIW displacement every 20 stands- 185 of 197 stands OOH at report time = 898'. Fluid losses— 6 BPH. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations 4 " ''t 10/02/2017-Monday Finished POOH w/ KOTs 5" x 6" tandem mill assy to BHA. B/D L/O all fishing tools and collars- minimual wear on 5" junk mill & 6" string mill (wind gusting 40-45 mph). M/U Tripoint 7" test pkr on 1st stand of workstring.TIH on 3 1/2" 12.95# P-110 PH-6 workstring to 8,631'. P/U 10' and put 6 RRHT in pipe-eased down and set 10k on pkr. Closed pipe rams and lined up to pump down annulus-took 40 bbls FIW to fill backside- pressured up to 1700#s and held on chart for 40 mins. Released pressure-solid test. POOH and B/O L/D Tripoint test tool. Cleared & cleaned floor- R/U McCoy power tongs and handling tools for 4 1/2". M/U Baker 5.25"TBR seal assembly(rerun) w/5.70" locator,4 1/2" IBT x 4 1/2" Vam X-over pup, 4 1/2" LTC x 4 1/2" IBT X-over pup, 4 1/2" x 3.812" X-nipple assy, 4 1/2" SuperMax x 4 1/2" LTC X-over pup,4 1/2" Hydril 503 x 4 1/2" SuperMax X-over pup= 37.23'. P/U R/I 120 jts 4 1/2" 12.75# L-80 Hydril 503 tb (rerun)-drifting w/3.83"then torqueing to 4600 FPT(3,704.88'). RIH to 3,738'. R/D McMoy tongs- R/U Gill tongs and changed out elevators. M/U Tripoint liner hanger pkr assy(4 1/2" LTC x 4 1/2" Hydril 503 X-over pup, 7" 23-32# Isolation/permanent pkr, 7"TBR, pkr running tool, 3 1/2" IF x 4 1/2" LTC X-over sub, 4 3/4" x 2 1/4" NOV bumper, WS X-over sub = 26.75'). PUW 40k.TIH w/4 1/2" liner assembly on 3 1/2" 12.95# P-110 PH-6 workstring from derrick (rabbitting stands)-from 3,767' to 4,510' (12 stands PH-6) at report time. 10/03/2017-Tuesday Continued RIH w/4 1/2" liner/isolation assy from 4,510'. Went thru top of liner at 8,506'with EOTs with no issues (did not see it). Continued into 12201'. R/U stripping head &element. Cont. rih t/tag @12317' pipe measurement. R/u circulating lines, up wt 129k, do wt 76k. Pump @ 1.8 bpm on back side, pressure up w/ no returns t/410psi, p/u till psi fell off( had 5k op before pressure fell off) break circ @ 2.5 bpm, @ 80 psi, slack off till pressure increased shut down pump, cont. slack off till tag @ 12321' (pipe measurement). P/U pup jt, cont. slack off set down 14k l/d pup jt, r/u circ line pump on back side w/no returns pressure up t/350 psi, bleed off, drop ball wait 30 min t/fall. Pump down tubing pressure up t/2300 psi, pressure fell t/420psi, increase rate t/2bpm, pressure up t/1000 psi while pumping but no pressure build. Discuss scenario, attempt pump again w/same results, slack off on string t/165k, picked up t/135k (6k over) appears packer set. Pressure up on back side t/690 psi & held. Discuss scenario w/Tri-point rep in town, decide to pump down tubing @ max rate (3bpm) was able to get 2700 psi. R/U test 7" pkr &casing t/ 1500 psi f/30 min, good. Bleed off pressure t/o P/U to neutral wt 88K release pkr rot to right 14 turns release f/pkr P/U 15' 88K top of 7" tie back receptacle @ 8575'. R/D stripping head & element and R/U to 1/d 3 1/2" ph 6 work-string. Continued POOH L/D work-string pumping 8 bbls FIW displacement every 40 jts. L/D BHA. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 9/4/17 10/8/17 Daily Operations: 10/04/2017-Wednesday Clean &clear floor. RIH w/59 stands 3 1/2 PH-6 work string t/3658'. POOH, L/d 118 jts 3 1/2" wk string. R/U wireline. RIH w/4 1/2" RK plug and set @ 12315'w/WLM. POOH and RIH w/ prong and set. POOH. R/U test equipment and close blind rams.Test 9 5/8" X 7" liner top and 7" pkr and 4 1/2" liner T/ 1500 PSI f/30 min,good. RIH w/wireline and retrieve prong. POOH, L/d prong and RIH f/4 1/2" RK plug. POOH w/ plug t/9700' and shear off of plug and cont pooh and repinned running tool. RIH and latch on plug @ 9700' pooh w/ plug and l/d plug 4 1/2" RK. Seems to be some scale in pipe and 1 piece metal. Continue M/U 2.63" magnet and RIH t/12400', POH recover small amount of metal fines. R/d W/L. 10/05/2017-Thursday Continue R/D pollard slick line unit and clean and clear floor. M/U 4 1/2" test joint, rig up all test equipment and set test plug. Organize equipment around rig, pre test bop 250/3500 and wait on state man due to weather hold. Stateman arrived @ 12:30 PM.Tested all BOPE to 250 psi low 3500 psi high as per Sundry in accordance to Hilcorp &AOGCC requirements. Performed successful Koomey draw down test.Tested w/4 1/2" tj. Witnessed by AOGCC Adam Earl. R/D all test equipment. R/d power swivel. R/U prep to p/u 4 1/2" Hydril 503 production used and new pipe tubing and tally pipe. L/D power swivel and set back in unit for shipping. P/U 4 1/2" 12.75# L-80 Hydril 503 tubing. M/U tq 4600 FPT, drift w/3.50 rabbit t/8187' (tot p/u 266 joints= 133 stds ). POOH t/7544' stand back in derrick 4 1/2" Hydril 503 production string. 10/06/2017- Friday Cont. POOH standing back 4 1/2" completion, 133 stands total. Rig up Summit ESP running eq. P/u m/u &service tandem 500hp motors & lower tandem seals. Cont. p/u ESP assembly&service- upper tandem seal, intake, tandem pumps, discharge & ported pressure sub. Tested power cables and flat pack,good. Continue RIH w/ESP Assy on 4 1/2" Hydril 503 12.75# L-80 Tubing t/5015' f/derrick. M/U 4600 FPT, perform checks on cable every 1000',good. 10/07/2017-Saturday Cont. RIH w/ ESP assembly on 4 1/2" tubing f/5015't/6000'. Change out cable spools& make splice. Splice landed mid jt 194. Cont RIH w/ ESP assembly on 4 1/2" tubing f/6000't/8326'. M/U hanger& landing jt. M/u penetrator splice. Due to too much slack in cable, decision was made to cut and resplice cable t/penetrator and tested good. RIH w/hanger and set w/60K on hanger placing end of assy @ 8362'. RILDS w/ NOS hand, tested ESP penetrator w/ Summit, good. B/O landing joint L/d same. P/U, set BPV, r/d Summit equipment B/o all cross over and pup joints. Continue r/d beaver slide, cat walk, hand rails & rig floor platform. 10/08/2017-Sunday Cont. prep & scope down derrick, lay over same. N/D BOPE & riser. Prep wellhead, change out all 1/d pin seals. N/U tree and test void to 500/5000 psi good. Completed production hookups. Pulled BPV and installed 2-way check. Shell tested to 5000 psi good.Turned well over to production. OF 7J • THE STATE Alaska Oil and Gas . of/� Conservation Commission LAsKA 333 West Seventh Avenue Anchorage, Alaska 99501-3572 GOVERNOR BILL WALKER g ® Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis Operations Manager %W A U Gi 0 12017 Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-13RD2 Permit to Drill Number: 201-046 Sundry Number: 317-329 Dear Mr. Golis: 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, 6COCC1 Hollis S. French Chair DATED this 2-P day of July, 2017. RBDMS Li' JUL 2 7 2017 • • • RECEIVED STATE OF ALASKA JUL 1 7 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION Pt-5 7 2-(4( 7 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well 0 Operations shutdown Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing ❑Q Change Approved Program Plug for Redrill 0 Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing t Other. Replace ESP l Install Liner 0- 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Hilcorp Alaska,LLC Exploratory 0 Development ❑' _ 201-046 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number Anchorage,AK 99503 50-733-20157-02 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? N/A • Will planned perforations require a spacing exception? Yes 0 No ❑ / Trading Bay Unit K-13RD2 • 9.Property Designation(Lease Number): 10. Field/Pool(s): ADL0018722 • McArthur River Field/Hemlock Oil Pool , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): ;2sgt.0,: Plugs(MD): Junk(MD): 15,485 - 9,737• 15,485 . 9,737 . 9709Trisi ;/L`- N/A 13,720 Casing Length Size MD TVD Burst Collapse Structural Surface 5,011 13-3/8" 5,011 1,482 3,090 psi 1,540 psi Production 8,707 9-5/8" 8,707 7,163 6,870 psi 4,750 psi Production 3,943 7" 12,430 9,657 8,160 psi 7,030 psi Liner 1,459 4-1/2" 13,779 9,770 5,350 psi 4,960 psi Liner 1,606 4-1/2"slotted 15,385 9,741 slotted slatted Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 12,520-13,675/13,779-15,385• 9,701-9,776/9,772-9,742 4-1/2" 12.75/L-80 8,168 (slotted) (slotted) Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A&N/A N/A&N/A 12.Attachments: Proposal Summary ❑r Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development C7� • Service 0 14.Estimated Date for 15.Well Status after proposed work: 10/1/2017 Commencing Operations: OIL 2 • WINJ 0 WDSPL 0 Suspended 16.Verbal Approval: Date: GAS 0 WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stan W.Golis Contact Name: Dan Marlowe Authorized Title: Operations Manager Contact Email: dmarlowei hi(COrp.com L "� • ,7 „ ( Contact Phone: (907)283-1329 Authorized Signature: S111••••• f...J Date: ( 1( L t--1 COMMISSION USE ONLY Conditions of approval: Notify Commission s that a representative may witness Sundry Number: 3k-r- 2, Plug Integrity 0 BOP Test [V Mechanical Integrity Test 0 Location Clearance 0 Other: k- 3SOD p' z- /&tP .-7-z-;74- 0-.j 0V p 5"- ,4n r'"-L1-4- 'frj Post Initial Injection MIT Req'd? Yes 0 No 0 RBDMS L J_UL 2 7 2017 Spacing Exception Required? Yes ❑ No Id Subsequent Form Required:I(, -4/a`'( --\ APPROVED BY l Approved by: c v COMMISSIONER THE COMMISSION Date: 'T Ile. Ila (�)� • ?1l01i- Of 77817 71 7,--t?-t7 `p/< O n IG414ALls Submit Form ane w �V� Form 10-403 Revised 412017 t�(` valid for 12 months from the date of approval. Attachments in Duplicate • 0 . • la Well Prognosis Well: K-13rd2 Hilcorp Alaska,LI., Date:07/17/2017 Well Name: K-13rd2 API Number: 50-733-20157-02 Current Status: Oil producer(ESP) Leg: Leg#2 (SE) Estimated Start Date: 10/01/2017 Rig: Moncla 404 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 201-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Stan Golis (907)777-8356 (0) Current Bottom Hole Pressure: 4,069 psi @ 9,701'TVD 0.419 lbs/ft(8.07 ppg)based on ESP Gauge Maximum Expected BHP: 4,069 psi @ 9,701'TVD 0.419 lbs/ft(8.07 ppg)based on ESP Gauge Maximum Potential Surface Pressure:**3,099 psi Using 0.1 psi/ft gradient 20 MC 25.280(b)(4) **Note-This is a No-Flow Well as of 06/15/2016.Current SIT'is 65 psig M '°As , Z.3`34 ,� 2 ' /7 Alt, ALTERNATE MPSP calculation requested per 20 AAC 25.280(b)(4)to use Moncla 404 BOPE system w/3 -'" preventers 0 & Last Casing Test: 05/15/2016 tested casing at 8,977'to 1,700 psig for 30 minutes on chart. Brief Well Summary The K-13rd2 well is currently completed with a failed ESP.This work over will replace the pump.At the time of ESP failure the well exhibited change in fluid characteristics causing us to suspect GGS water influx. Casing diagnostics will be run to identify and isolate this water. (-----"? ie. c...-,..s;Act_ 144.4.. . Brief Procedure: 1. MIRU Moncla Rig#404. 2. Kill well and circulate Hydrocarbon off of well through ESP.Work over fluid to be FIW. BOP's will be closed as needed to circulate the well. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test all BOP equipment per AOGCC guidelines to 250psi low/3,500psi high/ si Annular. 4. Monitor well to ensure it is static. Zc' 5. Unseat hanger and POOH with completion. 6. Diagnose casing to identify source of water influx. a. PU 9-5/8" RTTS and RIH to ±8,475'. Set packer, test casing to '1,500 psi and chart for 30 minutes. Move packer up hole as required to identify source of water influx. POOH. b. If 9-5/8" passes test, PU 7" RTTS and RIH to ±8,950'. Set packer, test casing to "'1,500 psi and chart for 30 minutes. Move packer up hole as required to identify source of water influx. POOH. 7. Ogtin.n-A- If leak is in 9-5/8" a. PU and RIH with liner top dressing mills and polish seal bore at±8,487'. POOH. b. RU and run tieback liner to cover casing leak. c. PU 7" RTTS and RIH to ±8,950'. Set packer, test casing to -1,500 psi and chart for 30 minutes. 8. )tion - If leak is in 7" a. PU and RIH with liner top dressing mills and polish seal bore at±12,320'. POOH. b. RU and run tieback liner to cover casing leak. —pl--*;F c� ,,� ��-oL P;` 9. Run ESP completion • • • Well Prognosis Well: K-13rd2 Hilcorp Alaska,is Date:07/17/2017 10. Set BPV. NU tree,test same. 11. Turn well over to production. 12. Conduct SVS tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form • II 0 Trading Bay Unit King Salmon Platform • Well: K-13RD2 SCHEMATIC PTD:201117 50-733-20157-02 Hilcorp Alaska,LLC Completed: 06/02/2016 RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 _ J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7"Liner 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Liner 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2"Slotted Liner 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' TUBING DETAIL N. 4-1/2" 12.75 L80 Hydril533 3.958" Surf 8,168' 1 JEWELRY DETAIL 2 4 1 1 0 No Depth Depth OD ID Item 3 (MD) (TVD) VIWIRR 33.70' 33.70' Hanger 4 1 8,168' 6,715' 5.130 - B/0 Discharge 2 8,170' 6,716' 6.750 - Pump(x2)45 Stg SH12000 5 3 8,213' 6,752' 6.750 - Intake 4 8,233' 6,768' 5.620 Motor(x2)562 Motor,KMSUT/KMSLT 500 HP >< >< 5 8,298' 6,821' 5.620 - Centralizer/Anode /L 6 12,320' 9,600' 4-1/2"Liner top(ZXP Packer) 9-5/8"Window Casing leak 30°H7ole Angle 8,977'-8,987 Perforation Detail Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Date Comments HK 1-2 12,520' 13,675' 9,701' 9,776' 05/31/2016 Open HK-2 13,779' 15,385' 9,772' 9,742' 06/19/2001 Slotted Liner 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME 4-1/2"J-55, 11.6#Tubing 20" - 119 hrs 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"- 229 hrs 13,779 MD-15,348' MD 9-5/8"-259.5 hrs 7"- 99.5hrs Lost 1 roller 2.6"dia.X.25"thick off Schlumberger roller stem ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000' MD W/blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD=15485'MD/9736'ND Revised By:JLL 06/13/16 • Trading Bay Unit 410 King Salmon Platform II Well: K-13RD2 PROPOSED PTD: 201-117 50-733-20157-02 Hilcorp Alaska,LLC Completed: Future RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' S 1® 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7-5/8" TBD ±8,487' A Option A 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' TBD- 4-112" ±8,600' ±12,320' ±8,487' 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' L h 4-1/2"Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' 4 a TUBING DETAIL 4-1/2" 12.75 L-80 Hydril 533 3.958" Surf ±8,200' S� C. �-.1 JEWELRY DETAIL -91111111116 • No Depth Depth OD ID Item (MD) (TVD) 1 33.70' 33.70' Hanger Bolt-On Discharge ><( Pump 1 Intake /Z. \2 Motor ±8,300' ±6,823' 5.620 Centralizer/Anode 9-5/8"Window 2 12,320' 9,600' 4-1/2"Liner top(ZXP Packer) @ 8707'MD, Casing leak 30°Hole Angle 8'977 8'987 OptionPerforation Detail Li u iLe✓- Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Date Comments HK 1-2 12,520' 13,675' 9,701' 9,776' 05/31/2016 Open HK-2 13,779' 15,385' 9,772' 9,742' 06/19/2001 Slotted Liner R. _ 2 A S\ 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole-' Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME 4-1/2"J-55, 11.6#Tubing 20" - 119 hrs 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"- 229 hrs 13,779 MD-15,348' MD 9-5/8"-259.5 hrs 7"- 99.5 hrs 40 Lost 1 roller 2.6"dia.X.25"thick off / Schlumberger roller stem ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000' MD WI blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD=15485' MD/9736'TVD Revised By:JLL 07/17/17 i S . iiKing Salmon Platform K-13 Current 01/18/2016 HiImrp 11aska,1.l.l: King Salmon Tbg hanger,OCT-UH-TC-1A- K-13 ESP,13 X 4'/BTC lift and 24X133/8X95/8X4%: susp,w/4' Type H BPV profile,3/8 cont control line port BHTA,B-11-A0,4 1/16 5M FE lc ii ,..„frin F 1 Valve,Swab,FE HWO EE triml/16 5M ��1c, ci ZO A 1116 t j\r w� ,.,,.. valve \ng o PM oiler' 6 Valve,Wing,Vetco,2 1/16 5M FE 7—/ HWO,AA trim , s i _ m / \ 4-Iii Valve,Master,OCT-75,4 1/16 5M ,\ ft `rwtr �'ri■��'j"�'`' FE,HWO,EE trim #.0 w1 7.,„/011,1."-Ti 00,87,,, Av Bad Ring Groove Petromec Ring Gasket Only Valve,Wing,OCT-20,4 1/16 5M FE, •- HWO,EE trim ` _ A - . Adapter,OCT-AS-ESP,13 5/8 5M API hub X 4 1/16 SM stdd top,w/2-1/2control i* 11V, if C line exits,prepped w/OCT 400-4 pocket • All unihead annular valves,2 Unihead,OCT type 3,13 5/8 5M API I ek�`� ? 1/16 5M FE OCT-20,HWO hub top X 13 3/8 BTC casing bottom, 1' „..,./------- rl` �IIa.iw/1-2 1/16 5M SSO on lower �• - i,. section,1-2 1/16 5M SSO on middle - section,3 2 internal SM SSO on upper = section,IP internal lockpin asst' rli j.,. Valve,OCT-20,3 1/8 2M'/< FE, HWO Starting head,OCT,21 2M FE X 1I Jii A 1 set of lockpins 1111 24" 13 3/8" 5� 9 5/8" 1 4%' a •. II King Salmon Platform Moncla BOP Ililrnrp laxkm-1.1i 4.34' OOril.•. 193,50ao ri•= III 111 11111111 III III III 111 III _gall -() r 7"Rams 2.83 �. IL -' iii .. .Jill kis ili 1I1 lel Ill III 'lit a Iii CI W-0 ' rim. Varia2h7/85le rams 7 t= 4.67 t' =— 1�' . 13 5/8-5000 ®�II—_t1� Blind Rams 111 Iii Iii lil III Choke and Kill valves 2 1/16 5M 2.26 i rtii4j ., i 1l1 111 111 111 111 TF H.1 •i . ,�- I I It; III lit'flail `�� MP III Ill III 1{I III Rise 13 5/8 5M FE X 135/8 SM FE lit !VIII III'1111 III ill 111 111 III 0 • King Salmon Platform BOP Stack(Moncla) Hilcnria %L•arka,LIS. • s • Illi 1 III itI - ' - _, 3.74' s. Shaffer III i11 Iii Iii iii 111 III11I III III P CIW Uimiiiii. Variable 27/8-5 4.67' _���. �!,. 13` o� '�111111 ' _Blind Rams 'itl ill III I ll di _ _ Choke and Kill Valves 2 1/16 5M w/Unibolt connections for 1 hoses �j ]� • III III 'ti i: IrIcIiI zoo i11J_ ` (;7�'"1 I .r:a� III i ' di Ili iii iii in igl Riser,13 5/8 5M FE X 13 5/8 5M API#13 Y 13.70' ° I - ' DED Fill t. 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J D U 0 • • Moncla Rig 404 BOP Test Procedure Hilcarp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, 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 the tubing hanger won't pressure test due to either a penetrator leak or the 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. 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) For ESP wells-Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr.Guy Schwartz(AOGCC)and Mr.Jim Regg(AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. 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.) 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.) • Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLC. Attachment#1 f) Record and report this test with notes in the remarks column that the tubing hanger/BPV profile/ penetrator 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 joint 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-RIH with test plug on joint of tubing. Install a pump-in sub w/test line plus an open TIW or lower Kelly valve in top of test joint w/open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump-install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 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(test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 1st valve on standpipe manifold,close valves 1, 2, 10 on choke manifold and close the annular preventer,open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer,close safety valve and open IBOP on test joint,close outside valve on kill side of mud cross,open ft valve of standpipe, close valves 3,4&9 on choke manifold,open valves 1&2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. 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 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross,close valves 5&6/open valves 3&4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5&6 on choke manifold. Pressure up to—1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR(outside valve on choke side of mud cross), open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. • • • Moncla Rig 404 BOP Test Procedure Hikorp Alaska,LLC Attachment#1 g) Close inside valve/open outside valve(HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off-open pipe rams and pull test joint leaving test plug/2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold,close valve 7&8/open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves(TIW or Lower Kelly Valve)and IBOPs as necessary. 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. Document both the rolling test and the follow up tests. • I -19.: .' co 0ca o m � V > O N 2 O Q i U E ¢ C.d C Q M CDL E -- E ° C •p o C d N = N 10. �, a L '— a, � om vi ai a) 73_oQYQai .m_= L o ._ a. v 03 az Cr cv a) C 0- o N et L Z O co al C rn °Z m Co C U ca Zcc a� 9 U L N O o m CD a -c o az O N > � a 14. e 2a L �M 0-' .L3 0) Y Cli c CC a m co CO V -a0 a) C/)1.... ° m OQ d d E L V L. p Oo- .0 a a) U ns Ci a) !=0 C '. C w O - c W11.1 U a > "o G N o U ) > a OL la-) ea d r a.� ^ O, a. co.oo O L. Ct Q• Ccr ,� Q .2 oY co o X XX o es Q c , X orn ~ - x L C.) w c=a X o a) n. N L CL. to V x is Q ii •.r .r+ p V a) x ^ 'a EU o c`o F�i Vcn in Q 0 y Q • • Schwartz, Guy L (DOA) From: Dan Marlowe <dmarlowe@hilcorp.com> Sent: Wednesday,July 19, 2017 9:46 AM To: Schwartz, Guy L(DOA) Cc: Juanita Lovett Subject: RE: MASP for K-13RD2 (PTD 201-046) Attachments: King Moncla rig BOP for liner job.pdf Guy Here is the requested information and also an updated BOP stack to cover Option A. 1. We will need an additional single gate in the stack(see attached)to cover the possibility of running 7-5/8" liner 2. If we run a liner inside of the 7", it will most likely be a 4-1/2" tieback with a hydraulic set packer. We would then set and test this casing with a wireline plug in an X nipple just above the seals stabbed into the existing 4- 1/2" production liner. 3. MASP-The calculated MASP for this wellbore when completely evacuated to gas is 3,099psi. However,for Cook Inlet Operations,we assume that the well can never flow 100%gas, due to water in the reservoir.We reduce this MASP calculation to 2,396psi which assumes that only 2/3 of the wellbore is evacuated to gas and 1/3 to 8ppg reservoir fluid. _moo Thanks /41/So is Dan Marlowe u �o - f/Q,., " kiae Hilcorp Alaska, LLC Operations Engineer Office 907-283-1329 7 7_/'-/7 Cell 907-398-9904 Email DMarlowe(cr7hilcorp.com Hilcorp A Company Built on Energy From:Schwartz,Guy L(DOA) [mailto:guy.schwartz@alaska.gov] Sent:Tuesday,July 18,2017 4:24 PM To: Dan Marlowe<dmarlowe@hilcorp.com> Subject: MASP for K-13RD2(PTD 201-046) Dan, In your request for alternate MASP you failed to provide a different calculated value as required. You currently list 3099 psi for the MASP but as you stated this is a confirmed No Flow well. In order to use a 3 preventer stack the calculated MASP must be less than 3000 psi. Were you planning on testing the 7" liner/casing if option B is done? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell OF T • y g ts-\\ I%/ ,v THE STATE Alaska Oil and Gas w 'AL=- oLAsKA f Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501 3572 pF P Main: 907.279.1433 A ,S Fax: 907.276.7542 www.aogcc.alaska.gov July 27, 2016 Mr. Stan Golis Operations Manager—CI Offshore Hilcorp Alaska, LLC P.O. Box 244027 Anchorage, AK 99524-4027 RE: No-Flow Verification SCANNED FED ' 6 2017 Trading Bay Unit K-13RD2 PTD 2010460 Dear Mr. Golis: On June 15, 2016 an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Trading Bay Unit K-13RD2 located on the King Salmon Platform in Cook Inlet. The well is operated by Hilcorp Alaska, LLC (Hilcorp). The AOGCC Inspector confirmed that the proper test equipment — as outlined in AOGCC Industry Guidance Bulletin 10-004 — was rigged up on Trading Bay Unit K-13RD2 prior to the test. The well performance was monitored for three hours with observed gas flow rates less than the regulatory limit and no liquid flow to surface. The well may be produced without a subsurface safety valve. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition in this well as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Trading Bay Unit K-13RD2 demonstrates an ability to flow unassisted to surface. Any cleanout, perforating or other stimulation work in this well will necessitate a subsequent no flow test. Please retain a copy of this letter on the King Salmon Platform. Sincerely, Javal b ke-7/ James B. Regg ( Petroleum Inspection Supervisor cc: P. Brooks AOGCC Inspectors • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission -?(2-1'i(� TO: Jim Regg 11 DATE: 6/15/16 P. I. Supervisor FROM: Jeff Jones SUBJECT: No Flow Test Petroleum Inspector TBU K-13RD2 - King Salmon Platform - Hil ska LLC - PTD 2010460 June 15, 2016: I traveled to Hilcorp's Trading Bay Unit King Salmon platform to witness the No Flow verification test on well K-13RD2. I met with Hilcorp representative Sandra Reynolds and we discussed the well history and test procedures. The well production was lined up from the tubing through an Erdco flow meter to an open top drum. Gas production from the well was less than 180 SCFH throughout the 3 hour test period and less than a cup of fluid was produced. The following table shows test details: Time Pressures Flow Rate Remarks (psi) Gas - scf/hr Liquid - gal/hr 11:30 0/0/46 <180 SCFH < 1 cup - 12:00. 0/0/46 - <180 SCFH - < 1 cup - 12:30 0/0/46 - <180 SCFH - < 1 cup 13:00 0/0/46 <180 SCFH - < 1 cup - 13:30 0/0/46 - <180 SCFH - < 1 cup - 14:00 0/0/46 <180 SCFH < 1 cup 14:30 0/0/46 <180 SCFH - < 1 cup - 1 Pressures are T/IA/OA Summary: I witnessed a successful No Flow verification test on TBU K-13RD2. Gas production from the well was less than 180 SCFH throughout the 3 hour test period and less than a cup of fluid was produced. Attachments: none %OHM APR 0 6 2017. 2016-0615_No-F1ow_TBUK-13 RD2_jj.docx Page 1 of 1 STATE OF ALASKA ASKA OIL AND GAS CONSERVATION COMM SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing CI Operations shutdown ❑ Performed: Suspend El Perforate CI Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill El Perforate New Pool ❑ Repair Well El Re-enter Susp Well❑ Other: Replace ESP El 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory El 201-046 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20157-02 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018722 Trading Bay Unit K-13RD2 RECEIVAires 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): JUN 2 0 N/A McArthur River Field/Hemlock Oil Pool 2016 11.Present Well Condition Summary: AOGCC Total Depth measured 15,485 feet Plugs measured N/A feet true vertical 9,737 feet Junk measured —13,720 feet Effective Depth measured 15,485 feet Packer measured 12,320 feet true vertical 9,737 feet true vertical 9,599 feet Casing Length Size MD TVD Burst Collapse Structural Surface 5,011' 13-3/8" 5,011' 1,482' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,163' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,657' 8,160 psi 7,030 psi Liner 1,459' 4-1/2" 13,779' 9,770' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"(slotted) 15,385' 9,741' slotted slotted Perforation depth Measured depth 12,520-13,675/ feet 13,779-15,385 (slotted) �e JAN t� True Vertical depth 9,701-9,776/ feet SCANNED 0 9 2017g-y 9,772-9,742 (slotted) Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.75/L-80 8,168'(MD) 6,715'(ND) 12,320'(MD) Packers and SSSV(type,measured and true vertical depth) ZXP Packer 9,599'(TVD) SSSV:N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 28 0 Subsequent to operation: 348 121 10,170 274 298 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory❑ Development Service❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil Q Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ 0 WAG ❑ GINJ 0 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: 316-036 , Contact Dan Marlowe(907)283-1329 Email dmarloweahilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature G t-0 y—:— Phone (907)777-8356 Date 6 is 6 11�0 Farm 111-4114 RPVICPr1 5/7n15 h t 1)nginal drily RBDMS k,'/ JUN 2 1 2016 G .L,-ice #1j(e/4 SCHEMATIC H 0 • Trading Bay Unit King Salmon Platform Well: K-13RD2 PTD:201117 50-733-20157-02 Hilcorp Alaska,LLC Completed: 06/02/2016 RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2"Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' TUBING DETAIL L , 4-1/2" 1275 L-80 Hydril 533 3.958" Surf 8,168' • 1 JEWELRY DETAIL 2 No Depth Depth OD ID Item AM 3 (MD) (TVD) =_^_^ 33.70' 33.70' Hanger of 4 1 8,168' 6,715' 5.130 - B/0 Discharge 2 8,170' 6,716' 6.750 - Pump(x2)45 Stg SH12000 - 5 3 8,213' 6,752' 6.750 - Intake 4 8,233' 6,768' 5.620 Motor(x2)562 Motor,KMSUT/KMSLT 500 HP \ >< 5 8,298' 6,821' 5.620 - Centralizer/Anode 6 12,320' 9,600' 4-1/2"Liner top(ZXP Packer) /L .\ 9-5/8"Window Casing leak @ 8707'MD, 8,977'-8,987' 30 Hole Angle Perforation Detail Top Zone (MD) Btm(MD) Top(ND) Btm(ND) Date Comments HK 1-2 12,520' 13,675' 9,701' 9,776' 05/31/2016 Open HK-2 13,779' 15,385' 9,772' 9,742' 06/19/2001 Slotted Liner A 7" liner cemented at 12,430' MD/9660'ND,+/-57 deg hole Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME 4-1/2"J-55, 11.6#Tubing � 20" - 119 hrs 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"- 229 hrs 13,779 MD-15,348 MD 9-5/8"-2593 hrs 7"- 99.5hrs •_._•_•_._•_._•_•_•_•_•_•_._•_._•_•_•_._.7-1 Lost 1 roller 2.6"dia.X.25"thick off NI Schlumberger roller stem ECP(inflated with mud)at 13696' MD(9774'ND) 90 Deg Section at 13,000'MD W/blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD=15485'MD/9736'ND Revised By:JLL 06/13/16 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/04/2016-Wednesday Pinned derrick in place. Began spotting accessory equipment.Stopped water flood and checked well-on slight vacuum. Knocked off tree cap and NOS rep set BPV-N/D tree.Set accumulator and choke house in place.Welder modified stairs going to carriage walkway. Laid out lines to accum. NOS prepped hanger and control lines. N/U riser, mud cross w/ wings,dual gate,annular, bell nipple and stripping head.Offload M/V Titan-5 picks. Install co-flex hose from HCR to choke house.JSA for use of crane man-basket to complete stripping head install. Raised derrick and secure half-mast guy lines. Presently spooling on drill line. 05/05/2016-Thursday Scoped out derrick and secured guy lines. Positioned power swivel. Mounted rig floor and installed floor supports,setup off-driller side stairway and racking mat. Positioned rig pump and tank.Quadco wired up fluid monitoring system. Raised driller's shack to working height, pinned legs and pinned to derrick. Installed gas buster exhaust and accumulator remote. Mount rig floor wind walls and handrails.Set up test pump. Hooked accumulator remote panel.Verified and recorded accumulator bottle pre-charge pressures(all>1000 psi). M/U up co-flex hose from HCR to stand pipe manifold. Inspected clevis and pins, installed safety pins as needed. M/U return lines from stand pipe to pit and mount pit steps. Presently rigging up floor with McCoy tongs and handling tools. 05/06/2016-Friday Finished R/U floor with tongs and tools. M/U 4 1/2"test jt w/blanked ported sub on btm and pumpin,SV, IBOP on top. Welder is working on walkway from driller's shack to pipe deck. Electrician is wiring needed equip. Functioned test BOP stack/accum. Landed 4 1/2"test jt in hanger and connected water flood to rig circ system. Filled stack w/FIW and closed hydril. Filled test jt w/test pump. Pretesting BOPs to 250#s low/2500#s high(working thru leaks).Checked accum draw down times.Welder mounted stairway from pipe deck to driller's shack. Finished pretesting.Welder rebuilt 2 floor support legs. Electrician checked gas alarm system and crane op organized deck in prep to receive Summit,catwalk,V- door and flying pipe racks. BOP test witness waived by Jim Regg,AOGCC. Housekeeping and prep for BOP test. M/V Titan arrives with catwalk,V-door and flying pipe racks.Off load and back load boat with 4-1/2"test joint made up.Tested BOPE to 250#low/2500#high as per Sundry following rig test procedures in accordance to AOGCC and Hilcorp requirements.Witness waived by Mr. Regg/AOGCC 3:14 PM 5/6/16 by email. Performed successful accum draw down test. Presently replacing 4 1/2"test jt with 3 1/2"test jt. • • Hilcorp Alaska, LLC .._ Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/07/2016-Saturday Finished testing w/3 1/2"test jt. Pulled test jt, pulled BPV and set 2-way check.Tested blinds to 250#s low/2500#s high (zero fail passes). Welder modified beaver slide to fit usage. R/U to circulate while welder finishes with 2 projects on rig floor, 1-beside rig draw works. Filled rig tank w/clean FIW, lined up to send returns to TBPF. Pumped LW at 2 BPM 300 PSI sending returns to TBPF.Welder completed needed projects while circ.Circulated a total of 820 bbls FIW to TBPF. Conducted an abandon platform drill with production. Backed out hold down pins and picked up on pipe. Hanger cleared head at 125k, pulled hanger to surface and NOS and Summit worked same.Summit R/U pulling equip.Start pulling 4- 1/2", power cable and flat pack. Unable to keep tong power pack running. Platform mechanic troubleshoots tong power pack. Power pack running. Pull 3 joints of 4-1/2" and power pack shuts down again.Swap tong hydraulics to rig hydraulic system. Resume pulling 4-1/2", power cable and flat pack with tongs operating off rig hydraulics. Pump 1.5 BBL FIW hole fill with 20 joints to surface and hole fill with 3 BBL FIW with each additional 20 joints pulled to surface. GLM#1 at surface.80 joints(257078357')of 4-1/2" pulled to surface.91 joints (2910'/8357')of 4-1/2" and power cable splice at surface.Cut out splice and megged same,still shorted to ground.Secured cable to spool,wrap cable, lift spool from spooler and set aside. Load empty cable spool in spooler.Secure well end of cut cable to empty spool. Resume pulling 4- 1/2", power cable and flat pack. 156 of 260 jts OOH at report time=3,405'.Tbg is in reusable condition. No damage to reeder cable spotted. 24 total bbls pumped for displacement. 05/08/2016-Sunday Finished POOH from 3,405'to ESP assy w/Summit's assistance, pumping displacement every 20 jts. Recovered production string being placed in flying pipe racks. B/D ESP assy. R/D Summit. No apparent reeder cable damage.Sensor at the btm of assy was badly eroded showing internals,erosion at intake,seals and motor to seal coupling. No oil in motor section.Soft broke pup/mandrel assemblies.Cleared and cleaned rig floor, pipe deck, beaver slide, BOPs and hand rails. Install wear bushing.Test start power swivel power pack. P/U handling tools to rig floor. R/U diaphram pump to take displacement returns. M/V Titan arrives. Backload recovered production string in flying pipe racks to open drill deck space.With 2 picks off platform M/V Titan moves off to wait for tide change. M/V Titan leaves to deliver tong power pack to Monopod. M/V Titan returns.Continue backload to open deck space.Offload drill collars,work strings and fishing tools. Move collars, BHA and first bundle of 3-1/2" 12.95#PH6 work string to pipe deck. M/U KOT BHA#1(6" rock bit,4 3/4"x 2 1/2" bit sub,6"x 2 1/2"string mill,4 3/4"x 2 1/4" bumper,4 3/4"x 2 1/4"oil jar,4 3/4"x 2 1/4" DCs x 4,4 3/4"x 2 1/4"Acc jar,4 3/4"x 2 1/2"x-over sub=169.86').TIH picking up 3 1/2" 12.95#P-110 PH6 workstring off deck- strapping,drifting and torqueing to specs. Finished working M/V Titon. Depth at report time is 810'. 05/09/2016-Monday Continued running KOT BHA#1 in hole(6" rock bit&string mill w/DCs and jars).Stopped running tbg in the hole at 1,223'after failures on available tong units. R/U BJ tongs while waiting on Gill tongs from Granite Point platform. Received parts for Knight McCoy tongs and repaired same. CIH w/Knight BHA#1.Stop running tbg in hole at 4,668'and shutin well. Generated Hot Work Permit and JSA for welders to install pad-eyes for power swivel snub lines.Welders installed pad-eyes on base beam.CIH w/Knight BHA#1.Went thru top of liner at 8,487'with no problems.Set down at 8,693'(9 5/8"window at 8,707'). PU weight=100K.Slack off weight=67K.Attempted to work past rotating w/tongs, NOGO. L/D JT 275. P/U power swivel and rotated thru" 2'tight spot to end of jt at 8,699'. Lined up to reverse btms up to check returns. S • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/10/2016-Tuesday Circulated btms up(@ 8,699') in reverse to check returns.Zero solids across shaker.700 units of gas at btms up falling off to zero.Stopped circ and M/U single#276 on swivel, rotated down (4500 FPT)without circulating,closed bag and circulated btms up plus with minimal solids in returns(slight plugging issues).Continued in hole running in singles with power swivel slacking off/rotating when necessary,circulating btms up every 2 jts. Last 2 went down W/O tagging (8,917'). B/O L/D swivel after circ btms up.TIH running singles and then attempted to break circ(@ 9,162')in reverse, pressured up, broke circ LW.Turned fluid around and circ btms up. R/U power swivel and began running singles,circ in reverse at 3 BPM 500 PSI.Circ 15 minute between connections with bottom up after every 5 connections. P/U weight at 306 jts(9,658')= 111k S/0=70k. Presently 314 jts+BHA in=9,904',^'4 bbls of solids recovered in returns with a total fluid loss of 26 bbls. 05/11/2016-Wednesday Continued washing/rotating down with power swivel from 9,904'circ in rev at 3 BPM 500 PSI-circulating btms up every 5 jts.Continued washing/rotating down with power swivel from 10,713'circ in rev at 3 BPM 500 PSI-circulating btms up every 6 jts. PUW= 127K, ROTW=89K,SOW=73K, BT=6500.Continued washing/rotating down with power swivel from 10,899'circ in rev at 3 BPM 500 PSI-circulating btms up every 7 jts. 5.50 bbl/hr avg.fluid loss to hole.JT 367(11,547') PUW=135K, ROTW=90K,SOW=78K, BT=7500.Continued washing/rotating down with power swivel from 11,547'circ in rev at 3 BPM 500 PSI-circulating btms up every 7 jts.0530 hrs changed out stripping rubber(@ 11,578'). 369 jts in hole at report time= 11,609'. 160 bbls lost in the last 24 hrs for a total fluid loss of 255 bbls. 05/12/2016-Thursday Continued cleaning out 7" 29#casing with power swivel picking up 3 1/2" 12.95#P-110 PH6 workstring off deck- washing/rotating/circulating 3 BPM 500 PSI from 11,609'.0800 hrs changed out cutting box and shaker screen. 1015 hrs platform power went down twice powering down Quadco monitors,shaker and water flood momentarily. Rerouted returns around shaker and continued circulating. Production restored power to Quadco and shaker. Routed returns over shaker-filled rig tank with FIW and continued washing out at 11,980'.Tagged top of Baker mdl F pkr at 12,196' (PM). P/U 136k,S/0 84k, RW 95k,6500-7000 FPT,84 RPMs. Circ hole clean. 160 bbls fluid lost and 9 bbls of solids recovered during report period for totals of 415 bbls of fluid lost and 24 bbls of solids recovered.Stopped circ and R/D swivel. POOH w/ KOT BHA#1-pumping 3 bbls every 10 stands. N/D 7"stripping head N/U 13 5/8" head-started B/D BHA. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date _K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/13/2016-Friday Finished B/D KOTs BHA#1(6" bit&mill,collars&jars). M/U KOTs BHA#2(4 3/4"x 1" pkr milling spear assy,4 15/16" mud motor,4 3/4"x 1 1/2" DP sub, 2-4 3/4"x 1 1/2" boot baskets,4 3/4"x 1 1/2" DB sub,4 3/4"x 2 1/4" B&0 jars,4-4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4"Acc jar,4 3/4"x 2 1/2"XO).TIH w/Pioneer one-trip pkr milling assy to top of liner at 8,520'(PM). Rotated into 7" liner with 2 1/2 rnds RHT.Continue in hole to 12,174' (6.90'pup+193 stands+BHA).45 bbl displacement recovery on trip in hole. Installed stripping head and P/U power swivel. M/U single#387 on swivel and installed stripping rubber-landed same.CIH and set down 15' high at 12,181'. P/U and establish parameters-P/U 140k, S/0 85k, RW 105k.Checked pump pressures: 68 SPM =630 psi,88 SPM =930 psi, 110 SPM =1200 psi. CIH rotating and pumping to wash off fill. Milled from 12,196-12,199'.Continued turning on pkr W/O making additional footage.Worked pipe to 170k several times then began moving uphole at 140k. L/D 2-single and pup. L/D power swivel. Pulling out of hole with KOT BHA#2-pumping 3 bbls every 10 stands. 11 stands OOH at report time= 11,493'.96 bbls FIW lost during milling operation. Net fluid loss for the day is 51 bbls-total fluid loss for job 526 bbls FIW. 05/14/2016-Saturday Continued POOH w/KOTs BHA#2(Pioneer pkr milling assy)from 11,493'to 7,062' (82 stands out). M/U test plug on jt of 3 1/2" PI-16. M/U to string and landed plug. B/O test jt and closed blind rams.Changed out 2 7/8"x 5" pipe ram blocks to 2 3/8"x 3 1/2"flex pkr blocks.Opened blinds and landed 3 1/2"test jt w/pumpin,SV and IBOP. Filled stack and pressured up to 2500#s. Repaired leaks as needed.Tested BOPE to 250#s low/2500#s high as per Sundry following Moncla 404 procedures in accordance to AOGCC and Hilcorp requirements. Performed successful accum draw down test.Tested w/3 1/2" &2 3/8"tb.Witnessed by Mr.Johnnie Hill/AOGCC. Pulled/laid out test plug, broke down all crossovers, N/U 13-5/8"spool on Hydril. Finished POOH w/KOTs BHA#2(Pioneer pkr milling assy)from 7,062'. B/D KOTs BHA#2. Began B/D recovered Baker mdl 'F' pkr and tail pipe.48 bbls FIW pumped for displacement while POOH.Total fluid loss for job=574 bbls. • • z Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/15/2016-Sunday Finished B/D BHA and recovered Baker mdl 'F'pkr&seal bore ass r fish (incomplete recovery= 14.15' long-.3' piece of seal bore ext mule shoe missing). M/U Halliburton test pkr(14.2')f/7"29#casing w/3 1/2" ph6 mule shoe on btm.TIH w/pkr on 3 1/2" 12.95#P-110 PH6 workstring to 11,977' (193 stands). P/U six singles placing pkr at 12,161'. P/U power swivel and M/U to string.Set packer 12,161'. Pressure Test casing = 1500 psi. Pressure falls to 900 psi"'5 minutes. Leak at tubing pins,tighten pins. Re-test with same pressure fall off. Release and re-set test packer. Retest casing at 1500 psi with same pressure fall off. Release packer. L/D power swivel. POOH with Halliburton test pkr 12,161'-9,992' (35 stands).Set packer 9,992'. Pressure test=1500 psi. Pressure falls to 600 psi"'10 minutes. Release packer. POOH with Halliburton test pkr 9,992'-9,308'(11 stands).Set packer 9,308'. Pressure test= 1750 psi. Pressure falls to 800 psi^'7 minutes. Release packer. POOH with Halliburton test pkr 9,308'-8,629' (11 stands).Set packer 8,629'. Pressure test= 1750 psi. PASS 30 minute test. Release packer. RIH 8,629'-8,742' (2 stands. ).Set pkr. Pressure test= 1750 psi. PASS^'11 minute test. Release packer. RIH 8,742'-8,866' (2 stands. ).Set pkr. Pressure test= 1750 psi. PASS"'10 minute test. „Release packer. RIH 8,866'-8,987'(2 stands).Set pkr. Pressure test=1750 psi. Pressure falls to 700 psi—6 minutes. 0( ,7,/"..Release packer. POOH 8,987'-8,977'.Set pkr. Pressure test= 1700 psi. PASS 30 minute test. LEAK OFF IS LOCATED 0( V BETWEEN 8,977'-8,987'. Released packer. POOH with Halliburton test packer pumping 3 bbls FIW every 10 stands. 100 stands OOH at report time=6,029'.Gained 48 bbls.TIH-Pumped 36 bbls POOH =12 bbls fluid gain.Total fluid loss for job of 562 bbls FIW. 05/16/2016-Monday POOH from 6,029'w/Halliburton test pkr(BHA#3)f/7"casing. B/D Halb tools. Installed wear bushing. M/U KOTs 6"x 2 1/2" pilot milling assy(BHA#4) (6"x 2 1/2" pilot mill,4 3/4" NOV mud motor,4 3/4"x 1 1/2" DP sub,2-5"x 1 1/2" boot baskets,4 3/4"x 1 1/2" DB sub,5"x 2 1/4" MI circ sub,4 3/4"x 2 1/4" B&0 jars,4-4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4" Acc jar,4 3/4"x 2 1/2"x-over sub=214.50'.TIH w/KOTs pilot mill assy filling tb ever 50 stands.Shutin well at 5,116(79 stands). N/U valve on flow cross for flow line to Mongoose shaker, built gravity feed flow line to same, plumbed in 2nd rig&charger pump.Continued in hole with milling assy to 12,181' (193 stands). N/D 13 5/8"spool N/U 13 5/8"x 7" stripping head. P/U power swivel w/single#387. Installed stripping rubber and M/U to string, landed rubber. Began pumping LW at 3.4 BPM 1050 PSI. Eased down and tagged at 12,210' (PM). Milled on obstruction.0400 hrs at EOJ= 12,212'. M/U single#388 and continue milling. ROP increase cont. milling t/12,243'. 05/17/2016-Tuesday Cont.wash&ream t/12,305', 3.4 bpm 1050 psi.CBU @ 3.6 BPM 890 psi. Break swivel connection,drop 1.75" ball to open circulating sub, pump ball @1.75 bpm, 200 psi, until ball seated. Pressured up t/1300 psi then t/1800 psi. Pressure dropped off opening circ sub. Line up both shakers start CBU,working through pump issues. Pump 7 bpm, 1870 psi,3000 stroked f/BU.Stand pipe manifold started leaking,shut down t/repair bypass manifold.Start CBU. Repair leak on hose connection.CBU @ 6.8 bpm, 1820 psi.Suction hose leak,remove hose, bypass#1 pump&charge pump. R/u drop shut off ball &circulate down t/seat in circ sub. Unable to rev out cuttings due to higher pressures. Pulled 3 singles (wet) and dropped 1 3/4" ball to open well commander circ sub. Laid down swivel. POOH laying down 60 jts of 3 1/2" PH6 work string-to be used for liner cleanout.Cleared floor of all unneeded equipment. POOH w/KOTs pilot milling assy from 10,757't/592'. • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/18/2016-Wednesday Finished POOH w/KOTs pilot milling assy. B/D BHA.Slipped &cut 130'of drill line. M/U KOTs 4 1/2" liner C/O BHA(#5) (3 3/4" rock bit,3 1/8" NOV mud motor,3 1/8"x 1"x-over sub,50 jts of 2 3/8" PH6 tb,4 3/4"x 1 3/4"x-over sub,4 3/4"x 1 1/2" DP sub, 2-5"x 1 1/2" boot baskets,4 3/4"x 1 1/2" DB sub,4 3/4"x 2 1/4"Swaco circ sub,4 3/4"x 2 1/4" B&O jars,4. 4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4"Acc jar,4 3/4"x 2 1/2"x-over sub= 1752.84').Surface tested mud motor and circ sub. TIH w/liner C/O assy to 12,234' (168 stands+2-singles). P/U 157k S/O 70k. N/D 13 5/8"spool and N/U 13 5/8"x 7 1/16" stripping head. P/U swivel with single#339. Install stripping rubber and M/U to string, land rubber.Attempted to break circulation LW at 12,234', pressured up to 3000#s. Pulled/laid down 4 jts and attempted to circ at 12,110'. Pressured up to 3000#s again. Laid down swivel. POOH w/BHA#5 KOTs 4 1/2" liner C/O assy(wet). t/11,180' Investigate drive noise on rig. Found rt angle drive broke. 05/19/2016-Thursday Disassembled right angle drive. Had some difficulties removing sprocket. Replacement arrived—0900 hrs. Performed rig maintenance and top deck housekeeping while drive is being disassembled.Assembled replacement drive and tested same. POOH w/plugged KOTs 4 1/2" liner C/O assy-from 11,180'to BHA. B/D BHA-collars,jars,circ sub, boot baskets, c/o handling tools t/2 3/8. 05/20/2016-Friday Finish POOH standing back 2 3/8 wk string. Found motor,xo&6'of first jt plugged off. Pull wear bushing. M/u &surface test bit&motor,good. Pull wear bushing. RIH w/2 3/8"wk string t/1,565'. P/u remaining BHA(BHA =(3 3/4" rock bit,3 1/8" NOV mud motor,3 1/8"x 1"x-over sub, 50 jts of 2 3/8" PH6 tb,4 3/4"x 1 3/4"x-over sub,4 3/4"x 1 1/2" DP sub, 2- 5"x 1 1/2" boot baskets,4 3/4"x 1 1/2", Bit sub w/float 4 3/4"x 2 1/4",Swaco circ sub,4 3/4"x 2 1/4" B&O jars,4-4 3/4"x 2 1/4" DCs,4 3t,BHA=(3 3/4" rock bit,3 1/8" NOV mud motor,3 1/8"x 1"x-over sub,50 jts of 2 3/8" PH6 tb,4 3/4"x 1 3/4"x-over sub,4 3/4"x 1 1/2" DP sub,2-5"x 1 1/2" boot baskets,4 3/4"x 1 1/2" Bit sub w/float,4 3/4"x 2 1/4"Swaco circ sub,4 3/4"x 2 1/4" B&O jars,4-4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4"Acc jar,4 3/4"x 2 1/2"x-over sub= 1752.84').Surface test circ.sub,good.TIH w/3 1/2 PH-6 wk string,filling pipe every 20 stands-167 stands in hole= 12,110'. N/D 13 5/8"spool N/U 13 5/8"x 7/16"stripping head. P/U swivel and M/U#335. Installed stripping rubber and M/U to string, landed rubber. Replaced ruptured 6"suction hose(from charger pump).Washed down from 12,110'circ 3 BPM 900 PSI. 12,544'at report time. S S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/21/2016-Saturday Continued washing from 12,544'to 12,634' (fluid losses increasing). Pulled and laid down 1st jt-attempted to pull second jt but pipe was stuck.Worked string from 70k to 180k-no success pulling free. M/U 10' pup and attempted to work back down hole with no success. Dropped open/close ball to shift circ sub at 11,012' in attempts to CBU-pump 7.5 BPM w/ 120 BPH losses.Continued working pipe-now jarring at 170k then pulling to 185k. Requested and received BOPE test extension from Mr. Regg/AOGCC. Dropped open/close ball to shift circ sub closed-mixed 16 bbl Drill Express/NW50 hi- vis pill and spotted at end of string.Attempted to mix second pill and circulating pump failed on Swaco pill pit.Ordered replacement/repair parts, mixing pump and size salt pill material. Received needed items from M/V Titon and R/U mixing pump to pill pit. Mixed 20 bbl Drill Express/NW50 pill and pumped down tb followed by 86 bbls FIW(spotted at end of string).Worked string from 50k up to 170k(hitting jars)then up to 185k while pill sat-checked tb&annular fillup. Tb fluid level^'1000'(7 bbls),annular fluid level^'58' (3.5 bbls). Mixed 3rd 20 bbl hi-vis pill followed by tb capacity while working string. 0300 hrs fluid level in tb is^'800',annulus is^'32'.Continued jarring on string. 0345 hrs took 10' pup out of string.Cont.working up hole 30' lost downward movement. 05/22/2016-Sunday Wk stuck pipe, 70k so, p/u t/165 jarring, pull t/180k, pump 3 BPM,940 psi,w/no returns. Mix 20 BBL NW-50 pill & pump.Spot pill while wk pipe.8:00 gained pipe movement and returns.Cont.wk pipe&circulate @ 3bpm,960 psi, up wt 135,do wt 79k, loss rate @ 120 BPH while pumping, 12 static. Mix&spot NW-50 pill at top of upper perfs, POOH t/12,419',started hanging up, attempt/wk free no go. Rig up&circulate @ 3 BPM 930 psi, pump OOH,had spots motor stalled &had to wk through (appear to be dragging something).Cont.t/12,327, POOH dry t/12,141' no issues.Change elevators. Drop ball pump on seat cycle circ sub.Spoke w/AOGCC Jim Regg,granted approval to test BOPE after POOH. POOH w/KOTs 4 1/2" liner C/O assy(BHA#6) (174 stands in derrick). B/D 1752.84' BHA(BHA intact). M/U test plug on 3 1/2"tb-landed test plug and M/U pumpin,SV, IBOP in top of jt.Set up chart recorder and test pump. Filled stack and closed annular-shell tested to 2500#s(working thru leaks). Began testing all BOPE to 250#s low 2500#s high as per Sundry following rig test procedure in accordance to AOGCC and Hilcorp requirements.Witness waived by Mr.Jim Regg (by phone). 05/23/2016-Monday Cont.testing BOPE.Test w/3 1/2&2 3/8 tj. Pull test plug, install wear bushing, m/u halls head adapter&flange. M/U BHA#7 KOTs(2 3/8" mule shoe,50 jts 2 3/8" 5.95#PH6 tb,4 3/4"x 1.867"x-over,4 3/4"x 2 1/4" B&0 jars,4-4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4"Acc Jar,4 3/4"x 2 1/2"x-over= 1,714.82').TIH t/8,535'. Rev CBU x2, @ 3 BPM,490 psi, loss rate 23 BPH.Cont.TIh t/12,196'-rev CBU x 2 @ 3 BPM 520 psi, loss rate 35.5 BPH.,Began washing down singles from 12,196'to 12,330' (10' in on#343) @ 3 BPM 500 PSI (reversing btms up)-started pressuring up.Turned circulation around and pressured up again-pulled/laid out#343 to get inside 7".Worked thru surface plugging and pump issues. Replaced stripping rubber. M/U#343 again.Continued washing at 12,320' (in rev)at 3 BPM 500 PSI-began washing fill at 12,330'.Washed to 12,341'with pressure beginning to spike. Reroute return line bypassing manifold.Continued washing to end of jt at 12,351'with no plugging-circ tb clean. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/24/2016-Tuesday Cont.wash down t/12,365'circ 3 bpm,585 psi,started pressuring up.Troubleshoot issues,able to p/u cycle pump& extra pressure would be gone,attempt to make more hole would lose circulation while on btm&pressure up. P/u cycle pump, lose extra pressure, make several attempts changing paramaters w/same results.CBU, POOH f/12,367'to BHA. B/D KOTs 2 3/8" mule shoe assy(BHA#7).Steel chunks,rocks, roll pins, bands,carbide jammed in end of mule shoe. Removed bypass line at stand pipe-broke all surface lines and manifold connections to check for debris-then flushed out same.Set up to handle 2 3/8"tb. M/U KOTs BHA#8(3 3/4"x 1 1/4"5-bladed junk mill,3 1/16"x 1"x-over sub, 3 1/8" NOV mud motor, 3 1/8"x 1"x-over sub,50 jts of 2 3/8" 5.95#PH6 tb,4 3/4"x 1 3/4"x-over sub,4 3/4"x 1 1/2" DP sub,2- 5"x 1 1/2" boot baskets,4 3/4"x 1 1/2" DB sub,5"x 1.047" MI circ sub,4 3/4"x 2 1/4" B&O jars,4-4 3/4"x 2 1/4" DCs,4 3/4"x 2 1/4"Acc jar,4 3/4"x 2 1/2"x-over sub= 1,754.02'). Flow tested mud motor at 3 BPM-stopped at 1,785'and function tested circ sub by dropping 1st ball to open 2nd ball to close,observing pressure changes and flow rates (recording same).Cont.TIH from 1,785't/4,732'. 05/25/2016-Wednesday Cont.TIH w/41/2 c/o assy,f/4,732't/12,325',filling every 20 stands, up wt 140k,do wt 75k. R/U halls head insert. P/u power swivel and M/U single#342. Installed rubber and screwed into string-landed rubber.Washed/milled down w/3 3/4" bladed mill &motor from 12,325'to 12,514'3 BPM 1000 PSI w/zero fluid losses. M/U single#348 on swivel and washed/milled down to 12,545'-fluid losses jumped to 70 BPH. Pumped 10 bbl size salt pill,fluid loss did not decrease. Pumped 2nd 20 bbl salt pill and losses decreased to 25 BPH. Continued pumping operations(sending 20 bbls hi-vis sweep around). Pumped 30 bbl sweep around to top of 7" liner @ 8,487'. Dropped open/close ball (1.750)and shifted circ sub opened. Brought pump rate up to 6 BPM 800 PSI.Circulated hole clean,adjusting pump rate to contain pill returns, bringing back sand. 05/26/2016-Thursday Finished circulating hole clean then dropped ball to close circ tool.Continued washing/reaming from 12,545'to 12,882' at 3 BPM 1000 PSI pumping sweeps as needed-fluid losses"'8 BPH. Made connection and washed down to 12,914'at same rate-fluid losses increased to 60 BPH-pumped 10 bbl size salt pill out thru motor.Continued making hole, pumping 5 bbl hi-vis sweeps every connection. Pumped 2nd salt pill at 13,007'. Fluid losses at 25 BPH at midnight(@ 13,069').Continued washing/reaming from 13,069'to 13,100'. Reduced pump rate at 1:30 hrs to 1.5 BPM to change screens on both shakers in order to handle pill returns-brought rate back to 3 BPM. P/U single#367 and washed down to 13,131'-pumped pill out EOT.Shutdown pump and M/U single#377.Could not establish circ. B/O L/D#377&tb was on a vacuum. M/U swivel and started pumping without returns.Worked pipe free. Pumped remainder of hi-visc pill away to make room to mix size salt pill (flushed mixing tank).Continued moving pipe while salt pill was being mixed. S • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily Operations: 05/27/2016-Friday Cont.working pipe&pumping 3 bpm wino returns while building size salt pill @ 13,131'. Pump 20 bbl salt pill, let seep to heal, pump 2 bpm establish circulation.Wash& ream f/13,131't/13,565' pump 3 bpm, 1120 psi-losses"'20 BPH. Continued washing/reaming down to 13,597'- lost returns momentarily-regained returns with fluid losses jumping to 80 BPH. Pumped sweep away to clear pill pit(15 bbls sweep)and mixed 30 bbl salt pill. Continued working pipe and circ'n while mixing pill. Pumped salt pill then chased with tb volume of FIW(92 bbls).Shutdown pump for 10 mins-took 10 mins to regain circ. M/U jt#382 and continued making hole from 13,597'to 13,720'3 BPM 1100 PSI-fluid losses holding at 60 BPH. Pumped 40 bbl hi-vis sweep.Continued working pipe until right angle drive broke on drawworks at 04:35 hr. Pusher called for repair parts-continued circ sweep around. 50 BBLS OF SALT PILL PUMPED&55 BBLS HI-VISC SWEEP PUMPED LAST 24 HRS. 05/28/2016-Saturday Cont.circulate hole clean. Mix&pump second high vis sweep. Remove rt. angle drive from rig. R/U circ lines,swap fluid system t/clean FIW,treating returns in rig tank w/bleach & pumping t/Trading Bay. Replacement right-angle drive arrived and rig crew mounted,tested and welded down same, put all guards back in place. Worked pipe to ensure it was still free. Laid down power swivel while pumping active tank away to TBPF. Dropped open/close ball and attempted to pump same on seat-failed to seat ball (working pipe&pump). Pulled 9 stands OOH (occasionally dragging)-pressured up and opened circ sub-EOTs at 13,162'/circ sub at 11,573' (368 stands+ BHA). Brought both pumps online LW at 6 BPM 1300 PSI-working pipe while pumping. 05/29/2016-Sunday Finished circ hole clean at 11,573'thru MI circ tool at 6 BPM 1300 PSI. POOH from 13,162'to KOTs BHA(3 3/4" mill & motor). B/D L/O out all 1,754.02' of KOTs BHA.Slipped and cut 130' of drill line. N/D 13 5/8"x 7 1/16"stripping head. Change pipe rams to 2 7/8"x 5"variables. Pulled wear bushing and M/U 3 1/2"test jt. Landed test plug and filled stack. Shell tested to 2500#s. Performed successful BOPE test to 250#s low 2500#s high as per Sundry in accordance to AOGCC and Hilcorp requirements using 3 1/2" &4 1/2"tb.Witness waived by Mr. Regg/AOGCC at 3:01 PM 27May16. Fluid level check shows 1,125'.Cleared floor and catwalk area in prep to run Halb TCP assy. Held PJSM with Halb, rig, crane crews and WSM. Began running pressure-fired 2 7/8"6 SPF 60* phasing VannGunn system w/HMX Millennium chrgs in hole- 400'of 1,155' of guns in hole at report time. 05/30/2016-Monday Cont. running pressure-fired 2 7/8" 6 SPF 60* phasing VannGunn system w/HMX Millennium chrgs in hole,w/running assy t/1,502'. P/u 2 stands 3 1/2" PH-6, install RA sub.Cont. RIH @ 60' min,filling pipe every 5 stands. 0200 hrs went thru 4 1/2" liner top @ 12,320'w/no problems.TIH to 13,715' (S/O 75k P/U 160k) P/U to 13,702'and M/U safety valve in string. R/U Pollard ELine w/full lubricator, rih make correlation pass w/GR, CCL tools. S • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Moncla 404 50-733-20157-02 201-046 5/4/16 6/3/16 Daily OperatiOrts: 05/31/2016-Tuesday Finish correlation log, POOH I/d e-line. Move string 18.63',up hole placing RA marker @ 12,047.82',top shot @ 12,520, BTM shot @ 13,675', up wt 168k,dn wt 73k. R/u circulating line w/safety valve&head pin. Close annular preventer. PJSM. Pressure up down tubing t/1298psi,guns fired, pressure dropped off,good indication at surface,monitored well tubing on vacuum then static. POOH t/12,266'standing back wk string, up wt 168k,dn wt 73k. Monitor well,static. POOH to Halb TCP assy. L/d 3 1/2" PH-6 wk string. B/D L/O Halliburton TCP assy(1,635.87')-all shots fired. RIH w/25 stands of 3 1/2" PH6 workstring-POOH laying tb down.Cleared and cleaned rig floor. P/U swivel and B/O subs. Packed up swivel. R/D Gills tongs. R/U McCoy tongs. 06/01/2016-Wednesday Continued prepping rig floor to begin running Summit ESP production assy. Finished working M/V Titon bringing on remainder of Summit equip&back loading work string, Halb TCP& Pollard equip. Fluid level shot by prod at 0630 hrs= 3,675'. P/U new Summit ESP assy.Serviced tandem 500hp mtr sections. M/u cap lines-found damage on motor lead ext, respliced same. M/U tandem seal sections and attempted to service. Decision was made to replace sections due to oiling issue. M/U remainder of assy adding clamps as needed. Fluid level shot by prod at 1400 hrs=3,490'.TIH w/Summit ESP assy picking 41/2" 12.75#L-80 Hydril Wedge 533 tb-strapping,drifting and torqueing to 4600 FPT-checking cable readings every 1000'. 122 jts+ESP assy in hole at report time=3,915'. Bottom 130 jts of 4 1/2" is new pipe. 06/02/2016-Thursday Continued RIH w/Summit ESP assy on 4 1/2" 12.75#L-80 Hydril 533 tb to 5,109'. Made reeder cable splice then continued in to 8,259' (PM). M/U hanger in string then built and installed thru-hanger cable penetrator. NOS rep terminated chemical lines thru hanger. Landed hanger w/EOT at 8,297.86'. Ran in pins, B/O landing jt and installed BPV. R/D Summit. Cleared rig floor, removed wind walls,hand rails,off-side steps,walkway to drill shack and floor supports then dismounted floor. N/D 13 5/8"spool. Prepped derrick to scope down. Lowered and moved driller's shack back. Began breaking bolts on stack.Scoped derrick down and laid in carrier. N/D BOPE at report time. 06/03/2016-Friday Finished N/D BOPE. N/U tree and test void to 500#s&5000#s.Completed production hookups. Pulled BPV and installed 2-way check.Shell tested to 5000#s.Turned well over to production. A SOF Tye THE STATE Alaska Oil and Gas • ��.�s of TTAsKA. Conservation Commission } == 333 West Seventh Avenue 1/4GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 \trm Main: 907.279.1433 oFALAS11J' Fax: 907.276.7542 www.aogcc.alaska.gov Stan Golis y '; Operations Manager Hilcorp Alaska, LLC 30 - 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-13RD2 Permit to Drill Number: 201-046 Sundry Number: 316-036 Dear Mr. Golis: 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 Foerster Chair �S� DATED this 2i day of January, 2016. RBDMS L I- JAN 2 5 2016 • • RECEIVED STATE OF ALASKA JAN 19 202 ALASKA OIL AND GAS CONSERVATION COMMISSION p7.5 (/Z/ l/ APPLICATION FOR SUNDRY APPROVALS AOGC �!! 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate LI - Other Stimulate ❑ Pull Tubing Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Replace ESP CI• 2.Operator Name: 4.Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development El 201-046 ' 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20157-02 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 228A Will planned perforations require a spacing exception? Yes ❑ No ❑ - Trading Bay Unit K-13RD2 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018772 McArthur River Field/Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 15,485 - 9,737 - 15,485 9,737 0 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 5,011' 13-3/8" 5,011' 1,482' 3,090 psi 1540 psi Production 8,707' 9-5/8" 8,707' 7,163' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,657' 8,160 psi 7,030 psi Liner 1,459' 4-1/2" 13,779' 9,770' 5350 psi 4,960 psi Liner 1,606' 4-1/2"(slotted) 15,385' 9,741' slotted slotted Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 12,580-12,600/13,779-15,348 9,726-9,733/9,772-9,743 4-1/2" 13.6#/L-80 8,266 (slotted) (slotted) Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker 7"Model F Perm Pkr,ZXP Prk&EXP Pkr 12,200'(MD)9,534'(TVD), 12,320'(MD)9,599'(TVD), 13,696'(MD)9,774'(TVD) 12.Attachments: Proposal Summary Il Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch E Exploratory ❑ Stratigraphic ❑ Development DI Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 2/2/2016 Commencing Operations: OIL LI - WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Dan Marlowe(907)283-1329 Email dmarlowe( hilcoro.co Printed Name Stan W.Golis Title Operations Manager Signature .,-4,.. tttre.;. Phone (907)777-8356 Date { ] LF> C I to COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3\4 - 03(-e Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: ar SOi oG�1 "7;5. �' l /V C /'" c cc.. r' Ir'• 1I ! -7 ,..4.4:,,-.--,x r -"‘ Ce-s;"7 . --A i Scr'ps Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: /L}— V D 9� ,,,,,y,...„,___ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: /-2/-/•`Z15 OfOeclitNsAito: Submit Form and Form 10- 1/2015 12 months from tbe date of approval. RBDMS Attachments in Duplicate JAN 2 5 2016 = i) -z.,-' fe. • Well Prognosis • Well: K-13rd2 Ililco=u Alaska,LL Date:01/11/2016 Well Name: K-13rd2 API Number: 50-733-20157-02 Current Status: Oil producer(ESP) Leg: Leg#2 (SE) Estimated Start Date: 2/2/16 Rig: Moncla 404 Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett 777-8332 Permit to Drill Number: 201-046 First Call Engineer: Dan Marlowe (907) 283-1329 (0) (907) 398-9904 (M) Second Call Engineer: Trudi Hallett (907) 777-8323 (0) (907) 301-6657 (M) Current Bottom Hole Pressure: 4,079 psi @ 9,786'TVD 0.417 lbs/ft(8.02 ppg)based on SBHP 08/11/2009 Maximum Expected BHP: 4,079 psi @ 9,786'TVD 0.417 lbs/ft(8.02 ppg)based on SBHP 08/11/2009 Maximum Potential Surface Pressure: 0 psi-No-Flow Well(05/12/2006)Will not flow based on an expected oil and water gradient of 0.437 psi/ft Brief Well Summary The K-13rd2 well is currently completed with an ESP which failed 11/08/15.This work over will replace the pump, cleanout the well, and add perforations. -r -(z_,-f �.5. Brief Procedure: 1. MIRU Moncla Rig#404. 2. Kill well and circulate Hydrocarbon off of well through ESP.Work over fluid to be FIW. 3. Notify AOGCC 48 hours before pending BOPE test. Set BPV, ND tree, NU BOPE.Test_all BOP equipment per AOGCC guidelines to 250psi low and 2,500psi high. 4. Monitor well to ensure it is static. 5. Unseat hanger and POOH with completion. 6. Cleanout to top of old production packer at 12,200' circulate well clean with FIW. POOH. 7. RIH, mill over and recover production packer. r- 12,2t)e) p4 "F 8. Cleanout 4-1/2" liner until refusal. Circulate clean. POOH. 9. PU retrievable test packer and RIH to +/-12,200'. Set packer, test casing to —1,500 psi and chart for -til 30 minutes. POOH. 10. PU TCP guns and RIH and perforate Hemlock zones per the Perf Recommendation. 11. After detonation, circulate perf gas, confirm well is static, POOH. 12. Run ESP completion. 13. Set BPV. NU tree,test same. 14. Turn well over to production. 15. Conduct SVS and No-Flow tests per AOGCC regulations. Attachments: 1. Well Schematic Current 2. Well Schematic Proposed 3. Wellhead Schematic Current/ Proposed (Same) 4. BOP Drawing 5. Fluid Flow Diagrams 6. RWO Sundry Revision Change Form II • • Trading Bay Unit SCHEMATIC King Salmon Platform Hikora Alaska,LLC Well: K-13rd2 PTD 201-117 50-733-20157-02 RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 1 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' Illin 13-3/8" 68 J-55 BTC 12.415" 2,509' 5,011' MOE 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 2 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2"Slotted Lnr I 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' NON TUBING DETAIL Z • , 4-1/2" 12.6 L-80 HYD 563/503 3.958" Surf 8,266' 3 XN 4 5 JEWELRY DETAIL 6 No Depth Depth OD ID Item (MD) (TVD) 7 1 33.77' FMC Tubing Hanger(4-1/2"HYD 503) 2,550' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 8 >< 4,429' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 5,720' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) /VZ 2, 6,451' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 7,079' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 wl RK Latch(Dummy) 9-5/8"Window 7,659' 7.063" 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) @ 8707' MD, 3 8,169' 5.000" 3.813" XD SSD Sliding Sleeve 300 Hole Angle 4 8,215' 5.000" 3.725" XN Profile Nipple(NO-Go:3.725") 5 8,266' 5.500" N/A Pressure Discharge Head 6 8,268' 6.750" N/A Pump J1200N 7 8,322' 7.380" N/A REDA 738 Dominator Motor 800HP 8 8,357' 4.500" N/A Tri-Plate Anode(bottom) -->-‹ 9 9 12,200' 5.875" 4.000" Baker 7"Model"F"perm.packer 10 10 12,249' 3.875" 2.813" "X"Nipple 11 12,283' 3.812" 3.062" Re-entry guide 11 12 12,320' 4-1/2"Liner top(ZXP Packer) ,2 �® 7 „I\ 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole 1.\ 12580'MD-12600'MD Slotted Liner at Near-Horizontal in HB-2 - ROTATING TIME HB-1 Sands 4-1/2"J-55, 11.6#Tubing zo" - 119 hrs 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"- 229 hrs 13,779 MD-15,348 MD 9-5/8"-259.5 hrs 7"- 99.5 hrs Lost 1 roller 2.6"dia.X.25"thick off Schlumberger roller stem-5-6-06 ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000'MD W/blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD=15485'MD/9736'ND Revised By:TDF 11/27/2012 Trading Bay Unit II 0 • King Salmon Platform Well: K-13RD2 PROPOSED PTD: 201-117 50-733-20157-02 Hilcorp Alaska,LLC Completed: Future RKB to TBG Hanger=33.77' CASING DETAIL r Size WT Grade Conn ID Top Btm 13-3/8" 61 J-55 BTC 12.415" Surf 2,509' 13-3/8" 68 J-55 BTC 12.415" 2,509' 5,011' 9-5/8" 47 N-80 BTC 8.681" Surf 4,749' 9-5/8" 47 S-95 BTC 8.681" 4,749' 8,707' 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2"Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' , TUBING DETAIL G 4-1/2" 12.6 L-80 Supermax 3.958" Surf ±8,265' JEWELRY DETAIL U. No Depth Depth OD ID Item (MD) (TVD) 1 33.77' Hanger 1 ±8,350' ±6,864' Bottom of ESP >C >< 2 12,320' 4-1/2"Liner top(ZXP Packer) /L 9-5/8" Window @ 8707' MD, 30°Hole Angle Perforation Detail Top Zone (MD) Btm(MD) Top(TVD) Btm(TVD) Date Comments HK-1 12,580' 12,600' 9,726' 9,733' 5/9/2006 Open _12,512' ±13,778' ±9,698' Future Proposed , jx1 R 2 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole \ Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME 4-1/2"J 55, 11.6#Tubing 20" - 119 hrs N, 2-1/2"x 1/8"slots, 16 slots/ft 13-3/8"— 229 hrs 13,779 MD—15,348' MD 9-5/8"—259.5 hrs 7"— 99.5 hrs _,_._._._._,_._._._._._._._._._._. ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000'MD W/blank 4-1/2" above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD= 15485'MD/9736'ND Revised By:JLL 01/18/16 . • King Salmon Platform 11 K-13 Current 01/18/2016 If Alaska,I.1.G King Salmon Tbg hanger,OCT-UH-TC-1A- K-13 ESP,13 X 4/:BTC lift and 24 X133/8 X95/8 X4susp,w/4"Type H BPV profile,3/8 cont control line port BHTA,B-11-A0,4 1/16 5M FE l 1 uu I.IE� Valve,Swab,WKM-M,4 1/16 5M �� �, 5• FE,N� FE,HWO,EE trim ,A c OUZO,e,. tttr\m 4: . valve \r�'o0 PM op CMS E rrn Pxels Valve,Wing,Vetco,2 1/16 5M FE, / ,� HWO,AA trim ��,%_ , ! �_—, mai xi 0 ,,*(41.7:;.f-.:# - , .,� Valve,Master,OCT 75,41/16 5M `�� r�# �` v ,moi m. FE,HWO,EE trim ;08. ��1 } ��� Bad Ring Groove Petromec Ring Gasket Only Valve,Wing,OCT-20,4 1/16 5M FE, ' HWO,EE trim — ..„ kiAdapter,OCT-AS-ESP,13 5/8 SM API hub -� X 4 1/16 5M stdd top,w/2-Y::control 14 it___--- MI DEE line exits,prepped w/OCT 400-4 pocket El S`., ilir,..1 ag IR " i 1 ii All unihead annular valves,2 Unihead,OCT type 3,13 5/8 5M API ,� 1J• :° ! (' 1/16 5M FE OCT-20,HWO hub top X 13 3/8 BTC casing bottom, j� Ff>`7.1� : "t''' w/1-2 1/16 5M SSO on lower [ � section,1-2 1/16 5M SSO on middle AM: -- ^\ section,3-2 1/16 5M SSO on upper - , section,IP internal lockpin assy ' ;jam j a Mihir qu a I� I Valve,OCT 20,3 1/8 2M FE, Starting head,OCT,21 Y.2M FE X 1 �, ri �, HWO 24"SOW,w/1-3 1/8 2M EFO,full � IJ 1 set of lockpins 111 24" 13 3/8" I_ L 9 5/8., 4%:" • 0 King Salmon Platform BOP Stack(Moncla) Hilrnrp %beaus,1.I.t. 111111` 111r111 Ill•111 fil Iii 3.74' Shaffer 135/8 SM 1 i I di iii lit iii kL. ill if i in I i n _�L aw-� . 2A-....ii "4. ._ Variable 27/8-5 _. e_ir_r _ - 4.6T _—C— �. 13 5/8-5000 I �=Blind Rams IiI.IIIiiiiiilail Choke and Kill Valves -- 2 1/16 5M w/Unibolt connections for hoses 1 � i 1•111'111•111'121,. 1 p, 1 2.00' i! - . 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O � ZZ no.- ■I If7 Q o.J Q Uj Ill Y a0 N) . d- zO COU U I s— (T)> CC j O CC JO a0 `/ LL aw CT ■ 1U M 1111M..... trie E X • Nil T- ac OQ mH to W a ET. - ...\S—___...0 z0 Q A CO Q J p Z O Z w Z Oz Q p a a CO J z r-11 3 -1 [H u) Q o O O U 4t Q Q j � 0wzC� Q O aO O J J J O ° Z = rce J O O N) LI3 tn Lu a N LLZo 4 Om z Q U' ~ Z 0 J Q 1 4 J D 0 CC 0 • • Moncla Rig 404 BOP Test Procedure Hilcorp Alaska,LLC Attachment#1 Attachment #1 Hilcorp Alaska, LLC - BOP Test Procedure: Moncla Rig 404, 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 the tubing hanger won't pressure test due to either a penetrator leak or the 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. 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) For ESP wells- Ensure that cap is on cable penetrator e) NU BOP. Test BOPE per standard procedure. 3) If both set of threads appear to be bad and unable to hold a pressure test and/or a penetrator leaks, notify Operations Engineer(Hilcorp), Mr. Guy Schwartz (AOGCC) and Mr.Jim Regg (AOGCC)via email explaining the wellhead situation prior to performing the rolling test. AOGCC may elect to send an inspector to witness. 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 • • Moncla Rig 404 BOP Test Procedure Hilcorp Ala.ska, Attachment#1 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.) 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 / penetrator 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 joint 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- RIH with test plug on joint of tubing. Install a pump-in sub w/ test line plus an open TIW or lower Kelly valve in top of test joint w/open IBOP. 3) Test BOPE per standard procedure. STANDARD BOPE TEST PROCEDURE(after 2-way check or test plug is set) 1) Fill stack and all lines with rig pump- install chart recorder on test line connected to pump-in sub below safety valve and IBOP in test joint assembly. 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(test pressures will be indicated in Sundry). 3) Referencing the attached schematics test rams and valves as follows. a) Close 15t valve on standpipe manifold, close valves 1, 2, 10 on choke manifold and close the annular preventer, open safety valve on top of test jt and close IBOP. Pressure test to 250 psi for 5 minutes and 2,500 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank and open annular. b) Close pipe rams and open annular preventer, close safety valve and open IBOP on test joint,close outside valve on kill side of mud cross, open 1st valve of standpipe,close valves 3,4& 9 on choke manifold, open valves 1 &2 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi high for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. 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 • Moncla Rig 404 BOP Test Procedure Hacorp ni�.k�,LI t, Attachment#1 them properly in the dual rams. Close rams. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. d) Close inside valve/open outside valve on kill side of mud cross, close valves 5 &6/open valves 3 &4 on choke manifold. Test to 250 psi for 5 minutes and 3,000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. e) Close manual and super choke/open valves 5 &6 on choke manifold. Pressure up to^ 1200 psi and bleed off 200—300#s recording change and stabilization. If passes after 5 minutes, bleed of pressure back to tank. f) Close HCR (outside valve on choke side of mud cross), open manual&super choke. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. g) Close inside valve/open outside valve (HCR)on choke side of mud cross. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. h) Ensure all pressure is bled off-open pipe rams and pull test joint leaving test plug/2-way check in place. Close blind rams and attach test line to valve 10 on choke manifold, close valve 7&8/ open valve 10 on choke manifold. Test to 250 psi for 5 minutes and 3000 psi for 5 minutes. If passes after 5 minutes on each, bleed off pressure back to tank. i) Test additional floor valves(TIW or Lower Kelly Valve)and IBOPs as necessary. 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 • • Moncla Rig 404 BOP Test Procedure Hilcoep Alaska,LLCAttachment#1 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. Document both the rolling test and the follow up tests. . • • � � 0 / > � 7 o & 0 Ts _ 2E moo ° / / 2 a § f « E Ec 73 S ? � E § x 0. E a a ±.- 7 § ) U) m % X � / 73 I L. - 05 a cr _ § 92 / n -0 ■ a) 2 \ � � � k k 2 %cp>- F/2 J qac x Q • -6 q o 13 X () a) a 2 m O k ( \k X �� X » C a) % / & 7? § co o J c < _ � a / a) c 2 -o 2 L - / 2 0) \ / g a) »> § c SP § / / 2 . Cl) Qp 2 in ■ _ $ g ■ k § % § Q 0 a. k � 0co « ( 0> 0 C 2 xco 6 § 2 - Q ■ x 2 a e c0 o x m : m ® Q Q .< § 0 / a) a $ 2 U 3 x \ k < � El a) 0 -. © % . k & $ -a E 0 a) > cu E a >0 Co t3Z () = = CO U) STATE OF ALASKA • ALIKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Plug Perforations❑ Fracture Stimulate El Pull Tubin0 Operations shutdown ❑ Performed: Suspend ❑ Perforate ❑ Other Stimulate 0 (ACid) asin1 Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp We❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory❑ 201-046 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-733-20157-02 • 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0018772 4 Trading Bay Unit/K-13RD2 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A McArthur River Field/Hemlock Oil Pool 11.Present Well Condition Summary: Total Depth measured 15,485 ° feet Plugs measured N/A feet NO r� true vertical 9,737 • feet Junk measured N/A feet N O V 1 1 2015 Effective Depth measured 15,485 feet Packer measured 12,200,12,320,13,69E feet A{OGCC true vertical 9,737 feet true vertical 9,534,9,599,9,774 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 5,011' 13-3/8" 5,011' 4,182' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,163' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,657' 8,160 psi 7,030 psi Liner 1,459' 4-1/2" 13,779' 9,770' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"slotted 15,385' 9,741' slotted slotted Perforation depth Measured depth 12,550-12,590/ feet 13,377-13,644 (slotted)/13,760- 15't4R/clnttpril FEB 0 9 2016 True Vertical depth 9,715-9,729/9,792- feet 9,777(slotted)/9,772- 9 743(slotted) Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.6#/L-80 8,266'(MD) 6,795'(TVD) Baker 7"Model F Pkr 12,200'(MD)9,534'(TVD) Packers and SSSV(type,measured and true vertical depth) ZXP Pkr 12,320'(MD)9,599'(TVD) ECP Pkr 13,696'(MD)9,774'(TVD) SSSV:N/A 12.Stimulation or cement squeeze summary: Intervals treated(measured): 13,779-15,385 Treatment descriptions including volumes used and final pressure: Fill well with 135 bbls FIW.Pump preflush consisting of 330 gallons WAW-5206 blended with 990 gallons Xylene.Pump 107 bbls 15%HCL Acid.Pump 225 bbls FIW displacement.Final pressure 1800 psi. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 244 133 8293 79 78 Subsequent to operation: 0 0 0 93 82 14.Attachments(required per 20 AAC 25.070.25.071,&25.263) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory Development 4 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ❑ • SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-665 ` Contact Stan W.Golis Email sgolis(a�hilcorp.com Printed Name Stan W.Golis Title Operations Manager Signature /Li ) V 1 Phone (907)777-8356 Date 11/16/2015 Form 1U-404 Kevisea b/L015 ,47!c' RBDMS (,NOV 1 8 1015 Sunmlc Ongmal unry /Z•fC•Is' • • II Trading Bay Unit SCHEMATIC King Salmon Platform Hilcorp Alaska,LLC Well: K-13RD RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 1 13-3/8" 61.0&68.0 1-55 BTC 12.415" Surf 5,011' 1.11.1 9-5/8" 47 N-80,S-95 BTC 8.681" Surf 8,707' III IN! =IMED Window 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2"Lnr 12.6 J 55 Hydril 511 3.875" 12,320' 13,779'1 2 44/2"Slotted Lnr 11.6 1-55 Hydril 511 3.875" 13,779' 15,385' TUBING DETAIL 11111 �' 4-1/2" 12.6 L-80 HYD 563/503 3.958" Surf 8,266' L JEWELRY DETAIL Ii 3 No Depth ID Item 1 33.77' FMC Tubing Hanger(4-1/2"HYD 503) ® 4 rol '®�'" _ 5 2,550' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 6 4,429' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 7 5,720' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 2 6,451' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 8 7,079' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) L 7,659' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 3 8,169' 3.813" XD SSD Sliding Sleeve 9-5/8"Window 4 8,215' 3.725" XN Profile Nipple(NO-Go:3.725") @8707' MD, 5 8,266' N/A Top of ESP Assy 300Hole Angle 6 8,268' N/A Pump J1200N 7 8,322' N/A REDA 738 Dominator Motor 800HP 8 8,357' N/A Tri-Plate Anade(bottom) J 9 9 12,200' 4.000" Baker 7"Model"F"perm.packer 10 10 12,249' 2.813" "X"Nipple nn ® 11 12 11 12,283' 3.062" Re-entry guide 12 12,320' 4-1/2"Liner top(ZXP Packer) Li t...., 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole 12550'MD-12590'MD Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME HB-1 Sands 4-1/2"J-55, 11.6#Tubing 2-1/2"x 1/8"slots, 16 slots/ft 20" - 119 hrs 13-3/8"- 229 hrs 13,377' MD-15,348' MD 9-5/8"-259.5 hrs s, 7"- 99.5 hrs cA Lost l roller 2.6"dia.X.25"thick off - Schlumberger roller stem-5-6-06 ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000'MD W/blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.75°@ 13413'TD=15485'MD/9736'TVD Revised By:TDF 11/27/2012 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date K-13RD2 Pumping 50-733-20157-02 201-046 11/6/15 11/8/15 Daily Operations: 11/06/2015- Friday Fly to platform. Fill out permits and review procedure. Rig up equipment. Shut-in well at 11:00. Pressure test treating lines to 500 low/2000 high. Fill well with 135 bbls FIW. Pump preflush consisting of 330 gallons WAW-5206 blended with 990 gallons Xylene down tubing taking returns to test header from annulus. Pump 80 bbls 15% HCL Acid down tubing taking returns to test header from annulus. Close annulus and finish bullheading remaining 27 bbls 15% HCL Acid down tubing. Alternate between pumping once per hour and letting well bleed down. Pressures up to 1800 psi with 8 bbls pumped each batch. Flush surface lines with FIW to production header. Displace with FIW. Alternate between pumping once per hour and letting well bleed down. Pressuring up to 1800 psi every 7-10 bbls. 70 bbls pumped at report time. 11/07/2015-Saturday Continue pushing acid away with FIW. Alternate between pumping once per hour and letting well bleed down. Pressuring up to 1800 psi every 6-10 bbls.Total of 128 bbls FIW pumped. Acid clear of production tubing. Continue pushing acid away with FIW. Alternate between pumping once per hour and letting well bleed down. Pressuring up to 1800 psi every 4-8 bbls. 206 bbls pumped at report time. 11/08/2015-Sunday Continue pushing acid away with FIW. Alternate between pumping once per hour and letting well bleed down. Pressuring up to 1800 psi every 4-8 bbls. 225 bbls total pumped. Final pressure 1800 psi. Rig down pumping equipment and turn over to production. • OF Tyi� • • &..0"S'\�\I%%i ,s THE STATE Alaska Oil and Gas ' LASKA �� Of �,— ��, o Conservation Commission 333 West Seventh Avenue MAV GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 1+ Main: 907.279.1433 ®FMill.-� .Mill.-ALAS Fax: 907.276.7542 C www.aogcc.alaska.gov Ted Kramer Sr. Operations Engineer o �� Hilcorp Alaska, LLC 1 o' 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: McArthur River Field, Hemlock Oil Pool, TBU K-13RD2 Sundry Number: 315-665 Dear Mr. Kramer: 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, ‘S Cathy . Foerster ., _ Chair DATED this GAJ day of October, 2015 Encl. RBDMS'1 ,fl 2 9 285 STATE OF ALASKA 0 / ' i ALASKA OIL AND GAS CONSERVATION COMMISSION r315 1 I"4(k. APPLICATION FOR SUNDRY APPROVALS \, " CI w 20 MC 25280 1.Type of Request: Abandon❑ Plug Perforations❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown 0 Suspend❑ Perforate ❑ Other Stimulate 0 (Acid) Alter Casing ❑ Change Approved Program 0 Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC . Exploratory ❑ Development 0 - 201-046 • 3.Address: 3800 Centerpoint Drive,Suite 1400Stratigraphic CI Service ❑ 6.API Number. Anchorage,AK 99503 50-733-20157-02 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? WA Will planned perforations require a spacing exception? Yes ❑ No 0 Trading Bay Unit K-13RD2 ' 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0018772 - McArthur River Field/Hemlock Oil Pool . 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 15,485 • 9,737 • 15,485 • 9,737 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 5,011' 13-3/8" 5,011' 4,182' 3,090 psi 1,540 psi Production 8,707' 9-5/8" 8,707' 7,163' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,657' 8,160 psi 7,030 psi Liner 1,459' 4-1/2" 13,779' 9,770' 5,350 psi 4,960 psi Liner 1,606' 4-1/2"(slotted) 15,385' 9,741' slotted slotted Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 12,550-12,590/13,377-13,644 ' 9,715-9,729/9,792-9,777(slotted)/ 4-1/2" 12.6#/L-80 8,266 (slotted)/13,760-15,348(slotted) 9,772-9743(slotted) Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker 7"Model F Perm Pkr,ZXP Pkr&ECP Pkr • 12,200'(MD)9,534'(TVD),12,320'(MD)9,599'(TVD),13,696'(MD)9,774'(TVD) 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 0 - Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 11/6/2015 OIL 0 • WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned 0 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ted Kramer Email tkramertu'�.hilcorp.com Printed Name Ted Kramer Title Sr.Operations Engineer Signature „4,-/ ....- Phone (907)777-8420 Date 10/22/2015 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 5/ce f lU^5. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test CILocation Clearance CI Other: RBDMSJCT 2 9 2015 Spacing Exception Required? Yes ❑ No LI Subsequent Form Required: i0 go I n APPROVED BY G1 Approved by: J'. L�' � COMMISSIONER THE COMMISSION Date:/cL2& / ���y e ( 1 A Submit Form and Form 10-403 Revised 5/2015 Approved appll anon is1/43A . 2 n h r7i_,ii� date of approval. Attachments in Duplicate • Well Work Plan Well: K-13RD2 flacon).aiaa a.LL Date: 10/22/2015 Well Name: K-13RD2 API Number: 50-733-20157-02 Current Status: ESP Lifted Producer Leg: Leg#2 SE Corner Estimated Start Date: November 6, 2015 Rig: N/A Reg. Approval Req'd? Date Reg.Approval Rec'vd: Regulatory Contact: Juanita Lovett Permit to Drill Number: 201-046 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) Current Bottom Hole Pressure: 758 psi @ 6,870' TVD ESP Intake Gauge Maximum Expected BHP: 4,250 psi @ 6,870' TVD (ESP intake Gauge). Well SIBP of 2,250 psi plus 2000 psi pump pressure. Max. Anticipated Surface Pressure: 1800-2,000 psi treatment pump pressure limit Well Summary The K-13 is an oil well producer which is currently on ESP artificial lift. Total fluid production from this well decreased suddenly after an unplanned generator shutdown of the ESP. Diagnostics of the well indicate that there is a restriction in the wellbore which is choking back inflow. This decrease is believed to have been caused by scale formation in the well bore at the X nipple located at 12,249' or at the slotted liner. Well Objective Hilcorp plans to pump an acid soak down the production tubing, out the ESP intake, and down across the X-nipple at 12,249', to clean up any scale deposition. The acid will then be pumped into the slotted liner. Procedure: 1. MIRU pumping equipment. 2. Shut down ESP. 3. Pressure test surface lines to 1800-2,000 psi (treatment pump relief valve limit). 4. Mix chemicals and pump in the following sequence: a. Open back side, pump FIW down tubing taking returns up the annulus. b. Pump 1320 gallons of pre-flush (330 gallons WAW-5206 mutual solvent blended with 990 gallons of Xylene. c. Pump ±4,500 gallons of±15% HCL d. Close the 9-5/8" casing return line and bullhead the chemical pills out the ESP intake and down across the X-nipple at 12,249' by following the acid with 9,437 gals of FIW. 5. Shut down pump and let acid soak for >_ 4 hours. • 6. Continue pumping an additional >_ 4,251 gals. of FIW to displace the acid to the bottom of the slotted liner. • • Well Work Plan Well: K-13RD2 Hilcorp Alaska,LL Date: 10/22/2015 7. RD Pumping equipment. 8. Return well to production. 9. Schedule a No-Flow test within 14 days of stable production. Attachments: 1. As-built Schematic • i rII Trading Bay Unit SCHEMATIC King Salmon Platform Ililcorp Alaska,LLC Well: K-13RD RKB to TBG Hanger=33.77' CASING DETAIL Size WT Grade Conn ID Top Btm 1 13-3/8" 61.0&68.0 1-55 BTC 12.415" Surf 5,011' N1 9-5/8" 47 N-80,S-95 BTC 8.681" Surf 8,707' P-SI Window I 7"Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' I NI 4-1/2"Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 1.11 2 4-1/2"Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' TUBING DETAIL L I N. 4-1/2" 12.6 L-80 HYD 563/503 3.958" Surf 8,266' NI JEWELRY DETAIL SSD 3 No Depth ID Item XN 1 33.77' FMC Tubing Hanger(4-1/2"HYD 503) � o XN a 4 5 2,550' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) a 6 r 4,429' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) B. t• , Y 1 7 4 2 5,720' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 6,451' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 8 >< 7,079' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) L 7,659' 3.833" 4-1/2"SFO-2 GLM R2 w/RK Latch(Dummy) 3 8,169' 3.813" XD SSD Sliding Sleeve 9-5/8" Window 4 8,215' 3.725" XN Profile Nipple(NO-Go:3.725") @ 8707' MD, 5 8,266' N/A Top of ESP Assy 30 Hole Angle 6 8,268' N/A PumpJ1200N 7 8,322' N/A REDA 738 Dominator Motor 800HP 8 8,357' N/A Tri-Plate Anade(bottom) > < 9 9 12,200' 4.000" Baker 7"Model"F" perm.packer .10 10 12,249' 2.813" "X"Nipple Emu 11 11 12,283' 3.062" Re-entry guide �® Q 12 /\ 12 12,320' 4-1/2"Liner top(ZXP Packer) 7" liner cemented at 12,430' MD/9660'TVD,+/-57 deg hole 11..........\,„ 12550'MD-12590'MD Slotted Liner at Near-Horizontal in HB-2 ROTATING TIME HB-1 Sands 4-1/2"J-55, 11.6#Tubing 2-1/2"x 1/8"slots, 16 slots/ft 20" - 119 hrs 13-3/8"— 229 hrs 13,377' MD—15,348' MD 9-5/8"—259.5 hr' vt 7"— 99.5 hrs Q'' Lost 1 roller 2.6"dia.X.25"thick c, Schlumberger roller stem—5-6-06 ECP(inflated with mud)at 13696' MD(9774'TVD) 90 Deg Section at 13,000'MD W/blank 4-1/2"above and two blank joints below MAX HOLE ANGLE=94.750 @ 13413'TD= 15485' MD/9736'TVD Revised By:TDF 11/27/2012 • a � 0 A UI r§1n� 51- 48 a zAg e- o f}s • i n D � Agat,o �u • ram Mg QE 6 pi C my D vmv� p m y r a z FFLf of -00 -00 -a o acs p 0 Imag~- 'roject Well History' File Cover ![i .:le XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. RESCAN DI~AL DATA [] Color items: ~ Diskettes, No. I [] Grayscale items: [] Other, No/Type [] Poor Quality Originals: [] Other: NOTES: BY: BEVERLY ROBIN VINCENT SHERYL~)WlNDY OVERSIZED (Scannable) [] Maps: [] Other items scannable by large scanner OVERSIZED (Non-Scannable) ~ Logs of various kinds [] Other Project Proofing BY: BEVERLY ROBIN VINCENT SHERYL~WINDY BY: BEVERLY ROBIN VINCENT SHERYL(~~INDY TOTAL PAGES Production Scanning Stage I PAGE COUNT FROM SCANNED FILE: //~. - ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: _.~ YES NO BEVERLY .,VINCENT SHERYL MARIA WINDY DATE:'"~'~'~"~,.~/S/ IF NO IN STAGE '1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO BY: Stage 2 BY~ (SCANNING IS coMPLETE AT THiS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) RESCANNEDB~': BEVERLY ROBIN VINCENT SHERYL MARIA WINDY General Notes or Comments about this file: DATE: /SI Quality Checked 12/10/02Rev3NOTScanned.wpd UNSCANNED, OVERSIZED MATERIALS AVAILABLE: cX~ I orf.tp FILE # e9-~ot:ý- / -/t(./) / -Tvt> / To request any/all of the above information, please contact: Alaska Oil & Gas Conservation Commission \333 W. 7th Ave., Ste. 100 ~ Anchorage, Alaska 99501 Voice (907) 279-1433 ¡Fax (907) 276-7542 STATE OF ALASKA RE'CE.IN/ED * ALAS AND GAS CONSERVATION COMMISS• 140 - REPORT OF SUNDRY WELL OPERATIONS JUL / 1 °710G/zors 1. Operations Abandon U Repair Well U Plug Perforations U Stimulate U Iklois64 G'r'f?'SP giBit"er Performed: Alter Casing ❑ Pull Tubing 1111 Perforate New Pool ❑ Waiver ❑ Time Extension ❑ t " • ' Change Approved Program El Operat. Shutdown ❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development rj Exploratory ❑ 201 -046 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic Service ❑ 6. API Number: 50 -733- 20157 -02 -00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL0018772 (King Salmon Platform) Trading Bay Unit K -13RD2 9. Field /Pool(s): McArthur River Field/ Hemlock Oil Pool 10. Present Well Condition Summary: Total Depth measured 15,485 feet Plugs measured N/A feet true vertical 9,736 feet Junk measured N/A feet Effective Depth measured 15,485 feet Packer measured 12,200/ 12,320/ 13,696 feet true vertical 9,736 feet true vertical 9,534/ 9,599/ 9,774 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 5,011" 13 -3/8" 5,011' 4,182' 3,090psi 1,540psi Production 8,707" 9 -5/8" 8,707' 7,163' 6,870psi 4,750psi Production 3,943' 7" 12,430' 9,657' 8,160psi 7,030psi Liner 1,459" 4 -1/2" 13,779' 9,770' 5,350psi 4,960psi Liner 1,606' 4 -1/2" (slotted) 15,385' 9,741' slotted slotted Perforation depth Measured depth 12,550'; - 12,590'/ 13,377'- 13,644'(slotted)/ 13,760'- 15,348'(slotted) True Vertical depth 9,714'- 9,7147 9,791- 9,776'(slotted liner)/ 9'775'- 9,742'(slotted liner) Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6#/ L -80 15,385' MD 9,741' TVD Baker 7" Model "F" Perm. 12,200'MD/9,534'TVD ZXP 12,320'MD/9,599'TVD Packers and SSSV (type, measured and true vertical depth) ECP 13,696'MD/9,774'TVD N/A N/A 11. Stimulation or cement squeeze summary: Intervals treated (measured): N/A SkANNED JUL 0 6 2011 Treatment descriptions including volumes used and final pressure: N/A 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 428 193 7,609 45 80 Subsequent to operation: 618 224 10,226 95 95 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development 1111 - Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 15. Well Status after work: Oil •- I ✓ f Gas L] WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 16. 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: 5,47) zThtie J 711 Contact Jack Newell Phone 263 -7832 Printed Name Timothy C. Brandenburg _ Title Drilling Manager ' Signature Phone 276-7600 Date 6/30/2011 `___.._ Air JUL 0 5 '2011 ,, '` ' ' Form 10 -404 Revised 10/2010 Submit Original Only Chevron Trading Bay K -13RD2 King Salmon Platform 1%110 11. Well # K -13RD2 Actual Wellbore Schematic Actual Completion Landed 06/27/11 RKB to TBG Hanger = 33.77' CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 13 -3/8" 61.0, 68.0 J -55 BTC 12.415" 35' 5,011' 9 -5/8" 47 N -80, S -95 BTC 8.681" 35' 8,707' Window 7 "Lnr 29 L -80 KC BTC 6.184" 8,487' 12,430' 4 -1/2" 12.6 J -55 Hydril 3.875" 12,320' 13,779' Blank Lnr 511 4 -1/2" 11.6 J -55 Hydril 3.875" 13,779' 15,385' Slotted Lnr 511 L , Tubing: 4 -1/2" 12.6 L -80 HYD 3.958" 34' 3375'/ 563/503 8,286' A 2 JEWELRY DETAIL r NO. Depth ID Item 3 33.5' FMC Tubing Hanger (4 -1/2" HYD 503) GLM #1. 2558' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) GLM #2. 4438' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) 4 GLM #3. 5729' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) >< >` GLM #4. 6460' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) L , GLM #5. 7088' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) R GLM #6 7668' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) \ A. 8,200' 3.813" 4 -1/2" SSD,3.813,4 1/2 4 1/2 IBT ,B -P 9 -5/8" Window 2. 8,243' 3.725" XN Profile Nipple (NO - Go: 3.725 ") @ 8707' MD, 3. 8,268' ND Reda ESP Assy 30 Hole Angle 90.28' 8304' ND Pump Intake 8355' ND Phoenix XT1 4. 8,356' ND Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer —.,,� 5 6. 12,249' 2.813" "X" Nipple 6 7. 12,283' 3.062" Re -entry guide 7 8. 12,320' 4 -1/2" Liner top (ZXP Packer) a � // 8 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole *■ 12550' MD - 12590' MD Slotted Liner at Near - Horizontal in HB - 2 ROTATING TIME HB -1 Sands 4 -1/2" J -55, 11.6# Tubing 2 -1/2" x 1/8" slots, 16 slots /ft 20" - 119 hrs 13,377' MD – 15,348' MD 13 -3/8 — 229 hrs 9 -5/8" — 259.5 hrs 7" — 99.5 hrs u Lost 1 roller 2.6" dia. X .25" thick off - - Schlumberger roller stem — 5 -6 -06 I ECP (inflated with mud) at 13696' MD (9774' TVD) 90 Deg Section at 13,000' MD W/ blank 4 -1/2" above and two blank joints below MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9736' TVD T. Fouts 6/27/2011 • • Chevron Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) K -13RD2 TRADING BAY UNIT K -13RD2 ADL0018772 5073320157 AR4376 100.00 Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Pump Repair Major Rig 5/27/2011 Work Over (MRWO) Primary Wellbore Affected Wellbore UWI Well Permit Number K -13RD2 507332015702 2010460 Daily Operations 5/10/2011 00:00 - 5/11/2011 23:00 Operations Summary PJSM - Mobilize slickline equipment to King Salmon platform for tree on slickline work - SD for night. 5/24/2011 00:00 - 5/2512011 00:00 Operations Summary RU Slickline. Pressure test lubricator to 3000psi high /250psi low. RIH w/ 3.78" GR to 8243'. POOH. RIH and set 4 -1/2" SV in XN @ 8243'. Fluid @ 1760'. POOH. Test SV and tubing to 250psi low for 10 min, 1500psi high for 10min. Good test. Bleed down. RIH w/ shifting tool, shifted sliding sleeve. Saw tubing pressure drop from 200psi to 60psi. POOH. Rig down. Turn well over to production. 5/27/2011 00:00 - 5128/2011 00:00 Operations Summary Begin rig up of Cudd HWO unit. Begin displacement of well to 3% KCI. 5/28/2011 00:00 - 6/29/2011 00:00 Operations Summary Continue Rig up of CUDD HWO unit. Pump sized salt pill and 3% KCI. Set BPV, ND tree, begin NU BOPE. 5129/2011 00:00 - 5/30/2011 00:00 Operations Summary Continue Rig up of CUDD HWO unit. Notified AOGCC of upcoming BOPE test. 5130/2011 00:00 - 5/31/2011 00:00 Operations Summary Continue Rig up of CUDD HWO unit. Pull BPV and install TWC. Prepare for testing BOPE. 5/31/2011 00:00 - 6/1/2011 00:00 Operations Summary Test BOPE 250psi low /3500psi high, test annular to 250psi low /2500psi high. Witness waived by AOGCC Bob Noble, AOGCC 7:30 AM. Pull TWC. Pump sized salt pill and 3% KCI, monitor well. 6/1/2011 00:00 - 6/2/2011 00:00 Operations Summary Monitor well, pull tubing hanger, start pulling 4 1/2" tubing out of hole, contunue TOOH to ESP. 6/2/2011 00:00 - 6/3/2011 00:00 Operations Summary LD BHA, tally GLM's, XN Nipple, sleeve. RU and prepare tools and equipment for ESP run, begin RIH with 4 -1/2" 12.6# L -80 ESP. 6/3/2011 00:00 - 6/4/2011 00:00 Operations Summary Continue RIH w/ 4 -1/2" ESP completion, megging cable and testing flat pack every 1000', continue TIH to 8310', 6/4/2011 00:00 - 6/5/2011 00:00 Operations Summary PU and MU tubing hanger, land hanger w/ BPV installed, w /ESP completion at 8356', pump intake at 8304'. Started ND BOPE equipment and NU tree. 6/6/2011 00:00 - 6/6/2011 00:00 Operations Summary Continue NU tree, Test tree to 250psi low /5000psi high. preparing rig for leg move. 6/6/2011 00:00 - 6/7/2011 00:00 Operations Summary Release rig - Initiate leg move to well K -01 RD2. II • • Page 1 of 3 Regg, James B (DOA) From: Regg, James B (DOA) PI ZEDS —044 Sent: Thursday, April 14, 2011 9:06 AM To: 'Johnson, Chris VV' '4 �� ���it Cc: DOA AOGCC Prudhoe Bay 1 Subject: RE: TBU K -13RD2 SSV Test -- Variance Request You have approval to to produce until 4/30/11. The well must be SI on 4/30 unless the SSV passes a performance test on or before 4/30, which the Commission will likely need to witness. There will be no consideration given to an extension. Hope that is clear enough. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 # � § , 1' Anchorage, AK 99501 AP `` 907 - 793 -1236 From: Johnson, Chris W [mailto:chris.johnson @chevron.com] Sent: Wednesday, April 13, 2011 3:43 PM To: Regg, James B (DOA) Cc: Martin, J. Hal Subject: FW: TBU K -13RD2 SSV Test -- Variance Request Mr. Regg, Is Hal interpreting this correctly? Is it ok to delay the test until 4/28 or 4/29, also If we do this will we still be able to run the pump if it restarts? Chris Johnson Lead Operator King Salmon Platform 907- 776 -6690 From: Martin, J. Hal Sent: Tuesday, April 12, 2011 5:22 PM To: Johnson, Chris W Cc: Njaa, Dale A; Reynolds, Sandy; Cole, David A; Myers, Chris S Subject: FW: TBU K -13RD2 SSV Test -- Variance Request Chris, K -13RD2 SSV variance request denied. If I read this correctly, we can continue to produce this well until 4/30 without having to test the SSV. What do you think about postponing the test on K -13RD2 until 4/28 or 4/29 so that if it fails to restart we should be at least that much closer to the workover? Remember, too, that the King should be getting a lot busier at that time because of the start of the workover program. 4/14/2011 • • Page 2 of 3 Thanx, Hal From: Regg, James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Tuesday, April 12, 2011 5:11 PM To: Martin, J. Hal Cc: Cole, David A; DOA AOGCC Prudhoe Bay; Aubert, Winton G (DOA) Subject: RE: TBU K -13RD2 SSV Test -- Variance Request TBU K -13RD2 (PTD 2010460) Union was granted approved for a similar request in October 2009, allowing the well to remain online without testing the SSV on 10/22/2009. That approval was specifically conditioned on repairs being completed to the ESP /well by April 30, 2010 or the well was to be shut in. It appears that Union chose to continue operating K -13RD2 by subjecting it to SSV testing 4/15/2010 and 10/8/2010 in lieu of repairs or shutting in the well. The no flow status of K -13RD2 - allowing it to operate without a subsurface safety valve - is conditioned on a fail -safe automatic SSV capable of preventing uncontrolled flow being maintained in proper working condition per 20 AAC 25.265. The Commission - required performance test as stated in our SVS regulations is designed to prove the SSV is in proper working condition. From our discussion on 4/11/2011, I understand that the rig workover of K -13RD2 timing is uncertain as it is preceded by other well workovers once the rig is mobilized to King Salmon platform. Union's request is denied based on uncertainty in when the TBU K -13RD2 rig workover will commence coupled with the need to demonstrate the failsafe automatic SSV. This denial may be reconsidered based on additional justification or an alternate means of demonstrating an acceptable means of verifying a surface or subsurface shut in capability in lieu of performance testing the SSV. Without a passing performance test of the SSV, Union may continue to produce TBU K- 13RD2 until April 30, 2011, at which time the well must be shut in for repairs. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 -793 -1236 From: Martin, J. Hal [mailto:Hal.Martin @chevron.com] Sent: Tuesday, April 12, 2011 9:08 AM To: Regg, James B (DOA) Cc: Cole, David A Subject: TBU K -13RD2 SSV Test -- Variance Request Jim, I would like to request a variance (extension) on the SSV test for TBU Well K -13RD2 (PTD 201046) until after the rig workover which is scheduled to begin in late May 2011. An SSV test is currently scheduled this Wednesday, April 13, 2011. The last SSV test was conducted on October 8, 2010. The variance is requested at this time because of the electrical frailty of the ESP completion, given the short time period between the upcoming workover and this scheduled SSV test. The current completion in K -13RD2 was installed in December 2008. In September 2009, the ESP went down and communication with the Phoenix gauge was lost and one of the three cable legs was grounded — indicating an electrically precarious condition. The Reda ESP was able to 4/14/2011 • • Page 3 of 3 be restarted in October 2009 and has been running since that time with five additional restarts - each time with uncertainty during this electrically critical period. K -13RD2 is operating under no -flow status. Keeping the well on and testing the SSV by deadheading the well against a closed valve is not recommended by Reda given the condition of the well and due to the high rate produced by the ESP. Therefore, if a SSV test is required, the well will be shut -in. K -13RD2 currently produces at about 7700 BFPD ( +/- 330 BOPD), which is about 2/3 of the fluid rate from the well expected following the upcoming workover. The current rate is intentionally limited in order to reduce the electrical Toad. Should the ESP not restart after going down for the SSV test, +/- six weeks of down time will significantly impact the production rate and revenue from the King Salmon platform. I apologize for the short fuse on this request, but thank you for your consideration. Hal Martin Optimization Engineer MidContinent /Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel 907 263 7675 Fax 907 263 7847 hal.martin @chevron.com 4/14/2011 • • Page 1 of 2 Regg, James B (DOA) From: Regg, James B (DOA) e ?7 Sent: Tuesday, April 12, 2011 5:11 PM To: Martin, J. Hal Cc: Cole, David A; DOA AOGCC Prudhoe Bay; Aubert, Winton G (DOA) Subject: RE: TBU K -13RD2 SSV Test -- Variance Request TBU K -13RD2 (PTD 2010460) Union was granted approved for a similar request in October 2009, allowing the well to remain online without testing the SSV on 10/22/2009. That approval was specifically conditioned on repairs being to the ESP /well by April 30, 2010 or the well was to be shut in. It appears that Union chose to t' CN�4 continue operating K -13RD2 by subjecting it to SSV testing 4/15/2010 and 10/8/2010 in lieu of repairs or shutting in the well. The no flow status of K -13RD2 - allowing it to operate without a subsurface safety valve - is conditioned on a fail -safe automatic SSV capable of preventing uncontrolled flow being maintained in proper working condition per 20 AAC 25.265. The Commission - required performance test as stated in our SVS regulations is designed to prove the SSV is in proper working condition. From our discussion on 4/11/2011, I understand that the rig workover of K -13RD2 timing is uncertain as it is preceded by other well workovers once the rig is mobilized to King Salmon platform. Union's request is denied based on uncertainty in when the TBU K -13RD2 rig workover will commence coupled with the need to demonstrate the failsafe automatic SSV. This denial may be reconsidered based on additional justification or an alternate means of demonstrating an acceptable means of verifying a surface or subsurface shut in capability in lieu of performance testing the SSV. Without a passing performance test of the SSV, Union may continue to produce TBU K -13RD2 until April 30, 2011, at which time the well must be shut in for repairs. Jim Regg AOGCC • 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Martin, J. Hal [mailto:Hal.Martin @chevron.com] Sent: Tuesday, April 12, 2011 9:08 AM To: Regg, James B (DOA) Cc: Cole, David A Subject: TBU K -13RD2 SSV Test -- Variance Request Jim, I would like to request a variance (extension) on the SSV test for TBU Well K- 13RD2 (PTD 201046) until after the rig workover which is scheduled to begin in late May 2011. An SSV test is currently scheduled this Wednesday, April 13, 2011. The last SSV test was conducted on October 8, 2010. The variance is requested at this time because of the electrical frailty of the ESP completion, given the short time period between the upcoming workover and this scheduled SSV test. The current completion in K -13RD2 was installed in December 2008. In 4/13/2011 • Page 2 of 2 September 2009, the ESP went down and communication with the P oenix gauge was lost and one of the three cable legs was grounded - indicating an electrically precarious condition. The Reda ESP was able to be restarted in October 2009 and has been running since that time with five additional restarts - each time with uncertainty during this electrically critical period. K -13RD2 is operating under no -flow status. Keeping the well on and testing the SSV by deadheading the well against a closed valve is not recommended by Reda given the condition of the well and due to the high rate produced by the ESP. Therefore, if a SSV test is required, the well will be shut -in. K -13RD2 currently produces at about 7700 BFPD ( +/- 330 BOPD), which is about 2/3 of the fluid rate from the well expected following the upcoming workover. The current rate is intentionally limited in order to reduce the electrical load. Should the ESP not restart after going down for the SSV test, +/- six weeks of down time will significantly impact the production rate and revenue from the King Salmon platform. I apologize for the short fuse on this request, but thank you for your consideration. Hal Martin Optimization Engineer MidContinent /Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel 907 263 7675 Fax 907 263 7847 hal.martin@chevron.com 4/13/2011 c44tct.xe.4- +1 4- 1(z-1 4 Safety Valve & Well Pressures Test Report -e.mia 6ActLyrz ,,,) Fad: TBU_KING_SALMON_PLA Insp Dt 10/22/2009 Inspected by Chuck Scheve Interval InspNo sysCS091027102524 Related Insp: SVSOP000007226 Field Name MCARTHUR RIVER Operator UNION OIL CO OF CALIFORNIA Operator Rep Jim Ryan Reason 180-Day Src: Inspector WAY0 C444iiiiiV --- -1 ' i Illots - ' SSV -;.KistX, Auto/ Dt Well - tvetiliirissuresr dial* -fvflivi .7--- ' 'bi6itent -_,L.--_ -' - : ' , '' .., , , , -- - ' :. -- , = - = ;-.., = - ' Ty L., - : ' ' - = = , - Well Permit Separ Set L/P Test Test Test Date SI OiI,WAG,GINJ, Inner Outer Tubing Number Number PSI PSI Trip Code Code Code GAS,CYCLE, SI PSI PSI PSI Yes/No Yes/No 7 _r___ I ' I — 1 K-12RD2 2080880 50 45 35 P P 1-OIL 1 1 • K-13RD2 2010460 50 45 45 P NT 1-OIL T K-19 1740080 50 45 45 P P 1-OIL 1 , , K-25 1850780 50 45 32 P P 1-OIL ] • , I 1 1 K-30 1700070 50 45 35 P P CO-20 L _J Comments Performance Per Jim Regg, ESP is "single phasing"; union given approval to not test SSV on TBU K-13RD2 due to Wells Components Failures Failure Rate concerns that ESP would not restart if S/D for testing. Repairs to ESP/well must be completed by April 30, 2010 or well must be S/I. 5 9 0 0 Monday, April 11, 2011 ... ce ,,,__ .... age,,,t,,-.4t, 4i Safety Valve & Well Pressures Test Report e.,,,k.(6,,,,,,,fa„..„ J 14k) Pad: TBU_KING SALMON_PLA Insp Dt 4/15/2010 Inspected by Bob Noble Interval InspNo sysRCNI00415172521 Related Insp: SVSOP000007896 Field Name MCARTHUR RIVER Operator UNION OIL CO OF CALIFORNIA Operator Rep Chuck Morse Reason 180-Day Src: Inspector F : Wdroata -': - r , : , -Pliots - -; ., SA(4 SSSI) e *0 g)i Weil Type , r' , WeliPressares Gas Lifi-' Co' mments- Well Permit Separ Set LIP Test Test Test Date SI Oil,WAG,GINJ, Inner Outer Tubing Number Number PSI PSI Trip Code Code Code GAS,CYCLE, SI PSI PSI PSI Yes/No Yes/No _ K-12RD2 1 2080880 45 40 36 PP 1-OIL K-13RD2 2010460 45 40 40 P P I 1-OIL -t - f - K-19 1740080 45 40 39 P P , 1-OIL K-25 1850780 45 40 36 P P 1-OIL III K-30 1700070 45 40 33 PP CO-20 1 ---- , 1 _ Comments Performance --- Wells were shut in when tested. They had removed the old pilots and installed new pressure switches. Wells Components Failures Failure Rate 5 10 0 • Monday, April 11, 2011 Safety Valve & Well Pressures Test Report �� ( b ac Ic J , L Pad: TBU_KING_SALMON_PLA Insp Dt 10/8/2010 Inspected by Chuck Scheve Interval InspNo sysCS101012110309 Related Insp: SVSOP000008532 iekft) Field Name MCARTHUR RIVER Operator UNION OIL CO OF CALIFORNIA Operator Rep Chris Johnson Reason 180 -Day Src: Inspector 4 well Dlita; R ,.,, ....w . Fl Ptlats ... , ,4 t s`SV , SSSV Shudn Ed well Type Well Prrsst res , GOft as Waiver ; _ C`e m , ` ,' ' Well Permit Separ Set L/P Test Test Test Date SI Oi1,WAG,GINJ, Inner Outer Tubing Number Number PSI PSI Trip Code Code Code GAS,CYCLE, SI PSI PSI pSI Yes/No Yes/No K -12RD2 2080880 ! 45 140 40 P P 1 -0IL 7 j K -13RD2 2010460 45 40 35 { P j P 1 -0IL -r K -19 1740080 45 40 40 P { P 1 -OIL K -25 ' 1850780 45 40 40 P P —'_- ! 1 -OIL ' —_ - - ^— III Comments Performance Wells Components Failures Failure Rate 4 8 0 II Monday, April 11, 2011 • • Sian OFF ALASEKKA SEAN PARNELL, GOVERNOR � ALASKA OIL AND =A 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMMISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Timothy C. Brandenburg Drilling Manager D � 4,6, Union Oil Company of California aol P.O. Box 196247 Anchorage, AK 99519 Re: McArthur River Field, Hemlock Oil Pool, TBU K -13RD2 Sundry Number: 311 -105 Dear Mr. Brandenburg: 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, _ � / Daniel T. Seamount, Jr. Chair p DATED this S day of April, 2011. Encl. • • Chevron Timothy C Brandenburg Union Oil Company of California %O. Drilling Manager P.O. Box 196427 Anchorage, AK 99519 -6247 Tel 907 263 7657 Fax 907 263 78888 4 Email brandenburgt @chevron.com RECEIVED March 28, 2011 \PR 41 Mu Commissioner Abeka ad > Gas cap Cananisaion Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 4 ictiorl ge Anchorage, Alaska 99501 -3572 Re: King Salmon Platform PTD: 201 -046 K -13RD2 ESP Repair, Application for Sundry Approval Dear Commissioner Enclosed is an Application for Sundry Approval (Form 10 -403) for the above referenced well. The outlined workover is for pull of and replacement of ESP assembly for well. • The location of the SSV is currently "adjacent to the vertical run" on the production tree of well K -30. i Union Oil Company requests a variance to 20 AAC 25.265 (c) (1), requiring that the SSV must be located in the vertical run of the tree. Per 20 AAC 25.285 the choke and kill lines are to be 3" in nominal diameter if MASP is greater than 3000PSI. The MASP expected is 3031 PSI. Union Oil Company requests a variance to utilize 2" nominal ID choke and kill lines on this workover. If you have any questions pertaining to this variance, please contact Jack R Newell 907 - 263 -7832. Timothy C. Brandenburg Drilling Manager Enclosure Cc: Well File Union Oil Company of California / A Chevron Company IRIG�- dzie ;��` fit 0�{�04I2o11 S �� ,L, STATE OF ALASKA 4 . "C ALASKA OIL AND GAS CONSERVATION COMMISSION 1 PRR 9 A Mil APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 witqa ' & b as (one 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well ❑ Ch wproy Program Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing 0 • TiNie Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Esp Repair 0 . 2. Operator Name: Union Oil Company of California 4. Current Well Class: 5. Permit to Drill Number: Development ISI • Exploratory ❑ 201 -046 • 3. Address: PO Box 196247, Anchorage, AK 99519 Stratigraphic ❑ Service ❑ 6. API Number: 50- 733 - 20157 -02 , 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No SI TRADING BAY UNIT K -13RD2 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL0018772 (King Salmon Platform) McArthur River Field/ Hemlock Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,485' • 9,736' • 15,485' 9,736' N/A N/A Casing Length Size MD ." TVD Burst Collapse Structural Conductor 4,976' 13 -3/8" 5,011' 4,182' 3,090psi 1,540psi Surface Production 8,672' 9 -5/8" 8,707' 7,163' 6,870psi 4,750psi Production 3,943' 7" 12,430' 9,657' 8,160psi 4,750psi Liner 3,065' 4 -1/2" 13,779' 9,770' 5,350psi 4,960psi Liner 1,606' 4 -1/2" (slotted) 15,385' 9,741' slotted slotted Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 12,550'- 12,590', 9,714' - 9,729', 4 -1/2" 12.6# L -80 8,286' 13,377'- 13,644' (slotted liner) 9,791'- 9,776' (slotted liner) 13,760'- 15,348' (slotted liner) 9,775' - 9,742' (slotted liner) Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A and N/A N/A and N/A 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program p BOP Sketch 0 Exploratory ❑ Development El • Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 1- May -11 Commencing Operations: Oil El • Gas ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ 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 Jack Newell 263 -7832 Printed Name Timothy C. Brandenburg Title Drilling Manager hy Signature C_ . Phone 276 -7600 Date 3/28/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 5■ \ ( O � Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ e.st 1roLmA go PE- tv 35 o0 yS.i 0.K.fti.c.le r $ P fo lSo l osti . Nit it a ,,,,.„3- t L ' O r 25' -L • 2. & S Co) CIyi ol. i tP- rHm.tc $ S v f il et et stt t It i S kepi (/8V. Ptays( c4' . 10 zo A/K.- zs. Z.45 (tt.) el. lt 8 o PE k a ppjoue4. Subsequent Form Required: 10 .. 04. APPROVED BY Approved by: , / COMMISSIONER THE COMMISSION Date: q 1 / • le Vii. (��nl �// � Form 10-403 Revised 1/2010 1, ` 1) I G1 \� l..a► L Submit in Duplicate • Chevron Trading Bay Unit K -13RD2 3 -28 -2011 Obiective: • Pull current ESP completion; re -run new 4 -1/2" ESP completion with gaslift mandrels. Current BHP: 4007psi @ 9770' TVD 7.9 PPG EMW Max BHP:,4007psi @ 9770' TVD 7.9 PPG EMW (Based on previous actual Phoenix Reading) MASP: 303Qpsi (Based on a pressure gradient of 0.1 psi per foot of true vertical depth) .r, o v- Procedure Summary: 1. MIRU HWO unit (rig). 2. RU Wireline. Pressure test lubricator 250psiLow/ 3100psi High. 3. RIH w/ 3.5" GR to clear tubing to +/ -8250' MD. 4. PU RIH 4 -1/2" CAT standing valve and place in XN profile at 8243' MD. r 5. Shift sliding sleeve @ 8199' MD or punch holes in tubing @ ±8220' MD. 6. RD Wireline. 7. Circulate wellbore with 3% KCI -FIW (filtered inlet water). 8. Spot sized salt pill as necessary. 9. ND tree. NU and test BOPE. Pressure test 250psi Low/ 3500psi High, Annular 250psi Low/ 2500psi High. • 10. Recover 4 -1/2" completion and ESP assembly. ' � 11. RIH 4 -1/2" 12.6# L -80 ESP and GLM completion w/ pump intake set at depth +/, ,/ 12. ND BOPE. NU and test tree. 250psi Low/ 5000psi High. 13. Secure and turn well over to production. 14. Rig down and release HWO unit (rig). 03/28/2011 AC Chevron %. K -13RD2 Trading Bay Unit King Salmon Platform %. Actual Wellbore Schematic Well # K -13RD2 Actual Completion Landed 12/06/08 RKB to TBG Hanger = 33.77' CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 13 -3/8" 61.0, 68.0 J -55 BTC 12.415" 35' 5,011' 9 -5/8" 47 N -80, S -95 BTC 8.681" 35' 8,707' — Window 7 Lnr 29 L -80 KC BTC 6.184" 8,487' 12,430' _ 4 -1/2" 12.6 J -55 Hydril 3.875" 12,320' 13,779' Blank Lnr 511 _ 4 -1/2" 11.6 J -55 Hydril 3.875" 13,779' 15,385' Slotted Lnr 511 L , Tubing: — 4 -1/2" 12.6 L -80 HYD 3.958" 34' 3375'/ A 563/503 8,286' 2 JEWELRY DETAIL NO. Depth ID Item 3 33.5' FMC Tubing Hanger (4 -1/2" HYD 503) GLM #1. 2,454' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch / 4 GLM #2. 4,450' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch ,< GLM #3. 5,795' 3.833" 4 -1/2" SFO-2 GLM w/ RK Latch L GLM #4. 6,368' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch GLM #5. 6,875' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch A. * 3.813" Sliding Sleeve 9 - 5/8" Window 2. I3,243' 3.725" XN Profile Nipple @ 8707' MD, 3. 8,286', Reda ESP Assy (70 St J12000N Pump & ) 30 Hole Angle 8322' 800 hp Pump 1Maoter P 8373' Phoenix XT1 4. 8,375' Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer Z� 5 6. 12,249' 2.813" "X" Nipple 6 7. 12,283' 3.062" Re -entry guide 7 8. 12,320' 4 -1/2" Liner top (ZXP Packer) �A 8 IZI Li - I 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 12550' MD - 12590' MD Slotted Liner at Near - Horizontal in HB -2 ROTATING TIME HB -1 Sands 4 -1/2" J -55, 11.6# Tubing 20" - 119 hrs 2 -1/2" x 1/8" slots, 16 SlotS /ft 13-3/8" — 229 hrs 13,377' MD — 15,348' MD 9 -5/8" — 259.5 hrs . 7" — 99.5 hrs c+' Lost 1 roller 2.6" dia. X .25" thick off - Schlumberger roller stem — 5 -6 -06 a ECP (inflated with mud) at 13696' MD (9774' TVD) 90 Deg Section at 13,000' MD W/ blank 4 -1/2" above and two blank joints below MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9736' TVD it Chevron IOW K -13RD2 Trading Bay Unit King Salmon Platform %. Proposed Wellbore Schematic % Well # K -13R02 Y Actual Completion Landed 12/06/08 RKB to TBG Hanger = 33.77' CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 13 -3/8" 61.0, 68.0 J -55 BTC 12.415" 35' 5,011' 9 -5/8" 47 N -80, S -95 BTC 8.681" 35' 8,707' ■ Window _ 7" Lnr 29 L -80 KC BTC 6.184" 8,487' 12,430' 4 -1/2" 12.6 J -55 Hydril 3.875" 12,320' 13,779' _ Blank Lnr 511 4 -1/2" 11.6 J -55 Hydril 3.875" 13,779' 15,385' Slotted Lnr 511 L , Tubing: 4 -1/2" 12.6 L -80 HYD 3.958" 34' 3375'/ A 563/503 8,286' MEM 2 JEWELRY DETAIL J �_ _ _ _ NO. Depth ID Item 3 1 33.5' FMC Tubing Hanger (4 -1/2" HYD 503) GLM #1. +2535' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) GLM #2. +4420' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) 4 GLM #3. +5700' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) >< >< GLM #4. +6458' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) GLM #5. +7065' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) GLM #6 +7665' 3.833" 4 -1/2" SFO -2 GLM R2 w/ RK Latch (Dummy) A. 8,200' 3.813" 4 -1/2" SSD,3.813,4 1/2 4 1/2 IBT ,B - 9 - 5/8" Window 2. 8,243' 3.725" XN Profile Ni le (NO -Go: 3.725 ") @ 8707' MD, 3. AL 30 Hole Angle +8320' ND Pump Intake 4. .. 5 6 7 21 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole •\ 12550' MD - 12590' MD Slotted Liner at Near - Horizontal in HB - 2 ROTATING TIME HB -1 Sands 4 -1/2" J -55, 11.6# Tubing 2 -1/2" x 1/8" slots, 16 slots/ft 13- 3/8' hrs 13,377' MD — 15,348' MD 9 -5/8" — 259.5 hrs 7" — 99.5 hrs G Lost 1 roller 2.6" dia. X .25" thick off Schlumberger roller stem — 5 -6 -06 ECP (inflated with mud) at 13696' MD (9774' TVD) 90 Deg Section at 13,000' MD W/ blank 4 -1/2" above and two blank joints below MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9736' TVD King Salmon Platform BOP Stackup NW 03/14/2011 King Salmon 2011 ESP Workovers OIL BOP Drawing K -1, K -13, K -30 4.54' .. al BOP based on Cudd rental Hydril stack drawing 13 5/8" 5000 i i iu 1 1 11 1 IFF 4.67' _ M -1 la l lit lit Ili III III All choke II line valves 2 /M w/ 111 ICI 1I1 1f1 111 i' unibolt endionnections 2.00' ;I� IOl I'UOI �� i ii i i t u t ill III III 111 III uSI 2.83' Ara.k11 lil lil lit lil lil .70' IND Is! igirgi.i!I 111 13.7 , Drill deck Riser 13 5/8 5M FE X135/85MAPI Hub 12.98' x'1.1 ,Iu n, 0 ' 1 '1. 5.70' ' i L! um fl ,, I I 1. i ( . . i u l ii, . L . 7 . ....„..-„,,, • ,, ,.., 1 • • Page 1 of 2 Regg, James B (DOA) ~ '~ ~_~4-~ ~._~_~~ .~~~~~_e~e~~._. ,.~.. u~_r~ _ __ From: Regg, James B (DOA) ~~~~E ~~ ~y~"~~~~~ Sent: Thursday, October 22, 2009 4:14 PM To: KRAMER, TED E Cc: Greenstein, Larry P; DOA AOGCC Prudhoe Bay; Aubert, Winton G(DOA) Subject: RE: K-13RD2 Waiver Request From the Leak Test Portion of the Surface Safety Valve Test. AOGCC Inspector witnessed SVS testing at TBU King Salmon platform today, 10/22/2009. I granted verbal approval to skip the leak test of the surface safety valve (SSV) on TBU K-13RD2 (PTD 2010460). Inspector was instructed to ensure the LPS for the SVS was tested on this well. This is a one-time, weil-specific waiver based on the explanation of circumstances as outlined below. Aiso factoring significantly into our decision was the excellent SVS test performance data for TBU K-13RD2. - According to our inspection database, TBU K-13RD2 has experienced no SVS component test failures since 5/2003 (LPS failure). Repairs should be completed before the next SVS test due date (end of April 2010) or the well must be shut in for ~ the required SSV leak test. It is unlikely that the Commission wi(f approve consecutive waivers of the SSV leak test on this well. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 ~~:v~7C0~'a-"..ieE r t' ~'.t ~'- ~' ~Ui~J~ From: KRAMER, TED E [mailto:TED.KRAMER@chevron.com] Sent: Wednesday, October 21, 2009 3:22 PM To: Regg, James B (DOA) Cc: Greenstein, Larry P Subject: K-13RD2 Waiver Request From the Leak Test Portion of the Surface Safety Valve Test. Jim, K-13RD2 is currently the highest producing ESP well in Cook Inlet and normally makes ~450 Bbls of Oil per day. It is due to be shut down for its bi-annual surface safety valve (SSV) test this week. Chevron is asking for a waiver from the leak test portion of the SSV test because there is a distinct possibility that if this ESP is shut down, it will not re-start. On or about 8/24/2009 the King Salmon platform experienced an electrical transformer failure on the power buss that powers the ESP wells. A replacement transformer is 6 months out so a temporary plan was devised to install a switch which effectively split the buss into two parts allowing a temporary transformer to be utilized, allowing the wells to be brought back on production while waiting for the replacement transformer. After the installation of this switch, K13RD2 was inadvertently re-started against a closed surface safety valve. Unfortunately, it took a little bit of time to discover that the surface safety valve was closed and as a resuit, one of the three electrical legs that run from the surface to the motor went to ground (commonly referred to as "single phasing"). Although it's not very common, there are times where an ESP pump will re-start and run with only finro of the three electrical legs intact. Chevron feels that we are very fortunate that that is what happened in this case. In the history of running ESP's in the Cook Inlet, only two other installations have started and ran with two of the I 0/22/2009 • • Page 2 of 2 three legs intact. One well ran for 11 more months before failing and the other ran for only three months totally going to ground and being replaced. In anticipation of this inevitable event, Chevron has already started preparing an AFE and making plans for this wells ESP replacement. In the meantime, steps have been taken to minimize the current draw on this ESP. The frequency has been reduced from 48 to 46 Hz. It is believed that this reduction will add to overall longevity although it has also reduced oil output to ~400 barrels a day. Another item that is important to consider is to avoid startups on the unit. During startup the inrush current is many times the equivalent running current. The reason Chevron requests the waiver of the leak portion of the surface safety to test is that in order to pertorm this part of the test, the ESP must be shut down which would then require a re-start. Rather than putting this well at risk for conducting this portion of the test, Chevron asks for the waiver until such time that either the well goes down for an unavoidable reason, or the well fails. With the inspector due to arrive on the King Salmon Platform this week, a quick response is needed and is most appreciated. Please call with any questions or concerns. Respectfully, Ted E. Kramer Petroleum Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tel 907 263 7960 Cell 907-382-0059 Fax 907 263 7847 ted. kramer@chevron.com 10/22/2009 ~ ~ \ F-f~~J ~ ~N~ vl ~~ ~~(.~`-~G';'.L 1 l ~ ~ ~ ~~~ J ~ I Combined SVS Test Results Jan 01,2005 Through (Excludes Reason = "Retest") PLT SSV SSSV Insp/ Date Test Retest Failure Well Name Permit # CP /F CP /F CP /F Oper Tested Reason Period Tests Components ~'ailures Rate TRADING BAY I1NIT K-O1RD2 2010090 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY LTNIT K-03RD 1801440 1 0 I 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY LJNIT K-12RD 1780570 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY LJNIT K-13RD2 2010460 1 0 1 0 0 0 IN 3/312005 180 2 0 TRADING BAY IJNIT K-18RD 2011170 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY iJNIT K-19 1740080 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY LJNIT K-25 1850780 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY LTNIT K-26RD 1950830 1 0 1 0 0 0 IN 3/3/2005 180 2 0 TRADING BAY [1NIT K-30 1700070 1 0 1 1 0 0 IN ~ 3/3/2005 180 2 1 TRADING BAY LTNIT K-O1RD2 2010090 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TI2ADING BAY iINIT K-03RD 1801440 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY LJNIT K-lORD 1740470 1 0 1 0 0 0 IN ll/2/2005 180 2 0 TRADING BAY LJNIT K-12RD 1780570 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY LTNIT K-13RD2 2010460 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY CJNIT K-18RD 2011170 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY LJNIT K-19 1740080 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY i1NIT K-25 1850780 1 0 1 I 0 0 IN 11/2/2005 180 2 1 TRADING BAY UNIT K-2bRD 1950830 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY iJNIT K-30 1700070 1 0 1 0 0 0 IN 11/2/2005 180 2 0 TRADING BAY [JNIT K-O1RD2 2010090 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY UNIT K-03RD 1801440 1 0 I 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY UNIT K-IORD 1740470 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY LTNIT K-12RD 1780570 1 0 1 1 0 0 IN 4/18/2006 180 2 1 TRADING BAY LTNIT K-13RD2 2010460 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY i1NIT K-18RD 201 I 170 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY L1NIT K-19 1740080 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY L1NIT K-26RD 1950830 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY L1NIT K-30 1700070 1 0 1 0 0 0 IN 4/18/2006 180 2 0 TRADING BAY iJNIT K-O1RD2 2010090 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY LJNIT K-03RD 1801440 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY UNIT K-12RD 1780570 1 0 1 0 0 0 IN 10/26/2006 180 2 0 Wednesday, October 21, 2009 ^f~, ( ~-( ~~a'~ ~ Page 1 of 3 1 "~---~ ~~.~j- I~G'L.~'. w ~_~j ~LrS.}- .~ N-- (_~s. ..~- 7 ,~ (~> r ~ ~ J • ~~ i~\Z.u~u~1 PLT SSV SSSV Insp/ Date Test Retest Failure Well Name Permit # CP /F CP /F CP /F Oper Tested Reason Period Tests Components Failures Rate TRADING BAY LJNIT K-13RD2 2010460 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY LJNIT K-18RD 20ll 170 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY LTNIT K-19 1740080 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY I1NIT K-25 1850780 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY LTNIT K-26RD 1950830 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY LTNIT K-30 1700070 1 0 1 0 0 0 IN 10/26/2006 180 2 0 TRADING BAY UNIT K-O1RD2 2010090 1 0 1 0 0 0 IN 4/13/2007 180 2 0 TRADING BAY UNIT K-12RD 1780570 1 0 1 0 0 0 IN 4/13/2007 180 2 0 TRADING BAY LTNIT K-13RD2 2010460 1 0 ] 0 0 0 IN 4/13/2007 180 2 0 TRADING BAY iJNIT K-18RD 2011170 1 0 1 0 0 0 IN 4/13/2007 180 2 0 ~ TRADING BAY LTNIT K-25 1850780 1 0 1 0 0 0 IN 4/13/2007 180 2 0 TRADING BAY CTNIT K-26RD 1950830 1 1 1 0 0 0 IN 4/13/2007 180 2 1 TRADING BAY LTNIT K-O1RD2 2010090 1 1 1 0 0 0 IN 10/12/2007 180 2 1 TRADING BAY LJNIT K-13RD2 2010460 1 0 1 0 0 0 IN 10/12/2007 180 2 0 TRADING BAY iJNIT K-18RD 2011170 1 0 1 0 0 0 IN 10/12/2007 180 2 0 TRADING BAY iJNIT K-19 1740080 1 0 0 0 0 0 IN 10/12/2007 180 1 0 TRADING BAY LJNIT K-25 1850780 1 0 1 0 0 0 IN 10/12/2007 180 2 0 TRADING BAY UNIT K-26RD 1950830 1 0 1 0 0 0 IN 10/12/2007 180 2 0 TRADING BAY LTNIT K-30 1700070 1 0 0 0 0 0 IN 10/12/2007 180 1 0 TRADING BAY iJNIT K-19 1740080 0 0 1 0 0 0 IN 10/16/2007 180 1 0 TRADING BAY UNIT K-30 1700070 0 0 I 0 0 0 IN 10/16/2007 180 1 0 TRADING BAY I1NIT K-O1RD2 2010090 1 0 1 0 0 0 IN 3/5/2008 180 2 0 TRADING BAY LJNIT K-13RD2 20t0460 1 0 1 0 0 0 IN 3/5/2008 180 2 0 TRADING BAY iJNIT K-18RD 2011170 1 0 1 0 0 0 IN 3/5/2008 180 2 0 TRADING BAY LJNIT K-25 1850780 1 0 1 0 0 0 IN 3/5/2008 180 2 0 TRADING BAY iJNIT K-26RD 1950830 1 0 1 0 0 0 IN 3/5/2008 180 2 0 • TRADING BAY LTNIT K-30 1700070 1 0 1 0 0 0 IN 3/5/2008 180 2 0 TRADING BAY LTNIT K-12RD2 2080880 1 0 1 0 0 0 IN 9/23/2008 180 2 0 TRADING BAY i1NIT K-13RD2 2010460 1 0 1 0 0 0 IN 9/23/2008 180 2 0 TRADING BAY UNIT K-18RD 2011170 1 0 1 0 0 0 IN 9/23/2008 180 2 0 TRADING BAY (JNIT K-25 1850780 1 0 1 0 0 0 IN 9/23/2008 180 2 0 TRADING BAY LJNIT K-26RD 1950830 1 0 1 0 1 0 IN 9/23/2008 180 3 0 TRADING BAY L1NIT K-30 1700070 1 0 1 0 0 0 IN 9/23/2008 180 2 0 TRADING BAY LJNIT K-12RD2 2080880 I 0 1 0 0 0 IN 4/17/2009 180 2 0 Wednesday, October 21, 2009 Page 2 of 3 . Well Name Permit # PLT CP /F SSV CP /F SSSV CP /F Insp/ Oper Date Test Retest Tested Reason Period Tests Components Failure Failures Rate TRADING BAY IJNIT K-13RD2 2010460 1 0 1 0 0 0 IN 4/17/2009 180 2 0 TRADING BAY LJNIT K-19 1740080 1 0 1 0 0 0 IN 4/17/2009 180 2 0 TRADING BAY LTNIT K-25 1850780 I 0 1 0 0 0 IN 4/17/2009 180 2 0 TRADING BAY iINIT K-30 1700070 1 0 I 1 0 0 IN 4/17/2009 180 2 1 TBU KING '5ALMON PLA 69 135 6 4.44% ~ ~ Wednesday, October 21, 2009 Page 3 of 3 STATE OF ALASKA /°?' ALASKA WAND GAS CONSERVATION COMMISSIW REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Lf Repair Well U - Plug Perforations U Stimulate U Other U ESP Pull & Rerun . Performed: Alter Casing ❑ Pull Tubing ig - Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown❑ Perforate ❑ Re -enter Suspended Well ❑ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 r Exploratory El 201 -046 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic❑ Service ❑ 6. API Number: 50- 733 - 20157 -02 7. KB Elevation (ft): 9. Well Name and Number: 33.77' Trading Bay Unit K -13RD2 8. Property Designation: 10. Field /Pool(s): ADL0018772 [King Salmon Platform] McArthur River / Hemlock Oil - 11. Present Well Condition Summary: Total Depth measured 15,485 -- feet Plugs (measured) N/A true vertical 9,736 - feet Junk (measured) +/- 12,600' (fish) Effective Depth measured 15,485 feet true vertical 9,736 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 4,976' 13 -3/8" 5,011' 4,182' 3,090 psi 1,540 psi Surface Intermediate 8,672' 9 -5/8" 8,707' 7,163' 6,870 psi 4,750 psi Production 3,943' 7" 12,430' 9,657' 8,160 psi 7,020 psi Liner 3,065' 4 -1/2" 15,385' 9,741' 5,350 psi 4,960 psi Perforation depth: Measured depth: See Attached Schematic True Vertical depth: See Attached Schematic r r ;. Z U 1't Tubing: (size, grade, and measured depth) 4 -1/2" 12.6# L -80 8,286' Packers and SSSV (type and measured depth) (No production Packer)/ N/A N/A 12. Stimulation or cement squeeze summary: N/A 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: 300 (gas lift) 5000 (gas lift) 4500 (gas lift) 1265 psi (gas lift) 420 psi (gas lift) Subsequent to operation: 700 400 10500 135 psi 140 psi 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development 0 - Service ❑ Daily Report of Well Operations X 16. Well Status after work: Oil © - Gas ❑ WAG ❑ GINJ ❑ WINJ ❑ 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: 308 -299 Contact Chantal Walsh 263 -7627 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature %/ ` — -- ~ Phone 276 -7600 Date 12/18/2008 Form 10 -404 Revised 04/2006 Ava k a _� L,il: Submit Original Only • Trading Bay Unit UNOCAL 76 King Salmon Platform Well # K -13RD2 Actual Completion Landed 12/06/08 RKB to TBG Hanger = 33.77' CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 1 13 -3/8" 61.0, 68.0 J -55 BTC 12.415" 35' 5,011' 9 -5/8" 47 N -80, S -95 BTC 8.681" 35' 8,707' Mb Window 7" Lnr 29 L -80 KC BTC 6.184" 8,487' 12,430' _ 4 -1/2" 12.6 J -55 Hydril 3.875" 12,320' 13,779' Blank Lnr 511 4 -1/2" 11.6 J -55 Hydril 3.875" 13,779' 15,385' Slotted Lnr 511 L , Tubing: — 4 -1/2" 12.6 L -80 Mod. 3.958" 34' 8,286' C A BTC 2 JEWELRY DETAIL r NO. Depth ID Item 3 33.5' FMC Tubing Hanger 1. C co 4-1/2" SFO -2 Gaslift Mandrels. GLM #1. 2,454' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch 4 GLM #2. 4,450' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch >` GLM #3. 5,795' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch L GLM #4. 6,368' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch GLM #5. 6,875' 3.833" 4 -1/2" SFO -2 GLM w/ RK Latch A. 8,199' 3.813" Sliding Sleeve 9 - 5/8" Window 2. 8,243' 3.725" XN Profile Nipple at 8707' MD, 3. 8,286' Centrilift ESP Assy (HC 10000 Pump & 800 30 deg hole angle hp HMI Motor) 4. 8,375' Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer 6. 12,249' 2.813" "X" Nipple 7. 12,283' 3.062" Re -entry guide >< 5 8. 12,320' 4 -1/2" Liner top (ZXP Packer) — - 6 — 7 1/ 8 Lost 1 roller 2.6" dia. X .25" thick off 413"-:--1<-------- Schlumberger roller stem — 5 -6 -06 7 liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole t\ 12580' — 600' TOTAL ROTATING TIME G Perf Blank Pipe Slotted Liner at Near - Horizontal in HB -2 and HB -1 20" - 119 hrs 4 -1/2" J -55, 11.6# tbg with 2 -1/2" x 1/8" slots, 16 slots /ft 13 -3/8" — 229 hrs 9 -5/8" — 259.5 hrs 7" — 99.5 hrs ■ 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' ECP (inflated with mud) at 13696' MD (9774' TVD) TD = 15485' MD/9737' TVD with blank 4-1/2" above and two blank joints below K -13RD2 Actual Schematic 12/17/08 CVK Chevron 1 1 Nisol Chevron - Alaska Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) K -13RD2 TRADING BAY UNIT K -13RD2 ADL0018772 5073320157 AR4376 100.00 • • Jobs Primary Job Type Job Category Objective Actual Start Date Actual End Date Pump Repair Major Rig 11/23/2008 12/7/2008 Work Over (MRWO) Primary Wellbore Affected Wellbore UWI Well Permit Number K -13RD2 5073320157 -02 2010460 Daily Operations 11/22/2008 00:00 - 11/23/2008 00:00 Operations Summary Rigging up 11/23/2008 00:00 - 11/24/2008 00:00 Operations Summary Wait on boat. Rig up slickline. 11/24/2008 00:00 - 11/25/2008 00:00 Operations Summary RU slickline. RIH w/ 3.8" guage ring to 6721', tagged up. POOH. RIH w/ 3.61" GR, set down again, worked through and ran to bottom of tubing, 8212'. POOH. RU 3.8" GR, could not work past 4474'. POOH. Attempt to RIH with kick over tool, no go past 4308'. POOH. RIH with 3.61" GR, no go past 4284'. POOH. 2.65" GR hung up at 4188'. Pump 50 bbl 3% KCI, no returns to surface. RIH w/ 2.65" to 8301'. POOH. RIH with impression block, confirm valve in 2nd GLM in place. RD slickline. 11/25/2008 00:00 - 11/26/2008 00:00 Operations Summary Mix sized salt pill. Circulated and lost 1,003 bbls to formation. no returns, Pumped 38 bbls saturated salt followed with 147 bbls sized salt pill, with 20 bbl saturated salt tail. Chased with 108 bbls of 3% KCL. No returns to surface. 11/26/2008 00:00 - 11/27/2008 00:00 Operations Summary Build Sized Salt pill, Did not have to pump pill. Notified AOGCC of upcoming BOP test. Nipple down tree. 11/27/2008 00:00 - 11/28/2008 00:00 Operations Summary Nipple Up BOP\ Test BOP's 250 psi low / 3,000 psi high. BOP test witness waived by AOGCC Bob Noble. 11/28/2008 00:00 - 11/29/2008 00:00 Operations Summary Squeeze Sized salt pill, POOH L/D 4 -1/2" 12.6# tubing. 11/29/2008 00:00 - 11/30/2008 00:00 Operations Summary POOH with ESP, Lay down all 4 -1/2" 12.6# tubing. 11/30/2008 00:00 - 12/1/2008 00:00 Operations Summary Lat down ESP, Load Boat, Clean while waiting on Boat. 12/1/2008 00:00 - 12/2/2008 00:00 Operations Summary Waiting on boat. 12/2/2008 00:00 - 12/3/2008 00:00 Operations Summary Waiting on boat. 12/3/2008 00:00 - 12/4/2008 00:00 Operations Summary ,, LJ uipnle t to run ESP completion. 12/4/2008 00:00 - 12/5/2008 00:00 Operations Summary Begin running ESP completion. 12/5/2008 00:00 - 12/6/2008 00:00 Operations Summary _ Continue running ESP on 263 jts 4 -1/2" Hydril 563 & 503 tubing to 8,375 Original RKB measurement. 12/6/2008 00:00 - 12/7/2008 00:00 Operations Summary ND BOPE, NU tree. Turn well over to production. Begin Demobe of CUDD unit. STATE OF ALASKA ALAS~OIL AND GAS CONSERVATION COMM~ON REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Replace ESP pump . Performed: Alter Casing ^ Pull Tubing0 Perforate New Pool ^ Waiver^ Time Extension^ Change Approved Program ^ Operat. Shutdown[] Perforate ^ Re-enter Suspended Well ^ 2. Operator Union Oil Company of California 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development ^~ - Exploratory^ 201-046 • 3. Address: P.O. Box 196247, Anchorage, AK 99519 Stratigraphic^ Service^ 6. API Number: 50-733-20157-02 ' 7. KB Elevation (ft): 9. Well Name and Number: 33.77' (100' AMSL) • Trading Bay Unit K-13RD2 • 8. Property Designation: 10. Field/Pool(s): ADL0018772 [King Salmon Platform] McARhur River / Hemlock Oil ~ 11. Present Well Condition Summary: Total Depth measured 15,485' ' feet Plugs (measured) N/A true vertical 9,736' ~ feet Junk (measured) +/- 12,600' (fish) Effective Depth measured 15,485' feet true vertical 9,736' feet Casing Length Size MD •ND Burst Collapse Structural Conductor 4,976' 13-3/8" 5,011' 4,182' 3090 psi 1540 psi Surface Intermediate 8,672' 9-5/8" 8,707' 7,163' 6870 psi 4750 psi Production 3,943' 7" 12,430' 9,657' 8160 psi 7020 psi Liner 3,065' 4-1/2" 15,385' 9,741' 5350 psi 4960 psi Perforation depth: Measured depth: See Attached Schematic _ ._ ,~ „ ~y ~ ~ ~:.o_" .~-~ 1 y~ ,. ''` ~V~.~::~ .~ ~:x a~,'~ i~$ True Vertical depth: See Attached Schematic ~~~~~~~~ Tubing: (size, grade, and measured depth) 4-1/2" 12.6# L-80 8,314' ~ ~ '~ za~~ Packers and SSSV (type and measured depth) (No production packer) N/A N/A Al~ska Oii & G~s ~~~i~, Cocr~rniss~~+~~ 12. Stimulation or cement squeeze summary: N/A R1C E7~i~~~ Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Represe~tative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Press~re Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 707 ~ 8559 428 80 670 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory^ Development ~ ' Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil ~^ ' Gas ^ WAG ^ GINJ ^ WINJ ^ 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: 307-115 Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager ~ ~ ~ .. .~ '~ µ ~ ' Phone 263-7600 Date 10/7/2008 Signature '' ~ -- -~'"~ ~....~: ~ ~~, r~~ ~ ~ ~~'.`=. -, ~ r~ ~ ~. ~ ~s ifs• ~- as Form 10-404 Revised 04/2006 "•. ~ ~,~S,~bmit Original Only . ~ . ~.,. ~6 • Trading~ay Unit U N 0 CA ~ 76 King Salmon Platform Well # K-13RD2 Actual Completion Landed OS/22/07 RKB to TBG Hanger = 33JT ('A~IN(: ANn T'I IRINr nF.TAII. 3 4 A 2 9-5/8" Window at 8707' MD, 30 de~ hole angli iH.wF.~.RV ~F.~rA~r, TOTAL ROTATING TIME 20" - 119 hrs 13-3/8" - 229 hrs 9-5/8" - 259.5 hrs 7" - 99.5 hrs 5 6 7 SIZE ~'~'T GRADE CONN ID TOP BTM. 13-3/8" 61.0, 68.0 J-55 BTC 12.415" 35' S,011' 9-5/8" 47 N-80, 5-95 BTC 8.681" 35' 8,70T Window 7" Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2" Blank Lnr 12.6 J-55 Hydril 51 I 3.875" 12,320' 13,779' 4-1/2" Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385 Tubin : 4-1/2" 12.6 L-80 Mod. BTC 3.958" 34' 8,314' NO. De th ID Item 33.7T FMC Tubin Han er 1. Camco 4-U2" SFO-2 Gaslift Mandrels. GLM #1. 2,405' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #2. 4,382' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch CLM #3. 5,710' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #4. 6,268' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLN1 #5. 6,762' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #6. 7,255' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #7. 7,716' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch A. 8,262' 3.813" Sliding Sleeve 2. 8,301' 3.725" XN Profile Nipple 3. 8,314' Centrilift ESP Assy (HC10000 Pump & 800 h HMI Motor 4. 8,405' Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer 6. 12,249' 2.813" "X" Nipple 7. 12,283' 3.062" Re-entry guide 8. 12,320' 4-1/2" Liner top (ZXP Packer) ~ g Lost I roller 2.6" dia. ?C .25" thick off Schlumbcrgcr rollcr stcm -- S-6-0fi 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 12580' - 600' PerfBlankPipe Slotted Liner at Near-Horizontal in HB-2 and HB-1 4- I/2" J-55, 11.6# tbg with 2-1 /2" x 1/8" slots, 16 slots/ft ._._._._._._._._._._._._._._._._._._._.~ _._._._._._._._._._._._._._._._._._._._~ 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD K-13RD2 Schematic ECP (inflated with mud) at 13696' MD (9774' TVD) with blank 4-1/2" above and two blank joints below REVISED:04/13/07 JAR ~Chevron ~ Chevron - Alaska ~ Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (fl) K-13RD2 TRADING BAY UNIT K-13RD2 ADL0018772 5073320157 AR4376 100.00 . , ,.. ~ u_ x ~ „ ;, ~ ~ . ~ ~ .. ,.•.;wr, ~, ~. ~, n Primary Job Type Job Categary Objective Adual StartSDate Actual End Date Pump Repair Major Rig Replace failed ESP 4/30/2007 Work Over (MRWO) Nnmary WeIIDOre Attectetl Wellbore UWI Well Permit Number K-13RD2 5073320157-02 2010460 ~' ~,, ,. ~; . x, s s ~. . ~ , ,,~ , ~ ~~; ; ~ ~ t.v ~.~ ~ - ,. ,~ s fr . ,. ~ ~ . w ~., ., ~.; .. ., ~ ~; 4t~f~12~07 00:00 - 5/1/2007~A0:00 ~ ~~ ~~~~' '~ ~ ' Fy., ~. ,: ,~ ~. , ,- ~ ~ ;.k~w Operetions Summary Prep to RU Cudd and start WO operations. ;~~~ x.~ 5/1/2007 OQ:00 - 5(?J2007 00:00 ' '' ~, Operations Summary ~ ~ ~ ~ ~ ~ Recieve Cudd equipment and continue RU operations. 5/2/2007 Q~ 00=~ ~f3/2007 00:00 ~ ;. ~~, ~~. ~,. N~~ _ ~. Operations Summary Continue to RU Cudd HWOU and prepare to start WO operations. 513/20(t~ Ot}:Ott `w 5/M2007 00:00 ~ ~ v~~r~x ;< Operations Summary Continue to RU Cudd HWOU and prepare to start WO operations. Notified Bob Nobel of AOGCC of upcoming BOP test. 5/4/2007 0~,00 - 5/5t200T'00:04 ` ~ ,x ,.. ~,:~~.~. ,. Operations Summary Continue to RU Cudd. Circulate well with 737bb1 of 3% KCL @ 6.25bpm and place 140bb1 sized salt piil @ 4bpm in perfs. ND tree and start NU BOPs. 5l5/20t~~f1t~:0~'"~'$!6/2007 00:00 ~~: ~ ~ ~-~a'~~~ ~ ~.,. ~~.:"~ ~.; Operations Summary Continue to RU cudd. Finish NU and test BOP's250psi low/ 3000psi high, Bob Noble of AOGCC waived witness. Start WO operations. 5/6/~0 ~~fN~tO~~~~ 5171200T~00:00 ~ ~ ~ ~ _ '~ ~ ° ~ Operations Summary~ Pull and recover tubing hanger. Start tripping out of hole with 4 1/2" tubing looking for potential leak. Pipe looks good. Pump 114bb1 sized salt pill @5bpm, displaced with 220bb13% KCL @ 3.8bpm & 1300psi. Having difficulty with cable spooler. 517I2007~OOs00 - 5l8/204?=Q4:00 `~'~~~' s~ ~ ~ ~ ~ Operations Summary Finish TOOH to pump assy. Find short in motor lead. Pump and motor assy appear to be in good condition. ~ 7x . . , , < .,,. a.. 5/8/2007 00:00 - 5/9/2QQ7 OQ:~O ~f' `. _ Operations Summary Finish laying down pump assy. TIH with tubing and test to 3500 psi ok. Start TOOH. 5/9/~QQ7 OQ':00.- 5/1Qt2t147 00:00 Operations Summary FOOH with 4 1/2" tubing. MU ESP assy. Troubleshoot Phoenix gauge and flat cable. y 5/10/2407 00:00 - 5/11~~OQTxQ0:1~ ,.. i'"' ~~ ~ ~ ,,,, ~ ~ ~~~.~ ~ Operations Summary Finish troubleshooting Phoenix gauge. Continue to TIH with ESP assy. , •. 5l1'1. ~ T 00:00 - 5/17J2~07 00:00 Operations Summary Continue TIH with ESP completion. Troubleshoot and resolve minor electrical problems. $f121200~ 00:00 - 5/13/2007 Q4;~0 r~< ~ ~ ~ ~ ~`~;" ~ ~ ~, ;~ Operations Summary FIH with ESP. Make final checks on electrical issues. Land tubing hanger. ND BOPs and NU tree. ~' fi ~ '~"$12007 00:00 - 5l14/2007 00:00 ' `' '4 ,..:)r~`'.. ,. '- ' ,..."~:... ~: , ` X , .r,t~<..~... Operations Summary Finish NU Tree and test void ok. Start moving HWOU. Test run ESP. Shut down for high motor temp. Start troubleshooting. 5!`'f4/2007 OOs00 - 5/15/2007 00:00 v'~'= :r` ~ ~ ~ ., ,~ , x <. ~. , ~.. , Operations Summary K-13RD2 ESP failed on startup. Start rigging up to pull completion. v. ~ -y.,=; .~ ~s . .. , ~, ,~ 5/15I2007 Q0:00 - 5l1612007 00:00 ' ~ . ~ , , , . ~ ~ ; ~ ~~' ~ i, ~ ~ ..~ Operations Summary Continue to RU HWOU. RU SLU to shift sliding sleeve open W/O success. Cant get down to sliding sleeve depth with wireline. 5l16/2007 ~:Oa - 5/17/2007 OO:OQ _ ; ' ~ ., t ° Operations Summary Continue to RU HWOU. ND tree and NU BOPE. Notice give to AOGCC of upcoming BOP test. a ~ i ~:„. 5117/2 ' _ ~;011- 5/181200 , OO;Oa" ~~ ~ , ~ v ` ~ Operations Summary Test BOP's 250psi low/3000psi high.. Repair leaks in choke manifold. Troubleshoot and repair Koomy ~ ~ ', ' ~ ~ ~~ 5f18/2007~00:00 - 5/19J2007 00: ~~ t~ '°`~ `; ~~":': ~ ~ ~ , ' ~ ~ ~ u~: ~~~~ ~ ~~ ` :~ ""` ~ Operations Summary Pull tubinq hanqer and start TOOH with ESP Comoletion. ~~hevron ~ Chevron - Alaska ~ Daily Operations Summary Well Name Legal Well Name Lease Surface UWI ChevNo Original RKB (ft) Water Depth (ft) K-13RD2 TRADING BAY U NIT K-13RD2 ADL0018772 5073320157 AR4376 100.00 ~ ~.~ ~ D8I . , Q ~; ~~r „-.., „ ~ . ~.v , . ~..~; . <. M~ ~ . ~ ~,, ~ . u.. 5/19f2007 00:00 -5F2Qt2007'00:00 ~ ~ ~ ~ ". : ~~ " ,> ~ ~. ~ > . ~. _~~, , ' ~'` ~.~ ~~~ , ~ Operations Summary Continue TOOH with ESP assy ~ 5l20/2QQ .~9!O:Ot~~~ 5t2172007 OO:QO ~~u..:. ~ ~ ~ , ~ ~ ~ ~~~ ~': . ; ...~. ~ , : ~ Operations Summary Continue TOOH with ESP assembly. . .. , 5/21I2~0~` ~00:00 - ~5%32I20Q~ OO.f~O "; , ~ ~~'~ h ,d .: ' ..:. '. ~ ~ ~ Y,.;'4 . ~. ~ . ~ ~ : .~r Operations Summary I TIH with ESP completion. I 5/22/2t~07 00:00 - 5/23/~dC#~~Ot1:00 z~ ~` . . ~ '' ~~~': Operations Summary TIH with completion to 8,405' ft~ `~t~07 OOtOQ - 5/24~~t1b7 00:00 ~,.~:~ ,~ ;. Operations Summary ND BOP, NU tree. 5/24/2007 00:00 - 5/25[2Q0~ :~0 ~ ~ ;i ~ w ~~~:. _. ~ Operations Summary Demobe • • .~ ~~ fl ~~ ~~ SARAH PAL/N, GOVERNOR ~58A OI~ ~ ~5 333 W. 7th AVENUE, SUITE 100 CO1~T5ERQATI01'IT COMI-II55IOH ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Timothy Brandenburg Drilling Manager UNOCAL Po Box 19x247 ~ ~,~~~~~ ~ lJ G ~ ~ 20Q 8 ~ 0 Anchorage AK 99519 a Re: McArthur River Field, Hemlock Oil Pool, Trading Bay Unit K-13RD2 Sundry Number: 308-299 Dear Mr. Brandenburg: 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum $eld inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, ~~ Daniel T. Seamount, Jr. Chaix DATED this ~ day of August, 2008 Encl. '`~~ STATE OF ALASKA ~ ~~ ~~ ~ ~~ ~~ ~ V` - ' a ` //- B'~ ALA OIL AND GAS CONSERVATION COM ION, 2OO$ ~ Waroer ~ Other^ 1. Type of Request: Abandon^ Suspend ^ Operational shutdown a },~r~ p Alter casing^ Repair well ['+~ Plug Perforations ^ Stimulate C` Tihie~Extension ^ ESP Pull & Rerun Change approved program^ Pull Tubing V[r Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Union Oil Company of California Development ^ , Exploratory ^ 201-046 3. Address: Stratigraphic ^ Service ^ 6. API Number: PO Box 196247, Anchorage, AK 99519 50-733-20157-02 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ~ Tradin Ba Unit K-13RD2 ' 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL0018772 Kin Salmon Platform 33.77' McArthur River /Hemlock Oil 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 15,485't 9,736' - 15,485' 9,736' _ N/A +/- 12,600' (fish) Casing Length Size MD TVD Burst Collapse Structural Conductor 4,976' 13-3/8" 5,011' 4,182' 3090 psi 1540 psi Surface Intermediate 8,672' 9-5/8" 8,707' 7,163' 6870 psi 4750 psi Production 3,943' 7" 12,430' 9,657' 8160 psi 7020 psi Liner 3,065' 4-1/2" 15,385' 9,741' 5350 psi 4960 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6# L-80 8,314' Packers and SSSV Type: Packers and SSSV MD (ft): (No production packer) / N/A N/A 13. Attachments: Description Summary of Proposal Q 14. Well Class after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development Q Service ^ 15. Estimated Date for 9/1/2008 16. Well Status after proposed work: Commencing Operations: Oil 0- Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chantal Walsh 263-7627 Printed Name Timothy C. Brandenburg Title Drilling Manager .W,. Signature Phone 276-7600 Date 8/21/2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~ ~' 02 Plug Integrity ^ BOP Test ~ M echanical Integrity Test ^ Location Clearance ^ ii~~ Other: ~oO®~S\ ~-'t~ ~ ~ ~1v vivo ` "~~~ \ ~~ Subsequent Form Required: ~..,` APPROVED BY ~/ 7 j / U ~ U p ( v Approved by: COMMISSIONER THE COMMISSION Date: G.. APPLICATION FOR SUNDDRY APPRC~/14L~ ~~ N 20 AAC 25.200 ."~ .. n ~ Form 10-403 Revised 06/20 R I G I N A L ~~~ ~~~ ~ i zoos Submit in Duplicate • Tradin~ay Unit V N ~ CA ~~ King Salmon Platform Well # K-13RD2 Actual Completion Landed 05/22/07 RKB to TBG Hanger=33.77' rn.clvr: nNn ~r1iRIN~: nF'Tnn. 3 4 1 A 2 .IF'.WF.I.RY rtF.TAII. TOTAL ROTATING TIME 20" - 119 hrs 13-3/8" - 229 hrs 9-5/8" - 259.5 hrs 7" - 99.5 hrs 9-5/8" Window at 8707' MD, 30 deg hole angle 5 6 7 S[ZE WT GRADE CONN ID TOP BTM. 13-3/8" 61.0, 68.0 J-55 BTC 12.415" 35' 5,011' 9-5/8" 47 N-80, S-95 BTC 8.681" 35' 8,707' Window 7" Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2" Blank Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2" Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' Tubin 4-1/2" 12.6 L-80 Mod. BTC 3.958" 34' 8,314' NO. De th ID Item 33.77' FMC Tubin Han er 1. Camco 41/2" SFO-2 Gaslift Mandrels. GLM #I. 2,405' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #2. 4,382' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #3. 5,710' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #4. 6,268' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #5. 6,762' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #6. 7,255' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #7. 7,716' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch A. 8,262' 3.813" Sliding Sleeve 2. 8,301' 3.725" XN Profile Nipple 3. 8,314' Centrilift ESP Assy (HC10000 Pump & 800 h HMI Motor 4. 8,405' Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer 6. 12,249' 2.813" "X" Nipple 7. 12,283' 3.062" Re-entry guide 8. 12,320' 4-i/2" Liner top (ZXP Packer) 8 Lost 1 roller 2.6" dia. ~ .25" thick off Schlumberger roller stem - 5-6-06 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 12580' - 600' PerfBlank Pipe Slotted Liner at Near-Horizontal in HB-2 and HB-1 4-1/2" J-55, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft ._._._._._._._._._._._._._._._._._._._. 1~ 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD ECP (inflated with mud) at 13696' MD (9774' TVD) with blank 4-1/2" above and two blank joints below K-13RD2 Schematic REVISED: 04/13/07 JAR • Trading~ay Unit V ND~A~ 76 Proposed King Salmon Platform Well # K-13RD2 Actual Completion Landed 05/22/07 RKBtoTBG Hanger=33.77' rACINr. Anrn~rliRlNC nH~rnn. 3 4 A 2 9-5/8" Window at 8707' MD, 30 del; hole angle .IEWF.I,RV t)F.TAI1. TOTAL ROTATING TIME 20" - 119 hrs 13-3/8" - 229 hrs 9-5/8" - 259.5 hrs 7" - 99.5 hrs 5 6 7 SIZF, WT GRADE CONN ID TOP BTM. 13-3/8" 61.0, 68.0 J-55 BTC 12.415" 35' 5,011' 9-5/8" 47 N-8Q 5-95 BTC 8.681" 35' 8,707' Window 7" Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2" Blank Lnr 12.6 J-55 Hydril 511 3.875" 12,320' 13,779' 4-1/2" Slotted Lnr 11.6 J-55 Hydril 511 3.875" 13,779' 15,385' Tubin 4-1/2" 12.6 L-80 Mod. BTC 3.958" 34' 8,314' NO. De th ID Item 33.77' FMC Tubin Han er 1. Cameo 4-I/2" SFO-2 Gaslift Mandrels. GLM #l. 2,350' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #2. 4,325' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #3. 5,655' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #4. 6,210' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #5. 6,705' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #6. 7,200' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch GLM #7. 7,660' 3.833" 4-1/2" SFO-2 GLM w/ RK Latch A. 8,210' 3.813" Sliding Sleeve 2. 8,245' 3.725" XN Profile Nipple 3. 8,260' Centrilift ESP Assy (HC10000 Pump & 800 h HMI Motor 4. 8,350' Bull Nose (bottom) 5. 12,200' 4.000" Baker 7" Model "F" perm. packer 6. 12,249' 2.813" "X" Nipple 7. 12,283' 3.062" Re-entry guide 8. 12,320' 4-1/2" Liner top (ZXP Packer) 8 Lost 1 roller 2.6" dia. X .25" thick off Schlumberger roller stem - 5-6-06 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 12580' - 600' PerfBlank Pipe Slotted Liner at Near-Horizontal in HB-2 and HB-1 4-1/2" J-55, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft ._._._._._._._._._._._._._._._._._._._. 1J 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD ECP (inflated with mud) at 13696' MD (9774' TVD) with blank 4-1/2" above and two blank joints below K-13RD2 Proposed Schematic 8/21/08 CVK Chevron ~ ~ King Salmon Platt©rm Well # K-13RD2 8/21/08 OBJECTIVE: • Pull and re-run ESP. PROCEDURE SUM cM~ARY: ~C~ 4~1/~ t--~ C.vcJ V ~~ ® ~ vii ~~~'`~. l ^~c~(~-5 1 1 Mobilize rig onto K-13RD2 j--~'~Ql~~ ~g ~ 2 PJSM - ND Tree - NU BOPS -All LP mud Lines -All HP Mud Lines -Test all lines -TEST BOPE Equipment (PULL & PEEK) Remove BPV. PUMU Landing Joint. BO LDS. PU tbg hanger. Pull tbg to first splice below hngr. 3 Cut cable below splice. Meg cable downhole. If cable megs good, resplice cable below hngr & land same. If cable still shows short downhole, raland tbg hngr and continue with WO. 4 PJSM - RU ESP handling equipment/ (Spooler, sheaves, power washer, ... ) 5 PJSM -Circulate well, displace well to inlet water, insure standing column of fluid in well, displace xeturns to production -Flow check well -Pump salt pill as needed -Flow check well 6 POOH LD 4-1/2" tubing & ESP Equipment 7 PJSM - RU Crane & ESP company to run ESP -Run ESP 8 Release Cudd Pressure Control K-13RD2 REVISED BY: CVK 8-21-08 . ¡~üŒ (ffi~ ~~~~~~ . / AI..ASIiA. OIL Al'O) GAS CONSBRVATlON COMMISSION ! 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 SARAH PALIN, GOVERNOR Timothy Brandenburg Drilling Manager Chevron Alaska PO Box 196247 Anchorage, AK 99519-6247 Re: McArthur River Field, Hemlock Oil Pool, K-13RD2 Sundry Number: 307-115 \~ out\' ~() sCANNED APR 2 :) 2007 Dear Mr. Brandenburg: 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. When providing 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 this tq day of April, 2007 Enc!. · f f)rg t:h~1t: rJIr 4 -I~ /01 '. REL;I:: IVI::U 7 / STATE OF ALASKA fh.t ALA OIL AND GAS CONSERVATION COM.ION (\« APK 0 4 2007 APPLICATION FOR SUNDRY APPROVALS AI k Oil & Gas Cons. Commission 20 MC 25 280 as a 1. Type of Request: Abandon 0 Alter casing 0 Change approved program 0 2. Operator Name: Chevron Alaska 3. Address: PO Box 196247, Anchorage, AK, 99519-6247 Suspend 0 Repair well 0 Pull Tubing 0 - Operational shutdown 0 Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: Development 0 Stratigraphic 0 Perforate 0 Waiver LJ Stimulate 0 Time Extension 0 Re-enter Suspended Well 0 5. Permit to Drill Number: Exploratory 0 201-046 v Service 0 6. API Number: 50-733-20157-02 V, Other 0 7. If perforating, closest approach in pool(s) opened by this operation to nearest property line where ownership or landownership changes: Spacing Exception Required? Yes 0 9. Property Designation: l1/" ADLß'117 IS7ï'J,..- /';¡.I'6·O 12. 8. Well Name and Number: Total Depth MD (ft): 15,485'. Casing Structural Conductor Surface Intermediate Production Liner 3,065' 4-1/2" Perforation Depth MD (ft): Perforation Depth TVD (ft): Total Depth TVD (ft): 9,737' - Length ./ No 0 K-13RD2 10. KB Elevation (ft): 11. Field/Pool(s): ./ 100' AMSL McArthur River Field, Hemlock PRESENT WELL CONDITION SUMMARY Effective Depth MD (ft): Effective Depth TVD (ft): 15,485' 9,737' Plugs (measured): nla Junk (measured): nla Collapse 7" MD TVD 5,011' 4,182' 8,707' 7,163' 12,430' 9,657' 15,385' 9,741' Burst Size 4,976' 8,762' 3,943' 13-3/8" 9-518" 2,730 psi 6,870 psi 8,160 psi 1 ,130 psi 4,760 psi 7,020 psi nla nla Packers and SSSV Type: Baker 7" Model F perm pkr Tubing Size: Tubing Grade: 4-1/2" L-80 Packers and SSSV MD (ft): 12,200' 7,780 psi 6,350 psi Tubing MD (ft): 8,350 13. Attachments: Description Summary of Proposal [2JJ Detailed Operations Program 0 BOP Sketch 0 15. Estimated Date for 4/21/2007 Commencing Operations: Date: 14. Well Class after proposed work: Exploratory 0 Development 16. Well Status after proposed work: Oil 0 - Gas 0 WAG 0 GINJ 0 0 , Service 0 0 Abandoned 0 0 WDSPL 0 17. Verbal Approval: Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name Timothy Brandenburg Title Drilling Manager Plugged WINJ Contact Jim Rose, 907-263-7637 Signature 7..--z;;;:<;( Ohone ~/'¿l 907-276-7600 Date ~f ~ }} _.. D-+ ",--.j //~J COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (~,- 115 Plug Integrity 0 BOP Test .~ Mechanical Integrity Test 0 Location Clearance 0 Other: ~aoo~\ ~V ~\-. c..cf'-\-c.,.c\--L"S~<¿C.\~- ÇO"o ~a\> \c::A·~\~~~. ~O ~\O ~ ~ "> \- N)\ ~~<ê '8", ~,,~ 'J i'-.O C- \<ëCJ.'^I.)Ù.\- Ö __ ~ « Mcl"'t>..\ \ "S, S,_,e,' Fonn R",,;,.., W.O,--\ /'í: r liMlss.,.....",,:::.riIO APPROVED BY ~ Approved by: { ~ ~~ ~n. THE COMMISSION Date: 4-1'l,ð 7 Form 10-403 Revised 06/2006 0 Ii'I t;W ~ I APR 20 2007 ~ *~bmitin~cat~/8.Dr Re: TBU K-13RD2--drawing attached F\-O~(o . Thanks for the comments Jim. When a short summary of the planned operations is provided, I normally have to "read in" some ofthe operational steps and then that prompts some questions. I can appreciate the challenge to provide a short summary that gives sufficient detail with out going into every torque value or the make up of every fishing assembly. Call or message with any questions. Tom Maunder, PE AOGCC Rose, Jim -Contractor wrote, On 4/17/2007 4:36 PM: Plans to perforate the tubing on K-13 and put the well on gas lift were under way when I wrote the sundry. It is on gas lift now. When I summarize an operation, I don't always include the same steps. These are very basic operational summaries. I prepared the sundry for k-12 months ago. Sorry omit that step on K-13. We would not, of course, start operations without blowing down the well (BTW blowing down the well is step no 1 in Pre Job Planning on in the detailed procedure given to the foreman) . Jim -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Tuesday, April 17, 2007 3:47 PM To: Rose, Jim -Contractor Subject: Re: TBU K-13RD2--drawing attached Sorry about that. Is K-13RD2 presently on gas lift? the K-12RD procedure mentions blowing down the well. operating, I'd expect the procedures to be similar. Thanks, Tom I only ask since If both wells are Maunder wrote, On 4/17/2007 3:40 PM: Sorry for the proposed start date? Jim, I am reviewin the application gett Has the equipment moving 1. Will the ri up largely be similar been used before and the line lagram dated Dec 7, 2004 (att 2. You d not propose a BOP test pressure. Ling into the file 3000 p . was the test pressure used last time. 3. Þ your choke diagram, there is a "new line". It ears to be a Þ1Pass line located at the top of the drawing. Would you omment 4/18/2007 7:29 AM 10f2 Re: TBD K-13RD2 . . Thanks Jim. As I looked at the file for K-12RD, I found the choke drawing you have included. It appears that a lot of the approvals to employ the hydraulic equipment were done for work in that well. Plan on having your Company Man contact the Inspectors for the BOP test. Since this is the first rig up in a while we will likely be out for a witness. It would be appreciated if a shell test could be conducted on the equipment prior to calling the Inspector out. Call or message with any questions. Tom Maunder, PE AOGCC Rose, Jim -Contractor wrote, On 4/1712007 4: 11 PM: Tom see below for answers.. Jim Jim, I am reviewing the proposed workover application. Sorry for the application getting misplaced. Is 4/21 still the proposed start date? nope..Jooks like we wiJJ be delayed until May 3 to start rigging up. Has the equipment started moving to the platform? Not yet. 1. Will the rig up largely be similar to what has been used before and the line diagram dated Dee 7, 2004 (attached)? To my knowledge, the configuration is genera!]y the same (I wasn't here at that time). I think we wiU use a different brand BOP stack and Inaybe a couple other sma!! differences. In any case. it wiJJ meet AOGCC requirements. 2. You do not propose a BOP test pressure. Looking into the file 3000 psi was the test pressure used last time. 3000 psi is what I propose as a test pressure. Although the stack is shown in a "3000 psi configuration", I faded to mention it. 'T'hanks for pointing that out. 3. On your choke diagram, there is a "new line". It appears to be a bypass line located at the top ofthe drawing. Would you comment please? According to my understanding, this is thc same manifold that is always used on the king ESP workovcrs and the line is a panic line that vents straight up. 10f2 4/18/20077:33 AM Re: TBU K-13RD2 . . 4. Will the operations be conducted according the general ESP workover procedure developed after the workover incident a few years back? Same genera] procedure. Chevron continues to make efforts to improve procedures that "vill minimize exposure to problems. Thanks in advance. I look forward to your reply. Tom Maunder, PE AOGCC 20f2 4/18/20077:33 AM . t . . Chevron =- Timothy C Brandenburg Drilling Manager Union Oil Company of California P.O. Box 196427 Anchorage, AK 99519-6247 Tel 907 263 7657 Fax 907 263 7884 Email brandenburgt@chevron.com March 30, 2006 Commissioner Alaska Oil & Gas Conservation Commission 333 W. ih Avenue Anchorage, Alaska 99501 Re: King Salmon Platform, Well K-13RD2, PTD 201-046 RECE\VED APR. 0 4 2007 Alaska Oil & Gas Cons. commission Anchorage Dear Commissioner, / Chevron intends to work over the above referenced well to replace a failed ESP. Attached is a Plan of Operations, BOPE information, current well sketch, and form 10-403 in duplicate. Please review and approve the Application for Sundry Approvals at your earliest convenience. Please contact Jim Rose at 907-263-7637 if you have any questions. Sincerely, ~c¿9 Timothy-G: Brandenburg Drilling Manager Attachment: BOP Sketch Choke Manifold Sketch K-13RD2 ESP Replacement Plan of Operations Current Well Sketch Form 10-403 in duplicate Cc: File Union Oil Company of California I A Chevron Company Page 1 of 1 Chevron -= . King Salmon Platform Well K- 13RD2 ESP Replacement Workover 2007 Basic Plan of Operations 1. MIRU Cudd HWOU over K-13R02. 2. Install and test BOPE. 3. TOOH with failed ESP completion. 4. PU OP, TIH and set RTTS. Test to 1000 PSI. TOOH. 5. Break and hang BOP stack. 6. Repair tubing head. 7. Nipple up BOP stack and test. 8. TIH and recover RTTS. TOOH. 9. Run new ESP completion. 10. NO BOPE, NU tree assembly and test. 11. ROMO Cudd HWOU. A 2 1/16" 5M HCR Valve B 21/16" 5M Manual gate valve C 2 1/16" 5M Manual gate Kill line D 21/16" 5M Manual gate Kill line E 3 1/8" 5M Target Tee F 21/16" 5M Target Tee G 13 5/8" 5M x 13 5/S" 5M # 13 Hub TQP Qfdrilldeck 3/31/2007 C:\Documents and Settings\roseji\Desktop\K-13\Equipment Info\Kíng BOP Stack .xls JAR K-13R 3 1/8" 5000 PSI Choke Manifold 2" to Production Separator or Gas Buster Bypass 5M National Ball Valves IÞ 2", 5M, Flanged, Hose From Choke Line Side of Drilling Spool · , RKB to TBG Hanger = 33.77' WT GRADE CONN 13-3/8" 61.0,68.0 1-55 BTC 9-5/8" 47 N-80, S-95 BTC 7" Lnr 29 L-80 KC BTC 4-1/2" 12.6 1-55 Hydri! Blank Lnr 511 4-1/2" 11.6 1-55 Hydri! Slotted Lnr 511 12.6 L-80 od. C 3 9-5/8" Window at 8707' MD, 30 deg hole angle 4-1/2" SFO-2 GLMwl Latch 4-1/2" SFO·2 GLMw/RKLatch 4-1/2" SFO-2 GLM wI RK. Latch 4-1/2" GLM wI RK. Latch 4-1/2" SFO-2 GLM wI RK. Latch 4-1/2" SFO-2 GLM wI RK Latch 4-1/2" SFO-2 GLM wI RK Latch XN Nipple Centrilift ESP (69 Stage HC12500 Pump 800 h HMI Motor Phoenix gauge Baker 7" Model "F" perm. pack;er "X" Nipple NO. 2. 3. 3.833" 3.833" 3.833" 3.833" 3.833" 3.833" 3.833" 3.752" 4. 5. 6. 7. 8. 8,412' 12,200' 12,249' 12,283' 12,320' 2.813" 3.062" 4-1/2" top (ZXP Packer) 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 0" slots/ft .-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-.-. -'-'-'-'-'-'-'-'-'-'-'-'-'-'-'-'-'-'-' 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.750 @ 13413' ECP (inflated with mud) at 13696' MD (9774' TVD) TD = 15485' MD/9737' TVD with blank 4-1/2" above \\Anc909ntshare 1 \Groups\DRILLlNG\Platforms\King_ Salmon\K-13RD2\~~~~~1?~¥ßRD2 Actual Schem Jun06..doc REVISED: 6/8/06 DRAWN BY: JHM STATE OF ALASKA AL. OIL AND GAS CONSERVATION COM_ION REP T OF SUNDRY WELL OPEI~10NS 1. Abandon Repair Well Operations Alter Casing 0 Pull Tubing Q , '"'- ~Cïïã-nge Approved Program 0 Ope rat. Shutdown 0 2. Operator Union Oil Company of California Name: 3. Address: PO Box 196247, Anchorage, AK 99519 Plug Perforations Perforate New Pool 0 Perforate 0 4. Current Well Class: Development Q Stratigraphic 0 Exploratory 0 Service 0 Stimulate Other,J iiiRun ESP . tit Waiver 0 Time Extension 0 :- Re-enter Suspended Well 0 9 5. Permit to Drill Number: Q:O C :Þ Ci) Z. ~ I» g n Þ'" ... 0 - I» ~ ~ 7. KB Elevation (ft): RKB to Tubing Head 33.77' 8. Property Designation: King Salmon Platform/Cook Inlet A-'b> L. ,,77Z ÞJ' ,z.¡.ob 11. Present Well Condition Summary: 201-046 6. API Number: 50-733-20157-02 .. 9. Well Name and Number: K-13RD2 10. Field/Pool(s): McArthur River Field. Hemlock Fm. Total Depth measured 15,485 true vertical 9,737 . feet feet Plugs (measured) n/a Junk (measured) n/a Effective Depth measured 15,485' true vertical 9,737 feet feet ,"j Casing Structural Conductor Surface Intermediate Production Liner Length Size MD 3,065' 4-112 " 15,385' TVD Burst 4,182' 2,730 psi 7,163' 6,870 psi 9,657' 8,160 psi 9,741' 7,780 psi Collapse 4,976' 8,762' 3,943' 13-3/8" 9-5/8" 7" liner 5,011' 8,707' 12,430' 1,130 psi 4,760 psi 7,020 psi 6,350 psi Perforation depth: Measured depth: 12,580' to 12,600, Horizontal Slotted Liner True Vertical depth: 9,726 to 9,772' RBDMS 8Ft ,¡UN 2 1J 2DD6 Tubing: (size, grade, and measured depth) 4-1/2", 12.6#, N-80 @ 8,321' Packers and SSSV (type and measured depth) n/a 12. Stimulation or cement squeeze summary: Intervals treated (measured): Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations X c....\-~ ~ 5' ~ \-4./ '0\0\ \ \ ,Ö \ / \ irQ ~ ~ ( >- Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure 125 4,180 1,240 442 9,360 20 15. Well Class after proposed work: Exploratory 0 Development Q 16. Well Status after proposed work: OiIQ· Gas 0 WAG 0 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. n/a \.:to \<. ~oQ '0 ~ \-c ('Çc . JCo \--\(~~\ <6 ,"\ ÿ,. I \ Treatment descriptions including volumes used and final pressure: 13. 4/9/2006 Oil-Bbl 476 850 Tubing Pressure 180 60 Service 0 GINJ 0 WINJ 0 WDSPL 0 Sundry Number or N/A if C.O. Exempt: 306-123 Contact Larry W. Buster 263-7853 Signature Title Drilling Manager Phone 907-276-7600 Date 6/14/2006 evised 04c)°R I GIN A L AFE 164796 Submit Original Only ~ ~'ZI·ð' :¿ o/S*~ Primary Job Type ESP Jobs QC Eng Daily Operations 5/25/2006 00:00 - 5/26/2006 00:00 Operations Summary RlU Slickline. RIH to shift open sliding sleeve. unable to shift, POOH. RID slickline. 5/26/2006 00:00 - 5/27/2006 00:00 Operations Summary Off load boat. Set BPV. N/D tree and flowline. 5/27/200600:00 - 5/28/2006 00:00 Operations Summary N/U BOPE and test to 3000/250 psi. RlU Cudd HWOU. 5/28/200600:00 - 5/29/2006 00:00 Operations Summary Pull BPV. RlU E-Line and RIH. Punch holes in tubing from 12117'-123'. Circulate annulus with 3% KCL FIW. 5/29/200600:00 - 5/30/200600:00 Operations Summary Hold drills. Pump 70 bbl sized salt LCM pill. Circulate well with 3% KCL FIW. 5/30/200600:00 - 5/31/200600:00 Operations Summary Pull 4-1/2" tubing and LID. 5/31/2006 00:00 - 6/1/2006 00:00 Operations Summary Pull and LID 4-1/2" and 3-1/2" tubing. M/U ESP assembly. 6/1/200600:00 - 6/2/2006 00:00 Operations Summary Finish M/U of ESP. RIH with ESP. 6/2/2006 00:00 - 6/3/2006 00:00 Operations Summary RIH with ESP. 6/3/200600:00 - 6/4/200600:00 Operations Summary M/U tubing hanger and land same. Install BPV. RID Cudd HWOU. 6/4/2006 00:00 - 6/5/2006 00:00 Operations Summary Continue RID of Cudd HWOU. N/D BOPE. 6/5/200600:00 - 6/6/2006 00:00 Operations Summary N/U and test tree and hanger to 5000 psi. Release unit. Chevron . Tradin.ay Unit King Salmon Platform Well # K-13RD2 Actual Completion 6/5/06 CASING AND TUBING DETAIL SIZE WT GRADE CONN ID TOP BTM. 13-3/8" 61.0,68.0 J-55 BTC 12.415" 35' 5,011 ' 9-5/8" 47 N-80, S-95 BTC 8.681" 35' 8,707' Window 7" Lnr 29 L-80 KC BTC 6.184" 8,487' 12,430' 4-1/2" 12.6 J-55 Hydril 3.875" 12,320' 13,779' Blank Lnr 511 4-1/2" 11.6 J-55 Hydril 3.875" 13,379' 15,385' Slotted Lnr 511 12.6 L-80 Mod. 3.958" 35' 8,321 ' BTC RKB to TBG Hanger = 33.77' 3 9-5/8" Window at 8707' MD, 30 deg hole angle NO. 1. GLM #1. GLM #2. GLM #3. GLM #4. GLM #5. GLM #6. GLM #7. 2. 3. 4. 5. 6. 7. 8. 8 JEWELRY DETAIL ID Item 33.77' FMC Tubin Han er Cameo 4-112" SFO-2 Gaslift Mandrels. 2,433' 3.833" 4-1/2" SFO-2 GLM wi RK Latch 4,412' 3.833" 4-1/2" SFO-2 GLM wI RK Latch 5,742' 3.833" 4-1/2" SFO-2 GLM wi RK Latch 6,298' 3.833" 4-1/2" SFO-2 GLM wi RK Latch 6,791' 3.833" 4-1/2" SFO-2 GLM wi RK Latch 7,283' 3.833" 4-1/2" SFO-2 GLM wI RK Latch 7,741' 3.833" 4-1/2" SFO-2 GLM wi RK Latch 8,278' 3.752" XN Nipple 8,320' Centrilift ESP (69 Stage HC12500 Pump & 800 h HMI Motor) Phoenix gauge Baker 7" Model "F" perm. packer "X" Nipple Re-entry guide 4-1/2" Liner top (ZXP Packer) 8,412' 12,200' 12,249' 12,283 ' 12,320' 4.000" 2.813" 3.062" 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD Slotted Liner at Near-Horizontal in HB-2 4-1/2" L-80, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft ._._._._._._._._._._._._._._._._._._._.-£1 _._._._._._._._._._._._._._._._._._._._~ ECP (inflated with mud) at 13696' MD (9774' TVD) with blank 4-1/2" above and two blank joints below C:\Documents and Settings\lbuster\Local Settings\Temporary Internet Files\OLK2B\K13RD2 Actual Schem Jun06.doc REVISED: 6/8/06 DRAWN BY: JHM 1. Operations Abandon Repair Well Performed: Alter Casing D Pull Tubing D Change Approved Program D Operat. Shutdown 0 2. Operator Union Oil Company of California Name: _ STATE OF ALASKA e RECEIVED AlA~ Oil AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS JUN 0 5 2006 Alaska Oil & Stimulate Other WaiverD Time Extension Re-enter Suspended Well 0 5. Permit to Drill Number: Plug Perforations Perforate New Pool Perforate 4. Current Well Class: Development 0 Stratigraphic D D 0' 7. KB Elevation (ft): RKB to Tubing Head 33.77' 8. Property Designation: King Salmon Platform, Cook Inlet II þ(... IS 712 11. Present Well Condition Summary: .JÞ ,.(,.OI., ExploratoryD 201-046 . ServiceD 6. API Number: 50-733-20157-02 9. Well Name and Number: K-13RD2 10. Field/Pool(s): McArthur River Field/Hemlock 3. Address: PO Box 196247, Anchorage, AK 99519 Total Depth measured 15,485' feet true vertical 9,737' feet Effective Depth measured 15,485' feet true vertical 9,737' feet Casing Length Size Structural Conductor 4,976' 13-3/8" Surface 8,762' 9-5/8" Intermediate 3,943' 7" Production Liner 3,065' 4-1/2" Plugs (measured) n/a Junk (measured) n/a MD TVD 5,011' 4,182' 8,707' 7,163' 12,430' 9,657' 15,385' 9,741' Burst Collapse 2,730 psi 6,870 psi 8,160 psi 1,130 psi 4,760 psi 7,020 psi 7,780 psi 6,350 psi Perforation depth: Measured depth: 12,580 to 12,600', slotted liner 13,779 to 15,348' v s:) í~ True Vertical depth: 9,725 to 9,732', slotted liner 9,737' Tubing: (size, grade, and measured depth) 4-1/2", N-80 @ 8,393'; 3-1/2", N-80 @ 12,283'; Packers and SSSV (type and measured depth) 1. Baker 4-1/2" TRDP-1A SSSV @ 348' 2. Baker 7" Model F perm pkr @ 12,200' 12. Stimulation or cement squeeze summary: Intervals treated (measured): n/a RBDMS BFL ,IUN 0 8 2006 Treatment descriptions including volumes used and final pressure: 13. Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Oil-Bbl 476 Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 125 4,180 1,240 Tubing Pressure 180 same same 15. Well Class after proposed work: Exploratory 0 Development 0 . 16. Well Status after proposed work: Oi10· Gas D WAG D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. same same same Service 0 x GINJ D WINJ 0 WDSPL D Sundry Number or N/A if C.O. Exempt: 306-140 Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Signature Title Drilling Manager Phone 907-276-7600 Date r:;, -2~ I G , N A rE R6001 . Submit Original Only i1t.! (~ ..dP ~';~4" Primary Job Type Perforating Jobs AFE No. QC Eng Daily Operations 5/8/200600:00 - 5/9/2006 00:00 Operations Summary RU & Spot Eline. PT BOPE to 2450 psi. RIH w/ 20' PJ Omega gun and roller bar(s) to 12,625'. GAMMA Ray off scale. Unable to tie-in. PU to 11,100'. Sent log to town for interpetation. 5/9/200600:00 - 5/10/2006 00:00 Operations Summary . Received new perf depths of 12,560' to 12,600'. RI worked gun down. Perforated 12,580' to 12,600'. POOH. Stuck at profile nipple @ 12,249' for a couple of hours. worked free. POOH. Decision not to continue with perf job. Found one roller off on roller bar on top of gun. RD Eline. Demobe same. RKB to TBG Hanger 33.77' 1 9·5/8"~Ú1dovv at 8707'MD, 30 deg hole angle 6 \ 7" 29 4·1/2" 12.6 4·1/2" 11.6 Tubing: 4·1/2" 12.6 3·1/2" BTC BTC BTC 35' 4711 ' 1 2 3 4 5 6 7 8 9 10 11 12 13 8286' 8818' 9348' 9941' 10694 ' 11380' 12100' L·80 KC buttress 8487' L·80 11.6 Hyd 511 blank liner 12320' L·80 Hyd 511 sltd liner ~13779' N-80 N-80 BTC BTC 8393' 34' 8393' 1. 4-1/2" TRDP·IA SSSV 2. 8393' 4-1/2" x 3-1/2" crossover 2a 11151' Baker 3~ 1/2" CMU sliding sleeve 3. 12200' dpm Baker 7" Model F perm packer 4. 12249' "x" nipple(ID=2.813") 5. 12283' 3·1/2" tbg tail, ~LEG 6 12320' Top liner with 12580' 12600' GLM withR·2 4-1/2" SFO-2 GLM with 4-1/2" SFO-2 GLM with 4-1/2"SFO-2 GLM 4·1/2" SFO-2 GLMwith 4·1/2" SFO·2 GLM with 4-1/2" SFO·2 GLM with 3·1/2" SFO-2 GLM with 3·1/2" SFO~2GLM 3-1/2" SFO·2 3-1/2" SFO·2GLMwithR-2 3-1/2" SFO-2 GLM with R-2 3·1/2" SFO·2 GLM with R·2 2.5" Pl 6 spf 7" !iner cemented at 12,430' MD/ 9660' TVD, +/. 57 deghole 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MÐl9737' TVD K13RD2 schematic .'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'-'.'.'q ECP(inflated with mud) at 13696' MD (9774' TVD) with blank 4-1/2" above and two blank joints below REVISED: OS/25/06 9:51 AM e Debra Oudean Technologist &ion Oil Company of California 909 W. 9th Avenue Anchorage, AK 99501 Tele: 9072637889 Fax: 9072637828 E-mail: oudeand(â)chevron.com Chevron May 16, 2006 To: AOGCC Helen Warman 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 201-046 507332042702 TBU K- COMPLETION RECORD 5 INCH 5/9/06 8370-12601 13RD2 2.5 HSD OMEGAS 6SPF, 60 DEGREE PHAZING 1 pds SCANNED JUN 1 ~1 20CB Please acknowledge receipt by signing and returning one copy ofthi~,Ç.~~~~~07 2637828. ...;:~~ Anchorage I Received By: I Date: e e MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: ,~> J. R !-/ 1m egg i\f2d¡ P. I. SupeNisor ( ?fcc DATE: May 12, 2006 .'... ..f~ ...Ii>.~~H:':1 ~v,.~r~:" ~~~,.-/ ...~ 1:'; " t',;'! SUBJECT: No Flow Test Trading Bay Unit King Salmon Platform Well # K-13RD2 Plb lO\-~ Mav 12.2006: I traveled to Chevron/Unocal's King Salmon Platform to witness a no-flow test on K-13RD2. FROM: John Crisp, Petroleum Inspector I arrived on the platform & began the no-flow test by verifying the SSSV was open. The master tree valve & swab valve were checked & in the open position. The Inner Annulus valve was closed & IA was @ 0 psi. The Outer Annulus valve was open & OA was stable with 250 psi. Armor-Flo gas meter was installed on the tubing. Armor-Flo meter model number is 3461-03TO, SIN 031189. Meter range is 0-18 SCFHx100. The meter had a 1" open-end hose attached down stream of meter to open top container. During the four-hour period I monitored K-13RD2 there was a very small amount of gas released thru meter & 1" hose. The small amount of gas would not register on the gas meter. The small amount of gas flow was effectively shut off when hose was placed 1 inch deep into a 5 Gal. Pail of fresh water. K-13RD2 was completed with Horizontal Slotted Liner; new perforations were added from 12,600 MD to 12,580 MD. Well was produced to clean perf's before no-flow test was performed. Summary: I witnessed a no-flow test on TBU King Salmon K-13RD2. The Operator was made aware my SupeNisor would make a No-Flow Determination. Verbal Approval was given to produce well as No - Flow. Attachments: K-13RD2 as run 6-25-01 schematic. Non-Confidential -r ~ \ . 'OJ J..-1" n [)fk '. n ~ ¡) I~ '-, -:\ , l I·, -~ \ -, I Nv \ I.{..q] ~i:r'::<.iVCuL ,.e..,v\--,<.> X,,'\"- -t'.::o\.HOúc.\.. J l\C<.c CtlltvJvv\ -¡.(-.¿. 1tMiJ\JLl 65- sSS V ',..1 No-flow King Samon Pit. K-13RD2 G-26 05-12-06 jc-l.doc e e I did not receive the attachment. Could you send the Ops Sum. to Jim Regg with the K13RD2 as run 6-25-01 schematic (Revised: 01109/03 )? This will complete my No-Flow report. Thanks for your help. John Crisp Walsh, Chantal-Petrotechnical wrote: John, Our DSM, Dave Smith, contacted us looking for the final perforation intervals for the May 8 and 9, 2006 add perforation job on the K-13RD2 well. The interval perforated was 12,580 - 12,600. You will find attached the operations summary for the job. Please contact me if you have any questions. Chantal Walsh I of 1 5/17/2006 8:22 AM Primary Job Type Perforating Jobs Prima;Y-jób TYPe- Perforatin.L.____. ____.. .____'_.'·__U._.._" A IIUWI ,..I.5_0-733-201~~:22u__._ ___ u__J~g~gg,! 8772 ¡Primary WeHbore Affected I Main Hole K-13RD2 ,. -- ¡Jõbc::ã¡egoryU" ÎAF-END: -¡Obiéctlvã- JS>~plet~~'2 ._ ,.~~[)::_u ------_._--_.__..~--~- -.-".--'.-- ------.-.------ .-- ¡Actual Start -- TÊrοfoate' - -!ÕC-EJ1gfn-ëer,_.-n L5/Y2~~~_u_._.__.,.L__.____ -- ----- --~. ".-- Daily Operations 518/2006 00:00 - 519/2006 00:00 QpË!rat1Ons -summar;' -------------- RU & Spot Eline, PT BOPE to 2450 psi RIH wi 20' PJ Omega gun and roller bares) to 12,62.5' GAMMA Ray off scale Unable to tie-in. PU to 11,100'. Sent log to town for interpetation ------------.----- _._------~._._-_.---~---..-.- 5/9/2006 00:00 - 5/10/2006 00:00 Operations Surñmary-----~ ---.-----.---.--. -.----...-- --. ---.---.--- ---- .-----------. Received new perf depths of 12,560' to 12,600'. RI worked gun down. Perforated 12,580' to 12,600', POOH. Stuck at profile nipple @ 12,249' for a couple of hours. worked free, POOH. Decision not to continue with perf job, Found one roller off on roller bar on top of gun, RD Eline, Demobe same. ._~_._._------- " - - -------_.___-0-__"·_-.- e UNOCALfi> RKB to TBG H~ger = 33.77' 1 9-5/8" Window at 8707' MD, 30 deg hole angle 6 SIZE WT 13-3/8" 61&68 9-5/8" 47 9-5/8" 47 e Trading B~y Unit King Salmon Platform Well # K-13RD2 As run 6/25/01 CASING AND TUBING DETAIL GRADE CONN TOP J-55 BTC 35' N-80 Class B BTC 35' S-95 BTC 4711' 7" 29 4-1/2" 12.6 4-1/2" 11.6 Tubing: 4-1/2" 12.6 3-1/2" 9.2 L-80 KC buttress 8487' L-80 11.6 Hyd 511 blank: liner 12320' L-80 Hyd 511 slotted liner-13779' BTC BTC N-80 N-80 34' 8393' JEWELRY DETAIL Pii â I-C4~ BOTTOM 5011' 4711' 8707' window 12430' 13779' 15385' 8393' 12283' NO. Depth Item 1. 348' Baker 4-1/2" TRDP-IA SSSV (ID = 3.813") 2. 8393' 4-1/2" x 3-1/2" crossover 2a 12151' Baker 3-1/2" CMU sliding sleeve 3. 12200' dpm Baker 7" Model F perm packer 4. 12249' "x" nipple (ID=2.813") 5. 12283' 3-1/2" tbgtail, WLEG 6 12320' Top of 4-1/2" liner with ZXP Liner top packer Gas Lift Information 1 2471' 4-1/2" SF0-2 GLM with R-2 valve and RK latch 2 4909' 4-1/2" SF0-2 GLM with R-2 valve and RK latch 3 6106' 4-1/2" SF0-2 GLMwithR-2 valve andRK latch 4 6653' 4-1/2" SF0-2 GLMwithR-2 valve andRK latch 5 7197' 4-1/1" SFO-2 GLMwithR-2 valve andRKlatch 6 7741' 4-1/2" SF0-2 GLMwithR-2 valve andRKlatch 7 8286' 4-1/2" SFO-2 GLMwith R-2 valve andRKlatch 8 8818' 3-1/2" SF0-2 GLMwithR-2 valveandRKlatch 9 9348' 3-1/2" SF0-2 GLMwithR-2 valve andRKlatch 10 9941' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 11 10694' 3-1/2" SF0-2 GLM with R-2 valve and RK latch 12 11380' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 13 12100' 3-1/2" SFO-2 GLM with R-2 orifice and RA latch 7" liner cemented at 12,430' MD/ 9660' TVD, +/- 57 deg hole 90 Deg beDy at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TV» K13RD2 as run 6-25-01 schematic Slotted Liner at Near-Horizontal in HB-2 4-1/2" L-80, 11.6# tbgwith 2-1/2" x 1/S"slots, 16 slots/fl ._._._,_._._._._,-,-,_._,-,_._._._._,_.~ _._._._._._'_._._._._._'_._'-'_._._._'-~ ECP (inflated with mud) at 13696' MD with blank 4-1/2" above and two blank joints below REVISED: 01/09/03 1:47 PM DRAWN BY: TAB e e ('ii1!., '¡ '\ \.- ','\ ru1'\j ~ p i.',.~.· ~L ~ FRANK H. MURKOWSKI, GOVERNOR A.,ASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Timothy Brandenburg Drilling Manager Union Oil Company of California PO Box 196247 Anchorage, AK 99519 '....g. h !J\.í~íEI(\ ß '.'·h"""!~,,~ç,,, ," ;:~ \ ~ D v¡b dP Re: McArthur River Field, Hemlock Oil Pool, Trading Bay Unit K-13RD2 Sundry Number: 306-140 Dear Mr. Brandenburg: 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. When providing 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 thisll day of April, 2006 Encl. STATE OF ALASKA ALA.IL AND GAS CONSERVATION COMMI_N APPLICATION FOR SUNDRY APPRðf'ALS 20 MC 25 280 1. Type of Request: Abandon U Alter casing 0 Change approved program 0 2. Operator Name: Union Oil Company of California 3. Address: PO Box 196247, Anchorage, AK 99519 7. KB Elevation (ft): RKB to Tubing Head 33.77' 8. Property Designation: King Salmon Platform/Cook Inlet 11. Suspend U Repair well 0 Pull Tubing 0 kr~ f'{h~ /1'1<:; Operational shutdown U Plug Perforations 0 Perforate New Pool 0 4. Current Well Class: PerforateL:J Waiver ~ Stimulate 0 Time Extension CE- Re-enter Suspended Well Cb 5. Permit to Drill Nllñiher: J> ./ "W v 201-046' ? CJ.! Xi ;::: C» 6.APINumberêf ~ 50-733-20157-ci ~ Qr.) (I);" "-' C,; Q 3 3 ....., (,;. õ' :::I Development Stratigraphic o o Exploratory 0 o Service 9. Well Name and Number: K-13RD2 10. Field/Pools(s): PRESENT WELL CONDITION SUMMARY McArthur River Field/Hemlock Total Depth MD (ft): 15,485' Casing Structural Conductor Surface Intermediate Production Liner Total Depth TVD (ft): 9,737' Length Size OtherU '']1 m o !.!.! < IT! o Effective Depth MD (ft): 15,485' Effective Depth TVD (ft): 9,737' Plugs (measured): n/a Junk (measured): n/a Collapse 13-3/8" 5,011' 9-5/8" 8,707' 7" 12,430' 4-112" 15,385' 4,976' 8,762' 3,943' 3,065' Packers and SSSV Type: Date: MD TVD Burst 4,182' 7,163' 9,657' 2,730 psi 6,870 psi 8,160 psi 1,130 psi 4,760 psi 7,020 psi 9,741' 7,780 psi 6,350 psi Tubing Grade: ¡Tubing MD (ft): N-80; N-80 8,393'; 12,283' 1. 348' 2. 12,200' 13. Well Class after proposed work: , Perforation Depth MD (ft): rperfOration Depth TVD (ft): Tubing Size: n/a n/a 4-1/2"; 3-1/2" 1. Baker 4-112" TRDP-1A SSSV 2. Baker 7" Packers and SSSV MD (ft): Model F perm pkr 12. Attachments: Description Summary of Proposal 0 Detailed Operations Program 0 BOP Sketch 0 14. Estimated Date for Commencing Operations: 16. Verbal Approval: Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Steve Tyler 263-7649 Printed Name Timothy C. Brandenburg Title Drilling Manager Signature ~ t" =:::z7; eft . / ¿.-Phone 907-276-7600 Date '--I - (7-- 0 C- 6 ¿~>" COMMISSION USE ONLY Exploratory 0 Development 15. Well Status after proposed work: 5/1/2006 Oil 0 'Gas 0 WAG 0 GINJ 0 o Plugged WINJ o o Service o Abandoned o o WDSPL Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 30Ce - 14D Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: \S \)V ~~~\~ ~~\- Ç? ~".. d~ ~ êJS""\ d-.~ \ , RBDMS 8Ft APR 2 Ú 2D06 $,""'"'''' Fo~ R",;.." 4C:;:>'ll ~ Approved by: (. U A COMMISSIONER l./ '-Y ~~/ Form 10-403 Revised 07/2005 0 R GINA L Date: 4- - /'1,06 .f.b ,¡. /8 'DG::. Submit in Duplicate ~ '11/06 APPROVED BY THE COMMISSION e e K-13RD2 King Salmon Platform Add Perfs to the HBl Sand MI/Spot and RU Eline. Test BOPE's. PUMU Well Tech Tractor and Gun Assy. RIH PerfHBl. POOH. Shut Down for Night. PUMU Well Tech Tractor and Gun Assy. RIH PerfHB 1. POOH. RD Eline Unit. Package for Demobe. RKB to TBG Hanger = 33.77' BTC Class B BTC BTC 8701' window L-80 KC buttress 8481' L-80 11.6 Hyd 511 blank liner 12320' L-80 Hyd 511 slotted liner~13779' T' 29 4-112" 12.6 4-112" 11.6 Tubing: 4-112" 12.6 3-1/2" 9.2 13779' 8393' 12283' 34' 8393' BTC BTC N-80 N-80 1. 348' 2. 8393' 2a 12151' Baker3-1I2" CMU sliding sleeve 3. 12200' dpm Baker 7" Model F perm packer 4. 12249' "x" nipple (ID=2.813") 5. 12283' 3-112" tbg tan, WLEG 6 12320' Top of4-l/2" liner with Liner top packer 2471 ' 4909' 6106' 6653' 7191' 7741' 8286' 8818' 9348' 9941' 10694 ' 11380' 12100' 1 2 3 4 5 6 7 8 9 10 11 12 13 9-5/8" Window at 8701' MD, 30 deg hole angle 3 6 ............ T' liner cemented at 12,430' MD/9660' TVD, +/-57 deg hole .-.-.- -'-'-'-'-'-'-'-'-'-'-'-' .-.-.-.-.-.-.-.-.-. .-.-.-.-.-.-.- 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD ECP (inflated with mud) at 13696' MD (9774' TVD) with blank 4-112" above and two blank joints below REVISED: 04/17/06 2:30 PM K13RD2 as run 6-25-01 schematic FW: K-13RD2 add perf e e Tom, The Hemlock bench one sands to be perforated in the K-13RD2 well are: 12550' - 12590' (40' total) If you have any other questions, don't hesitate to get ahold of me. Chantal 263-7627 -----Original Message----- From: Thomas Maunder [rnailto:tom rnaunder@admin.state.ak.us] Sent: Wednesday, April 19, 2006 9:47 AM To: Steve Tyler Subject: K-13RD2 add perf Hi Steve, I am reviewing the sundry for adding perfs to K-13RD2. It is noted that you intend to perf bench 1 in the Hemlock. Could you provide some depth information as to where you plan to shoot and what interval length? Thanks, Tom Maunder, PE AOGCC 1 of 1 4/19/2006 1 :22 PM e ~1f~1fŒ lID~!Æ !Æ~ e FRANK H. MURKOWSKI, GOVERNOR AI1ASIiA. OIL AND GAS CONSERVATION COMMISSION 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Timothy Brandenburg Drilling Manager UNOCAL PO Box 196247 Anchorage, AK 99519 lD I"' 0 '+0 Re: McAurthur River Field, Hemlock Oil Pool, K-13RD2 Sundry Number: 306-123 Dear Mr. Brandenburg: t'.... ~~J 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. When providing 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 this.1: day ~~06 Encl. ~ 1)'7:$ 3/ '3/ (,..£ STATE OF ALASKA _ y_ RECEIVED ALA~ Oil AND GAS CONSERVATION COMM.ON P';',.;\ MAR 3 1 2006 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Alaska Oil & Gas Cons. Commission 1. Type of Request: Abandon U Alter casing D Change approved program D 2. Operator Name: Union Oil Company of California 3. Address: PO Box 196247, Anchorage, AK 99519 7. KB Elevation (ft): RKB to Tubing Head 33.77' 8. Property Designation: King Salmon Platform/Cook Inlet 11. Suspend U Repair well D Pull Tubing D Operational shutdown U Plug Perforations D Perforate New Pool D 4. Current Well Class: Perforate U Waiver Lßncnorage Other U Stimulate D Time Extension D ESP Conversion ~ Re-enter Suspended Well D 5. Permit to Drill Number: Development 0 Stratigraphic D Exploratory D 201-046... Service D 6. API Number: 50-733-20157-02 ~ 9. Well Name and Number: K-13RD2 . 10. Field/Pools(s): McArthur River Field/Hemlock PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): 15,485' , Casing Structural Conductor Surface Intermediate Production Total Depth TVD (ft): 9,737' ' Length Effective Depth MD (ft): 15,485' Effective Depth TVD (ft): 9,737' Plugs (measured): n/a Junk (measured): n/a Collapse Size MD TVD Burst 4,976' 8,762' 3,943' 13-3/8" 9-5/8" 7" 5,011' 8,707' 12,430' 4,182' 7,163' 9,657' 2,730 psi 6,870 psi 8,160 psi 1 ,130 psi 4,760 psi 7,020 psi Liner 3,065' 4-1/2" 15,385' Tubing Size: 4-1/2"; 3-1/2" 9,741' Tubing Grade: N-80; N-80 7,780 psi 6,350 psi Tubing MD (ft): 8,393'; 12,283' Perforation Depth MD (ft): n/a Perforation Depth TVD (ft): n/a Packers and SSSV Type: 1. Baker 4-1/2" TRDP-1A SSSV 2. Baker 7" Packers and SSSV MD (ft): 1.348' 2. 12,200' Model F perm pkr 12. Attachments: Description Summary of Proposal 0 13. Well Class after proposed work: Detailed Operations Program D BOP Sketch 0 Exploratory D Development 0 Service D 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 5/8/2006 Oil 0 Gas D Plugged D Abandoned D 16. Verbal Approval: Date: WAG D GINJ D WINJ D WDSPL D Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Timothy C. Brand~!1burg _... Title Drilling Manager Signature /-=r::;:::; c-/') /' "/Phone 907-276-7600 Date L.../ )7'" COMMISSION USE ONLY ~ Larry Buster 263-7853 ~-30-D,- Conditions of approval: Notify Commission so that a representative may witness Sundry Number: (7;{)1 () - 1 d- ~ Plug Integrity D BOP Test ~ Mechanical Integrity Test D Other: ~~S, ~'C)\:> ~(..'?\ G..~ ~\c:....'t'-~ Location Clearance D Sob"",""o! Fooo Reqo;rnd, l.\,OL ~ Approved by: ~ CO VC/ Form 10-403 Revised 07/20050 R 1 51 N A L RBDMS APPROVED BY THE COMMISSIOtt;;:. L APR 5 2006'..."'£,. Date: J.f~3,()b A 3'3(wO~ :f~it{~~'cate SIONER AFE 164796 Chevron === e e King Salmon Platform Well K-13RD2 ESP Conversion OBJECTIVE: Pull the existing single string gas lift completion and replace with an ESP completion. ' PROCEDURE SUMMARY: '\ "") ("\.a'\·\~'-L :s:~~\'~'C\oc~,- 1. Shut off gas lift gas and bleed pressure off annulus. Perform a No-Flow Test on K-13RD2.'; ~,\-K.<-5 '> 2. Circulate oil out of annulus and load well wi 3% KCL in Filtered Inlet Water. /ij:?M 3. Spot sized salt pill (if necessary) to manage losses and keep hole full while POH with tubing. :z; 4. Set BPV and NID tree on Well K-13RD2. N/U BOPE and CUDD HWOU. Test 13-5/8" BOPE ~\ (see attached diagram) to 250/3,000 psi. v 5. Verify well dead. Circ. well clean to verify no oil has entered the tubing or annulus. 6. POH wi gas lift completion. 7. Rill wi replacement ESP assembly (see attached proposed schematic). 8. Install BPV. RID CUDD HWOU. NID BOPE. N/U & test tree. 9. Install flow line and surface facilities. 10. Startup ESP and confirm it is functioning properly. AOGCC K-13RD2 ESP Workover Summary vI 1 of 1 March 29,2006 "" 9 Well Name: Field: API: Well Status: Well Type: Permit: RKB to TH: TD/TVD: Type Buttress Class BBTC Buttress KC Buttress Hyd 511 Blank Liner Hyd 511 Slotted Liner Tubin Size 4-1/2" 10 1 2 3 4 5 6 7 8 9 10 11 GLM with R-2 valve and RK latch 4-1/2" SFO-2 GLM with R-2 valve and RK latch 4-1/2" SFO-2 GLM with R-2 valve and RK latch 4-1/2" SFO-2 GLM with R-2 valve and RK iatch 4-1/2" SFO-2 GLM with R-2 valve latch 4-1/2" SFO-2 GLM with R-2 valve and RK latch 4-1/2" SFO-2 GLM with R-2 valve and RK latch X-Nipple ESP Assembly: HC 12,500, 800 HP Top of 4-1/2" liner with ZXP Liner top packer ECP filled with mud 11 Top (FT) Btm (FT) 35.00 35.00 4,711,00 8,487.00 12,320,00 13,779.00 Length 5,011.00 4,711.00 8,707.00 12,430.00 13,779.00 15,385.00 Btrn (FT) 8,350.00 Length (H) 8,316.00 Notes 90 degree dog belly at 13,000' MD. Max hole angle is 94.75 degrees at 13,413' Slotted lioer at near-horizontal in HB-2. 4-1/2" L-80, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft. I Revised By: IDED .. ~ Test Pressure: 250/3000 psi 3 111S"SM x 4111S"5M DSA Top Deck A 41/16" 5M Foster HCR Valve B 4 1/16" 5M Manual gate valve C 31/16" 5M Manual gate Kill line D 31/16" 5M Manual gate Kill line Gra lock Hub 55" 34" 27" ¡ 14" 10.90' 12.67' 't \$ \ þ. Bypass 2" 1502 Hook up to Production separator or poor-boy gas buster (if needed) Drain wI 1502 Bull plug 2" Dual Manual Choke Manifold 2" HP Hose w/4 1/16" 5M Flange II e e r~. .,~ - ........ . . ~'..~\~ , MICROFILMED 07/25/06 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LascrFichc\CvrPgs _Il1scrts\Microfihn _ Marker. doc ~l~k OIL AN~D GAS CO~SER¥&TIO~ COMMISSIO~ Dwight Johnson Field Superintendent Unocal 260 Caviar Street Kenai, Alaska 99611 August 21, 2003 FRANK H. MURKOWSKI, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 RE: No-Flow Verifications McArthur River Unit Well K-13RD2, PTD 201-046 Well K-30, PTD 170-007 Dear Mr. Johnson: On August 20, 2003, AOGCC Petroleum Inspector Lou Grimaldi witnessed "no flow tests" on Unocal's McArthur River Unit, King Salmon Platform, Wells K-13RD2 and K- 30. Each well was opened to atmosphere through flow measurement equipment with suitable range and accuracy. Both wells produced short duration, low volume gas that quickly diminished; the sustained gas rates were less than API leakage criteria for subsurface safety valves (900 SCF per hour). No liquid hydrocarbons were produced to surface during the tests. Based on the results of these no-flow tests, subsurface safety valves may be removed from service in Wells K-13RD2 and K-30. These wells must continue to be equipped with fail-safe automatic surface safety valve systems capable of preventing uncontrolled flow, maintained in proper working condition, and tested as required in 20 AAC 25.265. If for any reason either well becomes capable of unassisted flow of hydrocarbons, the subsurface safety valve must be returned to service. Please retain a copy of this letter on the King Salmon platform. Sincerely James B. Regg [ I Petroleum Inspection Supervisor cc: Bob"~"~e~k~'nstein MEMORANDbM State of Alaska THRU: Alaska Oil and Gas Conservation Commission TO: Randy Ruedrich, ~N,~ DATE' Commissioner Jim Regg, ~-~'i ~it~'~t~-~ P. I. Supervisor August 20, 2003 FROM: Lou Grimaldi, SUBJECT: Petroleum Inspector No-Flow Test Unocal, King Salmon K-13RD2 Trading Bay Unit PTD 201-0460 NON-CONFIDENTIAL Wednesday, August 20, 2003: I witnessed a No-Flow verification on the King Salmon platform well # K-13 in the McArthur River field. Following is a timeline and well status during test. 0700 0710 0810 0815 0925 0930 1030 1035 1300 1315 Wireline rigged up on well for static BHP survey. Well shut-in @ 0 psi Open well to flow meter, < 180 scf @ >0 psi. Shut-in well @ 0 psi SITP >0 psi, open well, initial flow 300 scf down to < 180 scf in <_ 1 minute. Shut-in well @ 0 psi. SITP >0 psi, open to atmosphere. <180 scf flow down to whisper in <_1 minute. Shut-in well @ 0 psi Shut-in @ <_1 psi, open well to flow meter. Initial flow 300 scf down to whisper in 1 minute. Observed in this state for fifteen minutes. Ended test, turned well back over to production. Note: The gauge used to check flow was incapable of measuring below 180 scf or above 2000 scf. 100-psi gauge used to check tubing pressure. Zero flow indicated by hose in bucket. This well exhibited inability to flow to surface unassisted and I recommend it be granted No-Flow status. I explained to Dave Condon (Platform Lead Operator) that any cleanout, perforating or other stimulation would require another No-Flow test. SUMMARY: I witnessed No-Flow verification on UNOCAL's King Salmon platform well #K-13 RD2 in the McArthur River field. NON-CONFIDENTIAL CC; Dwight Johnson (Unocal), (platform) 2003-0820_No-Flow_TBU_K- 13RD2_lg.doc Permit to Drill 2010460 MD 15485 ~ 'I'VD DATA SUBMITTAL COMPLIANCE REPORT 7/812003 Well Name/No. TRADING BAY UNIT K-13RD2 Operator UNION OIL CO OF CALIFORNIA 9737 ~'~Completion Dat 6/25/2001 ~ Completion Statu 1-OIL Current Status 1-OIL APl No. 50-733-20157-02-00 UIC N REQUIRED INFORMATION Mud Log N_~o Sample No Directional Survey N_go DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Digital Digital Type M ad. ia Fmt (data taken from Logs Portion of Master Well Data Maint) Interval Log Log Run OH I Dataset Name Scale Media No Start Stop CH Received Number Comments [ L L ~""-S ee Notes C~f~See Notes ._Cna-See Notes 6000 15485 Open 10251 FINAL 6000 15485 oh 10321 FINAL 6000 13530 CH 10322 FINAL 9050 13714 CH Real Time measured 5 2-4 6000 13530 CH Depth Log /~;Y~essure Build-Up FINAL 1000 12250 CH ~C~ompletion Record 6- 5 1 12600 13570 CH 14-01 ~,.IJ,,,-~P.~ ~ Completion Record 5 I 12700 13250 CH r---~T Sigma Porosity 5 1 9050 13714 CH ~secl_klo~ Fc,,-m, ation~5 1 I-t560 ~3720_ CH Res Completion Record 5 1 8100 13716 CH 1 8740 15485 Case 1 8740 15485 Case 1 8740 15485 Case 9/12/2001 ~10251 6000-15485 9/12/2001 ~0251 6000-15485 digital data 8/27/2001 ~ 6000-13530 Digital Data 8/27/2001 ~9050-13714 Digital Data 8/27/2001 6000-13530 BL 8/27/2001 1000-12250 BL, Sepia 8/27/2001 l~OBL~Sepia 8/27/2001 12700-13250 tgE;-Sepia- // 8/27/2001 9050-13714 BL, Sepia /~ 8/27/2001 8100-13716 BL, Sepia 5/6/2002 Final Well Report 5/6/2002 Formation Log 5/6/2002 Formation Log Well Cores/Samples Information: Name Interval Dataset Start Stop Sent Received Number Comments ADDITIONAL INFORMATION DATA SUBMITTAL COMPLIANCE REPORT 7/812003 Permit to Drill 20'10460 Well Name/No. TRADING BAY UNIT K-13RD2 Operator UNION OIL CO OF CALIFORNIA MD 15485 'I'VD 9737 Well Cored? Y / r~ Chips Received? ~ Analysis ~ R~.r~iv~d? Completion Dat 6/25/2001 Completion Statu 1-OIL Current Status Daily History Received? f~)/N Formation Tops '~'~ / N 1-OIL APl No. 50-733-20157-02-00 UIC N Comments: Compliance Reviewed By: Date: Unocal Alaska 909 W. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7651 Fax: (907) 263-7828 E-mail: harrisonb@unocal.com UNOCAL ) Beverly Harrison Business Ventures Assistant May 3, 2002 To: Lisa Weepie AOGCC 333 W. 7th Ave, #100 Anchorage, AK 99501 DATA TRANSMITTAL - KING SALMON PLATFORM ~ WELL; LOG'TYPE:,,,,' m : m m : : imm : m II I m m m ,'SCALE I~ DATE': 'INITERVAL: m : cO :m'MEDIUM O K-13RD2 EPOCH FINAL WELL REPORT 6/16/2001 1 PAPER K-17 COMPLETION RECORD / BRIDGE PLUGS 5 INCH 4/26/2002 2300-2603 1 Film -- K-17 COMPLETION RECORD / BRIDGE PLUGS 5 INCH 4/24/2002 6780-7035 1 B-Line ~) K-17 COMPLETION RECORD / BRIDGE PLUGS 5 INCH 4/24/2002 6780-7035 1 Film ~ K-17 COMPLETION RECORD / BRIDGE PLUGS 5 INCH 4/26/2002 2300-2603 1 B-Line ~K-17 TCPCORRELATION/GR 5 INCH 4/2/2002 10200-10710 1 B4.ine ~" K-17 TCPCORRELATION/GR 5 INCH 4/2/2002 10200-10710 1 Film -(N K-18RD EPOCH FINAL WELL REPORT 8/2/2001 1 PAPER · K-18RDST1 EPOCH FINAL WELL REPORT 8/2/2001 1 PAPER '×~ K-19 HALLIBURTON TCP CORRELATION 5 INCH 3/20/2002 12050-12450 1 B-Line K-19 HALLIBURTON TCP CORRELATION 5 INCH 3~20~2002 12050-12450 1 Film ~ --~ HALLIBURTON TCP CORRELATION / GR / CCL / K-20 COMPLETION RECOR 5 INCH 4/10/2002 5750-6830 1 Film ..9 HALLIBURTON TCP CORRELATION / GR / CCL / ~ K-20 COMPLETION RECOR 5 INCH 4/10/2002 5750-6830 1 B-Line C3 HALLIBURTON TCP GUN CORRELATION / GR / (::7' K-20 CCL / COMPLETION RECOR 5 INCH 4/13/2002 6400-7140 1 B-Line ~ HALLIBURTON TCP GUN CORRELATION / GR / K-20 CCL / COMPLETION RECOR 5 INCH 4/13/2002 6400-7140 1 Film ,_ , F" K-24RD2 CEMENT BOND LOG 5 INCH 9/29/2001 7900-14143 1 Film ~ K-24RD2 CEMENT BOND LOG 5 INCH 9/29/2001 7900-14143 1 B-Line K-24RD2 COMPLETION RECORD/2.5" HSD 6 SPF 5 INCH 10/16/2001 13200-13565 1 Film ~ K-24RD2 COMPLETION RECORD/2.5" HSD 6 SPF 5 INCH 10/16/2001 13200-13565 1 B-Line -- Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828. O I-/~.r"lt Ir-r~ Received Date: Ala a & Cons. Commjs n (. Unocal Alaska 909 w. 9th Avenue Anchorage, AK 99501 Tele: (907) 263-7889 Fax: (907) 263-7828 E-mail: childersd@ unocal.com UNOCAL Debra A. Childers Technologist DATA TRANSMITTAL August 30, 2001 To: Lisa Weepie 333 W 7th Ave, #100 , Anchorage, AK 99501-3539 i AlaskaOil&Gas , From' Debra Childers 909 W. 9th Avenue Anchorage, AK 99501 Unocal Alaska Transmitting the following: Well · LOG TYPE SCALE LOG INTERVAL COPIES Medium TBU D-48 1'1 FORI~ATION 'Ev'AL I'~GS .... 10/30/99 .... 1' CD FORMATION EVAL DIGITAL DATA I ~--b-)l SURVEYS TBU K-13 RO2 FORMATION'EVALLOGS 6/15/01 1 CD c.~ol.-O~L,., SURVEYS Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to (907) 263-7828, Received b I ,. Date: ! STATE OF ALASKA (' ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well Classification of Service Well OIL: X GAS: SUSPENDED: ABANDOI~J-'DL SERVICE: 2. Name of Operator .{']~I~Ti~N,~, ,~,~, 7. Permit Number Unocal Oil Company of California (UNOCAL) '~jl.~l,[,O fi 201-046 3. Address ~ ! 8. APl Number P. O. Box 196247, Anchorage, Ak 99519 . .~"~::~I~,,~ 50- 733-20157-02 4. Localion of well at surface Leg B1, Slot 10 Steelhead Platform.-.-, . ..~ '~!-~;~"i'-'i'(~i.7'":,____~ 9. Unit or Lease Name 615' FSL, 120' FEL, Sec. 17, TDN, R13W, SM ,.";__ ,.? ,,::~, ..... Trading Bay Unit At Top Producing Interval (13779' MD/9772' TVD, top of slotted liner) ii --~' ~-- ~'~'--:-~-./.'. ' 10. Well Number 1381' FNL, 1360' FWL, Sec. 15, TDN, R13W, SM .,.i ~.'::r'":~;:~, K-13RD2 At Total Depth .~i ......... "-~'.~.'. .... '.!" 11. Field and Pool 175' FNL, 2509' FVVL, Sec. 15, TDN, 13W, SM 5. Elevation in feet (indicate KB, DF, etc.) 6. Lease Designation and Serial No. McArthur River Field 100' KB above MS L ADL-18772 Hemlock Pool 12. Date Spudded 13. Date T.D. Reached I 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore I 16. No. of Completions 5/13/01 6/15/01I 6/25/01 completed 100' RKB to MSLI 1 17. Total Depth (MD+TVD) 18. Plug Back Depth (MD+TVD) 119. Directional Survey 20. Depth where SSSV set I 21. Thickness of Permafrost 15485' MD/9737' TVD 15385' MD/9742' TVDI Yes: X No: NA feet MDI NA 22. Type Electric or Other Logs Run AnadrillLWD GR/Res/Neutron/Density, 6/15/01 23. CASING, LINER AND CEMENTING RECORD SET'rING DEPTH MD CASING SIZE vv'r'. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 24" 0 394' Driven 0 13-3/8" 61&68# J-55 0 5011' 18" 1250 sx 0 9-5/8" 47# N-80/S-95 0 8707' 12-1/4" Window for redrill 0 7" 29# L-80 8487' 12430' 8-1/2" 71 sx 0 4-1/2" 11.6# L-80 12320' 15385' 6" None, slotted liner 0 24. Perforations open to Production (MD+TVD of Top and Bottom and 25. TUBING RECORD interval, size and number) SIZE DEPTH SET (MD) PACKER SET (MD) 4-1/2" 8393' 4-1/2" horizontal slotted liner 3-1/2" 12283' 12200' 2-1/2" x 1/8" wide slots, 16 slots/ft 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Slotted liner from 13779' MD/9772' TVD to 15348' MD/9743' TVD DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production I Method of Operation (Flowing, gas lift, etc.) 6/28/01I Flowi ng Date of Test Hours Tested PRODUCTION FOR OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE I GAS-OIL RATIO 7/3/2001 24 TEST PERIOD=> 8552 2556 412 UnknownI 299 Flow Tubing Casing Pressure CALCULATED OIL-BBL GAS-MOF WATER-BBL OIL GRAVITY-APl (corr) Press. 180 20 24-HOUR RATE => 8552 2556 412 34 28. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. None R'ECEIVED 0 RIG INA L CUE. Alaska Oil & Gas Co~s. Commission AnchoragE #148256 Form 10-407 ~ Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in duplicate 29. 30. GEOLOGIC MARKERS FORMATION TESTS , , NAME Include interval tested, pressure data, all fluids recovered and gravity, MEAS. DEPTH TRUE VERT. DEPTH GOR, and time of each phase. Tyonke F 9161 7591 Tyonek G 11202 8931 Hemlock 12485 9685 31. LIST OF ATTACHMENTS Wellbore schematic, Daily Summary of Rig Operations, Directional Survey Report 32. I hereby certify that the foregoing j~s true ~nd correct to the best of my knowledge S i g n e d~J~,~../~_f~,~J~Jv~ ~/v v I~[)1~/~~/~ "lritle. Drillinq Manaqer Date INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other space on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the productin intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.). Item 23: Attached supplemental records for this well should show the details of any multiple stage cement- ing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water In- jection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 UNOCAL RKB to TBG Hanger = 33.77' 9-5/8" Window at 8707' MD, 30 del~ hole angle 3 6 SIZE WT Trading Bay Unit King Salmon Platform Well # K-13RD2 As run 6/25/01 CASING AND TUBING DETAIL GRADE CONN TOP 13-3/8" 61&68 J-55 9-5/8" 47 N-80 ClassB 9-5/8" 47 S-95 BTC BTC BTC BOTTOM 7" 29 4-1/2" 12.6 4-1/2" 11.6 Tubing: 4-1/2" 12.6 3- I/2" 9.2 L-80 KC buttress L-80 11.6 Hyd 511 blank liner L-80 Hyd 511 slotted liner 35' 5011' 35' 4711' 4711' 8707' window 8487' 12430' 12320' 13779' 13779' 15385' N-80 BTC 34' 8393' N-80 BTC 8393' 12283' JEWELRY DETAIL NO. Depth Item 1. 348' 2. 8393' 2a 12151' 3. 12200'dpm 4. 12249' 5. 12283' 6 12320' Baker 4-1/2" TRDP-IA SSSV (ID = 3.813") 4-1/2" x 3-1/2" crossover Baker 3-1/2" CMU sliding sleeve Baker 7" Model F perm packer "X" nipple (ID=2.813") 3-1/2" tbg tail, WLEG Top of 4-1/2" liner with ZXP Gas Lift Information Liner top packer I 2471' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 2 4909' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 3 6106' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 4 6653' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 5 7197' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 6 7741' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 7 8286' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 8 8818' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 9 9348' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 10 9941' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 11 10694' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 12 11380' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 13 12100' 3-1/2" SFO-2 GLM with R-2 orifice and RK latch 7" liner cemented at 12,430' MD/9660' TVD, +/- 57 deg hole Slotted Liner at Near-Horizontal in HB-2 4-1/2" L-80, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD= 15485'MD/9737' TVD KI3RD2 as run 6-25-01 schematic.doc ECP (inflated with mud) at 13696' MD with blank 4-1/2" above and two blank joints below REVISED: 06/29/01 12:59 PM DRAWN BY: TAB K-13RD Abandonment Daily Summary Unocal Alaska Drilling Daily Summary Report K-13RD Abandonment 5/5/01 to 5/11/01 5/5/01 Pump 320 bbls FIW down tubing with good clean returns from annulus. Tbg on vacuum, bled annulus from 20 psi to 0 psi. ND tree, NU BOPE. Wait on crane work to finish up leg move before continuing with well work. 5/6/01 Finish leg move and rig up with repaired cranes. 5/7/01 Test BOPs with blind ram and lower pipe ram test waivered until after tubing is removed. RU jet cutter with APRS. 5/8/01 RIH with 3.5625" jet cutter, set down @ 3905' and pump down to 4700', fell through to 7500' and pump down again to work through. Fire cutter at 8898' ELM. POOH with jet cutter and RD APRS. POOH laying down tubing; holes at 3730' and 3820'. 5/9/01 Change top rams to 5", test blind rams, lower and top rams to 3000 psi. PU drill pipe. RIH with tri-mill cleanout assembly. 5/10/01 Tag top of tubing stub at 8869' dpm. Circ hole clean. POOH with mill assembly. RU Schlumberger, run CBT Icg from 8873' to 7000'. Some cement at proposed KOP. Run Baker retainer and set at 8731' 5/11/01 Pressure test casing above retainer to 1500 psi for 15 min. RIH with cement stinger on drill pipe. Stab into retainer at 8728' dpm. Establish injection rate with FIW at 4 bpm, 400 psi. Mix and pump 36 bbls of 15.8 ppg cement, displace cement to 2 bbl below retainer with FIW, final pressure had climbed to 560 psi at 2.5 bpm. Unsting and reverse circ drill pipe clean with no signs of cement. Circ down drill pipe and annulus volume to further clean up drill pipe. POOH with stinger. Remove 9-5/8" casing packoff from Unihead with pulling tool, pulled free at 60K. Run new FMC packoff, failed pressure test. Remove new packoff and saw mark on OD of packoff from lock down screw. Remove LDS and saw 1-1/2"1ong x 1-1/2" OD piece of LDS had broke off and fell down hole. Rerun packoff and tested OK to 3000 psi. k- 13rd2 daily summary.doc K-13RD2 Redrill Daily Summary Unocal Alaska Drilling Daily Summary Report K-13RD2 Redrill 5/12/01 to 6/27/01 5/12/01 RIH with whipstock. Tag top of bridge plug at 8728', set whipstock 60 deg left of high side. Displace well from FIW to 9.1 ppg OBM from pits and from K-24 storage well. · 5/13/01 Mill window from 8704' to 8740', initial high loss rate but slowed to no during mill run. Total losses 117 bbls, most of which occurred soon after exiting casing. No losses at end of mill run. Test run up and down thru window with no problem. Perform FIT to 11.0 ppg EMW with 700 psi and 9.15 ppg mud, no losses. POOH with mills, window mill 1/2" under gauge, watermelon mills in gauge. PU Bit #1-Smith 15MF 8-1/2" insert bit, RIH to window. 5/14/01 Drill from 8740' to 9234', lost 1 hr for repairing leaking air boot on flow line and 3.5 hrs for plugged flowline, cleaned out cuttings and metal shavings buildup from flowline. 5/15/01 Drill from 9234' to 9855'. 5/16/01 Drill from 9855' to 9984'. Bit trip. Test BOPE. PU Bit #2 BHA with Hycalog DS75 PDC bit. Lost 2 hrs due to Anadrill MWD failure during surface testing. 5/17/01 RIH with Bit #2. Drill from 9984' to 10738'. 5/18/01 Drill from 10738' to 11249'. 5/19/01 Drill from 11249' to 11594'. 5/20/01 Drill from 11594' to 11717', unable to build angle on slide, trip bit. Bit and stabilizers 1/8" undergauge. 5/21/01 RIH with Smith MGR35 PDC Bit #3. Drill from 11717' to 11953'. Lost 1.5 hrs due to leak on top drive. 5/22/01 Drill from 11953' to 12232'. 5/23/01 Drill from 12232' to 12430', 7" casing point. Circ hi-vis sweep and short trip. 5/24/01 Tight spot pulled 75k over at 11770' (keyseat). Back ream from 11770' to 11630'. Pull to shoe at 8700' with no other problems. RIH with 30k down drag at 11770'. Worked up and down at 11770' with further overpulls. RIH to 12430', POOH with no problems. Change to 7" rams and test. RU to run 7" liner. 5/25/01 Ran 7" 29#, L-80, Buttress KC liner. Tagged bottom with liner at 12430'. Dropped ball and set hanger at 1600 psi, release running tool at 2300 psi. Shear out ball at 4500 psi (500 psi over max pin setting). Pump 20 bbls chem wash, 32 bbls (71 sx) of 12.1 k- 13rd2 daily summary.doc 5/26/01 5/27/01 5/28/01 5/29/01 5/30/01 5/31/01 6/1/01 6/2/01 6/3/01 6/4/01 6/5/01 6/6/01 6/7/01 6/8/01 6/9/01 6/10/01 6/11/01 6/12/01 ppg Litecrete cement, displace with 286 bbls OBM. Bump plug to 2500 psi. PU and set ZXP packer. Reverse out with no sign of cement. Test liner top packer to 1500 psi with 73 psi bleed off in 30 min, OK. Drop mud dog wiper and POOH. Did not recover mud dog. Change rams to 5" and test BOPE to 250 psi/3000 psi. PU 6" bit and BHA. RIH. Tag landing collar at 12297', drill out cement and float equipment and new hole to 12450'. Circulate, perform formation integrity test to 700 psi @ 9671' TVD with 9.6 ppg mud = 11.0 ppg EMW. Drill from 12450' to 12627', trip for bit. RIH with new 6" bit, drill from 12627' to 12848'. Trip for bit. Drill from 12848' to 13000'. Drill from 13000' to 13278'. Trip for bit. RIH with 6" PDC bit, drill from 13278' to 13325'. Poor ROP of only 10 ft/hr. Trip for bit. Weekly BOP test. RIH with 6" insert bit. Drill from 13325' to 13607'. Trip for bit. Drill with 6" insert bit from 13607' to 13744'. Drill from 13744' to 13900', trip for bit. Pulled tite at 12904' with 60 k overpull. Worked free and clean up hole from 12874' to 12794'. Continued POOH. RIH with 6" insert bit, no problems. Drill from 13900' to 14226', trip for new bit. Drill from 14226' to 14336', erratic torque and unable to slide. Trip for bit. Bit was in gauge, suspect motor problems were the cause for torque and weight transfer to bit. RIH with new motor. Drill from 14336' to 14363'. Drill from 14336' to 14600', trip for bit. Test BOPE. RIH with new bit, slight tight spot at 12760'. Drill from 14600' to 14704'. Drill string plugged, POOH. Motor failed. RIH with new bit and new motor. Drill from 14704' to 14920'. Drill from 14920' to 15014', pull bit, 3/8" undergauge. RIH with new bit, some drag in from 14530' to 14850'. Drill from 15014' to 15067'. Drill from 15067' to 15230' (Coal at 15107' to 15110'.) Trip for bit. RIH with LWD assy with 2' x 5-7/8" stabilizer on Density tool. k- 13rd2 daily summary.doc 6/13/O 1 6/14/01 Tag up at 12635', had to ream and work down to 12691' with 100k overpulls. Pull logging tools out. RIH with slick LWD assy (density tool will not provide imaging data in this slick configuration). No problems until work through tight hole from 14288' to 14733'. RIH with little resistance from 14733' to 15200' and safety ream down to 15230'. Drill from 13230' to 15468'. 6/15/01 Drill with LWD tools from 15230' to 15485'. Called TD due to coal from 13400' to bottom. POOH logging with LWD. ADN ran out of memory from 13010' to shoe at 12430'. POOH. 6/16/01 Analyzed logs and picked ECP placement point at 13,700'-13725'. RIH with 4-1/2" slotted liner. 6/17/01 RIH with 2-1/16" inner string. MU liner hanger assembly to inner string and to liner. RIH, work thru tite spots at 14250'-14948', (ECP at max dogleg). Made it to top of coal at 15390' with bottom of liner, ECP at 13702, hanger at 12345'. Last 7 stands were back flowing, bad float. Circ at slow rate of .47 bpm and 650 psi. 6/18/O 1 Drop ball and set hanger, pressure up to 2200 psi to release running tool but ball seat blew out early. Unable to release running tool. Drop wiper plug and land same, pressure up to 3500 but unable to release running tool. Bleed pressure and attempt left hand torque to release running tool, unsuccessful. Pressure up to 4250 psi and blow drain sub. PU 10k over and parted something. POOH, recovered liner running tool and inner string parted just above Pressure Port Isolation Tool upper cup assembly near top of inner string. 6/19/01 RIH with 2.000" spear to fish inner string. Engage fish at 12337', work fish between 12308' and 12344' where inner string no-go bottomed out on liner packoff bushing. No sign of inner string being stuck at this point in time. POOH with fish. 6/20/01 Recovered Pressure Port Isolation Tool for setting hanger; upper cup of PPIT was torn off but no sign of cause of inner string being stuck. Laid down 2-1/16" inner string down to lower cup inflation tool for ECP inflation. Inspected and redressed/replaced lower ECP inflation tools, no sign of damage. RIH with inner string on drill pipe to inflate ECP without upper PPIT assembly. 6/21/01 Tag stinger no-go at 15354', circ, PU out of pack-off bushing, locate across ECP with 15k overpull. Drop ball, circ ball on seat. Pressure up to set ECP with increments up to 1850 psi. Did not see pressure spike down when ECP inflate valve opened but did flow back 12.6 gallons less than used to pressure up indicating ECP inflated. Shear ball at 3000 psi. Stab back in to pack-off bushing. Spotted 86 bbls base oil in 4-1/2' slotted liner x open hole annulus and inside 4-1/2" slotted and blank liner. POOH, LD inner string. 6/22/01 Test BOPE. RIH with 4-1/2" tie-back seal assembly and 5-3/4" Iocator. With seals above tie-back, reverse circ at 1 BPM and 400 psi. Stab seals into tie-back receptacle at 12319' and was able to reverse circulate at 3/~ BPM and 500 psi indicating ECP is restricting flow but is not holding. Set ZXP with 60K down weight. Test ZXP to 1495 psi with 30 min pressure at 1451 psi, good test. POOH. k- 13rd2 daily summary.doc 6/23/01 RIH with Baker Model F packer with 15' seal bore extension on drill pipe and Model B- 2 running tool. Drop ball and set packer at 12,200' with 2000 psi. Blow ball with 3700 psi. Pressure test annulus to 1547 psi with 30 min pressure at 1478 psi, good test. Released running tool with 10 right hand turns. POOH LD DP. 6/24/01 RIH with 3-1/2" x 4-1/2" tubing, GLMs, open sliding sleeve, 15' of seals and stab thru tubing tail. 6/25/01 Space out and land hanger with locater 1' above packer. ND BOPE and NU and test tree to 5000 psi. 6/26/01 Circulate tubing and annulus to 684 bbl of diesel through sliding sleeve with choke on returns from annulus. Bleed off trapped choke pressure until tubing stable at 617 psi. Calculated reservoir pressure with diesel and OBM gradient = 4145 psi at 9772' TVD top of slotted liner. Attempt to close sliding sleeve with slickline, no luck. 6/27/01 Close sleeve, RD slickline. Release rig from K-13RD2 at 23:59 on 6/27/01 for leg move to K-18. k- 13rd2 daily summary.doc UNOCAL ) RKB to TBG Hanger = 33.77' 9'5/8" Window at 8707' MD, 30 de~; hole angle Trading Bay Unit King Salmon Platform Well # K-13RD2 As run 6/25/01 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 61&68 J-55 BTC 35' 9-5/8" 47 N-80 ClassB BTC 35' 9-5/8" 47 S-95 BTC 4711' 7" 29 4-1/2" 12.6 4-1/2" 11.6 Tubing: 4-1/2" 12.6 3-1/2" 9.2 L-80 KC buttress 8487' L-80 11.6 Hyd 511 blank liner 12320' L-80 Hyd 511 slotted liner-13779' 5011' 4711' 8707' window 12430' 13779' 15385' N-80 BTC 34' 8393' N-80 BTC 8393' 12283' JEWELRY DETAIL NO. Depth Item 1. 348' 2. 8393' 2a 12151' 3. 12200'dpm 4. 12249' 5. [2283' 6 12320' Baker 4-1/2" TRDP-1A SSSV (ID = 3.813") 4-1/2" x 3-1/2" crossover Baker 3-1/2" CMU sliding sleeve Baker 7" Model F perm packer "X" nipple (ID=2.813") ,3-1/2" tb g t:~ i 1, \V LE(i; Top o1" 4-1/2" li~er witll 1 2471' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 2 4909' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 3 6106' ' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 4 6653' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 5 7197' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 6 7741' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 7 8286' 4-1/2" SFO-2 GLM with R-2 valve and RK latch 8 8818' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 9 9348' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 10 9941' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 11 10694' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 12 11380' 3-1/2" SFO-2 GLM with R-2 valve and RK latch 13 12100' 3-1/2" SFO-2 GLM with R-2 orifice and RK latch 7" liner cemented at 12,430' MD/9660' TVD, +/- 57 deg hole Slotted Liner at Near-Horizontal in HB-2 4-1/2" L-80, 11.6# tbg with 2-1/2" x 1/8" slots, 16 slots/ft 90 Deg belly at 13,000' MD MAX HOLE ANGLE = 94.75° @ 13413' TD = 15485' MD/9737' TVD K 13RD2 as run 6-25-01 schematic.doc ECP (inflated with mud) at 13696' MD with blank 4-1/2" above and two blank joints below DRAWN BY: TAB 06/27/01 REVISED: 06/27/01 Schlumberger ANADRI LL SCHLUMBERGER Survey report Client ................... : UNOCAL King Salmon Field .................... : McArthur River Unit Well ..................... : K-13RD2 API number ............... : 50-733-20157-02 Engineer ................. : Carlos Pacheco COUNTY: .................. : Cook Inlet State: ................... : Alaska Survey calculation methods Method for positions ..... : Minimu/n curvature Method for DLS ........... : Mason & Taylor Depth reference -- Permanent datum .......... : MEA/q SEA LEVEL Depth reference .......... : Driller's Pipe Tally GL above permanent ....... : 0.00 ft KB above permanent ....... : TOP DRIVE DF above permanent ....... : 100.00 ft Vertical section origin Latitude (+N/S-) ......... : Departure (+E/W-) ........ : 0.00 ft 0.00 ft Platform reference point .... Latitude (+N/S-) ......... : -999.25 ft Departure (+E/W-) ........ : -999.25 ft Azimuth from rotary table to target: 40.05 degrees 15-Jun-2001 18:05:42 Page 1 of 4 Spud date ................ : 12-May-01 Last survey date ......... : 15-Jun-01 Total accepted surveys...: 79 MD of first survey ....... : 8700.00 ft MD of last survey ........ : 15485.00 ft Geomagnetic data Magnetic model ........... : BGGM version 2000 Magnetic date ............ : 12-May-2001 Magnetic field strength..: 1107.34 HCNT Magnetic dec (+E/W-) ..... : 20.85 degrees Magnetic dip ............. : 73.54 degrees MWD survey-Reference Criteria Reference G .............. : 1002.03 mGal Reference H .............. : 1107.34 HCNT Reference Dip ............ : 73.54 degrees Tolerance of G ........... : (+/-) 2.50 mGal Tolerance of H ........... : (+/-) 6.00 HCNT Tolerance of Dip ......... : (+/-) 0.45 degrees Corrections ............ Magnetic dec (+E/W-) ..... : 20.85 degrees Grid convergence (+E/W-).: 0.00 degrees Total az corr (+E/W-) .... : 20.85 degrees (Total az corr = magnetic dec - grid conv) Sag applied (Y/N) ........ : No degree: 0.00 Schlumberger ANADRILL SCHLUMBERGER Survey Report 15-Jun-2001.18:05:42 Page 2 of 4 Seq Measured Incl Azimuth Course # depth angle angle length - (ft) (deg) (deg) (ft) 1 8700.00 31.50 105.00 2 8704.00 31.47 104.96 3 8720.00 32.29 101.68 4 8764.38 31.24 96.18 5 8856.09 33.75 84.82 0.00 4.00 16.00 44.38 91.71 TVD Vertical Dispt Dispi Total At DLS depth section +N/S- +E/W- displ Azim (deg (ft) (ft) (ft) (ft) (ft) (deg) 100f 7157.85 2874.05 135.26 4305.67 4307.79 7161.26 2874.93 134.72 4307.69 4309.79 7174.85 2878.73 132.78 4315.91 4317.95 7212.59 2890.78 129.14 4338.96 4340.89 7290.01 2922.16 128.88 4388.03 4389.93 Srvy Tool / tool qual ) type type 88.20 0.00 TIP 88.21 0.91 MWD 88.24 11.98 MWD 88.30 6.94 MWD 88.32 7.18 MWD 6 8950.06 34.77 73.18 93.97 7367.76 2963.17 139.00 4439.74 4441.91 7 9043.70 34.86 61.58 93.64 7444.72 3010.48 159.48 4488.89 4491.72 8 9138.26 34.57 55.10 94.56 7522.47 3061.54 187.70 4534.67 4538.55 9 9231.80 33.52 51.53 93.54 7599.99 3112.49 218.96 4576.66 4581.90 10 9323.72 33.16 48.84 91.92 7676.78 3162.21 251.30 4615.46 4622.30 88.21 7.05 MWD 87.97 7.07 MWD 87.63 3.91 MWD 87.26 2.41 MWD 86.88 1.66 MWD 6-axis 6-axis 6-axis 6-axis 11 9417.87 34.94 44.88 94.15 7754.80 3214.53 287.35 4653.88 4662.74 12 9509.71 38.25 42.76 9t.84 7828.53 3269.15 326.87 4691.75 4703.12 13 9602.79 39.46 40.74 93.08 7901.01 3327.51 370.44 4730.62 4745.10 14 9697.30 40.29 40.27 94.51 7973.54 3388.10 416.51 4769.97 4788.12 15 9791.81 45.68 38.89 94.51 8042.66 3452.51 466.18 4810.98 4833.52 86.47 3.02 MWD 86.01 3.86 MWD 85.52 1.88 MWD 85.01 0.93 MWD 84.47 5.79 MWD 6-axis 6-axis 6-axis 6-axis 6-axis 16 9884.01 48.82 36.99 92.20 8105.24 3520.15 519.59 4852.58 4880.32 17 9925.05 50.71 35.36 41.04 8131.75 3551.41 544.88 4871.06 4901.44 18 9988.98 51.20 35.27 63.93 8172.02 3600.89 585.39 4899.77 4934.61 19 10082.81 50.76 34.68 93.83 8231.09 3673.50 645.12 4941.55 4983.49 20 10176.36 51.81 35.17 93.55 8289.60 3746.20 704.97 4983.34 5032.96 83.89 3.73 MWD 83.62 5.51 MWD 83.19 0.77 MWD 82.56 0.68 MWD 81.95 1.19 MWD 6-axis -- 6-axis 6-axis 6-axis 21 10269.53 52.17 35.30 22 10363.74 52.22 34.84 23 10456.15 52.07 34.08 24 10549.40 52.00 33.36 25 10642.90 51.40 33.19 93.17 94.21 92.41 93.25 93.50 8346.98 3819.35 764.93 5025.70 5083.57 8404.73 3893.51 825.85 5068.46 5135.30 8461.44 3966.12 886.01 5109.75 5186.00 8518.80 4039.19 947.16 5150.56 5236.92 8576.75 4112.05 1008.50 5190.82 5287.88 81.35 0.40 MWD 80.75 0.39 MWD 80.16 0.67 MWD 79.58 0.61 MWD 79.01 0.66 MWD 6-axis 6-axis 6-axis 6-axis 6-axis 26 10737.21 51.06 32.52 27 10831.62 50.91 32.11 28 10924.08 50.56 32.02 29 11015.91 50.45 31.77 30 11108.48 49.87 31.11 94.31 8635.81 4185.00 1070.27 5230.71 5339.08 94.41 8695.24 4257.69 1132.26 5269.92 5390.19 92.46 8753.76 4328.58 1192.93 5307.93 5440.33 91.83 8812.17 4398.73 1253.09 5345.37 5490.28 92.57 8871.47 4469.01 1313.73 5382.45 5540.45 78.44 0.66 MWD 77.87 0.37 MWD 77.33 0.39 MWD 76.81 0.24 MWD 76.28 0.83 MWD 6-axis 6-axis 6-axis 6-axis 6-axis Schlumberger ANADRILL SCHLUMBERGER Survey Report Seq Measured Incl Azimuth COurse # depth angle angle length - (ft) (deg) (deg) (ft) 31 11203.91 49.54 31.31 32 11298.60 49.84 30.84 33 11390.50 50.42 31.26 34 11483.24 50.69 31,33 35 11579.16 49.98 30.49 36 11671.49 48.84 30.11 37 11762.05 51.80 31.32 38 11855.52 55.47 32.06 39 11950.41 56.90 31.82 40 12042.41 56,90 32.98 41 12136.36 57.09 34.69 42 12231.22 57.53 36.13 43 12323.71 57.14 36.65 44 12367.72 57.15 36.26 45 12464.29 59.76 36.55 46 12559.80 67.63 38.45 47 12653.67 72.70 40.20 48 12746.03 76.58 41.98 49 12839.33 78.83 42.88 50 12933.77 85.15 43.90 51 13026.62 92,80 43.80 52 13118.27 91.90 43.80 53 13213.79 93.05 42.53 54 13272.47 92.75 42.45 55 13320.00 93.48 42.00 56 13413.27 94.75 41.80 57 13508.27 93.30 42.08 58 13603.54 92.63 42.63 59 13696.04 91.55 42.60 60 13787.99 92.53 43.22 95.43 94.69 91.90 92.74 95.92 92.33 90.56 93.47 94.89 92. O0 15-Jun-2001 18:0'5:42 TVD Vertical Displ Displ depth section +N/S- +E/W- (ft) (ft) (ft) (ft) 8933.19 8994.44 9053.36 9112.28 9173.50 __ 4540.93 1375.99 5420.16 4612.25 1437.83 5457.43 4681.91 1498.26 5493.81 4752.70 1559.45 5531.01 4825.60 1622.80 5568.94 9233.58 4894.70 1683.34 5604.32 9291.39 4963.46 1743.24 5639.93 9346.80 5037.92 1807.27 5679.47 9399.61 5115.97 1874.17 5721.18 9449.85 5192.35 1939.24 5762.47 93.95 9501.03 5270.67 2004.68 5806.34 94.86 9552.27 5350.24 2069.74 5852.60 92.49 9602.19 5427.94 2132.42 5898.79 44.01 9626.06 5464.84 2162.16 5920.76 96.57 9676.58 5546.97 2228.39 5969.60 9718.88 9750.73 9775.20 9795.09 9808.25 5632.43 2296,22 6021.71 5720.69 2364.49 6077.66 5809.71 2431.59 6136.19 5900.78 2498.88 6197.68 5994.09 2566.80 6261.88 95.51 93.87 92.36 93.30 94.44 92.85 91.65 95.52 58.68 47.53 9809.91 6086.65 2633.70 6326.15 9806.15 6178.03 2699.79 6389.53 9802.03 6273.31 2769.40 6454.81 9799.06 6331.87 2812.62 6494,39 9796.48 6379.29 2847.77 6526.28 93.27 9789.79 6472.27 2917.01 6588.41 95.00 9783.13 6566.98 2987.50 6651.74 95.27 9778.20 6662.05 3057.82 6715.83 92.50 9774.82 6754.39 3125.85 6778.41 91.95 9771.55 6846.17 3193.16 6840.97 Page Total displ (ft) At Azim (deg) 5592.09 5643.66 5694.45 5746.65 5800.57 5851.67 5903.19 5960,08 6020.33 6080.03 6142.66 6207.79 6272.39 6303.20 6371.96 6444.66 6521.41 6600.41 6682.48 6767.54 6852.49 6936.50 7023.83 7077.28 7120.54 7205.28 7291.83 7379.20 7464.43 7549.51 75.76 75.24 74.75 74.25 73.75 73.28 72.82 72.35 71.86 71.40 70.95 70.52 70.13 69.94 69.53 69.13 68.74 68.38 68.04 67.71 67.40 67.09 66.78 66.58 66.43 66.12 65.81 65.52 65.24 64.98 3 of 4 DLS (deg/ 100f) 0.38 0.49 0.72 0.30 1.00 1.27 3.43 3.98 1.52 1.06 1.54 1.36 0.63 0.74 2.71 8.42 5.69 4.58 2.59 6.79 8.24 0.98 1.80 0.52 1.79 1.39 1.55 0.91 1.17 1.26 Srvy tool type MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD SP SP SP SP SP SP SP SP SP SP SP SP SP SP SP Tool qual type 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis 6-axis -- 'Schlumberger ANADRILL SCHLUMBERGER Survey Report Seq Measured Inct Azimuth # depth angle angle - (ft) (deg) (deg) 61 13848.70 91.45 43.02 62 13963.07 89.65 42.25 63 14056.31 87.12 43.34 64 14150.28 87.10 44.00 65 14261.29 87.36 42.80 66 14353.90 88.28 43.95 67 14448.53 89.73 44.25 68 14539.64 89.75 45.35 69 14570.25 90.18 45.83 70 14657.61 92.35 46.10 71 14750.95 94.45 45.18 72 14844.85 93.75 43.35 73 14941.75 93.35 40.40 74 15041.72 93.10 39.20 75 15133.27 94.23 38.90 76 15218.72 93.00 38.93 77 15312.75 92.63 39.25 78 15406.88 92.70 38.90 79 15485.00 92.70 38.90 15-Jun-2001 18:05:42 Course TVD Vertical Displ Displ Total length depth section +N/S- +E/W- displ (ft) (ft) (ft) (ft) (ft) (ft) __ 60.71 9769.44 6906.75 3237.44 6882.44 7605.85 114.37 9768.34 7021.00 3321.57 6959.90 7711.88 93.24 9770.97 7114.08 3389.96 7023.21 7798.55 93.97 9775.71 7207.75 3457.84 7088.02 7886.49 1tl.01 9781.08 7318.44 3538.41 7164.20 7990.37 9784.60 7410.82 3605.67 7227.75 8077.21 9786.25 7505.20 3673.61 7293.60 8166.52 9786.67 7595.99 3738.26 7357.79 8252.98 9786.69 7626.46 3759.68 7379.66 8282.18 9784.76 7713.33 3820.39 7442.44 8365.72 92.61 94.63 91,11 30.61 87.36 Page At Azim (deg) 64.81 64.49 64.23 63.99 63.72 63.49 63.27 63.07 63.00 62.83 93.34 9779.23 7806.06 3885.54 7509.05 8454.77 62.64 93.90 9772.51 7899.46 3952.61 7574.41 8543.70 62.44 96.90 9766.51 7996.11 4024.62 7638.96 8634.31 62.22 99.97 9760.89 8095.92 4101.30 7702.85 8726.66 61.97 91.55 9755.04 8187.27 4172.25 7760.40 8810.88 61.74 9749.66 9745.05 9740.67 9736.99 85.45 94.03 94.13 78.12 8272.53 4238.61 7813.97 8889.54 8366.43 4311.51 7873.18 8976.42 8460.45 4384.51 7932.45 9063.53 8538.46 4445.24 7981.45 9135.85 61.52 61.29 61.07 60.88 4 of 4 DLS (deg/ i00f) 1.81 1.71 2.95 0.70 1.10 1.59 1.55 1.21 2.08 2.50 2.46 2.07 3.07 1.22 1.27 1.43 0.53 0.38 0.00 Srvy tool type SP SP SP SP SP SP SP SP SP SP SP SP SP SP SP SP SP SP Project Tool qual type 6-axis -- 6-axis K-13RD MD 0 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 17OO 1800 19OO 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 4200 4300 4400 4500 4600 4700 4800 4900 TVD 0 200 300 400 499 599 698 797 896 995 1093 1191 1289 1387 1485 1582 1679 1775 1871 1965 2059 2152 2243 2333 2420 2505 2588 2668 2747 2825 2901 2976 3051 3126 3201 3274 3346 3415 3481 3544 3604 3664 3725 3787 3850 3913 3978 4043 4109 SSTVD 100 -1 O0 -200 -300 -399 -499 -598 -697 -796 -895 -993 -1091 -1189 -1287 -1385 -1482 - 1579 -1675 -1771 -1865 -1959 -2052 -2143 -2233 -2320 -2405 -2488 -2568 -2647 -2725 -2801 -2876 -2951 -3026 -3101 -3174 -3246 -3315 -3381 -3444 -3504 -3564 -3625 -3687 -3750 -3813 -3878 -3943 -4009 XOFF 0 0 0 0 -3 -11 -19 -19 -12 0 15 32 5O 69 9O 111 135 160 188 218 252 289 329 372 420 472 527 586 647 710 774 840 906 972 1038 1106 1175 1247 1322 1400 1479 1558 1637 1714 1792 1868 1944 2019 2094 YOFF 0 0 0 0 2 10 21 34 46 56 65 73 82 90 99 108 117 126 135 143 152 161 169 178 187 195 203 210 218 224 229 234 239 245 251 257 264 271 278 285 293 3O4 314 324 334 345 357 367 375 X 213765 213765 213765 213765 213762 213754 213746 213746 213753 213765 213780 213797 213815 213834 213855 213876 213900 213925 213953 213983 214017 214054 214094 214137 214185 214237 214292 214351 214412 214475 214539 2146O5 214671 214737 2148O3 214871 214940 215012 215O87 215165 215244 215323 215402 215479 215557 215633 2157O9 215784 215859 Y 2511695 2511695 2511695 2511695 2511697 2511705 2511716 2511729 2511741 2511751 2511760 2511768 2511777 2511785 2511794 2511803 2511812 2511821 2511830 2511838 2511847 2511856 2511864 2511873 2511882 2511890 2511898 2511905 2511913 2511919 2511924 2511929 2511934 2511940. 2511946 2511952 2511959 2511966 2511973 2511980 2511988 2511999 2512009 2512019 2512029 2512040 2512052 2512062 2512070 Inclination 0 0 0 0 4.8 8 8 7.3 8.8 10 10.3 11 12 12.5 13.3 14 15 16 17.8 19.5 21.3 23 25.3 27 31.3 33 35 37.3 38.8 39.8 40.5 42 41.3 41.5 42 43 45.5 47.5 49.8 52.5 53.3 52.8 52 51.5 51.3 50 49.5 49 48.5 Azimuth 36O 3O9 3O9 3O9 3O9 311 34O 14 45 57 6O 63 64 66 65 67 66 71 73 73 75 76 76 78 79 80 81 82 82 84 84 84 84 83 84 83 83 83 84 83 82 80 82 81 81 80 8O 82 83 K-13RD MD 5000 5100 5200 5300 5400 5500 5600 5700 5800 5900 6000 6100 6200 6300 6400 6500 6600 6700 6800 6900 7000 7100 7200 7300 7400 7500 7600 7700 7800 7900 8000 8100 8200 8300 8400 8500 8600 8700 8704 8720 TVD 4175 4243 4314 4390 4468 4546 4624 4701 4777 4853 4930 5009 5089 5170 5252 5334 5417 5499 5582 5664 5747 5829 5912 5995 6O78 6161 6244 6328 6411 6494 6576 6658 6740 6822 6905 6988 7072 7157 7160 7174 SSTVD -4O75 -4143 -4214 -4290 -4368 -4446 -4524 -4601 -4677 -4753 -4830 -4909 -4989 -5070 -5152 -5234 -5317 -5399 -5482 -5564 -5647 -5729 -5812 -5895 -5978 -6061 -6144 -6228 -6311 -6394 -6476 -6558 -6640 -6722 -6805 -6888 -6972 -7057 -7060 -7074 XOFF 2168 2241 2311 2376 2439 2500 2563 2626 2691 2755 2818 2879 2939 2997 3054 3109 3165 3221 3276 3332 3387 3443 3498 3552 3606 3661 3715 3768 3822 3876 3930 3985 4040 4095 4150 4204 4256 4307 4309 4317 YOFF 382 391 399 401 401 398 39O 381 372 364 355 347 338 330 321 312 302 293 283 273 262 251 239 226 213 201 189 177 162 146 130 114 99 85 71 57 44 31 30 28 X 215933 216006 216076 216141 216204 216265 216328 216391 216456 216520 216583 216644 216704 216762 216819 216874 216930 216986 217041 217097 217152 217208 217263 217317 217371 217426 21748O 217533 217587 217641 217695 217750 217805 217860 217915 217969 218021 218072 218O74 218082 Y 2512077 2512086 2512094 2512096 2512096 2512093 2512O85 2512076 2512067 2512059 2512050 2512042 2512033 2512025 2512016 2512O07 2511997 2511988 2511978 2511968 2511957 2511946 2511934 2511921 2511908 2511896 2511884 2511872 2511857 2511841 2511825 2511809 2511794 2511780 2511766 2511752 2511739 2511726 2511725 2511723 Inclination 48.8 46 42.5 39.5 37.8 38.8 39.3 40.3 40.8 40.3 38.5 37.5 37 35 35 34 34.8 34.3 34.3 34.3 34.5 34.5 34 34 34 33.8 33.3 33.5 34 34.3 34.8 34.8 35 34.8 34.3 33 32.3 31.5 31.5 32.3 Azimuth 83 80 84 89 89 94 97 97 96 96 96 97 97 97 97 99 98 98 99 99 100 100 102 102 102 101 100 103 106 105 104 105 104 102 103 103 102 105 105 102 UNOCAL ALASKA RESOURCES, INC. K-13RD2 McARTHUR RIVER FIELD Section 17- TgN. R f 3W Cook Inlet, Alaska June 16, 2001 Brian O'Fallon- Sr. Logging Geologist Ralph Winkelman- Logging Geologist Andrew Buchanan- Sr. Logging Geologist EPOCH UNOCAL ) Unocal Alaska Resources, Inc. K-13RD2 McArthur River Field Cook Inlet, Alaska TABLE OF CONTENTS WELL RESUME .................................................................................................................... 3 LITHOLOGY SUMMARY ...................................................................................................... 4 DALLY CHRONOLOGY ...................................................................................................... 20 MUD RECORD ................................................................................................................... 27 SURVEY RECORD ............................................................................................................. 29 BIT RECORD ...................................................................................................................... 31 DAILY REPORTS ............................................................................................................... 32 WELL LOGS ...................................................................................................... APPENDIX 1 EPOCH 2 UNOEAL K-13RD2 WELL RESUME UNOCAL ALASKA KING SALMON PLATFORM K-13RD2 WELL NAME: K-13RD2 FIELD: McARTHUR RIVER FIELD REGION: LOCATION: COOK INLET, ALASKA SEC. 17 T9N R13W SM BOROUGH: KENAI BOROUGH STATE: ALASKA ELEVATION: RKB: 100.0' AMSL APl NUMBER: #50-733-20157-02 OPERATOR: Operator Representatives: Company Geologist: CONTRACTOR: UNOCAL ALASKA RESOURCES, INC. SHANE HAUCK, TERRY COLEMAN MATT FRANKFORTER NABORS ALASKA DRILLING DRILLING RIG: KING SALMON PLATFORM MUDLOGGING COMPANY: Logging Geologists: EPOCH WELL SERVICES, INC. BRIAN O'FALLON, RALPH WINKELMAN ANDREW BUCHANAN MUD COMPANY: Mud Engineers: MWD COMPANY: MWD Engineer: DIRECTIONAL COMPANY: Directional Driller: CEMENT COMPANY: MI JIM BROWN, MONTY KANTA, MIKE FORMAN ANADRILL/SCHLUMBERGER MARK BROWN, CARLOS PACHECO ANADRILL/SCHLUMBERGER MIKE WARD, M.VERY. CORKER DOWELL/SCHLUMBERGER WlRELINE COMPANY: SCHLUMBERGER EPOCH UNOCAL ) K-13RD2 LITHOLOGY SUMMARY DRILLED TYONEK AND HEMLOCK (8730-15485') TYONEK (COMMEMCE LOG TO 15270) 8770' Sand = light gray to light brownish gray overall appearance; individual grains dominantly light gray to frosted white; scattered dark gray and greenish gray; common black lithics; trace dusky red lithics, fine to very coarse, dominantly medium; angular to subangular; disaggregated to very loosely consolidated; moderately well sorted; trace to common black carbonaceous material present; dull greenish yellow sample fluorescence from oil base mud. 8835' Tuffaceous Claystone = medium to dark gray; firm to brittle; irregular cutting clayey to ashy texture; earthy to microsparkly luster; hydrophilic; expansive when hydrated; non calcareous; trace calcite pieces; common black carbonaceous material throughout. 8880' Coal = black to brownish black; slightly firm to occasionally very firm; subplaty to hackly; dull earthy to smooth shiny luster; hackly to planar/fissile fracture as mostly Iow grade coal grading to carbonaceous shale; occasional interbedded gray claystone, conglomeratic sand and sandstone, and trace calcite. 8925' Claystone = gray to brownish gray to very dark gray to light gray to white; slightly firm to moderately firm; mostly subplaty to wedge, some rounded and pebble-shaped possibly reworked as conglomerate, mostly slightly to moderately organic some with dark patchy matter on fissile partings grading carbonaceous shale; moderately to slightly hydrophilic and possibly tuffaceous; occasionally kaolic especially associated with sandstone; mostly slight disseminated mica; associated with some pebbles and rock fragments including siliceous lithics, chert, and quartz; non calcareous. 9010' Sand = light gray overall; mostly medium to some fine and coarse to scattered pebble; subangular; well sorted; 90% quartz, and %10 coal and siliceous gray to black lithics, trace feldspar; estimate good to some fair porosity and permeability; faint dull yellow green fluorescence from mud contamination more visible on sand grains; slight instantaneous to slow streaming cut similar on sands and clays. 9070' Claystone = dark gray to brownish gray to medium gray to occasional light gray; slightly firm to moderately firm; mostly subplaty to wedge, often rounded and pebble-shaped possibly reworked as conglomerate, mostly slightly to moderately organic grading carbonaceous shale and coal; moderately to slightly hydrophilic and possibly tuffaceous; occasionally kaolic especially associated with sandstone; mostly slight disseminated mica; associated with some pebbles and rock fragments including dark siliceous lithics, quartz, and chert; non-calcareous. [:::1 EPOCH 4 UNOCALe K-13RD2 9150' Coal = black; moderately firm; brittle to crumbly; subblocky to platy and fissile; hackly; interbedded with carbonaceous shale and claystone. F-MARKER 9177' 9175' Sand = very light gray; mostly medium grained and some fine upper and coarse lower; subangular; moderate sphericity; estimate well sorted; mostly loose grains; occasional in matrix supported kaolic clay; predominantly quartz and some coal and clay to siliceous clay lithics; estimate mostly good to fair porosity and permeability; no oil indicated above oil base mud background. 9250' Sand = light gray with strong salt and pepper appearance; individual grains dominantly light gray to frosted white, common dark gray to black, scattered light greenish gray and dark dusky red lithics; fine to very coarse, dominantly medium to coarse; angular to subangular, occasional broken shards; moderately well sorted; dominant disaggregated; trace calcite; common black carbonaceous material throughout; 30% to 40% dull yellow sample fluorescence; instant bright yellowish white cut fluorescence from oil base mud; no oil indicators. 9320' Tuffaceous Claystone = medium to dark gray outer coloration, interior, hydrated color is light gray; firm to brittle dry; very soft hydrated; hydrophilic; very expansive when wet; ashy to clayey texture; dull to earthy luster to microsparkly; visible glass shards; non to slightly calcareous; occasionally grading to carbonaceous shale. 9370' Carbonaceous Shale = dark brown to black very firm to hard; blocky to platy; planar fracture; smooth to slightly gritty texture; dull earthy luster; occasionally grading to lignitic coal; trace waxy tuffs. 9405' Sand/Conglomerate = light gray overall with varicolored individual lithics such as white, black, dark greenish gray, dark dusky red, translucent; fine grain sand to very coarse broken pebble fragments; well rounded pebbles to broken, angular pieces; poorly sorted; unconsolidated to disaggregated; common to abundant black carbonaceous material/ coal; trace light gray waxy tuffs; continued oil base mud fluorescence; no oil indicators present. 9465' Coal = black with very dark brown secondary hues; firm to brittle, splintery; platy to elongated, irregular cuffings; dominantly planar fracture with scattered to common birdseye fracture; smooth to dense matte texture; earthy to resinous luster; none to rare visible outgassing bubbles; common light to dark greenish gray, waxy tuffs, very calcareous. EPOCH 5 UNOEi _L K-13RD2 9525' Claystone = mostly medium gray to brownish gray to medium dark gray; amorphous to subplaty; smooth; slightly to moderately organic grading shale; occasional patchy carbonaceous partings and thinly interbedded Iow grade coal; moderately hydrophilic expanding to light brownish gray to medium light gray to light gray; trace micas; non-calcareous: = some very light gray to cream gray; slightly firm to firm and crumbly to brittle; dull to slightly greasy luster; slightly soluble and kaolic to thin zones moderately hydrophilic; often calcareous in part; often sandy including subangular to angular medium to fine grains and shards of quartz; trace chlorite and brown mica flakes; slight black carbonaceous inclusions and lineations; grading matrix supported sandstone and ash fall tuff. 9640' Sandstone = very light gray to white to light gray; mostly medium grained, some fine and coarse lower, scattered very coarse and pebble; subangular to angular moderately to well sorted; mostly supported in kaolic-ashy matrix including locally slight silty shards and often calcareous in part; predominantly quartz and minor coal and clay lithics, and trace red feldspar and chlorite; estimate mostly very poor porosity; dull yellowy oil mud fluorescence and cut. 9705' Sand/Sandstone = very light gray; fine upper to coarse lower and scattered coarse and pebble; angular to subangular; moderately sorted; mostly loose grains, some in kaolic-ashy matrix, calcareous in part; occasionally silty; 80% quartz, 20% coal and clay lithics, and trace chert, feldspar, chlorite, and hematite; estimate mostly fair porosity and permeability; dull green yellow fluorescence and cut from oil mud contamination. 9765' Sandstone/Sand = very light gray; fine upper to coarse to occasional pebble; angular to subangular; moderately to poorly sorted; mostly kaolic-ashy matrix, calcareous and carbonaceous streaks; occasionally silty; 80% quartz, 20% coal and clay lithics, minor chert increasing in coarser fraction, and trace partially altered feldspar and chlorite; thin zones grading claystone; estimate some fair porosity and permeability; dull green yellow fluorescence and cut from oil mud contamination. 9855' Tuffaceous Claystone = light to medium gray with light brownish gray secondary hues; very firm; dense; massive, irregular cuttings; resinous to waxy luster; clayey to microsparkly luster; expansive and soluble in water; trace microthin black carbonaceous laminations and piece throughout; trace to scattered light gray to greenish gray waxy tuffs; dull green to yellow fluorescence and cut from oil base mud system; no other oil indicators. 9915' Coal = dominantly black with very dark, dusky brown secondary hues; occasionally very firm to hard; brittle to crunchy; dominant planar fracture with occasional Birdseye and conchoidal fracture; platy to blocky cuffings; smooth dense texture earthy to resinous luster; abundant light gray to light greenish gray tuffs; waxy; firm; crumbly; non calcareous. [::1 EPOCH 6 UNOr.,,AL K-13RD2 10000' Tuffaceous Claystone = light to medium gray with strong brownish medium gray secondary hues; irregular shaped cuffing of scooped, curved nature due to pdc bit cuffing action; firm; brittle to crumbly clayey to slightly gdtty texture; dull to earthy to microsparkly luster; trace microthin black carbonaceous laminations interbedded; non calcareous. 10050' Coal = black with dark dusky brown secondary hues; firm to moderately hard; brittle at times; massive, irregular shaped cuffings; planar to birdseye fracture; smooth to slightly gritty texture; earthy to resinous luster; no visible outgassing bubbles detected. 10090' Tuffaceous Claystone = light to medium gray with strong brownish medium gray secondary hues; irregular shaped cuffing of scooped, curved nature due to pdc bit cuffing action; firm; brittle to crumbly clayey to slightly gritty texture; dull to earthy to microsparkly luster; trace microthin black carbonaceous laminations and pieces interbedded; non calcareous; continued greenish yellow fluorescence and cut fluorescence from oil base mud; no oil indicators present. 10155' Sand = very light gray, translucent to clear quartz; very fine to fine with rare medium lithics; angular; well sorted; disaggregated to very loosely consolidated in clayey supporting matrix; trace light gray to light greenish gray, waxy tuff; non calcareous; continued oil base mud masking any possible oil indicators. 10205' Carbonaceous Shale = dark grayish brown to dark brownish black; firm to moderate hard; brittle at times; irregular cuttings due to bit action, occasionally blocky; gritty texture; earthy luster; trace tuffs; greenish yellow sample fluorescence and cut fluorescence due to oil base mud; no oil indicators present. 10250' Sand =light gray overall with individual grains dominantly translucent to frosted white, very light gray, light greenish gray and scattered light to dark dusky red lithics; very fine to coarse grain, dominantly fine to medium; angular; moderate to well sorted; unconsolidated; non calcareous; trace light greenish gray, waxy tuffs; oil indicators masked by oil based mud. 10310' Sand = very light gray; fine to medium and occasional coarse lower to scattered very coarse and pebble; subangular to angular and rare bimodal subrounded pebble; estimate moderately to poorly sorted in variable clay matrix; clay mostly white to light gray with occasional greenish hue, slightly hydrophilic and often calcareous in part, probably dominantly kaolic and locally chloritic in part; occasionally grading claystone, some slightly to moderately organic grading carbonaceous shale; grains 80% quartz, and 20% mostly black to gray partially siliceous coal and clay lithics, and minor feldspar; estimate mostly fair to good porosity and permeability; no oil indicators above oil base mud back ground. [::1 EPOCH 7 UNOr..ALI K-13RD2 10410' Coal = black; slightly firm and brittle; flaky to splintery to hackly; Iow grade; earthy to smooth and shiny luster. 10430' Claystone = medium gray to light gray to brownish gray to cream gray; slightly firm to moderately firm and crumbly to brittle; mostly slightly to occasionally moderately organic often with microlams of various shades of gray and streaks of carbonaceous/coal matter and occasional clasts of coal; some grading carbonaceous shale; moderately hydrophilic decreasing sandy-kaolic; some calcareous in part especially light colored sandy clays; locally interbedded with sandstone and coal. 10500' Sandstone = very light gray; very fine to fine and scattered medium to very coarse; angular to subangular; poorly sorted and matrix supported in ashy kaolic clays; some silty-shard like; often calcareous in part; poorly consolidated to trace hard and siliceous; grains mostly quartz, some partially siliceous coal and clay lithics, and occasional feldspar; often grading to claystone; commonly streaked with carbonaceous matter especially claystone; some grading carbonaceous shale and some interbedded coal. 10575' Coal = black to brownish black; slightly firm and brittle pdc bit splinters and shavings; grading dark brown carbonaceous shale and interbedded with tuffaceous/kaolic claystone. 10605' Claystone = medium light gray to brownish gray to medium gray to very light gray; slightly firm and brittle; abundant bit shavings and splinters; slightly to moderately silty/gritty texture grading clayey siltstone to very fine grained sandstone; mostly slightly to moderately organic including microlams and streaks of carbonaceous matter; moderately hydrophilic expanding light grayish brown to light gray to white; silt mostly angular and shard-like; often very slight disseminated mica; very slight calcareous matter. 10680' Sandstone = very light gray; mostly fine to very fine grains, locally scattered medium to coarse to rare pebble; subangular to angular; poorly sorted in ashy-kaolic matrix with silty texture grading tuffaceous siltstone; often with carbonaceous streaks; grading claystone and minor carbonaceous shale; very poor estimated porosity; no oil indicators above mud background. 10755' Coal = very dark dusky brown to black; firm to brittle; crunchy to crumbly; irregular shaped cuttings due to pdc bit cutting action, finely ground, pulverized shavings; slightly gritty to dense texture; earthy to slightly vitreous luster; lignitic; grading to carbonaceous shale; trace waxy tuffs. EPOCH 8 UNOCAL K-13RD2 10800' Sand/Sandstone = light to medium gray to light greenish medium gray overall; individual grains dominantly light greenish gray, translucent, frosted white, medium gray; very fine to coarse grain, dominantly fine to medium; angular to subangular, larger lithics are more weathered; moderately well to well sorted; very loosely consolidated to dominantly unconsolidated; non calcareous; very light gray, clayey supporting matrix; no oil indicators above oil base mud. 10865' Sand/Sandstone = light to medium gray to light greenish medium gray overall; individual grains dominantly light greenish gray, translucent, frosted white, medium gray, scattered black and rare dusky red; very fine to coarse grain, dominantly fine to medium; angular to subangular, larger lithics are more weathered; moderately well to well sorted; very loosely consolidated to dominantly unconsolidated; non calcareous; no oil indicators above oil base mud background. 10930' Tuffaceous Claystone = medium gray with light brownish gray secondary hues; firm brittle to crumble; scooped shavings from pdc bit action, finely ground and pulverized; clayey to silty to gritty texture earthy to slightly microsparkly luster; occasionally grading to very fine sandstone to coarse siltstone; non to slightly calcareous. 10985' Sandstone = very light gray to light gray; very fine to coarse lower to occasional very coarse and pebble; angular to subangular; poorly sorted in kaolic-ashy matrix; mostly white to translucent quartz and minor chert, some gray to black reworked coal and clay clasts and ram green clasts hard to commonly altered to clay; matrix supported grading to claystone with slight silt to very fine sized shards; poorly consolidated to frosted loose grains; estimate very poor porosity; faint yellow green fluorescence and light, blue diffuse cut indistinguishable from oil mud contamination. 11070' Coal = black; mostly brittle pdc bit splinters and shavings; massive and dense angular to hackly cavings fairly easily fractured along bedding plane laminations; bleeding gas along fresh broken laminations; commonly mottled and microlams in claystone grading carbonaceous shale. 11115' Sandstone = light gray to very light gray; coarse to very fine and scattered very coarse to pebble; angular to subangular; poorly sorted and matrix supported in ashy-kaolic clay with common carbonaceous streaks and occasional calcareous streaks and matter; lithics include mostly quartz and some coal and dark clay lithics, and trace green and dark red lithics hard to partially altered to clay; slightly silty texture overall including shards; estimate very poor porosity; dull greenish yellow fluorescence and light blue to yellow green diffuse cut indistinguishable from oil mud contamination. MARKER 112oo' [:1 EPOCH 9 UNOCAL ) K-13RD2 11200' Coal = black; mostly brittle pdc bit splinters and shavings; massive and dense hackly to wedge cavings; slightly silty texture from brassy microspecs of apparent pyrite; visible laminar beds and blocky/hackly fracture with gas bleeding on fractures. 11260' Sand/Sandstone = light gray to light brownish gray overall with individual grains dominantly frosted translucent quartz grains, light gray to light greenish gray, white, and rare dusky red lithics very fine to rare very coarse lithics, dominantly fine to medium; angular; moderately sorted; angular; loosely consolidated in clayey / ashy supporting matrix; slight to moderately calcareous; trace calcite fragments; sandstone occasionally grading to sandy siltstone; weak greenish yellow fluorescence and cut fluorescence indistinguishable from oil base mud contamination; no oil indicators present. 11340' Carbonaceous Shale = very dark brownish gray to brownish black; slightly firm; brittle and crunchy; splintery and elongated cuttings from pdc bit cutting action; gritty to matte texture; earthy to dull luster; easily fractured along bedding plane; grading to poor grade coal; oil indicators masked by oil base mud. 11390' Coal = black; abundant fine brittle pdc splinters and shavings; occasional cavings subplaty to hackly and dense with thick platy laminations; subblocky cleavage fairly easily fractured mostly along bedding planes; slight bleeding gas mostly from bedding planes; interbedded with dark gray to medium light gray variably organic claystone. 11440' Sandstone = very light gray to light gray; very fine to fine to some medium to coarse grains; angular to subangular; matrix supported throughout grading moderately to slightly hydrophilic ashy-kaolic claystone; slight silty texture overall with common silty shards; slight to very slight calcareous matter; trace with greenish hue; clasts predominantly quartz, some coal and clay; slight to locally moderate carbonaceous streaks and laminations locally grading carbonaceous shale and interbedded coal with slight pyrite; estimate some very poor porosity and permeability; pale green yellow fluorescence and weak cut probably from oil mud contamination. 11530' Carbonaceous Shale = dark gray to dark brownish gray; slightly firm and brittle to crumbly; smooth to slightly silty/gritty texture; moderately to slightly hydrophilic; often medium to very light gray grading tuffaceous claystone and minor sandstone with streaks and microlams of carbonaceous matter; some thinly bedded coal; moderately abundant isolated micropyrite crystals; slightly calcareous; oil indicators masked by oil base mud system. 11615' Coal = black with dark dusky brown secondary hues; finely ground, splintery cuttings from pdc bit action; crunchy and brittle, occasionally hard to very hard with larger pieces; earthy to slightly vitreous luster; smooth to occasionally gritty texture; common planar fracture; rare Birdseye and conchoidal fracture; none to rare visible outgassing bubbles. 39 COAL 11650' [::1 EPOCH 1 o UNOCAL ) K-13RD2 GIST 11677' 11665' Sandstone = light gray overall with individual grains dominantly light gray to light greenish gray, translucent, frosted white and rare dusky red lithics; fine to medium with rare coarse lithics; angular to subangular; moderate to moderately well sorted; unconsolidated to very loosely consolidated with clayey/ashy matrix; estimate some fair to good porosity and permeability; oil indicators masked by oil base mud. 11750' Sand/Sandstone = light gray to light greenish gray, slight to moderate salt and pepper appearance; individual grains dominantly translucent to clear, frosted white, common very dark gray to black lithics, rare light to dark dusky red lithics very fine to occasionally very coarse, angular to subangular; some loose grains to mostly matrix supported in ashy-kaolic matrix grading to claystone; estimate some fair porosity; oil indicators masked by oil base mud system. 11820' Claystone = brownish gray to medium gray to dark brownish gray to medium light gray; slightly firm and brittle to crumbly to occasionally very firm; slightly to very carbonaceous with thinly bedded brownish black to black coal; lightly speckled micropyrite associated with carbonaceous matter; smooth to silty texture including shards; non-calcareous; moderately hydrophilic overall; some interbedded ashy-koalic sandstone/claystone. G3ST 11850' 11885' Sand/Sandstone = very light to light gray; fine to medium to some scattered very coarse and pebble; angular to subangular; poorly to some moderately sorted in mostly matrix supported ashy-kaolic clay; some interbedded variably carbonaceous to tuffaceous claystone, and siltstone to very fine sandstone; mostly quartz and some coal, dark clay, and chert lithics; trace chloritic clay; slight calcareous; estimate some fair porosity and permeability; oil indicators masked by oil base mud. 11975' Sand/Sandstone = light gray to very light brownish light gray overall; individual grains dominantly translucent to frosted, light gray to light greenish gray, black; fine to very coarse, common pebbles and pebble fragments, dominantly medium grain; angular; poorly sorted; loosely consolidated in clayey/ashy supporting matrix; slightly calcareous; dominantly quartz grains and very coarse quartz fragments; estimate poor to fair porosity and permeability; yellowish white sample fluorescence and instant bright greenish yellow cut fluorescence; indistinguishable from oil base mud fluorescence; no oil indicators present. 12065' Conglomerate = medium gray to light gray overall; pebbles and fragments in sandy to clayey matrix; clay light gray and commonly streaked to laminated with carbonaceous matter; non to slightly calcareous; lithics include smoky chert, quartz, dark partially siliceous clays, coals, and siltstone to very fine sandstone, rare varicolored meta lithics, and trace red; very poor porosity. EPOCH 11 UNOCAL ) K-13RD2 12120' Coal = black to some brownish black; abundant brittle pdc bit shavings; some firm to hard cavings with hackly to angular to slightly conchoidal fracture; some visible laminar bedding; massive to locally grading dark gray to dark brown gray carbonaceous shale; slight tiny micropyrite speckles throughout; slight bleeding gas. GSST 12160' 12170' Sand/Sandstone = very light gray to light gray; very fine to very coarse grains especially fine upper to medium, and locally scattered pebble; angular to subangular, occasional rounded pebble; poorly to moderately sorted often matrix supported in ashy-kaolic clay; lithics mostly quartz and minor chert, coal, and clay, and trace green; very slightly calcareous; some carbonaceous streaks in clay matrix; estimate mostly poor to some fair porosity and permeability; oil indicators masked by oil based mud. 12265' Coal =black with very dark brown secondary hues; firm to brittle; splintery, finely ground cuttings due to pdc bit action; planar to conchoidal fracture; scattered visible laminar bedding; gritty to smooth texture; earthy luster; grading to dark brown to dark brownish gray carbonaceous shale; no to very slight visible outgassing bubbles; present as very thin beds in dominantly claystone/siltstone formation. G6ST 12350' 12330' Siltstone = medium gray; slightly firm; pdc splinters and shavings; very clayey grading claystone; some gritty grading medium light gray very fine grained sandstone with scattered fine to medium grains; moderately hydrophilic; non to very slightly calcareous; lightly streaked carbonaceous matter and clasts occasionally grading carbonaceous shale; very slight micropyrite. 12385' Claystone = medium gray to medium light gray to brownish gray; slightly firm and brittle to crumbly; abundant pdc bit shavings; smooth to silty/gritty texture; some grading siltstone and very fine to fine grained sandstone; mostly slight carbonaceous matter to some grading carbonaceous shale and locally interbedded coal. CASING DEPTH AT 12430' FOR 7" LINER IN G7ST TOP HEMLOCK 12470' 12470' Sand = light gray to light brownish light gray overall with individual grains dominant light gray, translucent to clear quartz, black, rare white clay, and trace chloritic clay and red lithics; fine to medium grains; angular to subangular to subrounded; locally some angular fragments and rounded pebbles including mostly coal and carbonaceous shale clasts and minor quartz; mostly loose grains to some clay matrix; estimate some fair to good porosity and permeability; dull yellow fluorescence and slight instantaneous to slow streaming cut; oil indicators masked by oil base mud. EPOCH 12 UNOCALe K-13RD2 12565' Sand/Sandstone = light gray to light olive gray; fine to coarse grains, mostly medium; angular to subrounded, some bit broken; moderate sphericity; estimate moderately sorted and poorly to moderately consolidated in slight overall clay matrix with minor quartz overgrowth; very slightly calcareous; clasts include quartz, coal, gray to white to green clay, and red and green hard lithics; estimate some fair to good porosity and permeability; oil indicators masked by oil base mud. 12650' Sand = light gray to light olive gray; fine to coarse lower, some very fine, and scattered very coarse to pebble; angular to some subangular and local subrounded fraction, some bit broken; Iow to moderate sphericity; poorly to moderately sorted; clasts include quartz, and some chert, coal, gray to olive gray to white partially siliceous clay, and trace red lithics; very slight calcareous; overall slight to very slight clay matrix; estimate mostly poor to fair porosity and permeability; dull even yellow fluorescence and very light brown stain indistinguishable from oil mud contamination; instantaneous light blue yellow cut. 12740' Sand = light olive gray to olive gray; fine to coarse lower and scattered very coarse and pebble sized grains and fragments; angular to subrounded; Iow to moderate sphericity; estimate poorly to moderately sorted in very slight to slight clay matrix; 80% quartz, and 20% coal, gray to grayish green to white occasionally slightly siliceous clay, bluish chert, and trace red possible feldspar; estimate mostly fair to poor porosity and permeability; dull even yellow fluorescence and faint light brown stain; instantaneous light bluish yellow cut; oil indicators indistinguishable from oil mud contamination. 12840' Sand = olive gray to light olive gray; very fine to coarse lower especially fine to medium grains, and often with scattered very coarse to pebble; subrounded to angular including bit broken pieces; estimate moderately to some poorly sorted with slight to very slight overall clay matrix; occasional gray to white clay probably clasts; slight calcareous cement throughout; clasts include 85% quartz, and 15% coal and carbonaceous matter, gray to dark gray to green to white lithics mostly clay and minor chert, and trace red including feldspar; estimate some fair to good porosity and permeability; dull yellow even fluorescence and faint light brown stain; instantaneous diffuse bluish yellow cut; oil indicators indistinguishable from oil mud contamination. 12975' Sand = light gray to light brownish gray with scattered "salt and pepper" appearance, individual grains dominantly translucent to frosted white, light gray, light green to light greenish gray, abundant black lithics, rare dusky red lithics; very fine to coarse, dominantly fine to medium grain; angular to subrounded; fair to moderate sorting; unconsolidated to very loosely consolidated; slightly calcareous; estimate fair porosity and permeability; trace black carbonaceous material; uniform, dull yellowish gold sample fluorescence; instant bright bluish yellow cut fluorescence; dull gold residual ring fluorescence; light straw residual; oil indicators indistinguishable from oil base mud contamination [:1 EPOCH 13 UNOCAL ) K-13RD2 13070' Sand = light gray to light brownish gray very fine to scattered coarse, dominantly fine to medium grain; angular to subround dominantly subangular to angular; fair to moderately well sorted; disaggregated to very loosely consolidated with clayey to ashy supporting matdx; none to slight calcareous cement; fair to good estimated porosity and permeability; oil indicators continue to be masked by oil base mud. 13125' Sand = light gray to light brownish gray with scattered "salt and pepper" appearance, individual grains dominantly translucent to frosted white, light gray, light green to light greenish gray, abundant black lithics, rare dusky red lithics; very fine to coarse, dominantly fine to medium grain; angular to subrounded; fair to moderate sorting; unconsolidated to very loosely consolidated with clayey supporting matrix; slightly calcareous; fair to good porosity and permeability; trace black carbonaceous material; dull yellow, uniform sample fluorescence; instantaneous, bright bluish yellow cut fluorescence; oil indicators indistinguishable from oil base mud contamination 13220' Sand = light olive gray to olive gray; very fine to coarse lower, especially fine to medium, and scattered very coarse to pebble sized; subangular to angular including bit broken; estimate moderately to poorly sorted with slight overall clay matrix; very slightly calcareous; clasts include 80% quartz, and 20% coal, carbonaceous matter, white to gray to green to brown lithics mostly clay and minor chert and silt, and trace red; estimate mostly fair porosity; oil indicators masked by oil base mud. 13305' Sand = light olive gray: very fine to coarse lower, especially fine to medium, and often locally scattered very coarse to trace pebble size; subangular to angular including some bit broken; moderate to some Iow sphericity; estimate moderately to poorly sorted in slight to very slight clay matrix; matrix very slightly calcareous including calcareous matter; 85% quartz, and 15% black to dark gray to brownish black to gray to white to green to red clasts including coal and carbonaceous matter, some siliceous or possible dark mafics, and clay, and minor chert and feldspar; estimate mostly fair to occasional good porosity and permeability; dull even yellow fluorescence and very faint light brown stain; instantaneous diffuse bluish yellow cut; oil indicators indistinguishable from oil mud contamination. 13430' Sand = light olive gray to some olive gray; very fine to medium and scattered coarse, and rare pebble sized clay, coal and locally quartz clasts; subangular to angular including bit broken; estimate poorly to moderately sorted with very slight to slight overall clay matrix; very slightly calcareous overall clasts 80% quartz, and 20% black to dark gray to gray to brownish black to green to white to red to rust including mostly coal and clay often siliceous to grading chert, possible dark mafics and minor feldspar; estimate mostly poor to fair and occasionally good porosity and permeability; uniform dull yellow fluorescence and very faint light brown stain; instantaneous bluish yellow cut; oil indicators indistinguishable from oil base mud contamination. EPOCH 14 UNOCALe K-13RD2 13535' Sand = light olive gray to olive gray; very fine to very coarse and scattered pebble, angular to subangular; Iow to moderate sphericity; poorly to moderately sorted in slight to very slight clay matrix with occasional lenses matrix supported; clasts include 75% quartz, and 25% coal, clay, siliceous lithics and chert, possible dark mafics, and minor feldspar; estimate poor to fair porosity and permeability; dull uniform fluorescence and faint stain indistinguishable from oil mud contamination. 13620' Sand = light olive gray to some olive gray; very fine to medium and scattered coarse, and rare pebble sized clay, coal and quartz clasts; subangular to angular including bit broken; estimate moderately to poorly sorted with very slight to slight overall clay matrix; very slightly to slightly calcareous overall including rare calcite; clasts 80% quartz, and 20% black to dark gray to gray to brownish black to white to rare green to red to rust, including mostly coal and clay often siliceous to rare chert, possible dark mafics and minor feldspar; estimate mostly fair porosity and permeability; uniform dull fluorescence and faint stain indistinguishable from oil mud contamination. 13730' Sand = light gray to olive gray; very fine upper to medium upper with occasional bit broken coarse and pebble size grains; sub angular to angular with occasional subround grains; Iow to moderate sphericity; moderate sorting; consists of 70% clear and translucent quartz grains, 20% light to dark gray chert, 10% coal, mafics and lithic fragments; rare tuffaceous ash and clay; estimated fair to occasional good intergranular porosity; fluorescence and cut obscured by oil based mud. 13800' Sand = light gray to olive gray; very fine lower to medium upper with increasing coarse and pebble size grains; predominantly subangular to angular with occasional subround; Iow sphericity; poorly to occasionally moderately sorted; composed of 60% clear and transparent quartz grains, 20% light and dark gray chert, 10% coal, lithics and mafics; estimated fair to occasional good intergranular porosity; oil indicators obscured by oil mud. 13870' Sand = light gray to olive gray; very fine lower to medium upper with occasional coarse and pebble size grains; predominantly subangular to angular with occasional subround; Iow sphericity; moderately poorly sorted; composed of 60% clear and translucent quartz grains; 20% light and dark gray chert, 10% lithic fragments and coal, 10% tuffaceous clay/ash; estimated fair to poor intergranular porosity; fluorescence and cut obscured by oil based mud. 13955' Sand = light gray to olive gray; predominantly very fine lower to medium lower with occasional coarse and pebble size grains; moderately sorted; predominantly subangular to angular; moderate to Iow sphericity; composed of 70% clear and translucent quartz grains, 20% light and dark gray chert; 10% coal, mafics and lithic fragments; estimated poor increasing to fair porosity with depth; grain size increasing with depth; oil indicators obscured by oil based mud. [::1 EPOCH 15 UNOEAL K-13RD2 14020' Sand = light gray to olive gray; fine upper to coarse with occasional very coarse pebble size grains; moderately well sorted; angular to subangular; Iow sphericity; consists of 90% quartz, 10% chert and lithic fragments; estimate mostly fair porosity and permeability; dull uniform yellow fluorescence and faint light brown stain; oil indicators obscured by oil based mud. 14080' Sand = light olive gray to olive gray; very fine to medium and scattered coarse to pebble sized grains including bit broken; angular to subangular; moderate to Iow sphericity; estimate moderately to some poorly sorted with estimated very slight overall clay matrix and occasional thin clayey lenses; clasts include 85% quartz, and 15% black to gray to white to green to trace red including coal, clay, chert to siliceous lithics, and minor feldspar; trace to rare calcareous matter; estimate mostly fair porosity and permeability; dull yellow even fluorescence and faint stain with instantaneous bluish yellow cut; oil indicators obscured by oil base mud contamination. 14175' Sand = light olive gray to olive gray; very fine to coarse and scattered very coarse to pebble sized grains including bit broken; angular to subangular; Iow to moderate sphericity; estimate moderately to poorly sorted with overall slight clay matrix and occasional clayey lenses/clasts; clasts include 80% quartz and 20% black to gray to white to brown to rare green and red lithics including coal, clay, siliceous lithics and chert, and minor feldspar; estimate fair to some poor porosity and permeability; oil indicators masked by oil base mud. 14265' Sand = light olive gray; very fine to coarse lower especially fine to medium, and scattered very coarse to occasional pebble sized grains and bit broken fragments; angular to subangular; estimate moderately to some poorly sorted; estimate very slight clay matrix with occasional clayey lenses commonly with coarse coal clasts; overall clasts 75% quartz, and 25% black to brownish black to gray to white to occasional green and red including coal, chert and siliceous lithics, clay, and rare feldspar; slight calcareous matter; estimate mostly fair porosity and permeability; oil indicators obscured by oil base mud contamination. 14370 'Sand = light gray; very fine to medium with occasional bit fractured coarse and pebble size grains; moderately poorly sorted; subangular to subangular; Iow to moderate sphericity; composed of 90% quartz, <5% chert, >5% lithic fragments and tuff material; trace coal; occasional tuffaceous clay laminae; estimated fair to occasional good intergranular porosity; oil indicators obscured by oil based mud. [::1 EPOCH 16 UNOCALe K-13RD2 t. 14435' Sand = light olive gray; very fine to coarse lower especially fine to medium, and scattered very coarse to occasional pebble sized grains and bit broken fragments; angular to subangular; estimate moderately to some poorly sorted; estimate very slight clay matrix with occasional very light gray clayey lenses; clasts 80-85% quartz, and 15-20% black to brownish black to gray to white to rare red and green including carbonaceous to tuffaceous to rare chloritic clay; coal, chert and siliceous lithics; and rare calcareous matter and feldspar; estimate mostly fair porosity and permeability; dull even yellow fluorescence and very faint light brown stain indistinguishable from oil mud contamination. 14530' Sand = light olive gray; very fine to coarse lower especially fine to medium, and slightly scattered very coarse to pebble sized grains and bit broken fragments; angular to subangular; estimate moderately to some poorly sorted; estimate very slight clay matrix with occasional very light gray clayey lenses; clasts 80-85% quartz, and 15-20% black to brownish black to gray to white to rare red and green including carbonaceous clay and coal, tuffaceous to kaolic to rare chloritic clay, chert and siliceous lithics; rare calcareous matter and feldspar; estimate mostly fair porosity and permeability; oil indicators masked by oil base mud contamination. 14635' Sand = light olive gray; very fine to medium, especially fine lower to medium lower, and scattered coarse to trace pebble; subangular to angular, estimate moderate to moderately well sorted; estimate very slight clay matrix; clasts 85% quartz, and 15% black to dark brown to gray to white to trace red and green including carbonaceous clay and coal, siliceous lithics and chert, rare tuffaceous to kaolic to chloritic clay, rare calcareous matter and trace feldspar; estimate mostly fair porosity and permeability; oil indicators masked by oil base mud contamination. 14730' Sand = light olive gray; very fine to medium, especially very fine upper to medium lower, and scattered coarse to very coarse; subangular to angular, moderately high to moderately Iow sphericity; estimate moderately to moderately well sorted with estimated very slight clay matrix and rare thin clayey lenses; clasts 80% quartz, and 20% black to dark brown to gray to white to rare red and green including predominantly siliceous-cherty coal and carbonaceous clay, kaolic to tuffaceous to trace chloritic clays, some siliceous, and trace feldspar; estimate mostly fair porosity and permeability; dull even yellow fluorescence and very faint brown stain and bluish yellow instantaneous to diffuse cut; oil indicators masked by oil based mud contamination. 14860' Sand = light gray to light olive gray; very fine lower to coarse, predominantly medium; moderately to poorly sorted; angular to subround; Iow sphericity; composed of 70% clear and translucent quartz grains, 15% light and dark gray chert, 10% lithic fragments, mafics, coal, trace feldspar, 5% tuffaceous clay and ash; estimated good to fair inter- granular porosity; occasional tuff clay/ash matrix infilling porosity in part; common tuffaceous clay laminae; oil indicators obscured by oil based mud. [::1 EPOCH 17 UNOCAL K-13RD2 14930' Sand = light to medium gray to olive; fine to coarse with trace bit fractured very coarse and pebble size grains; moderately poorly sorted; subangular to angular; Iow to moderate sphericity; composed of 70% clear and translucent quartz grains, 15% light and dark gray chert, 10% lithic fragments, mafics, coal, trace feldspar, 5% tuffaceous clay and ash; estimated good to fair inter- granular porosity; occasional tuff clay/ash matrix infilling porosity in part; common tuffaceous clay laminae; oil indicators masked by oil based mud. 15020' Sand = light gray to olive gray; very fine to lower coarse; moderately poorly sorted; angular to subangular; Iow sphericity; abundant evidence of bit shattering of grains; composed of 80% clear and translucent quartz grains, 10% light and dark gray chert, 10% lithics and coal; estimated fair to poor inter- granular porosity; occasional tuffaceous ash/clay laminae; possible ash/clay infilling porosity in part; oil indicators obscured by oil based mud. 15085' Coal = black to occasionally brownish- black; hard; brittle; fissile to platy; tabular to wedge like cuttings; planar to irregular fracture; resinous luster. 15110' Tuffaceous Claystone = light to medium gray; brittle to crumbly in part; massive to irregular cuttings habit; irregular to subplatey fracture; smooth to slightly gritty texture in part; trace carbonaceous material. 15145' Sand = medium gray to grayish brown; very fine to predominantly medium to coarse; moderately sorted; angular to subangular; Iow to moderate sphericity; abundant bit fractured grains; composed of 80% clear and translucent quartz grains, 10% lithics, mafics and feldspar, 10% tuffaceous clay and ash; abundant coal cavings decreasing with depth; clay appears as laminae and infilling porosity in part; estimate fair to poor intergranular porosity; oil indicators obscured by oil based mud. 15230 Sand = light to medium gray; very fine lower to coarse upper with common bit fractured pebble size grains; poorly sorted; angular to sub angular; Iow to moderate sphericity; samples very finely ground in part due to slow penetration composed of 75% quartz grains; 15% lithics, coal, mafics and accessories; 10% light and dark chert; common dark gray to brownish gray to cream clay and silty clay as matrix to thinly bedded, possible trace lenses/laminations of coal; estimate mostly poor to fair porosity and permeability; oil indicators masked by oil based mud [-.1 EPOCH 18 UNOCALe K-13RD2 15315 Sand = medium dark gray to olive gray; very fine to coarse lower, and ram very coarse to trace pebble; angular to subrounded including bit broken fragments; Iow to high sphericity; poorly sorted in slight clay and silty clay matrix; clasts 80% quartz, and 20% dark gray to very light gray clay and minor coal; clay and coal clasts appear mostly reworked to some flaky to subplaty and probably thinly bedded; very slight calcareous matter; trace green hue in clay and trace red lithics; estimate poor to fair porosity and permeability; very dull even yellow green fluorescence and weak cut; oil indicators masked by oil based mud contamination 15405 Coal = black; moderately firm and moderately brittle; hackly to flaky fracture; massive to thinly bedded in claystone and sandstone. 15435 Tuffaceous Claystone = light to medium gray; brittle to crumbly in part; massive to irregular cuttings habit; irregular to subplaty fracture; smooth to slightly gritty texture in part; commonly with carbonaceous streaks; interbedded with coal in part. TOTAL DEPTH: MD: 15485' TVD: 9737' [::1 EPOCH 19 UNOCAL ) K-13RD2 DAILY CHRONOLOGY 0511312001: 8740' Epoch arrived on location on 5/13/01 at 12:30 PM, attended safety meeting, and rigged up. Rig had cut window in casing at 8730' and drilled to 8740' before testing formation, pulling out of hole and picking up mud motor assembly with MWD tool, and were tripping to bottom to drill ahead while Epoch dgged up. 0511412001: 8740-9240' Epoch commenced logging at 8740' at 12:20 am. Rotate and slide as per directional plan from 8740' to 8912'. Pull out of hole to window to clear flow line, orient mud motor, trip to bottom, and continue to rotate and slide from 8912' to 9240'. Drilling averaged 34 feet per hour, and gas averaged 15 units with no detectable downtime or connection gas. Drilled with oil base mud, 9.1 to 9.2 ppg. 0511512001: 9240-9856' Rotate and slide from 9240 to 9856'. Drilling averaged 34 feet per hour, gas averaged 8 units with no detectable downtime or connection gas, while mud weight was maintained at 9.2 PPg. 0511612001: 9856-9983' Rotate and slide as per directional plan from 9856' to 9983'. Pull out of the hole and lay down the BHA. Make up test jet and pull wear ring. Test BOPs, fix leak in hydrill accumulator hose, fix control on IBOP, and install air dryer in sub base. Pick up and run in with new BHA with new mud motor, and test MWD. Pull out BHA and change MWD. Pick up 72 joints of 5" drill pipe, and trip in hole. Drilling averaged 25 feet per hour, gas averaged 10 units with no detectable downtime or connection gas, and the mud weight was reported at 9.25 ppg. 05/1712001: 9983-10738' Finish tripping in hole to 9920', and ream to 9983', drill ahead from 9983' to 10738' sliding from 10159' to 10181'. Drilling averaged 42 feet per hour, and gas averaged 10 units with no detectable connection gas. The mud weight was reported at 9.3 ppg, while recording 71 units of trip gas. EPOCH 20 UNOCALe K-13RD2 05118/2001: 10738-11250' Drill from 10738 to 11250', sliding from 11212 to 11232', and drilling with pump no. 1 from 11232 to 11240' while working on pump no. 2. Drilling averaged 26 feet per hour, the mud weight was maintained at 9.2 to 9.3 ppg, and gas averaged 9 units with no detectable downtime or connection gas. 0511912001: 11250-11594' Drill ahead from 11250' to 11594', sliding from 11375-11385', 11393-11417', and 11583-11594'. Drilling averaged 16.5 feet per hour, the mud weight was maintained at 9.3 to 9.35 ppg, and gas averaged 9 units with no detectable downtime or connection gas. 0512012001: 11594-11717' Drill ahead from 11594' to 11717', sliding from 11697 to 11703'. Drilling averaged 11.4 feet per hour, the mud weight was maintained at 9.2 to 9.35 ppg, and gas averaged 11 units with no detectable downtime or connection gas. Circulate out and pump pill, and pull out of hole for new bit and mud motor. Trip in hole with bit #3. Cut and slip drill line at shoe. 0512112001: 11717-11954' Finish cut and slip drill line at shoe, orient mud motor, and trip in to 11600'. Ream to 11717', and drill ahead from 11717' to 11954', sliding at 11722 to 11733', 11742 to 11777', 11807 to 11812', and 11841 to 11873'. Drilling averaged 15.9 feet per hour, mud weight was reported at 9.4 ppg, and gas averaged 6 units with no detectable connection gas. Trip gas at 11717' was 120 units. 0512212001: 11954-12236' Rotate and slide from 11954' to 12236', sliding from 11974-11982', 12127-12152', 12160- 12171' Drilling averaged 13.8 feet per hour, mud weight was reported at 9.3 to 9.35 ppg, and gas averaged 10 units. Connection gas measured 22 units over background at 12,199', the result of coal sloughing while back reaming through a thick coal zone drilled before the connection. No other detectable connection gas occurred. 0512312001: 12236-12430' Drill ahead, rotating from 12236' to 12430', casing point, circulate bottoms up to confirm out of coal zone, circulate out high viscosity sweep, pump dry job, and begin to pull out of the hole. Drilling averaged 9.7 feet per hour, mud weight was increased from 9.3 to 9.4 ppg due to sloughing coals, and gas averaged 10 units. Connection gas measured 6 units over background at 12286', due to coal zone at connection depth. No other detectable connection gas occurred. EPOCH 21 UNOr..AL K-13RD2 0512412001: 12430' Pull out off hole to shoe, back reaming at 11765' and 11698'. Run back in hole and circulate and condition hole, trip gas 33 units with a 9.45 ppg mud. Pull out of hole and lay down BHA. Install 7" rams and test BOP. Rig up GBR tools to run liner. Begin to run in hole with 7" liner. 0512512001: 12430' Run in with 7" liner. Run liner in with drill string, and circulate and condition hole while working pipe, 92 units of trip gas. Rig up Dowell, and complete cement job setting liner from 12430' to 8487'. Attempt to test backside. 05/2612001: 12430' Pressure test surface equipment, no good, look for leaks. Retest, hold for 40 minutes, good test. Pump dry job, and pull out of hole to 3731'. Lay down 5" drill pipe and HWDP. Change rams and test BOP. Service top drive and change out saver sub. Pick up bales and 3 %" lift equipment. Start making up BHA. 0512712001: 12430-12446' Finish making up BHA, and test MWD Tool. Pick up and run in with 3 %" HWDP. Pick up and run in with 5091.2' of 3 %" drill pipe and one stand of 5" drill pipe. Cut and slip drill line. Continue to run in hole with 5" drill pipe down to 12216'. Wash down to 12297' and drill landing collar. Wash and ream cement, shoe and formation down to 12446'. Drilled formation at 16 feet per hour average, with 21 units of trip gas, and an average 13 units of background gas with a 9.8 ppg mud. 0512812001: 12446-12627' Drill from 12446' to 12450' and circulate out. Perform formation integrity test, 11.0 EMW. Drill ahead, rotating and sliding, from 12450' to 12627'. Circulate 35 minutes, pull three stands wet, circulate and pump pill and trip out of hole. Drilling averaged 17.7 feet per hour, mud weight was reported at 9.4 ppg, and gas averaged 8 units with no detectable downtime or connection gas. 0512912001: 12627-12842' Finish tripping out of hole, change BHA and bit, download MWD, service top drive, rig, and crown, and test MWD. Trip in hole to 12513', ream to 12627', and drill ahead, rotating and sliding, from 12627' to 12842'. Trip gas was 10 units. Drilling averaged 18.4 feet per hour, mud weight was reported at 9.35 to 9.5 ppg, and gas averaged 7 units with no detectable downtime or connection gas. EPOCH 22 UNOr. K-13RD2 0513012001: 12842-13002' Drill ahead from 12842' to 12847', circulate 30 minutes, and pull out of hole to shoe. Drop dart and pump pill and pull out of hole. Change pump out sub and bit, and test MVVD twice. Trip in hole to 12419', ream to 12847', and drill ahead, rotating and sliding, from 12847' to 13002'. Drilling averaged 34.8 feet per hour, mud weight was reported at 9.35 to 9.45 ppg, and gas averaged 8 units with no connection gas. Trip gas was 8 units. 0513112001: 13002-13278' Drill ahead, rotating and sliding, from 13002' to 13278', circulate 30 minutes, and pull out of hole 9 stands. Drilling averaged 20.8 feet per hour, mud weight was reported at 9.3 ppg, and gas averaged 13 units with no detectable downtime or connection gas. Drop dart and pump pill and pull out of hole. Change out bit and motor. Pick up and run in with 18 joints 3 ~" drill pipe. Continue running in hole with 3 ~" pipe, and begin running in with 5". 06/0112001: 13278-13325' Finish tripping in hole, and ream from 13128 to 13278', as old bit was %" out of gage. Drill ahead, rotating, from 13278' to 13325'. Drilling averaged 15.8 feet per hour, mud weight was reported at 9.4 ppg, and gas averaged 13 units with no connection gas and 9 units of trip gas. Circulate 65 minutes, and pull out of hole 9 stands. Drop dart and pump pill and pull out of hole. Test BOPE'S. Change out bit and motor, test MWD, trip in hole. 06102/2001: 13325-13602' Test top drive, pick up bit and motor, run in hole with BHA, and test MWD. Run in hole with 3 ~" drill pipe, cut and slip drill line, and service top drive and draw works. Run in hole with 5" drill pipe to bottom at 13325', washing down on last stand. Drill ahead, rotating and sliding, from 13325' to 13602'. Drilling averaged 23.3 feet per hour, mud weight was reported at 9.4 ppg, and gas averaged 9 units with 12 units of trip gas and no detectable connection gas. 0610312001: 13602-t3745' Drill ahead from 13602' to 13607', circulate 35 minutes, check flow, pump dry job and pull out of hole. Make up BHA with new bit and stabilizer, test MWD, and trip in hole with 3 %" pipe and 5" pipe. Wash and ream last stand, and drill ahead from 13607' to 13745'. Drilling averaged 19.6 feet per hour, mud weight was reported at 9.4 ppg, and gas averaged 8 units with no detectable connection gas and 9 units of trip gas. EPOCH 23 UNOr. K-13RD2 0610412001: 13745-13900' Drill ahead from 13745' to 13900'. Drilling averaged 21.5 feet per hour, mud weight was reported at 9.35 to 9.45 ppg, and gas averaged 15 units with no detectable downtime or connection gas. Circulate 30 minutes, survey, check flow, and pump dry job. Pull out of hole to 12904', work tight spot, then circulate 2 hours while working pipe. Pull out of hole to bottom of liner, shear pump out sub, pump pill, and pull out of hole. Make up BHA with new bit, MWD probe, and pump out sub, and trip in hole with 3 %" pipe. Trip in to 7" liner shoe with 5" drill pipe. 06105/2001: 13900-14226' Finish tripping in with 5" drill pipe and ream 50 feet to bottom at 13900'. Drill ahead, rotating, from 13900' to 14226'. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with 7 units of trip gas but no connection gas. Circulate 30 minutes, pump dry job, and pull out of hole with 5" drill pipe. 06106/2001: 14226-14336' Finish pulling out of hole with 5" drill pipe, and pull out of hole with 3 %". Change BHA with new bit and mud motor sleeve. Pick up 15 joints of 3 %" drill pipe and run in hole with 3 %". Cut and slip drill line, and service brakes and top drive. Run in hole with 5" drill pipe to 14219'. Ream to bottom, 14219' to 14226', and drill ahead, rotating and sliding, from 14226' to 14336'. Trip gas at 14226' was 9 units, drilled an average 24.4 feet per hour, and gas averaged 8 units with no connection gas. Mud weight was reported at 9.5 ppg. Circulate 30 minutes and pump pill. Begin tripping out of hole. 06107/2001: 14336-t4364' Pull out of hole to shoe, check flow, and pull out of hole. Make up new BHA with new bit and mud motor, service rig, and run in hole with 3 %" drill pipe. Run in hole with 5" drill pipe, ream to bottom, 14219' to 14336', and slide from 14336' to 14364'. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with 7 units of trip gas but no connection gas 06/0812001: 14364-14600' Drill ahead sliding and rotating from 14364' to 14600', circulate 30 minutes and pump dry job. Pull out of the hole to shoe and drop dart, pressure test to 1800 psi, pump out sub and continue to pull out of the hole. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with no detectable downtime or connection gas El EPOCH 24 UNOCALe K-13RD2 06109/2001: 14600-14704' Test BOPE's, and run in with BHA with new bit #13. Pick up and run in with 9 joints of 3 %", and run in with rest of 3 %" and fill pipe. Run in with 5" to bottom, filling pipe at shoe and washing down on last stand. Ddll ahead, sliding and rotating to 14704', and unable to circulate after back reaming at connection. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with 7 units of trip gas but no connection gas. Pull out of hole. 06/1012001: 14704-14719' Pull out of hole with 3 %". Make up BH^ with new motor, bit #14, and pump out sub, and download and test MWD tool. Run in with new BHA and 3 %", fill hole, cut and slip drill line, and service rig. Run in hole with 5" down to 14607', and wash to bottom at 14704'. Drill ahead, rotating and sliding, from 14704' to 14919'. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with 7 units of trip gas but no connection gas 0611112001: 14919-15069' Drill ahead, rotating and sliding, from 14919' to 15014', circulate 45 minutes, check flow, and pull out of hole to shoe. Drop dart, pull out 5 stands, pump dart and shear sub, and pump dry job. Pull out of hole, and change BHA with new bit and pump out sub, and add stabilizer. Test MWD and pick up and run in hole with 15 joints of 3 %" drill pipe. Run in hole to 14899', and ream to bottom. Drill ahead, rotating from 15014' to 15069'. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with 7 units of trip gas and no connection gas 0611212001: 15069-15230' Drill ahead, rotating and sliding, from 15069' to 15230', circulate 20 minutes, check flow, and pull out of hole to shoe.. Drilling averaged 20.5 feet per hour, mud weight was reported at 9.4 to 9.5 ppg, and gas averaged 10 units with no detectable downtime or connection gas. Drop dart, pump dart, shear sub, and pump dry job. Pull out of hole, and change BHA with new bit and pump out sub, and add MWD logging tool. 061131200t: 15230' Continue making up BHA and load nukes. Run into hole. Wash and ream 12667'-12691', no go, tight. Pull out of hole to shoe and circulate bottoms up and pump dry job. Pull out of hole and change BHA. Run into hole and then slip and cut drill line. ,,061!412001: 15230-15468' Finish running in hole after filling pipe at shoe, and working through tight spots at 14288 to 14322', 14342 to 14621', and 14723 to 14733'. Wash and ream to bottom on last stand, and drill ahead, rotating, from 15230' to 15468'. Drilled at an average 13.4 feet per hour and 5 units of gas, with 8 units of trip gas and no connection gas. Mud weight was 9.3 PPg. ['-I EPOCH 25 UNOCAL ) K-13RD2 06115/2001: 15468-15485' (TOTAL DEPTH) Drill ahead from 15468 to 15485', total depth as drilled into coal, and circulate 20 minutes. Drilled at an average 12.0 feet per hour and 12 units of gas. Mud weight was 9.3 ppg. Pull out of hole to shoe back reaming at less than 300 feet per hour, as logging while back reaming. Pull out of hole 11 stands and service rig, and continue to pull out of hole. EPOCH 26 UNOCAL K13 RD2 MUD RECORD Date Depth TVD MW VIS PV YP Gel FL HTHP Cake Sol C.Sol Oil Wtr O/W Pom! CI- Salt Lime E- stab 5/13/01 8,740' 7,190' 9.15 127 23 21 19/25/27 7.0 /2 8 7.1 76 16 83/17 .4 20K 16.36 0.52 1200 5/14/01 9,248' 7,405' 9.15 107 25 18 18/23/24 6.8 /2 8.5 7.5 77 14.5 84/16 .5 25K 21.25 0.65 1320 5/15/01 9,868' 8,096' 9.20 95 27 20 19/25/26 6.8 /2 9 8 77 14 85/15 .6 23K 20.45 0.78 1350 5/16/01 9,983' 8,166' 9.25 102 26 17 21/27/29 6.5 /2 9 8 77 14 85/15 .75 25K 21.84 0.98 1656 5/17/01 10,733' 8,635' 9.30 90 28 18 24/29/32 5.7 /2 10 10 78.5 11.5 88/12 .65 25K 3.29 0.85 1875 5/18/01 11,225' 8,963' 9.30 82 24 17 23/27/30 /2 10 10 79 11 89/11 .65 23K 24.65 0.85 1775 5/19/01 11,595' 9,183' 9.35 81 27 17 22/29/31 6.3 /2 11 11 78 11 89/10 .7 24K 25.45 0.91 1900 5/20/01 11,717' 9,283' 9.35 108 27 17 24/28/32 6 /2 13 13 78 9 91/9 .6 26K 31.13 0.78 1950 5/21/01 11,955' 9,403' 9.40 88 27 17 21/28/32 6.4 /2 12 12 80 8 91/9 .5 25K 32.84 0.65 1950 5/22/01 12,233' 9,552' 9.35 83 25 18 19/24/27 6.2 /2 11 10 81 8 91/9 .6 22.5K] 30.56 0.78 1900 5/23/01 12,430' 9,660' 9.40 78 24 19 19/24/25 6.2 /2 11 10 82 7 92/8 .5 21K 31.95 0.65 2000 5/24/01 t2,430' 9,660' 9.45 104 25 19 19/25/26 6.0 /2 12 11 82 6 93/7 .5 20K 34.28 0.65 2000 5/25/01 12,430' 9,660' 9.50 115 26 18 19/25/26 6.0 /2 12 11 82 6 93/7 .5 20K 34.28 0.65 2000 5/26/01 12,430' 9,660' 9.50 115 26 17 18/24/25 6.0 /2 12 11 82 6 93/7 .5 20K 34.28 0.65 2000 5/27/01 12,446' 9,665' 9.80 115 25 20 23/28/29 6.0 /2 12 11 80 8 91/9 .7 19K 27.1 0.91 2000 5/28/01 12,627' 9,744' 9.40 115 21 19 17/25/26 6.0 /2 11 10 82 7 92/8 .6 18K 28.69 0.78 2000 5/29/01 12,842' 9,797' 9.35 112 24 17 19/27/31 6.2 /2 12 12 80 8 91/9 .6 25K 32.84 0.78 1975 5/30/01 13,003' 9,815' 9.35 113 25 17 22/27/31 6.7 /2 12 12 79 9 90/10 .4 27K 31.95 0.52 1975 5/31/01 13,278' 9,798' 9.30 134 25 18 22/29/32 6.2 /2 11 10.15 79 10 89/11 .4 27K 29.7 0.52 1950 6/1/01 13,330' 9,800' 9.40 129 25 16 22/27/31 6.6 /2 11 11 79 10 89/11 .6 26K 28.92 0.78 1900 6/2/01 13,600' 9,778' 9.40 121 26 16 23/29/33 6.7 /2 11 11 79 10 89/11 .55 25K 28.12 0.72 1975 6/3/01 13,745' 9,769' 9.40 134 26 16 24/30/33 6.1 /2 11 11 79 10 89/11 .6 26K 28.12 0.78 2000 6/4/01 13,900' 9,768' 9.45 141 28 16 23/29/33 6.3 /2 10 10 80 10 89/11 .5 23.5K 26.89 0.65 2000 6/5/01 14,227' 9,770' 9.40 115 28 17 19/28/31 6.4 /2 11 10 80 9 90/10 .5 21K 26.75 0.65 2000 6/6/01 14,336' 9,784' 9.50 120 26 16 23/28/32 6.4 /2 11 10 80 9 90/10 .5 21K 26.75 0.65 1970 6/7/01 14,360' 9,785' 9.50 122 25 17 21/29/34 6.3 /2 11 10 80 9 90/10 .4 20K 25.8 0.52 1920 6/8/01 14,598' 9,787' 9.30 120 28 15 25/31/36 6.4 /2 11 10 80 9 90/10 .5 21K 26.75 0.65 2000 EPOCH 27 UNOCALe K13 RD2 Date Depth TVD MW VIS PV YP Gel FL HTHP Cake Sol C.Sol Oil Wtr O/W Pom CI- Salt Lime Er-- stab 6/9/01 14,704' 9,786' 9.40 104 25 16 25/33/39 6.4 /2 10 10 81 9 90/10 .5 21K 26.75 0.65 2010 6/10/01 14,879' 9,786' 9.40 110 26 18 27/34/40 6.4 /2 10 9.16 81 9 90/10 .5 20.5K 26.28 0.65 2018 6/11/01 15,068' 9,755' 9.40 123 25 16 25/35/40 6.3 /2 10 9.16 81 9 90/10 .45 21K 26.75 0.59 2047 6/12/01 15,230' 9,755' 9.40 132 27 16 26/34/39 6.3 /2 9 8 81 10 89/11 .5 21K 24.73 0.65 2018 6/13/01 15,230' 9,755' 9.50 130 26 15 25/34/39 6.4 /2 9 8.14 81 10 89/11 .45 21K 24.73 0.59 2039 6/14/01 15,429' 9,755' 9.3 100 26 15 23~33~38 6.6 /2 8 7.1 82 10 98/11 .5 22.5K 26.04 .65 2030 6/15/01 15,485' 9.745' 9.3 130 26 15 23~33~39 6.5 /2 8 7.1 82 10 89111 .5 22K 25.61 .65 2027 EPO' H 28 UNOCALe K13 RD2 SURVEY RECORD · MD Incl Azim TVD VSec NS EW DLS Course Closure (ft) (°) (°) (ft) (ft) (ft) (ft) (°/lOOtD (fl) (ft) , 8700.00 31.50 105.00 7157.85 2874.05 135.26 4305.67 4307.79 88.20 --- , 8704.00 31.47 104.96 7161.26 2874.93 134.72 4307.69 4309.79 88.21 0.91 8720.00 32.29 101.68 7174.85 2878.73 132.78 4315.91 4317.95 88.24 11.98 8764.38 31.24 96.18 7212.59 2890.78 129.14 4338.96 4340.89 88.30 6.94 8856.09 33.75 84.82 7290.01 2922.16 128.88 4388.03 4389.93 88.32 7.18 8950.06 34.77 73.18 7367.76 2963.17 139.00 4439.74 4441.91 88.21 7.05 9043.70 34.86 61.58 7444.72 3010.48 159.48 4488.89 4491.72 87.97 7.07 9138.26 34.57 55.10 7522.47 3061.54 187.70 4534.67 4538.55 87.63 3.91 9231.80 33.52 51.53 7599.99 3112.49 218.96 4576.66 4581.90 87.26 2.41 9323.72 33.16 48.84 7676.78 3162.21 251.30 4615.46 4622.30 86.88 1.66 9417.87 34.94 44.88 7754.80 3214.53 287.35 4653.88 4662.74 86.47 3.02 9509.71 38.25 42.76 7828.53 3269.15 '326.87 4691.75 4703.12 86.01 3.86 9602.79 39.46 40.74 7901.01 3327.51 370.44 4730.62 4745.10 85,52 1.88 9697.30 40.29 40.27 7973.54 3388.10 416.51 4769.97 4788,12 85.01 0.93 9791.81 45.68 38.89 8042.66 3452.51 466.18 4'810.98 4833.52 84.47 5.79 9884.01 48.82 36.99 8105.24 3520,15' 519.59 4852.58 4880.31 83.89 3.73 9925.05 50,71 35.36 8131.75 3551.41 544.88 4871.06 4901.44 83.62 5.51 9988.98' 51.20 35.27 8172.02 3600.89 585.39 4899.76 4934.61 83.19 0.77 10082.81 50.76 34.68 8231.09 3673.50 645.12 4941.55 4983.48 82.56 0.68 10176.'36 51.81 35.17' 8289.60 3746.20 704.97 4983.34 5032.96 81.95 1.19 10269.53 52.17 35.30 8346.98 3819.35 764.93 5025.69 5083.57 81.35 0.40 10363.74 52.22 34.84 8404.73 3893.51 825.85 5068.46 5'135.30 80.75 0.39 10456.15 52.07 34.08 8461.43 3966.12 886.01 5109.75 5185.99 80.16 0.67 10549.40 52.00 33.36 8518.80 4039.19 947.16 51'50.56 5236.92 79.58 0.61 10642.90 51.40 33.1'9 8576.75 4112.05 1008.50 5190.82 5287.88 79.01 0.66 10737.21 51.06 32.52 8635.81 4185.01 1070.27 5230.71 5339.08 78.44 0.66 10831.62 50.91 32.11 8695.24 4257.69 1132.26 5269.92 5390.19 77.87 0.37 10'924.08 50.56 32.02 8753.76 4328.58 1192.93 5307.93 5440.33 77.33' 0.39 11015.91 50.45 31.77 8812.16 4398.73 1253.09 5345.37 5490128 76.81 0.24 ,, 11108.48 49.87 31.11 8871.47 4469.01 1313.73 5382.44 5540.45 76.28 0.83 11203.91 49.54 31.31 8933.18 45'40.93 1375.99 5420.16 5592.09 75.76 0.38 .... i"12'98.60 49.84 30.84 8994.44 4612.25 1437.83 5457.43 5643.66 75.24 0.49 11390.50 50.42 31.26 9053.35 4681.91 1498.26 5493.81 5694.45 74.75 0.72 11483.24 50.69 31.33 9112.28 4752.70 1559.45 5531.01 5746.65 74.25 0.30 11579.16 49.98 30.49 9173.50 4825.60 1622.80 5568.94 5800.57 73.75 1.00 11671.49 48.84 30.11 9233.57 4894.70 1683.34 5604.32 5851.67 73.28 1.27 11762.05 51.80 31.32 9291.39" 4963.46 1743.24 5639.93 '5903.19 72.82 3.43 ;Ji855.52 55.47 32.06 9346180 5037,92 1807.27 5679,47 '5960,08 72.35 3.98 ,, 11950.41 56.90 31.82 9399.61 5115.97 1874.17 5721.17 6020.33 71.86 1.52 12042.41 56.90 32.98 9449.85 5192.35 1939.24 5762.47 6080.02 71.40 1.06 EPOCH 29 UNOCALe K13 RD2 MD Incl Azim TVD VSec NS EW Closure CI Azim DLS (~) (°) (°) (ft) (ft) (ft) (ft) (ft) (°) (°/'~OOft) 12136.36 57.09 34.69 9501.03 5270.67 2004.68 5806.34 6142.66 70.95 1.54 12231.32 57.53 36.13 9552.32 5350.32 2069,81 5852.64 6207.86 70.52 1.36 12323.71 57.14 36.65 9602.19 5427.94 2132.42 5898.79 6272.39 70.12 0.63 12367.72 57.15 36.26 9626.06 5464.84 2162.16 5920.75 6303.19 69.94 0.74 12464.29 59.76 36.5 9676.58 5546.97 2228.39 5969.60 6371.95 69.5 2.71 12559.80 67.63 38.5 9718.87 5632.43 2296.23 6021.71 6444.66 69.1 8.43 12653.67 72.70 40.2 9750.72 5720.69 2364.50 6077.67 6521.42 68.7 5.68 12746.03 76.57 42.0 9775.19 5809.71 2431.60 6136.19 6600.42 68,4 4.58 12839.33 78.83 42.9 9795.06 5900.79 2498.89 6197.68 6682.49 68.0 2.60 12933.77 85.15 43.9 9808.22 5994.10 2566.81 6261.89 6767.55 67.7 6.78 13026.62 92.80 43.8 9809.88 6086.66 2633.71 6326.15 6852.49 67.4 8.24 13118.27 91.90 43.8 9806.12 6178.04 2699.80 6389.53 6936,50 67.1 0.98' ' 13213.79 93.05 42.5 9801.99 6273.32 2769.41 6454.82 7023,84 66.8 1.79 13272.47 92,75 42.5 9799.02 6331.88 2812.62 6494.40 7077.29 66.6 0.53 13320.00 93.48 42.0 9796.44 6379.30 2847.76 6526.30 7120.56 66.4 1.80 13413.27 94.75 41.8 9789.75 6472.28 2917.01 6588.42 7205.29 66.1 1.38 13508.27 93.30 42.1 9783.08 6566.99 2987.50 "6651.75 7291.84 65.8 1.55 13603.54 92.63 42,6 9778.15 6662.06 3057.81 6715185 7379.21 65.5 0.92 13696.04 91.55 42.6 9774.78 6754.40 3125,84 6778.43 7464.45 65.2 1.17 "13787.99 92.53 43.2 9771,51 6846.18 3193,'14 6841.00 7549.53 65.0 1.26 13848.70 91.45 43.0 9769.40 6906.76 3237.43 6882.47 7605.87 64.8 1.81 13963.07 89.65 42,2 9768.30 7021.00 3321.56 6959.93 7711.90 64.5 1.71 14056.31 87.12 43.3 9770.93 7114.09 3389.95 7023.24 7798.57 64.2 2.95 14150.28 87.10' 44.0 9775.67 7207.75 3457.83 7088.04 7886.50 64.0 0.70 14261.29 '87.36 42.8 9781.03 7318.44 3538.39 7164.23 7990.39 63.7 1.10 14353.90 88.28 43.9 9784.55 7410.83 3605.66 7227.78 8077.23 63.5 1.59 14448.53 89.72 44.2 9786.20 7505.20 3673.60 7293.62 8166.53 63.3 1.55 14539.64 89.75 45.2 9786.63 7596.01 3738.30 7357.76 8252.98 63.1 1.10 14570.25 90.18 45.8 9786.64 7626.48' 3759.74 7379.61 8282.17 63.0 2.36 14657.61 92.35 46,1 9784,72 7713.34 3820.45 7442.40 8365.71 62.8 2.50 14750.95 94.45 45,2 9779.18 7806.07 3885.59 7509.01 8454.76 62.6 2.46 14844.85 93.75 43.3 9772.47 7899.47 3952.66 7574.38 8543.69 62.4 2.08 14941,75 93.35 40.4 9766.46 7996.13 4024.67 7638.93 8634.30 62.2 3.07 15041,72 93.10 39.2 9760.84 8095.93 4101.35 7702.82 8726.65 62.0 1.22 15133.27 94.22 38.9 9755.00 8187.28 4172.30 7760.37 881'0.87 61.7 1.27 15218.72 93.00 38.9 9749.66 8272.53 4238.61 7813.97 8889.54 61.5 1.43 '~5312,75 92.63 39.3 9745.05 8366.43 4311,51 7873.18 8976.42 61,3 0.53 15406.88 92.70 38.9 9740.67 8460.45 4384.51 7932.45 9063.53 61.1 0.38 15485.00 92.70 38.9 9736.99 8538.46 4445.24 7981.45 9135.85 60.9 0.00 EPOCH 30 UNOCALe RD2 BIT RECORD Bit # Size Vendor Type Serial # Jets In Out Feet Hm-On Hm-Off ROP WOB 1 8.5" SMITH 15MFDGPS LW3150 3X16 8740 9983 1243 37.9 20.4 58.0 15.5 2 8.5" HYCLOG 2057J HTGJN 100672 8X10 9983 11717 1734 69.7 14.9 45.0 8.6 3 8.5" SMITH MGR35SPX JS5065 6X12 11717 12430 713 55.3 13.1 18.7 16.0 4 6" SMITH XR20HTDGPS LX7956 3X12 12430 12627 197 13.2 9.5 41.6 13.4 5 6" SMITH XR20HTDGPS LY6997 3X12 12627 12847 220 12.1 4.2 24.9 23.0 6 6" SMITH XR20HTDGPS 3X12 12847 13278 431 15.0 6.9 35.4 21.0 7 6" SMITH M20SPX PDC JS4363 4X11 13278 13325 47 3.3 4.3 23.4 11.5 8 6" SMITH XR20HTDGPS LX7949 3X12 13325 13607 282 12.2 3.4 29.7 22.1 9 6" SMITH XR20HTDGPS LY1474 3X12 13607 13900 293 14.2 4.9 27.6 17.8 10 6" SMITH XR20HTDGPS LX8442 3X12 13900 14226 326 15.9 3.3 23.2 17.2 11 6" REED SL51H KPRDG EJ9813 3X12 14226 14336 110 4.5 5.4 37.9 26.3 12 6" SMITH XR20HTDGPS LY0746 3X12 14336 14600 264 11.4 11.8 34.1 32.6 13 6" HUGHES EP4970 D35JN 3X12 14600 14704 104 5.0 2.4 33.8 35.8 14 6" SMITH XR20HTDGPS MH0863 3X12 14704 15014 310 12.8 6.1 30.0 26.2 15 6" SMITH XR20HTDGPS MH0859 3X12 15014 15230 216 11.4 3.1 24.8 21.1 16 6" HUGHES EP4970 D36JN 3X12 15230 15485 255 19.0 19.4 25.5 21.7 EPOCH 31 UNOCAL ) K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 14, 2001 DALLY COST: $1715 CUM COST: $1715 YESTERDAY: 8740' 24 HR FTG: 0' PRESENT: 6.4 24 HR AVE: NA 12:01 AM DEPTH: 8740' ROP (FTIHR): CURRENT BIT INFORMATION: NO.: 1 MAKE: SMITH TYPE: 15MFDGPS DEPTH IN: 8740' Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 1.2 YESTERDAY'S TOTAL: PAST 24 HOURS: GAS SUMMARY BACKGROUND GAS: Max:I NA AVerage:INA Current:INA ..... CONNECTION GAS: Max: NA Average: NA Current: NA TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: % SILTSTONE: ~% SANDSTONE: ~% CLAYSTONE: ~% TUFF: % COAL INTERVALS: COAL ANTICIPATED: .NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: . . INTERVAL: ...... TOTAL: ' " NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP W, OB MWt GAS C..~1 C..~2 C3 C~4 C..~5 Epoch commenced logging at 8740' at 12:20 am after report time. Arrived on location on 5113101 at 12:30 pm, attended safety meeting, and rigged up. gl EPOCH 33 UNOCALe K't3 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 15~ 2001 DAILY COST: 12:01 AM DEPTH: 9240' YESTERDAY: 8740' ROP (FTIHR): PRESENT: 112 CURRENT BIT INFORMATION: $1715 CUM COST: $3430 24 HR FTG: 500' 24 HR AVE: 34.3 NO.: 1 MAKE: SMITH TYPE: 15MFDGPS DEPTH IN: 8740' Footage Houm On Bottom Off Bottom TOTAL: 500 24 14.6 11.4 YESTERDAY'S TOTAL: 0 0 0 2.0 PAST 24 HOURS: 500 24 14.6 9.4 GAS SUMMARY BACKGROUND GASi Max: 47u(~9053' Average: I 9u Current: I 15 CONNECTION GAS: Max: 4u~9099' Average: 2u Current: 2u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 15 % SILTSTONE: , 10 % SAND: 25 % CLAYSTONE: 50 % TUFF: % COAL INTERVALS: COAL ANTICIPATED: 9050-9070', 9170-9180' .Currently running flat with type log SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: , INTERVAL: TOTAL: ' 'NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WO.B MWt GAS C_~1 C..~2 C_~3 Ca, C..~5 Rotate and slide as per directional plan. POOH to window to clear flow line. TIH to window and orient through same. Continue to rotate and slide. EPOCH 34 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 16, 2001 DAILY COST: 12:01 AM DEPTH: 9856' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $5145 9240' 24 HR FTG: 616' 22 24 HR AVE: 33.7 NO.: 1 MAKE: SMITH TYPE: 15MFDGPS DEPTH IN: 8740' ....... Footage ............. Houm On Bottom "' Off Bottom TOTAL: 1116 50.1 32.9 17.2 YESTERDAY'S TOTAL: 500 26.1 14.6 11.5 PAST 24 HOURS: 500 24 18.3 5.8 GAS SUMMARY ,., BACKGROUND.GAS: Max: 44u~9405' Average: 18u Current: 2u CONNECTION GAS: Max: 0u~9846' Average:] 0u Current: 0u TRIp GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: SAND: TUFF: COAL INTERVALS: COAL ANTICIPATED: SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: 10 % $1LTSTONE: 0 % 40 % CLAYSTONE: 45 % 9500-9510', 9565-9575' .Currently estimating 100' high to type log. TbTAL: ' NET BEFORE DURING MAXIMUM AFTER REMARKS: R0P WOB MWt GAS c...~1 c...~2 c__~3 i i i Rotate and slide as per directional plan. C4 CS EPOCH 35 UNOrJBLLe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 17, 2001 DAILYCOST: $1715 12:01 AM DEPTH: 9983' YESTERDAY: ROP (FTIHR): PRESENT: 21 CURRENT BIT INFORMATION: CUM COST: $6860 9856' 24 HR FTG: 127' 24 HR AVE: 25.4 NO.: I MAKE: SMITH TYPE: 15MFDGPS DEPTH IN: 8740' DEPTH OUT: 9983' Footage Hours On Bottom Off Bottom TOTAL: 1243 58.3 37.9 20.4 YESTERDAY'S TOTAL: 1116 50.1 32.9 17.2 PAST 24 HOURS: 127 8.2 5.0 3.2 NO.: 2 MAKE: HYCALOG TYPE: 2057JHTGJN DEPTH IN: 9983' Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 PAST24HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: Max: 0u(~9846' Average: 0u Current: 0u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 5 % SILTSTONE: 0 % SAND: 25 % CLAYSTONE: 65 % TUFF: 5 % COAL INTERVALS: COAL ANTICIPATED: 99t0-9920' .Currently estimating 120' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: ..... INTERVAL:' ' TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C_.~1 C:2 C.~3 Ca, C5 . Rotate and slide as per directional plan from 9856' to 9983'. Pull out of the hole and lay down the BHA. Make up test jet and pull wear ring. Test BOPs, fix leak in hydrill accumulator hose, fix control on IBOP, and install air dryer in sub base. Pick up and run in with new BHA with new mud motor, and test MWD. Pull out BHA and change MWD. Pick up 72 joints of 5" drill pipe, and trip in hole. [:l EPOCH 36 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 18, 2001 DALLY COST: $1715 12:01 AM DEPTH: 10738' YESTERDAY: ROP (FTIHR): PRESENT: 6.1 CURRENT BIT INFORMATION: CUM COST: $8575 9983' 24 HR FTG: 755' 24 HR AVE: 41.7 NO.: 2 MAKE: HYCALOG TYPE: 2057JHTGJN DEPTH IN: 9983' Footage Hours On Bottom Off Bottom TOTAL: 755 21.9 18.1 3.8 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 755 21.9 18.1 3.8 GAS SUMMARY BACKGROUND GAS: Max:[ 53u(~10391' Avera§e: [ 10u Current: I 6u CONNECTION GAS: Max: 0u(~1.0704' Avera§e: 0u Current: 0u TRIP GAS: 71u~9983' WIPER TRIP GAS: ] NA GROSS LITHOLOGY: COAL: SAND: TUFF: COAL INTERVALS: COAL ANTICIPATED: SHOW SUMMARY: NONE Lithology Descriptions: ,,Bit Type: INTERVAL: 10 % SILTSTONE: 10 % 25 % CLAYSTONE: 50 % 5 % 10060-10070', 10210-10220', 10385-10400', 10570-10580', 10715-report depth .Currently estimating 110' high to type log. ..... TOTAL: ...... NET " ' BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C_.~ C:2 C.~3 C_~4 C_.~5 Finish tripping in hole to 9920', and ream to 9983', drill ahead from 9983' to 10738' sliding from 10159' to 10181'. [:l EPOCH 37 UNOr. ALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-t3RD2 DATE: MAY 19, 2001 DAILY COST: $17!5 CUM COST: $10290 12:01 AM DEPTH: 11250' ROP (FTIHR): YESTERDAY: 10738' 24 HR FTG: 512' PRESENT: 12.7 24 HR AVE: 25.6 CURRENT BIT INFORMATION: NO.: 2 MAKE: HYCALOG TYPE: 2057JHTGJN DEPTH IN: 9983' Footage Hours On Bottom Off Bottom TOTAL: 1267 38.1 38.1 7.8 YESTERDAY'S TOTAL: 755 21.9 18.1 3.8 PAST 24 HOURS: 512 24 20 4 GAS SUMMARY BACKGROUND GAS: Max: 39u~11194' Average: I 9u Current: 12u CONNECTION GAS: Max: 0u~11170' Average:I 0u Current: 0u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 5 % SILTSTONE: 5 % SAND: 35 % CLAYSTONE: 50 % TUFF: 5 % COAL INTERVALS: 11080-85', 11185-95'. COAL ANTICIPATED: .Currently estimating 130' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: .......... "TOTAL:' NE INTERVAL; ...... T ... BEFORE DURING MAXIMUM AFTER R0P WOB MWt GAS C_~1 C2 C_~ C~4 C..~5 REMARKS: Drill from 10738 to 11250', sliding from 11212 to 11232', and drilling with pump no. 1 from 11232 to 11240' while working on pump no. 2. EPOCH 38 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 20, 2001 DAILY COST: $1715 12:01 AM DEPTH: 11594' YESTERDAY: ROP (FTIHR): PRESENT: 2,0 CURRENT BIT INFORMATION: NO.: 2 MAKE: HYCALOG TYPE: 2057JHTGJN CUM COST: :$12005 11250' 24 HR FTG: 24 HR AVE: 16.5 DEPTH IN: 9983' Footage Houm On Bottom Off Bottom TOTAL: 1611 69.9 58.9 11.0 YESTERDAY'S TOTAL: 1267 45.9 38.1 7.8 PAST 24 HOURS: 512 24 20.8 3.2 GAS SUMMARY CONNECTION GAS: ~4ax: 0u~11170' Average: 0u Current: 0u TRIP GAS: NA WIPER TRIP GAS: I NA 10 % SILTSTONE: 10. % 30 % C LAYSTON E: .50 % 0 % 11245.11265', 1 t 390-t 1400', 11465.t 1480', t 1530.11540'. .Currently estimating 145' high to type log. GROSS LITHOLOGY: COAL: SAND: TUFF: COAL INTERVALS: COAL ANTICIPATED: SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: , , INTERVAL: ...... TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB M,Wt GAs C_~1 C_~2 c3 c_~4 c..~5 Drill ahead from 11250' to 11594', sliding from 11375-11385', 11393-11417', and 11583-11594'(report depth). EPOCH 39 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY21., 2001 DAILY COST: $1715 CUM COST: :$13720 12:01 AM DEPTH: 11717' ROP (FTIHR): YESTERDAY: 11594' 24 HR FTG: 123' PRESENT: 9.5 24 HR AVE: 11.4 CURRENT BIT INFORMATION: NO.: 2 MAKE: HYCALOG TYPE: 2057JHTGJN DEPTH IN: 9983' DEPTH OUT: 11717' Footage Hours On Bottom Off Bottom" TOTAL: 1734 84.6 69.7 14.9 YESTERDAY'S TOTAL: 1611 69.9 58.9 11.0 PAST 24 HOURS: 123 14.7 10.8 3.9 NO.: :3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' i Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY BACKGROUND GAS: Max: 29u@11652' Average: ITM Current: I 15u CONNECTION GAS: Max: 0u(~11639' Avera§e: 0u Current: 0u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 15 .% SILTSTONE: 10. % SAND: 25 % CLAYSTONE: 50. % TUFF: 0 % COAL INTERVALS: 11620-11665', 11710-11717'. COAL ANTICIPATED: Currently estimating 155' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: "' TOTAL:' ' NET ' BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt ,GAS C_.~1 C_~2 C_.~3 C~4 C.~5 Drill ahead from 11594' to 11717', sliding from 11697 to 11703'. Circulate out and pump pill, and pull out of hole for new bit and mud motor. Trip in hole with bit #3. Cut and slip drill line at shoe. EPOCH 40 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 22, 2001 DALLY COST: 12:01 AM DEPTH: 11954' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $15435 11717' 24 HR FTG: 237' 1,~.4. 24 HR AVE: 15.9 NO.: 3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' Footage Hours On Bottom Off Bottom TOTAL: 237 19.2 14.9 4.3 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 237 19.2 14.9 4.3 GAS SUMMARY CONNECTION GAS: lVlax: 0u(~11639' Average: 0u Current: 0u TRIP GAS: .120u~11717' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 5 % SILTSTONE: 15 % SAND: 40 % CLAYSTONE: 40 % TUFF: .0 .... % COAL INTERVALS: 11810-11815', 11830-t1835', 11915-11925'. COAL ANTICIPATED: Currently estimating 180' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type,: ..... INTERVAL: :I"O'I:AL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP woB MWt cas c_.~1 c2 c...~3 ca, c...~5 Finish cut and slip drill line at shoe, orient mud motor, and trip in to 11600'. Ream to 11717', and drill ahead from 11717' to 11954', sliding at 11722 to 11733', 11742 to 11777', 11807 to 11812', and 11841 to 11873'. EPOCH 41 UNOr. K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 23, 2001 DAILY COST: $1715 CUM COST: $17150 12:01 AM DEPTH: 12236' YESTERDAY: 11954' 24 HR FTG: 282' ROP (FTIHR): PRESENT: 11.2 24 HR AVE: 13.8 CURRENT BIT INFORMATION: NO.: 3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' ...... Fo0tage Hours On Bottom ...... Off Bottom TOTAL: 519 43.2 35.3 7.9 YESTERDAY'S TOTAL: 237 19.2 14.9 4.3 PAST 24 HOURS: 282 24 20.4 3.6 GAS SUMMARY BACKGROUND GAS: Max:I 24u~12152' Average: I lOu Current: ] 17u CONNECTION GAS: Max: 22u(~12199' Average: 7u Current: 22u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: . 20. % SILTSTONE: 5 % SAND: 4.0 % CLAYSTONE: 35 % TUFF: 0 % COAL INTERVALS: 11980-11995', 12000-12135'. COAL ANTICIPATED: Currently estimating 155' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: ......... INTERVAL: TOTAL: i ii NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C._~1 C_.~2 C3 Ca, C5 Rotate and slide from 11954' to 12236', sliding from 11974-11982', 12127-12152', 12160-12171'. EPOCH 42 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 24, 2001 DAILY COST: 12:01 AM DEPTH: 12430' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 3 MAKE: SMITH TYPE: MGR35SPX $1715 CUM COST: $18865 12236' 24 H R FTG: 194' NA 24 HR AVE: NA DEPTH IN: 11717' DEPTH OUT: 12430' ......., Fo0~ge Houm ......... On Bottom Off Bottom' TOTAL: 713 66.9 55.3 13.1 YESTERDAY'S TOTAL: 519 43.2 35.3 7.9 PAST 24 HOURS: 194 23.7 20.0 3.7 GAS SUMMARY BACKGROUND GAS: Max:I 12u~12259' Average: ] 7u Current: 5u CONNECTION GAS: Max: 6u(~12386' Average: 3u Current: 3u TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: (ON BOTTOM) COAL: 10 % SlLTSTONE: 20 % SAND: .20 .... % CLAYSTONE: 50.. % TUFF: 0 % COAL INTERVALS: COAL ANTICIPATED: 12335-12345', 12387-12395', 12400-12405'. Currently estimating 150' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS c_.t~ c_~2 c_3 c_~4 c_~s Drill ahead, rotating, from 12236' to 12430', casing point, circulate bottoms up, circulate out high vis sweep, pump dry job, and begin to pull out of hole. EPOCH 43 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 25, 2001 DALLY COST: 12:01 AM DEPTH: 12430' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $20580 12430' 24 HR FTG: 0' NA 24 HR AVE: NA NO.: 3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' DEPTH OUT: 12430' ......... --,,'-,-5 ,' - ' Footage Hours On Bottom Off Bottom TOTAL: 713 68.4 55.3 13.1 YESTERDAY'S TOTAL: 713 66.9 55.3 11.6 PAST 24 HOURS: 0 1.5 0 1.5 GAS SUMMARY CONNECTION GAS: Max: NA Average:[ NA Currant:I NA TRIP GAS: NA WIPER TRIP GAS: I 33u(~12430' GROSS LITHOLOGY: (ON BOTTOM) COAL: 0 % SILTSTONE: 30 % SAND: 20 % CLAYSTONE: 50 % TUFF: 0 % COAL INTERVALS: COAL ANTICIPATED: NA. Currently estimating 150' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: ,, INTERVAL: TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C..~1 C_.~2 C_~3 Ca, C..~5 Pull out off hole to shoe, back reaming at 11765' and 11698'. Run back in hole and circulate and condition hole, trip gas 33 units. Pull out of hole and lay down BHA. Install 7" rams and test BOP. Rig up GBR tools to run liner. Begin to run in hole with 7" liner. [::1 EPOCH 44 UNOCALe K13 RD2 DATE: MAY 26, 2001 DAILY COST: 12:01 AM DEPTH: 12430' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 $1715 12430' 24 HR FTG: NA 24 HR AVE: CUM COST: $22295 0' NA NO.: 3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' DEPTH OUT: 12430' ..................... Footage Hours On Bottom Off Bottom' TOTAL: 713 68.4 55.3 13.1 YESTERDAY'S TOTAL: 713 68.4 55.3 13.1 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY BACKGROUND GAS: Max: 92u(Trip Gas) Average: [20u Current: [7u CONNECTION GAS: Max: NA Average: NA Current: NA TRIP GAS: NA WIPER TRIP GAS: I 92u(~12430' GROSS LITHOLOGY: (ON BOTTOM) COAL: .0 ..% SILTSTONE: 30 % SAND: 20 % CLAYSTONE: 50 % TUFF: 0 % COAL INTERVALS: NA. COAL ANTICIPATED: Currently estimating 150' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type; ............... INTERVAL: TOTAL: NE:I' BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C~1 C2 C_~3 C~4 C__5. Run in with 7" liner, total '. Run liner in with drill string, and circulate and condition hole while working pipe, 92 units of trip gas. Rig up Dowell, and complete cement job setting liner from 12430' - 8487'. Attempt to test backside. EPOCH 45 UNOCALe) K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 27, 2001 DAILY COST: 12:01 AM DEPTH: 12430' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $24010 12430' 24 HR FTG: 0' NA 24 HR AVE: NA NO.: 3 MAKE: SMITH TYPE: MGR35SPX DEPTH IN: 11717' DEPTH OUT: 12430' Footage Hours On Bottom Off Bottom TOTAL: 713 68.4 55.3 13.1 YESTERDAY'S TOTAL: 713 68.4 55.3 13.1 PAST 24 HOURS: 0 0 0 0 NO.: 4 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 12430' Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0 0 0 , , GAS SUMMARY BACKGROUND GAS: Max: NA Average: INA Current:INA CONNECTION GAS: Max: NA Average: NA Current: NA TRIP GAS: NA WIPER TRIP GAS: I NA GROSS LITHOLOGY: (ON BOTTOM) COAL: 0 % SAND: 20 % TUFF: 0 % COAL INTERVALS: COAL ANTICIPATED: SHOW SUMMARY: NONE Uthology Descriptions: Bit, T~,pe: .... INTERYAL: SILTSTONE: 30 % CLAYSTONE: 50 % NA. Currently estimating 150' high to type log. TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOmB MWt GAS C._~1 C..~2 C_.~3 C4 C_~5 Pressure test surface equipment, no good, look for leaks. Retest, hold for 40 minutes, good test. Pump dry job. POOH to 3731'. Laydown 5" drill pipe and HWDP. Change rams and test BOP. Service top drive and change out saver sub. Pick up bales and 3 Va" lift equipment. Start making up BHA. EPOCH 46 UNOCALe RD2 DATE: MAY 28, 2001 12:01 AM DEPTH: 12446' ROP (FTIHR): EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DAILY COST: $1715 CUM COST: $25725 YESTERDAY: 12430' 24 HR FTG: 16' PRESENT: 0.5 24 HR AVE: 5.3 CURRENT BIT INFORMATION: NO.: 4 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 12430' ~ Footage HOU'm' ' On Bottom Off Bott~'""~m TOTAL: 16 5.3 3.0 2.3 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 16 5.3 3.0 2.3 GAS SUMMARY BACKGROUND GAS: Max: 15u(~12432' Average: 113u Current: I 6u CONNECTION GAS: Max: NA Average: NA Current: NA TRIP GAS: 21(~12430' WIPER TRIP GAS: I NA GROSS LITHOLOGY: (ON BOTTOM) COAL: 0 % SILTSTONE: 0 SAND: 10. % CLAYSTONE: 10 % CEMENT: 80 % COAL INTERVALS: COAL ANTICIPATED: NONE. Currently estimating 150' high to type log. SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: . INTERVAL: TOTAL': '' NET BEFORE DURING MAXIMUM AFTER ROP WOB MWt GAS C~1 C2 C3 C.~4 C..~5 REMARKS: Finish making up BHA, and test MWD Tool. Pick up and run in with 3 ½" HWDP, Pick up and run in with 5091.2' of 3 W' drill pipe and one stand of 5" drill pipe. Cut and slip drill line. Continue to run in hole with 5" drill pipe down to 12216', Wash down to 12297' and drill landing collar. Wash and ream cement, shoe and formation down to 12446'. EPOCH 47 UNOr. ALe K13 RD2 DATE: MAY 29, 2001 12:01 AM DEPTH: 12627' ROP (FTIHR): EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DAILY COST: $1715 CUM COST: YESTERDAY: 12446' 24 HR FTG: PRESENT: 18 24 HR AVE: CURRENT BIT INFORMATION: $27440 181' 17.7 "' Footage .............. H'0'urs On Bottom Off Bottom TOTAL: 197 22.7 13.2 9.5 YESTERDAY'S TOTAL: 16 5.3 3.0 2.3 PAST 24 HOURS: 181 17.4 10.2 7.2 NO.: 4 MAKE: SMITH TYPE: XR20HTGDGPS 61.1 DEPTH IN: 12430' GAS SUMMARY BACKGROUND GAS: Max=I 18u(~12533' Average: I 8u Current: I 7u CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~.12589' TRIP GAs: NA WIPER TRIP GAS: I ' NA 0 % SILTSTONE: 0 % 60 % CLAYSTONE: 10 % 30 % NONE. NA 'TOTAL:' 'NET' GROSS LITHOLOGY: COAL: SAND: CEMENT: COAL INTERVALS: COAL ANTICIPATED: SHOW SUMMARY: NONE Lithology Descriptions: Bit Type:, ,, INTERVAL: BEFORE DURING MAXIMUM AFTER REMARKS: ,RO.P, ,WOB M,Wt GAS Cl C...~2 C..~3 C4 C5 Drill from 12446' to 12450' and circulate out. Perform formation integrity test, 11.0 EMW. Drill ahead, rotating and sliding, from 12450' to 12627'. Circulate 35 minutes, pull three stands wet, circulate and pump pill and trip out of hole. [::1 EPOCH 40 UNOCJBLLe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 30, 2001 12:01 AM DEPTH: 12842' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 4 MAKE: SMITH TYPE: XR20HTGDGPS DAILY COST: $1715 CUM COST: $29155 12627' 24 HR FTG: 215' 22.9 24 HR AVE: 18.4 DEPTH IN: 12430' DEPTH OUT: 12627' ............ Footag~ ......... Houm O~ Bottom Off Bottom TOTAL: 197 22.7 13.2 9.5 YESTERDAY'S TOTAL: 16 5.3 3.0 2.3 PAST 24 HOURS: 181 17.4 10.2 7.2 NO.: 5 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 12627' Footage Hours On Bottom Off Bottom TOTAL: 215 15.1 11.7 3.4 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 215 15.1 11.7 3.4 ,,, GAS SUMMARY BACKGROUND GAS: Max:I 12u(~12645' Average= I 7u Current: CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~12792' TRIP GAS: 10u(~12627' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 SAND: 95 TUFF: 0 COAL INTERVALS: NONE, COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Typei , INTERVAL: ~% SILTSTONE: 0 % % CLAYSTONE: 5 % % ' TOTAL:' NET ....... BEFORE DURING MAXIMUM AFTER REMARKS: ROP W0B MW.t GAS C1 C:2 C...~3 Ca, C.._.~5 Finish tripping out of hole, change BHA and bit, download MWD, service top drive, rig, and crown, and test MWD. Trip in hole to 12513', ream to 12627', and drill ahead, rotating and sliding, from 12627' to 12842'. EPOCH 49 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: MAY 31, 2001 12:01 AM DEPTH: 13002' ROP (FTIHR): CURRENT BIT INFORMATION: DAILY COST: $1715 CUM COST: $30870 YESTERDAY: 12842' 24 HR FTG: 160' PRESENT: 33.0 24 HR AVE: 34.8 NO.: 5 MAKE: SMITH TYPE: XR20HTGDGPS DEPTH IN: 12627' DEPTH OUT: 12847' ......... Footage ' ' Hours On Bottom Off Bottom TOTAL: 220 16.3 12.1 4.2 YESTERDAY'S TOTAL: 215 15.1 11.7 3.4 PAST 24 HOURS: 5 1.2 0.4 0.8 NO.: 6 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 12847' Footage Hours On Bottom Off Bottom TOTAL: 155 8.6 4.6 4.0 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 155 8.6 4.6 4.0 GAS SUMMARY BACKGROUND GAS: Max: 13u(~12930' Average: 18u Current: I 10u CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~12979' TRIP GAS: 8u(~12847' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SILTSTONE: 0 % SAND: 90. % CLAYSTONE: 0 % CONGLOMERATIC SAND: 10 % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: ..... INTERVAL: TOTAL: NET' BEFORE DURING MAXIMUM AFTER REMARKS: ROp WOB MWt GAS C_~1 C..~2 C~3 Ca, C...~5 Drill ahead from 12835' to 12847', circulate 30 minutes, and pull out of hole to shoe. Drop dart and pump pill and pull out of hole. Change pump out sub and bit, and test MWD twice. Trip in hole to 12419', ream to 12847', and drill ahead, rotating and sliding, from 12847' to 13002'. EPOCH 50 UNOr. ALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 1, 2001 12:01 AM DEPTH: 13277' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 6 MAKE: SMITH TYPE: XR20HTGDGPS DAILY COST: $1715 CUM COST: $32585 13002' 24 HR FTG: 275' 22.0 24 HR AVE: 20.8 DEPTH IN: 12847' DEPTH OUT: 13277' Footage Hours On Bottom Off Bottom TOTAL: 430 21.9 15.0 6.9 YESTERDAY'S TOTAL: 155 8.6 4.6 4.0 PAST 24 HOURS: 275 13.3 10.4 2.9 NO.: 7 MAKE: SMITH TYPE: M20SPX PDC 6" DEPTH IN: 13277' Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 PAST24 HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~13259' TRIP GAS: (~13278' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: 85 % CONGLOMERATIC SAND: COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: , , INTERVAL: SILTSTONE: 0 % CLAYSTONE: 5 % 10 % TOTALi NET BEFORE DURING MAXIMUM AFTER REMARKS: R0P W0,B MWt GAS C.~.1 C_~2 C_~3 C4 C..~5 Drill ahead, rotating and sliding, from 13002' to 13278', circulate 30 minutes, and pull out of hole 9 stands. Drop dart and pump pill and pull out of hole. Change out bit and motor. Pick up 18 joints 3 ½" drill pipe. RIH. EPOCH 51 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 2, 2001 12:01 AM DEPTH: 13330' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 8 MAKE: SMITH TYPE: XR20HTGDGPS DALLY COST: $1715 CUM COST: $34300 13277' 24 HR FTG: 52' 24.0 24 HR AVE: 15.8 DEPTH IN: 13330' DEPTH OUT:' Footage' Hours On Bottom Off ottom TOTAL: YESTERDAY'S TOTAL: PAST 24 HOURS: NO.: 7 MAKE: SMITH TYPE: M20SPX PDC 6" DEPTH IN: 13278' DEPTH OUT: 13330' Footage Hours On Bottom Off Bottom TOTAL: 52 7.6 3.3 4.3 YESTERDAY'S TOTAL: 0 0 0 0 , PAST 24 HOURS: 52 7.6 3.3 4.3 GAS SUMMARY BACKGROUND GAS: M x=I 20u(~13192' Average: I 13u Current: I 13u CONNECTION GAS: Max: 0u Average: 0 Current: 0u~13278' TRIp GAS: 9u(~13278' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: 90 % CONGLOMERATIC SAND: 5, COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Uthology Descriptions: Bit Type: .... INTERVAL: $1LTSTONE: 0 % CLAYSTONE: 5 % % TOTAL: NET' BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB MWt GAS C_.~1 C:2 C~3 Ca, C_.~5 Finish tripping in hole, and ream from 13128 to 13278', as old bit was %" out of gage. Drill ahead, rotating, from 13278' to 13330', circulate 65 minutes, and pull out of hole 9 stands. Drop dart and pump pill and pull out of hole. Test BOPE'S. Change out bit and motor, test MWD, trip in hole. [::1 EPOCH 52 UNOEAL K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 3, 2001 12:01 AM DEPTH: 13602' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 8 MAKE: SMITH TYPE: XR20HTGDGPS DAILY COST: $1715 CUM COST: :$36015 13325' 24 HR FTG: 277' 34.0 24 HR AVE: 23.3 DEPTH IN: 13330' DEPTH OUT:' ...... Footage Houm .... ~n Bottom Off ~ottom TOTAL: 277 14.4 11.9 2.5 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 277 14.4 11.9 2.5 NO.: 7 MAKE: SMITH TYPE: M20SPX PDC 6" DEPTH IN: 13278' DEPTH OUT: 13325' Footag,e Hours On Bottom Off Bottom TOTAL: 47 7.6 3.3 4.3 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 47 7.6 3.3 4.3 GAS SUMMARY BACKGROUND GAS: Ma/:I 14u@13422' Average: I 9u Current: I 7u CONNECTION GAS: Max: ' 0u Average: lO Current: 0u(~13557' TRIP GAS: 12u~13325' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: 85 % CONGLOMERATIC SAND: COAL INTERVALS: NONE, COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit T~pe: ..... INTERVAL: SILTSTONE: 0 % CLAYSTONE: 5 % 15 .% ......... TOTAL: ' NET ' ' ' BEFORE DURING MAXIMUM AFTER REMARKS: R0P WOB MWt GAS C~1 C..~2 C~3 Ca, C_~5 Test top drive, pick up bit and motor, run in hole with BHA, and test MWD. Run in hole with 3 V2" drill pipe, cut and slip drill line, and service top drive and draw works. Run in hole with 5" drill pipe to bottom at 13325', washing down on last stand. Drill ahead, rotating and sliding, from 13325' to 13602'. [::1 EPOCH 53 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 4, 2001 12:01 AM DEPTH: 13745' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: NO.: 8 MAKE: SMITH TYPE: XR20HTGDGPS DAILY COST: $1715 CUM COST: $37730 13602' 24 HR FTG: 143' 27.0 24 HR AVE: 19.6 DEPTH IN: 13325' DEPTH OUT: 13607' ............ Footage Hours On Bottom Off B°~tom' TOTAL: 282 15.6 12.2 3.4 YESTERDAY'S TOTAL: 277 14.4 11.9 2.5 PAST 24 HOURS: 5 1.2 0.3 0.9 NO.: 9 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13607' .. Footage Hours On Bottom Off Bottom TOTAL: 138 7.8 7.0 0.8 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 138 7.8 7.0 0.8 GAS SUMMARY 'BACKGROUND GAS: Max:[ 10u(~13701' Avera§e: [ 8U Current: I 9u CONNECTION GAS: Max: 0u Average: 0 Current: . 0u(~13652' TRIP GAS: 9u(~13607' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SiLTSTONE: 0 % SAND: 85 % CLAYSTONE: 5 % CONGLOMERATIC SAND: 10 % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit T pe' INTERVAL: TOTAL: ' 'NET BEFORE DURING MAXIMUM AFTER REMARKS: R, oP WOB MWt GA, S ~ C2 C3 C~ C5 Drill ahead from 13602' to 13607', circulate 35 minutes, check flow, pump dry job and pull out of hole. Make up BHA with new bit and stabilizer, test MWD, and trip in hole with 3 ½" pipe and 5" pipe. Wash and ream last stand, and drill ahead from 13607' to 13745'. EPOCH 54 UNOCAL K'I3 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 5, 2001 DALLY COST: 12:01 AM DEPTH: 13900' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $17,15 CUM COST: $39445 13745' 24 HR FTG: 155' 12.8 24 HR AVE: 21.5 NO.: 9 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13607' DEPTH OUT: 13900' ........................... I~0~0tage " Hours On Bottom Off Bottom TOTAL: 293 19.1 14.2 4.9 YESTERDAY'S TOTAL: 138 7.8 7.0 0.8 PAST 24 HOURS: 155 11.3 7.2 4.1 NO.: 10 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13900' '~ Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 pAST 24 HOURS: 0 0 0 0 GAS SUMMARY BACKGROUND GAS: Max:I 21u(~13797' Average: I 15u Cu'rrent: I 1iu CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~13840' TRIP GAS: u(~13900' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: 70 % CONGLOMERATIC SAND: COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: B,it,Typ, ei INTERVAL: SILTSTONE: 0 % CLAYSTONE: 10 % 20 % TOTAL: NET BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOE MWt GAS,, C._~1 C..~2 C3 Ca, C5 Drill ahead from 13745' to 13900', circulate 30 minutes, survey, check flow, and pump dry job. Pull out of hole to 12904', work tight spot, then circulate 2 hours while working pipe. Pull out of hole to bottom of liner, shear pump out sub, pump pill, and pull out of hole. Make up BHA with new bit, MWD probe, and pump out sub, and trip in hole with 3 ½" pipe. Trip in to 7" liner shoe with 5" drill pipe. [::1 EPOCH 55 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 6, 2001 DAILY COST: :$1715 CUM COST: $41160 12:01 AM DEPTH: 14226' ROP (FT/HR): YESTERDAY: 13900' 24 HR FTG: 326' PRESENT: 18 24 HR AVE: 20.5 CURRENT BIT INFORMATION: NO.: 9 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13607' DEPTH OUT: 1.3900' ............... ' ............... ~Foo~age ~ Houm 'On Bottom Off BOttOm TOTAL: 293 19.1 14.2 4.9 YESTERDAY'S TOTAL: 293 19.1 14.2 4.9 PAST 24 HOURS: 0 0 0 0 NO.: 10 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13900' DEPTH OUT: 14226' ~ Footage Houm On Bottom Off Bottom TOTAL: 326 19.2 15.9 3.3 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 326 19.2 I.. 15.9 3.3 GAS SUMMARY CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~14212' TRIP GAS: 7u.(~13900' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: .80. % CONGLOMERATIC SAND: SILTSTONE: 0 % CLAYSTONE: 5 % ,1,5,,,, % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit TyPe,: ....... INTERVAL: ............. ~oTAL: ' N'E~: ............ BEFORE DURING MAXIMUM AFTER iiii I .i I i II i i REMARKS: Roe W0B MWt GAS C._~1 C..~2 C_~ Ca, ~ I I I I I I I I I I L I I II I iii I iii I I I I iii Finish tripping in with $" drill pipe and ream 50 feet to bottom at 13900'. Drill ahead, rotating, from t3900' to 14226'. Circulate 30 minutes, pump dry job, and pull out of hole with 5" drill pipe. EPOCH 56 UNOCAL K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 7, 2001 DALLY COST: $1715 CUM COST: ,~t2875 12:01 AM DEPTH: 14336' ROP (FTIHR): YESTERDAY: 14226' 24 HR FTG: 110' PRESENT: 23 24 HR AVE: 24.4 CURRENT BIT INFORMATION: NO.: 10 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 13900' DEPTH OUT: 14226' ................ - ........... Footage Hours 'On Bottom Off BOttom TOTAL: 326 19.2 15.9 3.3 YESTERDAY'S TOTAL: 326 19.2 15.9 3.3 PAST 24 HOURS: 0 0 0 0 NO.: 11 MAKE: REED TYPE: SL51HKPRDG 6" DEPTH IN: 14226' DEPTH OUT: 14336' Footage Hours .... On Bottom Off B~ttom TOTAL: 110 9.9 4.5 5.4 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 110 9.9 4.5 5.4 GAS SUMMARY BACKGROUNDGAS: Max: .I 12u(~14321' Average_: I8u Current: I 12u CONNECTION GAS: Max:' 0u Average: 0 Current: 0u(~14312' TRIP GAS: 9u(~14226' WIPER TRIP GAs: I NA GROSS LiTHOLOGY: COAL: 0.. % SILTSTONE: 0 % SAND: 85 % CLAYSTONE: 5 % CONGLOMERATIC SAND: 10 % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: ..... INTERVAL: TOTAJ.~ NET BEFORE DURING MAXIMUM AFTER REMARKS: R0P W0B MWt GAS c_~ c..~2 c_~3 c.~4 c_~s Finish pulling out of hole with 5" drill pipe, and pull out of hole with 3 ½". Change BHA with new bit and mud motor sleeve. Pick up 15 joints of 3 1/2" drill pipe and run in hole with 3 ½". Cut and slip drill line, and service brakes and top drive. Run in hole with 5" drill pipe to 14219'. Ream to bottom, 14219' to 14226', and drill ahead, rotating and sliding, from 14226' to 14336'. Circulate 30 minutes and pump pill. Begin tripping out of hole. [::1 EPOCH 57 UNOr. K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-'I3RD2 DATE: JUNE 8, 2001 DALLY COST: 12:01 AM DEPTH: 14364' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $44590 14336' 24 HR FTG: 28' 3 24 HR AVE: 8.5 NO.: 12 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 14336' Footage Houm On Bottom Off Bottom TOTAL: 28 6.9 3.3 3.6 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 28 6.9 3.3 3.6 NO.: 11 MAKE: REED TYPE: SL51HKPRDG 6" DEPTH IN: 14226' DEPTH OUT: 14336' Footage Hours On Bottom Off Bottom TOTAL: 110 9.9 4.5 5.4 YESTERDAY'S TOTAL: 110 9.9 4.5 5.4 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: l~Iax: 0u Average: 0 Current: 0u<~14312' TRIP GAS: 8u(~14336' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 .. % SAND: 85 % CONGLOMERATIC SAND: COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: , Bit Typei INTERVAL: SILTSTONE: 0 % CLAYSTONE: 5 % .1.0. % TOTAL: NEtI BEFORE DURING MAXIMUM AFTER REMARKS: ROP WOB M,Wt, GAS Cl C...~2 c._~3 ca, c5 Pull out of hole to shoe, check flow, and pull out of hole. Make up new BHA with new bit and mud motor, service rig, and run in hole with 3 ½" drill pipe. Run in hole with 5" drill pipe, ream to bottom, 14219' to 14336', and slide from 14336' to 14364'. EPOCH 58 UNOr. JtLe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 9, .2001 DAILY COST: 12:01 AM DEPTH: 14600' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $46305 14364' 24 HR FTG: 236' 0 24 HR AVE: .20.6 NO.: 12 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 14336' Footage Hours On Bottom Off B~t~0~n" ' TOTAL: 376 23.2 11.4 11.8 YESTERDAY'S TOTAL: 28 6.9 3.3 3.6 PAST 24 HOURS: 348 16.3 8.1 8.2 NO.: 11 MAKE: REED TYPE: SL51HKPRDG 6" DEPTH IN: 14226' DEPTH OUT: 14336' Footage Hours On Bottom Off Bottom TOTAL: 110 9.9 4,5 5.4 YESTERDAY'S TOTAL: 110 9.9 4.5 5.4 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~14312' TRIP GAS: N/A WIPER TRIP GAS: I ' NA GROSS LITHOLOGY: COAL: .0 .... % SAND: 85 % CONGLOMERATIC SAND: SILTSTONE: 0 % CLAYSTONE: . 5 . % 10. % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: TOTAL: NET BEFORE DURING MAXIMUM AFTER RoP WOB MWt GAS C._~1 C...~2 C.~3 C~4 C...~5 REMARKS: Drill ahead sliding and rotating as required to 14600'; circulate 30 minutes and pump dry job. Pull out of hole to shoe and drop dart; pressure test to 1800 psi. Pump out sub and continue to POOH. EPOCH 59 UNOCAL K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 10, 2001 DAILY COST: 12:01 AM DEPTH: 1470ft. ' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $48020 14600' 24 HR FTG: 104' 32 24 HR AVE: 20.8 NO.: 13 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN: 14600' Footage Hours On Bottom Off Bottom TOTAL: 104 7.4 5.0 2.4 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 104 7.4 5.0 2.4 NO.: 12 MAKE: SMITH TYPE: XR20HTGDGP~ 6" DEPTH IN: 14336' DEPTH OUT: 14600' 'Footage' Hours On Bottom Off Bottom TOTAL: 374 23.2 11.4 1 t .8 YESTERDAY'S TOTAL: 374 23.2 11.4 11.8 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: Max: 0u Average: 0 Current: 0u(~14611' TRIP GAS: 8u(~14600' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SAND: .9.0 .. % CONGLOMERATIC SAND: SILTSTONE: 0 % CLAYSTONE: 5 .. % % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: I TOTAL: NET BEFORE DURING MAXIMUM AFTER R0P WOB MWt GAS c._~1 c._~2 c_~3 ca, c..~5 REMARKS: Test BOPE's, and run in with BHA with new bit #13. Pick up and run in with 9 joints of 3 %% and run in with rest of 3 ½" and fill pipe. Run in with 5" to bottom, filling pipe at shoe and washing down on last stand. Drill ahead, sliding and rotating to 14704', and unable to circulate after back reaming at connection. Pull out of hole. EPOCH 60 UNOr. K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 11, 2001 DAILY COST: 12:01 AM DEPTH: 14919' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $49735 14704' 24 HR FTG: 215' 18 24 HR AVE: 23.8 NO.: 14 MAKE: SMITH TYPE: XR20HT .~DGPS 6" DEPTH IN: 14704' Footage Houm On Bottom Off Bottom TOTAL: 215 13 9.0 4.0 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 215 13 9.0 4.0 NO.: 13 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN: 14600' DEPTH OUT: 14704' Footage Hours' On Bottom Off Bottom TOTAL: 104 7.4 5.0 2.4 YESTERDAY'S TOTAL: 104 7.4 5.0 2.4 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY CONNECTION GAS: Max: 0u Avera§e: 0 Current: 0u~14885' ... TRIP GAS: 8u(~14704' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SILTSTONE: 0 % SAND: 95 % CLAYSTONE: 5 . % CONGLOMERATIC SAND: 0 % COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: I TOTAL: NET BEFORE DURING MAXIMUM AFTER ROP WOB MWt GAS C_~1 C..~2 C.~3 C_~4 C._~5 REMARKS: Pull out of hole with 3 ½% Make up BHA with new motor, bit #14, and pump out sub, and download and test MWD tool. Run in with new BHA and 3 %", fill hole, cut and slip drill line, and service rig. Run in hole with 5" down to 14607', and wash to bottom at 14704'. Drill ahead, rotating and sliding, from 14704' to 149t9'. EPOCH UNOr. ALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 12, 2001 DAILY COST: 12:0t AM DEPTH: 15069' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $51450 14919' 24 HR FTG: 150' 23 24 HR AVE: 22.7 NO.: 15 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 15014' Footage ............... H~Urs On Bottom ........ Off Bottom TOTAL: 55 3.9 2.8 1.1 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 55 3.9 2.8 1.1 NO.: 14 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 14704' DEPTH OUT: 15014' Footage Hours On Bottom Off Bottom TOTAL: 310 18.9 12.8 6.1 YESTERDAY'S TOTAL: 215 13 9.0 4.0 PAST 24 HOURS: 95 5.9 3.8 2.1 GAS SUMMARY BACKGROUND GAS: Max=[ 21u(~14961' Average: [ 13u Current: I 7u CONNECTION GAS: Max: 0u Average: 0 Current:' 0u(~14979' TRIP GAS: 7u(~15014' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 0 % SILTSTONE: 0 % SAND: 80 % CLAYSTONE: 10 % CONGLOMERATIC SAND: 10 .% COAL INTERVALS: NONE. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: I TOTAL: NET BEFORE DURING MAXIMUM AFTER R0P WOB MWt GAS, C_~1 C..~2 C..~3 C_~4 C..~5 REMARKS: Drill ahead, rotating and sliding, from 14919' to 15014', circulate 45 minutes, check flow, and pull out of hole to shoe. Drop dart, pull out 5 stands, pump dart and shear sub, and pump dry job. Pull out of hole, and change BHA with new bit and pump out sub, and add stabilizer. Test MWD and pick up and run in hole with 15 joints of 3 %" drill pipe. Run in hole to 14899', and ream to bottom. Drill ahead, rotating from 15014' to 15069'. [::1 EPOCH 62 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 13, 2001 DAILY COST: 12:0t AM DEPTH: 15230' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: $1715 CUM COST: $53165 15069' 24 HR FTG: 161' 7 24 HR AVE: 18.7 NO.: 16 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN: 15230' Footage Hours On Bottom Off Bottom TOTAL: 0 0 0 0 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0 0 0 NO.: 15 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 15014' DEPTH OUT: 15230' ................ "~"-':':-"-'- ..... ':'~ Footage "'Hours "'on' Bottom Off BottOm TOTAL: 216 14.5 1i.4 3.1 YESTERDAY'S TOTAL: 55 3.9 2.8 1.1 PAST 24 HOURS: 161 10.6 8.6 2.0 GAS SUMMARY CONNECTION GAS: Max: 0u Average: 0u Current:. 0u(~15177' TRIP GAS: 7u(~150141 WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 5 % SILTSTONE: 0 % SAND: 75 % CLAYSTONE: 20. % CONGLOMERATIC SAND: 0 % COAL INTERVALS: 15104-15t08'. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: I BEFORE DURING MAXIMUM AFTER TOTAL: NET ROP WOB MW.t GAS, C~1 C_.[2 C~3 C_~4 C..~5 REMARKS: Drill ahead, rotating and sliding, from 15069' to 15230', circulate 20 minutes, check flow, and pull out of hole to shoe. Drop dart, pump dart, shear sub, and pump dry job. Pull out of hole, and change BHA with new bit and pump out sub, and add MWD logging tool. EPOCH 63 UNOCAL K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 14, 200.1 DAILY COST: $1715 12:01 AM DEPTH: 15230' YESTERDAY: ROP (FTIHR): PRESENT: CURRENT BIT INFORMATION: CUM COST: $54880 15230' 24 HR FTG: 0' 0 24 HR AVE: 0 NO.: 16 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN/OUT: 15230' Footage Hours On Bottom Off Bottom TOTAL: 0 0.5 0 0.5 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0.5 0 0.5 NO.: 15 MAKE: SMITH TYPE: XR20HTGDGPS 6" DEPTH IN: 15014' DEPTH OUT: 15230' Footage Houm On Bottom Off Bottom TOTAL: 216 14.5 11.4 3.1 ,, YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0 0 0 BACKGROUND GAS: Max: 0u~15105' Average: I 0u Current: I 0u ... CONNECTION GAS: Max: 0u Average:I 0u Current:I 0u(~15177' TRIp GAS: N/A WIPER TRIP GAS: I NA GAS SUMMARY GROSS LITHOLOGY: SILTSTONE: 0 % CLAYSTONE: 20. % 0 % COAL: 5 % SAND: 75 % CONGLOMERATIC SAND: COAL INTERVALS: 15t04'-15108'. COAL ANTICIPATED: NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: TOTAL: NET BEFORE DURING MAXIMUM AFTER ROP WOB MWt (;AS C._~t C:2 C_~3 Ca, C_~5 REMARKS: Continue making up BHA and load nukes. Run into hole. Wash and ream 12667'. 12691', no go, tight. Pull out of hole to shoe, circulate bottoms up and pump dry job. Pull out of hole and change BHA. Run into hole and slip and cut drill line. EPOCH 64 UNO J L K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 15, 2001 DALLY COST: $1715 CUM COST: $56595 12:01 AM DEPTH: 15468' ROP (FTIHR): YESTERDAY: 15230' 24 HR FTG: 238'.... PRESENT: 65 24 HR AVE: 13.4 CURRENT BIT INFORMATION: NO.: 16RR MAKE: HUGHES TYPE: EP4970 6" DEPTH IN: 15230' Footage Hours on'Bottom off Bottom TOTAL: 238 19.9 17.8 2.1 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 238 19.9 17.8 2.1 NO.: 16 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN/OUT: 15230' Footage Houm On Bottom Off Bottom TOTAL: 0 0.5 0 0.5 YESTERDAY'S TOTAL: 0 0.5 0 0.5 ,, PAST 24 HOURS: 0 0 0 0 GAS SUMMARY BACKGROUND GAS: .Max:[ 22u(~15404' Average: I 5u Currant: CONNECTION GAS: Max: 0u Average: 0u Current: 0u~15375' TRIP GAS: 8u(~15230' WIPER TRIP GAS: I NA GROSS LITHOLOGY: COAL: 10 % SILTSTONE: 10 % SAND: 40 % CLAYSTONE: 30 % CONGLOMERATIC SAND: 10 % COAL INTERVALS: COAL ANTICIPATED: 15400'-15415'. NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: TOTAL: NET ROP WOB MWt GAS C.~ C...~2 C._~3 C.~4 C...~5 BEFORE DURING MAXIMUM AFTER REMARKS: Finish running in hole, filling pipe at shoe, and working through tight spots at 14288 to 14322', 14342 to 14621', and 14723 to 14733'. Wash and ream to bottom on last stand, and drill ahead, rotating, from 15230' to 15468'. EPOCH 65 UNOCALe K13 RD2 EPOCH MORNING REPORT UNOCAL ALASKA RESOURCES, INC. K-13RD2 DATE: JUNE 16, 2001 DAILY COST: $1715 CUM COST: $58310 12:01 AM DEPTH: 15485' ROP (FTIHR): YESTERDAY: 15468' 24 HR FTG: 17' PRESENT: 12 24 HR AVE: 14.2 CURRENT BIT INFORMATION: NO.: 16RR MAKE: HUGHES TYPE: EP4970 6" DEPTH IN: 15230' DEPTH OUT: 15485' .... ' Footage Hours .......... On Bottom off"B~fl:om TOTAL: 255 38.8 19.0 19.4 YESTERDAY'S TOTAL: 238 19.9 17.8 2.1 PAST 24 HOURS: 17 18.5 1.2 17.3 NO.: 16 MAKE: HUGHES TYPE: EP4970 6" DEPTH IN/OUT: 1523C' Footage Hours On Bottom Off Bottom TOTAL: 0 0.5 0 0.5 YESTERDAY'S TOTAL: 0 0 0 0 PAST 24 HOURS: 0 0 0 0 GAS SUMMARY BACKGROUND GAS: Max:] 42u~15462' Average: I 24u Current: I 12u CONNECTION GAS: Max: 0u Average: 0u Current:. 0u(~15375' TRIP GAS: NA WIPER TRIP GAS: i ' NA GROSS LITHOLOGY: COAL: 70 % SILTSTONE: 0 ...... % SAND: 10~ % CLAYSTONE: 20 . % CONGLOMERATIC SAND: 0 % COAL INTERVALS: COAL ANTICIPATED: 15440'-15470'. NA SHOW SUMMARY: NONE Lithology Descriptions: Bit Type: INTERVAL: I TOTAL: NET BEFORE DURING MAXIMUM AFTER ROP WOB MWt GAS C...~t C..~2 C_~3 C._~4 C.~5 REMARKS: Drill ahead, rotating, from 15468 to 15485', total depth as drilled into coal, and circulate 20 minutes. Pull out of hole to shoe back reaming at less than 300 feet per hour, as logging while back reaming. Pull out of hole 11 stands and service rig, and continue to pull out of hole. EPOCH 66 Re: FW: K-13RD abandon and redrill BOP tests Subject: Re: FW: K-13RD abandon and redrill BOP tests Date: Thu, 03 May 2001 10:28:07 -0700 From: Tom Maunder <tom_maunder@admin.state.ak.us> To: "Billingsley, Tim" <billita@unocal.com> CC: ^OGCC North Slope Office <aogcc_prudhoe_bay@admin.state.ak.us> Tim, Thanks for the additional information. On further discussion, we do concur that although threads do exist in the hanger it is quite possible that they might not be able to provide the seal desired. In the presented plan, you will have killed the tubing, loaded the annulus and placed a BPV prior to removing the tree. After NU the BOP, the only components that will not be tested are the lower pipe rams and blind rams. Although the sealing ability of the rams will not be tested, the integrity of the BOP body will be verified when the upper rams and annular are tested. Based on the above discussion, your ram arrangement and proposal to test the lower pipe rams and blinds after pulling the completion is accepted. Good luck and do not hesitate to call with any questions. Tom Maunder, PE Petroleum Engineer AOGCC "Billingsley, Tim" wrote: As we discussed on the telephone the morning of 4/28/01, the FMC equipment at King Salmon does allow us to set a BPV in the tubing hanger profile and then screw in a blanking plug in the hanger lifting threads above the BPV. The blanking plug running tool has a left hand thread where once the blanking plug is seated, the running tool can be further turned to the right to re/ease the running tool. This would allow us to test the blind rams and lower pipe rams on the initial rig up of the BOPs. Unocal prefers not to run the blanking plug for two main reasons; 1) The hanger lift threads are of questionable quality and may not hold pressure. In K-13RD's case, the tubing was run in 1983 so considerable time may have deteriorated the threads. We won't know this until the tree is pulled. In any case, it is difficult to screw in a blanking plug with sufficient torque to give pressure integrity, screw off with left hand threads and still be able to recover it after testing blind rams so you can make up the landing joint. 2) Even if the hanger threads are good, there is still an unknown and unmonitorable situation below the blanking plug once it is installed. FMC does not make a two-way check for this equipment, it is a blanking plug. The BPV gives you an added level of protection below the blanking plug but there is no way to check to see if it is working with the blanking plug in p/ace. A piece of debris has in the past kept the BPV open 1 of 3 5/3/01 10:28 AM Re: FW: K-13RD abandon and reddll BOP tests and alllowed two way communication through it. This could allow pressure to become trapped under the blanking plug, with no way to determine that it's there, resulting in a safety hazard. Therefore, even though there is FMC equipment available to test the blind rams and lower pipe rams with the tubing hanger still on seat, Unocal requests permission to wait until after the tubing and tubing hanger has been pulled to test these lower rams with a test plug. This would be safer and more efficient than using a blanking plug screwed into the tubing hanger. Thank you for your consideration and please call with any questions. We are currently running the completion on K. 1RD on 4/27/01 and expect about a 1 week leg move. Therefore, the initial BOP test on K-13RD will be probably the weekend of May 5-7. Tim Billingsley Drilling Engineer, Unocal 263.7659 .--Original Message--- From: Billingsley, Tim Sent: Tuesday, April 17, 2001 2:55 PM To: Maunder Tom (E.mail) Cc: Byrne, Don S Subject: K-13RD abandond and redrill BOP tests Unocal would like to propose a BOP ram configuration and test procedure for the K. 13RD abandonment. As you know, we have had problems with landing joint thread leaks in old tubing hangers and trapped pressure safety concerns under blanking plugs instal/ed in tubing hangers. For K-13RD (which has 4.1/2" tubing), Unocal proposes to install the BOPs as follows: Annular Top of double gate with 4-1/2" pipe rams Bottom of double gate with blind rams Drilling cross Single gate with 2-7/8" x 5" variable bore rams 1) The initial test after ND the tree would be a 3000 psi test of the choke manifold, choke and kill valves, 3000 psi test of the annular and a 3000 psi test of the 4-1/2" upper pipe rams only. A cut will be made in the 4-1/2" tubing at 8900', then pull the 4.1/2" tubing. 2) After the tubing is out of the way, change the 4-1/2" pipe rams to 5" pipe rams for the upcoming drill pipe work, run a test plug into the tubing head, and test the 5" rams, the blind rams and the VBR's to 3000 2 of 3 513/01 10:28 AM Re: FW: K-13RD abandon and reddll BOP tests psi. This would avoid setting a blanking plug in the old tubing hanger. It is a potential hazard to remove the blanking plug if an air bubble has accumulated under the plug while testing the rams. K-13RD is a shut-in gas lifted producer. The tubing and 9-5/8"x tbg annulus will be killed with FIW prior to ND the tree. Please let us know if it is acceptable to proceed on the proposed initial BOP test of only the annular and the upper pipe rams with deferring the blind ram and lower ram test until after the tubing is pulled. Thank you for your consideration. Tim Billingsley 263-7659 Tom Maunder <tom maunder~admin.state,ak, us> Petroleum Engineer Alaska Oil and Gas Conservation Commission 3 of 3 5/3/01 10:28 AM AI,ASKA OIL AND GAS CONSERVA~ION CO~SSION Dan Williamson Drilling Manager Unocal P.O. Box 196247 Anchorage, Alaska 99519-6247 TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Trading Bay Unit K13RD2 Unocal Permit No: 201-046 Sur Loc: 615' FSL and 120' FEL Sec. 17, T9N,~ Btmhole Loc. 5249' FSL and 2535' FEL, SeE 15, T9N, R13~, SM Dear Mr. Williamson: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by. law from other governmental agencies3 and does not authorize conducting drilling operations until all other required permitting determinations, are made. Annular disposal has not been requested as part of the Permit to Drill application for Trading Bay Unit Well No. K- 13RD2. Please note that any disposal of fluids generated from this drilling operation which are pumped down the surface/production casing annulus of a well approved for annular disposal on the King Salmon Platform must comply with the requirements and limitations of 20 AAC 25.080. Approval of this permit to drill does not authOrize'disposal of drilling waste in a volume greater than 35,000 barrels through the annular space of a single well or to use that well for disposal purposes for a period longer than one year. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given to allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission at 279-1433. Daniel T. Seamount, Jr. Commissioner BY ORDER OF THE COMMISSION ~. ?~ ~' ( DATED this '~ ~' day of ~ 2001 ' jjc/Enclosures cc: Department of Fish & Game, Habitat Section w/o enCl. Department of Environmental Conservation w/o encl. ALASKA OIL AND GAS CONSI RYA ION COM v SSION TONY KNOWLES, GOVERNOR 333 W. 7TM AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 80.81 Re: The application of Union Oil Company of Califomia, operator of the Trading Bay Unit (TBU), to drill and complete the McArthur River Field K-13RD2 well. Shannon W. Martin Land/Legal Analyst UNOCAL Corporation P O Box 190247 Anchorage, AK 99519-0247 Dear Mr. Martin: Your application dated February 7, 2001 for a "Permit to Drill" for McArthur River Field well K13RD2 is proposed to recover additional oil from Hemlock Oil Pool. The Alaska Oil and Gas Conservation Commission hereby authorizes the drilling and completion of the McArthur River Field well K-13RD2 well pursuant to Rule 5 of Conservation Order 80. p,,,,'/__ Done at Anchorage, Alaska and dated l~h _~, 2001. Commissio~e~ Camill60echsli Taylor Commissioner Julie M. Heusser Commissioner BY ORDER OF THE COMh~SSION MAP,- 5-01 MOi~ UMOCAL LAW DEPT, ., - AK PAX HO, 9072637698 Unocal Alaska Resourc , Unocat Corporal;on 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 P. 1 UNOCAL March 5, 2001 Mr. Bob Crandall Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 February 7, 2001 - Request for Spacing Exception Well K-13RD2 ADL 18772 VIA FACSIMILE Dear Mr. Crandall: Per our discussion this afternoon regarding Unocai's February 7, 2001 Request for Spacing Exception on Well K-13R°2, ADL 18772, Unocal respectfully requests withdrawal of the request as such an exception is not necessary under 20 AAC 25.055(a)(1). We do apologize for any inconvenience this may have caused you or your staff, Thank you and best. Very Truly Yours, Shannon W. Martin Land/Legal Analyst ALASKA OIL AND GAS CONSERVATION COMMISSION F F_ ~ 1_ 2, ~ 001 PERMIT TO DRILL 20 AAC 25.005 Alaska Oil & Gas Cons. Commission la. Type of work Drill Redrill X lb. Type of well Exploratory Stratigraphic Test Developmen~'~ICJ~ge Re-entry Deepen Service Development Gas Single Zone Multiple Zone 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool Unocal 100' RKB above MSL McArthur River Field 3. Address P. O. Box 196247 6. Property Designation Hemlock Anchorage, Ak 99519-6247 ADL 18772 4. Location of well at surface 7. Unit or Property Name 11. Type Bond (see 20AA025.025) 615' FSL and 120' FEL Sec. 17, T9N, R13W, SM Trading Bay Unit AK Statewide Oil & Gas Bond At top of productive interval Hemlock (9700' TVD) 8. Well Number Number 2997' FSL and 5031' FEL Sec. 15, T9N, R13W, SM K-13RD2 U 62-9269 At total depth 9. Approximate spud date Amount 5249' FSL and 2535' FEL, Sec. 15, T9N, R13W, SM 4/5/01 $200,000 12. Distance to nearest 13. Distance to nearest well 14. Number of acres in property 15 Proposed depth (MD and TVD) property line 392'@ 11600' MD 15,860' MD 31' @ TD (McArthur st. #1) Lease 1902 acres 9835' TVD 16. To be completed for deviated wells 17. Anticipated pressure (see 20 AAC 25.035 (e)(2) Kickoff depth 8900 feet Maximum hole angle 90° Maximum Surface 2726 psig. At total depth (TVD) 3836 psig 18. Casing Setting Depth program size Specifications Top Bottom Quantity of cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD exist 24" 394' 0 0 394' 394' exist 13-3/8" 61&68 K-55 Butt 5011' 0 0 5011' 4176' 1250 sx exist 9-5//8" 47 S-95 Butt 11540' 0' 0' 8900' 7330' 1000 sx from 11540' N-80 KOP 8.5" 7" 29 L-80 Butt 3800' 8700' 7157' 12500' 9709' 515 sx 6" 4-1/2" 12.6 L-80 Butt 3560' 12300' 9598' 15860' 9835' None, slotted liner 19. To be completed for Redrill, Re-entry and Deepen Operations Present well condition summary Total depth: measured 12,173 feet Plugs (measured) true vertical 10,021 feet Effective Depth measured 12,078 feet Junk (measured) 8954' MD/7369' TVD solids in tubing true vertical 9949 feet Casing Length Size Cemented Measured Depth True Vertical Depth Structural Conductor 394' 24" Yes 394' 394' Surface 5011' 13-3/8" 1250 sx 5011' 4176' Intermediate Production 11540' 9-5/8" 1000 sx 11540' 9429' Liner 901' 7" 300 sx 11230'- 12131' 9399'-9989' Perforation Depth: measured 11688'-11712', 11728'-11734', 11751'-11830' true vertical 9634' - 9747' gross interval 20. Attachments: Filing Fee X Property Plat BOP Sketch X Diverter Sketch Drilling Program X Drilling Fluid Program X Time vs Depth PIct Refraction analysis Seabed Report 20AAC25.050 Requirements X 21. I he,.r.~ .~/certifY~at,,t~,~oregoing is true and correct to the best of my knowledge Signe~~/\) .~~,{J,~({XI\'"~tA~t]'~L' Title: Drilling Manager Date ~ -7~ ~ / Commission Use Only Permit Number APl Number _ _ ! Approval date / ISee cover letter o / - -I for other requirements Conditions of approval Samples required Yes ~ Mud log required Yes ~ Hydrogen Sulfide measures ~ No Directional Survey required ~ No R equiredworkingpressureforBOPE 2M ~ 5M 10M 15M~ Other: ORIGINAL SIGNED RY by order of Approved by FI T,,,,J,.,,. ~,7,'~,~7.~'-- Commissioner the commission Date Form 10-401 Rev. 12-1 AFE #148256 Sui n triplicate ORIGIklAL (A) (B) (c) King Salmon K-13RD2 Hazard Analysis for APD 20AAC 25.005 (c) 4 .Alaska Oil & O~s Cons. Commissic, r~ Anchorsge The maximum downhole pressure that may be encountered is at the base of the TyonekJtop of Hemlock at 9709' TVD' with a formation pressure of 4342 psi (8.6 ppg EMW). The maximum potential surface pressure based on the unlikely event of full-evacuation with a methane gradient is 2726 psi. (See Maximum Anticipated Surface Pressure attachment) The Hemlock production in the area has an H2S content of up to 400 ppm. Prior to drilling the K-13RD2, a full cascade system and individual SCBA's will be in place. An H2S Safety Technician will service the equipment, conduct drills and refresh crew members in the proper use of the equipment. The first and second hole sections will be drilled with an 8.8 ppg oil based mud. This Tyonek interval is expected to be normally to subnormally pressured. The Hemlock is expected to be subnormal pressure at 7.5 ppg EMW. If sloughing coals prove troublesome, the mud weight can be increased to appx 10.0 ppg. A potential for lost circulation exists and adequate supplies of lost circulation material will be on board before drilling commences. APD procedure and Hazard k- 13RD2.doc 2~6/01 King Salmon Well #K-13RD2 Maximum Anticipated Surface Pressure Alaska Oil & Gas Cons. Co~,.'n, missior~ Anchorage The following presents data used for calculation of anticipated surface pressures (ASP) during drilling of the sidetrack K-13RD2. The pore pressure gradient was estimated from the following information for McArthur River Field Northern Nose prospect: BHP Depth Well psi TVD EMW, ppg Comment 4250 9450' 8.6 Original G zone pressure G-7 3800 9733' 7.5 12/97 pressure survey in Hemlock The fracture gradient at sidetrack window at 8900'MD/7330'TVD was estimated at .74 psi/ft or 14.2 ppg based on K-8RD (now known as K-26RD) leak off test on 1/25/85. Casing Pore Casing Setting Fracture Pressure Mud Pore ASP Size Depth Gradient Gradient Weight Pressure Drilling (in.) (TVD ft) (Ibs/.qal) (Ibs/qal) (Ib/.qal) (psi) (psi) 9-5/8" 7330 14,2 8.6 8.8 3265 2058 KOP 7"liner 9709' 14.2 8.6 8.8 4342 2726 4-1/2" 9835' 14.2 7,5 8.8 3836 slotted liner Procedure for Calculating Anticipated Surface Pressure While Drillinq ASP is determined as the lesser of 1) surface pressure at breakdown of the formation at the casing seat (with gas bubble just below shoe and mud gradient above shoe) or 2) formation pore pressure at the next casing point less gas gradient to the surface as follows: For 8-1/2" Hole Section from 7730' TVD to 9709' TVD 1)' ASP : (FGx.052xD) - (MWx.052xD) : (14.2 x .052 x 7330) - (8.8 x .052 x 7330) = 2058 psi OR 2) ASP : FPP - (0.1gas gradient xD) = 4342 - (.lx 9709) = 4342 - 971 = 3371 psi For 6" Hole Section from 9709' TVD to 9835' TVD @ TD 1) ASP = (FGx.052xD) - (MWx.052xD) -- (14.2 x .052 x 9709) - (8,8 x .052 x 9709) = 2726 psi OR 2) ASP FPP - (0.1gas gradient xD) 3836-(.lx 9835) 3836 - 984 2852 psi Alaska Oil & ~',~::? Cons. Cc,~'i~mission Anchorage Procedure Summary of Proposed K-13RD2 Redrill (See Separate Description Summary for K-13RD Proposed abandonment) '~C) ~ -t:~m-~1 20 AAC 25.005(c) 5, 13 and 14 1 RIH with one-trip whipstock milling assy. (BOPE previously tested to 3000 psi during start of proposed abandonment procedure, weekly test will also be to 3000 psi) 2 Orient and set whipstock on top of abandonment retainer at 8900'. 3 Change over from brine to oil based mud. 4 Mill window in 9-5/8" casing at 8900'. Drill 20' of new formation. 5 Circ BU and perform Formation Integrity test to 11.0 ppg EMW. (If mills will not drill 20' of new formation, perform FIT after drilling 20' with first 8-1/2" bit) 6 POOH with mills. 7 Directionally drill 8-1/2" hole from 8900' to 12,500'. 8 Run and cement 7" liner with appx 515 sx of 15.8 ppg cement, (see attached Cementing Program). 9 Drill out liner and 20' of new formation. Perform FIT to 11.0 ppg EMW. 10 Continue drilling with 6" bit building to horizontal. 11 Drill appx 2000' of Hemlock HB-1 and HB-2 pay to a TD of 15,860'. 12 Log with LWD Gamma Ray/Resistivity tools. 13 Run 4-1/2" slotted liner with inner string. Circ out oil based mud with diesel. 14 POOH with drill pipe and inner string. 15 Set 7" permanent packer at appx 12,200'. 16 Run 4-1/2" x 3-1/2" tubing with gas lift mandrels. 17 Space out and stab seals in packer while landing hanger. 18 ND BOPE, NU tree. 19 Move rig and place well on gas lift production. Co;~S. )~/aska C)i/[~ ~ GommisstO'a The cuttings will be processed through a grinding unit on the King Salmon platform and the oil based mud and processed cuttings will be disposed in one of five annuli at King Salmon. A separate Sundry Application will be submitted for each of the five proposed annuli: K-6RD, K- 12RD, K-19, K-25, K-26RD. APD procedure and Hazard k-13RD2.doc 2/6/01 UNOCAL( RKB to TBG Hanger = 35.00' SIZE WT Trading Bay Unit King Salmon Platform Well # K-13RD Current Completion 12/20/83 CASING AND TUBING DETAIL GRADE CONN TOP BOTTOM 13-3/8" 61&68 J-55 BTC 35' 5011' 9-5/8" 47 N80 BTC 35' 4711' 9-5/8" 47 S-95 BTC 4711' 11540' 7" 29 N-80 BTC 11230' 12131' Tubing: 4-1/2" 12.6 N-80 3-1/2" 9.2 N-80 BTC 35' 11187' BTC 11187' 11329' LAST , TAG 8954' w/3 70" GR 11/1 JEWELRY DETAIL NO. Depth Item 1. 338' 2. 11187' 3. 11290' 4. 11316' 5. 11329' Camco 4-1/2" TRDP-1A SSSV (ID = 3.813") 4-1/2" x 3-1/2" crossover Baker 7" FB-1 wireline set packer Camco"D" nipple (ID=2.75") Baker Bull nose shear out sub 3.00" Gas Lift Information 1 2322' 4-1/2" Camco MMG w/RK latch 2 4731' 4-1/2" Camco MMG w/RK latch 3 6441' 4-1/2" Camco MMG w/RK latch 4 7496' 4-1/2" Camco MMG w/RK latch 5 8320' 4-1/2" Camco MMG w/RK latch 6 8845' 4-1/2" Camco MMG w/RK latch 7 9288' 4-1/2" CamcoMMG w/RKlatch 8 9487' 4-1/2" Camco MMG w/RKlatch 9 9685' 4-1/2" Camco MMG w/RK latch, dummy 10 9891' 4-1/2" Camco MMG w/RK latch, dummy 11 10067' 4-1/2" Camco MMG w/RK latch, dummy 12 10246' 4-1/2" Camco MMG w/RK latch, dummy PBTD = 12078' TD = 12173' TOP 11688 11728 11751 MAX HOLE ANGLE = 53° @ 4100' KI3RD schACT 12-20-83.DOC Tag Information 4/14/94 9/12/95 2/26/97 3/1/97 3/8/97 11/00 11/17/00 11/18/00 2.50" GR sat down at 11,937' 2.70" GR sat down at 11,316' Well production became erratic, solids produced Bailed sand from 8942' 2.25" GR tagged fill at 9348' 2.25" Bailer worked between 8952'-8988', flow well Inject 6000 bpd dwon tbg, 3.70" GR tag fill at 8954' PERFORATION DATA BTM ZONE SPF DATE COMMENTS 11712 H-1 4/8 11734 H-I 2 11830 H-2 4/8 REVISED: 01/31/01 DRAWN BY: TAB UNOCAL ) ,. Trading Bay Unit King Salmon Platform Well # K-13RD Proposed Abandonment, 2001 RKB to TBG Hanger = 35.00' LAST FILL TAG 8954' w/3.70" GR 11/18/00 PBTD = 12078' TD = 12173' CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP BOTTOM 13-3/8" 61&68 J-55 BTC 35' 5011' 9-5/8" 47 N-80 BTC 35' 4711' 9-5/8" 47 S-95 BTC 4711' 11540' 7" 29 N-80 BTC 11230' 12131' Tubing: JEWELRY DETAIL NO. Depth Item 1. 338' 2. 11187' 3. 11290' 4. 11316' 5. 11329' rop Cmt Retainer @8900' Camco 4-1/2" TRDP-1A SSSV (ID = 3.813") 4-1/2" x 3-1/2" crossover Baker 7" FB-1 wireline set packer Camco"D" nipple (ID=2.75") Baker Bull nose shear out sub 3.00" Proposed Tbg Cut @8920' TOP 11688 11728 11751 MAX HOLE ANGLE = 53° @ 4100' K 13RD proposed abdn.doc Gas iLift Information 7 9288' 8 9487' 9 9685' 10 9891' 11 10067' 12 10246' 4-1/2" Camco MMG w/RK latch 4-1/2" Camco MMG w/RK latch 4-1/2" Camco MMG w/RK latch, dummy 4-1/2" Camco MMG w/RK latch, dummy 4-1/2" Camco MMG w/RK latch, dummy 4-1/2" Camco MMG w/RK latch, dummy Tag Information 4/14/94 9/12/95 2/26/97 3/1/97 3/8/97 11/00 11/17/00 11/18/00 2.50" GR sat down at 11,937' 2.70" GR sat down at 11,316' Well production became erratic, solids produced Bailed sand from 8942' 2.25" GR tagged fill at 9348' 2.25" Bailer worked between 8952'-8988', flow well Inject 6000 bpd down tbg, 3.70" GR tag fill at 8954' PERFORATION DATA BTM ZONE SPF DATE COMMENTS 11712 H-1 4/8 11734 H-1 2 11830 H-2 4/8 REVISED: 01/31/01 DRAWN BY: TAB UNOCAL RKB to TBG Hanger = 35.00' Trading Bay Unit King Salmon Platform Well # K-13RD2 Proposed Redriil, 2001 CASING AND TUBING DETAIL SIZE WT GRADE CONN TOP 13-3/8" 61&68 J-55 BTC 35' 9-5/8" 47 N-80 BTC 35' 9-5/8" 47 S-95 BTC 4711' 7" 29 N-80 BTC 8700' 4-1/2" 12.6 L-80 slotted liner 12300' Tubing: 4-1/2" 12.6 N-80 BTC 35' 3-1/2" 9.2 N-80 BTC 8700' BOTTOM 5011' 4711' 8900' window 12500' 15860' 8700' 12300' JEWELRY DETAIL NO. Depth Item 1. 338' 2. 8700' 3. 12200' 4. 12250' 5. 12280' Camco 4-1/2" TRDP-1A SSSV (ID = 3.813") 4-1/2" x 3-1/2" crossover Baker 7" Model D perm packer "X" nipple (ID=2.813") 3-1/2" tbg tail Gas Lift Information 4-1/2" GLMs appx 6 3-1/2" GLMs appx 6 9-5/8" Window at 8900' MD, 30 deg hole angle liner cemented at 12,500' MD, +/- 65 deg hole angle ',, % Slotted Liner at Near-Horizontal in HB-1 and HB-2 · , ", 4-1/2" L-80, 12.6# tbg with 2-1/2" x 1/8" slots, 48 slots/ft ~% ·%., "'% TD = 15860' MD/9835' TVD MAX HOLE ANGLE = 89° @ 12900' to 15860' K 13RD2 proposed 2001 schematic.doc REVISED: 01/31/01 DRAWN BY: TAB Unocal ~ Forcenergy~ A-;~DING BAY ~-2~/~ _,0 A-20 A-27 17594-1,A Unocal Forcenergy I KING 17594-2, Unocal Marathon K-6 Note: TD is 3'I' from northern unit bdry. line 524.9 FSL 2535 FELL. MC ARTHUR ST. Note: K-13 Distance to nearest well:~ :392~ (McArthur St. #1) ~ K-6RD o ADING B I ., ,,,,~r,~, ,- .... ", ,OilS. L,;iL~[T;i'rii~,;f [O?l Ar c? ','&o :~ 18772-1 Unocal Tra~ing Bay Unit iBoundary K-17 (OH) 18730-1 .~ Unocal Marathon 18730-2,A I 18772-A Marathon K-2RD [K--5 K-; K-7 [-27 18730-2~ Unocal~ I Forcenergy 18772-B Force 0 1,000 2,000 3,000 SCALE IN FEET UNOCAL~) Trading Bay Unit Iii King Salmon Platform l!I Well K-13RD2 PROPERTY PLAT I UNOCAL P~ view Client: Unocal Well: K-13RD2 (P3) Field: McArthur River Unit Structure: King Salmon Scale: 1 in = 2000 ft Date: 15-Jan-2001 Schlumberger -2000 0 2000 4000 6000 8000 10000 True North - · 15861 MD 9~5TV1) 6g.33' 48.G~' az 463214 8146E 12~.0 MD ~611 'WD / ~d ~lT~l r t~76 MD ~ ~ 89.~' ~.~ ~ 2~1 N 5~ E ~ur ST 1 .K-13RD KOP ~ ~1~ / 89~0 MD 7330 TVD End Crv 30.00' 107_~0'-', g530MD 783i:'WD 111N 4405E 50.51. 24.99' 312N 4680E I 6000 6000 ^ ^ -i- 4000 4000 0 2000: · 2000 0 -2000 0 2000 4000 6000 8000 10000 <<< WEST EAST >>> V V V UNOCAL ) VERTICAL SECTIONVZEW Client: Unocal Well: K-13RD2 (P3) Field: McArthur River Unit Structure: King Salmon Section At: 39.61 deg Date: January 15, 2001 Schlumberger I- > LU __ KOP Ch' 8/t00 8900 MD 7330 TVD 30,00° 102.00' az '""Id~~. clv 61100 2894departure / 12320 MD 9611 TVD / 50.5t* 24.99' ez 50.51 ° End Cn~ < ~ /'/ 9530MD 78361'~ End CwlTgtl 12876 MD 9800 50.51' 24.96" az /89.33" 48.G8' az TD 3224 departure 5814 departure 16861 M 89.33' , 8762 de; K-13RD \ Hold Angle 39.33° McArthur ST 1 F -13 -- 0 2000 4000 6000 8000 Vertical Section Departure at 39.61 deg from (0.0, 0.0). (1 in = 2000 feet) UNOCAL ) Report Date: Client: Field: Structure I SI0t: Well: Borehole: UWI/API~: Proposal Name I Modified Date: Tort I AHD I DDI I ERD ratio: Grid Com'dinate System: Location Lat/Long: Location Grid FUE Y/X: Grid Convergence Angle: Grid Scale Factor: Proposed Well Profile - Geodetic Report January 15, 2001 Survey I DLS Co~nputalion Method: Minimum Curvature I Lubinski Unocal Vertical Section Azimuth: 39.610' McArthur River Unit .._,,,,., OnlyVertical Section Origin: N 0.000 fl, E 0.000, King Salmon/K-13 (slot 13, stud~ TVD Reference Datum: KB K-13 -- _ ----,,,,,!, 'rvD Reference Elevation: 100.0 It relalive to Mean Sea Level K-13RD2 50-733-20157-02 Magnetic Declination: 20.960° K-13RD2 (P3)/January 15, 2001 Total Reid Strength: 55363.909 nT 224.557° 110726.52 tt 16.589 / 1.091 Magnetic Dip: 73.532' NAD27 Alaska State Planes, Zone 04, US Feet Declination Date: October 30, 2000 N 60 51 54.903. W 151 36 21.032 Magnetic Declination Model: BGGM 2000 N 2511695.000 flUS, E 213765.000 ItUS North Reference: True Norlh -1.40275397° Total Corr Mag North -> True North: +20.960' 0.99999323 Coordinate Reference To: Well Head Schlumberger Station ID KOP Crv 8/100 8900.00 9000.00 9100.00 9200.00 9300.00 Incl 30.00 29.22 30.40 33.34 37.61 Grid Coordinates {°) (wi {"! {~! (~! {on00.) (.usI 102.00 7329.73 2893.89 110.93 4404.98 0.00 2511698.06 85.84 7416.81 2922.41 107.50 4453.85 8.00 2511693.44 69.89 7503.71 2961.20 117.98 4502.04 8.00 2511702.73 55.75 7588.75 3009.53 142.19 4548.59 8.00 2511725,80 44.07 7670.26 3066.44 179.64 4592.60 8.00 2511762.16 Easflng 218171.34 218220.11 218268.54 218315.67 218360.58 Geo~lraphlc Coordinates Latitude I Longitude N 60 51 55.988 W 151 34 52.080 N 60 51 55.954 W 151 34 51.093 N 60 51 56.057 W 151 34 50.120 N 60 51 56.295 W 151 34 49.180 N 60 51 56.663 W 151 34 48.291 End Crv Crv 8/100 12' coal 9400.00 9500.00 9529.93 12320.31 124OO.00 12479.91 12500.00 12505.61 12600.00 12700.00 42.83 48.67 50.51 50.51 55.81 61.27 62.66 63.05 69.66 76.75 34.65 7746.66 3130.83 229.61 4633.21 8.00 2511811.12 27.00 7816.46 3201.45 291.12 4669.64 8.00 2511871.72 24.99 7835.87 3223.60 311.60 4679.63 8.00 2511891.95 24.99 9610.52 5307.17 2263.39 5589.22 0.00 2513820.87 29.41 9658.30 5369.42 2320.03 5618.42 8.00 2513876.78 33.30 9700.00 5436.85 2378.17 5653.92 8.00 2513934.03 34.22 9709.44 5454.49 2392.91 5663.78 8.00 2513948.52 34.47 9712.00 5459.46 2397.03 5666.59 8.00 2513952.57 38.46 9749.84 5545.73 2466.47 5718.00 8.00 2514020.73 42.34 9778.73 5641.38 2539.27 5780.04 8.00 2514091.99 218402.40 218440.33 218450.81 219407.90 219438.48 219475.39 219485.61 219488.52 219541.62 219605.42 N 60 51 57.155 W 151 34 47.470 N 60 51 57.761 W 151 34 46.734 N 60 51 57.963 W 151 34 46.532 N 60 52 17.179 W 151 34 28.145 N 60 52 17.736 W 151 34 27.555 N 60 52 18.309 W 151 34 26.837 N 60 52 18.454 W 151 34 26.638 N 60 52 18.494 W 151 34 26.581 N 60 52 19.178 W 151 34 25.542 N 60 52 19.894 W 151 34 24.288 K-13RD2 (P3) report.xls Page 1 of 2 1/15/2001-4:20 PM Grid Coordinates Geo{~raphlc Coordinates 12800.00 83.90 45.99 9795.53 5739.56 2609.91 5848.69 8.00 2514160.93 219675.78 N 60 52 20,590 W 151 34 22.901 End Crv / Tgt 1 12875.75 89.33 48.68 9800.00 5814.45 2661.13 5904.27 8.00 2514210.77 219732.59 N 60 52 21.094 W 151 34 21.778 TD 15860.~6 89.33 48.68 9835.00 8762.01 4631.85 8146.13 0.00 2516126.00 222022.01 N 605240.487 W151 33 36.469 Le.qal Description: Surface: 620 FSL 129 FEL S17 T9N R13WSM Tie-In: 730 FSL 1004 FEL S16 T9N R13WSM End Crv / Tgt I .' 3280 FSL 4780 FEL S15 T9N R13W SM TD ! BHL: 5249 FSL 2535 FEL S15 T9N R13W SM Northin.~ PD [flUS] Eastin_~ {X) I'ftUS1 2511695.00 213765.00 2511698.06 218171.33 2514210.77 219732.59 2516126.00 222022.00 K-13RD2 (P3) report.xls Page 2 of 2 1/1512001-4:20 PM K-13RD2 Casing Design 20 AAC 25.005 (c) (6) 9-5/8" Production Casinq: 47#1 N-80 from 0'-4711'MD, 47# S95 from 4711'-8900' KOP Worst case for burst is the unlikely event of a gas kick while drilling at TD. If the wellbore filled up 50% with gas as described on the Maximum Anticipated Surface Pressure attachment, the maximum surface pressure would be 1094 psi. Burst= 1094 psi 9-5/8" 47# N-80 rated @ 6670 psi for burst Safety Factor = 6.1 OK Worst case for collapse is if lost returns occur while drilling below the 9-5/8" casing. The 9-5/8" casing 47# N-80 is from surface to 4711' MD/3968'TVD. The 9-5/8" casing 47# S-95 is from 4711' MD/3968' TVD to 8900' MD/7330' TVD. Collapse = (8.6 x. O52x3968') -(3968' x .1) = 1378 psi for full evacuation Collapse = (8.6 x .052 x 7330')-(7330' x .1) = 2545 psi for full evacuation 47# N-80 rated @ 4750 psi for clpse Safety Factor = 3.4 OK 47# S-95 Rated @ 5080 psi fpr clpse Safety Factor = 2.0 OK Tension = NA (casing already in place and cemented) 7" 29#, L-80, liner from 8700' MD/7157' TVD to 12500' MD/9709' TVD Burst: There is no significant burst requirements for a drilling liner. The 7" 29# L-80 liner is rated to 8160 psi which is much more than even the pore pressure of 3787 psi at TD. Worst case for collapse is if lost returns occur while drilling below the 7" liner. Collapse = (7.5 x .052 x 9709')-(9709' x .1) = 2816 psi for full evacuation 29# L-80 Rated @ 7020 psi fpr clpse Safety Factor = 2.5 OK Tension= (12500'-8700') x 29#= 110K Rated = 676K for body yield Safety Factor = 6.1 OK 4-1/2" 12.6#, L-80, slotted liner from 12300' MD tO 15860' MD Tension= (15860'-12300') x 12.6#= 45K Rated = 288K for body yield Safety Factor = 6.4 QK Collapse = Not applicable for slotted liner Burst = Not applicable for slotted liner King Salmon K-13RD2 Cementing Program 7" Liner 8-1/2" hole @ 12500' MD, top of liner at 8700' MD Cement volume for liner based on open hole volume plus 20%, liner lap, and shoe joints. Estimated volume is: 3600' (12500' - 8900') x 0.1268 cuft/ft (8-1/2" x 7") x 1.20 = 548 cuft 200' liner lap @ 0.1438 cuft/ft: 29 cuft 80' shoe jts x 0.1845 cuft/ft (7" liner capacity) = 15 cuff Total Cement = 548 + 29 +15 = 592 cuft or 515 sx of Class G cement @ 15.8 ppg with additives. 4-1/2" Liner Slotted liner will not require any cement Drilling Fluids Program UNOCAL King Salmon K-13RD2 Prepared by: Reviewed by: Presented to: Lee Dewees Tim Billingsly February 2, 2001 M-I Drilling Fluids L.L.C. ~ 721 West First Avenue OI~ILLINI:; Anchorage, Alaska 99501 i=LUliJS (907) 274-5564 (907) 279-6729 Fax ,~, ?,,i3,;'..:s ,2;',! & "J'--'::, '3c:~:';. L.,on-,i'ntss~cn Project Summary Well K-13RD2 · Casing Hole Casing Depth TVD Mud Mud Sum Cumulative Size Size Program System Weight Days Mud Cost Window Existing 8.5" ~ Versadrill 8.5-9.0 20 $80,000 9 5/8" 8900' 12,500' 8.8 12,500'- 9835' 4 1/2" 6" 15,860' Versadrill 20 $145,000 Comple- 15,860' 9835' Mapco Base Oil 7.4 5 $180,000 tion II III '1 .Key Issue ,No. ,1 Sloughing Coal · If coal sloughing becomes a problem add Ventro1401. In- crease mud weight if required to stabilize coals. .Key ,Is. sue .NO. 2 ..Hole Cleaning Key .ISs u e No. 3 .Drill Solids · Maintain sufficient 3 RPM reading in 8 1/2" interval to in- sure adequate hole cleaning. Sweep hole as needed to avoid cuttings buildup. Pump weighted sweeps in 6" interval to aid in hole cleaning. · Run as fine a mesh shaker screen as possible. Run centri- fuge during trips to reduce drill solids in mud. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRILLING FLUIDS 6500' - 12,500' Drilling Fluid System Key Products Solids Control Potential Problems Versadrill Oil Mud Mapco 200 / Versawet / Versacoat / Versa HRP / VG-69 / Versa- mod / Lime / Calcium Chloride / MI Bar/Ventrol 401/Borax Shale Shakers / Desilter / Centrifuge Coal sloughing, hole cleaning, drill solids buildup ,. : ... =.lnterval Drilling'FlUid ProPerties .. · · · · . · . : :.. . . . . . : Depth Mud Plastic Yield HTH P Interval Weight Viscosity Point Fluid Loss O/W Gels (ft) (PPg) (cP,) (Ib/100ft~) (ml/30min) Ratio (Ib/100ft 8900-12500' 8.5-9.0 20 - 25 18 - 22 4 - 5 cc's 85/15 15 - 30 · Displace hole to oil based mud. Insure no spacer or oil based mud is discharge& · Drill ahead, maintain low shear rate values with VG-69, Versamod, Versa HRP, and Alcomer 274. · Run centrifuge as needed to reduce solids buildup. · Pump weighted sweeps to aid in hole cleaning. · If sloughing coal becomes a problem, add 2 - 4 ppb of Ventrol 401 to mud system or spot a concentrated pill of 20 - 25 ppb Ventrol 401 across coal zone prior to trips. · Run 7" liner. Treat cement returns with Borax. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRILLING FLUIDS F,, c:~:,,~L:l ,~,: (~ 2:: Interval Summary (0" ho e) K-13RD2 12,500' - 15860' Drilling Fluid System Key Products Solids Control Potential Problems Versadrill Oil Mud Mapco 200 / Versawet / Versacoat / Versa HRP / VG-69 / Versa- mod / Lime / Calcium Chloride / MI Bar / Ventrol 401/Borax Shale Shakers / Desilter / Centrifuge Coal sloughing, hole cleaning, drill solids buildup ......· . ....,. lnte.~al. D r,iiling:' FI.U'i'd . pr°perties .... · ' · ..... ="' :..':.: "~ ................ ,, , ,, ,, ,, Depth Mud Plastic Yield HTH P Interval Weight Viscosity Point Fluid Loss O/W Gels (ft) (ppg) (cp.) (Ib/100ft2) (ml/30min) Ratio (Ib/100fF) 12500-15860 8.8 20 - 25 15-20 4 - 5 cc's 90/10 15 - 30 · .Drill ahead, maintain low shear rate values with VG-69, VersamOd, Versa HRP, and Alcomer 274. · Run centrifuge as needed to reduce solids buildup. · Pump weighted sweeps to aid in hole cleaning. Maintain adequate 3 & 6 RPM readings (8 to 12) to prevent settling in the horizontal section · If sloughing coal becomes a problem, add 2 - 4 ppb of Ventrol 401 to mud system or spot a concentrated pill of 20 - 25 ppb Ventrol 401 across coal zone prior to trips. · Run 4 1/2" pre-drilled liner. Displace open hole volume to base oil (Mapco 200). · Pump a Clean-up spacer for displacement to brine. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRILLING FLUIDS Interval Summary (8.5" and 6" hole) LOST CIRCULATION Lost Circulation Recommended LCM Pill Formulas Problems Key Products Drilling Fluid / OM Seal / SafeCarb Fine, Medium, Coarse / Versa- HRP ' 'LOst Circulation'Pill (Slig'ht Losses) " ..' ':. Volu'me M IX'II Fine SafeCarb SafeCarb Versa H RI5 of Mud Fine Medium (barrels) (ppb) (ppb) (ppb) (ppb) 30 10 10 10 1/4 ..Lo.st Circulati°n. Pill :(M:odera.te Losse.s)..~. · '. '.... :~..: Volume OM B SealIMIX II SafeCarb SafeCarb Versa HRP Fine of Mud Medium Coarse (barrels) (ppb) (ppb) (ppb) (ppb) 40 15 15 10 1/2 · ":..".. '"' · .;." .' .' ....' '.ost .C'~.rculation' Pill. '(severe .Losses) Volume I OM Seal SafeCarb SafeCarb of Mud I Medium Coarse (barrels) (ppb) (ppb) (ppb) 50 15 20 30 Versa HRP Polymer (ppb) ] · Versa HRP should be added last, only after all lost circulation material has been mixed. · If possible, spot pill across theft zone. Apply moderate pressure (50 - 100 psi) to squeeze pill into theft zone. (Do not exceed previous E.C.D. of circulation fluid). M-I Drilling Fluids L.L.C. 721 West First Avenue ~ BI~ILLIIIII~ Anchorage, Alaska 99501 (907) 274-5564 ~~ FLUlBS (907) 279-6729 Fax Kin~ Se.tmon Mud Pits with Suction Aug, '1993 Lines T la' IX // lO' Equolizerw Mud Pi~ ~1 1~'4 BBLS -16 BBL / FT [4 BBL / IN ]0' rquollzer w 10' Equalizer 6' Suction Line Mud Pii; 239 BBLS 3! BBL / FT &6 BBL / IN '1 · ,-DesiH:er .... 10' Suction_ ~3 -H 10' Equolizer____m. Mud Pit ;239 BBLS 3! ]~BL / Fl 2,6 BBL / tN 10' Equolizer~ ,.. 10' gut'S,on '~-~"1 H · X 10' 0" __!__ 29' // 19' 9" K-lrd BOP Stack r Table 3 1116"5M x 4 1116"5M DSA A 41116" 5M Foster HCR Valve B 4 1116" SM Manual gate valve C 3 1116" 5M Manual gate Kill line D 3 1116" 5M Manual gate Kill line 2.05' Btm of Trolly beam 4.75' ~ .62' Top of drill deck 16.00' 12.83' Graylock Hub Top of FMC Type 3 Unihead TO lO" CROWN VENT I II II ii iii BLOW DOWN GAS BUSTER TO CHOKE PANEL MANUAL SWACO CHOKE NOTE: SWACO CHOKES EACH HYDRAULICALLY ACTUATED VIA REMOTE. TO BOPE SWACO CHOKE CHOKE MANIFOLD Unocal PIATFORM 4-1/1~' & 3-1/li', 5M ~ISP Unocal Corporation P.O. Box 196247 Anchorage, AK 99501 Telephone (907) 263-7660 UNOCAL ) Dan Williamson Drilling Manager February 7, 2001 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Attn: Re: Commissioner Dan Seamount Application fro Permit to Drill (Form 10-401) McArthur River Field King Salmon Platform, Well K-13RD2 Commissioner Seamount: Enclosed is an Application for Permit to Drill (Form 10-401) for King Salmon Well #K-13RD2. A separate Sundry Application (Form 10-403) has been sent' to you for the proposed abandonment of K-13RD. K-13RD2 will consist of approximately 3600' of 8-1/2" hole and 3400' of 6" hole drilled with oil based mud. The OBM liquid waste and ground cuttings will be disposed of in King Salmon annuli. Separate Sundry Applications have been or will be sent for proposed annular injection in K-6RD, K-12RD, K-19, K-25 and K-26RD. A spacing exception is required due to proposed redrill TD proximity to the north lease line and a separate spacing exception request is attached. The expected spud date for this K-13RD2 is April 5, 2001 so your timely consideration for approval is appreciated. If there are any questions, please contact Dan Williamson at 263- 7677 or Tim Billingsley at 263-7659. Sincerely, ..... Dan Williamson Drilling Manager FEB ~. 2 Alaska Oil & Gas Cons. Coi'~'/rnissiot~ Anchorage AOGCC cover letter K-13RD2 APD.doc Tim Billingsley Unocal Alaska Resou~" Unocal Corporation 909 West 9th Avenue, P.O. Box 196247 Anchorage, Alaska 99519-6247 Telephone (907) 276-7600 UNOCAL ) February 7, 2001 Mr. Dan Seamount, Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 McArthur River Field, Hemlock Pool, G-Intervals, King Salmon Platform, Well K-13RD2 REQUEST FOR SPACING EXCEPTION ADL 18772 Dear Chairman Seamount: Enclosed is our application for Permit to Drill McArthur River Field, Hemlock Pool, King Salmon Platform Well K-13RD2 (form 10-401) pursuant to 20 AAC 25.005 and our check No.2004672 in the amount of $100.00 as required under 20 AAC 25.005 (c)(1). Verification of Application by the undersigned stating that applicant is acquainted with the facts, pursuant to 20 AAC 25.055 (b), is attached as part of this application. Conservation order 228 establishes ten-acre drilling units for the McArthur River Field. 20 AAC 25.055 (a)(1) provides that a governmental quarter section constitutes the drilling unit for oil exploration and that the surface location for a well exploring for oil must be at least 500 feet from the drilling unit boundary. 20 AAC 25.055 (a)(3) provides that no more than one well is to be drilled within any governmental quarter section; not closer than 1,000' from any well drilling to or capable of producing from the same pool. It is requested that the Commission approve an exception to the statewide spacing regulation for the drilling of Well K-13RD2, ADL 18772. The specific location, interval and depth for the King Salmon Platform Well K-13RD2 are as follows: Surface Location: Surface Location: 615' FSL and 120' FEL Sec. 17, T9N, R13W, SM At Top Productive Interval: 2993' FSL and 254' FWL Sec. 15, T9N, R13W, SM At Total Depth: 5249' FSL and 2535' FEL, Sec. 15, T9N, R13W, SM Kickoff Depth: 8900' Distance to nearest well (McArthur St. #1)): 360' ~ 11660'MD Unocal and Forcenergy are working interest owners in the K-13RD2 well. Furthermore, Unocal and Forcenergy are the owners and Unocal is the operator of all directly or diagonally offsetting sections. Thus, pursuant to 20 AAC 25.055 (d), notices by registered mail to contiguous landowners are not necessary. Pursuant to and 20 AAC 25.005 (c)(2) and AAC 25.055 (d)(2), enclosed is a plat showing the location of the well for which the exception is sought, all other completed and drilling wells on the property, and all other adjoining properties and wells. If you require additional information, you may contact me at 907-263-7882. Very Truly Yours, Shannon W. Martin Land/Legal Analyst Enclosures VERIFICATION OF APPLICATION FOR SPACING EXCEPTION COOK INLET, ALASKA ADL # 18772 Well: McArthur River Field Well K-13RD2 I, SHANNON W. MARTIN; Land/Legal Analyst, Union Oil Company of California, do hereby verify the following: I am acquainted with the application submitted for the drilling of the McArthur River Field, Well K-13RD2. I have reviewed the application submitted for the exception to 20 AAC 25.055 (a)(4) (statewide spacing) and all facts therein are true. I have reviewed the plat attached to said application, and it correctly portrays pertinent and required data. DATED at Anchorage, Alaska this 7th day of February 2001. ,g-tf~o~ ~. ~lartin Land/Legal Analyst STATE OF ALASKA THIRD JUDICIAL DISTRICT ) ) ss ) SUBSCRIBED TO AND SWORN before me this 7th day of February 2001. NOTARY PUBLIC THE STATE OF ALASKA My Commission expires: t ! Abska O[i E (7!as Co:~s. Corr~n'i]ssicn INQUIRIES CONTACT LOCATION WHERE INVOICES WERE SUBMI'FI'ED VENDOR NO. DATE ' CHECK ,., 1031548 01-FEB-0L 2004672 DATE INVOICE/CREDIT MEMO NO. VOUCHER NO. GROSS DISCOUNT NET 01-FEB-01 DRILLPERMITK13RD2 0201300000_" 100.00 100.00 I TOTAL ~. 10 0 0 0 10 000 3RM 4-2B1 81 (REV. 11 PRINTED IN U.S.A. C:TA/'~LI C'TI I~ 131:1:('M:3r' r'lr'O('lQITIkl~ /'"Mr'~' ' ;ITIBANK DELAWARE Subsidiary ofCitic.o, rp - )NE PENN~S WAY .... . . ... .. ._. EW C';ASTLE, "DE 19720 'ay rthe/: der .:- ed Dollars JLud 0'0 **************************************** _ . . Date Check Amount V 01-FEB-,01 *****i00,00 ANCHORAGE, AK 99501 United. States .. "' 00 h' "'?' 'il'::'"i~:' ~"::~"!:"':~,~, ' . Void'after six. months 'frd~.~ ~bo~ 'date:,.: ..... - ':-'- -'7. -'~. "; , , WELL PERMIT CHECKLIST FIELD & POOL ADMINISTRATION COMPANY ~,~/N~_~ / INIT CLASS 4~ ENGINEERING WELL NAM~ PROGRAM: exp __ dev ~ redrll ~ serv /C~wV GEOL AREA lrZ,~ UNIT# 1. Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from ddlling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available, in ddlling unit ............ 8. If deviated, is wellbore plat included ............. ·.. 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit canbe issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... 14. Conductor string provided ................... 15. Surface casing protects all known USDWs ........... 16. CMT vol adequate to circulate on conductor & surf csg ..... 17. CMT vol adequate to tie-in long string to surf csg .... ' .... 18. CMT will cover all known productive horizons ..... ' ..... 19. Casing designs adequate for C, T, B & permafrost ....... 20. Adequate tankage or reserve pit ................. 21. If a re-drill, has a 10-403 for abandonment been approved... 22. 23. 24; 25. _.. DATE 26. $/,-3-~ 27. 28. 29. GEOLOGY 30. 31. 32. · _ , ,. ~ . 34. ANNULAR DISPOSAL35. With proper cementing records, this plan (A) will contain.waste in a suitable receiving zonei ....... APPR DATE (B) will not contaminate freShwater; or cause drilling waste to surface; ' ' (C) will not impair mechanical integrity of the Well used for disposal; (D) will not damage producing formation or impair recovery from a pool; and (E) will not cimumvent 20 AAC 25.252 or 20 AAC 25.412. wellbore sag ~ ann. disposal para req ~ ON/OFF SHORE ~;~7" N- ' Adequate wellbore separation proposed. . If dive~r required, does it meet regulations .......... DHIling .fluid program schematic & equip list adequate ..... BOPEs, do they meet regulation ......... ~ ...... ~ N BOPE press rating appropriate; test to ~~ psig. Choke manifold ~mplies w/APl RP-53 (May 84) ........ ~ N Work will o~ur without operation shutdown ........... Is presen~ of H2S gas probable ................. Y N Pe~it ~n be issued wlo hydrogen sulfide measures ..... Y N~ Data presented on potential ove~ressure zones ....... y~ Seismic analysis of shallow gas zones ............. Seabed ~ndition suwey (if off-shore) ............. .Conta~ name/phone for weekly progress repods [explorato~y] Y N Y'N Y N Y N GEOLOGY: ENGINEERING: UlClAnnular COMMISSION: 8 s. r ,' Comments/Instructions: 0 Z O Z --I '3- c:~n~soffice\wordian~liana\checklist (rev. 111011100)
