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205-135
STATE OF ALASKA RECEIVED ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS MAR 2017 r2._.95l33 AOGi C 1.Operations Abandon Li Plug Perforations U Fracture Stimulate Lf Pull Tubing U mpplete Lf Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Coil Tubing FCO❑ Kill Well w/Coil ❑ Plug for Redrill ❑ Peri.New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other:❑ 2. Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska LLC Development ❑ Exploratory ❑ 205-135 3.Address: Stratigraphic❑ Service Q 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-23276-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0380109/ADL0380110 MILNE PT UNIT IVISH/SAG S-90 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/IVISHAK UNDEF WTRSP/SAG River Frac 11.Present Well Condition Summary: Total Depth measured 10,600 feet Plugs measured 9,750 feet true vertical 9,733 feet Junk measured N/A feet Effective Depth measured 9,750 feet Packer measured 7,795&9,496 feet true vertical 8,916 feet true vertical 6,967&8,666 feet Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/Q _ N/A Surface 4,372' 13-3/8" 4,372' 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic M True Vertical depth See Attached Schematic CANNED PP1 01? Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.7/13CR-85/BTS-8 9,593' 8,762' 7"ZAP Liner Packers and SSSV(type,measured and true vertical depth) Baker S-3 N/A See Above N/A 12.Stimulation or cement squeeze summary: Fracture Stimulation Intervals treated(measured): Sag River 9,623'-9,659' Treatment descriptions including volumes used and final pressure: See attached documents for volumes. ISIP=2,149psi 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 240 0 Subsequent to operation: 449 420 519 200 226 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ U' 16.Well Status after work: Printed and Electronic Fracture Stimulation Data 0 'f\'i GSTOR Oil 0 Gas ❑ WDSPL❑ 1 I ❑ 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: 4r?t/-./ 316-545 Contact Ted Kramer Email tkramer(c�hilcorp.com Printed Name Bo York Title Operations Manager Signature 7r,r Phone 777-8345 Date 3/30/2017 oto 1 .2.017 ,1, Form 10-404 Revised 5/2015 /0 lOj RBD�IS U\-/ �`"3� - 3 ZO�� 7 Submit Original Only Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 5-90 CTU 50-029-23276-00-00 205-135 11/9/16 12/4/17 Daily Operations: 11/9/26/2016-Wednesday PU LUBE, MU PCE/TOOLSTRING, STAB ONTO WELLHEAD PT TO 300 PSI LOW, 3500 PSI HIGH. PERFORATE INTERVALS: 9623'- 9629', 96291-9644', 96441-9659'. USING 3-1/8" HSC LOADED 6 SPF, PHASED 60 DEG, 21 GM MAX FORCE FRAC RDX CHARGES. CORRELATED TO SLB ULTRASONIC IMAGING CEMENT EVALUATION LOG DATED 27 NOV 2000. 11/10/2016-Thursday No activity to report. 11/11/2016- Friday 2016 "**WELL S/I ON ARRIVAL, NOTIFY PAD-OP, PT PCE 250L/2500H**. PULL FRAC SLEEVE FROM 9253' SLM (no abnormal marks seen). RUN 4-1/2" BRUSH & 3.50" G-RING AND BRUSH TBG FROM 9200'-9300' SLM. RUN 42-BO SHIFTING TOOL (keys up)TO XD SS AT 9284' MD (pass through multible times, sleeve closed). SET FRAC SLEEVE (OAL=58", 3.83"" no-go, serial#ON183 S1600267.001.1 4140 P110) IN XD SS AT 9284' MD. **RDMO, NOTIFY PAD-OP**" . 11/12/2016 -Saturday No activity to report. 11/13/2016-Sunday No Activity. Frac Tanks and Sand Chief have been previously spotted for Frac Job. MIRU SLB Frac equipment. Start loading frac tanks with 105 degree fresh water. PU and Install Oil States Tree Saver with cup mandrel set up for 4-1/2" 12.6# tubing. Observed pressure increase when cup mandrel entered tubing hanger. Pressure fell off and complete installation. PT Treesaver flange to 4.5k. RU 4" standpipe from TreeSaver to ground. Continue to spot frac and support equipment. Wells Support RU bleed off lines and annulus pop-off skid.Tie lines into bleed tanks. MIRU LRS portable test separator. 11/14/2016 - Monday PJSM. Complete RU of frac treating line. RU IA line to PRV skid. RU bleed lines to tanks. Heat and load 90 bbls diesel. Spot returns tanks at portable test separator. Fire up pumps-3 hrs to get all pump engines started. Bucket test LAS. Set up communications to read DHPG. PT treating line to 7,500psi. Open well to 100 psig. Pump 1 bbl diesel. WHP increased to 2,200psi. Set cups on tree saver. Shut in well. Bleed lines. Secure location. Well testers RU lines to return tanks. Stand by. 11/15/2016-Tuesday Frac on site. Fire up equipment. LRS top off diesel tanker. Spot and RU LRS to IA. Test line. Set IA pop-offs to 3,000psi. Open IA and pressure up to 2,000psi. Perform pre-job fluid testing. Pre-frac safety meeting. RTP. Open well to 580psi SITP/1,900 IAP/1,70psi OAP. Lead in with pumping diesel to verify injectivity. Pumped 1.9 bbls . Observed breakdown at 3,315psi WHP/6,975psi BHP. Flush diesel from lines with linear gel. Pump injetion test with linear gel - Established 30 bpm/ 4,300psi WHP/6,019psi BHP. ISIP-2,149psi/5,938psi BHP. Pump Calibration Test with 300 bbls YF130FIexD X-linked gel. Displace with linear gel. Ave pump rate was 30 bpm/4,300psi. SD. ISIP- 2,615psi WHP/6,531psi BHP. Monitor pressure fall off to determine closure. Redesign frac. Increase frac size by 50,000Ibs to a total of 202,877 lbs total. Wait for chemicals before pumping main frac. Chemicals on site.Transfer to PCM. Start main frac at 17:52. Pumped frac as per design. Pumped a total of 1,546 bbls slurry volume. Placed 197,164 lbs of prop into formation. Pumped total of 197,243 lbs of 16/20 resin coated proppant. Ave pump rate was 30 bpm. Freeze protected well with 30 bbls diesel. Shut in Well at tree saver. Flush pumps an lines. Evacuate fluid from all equip. Bleed IAP to 500psi. RD LRS . Return in morning to RDMO frac equipment. LRS Well testers on site. Hilcorp Alaska, LLC flileorp Alaska,LIA: Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPU S-90 Slickline/CTU 50-029-23276-00-00 205-135 11/9/2016 12/4/2017 �,a :e -°17.1,A11-1_...... :' � ��� `� ,:; 1116/1.6 Wednesday 1,1: Pull Tree-saver,secure well. RD treating lines and all frac equipment. MIRU Slickline to pull frac sleeve and tag TOS. Found TOS at 9,368' md. Vac out remaining water from frac tanks.Spot upright tank for CTU. 11/17/16-Thursday LRS Well testing RU flowcross on tree. Finish rigging up inlet line from flowcross to seperator.Complete RU. Finish loading upright for cleanout,MIRU Hal 1.75"CT mast unit. RU pump unit. Perform BOPE test. No night activity with CTU. 11/18/16 Fridy s �� ��� CTU crew on loc. PJSM. MU BHA with 2"down jet nozzle.Stab on well with injector. PT low-347psi/high-3,733psi.Open Well to 2,922psi SITP. RIH,take returns to tanks via portable test separator. Bleed WHP down to 1,000psi an main ain. ry ag TOS at 9,362'ctmd.Clean out down to PBTD at 9,747'ctmd pumping slick water and gel sweeps at 2.5 bpm/4,800psi CTP/950psi WHP. Minimal solids in returns until BU from rathole in 7" hit surface. Initial tag may have been bridge. Pump 10 bbl sweep off bottom. POOH at 80%. Freeze protect coil with 60/40. Tag up and shut in well. RD coil off well.Turn well over to LRS well testers to flowback frac to tanks. RDMO CT equipment.Well flowing to portable test separator. Continue cleaning up well to portable test separator.At 17:30 WHP increased from 95psi to 250psi. Flow rate increased from 200 bpd to'900 bpd.At 0500-RATE-4,200 BPD/491psi WHP/83 DEG WHT/23-30%WC/.1%SOLIDS/CHOKE AT 60/64THS/1,788 BBL FLOWED BACK/FRAC VOL PUMPED WAS 1,946 BBLS+150 BBLS CT VOL ON CLEANOUT.AT 0530 DIVERT WELL TO PRODUCTION VIA MPS-3 FLOWLINE. 11/19/11''Iolitox„tirodY 'r Produce MPS-90 through LRS test separator to MPS-3.Average rate through separator 4,100 BPD/15 20%WC/380psi WHP 11/20/16-Sunday��;r ir0IP�) �i i' �i .�" 4,yi��� ��i _ 7� 664" 00 Produce MPS-90 through LRS test separator to MPS-3.Average rate through separator- 3,500 BPD/10-15%WC/400psi WHP 11/21 pi nday �'( 6 ' . L i i66 iii Flowing S-90 through portable test separator to production via S-03 11/22/16 'Ii II Ilii �i alit ii- Flowing S-90 through portable test separator to production via S-03 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPU S-90 Slickline/CTU 50-029-23276-00-00 205-135 11/9/2016 12/4/2017 Daily Operations: 11/23/26/2016-Wednesday Flowing S-90 through portable test separator to production via S-03 11/24/2016-Thursday Flowing S-90 through portable test separator to production via S-03 11/25/2016- Friday Flowing S-90 through portable test separator to production via S-03 11/26/2016 -Saturday Flowing S-90 through portable test separator to production via S-03 11/27/2016-Sunday Flowing S-90 through portable test separator to production via S-03 11/28/2016- Monday Flowing S-90 through portable test separator to production via S-03 11/29/2016-Tuesday Flowing S-90 through portable test separator to production via S-03 • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MPU S-90 Slickline/CTU 50-029-23276-00-00 205-135 11/9/2016 12/4/2017 Daily Operations: 11/30/26/2016-Wednesday Flowing S-90 through portable test separator to production via S-03 12/1/2016-Thursday Flowing S-90 through portable test separator to production via S-03 12/2/2016- Friday Flowing S-90 through portable test separator to production via S-03 12/3/2016-Saturday Flowing S-90 through portable test separator to production via S-03. RDMO test separator. 12/4/2016-Sunday RDMO LRS portable test separator.Job Complete 12/5/2016- Monday No operations to report. 12/6/2016-Tuesday No operations to report. L" U) Cv E E 0.6 E 0 �... U C K (9 a) C � 2 = ,0 L IL m XE co m u) I) _ .n -X C o .. U O o ° � MI 3 it E -6 "-d '6 E 4 7 a5 p) UQ73 � m o C UNNI 133 ii 0 U U V a) k o ttoLC) TD . N N (1) , Q oS m +� o UQ � ZV M C '�" N. (-7, N J C Q) X_ O 0 0 0 0 N- 0 0 O O c C-O (r) `,2 O J ) ooN Z Z 2 aCO O o Oo ()) . U O- r co .. 7 O .- U N t6 •d' v� a) 01 N Q $ O � L a) Qth i I-- .1- E a) m e 4-it iN O i ' @ (6 .2 U O v 13 Ln = O ( I u) 1 i c n } ^^ _= � LL t) Q ca U. 1 1 22 L2. Z CO E a a) >' L a) L O 6 = = L a) 73 fa7) V L a) Q) .L (6 a) C6 E I N E a > 0 0) = _= a a) a) -t 'o U = Z a - c2II 0 > Lt. Q E E C) W Z ° z J ° o o v E tT co n = 03 ( a E t2 J 0 o .� O a) C L L i- o Q aa)) to L_ > •i (n U) Ll. 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K) O a) K) t L 3 u) K) E ca z a) E 2..? ) co a) > O co co E a) N / % % 0 / / / 0 0 0 CO 0 0 0 0 0 0 a CO 0 0 0 0 0 o CO — N- f J N — 2 / \ / \ \ \ 0 \ \ \ \ \ } 0 0 0 0 0 0 0 0 0 m o co 2 \ / 3 § -57 0 co 4 r « f % D > •_\ $ § 6 / 9 0 i 0 w \ / \\ 9 \ 2 ¥ \ \ / \ N— / \ 00- \ \ _� = ��co o � ( \ \ CO o5 ° \ o � 2 \ \ \ % � �\ 0- 0 2 / \ \ a f>$ y as \ - \ 0 a / a E -E - \ a / \ \ / a a » � — E 00 % e ) 2 2 m § / © § // 5 ! E # 3 $ \ 2 $ 2 ƒ @ )} / ) /# / \ / _ \ r, e e ® § 0 ill §\ ��, ,/ \\c u\\ j\ 7® \m.c73 C / )ra f 3\ \• O. & -- E ) 0 u) ) \ ƒ.— u)r.{ \ ) 0 • ° E \ e ° E 0 / f %\[\/ \ ±) /) { / /\ 8 0 To 00 „• ; z5 Section 3: Propped Frac: As Measured Pump Schedule As Measured Pump Schedule Ste Ste Slurry Slurry Pump Fluid MaxoProp Prop p p Volume Rate Time Fluid Name Volume Proppant Name p Conc Mass I Name (bbl) (bbl/min) (min) (gal) FPA) (PPA) (Ib) Warm 1 100.1 5.1 20.3 WF130 4207 0.0 0.0 0 Lines 2 Pad 450.0 29.5 15.5 YF130FIexD 18900 0.0 0.0 0 3 1.0 PPA 60.0 29.9 2.0 YF130FIexD 2424 16/20 CarboBond Lite 1.0 0.2 2042 4 2.0 PPA 58.7 29.9 2.0 YF130FIexD 2317 16/20 CarboBond Lite 1.8 0.7 3198 5 3.0 PPA 58.8 30.0 2.0 YF130FIexD 2222 16/20 CarboBond Lite 2.9 2.1 5299 6 4.0 PPA 58.8 30.0 2.0 YF130FIexD 2134 16/20 CarboBond Lite 3.8 1.3 7241 7 5.0 PPA 58.9 30.0 2.0 YF130FIexD 2053 16/20 CarboBond Lite 4.8 2.1 9036 8 6.0 PPA 58.9 29.9 2.0 YF130FIexD 1979 16/20 CarboBond Lite 5.8 1.6 10675 9 7.0 PPA 59.0 30.0 2.0 YF130FIexD 1909 16/20 CarboBond Lite 7.0 2.2 12234 10 8.0 PPA 59.0 30.0 2.0 YF130FIexD 1844 16/20 CarboBond Lite 7.9 3.1 13642 11 9.0 PPA 60.0 30.0 2.0 YF130FIexD 1782 16/20 CarboBond Lite 9.1 3.9 15895 12 10.0 PPA 60.0 29.8 2.0 _ YF130FIexD 1726 16/20 CarboBond Lite 10.3 7.2 17116 13 11.0 PPA 60.0 29.9 2.0 YF130FIexD 1674 16/20 CarboBond Lite 11.1 4.7 18237 14 12.0 PPA 262.3 30.0 8.7 YF130FIexD 7196 16/20 CarboBond Lite 12.1 0.0 82599 15 XL Flush 30.0 30.1 1.0 YF130FIexD 1260 16/20 CarboBond Lite 0.1 0.0 16 16 Flush 79.0 28.9 2.8 WF130 3342 16/20 CarboBond Lite 0.0 0.0 13 17 Freeze 79.3 12.0 7.4 Freeze Protect 3517 -2.4 0.0 0 Protect Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Step I Step Name Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) _ (psi) 1 Warm Lines 5.1 5.6 2322 2405 474 2 Pad _ 29.5 _ 30.5 _ 3716 4043 471 3 1.0 PPA 29.9 30.2 3998 4039 3938 4 2.0 PPA 29.9 30.0 3889 3941 3831 5 3.0 PPA 30.0 30.1 3775 3838 3741 6 4.0 PPA 30.0 30.3 3742 3749 3734 7 5.0 PPA 30.0 30.1 3761 3789 3738 8 6.0 PPA 29.9 30.1 3834 3899 3780 9 7.0 PPA 30.0 30.2 3945 4013 3892 10 8.0 PPA 30.0 30.2 4071 4124 4008 11 9.0 PPA 30.0 30.1 4171 4227 4117 12 10.0 PPA 29.8 30.2 4236 4289 4137 13 11.0 PPA 29.9 30.2 4263 4288 4203 14 12.0 PPA 30.0 30.4 4421 4749 4245 15 XL Flush 30.1 30.6 4775 4975 4680 16 Flush 28.9 30.6 5178 5322 4563 17 Freeze Protect 12.0 18.0 2087 5345 19 r Client Hilcorp Alaska SChlUnglePper Well:MPS-Hilco90 Formation:Sag River District Prudhoe Bay Country.United States As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 1592.6 65.1 57963 197243 Average Treating Pressure: 3914 psi Maximum Treating Pressure: 5345 psi Minimum Treating Pressure: 19 psi Average Injection Rate: 28.3 bbl/min Maximum Injection Rate: 30.6 bbl/min Average Horsepower: 2785.0 hhp Maximum Horsepower: 3974.8 hhp Maximum Prop Concentration: 12.1 PPA • OF T2y yy�s THE STATE Alaska Oil and Gas ofT e C1 � � Conservation Commission �Ll 1VJ��1 1 333 West Seventh Avenue T Anchorage, Alaska 99501-3572 ' ' wR GOVERNOR BILL WALKER g Main: 907.279.1433 OSA S . Fax: 907.276.7542 www.aogcc.alaska.gov March 14, 2017 Mr. John Barnes Hilcorp Alaska, LLC P.O. Box 244027 Anchorage,AK 99524-4027 RE: No-Flow Verification SCANNED MAY MPU S-90 PTD 2051350 Dear Mr. Barnes: On February 17, 2017, an Alaska Oil and Gas Conservation Commission (AOGCC) Petroleum Inspector witnessed a no-flow test of Milne Point Unit S-90. The AOGCC Inspector confirmed that the proper test equipment was rigged up to evaluate the well.Tubing, inner annulus,and outer annulus pressures were monitored and recorded during a continuous three-hour well shut in period. Upon opening the well to production,the tubing pressure.bled to zero immediately with no discernible flow. A subsurface safety valve is not required to be installed in this well based on the no-flow test result. A fail-safe automatic surface safety valve system capable of preventing uncontrolled flow must be maintained in proper working condition as required in 20 AAC 25.265. The subsurface safety valve must be returned to service if Milne Point Unit S-90 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. Sincerely, javiteA James B. Regg Supervisor,Petroleum Inspections ecc: P. Brooks AOGCC Inspectors STATE OF ALASKA - ALAR OIL AND GAS CONSERVATION COMSION MAR '� � - REPORT OF SUNDRY WELL OPERATIONS 7 AOGGNC 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing u Complete P LI Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Coil Tubing FCO❑ Kill Well w/Coil El Plug for Redrill ❑ Perf.New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: Install Jet Pump 0 2. Name: 4.Well Class Before Work: 5.Permit to Drill Number: Hilcorp Alaska LLC Development ❑✓ Exploratory ❑ 205-135 3.Address: Stratigraphic El Service ❑ 6.API Number: 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-23276-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL0380109/ADL0380110 MILNE PT UNIT S-90 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/SAG RIVER OIL POOL 11.Present Well Condition Summary: Total Depth measured 10,600 feet Plugs measured 9,750 feet true vertical 9,733 feet Junk measured N/A feet Effective Depth measured 9,750 feet Packer measured 7,795&9,496 feet true vertical 8,916 feet true vertical 6,967&8,666 feet Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 4,372' 13-3/8" 4,372' 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 2-3/8" 4.6/13CR-95/JFE Bear 9,249' 8,420' Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.7/13CR-85/BTS-8 9,593' 8,762' 7"ZXP Liner Packers and SSSV(type,measured and true vertical depth) Baker S-3 N/A See Above N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A t� c� ��,� Treatment descriptions including volumes used and final pressure: N/A ��I EV /a P R 0 2L'1?, 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 356 0 Subsequent to operation: 484 388 710 308 245 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations Exploratory❑ Development El Service ❑ Stratigraphic Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil 0 Gas ❑ WDSPL El Printed and Electronic Fracture Stimulation Data El GSTOR ❑ WINJ ❑ WAG p GINJ ❑ SUSP 0 SPLUG El 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: 317-005 Contact Stan Porhola Email sporholac hilcorp.com Printed Name Bo York Title Operations Manager Signature4f\..1. /1. _ p �V/� Phone 777-8345 Date 3/4/i 7 ?--13-17 RSDS _ R�; Form 10-404 Revised 5/2015 9//iJ/ �``` f`E°'°° 6 2U f/ Submit Original Only • illWell: Point Unit Well: MPS-90 _ -II SCHEMATIC Last Copleted: 1/17/2017 tiikcorp Alaska,LLC PTD: 205-1m35 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 2-1/16" 5M f' i-,..: t �t 13-3/8"x 4-1/2"FMC 5M w/ Wellhead 4-1/2"TC-II Tubing Hanger 20' 2-7/8"EUE Tubing Hanger OPEN HOLE/CEMENT DETAIL k 20" 260 sx Arctic Set(Approx.)in a 42"Hole iig I:1 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 9-5/8" 723 sx Class'G'in a 12-1/4"Hole S' 7" 393 sx Class'G'in a 8-1/2" il CASING DETAIL 13-3/8" oa Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 92/H-40/N/A N/A Surface 113' N/A HES Cementer yt� 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 @5,218' 00 \ L 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 4 • 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL `� Z 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surface 9,593' 0.0152 w✓Vs.• -41 3/8" Tubing 4.6/13CR-95/JFE Bear 1.995" Surface 9,249' 0.0039 tWELL INCLINATION DETAIL ik/. ..„,„..-.9 KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 7,786' 9-5/8"x 7"Baker Liner Tie Back Sleeve 2 7,795' 7"Baker HR ZXP Liner Packer 3 7,805' 7"Baker Liner HMC Hanger 4 9,226' Pressure Discharge Gauge-ID=3.855" 5 9,226' Jet Pump Cavity(Ser#E-7 jet pump w/1.875"check valve set 1/18/17) 6 9,228' Locator Seal Assembly 3.125"No-Go-Min ID=1.930" 7 9,229' Seal Bore Extension(14.75'+4.0'Seal Unit)-Min ID=1.930" 8 9,232' 4-1/2"x 2-3/8"Paragon Packer w/PBR(Packer @ 9,255'ELM) 9 9,249' WLEG-Min ID=1.930" 10 9,284' Sliding Sleeve-3.813"HES XD shift down to open 11 9,337' Pressure Intake Gauge-ID=3.855" 9-5/8"AP IL 1,2&3 12 9,442' X-Nipple-3.813" 4 13 9,451' Baker PBR Assembly 6 JPtmp set et 9,496' Baker S-3 Packer-3.73"Min ID 7 1/18/1715 9,589' Self-Align Mule Shoe-Bottom @ 9,593' MO ID=1.93" 16 9,850' 7"Cement Retainer(22b1 cmt sqi d) L" 8 17 10,281' IBP-Installed 2013 9 ••• 10 M. PERFORATION DETAIL ,vin. ii 1114 12 Ivishak Top(MD) Btm(MD) Top(ND) Btm(ND) FT Date Status Min ID=3.73' 13 Sag River 9,623' 9,659' 8,791' 8,827' 36' 11-10-16 Open 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated ._' 6 " 14 Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated RA Tag 9,638' 15 - 4505 PowerJet HMX,HSD,5SPF,72 Deg.Phasing to 9,658'``_ - RATag 9743'�!9 TOC@9,750 GENERAL WELL INFO to9,762 r,` 16 API:50-029-23276-00-00 -Ivishak Cased&Completed by Doyon 14 -12/3/2005 17 Plugback and Recomplete by ASR 1-10/27/2016 r 1 '`4" Run 2-3/8"inner string by Doyon 14-1/17/2017 TD=10,600'(MD)/TD=9,733'(TVD) NOTE PBTD=9,750'(MD)/PBTD=8,916'(ND) There is a spliced section in the 9-5/8"casing from the cut @ 1,939 to the baker cutlip guide assembly @ 1,965.This splice was pressure tested to 3,500psi for 30 min.and passed Revised By:STP 1/17/2017 • 1) Hilcorp Alaska, LLC lilearpAlaska,LLC MP S-90 Operations Summary Well Name Rig API Number I Well Permit Number Start Date End Date MPS 90 Doyon 14 50-029-23276-00-00 205-135 1/14/2017 1/17/2017 ko 1/11/17 °nesday *t�. 0° 1111k55,411 ' 55 0 11�6�i 1le ��u�����pp �7 ��li 4�a� i om" �ryN� '4%% No Operationsgto Report. 1/12/17-Th rsday':',, ' _--4R144;15005111101100Nti iy4i i(f No Operations to Report. 4/1342 relay 1 ti 1 h(i yr *_� i` .r _ o 1y1h 11 N Init =_ Clean and Maintain Rig Waiting on Schlumberger E-Line and Halliburton to Turn S-90 over to Doyon Rig 14. 1/14/17-Saturday iii i 11,— --'s1:1srZ (91111 i9,� Plu l Standby,waiting on Prep of MPS-90,maintain rig &perform rig maintenance.Rig Move Doyon Rig 14 F/Milne Point Intersection to S-Pad,Set Matting Boards,Spot Rig Over Well,Move and Center Derrick over Well Head.(Diesel Received 4002 Gal) (Daily Rig Diesel Usage 1,002 Gal)(Diesel on Location 4,800 Gal)(Daily Camp Diesel usage 320 Gal)(Diesel on Location at Camp 4,160Gal).(Daily Fluid Loss 0 bbl..)(Total loss for Well 0 bbl.) � �i���uiyr �� i 5/17y' id l(I li g� I ( � ,'til Id (9 li�i ID��iII , Eliwg Continue to Rig up Rig on MPS-90 Accept rig @ 0600 hrs.1-15-17,Pull BPV with Lubricator,Rig up for Load Tubing string in pipe shed&tally,Wait on AOGCC approval to drop lower set of pipe rams due to tubing spool height.Guy Schwartz approved at 13:39 PM,Test lines,2500 psi,bullhead with 165 bbls.of seawater down 4.5"tubing @ 2 BPM @ 2300 psi,Monitor wellbore on 4.5"tubing.From psi=160.to Psi-0 on Tubing Total Bleed Back 13 bbl.to Pits,Well Head Rep Tee Bar install TWC Valve in Hanger Fill Tree With Diesel test to 1,000 psi 5 min Bleed off Pressure Drain Tree,Nipple Down Production Tree,Nipple up Bope,Rig up Test Equipment Fill Bop Stack (Diesel Received 0 Gal) (Daily Rig Diesel Usage 1,000 Gal)(Diesel on Location 3,300 Gal)(Daily Camp Diesel usage 480 Gal)(Diesel on Location at Camp 3,680Gal).(Daily Fluid Loss 0 bbl..)(Total loss for Well 0 bbl.),Test Bop Test all Rams and Valves to 250/3,500 psi 5 min Each,Test Annular with 2-3/8 Test Joint 250/2,500 psi 5 Min each,Test PVT Alarms(AOGCC Brian Bixby on Location Witness Test 2300hrs.) — t a li ire -444k/10446401,1,-;=7W -14 i'V IU ACl� oe IFIL N.. $i�� r." - ,01,M0111 Continue to Test BOPs per AOGCC Regs.and approved Sundry(Test was witnessed by AOGCC Rep.Brian Bixby),Attempt to pull TWC,rig up and wash out TWC with mud pump to clear debris,pull TWC with Tee bar.Rig up GBR casing equipment with torque turn.Pick up&RIH with Seals,Seal assembly extension,locator seal assembly&2 3/8"Jet Pump Cavity on 2 3/8"JFE Bear 4.6#13CR95 tubing&torque turn connections.Tagged top of the PBR 295 Joints at 9,232ft.Set 5k down Taking weight Pick back up Rotate Pipe 2-Turns Set back Down Swallowed 20 ft.to the no go with 5k Down at 9,252 ft. Spaced well out Ran(294)Joints 2-Pup Joints and Tubing Hanger P/U/W=105K D/N/W=65K,Make up Landing Joint into Tubing Hanger,Drain Bop Stack Land hanger,(Diesel Received 3,307 Gal) (Daily Rig Diesel Usage 2,307 Gal)(Diesel on Location 4,300 Gal)(Daily Camp Diesel usage 320 Gal)(Diesel on Location at Camp 3,360Gal).(Daily Fluid Loss 20 bbl..)(Total loss for Well 20 bbl.) a/ -tt) 31115L (Illi Change.topiiams.from.2 3[8"to 2 7/8"x 5"VBRs,Nipple down BOP,bolt up lower ram to BOP,Nipple up production tree.Test Hanger void to 500/5000 psi.Test Production tree to 5000 psi.PJSM,Rig up Little Red Services,test lines,bullhead 22 bbls.of diesel down 2 3/8"x 4.1/2"Annulus,bullhead 9 bbls of diesel down 2 3/8"tubing.Clean mud tanks,Release rig @ 18:00 Hrs.Track Derrick Center over Carrier,Install Boosters Axel in Cellar,Pick up and Stack Matting Boards,Doyon Rig 14 Rig Move F/MPS-90 to MPL-Pad MEMORANDUM S State ef Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg c„ 7(z!I -7 DATE: February 17, 2017 P. I. Supervisor FROM: Chuck Scheve SUBJECT: No Flow Test Petroleum Inspector MPU S-90 Hilcorp PTD 205-135 - Friday, February,17 2017: I traveled to the Milne Point Field to witness verification of no-flow status on Well S-90. The well was open to atmosphere when I arrived at location with no discernable flow. The well was then shut in for 3 hours with only a very slight pressure build up. Upon reopening the well to atmosphere the pressure dissipated rapidly with no measurable flow. The following table shows test details: Time Pressures Flow Rate Remarks (Time Start) (psi) Gas - scf/hr Liquid - gal/hr 0/0/0 0 0 Open to atmosphere 8:50 0/0/0 , 0 - 0 - shut in 9:50 0/3/0 0 • 0 shut in 10:50 0/4/0 0 0 shut in 11:50 0/4/0 0 0 shut in 11:50 0/0/0 - 0 0 Open to atmosphere 1 Pressures are T/IA/OA Summary: This well exhibited inability to flow to surface unassisted. Attachments: none SCANNED NtAl 1120 7 2017-0217_No-FlowMPU_S-90_cs.docx Page 1 of 1 • Schwartz, Guy L (DOA) e7-7 From: Schwartz, Guy L(DOA) �,-� ' •3 Sent: Thursday,January 19,2017 1:32 PM Z--� ) To: Ted Kramer Cc: Alaska NS - Milne - Field Foreman; Bo York;Wyatt Rivard Subject: RE:S-90 Variance Request to 20AAC 25.265(c)(1) -To operate a surface safety valve out of the vertical run of the tree on MPS-90 Ted, As per our phone conversation the variance for placing the SSV( under 20 AAC 25.265(o)(1) )out of vertical run will be approved. Precedence has been set in wells S-27 and S-25 with similar jet pump completions although they are Schrader Bluff wells vs Sag River fm. One additional condition for approval will be the requirement for the well to perform and pass a "No-flow Test"within 30 days of being put on production. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC SCANNED MAR 0 2017. 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent:Thursday,January 19, 2017 7:15 AM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Cc:Alaska NS-Milne-Field Foreman<AlaskaNS-Milne-FieldForeman@hilcorp.com>; Bo York<byork@hilcorp.com>; Wyatt Rivard<wrivard@hilcorp.com> Subject: FW:S-90 Variance Request to 20AAC 25.265(c)(1)-To operate a surface safety valve out of the vertical run of the tree on MPS-90 Guy, Was there any more needed to grant this variance? We will be ready to place this well back on production later today but I have been told by our regulatory folks here that we cannot until this waiver is approved. Can you please check and advise on the status of this? Thanks, Ted Kramer 1 Sr. Operations Engineer • Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From:Ted Kramer Sent:Friday,January 13,2017 4:57 PM To:Schwartz,Guy L(DOA)(guy.schwartz@alaska.gov)<guy.schwartz@alaska.gov> Cc:Wyatt Rivard<wrivard@hilcorp.com>;Tom Fouts<tfouts@hilcorp.com>;Alaska NS-Milne-Wellsite Supervisors <AlaskaNS-Milne-WellsiteSupervisors@hilcorp.com>;Alaska NS-Milne- Field Foreman<AlaskaNS-Milne- FieldForeman@hilcorp.com> Subject:S-90 Variance Request to 20AAC 25.265(c)(1)-To operate a surface safety valve out of the vertical run of the tree on MPS-90 Guy, Hilcorp is requesting a variance to remove the surface safety valve from the vertical run of the tree and move it to the wing. Justification for this change is as follows: The well will be completed as a "normal flow"jet pump with high pressure power fluid pumped down the innermost 2-3/8" completion and lower pressure production fluids returning up the 2-3/8"x 4-1/2"tubing annulus. Because production is around the innermost 2-3/8"completion,there is no way to utilize an SSV within the vertical run of the tree. Instead, HAK plans to horizontally mounted the SSV directly to the tree.The valve will be a standard 2-1/16" valve that will be tied into the Safety Valve System (SVS) low pressure trip.Additionally,there will be an actuated power fluid valve installed that will shut-in the high pressure power fluid in the event of a low pressure SVS trip.This configuration provides an equivalent level of protection to an SSV mounted in the vertical run of the tree. In support of the Variance I have attached the following: Well Schematic Proposed Well head Drawing P&ID This Request for S-90 is consistent with approved variances for S-27 and 5-25 at Milne Point. Please let me know if you need anything else in order to grant this variance or if you need a different format. Sincerely, Ted Kramer Sr.Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 2 II • • Milne Well: Point MPS-90Unit Proposed SCHEMATIC Last Completed: 10/27/2016 Fiilcorp Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 4-1/16"- 5M Wellhead 13-3/8"x 4-1/2"FMC 5M w/ 20" 4-1/2"TC-Il Tubing Hanger J . , L OPEN HOLE/CEMENT DETAIL I 20" 260 sx Arctic Set(Approx.)in a 42"Hole 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 9-5/8" 723 sx Class'G'in a 12-1/4"Hole 7" 393 sx Class'G'in a 8-1/2" .1 CASING DETAIL 13-3/8 ,- 'Ype Wt/Grade/Conn ID Top Btm 8P1 d �A 20" Conductor 92/H-40/N/A N/A Surface 113' N/A i /1 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 3Certder GO MN" 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5,218 'O 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surface 9,593' 0.0152 4.64; .195/JFE Bear 1. WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL i No Depth Item 1 7,786' 9-5/8"x 7"Baker Liner Tie Back Sleeve 2 7,795' 7"Baker HR ZXP Liner Packer 3 7,805' 7"Baker Liner HMC Hanger 4 9,226' Pressure Discharge Gauge-ID=3.855" 249' Jet Pump Cavity ±9,252' Locator Seal Assembly 3.00"No-Go ' ±9,253 Seal Bore Extension ±9,272' 2-3/8"x 4-1/2"Paragon Packer 9 ±9,278' WLEC 10 9,284' Sliding Sleeve-3.813"HES XD shift down to open Pump pulled 12-31-16 11 9,337' Pressure Intake Gauge-ID=3.855" ` 12 9,442' X-Nipple-3.813" 9-5/8"a II 1,2&3 13 9,451' Baker PBR Assembly 4 14 9,496' Baker S-3 Packer- Min ID s15 9,589' Self-Align Mule Shoe-Bottom @ 9,593 7 16 9,850' 7"Cement Retainer(22b1 cmt sqz'd) 8 17 10,281' IBP-Installed 2013 1:_. PERFORATION DETAIL trplo ® 11 Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 'a 12 Sag River 9,623' 9,659' 8,791' 8,827' 36' 11-10-16 Open 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated I 13 Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 14 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 4505 Powerlet HMX,HSD,5SPF,72 Deg.Phasing RA Tag 9,636' 15 to 9,658' RATag9, 3' 4/r oc@s,7sa 74GENERAL WELL INFO �9�2 16 API:50-029-23276-00-00 Cased&Completed by Doyon 14 -12/3/2005 - =}Ivishak Plugback and Recomplete by ASR 1-10/27/2016 17 7' .• 401E TD=10,6W(MD)/TD=9,733'(TVD) There is a spliced section in the 9-5/8"casing PBTD=9,750'(MD)/PBTD=8,916'(1VD) from the cut @ 1,939 to the baker cutlip guide assembly @ 1,965.This splice was pressure tested to 3,500psi for 30 min.and passed Revised By:CJD 1/4/2017 • • MPS-90 Proposed Wellhead Drawing .SPS -,- ,--3--1 1 BH TA,Otls,2 9/16 5 r 1r-.1 1.11-7. Tubing hanger,FMC-TC-B- •I l ,I• EC,11 X 4 1/2 EUE lard lift Valve,Swab,seaboard and susp,w/4'pup&4" 2 9/16 SM FE,HWO,DO type H BPV profile,TOP Vim (hanger r a 2 3/6 seaboard ,. . 1,..„. L., „.... 1 _ .per, .4 . v., ir in fftimit _. Aiiii,.. OAN 4�3. ly. Valve,Mase r,seabaard, ce 29/165M L,IIWO,DD �, e" w� trim '' 'SQL 0... rag:� , i• Ca ill uuimitsi ,it �„,qt-t`� to _ nne hinge* 1 1(16 X 2 3.'z3 '1, �sti6 b -JoartS r',41 2 NPV pr oil e ��\4th lx.• .. a�` a d54°°� a¢a`a¢y 2 1/16SSv 03 O Saa�1_ 1 I +I! M ' '' 1 1111411111 , - ftt j ,: It! SSV i-wire Connection < " "I l-MC i 11"5M fig btrn X 4 1/16 5M stdd top, Int ' �h I�.l. `- Tubing head, I.■ . 11-=:f DOI -._ 3 - `0.Nik,-. .-4.00-1100... = t+� **4111 •_.v .._._^# - Ala casing valves2 1/16 5M Casing head,FMC OCT 20 tlttl 1 t■' r7) - - TO:- 14C II A*. Sp -All I. -if i ,,• Ad!I I I la i-I- 11m■► z � ' 49_ 10 I! C y go- 51 Z <o as o ^ B: S� J O �� 1 ( ) 3 z. 8 I I E ` En age 1ig o I I bt \� N N a — 1 I = = 0.5?W a — H? HY a '.6.' it2431i 0 1 ; (u eller I)11 = 1 -0a .4 C I I ^ 4 ® `, `' T — a a= �$ I 1 e elkti—'—'—. --h tit q A 1 ifhtti eir- -- ----- I 41 RIO; °-0-1— I1 _ — -'— ♦ . e- .e 4 —pi: w F ere, 6� � I 1 4 I 1 a i 0—J _ - N M N dig ��� � �:E I I PRA' _ 7 1gL a Gam- . 1 ------ --- ---� FL_' , ' 511e 9 _� P_ , I d N a� PO ` s L-J-__i:: :6A� so Ag 44 0 gl< L� i' Q wb- I IES iaF — I— $i«o osas I 6 Ig 1 Ids Vg* - - a C fl 1 � 4 g i i F,. I tJ t w I a VOr T8 , \ iy/,�sv THE STATE Alaska Oil and Gas h �M OfALASKA Conservation Commission 333 West Seventh Avenue ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OF ALAs�� Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager SCANNED MAR 2 9 21',17. Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Sag River Oil Pool, MPU S-90 Permit to Drill Number: 205-135 Sundry Number: 317-005 Dear Mr. York: 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 '. Foerster Chair DATED this `Z2.day of January, 2017. RBDMS \,`- JAN 2 6 2017 0 • RECEIVED STATE OF ALASKA JAN 06 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION AOGCC APPLICATION FOR SUNDRY APPROVALS y 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate ❑ Repair Well ❑ Kill Well with Coil❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Install Jet Pump Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska LLC Exploratory ❑ Development DI • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-029-23276-00-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20AAC.25.055 ` Will planned perforations require a spacing exception? Yes ❑ No ❑., ✓ MILNE PT UNIT IVISH/SAG S-90 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0380109/ADL0380110 ' MILNE POINT/SAG RIVER OIL POOL • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): .a/ .1 Plugs(MD): Junk(MD): 10,600' ' 9,733' • 10,511' • 9,647' • rS-8OtT 10,511' N/A Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 4,372' 13-3/8" 4,372' 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic NJ See Attached Schematic 4-1/2" 12.7#/13CR-85/BTS-8 9,593' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): r 7"ZXP Liner/Baker S-3 7,795/9,496'(MD)/6,967'/8,666' 12.Attachments: Proposal Summary Q Wellbore schematic U 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑., Exploratory ❑ Stratigraphic❑ Development❑., • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 1/15/2017 Commencing Operations: OIL ❑., a WINJ ❑ WTRSP ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandonedon ❑ 17. I hereby certify that the foregoing is true and the procedure approved Ire herein will not be deviated from without prior written approval. Contact Ted Kramer Ts+G- Email tkramer@hilcorp.com Printed Name Bo York Title Operations Manager Signature / Phone 777-8345 Date 1/4/2017 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness 5PlugSundry Number: ski _ O 0.5- Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: 1("3 S 7 ° ✓'s r' 1'' c> Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod L/Subsequent Form Required: 1 0 — l oy RBDMS lily JAN 2 6 2017 t) APPROVED BY Approved by: 902-1.-'74•---- COMMISSIONER THE COMMISSION Date:'— /2._/7 iM " 7 � r� © � � ,.. �� Submit Form and Form 10-403 Revised 11/2015 valid for 12 months from the date of approval. Attachments in Duplicate • S Well Prognosis Well: MPS-90 • Hilcorp Alaska,LL, Date:9/15/2016 Well Name: MPS-90 API Number: 50-029-23276-00 Current Status: Sag River Oil Producer Pad: S Pad Estimated Start Date: January 15, 2017 Rig: Doyon#14 Reg.Approval Req'd? Date Reg.Approval Rec'vd: Regulatory Contact: Cody Permit to Drill Number: 205-135 First Call Engineer: Ted Kramer (907)-777-8420 (0) (985)-867-0665 (M) Second Call Engineer: Stan Porhola (907)777-8412 (0) (907) 331-8228 (M) AFE Number: '7 7 per' Current Bottom Hole Pressure: 3,405 psi @ 8,507' TVD (Downhole pressure gauge @ 9,337' MD). Maximum Expected BHP: 3,500 psi @ 8,507' TVD (Extrapolated from the intake Gauge on 1-3-17). Max.Anticipated Surface Pressure: 3,150 psi Using a 0.1 psi. I ft. hydrostatic press. gradient. Brief Well Summary: The Milne Point S-90 well was recently re-completed to a Sag River oil producer in November of 2016. The well flowed on its own until December 23rd, when it loaded up and died. Attempts to kick the well off to a tank were unsuccessful. S-90 was then placed on artificial lift (Reverse Flow Jet Pump). The IA pressure limit was set at 3,000 psi since that was the pressure of the casing test. After production commenced on artificial lift for 24 hours, pressure was noted on the OA. A couple of bleeds were attempted to insure that it was not thermal expansion. Once the pressure returned and it was determined not to be thermal expansion,the well was shut in. RWO Objective: This workover will involve setting a packer inside of the 4-1/2" tubing and running a concentric string of 2-3/8" .' tubing inside of the 4-1/2"with a jet pump cavity on the bottom. The well will then be placed back on production as a conventional jet pump with power fluid going down the 2-3/8" tubing and returns up the 2-3/8" by 4-1/2" annulus. This completion will prevent produced fluids from reaching the 9-5/8" casing. Pre-Rig Procedure: (Non-Sundry Work) 1. MIRU slick line unit. RIH and open sliding sleeve. POOH. 2. RU Pump Truck. Pump 345 bbls of corrosion inhibitor followed by 123 bbls of freeze protection "4.17 down the 9-5/8" X 4-1/2" Annulus. 3. RIH W/Slick line and close sliding sleeve. Pooh with Slick line and pick up X plug. RIH and set plug in X-nipple at 9 442'. Pressure up to 1,000 psi to confirm that the sliding sleeve is closed. Pull X- s plug and POOH with Slick line. RD Same. 4. RU E-line. Test lubricator according to AOGCC requirements. PU and RIH with 4-1/2" paragon packer. Log on depth placing the bottom of the wireline entry guide at 9,278' (+/-). Set packer. j� Note: Ensure we are not setting in a collar. • ' Well Prognosis Well: MPS-90 Hilcorn Alaska,LL Date: 1/9/2017 5. RU Slickline. PU RIH with seal bore extension and latch into the top of the packer. WO Rig Procedure:(Sundry Work) 6. MIRU Doyon#14 Rig. — *est-- 7. Set BPV, Kill well as needed. Pull BPV and install TWC. 8. ND Well head. 9. Install 7-1/16'X 2-3/8" Spool and 13-3/8"X 7-1/16" adapter flange. 10. NU BOP and Test same to 250 psi low/3f2Jpsi_high. a. Note: Notify AOGCC 24 hours in advance of BOP test to provide them the opportunity to witness. b. Test Rams on 2-3/8"test joint. c. Send BOP test report in to AOGCC within 5 days. 11. PU RIH with Seals,Seal Assembly Extension, Locator Seal Assembly,and 2-3/8"Jet pump cavity on the 2-3/8"tubing string. RIH and stab seals into the seal bore extension setting down on the Locator. 12. PU, space out and hang off tubing. 13. ND BOP, NU Wellhead and test to 5,000 psi. 14. RDMO Doyon# 14 Rig. 15. Turn well over to Production. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Wellhead Drawing 4. BOP Schematic 5. Doyon#14 Choke manifold . . El • • / Well Prognosis Well: MPS-90 Hilcorp Alaska,LL Date:9/15/2016 5. RU Slickline. PU RIH with seal bore extension and latch into the top of the packer. WO Rig Procedure: (Sundry Work) 6. MIRU Doyon#14 Rig. J 7. Set BPV, Kill well as needed. r......_ 18. ND Well head, NU BOP and Test same to 25 psi low/3,200 psi high. a. Note: Notify AOGCC 24 hours in dvance of BOP test to provide them the opportunity to witness. b. Test Rams on 2-3/8"test join . et;,'c� c. Send BOP test report in to AOGCC within 5 days. II) , � 9. PU RIH with Seals, Seal Assembly Extension, Locator Seal Assembly, and 2-3/8"Jet pump cavity on �}w/ the 2-3/8" tubing string. RIH and stab seals into the seal bore extension setting down on the f, ; Locator. "! 10. PU, space out and hang off tubing. 11. ND BOP, NU Wellhead nd test to 5,000 psi. 12. RDMO Doyon# 14 13. Turn well over to roduction. Attachments: 1. As-built Sch matic 2. Proposed Schematic 3. Wellhead Drawing 4. BOP Schematic 5. Doyon# 14 Choke manifold H . Milne Point Unit Well: MP S-90 SCHEMATIC Last Completed: 10/27/2016 Hilcor)Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 4-1/16" SM I '41' 4 Wellhead 13-3/8"x 4-1/2"FMC 5M w/ P. 20IM 4-1/2"TC-II Tubing Hanger ;w OPEN HOLE/CEMENT DETAIL x 20" 260 sx Arctic Set(Approx.)in a 42"Hole 4: 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole y 9-5/8" 723 sx Class'G'in a 12-1/4"Hole j i 7" 393 sx Class'G'in a 8-1/2" l 1 CASING DETAIL 3/8" Size Type Wt/Grade/Conn ID Top Btm BPF ii 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cerrenter 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5,218'-4'0 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL ( 4-1/2" 1 Tubing 12.75/13CR-85&110/BTS8 3.958" Surface 9,593' 0.0152 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 7,786' 9-5/8"x 7"Baker Liner Tie Back Sleeve 2 7,795' 7"Baker HR ZXP Liner Packer 3 7,805' 7"Baker Liner HMC Hanger 4 9,226' Pressure Discharge Gauge-ID=3.855" 5 9,284' Sliding Sleeve-3.813"HES XD shift down to open Pump pulled 12-31-16 6 9,337' Pressure Intake Gauge-ID=3.855" 7 9,442' X-Nipple-3.813" 8 9,451' Baker PBR Assembly 9 9,496' Baker S-3 Packer-3.73"Min ID 10 9,589' Self-Align Mule Shoe-Bottom @ 9,593' 11 9,850' 7"Cement Retainer(22b1 cmt sqz'd) 12 10,281' IBP-Installed 2013 PERFORATION DETAIL Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status I Sag River 9,623' 9,659' 8,791' 8,827' 36' 11-10-16 Open 9-5/8"411 1 1,2&3 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated Is 4 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 5 4505 Powerlet HMX,HSD,5SPF,72 Deg.Phasing 6 GENERAL WELL INFO s 7 API:50-029-23276-00-00 F. 8 Cased&Completed by Doyon 14 -12/3/2005 asii 9 Plugback and Recomplete by ASR 1-10/27/2016 10 NOTE RATag 9,638' - There is a spliced section in the 9-5/8"casing to9,658'---,iii =.= from the cut @ 1,939 to the baker cutlip guide R4Tag 9,743 TOC @9,750 assembly @ 1,965.This splice was pressure to 9,762' ,- ,1,,- 11 tested to 3,SOOpsi for 30 min.and passed 12 7' TD=10,600'(MD)/TD=9,733'(1VD) PBTD=9,750'(MD)/PBTD=8,916(TVD) Revised By:JCM 12/25/2016 .Proposed SCHEMATI! Milne Point Unit Well: MPS-90 Last Completed: 10/27/2016 Hilcoru Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 4-1/16"- SM '' '" 4j k Wellhead 13-3/8"x 4-1/2"FMC SM w/ 2cr 4-1/2"TC-Il Tubing Hanger ,` a OPEN HOLE/CEMENT DETAIL 20" 260 sx Arctic Set(Approx.)in a 42"Hole 0 Pi 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 'l 9-5/8" 723 sx Class`G'in a 12-1/4"Hole r ti o t 7" 393 sx Class'G'in a 8-1/2" 3 4 CASING DETAIL 3/g,13- Size Type Wt/Grade/Conn ID Top Btm BPF 10 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cementer 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5,218' ►O 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surface 9,593' 0.0152 2-3/8" Tubing 4.6#/13CR95/JFE Bear 1.995" Surface ±9,278 0.0039 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. €€; $ JEWELRY DETAIL No Depth Item 1 7,786' 9-5/8"x 7"Baker Liner Tie Back Sleeve 2 7,795' 7"Baker HR ZXP Liner Packer 3 7,805' 7"Baker Liner HMC Hanger 4 9,226' Pressure Discharge Gauge-ID=3.855" I 5 ±9,249' Jet Pump Cavity d 6 ±9,252' Locator Seal Assembly 3.00"No-Go 7 ±9,253 Seal Bore Extension 1 8 ±9,272' 2-3/8"x 4-1/2"Paragon Packer 9 ±9,278' WLEG 10 9,284' Sliding Sleeve-3.813"HES XD shift down to open Pump pulled 12-31-16 11 9,337' Pressure Intake Gauge-ID=3.855" ® 12 9,442' X-Nipple-3.813" 9-5/8" 't 1,2&3 13 9,451' Baker PBR Assembly 4 14 9,496' Bakers-3 Packer-3.73"Min ID Ii 5 15 9,589' Self-Align Mule Shoe-Bottom @ 9,593' E s 16 9,850' 7"Cement Retainer(22b1 cmt sqz'd) 17 10,281' IBP-Installed 2013 8 MP 9 PERFORATION DETAIL ••• 10 11 Ivishak Top(MD) ' Btm(MD) Top(ND) Btm(TVD) FT Date Status 1 12 Sag River 9,623' 9,659' 8,791' 8,827' 36' 11-10-16 Open 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated 13 Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated ®:r III►m', 14 10,088' 10,322' 9,242 9,466' 234 , 11/28/2005 Isolated 4505 PowerJet HMX,HSD,SSPF,72 Deg.Phasing R4 Tag 9,638' 15 to 9,658'--,110GENERAL WELL INFO R4 Tag 9,743 TOC @ 9,750 16 API:50-029-23276-00-00 to 9,767 : Cased&Completed by Doyon 14 -12/3/2005 _�Ivishak Plugback and Recomplete by ASR 1-10/27/2016 17 7' AV ' NOTE TD=10,600 (MD)/TD=9,733'(TVD) There is a spliced section in the 9-5/8"casing PBTD=9,750'(MD)/PBTD=8,916'(TVD) from the cut @ 1,939 to the baker cutlip guide assembly @ 1,965.This splice was pressure tested to 3,500psi for 30 min.and passed Revised By:OD 1/4/2017 MPS-90 Proposed Wellhead Drawing tv'rc 0. BH TA,Otis,2 9/16 SM f—�, Tubing hanger,FMC-TC-S MEW EC,11 X 4 1/2 EliE 8rd lift Valve,Swab,seaboard and susp,w/4'pup&4" 2 9/16 SM FE,HWO,DD ir type H BPV profile,TOP trim - hanger r x 2 3/8 seaboard mar • �I / 1I 'leaf tilt ....., .,, Valve,Master,seaboard, "tz, 43. - 1�S,:1k' 29/16 SM FE,HWO,DO is ��4 e;, a. trim �� ., .. ley y 111. NH II ,65ts'SO 131 tubing hanger 7 1/16 X 2 3/8 X1'1%Vs. prois-3.1=1_, . a 14 Seaboard/W 2"BPV probe e1' 4iV eco D. acO � a�`yes ' 2 1/16 SSV �o O 1 ,,t-b°,a Sea y,soz, 1 1 �0c.tlur-#' 14-4-41-49, ( . -• ,. :' - ,,,,,_i = �� I-wire onnection ',f Adapter,FMC 11'SM fig btm X 41/16 5M stdd top, in - 1. f t ', Tubing herr., - + Ai + _■moi I , — . f#t �� I IIt , �,� - All casing valves2 1/165M Casing head,FMC y-MION 1.1. ' .1.1•11 NW ;_ OCT•20 I 1 i iSt rrl' tIIke 1 M Mil 1"':. SW•W:414 ,. lr is WZ t' ' „._ re--- i -0-- A itiii—e-b---) _� z3/ ,,,- 6 G pg 1 • . Doyon 14 BOP Schematic tl \ 1 5 Hydril GK Annular BOP 13-5/8"x 5M CLT �o � 9.w ii 0 013-5/8" x 5M OD. 1 i ' i l ' . o 0 o cm ofTwif0 IIan As - � I3"x5M HCR • , 7 - ■ lin�` I I[�` •'i�II 1.11 `"`Choke Line Kill Line r IllOY ell 1M Qs ''''''''.*---3"x 5M Manual Gate Valve — ^ r 13-5/8"x 5M ' E 1—E , -------------11"x 5M _ I1► �!i 9-5/8"DBL D Seal Aipir._ :410, Awl, 2-1/16"x 5M CasingHanger f ?Sj -16-314"x 3M - .01111 [Alio' rill SMB-22 ! 16-3/4"NOM oi 9-5/8"BTC Btm x 2-1/16"x 5M 10.5"-4 SA Pin Top W/Primary Seas 20"Casing 9-5/8"Casing !A, 9 ct `OICI1ci):ct '-.4 A \ SalH 0 , r lati O. p 0 ;L-1ir 8 V 0 411110' OM _ill, 9•in a) (.::::;111,1111i0 �` c) C ' ;�liki -I 0 illik 111, Q 0 111. Z V. I' I00 eai N 1 > Q r ID�, >74d > 0 2 0 co 0 L o > A — s CL U 112 L7cct c Wgg „, 3 _ et > cif Ce -° E E 0k 7 N v > a) � X11 0\0 N N0o — M > L a a/ cd a M 1 rn N ct 4-)+ _ E — cd t d c Z s L -Cjcq L N N U .N N Lu Z = Z N W V 00 N (11) o tn °' > > > J \ I \I oZ -^ _ M • • Schwartz, Guy L (DOA) From: Ted Kramer <tkramer@hilcorp.com> Sent: Tuesday,January 03, 2017 8:27 AM s' 3 `J To: Schwartz, Guy L(DOA) a b 0 5* 3 -- Subject: S-90 Sag River Well IA to OA Communication Attachments: MP S-90 SCHEMATIC 12-25-2016.doc; MPU S-27 SCHEMATIC 9-15-2016.doc Guy, Over the Holiday Weekend the above well demonstrated a casing leak from the IA to the OA(Schematic Attached). This is a Jet pump well (Reverse Flow)and was just put on production as a Jet pump well in the last 10 days. As soon as we noticed this pressure increase in the OA,we shut the power fluid injection down and Shut in the well. Hilcorp is evaluating our options for repairing this well,one of which is to complete this well in the same fashion as S-27 (Schematic Attached). A 2-3/8" inner string will be installed inside of the current 4-1/2" tubing string. High pressure power fluid would be pumped down the 2-3/8"string and low pressure production fluid would go up the 2-3/8"X 4-1/2" annulus. The current IA(4-1/2'X 9-5/8")annulus would become the OA and would be monitored for pressure and should not see any additional produced fluid. The 9-5/8"X 13-3/8"would become the OOA and would also be monitored for pressure. I would like to give you a call to discuss if this would be an acceptable completion for this well. Please let me know what a convenient time will be. If I do not hear back from you, I will call you this afternoon. Sincerely, Ted Kramer Sr.Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 1 STATE OF ALASKA ALIIIA OIL AND GAS CONSERVATION COMOSION REPORT OF SUNDRY WELL OPERATIONS [1//54I ---ti,:wii4-Ie----fr 5461 1.Operations Abandon ❑ Plug Perforations Elic l r im ttAtePull Tubing Li Complete U Performed: Suspend ❑ Perforate U Other Stimulate ❑ Coil Tubing FCO ❑✓ Kill Well w/Coil .❑ Plug for Redrill ❑ Perf.New Pool ❑.. Repair Well ❑ Re-enter Susp Well ❑ Other: Install Jet Pump El 2. Name: 4.Well Class Before Work: 5. Permit to Drill Number: Hilcorp Alaska LLC Development ❑ Exploratory ❑ 205-135 3.Address: Stratigraphic El Service ❑✓ 6.API Number 3800 Centerpoint Dr,Suite 1400 Anchorage,AK 99503 50-029-23276-00-00 7. Property Designation(Lease Number): 8.Well Name and Number: ADL0380109/ADL0380110 MILNE PT UNIT IVISH/SAG S-90 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A MILNE POINT/IVISHAK UNDEF WTRSP/SAG River Frac 11. Present Well Condition Summary: Total Depth measured 10,600 feet Plugs measured 9,750 f#lECEIVED true vertical 9,733 feet Junk measured N/A feet JAN 06 2017 4►, Effective Depth measured 9,750 feet Packer measured 7,795&9,496 feet true vertical 8,916 feet true vertical 6,967&8,666 feet AOGCC Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 4,372' 13-3/8" 4,372' 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 4-1/2" 12.7/13CR-85/BTS-8 9,593' 8,762' 7"ZXP Liner Packers and SSSV(type,measured and true vertical depth) Baker S-3 N/A See Above N/A 12.Stimulation or cement squeeze summary: N/A yr--- ,.g.{, Intervals treated(measured): N/A cAbk tc-3,& - Treatment descriptions including volumes used and final pressure: N/A t ~ 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 240 0 Subsequent to operation: 1,081 1,063 230 100 263 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory Ell Development U 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 ❑ 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: 316-478&, -- Contact Ted Kramer ��/L Email tkramer(a�hilcorp.com Printed Name Bo York 7111'. Title Operations Manager �" t'I Z c.—. Z O l} Signature i!lielPhone 777-8345 Date 1,2/27d2g48' , / 3.---Zg-17- 71.2, 7 Form 10-404 Revised 5/2015 RBDMS w JAN Z 5 2017 Submit Original Only .., in H . Milne Point Unit Well: MPS-90 SCHEMATIC Last Completed: 10/27/2016 Hilcorp Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.4 .r).e. KB Elev.:72'-Doyon 14 Tree 4-1/16" 5M Wellhead -, t 13-3/8"x 4-1/2"FMC 5M w/ LI 4-1/2"TC-II Tubing Hanger 20 gr k* � OPEN HOLE/CEMENT DETAIL 20" 260 sx Arctic Set(Approx.)in a 42"Hole «, 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole ss ., 9-5/8" 723 sx Class`G'in a 12-1/4"Hole 14 7" 393 sx Class`G'in a 8-1/2" CASING DETAIL 4.13-3/8" 0 Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cementer ' 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5218' O s `( 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surface 9,593' 0.0152 { WELL INCLINATION DETAIL i E KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 7,786' 9-5/8"x 7"Baker Liner Tie Back Sleeve ( 2 7,795' 7"Baker HR ZXP Liner Packer 3 7,805' 7"Baker Liner HMC Hanger 4 9,226' Pressure Discharge Gauge-ID=3.855" 5 9,284' Sliding Sleeve-3.813"HES XD shift down to open 11-12-16 Frac SLEV installed 6 9,337' Pressure Intake Gauge-ID=3.855" 7 9,442' X-Nipple-3.813" 8 9,451' Baker PBR Assembly 9 9,496' Baker S-3 Packer-3.73"Min ID 10 9,589' Self-Align Mule Shoe-Bottom @ 9,593' 11 9,850' 7"Cement Retainer(22b1 cmt sqz'd) 12 10,281' IBP-Installed 2013 PERFORATION DETAIL Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Sag River 9,623' 9,659' 8,791' 8,827' 36' 11-10-16 Open 9-5/8 j 11,2&3 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 5 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 0 4505 PowerJet HMX,HSD,5SPF,72 Deg.Phasing 6 ;' GENERAL WELL INFO API:50-029-23276-00-00 8 Cased&Completed by Doyon 14 -12/3/2005 Plugback and Recomplete by ASR 1-10/27/2016 .:®II s.;: 9 - 10 �G NOTE RA Tag 9,638' = 5 FM There is a spliced section in the 9-5/8"casing to9,658'�M - from the cut @ 1,939 to the baker cutlip guide RATag9743' TOC@ 9,750' assembly @ 1,965.This splice was pressure to 9,762 *,,,. x. 11 tested to 3,SOOpsi for 30 min.and passed 44"I' 1 Itishak TD=10,600'(MD)/TD=9,733'(TVD) PBTD=9,750'(MD)/PBTD=8,916'(TVD) Revised By:JCM 12/25/2016 • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 5-90 CTU 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: 9/28/2016-Wednesday No activity to report. 9/29/2016 -Thursday No activity to report. 9/30/2016- Friday No activity to report. 10/1/2016-Saturday MIRU Halliburton 1.75" CT. Perform BOPE test. Open well to 315psi SITP. RIH w/ 1.75" OD nozzle to 9,801' ctmd. Circulate 356 bbls of 9.1 brine up to the tubing tail, displacing coil with diesel. Average 2 bpm /4,600psi CTP/240psi WHP. Pump down the IA-22 bbls diesel - 156 bbls 9.1 brine -followed by 102 bbls diesel taking returns from the tubing at 4 bpm. POOH pumping 29 bbls diesel down backside of coil.Total fluids pumped = 512 bbls 9.1 ppg/ 189 bbls diesel. Well FP to 2,200'. Final WHP and IAP was 80psi and decreasing at time of shut in. RDMO. 10/2/2016-Sunday No activity to report. 10/3/2016- Monday No activity to report. 10/4/2016-Tuesday No activity to report. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP S-90 ASR#1 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations1D 10/12/2016-Wednesday No activity to report. 10/13/2016-Thursday Begin R/D process. Electricians on location to R/D fire and gas alarm system. L/D ESP sheave, un-pin torque tube connection in mast, adjust rig floor equipment into position f/ move, load catwalk, pipe racks,tool sheds, etc and move to S-pad. Roll up herculite containment and re-use on S-pad. L/D mast section in half and then L/D onto truck carrier. Mobilize rig equipment to MPS-90,SIMOPS: Mobilize Hilcorp crane to MPS-90,verify no pressure on IA, break all wellhead adapter bolts, line cellar w/herculite and pull tree. 10/14/2016-Friday Continue to Move Rig& Equipment From MPF pad to MPS-90, Spot Mud Tanks,Spot Well Site trailer, spot Hilcorp office & crew change house. Repair work on Rig Engine at VMS shop. Changed EGR Manifold &Gasket to EGR cooler. Nipple up 13- 5/8" BOPs,(AOGCC notified of upcoming BOP test f/ MPS-90 @ 15:59 on 10-13-16, witnessed waived by AOGCC rep Lou Grimaldi @ 16:10 on 10-13-16.) Set Well cover& Rig Floor with crane, Continue to Nipple up BOPs,Torque all connections. Remove mounted space heaters from wellhouse to make room for 13-5/8" stack. L/D herculite containment for pipe racks, begin spotting catwalk into place. R/U accumulator to BOPE. (NPT) Wait for VMS shop to complete repairs on rig carrier unit.Vac Truck on location to offload 9.3ppg brine into pits. Wellhead rep Dean Norris on location. P/U T-bar, screw into BPV, remove BPV, (well still on a vaccum) M/U TWC on T-bar and set in tubing hanger.Attempt to shell test 13-5/8" BOP stack. Pressure holding at 250psi low test, raise pressure to 3,SOOpsi, leak coming from mud pit side blind shear door seal. Re-torque door lugs and attempt to shell test to 3,500psi, both blind shear ram doors leaking. Open blind shear ram doors, clean and clear both door seal cavities and clean off all sealing surfaces. Change out door seal on mud pit side blind shear ram door. Close both ram doors, re-torque lugs. Attempt to shell test 13-5/8" BOP stack again. Slow pressure leak, no fluid seen coming from ram door seals. 10/15/2016-Saturday Raise Derrick, Pin Derrick, Install anchor lines to Mud boat. Continue to Rig up, Install stairs, circulating lines. Grease all p�j valves on Choke Manifold & BOP wing valves. MP Electricians connected gas alarms and tested good. Rig up &Test BOPs, Ft` Test Rams&all valves to 250/3,SOOpsi,Test Annular to 250/2,500psi,Tested with 3.5" &5.5" Test joints. Performed Accumulator draw down test. Pick up Tee bar& pull TWC, lay down Tee bar. Make up landing joint to tubing hanger, back out lock down screws, Pull tubing hanger to rig floor& lay down hanger& landing joint. (Hanger pulled free @ "70klbs). POOH w/5-1/2" IBT-Mkill strinaf/4,012.O9'md to surface. Recover 97 jnts, 2 pups, XN nipple and WLEG. Clean and clear rig floor of 5-1/2" handling equipment. Strap first row of 3-1/2" BTS-8 workstring. Strap and tally Baker fishing cleanout BHA#1. Change out slips, elevators and tong dies. P/U, M/U and RIH w/Baker fishing scraper cleanout BHA# 1 f/surface. 10/16/2016-Sunday TIH with 9-5/8" CSG scraper on 3.5" work string f/surface to 7,767'md as per program. Lightly set down 1klbs on LNR top, P/U 1 joint and rig up to circulate down the TBG. No signs of drag or debris on trip to LNR top. Pump 9.3ppg brine down the TBG at 2.5bpm, catch pressure after 7.5bbls away (fluid level "860'md). Continue to circulate at 2.5bpm until returns are seen (17bbls away total). Diesel seen in returns, divert returns to flowback tank and continue to circulate 22bbls at 2.5bpm 250psi, until fluid cleans up. Shut down pumps, blow down lines, and prepare to POOH w/9-5/8" CSG scraper BHA#1. POOH w/9-5/8" CSG scraper BHA#1 f/7,767'md to 1,200'md. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 5-90 ASR#1 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: 10/17/2016-Monday, Continue to TOOH with 9 5/8" Casing scraper on 3.5" work string from 1,200'to Surface, Lay down 9-5/8"casing Scraper assembly. Make up 7" Casing Scraper assembly&TIH on 3.5" RTS-8 work string f/surface to 9,860'md. L/D 1 joint and reverse circulate 142bbls of 9.3ppg brine @ 3.5bpm, 550psi. 3bbl diesel cap diverted out to flowback tank at start of circulation. 5bbl total losses after 142bbls away. Blow down all lines and prepare to POOH. POOH w/ Baker 7" scraper BHA #2 f/9,8601md to 8,000'md. Rig system throwing codes,followed by de-rating itself.Shut down operations and contact VMS mechanic to assess codes. (NPT)VMS mechanic plug into computer and trouble shoot system codes.After system shut down, error codes and de-rating stopped. Decision to continue to POOH and have day mechanic return to trouble shoot. Continue to POOH f/—8,000'md. 10/18/2016-Tuesday Continue to TOOH with 7" Casing scraper assembly on 3.5" RTS-8 work string F/8,000'T/3,450'. (NPT) Call out VMS mechanic to troubleshoot codes on Rig Engine, Mechanic cleared EGR codes. Continue to TOOH F/3,450'to surface. L/D 7" Baker scraper BHA. No signs of wear or debris on scraper. (NPT) Frayed cable on catwalk pully system. Replace worn cable. P/U cement retainer and inspect. When reviewing setting procedure w/Halliburton rep it was noted that we most likely won't be able to over pull to the weight required to shear the shear sleeve on the cement retainer setting tool. Call ODE and discuss plan forward. Decision to de-rate the shear sleeve on the cement retainer by drilling holes in the brass shear sleeve, as per Halliburton global advisor. R/U CSG jacks as a contingency if we are unable to shear off of cement retainer. 13-5/8" BOP stack is taller than 11", so CSG jacks would be elevated above rig floor several feet for a working height. Decision to strip CSG jacks on if necessary once on setting depth. P/U Halliburton cement retainer w/running tool and RIH on 3.5" work string f/surface to 4,000'md as per Halliburton rep. • 1110 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP S-90 ASR#1/ EL 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: ��� - �� n� 10/19/2016-Wednesday Continue to TIH with Halliburton Cement retainer F/4,000'T/9,850'. Establish parameters, PU Wt. = 117K, Slack off Wt. =45K Break circulation, Circ. @ 3 bpm. @ 500psi.Attempted to set Cement retainer, power swivel stalled out at 4,100'/lbs. torque. Mix& pump 2 drums of Safe lube down work string and attempt to rotate cement retainer w/power swivel, in order to set. (No Success) Utilize rig power tongs to rotate 3.5" work string 35 turns to the right, as per Haliburton cement retainer setting sequence. Release rig tongs, allow torque to release from string, back out power swivel and latch up elevators. P/U work string to 10klbs over string weight and hold for 1min. Repeat steps 3 times successively to until rig reaches 150k lbs (No sign of shear release). Release tension followed by abruptly pulling to max overpull (150klbs) in order to wear the shear sleeve. After 3 sequences of overpulls, shear sleeve released and work string was free. P/U 20' above the retainer and utilize the rig tongs to rotate the workstring 20 more times to the right to release the stinger on the retainer, sting the workstring down into the retainer and perform injectivity test. Pump lbpm = 1,200psi, 2bpm = 1,500psi, 3bpm = 1,600psi,for 5bbls down the tubing and into the retainer. No pressure seen on the annulus side while pumping (indicator ,%,y/C retainer is not leaking.) PJSM w/ Halliburton cementers, PEAK truck drivers, Halliburton service hand, and rig crew. R/U in r ,$1k1‘1"- prep to pump cement. Pressure test cement line back to TBG stump, 250psi low, 5000psi high. Pump 5bbl fwspacer,_, followed.by26bbls of 15.8ppg class G cement,followed by 5bbls of fw spacer. Chase cement with 75bbls of 9.1ppg brine @ 3bpm = 1,200psi. Pressure increase to 1,600psi as cement enters retainer.Shut in TBG, unsting from cement retainer, open TBG and allow 4bbls of cement to U-tube into place on top of cement retainer(4bbls= 100'). Flow occuring on annulus to indicate cement U-tubing. Slowly L/D 4 jnts of work string to get BHA out of cement plug. L/D 17 more joints to get 500'md space out from the top of cement. SIMOPS: R/D Halliburton cement equipment, blow down lines. R/U to reverse circulate 1.5x workstring volume (130bbls)taking returns to cuttings tank. Reverse circulate @ 3bpm =400psi for 130bbls. PEAK vac truck removing returns from cuttings tank while reverse circulating. Small volume of cement seen back after reversing 75bbls. Continue to POOH w/cement retainer running tool on 3.5" work string f/9,350'md to 7,000'md. 10/20/2016-Thursday Continue to TOOH with 3.5" Work string F/7,000'T/6,000'. Circulate 50 bbls to displace fresh water from wellbore that was left in hole on cement job with 9.1 ppg. brine water. Continue to TOOH with 3.5" Work string F/6,000' to surface. L/D cement retainer running tool. Shear sleeve parted where the holes were drilled to weaken the sleeve, as planned. Good indiactions of proper set. R/U Halliburton E-line and prepare to RIH w/7" 26#gauge ring,junk basket, GR/CCL. RIH w/ E- line logging string to 9,620'md.Tag up on obstruction.Attempt to work down through obstruciton by progressively tagging it with more velocity. Obstruction depth remained constant, and pick up weights after tagging remained constant, so no idications of obstruction moving, or BHA sticking when tagging. Log out of hole to surface to record GR/CCL data for future utility. L/D logging BHA# 1, and P/U 40 arm caliper logging BHA#2, w/GR/CCL. RIH to 5,000' and and log to surface w/40 arm caliper. Once at surface and caliper data was partially processed and it was noted that the caliper wasn't properly centralized through the deviated section of the hole resulting in bad data for a section of the logging run. Decision to re- centralize the caliper and re-log the section of hole where the bad data was encountered. RIH w/40 arm caliper, GR/CCL and re-log bad data section. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP S-90 ASR#1/ EL 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: -tz. 10/21/2016- Friday Service rig. Off load clean out run tools f/ NES truck.Verify lengths, ID's & OD's on same. PU mud motor w/6 1/8" bladed junk mill, pump out sub, 3-1/2" IF pup joint&XO. RIH w/clean out assembly on 3-1/2" RTS-8 tubing f/surface to ±1,250'. VMS mechanics troubleshooting error codes on rig engine and clear same. Continue RIH w/motor clean out assembly on 3- 1/2" workstring f/ 1,250' to 7,775'md.Tag top of LNR, P/U 10' and gain parameters, P/U weight=80klbs, S/O weight= 38klbs, Rotating @ 36RPM = 2,300ft-lbs, 620psi @ 3BPM. Set down several times on LNR top w/ 1-1.5klbs. Attempt to rotate pipe a quarter turn and set down on LNR top, (no success). Continue to rotate work string quarter turns followed by varying the speed prior to tagging LNR top in order to shake the pipe slightly. 6-1/8" mill worked into LNR. Continue to RIH w/6-1/8"junk mill BHA down to 9,616' md. Set down 8klbs on obstruction. P/U with no noticible excess overpull. Gain drilling parameters, P/U = 120klbs, S/O =42klbs, Circ @ 3.5bpm = 1,000psi. Set down 5klbs on obstruction and begin milling. 20psi differential seen w/5klbs, continue to set down weight to 10klbs= 50psi differential. Obstruction milling away easily. Continue to mill down to 9,750'md. 10/22/2016-Saturday Drop dart for pump out sub. Pump down on seat. Pressure up and shear POS w/2,300psi. NOTE: AOGCC was notified via website of upcoming BOP test at 12:00 hrs on 10-21-16. Inspector Bob Noble replied with a request for update which was given at 08:00 on 10-22-16. RU and reverse circulate hole clean w/4X DP volume w/3-1/2 bpm, 550psi.Service rig. POH LD 6-1/8"junk mill w/4-3/4" mud motor BHA on 3-1/2" work string f/9,745'to surface. Clean and clear rig floor prep to begin testing BOPE.Test BOPE w/3.5" and 4.5" test joints to 250psi low and 3,500psi high f/5 charted mins each.Test annular element w/3.5" test joint to 250psi low, 2,500psi high f/5 charted mins each.AOGCC rep Bob Nobel waived witness to the test @ 16:35 10/22/2016. Call out Halliburton rep in prep to RIH w/ RTTS tool on 3.5" workstring. R/D BOPE testing equipment, prep rig floor to RIH w/ Halliburton RTTS PKR on 3.5" work string. M/U Halliburton RTTS PKR and RIH on 3.5" work string f/surface to 1,600'md 10/23/2016-Sunday Secure well and travel crews to MPOC for safety meeting. Night WSM stayed back to man the rig. Day WSM,Jerry Chitwood,Toolpusher, both crews ands Rob Handy attended meeting. Service rig. Continue to RIH w/7" RTTS on 3-1/2" work string f/±1,600' to ±2,718'. Shut down and troubleshoot error codes on Rig Engine (engine RPM &torque erratic.) Shut down engine, disconnect power and attempt to self reset w/ no success.VMS mechanic arrived location. Troubleshooting and inputting update. Continue to RIH w/7" RTTS on 3-1/2" W.S. f/2,718' to 6,100'. Perform "Man Down Drill". Crew responded in good time. Secure the well, muster and took head count.Took notice of wind direction and did a perimeter check. Discussed results w/crew. Continue to RIH w/7" RTTS on 3-1/2" W.S.1/6,100' to 7,450'. Rig continuing to produce error codes and de-rating the output power.VMS on location assess. Decision to replace the EGR valve based on the error codes. SIMOPS: Half the rig crew service the rig engines, swapping out oil and filters,the other half prep J-02 for rig arrival. Dean Norris on J-02 location to set BPV, nipple down production tree and begin N/U of BOPE.VMS complete swap of EGR, rig not producing any error codes. Continue to RIH w/7" RTTS PKR to 9,540'md. SIMOPS: Continue to N/U BOPE on J-02 and spot wellhouse into place. Set RTTS in 7" LNR and R/U to test the cement retainer/cement plug to 4,400psi as per sundry. • • Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date MP 5-90 ASR#1/ EL 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: , 10/24/2016-Monday Continue to test Retainer/Cement plug below RTTS to 4,400psi f/30 charted min. Good test. Bleed pressure. Close rams. Test above RTTS f/9,530' to surface w/3,000psi f/30 charted min. Good test. Bleed pressure. Release RTTS per HES Rep. LD 1 joint to 9,506'. Erratic RPM's while attempting to LD pipe. Rig engine continues to de-rate showing error codes. Decision made to stop at this point and await arrival of Cummins Mechanic. Break circulation. Circulate well w/ 1- 1/2 bpm, 150psi. Rig crews performing various maintenance/cleaning on rig. Continue training on Certek heat system. Cummins Mechanic arrived on location. Shut down pumps. Blow down lines. Mechanic providing Cummins engine computer updates and troubleshooting error codes. Reset engine computer system. Attempt to POOH w/ RTTS PKR on 3.5" work string, rig engine quickly de-rated itself. Mechanics continue to assess engine error codes. Fix loose connection on EGR valve temp sensor and perform SCR regeneration. Engine running fine again. POOH w/ Halliburton RTTS PKR f/9,540'md to 8,200'md. Issue w/rig elevators locking mechanism. Change out elevator door w/spare components and test to ensure proper setting (Good latch achieved w/proper slip engagement in the elevators.) Continue to POOH w/ Halliburton RTTS PKR on 3.5" work string f/8,200'md to 6,500'md. 10/25/2016-Tuesday Continue to POH LD 3 1/2" WS and RTTS f/6,500'to 4,580'. Shut down to allow Cummins Mechanic to load upgrade on computer. Check particulate filter on exhaust. Continue to LD WS to surface. LD RTTS. Change handling equipment to 4- 1/2". Spot Halliburton spooling unit and hook up air supply to same. Spot completion jewelry on catwalk in running order. Discuss completion with Halliburton and Baker Rep. Load 2 rows of 4-1/2" BTS-8 tubing on pipe rack.Talley same. Conduct pre-job meeting with Halliburton completions, Baker completions, and rig crew. Prep rig floor to RIH w/4-1/2" BTS-8 13-Cr completion.Verify tally and components to RIH. RIH w/4-1/2" 13 Cr BTS-8 completion as per tally to ROC gauge at 400'md. Baker completions and Halliburton completions hands on location to verify equipment and tally as it is RIH. Halliburton perform splice on TEC wire, pressure test all crush ring connections, and verify conductivity of TEC wire. (Good Tests) Continue to RIH w/4-1/2" 13-Cr BTS-8 completion w/TEC wire as per tally f/400'md to 1,300'md. • 411 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number _ Well Permit Number Start Date End Date MP S-90 ASR#1/SL 50-029-23276-00-00 205-135 10/1/16 11/20/16 Daily Operations: 10/26/2016-Wednesday Continue to RIH w/4-1/2" 12.75# 13cr BTS-8 completion f/ 1,300'to 6,100'. Load pipe rack w/4-1/2" tubing. Pull protectors and clean threads on both ends. Reinstall protectors.Tally same. Continue to RIH w/4-1/2" 12.75# 13cr BTS-8 completion f/6,100' to 9,592.73'md (249 jts+2 Pups). P/U landing joint and hanger. Drain the BOPE stack so wellhead rep Greg Ruge has a visual of the LDS. Line up to reverse circulate 370bbls of corrosion inhibited 9.1ppg brine. Land 13-3/8" tubing hanger, RILDS, R/U headpin to reverse circulate down the IA,taking returns up the TBG. Circulate 370 bbls of corrosion inhibited 9.1ppg brine down the IA.SIMOPS: Spot Halliburton slick line into place in prep to set EVO-Trieve plug in TBG tail. 10/27/2016-I Thursday Continue to RU Halliburton Slickline. PJSM w/ Rig & HES crews. PU Evo-Trieve and slickline tools. RIH w/ Evo-Trieve. Observe down weight while going through PBR and packer. Hook Muleshoe to verify depth. Pull up and spot E.T. at 9,549' middle of last full jt of 4-1/2" tailpipe. PUW 1300-SOW 400. Wait on DPU to set plug (1 hr.). Observed plug set. PUW 1,100 -SOW 250. Set down &tag plug at 9,549'. POH w/S.L. RD same. RU to pump down tubing. Flush air from lines. Pressure up to set packer and continue to pressure up to 5,000psi. Hold pressure for 30 charted min. Good test. Bleed pressure. RU to pump down backside.Test backside to 3,000psi f/30 charted min. Bleed pressure. RD & Blow Down Lines. Pull landing pups & break down same for return to D-Pad storage. Install BPV. (Release Rig @ 1800 hrs.) Blow Down Service Lines, Nipple bop Stack down to 4 Bolts, unpin Top section of Derrick and Lower, Electricians Disconnected Fire and Gas Alarms Drove ASR Rig to A-Pad ASRC Mechanic change out Oil Plug on Oil pan, ASRC Crane Assisted in Removal of Rig Floor, Stairs and Well House Finished Nipple down Bop Loaded on Low Boy Trailer, Nipple up Tree Test Hanger Void to 5,000, Pulled BPV Installed TWC Valve, Fill Tree with Diesel Tested Tree to 5,000psi, Good Test. 10/28/2016 - Friday No activity to report. 10/29/2016-Saturday No activity to report. 10/30/2016-Sunday No activity to report. 10/31/2016 - Monday No activity to report. 11/1/2016-Tuesday, No activity to report. • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Monday, November 14, 2016 9:42 AM L�- To: 'Ted Kramer' Cc: Bettis, Patricia K(DOA) Subject: RE: Discuss MPS-90 Frac Job PTD#205-135, Sundry#316-545 Ted, We have reviewed the changes to the stimulation on MPS-90. You have approval to move forward with the new proposed changes. Update the MOC and good luck with the Sag fracture stimulation. Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell SCANNED MAY 2 62012 907-793-1226 office CONFIDENTIALRY 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:Schwartz,Guy L(DOA) Sent:Saturday, November 12, 2016 10:49 AM To:Ted Kramer<tkramer@hilcorp.com> Subject: RE: Discuss MPS-90 Frac Job PTD#205-135,Sundry#316-545 Ted, Will look at this by Monday...should not be a problem. Will need to update the MOC form. 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). From:Ted Kramer(mailto:tkramer@hilcorp.com] Sent: Friday, November 11,2016 8:44 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Subject: FW: Discuss MPS-90 Frac Job PTD#205-135,Sundry#316-545 Guy, 1 • S Attached is the latest FracCade model and pump schedule from Schlumberger for the 5-90 well. This E-mail if to let you know that the Pump schedule has been modified for the upcoming job. What has changed is that the overall job has been increased from 105K pounds of sane to 145K pounds of sand ( see page 9 of this model and compare to page 8 of the FracCADE model in the approved sundry). This addition increases the frac height by 4 feet from 171.5 feet to 175.5 feet. This change will not affect the containment of the frac since the containment layer is over 1,000 ft thick. This change is being sent to you in accordance with AAC 25.283 Please be advised that this job is scheduled to be pumped on Tuesday, November 15, 2016. The job size and pump schedule may change again after the Data Frac is pumped. Sincerely, APiV 3� Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Gunther Rutzinger [mailto:grutzinger@sib.com] Sent: Friday, November 11, 2016 6:41 PM To: Anthony McConkey; James Fagnant- (C);Ted Kramer; Olga Aivano(olga.aivano@alaskafracconsulting.com) Subject: RE: Discuss MPS-90 Frac Job All, Attached are the FracCADE simulation and pump schedule. Regards, Gunther Rutzinger Stimulation Domain Champion Schlumberger 6411 A Street Anchorage, AK, 99518 Mobile: +1 (907) 223 9527 Office: +1 (907) 273 1788 e-mail: grutzinger0slb.com 2 Original Appointment From:Anthony McConkey[mailto:amcconkey@hilcorp.com] Sent:08 November 2016 13:20 To:Anthony McConkey;James Fagnant-(C);Ted Kramer;Gunther Rutzinger;Olga Aivano (olga.aivano@alaskafracconsulting.com) Subject: [Ext] Discuss MPS-90 Frac Job When: 11 November 2016 15:00-15:30(UTC-09:00)Alaska. Where:Call-In 907-777-8599 Hey All, As suggested in Ted's e-mail, it would probably be wise to discuss the upcoming frac job this Friday and ensure there are now outlying concerns or questions. Thank you, Anthony McConkey Reservoir Engineer Northern Asset Team, Hilcorp Alaska 3800 Centerpoint Dr.,Anchorage,AK 99503 (w)907-777-8460 (c) 907-529-6199 3 • • ScNlumOerger crox- �fc 194 t 4 1,3 5-ois6 FracCADE* STIMULATION PROPOSAL Operator : Hilcorp Alaska Well : MPS-90 Field : Milne Point Formation : Sag River Well Location : P4" County o L State : Alaska Country : United States Prepared for : Ted Kramer Service Point : Prudhoe Bay Proposal No. Business Phone : 907 659 2434 Date Prepared : 17 Oct 2016 FAX No. : 907 659 2538 Prepared by : Gunther Rutzinger Phone : 907 2731788 E-Mail Address : grutzinger@slb.com Mark of Schlumberger Disclaener Notice. This information is presented in good faith,but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service.The results given are estimates based on calculations produced bye computer model including various assumptions on the well, reservoir and treatment The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate then the model,the assumptions and such input data.The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values.The quality of input data,and hence results,may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well,the reservoir,the field and conditions affecting them.If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue.Actual charges may vary depending upon time,equipment,end material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is notto be inferred. • • Client : Hilcorp Alaska SriWWII! Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Contents Section 1: Wellbore Configuration 3 Section 2: Zone Data 4 Section 3: Propped Fracture Schedule 6 Section 4: Propped Fracture Simulation 9 Section 5: Propped Fracture Simulation Results 12 Section 6: Fluid Descriptions 13 Section 7: Treatment Fluid Data 14 Section 8: Proppant Data 15 Section 9: Hole Survey 16 2 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 1: Wellbore Configuration Bottom Hole Temperature 235 degF Deviated Hole YES Treat Down TUBING Well Type Vertical Well Location OnShore Tubing Data OD Weight ID Depth (in) (lb/ft) (in) (ft) 4.500 12.8 3.960 9573.0 Casing Data OD Weight ID Depth (in) (lb/ft) (in) (ft) 7.000 26.0 6.276 10598.0 Perforation Data Top Top Bottom Bottom Shot Number Diameter MD TVD MD ND Density (ft) (ft) (ft) (ft) (shot/ft) (in) 9623.0 8791.2 9659.0 8826.5 6.00 216 0.32 3 . 0 • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145kIbs Section 2: Zone Data Formation Mechanical Properties Zone Name Top TVD Zone Frac Insitu Young's Poisson's Toughness (ft) Height Grad. Stress Modulus Ratio (psi.in0.5) (ft) (psi/ft) (psi) (psi) Kingak 8585.8 79.7 0.823 7099 2.957E+6 0.36 1000 Kingak 8665.4 69.5 0.833 7247 2.672E+6 0.36 1000 Kingak 8734.9 29.6 0.843 7376 2.365E+6 0.37 1000 Sag D 8764.6 5.9 0.715 6269 3.909E+6 0.26 1000 Sag D 8770.5 8.9 0.748 6564 3.118E+6 0.29 1000 Sag C 8779.4 4.9 0.767 6736 2.685E+6 0.31 1000 Sag C 8784.3 3.9 0.726 6379 3.852E+6 0.27 1000 Sag C 8788.2 3.0 0.700 6153 4.161E+6 0.25 1000 Sag B 8791.2 3.0 0.685 6023 4.295E+6 0.23 700 Sag B 8794.1 15.7 0.680 5985 4.110E+6 0.23 1200 Sag B 8809.8 4.9 0.696 6133 4.229E+6 0.24 1200 Sag B 8814.7 2.9 0.710 6260 4.451E+6 0.26 700 Sag A 8817.7 13.3 0.710 6265 4.313E+6 0.26 1200 Sag A 8831.0 4.2 0.712 6289 4.630E+6 0.26 1200 Sag A 8835.2 1.8 0.746 6592 5.286E+6 0.29 1000 ,;, Sag A 8837.0 4.2 0.732 6470 4.887E+6 0.28 700 Shublik 8841.2 3.1 0.837 7401 6.739E+6 0.31 1000 -, Shublik 8844.3 2.0 0.867 7669 8.427E+6 0.34 1000 Shublik 8846.3 2.5 0.851 7529 8.298E+6 0.32 1000 Shublik 8848.8 3.3 0.831 7355 8.381E+6 0.31 1000 Shublik 8852.2 6.7 0.731 6473 7.928E+6 0.28 700 Shublik 8858.9 5.2 0.687 6088 7.262E+6 0.23 1200 Shublik 8864.1 4.7 0.695 6162 6.598E+6 0.24 700 Shublik 8868.8 3.2 0.758 6724 4.361E+6 0.29 1000 Shublik 8872.0 25.8 0.721 6406 5.043E+6 0.27 700 Shublik 8897.8 8.8 0.776 6908 3.969E+6 0.32 1000 Shublik 8906.6 20.5 0.768 6848 4.465E+6 0.31 1000 Shublik 8927.0 7.6 0.719 6421 5.868E+6 0.27 1000 Shublik 8934.6 16.3 0.747 6680 5.148E+6 0.29 1000 SHALE 8951.0 7.4 0.839 7513 8.794E+6 0.36 1000 SILTSTONE 8958.3 16.3 0.777 6967 8.502E+6 0.32 1000 SILTSTONE 8974.7 12.9 0.736 6610 6.121E+6 0.28 1000 SILTSTONE 8987.6 5.6 0.761 6842 7.282E+6 0.30 1000 SHALE 8993.2 5.7 0.696 6261 6.082E+6 0.24 1000 SILTSTONE 8998.9 13.6 0.744 6700 6.581E+6 0.29 1000 DIRTY-SANDSTONE 9012.6 14.5 0.697 6287 5.403E+6 0.25 700 DIRTY-SANDSTONE 9027.1 55.0 0.666 6030 5.025E+6 0.21 700 4 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145kIbs Formation Transmissibility Properties Zone Name Top TVD Net Perm Porosity Res. Gas Oil Sat. Water (ft) Height (md) (%) Pressure Sat. (%) Sat. (ft) (psi) (%) (%) Kingak 8585.8 0.1 0.001 1.0 4037 65.0 10.0 25.0 Kingak 8665.4 0.1 0.001 1.0 4072 65.0 10.0 25.0 Kingak 8734.9 0.1 0.001 1.0 4095 65.0 10.0 25.0 Sag D 8764.6 1.0 0.100 10.0 4103 65.0 10.0 25.0 Sag D 8770.5 1.5 0.100 10.0 4107 65.0 10.0 25.0 Sag C 8779.4 2.0 0.100 10.0 4110 65.0 10.0 25.0 Sag C 8784.3 1.0 0.100 10.0 4112 65.0 10.0 25.0 Sag C 8788.2 0.1 0.001 1.0 4114 65.0 10.0 25.0 Sag B 8791.2 2.5 1.000 10.0 4115 65.0 10.0 25.0 Sag B 8794.1 15.7 8.000 14.0 4119 65.0 10.0 25.0 Sag B 8809.8 4.9 8.000 14.0 4124 65.0 10.0 25.0 Sag B 8814.7 2.0 2.000 12.0 4126 65.0 10.0 25.0 Sag A 8817.7 13.3 8.000 14.0 4130 65.0 10.0 25.0 Sag A 8831.0 4.2 8.000 14.0 4134 65.0 10.0 25.0 Sag A 8835.2 0.5 0.100 10.0 4135 65.0 10.0 25.0 Sag A 8837.0 3.0 2.000 12.0 4137 65.0 10.0 25.0 Shublik 8841.2 0.1 0.001 1.0 4138 65.0 10.0 25.0 Shublik 8844.3 0.1 0.001 1.0 4140 65.0 10.0 25.0 Shublik 8846.3 1.0 0.100 10.0 4141 65.0 10.0 25.0 Shublik 8848.8 1.0 0.100 10.0 4142 65.0 10.0 25.0 Shublik 8852.2 5.0 1.000 12.0 4144 65.0 10.0 25.0 Shublik 8858.9 5.2 5.000 14.0 4147 65.0 10.0 25.0 Shublik 8864.1 3.5 1.000 12.0 4149 65.0 10.0 25.0 Shublik 8868.8 1.0 0.100 10.0 4151 65.0 10.0 25.0 Shublik 8872.0 20.0 1.000 12.0 4158 65.0 10.0 25.0 Shublik 8897.8 2.0 0.100 10.0 4166 65.0 10.0 25.0 Shublik 8906.6 4.0 0.100 10.0 4173 65.0 10.0 25.0 Shublik 8927.0 2.0 0.100 10.0 4180 65.0 10.0 25.0 Shublik 8934.6 5.0 0.100 10.0 4185 65.0 10.0 25.0 SHALE 8951.0 0.1 0.001 1.0 4191 65.0 10.0 25.0 S I LTSTO N E 8958.3 2.0 0.100 10.0 4196 65.0 10.0 25.0 SILTSTONE 8974.7 2.0 0.100 10.0 4203 65.0 10.0 25.0 SILTSTONE 8987.6 2.0 0.100 10.0 4207 65.0 10.0 25.0 SHALE 8993.2 0.1 0.001 1.0 4210 65.0 10.0 25.0 SILTSTONE 8998.9 3.0 0.100 10.0 4215 65.0 10.0 25.0 DIRTY-SANDSTONE 9012.6 12.0 1.000 10.0 4265 65.0 10.0 25.0 DIRTY-SANDSTONE 9027.1 35.0 1.000 10.0 4325 65.0 10.0 25.0 5 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 3: Propped Fracture Schedule Pumping Schedule The following is the Pumping Schedule to achieve a propped fracture half-length(Xi)of 334.5 ft with an average conductivity(Kfw)of 3864 md.ft. Job Description Step Pump Fluid Name Step Fluid Gel Prop. Prop. Name Rate Volume Conc. Type and Mesh Conc. (bbl/min) (gal) (Ib/mgal) (PPA) PAD 30.0 YF130FIexD 18900 30.0 0.00 1.0 PPA 30.0 YF130FIexD 2408 30.0 16/20 CarboBond Lite 1.00 2.0 PPA 30.0 YF130FIexD 2306 30.0 16/20 CarboBond Lite 2.00 3.0 PPA 30.0 YF130FIexD 2212 30.0 16/20 CarboBond Lite 3.00 4.0 PPA 30.0 YF130FIexD 2126 30.0 16/20 CarboBond Lite 4.00 5.0 PPA 30.0 YF130FIexD 2046 30.0 16/20 CarboBond Lite 5.00 6.0 PPA 30.0 YF130FIexD 1972 30.0 16/20 CarboBond Lite 6.00 7.0 PPA 30.0 YF130FIexD 1903 30.0 16/20 CarboBond Lite 7.00 8.0 PPA 30.0 YF130FIexD 1838 30.0 16/20 CarboBond Lite 8.00 9.0 PPA 30.0 YF130FIexD 1778 30.0 16/20 CarboBond Lite 9.00 10.0 PPA 30.0 YF130FIexD 1722 30.0 16/20 CarboBond Lite 10.00 11.0 PPA 30.0 YF130FIexD 1669 30.0 16/20 CarboBond Lite 11.00 12.0 PPA 30.0 YF130FIexD 1619 30.0 16/20 CarboBond Lite 12.00 Please note that this pumping schedule is under-displaced by 36.7 bbl. Fluid Totals 42501 gal of YF130FIexD Proppant Totals 143300 lb of 16/20 CarboBond Lite Pad Percentages %PAD Clean 44.5 %PAD Dirty 38.5 6 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Job Execution Step Step Cum.Fluid Step Cum. Step Cum. Avg. Step Cum. Name Fluid Volume Slurry Slurry Prop Prop. Surface Time Time Volume (gal) Volume Volume (Ib) (Ib) Pressure (min) (min) (gal) (bbl) (bbl) (psi) PAD 18900 18900 450.0 450.0 0 0 4337 15.0 15.0 1.0 PPA 2408 21308 60.0 510.0 2408 2408 4040 2.0 17.0 2.0 PPA 2306 23615 60.0 570.0 4613 7021 3964 2.0 19.0 3.0 PPA 2212 25827 60.0 630.0 6637 13658 3948 2.0 21.0 4.0 PPA 2126 27953 60.0 690.0 8504 22162 3980 2.0 23.0 5.0 PPA 2046 29999 60.0 750.0 10230 32392 4048 2.0 25.0 6.0 PPA 1972 31971 60.0 810.0 11831 44223 4094 2.0 27.0 7.0 PPA 1903 33874 60.0 870.0 13320 57542 4098 2.0 29.0 8.0 PPA 1838 35712 60.0 930.0 14708 72250 4104 2.0 31.0 9.0 PPA 1778 37491 60.0 990.0 16005 88256 4126 2.0 33.0 10.0 PPA 1722 39213 60.0 1050.0 17221 105476 4156 2.0 35.0 11.0 PPA 1669 40882 60.0 1110.0 18361 123837 4140 2.0 37.0 12.0 PPA 1619 42501 60.0 1170.0 19434 143271 4101 2.0 39.0 co cil ca -v <' P r. m 7 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Pumping Schedule Totals Summary for This Stage: Average Pump Rate 30.0 bbl/min Volume Weighted Average Rate 30.0 bbl/min Total Fluid Volume 1012 bbl Total Proppant Mass 143300 lb Total Slurry Volume 1170.0 bbl Total Pump Time 39.0 min Fluid Based Totals for This Stage Average Volume Total Total Total Total Fluid Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (lb) (bbl) (min) YF130FIexD 30.0 30.0 42501 143271 1170.0 39.0 Proppant Based Totals for This Stage Average Volume Total Total Total Total Proppant Pump Weighted Fluid Proppant Slurry Pump Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (lb) (bbl) (min) 16/20 CarboBond Lite 30.0 30.0 23601 143271 720.0 24.0 Summary for Each Treatment Average Volume Total Total Total Total Treatment Pump Weighted Fluid Proppant Slurry Pump Type Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (Ib) (bbl) (min) Propped Fracture 30.0 30.0 42501 143271 1170.0 39.0 Summary for Each Fluid in Each Treatment Average Volume Total Total Total Total Treatment Fluid Pump Weighted Fluid Proppant Slurry Pump Type Rate Average Rate Volume Mass Volume Time (bbl/min) (bbl/min) (gal) (lb) (bbl) (min) Propped Fracture YF130FIexD 30.0 30.0 42501 143271 1170.0 39.0 8 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 4: Propped Fracture Simulation The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model.Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Initial Fracture Top TVD 8794.1 ft Initial Fracture Bottom TVD 8809.8 ft Propped Fracture Half-Length 334.5 ft EOJ Hyd Height at Well 175.5 ft Average Propped Width 0.161 in Average Gel Concentration 808.0 lb/mgal Average Gel Fluid Retained Factor 0.50 Net Pressure 1119 psi Efficiency 0.361 Effective Conductivity 6099 md.ft Effective Fcd 3.9 Max Surface Pressure 4452 psi Simulation Results by Fracture Segment From To Prop.Conc. Propped Propped Frac. Frac. Fracture (ft) (ft) at End of Width Height Prop. Gel Conc. Conductivity Pumping (in) (ft) Conc. (lb/mgal) (md.ft) (PPA) (Ib/ft2) 0.0 83.6 11.6 0.205 169.1 1.80 283.8 4946 83.6 167.2 11.4 0.201 154.2 1.80 267.1 4982 167.2 250.8 11.3 0.198 106.8 1.77 305.7 5054 250.8 334.5 7.4 0.042 74.1 0.37 2333.5 814 Proppant bridged at 331 ft after 48 bbl in step 7 9 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145kIbs Fracture Geometry Data Per Zone for Production Prediction Zone Name Top Top Gross Net Fracture Fracture Fracture MD TVD Height Height Width Length Conductivity (ft) (ft) (ft) (in) (ft) (md.ft) Kingak 9416.0 8585.8 79.7 .1 0.000 .0 0 Kingak 9496.0 8665.4 69.5 .1 0.000 .0 0 Kingak 9566.0 8734.9 29.6 .1 0.042 238.0 999 Sag D 9596.0 8764.6 5.9 1.0 0.099 323.4 2315 Sag D 9602.0 8770.5 8.9 1.5 0.141 334.5 3291 Sag C 9611.0 8779.4 4.9 2.0 0.179 334.5 4185 Sag C 9616.0 8784.3 3.9 1.0 0.210 334.5 4879 Sag C 9620.0 8788.2 3.0 .1 0.236 334.5 5466 Sag B 9623.0 8791.2 3.0 2.5 0.255 334.5 5896 Sag B 9626.0 8794.1 15.7 15.7 0.278 334.5 6417 Sag B 9642.0 8809.8 4.9 4.9 0.276 334.5 6397 Sag B 9647.0 8814.7 2.9 2.0 0.267 334.5 6186 Sag A 9650.0 8817.7 13.3 13.3 0.242 334.5 5641 Sag A 9663.6 8831.0 4.2 4.2 0.210 334.5 4939 Sag A 9667.9 8835.2 1.8 .5 0.187 334.5 4417 Sag A 9669.7 8837.0 4.2 3.0 0.161 334.5 3824 Shublik 9674.0 8841.2 3.1 .1 0.136 302.9 3258 Shublik 9677.2 8844.3 2.0 .1 0.116 233.4 2810 Shublik 9679.2 8846.3 2.5 1.0 0.111 231.3 2706 Shublik 9681.8 8848.8 3.3 1.0 0.118 227.9 2866 Shublik 9685.2 8852.2 6.7 5.0 0.133 220.9 3225 Shublik 9692.1 8858.9 5.2 5.2 0.140 215.4 3409 Shublik 9697.4 8864.1 4.7 3.5 0.134 205.5 3249 Shublik 9702.2 8868.8 3.2 1.0 0.124 199.1 3013 Shublik 9705.5 8872.0 25.8 20.0 0.098 189.4 2374 Shublik 9731.9 8897.8 8.8 2.0 0.049 167.7 1183 Shublik 9740.9 8906.6 20.5 4.0 0.023 113.0 567 Shublik 9761.9 8927.0 7.6 2.0 0.000 .0 0 Shublik 9769.7 8934.6 16.3 5.0 0.000 .0 0 SHALE 9786.5 8951.0 7.4 .1 0.000 .0 0 SILTSTONE 9794.1 8958.3 16.3 2.0 0.000 .0 0 SILTSTONE 9810.9 8974.7 12.9 2.0 0.000 .0 0 SILTSTONE 9824.2 8987.6 5.6 2.0 0.000 .0 0 SHALE 9830.0 8993.2 5.7 .1 0.000 .0 0 SILTSTONE 9835.9 8998.9 13.6 3.0 0.000 .0 0 DIRTY-SANDSTONE 9850.0 9012.6 14.5 12.0 0.000 .0 0 DIRTY-SANDSTONE 9865.0 9027.1 55.0 35.0 0.000 .0 0 10 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Exposure Time Prediction by Step Step Name Fluid Name Pump Fluid Perforation Exposure at Exposure Rate Volume Injection BHST of aboveWatch (bbl/min) (gal) Temp. 235 degF Temp.of (degF) (min) 230 degF (min) PAD YF130FIexD 30.0 18900 132 6.0 6.0 1.0 PPA YF130FIexD 30.0 2408 101 10.2 10.2 2.0 PPA YF130FIexD 30.0 2306 99 9.0 9.0 3.0 PPA YF130FIexD 30.0 2212 99 0.0 0.0 4.0 PPA YF130FIexD 30.0 2126 98 0.0 0.0 1 5.0 PPA YF130FIexD 30.0 2046 97 0.0 0.0 6.0 PPA YF130FIexD 30.0 1972 97 0.0 0.0 7.0 PPA YF130FIexD 30.0 1903 96 0.0 0.0 8.0 PPA YF130FIexD 30.0 1838 96 0.0 0.0 9.0 PPA YF130FIexD 30.0 1778 95 0.0 0.0 10.0 PPA YF130FIexD 30.0 1722 95 0.0 0.0 11.0 PPA YF130FIexD 30.0 1669 95 0.0 0.0 12.0 PPA YF130FIexD 30.0 1619 95 0.0 0.0 11 • • Client : Hilcorp Alaska Scklin rger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 5: Propped Fracture Simulation Results (1) ACL Fracture Profile and Proppant Concentration Plot FracCADE' Hilcorp Aladal MPS-90 145Nbe 1704 2018 ACL Fracture Profile and Proppant Concentration 8600 8700- - - - - <0.0IbM12 0.0-0.311,82 0.3-0.6 1bft2 0.6-0.91b412 -__ 0.9-1.2 1b4t2 1.2-1.5 Ib4t2 j 1.5-1.8 Ib1t2 5 8800• - = 1.8-2.111,412 NI 2.1-2.41bert2 d M >2.4 Ib/02 Lt l 8900• Ci - IFF - - - HFracture#1 Initiation MD=9834.01 1 = 3 9000 - CD 5400 8600 7800 -0 2 -0I 0 0.1 0.2 0 200 400 600 Stress-pa ACL Width at Wellbore-in Fracture Half-Length-ft XICD Y (2) Treating Plot < N — &tiomhie Preseue - Suface Pressue ----- Tata)lrj.Rale —"t'— EOJ •CD + 8000I t I 40 I I I I .30 I I i 1 9 _ 1 g 1 C3 1 7 5000.--•—._ ._.—.--.—, —. 1_. ---, --- 2) g i 1 O O n i i i 10 i i 1 I I I2700 I I I .0 0 10 21 30 40 W m TreamentTime-min 12 • I Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 6: Fluid Descriptions 2% KCI brine • M117,Potassium Chloride 166.00 lb/mgal YF130FIexD • J580,Gelling Agent 30.00 lb/mgal • L071,Temporary Clay Stabilizer 2.00 gal/mgal • J450,Stabilizer 0.50 gal/mgal • U028,Activator 2.00 gal/mgal • J604,Crosslinker 2.50 gal/mgal • F103,EZEFLO Surfactant 1.00 gal/mgal • M275,Microbiocide 0.30 lb/mgal • J569,EB-CLEAN Med Temp Breaker 1.00 lb/mgal WF130 • M275,Microbiocide 0.50 lb/mgal • L071,Temporary Clay Stabilizer 2.00 gal/mgal • J580,Gelling Agent 30.00 lb/mgal • F103,EZEFLO Surfactant 1.00 gal/mgal • J569,EB-CLEAN Med Temp Breaker 1.00 lb/mgal `D ro 13 MEW • e . Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 7: Treatment Fluid Data Fluid data is given at 7.233 md. Fluid Name 2% KCI brine YF130FIexD WF130 Friction Rate Low(bbl/min) 5.0 1.0 1.0 Pressure Low(psi/1000ft) 10.0 20.0 1.2 Rate Pivot(bbl/min) 25.0 10.0 30.0 Pressure Pivot(psi/1000ft) 400.0 40.0 75.0 Rate High(bbl/min) 60.0 100.0 100.0 Pressure High(psi/1000ft) 1000.0 500.0 300.0 Fluid Loss CW (ft/min0.5) 1.0E+0 5.5E-3 5.5E-3 Spurt(ga1/100ft2) 0.0 0.0 1.6 Ct (ft/min0.5) 2.6E-2 4.5E-3 5.0E-3 Rheology Temperature(degF) 235 235 235 Time(hr) 0.0 0.0 0.0 Behavior Index(N') 1.00 0.67 1.00 Consist.Index(K')(lbf.sAn/ft2) 5.21 E-6 4.81 E-2 2.09E-5 Viscosity @ Shear Rate(cP) 0.250 295.877 1.000 Shear Rate(1/s) 170 170 170 14 • • Client Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Section 8: Proppant Data Proppant Permeability is calculated based on the following parameters: BH Static Temperature: 235 degF Stress on Proppant: 3985 psi Propped Fracture Conc.: 1.00 lb/ft2 Average Young's Modulus: 4.231E+06 psi Proppant Data Proppant Name Specific Mean Pack Permeability Gravity Diameter Porosity (md) (in) (%) Jordan Unimin 20/40 2.65 0.022 35.0 131283 CarboLite 16/20 2.74 0.043 35.0 788540 16/20 CarboBond Lite 2.59 0.041 39.3 521400 Proppant Permeability Plot P ropp t Permeability 1100000 Stress m Prcpp-nl I I 900000 - --- ------.------- 80x20 .._ ii ♦♦ ` ---._.-_ -._.._.i._._._±._.---4- t..._.._.._..�.._.._- 11 ♦ 700100 - \— -- \ a • 20020 ._... - - - - --4-- - - - - ---`- -� .._. .. - ---._._._.._.._.._ .a D \ 1C:ro e 16'220/40 Z •`•`` \♦ -f- Cabdile 1fy2u y ♦ --A-•- 1620Cabo2rd Ule d — Ce..._.F. Prcq Stress 400000 .�♦ 300000 ♦' `.i. r. _ ._._.—.-- -._ ._-._._-._._ _�._—.tri_"_-_._-_-._ `s. 101 201 2010 4000 5000 2000 7000 802 9000 10010 noon 1220 13000 14000 Closure Stress(psi) 15 • i Client : Hilcorp Alaska Schlumberger Well . MPS-90 g Formation : Sag River District : Prudhoe Bay Country : United States loadcase : 145klbs Section 9: Hole Survey Deviated Hole YES MD/TVD Calculation Relationship Unknown Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 100.0 100.0 0.4 0.4 8.2 8.2 0.4 171.0 171.0 0.8 0.6 347.4 -29.3 0.6 261.0 261.0 0.3 -0.6 226.4 -134.4 1.1 350.0 349.9 3.2 3.3 180.3 -51.8 3.4 441.0 440.7 5.1 2.1 180.1 -0.2 2.1 532.0 531.3 5.7 0.7 178.2 -2.1 0.7 621.0 619.9 4.9 -0.9 179.8 1.8 0.9 714.0 712.7 2.8 -2.3 184.0 4.5 2.3 808.0 806.6 1.1 -1.8 192.0 8.5 1.8 837.1 835.7 0.6 -1.7 196.5 15.5 1.7 929.0 927.7 0.2 -0.4 276.1 86.6 0.6 1023.6 1022.2 0.1 -0.1 319.3 45.7 0.2 1118.4 1117.0 0.5 0.4 8.2 51.6 0.5 1211.5 1210.2 1.0 0.5 358.0 -11.0 0.6 1306.8 1305.4 1.5 0.5 354.0 -4.2 0.5 1401.0 1399.6 1.6 0.1 357.6 3.8 0.1 1493.1 1491.6 0.7 -1.0 2.8 5.6 1.0 1586.5 1585.1 0.9 0.2 27.8 26.8 0.4 1680.5 1679.0 1.2 0.3 36.4 9.1 0.4 1774.5 1773.0 0.6 -0.6 74.0 40.0 0.9 1869.9 1868.4 0.5 -0.1 109.0 36.7 0.4 1963.8 1962.3 1.9 1.5 310.8 -168.4 2.5 2057.9 2056.0 7.1 5.5 312.5 1.8 5.5 2151.4 2148.7 9.2 2.2 314.0 1.6 2.3 2244.4 2240.5 8.8 -0.4 313.4 -0.6 0.4 2338.0 2332.6 11.2 2.6 313.3 -0.1 2.6 2427.2 2419.6 14.8 4.0 314.6 1.5 4.0 2522.1 2510.2 19.4 4.8 316.9 2.4 4.9 2615.0 2596.7 23.3 4.2 316.8 -0.1 4.2 2709.2 2681.9 27.3 4.2 316.6 -0.2 4.2 2803.2 2764.0 30.9 3.8 315.1 -1.6 3.9 2898.3 2843.9 34.6 3.9 314.8 -0.3 3.9 2992.1 2919.3 38.5 4.2 315.6 0.9 4.2 3085.4 2990.2 42.6 4.4 315.5 -0.1 4.4 3181.1 3058.4 46.4 4.0 316.8 1.4 4.1 16 • • Client Hilcorp Alaska Schlumberger Well MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145kIbs Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 3269.0 3118.5 47.4 1.1 317.2 0.5 1.2 3363.5 3182.1 48.0 0.6 316.4 -0.8 0.9 3456.0 3244.7 46.8 -1.3 317.6 1.3 1.6 3549.0 3309.2 45.3 -1.6 317.5 -0.1 1.6 3642.5 3374.7 45.8 0.5 316.7 -0.9 0.8 3736.9 3440.0 46.8 1.1 316.5 -0.2 1.1 3830.8 3503.2 48.5 1.8 315.9 -0.6 1.9 3924.7 3565.1 49.0 0.5 316.5 0.6 0.7 4016.2 3625.5 48.5 -0.5 316.1 -0.4 0.6 4112.0 3689.2 48.0 -0.5 315.4 -0.7 0.8 4206.7 3752.5 48.2 0.2 316.9 1.6 1.2 4300.5 3815.1 48.1 -0.1 317.6 0.7 0.6 4393.5 3877.6 47.5 -0.6 318.7 1.2 1.1 4487.7 3941.3 47.2 -0.3 318.9 0.2 0.4 n 4581.6 4006.0 45.7 -1.6 318.8 -0.1 1.6 = 4613.9 4028.7 45.3 -1.2 318.9 0.3 1.3 3 4691.3 4083.3 45.1 -0.3 320.6 2.2 1.6 m 4786.0 4150.3 44.8 -0.3 317.7 -3.1 2.2 a 4879.8 4217.1 44.3 -0.5 315.5 -2.3 1.7 4973.5 4285.2 42.4 -2.0 312.1 -3.6 3.2 <' 5066.4 4355.1 40.1 -2.5 311.1 -1.1 2.6 5160.7 4429.0 36.6 -3.7 309.9 -1.3 3.8 5256.5 4507.7 32.9 -3.9 312.9 3.1 4.3 5349.7 4587.0 30.6 -2.5 313.1 0.2 2.5 5443.9 4668.4 29.8 -0.8 312.2 -1.0 1.0 5537.8 4750.0 29.5 -0.3 311.3 -1.0 0.6 5631.2 4832.1 27.6 -2.0 310.4 -1.0 2.1 5724.0 4915.5 24.1 -3.8 310.1 -0.3 3.8 5814.9 4999.7 20.4 -4.1 309.8 -0.3 4.1 5909.2 5089.1 16.7 -3.9 308.6 -1.3 3.9 6002.4 5179.1 12.7 -4.3 310.2 1.7 4.3 6096.4 5271.5 8.9 -4.0 311.1 1.0 4.0 6189.9 5364.2 6.6 -2.5 307.2 -4.2 2.5 6284.2 5457.9 5.1 -1.6 297.3 -10.5 1.9 6377.9 5551.4 3.3 -1.9 271.3 -27.8 2.8 6472.7 5646.1 1.5 -1.9 239.6 -33.4 2.3 6566.4 5739.8 2.5 1.1 190.9 -52.0 2.0 6609.7 5783.0 3.4 2.1 186.9 -9.2 2.1 6655.7 5828.9 3.2 -0.4 182.6 -9.3 0.7 6750.2 5923.3 2.8 -0.4 185.5 3.1 0.5 6842.4 6015.4 2,5 -0.3 187.5 2.2 0.3 17 ! 4 ' Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145klbs Hole Survey MD TVD Deviation Deviation Azimuth Azimuth Dogleg (ft) (ft) Angle Build Rate Angle Build Rate Severity (deg) (deg/100ft) (deg) (deg/100ft) (deg/100ft) 6936.4 6109.3 2.1 -0.4 199.0 12.2 0.6 7030.2 6203.0 2.1 0.0 200.3 1.4 0.1 7123.7 6296.5 2.4 0.3 189.1 -12.0 0.6 7217.4 6390.1 2.7 0.3 185.5 -3.8 0.4 7311.6 6484.2 2.8 0.1 183.8 -1.8 0.1 7402.8 6575.3 2.7 -0.1 185.1 1.4 0.1 7498.5 6670.9 2.6 -0.1 181.1 -4.2 0.2 7592.7 6765.0 2.6 0.0 183.3 2.3 0.1 7687.1 6859.3 2.5 -0.1 182.5 -0.8 0.1 7779.9 6952.0 2.3 -0.2 180.5 -2.2 0.2 7874.1 7046.1 2.1 -0.2 178.9 -1.7 0.2 7961.4 7133.3 2.0 -0.1 181.1 2.5 0.1 8055.6 7227.6 1.8 -0.2 189.1 8.5 0.4 8149.9 7321.8 1.6 -0.2 182.9 -6.6 0.3 8242.6 7414.5 1.6 0.0 183.7 0.9 0.0 8336.9 7508.7 1.6 0.0 173.9 -10.4 0.3 8431.6 7603.4 2.4 0.8 175.3 1.5 0.8 8526.5 7698.1 3.9 1.6 173.9 -1.5 1.6 8622.3 7793.7 3.5 -0.4 176.4 2.6 0.5 8713.7 7885.0 3.0 -0.5 171.3 -5.6 0.6 8802.9 7974.0 2.7 -0.3 183.5 13.7 0.8 8897.0 8068.1 2.9 0.2 193.1 10.2 0.5 8990.3 8161.2 3.4 0.5 199.5 6.9 0.7 9082.1 8252.8 4.2 0.9 215.7 17.6 1.4 9176.3 8346.8 3.7 -0.5 222.3 7.0 0.7 9270.3 8440.6 4.1 0.4 229.8 8.0 0.7 9363.3 8533.3 4.9 0.9 252.1 24.0 2.1 9458.3 8627.9 5.2 0.3 257.2 5.4 0.6 9549.5 8718.6 7.6 2.6 288.8 34.6 4.6 9645.8 8813.6 11.3 3.8 300.4 12.1 4.3 9739.3 8905.0 12.8 1.6 305.2 5.1 1.9 9810.6 8974.3 13.9 1.5 305.6 0.6 1.5 9905.0 9065.7 15.8 2.0 306.3 0.7 2.0 9998.9 9155.9 15.9 0.1 306.2 -0.1 0.0 10092.7 9246.1 15.9 0.0 305.9 -0.3 0.1 10186.0 9335.8 16.2 0.3 305.0 -1.0 0.4 10281.4 9427.4 16.6 0.4 305.2 0.2 0.4 10376.1 9518.0 16.9 0.3 305.0 -0.2 0.3 10465.4 9603.4 16.9 0.0 304.1 -1.0 0.3 10533.4 9668.6 16.4 -0.7 303.5 -0.9 0.8 10600.0 9732.5 16.4 0.0 303.5 0.0 0.0 18 • • Client : Hilcorp Alaska Schlumberger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : United States Loadcase : 145kIbs Cl) 3 CD S,Q A fD 19 III 411 i282P88 »8888888888888 rn m E 3 3 8;7 N B F (888888 F (8888888888888000 da a 0aW02ppppppNO 20M8888888888888WV 1 ,1.4,0‘-elm E . . y E o .9. ./V N N N N N N N N 1-Eo90FE -99OOOO000000M o y2888 8 8 8 ° 28888888888 8 8 8 8 8 LLO 2 N � ) N y P 0 > o f - K Jmf a 8s W V y W K Oz ,.tr O m Za2 `,thio 0000 A _ 0000000000000 J w` md � 04wm? ` it t m Fc , 6- E oa E p DafJ NE JOONM « MnN4 W3a O J J o a O 0 > > > 7 z — W a y W y o p u 8 d O N M 8, U O m N n N M W A•N N o o M M 2 . gas- „ m v,nwinovvvvvvvM.-M' g g g gO$ o _ N O N Oi $ i a U u 8 a I u LL W o o m m 8 y 8 m m mmmmmm x O myW R YA mm mm10V, tOV 0 10 m o + .F. O m W w 7 LLagm O QEmJOpNyyNO000 n moVJ — o -M0-rNMR2rWONaaY 0 - . n za F •J yO n WO,y 0 wN OV OM hANv A A rZ0hFw>y� fK. w N al NO . m0<00ppNMAONM Pi. Owpy y - NV(OODg ^Wm 52 Jw 222L ESw G , LL ° o � m m m o 3 y Op{p ppb (p Q a h ' > > O a gl 7< IA tp i N 7 a O(f g1 Q t0 2 np N r aN t gp M ONO M A O ctwcem d W W (7 U' U Uf/ RR^^N V 4Q V inNN2G IST17.n,g! K ' ] 0 w 0=1,TctN 8884 OO2 b j§NO ON OPI O N hO hO NO NO NO O NO n 8i 010 MNVNVW ° CONNNNNN NNNNNNO y07 0 O c> qq x aa a p > ppO) O U m N R 8 m U m O w w N n h O V)MO N m A O N O tl .-MI .- O„ Z 2 J mI�2 O e.. 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Y n 2- : .-*YO n 0 a3 020 K F y • • w\�O��//7, s9 THE STATE Alaska Oil and Gas g�,"l-11i�a Of jL A S KA Conservation Commission 333 West Seventh Avenue /. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OSA : Fax: 907.276.7542 www.aogcc.alaska.gov Bo York NN�� Operations Manager 114M 0 2 2017, Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Milne Point Field, Ivishak Undefined WTRSP Pool, MPU S-90 Permit to Drill Number: 205-135 Sundry Number: 316-545 Dear Mr. York: 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, Daniel T. Seamount, Jr. Commissioner DATED this day of November, 2016. RBDMS Lv - 8 2016 III III t., I ... STATE OF ALASKA OC.� Z g �1 ALASKA OIL AND GAS CONSERVATION COMMISSION 6 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AUL3 CC 1.Type of Request: Abandon 0 Plug Perforations 0 "` Fracture Stimulate ❑. Repair Wel 0 KM Wel with Col❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Complete❑ Plug for Redrill ❑ Perforate New Pool 0 Re-enter Susp Well ❑ Alter Casing 0 Other. CTFCO Q 2.Operator Name: 4.Current Well Class: 5-Permit to DM Number tq ji iv z— Hilcorp Alaska LLC Exploratory ❑ Development 9 205-135 ' 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ® Service ❑, 6_API Number: Anchorage Alaska 99503 50-029-23276.00.00 • 7.If perforating: 8.Wel Name and Number 9 governsspacing pool? 20AAC.25.055 / 4 r c. What Regulation or Conservation Order wells acin in this 1r � P�r�s ` Will planned perforations require a spacing exception? Yes ❑ No Q/ MILNE PT UNIT IVISH S-90 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0380109/ADL0380110 • MILNE POINT/IVISHAK UNDEF WTRSP ' 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): . 10,600' . 9,733' 10,511' • 9,647' 8,000 10,511' N/A Casing Length Size MD TVD Bust Collapse Conductor 113' 20" 113' 113' N/A NIA Surface 4,372' 13-3/8" 4,372' 3,863' 5,O20psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(it): See Attached Schematic / See Attached Schematic 5.5" 17#/L-80/BTC-M 4,012 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft)E Baker HR ZXP Liner Packer and N/A 7,79501D)/6,967(TVD)and NIA 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch Q Exploratory 0 Stratigraphic ❑ Development❑' Service ❑ 14.Estimated Date for 15.Well Status after proposed work ta Commencing Operations: 11/32x16 � `, OIL ❑, WINJ 9 WTRSP ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑ WAG 0 GSTOR 0 SPLUG ❑ Commission Representative: GINJ 9 Op ShutdoYm 0 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 Ted Kramer Email tkrarrter©hitorp.ccm Printed Name Bo York Title Operations Manager Signature ./. ' Phone 777-8345 Date 1IY2012016 /--- COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 3 \4. _ L{ Plug Integrity 0 BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance 0 Other: r4- i t.c.7 m i 4-{J p z''5 f-- /'yet-c— l^Ec. Otws $ 11A pp�� �t C Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS (r'AG r - 8 2016 Spacing Exception Required? Yes ❑ No Subsequent Form Required: /0•--Lf 0 Ll C• t1 i411b APPROVED BY Approved b 9 fr COMMISSIONER THE COMMISSION Date: / f i 7/ OtRolealli Submit Form and Form 10-403 Revised 11/2015 A lid for 1 months from the date of approval. Attachments in Duplicate I til' l6 CA)kJ I 0/25/20/b • • Hilcorp Alaska, LLC RECEIVED Post Office Box 244027 c� Anchorage,AK 99524-4027 OCT 2 0 2016 3800 Centerpoint Drive Suite 1400 kOGiV=C Anchorage,AK 99503 Ted Kramer October 20, 2016 Senior Operations Engineer (907) 777-8420 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 11 Re: Hydraulic Fracturing Application, Milne Point Unit, MP S-90 Dear Commissioner Foerster, Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Milne Point Unit, herein submits its application to fracture stimulate MP S-90. Please do not hesitate to contact Ted Kramer at 907-777-8420 should you have any questions regarding this application. Kw° 4"-jsgY r Sincerely, y w� <,A, n J HILCORP ALASKA, LLC U^ 3 Bo York • Operations Manager `/9/ Enclosures: Form 10-403 Sundry Attachments • Section 1—Affidavit 10 AAC 25.283 (a)(1) Landowner Notlacation Leitei MPS-91) Pace 3 of) VERIFIATION OF NOTICE PER 20 AAC 25.283(a) MILNE POINT UNIT MPS-90 I,TED KRAMER,Senior Operations E'nginecr.do hereby verify the following: [ am acquainted with Hilcorp Alaska, LLC's application for sunday approval to the Alaska Oil and Gas Conservation Commission to enhance production of the MPS-90 well via hydraulic fracturing. Pursuant to pending regulation 20 AAC 25.283, I assert that all owners, landowners, surface owners, and operators within a one-half mile radius of the current or proposed wellbore trajectory have been provided notice of Hilcorp Alaska,LI,C's proposed operations. DATED at Anchorage,Alaska this rfray of October,2016. ••• /C-'""4-7 Ted Kramer,Sr.Operations Engineer I I ilcoq)Alaska,LIC STATE OF ALAKSA )ss THIRD JUDICIAL DISTRICT 1"4 SUBSCRIBED TO AND SWORN before me this Vday of October,2016 STATE OF ALASKA NOTARY PUBLIC NOARY PUBLIC II4t1FOR David W. Duffy "+,'- THE STATE OF ALSKA cornfrilmion ExIAres—SeS Vint_ My Commission expires: • 0 Section 2—Plat 20 AAC 25.283(a)(2) ...........__ _......,...„..._.„ , . . 1 , . > , e , • „.J - . * I ' ' 4 p " •• / ; .,f` ' '•• -, ", • ;, , i t , / i- , .4; ''; , ; %. ,• 'f ( . , I ' . t ,..., . ' i ."°. ; ,/ i ,,,l'C'''.,'' • A DL80108., „,,,,"•:::`,,,' ' ''''-_, ; - „';'-'4't•-•;;Z:1::;;-:4",,t,,,, ;:-;'-•:`';;;'Y''''- ; i , ' ,';',';;;/;;'•''.1 ' ', S - •tlai ' ' ' ' '''' '' :; 1:' ''-'; Avk , _i. .. --,.. --- -,-,:-.-- -,,,,,,, _ • ':-.,, .,,,,:. , ..,„,-,,,,,„ ,,, L1012NITHE . S. ., .,,,,"•-;;„/, .„,,;:-ii,”-'; ,/ '• - 0".e..,:',"•• ; „ - '1''',.;;,' -/:. _ „:;;;,,„,„,,,,,,„„,;•,-E' ' ,-/,,•-','"',r,..:t' ' '7:,,TL-—'2[1.7-'-'--,;'.'1'; -- - - /- -I 4,‘,„ .... MILNE,'' ; 1 '' '' 1 ; 'POINT/LINIT ; . it, 1 . . . -.--: , ,.. . - .. . .._ 0 ',, —: a•••t .'•"-, Lege/id ,. -vtua Tuaiotory MR540 ''i:,, (*No Wei Tialockaies . AEU.SYT0SV1 - OTHER — - (Kupatt*fed .1 Seaadarl ,, :•'.. IT. 1-. roman! "I.."14 Mao Radus-Frac Zane V :,.!,,,, , C., PLUt3 EACK fik, - - 122 uida Radus,..ma Bore 'S + 51111t44 C:1(J and Gas Unit Boundary lit Milne Point Unit pulia tAic.1 z'..,a:atu,sa_•-ii„..... MPS-60 DoliNtb*Stitosy No Visief Wells Allhu lt2 folio MPS-90 Well 0 ry., ix° 1,571.) 1.21T.,rte.,ti 1 t.-.',,-1 iti 11111.11.1==1.1111111t'eet Plat depicting all well types within a Y2 mile radius of MP S-90 • Ilase otErsc $ ADL 3801 AOL 38010 U012N010E U012N0111 ".$ oto to` ot, MILNE POINT UNIT Legend • &glace Ka*iccatton Wen TrapeFlary MPS SO Ss...Mfg Mde RAZI4t/S Frac Zary - %Ma Ffadous Wati ttoac * P t2211 01014 Gs*thott1 Milne Point Unit Datana-.e RAF DatratFm Sorvoy VVate,Wefit VAtte, Mkt MPS-90 Well co 500 1,000 5C00 Feet Plat depicting no other Sag well penetrations within a Y2 mile Radius of S-90 / _ _ • • Section 3—Freshwater Aquifers 20 AAC 25.283(a)(3) There are no freshwater aquifers of underground sources of drinking water within one-half mile radius of the current well bore trajectory. Any and all freshwater aquifers lying below the Milne Point Unit are exempted aquifers under Aquifer Exe i tiorrOrder2 (AEO 2). '\ S-- •- - . "• • A • • . • , - •• - f. .•i - lying dire_ . . . - =•. • • : .: • . . - - • - v . - aqui - • •- : . . - ADL380110 ADL38 1Ufl U0121,10 90E U012N011E F, T Sec.12 tSRG, MILNE POINT UNIT �".f.:tF', Surface Hale Location(SHII Well Trapciery MPS-90 17 Milt RDdIW-5ML OQI 0110 Ga:UnC er-n cry Perry 11 Well - cII O.LaverDefinitiveDefinitiveS MP5- Definitive Survey ey Milne Point Unit Ne Water Welk within 1r2Mie MPS-9D Well .„cc f eoo 1 goo ITNJ .....,.... .. -�Feet Plat depicting the S-90 well location with no water wells within 1/2 mile radius of the S-90 surface location • • Section 4—Plan for Baseline Water Sampling for Water Wells 20 AAC 25.283(a)(4) There are no water wells located within one-half mile radius of the current wellbore trajectory and fracturing interval. A water sampling plan is not applicable.( • • Section 5—Detailed Cementing and Casing Information 20 AAC 25.283(a)(5) 13-3/8" 68#/ft L-80 buttress surface casing set at 4,373' MD and cemented with 1,035 sxs Arctic Set Lite followed by 455 Sxs. Class G. 9-5/8"40#/ft L-80 buttress production casing set at 7,942 MD and cemented with 723 sxs. Class'G'. 7" 26#/ft L-80 production liner set at 10,600' (top at 7,786'), cemented with 393 sxs. Class 'G'. f'^'/ i' Detailed Casing Information Size Type Wt/Grade/Conn Pipe Body Yield Collapse Pressure Internal Yield Pressure (lbs) (psi) (psi) 20" Conductor 92#/H-40 N/A N/A N/A 13-3/8" Surface 68#/L-80/BTC 1,556,000 2,260 5,020 9-5/8" Production 40#/L-80/BTC-M 916,000 3,090 5,750 7" Liner 26#/L-80/BTC-M 604,000 5,410 7,240 Detailed Tubing Information 4 '/" Tubing 12.75/13Cr-85 and 110/BTS-8 306,000* 7,820* 8,960* *Note: Since the tubing string is a mixed string of 85 and 110 KSI steel, only the lower ratings are given o • Section 6—Assessment of Each Casing and Cementing Operation to be Performed to Construct or Repair the Well 20 AAC 25.283(a)(6) The S-90 well was constructed in accordance with 20 AAC 25.030. 13-3/8"Surface Casing- The Surface casing setting on S-90 did not go as planned. The well plan called for the casing to be set at 4,679' and (4,072'tvd). While running the casing,the casing became stuck at 4,373' (306' short of the planned casing point). Working the pipe with 475K up pull was unsuccessful in freeing the casing. The well maintained full returns and the decision was made to cement the casing in place at 4,373'. This casing string was cemented with 1,035 sx.Of Arctic Set Lite Cement followed by 455 Sx. Class'G' 15.8 ppg cement. Full Returns were observed throughout the cement job and the plug bumped with / 1,800 psi of pressure. The floats held. 475 bbls of"good "cement +/ was circulated out at surface. The cement was drilled out and a FIT test was conducted to 12.0 ppg. 9-5/8"Intermediate Casing— The intermediate casing setting also did not go as planned. When running the 9-5/8"47#casing the last joint was washed down to 7,941'. The rig at that point could not pick up the casing string due to the hanger becoming stuck in the BOP stack. Circulation was still achieved in the well. Therefore, permission was given and the first stage of the cement job was pumped. Pumped 433 Sx of Class`G'cement at 6 bpm. Bumped plug with 1000 psi., Floats held. Pressured up and the cementer opened at 2,200 psi (set to open at 3,300 psi),established circ for Stage#2 at 6 bpm. Pumped cement Stage#2 290 Sx Class'G'cement(60 bbls.) at 6 bpm. Closing plug hit, pressured up to 1,600 psi (1,200 psi over circ. Pressure) Closed annular and pumped down backside 6 bbls at 800 psi. Suspected that the cementer was leaking. Bleed off pressure on back side. Pressured back up on cementer closing plug to 1,600 psi and held for 5 min. Closed Annular and injected 40 bbls of mud down back side @ 1,100 psi 1.5 bbls/min. determined that 9-5/8" by 13-3/8"annulus was plugged. Continued with well. (See note at the bottom of this section) 7"26#Production Casing- Cemented with 498 sx. (103 bbls)of Class 15.8#'G'cement. Bumped plug with 3,500 psi. Set liner top packer. POOH. Tested liner lap to 1,000 psi good test. Pressure tested casing to 4,000 psi on chart for 30 min. (Good test) Ran Schlumberger USIT Log on 7" casing. rl .Q) Cc rvz,rz - C J.eN �`� • • Note: It was determined that the 9-5/8" by 13-3/8" annulus became plugged during the cement job. This was an issue because there was no way to freeze protect this annulus. This issue was corrected by cutting and pulling the 9-5/8" casing at 1,939'. 5" DP was ran in the well and the well was displaced with diesel from 2070'to surface. The 9-5/8" casing cut stub was backed out, and the 9-5/8" Casing replaced screwing back into the collar at 1,960'. The casing was tested to 3,500 psi on chart for 30 min.from 4,038' (RBP) up. (Good Test) Attachment#1 is a Schlumberger USIT Log dated November 27, 2005. The log shows TOC as being 8,680' and good to excellent cement starting at 8,854' down to 9,678'. • Section 7—Pressure Test Information and Plans to Pressure Test Casings and Tubings Installed in the Well 20 AAC 25.283(a)(7) The 13-3/8"Surface casing was pressure tested to 2,000 psi on 11/11/2005. The 9-5/8" Intermediate casing was pressure tested to 2,000 psi on 11/18/2005. The 9-5/8" intermediate casing was pressure tested to 3,50 from 4,038'to surface on 12/02/2005. (after casing cut and ✓ replace). The 7" Production liner was pressure tested to 4,000 psi. on 1.7 11/27/05. For the Frac.Job- Pressure Testing Plan The 7" production liner, below the packer, is to be pressure tested to 4,400 psi with 9.1ppg brine during the workover. he 9-5/8" Surface Casing by 7" Production liner annulus(above .ate' r �ti the packer) is to be tested to 3,000 psi during the well �3 , Nal _ workover. (Note:this pressure may be adjusted downward g, � � `1z ZOO')e30"` depending on the results of the 9-5/8" Caliper log.) The 4-1/2" Frac.String will be pressure tested tosi. A" - - (Note:this pressure may be adjusted upward, depending upon the results of the 9-5/8" Caliper log.) Weite f5 S� • • Section 8—Pressure Ratings and Schematics for the Wellbore 20AAC 25.283(a)(8) Detailed Casing Information Size Type Wt/Grade/Conn Pipe Body Yield Collapse Pressure Internal Yield Pressure (lbs) (psi) (psi) 20 Conductor 92#/H-40 N/A 520 1530 13-3/8 Surface 68#/L-80/BTC 1,556,000 2,260 5,020 9-5/8" Production 40/L-80/BTC-M 916,000 3,090 5,750 7" Prod. Liner 26/L-80/BTC-M 604,000 5,410 7,240 +— , I Detailed Tubing Information .f✓1� / 5 e 4-W Tubing 12.75/13Cr-85/BTS-8 306,000* 7,820* 8,9-60* *Note: the tubing string is a split string of 13Cr-85 and 13Cr-110. Only the lower numbers of the 13Cr85 are given here. Tree Saver 15,000 psi Wellhead 5,000 psi BOPE N/A Schematic—See Next Page Milne Point Unit PROPOSED Wel(:MPS-90 Last Completed.12/3/2005 tris ai,.s .a I PTD:205-135 TREE&WELLHEAD KB fiev:72'-Down14 see 4-1/1 '-5M 4eRlheai 15-31$"x4" MC5Mw/4"TGSTubinar 1-1ees,7"C1WTtpe- 8PVPci OREN HOLE/CEMENT DETAIL 20" 260 sr Arctic Set(Approx.)in a 42"Hole 13-3/8" 1,035 14,A5 Lite,455sx.Cbss'0'ina16"tide 9-5/6" 723 SS Class'0"in a 12-1/4"Hole 7 393 sx Class'G'in a 8-i/2" CASING DETAIL £=yB ' Sae Type Wt/Grade/Conn ID Top Brm EPF 20" Conductor 92/H-40/N/A N14 Surface 113' N/A 13-3/r Surface 681 L-80/BTC _2.415" Surface 4372' 0.1497 ti>t Ge^et, 9-5/8" Intermedia 40/L-80/6ttc- 8.835" Surface 7,942' 0.0758 511cKJ 7' Production 26/1-80/6tcc. 6.276" 7,775' 10,598' 0.0583 TUBING DETAIL 7.3:-7, 112.75/13CR-85&110/8Ta$t 3.958" I EJrfxe I 19,750' I 0.0152 WELL INCLINATION DETAIL KOP 300' Max Hole Angle.48 mss. 3,600' Hole Ano a ttru Erri.. 16 des. JEWELRY DETAIL No Depth Item 1 .<:cc LL',1{D, rrrFedGfi—tC-3.833" Nr L 2 7,786' 9-5/8"x 7'ticker Liner Tie Back 5lc L • 3 7,795' 7"Baker HR 29P Liner Packer ' 4 7,805' 7"Baker Liner HMC Hanger 5 19430` Pressure Discharge Gauge-Ix385S 6 `_9438' SSdingSleeve—3213' 7 ±9,448' Pressure Intake Gauge—3.855' 8 19,514' X-N pple—3_813' 9 ±9,540' Baker S-3 Packer-3.73 10 19,564' Baker SaP Shear Sub 11 19,850' CIE= 12 10281' ISP—Installed 2013 / PERFORATION DETAIL )y)stJt, Top(MD) glIm(MD) Top(TVD: ) (TVD) FT Date44.4112.01—, Sag River 1'9,523' Tn.E_`,7 =8 79: 18,827' '35' Future °'—ar 4°7/4 417 9,884' 9,996' 9,046' 9,153' 112 11128/005 Isolate: 9.5/134 35e bestrak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10322' 9,242 9,466' 234 11/28/005 Isolated 45059. .z.IptHMK.HSD,55PF,72Des.Phasng GENERAL WELL INFO API:50-029.232760000 Cased&Completed by Doyon 14-12/3/2005 *Mt E NOTE 1' There is a spaced section in the 9'5;13'casing r'ch'rsp SEM from the cut@ 1,939 to the baker Wtlips :a 9E9—.,41 —. assembly*1,965.Th is splicewas pressgyre NNW q C ,r'' tested to3,500csi for 30 min.and passed .4114;- . }3vlC�c is TD=105600'(A!D)/TD=9733'CND) PBTD=i0,511'(MD)/SID=9,647'(TO Revised By:TOF 9/16{2016 0 • WELL MPS 90 DATE S-23-16 [Jih or{I Alaska. 1.1.1. Tree Cap.Otis style,71/16" -,.(z-t„ 9H"Acne dud f a a�- ibIllik Swab valve CIW Model Ft,7 i,...11-"1 1/16*SK,FE,00 1.-U 11't► , Wing valve OW Model FL,7 .. 1/16"SK,FE,00 L-U i 0 SW valve Cameron FL 71/ .tam iimemil 16"SK reverse actuating r gate valve,EE.PSl2,PR2 w/ Otis actuator df ��� Master valve COW Model Ft. 3'S" 71/16"SK,FE,OO 1.4) Tbg Hd Adpt,FMC SM- E-CL, M-E CL,13 SA*x 71/16" '_ API 13 S/3"SK 1=�' +. AM 13 S/S"SK 11 0 0 „."nit sTATEs PROPOSAL: ILVAI la I Casing isolation Tool Energy SeRrices(Canada)Inc. -- - Maximum Allowable Pumping Rates SIZE it-) Et n RATE ryt'irrnin CSG 2.250 3.760 10 fre Mitt ' ri1/2-Bi9 Bate 1.760 2.750 4 rulinin r2tal"&3 isr 1438 2.340 4 m'insin 1.000 .L500 2m'frnk 3 1.11A A 4 11$0;..ith tzmearil mandr01 t,760 4.000 - 15 isalidtir4- 4 1/16 X Tool Ilandral 3410 , 4.750 — 24 ó, n , Ofts,Faunal* 411411.Pomo. it,,,,,,,,,.:,,.....,,i 1,.....t.iiiiiii A 1): • t,,...41.,./, t. , •-7= j, swam. ' .4.......- ..,. PIP ,&Yen ...lirr 4 I '' I .II .,-. ark- _a 1P1 , - .IIIIIr-.4 I•'.... ; I:, '.. ,!,, ...sr - - i .....1 r www.StingarCanada.com 15M Treating Head • • Section 9—Data for Fracturing Zones and Confining Zones 20 AAC 25.283 (a)(9) Data for the Fracturing Zone and Confining Zones (A) a lithologic description of each zone; (B)the geological name of each zone; (C)the measured depth and true vertical depth of each zone; (D)the measured thickness and true vertical thickness of each zone; and (E)the estimated fracture pressure for each zone; The Sag River formation is a Triassic-aged, fine-grained marine sandstone. The productive Sag River interval is 36'TVD thick. The top Sag River is at 9,596' MD/8765'TVD. The estimated fracture gradient for the Sag River interval is 0.575 psi/ft. The overlying confining zone consists of 1099'TVD of Kingak shales. The top Kingak shale is at 8492' MD /7663'TVD. The estimated fracture gradient for the Kingak is 0.689 psi/ft. The underlying confining zone consists of 173'TVD of Shublik mixed carbonates,siltstones and shales. The top Shublik is at 9,662' MD/8,830'TVD. The estimated fracture gradient for the Shublik is 0.601 psi/ft. • • Section 10-Location, Orientation and a Report on Mechanical Condition of Each Well that may Transect Confining Zone 20 AAC 25.283 (a) (10) No other wells transect the confining layer(Kingak shale) in the 1/2 mile radius surrounding S-90. • , _ _,,, -- - - _ A,,,,, _ q,,,i,..,,,---1,, * ., , , .,, g _ .\\ MPS-90 ./:___ ) \ ,, ._,„..,, ‘cp: , -y, .....i.,„:,..,: „„, I 1 Fault 1 00 \\: '' -SN'4-..„ ,,,,, ' :6:2Dault foo„, ' \ NI o o 9�soo CO /cO w o5r \Fault 2 o�oes � , �o s so C° 1-0t co 0 '8700 '8900—-- 8 d '� Fault 3 �,” �� 8650 ' Fault 4 o 00 L f 0 s m��� \ :mss a 910 tip, p i The map above shows the structure at the top of the Sag River interval (TVDSS). All faults shown are inferred from seismic data.The MPS-90 well did not encounter any faults during drilling. There are several faults based off of seismic data that are within the%2 mile radius of the MPS-90 wellbore. However, MPK-33 and MPC-23 (both vertical, hydraulically fractured Sag River producers, similar to what is proposed here) are similar distances to mapped faults and did not suffer containment issues. Horizontal principal stress from surrounding well data indicate that the fracture should propagate approximately NW-SE (SHmax is NW-SE, SHmin is NE-SW). Based on current mapping, the fracture wings should not extend into suspected faults. The table below summarizes the fault properties within 1/2 mile radius of the Sag River frac zone. Fault number Distance to fracture zone (feet) Vertical displacement(feet) 1 1262 47 2 347 158 3 961 93 4 1722 80 5 1567 78 ���� ���� Section 11 - Location of, Orientation of and Geological Data for Faults and Fractures That May Transect the Confining Zones 20 AAC 25.283 (a) (11) _ r�� � �� /'— ' .............,,,N.,,........s.N.,N,,,,,,,,,_____' fili co I i - - MPS-90 'cf, ° Ig. .k\i\N:\\\--so% \--*,,, X .6:96'0 1 4.11 \ '%4 ‘1' 47\ 0 1 i >\ Y .., \ '0„ \ % % \ \ ------ . iiiiiiiwar imh... . q, ..,._ 04 ....... , ___ _9, \ im-f .... „ , The map above shows the structur- .t the top of the Sag River interval (TVDSS).All faults shown are inferred from seismic data.The MPS-90 well did not encounter any faults during drilling. There are several faults based off of seismic data that are within the /2 mile radius of the MPS-90 wellbore. However, MPK'33andMP['23 (bothvertica|, hydrau|icaUyf/actured3agKiverproduceo, similar to what is proposed here) are similar distances to mapped faults and did not suffer containment issues. Horizontal principal stress from surrounding well data indicate that the fracture should propagate approximately NW-SE (SHmaxis NVV'3E, SHmin is NE-SW). Based on current mapping, the fracture wings should not extend into suspected faults. • Section 12—Proposed Hydraulic Fracturing Program 20 AAC 25.283(a)(12) Proposed Hydraulic Fracturing Program 1.) MIRU frac fleet. MIRU frac and slop tanks. MIRU CTU and associated equipment. Stump test CT BOPE, if possible. MIRU all ancillary support equipment. 2.) Fill frac tanks with fresh water. Heat water as needed. 3.) Lay all hardlines and manifolds. Install pressure monitoring equipment on wellhead and tree. 4.) RU 15K tree Saver and hard line. 5.) Pressure test all high pressure treating lines to 8000 psi. 6.) Set the GORV(gas operated relief valve) at±7,000 si. Set the staggered pump kickouts between 7,000 psi and 6,500 psi. Cg CG. 7.) Pressurize annulus to 2,000 psi. Set annular PRV at 3 00 si. 8.) Prepare frac fleet to pump. 9.) Pump Sag DFIT and analyze the results to obtain fluid loss coefficients. Adjust frac design. 10.) Fracture stimulate Sag interval with 16/20 mesh resin coated proppant in cross-linked gel. See "Pump Schedule"for proposed design. 11.) Under displace by 3 bbls. Do not over displace. 12.) Shut well in. RDMO. > /Un.. 4=5cp(xr,5=,) 13.) RU CTU BOPE and PT to 3500 psi. (Note:tictigfrnspectorroofBOP test giving 24 hours notice tom Alc 1-1 witness) fh,Pee 14.) RIH and cleanout frac sand/frac fluid to a portable test separator with filtered 2% KCI brine and N2 as needed to 9,750' MD. /4k/L 15.) POOH jetting liner and tubing clean. RD CTU. 16.) RU SL. Pull sleeve from XD sliding sleeve. Drift and tag tubing to maximum TD with GR/JB. 17.) Brush sliding sleeve. Shift sleeve open. Set jet pump. RDMO. 18.) Turn well over to operations. Pin ol2 � 70o) I�s III 4111 Frac Fleet Layout r 1 t' r' r t° 4m is ! Y L' :a. it IZ w11.03a- :. ,L_.7.- lib .:rr rr �1 iwil `' binCE:rttE ` '''', • ISMOL:0321 Stinger ®. _ Popoff/ MPS-90 )'1 Check .6 1. Vah+e Skid p yt=1213 i A Milne Point MPS-5C f&orp Energy 1. ,» n „� 1 stcsI .va I 4111 • 20 AAC 25.283(a)(12) (A) Estimated Total Volumes Planned Frac Pump Schedule PUMP SCHEDULE 7000 Slurry Rate 30 Highest Pump Tnp 6500 Well Name MPS-90 AFE 6700 Annulus Pressure 3000 Fluid Type YF130FlexD STEP FLUX) PUMP DIRTY VOLUME PROPPANT a TYPE RATE STAGE CUM STAGE CUM STAGE CUM SIZE (RPM) (BBL) (681) (GAL) (GAL) (IBS) (IRS) 1 WF130 30 100 100 4200 4200 2 YF130FlexD 30 300 400 12600 16800 3 WF130 30 150 550 6280 23080 ‘ Hard shutdown;monitor pressure. FLUID PUMP DIRTY VOLUME PROPPANT STEP AVERAGE TYPE RATE STAGE CUM STAGE CUM STAGE CUM SIZE 8 PPA (RPM) (BBL) (BBL) (GAL) (GAL) (LBS) (IBS) 4 YF130FlexD 30 200 750 8400 31480_,. 0 0 ._... 5 0.5 YF130FlexD 30 50 800 2100 33580 1,026 1,026 16120 CarboBond Lite 6 YF130Flex0 30 200 1000 8400 41980 0 1,026 7 1 YF130FlexD 30 50 1050 2100 44080 2,007 3,034 16120 CarboBond Lite 8 2 YF130F1exD 30 50 1100 2100 46180 3,845 6,879 16120 CarboBond Lite 9 3 YF130FlexD 30 40 1140 1680 47860 4,427 11,307 16120 CarboBond Lite 10 4 YF130Flex0 30 40 1180 1680 49540 5,673 16,980 16/20 CarboBond Lite 11 5 YF130FlexD 30 40 1220 1680 51220 6,826 23,806 16120 CarboBond Lite 12 6 YF130FlexD 30 40 1260 1680 52900 7,895 31,701 16/20 CarboBond Lite 13 7 YF130FlexD 30 40 1300 1680 54580 8,890 40,591 16120 CarboBond Lite 14 8 YF130FlexD 30 40 1340 1680 56260 9,818 50,409 16120 CarboBond Lite 15 9 YF130Flex0 30 40 1380 1680 57940 10,685 61,094 16120 CarboBond Lite 16 10 YF130Flex0 30 40 1420 1680 59620 11,498 72,592 16120 CarboBond Lite 17 11 YF130Flexl) 30 50 1470 2100 61720 15'326 87,918 16120 CarboBond Lite -Or.— 18 12 YF130FlexD 30 aik I 1520 2100 6380,g 16222 104,140 16120 CarboBond Lite 16 W1130 30 IIIF ,if:. 68810 104,140 19 Freezeprotect 15 3 „mgi -MI • • 7001 104,140 TOTALS 1 v. mi. NUIr 104140 • • 20 AAC 25.283(a)(12) (B)and (C) Frac Chemical Listing %kola Mask.%Lit Schlumberger RasinxIMM MPS 33 341M4 Pula StMe Alaska CulastvAMTOk tenth Slone Gumul101 Case: 61331003 13mistsure Tice: Pm-fob Wei Completed: 9/13/2310 Date Presume& 4/1/2010 5:20 PM ;Maud EX RP7-43700 Ackinive Adchtive Desolation Comentralicr r.1.C3 St.rfmlar-. 03 Gal/2030 GA MO Gri St".,:.,u,re a!erd 0.0 Gal j 1000 Gal 30.0 Eel 2.3 Lb/1000Gal 205_0 ib .C.04 C'c,I,-1,c• 2.2 Gal i 3.000 Gal 132 0 GO IfF13Ntesd):19c130 09,720 Gal .1831 GT...st ll.-e, 0.0 Gal/1000GO 4000 Gal 21 Cla,Cant-.:.)As.It 13 5017000 Gist 1300 GM *Mame 11 Os/1OCOGal - 223.0 1.6 PM722i 1 Bactericide OA Lb/200120id 300 Lb 9320-1020 i eraMIrOA0eld varied contentollan 1C4,2C0.0 Lb lbw idarlmodonsitttiotin fir dalltLatcnv misonastrao raasenatkagf*Mr am/WWI*.Ittelark ouppialsoLfisst. - Meter°admire/Ma Water Supplied beCherej• -114% 04-19-7Acetic acid limpuntyl 40.0001% , 01.411-1 24nniroartnitte-tvienettndethariaminium chlante c 1 SI 47-03-0 Pa39an-2-M , 10241-6 , 2,2',-andlontethanal c 0.1 31-- 201-21-1 Ethylene Gh A 0,1% 11/317-8 FimuMc add A 0.011 131-70-2 Ibitiontethillel c 0.1% 112-42-3 1-undecanal c 0.01% 127011-2 Audit ant pataseidia sok ...60003% 3310-73-2 — Sodium hydecitide c 01 16 ....----. --- , .--- - 3319-33-1 Iliwonateadddte 40.1% 1330-434 Bochum tetrathande 40.01% 2OM-2134 2inedetE2h-lanitinzola-one 40.0001% 7031-1163 Slike""Swat. -- -73 Micaodhjmfu.i 40.01% 7727-34-0 DianumaThms peninatisulphate 40.1% 7780-30-3 taariesindi disci& <0.00]% 90130-3430 Gam gum <1% 0002-940 polyfteminiaraethyrinvel c 0001 la 30443-33-3 Berk add <0.02% 10377-00-3 Magnesium ollrate 40101% 3446440-1 Cristobal* <0000]% 14107-96-0 _Mar es:lurn shade*Irate OMI3 40.001% 148084.0-7 _ quartz,Crystalkne Aids <0.0001% 2933672-0 Vas-Mena chlettcleimeihrlacryiate copolymer 40.02% 20277-33-4 3-Micro-2-rneth3i-24scOlam/M-3-0ne 4 0.002% 04742-47-8 misdates,petroleum,hydrotreated litibL (1% 63402-0134 CalTIMIL.trAterials and VOLITCS,Cbelltiali 0/1111-39-3 C12-23 alcohol ethymMated 40.01% 05333-300 , Maine nested smecate clay A GM 14 91039-39-3 Matomacemo eallls,calclnad 43301% 123003-17-0 Maar gum 4 0.001% .waren.,istausetal*Man*.Sakextrrrpev leapantermeno werWelt at tt4 oder alit Lew.gawk*v Wrahlamot Womormarte Vkli r.sp lama bane.Male*.Mr wetter*thReyernSe. .The matzo.4extretomf eisvnEnt 4 potrams441.4.44 as dr sorricoMon 4f thr WastrinIpeaalsh ro as achns hat ex 6 onvelettne Mamma=Ira*mon*a ORC-aservieri.at sf the daft Ltilarttsastast eapP441.4.Mr ton e apetallgyaN nor io erjhrstatto We simurrert. • 20 AAC 25.283 (a)(12) (D) Frac Design -See Page#6 (Note: Volumes and Weights may change slightly after Data Frac) Schlumberger FracCADE. STIMULATION PROPOSAL Operator : Hilcorp Alaska Well : MPS 90 Field : Milne Point Formation : Sag River Well Location : Milne Point County : North Slope State Alaska Country United States 0 Prepared for : Ted Kramer Service Point : Pill dtpe Bay Proposal No. : Business Phone : 907 659 2434 Date Prepared : 7 Sep 2016 FAX No. : 907 6.59 253R Prepared by : 4nther Rioinger Phone 907 273 178S E-Mat Address gruvingerPsib burl •/An Stattiepti Dn otyiroytt ii puemril it pit tot to Jr.."4.) pt.It ill I-too/tot,fIRMI Pttext)IT Its-tirr,itittirdimdis mit[C,,,fmn kp5/It Irt fAS104 NC iirrt II.o ttd140 totityr. (wit yomi Itto tlid Yid r.to k.,4u I,lii Pt aosar go*g gi 14441 4gAl no.01 141g..1.add T1VThM Ill nryits iittimis,rpt dirt{MA*/It Tt!Uvn,IPI t41MPP ti mrp04 m ts It ow,IC /*Itty P044,1.' ititallIttl lit 1,2,rtfit 71*I Ormolu goo no1 I Sstintslif*toil ltInl 114 ititid 14,481 nr'up$4 pill lOilI ta 0411 VA:Mel triter Ito Kato whey rittepLidet41 rt.611.MI ttiitt telt ti Mill It ri tit de UM COC1.51-.1ids III pitictritttyl witt 3 if tntioidirc,ty SIAWA.4 its Nemo,Ism 94:cnr1rtedefli ct Ps.*F Il%wow tr 441 err 11111.11 ittroit tod itt.1.13ii-rdi 51814*111514tIstit.4 OM%a ne.ria'al Ml to^Mill riCirAirrtfii071044 Wit el thOG.P.O.VO h II ION? 1 Ill MIt01 c.wifth P414+4 Quiff ir9 41.11141 Stk 04114 Vie rt., *Oho*NI4 .4141 Att ttpipt ylly tiOttliv 0),It4..4404c if g riro4.1.100 eivryv$ •"..,131.5tIllaafrr,l,Onel 'WTI,'+'1° S Tient Hilcorp Alaska Well MPS-90 Formation : Sag River D+suict : Prudhoe Bay Country : 43 o d Stata: games : 105kIbs Content Section 1: Wellbore Configuration _ _..__.__.__. _.._ .._._.______3 Section 2: Zone Data 4 Section 3: Propped Fracture Schedule _ _. -._..8 Section 4: Propped Fracture Simulation...................................._.__..._._..__.._.. Section 5: Propped Fracture Simulation Results Section 6: Fluid Descriptions __.._._.__..............._....12 Section7: Treatment Fluid Data........._.._......._.........._... ._..._.._.._.._........_. _..............._13 Section 8: Proppant Data _.......___.-___--...._.__.._14 Section 9: Hole Survey 15 7 • CtiEart Hilcorp Alaska Sclimlerier Weil MPS-90 Furnatun : Sag River Dario : Prudhoe Bay Country L trod t.cadcase 705klbs Section 1: Wellbore Configuration Bottom Hole Temperature 235 degf Deviated Hole.....,._.a .YES Treat Down ...................... TUBING Well Type _.__..._ .'articat Well Li)ratinn fnSMrr- Tubing Data OD Weight ID Depth fin! I hIfrl lint {ft} L 590 12.8 _3960 9573tt ; Casing Data OD Weight ID Depth Irnl 1HOP. ... _ _, 4H# 7 OM 26.1) 9.278 105964 Perforation Data Top Top Bottom Bottom Shut Number Diameter S-A OF-A- MD TVD MD TVD Dertsiiyr iftt lite (Rt lift Ishotftl tin! 96234 8791.2 %59.0 8826.5 6.00 216 11.37 3 • Ch cot : Hilcorp Alaska Sclimierger Well : MPS-90 fonrasion : Sag River Devitt : Prudhoe Bay Courtin/ : Onced Sates izaoLase : 105k1,s Section 2: Zone Data Formation Mechanical Properties Zone Name Top TVO Zone Frac Insitu Young's Poisson's Toughness It Height Sra d. Stress Modulus Ratio lusi 1111 {Pat psi ipsi) Kingak 8585.8 79.7 0.823 7099_ 2.957E46 0.36 1000 Kiagak 8665 4 69.5 0.833 7247 2-672E+6 036 1000 King!1_c_ 8734.9 29.6 0.843 7375 2.365E+6 0.37 1000 Sag 0 8764.6 5.9 0.715 6269 3.909E+6 026 1000 Sag D 8770.5 8.9 0.748 6564 3.118E+6 0.29 1000 Sag C 8779.4 4.9 0.767 6736 2.685E+6 031 1000 Saq C 8784.3 39 0.726 6379 , 3.852E+6 021 1000 Sag C 8788 2 3 0 1 0 709 6153 161E+6 0.25 WOO Sag , 8791.7 10 0.685 6073 4 295F 4 6 023 700 Sag 13 11794 1 15.7 C.680 5965 4 1191-t6 0_23 1200 Sag B 8809 8 4 9 0.696 6133 4 229E k6 024 1200 Sag 13 :114./ 2.9 0./10 6268 4.451E+6 016 700 SagA ;17_7 13.3 0./10 6265 4.313E+6 016 1200 SagA 8621.0 4.2 112 6289 4.630E46 026 1200 SagA 8835.2 1.8 0.745 6592 5.286E+6 0..29 1000 SaRA 8937.0 42 0.732 6470 4.887E+6 028 700 Shuhlit 86412 3.1 0.837 7401 6.739646 0.31 1000 Shublik 88413 20 0.867 7669 8.427E+6 0.31 1000 Shublik 8846.3 2.5 0.851 7529 0.2 ;646 0.32 1000 Shublik ;.8 3.3 0.831 7355 8,381E4-6 0.31 1000 Shublik 8852.2 6.1 0.731 6473 7.928E+6 028 700 Shublik 8858.9 52 0.687 7,262E46 023 1200 Shublik 8864.1 47 0695 6162 6.598E+6 024 700__ Shublik 8868.8 32 0.758 6724 1361E46 029 Shublik 8872.0 25.8 0.721 6406 5143E+6 0.27 700 Shublik 8897.8 8.8 0.776 6908 3.969E+6 0.32 1000 Shublik 8906.6 20.5 0268 6848 4.465E+6 ' 0.31 1000 Shublik 8927.0 7.6 0.719 6421 5.8;^:E4-6 027 1000 Shublik 8934.6 16.3 0.747 6680 5.148E+6 0.29 1000 SHALE 8951.0 7.4 0.839 7513 8394E+6 0.36 1000_ SILTSTONE 8958,3 161 0 777 6967 8.502E46 032 1000 S1LTS1ONE 8974.7 12.9 0.736 6610 6.121E+6 525 1000 SILTSTONE 8y.7,6 5.6 0.761 6842 7.282E+6 0.30 1000 SHALE 8993.2 5.1 0.696 6261 6.082E+6 0.24 1000 SILTSTONE 8998.9 13.6 0.744 6700 6.581E46 0.29 1000 DIRTY-SANDSTONE 9012,6 14.5 0.697 , 287 5.403E+6 025 700 DIRTY-SANDSTONE 9027.1 I 55.0 0.66660=M0 5.025E46 021 700 4 0 • Client : Hilcorp Alaska Sd mkerger Well : MPS-90 kirrauon : Sag River Det X1 : Prudhoe Bay Country : Lined States caczaw : 905ktbs Formation Transmissibility Properties Zone Name Top NU Net Penn Porosity Res. Gas Oil Sot. Water In) Height (Ind) ; -1 Pressure Sat. 1%1 ' Sat 1111 , iost) 1%1 1%1 Kingsk 85858 0.1 , 0-001 1.0 4037 65.0 10.0 25.0 Kings k 8665.4 0.1 0.001 IA 4072 65.0 ! 10.0 25.0 Kingsk _ 8734.9 _ 01 _,0_001 1.0 !)S 65.0 a 100 25.0 Se&D _.. : I00 4103 Y 650 10.0 25.0_ 8764$ IA 0.100 Sag D 17705 I.5 0.100 100 4107 65.0 10.0 25.0 Sag C 8779.4 2.0 0.100 10.0 4110 65.0 10.0 25.0 Sag C 8784.3 1.0 0.100 10.0 4112 65.0 10.0 25.0 Saa C 87. 2 0.1 0.001 10 4114 650 100 25.0 Sag.8 .. _,..._. __8791.2 2.5 1.SN 10.0 4115 65.0 10.0 25.0 Sag 13 8794,1 15.7 3000 14.0.,_:, , 4119. 65.0 10.12 25.0 Sag B 8809.8 4.9 8.000 ' 14.0 4124 65.0 10.0 25.0 Sag 8 14.7 2.0 2.000 a._ 1.2-0 4125 65.0 10.0 25.0 Sag A 8817.7 13.3 ` 8.000 14.0 4130 1 65.0 i 100 25.0 Sat:A 8E31.0 4.2 8.000 14.1) 4134 r 65.0 i 10.0 2i0 S3r,A 8635 2 0.5 0-100 100 4135 65.0 10.0 25 0 5a9A8837.0 30 2.000 12.0 4137 650 10.0 250 ShubA 88412 0.1 0001 10 4138 658 10.0 25.0 Shutti+k 86443 0I 0001 I.0 4140 65.0 10.0 25.0 S h u b le 8E463 1.0 0.100 10.1) 4141 65.0 10.0 25.0 Shublik 8E48_8 1 10 0.100 100 4142 65.0 10.0 25.0 Shub+1. 8E522 , 5.0 1.000 12.0 4144 65.0 10.0 1 25.0 i Shub ik 8E589 52 5.000 14.0 4147 65.0 10.0 25.0 , _ Shubl+k 8864.1 3.5 _ 1000 , 128 4149 65.0 109 25.0 Shublik . .18668 1A __0.100 - 108 4151 65.0 10.0 25.0 5hubik 88720 r 20.0 1000 120 4158 f 65.0 10.0 25.0 ' Shublik 88978 2.0 0.100 10.0 4166 65.0 10.0 259 i Shublik 8906.6 40 0.100 10.0 4173 65.0 € 10.0 25.0 Shublik 8927.0 2.0 0.100 10.0 4180 ' 65.0 i 10.0 25.0 Shublik 8934.6 5.0 0.100 10.0 4185 65.0 10.0 25.0 SHALE 00518 0.1 0.001 1A 4191 65.0 10.0 25.0 r �- ._.., SILTSTONEt 89583 20 0.1001 10.0 4196 659 100 250 SILTSTDNE l 8974.7 20 0.100 10.0 4203 65.0 10.0 25.0 SILTSTONE 8967.6 20 0.100 10.0 4207 65.0 10.0 25.0 SHALE i 89932 ' 0.1 0101 1.0 4210 659 10.0 25.0 SILTSTONE 8998.9 3.0 0.100 100 I 4215 65.0 10.0 25.0 DIRTY-SANQSTQNE 1 90126 120 1.000 , 100 4265 65.0 10.0 25.0 DIRTY-SANDSTONE 1, 9027.1 350 1.000 1 10.0 4325 650 : 10.0 1 250 5 • ID Client : Hilcorp Alaska Schlumlerger Wet : MPS-90 kefraZiarl : Sag River District : Prudhoe Bay Ccurnry : Cured 67atEs Lcadcase : 105klbs Section 3: Propped Fracture Schedule Pumping Schedule The tnllowirig is the Pump mg Schedule to achieve a propped fracture hag-length Of el of 301.1 ftwith an a eera w condar frilly IIC,wi of 2896 md.ft Jab Descriltion Step Pump fluid Name Step'luu7 1.1c1 Prop. Prop Name Nate Volume Conc. Type and Moth Cone, htil,,roin I oili.Lil 4r):-,0 I IPPAI PAD 33 0 010 lex() MO 30.0 000 OOPPA 3911 YF13041er0 2100 -300 0.00 PAD? 3011 1113311er0 5400 XI 0 UI)) I 3 PPA 3011 YFI30Fler13 2007 300 1h'20 Carbegcnd 1-rte II)) 21 l'I'A 3011 Y i 1334 le idi 1972 300 1628 C a rb a gond Lite 2(d) 3 0 PPA 3011 `it 1301 ler(' 1476 300 16,20 Carbe good L4e 300 411 PPA 300 YF130fler0 1417 300 1620 Garbo Dune lle L(d) 5 0 PPA 3011 '0 13171ex0 1364 30 0 - 1620 Carbefterid 1i.2 51)) 6OPPA 300 01301lei(0 , 1315 3110 1620Surbuttod Lw 603 7OPPA 330 ---Yiiiii le ID — 12601:::::300L TOO tiaAlteMTLac 700 8 OPPA 3)0 0130ifle47 1226 NO 1670 Ceiba Bend L4e SI)) 90 PPA 3011 Yi13071c0 1106 3110 16170 Carbe Bend Lrie 9.00 10 0 PPA 300 Yr1304 loll 1148 300 16'20 Cadre Bond Lite 10 011 110 PPA 3011 YF130FlexEl 1391 30.0 16/20 CarbeBend Lite 1110 12 0 PPA 3011 111331ler0 1350 3110 1620 Cerho geld lire 12111) Please note that this pumping siIedile is under-I Isere c ed hy-26 7 bt: Fluid Totals i! 353613,RI ci YI CI I:xt: P ro ppant Totals . 133300 l'.1 f.:1 1C C:1114 51:-le lt. ' --- I . b..:. , Pad Paireerktigati PAD Clean 46.7 %PAD Ouly 41.2 6 S 4110 Dent Hilcorp Alaska Sciiimkerger Wet : MPS-90 Foimution : Sag River Diana : Prudhoe Bay Country : United tcaocase : TOrthlbs Job Execution Step Step Cum.Fluid Step Cum. Step ' Cum. Avg. , Step Cum. Name fluid Volume Slurry Slurry Prop Prop Surlace , Thee Time Volume lgall Volume Volume il(4 90 Pressure ;mini filen) 21-3411) i . k' .,............,....- - P4D 8400 840 2000 200,0 0 ' 0 4326 83 53 0 0 PPA 2100 10500 500 250 0 0 0 4337 1.7 83 P )2 0-tV 18900 2000 4500 0 0 4326 6.7 15 0 1.0 PPA 2307 20907 50.0 500.0 2047 2007 4032 1.7 16.7 ' 2.0 PPA 1322 22829 500 5500 AM 5851 3955 1.7 18.3 3.0 PPA 1475 24304 4.0,0 5900 4425 10276 3967 1,3 19.7 4 0 PPA loll 2572) 40.0 630 0 5669 15945 4000 1.3 21.0 5 0 PPA 1364 27445 40,0 6700 6020 22765 4040 13 223 613 PPA 1315 21400 40.0 7100 7107 30552 4066 1,3 23.7 70 PPA 1259 29668 40,0 750,0 WM 39532 4069 1,3 25,0 .,,,..„........,_ 8,0 PPA 1226 30894 40,0 noo 9E05 49337 4058 13 2E3 90 PPA 11M 32079 40,0 8100 10670 50007 4079 13 21,7 10,0 PPA 1148 33227 40.0 870,0 11480 71418 4075 1.1 290 11,0 PPA 1391 36618 50,0 920.0 15301 :•.7t9 4046 1.7 30.7 rd. r, 12.0 PPA 1350 35968 5E0 970.0 16195 132984 4418 1.7 32.3 _ .. a Pumping Schedule Totals g V. Summery Our This Stage -o Average Pump Rate 30.0 bbl/min ‹ Volume Weighted Average Rate 30.0 bblimin g ry Total Fluid Volume 35968 gal Total Proppant Mass 103000 lb Total Slurry Volume 970.0 bbl Total Pump Time 32.3 min Fluid Based Totals for This Stage Average Volume I die. I uiai. I oia 1 total Fluid Pump Atighteil Fluid vi(ippon! Slurry Pump Rate Average Rate Volume , Moss Volume Time ibbiarliiii , lblif:iniul Nall 1 lit0 1131311 iminl YF13Cflex0 300 300 35968 I 102984 9700 1 32) Proppant Based Totals for This Stage Average Volume Total ' Total 7 Total Total Proppant Pump Weighted Fluid Proppant Slurry Pump Hate Average Rate Volume Mass Volume Time 1)111;Irnin I ibbt4nail ball OW 14411 (mini 16120 Carho 6ond Lire 30.0 3Q13 19168 102904 . 570.0 190 7 S • Chet : Hilcorp Alaska Wee : MPS-90 SchimMerger Fcerratipil : Sag River Distict : Prudhoe Bay Ccuritry : Lirml S'a7-7,3 Leaecpse : 1 05klbs Section 4: Propped Fracture Simulation The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo ID Verbco I model.Effective Conductivity and EN cave Fcd are calculated based on perforated intervals with Positive net heights. Initial Fracture Top TVO_______..._... 8794.1 ft Initial Fracture Bottorn TIM _„„,_.„ R809.8 ft il'4 '1 Propped Fracture Half-Length 3011 ft 'A Al- it.f4 q t ECU Hyd Height at Well 171 511 Average Propped Width 0.125 in Average Gel Concentration 845.4 Ilgrogal Average Gel Fluid Retained Facter....., 0.50 Net Pressure 1038 psi Efficiency . 0.329 Effective Conductivity 4635 md.ft cr, Effective Fcd 3.4 Mae Surface Promo (4448 psi e- 3 - -- g li Simulation Results by Fracture Segment from To Prop,Cant Propped Propped Inc Inc fracture OM 00 at End of Width Ileight Prop Gel Coot Conductivity r, Pumping tint ill') Conc. It.sl-ogoll Irld ft I T,P,i1 1P,172 OD 75 3 117 010 157,1 1L4 nt 4 3335 n 3 . 15C15 10 6 0 153 153 9 1 33 1 315 5 3535 1505 225 8 8 3 a 1 n 105 8 1 10 1 461.0 3773 225 8 , 331 1 179 0 060 660 05? ma a 1LE3 Propparid bridged at 2%ft after HI bhi in step 11 13 e • CGe t. : Hilcorp Alaska Stiim`eppan Wet : MPS-90 A 1l�jl fcma:on : Sag River )arc: : Prudhoe Bay Cc,my . .iced Sates .c : 105k1bs Fracture Geometry Data Per Zone for Production Prediction Tone Name Top Top Cross Net Fracture Fracture • Fracture MD ND Height Height Width Length Conductivity ti ;-, "i in {ti 1,nd h{ Krr-,Fic 341i0 8358 737 1 0.004 0 0 K rr,., 949 0 815 G E9 5 1 0 007 0 Ci K ngak 9560 0 8734.9 29.6 .1„ 0.031 . ., 234 6 724 Sag C 9596.0 "; 8764.6 5.9 1.0 0.066 273 3 1529 Sag C 9602.0 % 8770.5 8.9 1.5 0102 284.4 2340 Sag C 9611.0 : 8779.4 4.9 2.0 0.132 286.6 3028 Sag C 9616.0 ' 87843 3-9 1.0 0159 292 9 3651 Say C 9620.0 8788.2 3.0 .1 0183 2966 4173 Sag 8 9623 0 '8791.2 3.0 2.5 0.197 799.1 4496 Sag 8 9626.0 ?8794.1 15.7 15.7 0.218 301.1 4957 Sag 8 9642.0 8909. 4.9 4.9 0.215 298.3 4915 Sag 8 9647.0 14.7 2.9 2.0 0.205 295.1 4677 Sag A 916500 ..17.7 13.3 13.3 0.182 2E9.7 4124 t. Sag A 9663.6 8831 0 4 2 4 2 0.153 I 2805 3543 E' 5 0.135 2740 3131 E -,_.-......�_� 9667.9 88352 j ,..- .rv�,.,ae..,.,��.. Seg A 9669.7 . 5837. _ 4.2 . 3.0 0110 272.8 2559 Shublik 9674,0 88412 3.1 .1 0.089 267 9 21 5 ' Shubl4 9677.2 88443 2.0 .1 0.074 2252 1735 '^ Shu`$'ik 2S , 1.0 0.070 202.2 1653 -' Shu't? III • 0.1 : Hilcorp Alaska 111he1- Well : MPS-90 'I' {,�d foirm+assn : Sag River District : Prudhoe Bay Commit : 1'nrad Sar cadcase : 105klbs Exposure Time Prediction by Step Slop Noose fluid Name Pmni Ilu,d Perforation Exposure al [Rposure Hare Volume Iniechofr 8H51 of abercWaseh 7it:171 r1 ,:g II Temp. 235 degE temp.of {dFgF} ?mill 230degF {mull PAD YF13Cflex17 30.0 6100 171 4.9 4.9 OA PPA YF13Cflg:x0 30.0 2100 126 5.1 5.1 PAD2 YFIICFI_,xl] 300 MO 177 5,5 5,5 10PPA 1113011, 11 36.0 2007 131 6.8 5,8 2.0 PPA VI13Cflo(0 30.0 1922 106 2.1 2.1 34PPA YF13CfIExl 300 1475 99 00 0.0 ' 40PPA YFl30Iexll 30,0 1417 99 0.0 0,0 50PPA Yf130EIex0 30.0 1364 98 0,0 0A PPA YF131JIInx0 330 1315 98 0.0 ,, 09 70PPA YF1Xfkxt) 30.0 1269 97 00 00 5 J IPPA Y113CFIrx) 30 0 1226- 97 0 0 00 9 0 PPA YF l3Cflextl 30.0 118E 97 0.0 0.0 10:3 PPA YFl3Cfi?x0 30.0 1108 96 0.0 0.0 110 PPA YI 13Et xI) 30 0 1391 96 0.0 0.0 L. i 1i0PPA YF13Ctl>x11 300 1350 96 0,0 00 E 3 g V ti id 10 • Chet : Hicorp Alaska 1i it- 1_ Well : MPS-90 Formation : Sag River Dict : Prudhoe Bay Cauntri : died States Lcac:ass : 105kts Section 5: Propped Fracture Simulation Results II) ACL Fracture Profile and Proppant Concentration Pint FracCADE' a nbeelrn *MA UV III a it a ase t i3 f11iYase MR*'w rr0010.000 4,0.10 - R Xx eat\a!SdYrbormat Sdfirgialer It • • Client : Hilcorp Alaska Stlinkerger Well : MPS-90 Formation : Sag River District : Prudhoe Bay Country : Wind States toadcase : 105klbs 17) Treating Plot 5.fax-rc, /A .3/1 •VT, rip t 2 1.111111M— : 111111111111111111111 F t, 11.111•111M-aln Section 6: Fluid Descriptions 2%KCI brine • M117„Potassium Chloride 166.0016/mgal YFI3ORML) • J580,Gelling Agent 30 00!nil-Nal • L071,Tempora ry Clay Stabilizer ga Volga! • J150,Stabilizer 0.50 galimgal • UPS,Activator 2.00 galimgal • J00*,Crusslinker 2.50 gat:algal • F103,EZEFLO Surfactant 1.00 g Vmgai • M275,Micrebiecide 0.3D Ibirnga I • J569,ES-CLEAN Med Tame Breaker 1.00 Iblmga I VklE30 • M275,Microbiocide 0.50 lb/mgal • 1071,Temporary Clay Stabilizer 2,00 go lAngal • J580,Golfing Agent 30_00 Iblrogal • F103,EZEFLO Surfactant 1,00 ea Vmgal • J 569,ES-CLEAN Med Temp Breaker 1.031b1mga I 12 • • tient : HilcorpAlaska SekkmMerger Wet : MPS 90 fcematon : Sag River Device : Prudhoe Bay Ccvnvyr : untied States i.ca©rase : 105kbs Section 7: Treatment Fluid Data Flttd data is gr%er,et7.233 rod. 1 Fluid Name 12%KCI brio) f YF130FlexD I W1130 Friction Rate Lnwlthl mint 5.0 1.0 1.0 Pressure Lr=.visi,'10001t} 101) 20.0 1.2 Rate Pivot{ntUt ir} 25.0 10.0 30.0 Pressure Pivati::sif100flit} 400.0 400 75.0 Rale High it;tL!nirl ; 00 100-01000 Pressure Ht h{ at 10O0t) 10000 5000 3000 fluid Loss C.Iftlmin0.5) 10E40 5.5E.3 5.5= Spurtl9 a i1100ft2) 00 0.0 1.6 C11ttintin0.5) 2.6E-2 , 4.5E-3 5.0E-3 itMe)M!Y Ternperaturelder#1 235 235 235 Tme(hr) 0.0 0.0 01) Behavior Index IN'I 1.00 0.67 100 Consist Index(C)(Ihf.sA Mft21 5_21E4 4.81E4 2.09E-5 Viscosiiy,ShearHateIFPI _ 0250 ,295211 1.000 Shear Rafe 11s1 . ' 170 170 I l0 13 Ch eg t Hilcorp Alaska Well : MPS-90 " Diener crate : Sag River Disnict Prudhoe Bay Cc.ntry : tired Satsi izaecaw 105klbs Section 8: Proppant Data Proppant Permeability is calculated based on the following para meters- Bli Static Temperature: 235 degF Stress on Proppant 3585 psi Propped Fracture Conc.: 1.00 Ibitt2 Average Young's Modulus: 4.231E-Ofi psi Proppant Data Proppant Name Specific Mean Pack Permeability Gravity Diameter Porosity Old) tins Jordan Unirnin NM 25 0 022 350 131283 Carbotne W20 274 0 043 350 780540 16/20 CarboBend Lite 2 59 0.041 39.3 521400 Proppant Permeability Plot I P tappatt Pt Tv,.BUMF 1 Otos attImatt w MA. tt? maz Rat]• #0, MID -- ww , VIM MT WV 11X, aAI ,Ja izsn Xat St =11., S • cliefit : Hilcorp Alaska Scibmktpr Well : MPS-90 formation : Sag River Ostia : PTUCRI049 Bay Cooney : Wad Slates jcadase : 105klbs Section 9: Hole Survey D evia tad Hole YES Hole Survey Mt) ND ' Deviation Deviation Azimuth Azimuth Dogleg :to itti Angle Bead Rate Angle Build Rate Severity Ideal ide3i0010 Heil idea/1030 (deg/1091t) C 0.0 0.0 01 01) 0.0 01 100.0 100.0 0.4 OA 02 , 82 0.4 111 171.0 0.8 0.6 347.4 493 011 2610 NI.0 03 -OS 726-4 ' -134.4 1.1 350 0 3491 32 13 1803 -51.83A - , ...... 441.0 4403 5,1 2,1 1801 -02 11 5320 5313 5.7 , 0.7 1782 • -2.1 0.7 6210 619.9 ; 4.9 41 1791 11 0.9 7141 712.7 21 -23 184.0 4.5 2.3 $06.0 806.6 1.1 -1-8 192.0 85 11 8371 8353 ' 0.6 -13 196.5 155 1.7 'f-... 9291 9273 0,2 -04 2781 ;1 0 6 r, . -.. .k... 1023.6 1022.2 0.1 -01 3193 45.7 0.2 1111.4 1117.0 05 0.4 82 51,6 0.5 12113 12102 1.0 05 MO .110 0$ 1306.8 1305.4 1 1.5 OS 354.0 4.2 03 ‹. 1401.0 1399.6 1.6 0.1 357$ 31 0.1 5" 14931 1491.6 0.7 -1.0 2.8 , 5.6 1.0 1586.5 ' 1585.1 01 02 271 26.8 0.4 16803 167911 12 03 364 9.1 0.4 1774.5 ' 1773.0 Oh -01 74.0 40.0 0.9 1869.9 ', 1:.NA 05 -0.1 109.0 36.7 0.4 1963.8 1962.3 19 1.5 3101 -168_4 2.5 205.9 2056.0 7.1 55 3123 s 11 5.5 21514 2148.7 . 92 2.2 314/ 11 2.3 2244,4 2240.5 8.8 -0.4 313 4 -06 0.4 2338.0 23321 11,2 7 6 2133 -0_1 2.6 2427.2 24191 14,8 41 314$ 1.5 4.0 2522.1 2510.2 19.4 41 316.9 2.4 4.9 2615.0 25953 23.3 4.2 3161 -0.1 4.2 2709.2 2''•1.9 27.3 4.2 3161 12 4.2 2803.2 ' 2764.0 30.9 3.8 315.1 -1$ 3.9 28982 28431 341 39 3141 -03 31 2992.1 2919.3 385 4.2 3150 09 42 3385.4 2990.2 42.6 4.4 315.5 -0.1 4.4 3181,1 " 3058.4 464 4.0 3161 1.4 4.1 3269.0 1 3118.5 47.4 1.1 3172 05 1.2 15 0 • chot : Hilcorp Alaska hien : MPS-90 Stimierger ,crroyi : Sag River -2oc. : Prudhoe Bay CcAt/e : ...Iced S:aiss 105klbs Hole Survey MD TVD Deviation Deviation Aiitnuth Ai im oth Dogleg 11-0 IIII Angle Build Rate Angle Build Rate ' Severity flag1 idegl103t) Idegl IdEr000t, Ideg110011) 33615 3162.1 480 0.6 316.4 i -01 0.9 3456.0 3244.7 46.8 ..12 317.6 1.3 1.6 3549,0 331)9.2 . 45.3 -1.6 3175 -0.1 1.6 3642.5 ' 3374 7 458 0.5 3162 -09 0 11 3736.9 . 3440.0 46.8 1.1 316-5 -02 LI 38301 3503.2 48.5 - 1.8 315.9 -0.6 1.9 3924,7 3565 1 49.0 1 05 316 5 0 6 07 4016.2 . 3625.5 48.5 1 05 316.1 .0.4 0.6 4112.0 3689.2 48.0 .05 315.4 .0.7 01 4205.7 ! 3752.5 48.2 0.2 316.9 15 1.2 4360.5 1 38151 48.1 -01 317.6 07 0,6 - 4393.5 ' 3877.6 47.5 -08 318.7 12 II 44877 3941.3 47.2 -03 318 9 02 04 45811 40E6.0 45.7 -1.6 318 8 -01 1 6 CA C. 46133 4028.7 45.3 -11 316.9 0.3 1.3 e- 1691.3 4003.3 45.1 43 3201 2.2 1.6 :-.. 47850 4150.3 44.8 41 317 7 -31 2.2 g 4879.8 4217,1 44.3 -0.5 315 5 -23 1 7 ti 4973,5 42052 424 _ 2.0 312 1 -3.6 32 :..s. 5066.4 4355.1 40.1 -2.5 311.1 -1.1 2.6 < 5160.7 8428.0 36.6 -3.7 3099 -1.3 33 .,- 5256.5 4501.7 32.9 3.9 312_9 3.1 4.3 53493 4581.0 30.6 -23 313.1 0.2 25 5443.9 4668.4 29.8 43.8 312.2 -1.0 1.0 5537.8 4750.0 29.5 -0.3 311.3 -1.0 0.6 56312 4832.1 271 -2,0 310.4 -10 21 5774.0 4915.5 . 241 -3.8 310.1 -0.3 38 5814.9 4999 7 20.4 ! -4.1 3090 -0.3 4.1 5909.2 5089.1 ' 16.7 -3.9 302.6 .1.3 35 6002.4 5179.1 1 12.7 .43 310.2 1.7 4.3 6096.4 - 5271.5 , 89 -41) 311 1 10 40 6189.9 5364.2 - 56 -2 5 3Q72 -47 2.5 6284 2 54575 51 -I 6 297 3 -10.5 15 . , . _._ 6377.9 , 5551.4 ' 3 3 -IS 2713 -27.8 21 6472.7 , 5646.1 1.5 -1.9 239 6 -33.4 2-3 6566.4 5739.8 i 2.5 : 1.1 190.9 -52.0 2.0 6609.7 5183.0 i 3.4 . 2.1 186.9 -92 2.1 6655.7 5828.9 i 3.2 -0.4 182,6 -9.3 0.1 6750.2 i 5973.3 1 2.8 -0.4 185.5 3.1 0.5 6842.4 60158 j 2.5 -0-3 187 5 22 03 6936,4 ' 6109.3 1 2.1 -0.4 1990 12.2 0-6 16 • • Del : Hilcorp Alaska Stilmkerger Well : MPS-90 Ramon : Sag River Detact : Prudhoe Bay County : Lired S7arEs joaeas.e , 105klbs , Hole Survey i MD ND Deviation Deviation tuirtnith ' Azimuth Dogleg ' Ito Ott Angle Rudd Rate Angle Raild Rate Severity :thil-,f1CilYt) Ide01 Itle0110010 Oleg/10010 7030_2 i 6203.0 21 0 0 2003 1.4 0.1 7123.7 6296.5 : 2.4 0.3 1891 -12.0 0.6 7217.4 6390.1 21 0.3 185-5 -3-8 04 7311/ 64E4 2 78 (II 1113.11 -II 01 74021 6753 2,7 ' -01 1801 IA 0.1 _ ........._...._ 7498.5 610.9 ''. 2.6 -0 1 181.1 -42 02 7592.7 - 6765.0 2.6 0.0 183.3 2.3 01 7687.1 6859.3 2.5 -0.1 182.5 .0.8 0.1 7779.9 6952.0 2.3 -0.2 180.5 -22 02 7874.1 7046.1 21 -0.2 178.9 -1.7 02 7961.4 7133.3 2 0 -OA 181 1 25 0.1 --i . - 8055.6 72276 11 -02 189 1 85 OA 8149.9 ' 7321.8 1.6 -0.2 182.9 -6 6 0-3 8242.6 i 7414.5 1.6 1 0.0 183 7 09 0.0 8336.9 ' 7508.7 1.6 : 01 173,9 -10.40.3 1-.... ' 8431.6 76034 2.4 ' 0.8 175.3 1.5e" 01 .4 8526.5 7.t1::.1 3.9 ' 1.6 1739 -15 1.6 8672.3 i 77933 1 3.5 ; -04 176.4 23 0.5 87133 7888,0 3,0 : -0.5 171.3 -56 06 ---.- -...? : 7974 0 ! 2.7 -03 1815 13,7 0.8 8897.0 8068.1 : 29 1 112 193 1 10.2 0.5 8993.3 8161.2 ' 3.4 0.5 199.5 6.9 0.7 9082.1 8252.8 42 0,9 215.7 ' 11.6 1.4 91763 8346.8 3.7 J3.5 222.3 7.0 0.7 927031448.6 4.1 04 229.8 5.0 0,7 _ . 9363.3 85333 41 09 252.1 241 2.1 9458.3 ' 8627.9 52 03 257_2 5.4 06 9549.5 ` 8718.6 7.6 2.6 288.1 34.6 4 6 9645.8 8813.6 11.3 3.8 300.4 111 4.3 97391 8905.0 17.8 1.5 305.2 5_1 1.9 98106 i 8974-3 139 15 305.6 0.6 15 9905.0 9065.7 15.8 2.0 306.3 0.7 2.0 -...--, 9998.9 9155.9 15.9 0.1 3062 -01 0.0 10092 7 : 9244,1 151 , 00 305.9 -03 01 10186 0 i 9335.8 16.2 0.3 305.0 -1.0 0.4 10281.4 9427.4 16.6 0.4 305-2 6.2 0.4 103761 9518.0 1 16.9 0.3 305.0 -0.2 0.3 10465.4 9603.4 16.9 0.0 304.1 -1.0 0.3 105304 9668/ 164 -0.7 303.5 -01 08 106000 97325 . 164 0.0 3035 0.0 00 .. 17 • • 20 AAC 25.283(a)(12)(E) Maximum Anticipated Treating Pressure and Information Sufficient to Support a Determination that the Well is Appropriately Constructed for the Proposed Fracturing Program. From the Frac design modeling the highest anticipated well head pressure for the Frac job is predicted to be 4,448psi. The 7" liner below the packer set depth will be pressure tested to 4,500 psi for 30 minutes with 9.1 ppg brine. The 7" liner and the 9-5/8"casing above the packer set depth will be pressure tested to 3,000 psi. tom../ The 4-1/2" production tubing will be Pressure tested to 5,500 psi. ak— During the Frac.Job, 2,000 psi will be maintained on the back side of the 4-1/2"frac string/production tubing. Therefore the maximum differential pressure that the tubing will be subjected to should be 5,000 psi. (7,000 psi GORV Max Pressure Setting—2,000 psi on the casing by tubing annulus.) the calculated Maximum treating pressure is 4,448 psi. • • 20 AAC 25.283 (a)(12) (F) Designed Height And Length Of Each Proposed Fracture (i) the calculated measured depth and true vertical depth of the top of the fracture: 9,626' MD/8,794 TVD (Note: This depth is the predicted initialization depth of the fracture. The fracture is expected to grow both up and downward and may actually penetrate into the Kingak on the top and the Shublik shale below the Sag River formation but will not break through either shale.) (ii) a description of each method and assumption used to determine designed fracture height and length: The MP S-90 fracture stimulation was modeled using Schlumberger FracCADE program. The input parameters are attached. • • 20 AAC 25.283(a)(13) Post Fracture Wellbore Cleanup and Fluid Recovery Plan Post Frac well flow back will be to a tank either directly or through a portable test separator to bleed down pressure and clean up the well. Once well fluids have cleaned up,the well will be turned over to production and placed into the system. (Initial flowback fluids will be taken from the tank to the G&I disposal facility and injected.) Contingency: If the well does not flow back on its own,then a Coil Tubing Unit will be placed on the well and the well cleaned out using nitrified fluids. 4-,�' Coiled Tubing Procedure: -r— 121tir-e 1. MIRU CTU. N ' .. : '. . es ing BUP. 2. Pick up lubricator. Stab on to well. 3. Pressure Test BOPE to 250psi low/3,500psi high. (Note: Notify State 24 hours before test to give them an opportunity to witness.) Fill out state BOPE test form and submit within 5 days. 4. Open tree and count turns on valves. Record in ops cab. Start RIH, perform weight checks as needed. Coil tubing speed not to exceed 80 ft/min due to SLB standards of running in chrome tubing. 5. RIH w/ coil washing to Sliding sleeve protector. Pull sleeve protector. POOH W/same. 6. Make up coil connector pull test 25k. Make up Cleanout BHA with nozzle. RIH W/Coil at running speeds not to exceed 80 ft/min due to chrome tubing. Note: Min ID is 3.73" through seals of the packer. 7. Attempt to dry tag fill. Start cleaning out to PBTD. Come online with 2%safe lube if needed. This should aid with metal to metal friction. 8. Come online with N2 at 800-1500 scf/min and fluid rate of 1.5 bbls/min if needed to get good returns . Cleanout to PBTD at+/-9,750MD.Circulate hole clean. 9. POOH w/coil. 10. RDMO Coil Unit. 11. Turn well over to production. • • 1- I 2 E a z rE ct = x o m g 'C C., F w F- w ,P. '� '� o p.E O a CC Z a Ce Z w W a ve=x: m aSoiFc 1 m C .iIUUZO 6: 1 P.' , Iii ci a w ' C' mo v a V a •5 0 • Y • O e t NF • e �y� *� NN /, > 1:01 D04 V A � w w t 0 I— Ig l , p ® u o �TR ,Pa srrII. -1 la Y -E w Q 10 LL VF a v `uO � `v O O O m w fL ~ C a D Z a H CA f11 O O • • x I- w = w 0. .. g m J , eo m m b az g b en 0--- v v P4 v > 0 E,,,Gs o ac cc > — H a .Q C W K W K 7 '-+ R 3 3 a 3 a Iii W W n , v Z Z O a Z d >y w w a ❑ is > l7 wO . > > ro V' ^' w > 7 m v a , dr Pill I 'a c ( m +{ m FI C Y VO L , S — V c = W goug' O F v n x, ° n - kis u Mil mefru mv El II 3 A O O O WN Z •$ WQR F LT. 15 iiii 0 O O O m w m ~ 0C a V Z 4 1- _,J Y J m m 00 Q STANDARD WELL PROCEDURE Hilcorp Alaska,LIC NITROGEN OPERATIONS 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets(formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines,adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport.Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure),whichever is higher.Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 12/08/2015 FINAL v1 Page 1 of 1 • • Bettis, Patricia K (DOA) From: Ted Kramer <tkramer©hilcorp.com> Sent: Tuesday, October 25, 2016 10:01 AM To: Bettis, Patricia K (DOA) Subject: RE: MPU S-90: Hydraulic Frac Sundry Application Attachments: Copy of Well Table 10-24-16.xlsx; MPS-90_FRACSUNDRY_FAULT_TABLE.DOCX Patricia, Attached please find the well list you requested. Also attached is the updated fault list that you asked for as well. Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@alaska.gov] Sent: Monday, October 24, 2016 2:53 PM To: Ted Kramer Subject: RE: MPU S-90: Hydraulic Frac Sundry Application Ted, b)All wells that come into the Y2 mile cylinder drawn around any part of the S-90 well. Thanks, Patricia From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Monday, October 24, 2016 2:51 PM To: Bettis, Patricia K(DOA)<patricia.bettis@alaska.gov> Subject: RE: MPU S-90: Hydraulic Frac Sundry Application Patricia One more question. This seems to confuse a lot of people and I want to be clear that we get you what you want. You want a table and I believe I know what you want the columns to contain but are you wanting : 1 a.) All wells with a bottom hole Irocation within a % mile radius of the bottom hole location of S-90? b.) All wells that come into the%z mile cylinder drawn around any part of the S-90 well? Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. 0 907-777-8420 C 985-867-0665 From: Bettis, Patricia K (DOA) [mailto:patricia.bettis@aalaska.gov] Sent: Monday, October 24, 2016 2:04 PM To: Ted Kramer Subject: RE: MPU S-90: Hydraulic Frac Sundry Application Ted, Yes, all wells within one-half mile radius of MPU S-90 with the name, well type (Producer, injector) and its status (producer, injector, plugged and abandoned, shut-in, suspended. Thank you, Patricia From:Ted Kramer [mailto:tkramer@hilcorp.com] Sent: Monday, October 24, 2016 1:57 PM To: Bettis, Patricia K (DOA)<patricia.bettisPalaska.gov> Subject: RE: MPU S-90: Hydraulic Frac Sundry Application Patricia, Thanks for your e-mail. I want to be clear on what you are asking for. There are several wells that are that are drilled to more shallow horizons than S-90, but none that penetrate to the Sag River horizon or the containment intervals. Are you wanting a table of the more shallow wells? Sincerely, Ted Kramer Sr. Operations Engineer Hilcorp Alaska, LLC. O 907-777-8420 C 985-867-0665 2 • • From: Bettis, Patricia K (DOA) [mailto:patricia.bettis©alaska.gov] Sent: Monday, October 24, 2016 1:16 PM To: Ted Kramer Subject: MPU S-90: Hydraulic Frac Sundry Application Good afternoon Ted, Please provide an Excel spreadsheet or a chart that lists the names, well type and well status for all wells within the half- mile radius of MPU 5-90. A plat was provided with the application; however,the print was too small to read. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage,AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at(907)793-1238 or patricia.bettis@alaska.gov. 3 IIIPWELLNAME LLNUM Well Type (P/I/SI) • MILNE POINT UNIT S-1 INJ MILNE POINT UNIT S-2 INJ MILNE POINT UNIT S-3 Producer MILNE POINT UNIT S-4 INJ MILNE POINT UNIT MPS-05PB1 Producer MILNE POINT UNIT S-6 INJ MILNE POINT UNIT S-7 Suspended MILNE POINT UNIT MPS-08PB1 Producer MILNE POINT UNIT S-9 INJ MILNE POINT UNIT S-10 INJ MILNE POINT UNIT S-11 INJ MILNE POINT UNIT S-12 Producer MILNE POINT UNIT SC S-13 INJ MILNE POINT UNIT S-14 INJ MILNE POINT UNIT MPS-15 INJ MILNE POINT UNIT MPS-16 INJ MILNE POINT UNIT MPS-17 Producer MILNE POINT UNIT MPS-18PB1 INJ MILNE POINT UNIT MPS-19 Producer MILNE POINT UNIT MPS-20 INJ MILNE POINT UNIT S-21 INJ MILNE POINT UNIT MPS-24PB1 Producer MILNE POINT UNIT S-25 Producer MILNE POINT UNIT S-26 INJ MILNE POINT UNIT S-27 Producer MILNE POINT UNIT MPS-28PB1 Producer MILNE POINT UNIT S-29 Producer MILNE POINT UNIT S-30 INJ MILNE POINT UNIT S-31 INJ MILNE POINT UNIT S-32 Producer MILNE POINT UNIT MPS-33ALS INJ MILNE POINT UNIT MPS-33ASS P&A MILNE POINT UNIT S-34 Producer MILNE POINT UNIT S-35 Producer MILNE POINT UNIT MPS-37 Producer MILNE POINT UNIT MPS-41A Suspended MILNE POINT UNIT MPS-43 Producer MILNE POINT UNIT MPS-90 WSW MILNE POINT UNIT MPH-05 Producer MILNE POINT UNIT MPH-06 INJ MILNE POINT UNIT MPH-08A Dry Hole • • - co 1.0 1.0 CD t.13 tD +.+ I r -I em-I epi e--1 r-I' r-I em-1 I r-I i O r-I d 1 0 0 0 0 OI 1 O O! 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Ds v u -t,L. a �0 4 ° U v0 0 Q • • e 4•".I jj�� THE STATE Alaska Oil and Gas hamofALAS}( 1 Conservation Commission 333 West Seventh Avenue c GOVERNOR BILL WALKER Anchorage, Alaska 99501-35720`�" .-• � Main: 907.279.1433 ALAe/l Fax: 907.276.7542 www.aogcc.alaska.gov Bo York Operations Manager SCANNED FEB 1 4101Z Hilcorp Alaska, LLC 3800 Centerpoint Dr., Ste. 1400 Anchorage,AK 99503 Re: Milne Point Field,Ivishak Undefined WTRS Pool, MPU WISH S-90 Permit to Drill Number: 205-135 Sundry Number: 316-478 Dear Mr. York: 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 '. Foerster . - Chair DATED this 2� day of September,2016. RBDMS 1,vSEP 2 9 2016 • • AECEIVED STATE OF ALASKA sEP 16 Z016 tis a 2-?/ j7 ALASKA OIL AND GAS CONSERVATION COMMISSIONAOGGC APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations Q Fracture Stimulate ❑ Repair Well ❑ Kill Well with Coil Q Suspend ❑ Perforate ❑✓ / Other Stimulate ❑ Pull Tubing Q Complete Q Plug for Redrill ❑ Perforate New Pool , Re-enter Susp Well ❑ Alter Casing ❑ Other: Tri:- ; Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: R,,,,...„ Hilcorp Alaska LLC Exploratory ❑ Development ❑ 205-135 w G6y,��p1i k,-- 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service Q. 6.API Number: Anchorage Alaska 99503 50-029-23276-00-00 , 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 20AAC.25.055 I Will planned perforations require a spacing exception? Yes ❑ No 0 MILNE PT UNIT IVISH S-90 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL0380109/ADL0380110 ,, MILNE POINT/IVISHAK UNDEF WTRSP • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): .j PS d Plugs(MD): Junk(MD): ore;10,600' . 9,733' . 10,511' , •9,647' ,$*9911' 10,511' N/A Casing Length Size MD TVD Burst Collapse Conductor 113' 20" 113' 113' N/A N/A Surface 4,372' 13-3/8" 4,372' 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" 7,942' 7,114' 5,750psi 3,090psi Production 2,823' 7" 10,598' 9,731' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic t See Attached Schematic 5.5" 17#/L-80/BTC-M 4,012 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Baker HR ZXP Liner Packer and N/A . 7,795(MD)/6,967(TVD)and N/A 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch Q Exploratory ❑ Stratigraphic ❑ Development Q. Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 10/20/206 Commencing Operations: OIL Q , WINJ ❑ WTRSP ❑ Suspended El 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Ted Kramer Email tkramer©hilcorp.com Printed Name Bo York Title Operations Manager %- Signatur: Phone 777-8345 Date 9/16/2016 COMMISSION USE ONLY Conditions of app oval: Notify Commission so that a representative may witness (� 4/7Sundry Number. Plug Integrity ❑ BOP Test Mechanical Integrity Test ❑ Location Clearance ❑ Other: at 3 coo f ._ r- (fief n (c s t- 'AC` 'e J l j .,. '2v f'S.: C-c�.S :A j �,e_S f- /`r.�j c�Z•^t J n ..L.,�,p Cv 11 Lz Post Initial Injection MIT Req'd? Yes ❑ No ❑ rel C1 f Y ( Lz�� t�i Spacing Exception Required? Yes ❑ No 4 Subsequent Form Required:, /d -`I 0-"t RBDMS L1, SEP 2 9 2016 APPROVED BY Approved by: aie€7/9,P,M41.6,4______ COMMISSIONER THE COMMISSION Date:-•27-/$ OftteitItstopc ta.fd Submit Form and Form 10-403 Revised 11 015 for 12 months from the date of approval. Attachments in Duplicate • • • Well Prognosis Well: MPS-90 FIilcorp Alaska,LL Date:9/15/2016 Well Name: MPS-90 API Number: 50-029-23276-00 Current Status: SI Water Source Well Pad: S Pad Estimated Start Date: October 20, 2016 Rig: ASR# 1 Reg.Approval Req'd? Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 205-135 First Call Engineer: Ted Kramer (907)-777-8420 (0) (985)-867-0665 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) AFE Number: 1621135 Current Bottom Hole Pressure: 3,654 psi @ 7,971' TVD (Based on SIBHP in the Ivishak 03-22-2012). Maximum Expected BHP: 3,654 psi @ 7,971' TVD (Based on SIBHP in the Ivishak 03-22-2012). Max. Anticipated 34--:"H .7$Y dt P�(Ivishak SITP from WSR dated 8/29/16) Surface Pressure: 350 psi Max.Anticipated Surface Pressure Sag River: —100 psi (Sag River after perforating —With 9.1 ppg fluid and pressures observed in MPU C-15 after perforating the Sag River Formation.) Brief Well Summary: The Milne Point S-90 well was drilled in December 2005 as a Ivishak Water Supply Well. The well was tested and then SI and never produced due to an elevated C0,2_coMttent. This well is currently on the Long Term Shut In List. v' RWO Objective: This workover will involve plugging the well back from the Ivishak to the Sag River Formation. The Sag River r Formation will be perforated, hydraulically fractured, and then completed as a jet pumped producer. cd^i 4--- 1;-4-- This Sundry will cover the workover to prepare the well for the fracture stimulation. A separate Sundry will be submitted for the actual Frac Job./ Pre-Rig Procedure: (Non -Sundry Work) 1. MIRU Coil Tubing Unit. 2. Test BOP to 4,000 psi. (Note: ► ' . :. = .. - .: .. - - :: ' - -to-give-them an opt.. xt.0to—wi `ness.) �%�'� y; �: qtr tt �-j , 3. Send BOP test report in to AOGCC within 5 days. 4. RIH with Coil tubing to 9,800'. Circulate 9.1 ppg kill fluid to (Note EMW=9.1 PPG). Connect to back side. Circulate the 5-1/2"X 9-5/8" back side with 9.1PPG fluid pumping down the annulus 51,41-t 0 and circulating up the 5-1/2" kill string. POOH With Coil tubing. � 5. RDMO CTU. 6. Clear and level pad area in front of well.Spot rig mats and containment. 7. RD well house and flowlines. Clear and level area around well. 8. RU Little Red Services and 500bbI returns tank with choke manifold. Well Prognosis Well: MPS-90 Hilcorp Alaska.LL Date:9/15/2016 9. Pressure test lines to 3,500 psi. 10. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. 11. RD Little Red Services. 12. Set BPV. RU crane. ND Tree. NU 13 5/8" BOPE. 13. NU BOPE house. Spot mud boat. RD Crane. WO Rig Procedure: (Sundry Work) 14. MIRU ASR# 1 Rig, ancillary equipment and lines to 500 bbl returns tank. �F.i.-= 15. Check for pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill hv well w/9.1 ppg seawater prior to pulling BPV. Pull BPV Set TWC. a. Test BOPE to 250psi Low/3,500 psi High, annular to 250psi Low/2,500psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. b. Perform Test per ASR#1 BOP Test Procedure dated 11/03/2015. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test rams on 3-1/2, 4-1/2" and 5-1/2"test joints. e. Send BOP test report in to AOGCC within 5 days. 16. Contingency: (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.) a. 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 test. j1.I� b. With stack out of the test path,test choke manifold per standard procedure. � dU" c. Conduct a rolling test: Test the rams and annular with the pump continuing to pump, (monitor 'r,t°V 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. 17. a leed any pressure off casing to 500bbI returns tank. Pull TWC. Kill well w/+/-9.1 ppg brine as needed. 18. PU landing joint and BOLDS. 19. Pull over string weight on tubing hanger and confirm free . LD tubing hanger. 20. POOH and lay down 4,012' of 5-1/2" 17#L-80 IBT-M kill string. If visual on the pipe is good, send pipe in for inspection. 21. PU RIH with a 9-5/8" C/O assembly on 3-1/2" WS. RIH to 7,786'. Circulate hole clean and POOH. 22. PU RIH W/7" 26#C/O assembly on 3-1/2"WS to 9,860'. Circ. Hole Clean. 1.,,,v4i/ 23. PU RIH with a 7" cement retainer and set @ 9,850' ( 34 ft above the top Ivishak perforation). Well Prognosis Well: MPS-90 Hilcorp Alaska.LL1 Date:9/15/2016 24. RU Cementers and Pump cement through the retainer equal to the volume to displace with cement/ from the retainer to 100' below the bottom Ivishak perforation (+/-22 bbls). Then un-sting from the retainer and lay 100' of cement on top of retainer(+/- 4 bbls). PU and reverse out to a tank to clean up the tubing POOH with WS. Note: Hilcorp asks for a variance from 20AAC25.112(c)(1)(D) since Hilcorp plans to set the retainer less than 50 feet above the top perforation of the Ivishak formation. This location was selected to take advantage of very good cement on the outside of the 7"casing at this depth for setting the retainer. �c.�,�' �e��r.�•sa�lt v je 25. While waiting on cement, RU E-line. PU Junk Basket,full Gauge Ring(GR)for 7" 26#casing (to 1:> v check for cement stringers) Gamma Ray, CCL. RIH and Tag TOC. Record depth and log out of well ,vv to surface for a tie in log( log lower portion of hole at a slower speed, 30—60 fpm up to the TOL @ t x'7,786'. Speed can be increased from there up to surface.). PU Caliper tool, Gamma ray, and CCL. RIH with Caliper tool to 5,000'. Tie in log and run Caliper Log in the 9-5/8" casing from 5,000'to surface. RD E-line. Note: Log needs to be processed and returned to the Operations Engineer ASAP. If casing wall loss greater than 40% is identified,then a new plan will need to be formulated. 26. If the TOC tagged in step#25 is higher than 9,750', PU Bit on WS and RIH on WS to dress off cement to 9,750'. Circ clean. If TOC is lower than 9,750', Contact Operations Engineer to discuss plan forward. Operations Engineer will discuss option with AOGCC. A waiver may be requested at that time from AOGCC. ---"P 4s1' 27. PU RIH W/7" Test Packer to 9,540'(+/-). Set and pressure test casing down the tubing to 4,400 psi �� . (need 8,500 psi @ mid perf depth of 9,641 (8809 TVD)for Frac job) on chart for 30 min. Bleed down pressure. giasces `=>� 28. Change pump over to back side. Pressure test back side to rA4psi on chart for 30 Min. R4,1' • Note: Backside test pressure will be determined by calculation based on caliper log in Step#25. Release pressure, POOH with test packer. a. Contingency: If the well does not test, notify the Operations engineer who will notify the AOGCC. i. Develop new path forward. 29. PU RIH with 4-1/2" completion to the setting packer depth of 9,540' (+/-). Note: TOC @ 8,680' (860' below TOC and 56' above the top of the Sag River). 30. RU Pump to back side. Pump corrosion inhibitor down Back side (370 Bbls)followed by freeze protection (123 bbls). Note: Well will be out of balance (pressure on back side) due to freeze protect fluid. 31. RU E-line. PU RIH with Evo-Trieve (tubing set bridge plug)to 9,558' and set. RD E-line. 32. Pressure up on packer setting same according to manufacturer's procedure. 33. Pressure test tubing to 5,000 psi for 30 minutes on chart. (Note: Tubing test pressure may need to be adjusted based on results of caliper log in step#25.) 34. Space out seal assembly. 35. Pressure test back side to same pressure as Step#28 psi on chart for 30 min. Bleed down pressure. 36. ND BOP, NU Wellhead and test to 5,000 psi. 37. RDMO ASR# 1 Rig. • Well Prognosis Well: MPS-90 Ililcorp Alaska,LI) Date:9/15/2016 38. Turn well over to Production to perforate. Perforating 39. RU E-line. Pressure test lubricator to 3,500 psi. 40. RIH and Retrieve Evo-Trieve bridge plug @ 9,558'. POOH with Same. 41. RIH W/3.60"Gauge Ring to ensure spent perf guns will pass through production tubing and packer to 9,570'. POH W/GR. ?oitit 42. PU RIH with 3-1/8" e-line guns and perforate the Sag River Formation from 9,623—9,659' (36 ft, adjusted for the Gamma Ray/CCL log ran in Step#25. (Note: Make sure log is corrected for depth by Anchorage geologist). Four runs will be required. POOH W/Eline. 43. RDMO E-line unit. Turn over to Frac operation. si, Attachments: cra ,QAC • 1. As-built Schematic 2. Proposed Schematic 3. Wellhead Drawing Sc•ZS-/i6 4. BOP Schematic 5. Fluid Flow Forward 6. Fluid Flow-Reverse 7. Fluid Flow Diagram—Bleed to Pits la III • Milnll:e PointMP Unit5-90 We SCHEMATIC Last Completed: 12/3/2005 Ililcorp Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 7-1/16" 5M • 13-3/8"x 7"FMC 5M w/7"TC-II T&B Tubing 20 4` } Wellhead Hanger,7"CIW Type"J"BPV Profile , OPEN HOLE/CEMENT DETAIL e 20" 260 sx Arctic Set(Approx.)in a 42"Hole u,� 413-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole ,., " 9-5/8" 723 sx Class'G'in a 12-1/4"Hole r 7" 393 sx Class'G'in a 8-1/2" A , ti. CASING DETAIL x_3/8" Size Type Wt/Grade/Conn ID Top Btm BPF 2 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cementer 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5,218'-0 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 5-1/2" Tubing 17/L-80/BTC-M 4.892" Surf 4,012' 0.0233 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 3,956' 5-1/2"HES X-Nipple(4.455"Profile) 2 4,011' 5-1/2"WLEG 9-CR-Bottom @ 4,012' 3 81A86' 9-5/8"x 7"Baker Liner Tie Back Slv 4 • 7,795' 7"Baker HR ZXP Liner Packer 5 7,805' 7"Baker Liner HMC Hanger 6 9,801' IBP-Installed in 2013 PERFORATION DETAIL 7 Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 4505 PowerJet HMX,HSD,5SPF,72 Deg.Phasing GENERAL WELL INFO API:50-029-23276-00-00 Cased&Completed by Doyon 14 -12/3/2005 NOTE There is a spliced section in the 9-5/8"casing from the cut @ 1,939 to the baker cutlip guide assembly @ 1,965.This splice was pressure tested to 3,500psi for 30 min.and passed 9-5/8" i 3,4&5 RA Tag 9,638' to 9,658' RA Tag 9,743' to9,762 _, , 6 Ivishak 7 _.. TD=10,600'(MD)/TD=9,733'(TVD) PBTD=10,511'(MD)/PBTD=9,647'(WD) Revised By:TDF 8/2/2016 li • Milne Point Unit • Well: MP S-90 PROPOSED Last Completed: 12/3/2005 Ililcorp Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 4-1/16"- SM Wellhead 13-3/8"x 4"FMC SM w/4"TC-II Tubing j ,20 Hanger,7"CIW Type"J"BPV Profile OPEN HOLE/CEMENT DETAIL 20" 260 sx Arctic Set(Approx.)in a 42"Hole 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 1 9-5/8" 723 sx Class'G'in a 12-1/4"Hole 7" 393 sx Class'G'in a 8-1/2" CASING DETAIL 13-3/8" ' ', Size Type Wt/Grade/Conn ID Top Btm BPF 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HESCemente 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5,218' ►O A 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surface ±9,750' 0.0152 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' E Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 ±2,200' GLM(Dummied Off)-ID=3.833" 2 7,786' 9-5/8"x 7"Baker Liner Tie Back Slv 3 7,795' 7"Baker HR ZXP Liner Packer 4 7,805' 7"Baker Liner HMC Hanger 5 ±9,430' Pressure Discharge Gauge-ID=3.855" 6 ±9,438' Sliding Sleeve-3.813" 7 ±9,448' Pressure Intake Gauge-3.855" 8 ±9,514' X-Nipple-3.813" 9 ±9,540' Bakers-3 Packer-3.73 10 ±9,564' Baker Ball Shear Sub 11 ±9,850' CIBP 12 10,281' IBP-Installed 2013 PERFORATION DETAIL Ivishak Top(MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status Sag River ±9,623' ±9,659' ±8,791' ±8,827' ±36' Future Future 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated 9-5/8'J . 2,3&4 Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 4505 PowerJet HMX,HSD,5SPF,72 Deg.Phasing 5 GENERAL WELL INFO 6 ate7 API:50-029-23276-00-00 al 8 Cased&Completed by Doyon 14 -12/3/2005 -b I.-, 9 NOTE 10 ��LS`` There is a spliced section in the 9-5/8"casing RATag 9,63t3' Sag Proposed1l from the cut @ 1,939 to the baker cutlip guide to 9,658' ,iv assembly @ 1,965.This splice was pressure RATag9,743' TOC@±9'750 tested to 3,500psi for 30 min.and passed to 9,767 k'4. 11 -Ivishak 12 r &lair, « . TD=10,600'(MD)/TD=9,733'(TVD) PBTD=10,511'(MD)/PBTD=9,647(TVD) Revised By:TDF 9/16/2016 • • WELL MPS,_90 DATE 5-23-16 lit 'larval)Alaska,1,1,(; 'tet i ,i Tree Cap.Otis style,7 1/16" 1�„;:\ 9h"Acme thrd it VtAf Swab valve CIW Model FL,7 '[4:50\-.11i 1/16"SK,FE,DD L-U � � s 11'6” . _... Wing valve CIW Model FL,7 7._4",a 1/16"5K,FE,DD L-U '`'r$9. SSV valve Cameron FL;7 1/ 16"5K reverse actuating gate valve,EE,P512,PR2 w/ Otis actuator 0 - s, 1 Master valve CIW Model FL, 7 1/16"5K,FE,00 L-U 3'5" Thg Hd Adpt,FMC SM- -_- E-CL,13 5/8"x 7 1/16" IIIIIIIIII :,' . API 13 5/8°'5K I . _' �,;:,, 1 a 1 - .qt '` pa. API 13 5/8"5K = ... LT1z'! I u { 1 ,-.0 1I1 • . fliMie Point ASR 13-5/8" BOP Hap.".kl:E.:,,ii C: 03/07/2016 .17, .., ::-: : . i11 l 1 I it III 1/1 fill iii ....... Hydril 13 5/8" 5M I1 111 til lit Al v - UI ilijil...1 III L Spacer Spool 13 5/8" 10M x 13 5/8" 5M 11i1 11t 1111111 :1 Shaffer i-i I Co 2 7/8" x 5" VBR Rams . a j _ C' . a 13 5/8" 5M1.. . 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C CO Z CO Y a • 'II' . ce W - Y o m ¢ O Y Y < H� aE 2 1 2 Y 9>1 Y •• • § § Y Y w i Ln a. ce a vE 0 a an a I a1c o = u iEl 3. u S RECEIVED STATE OF ALASKA AUG 19 2010 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS A G 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations Q Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q / Other Stimulate ❑ Pull Tubing Q Complete Q Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Plug Back 0 2.Operator Name: 4.Current Well Class: 5.prmit to Drill Number: Hilcorp Alaska LLC ' Exploratory ❑ Development ❑ X05-135 ' 3.Address: 3800 Centerpoint Dr,Suite 1400Stratigraphic ❑ Service ` an /6.API Number. Anchorage Alaska 99503 50-029-23276-00-00 7.If perforating: aO Al.G as 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 1. • D'►% Will planned perforations require a spacing exception? Yes ❑ No Ogg MILNE PT UNIT IVISH S-90 9.Property Designation(Lease Number): 10.Field/Pool(s): IP ADL0380109/ADL0380110 . MILNE POINT/IVISHAK Dr F WTRSP • 11. PRESENT WELL CONDITION SUMM;i- Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD SP(psi): Plugs(MD): Junk(MD): 10,600' ` 9,733' ' 10,511' 9,647' 4) 8,000 10,511' N/A Casing Length Size MD* V TVD Burst Collapse Conductor 113' 20" 11 4.,, 113' N/A N/A Surface 4,372' 13-3/8" 4,3 3,863' 5,020psi 2,260psi Intermediate 7,942' 9-5/8" i1 7,114' 5,750psi 3,090psi Production 2,823' 7" �10• 8' r� 9,731' 7,240psi 5,410psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubi ze: Tubing Grade: Tubing MD(ft): See Attached Schematic/ See Attached Schematic % 5. " 17#/L-80/BTC-M 4,012 Packers and SSSV Type: ,, V tr.. kers and SSSV MD(ft)and TVD(ft): Baker HR ZXP Liner Packer and N/A P , , 7,795(MD)/6,967(TVD)and N/A 12.Attachments: Proposal Summary ❑✓ Wellbor`r>a emati• H 13.Well Class after proposed work: 1137 Detailed Operations Program ❑ BOP S -t.1.0 Exploratory [ Stratigraphic ❑ Development[4 Service ❑ 14.Estimated Date for _ 15.Well Status after proposed work: Commencing Operations: 9 X16 OIL ❑✓ WINJ ❑ WTRSP ❑ Suspended ❑ 16.Verbal Approval: Dat--* GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true a the procedure approved herein will not be deviated from without prior , ritten approval. Contact Ted Kramer 0id?' Email tkramer0.hilcorD.com Printed Name • York Title Operations Manager Signature '`vr �ju '-I), Phone 777-8345 Date &I 5 )i a,-b COMMISSION USE ONLY Conditions of approval: Notify C,mmission so that a representative may witness Sundry Number. 3\LQ — �,2v O Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ I Other: SCANNED JAN w1 0 201 Post Initial Injection ',IT Req'd? Yes ❑ No ❑ RBDMS kir AUG 3 0 2016 Spacing Exceptio ,-equired? Yes ❑ No r, Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: OR+GpiliNoAtd Subs in Form ane Form 10-403 Revised 1112015 for 12 months from the date of approval. Attachments in Duplicate Well Prognosis Well: MPS-90 Hilcorp Alaska,Ll) Date:8/19/2016 Well Name: MPS-90 API Number: 50-029-23276-00 Current Status: SI Water Source Well Pad: S Pad Estimated Start Date: August 1, 2016 Rig: ASR# 1 Reg.Approval Req'd? Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts Permit to Drill Number: 205-135 First Call Engineer: Ted Kramer (907)-777-8420 (0) (985)-867-0665 (M) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) AFE Number: 1621135 Current Bottom Hole Pressure: 4,100 psi @ 8,719' TVD (Based on the Sag River Pressure observed in MPC-15.) Maximum Expected BHP: 4,100 psi @ 8,719'TVD (Based on the Sag River Pressure observed in MPC-15.) Max. Allowable Surface Pressure: 3,229 psi (Assuming Gas gradient of 0.1 psi/ft.) Brief Well Summary: The Milne Point S-90 well was drilled in December 2005 as a Ivishak Water Supply Well. The well was tested and then SI and never produced due to an elevated CO2 content. This well is currently on the Long Term Shut In List. RWO Objective: This workover will involve plugging the well back from the Ivishak to the Sag River Formation. The well will be perforated, hydraulically fractured, and then completed as a jet pumped producer. This Sundry will cover the workover to prepare the well for the fracture stimulation. A separate Sundry will be submitted for the actual Frac Job. Waiver Request Hilcorp is requesting a Waiver in step# 19 of 20 AAC 25.112 (c)(1)(E) which requires a mechanical bridge plug be set no more than 50' above the top of a perforated interval that is to be abandoned. Hilcorp will be setting an easy drill bridge plug (differential pressure rated at 10,000 psi) at(+/-) 9800'which is 84'above the existing perforation. This is due to an inflatable bridge plug installed at 9801'. Hilcorp will then place 75' of cement on top of the plug. The 75' of cement to be placed inside of the casing corresponds to 45' of cement on the outside of the pipe showing cement bod that is excellent to good and the remaining 30' showing fair bonding according to a Sclumberger USIT log ran in the well dated November 27, 2005. Pre-Rig Procedure: 1. Clear and level pad area in front of well. Spot rig mats and containment. 2. RD well house and flowlines. Clear and level area around well. 3. RU Little Red Services and 500bbl returns tank with choke manifold. 4. Pressure test lines to 3,000psi. 5. Confirm well is dead. Freeze protect tubing/casing as needed with 60/40 McOH or diesel. Well Prognosis Well: MPS-90 ililcoi p Alaska,LLI Date:8/19/2016 6. RD Little Red Services. 7. Set BPV. RU crane. ND Tree. NU 11" BOPE. 8. NU BOPE house.Spot mud boat. RD Crane. WO Rig Procedure: 9. MIRU ASR# 1 Rig, ancillary equipment and lines to 500 bbl returns tank. 10. Check for pressure. If needed, bleed off any residual pressure off tubing and casing. If needed, kill well w/8.5ppg seawater prior to pulling BPV. Pull BPV Set TWC. a. Test BOPE to 250psi Low/3,000psi High, annular to 250psi Low/2,500psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. b. Perform Test per ASR#1 BOP Test Procedure dated 11/03/2015. c. Notify AOGCC 24 hrs in advance of BOP test. d. Test rams on 3-1/2, 4-1/2" and 5-1/2"test joints. e. Send BOP test report in to AOGCC within 5 days. 11. Contingency: (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.) a. 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 test. 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 v 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. 12. Bleed any pressure off casing to 500bbl returns tank. Pull TWC. Kill well w/8.5 ppg seawater as needed. 13. PU landing joint and BOLDS. 14. Pull over string weight on tubing hanger and confirm free . LD tubing hanger. 15. POOH and lay down 4,012' of 5-1/2" 17# L-80 IBT-M kill string. 16. PU RIH with a 9-5/8" C/O assembly on 3-1/2" WS. RIH to 7,786'. Circulate hole clean and POOH. 17. PU RIH W/7" 26#C/O assembly on 3-1/2" WS to 9,801' to tag IBP. (Note: If IBP is not there, continue in the hole to 9,860'.) Circ. Hole Clean. 18. PU RIH with a 7" plug and set above the IBP (9,800 '+/-) (Note: If IBP is not there, we will set the CIBP deeper (9,860+/-).) Release from plug. 19. Spot 75' balanced cement plug from 9,800' to 9,725'. Note: Hilcorp asks for a waiver from setting 2 .112 c 1 E . The CIBP when v topperforated interval 20 AAC 5 the plug no more than 50' above ( ( )( )( )) set at 9,800' will be 84' above the top existing Ivashak perforation which Hilcorp wants to isolate. ✓ Well Prognosis Well: MPS-90 Uncurl)Alaska,LU Date:8/19/2016 20. RU E-line. PU RIH with Caliper log to 9,700'. Run Caliper log from 9,700'to the 7" liner top at 7,786'. POH with Caliper log. 21. PU RIH W/7" Test Packer to 9,000'. Set and pressure test casing to 3,500 psi on chart for 30 min. POOH with test packer. a. Contingency: If the well does not test, notify the Operations engineer who will notify the AOGCC. i. PU a 9-5/8" test packer and RIH to 7,700 ft.to eliminate the liner top and re-test. If still does not test, progress up hole W/test pkr. locating the leak. Determine new path forward. 22. PU RIH with pump out sub,X-nipple, Production packer,gauge and TEC wire, GLM on 13Cr tubing until packer reaches a depth of 9,531'(+/-). Note: TOC @ 8,680' (851' below TOC). 23. Space out seal assembly. 24. Drop Ball, Pressure up on packer setting same according to manufactures procedure. 25. Continue to pressure up tubing to Shear Ball Sub. 26. Pressure test back side to 3,500 psi on chart for 30 min. Bleed down pressure. 27. RU E-line. RIH W/3.60"GR to insure spent perf guns will pass through production tubing and packer. To (+/-) 9,570'. POH W/GR. 28. PU RIH W/WRP to 9,550' (+/-) and set. Pooh W E-line. 29. Pressure up on Tubing to 4,800 psi. (+/- but do not exceed 5,000 psi.). Achieve a 4,500 psi tubing pressure test for 30 min on chart. Bleed down pressure on the tubing. 30. RIH W/ E-line and retrieve Plug. 31. PU RIH with 3-1/8" e-line guns and Perforate well from 9,623'—9659' (36ft.) according to gamma ray ran with the caliper log ran in step#20. (Make sure log is corrected for depth by Anchorage geologist). 32. RDMO E-line unit. 33. Space out and land tubing hanger. Install BPV. 34. ND BOP/ NU tree and test to 5,000 psi. 35. RDMO ASR#1 Rig,turn over to Frac operation. Attachments: 1. As-built Schematic 2. Proposed Schematic 3. Wellhead Drawing 4. BOP Schematic 5. Fluid Flow Forward 6. Fluid Flow- Reverse 7. Fluid Flow Diagram—Bleed to Pits Milne Point Unit Well: MP S-90 SCHEMATIC Last Completed: 12/3/2005 Hilcorp Alaska,LLC PTD: 205-135 TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 7-1/16"- 5M Wellhead 13-3/8"x 7"FMC 5M w/7"TC-II T&B Tubing 20 Hanger,7"CIW Type"J"BPV Profile OPEN HOLE/CEMENT DETAIL 20" 260 sx Arctic Set(Approx.)in a 42"Hole 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 9-5/8" 723 sx Class'G'in a 12-1/4"Hole 7" 393 sx Class'G'in a 8-1/2" 1 CASING DETAIL Size Type Wt Grade Conn ID To Btm BPF 13-3/8" Yp / / p 2 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cementer 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5218' 0'0 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 5-1/2" Tubing 17/L-80/BTC-M 4.892" Surf 4,012' 0.0233 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 3,956' 5-1/2"HES X-Nipple(4.455"Profile) 2 4,011' 5-1/2"WLEG 9-CR-Bottom @ 4,012' 3 7,786' 9-5/8"x 7"Baker Liner Tie Back Slv 4 7,795' 7"Baker HR ZXP Liner Packer 5 7,805' 7"Baker Liner HMC Hanger 6 9,801' IBP-Installed in 2013 PERFORATION DETAIL / Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated Ivishak 10,026' _ 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 4505 Poweriet HMX,HSD,5SPF,72 Deg.Phasing GENERAL WELL INFO API:50-029-23276-00-00 Cased&Completed by Doyon 14 -12/3/2005 NOTE There is a spliced section in the 9-5/8"casing from the cut @ 1,939 to the baker cutlip guide assembly @ 1,965.This splice was pressure tested to 3,500psi for 30 min.and passed 9-5/8" 13,4&5 RA Tag 9,638' to 9,658' RA Tag 9,743' to 9,762' 6 -Ivishak 7" TD=10,600'(MD)/TD=9,733'(1VD) PBTD=10,511'(MD)/PBTD=9,647'(TVD) Revised By:TDF 8/2/2016 Milne Point Unit • WeII: MPS-90 11 PROPOSED Last Completed: 12/3/2005 Hileorp LL( PTD: 205-135 II rp TREE&WELLHEAD Orig.KB Elev.:72'-Doyon 14 Tree 4-1/16"- 5M j ;'''' ', I 13-3/8"x 4"FMC 5M w/4"TC-II Tubing ( Wellhead 20 # * Hanger,7"CIW Type"J"BPV Profile }, OPEN HOLE/CEMENT DETAIL k, t ;t . €il 1 20" 260 sx Arctic Set(Approx.)in a 42"Hole ; 13-3/8" 1,035 sx AS Lite,455 sx Class'G'in a 16"Hole 9-5/8" 723 sx Class'G'in a 12-1/4"Hole €" 1 s? 7" 393 sx Class'G'in a 8-1/2" 1 CASING DETAIL " Size Type Wt/Grade/Conn ID Top Btm BPF 13-3/8" E la 20" Conductor 92/H-40/N/A N/A Surface 113' N/A 13-3/8" Surface 68/L-80/BTC 12.415" Surface 4,372' 0.1497 HES Cementer 9-5/8" Intermediate 40/L-80/Btrc. 8.835" Surface 7,942' 0.0758 @5218-*0 7" Production 26/L-80/Btrc 6.276" 7,775' 10,598' 0.0383 TUBING DETAIL 4-1/2" Tubing 12.75/13CR-85&110/BTS8 3.958" Surf 9,750' 0.0152 WELL INCLINATION DETAIL KOP @ 300' Max Hole Angle=48 deg.@ 3,800' Hole Angle thru Perfs=16 deg. JEWELRY DETAIL No Depth Item 1 ±2,200' GLM(Dummied Off)-ID=3.833" 2 7,786' 9-5/8"x 7"Baker Liner Tie Back Sly 3 7,795' 7"Baker HR ZXP Liner Packer 4 7,805' 7"Baker Liner HMC Hanger 5 ±9,430' Pressure Discharge Gauge-ID=3.855" 6 ±9,438' SlidingSleeve-3.813" 7 ±9,448' Pressure Intake Gauge-3.855" 8 ±9,514' X-Nipple-3.813" 9 ±9,531' Baker S-3 Packer-3.73 10 ±9,564' Baker Ball Shear Sub 11 ±9,750' CIBP 12 9,801' IBP-Installed 2013 PERFORATION DETAIL Ivishak Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status Sag River ±9,623' ±9,659' ±8,791' ±8,827' ±36' Future Future 9,884' 9,996' 9,046' 9,153' 112 11/28/2005 Isolated }5/8'40 12,3&4 Ivishak 10,026' 10,064' 9,182' 9,219' 38 11/28/2005 Isolated 10,088' 10,322' 9,242 9,466' 234 11/28/2005 Isolated 4505 PowerJet HMX,HSD,5SPF,72 Deg.Phasing 5 GENERAL WELL INFO is6 7 API:50-029-23276-00-00 wk8 Cased&Completed by Doyon 14 -12/3/2005 ►-=' 9 « NOTE 10 { 3r Tu s There is a spliced section in the 9-5/8"casing RA Tag 9,638' SINC".�42 r from the cut @ 1,939 to the baker cutlip guide to 9,658'�igq �r assembly @ 1,965.This splice was pressure RA Tag 9,7 11 C(1 Cb tested to 3,500psi for 30 min.and passed to9,762' , `' k =,__mi.12 _}Ivishak 7" a`,,LeliA0ili TD=10,600'(MD)/TD=9,733'(TVD) PBTD=10,511'(MD)/PBTD=9,647'(TVD) Revised By:TDF 8/19/2016 WELL MPS 9O DATE 5-23.16 Hilcurir.Alaska,LIT Tree Cap.Otis style,71/16" 934"Acme thrd � s, Swab valve CIW Model FL,7 �e R 1/16"SK,FE,DD L-U y . r e gili, 11'6" Wing valve CIW Model FL,7 •"•OKI." 1/16"5K,FE,DD t-U P 9 ' SSV valve Cameron FL;7 1/ AO16"5K reverse actuating • gate valve,EE.PSL2,PR2 w/ e':e.. 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Z. p R rx ^� M8 X Z 2 u� up « V 'a > u tj o Z a a .., ..,..4 ., = w a 3 ~ z 2� n.to 6)Ti) bT) too .'J., V, Y M V. M 0 m a u o m V a o ¢ a o c to o < 8J t� So - r- o o �-t§ vi ,O r- vi u Uj II II II II II W 0 as 4 to M 3 3 3 TT ,,., ,., d YO a C L C L 2. '71 'LS toil co, Ft. e'7 0 0 x t. x x x N N rn !V 'Y I GI Ua N m t t u :°fie C �_ 'gin u a'''''..-.1',30:3-1 Nutgny I • s II a " o Y S C I Z x to r. _ Q 7 I u V d C m -71 m O Y cn 01 IFC ad I j 0y w .---1 D Y m Q I- O m Q to 2 Q Y$ YN t Z - DOI < �X 9N o Y,IE YJ - j Y a� Y M § 8 g I- I L9 a.2 j a H. ¢ a too 0 .5 too ^.._ a a i c C. 0 u T E _ u a In • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday,August 30, 2016 8:54 AM To: 'Tom Fouts' Cc: samantha.carlisle@alaska.gov Subject: RE: Hilcorp - Milne Point - S-90 Sundry PTD#205-135 Tom , AOGCC will withdraw sundry#316-428 for S-90(PTD 205-135) as requested. 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). From: Tom Fouts [mailto:tfouts(ahilcorp.corr Sent: Tuesday, August 30, 2016 7:16 AM To: Schwartz, Guy L(DOA) Subject: FW: Hilcorp - Milne Point- S-90 Sundry PTD# 205-135 Guy, Hilcorp Alaska LLC wishes to withdraw the S-90 10-403 sundry submitted on 8/19/2016. We will be submitting a revised version for this work. Thanks, Tom Fouts I Senior Ops/Reg Tech Hilcorp Alaska, LLC tfouts@hilcorp.com Direct: (907)777-8398 Mobile: (907)351-5749 From: Bo York Sent: Wednesday, August 24, 2016 8:38 AM To: 'Schwartz, Guy L(DOA)' Cc: Tom Fouts; Ted Kramer; John Barnes Subject: Hilcorp - Milne Point- S-90 Sundry Guy- We submitted a sundry for S-90 last week. We have had some more internal discussions on it and have found some more info about the current status of the well and we will be reviewing and likely adjusting our plan on the well. Can you 1 please pull the sundry from your review pile and take no action on it at this time? I don't want to waste your time reviewing it if we think we may be changing the plan. Thanks Guy.We will get back in touch and/or resubmit after we review the plan more. Bo York Operations Manager, Milne Point byork@Hilcorp.com 907.777.8345 907.727.9247 cell 2 i ~ Image Project Wetl History Fite Cover Page 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. ~~~ ~ 3 ~ Well History File Identifier ,.o,aea uiuiumiiiuiu DIGITAL DATA ~iskettes, No. ^ Other, No/Type: Date: Date: ~ f ~ ~' Q x 30 = t1/ 0 Date: 1 ~ 4 UJ ~ (~ ~ ae=~a~~ee~ea iiuuiiiriuuiii OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other:: /s! III 111111 VIII Il lli /s/ 1 ' Y + ~ =TOTAL PAGES ~ " (Count does not include cover sheet) 1 /s/ Production Scanning Ilillllllllllllllll Stage 1 Page Count from Scanned File: _~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES NO BY: Maria Date: ~ ~ ' ~ ~ V $ /s/ Y ~/ 1 Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO ` BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II II II III II I I III ReScanned III II'III VIII II III BY: Maria Date: /s! Comments about this file: Quality Checked III IIII~I III II'I III Organizing (aone> RESCAN ~otor Items: ^ Greyscale Items: ^ Poor Quality Originals: ^ Other: NOTES: BY: Maria _ Project Proofing BY: Maria _ Scanning Preparation BY: Maria 10/6!2005 Well History File Cover Page.doc I~ • • bp BP Exploration (Alaska) Inc. Attn: Well Integrity Coordinator, PRB -20 Post Office Box 196612 Anchorage, Alaska 99519 -6612 r, ' N ,P FEB , 4 - December 30, 2011 a t 35 Mr. Tom Maunder i S - 0 Alaska Oil and Gas Conservation Commission 1 I 333 West 7 Avenue Anchorage, Alaska 99501 Subject: Corrosion Inhibitor Treatments of MPS -Pad Dear Mr. Maunder, Enclosed please find multiple copies of a spreadsheet with a list of wells from MPS -Pad that were treated with corrosion inhibitor in the surface casing by conductor annulus. The corrosion inhibitor is engineered to prevent water from entering the annular space and causing external corrosion that could result in a surface casing leak to atmosphere. The attached spreadsheet represents the well name, API and PTD numbers, top of cement depth prior to filling and volumes of corrosion inhibitor used in each conductor. As per previous agreement with the AOGCC, this letter and spreadsheet serve as notification that the treatments took place and meet the requirements of form 10 -404, Report of Sundry Operations. If you require any additional information, please contact me or my alternate, Gerald Murphy, at 659 -5102. Sincerely, 1. ) Mehreen Vazir BPXA, Well Integrity Coordinator _ _ . yin , --v -rr.. : "-- a°rrN . . .. ue a , • • BP Exploration (Alaska) Inc. Surface Casing by Conductor Annulus Cement, Corrosion inhibitor, Sealant Top-off Report of Sundry Operations (10 -404) MPS -Pad 10/11/2011 Corrosion Vol. of cement Final top of Cement top off Corrosion inhibitor/ Well Name PTD # API # Initial top of cement pumped cement date inhibitor sealant date ft bbls ft gal MPS-01A 2070340 50029231410100 0.25 NA 0.25 NA 5.1 9/6/2011 MPS -02 2031270 50029231690000 2.5 NA 2.5 NA 23.8 7/30/2011 MPS-03 2021460 50029231050000 Open Flutes - Treated MPS-04 2030520 50029231480000 1.7 NA 1.7 NA 17.0 7/30/2011 MPS-05 2021370 50029231000000 Open Flutes - Treated MPS-06 2031090 50029231630000 1.7 NA 1.7 NA 17.0 7/30/2011 MPS-07 2020720 50029230790000 1 NA 1 NA 13.6 11/3/2009 MPS-08 2031230 50029231680000 1.3 NA 1.3 NA 10.2 7/30/2011 MPS-09 2020200 50029230670000 0.5 NA 0.5 NA 5.1 11/3/2009 MPS -10A 2051250 50029231520100 1.3 NA 1.3 NA 11.9 7/29/2011 MPS-11 2021130 50029230920000 1 NA 1 NA 10.2 7/29/2011 MPS-12 2030230 50029231390000 0.6 NA 0.6 NA 6.8 7/29/2011 MPS -13 2021240 50029230930000 1 NA 1 NA 11.9 11/3/2009 MPS-14 2031040 50029231620000 1.8 NA 1.8 NA 22.1 7/29/2011 MPS-15 2012450 50029230610000 9.6 NA 9.6 NA 88.4 7/31/2011 MPS -16 2030650 50029231510000 1.2 NA 1.2 NA 102 7/29/2011 MPS-17 2021730 50029231150000 Open Flutes - Treated MPS -18 2022420 50029231330000 1.3 NA 1.3 NA 11.9 7/29/2011 MPS -19A 2022330 50029231210100 1.8 NA 1.8 NA 23.8 7/29/2011 MPS-20 2022410 50029231320000 1.3 NA 1.3 NA 11.9 7/29/2011 MPS-21 2020090 50029230650000 1.8 NA 1.8 NA 22.1 11/3/2009 MPS-22 2031470 50029231760000 9.1 NA 9.1 NA 83.3 7/28/2011 MPS -23 2021320 50029230980000 Open Flutes - Treated MPS -24 2030380 50029231420000 1.3 NA 1.3 NA 102 7/28/2011 MPS-25 2021030 50029230890000 Open Flutes - Treated MPS -26 2030610 50029231500000 1 NA 1 NA 8.5 7/28/2011 MPS -27 2020850 50029230840000 0.9 NA 0.9 NA 8.5 7/28/2011 MPS -28 2030940 50029231580000 1.1 NA 1.1 NA 11.9 7/28/2011 MPS -29 2021950 50029231190000 Open Flutes - Treated MPS-30 2022360 50029231310000 12 NA 12 NA 11.9 7/28/2011 MPS-31 2020140 50029230660000 Open Flutes - Treated MPS -32 2030920 50029231570000 0.8 NA 0.8 NA 6.8 7/28/2011 MPS -33A 2061720 50029231230100 1 NA 1 NA 6.8 7/28/2011 MPS-34 2031300 50029231710000 6 NA 6 NA 49.3 7/28/2011 MPS-35 2031430 50029231750000 12 NA 1.2 NA 11.9 7/28/2011 MPS-37 2070520 50029233550000 13.9 Need top job NA MPS-39 2081830 50029234050000 0.7 NA 0.7 NA 4.3 8/18/2011 MPS -41A 2081610 50029234010100 Sealed NA NA NA NA NA MPS-43 2081760 50029234040000 Dust Cover NA NA NA 6.8 10/11/2011 "3' MPS -90 2051350 50029232760000 0.6 NA 0.6 NA 3.4 9/62011 MPSB -04 500299990799 0.6 NA 0.6 NA 3.4 7/30/2011 3~~.~~~ DATA SUBMITTAL COMPLIANCE REPORT 1 /16/2008 Permit to Drill 2051350 Well Name/No. MILNE PT UNIT IVISH S-90 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-2~3276-00-QO MD 10600 TVD 9732 Completion Date 12/3/2005 Completion Status WTRSP Current Status WTRSP UIC Y REQUIRED INFORMATION Mud Log Yes Samples No DATA INFORMATION Types Electric or Other Log s Run: MWD. GR. PHOTO-GYRP, IFR/CASANDRA, RES, NEU, DEN, SONI Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No D Asc Directional Survey Sgn+e' Ly.AnM~\ ~ ~ Bv1 5 Col 1 C Pds 13962 Soyic C 5 Col 1 ~p C Lis 13985 Induction/Resistivity ED C Asc 13985 Induction/Resistivity 13985 Induction/Resistivity rtD C Las 14386 Induction/Resistivity Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? Y ' N Chips Received'~Y N Analysis ~" Received? Comments: 34 10600 Open 1/9/2006 7770 10470 Case 3/3/2006 Ultrasonic Imaging Cement Eval USIT/GR/CCL 27-Nov- 2005 7770 10470 Case 3/3/2006 Ultrasonic Imaging Cement Eval USIT/GR/CCL 27-Nov- 2005 0 0 Open 7/19/2006 LIS 0 0 Open 7/19/2006 Text 0 0 Open 7/19/2006 73 10600 Open 1/29/2007 LIS Veri, GR, ROP, FET, NCNT, RHOB, NPHI w/Graphics Sample Interval Set Start Stop Sent Received Number Comments Cores andlor Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 9/26/2005. Daily History Received?~~, N Formation Tops 1' 9 N (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments Directional Survey DATA SUBMITTAL COMPLIANCE REPORT 1/16/2008 Permit to Drill 2051350 Well Name/No. MILNE PT UNIT IVISH S-90 Operator BP EXPLORATION (ALASKA) INC API No. 50-029-23276-00-00 MD 10600 TVD 9732 Completion Date 12/3/2005 Completion Status WTRSP Current Status WTRSP UIC Y Compliance Reviewed By: Date: • • WELL LOG TRAI~ISMITTAL To: State of Alaska November 13, 2006 Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs: MPS-20, MPS-22, MPS-30, MPS-90. The technical data listed below is being submitted herewith. Please address any problems or concerns to the attention of: Rob Kalish, Sperry Drilling Services, 6900 Arctic Blvd. , Anchorage, AK 99518 MPS-20: U =C 2~~ - awl ( ~ /1345 *'-f Digital Log Images: 1 CD Rom 50-029-23132-00 MPS-22: ~ 03 - ~ ~~ ~ '~ 1 ~-! 3~S 5 Digital Log Images: 1 CD Rom 50-029-23176-00 MPS-30: v T~ 2a2 -a-3(~ ~ ?'13~~ Digital Log Images: 1 CD Rom 50-029-23131-00 MPS-90: a~S- 13S *l Cl 3~5~ Digital Log Images: 1 CD Rom 50-029-23276-00 j • WELL LOG TRANSMITTAL • To: State of Alaska July 10, 2006 Alaska Oil and Gas Conservation Comm. Attn.: Librarian 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RE: MWD Formation Evaluation Logs MPS-90, AK-MW-4018179 1 LIS formatted Disc with verification listing. API#: 50-029-23276-00 PLEASE ACKNOWLEDGE RECEIPT BY SIGNING A COPY OF THE TRANSNHTTAL LETTER TO THE ATTENTION OF: Sperry Drilling .Services Attn: Rob Kalish 6900 Arctic Blvd. Anchorage, Alaska 99518 Date: BP Exploration (Alaska) Inc. Petrotechnical Data Center MB33 900 E. Benson Blvd. Anchorage, Alaska 99649-6612 Signed: aos =135 ~ ~39~5- ~/ i- Scbfum6erger ,i ~ •{~ 41`F 7. •~ ~~j1JlJ Alaska Data 8: Consulting Services _ ,t 2525 Gambell Street, Suite 400 ~-~ .~ l;~S ~ii'iS•'~~iiili~«SStC~ Anchorage, AK 99503-2838 ~PC~~~ ATTN: Beth Walt .Inh }E ~~,35 ~~ 1 nn rlaer.infinn NO. 3854 Company: State of Alaska Alaska Oil & Gas Cons Comm Attn: Christine Mahnken 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Field: Prudhoe Bay n~fe CI r..i... rn os/2o/os 07-18 9153238 LDL 01/31/03 C-04A 10649975 SBHP SURVEY 06!26/03 1 N-11C 10980595 PRODUCTION PROFILE 08/09/05 1 MPF-89 11084328 SCMT 11/24/05 1 D-10 10913021 MULTI-FINGER CALIPER 06102/05 1 NGI-09 11212860 USIT 05/23/06 1 MPH-09 11211412 USIT 05!28/06 1 MPH-15 11076486 CH EDIT PDC-GR OF USIT 12/15/05 Prints sent earlier 1 MPS-90 11162721 CH EDIT PDC-GR OF USIT 11/27/05 Prints sent earlier 1 AGI-07A 11212865 CH EDIT PDC-GR OF USIT 05/28/06 1 1 15-20C 11075906 MCNL 08/12/05 1 1 18-30 11209593 MCNL 03/25/06 1 1 Petrotechnical Data Center LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 Hlaslca uata ts< consuttmg services 2525 Gambell Street, Suite 400 Anchorage, AK 99503-2838 ATTN: Beth • ,a STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG ~iECEIVED ,lAN 2 0 2006 Alaska Ofd ~ Gas Cons. Commisa+o~ 1a. Well Status: ^ Oil ^ Gas ^ Plugged ^ Abandoned 2oAACZS.~os ^ GINJ ^ WINJ ^ WDSPL No. of Completions ^ Suspended ^ WAG 2oAAC2s.»o One Other Water Source Well ~ ib. Well Class: ^ Development ^ Exploratory ^ Stratigraphic ®Service ~ 2. Operator Name: BP Exploration (Alaska) Inc. 5. Date Comp., Susp., or Aband. 12/3/2005 - 12. Permit to Drill Number 205-135 305-369 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Date Spudded 11/04/2005 13. APl Number 50-029-23276-00-00 4a. Location of Well (Governmental Section): Surface: ' ' 7. Date T.D. Reached 11/24!2005 14. Well Name and Number: MPS-9d 3390 FSL, 4656 FEL, SEC. 07, T12N, R11 E, UM Top of Productive Horizon: 4897' FSL, 1583' FEL, SEC. 12, T12N, R10E, UM g, KB Elevation (ft): 72' 15. Field 1 Poo1(s): Milne Point Unit I Ivishak, Eileen Total Depth: 5021' FSL, 1759' FEL, SEC. 12, T12N, R10E, UM 9. Plug Back Depth (MD+TVD) 10473 + 9611 Ft 4b. Location of Well (State Base Plane Coordinates): Surface: x- 566135 ' y- 6000059 'Zone- ASP4 10. Total Depth (MD+TVD) - 10600 + 9732 - Ft 16. Property Designation: ADL 380109 _ TPI: x- 564413 y- 6001553 Zone- ASP4 Total Depth: x- 564237 - y- 6001676 ~ Zone- ASP4 11 • Depth where SSSV set NIA MD 17. Land Use Permit: --" ----" --~ ----"~-- -- ---- - -- -~---"-- --~----" ---~---- 18. Directional Survey ®Yes ^ No 19. Water depth, if offshore N1A MSL 20. Thickness of Permafrost 1800' (Approx.) ° 21. Logs Run: MWD, GR ,PHOTO-GYRO , IFR/CASANDRA , RES , NEU, DEN ,SONIC , PWD 2. ASING, LINER AND EMENTING RECORD CASING ETTING EPTH MD ETTIN(>, EPTH ND 04E OUNT SIZE WT. PER FT. GRADE OP TTOM OP TTOM ~IZE CEMENTING RECORD PULLED 20" 92# H-40 35' 114' 35' 114' 42" 60 sx Arctic Set A rox. 13-3/8" 68# L-80 35' 4373' 35' 3864' 16" 1035 sx AS Lite, 455 sx Class 'G' 9-5/8" 47# L-80 31' 7942' 31' 7114 12-1/4" 23 sx Class 'G' 7" 26# L-80 7777' 10600' 6949' 9733' 8-1/2" 93 sx Class 'G' 23. Perforations open to Produc tion (MD + TV D of Top and " " 24. TUBING RECORD Bottom Interval, Size and Number; if none, state none ): SIZE DEPTH SET (MD) PACKER SET (MD) 4-1/2" Gun Diameter, 12 SPF 5-1l2", 17#, L-80 4012' None MD TVD MD TVD 9884' - 9996' ~ 9046' - 9153' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. , 10026' - 10064' 9182' - 9219' 10088' 10322' " 9242' 9466' DEPTH INTERVAL MD AMOUNT 8c KIND OF MATERIAL USED - - Freeze Protected with 150 bbls Deisel 26• PRODUCTION TEST Date First Production: Not on Production - Method of Operation (Flowing, Gas Lift, etc.): N/A Date of Test Hours Tested PRODUCTION FOR TEST PERIOD OIL-BBL GAS-MCF WATER-BBL CHOKE SIZE GAS-OIL RATIO Flow Tubing PreSS. Casing Pressure CALCULATED 24-HOUR RATE OIL-BBL GAS-MCF WATER-BBL OIL GRAVITY-API (CORK) 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". -.. ;+ None ~° ,~~i~~ ~ ~ ~fl~~ .~.~_ , ~. Form 10-407 Revised 12/2003 + ' ~ ~ ~ ~ ~ ~N INUED ON REVERSE SIDE fe/j ~j i 28. GEOLOGIC MARKERS 29' FORMATION TESTS Include and briefly summarize test results. List intervals tested, NAME MD TVD and attach detailed supporting data as necessary. If no tests were conducted, state "None". Top of MA 4379' 3868' Top of MB1 4403' 3884' None Top of MB2 4479' 3936' Top of MC 4662' 4063' Top of NA 4705' 4093' Top of NB 4738' 4116' Top of NC 4777' 4144' Top of NE 4793' 4155' Top of NF 4860' 4203' Top of OA 4900' 4232' Base of OA 4932' 4255' Top of OB 4970' 4283' Base of OB 5005' 4309' KUD 7447' 6620' KC 1 7600' 6772' KUB/LCU 7627 6799' KUA 7796' 6968' MLV 7895' 7067' Sag River 9592' 8761 ` Shublik 9661' 8829' Eileen 9821' 8985' Top of Sadlrochit 9834' 8997' Base of Sadlrochit 10473' 9611' 30. List of Attachments: Summary of Daily Drilling Reports, Well Schematic Diagram, Surveys and aLeak-Off Test Summary. 31. l hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Sondr Stewman Title Technical Assistant Date ~, "' ~~( " MPS-90 205-135 305-369 Prepared ByName/Number.• SOnd~a Stewman, 564-4750 Well Number Permit No. ! A royal No. OriOing Engineer: Skip Coyner, 564-4395 INSTRUCTIONS GeNERa~: 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 1a: Classification of Service Wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. ITEM 4b: TPI (Top of Producing Interval). ITEM 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. ITEM 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). ITEM 20: True vertical thickness. ITEM 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. ITEM 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). ITEM 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-In, or Other (explain). ITEM 27: If no cores taken, indicate "None". ITEM 29: List all test information. If none, state "None". Form 10-407 Revised 1212003 Submit Original Only Tree:Cameron 7-1/16' MPU S-9~ ~ Orig. DF Elev. _ Wellhead: Orig. GL Elev. _ 20" 92# ppf, H-40 113' KOP @300` Max. hole angle =48 deg. @ 3,800` Hole angle thru' perfs = 16 deg. 13- 3/8" Halliburton Float Collar 4,286` 13-3/8"" Halliburton float shoe 4,372` 5.5" 17" L-80 IBT-M Tbg. 13-318" 68 #!ft, L-80 BTC ( Drift id = 12.415" / Cap. = 0.1497 Bpf. ) 9-5/8" 40 #/ft, L-80 BTC-M ( Drift id = 8.835" !Cap. = 0.0758 Bpf ) 7" 26 #/ft, L-80 BTC-M ( Drift id = 6.276" !Cap. = 0.0383 Bpf } 5.5" 17 #/ft, L-80 BTC-M ( Drift id = 5.190" /Cap. = 0.0262 Bpf ) 9-518" Weatherford Landin Collar 7,856' 9-5/8" Weatherford Float Collar 7,$g7' 9-5/8" Weatherford float shoe 7,942` Perforation Summary Size Spf Interval (TVD) 5.5" HES XN-Nipple 3,966` 5.5" WLEG 4,012` HES Cementer @ 5,218' 9-518"x 7" Baker Liner Tie Back Slv. 7,786` 7" Baker HR " ZXP" Liner Pkr. 7,795' 7" Baker Liner HMC Hng. 7,$05' RA Tag (9,638` - 9,658' ) RA Tag (9,743' - 9,762' ) DATE REV. BY COMMENTS 12/03/05 MDO Drill & Casing Doyon - 14 7" Halliburton Float Collar 10,553` 7" Halliburton float shoe 10,598` MILNE POINT UNIT WELL No.: S-90 API : 50-029-23276-00 BP EXPLORATION • BP Operations Summary Report Legal Well Name: MPS-90 Common Well Name: MPS-90 Event Name: DRILL+COMPLETE Contractor Name: DOYON DRILLING INC Rig Name: DOYON 14 Date I From - To ' ~ Hours ~ Task ~ Code j 1 ~ ' 11/3/2005 - -- - 06:00 - 07:00 1.00 - MOB - - P 07:00 - 10:00 3.00 MOB P 10:00 - 11:00 1.00 RIGU P 11:00 - 11:30 0.50 RIGU P 11:30 - 15:00 3.50 RIGU P 15:00 - 17:30 I 2.501 RIGU I P 17:30 - 23:00 5.50 RIGU P 23:00 - 00:00 1.00 RIGU P 11/4!2005 00:00 - 02:00 2.00 RIGU P 02:00 - 02:30 0.50 RIGU P 02:30 - 03:00 0.50 EVAL P 03:00 - 04:00 1.00 DRILL P 04:00 - 04:30 0.50 DRILL N 04:30 - 06:30 2.00 DRILL P 06:30 - 07:30 1.00 DRILL P 07:30 - 00:00 16.50 DRILL P 11(5!2005 100:00 - 06:00 I 6.00 {DRILL I P 06:00 - 07:00 1.00 DRILL P 07:00 - 08:30 1.50 DRILL P 08:30 - 09:30 1.00 DRILL P 09:30 - 00:00 14.50 DRILL P 11/6/2005 100:00 - 03:30 I 3.501 DRILL I P 03:30 - 05:00 1.50 DRILL P 05:00 - 08:00 3.00 DRILL P 08:00 - 09:00 1.00 DRILL P 09:00 - 00:00 15.00 DRILL P 11!7/2005 ~ 00:00 - 12:00 ~ 12.00 ~ DRILL { P 12:00 - 13:30 1.50 DRILL P 13:30 - 15:00 1.50 DRILL P 15:00 - 16:30 1.50 DRILL P 16:30 - 20:00 3.50 DRILL P Page i of i 2 Spud Date: 11/4/2005 Start : 10/26/2005 End: 12/3/2005 Rig Release: 12/3/2005 Rig Number: ! NPT i Phase J Description of Operations - --- PRE -- - --_ _ --- PJSM -Skid rig floor from drlg position to move position PRE Move rig off well MPS-01 to to Well MPS-90 -Shim rig PRE Skid rig floor from move position to drill position -Spot rockwasher -Berm same PRE Rig up floor and spot water tank PRE Accept rig 11:30 hrs - NU Diverter system -Annular -Riser - Diverter -Rig floor prep PRE PJSM -Change out saver sub from 4" to 5" -Change out handling equipment PRE PU 5" DP stand back in derrick - PU 150 jts - 50 stands PRE Mobilize short BHA to rig floor PRE MU BHA -Bit -Bit sub -Motor -Float sub -Stab - MW D - XO - 5" HWDP PRE Pre Spud meeting with crew and all service personne{ - RU Sperry Sun Gyro equipment SURF Function test Diverter on 5" HWDP -Perform Accumulator test - Chuck Scheve with AOGCC waived witness of function test of Diverter -Fill conductor with mud -Check surface equipment for leaks SURF Spud in well -Drill from 114' to 140' RREP SURF Repair drag on conveyer SURF Drill from 140' to 253' - WOB 12 to 15 -RPM 45 - TO on 2 -off 0-GPM450-PPon890-off 820-PU70-S070-ROT 70 SURF POH, PU DC's. SURF Drill from 253' to 1420' - WOB 20 to 25 -RPM 70 - TO on 4!5 - off2-GPM550-PPon1900-off1600-PU98-S098-ROT 98 SURF Directional Drill from 1420' to 1900' - WOB 25 to 28 -RPM 70 - TOon4to5-off3-GPM550-PPon1810-off-1600 PU 110 - SO 105 -ROT 105 SURF CBU 2 X -RPM 70 -GPM 550 - PP 1630 SURF Pump out from 1900' to 711' -Pump at drlg rate SURF RIH -Hole in good shape SURF Directional Drill from 1900' to 3144' - WOB 20 / 25 -RPM 70 - TOon8-off4-GPM550-PPon1900-off 1610-PU143- SO 120 -ROT 128 - SURF Directional Drill from 3144' to 3328' - WOB 20 / 25 -RPM 70 - TO on 8 -off 6 -GPM 550 - PP on 1980- off 1740 - PU 144 - SO 115 -ROT 130 SURF CBU 2 X -GPM 600 - PP 2000 SURF Pump out to HWDP -Pump at drlg rate. SURF RIH to 3233' -Precautionary wash last stand to bottom from 3233 to 3328' SURF Directional Drill from 3328' to 4090' - WOB 30 to 35 -RPM 70 -TOon7to9-off6-GPM 600-PP on 2180-off 1920-PU 155 - SO 120 - ROT 144 SURF Directional Drill from 4090' to 16" TD at 4672' - WOB 20-30k - RPM 80-90 - Tq on 9-12k off 11 k -GPM 625 - PP on 2300 psi, off 2030 psi - PU 180k - SO 118k -ROT 145k. SURF CBU iX -GPM 625 PP 1900 SURF Pump out 3982 @ Drlg rate SURF CBU 1.5X -GPM 625 - PP 1750 SURF Pump out from 3982' to 711' - @ Drlg rate Printed: 12/5/2005 11:09:03 AM gp Page 2 of 12 Operations Summary Report Legal Well Name: MPS-90 Common W ell Name: MPS-90 Spud Date: 11/4/2005 Event Nam e: DRILL+C OMPLE TE Start : 10/26/2005 End: 12/3/2005 Contractor Name: DOYON DRILLIN G INC . Rig Release: 12/3/2005 Rig Name: DOYON 14 Rig Number: Date From - To I Hours ~i Task ~ Code , I NPT ~ i i Phase ~! i Description of Operations 11/7/2005 - 20:00 - 22:30 2.50 DRILL P SURF RIH from 711' to 4577' 22:30 - 00:00 1.50 DRILL P SURF Precautionary wash from 4577' to 4672' -CBU 2.5 X -GPM 625 - PP 11/8/2005 00:00 - 01:00 1.00 DRILL SURF Continue CBU 2X 625 gpm - 1950 psi - R&R DP 80 rpm. 01:00 - 04:30 3.50 DRILL SURF Pump out to HWDP at full drlg rate. 04:30 - 05:00 0.50 DRILL SURF Stand back 1 stand HWDP + 1 stand w/jars. 05:00 - 10:00 5.00 DRILL SURF Pulled into tight spot at 500'. Pull 30-40k over. RIH to 560' - Breakcirc. -Backream to 470' - Rih to 560'- Pull to 470' - Pulling tight -Backream &circ. 400 gpm to 259' -Pull last stand hwdp w/ no rotary -Pull DC's w/ no rotary, no pump to 78' (inside conductor) -RIH -Hit bridge at 500' -Wash down to 711' -Backream &circ. w/ 400 gpm to DC's -RIH to 711' w/ no issues. POH stand back hwdp & DC's - No tight spots. 10:00 - 12:30 2.50 DRILL SURF Down load MWD tools - LD BHA 12:30 - 14:00 1.50 CASE SURF Rig up to run 13 3/8 68# L-80 Csg 14:00 - 00:00 10.00 CASE SURF PJSM, Picking up 105 jts 13 3/8 68# L-80 csg Break circ ever 20 jts.,,( had to working csg past tight spot 2020 ft to 2600 ft.) pipe set down @ 4372' couldn't pick up with 450K 11/9/2005 00:00 - 01:30 1:50 CASE N STUC SURF Working stuck 13 3/8 csg Q 4372' with 475k up and 50k down, 5 bbls min 400 psi 01:30 - 05:00 3.50 CASE N STUC SURF Circ, thin mud vis to 60 for cement job, circ 1 1/2 csg volumes, working stuck csg. 05:00 - 12:00 7.00 CASE N HMAN SURF Attempt to release casing elevators in order to back out & LD Jt. # 106. Elevators stuck on jt 40' up. Continue circ. w! 5 bpm 300 psi. while working to release elevators. 12:00 - 12:30 0.50 CASE N HMAN SURF Hold PJSM w/all crew members involved. Discuss process of laying down 40' joint w! elevators still attached. Mitigate hazards & risks involved. 12:30 - 13:30 1.00 CASE N HMAN SURF RU super tugger on elevators w/ 11,000 # rated slings on each side. Remove bales from elevators and lift blocks above & out of the way. Break out 13 3/8" casing & LD same w/ elevators still attached. 13:30 - 15:30 2.00 CASE N HMAN SURF Break circ. w/ 5 bpm 300 psi. fl 45 min. Rig down Franks fill up tool. Blow down Top drive. 15:30 - 16:30 1.00 CASE N HMAN SURF Rig up different set of 350 ton casing elevators. Remove casing slips. Slack string off to 90k. RU cement head & lines. 16:30 - 17:00 0.50 CASE P SURF Break circ. & hold PJSM w( crew, Dowell & other personel involved w/ cement job. 17:00 - 00:00 7.00 CEMT P SURF Turn over to Dowell, Pump 5 bbls H2O, Test lines to 3000 psi., 10 bbls water with i gal of dye, 20 bbls CW 100, 75 bbls Mud push mixed @ 10.5, Drop bottom plug, Lead 1035 sxs 827 bbls 10.7# ASL cement, Tail 94.4 bbls 455 sxs Class G mixed C~3 15.8#, Drop Top plug, Kicked out with 30 bbls water, switch to rig pumps and displace with 612 bbls of old mud, cement job was mixed and displace C~ 5 bbls min., full return thru out job,bump plug with 1800 psi, float held, 475 bbls good cement to surface, cemnt was in place @ 23:30 hrs 11/10/2005 00:00 - 01:00 1.00 CEMT P SURF Remove cement head and cross over from landing jt. 01:00 - 02:00 1.00 CEMT P SURF Flush stack with H2O and drain, remove diverter line 02:00 - 03:00 1.00 CASE P SURF Picked up Diverter 03:00 - 04:30 1.50 CASE P SURF Set slips with 100K. 04:30 - 05:30 1.00 CASE P SURF Cut casing w/ Wachs cutter. LD landing jt. 05:30 - 06:30 1.00 CASE P SURF Pu{I riser off & set stack in corner of cellar & secure. Printed: 12!5/2005 11:09:03 AM • BP Operations Summary Report Page 3 of 12 Legal Well Name: MPS-90 Common Well Name: MPS-90 Spud Date: 11!412005 Event Name: DRILL+COMPLETE Start: 10/26/2005 End: 1213/2005 Contractor Name: DOYON DRILLING INC. Rig Release: 12/3/2005 Rig Name: DOYON 14 Rig Number: Date I From - To ~' Hours ~ Task Code ~ NPT ~ Phase 11/10/2005 06:30 - 09:00 ~ 2.50 ~ CASE ~ P ~ ~ SURF 09:00 - 09:30 0.50 CASE P SURF 09:30 - 13:00 3.50 CASE P SURF 13:00 - 17:30 4.50 CASE P SURF 17:30 - 18:00 0.50 CASE P SURF 18:00 - 20:00 2.00 CASE P SURF 20:00 - 20:30 0.50 CASE P SURF 20:30 - 22:00 1.50 CASE P SURF 22:00 - 00:00 2.00 CASE P SURF 11/11/2005 00:00 - 01:00 1.00 CASE P SURF 01:00 - 05:00 4.00 CASE P SURF 05:00 - 06:00 1.00. CASE P SURF 06:00 - 08:00 2.00 CASE P SURF 08:00 - 09:30 1.50 CASE P SURF 09:30 - 10:00 0.50 CASE P SURF 10:00 - 13:30 3.50 CASE P SURF 13:30 - 14:00 0.50 CASE P SURF 14:00 - 15:00 1.00 CASE P SURF 15:00 - 21:00 6.00 CASE P SURF 21:00 - 22:30 1.50 CASE P SURF 22:30 - 23:00 0.50 CASE P SURF 23:00 - 00:00 1.00 CASE P SURF 11/12!2005 00:00 - 00:30 0.50 CASE P SURF 00:30 - 00:00 23.50 DRILL P INT1 11(13/2005 00:00 - 21:00 21.00 DRILL P INT1 21:00 - 22:00 1.00 DRILL N SFAL INT1 22:00 - 00:00 2.00 DRILL P INTi 11/14/2005 00:00 - 04:00 4.00 DRILL P INTi 04:00 - 06:30 2.50 DRILL P INTi 06:30 - 09:00 2.501 DRILL P ( INT1 09:00 - 10:30 I 1.501 DRILL I P I I INTi 10:30 - 11:00 0.50 DRILL P INT1 11:00 - 11:30 0.50 DRILL P INTi 11:30 - 13:30 2.00 DRILL P INT1 13:30 - 16:30 3.00 DRILL P INT1 16:30 - 00:00 7.50 DRILL P INT1 11/15/2005 100:00 - 18:00 I 18.001 DRILL I P I I INT1 18:00 - 21:00 I 3.001 CASE I P I I INTi Description of Operations Prep top of casing for transition head installation. Install head & tack in place. Set off "Hot Head " in transition head. Make root pass & cover pass on transition head. Install "Hot Head "and set off. wrap w/ insulation and let cool. Test Weld on head to 1300 psi (60% of 13 3(8" 68# collapse press. ). Con't to let head cool Pjsm on Nipple up Uni-head Remove diverter from cellar area, set bops on Uni-head, test Uni-head to 1000 psi for 10 min. Nipple up BOPS Rig up to Test BOPS Test bops and manifold with 250-5000 psi for 5 min per test, Hydrill 250-2500 psi 5 min per test, The right to witness test was wavier by Lou Grimauidi AOGCC, test was witness by WSL RD test equip. - InstaA wear ring. PU BHA Slip & cut drilling line Test MWD & motor - 430 gpm, 720 psi PU 5" DP f/ pipeshed + 2 stds f/ derrick. Wash down & tag cmt at 4278'. RU & test 13 318" casing to 2000 psi 1130 min. - OK Drilling F.C. at 4286' -Drill cement & tag shoe at 4372'., Wash and ream to bottom 4672' Drill new hole to 4692' Displace hole with new 9.1 LSND mud 400 Gpm. 900 psi Flow check, pump out to shoe @ 4372' FIT test, to 12.0 ppg, Mwt 9.1, TVD 3867', Md 4692', 585 Psi Blow down Iines,RlH washed fast stand to bottom @ 4692' Drill 4692' to 5880' with 80 rpms, 550 gpm, 1900 psi AST 8.8,ART 5.57,Tq 6K Drill 5880' to 6633' with 80 rpm, 600 gpm, 2000 psi Circ. repair mud pump Drill 6633' to 6725' with 80 rpms, 2300 psi. 600 gpm, AST 10.79, ART 5.34, TO 9k Drill 6725' to 7003' with 80 rpms, 2300 psi. 600 gpm Circ, two bottoms up with 600 gpm, 2300 psi, R&R drillpipe 80 rpm. Flow check, pump out of hole @ drlg. rate to 4290' (82' above 13 3/8" shoe ). Flow check, CBU 2x w/ 600 gpm 1820 psi. R&R drillpipe w/ 60 rpm. RU head pin & rest equipment. Perform FIT to 11.1 ppg EMW. Shoe at 4372', TVD at 4308', MW 9.7 ppg. 310 psi applied. RIH f/ 4290'. Wash last stand down to TD at 7003'. Circulate & raise mud weight to 10.0 ppg Drill 7003' to 7220' with 80 rpms, 2500 psi. 600 gpm, AST 1.82, ART 5.86, Tq 12K Drill 7220' to 7952' with 80 rpms, 2500 psi. 600 gpm, AST .24,ART 14.34,Tq 13k Circ Three bottoms up with 80 rpms, 2500 psi, 600 gpm Printed: 12/5/2005 11:09:03 AM BP Legal Well Name: Common Well Name Event Name: Contractor Name: Rig Name: Operations Summary Report MPS-90 MPS-90 DRILL+COMPLETE DOYON DRILLING INC DOYON 14 Date I, From - To ~, Hours ~, Task _-- - - -i - _- +- 11/15/2005 21:00 - 00:00 3.00 CASE 11/16/2005 00:00 - 01:30 1.50 CASE 01:30 - 02:00 0.50 CASE 02:00 - 03:30 1.50 CASE 03:30 - 07:30 4.00 CASE 07:30 - 10:30 3.00 CASE 10:30 - 12:00 1.50 CASE 12:00 - 15:00 3.00 CASE 15:00 - 18:00 3.00 CASE 18:00 - 20:30 2.50 CASE 20:30 - 22:30 2.00 CASE 22:30 - 00:00 1.50 CASE 11(17(2005 00:00 - 04:00 4.00 CASE 04:00 - 05:00 1.00 CASE 05:00 - 09:00 4.00 CASE 09:00 - 10:30 1.50 CASE 10:30 - 11:00 0.50 CASE 11:00 - 13:00 2.00 CEMT 13:00 - 14:00 1.00 CEMT 14:00 - 16:00 I 2.001 CEMT 16:00 - 16:30 0.50 CEMT 16:30 - 18:00 1.50 CEMT 18:00 - 19:30 1.50 CEMT 19:30 - 19:45 0.25 CEMT 19:45 - 20:00 0.25 CEMT 20:00 - 21:00 21:00 - 22:00 22:00 - 23:00 1.001 CEMT 1.00 CASE 1.00 CASE Start: 10/26/2005 Rig Release: 12/3/2005 Rig Number: Page 4 of 12 Spud Date: 11 /4!2005 End: 12!312005 ~ Code I, NPT ~~~ Phase '~~ - L - Description of Operations - - P - INT1 - - __ _ -- - - Pumping out from 7952' to 5600' with full drilling rate, tight spot C~3 7634 P INTi Pumping out from 5600' to 4372' with full drilling rate, tight spot @ 7634 P INTi Service rig and topdrive P INT1 Trip to bottom, wash last stand to bottom ~ 7952', no problems P INTi Circ Three bottoms up with 2500 psi,600 gpm,80 rpms P INTi Pumping out to Csg shoe, @ 4372' with full drilling rate P INTi Circ bottoms up from 4372' with 600 gpm, i 830 psi, 60 rpms P INTi POH to BHA P INT1 PJSM, Laying down BHA P INT1 PJSM, Pull wear ring, install test plug, change top rams to 9 5/8, test door seals to 1000 psi for 5 min.,pull test plug P INTi PJSM, rig up to run 9 5/8 CSG P INT1 PJSM, Picking up 9 5/8 47# L-80 BTC-M csg P INT1 PJSM, Picking up 9 518 47# L-80 BTC-M csg to 4370' P INT1 Circ. one Csg Volume stage pump up to 6 bbls min. P INT1 Picking up 9 5/8 47# L-80 BTC-M csg to 7904' circ last jt down, land csg Q7941, could not pick up csg, hanger hanging up in BOPS. P INT1 Circ one CSG volume, stage pump up to 6.5 bbls min, 500 psi P INTi Rig down franks tool, rig up cement head P INTi Circ and thin mud for cement job 6.5 bbls min., 400 psi P INT1 Cement with Schlumberger stage #1 10 bbls water, test lines to 3,500 psi, 25 bbls CW 100, 45 bbls Mud Push @ 11.O,drop bottom plug,reload head with top plug,433 sxs. Class G 89.5 bbls mixed C«~ 15.8, yield 1.16, drop top plug, kicked out with 10 bbls water. cement was mixed and pumped Q 6 bbls min, give to rig P INTi Displace with rig pumps, with 579 bbls mud @ 6 bbls min., bump plug with 1000 psi,check floats, load closing plug in head, open Cementer with 2200 psi, was set to open with 3300 psi P lNT1 Circ for Cement job #2, 6.5 bbls min. 250 psi P INT1 Cement with Schlumberger stage #2, 10 bbls water, test lines to 3,500 psi, 25 bbls CW 100, 45 bbls Mud Push @ 11.0, 290 sxs. Class G, 60 bbls mixed Q 15.8, yield 1.16, drop closing plug, kicked out with 10 bbls water. cement was mixed and pumped C~ 6 bbls min, give to rig P INT1 Displace with rig pumps, 6 bbls min, 385 bbls mud, pressure up on closing plug with 1600 psi, 1200 psi over circ pressure. check cementer for flow back, none. P INT1 Close Annular ,rig to inject down backside, pump 6 bbls 800 psi and look like cementer was leaking, bleed off pressure., open annular P INT1 Pressure back up on cementer closing plug to 1600 psi for 5 min., no flow back P INT1 Close Annular, inject 40 bbls mud C«? 1100 psi, 1.5 bbls min, shut down 1000 psi, pressure decrease to 700 psi, bled of 5 bbls mud P INT1 Rig down landing jt., lay down Csg elevators and bails P INT1 Install packoff and test to 5000 psi for 10 min. Printed: 12/5/2005 11:09:03 AM • BP Operations Summary Report Legal Well Name: MPS-90 Common Well Name: MPS-90 Event Name: DRILL+COMPLETE Contractor Name: DOYON DRILLING INC. Rig Name: DOYON 14 i Date ;From - To ~ Hours ~ Task ~ Code NPT 11/17/2005 23:00 - 00:00 1.00 CASE P 11/18/2005 00:00 - 00:30 0.50 CASE P 00:30 - 02:00 1.50 CASE P 02:00 - 03:30 I 1.501 CASE I P 03:30 - 04:00 I 0.501 CASE P Start: 10/26/2005 Rig Release: 12/3/2005 Rig Number: Phase INTi INTi INT1 INTi INT1 04:00 - 06:00 2.00 CASE P INTi 06:00 - 07:30 1.50 CASE P INTi 07:30 - 08:30 1.00 CASE P INT1 08:30 - 09:30 1.00 CASE P INTi 09:30 - 10:30 1.00 CASE P INT1 10:30 - 11:30 1.00 CASE P INT1 11:30 - 13:00 1.50 CASE P INT1 13:00 - 16:00 I 3.001 CEMT I P I I INT1 16:00 - 18:30 2.50 CASE P INT1 18:30 - 19:30 1.00 DRILL P PROD1 19:30 - 20:30 1.00 DRILL P PROD1 20:30 - 21:00 0.50 DRILL P PRODi 21:00 - 22:00 1.00 DRILL P PROD1 22:00 - 00:00 2.00 DRILL P PROD1 11/19/2005 00:00 - 01:30 1.50 DRILL P PROD1 01:30 - 03:00 1.50 DRILL P PROD1 03:00 - 07:00 4.00 DRILL N SFAL PROD1 07:00 - 09:00 2.00 DRILL P PROD1 09:00 - 12:30 3.50 DRILL P PROD1 12:30 - 00:00 1 i .50 DR{LL P PROD1 11/20/2005 00:00 - 00:00 24.00 DRILL P PROD1 11/21/2005 00:00 - 01:30 1.50 DRILL P PROD1 01:30 - 02:00 I 0.501 DRILL I N I DFAL I PROD1 02:00 - 02:30 0.50 DRILL N DFAL PROD1 02:30 - 04:30 2.00 DRILL N DFAL PROD1 04:30 - 07:00 I 2.501 DRILL I N I DFAL I PROD1 07:00 - 09:00 2.00 DRILL N DFAL PRODi 09:00 - 11:30 2.50 DRILL N DFAL PROD1 Page 5 of 12 Spud Date: 11 /4/2005 End: 12/3/2005 Description of Operations PJSM, Change top rams to 2 7/8 x 5" Finish changing top ram Rig up to test rams, doors seals leaking, re tighen,still leaking, open doors, replace door seals, test rams 250-5000 psi for 5 min. per test, test witness by WSL Rig down test equipment, install wear ring, Pickup bails and Elevators, Mobilize BHA PJSM, Picking up BHA, 8 1/2 Mill tooth bit, bit sub, 5" HWD pipe, Jars PJSM, Picking up 66 jts 5" pipe from pipe shed PJSM, Cut Drill line, service top drive RIH to 5061' Wash from 5061 to 5218' Drill Cementer C~ 5218 to 5220' RIH to 7700' wash down to 7855' float collar @ 7855' Circ one bottoms up with 400 gpm 1300 psi Rig up to test CSG to 2000 psi, test csg to 2000 psi for 30 min. good test Drill out shoe track to 7941' with 80 rpm, 400 gpm, 1300 psi, wash to bottom @ 7951 PJSM, pump sweeps, Displace we11 with new 10.5 LSND mud Drill 20 ft of new hole to 7971' with 400 gpm 1300 psi, 80 rpms Circ bottoms up with 400 gpm 1300 psi, 80 rpms Pull in to Csg, FIT test with 10.5 MWT, TVD 7113, 1110 psi= 13.5 EMWT good test Circ spot EP mud tube pill, slug pipe, blow down mud lines POH POH, stand back 5" HWDP, UD BHA, Clear floor Pickup BHA #4 M/u Bit,Motor,MWD,Program same Change out REUSED not working, reprogram tool. Ran tool in hole and pumped through to warm up tool. Finish picking up BHA #4 M/u Bit,Motor,MWD,Program same,Function MWD,PJSM, Load sources RIH, fill pipe ever 25 stands, wash last stand to bottom Drilling 7972 to 8661 with 500 gpm, 2500 psi, 80 rpms, AST .86, ART 8.62,Tq 10K, ECD 11.5 Drilling 8661' to 9741' with 500 gpm, 2600 psi, 80 rpms, ECD 11.3, started to have mud loss C~ 8659, top of Shublik 8660' mixing 5 sxs per hr. of Mix II med. and 5 sxs per hr. Mix II fine, losing 28 to 30 bbls hr. slowed pumps to 475 gals min. ECD running 11.3 to 11.5, total foss 90 bbls Circ bottoms up 1.5 times, ECD starting at 11.3, final 11.3,mixing 5 sxs per hr. of Mix II med. and 5 sxs per hr. Mix II fine, still have 28 bbls hr. mud loss Attempt to drill, MW D quit, attempt to start MW D couldn't, spot 15# per bbl LCM pill, loss stopped Girc and pump Pill #2, 20# per bbls, spot on bottom, no losses Pumping out to csg shoe @7941 with full drilling rate, no losses Montor well, Circ bottoms up, over pull coming into csg., Lots of shale on bottoms up Slug pipe, POH Stand back BHA #4,PJSM, remove sources,download MWD.UD sonic,TM Hoc,Rll-SLD tool and MWD, inspect BIT Printed: 12/5/2005 11:09:03 AM BP Operations Summary Report Legal Well Name: MPS-90 Common Well Name: MPS-90 Event Name: DRILL+COMPLETE Contractor Name: DOYON DRILLING INC Rig Name: DOYON 14 Date ~ From - To ~~ Hours ~'~ Task !.Code I ---~---~_ - I 11/21/2005 09:00 - 11:30 2.50 DRILL N 11:30 - 15:30 4.00 DRILL N 15:30 - 19:00 3.50 DRILL N 19:00 - 20:30 1.50 DRILL N 20:30 - 22:00 1.50 DRILL N 22:00 - 23:00 1.00 DRILL N 23:00 - 00:00 1.00 DRILL N 11/22/2005 00:00 - 00:30 0.50 DRILL P 00:30 - 01:30 1.00 DRILL P 01:30 - 02:00 0.50 DRILL P 02:00 - 07:30 5.50 DRILL P 07:30 - 08:30 1.00 DRILL P 08:30 - 11:00 2.50 DRILL P 11:00 - 11:30 0.50 DRILL P 11:30 - 12:00 0.50 DRILL P 12:00 - 13:30 1.50 DRILL N 13:30 - 15:30 2.00 DRILL N 15:30 - 17:00 1.50 DRILL N 17:00 - 20:00 3.00 DRILL N 20:00 - 20:30 0.50 DRILL N 20:30 - 23:30 3.00 DRILL N 23:30 - 00:00 0.50 DRILL N 11/23/2005 00:00 - 01:30 1.50 EVAL P 01:30 - 05:00 3.50 EVAL P 05:00 - 05:30 I 0.501 EVAL I P 05:30 - 09:30 09:30 - 13:00 4.001 DRILL I N 3.501 DRILL I N Page 6 of 12 Spud Date: 11/4/2005 Start: 10!26/2005 End: 12/3/2005 Rig Release: 12/3/2005 Rig Number: NPT I Phase j Description of Operations DFAL PROD1 Electronics failure on MWD tool DFAL PROD1 Make up BHA # 5, load MWD,pulse test MWD, PJSM, Load source, finish picking up BHA DFAL PROD1 RIH to 7821' fill pipe ever 25 stands DFAL PROD1 Slip and cut drill line, service top drive DFAL PROD1 Circ. raise mud wt to 10.7 DFAL PROD1 RIH to 9126' DFAL PROD1 Wash and ream 9126 to 9686, tag fill at 9643', 450 gal per min. 80 rpms, 2100 psi, TQ 15k, ECD 11.4 bottoms up gas 9,000 units, mud cut to 9.7, lots of shale coming over shaker PROD1 Wash and ream to bottom 9683 to 9741' PROD1 Circ 1.5 bottoms up 475 gIm,2200 psi, 80 rpms, loads of shale med. size, no real large size., shakes started to clean up after 1.5 bottoms up, Mud loss 25-30 bbls hr PRODi MWD Quit, restart same. PROD1 Drill 9,741' to 9,830' with 475 gpm, 2200 psi. 80 rpms, raise mud wt to 11.8, mixing 5 sxs per hr of Mix II fine, 5 sxs per hr of mix II med. mud loss 25- 30 bbls hr, ECD 11.35 sliding, BG gas 300 units, C~ 04:00 shale started increasing on shakers, thumb nail size, raising mud wt to 10.9, mud loss slowed down to 7 bbls hr. PROD1 CBU 2 X -GPM 460 - PP 1920 -RPM 80 PROD1 Dril{ from 9830' to 9860' - WOB 10 to 15 -RPM 80 - TQ 13 -off 11 -GPM475-PPOn2470-off2130-PU275-S0195- ROT 230 -ECD 11.58 PROD1 Restart MWD -CBU 1/2 X -GPM 470 - PP 2100 -RPM 80 PROD1 Directional Drill -from 9860 to 9867' -GPM 475 - PP on 2470 - off2100-RPM80-TOon l3-off10-PU275-SO-195- ROT 230 -ECD 11.52 DFAL PRODi Circ ! Cond mud -GPM 540 - PP 2590 -RPM 80 - TQ 11 - MWD -Failure -Flow check DFAL PROD1 Pump out hole -From 9867' to 7941' -GPM 500 - PP 2180 DFAL PROD1 CBU 2 X ~ shoe -GPM 550 - PP 2510 -RPM 40 -Lots of shale across shakers -Shakers cleaned up after 2nd bottoms up -Flow check -Pump dry job DFAL PROD1 POOH -From 7941 to 774' (~ BHA DFAL PROD1 Stand back HWDP - DC's DFAL PROD1 PJSM -Remove Nuke sources -Down load MWD - LD MWD - Break bit - LD motor DFAL PROD1 Clear rig floor -Pull wear ring PROD1 Install test plug -Open annulus valves - RU testing equipment PROD1 Test BOP's -Annular 250 low 2500 high 5 mins each test -Top VBR rams -Choke manifold -Choke /Kill HCR valves -Manual Choke /Kill valves -Upper 1 Lower IBOP -Floor safety valve - Dart valve -Bottom VBR rams -Blind rams - 250 low - 5000 high - 5 mins each test -Jeff Jones with AOGCC waived witness of BOP test -All test witnessed by W SL PROD1 Pull test plug -Install wear ring -Close annulus valves - LD test joint - Moblize BHA to rig floor DFAL PROD1 MU BHA -Bit -motor -MWD -Orient same -Upload -Function test -PJSM -Load Nukes -Run DC's -Jars -HWDP DFAL PROD1 RIH with BHA #6 -from 774' to 7941' -Controlled running Printed: 12/5/2005 11:09:03 AM • gp Page 7 of 12 Operations Summary Report Legal Well Name: MPS-90 Common W ell Name: MPS-90 Spud Date: 11/4/2005 Event Nam e: DRILL+C OMPLE TE Start : 10/26/2005 End: 12/3/2005 Contractor Name: DOYON DRILLIN G INC . Rig Release: 12/3/2005 Rig Name: DOYON 14 Rig Number: Date ii From - To II Hours ~ Task i - Code ~ I NPT ~ I Phase ~ ! Description of Operations - - _ 11/23/2005 - 09:30 - 13:00 --- 3.50 DRILL N DFAL _ _ __ PROD1 - - - - __ _ - __ _ - speed to reduce surge pressure 13:00 - 14:30 1.50 DRILL N DFAL PRODi CBU hole volume C~ shoe -GPM 480 - PP 2070 -RPM 40 - TO 13.5 14:30 - 17:00 2.50 DRILL N DFAL PROD1 RIH from 7941' to 9764' -Tag fill (100')- Wash /Ream from 9764' to 9867' -GPM 300 to 400 - PP 1180 to 1740 -RPM 80 - TO 13 17:00 - 00:00 7.00 DRILL P PROD1 Drill from 9867' to 10253' - WOB 10 to 20 -RPM 80 - TO on 17 -off 14-GPM470-PPon 2490-off 2210-PU275-S0200- ROT 235 -ECD 11.75 11/24/2005 00:00 - 08:30 8.50 DRILL P PROD1 Drill from 10253' to 10600' - T.D. 8 1/2" Hole - WOB 10 to 20 - RPM80-TQon24-off20-GPM470-PPon2440-off 2240 - PU 290 - SO 205 -ROT 245 -ECD 11.7 -ART= 7.2 AST= 0.0 ADT= 7.2 08:30 - 11:30 3.00 CASE P PRODi Circulate 4 x bottoms up 466 gpm = 2140psi /Rotate @80 rpm and reciprocate -Flow check 11:30 - 14:00 2.50 CASE P PROD1 Short trip out to shoe tight C~3 10,000', 9959', 9713', and 9664' pulled 20-50k worked through spots 14:00 - 15:30 1.50 CASE P PROD1 CBU GPM 470 - PP 1980 -RPM 40 15:30 - 17:00 1.50 CASE P PROD1 Cut drlg line -Top drive service -Rig service 17:00 - 18:00 1.00 CASE P PROD1 RIH from 7900' to 10501' -Break circulation -Stage up pumps - Precautionary wash to bottom - 25' fill on bottom 18:00 - 21:30 3.50 CASE P PROD1 CBU 4 X -GPM 470 - PP 2250 -RPM 80 - TQ 12 -ECD 11.7 - Flow Check 21:30 - 23:30 2.00 CASE P PRODi POH from 10,600' to 7900' -Tight @ 10002', 9965', 9876' - 30 to 50K over - Work through tight spots - Con't POH to shoe 23:30 - 00:00 0.50 CASE P PRODi CBU 4 X -GPM 500 - PP 2100 -RPM 40 - TQ 9.5 11/25/2005 00:00 - 02:30 2.50 CASE P PROD1 CBU 4 X -GPM 500 - PP 2100 -RPM 40 - TO 7.5 - 11.61 - Flow check -Pump dry job 02:30 - 05:00 2.50 CASE P PROD1 POH from 7900' to 774' 05:00 - 08:30 3.50 CASE P PROD1 Stand back HWDP - DC's -Down load MWD -PJSM -Remove Nukes - LD MWD - Sreak bit - LD Motor 08:30 - 10:00 1.50 CASE P PROD1 Clear Rig Floor /Rig up to run 7" Liner 10:00 - 15:30 5.50 CASE P PROD1 PJSM Run 7" #26 L-80 BTC-M Liner to 2830' Make up ZXP HangerlPacker 15:30 - 16:30 1.00 CASE P PROD1 Circulate Liner volume @ 5.5 bbl/min - 230gpm 300psi Pick up wt 105K Slack off 102K 16:30 - 20:00 3.50 CASE P PROD1 RIH with 7" Liner at controlled speed -From 2830' to 7900' -Fill every 25 stands 20:00 - 23:30 3.50 CASE P PRODi Circulate /Condition mud -Stage up pump from 2.5 BPM to 5.5 BPM - PP 860 -Pumped 100 bbls -Pressure increasing flow decreasing -losing mud -Slow pump to 2.5 bpm - PP 980 - Loss stopped -Staged pump up to 3.5 BPM - PP 800 - No loss -Stage up pump to 5 BPM - PP 950 -Losing mud - Decrease rate to 4.5 BPM - 850 -Holding -Circulate surface to surface -Lots of air cut mud back -Stage up pump to 5.5 BPM - 840 psi - No losses -Circulate total 780 bbls -Lost total 54 bbls - PUW 215 -SOW 155 -Blow down top drive 23:30 - 00:00 0.50 CASE P PROD1 Con't RIH with 7" Liner from 7900' to 8900' 11/26/2005 00:00 - 01:30 1.50 CASE P PRODi Con't RIH with 7" liner from 8900' to 9200' -Break circulation - Con't RIH from 9200' to 10499' -Break circulation wash last stand to bottom from 10499 to 10594' 01:30 - 05:00 3.50 CASE P PROD1 Make up Baker plug dropping head -Cementing lines - 6' fill - Wash from 10594' to 10600' -Circulate /Condition mud for Printed: 12/5)2005 11:09:03 AM • BP Page 8 of 12 Operations Summary Report Legal Well Name: MPS-90 Common W ell Name: MPS-90 Spud Date: 11/4/2005 Event Nam e: DRILL+C OMPLE TE Start : 10/26/2005 End: 12/3/2005 Contractor Name: DOYON DRILLIN G INC . Rig Release: 12/3/2005 Rig Name: DOYON 14 Rig Number: Date From - To ~ Hours ~~ Task I Code ~ NPT Phase Descriptron of Operations _ L- I -- ~ -------- 11/26/2005 01:30 - 05:00 3.50 CASE P PROD1 cement job 05:00 - 06:30 i.50 CEMT P PROD1 Give to Schlumberger Dowell - Pump 5 bbls water Test lines to 4000 psi Pump 40 bbls Mud Push mixed @ 12 ppg - 3.1 bpm @ 550 PSI Pump 103 bbls Class "G" Cement mixed @ 15.8 ppg - 4.8 bpm @ 500 PSI Dropping to 25 psi Shut down -Close isolation valve -Drop dart -Test isolation valve to 1200 psi -Flush cementing line with 11 ppg brine - Open isolation valve Kick out plug with 110 bbls 11 ppg brine with Schlumberger Give to rig - Displace with 131.5 bbls 10.9 ppg mud - 5 BPM @ 1150 psi Bump plug with 3500 psi Cement in place @ 06:34 hrs 06:30 - 07:30 1.00 CASE P PROD1 Set HMC hanger - ZXP Packer -Release off liner - Circ out cement at 12 BPM @ 1670 psi -Contaminated mud back to suface 07:30 - 08:00 0.50 CASE P PROD1 Lay down Baker plug dropping head 08:00 - 08:30 0.50 CASE P PROD1 CBU - 12.3 BPM @ 1140 psi -Reciprocate string 90' strokes 08:30 - 09:00 0.50 CASE P PROD1 Test liner lap to 1000 psi for 10 mins -Good test 09:00 - 09:30 0.50 CASE P PROD1 CBU 1.5 X - 18 BPM @ 2100 psi -Reciprocate 90' strokes 09:30 - 18:30 9.00 CASE P PROD1 Cleaning pits -Filling with 10 ppg brine for displacement 18:30 - 21:30 3.00 CASE P PROD1 PJSM -Displacement of 10 ppg brine -Displace well with 10 ppg brine as follows 40 bbls Fresh water Hi-vis spacer - 8 BPM @ 1150 100 bbls fresh water - BPM @ 1150 50 bbls Hi-vis spacer - 9.9 BPM @ 1370 50 bbls Brine - 12.5 BPM @ 1510 50 bbls Hi-vis spacer - 13.4 BPM @ 1360 560 bbls 10 ppg brine - 8 to 16 BPM @ 600 to 1450 Fill Pit # 3 with HI-Vis Pert pill -Flow Check -Well Static Spot 100 bbls Hi-vis Perf pill on top of liner - 12 BPM 680 21:30 - 00:00 2.50 CASE P PROD1 Flow Check -Well Static -Blow down Top Drive - POH - Standing back 56 stands 5" DP 11/27/2005 00:00 - 02:00 2.00 CASE P PROD1 LD 26 stands of 5" DP -Baker 7" Liner running tool 02:00 - 02:30 0.50 CASE P PROD1 RU 4" Handling equipment 02:30 -04:30 2.00 CASE P PROD1 RIH Flex DC's - 5" HWDP -Jars - PU 69 joints 4" DP from pipe shed 04:30 - 05:30 1.00 CASE P PROD1 PJSM -Cut drlg line -Top drive service -Rig service 05:30 - 06:30 1.00 CASE P PROD1 POH with 4" DP 06:30 - 07:30 1.00 CASE P PROD1 LD DC's - 5" HWDP -Jars 07:30 - 14:00 6.50 BUNCO RUNCMP RU Schlumberger -RIH RUN USIT log on 7" Liner - RD Schlumberger 14:00 - 15:00 1.00 BUNCO RUNCMP RU testing equipment -Test casing to 4000 psi -Chart on recorder for 30 mins -Test good - RD testing equipment 15:00 - 17:30 2.50 BUNCO RUNCMP PJSM - MU Perforating BHA -Guns - 3 i/2" DP -Bumper sub - Floatsub -MWD - 10' 4" DP pup -Test MWD @ 200 GPM 17:30 - 00:00 6.50 BUNCO RUNCMP RIH with perforating guns -Fill every 25 stands - 3.5BPM @ 720 psi -Tag landing plug @ 1051 i' 11/28/2005 00:00 - 04:00 4.00 EVAL P PROD1 Running tie in log for perforating 04:00 - 05:00 1.00 PERFO P OTHCMP PJSM -Perforating -Guns on depth -Close Top rams - Printed: 12/5/2005 11:09:03 AM • gp Page 9 of 12 Operations Summary Report Legal Well Name: MPS-90 Common Wetl Name: MPS-90 Spud Date: 11/4/2005 Event Name: DRILL+COMPLETE Start: 10/26/2005 End: 12!3/2005 Contractor Name: DOYON DRILLING INC. Rig Release: 12/3J2005 Rig Name: DOYON 14 Rig Number: Date ~ From - To I; Nours 'I Task ~i Code ~ NPT ~ Phase li Description of Operations 11/28/2005 104:00 - 05:00 ~ 1.00 1112912005 11/30/2005 05:00 - 06:00 06:00 - 08:30 08:30 - 09:00 09:00 - 14:00 14:00 - 14:30 14:30 - 16:30 16:30 - 20:30 20:30 - 21:00 21:00 - 00:00 00:00 - 01:00 01:00 - 04:30 04:30 - 05:00 05:00 - 09:00 09:00 - 09:30 09:30 - 10:00 10:00 - 11:30 11:30 - 12:30 12:30 - 13:00 13:00 - 14:30 1.00 2.50 0.50 5.00 0.50 2.00 4.00 0.50 3.00 1.00 3.50 0.50 BUNCO 4.00 BUNCO 0.50 BUNCO 0.50 BUNCO 1.50 BUNCO 1.00 BUNCO 0.50 BUNCO 1.501 RU 14:30 - 17:00 2.50 RUN 17:00 - 18:30 1.50 RUN 18:30 - 20:30 2.00 RUN 20:30 - 21:00 0.50 RUN 21:00 - 22:00 1.00 RUN 22:00 - 23:30 1.50 RUN 23:30 - 00:00 00:00 - 01:00 01:00 - 01:30 01:30 - 02:00 02:00 - 03:00 0.50 RUN 1.00 RUN 0.50 0.50 RUN 1.00 RUN P OTHCMP _ _ - - - -- Pressure to 3500 psi -Hold for 2 mins -bleed off pressure - Guns fired three mins -Perforating depths 9884 to 9996 - 112' - 10026 to 10064 - 38' 10088 to 10322 - 234' Total footage perforated 384' RUNCMP Monitor well - We{I stable -Pull 6 stands -Monitor well 30 mins RUNCMP CBU 1.5 X - 5.4 BPM @ 800 psi RUNCMP Flow check -Blow down Top drive RUNCMP POH -Standing back 5" DP - LD 4" DP RUNCMP Circ 130 degree 10 ppg brine @ 2100' RUNCMP Con't LD 4" DP RUNCMP PJSM - LD Guns -Perforating BHA -Clear floor DPRB RUNCMP MU 9 5/8" RTTS Packer -Circ valve DPRB RUNCMP RIH with RTTS to 6106' DPRB RUNCMP Con't to RIH with RTTS from 6106' to 7765' DPRB RUNCMP Rig up testing fines -Set RTTS packer middle of element 7759' -Pressure up 9 5/8" casg to 2500 psi -Attempt to establish injection rate on outer annulus -Bleed pressure off nutter annulus -Bleed off pressure off 9 518" casg - RD testing lines -Unseat RTTS packer - DPRB RUNCMP Monitor well - DPRB RUNCMP POH with RTTS packer DPRB RUNCMP LD RTTS Packer DPRB RUNCMP MU Howco retrievable bridge plug DPRB RUNCMP RIH with bridge plug to 4045' DPRB RUNCMP Set Retrievable bridge plug @ 4038' DPRB RUNCMP Test bridge plug to 3500 psi for 30 mins -Record on chart - Test good DPRB RUNCMP PJSM -Pump sand on top bridge plfug Pump 5 bbls Brine Test lines 4000 psi 2 bbls Hi-vis spacer 4 bbls 20-40 sand slurry 5 bbls Hi-vis spacer spot with 67 bbls brine Pull 1 stand DPRB RUNCMP Wait on trucks for 10 ppg mud DPRB RUNCMP Displace brine with 70 bbls Hi-vis spacer - 190 bbls 10 ppg mud @ 3915' DPRB RUNCMP POH with Howco retrievable running tools DPRB RUNCMP Lay down Howco running tool - Moblize Baker tools to rig floor DPRB RUNCMP PU test joint -Pull wear ring -Back out lock down screws -Pull pack-off DPRB RUNCMP MU 9 5/8" 40# Baker casg spear -Spear casg -Take stretch reading ~ 50, 100, 150 over string weight -release spear - POH - LD spear RUNCMP Cut Drlg line RUNCMP Cut drlg line -Top Drive service -Rig service N DPRB RUNCMP Install wear ring - LD test joint DPRB RUNCMP BHA - MU Baker casing cutter DPRB RUNCMP RIH with cutter to 1958 Printed: 12/512005 11:09:03 AM • gP Page 10 of 12 Operations Summary Report Legal We{I Name: MPS-80 Common W ell Name: MPS-90 Spud Date: 1114/2005 Event Nam e: DRILL+C OMPLE TE Start : 10/26/2005 End: 12/3/2005 Contractor Name: DOYON DRILLIN G INC . Rig Release: 12/3/2005 Rig Name: DOYON 14 Rig Number: Date ~ ~ From - To i Hours Task ~ - ~ , Code ~ NPT I' 1 ~ ~ Phase Description of Operations 11/30/2005 03:00 - 04:00 1.00 - - _ N DPRB ~ RUNCMP - - - _ _ -_ __ _- Locate collar @ 1959' -Pull up to 1939' cut casg - SPM 10 C~ 100 psi to 26 C~? 540 psi -RPM 40 to 80 - TO 1 to 7K -Confirm cut -String dropped 1'- top string 1940' 04:00 - 04:30 0.50 BUNCO DPRB RUNCMP Pump sweep - 6 BPM @ 2200 psi 04:30 - 05:30 1.00 BUNCO DPRB RUNCMP Flow check - POH with Baker casg cutter 05:30 - 06:00 0.50 BUNCO DPRB RUNCMP LD BHA 06:00 - 06:30 0.50 BUNCO DPRB RUNCMP Pull wear ring 06:30 - 07:30 1.00 BUNCO DPRB RUNCMP RU spear assembly 07:30 - 08:00 0.50 BUNCO DPRB RUNCMP Engage spear -Pull hanger free w/ 125k up -Pull casing to rig floor w1 120k up -Release spear & LD same 08:00 - 09:00 1.00 BUNCO DPRB RUNCMP RU casing equip. 09:00 - 14:00 5.00 BUNCO DPRB RUNCMP LD 9 5/8" 40# casing -Recovered 45 joints + cut jt. (22.54' ) 14:00 - 15:00 1.00 BUNCO DPRB RUNCMP Clear rig floor- LD casing equip.- Change out handling equip.- Install wear ring. 15:00 - 16:30 1.50 BUNCO DPRB RUNCMP MU mule shoe on 5" DP & RIH to 2070' 16:30 - 19:00 2.50 BUNCO DPRB RUNCMP PJSM -Rev. circ. 35 bbl. hi-visc. spacer - 5 bpm 550 psi - Charge rig pumps w/ vac. truck -Rev. circ. & displace well w/ diesel - 5 bpm 600 psi. 19:00 - 20:00 1.00 BUNCO DPRB RUNCMP POH - LD Mule shoe 20:00 - 22:30 2.50 BUNCO DPRB RUNCMP PU Baker casing back off too{ 22:30 - 00:00 1.50 BUNCO DPRB RUNCMP RIH with back off tool to 1949' -Fill DP with water on trip in 12!1!2005 00:00 - 01:00 1.00 BUNCO DPRB RUNCMP RU cementing lines to function back off tool 01:00 - 02:30 1.50 BUNCO DPRB RUNCMP PUW 115 -SOW 115 -Pressure up to 1500 psi to set Btm slips -sheared @ 750 psi -Slack off to 95K - PU to 96K - Pressure up to 1700 psi to set top slips -Slack off 80K -Set DP slips -Slack off on blocks -Top slips set @ 1946' - BTM slips set C~ 1973' -Pressure up to 4000 psi to turn tool -Tool cycled but pipe did not turn -Bleed off pressure -Pressure up 4000 with same results -Bleed off pressure -Pressure up to 5000 - (4000 with rig pump then to 5000 with test pump) - Could not tell that tool was cycling - No pipe movement -Bleed off pressure -Pressure up to 4000 psi - No indication of tool cycling or pipe movement 02:30 - 03:00 0.50 BUNCO DPRB RUNCMP Pull tool lose @ 120K -Break down cementing lines 03:00 - 04:00 1.00 BUNCO DPRB RUNCMP POH with back-off tool -Last 5 stands of drill pipe and 2 stands HWDP had emulsified mud on top of back-off tool 04:00 - 05:00 1.00 BUNCO DPRB RUNCMP Cycle back-off tool three times -Tool cycled with 250 psi 1/4" round each cycle -Blow down top drive -Install new shear pins in top & bottom anchors. 05:00 - 07:30 2.50 BUNCO DPRB RUNCMP R!H w! casing backoff tool -Spot power section across collar at 1960'. 07:30 - 08:00 0.50 BUNCO DPRB RUNCMP RU to back out 9 5/8" casing stub. 08:00 - 09:30 1.50 BUNCO DPRB RUNCMP Press. to 1000 psi (observed shear at 800 psi) to set bottom anchor -Set down 25k -Wait 15 min. -set down 5k more - Press. to 4000 psi - No indication of top anchor shear - Bleed off -Set down all weight (35k) & slack off elevators -Press. to 4000 psi - No turn. 09:30 - 11:00 1.50 BUNCO DPRB RUNCMP RU on annulus - Pressure up to 500 psi to assist tool in cycle - Bleed off -Press. down DP -Casing broke w/ 1400 psi. 3/4 turn on pipe- Continue to cycle tool & press. up until 6 turns were achieved. 11:00 - 13:00 2.00 BUNCO DPRB RUNCMP Pick up on string to release anchors - POH ~ 13:00 - 14:30 1.50 BUNCO DPRB RUNCMP LD casing backoff tool (all screws were sheared ). Printed: 12/5/2005 11:09:03 AM • gp Page 11 of 12 Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date ~ From - To ~, Hours I Task 12/1/2005 14:30 - 15:30 1.00 RUNC( 15:30 - 16:30 1.00 RUNC( 16:30 - 17:00 0.50 RUNC( 17:30 - 18:00 0.50 RUNC( MPS-90 MPS-90 Spud Date: 11/4/2005 DRILL+COMPLETE Start: 10/2612005 End: 12/3/2005 DOYON DRILLING INC. Rig Release: 12/3/2005 DOYON 14 Rig Number: Code NPT I Phase Description of Operations V DPRB RUNCMP Pull wear ring - PU spear BHA N DPRB RUNCMP RIH -POW 85 -SOW 85 V DPRB RUNCMP Engage stump -Back out N DPRB RUNCMP LD cut 9 5/8" casg stump -Total recovered 19.88 -Pin in excellent shape -Make service breaks - LD spear asst' V DPRB RUNCMP Clear rig floor - LD Baker tools - RU to run 9 5/8" casing V DPRB RUNCMP PJSM - MU cut lip guide -Triple connection bushing -Run 9 5/8" L-80 BTC-M casg to 1938' -Change out bails, elevators - Make up last joint run in and tag up on collar @ 1960' V DPRB RUNCMP Change bails/ elevators -Make up last joint run in and tag up on collar @ 1960' - RU to reverse diesel on annulus V DPRB RUNCMP Reverse circulate 32.9 bbls diesel in annulus N DPRB RUNCMP Screw into collar on 9 5/8" casing - 12 rds 9000 TO - 4 additional rds for total 16 with 9000 TO -First 10 joints ran average 11.5 rds with 8200 TQ V DPRB RUNCMP Pressure test 9 5/8" casing to 3500 psi -Record on chart for 30 mins -Test good V DPRB RUNCMP Blow down top drive -injection line -other circulating line V .DPRB RUNCMP ND stack - PU stack for setting slips V DPRB RUNCMP Set emergency slips -String weight 290K -Blocks 50K - Weight on slips 240K (165 over string weight at screw in) V DPRB RUNCMP Void 60' of 9 5/8" casing to cut off - Ru to cut casing V DPRB RUNCMP Cut casing w/ Wachs cutter -Break out cut piece f/ landing joint. V DPRB RUNCMP Install pack-off -Test pack-off -Flanges to 3000 psi for 10 mins - Good test V DPRB RUNCMP Continue NU BOP equip. V DPRB RUNCMP Install wear ring V DPRB RUNCMP Change out bales -Clear rig floor V DPRB RUNCMP MU retrievable bridge plug tool -RIH 2000' V DPRB RUNCMP Displace diesel - BPM 9 - PP 220 V DPRB RUNCMP RIH 4038' -Wash down to top RBP V DPRB RUNCMP Circulate 10 ppg LSND mud surface to surface V DPRB RUNCMP Displace well w/ 10.0 ppg brine -Pump 35 bbl. polymer spacer - 150 bbl H2O - 35 bb{ polymer spacer - 300 bbls 10.Oppg brine w/ 600 gpm. V DPRB RUNCMP Set down & engage RBP w/ retrieving tool. Pull free w/ 15k over- Monitor well - CBU 1x w/ 1280 psi 80 spm V DPRB RUNCMP Blow down T.D. & monitor well f/ 30 min. V DPRB RUNCMP POH - LD 5" DP V DPRB RUNCMP Clear rig floor of Howco tools -Monitor well RUNCMP RIH with 5" from derrick to 4000' RUNCMP RIH to 4000' RUNCMP LD 5" DP RUNCMP Pull wear ring RUNCMP RU tubing tools to run kill string RUNCMP PJSM - PU /Run 96 joints 5.5" L-80 17# IBT-M tubing to 4012' RUNCMP PU hanger -obtain parameters - PU wt. 107k w/ blocks - Dn wt. 100k w/ Blocks (blocks = 55k ). Land tubing -Run in lock down screws. Test TWC to 1000 psi RUNCMP Blow down lines on rig floor & BOP's RUNCMP ND BOPE RUNCMP NU adapter flange & tree. 18:00 - 19:00 1.00 19:00 - 23:00 4.00 23:00 - 00:00 1.00 12/2/2005 00:00 - 01:00 1.00 01:00 - 02:00 1.00 02:00 - 03:00 12/3/2005 03:00 - 03:30 03:30 - 04:30 04:30 - 05:30 05:30 - 07:00 07:00 - 08:30 08:30 - 09:30 09:30 - 10:30 10:30 - 11:00 11:00 - 11:30 11:30 - 12:30 12:30 - 13:30 13:30 - 14:30 14:30 - 15:00 15:00 - 18:00 18:00 - 19:00 19:00 - 19:30 19:30 - 23:00 23:00 - 23:30 23:30 - 00:00 00:00 - 01:00 01:00 - 03:30 03:30 - 04:00 04:00 - 04:30 04:30 - 08:30 08:30 - 09:30 09:30 - 10:00 10:00 - 12:00 12:00 - 14:30 1.00 0.50 1.00 1.00 1.50 1.50 1.00 1.00 0.50 0.50 1.00 1.00 1.00 0.50 3.00 1.00 0.50 BUNCO 3.50 BUNCO 0.50 BUNCO 0.50 BUNCO 1.00 BUNCO 2.50 BUNCO 0.50 BUNCO 0.50 BUNCO 4.00 BUNCO 1.00 BUNCO 0.50 BUNCO 2.00 BUNCO 2.50 BUNCO Printed: 12!5/2005 11:09:03 AM Printed: 72/5/2005 17:09:03 AM Printed: 12/5/2005 11:08:57 AM ~ ~ i Halliburton Global Company: BP Amoco Date: 12/20/2005 Time: 08:35:05 Page: ] ~ Field: Milne Point Co-ordinate(NE) Reference: W ell: MPS-90, True North ~ Site: M Pt S Pad Vertical ('fVD) Refer ence: MPS-90 72.0 WeIL• MPS-90 Section (VS) Reference: Well (O.OON,O.OOE,310.90Azi) Wellpath: MPS-90 - - -_ _ _ ._ ____ - _ _- _- _ _ Survev Calculation Method: Mi .-._-_ _ _ _ _ _ _ __ nimum Curvature - _ _ . _ Db: Oracle _ _- -. _- _ _i Field: Milne Point North Slope UNITED STATES Map System:US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 Geo Datum: NAD27 (Cla rke 1866) Coordinate Syste m: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2005 Well: MPS-90 Slot Name: Well Position: +N/-S 84.31 ft Northing: 6000060.44 ft Latitude: 70 24 38.158 N +E/-W -209.69 ft Easting : 566134. 59 ft Longitude: 149 27 41.317 W Position Uncertainty: 0.00 ft Wellpath: MPS-90 Drilled From: Well Ref. Point 500292327600 Tie-on Depth: 34.00 ft Current Datum: MPS-90 Height 72.00 ft Above System Datum: Mean Sea Level Magnetic Data: 10/28/2005 Declination: 24.39 deg Field Strength: 57575 nT Mag Dip Angle: 80.87 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ft ft ft deg 34.00 0.00 0.00 310.90 Survey Program for Definitive Wellpath Date: 11/30/2005 Validated: Yes Version: 6 Actual From To Survey Toolcode Tool Nam e ft ft 100.00 808.00 MPS-90 GYRO (100.00-808.00) CB-GYRO-SS Camera based gyro single shots 837.10 10533.40 MPS-90 IIFR (837:10-10533.40) MWD+IFR+MS MWD +IFR + Muiti Station Survey A1D Incl lzim TVD Sys"fVD N/S IC/W MapV J1apE "fool I ft deg _ deg ft ft ft ft ft ft __ - _ _ 34.00 0.00 __ _ 0.00 34.00 _ -38.00 - - _ 0.00 0.00 6000060.44 - _ 566134.59 - - - TIE LINE 100.00 0.41 8.17 100.00 28.00 0.23 0.03 6000060.67 566134.62 CB-GYRO-SS 171.00 0.77 347.35 171.00 99.00 0.95 -0.03 6000061.39 566134.55 CB-GYRO-SS 261.00 0.33 226.42 260.99 188.99 1.36 -0.36 6000061.80 566134.22 CB-GYRO-SS 350.00 3.17 180.25 349.94 277.94 -1.28 -0.55 6000059.16 566134.05 CB-GYRO-SS 441.00 5.09 180.14 440.70 368.70 -7.83 -0.57 6000052.61 566134.09 CB-GYRO-SS 532.00 5.70 178.23 531.30 459.30 -16.38 -0.44 6000044.06 566134.29 CB-GYRO-SS 621.00 4.90 179.75 619.92 547.92 -24.60 -0.29 6000035.84 566134.52 CB-GYRO-SS 714.00 2.84 183.97 712.70 640.70 -30.87 -0.43 6000029.57 566134.43 CB-GYRO-SS 808.00 1.06 191.96 806.64 734.64 -34.05 -0.77 6000026.39 566134.12 CB-GYRO-SS 837.10 0.65 196.54 835.74 763.74 -34.47 -0.88 6000025.97 566134.02 MWD+IFR+MS 929.05 0.20 276.10 927.69 855.69 -34.95 -1.18 6000025.48 566133.72 MWD+IFR+MS 1023.56 0.09 319.31 1022.20 950.20 -34.88 -1.40 6000025.55 566133.50 MWD+IFR+MS 1118.40 0.52 8.21 1117.04 1045.04 -34.40 -1.38 6000026.04 566133.51 MWD+IFR+MS 1211.54 0.99 357.95 1210.17 1138.17 -33.17 -1.35 6000027.26 566133.53 MWD+IFR+MS 1306.83 1.45 353.95 1305.44 1233.44 -31.15 -1.51 6000029.28 566133.36 MWD+IFR+MS 1401.01 1.64 357.59 1399.58 1327.58 -28.62 -1.69 6000031.81 566133.15 MWD+IFR+MS 1493.09 0.69 2.81 1491.64 1419.64 -26.75 -1.72 6000033.68 566133.11 MWD+IFR+MS 1586.52 0.88 27.83 1585.06 1513.06 -25.55 -1.36 6000034.88 566133.46 MWD+IFR+MS 1680.52 1.16 36.37 1679.05 1607.05 -24.15 -0.46 6000036.29 566134.35 MWD+IFR+MS 1774.46 0.61 73.98 1772.98 1700.98 -23.24 0.59 6000037.20 566135.39 MWD+IFR+MS 1869.86 0.48 109.04 1868.37 1796.37 -23.23 1.46 6000037.22 566136.25 MWD+IFR+MS 1963.80 1.88 310.77 1962.30 1890.30 -22.36 0.66 6000038.09 566135.45 MWD+IFR+MS 2057.85 7.05 312.47 2056.03 1984.03 -17.45 -4.77 6000042.95 566129.98 MWD+IFR+MS 2151.43 9.21 314.03 2148.67 2076.67 -8.37 -14.39 6000051.95 566120.28 MWD+IFR+MS 2244.44 8.84 313.41 2240.52 2168.52 1.72 -24.93 6000061.94 566109.64 MWD+IFR+MS 2337.97 11.16 313.29 2332.63 2260.63 12.87 -36.74 6000072.98 566097.74 MWD+IFR+MS 2427.21 14.76 314.65 2419.58 2347.58 26.78 -51.12 6000086.77 566083.24 MWD+IFR+MS 2522.11 19.35 316.88 2510.28 2438.28 46.76 -70.48 6000106.57 566063.71 MWD+IFR+MS • Halliburton Global Company: BP Amoco Date: 12/20/2005 Time: 08:35:05 Pane: 2 Field: Mil ne Point Co-ordinate(NE) Reference: Well: MPS-90, True North Site: M Pt S Pad Vertical (TVD) Refer ence: MPS -90 72.0 Well: MPS-90 Section (VS) Reference; Well (O.OON,O.OOE,310.90Azi) Wellpath: MPS-90 Survev Calculation Method: Minimum Curvature Db: Oracle Survev VID Incl Azim T~'ll Sys TVD \/S E/W MapN MapE Tool ft deg deg ft - ft ft ft ft ft J __ . 2615.00 _-_ 23.32 - - 316.75 - __ - 2596.79 _ _ _ _ 2524.79 _ __- 71.40 - __ -93.61 ____ _ 6000131.00 _ __ 566040.36 -- _ - -- MWD+IFR+MS 2709.20 27.30 316.63 2681.93 2609.93 100.69 -121.23 6000160.05 566012.49 MWD+IFR+MS 2803.20 30.90 315.08 2764.05 2692.05 133.47 -153.08 6000192.53 565980.34 MWD+IFR+MS 2898.25 34.64 314.77 2843.96 2771.96 169.79 -189.51 6000228.53 565943.60 MWD+IFR+MS 2992.08 38.52 315.56 2919.30 2847.30 209.44 -228.91 6000267.83 565903.85 MWD+IFR+MS 3085.41 42.56 315.52 2990.21 2918.21 252.73 -271.39 6000310.73 565860.99 MWD+IFR+MS 3181.07 46.36 316.76 3058.47 2986.47 301.05 -317.79 6000358.63 565814.18 MWD+IFR+MS 3269.03 47.41 317.20 3118.59 3046.59 347.99 -361.60 6000405.18 565769.96 MWD+IFR+MS 3363.47 47.95 316.40 3182.17 3110.17 398.89 -409.40 6000455.65 565721.72 MWD+IFR+MS 3456.01 46.81 317.64 3244.84 3172.84 448.70 -455.82 6000505.05 565674.85 MWD+IFR+MS 3548.97 45.31 317.53 3309.34 3237.34 498.12 -500.97 6000554.06 565629.27 MWD+IFR+MS 3642.51 45.78 316.74 3374.85 3302.85 547.06 -546.39 6000602.59 565583.43 MWD+IFR+MS 3736.93 46.84 316.48 3440.07 3368.07 596.67 -593.30 6000651.78 565536.09 MWD+IFR+MS 3830.76 48.48 315.90 3503.27 3431.27 646.72 -641.31 6000701.39 565487.64 MWD+IFR+MS 3924.72 48.97 316.50 3565.25 3493.25 697.68 -690.18 6000751.92 565438.32 MWD+IFR+MS 4016.22 48.48 316.12 3625.61 3553.61 747.41 -737.68 6000801.22 565390.39 MWD+IFR+MS 4111.97 48.01 315.39 3689.37 3617.37 798.58 -787.52 6000851.94 565340.10 MWD+IFR+MS 4206.67 48.23 316.87 3752.59 3680.59 849.41 -836.38 6000902.33 565290.80 MWD+IFR+MS 4300.48 48.12 317.59 3815.15 3743.15 900.72 -883.85 6000953.22 565242.88 MWD+IFR+MS 4393.54 47.50 318.74 3877.65 3805.65 952.09 -929.84 6001004.17 565196.44 MWD+IFR+MS 4487.68 47.21 318.92 3941.43 3869.43 1004.22 -975.42 6001055.89 565150.40 MWD+IFR+MS 4581.58 45.65 318.84 4006.15 3934.15 1055.47 -1020.16 6001106.73 565105.22 MWD+IFR+MS 4613.87 45.29 318.87 4028.79 3956.79 1072.80 -1035.31 6001123.93 565089.92 MWD+IFR+MS 4691.34 45.12 320.56 4083.37 4011.37 1114.74 -1070.86 6001165.54 565054.01 MWD+IFR+MS 4786.00 44.76 317.67 4150.39 4078.39 1165.28 -1114.61 6001215.69 565009.81 MWD+IFR+MS 4879.77 44.35 315.45 4217.21 4145.21 1213.05 -1159.83 6001263.05 564964.17 MWD+IFR+MS 4973.48 42.41 312.11 4285.32 4213.32 1257.59 -1206.27 6001307.18 564917.35 MWD+IFR+MS 5066.40 40.10 311.13 4355.18 4283.18 1298.29 -1252.06 6001347.47 564871.20 MWD+IFR+MS 5160.71 36.60 309.86 4429.13 4357.13 1336.30 -1296.53 6001385.08 564826.40 MWD+IFR+MS 5256.51 32.86 312.87 4507.85 4435.85 1372.30 -1337.52 6001420.71 564785.10 MWD+IFR+MS 5349.69 30.62 313.09 4587.09 4515.09 1405.71 -1373.38 6001453.81 564748.95 MWD+IFR+MS 5443.87 29.76 312.24 4668.50 4596.50 1437.81 -1408.20 6001485.59 564713.85 MWD+IFR+MS 5537.80 29.47 311.32 4750.16 4678.16 1468.74 -1442.81 6001516.21 564678.96 MWD+IFR+MS 5631.22 27.59 310.37 4832.23 4760.23 1497.93 -1476.56 6001545.09 564644.97 MWD+IFR+MS 5723.95 24.08 310.14 4915.68 4843.68 1524.04 -1507.39 6001570.93 564613.91 MWD+IFR+MS 5814.89 20.40 309.79 4999.84 4927.84 1546.15 -1533.76 6001592.80 564587.35 MWD+IFR+MS 5909.24 16.66 308.65 5089.28 5017.28 1565.13 -1556.97 6001611.57 564563.97 MWD+IFR+MS 6002.35 12.74 310.17 5179.33 5107.33 1580.09 -1575.24 6001626.37 564545.57 MWD+IFR+MS 6096.39 8.90 311.08 5271.68 5199.68 1591.57 -1588.65 6001637.73 564532.06 MWD+IFR+MS 6189.93 6.55 307.20 5364.36 5292.36 1599.55 -1598.36 6001645.62 564522.28 MWD+IFR+MS 6284.19 5.06 297.29 5458.14 5386.14 1604.70 -1606.34 6001650.71 564514.26 MWD+IFR+MS 6377.86 3.25 271.26 5551.57 5479.57 1606.66 -1612.66 6001652.60 564507.92 MWD+IFR+MS 6472.72 1.54 239.59 5646.34 5574.34 1606.07 -1616.45 6001651.98 564504.13 MWD+{FR+MS 6566.39 2.50 190.93 5739.96 5667.96 1603.43 -1617.92 6001649.33 564502.69 MWD+IFR+MS 6609.67 3.36 186.90 5783.18 5711.18 1601.24 -1618.26 6001647.14 564502.37 MWD+IFR+MS 6655.69 3.19 182.56 5829.13 5757.13 1598.62 -1618.48 6001644.52 564502.18 MWD+IFR+MS 6750.15 2.79 185.52 5923.46 5851.46 1593.71 -1618.81 6001639.60 564501.88 MWD+IFR+MS 6842.36 2.54 187.50 6015.57 5943.57 1589.45 -1619.30 6001635.34 564501.44 MWD+IFR+MS 6936.41 2.08 198.98 6109.54 6037.54 1585.77 -1620.12 6001631.65 564500.64 MWD+IFR+MS 7030.15 2.12 200.32 6203.22 6131.22 1582.54 -1621.28 6001628.41 564499.52 MWD+IFR+MS 7123.72 2.43 189.12 6296.72 6224.72 1578.95 -1622.19 6001624.82 564498.63 MWD+IFR+MS 7217.38 2.67 185.47 6390.28 6318.28 1574.82 -1622.72 6001620.68 564498.15 MWD+IFR+MS • Halliburton Global Company: BP Amoco Date: 12!20/2005 'l'ime: 08:35:05 Page: 3 i Field: Mil ne Point Co-ord inate(NE) Reference: Well: MPS-90, True North I Site: M Pt S Pad Vertical (TVD) Refer ence: MPS -90 72.0 Well: MPS-90 Section (VS) Reference: Well (O.OON,Q_OOE,310.90Azi} Wellpath: MPS-90 Survey Calculation Mcthod: Minimum Curvature Db: Oracle Survey MD Inc! .acim TVD Sys TVD \/S E/W ~tapN MapE Tool ft deg deg ft ft ft ft ft ft 7311.64 2.80 183.84 6484.44 6412.44 1570.34 -1623.08 6001616.20 564497.82 MWD+IFR+MS 7402.76 2.72 185.07 6575.45 6503.45 1565.97 -1623.42 6001611.82 564497.52 MWD+IFR+MS 7498.54 2.63 181.08 6671.13 6599.13 1561.50 -1623.66 6001607.36 564497.32 MWD+IFR+MS 7592.72 2.63 183.27 6765.21 6693.21 1557.19 -1623.83 6001603.04 564497.19 MWD+IFR+MS 7687.09 2.51 182.47 6859.48 6787.48 1552.96 -1624.04 6001598.81 564497.02 MWD+IFR+MS 7779.88 2.34 180.47 6952.19 6880.19 1549.04 -1624.14 6001594.89 564496.95 MWD+IFR+MS 7874.09 2.12 178.90 7046.33 6974.33 1545.37 -1624.12 6001591.22 564497.00 MWD+IFR+MS 7961.35 1.99 181.12 7133.53 7061.53 1542.24 -1624.12 6001588.10 564497.03 MWD+IFR+MS 8055.64 1.76 189.15 7227.77 7155.77 1539.18 -1624.39 6001585.03 564496.79 MWD+IFR+MS 8149.90 1.60 182.87 7321.99 7249.99 1536.43 -1624.68 6001582.28 564496.52 MWD+IFR+MS 8242.64 1.60 183.73 7414.70 7342.70 1533.85 -1624.83 6001579.70 564496.40 MWD+IFR+MS 8336.89 1.61 173.87 7508.91 7436.91 1531.22 -1624.77 6001577.07 564496.48 MWD+IFR+MS 8431.60 2.38 175.31 7603.56 7531.56 1527.94 -1624.47 6001573.79 564496.81 MWD+IFR+MS 8526.46 3.92 173.92 7698.27 7626.27 1522.75 -1623.97 6001568.60 564497.36 MWD+IFR+MS 8622.25 3.55 176.45 7793.86 7721.86 1516.53 -1623.44 6001562.39 564497.94 MWD+IFR+MS 8713.70 3.00 171.27 7885.16 7813.16 1511.34 -1622.90 6001557.21 564498.53 MWD+IFR+MS 8802.88 2.73 183.47 7974.23 7902.23 1506.91 -1622.67 6001552.78 564498.79 MWD+IFR+MS 8897.05 2.86 193.11 8068.29 7996.29 1502.39 -1623.34 6001548.25 564498.16 MWD+IFR+MS 8990.29 3.36 199.47 8161.39 8089.39 1497.55 -1624.78 6001543.40 564496.77 MWD+IFR+MS 9082.13 4.16 215.68 8253.04 8181.04 1492.30 -1627.62 6001538.13 564493.98 MWD+IFR+MS 9176.30 3.65 222.31 8346.99 8274.99 1487.31 -1631.63 6001533.10 564490.01 MWD+IFR+MS 9270.34 4.05 229.75 8440.82 8368.82 1482.95 -1636.18 6001528.71 564485.50 MWD+IFR+MS 9363.31 4.88 252.05 8533.51 8461.51 1479.61 -1642.45 6001525.31 564479.26 MWD+IFR+MS 9458.26 5.20 257.17 8628.09 8556.09 1477.41 -1650.49 6001523.04 564471.24 MWD+IFR+MS 9549.55 7.61 288.78 8718.83 8646.83 1478.44 -1660.25 6001523.98 564461.48 MWD+IFR+MS 9645.80 11.31 300.44 8813.77 8741.77 1485.28 -1674.42 6001530.69 564447.24 MWD+IFR+MS 9739.26 12.81 305.24 8905.16 8833.16 1495.90 -1690.79 6001541.17 564430.78 MWD+IFR+MS 9810.57 13.85 305.61 8974.55 8902.55 1505.43 -1704.18 6001550.58 564417.30 MWD+IFR+MS 9905.04 15.77 306.30 9065.88 8993.88 1519.61 -1723.73 6001564.59 564397.64 MWD+IFR+MS 9998.86 15.90 306.18 9156.14 9084.14 1534.75 -1744.37 6001579.54 564376.86 MWD+IFR+MS 10092.68 15.90 305.94 9246.37 9174.37 1549.88 -1765.15 6001594.48 564355.95 MWD+IFR+MS 10186,00 16.21 305.00 9336.05 9264.05 1564.85 -1786.17 6001609.27 564334.80 MWD+IFR+MS 10281.44 16.64 305.20 9427.59 9355.59 1580.37 -1808.25 6001624.59 564312.59 MWD+IFR+MS 10376.06 16.94 304.98 9518.18 9446.18 1596.08 -1830.61 6001640.10 564290.09 MWD+IFR+MS 10465.37 16.90 304.15 9603.62 9531.62 1610.83 -1852.02 6001654.65 564268.56 MWD+IFR+MS 10533.40 16.38 303.47 9668.81 9596.81 1621.67 -1868.20 6001665.35 564252.28 MWD+IFR+MS 10600.00 - 16.38 303.47 9732.70 - 9660.70 1632.03 -1883.87 6001675.57 - 564236.52 PROJECTED to TD • 04-Jan-06 AOGCC Helen Warman 333 W. 7th Ave. Suite 100 Anchorage, AK 99501 DEFINITIVE Re: Distribution of Survey Data for Well MPS-90 Dear Dear Sir/Madam: Enclosed is one disk with the *.PTT and *.PDF files. Tie-on Survey: 34.00' MD Window /Kickoff Survey: 10,533.40' MD (if applicable) Projected Survey: 10,600.00' MD PLEASE ACKNOWLEDGE RECEIPT BY SENDING AN EMAIL TO CARL.ULRICH@HALLIBURTON.COM OR SIGNING AND RETURNING A COPY OF THE TRANSMITTAL LETTER TO THE ATTENTION OF: Sperry-Sun Drilling Services Attn: Carl Ulrich 6900 Arctic Blvd. Anchorage, AK 99518 ~ G Date -( Juv~.,..a~~A Signed Please call me at 273-3545 if you have any questions or concerns. Regards, Carl Ulrich Survey Manager Attachment(s) a o s-- ~ 3~~- r-,'!~. • ~ ~ . ~~ Y ~ ~"' ~ FRANK H. MURKOWS ~ , ~ ~ ~ "~~ ~ Kl, GOVERNOR ~~t~ ~~ ~~rr ~+ ~-~t~r~~a~r ~~ ~ u~-7 ~,~ 333 W. 7r" AVENUE, SUITE 100 C0~~7FjRQ~1i01` CD~IISSj~~ ANCHORAGE, ALASKA 99501-3539 1 PHONE (907) 279-1433 Dan Kara Senior Drilling Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: MPS-90 Sundry Number: 305-369 Dear Mr. Kara: FAX (907)276-7542 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DATED this ~ day of December, 2005 Encl. Sincerely, ~. `S ~ ~. rv~~ o r~~~~~~~, ~sr~r~1\ ~ 5 ~ T~~ ~~ ~ ~~ Sp ~ ~~~- +~ c~e~e~J~v~ ~~ ~6 C~'~CV~ \~ 1~~ ~C~~i+MC`S ~\L4~~I 'v~GtJ~S f ~~ ~ r L~~~ RECEIVEQ • STATE OF ALASKA ~~ ALASKA OIL AND GAS CONSERVATION COMMISSION NOV ~ ~ ~~~~ APPLICATION FOR SUNDRY APPROVA~,aska Oil & Gas Cons. C n,mis~pn 20 AAC 25.280 ~ ~ ~Z~z~S Anchorage 1. Type Of Request: ^ Abandon ^ Suspend ^ Operation Shutdown ^ Perforate ^ Other ^ Alter Casing ^ Repair Well ^ Plug Perforations ^ Stimulate ^ Re-Enter Suspended Well ® Change Approved Program ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension 2. Operator Name: 4. Current Well Class: 5. Permit To Drill Number BP Exploration (Alaska) Inc. ^ Development ^ Exploratory 205-135 3. Address: ^ Stratigraphic ®Service 6. API Number: P.O. Box 196612, Anchorage, Alaska 99519-6612 50- 029-23276-00-00 7. KB Elevation (ft): 72, 9. Well Name and Number: MPS-90 8. Property Designation: 10. Field /Pool(s): ADL 380109 Milne Point Unit / Ivishak, Eileen ~ • PRESENT W ELL. CO NDITION. SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 10600 9732 10473 9611 None None Casin Len h Size MD TVD Burst Colla se r I 80' 20" 114' 114' 1530 520 4338' 13-3/8" 4373' 3864' 4930 2270 7911' 9-5/8" 7942' 7114' 6870 4760 in r 2823' T` 7777 - 10600' 6949' - 9733' 7240 5410 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 9884' - 10322' 9046' - 9466' None (Yet) Packers and SSSV Type: N/A Packers and SSSV MD (ft): N/A 12. Attachments: 13. Well Class after proposed work: ® Description Summary of Proposal ^ BOP Sketch ^ Exploratory ^ Development ®Service ^ Detailed Operations Program 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: November 29, 2005 ^ Oil ^ Gas ^ Plugged ^ Abandoned 16. Verbal Approval: Date: 11/29/2005 ^ WAG ^ GINJ ^ WINJ ^ WDSPL Commission Re resentative: Tom Maunder 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Skip Coyner, 564-4395 Printed Name Dan Kara Title Senior Drilling Engineer Prepared By Name/NUmber: -.~ I Si nature Phone 564-5667 Date ii~?R eS Terris Hubble, 564-4628 Commission Use Only Sundry Number: - Conditions of approval: Notify Commission so that a representative may witness ^ Plug Integrity ~OP Test ^ Mechanical Integrity Test ^ Location Clearance Other: 3 ~j ~~ pS~ 1~-~~ ,~'f-S~ ~~ ~« O ~ ~ ~CR~ ~~ ~~ ~ec'~~i©h~ cc c`~c COh~i~0~1S ~ Q u P~~fi~ , Subsequent 7m qu ed• ~ ~~~~ ~.~. i~ E~ APPROVED BY THE COMMISSION ~ Date Approve COMMISSIONER Form t0-a03 'Rev' o ~~~ Submit In Duplicate I ~ A L ~~L nE~ ~ ~ ~40~ • MPS-90 Drilling Program by rT~7~ MPS-90 DOYON 14 Date: 29 November, 2005 Prepared By: Skip Coyner OBJECTIVES: 1. Maintain well control and appropriate barriers to flow. 2. Freeze Protect the 13-3/8" x 9-5/8" annulus to at least 2000' MD. 3. Maintain the mechanical integrity of the 9-5/8" casing. CRITICAL ISSUES: 1. The Ivishak perforations are open: BHP ± 9.6 ppg EMW. 2. The 13-3/8" x 9-5/8" annulus passed an MIT to 4000 psi on 11/28/05. 3. The 13-3/8" x 9-5/8" annulus has ±10 ppg mud in it. 4. Baker requires clean fluid (diesel) to operate their "Back Off Tool". 5. The 9-5/8" casing is currently hung on a mandrel hanger. 6. The 9-5/8" must be hung on slips after screwing in to the original casing. De-Complete: Cut and Pull 9-5/8" Casino: 1. RIH with Halliburton's RBP for 9-5/8", 40# casing and set same at ±4000' MD. Test the RBP to 3500 psi. Pull up 50' - 100' and spot 5 - 10 cu-ft of 20-40 sand to top of the RBP. Pull up another 100' and displace the 9-5/8" casing with 10 ppg mud. POOH. 2. Back out the LDS's. Pull the 9-5/8" pack-off. Spear the 9-5/8" casing. Pick up and take stretch readings on the 9-5/8" as follows: pick up weight +50K, +100K and +150K. Determine free point: must be greater than 2500' deep. Example: Free Point = 2500', Overpull =100,000#, Stretch = 9" Confirm free point calculations with Anchorage. LD the spear. Prepare to cut casing. Note: Schlumberger has an E-Line free point tool as a back up plan only. 3. RIH with Baker's mechanical casing cutter and cut the 9-5/8" casing above the free point. The desired cut depth is 2500' MD. Use ditch magnets, etc. Circulate as/if needed. POOH. 4. RU casing tools. LD the 9-5/8" casing (±60 jts). RD casing tools. RIH with the Johnny Wacker to the cut and displace the 13-3/8" casing with diesel. POOH. 5. RIH with Baker's back-off tool and DC's as needed. Engage the 9-5/8" dutchman and back it out. POOH LD the back-off tool. RIH and spear the dutchman. POOH and LD the spear. 6. RU casing tools. Make up Baker's screw-in sub on a 9-5/8" x 20' pup joint (to alter the wellhead space out. Run 9-5/8" casing as needed to engage the old 9-5/8" casing. Make sure a 9-5/8" casing collar is not in the wellhead (slip area). Screw-in to the old 9-5/8" casing as per Baker's procedure. Work torque down to the screw-in and into the entire string if needed. Pressure test the 9-5/8" casing to 3500 psi. Pull tension (150,000) and set the slips. Version 1.0 1 11/29/2005 • • MPS-90 Drilling Program 7. Flow check the OA and the 9-5/8" casing. ND the BOP's. Cut of the 9-5/8" casing. Install and test the pack-off bushing. NU the BOP's and test the break(s). 8. RIH with Halliburton's RBP retrieving tool on DP. Wash the sand off the top of the RBP and circulate the 9-5/8" casing clean. Displace with 9.6 ppg bring as before. Engage and release the RBP. Check for flow. POOH slowly making sure not to swab the well in. Monitor fill up volume on the trip sheet. LD the RBP. Prepare to run the ESP completion. Note: AOGCC 10-403 required. Verbal approval from Tom Maunder received 11/29/2005 Version 1.0 2 11/29/2005 RE: MPS-90 • Subject:'RE: MPS-9(~ From: "Coyner, Ship (N~~~f~~`f Il~)1" ._coyns0(ci,BP.com> Date: Tue, 29 New 2011> 12:-15: I ~ -0~~~)0 'Co: ~[~honris ~~1<iunder °~tom maunclcr(ci admi~~.statc.ak.us=- 4000' is arbitrary -although we expect that the 9-5/8" is cemented at (or near) that depth. And we preserve as much brine as possible (below) and minimize fluid volumes (above). Life is a trade off. I've heard arguments for all depths this morning. The 9-5/8" will be cut with Cameron's external /mechanical cutter. Thanks for noticing. Your input is alway welcome. Skip Coyner 907-564-4395 BPXA 907-748-3689 cell From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Tuesday, November 29, 2005 12:38 PM To: Coyner, Skip (NATCHIQ) Subject: Re: MPS-90 Skip, Thanks for sending the program. Anything "magic" about setting the RBP at 4000'? Does it make sense to set it deeper in case there are problems pulling it? Makes for a longer trip, but then you preserve all the wellbore you can. Just an observation, no design to "tell you what to do". Lots of trips with diesel in the hole. I presume the cutoff after the slips are set will be made with a non-sparking device. I will look forward to the sundry. Tom Maunder, PE AOGCC Coyner, Skip (NATCHIQ) wrote, On 11/29/2005 10:59 AM: Terry Hubble will prepare the Sundry Application. Here's what the game plan is. «Freeze Protect Program.doc» Skip Coyner 907-564-4395 BPXA 907-748-3689 cell 1 of 1 11/30/2405 7:35 AM RE: Cementing 9-5/8" Casing -Milne Point MPS-90 Subject: RE: Cementing 9-Sl$" Casing - Milne'Point MPS-90 From: "Johnson, David A. (Fairweather)" <john23@BP.com> Date: Thu, 17 Nov Z(i0514:52:32 -0900 To: Thom~is ~~1~ulnd~•r ~=tom maunder(ci~~adn~in.statc.ak.us-,. Tom, We are planning on down squeezing later, towards the end of completion. We prefer not to do it immediately due to the fact that the annulus could build pressure from temperature increases and require diesel to be bled at the surface. The rig does not have a good way of bleeding diesel. I am not sure of down squeezing problems, but we have freeze protected Later without problems. Dave From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Thursday, November 17, 2005 2:38 PM To: 7ohnson, David A. (Fairweather) Subject: Re: Cementing 9-5/8" Casing -Milne Point MPS-90 Dave, Is the plan to do the downsqueeze and freeze protect as soon as you can or will you wait until the "end" of the well?? What is the history of downsqueezing "later". If you are successful clearing the shoe, it shouldn't be a problem. Your plan should isolate the sands. Bummer the casing got stuck, but I guess it was your number j Good luck with the operations. Tom Maunder, PE AOGCC Johnson, David A. (Fairweather) wrote, On 11/17/2005 1:58 PM: Tom, With the 13-3/8" casing shoe programmed to be +/-200' above the Schrader OA sand, originally the program called for cementing the stage II from below the Schrader Bluff oil sands and bringing class G cement up into the 13-3/8" shoe. After closing the H-ES cementer, we would immediately bullhead mud down the 13-3/8" x 9-5/8" annulus to maintain the ability to down-squeeze later and freeze protect. At a convenient time, we would down squeeze with at least 50 bbl (238 sx) of class G and displace it to a depth < 150' above the 13-3/8" shoe depth with freeze protect fluid (crude oil). The 13-3/8" casing was stuck at 4372', 7' above the Ugnu MA sand. We still plan on cementing the 2nd stage from below the Schrader up into the 13-3/8 casing shoe, bullheading to clear the shoe and down squeezing the annulus with cement followed by mud and diesel for freeze protect. Due to the close proximity of the 13-3/8" casing shoe to the Ugnu MA sand, we plan on leaving 500' of cement inside the casing by casing annulus instead of 150'. Our basic plan is to pump 50 BBLS of class G cement mixed at 15.8 ppg, followed by 112 BBLS of mud and 119 BBLS of diesel for freeze protect. This would leave +/- 30 BBLS of cement inside the casing annuli and 20 BBLS squeezed out at the shoe. Please call if you have any questions. Thanks Dave 564-4171 1 of 1 11/30/2005 7:33 AM RE: MPS-90 / 10-401 Subject: RE: MPS-90 ~' 10-4(71 From: "Coyner;Ski~ (N.-~~fClll(~) " <co~ns0(a~BP.con1=~ Date: ~~"cc1, ~ 1 Sci~ ?U0~ 0:49:1 ~ -(10(7 '['o: Thomas ~~iaut~der <-tom maur~der(i_admin.state.ak.us= yes. The H-ES tool will be +/- 500' below the B/Schrader in the Colville. The annulus should be a "dead cylinder" from the B/Schrader on down. The bullheaded fluid should go into the first permeable (or weakest) sand below the 13-3/8" shoe. So in the end, we'll have 500' of cement below, cement across and 500' of cement above the Schrader. Given the proximity of the shoe to the T/Schrader, 500' of cement above the T/Schrader will seal up that annulus. Skip Coyner 907-564-4395 BPXA 907-748-3689 cell From: Thomas Maunder [mailto:tom_maunder@admin.state.ak.us] Sent: Wednesday, September 21, 2005 8:39 AM To: Coyner, Skip (NATCHIQ) Subject: Re: MPS-90 / 10-401 Skip, Is the expectation that some cement will remain below the Schrader from the stage tool job prior to the bullhead?? Tom Coyner, Skip (NATCHIQ) wrote, On 9/20/2005 2:43 PM: Tom, Please make a change in the intermediate casing cementing strategy /Stage II cement job. We still plan on doing a 2-Stage job, but we will not be able to get enough "lift" to bring cement back to surface. Our original strategy was to displace the water based mud with cement and thus freeze protect while cementing. This stragegy required the use of a pack-off stage collar, however, a pack-off stage collar will not be available in time. So, our new strategy is to cement stage II from below the Schrader Bluff oil sands and bring class G cement uo into the shoe. After closing the H-ES cementer, we will immediately bullhead mud down the 13-3/8" x 9-5/8" annulus so that we maintain the ability to down-squeeze later. Then when it is concenient, we will downsqueeze with at least 50 bbl (238 sx) of class G and displace it to a depth < 150' above the 13-3/8" shoe depth with freeze protect fluid (crude oil). This technique will cover the Schrader with adequate cement an allow us to freeze protect the well. As such, Stage II of the intermediate casing job includes only the original 37.8 bbl of class G cement. The down-squeeze will include 50 bbl (238 sx) of class G followed by 150 bbl of mud followed by +120 bbl of crude oil. The current projected spud date is +/- October 15th. 1 of 2 9/21/2005 8:51 AM ,~~~L "~ .~ ~: :>. ~~:' BP EXPLORATION ~",, ;~;: `~~~~ # MPS-90 Field: Milne Point Ivishak ENG: S. Coyner Pad: S-Pad Water Supply Well RIG: Doyon 1a RKB: 72 ft DIR / LWD Mud FORM DEPTH HOLE CASING MUD INFO MWD Weight MD TVD SIZE SPECS PIT INFO INFO 20" x 34" Wellhead NONE NONE Permafrost Insulated FMC Gen 5 115' 42" Conductor 20" x 11" 5K MWD/GR 8.6 Gyro as needed 150% Excess In Permafrost Surface Csa Cement Job Base Permafrost 1,873' 1,872' 13-3/8", 68# 575 bbls, 727 sx of 0.0° L-80, BTC ASL at 4.44 cf/sx Test Csg to Int. Yield 5210 psi 60.7 bblS, 292 Sx 2000 psi 47.1° Collaspse 2470 psi Class G + CaCl2 TUZC 4,093' 3,672' 85 ft Shoe Track Ugnu MA Sand 4,380' 3,867' 30% Excess Ugnu MB Sand 4,483' 3,937 Below Ugnu MC Sand 4.658' 4.057 Permafrost 9 3 Casing Point 4,679' 4,072' 44.0° 16" MWU/GR/RES 8.6 T/Schrader Bluff 4,706' 4,092' Inter. Casing Stage II T/SB OA Sand 4,887' 4,222' 9-5/8", 40# 37.8 bbls, 183 sx 35% Excess IFR/Cas Surf - 5200' 15.8 ppg Stage II H-ES Cementer 5,200' 4460 34.3° L-80, BTC-M 1.16 ft3/sx Int. Yield 5750 psi CIaSS "G" Collaspse 3090 psi 9.3 TOC 7,007' 6,113' Inter. Casing Test Csg to 10.0 T/HRZ 7,111' 6,277' 2.75° 9-5/8", 47# Staae I 3500 psi KLGM 7,261' 6,427' 5200' - 8007' 89.5 bbls, 433 sx T/Kuparuk D 7,431' 6,597' L-80, BTC-M 15.8 ppg 50% Excess T/Kuparuk C 1 7,596' 6,762' i Int. Yield 6870 psi 1.16 ft3/sx Stage I T/Kuparuk A 7,778' 6,942' Collaspse 4750 psi Class "G" 85 ft Shoe Track 10.0 Casing Point 8.007 7.172' i' 2.75° 1225" Miluveach MWD/GR/RES 10.0 NEU/DEN/Sonic `~ ` PWD 10.2 Kingak Shale 8,377' 7,542' ~ f c? `s ~' Test LNR to %` ~ 3500 psi iRi !?i :: 10.5 Sag River 9,559' 8,722' 2.75° Shublik 9,629' 8,792' ~ 3.90° Liner Liner Cement T/Eilene 9,780' 8,942' 7" , 26#, L80, BTC 100 bbl, 480 sx 40% Excess T/Ivishak 9,822' 8,982' 14.8° Int. Yield 7240 psi Class G, 15.8# IFR/Cas Kavik 10,581' 9,572' E> Collaspse 5410 psi 10.5 Liner Point 10,780' S.f~85' 55.4° 8.50" Kavik Shale [10/04/04] MPS-90 Well Plan Schematic.xls ~ I ti ~ ~ ~ ! i ~ i ~ 7 ~ ~ / - r r ~ a ~ ALASSiA OIL A1~TD GAS COI~TSER~A'TIO1Q CO1~II-IISSIOI~T Dan Kara Senior Drilling Engineer BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 J~ ~'r FRANK H. MURKOWSKI, GOVERNOR r ' 333 W. T" AVENUE, SUITE 100 r~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: MPS-90 BP Exploration (Alaska) Inc. Permit No: 205-135 Surface Location: 1891' FNL, 125' FWL, SEC. 07, T 12N, R 11 E, (planned) Bottomhole Location: 9' FNL, 2010' FEL, SEC. 12, T12N, RlOE, UM Dear Mr. Kara: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Samples and a mud log are required for MPS-90 across the 8-1 /2 inch production hole because the nearest Ivishak Formation penetrations are located from 3 to 4-1 / 2 miles away. All dry ditch sample intervals from below the 9-5/8 inch casing shoe to the top of the target zone. A sample interval of 10-feet should be maintained through the target zone. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty- four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659- 3607 (pager). DATED this- day of month, 2005 • cc: Department of Fish 8s Game, Habitat Section w/ o encl. Department of Environmental Conservation w/ o encl. ` ~ STATE OF ALASKA ALASKA~L AND GAS CONSERVATION COMMIS;510N ~' PERMIT TO DRILL l~i~ 20 AAC 25.005 1a. Type of work ®Drill ^ Redrill ^ Re-Entry 1b. Current Well Class ^ Exploratory ^ Development Oil ®Multiple Zone ^ Stratigraphic Test ®Service ^ Development Gas ^ Single Zone 2. Operator Name: BP Exploration (Alaska) Inc. 5. Bond: ®Blanket ^ Single Well Bond No. 6194193 11. Well Name and Number: MPS-90 3. Address: P.O. Box 196612, Anchorage, Alaska 99519-6612 6. Proposed Depth: MD 10781 *' TVD 9685 .~ 12. Field /Pool(s): Milne Point Unit / Ivishak, Eileen 4a. Location of Well (Governmental Section): Surface: ~ 1891' FNL 125' FWL SEC T12N R11E 07 (planned) 7. Property Designation: ADL 380109 , , . , , , Top of Productive Horizon: 418' FNL, 1554' FEL, SEC. 12, T12N, R10E, UM 8. Land Use Permit: 13. Approximate Spud Date: October 11, 2005 Total Depth: 9' FNL, 2010' FEL, SEC. 12, T12N, R10E, UM 9. Acres in Property: 2560 14. Distance to Nearest Property: 4880' 4b. Location of Well (State Base Plane Coordinates): Surface: x- 566135 ~ - 6000059 ~ Zone- ASP4 ' 10. KB Elevation (Height above GL): 72' "~ feet 15. Distance to Nearest Well Within Pool 14800' away from NW E2-01 16. Deviated Wells: Kickoff Depth: 300' ~ feet Maximum Hole Angle: 55.4 ` de rees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035). Downhole: 4448 Surface: 3550 r' . Casing Program: Size Spec~eations Setting Depth To Bottom Quantity of ement c.f. or sacks Hole Casin Wei ht Grade Cou lin Len th MD TVD MD TVD includin sta a data 42" 20" 92# H-40 Welded 80' 34' 34' 114' 114' 60 sx Arctic Set A rox. 16" 13-3/8" 68# L-80 BTC 4649' 30' 30' 4679' 4072' 727 sx AS Lite, 291 sx Class 'G' 12-1 /4" 9-5/8" 47# L-80 BTC-M 8007' 30' 30' 8007' 7172' - 1203 sx Class 'G' 8-1/2" 7" 26# L-80 BTC-M 2924' 7857' 7022' 10781' 9685' 80 sx Class 'G' 1g, PRESENT WELL CONDITION SUMMARY (To be`completed forRedrill AND Re-entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD n t Perforation Depth MD (ft): Perforation Depth ND (ft): 20. Attachments ®Filing Fee, $100 ^ BOP Sketch ®Drilling Program ^ Time vs Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^ Diverter Sketch ^ Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Skip Coyner, 564-4395 Printed Name Dan Kara Title Senior Drilling Engineer Prepared By Name/Number: Si nature ~ -' Phone 564-5667 Date ~ oG~~~ Sondra Stewman, 564-4750 Commission Use Only Permit To Drill ~, _. Number: J~ ' 1 ~5 API Number: , 50- L} ~ ~ `~ ~--~z_7rr- ' ~-~ ~ Permit pr v Date: ~0 See cover letter for other requirements Conditions of Approval: Sampl equired Ye ~ ^ No Mud Log Required Yes' ~ No ~S'c~rc~taUO`e~~~ Hyd ge Sulfide Measures ^ Yes ~No Directional Survey Required Yes ^ No` Other:. ~r 4 ~ ~S~ ~ ~~' ~er~s's ~ .~~ ~' , Y~/v~-fi~~. t,~. (~, ~~ ,. b~© ~ c~p~,~NSi=c.J. Pc~ss~~.~5~ S r~~.E~- ~~r~r~~~~ Pr~c-'~rc:~,r.~.,~ ~ g~~ sh '~ c,,r'k-~`c~ ~ 'ESQ co w.p ~~zo ~ /Q ~aa~~ r ~.ccstp ~c~b~ rc, APPROVED BY D A rove THE COMMISSION Date -~r Form 10-401 Rwie~d /20 1 ~` i ~ ~ ~ ~bmit Irt/buplicate • • by ~~ Well Name: MPS-90 Ivishak Water Source Well Drilling and Completion Plan Summary T e of Well: Ivishak WSW Surface Location: 1,891' FNL and 125' FWL - Section 7, T12N, R11 E UM E = 566,135' N = 6,000,059' Top Schrader at 4,693' MD 790' FNL and 951' FEL Section 12, T12N, R10E UM E = 565,049' N = 6,001,151' Z = 4,082' TVD T/SAD at 9,822' MD 418' FNL and 1,554' FEL Section 12, T12N, R10E UM E = 564,451' N = 6,OOi,512' Z = 8,942' TVD BHL at 10,781' MD 9' FNL and 2,010' FEL Section 12, T12N, R10E UM E = 563,983' N = 6,001,922' Z = 9,685' TVD Distance to Pro a line 4,880' Distance to nearest well 14,800' from NW E2-01 AFE Number: Estimated Start Date: 10/11/2005 Ri Do on 14 Ri da s to com lete: 20 MD: 10,781' TVD: 9,685' Max Inc: 55.4° KOP: 300' KBE: 72' Well Desi n: "S-Curve", Ivishak, WSW with Intermediate Casin - Ob'ective: Ivishak Zones 1-4 1 ,' Mud Program: 16" Surface Hole (0' - 4.679'1: Snud `Densi PV YP HTHP H API Filtrate I.G Solids 8.6-9.4 10-20 30-50 10- 11 8.5-9.5 <8 < 15 12-1/4" Unner Intermediate Hole Section (4.679' - 6.800'1 LSND Densit PV YP HTHP H API Filtrate LG Solids 9.0-10.0 8-15 24-30 NC 9.0-9.5 6-8 <15 12-1/4" Lower Intermediate Hole Section (6.800' - 8.007'1: LSND Densi PV YP HTHP H API Filtrate LG Solids 9.0-10.0 8-15 24-30 <12 9.0-9.5 5-6 <15 8-1/2" Production Hole (8.007' -10.781'1: LSND Densi PV YP HTHP H API Filtrate LG Solids 10.0-11.0 15-25 22-30 <12 9.0-9.5 5-6 <10 Waste Disposal: NO ANNULAR INJECTION. Drill Cuttings taken to DS-4 disposal site ~ Call the Pad 4 waste disposal site prior to truck leaving location so the site can be ready to unload waste. Exempt liquid wastes can be taken to DS-4 or Phillips KRU 1 R. Evaluation Program: 16" Section Open Hole: MWD/GR/Photo-gyro IFR/CASANDRA S er InSite 12-1/4" Section Open Hole: MWD/GR/RES IFR/CASANDRA S er InSite 8-1 /2" Section Open Hole: MWD/GR/RES/NEU/DEN/SONIC/PWD IFR/CASANDRA S er InSite Cased Hole: CBL: TD to 500' above Ivishak - Casing/Tubing Program: Hole Size Csg / Tb O.D. WUFt Grade CPLG Length Top MD / TVD Bottom MD / TVD 42" 20" 92# H-40 Welded 80' 34' 114' 16" 13.375" 68# L-80 BTC 4,649' 30' 4,679' / 4,072' 12.25" 9.625" 47# L-80 BTC-M 7,977' 30' 8,007' / 7,172' 8.5" 7" 26# L-80 BTC-M 2,924' 7,857' / 7,022' 10,781' / 9,685' • Conductor: 20" x 34" insulated conductor 2 Recommended Bit Program: • BHA H©ie Size Depth (MD) Footage Bit Type TFA GPM 1 16 in Surt - 4,679' 4,679' Mill Tooth .75 - .90 450 - 650 2 12.25 in 4,679' - 8,007' 3,328' PDC .50 - .75 400 - 550 3 8.5 in 8,007' -10,781' 2,774' PDC .30 - .50 250 - 300 Cement Program: Casin Size 13-3/8", 68#, L-80, BTC Surface Casin at 4,679' MD Basis Excess from B/Permafrost to Surface =150%. Use 30% excess below the B/Permafrost 1873' MD . 85' Shoe Joint. Total Cement Wash & 10 bbl water Volume: 636 bbl Spacer 20 bbl CW 100 75 bbl MudPush Lead 575 bbl, 727 sx of Arctic Set Lite: 10.7 and 4.44 ft /sx Tail 60.7 bbl, 292 sx "G" mixed at 15.8 Ib/ ai & 1.17 ft /sx Tem BHST ~ 85°F from Schlumber er Chart Casin Size 9-5/8", 47#, L-80, BTC-M Intermediate Casin at 8,007' MD Basis• excess and TOC to be 1000' MD above the shoe (7,007' MD): 50% excess. 85' Shoe Joint. Other parameters H-ES Cementer at 5200' MD. Stage 2 CH Excess (surf - 4,679' MD) =10%. Sta e 2 OH Excess 4,679' - 5,200' MD = 30%. Stage I Wash & 10 bbl water Total Cement Spacer 25 bbl CW 100 Volume: 89.5 bbl 45 bbl MudPush Tail 89.5 bbl, 433 sx "G" mixed at 15.8 Ib/ al & 1.16 ft /sx Tem BHST ~ 163°F from Schlumber er Chart Stage II Total Cement Wash & 10 bbl water i~ ~Q~e~ - fit--- ~ ~ .~ ~ 25 bbl CW 100 ~" '~~~~ ~ V l Spacer ~ J C~~ `~~`~ l M P o ume: 346 bbl pv 45 bb ud ush Lead 30 enders: 11.5 .95 ft / Tail 37.8 bbl, 183 sx "G" mixed at 15.8 Ib/ al & 1.16 ft /sx Liner Size 7", 26#, L-80, BTC-M Production Liner: 7,857' to 10,781' MD Basis Top of cement to be 100' above the TOL. Liner Lap > 150'. O en Hole excess = 40%. Shoe Joint = 85 ft. TOC = 7,757' MD. Total Cement Volume: 99.7 bbl Wash & Spacer 10 bbl water 40 bbl MudPush Tail 99.7 bbl, 480 sx "G" mixed at 15.8 Ib/ al & 1.17 ft /sx Tem BHST = 226°F from Schlumber er Chart Well Control: Intermediate/Production hole: • Maximum possible BHP: • Maximum surface pressure: • Planned BOP test pressure: • BOP Test Interval: • Integrity tests: Kick tolerance: • Planned completion fluid: ~C~ ~ 4,448 psi at 8,982' TVD (T/Ivishak) -' 3.550 psi at (Based on a full column of gas at 0.1 psi/ft) ' 5,000 psi `~/~.uc,~.~~~~~e ~AS~' ~.~~ ~\ Not to exceed 14 days FIT to 11.3 Ib/gal 20' below the 13-3/8" shoe. ~a, 70-bbl with 9.3 Ib/ga! mud at the 13-3/8" shoe. Kill Weight Brine. 3 • Formation Markers: Formation Tops MD ft TVD (ft Pore Pressure si EMW Ib/ al BPRF 1873 1872 782 8.35 TUZC 4071 3657 1563 8.35 U nu MA 4365 3857 1648 8.35 Ugnu M62 4468 3927 1678 8.35 U nu MC 4644 4047 1730 8.35 Top Schrader 4693 4082 1623 8.00 TSBD-OA 4873 4212 1185 6.00 Base Schrader 4957 4272 1828 8.35 THRZ 7116 6282 2694 8.35 BHRZ 7166 6332 2716 8.35 KLGM 7266 6432 2759 8.35 TKUD 7436 6602 2833 8.35 TKC1 7601 6767 3027 9.00 TKUA 7777 6942. 2983 8.35 TMLV 7877 7042 3026 8.35 TKNG 8357 7522 3243 8.35 TSGR 9559 8722 4318 9.60 TSHU 9629 8792 4353 9.60 TEIL 9780 8942 4428 9.60 TSAD 9822 8982 4448 9.60 BSAD 10581 9572 4742 9.60 ,f / , `/d e ~c ., /Z ~ ~vte N/ / 0~~2 /~Dl ~ Drilling Hazards & Contingencies: • Hydrates may be present encountered at 1059' and 2021' in S-15. Generally occur just below permafrost but may be present in shallower SV sands and also as deep as 3000 ft. • Tight hole and stuck pipe due to poor hole cleaning have occurred in S Pad wells. Lost Circulation • S-12 reported lost circulation drilling to TD and crossing a fault; mud weight 9.2 ppg, treated with three LCM pills, lost 128 bbls. • Losses are also possible while running and cementing the surface casing. Expected Pressures i Potential Schrader Bluff sands overpressure in MPS-15 fault block (up to 11.9 ppg); this directional drilling well plan avoids the MPS-15 fault block. Probability of depleted reservoir pressure in Schrader sands (as low as 5.0 ppg). Pad Data Sheet • Please Read the MPS-Pad Data Sheet thoroughly. Hole Breathing • Breathing possible in the Colville interval if ECD's exceed 11.5 ppg. • Flow checks should be done to differentiate between breathing and flowing. Hydrocarbons • Hydrocarbons may be encountered in the Ugnu through the Schrader Bluff sands, the Kuparuk C sands, and the Sag River and Ivishak. ' 4 Faults • This well path should not intersect any faults although it parallels several faults; build section in Ivishak interval is secondary to maintaining NW azimuth parallel to faulting. Anti-collision Issues • MPS-90 passes the Major Risk Criteria, however, gyro surveys will be required for close approach issues and magnetic interference down to ± 1000 ft MD. - Hydrogen Sulfide • MPS Pad is not designated as an H2S Pad.' Distance to Nearest Property • MPS-90 is 4,880 ft from the nearest Milne Point property line. Distance to Nearest Well Within Pool • MPS-90 is 14,800 ft from the nearest Eileen penetration in NWE2-01. - DRILL & COMPLETION PROCEDURE Pre-Riq Operations 1. The 20" x 34" insulated conductor will be installed pre-rig. Drillin 1. MIRT. NU & test diverter system. PUDP, BHA, etc. 2. Drill 16" surface hole to near base of Ugnu MC. 3. Run and cement 13.375" surface casing. 4. Install wellhead and NUlTest BOPE. 5. Drill 12.25" intermediate hole through the Kuparuk sands (if possible). 6. Run and cement 9-5/8" intermediate casing. Cement in two stages. 7. Drill 8.5" hole through to B/SAD + 200 ft (Kavik). 8. Run and cement a 7" liner with HMC & ZXP. 9. Displace the well with kill weight brine. LDDP. ~~" cc~S~~SC `` `~~~ oc-~ 10. Run a GR/CBLlCCL. ~~ssvct~, ~5 ~ ~ ~~5~~ 11. Perforate the SAD (Ivishak) as directed. = ~p~C~C1.c~ ~\K~cS~,~c~.~ ~`~ 12. RIH with ESP and 5.5" tubing. 13. ND BOP/NU Tree. W ~`~ ~~ ~E ~~'~~~ ~~"~-c'6` 14. Freeze Protect. C~C~~Z ~ 15. RD & MO Doyon 14. Post-Riq: 1. Tie in flow lines and ESP power source to VSD. 2. Retrieve the BPV. 3. Put the well on production. ~~ C 5 Tree: 7-1/16" - 5M Came Est. DF elev. = 72.0' D 74 Wellhead: 13-5/8" x 5.5" MPS-90 Propose Orig. GL. elev.= 36.0' Gen 6 w/ 5.5" BTC-M Tubing Hanger, CIW "H" BPV profile KOP @ 300' Max sale angle = 47.1° 20" x 34" Insulated Conductor 114' 16" Hole 4179' MD 13.375-in 68-Ib/ft L-80 BTC casing 4679' MD 4072' TVD 5200` MD 12.25" Hole 5.5" 17.0# L-80 IBT tubing 5.5" HES XN-Nipple Set in Schrader Bluff NA Shale Schrader Bluff NB Sand Schrader Bluff OA Sand Schrader Bluff OB Sand Q ~ ~ 9.625" H-ES Hydraulic Cementer 7007' MD `~~ U~J HMC & ZXP at 7857 MD `" f 9.625-in 47-Ib/ft L-80 BTC-M casing 8007 MD (drift ID = 8.525", cap = 0.0732-bbl/ft) 7172' TVD 8.5" hole Perforate SAD Estimated T/SAD - 9822' MD °~' 7-in, 29.7-Ib/ft L-80 BTC-M Liner Shoe at' 10780` MD J 9685' TVD DATE REV. BY COMMENTS MILNE POINT UNIT 01 Sept'05 SC/AM Proposed Completion WELL MPS-90 - API NO: - BP EXPLORATION ~AK~, ~.. • a rn c? cp N M O ~_ 0 i 0 N T I 1 T t I ~~~~~~ ~ 270'-0"-ice MOD 8003 TRANSFORMER SKID CRUDE HEATER n rt--„ - _ ~. • ;~ M. BAKER (OWG. PL-MOS-000tC ~~ NCE (PP-MOS-OOOtB/OOt) w ~ v o ~ 3W z o o ~ I O= v ~ W O ~ o Z U ~ w ~' - ~ o 0 5 a ? a N.2463'-9" PF SEPARATORS (SKIDS 8009A/B) (MOD.8005) ~ ~ CHEM. INJ. & VALVE MANIFOLD MOO. Y~r- _. .- ~~ --- c ~~ --c TEST I~ SEP. o~ o ~W ~ -05 S-Oi o • t 5'_0.. - I (T~'P> o /OS~ i ~ POWER FLUID PUMPS ~ ~ vl ;~ ~ (MOD.8008) ~[) - -- -___ , _ _ ~ ~t~ ~,-: #J - - - - - - `COL.- N.2293-0" - _ -- - - - - ~ f ~' , - ~ - -~ L • , ~ !r -+ WELLS N.223P-0" - -~ s ~---= -..~. - ~ - - - ~ - R\\ 1...Jt ` ~~1 LJ I ' ~ vL Zv.z ~ . - a, I .._ W. SURFACE ELEV: 38'-9" PdSL .'I N~ ~J.1 3 g N N cD (D MPS-90 WSW Proposed Surface Location 1891' FNL & 125' FWL Section 7, T12N, R11 E UM ' 566,135' E & 6, 00, 059' N 0 i 3 ~v 0 Qs Y 0 J n. d c V1 !T C .~ 0 a a ai H • Sperry-Sun BP Planning Report Company: BP Amoco Date: 8!16/2005 Time: 16:2033 Yage: Field: Milne Point Co-ordinate(NE) Rcfcrcncr. Welk Plan MPS-90, True North Sitc: M Pt S Pad Vcr6cal (TVD) Reference: 72' pre plan RKBE 72.0 Well: Plan MPS-90 Section (VS) Reference: Well (O.OON,O.OOE,311.40Azi) Wellpath: Plan MPS-90 Survey Calculation Method: Minimum Curvature Db: Oracle Plan: MPS-90 wp09 Date Composed: 3/29/2005 Version: 63 Principal: Yes Tied-to: From Well Ref. Point Field: Milne Point North Slope UNITED STATES Map System: US State Plane Coordinate System 1927 Map Zone: Alaska, Zone 4 ~ Geo Datum: NAD27 (Clarke 1866) Coordinate System: Well Centre Sys Datum: Mean Sea Level Geomagnetic Model: bggm2005 Site: M Pt S Pad Site Position: Northing: 5999978.00 ft Latitude: 70 24 37.329 N From: Map Easting: 566345.00 ft Longitude: 149 27 35.171 W Position Uncertainty: 0.00 ft North Reference: True ° Ground Level: 0.00 ft Grid Convergence: 0.51 deg Well: Plan MPS-90 Slot Name: Source Water Well Well Position: +N/-S 82.37 ft Northing: 6000058.50 ft Latitude: 70 24 38.139 N +E/-W -209.10 ft Easting : 566135.20 ft Longitude: 149 27 41.300 W Position Uncertainty: 0.00 ft b1D "fVD Diameter Hole Size Name ft ft in in 4678.70 4072.00 13.375 16.000 13 3/8" 8006.91 7172.00 9.625 12.250 9 5/8" 10780.00 9684.97 7.000 8.500 7 5/8" Casing Points Map Map <_-_ Latitude ---> <-- Longitude ---> Name Description TVD +N/-S +F/-W Northing Eastinh_ Deg D1in Sec Deg Min Sec I ~ Dip. Dir. ft ft ft ft ft MPS-90 T1 wp08 4222.00 1200.00 -1170.00 6001247.98 564954.73 70 24 49.940 N 149 28 15.599 W -Plan hit target MPS-90 T2 wp08 8722.00 1460.00 -1650.00 6001503.69 564472.49 70 24 52.496 N 149 28 29.672 W -Plan hit target Formations Mll TVD Formations Lithology llip Angle llip Direction ft ft deg deg 1873.12 1872.00 BPRF 0.00 0.00 4071.36 3657.00 TUZC 0.00 0.00 4365.16 3857.00 Ugnu MA 0.00 0.00 4467.99 3927.00 Ugnu M62 0.00 0.00 4643.56 4047.00 Ugnu MC 0.00 0.00 4692.60 4082.00 Top Schrader 0.00 0.00 4873.32 4212.00 TSBD-OA 0.00 0.00 4956.73 4272.00 Base Schrader 0.00 0.00 7115.88 6282.00 THRZ 0.00 0.00 7165.94 6332.00 BHRZ 0.00 0.00 7266.05 6432.00 KLGM 0.00 0.00 7436.25 6602.00 TKUD 0.00 0.00 7601.44 6767.00 TKC1 0.00 0.00 7776.64 6942.00 TKUA 0.00 .0.00 7876.76 7042.00 TMLV 0.00 0.00 8357.31 7522.00 TKNG 0.00 0.00 9558.70 8722.00 TSGR 0.00 0.00 9628.79 8792.00 TSHU 0.00 0.00 9780.41 8942.00 TEIL 0.00 0.00 9821.56 8982.00 TSAD 0.00 0.00 10580.91 9572.00 BSAD 0.00 0.00 Targets ~ '' ~ • • .Sperry-Sun BP Planning Report Company: BP Amoco Date: 8/16/2005 'Circe: 16:20:33 Page: 2 Field: Mi lne Point Co-or dinate(NE) Reference: Well: Plan MPS-90, True Nort h Site: M Pt S Pad Vertical (TVD) Reference: 72' pre plan R KBE 72.0 Wdl: Plan MPS-90 Section (VS) Reference: Well (O.OON,O .OOE,311.40Azi) Wellpath: Plan MPS-90 Survey Calculatim~ Method: Minimum Curvature Db: Oracle Targets Map Map <-- Lafitude --> <-- Lougihidc ---> '~ Name De scription TVD +N/-S +E/-W Northi ng Eastin g Dee Nlin Sec Deg Nlin Sec i Dip. Uir. ft ft ft ft ft MPS-90 T3 wp08 9572.00 1770.00 -2015.00 6001810 .42 564104 .80 70 24 .55.544 N 149 28 40.375 W -Plan h it target Plan Section Information MD Intl Azim TVD +N/-S +E/-@V DLS Build Turn TFO "Cargct ft deg deg ft ft ft deg/100ft deg/100ft deg/100ft deg 34.00 0.00 0.00 34.00 0.00 0.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 0.00 0.00 0.00 500.00 3.00 180.00 499.91 -5.23 0.00 1.50 1.50 0.00 180.00 650.00 6.00 180.00 649.43 -17.00 0.00 2.00 2.00 0.00 0.00 950.00 0.00 0.00 948.88 -32.70 0.00 2.00 -2.00 -60.00 180.00 2001.12 0.00 0.00 2000.00 -32.70 0.00 0.00 0.00 0.00 0.00 3178.61 47.10 316.49 3049.28 299.00 -314.84 4.00 4.00 0.00 0.00 4599.73 47.10 316.49 4016.68 1054.07 -1031.51 0.00 0.00 0.00 0.00 4677.22 44.00 316.50 4070.94 1094.18 -1069.58 4.00 -4.00 0.01 179.92 4887.22 44.00 316.50 4222.00 1200.00 -1170.00 0.00 0.00 0.00 0.00 MPS-90 T1 wp08 4957.22 44.00 316.50 4272.35 1235.27 -1203.47 0.00 0.00 0.00 0.00 5211.22 33.89 314.92 4469.65 1349.57 -1314.63 4.00 -3.98 -0.62 -175.00 5461.22 33.89 314.92 4677.19 1447.99 -1413.34 0.00 0.00 0.00 0.00 6340.40 2.75 199.01 5507.42 1606.10 -1599.65 4.00 -3.54 -1 3.18 -175.70 9558.70 2.75 199.01 8722.00 1460.00 -1650.00 0.00 0.00 0.00 0.00 MPS-90 T2 wp08 10501.81 55.43 313.04 9527.12 1725.55 -1967.40 6.00 5.59 1 2.09 115.71 10580.91 55.43 313.04 9572.00 1770.00 -2015.00 0.00 0.00 0.00 0.00 MPS-90 T3 wp08 10780.91 55.43 313.04 9685.49 1882.40 -2135.36 0.00 0.00 0.00 0.00 Survey MD Ind Azim TVD Sys TVD N/S E/W DLS MapN AIapE Tool/Comme t ft deg deg ft ft ft ft deg/100ft ft ft 34.00 0.00 0.00 34.00 -38.00 0. 00 0.00 0.00 6000058.50 ~ 566135.20 ' CB-GYRO-SS 100.00 0.00 0.00 100.00 28.00 0. 00 0.00 0.00 6000058.50 566135.20 CB-GYRO-SS 200.00 0.00 0.00 200.00 128.00 0. 00 0.00 0.00 6000058.50 566135.20 CB-GYRO-SS ,~ 300.00 0.00 0.00 300.00 228.00 0. 00 0.00 0.00 6000058.50 566135.20 Start Dir 1.5?/ 400.00 1.50 180.00 399.99 327.99 -1. 31 0.00 1.50 6000057.19 566135.21 CB-GYRO-SS 500.00 3.00 180.00 499.91 427.91 -5. 23 0.00 1.50 6000053.27 566135.25 Start Dir 2?/10 600.00 5.00 180.00 599.66 527.66 -12. 21 0.00 2.00 6000046.29 566135.31 CB-GYRO-SS 650.00 6.00 180.00 649.43 577.43 -17. 00 0.00 2.00 6000041.50 566135.35 CB-GYRO-SS 700.00 5.00 180.00 699.20 627.20 -21. 79 0.00 2.00 6000036.71 566135.39 CB-GYRO-SS 800.00 3.00 180.00 798.95 726.95 -28. 77 0.00 2.00 6000029.73 566135.45 CB-GYRO-SS 900.00 1.00 180.00 898.88 826.88 -32. 26 0.00 2.00 6000026.24 566135.49 CB-GYRO-SS 950.00 0.00 0.00 948.88 876.88 -32. 70 0.00 2.00 6000025.81 566135.49 End Dir :950' 1000.00 0.00 0.00 998.88 926.88 -32. 70 0.00 0.00 6000025.81 566135.49 CB-GYRO-SS 1100.00 0.00 0.00 1098.88 1026.88 -32. 70 0.00 0.00 6000025.81 566135.49 CB-GYRO-SS 1200.00 0.00 0.00 1198.88 1126.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1300.00 0.00 0.00 1298.88 1226.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1400.00 0.00 0.00 1398.88 1326.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1500.00 0.00 0.00 1498.88 1426.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1600.00 0.00 0.00 1598.88 1526.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1700.00 0.00 0.00 1698.88 1626.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1800.00 0.00 0.00 1798.88 1726.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 1873.12 0.00 0.00 1872.00 1800.00 -32. 70 0.00 0.00 6000025.81 566135.49 BPRF 1900.00 0.00 0.00 1898.88 1826.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 2000.00 0.00 0.00 1998.88 1926.88 -32. 70 0.00 0.00 6000025.81 566135.49 MWD+IFR+MS 2001.12 0.00 0.00 2000.00 1928.00 -32. 70 0.00 0.00 6000025.81 566135.49 Start Dir 3?/10 2100.00 3.96 316.49 2098.80 2026.80 -30. 22 -2.35 4.00 6000028.26 566133.12 MWD+IFR+MS 2200.00 7.96 316.49 2198.24 2126.24 -22. 70 -9.49 4.00 6000035.72 566125.91 MWD+IFR+MS 2300.00 11.96 316.49 2296.72 2224.72 -10.16 -21.39 4.00 6000048.15 566113.90 MWD+IFR+MS • • Sperry-Sun BP Planning Report Company: BP Amoco Date: 8/16/2005 Time: 16:20:33 Page: 3 L~'icld: Mil ne Point Co-ordinate(NI•:) R eference: Well: Plan MPS-90, True North Sitr. M Pt S Pad Vertic al (TVD) Reference: 72' pre plan R KBE 72.0 Well: Pla n MPS-90 Sectio n (VS) Reference: Well (O.OON,O .OOE,311.40Azt) Wellpath: Pla n MPS-90 Survey CatculaHon Method: Minimum Curvature Db: Oracle Survev MD Incl Azim TVD Sys TVD ~/S E/W DLS MapN MapE ToollComme t ft deg deg ft ff ft ft degl100ft ft ft 2400 .00 15.96 316.49 2393.75 2321.75 7.33 -37.99 4.00 6000065.49 566097.15 MWD+IFR+MS 2500 .00 19.96 316.49 2488.86 2416.86 29.68 -59.21 4.00 6000087.65 566075.74 MWD+IFR+MS 2600 .00 23.96 316.49 2581.59 2509.59 56.79 -84.94 4.00 6000114.53 566049.77 MWD+IFR+MS 2700 .00 27.96 316.49 2671.48 2599.48 88.53 -115.06 4.00 6000146.00 566019.37 MWD+IFR+MS 2800 .00 31.96 316.49 2758.10 2686.10 124.74 -149.43 4.00 6000181.90 565984.68 MWD+IFR+MS 2900 .00 35.96 316.49 2841.03 2769.03 165.24 -187.88 4.00 6000222.06 565945.89 MWD+IFR+MS 3000 .00 39.96 316.49 2919.87 2847.87 209.84 -230.21 4.00 6000266.28 565903.16 MWD+IFR+MS 3100 .00 43.96 316.49 2994.22 2922.22 258.32 -276.22 4.00 6000314.34 565856.73 MWD+IFR+MS 3178 .61 47.10 316.49 3049.28 2977.28 299.00 -314.84 4.00 6000354.68 565817.76 MWD+IFR+MS 3200 .00 47.10 316.49 3063.85 2991.85 310.37 -325.62 0.00 6000365.95 565806.87 MWD+IFR+MS 3300 .00 47.10 316.49 3131.92 3059.92 363.50 -376.05 0.00 6000418.62 565755.98 MWD+IFR+MS 3400 .00 47.10 316.49 3199.99 3127.99 416.63 -426.48 0.00 6000471.30 565705.08 MWD+IFR+MS 3500 .00 47.10 316.49 3268.06 3196.06 469.76 -476.91 0.00 6000523.98 565654.19 MWD+IFR+MS 3600 .00 47.10 316.49 3336.14 3264.14 522.89 -527.34 0.00 6000576.66 565603.30 MWD+IFR+MS 3611 .82 47.10 316.49 3344.18 3272.18 529.18 -533.31 0.00 6000582.88 565597.28 End Dir.: 3611 3700 .00 47.10 316.49 3404.21 3332.21 576.03 -577.77 0.00 6000629.33 565552.40 MWD+IFR+MS 3800 .00 47.10 316.49 3472.28 3400.28 629.16 -628.20 0.00 6000682.01 565501.51 MWD+IFR+MS 3900 .00 47.10 316.49 3540.35 3468.35 682.29 -678.63 0.00 6000734.69 565450.62 MWD+IFR+MS 4000 .00 47.10 316.49 3608.43 3536.43 735.42 -729.06 0.00 6000787.37 565399.72 MWD+IFR+MS 4071 .36 47.10 316.49 3657.00 3585.00 773.33 -765.05 0.00 6000824.95 565363.41 TUZC 4100 .00 47.10 316.49 3676.50 3604.50 788.55 -779.49 0.00 6000840.04 565348.83 MWD+IFR+MS 4200 .00 47.10 316.49 3744.57 3672.57 841.68 -829.92 0.00 6000892.72 565297.93 MWD+IFR+MS 4300 .00 47.10 316.49 3812.64 3740.64 894.81 -880.35 0.00 6000945.40 565247.04 MWD+IFR+MS 4365 .16 47.10 316.49 3857.00 3785.00 929.43 -913.21 0.00 6000979.72 565213.88 Ugnu MA 4400 .00 47.10 316.49 3880.72 3808.72 947.94 -930.78 0.00 6000998.08 565196.15 MWD+IFR+MS 4431 .34 47.10 316.49 3902.05 3830.05 964.60 -946.59 0.00 6001014.59 565180.20 Start Dir 3?/10 4467 .99 47.10 316.49 3927.00 3855.00 984.07 -965.07 0.00 6001033.89 565161.54 Ugnu MB2 4500 .00 47.10 316.49 3948.79 3876.79 1001.08 -981.21 0.00 6001050.75 565145.25 MWD+IFR+MS 4600 .00 47.09 316.49 4016.86 3944.86 1054.21 -1031.64 0.01 6001103.43 565094.36 MWD+IFR+MS 4643 .56 45.35 316.50 4047.00 3975.00 1077.02 -1053.29 4.00 6001126.05 565072.51 Ugnu MC 4677 .22 44.00 316.50 4070.94 3998.94 1094.18 -1069.58 4.00 6001143.07 565056.07 MWD+IFR+MS 4678 .70 44.00 316.50 4072.00 4000.00 1094.93 -1070.29 0.00 6001143.80 565055.36 13 3/8" 4692 .60 44.00 316.50 4082.00 4010.00 1101.93 -1076.94 0.00 6001150.75 565048.65 Top Schrader 4700 .00 44.00 316.50 4087.32 4015.32 1105.66 -1080.48 0.00 6001154.45 565045.08 MWD+IFR+MS 4775 .38 44.00 316.50 4141.55 4069.55 1143.64 -1116.52 0.00 6001192.10 565008.70 End Dir :4775 4795 .38 44.00 316.50 4155.93 4083.93 1153.72 -1126.08 0.00 6001202.10 564999.05 Start Dir 3?/10 4800 .00 44.00 316.50 4159.26 4087.26 1156.05 -1128.29 0.00 6001204.40 564996.82 MWD+IFR+MS 4873 .32 44.00 316.50 4212.00 4140.00 1192.99 -1163.35 0.00 6001241.03 564961.44 TSBD-OA 4887 .22 44.00 316.50 4222.00 4150.00 1200.00 -1170.00 0.00 6001247.98 564954.73 MPS-90 T1 wp 8 4900 .00 44.00 316.50 4231.19 4159.19 1206.44 -1176.11 0.00 6001254.36 564948.57 MWD+IFR+MS 4956 .73 44.00 316.50 4272.00 4200.00 1235.02 -1203.24 0.00 6001282.70 564921.19 Base Schrader 4957 .22 44.00 316.50 4272.35 4200.35 1235.27 -1203.47 0.00 6001282.95 564920.95 MWD+IFR+MS 5000 .00 42.30 316.28 4303.56 4231.56 1256.45 -1223.65 4.00 6001303.95 564900.59 MWD+IFR+MS 5100 .00 38.31 315.70 4379.81 4307.81 1302.97 -1268.57 4.00 6001350.07 564855.26 MWD+IFR+MS 5200 .00 34.33 315.01 4460.36 4388.36 1345.12 -1310.18 4.00 6001391.84 564813.29 MWD+IFR+MS 5211 .22 33.89 314.92 4469.65 4397.65 1349.57 -1314.63 4.00 6001396.25 564808.79 MWD+IFR+MS 5300 .00 33.89 314.92 4543.35 4471.35 1384.52 -1349.68 0.00 6001430.88 564773.44 MWD+IFR+MS 5400 .00 33.89 314.92 4626.36 4554.36 1423.89 -1389.16 0.00 6001469.90 564733.61 MWD+IFR+MS 5461 .22 33.89 314.92 4677.19 4605.19 1447.99 -1413.34 0.00 6001493.79 564709.23 MWD+IFR+MS 5500 .00 32.34 314.70 4709.66 4637.66 1462.92 -1428.36 4.00 6001508.58 564694.07 MWD+IFR+MS 5600 .00 28.36 314.04 4795.94 4723.94 1498.26 -1464.46 4.00 6001543.60 564657.67 MWD+IFR+MS 5700 .00 24.37 313.19 4885.53 4813.53 1528.91 -1496.58 4.00 6001573.95 564625.28 MWD+IFR+MS • Sperry-Sun BP Planning Report Company: BP Amoco Date: 8/16/2005 ' l'ime: 16:20:33 Page: 4 Nicld: Mil ne Point Co-ordinatc(nE) R eference: Well: Plan MP S-90, True No rth Sitr. M Pt S Pad Vertic al (TVD) Reference: 72' pre plan RKBE 72.0 Well: Ptan MPS-90 Sectio n (VS) Kefcrcnce: Well'(O.OON,O. OOE,311.40Azi) Wellpath: Plan MPS-90 Survey Calculation Method: Minimum Curvature Db: Orade Survey Mll lnd Azim TVD Sys TVD N/S E/W DLS MapN NIapE Tool/Comme t ft deg deg ft ft ft ft deg/100ft ft ft 5800.00 20.40 312.03 4977.97 4905.97 1554.71 -1524.58 4.00 6001599.50 564597.06 MWD+IFR+MS 5900.00 16.43 310.33 5072.83 5000.83 1575.54 -1548.32 4.00 6001620.12 564573.14 MWD+IFR+MS 5997.97 12.57 307.67 5167.67 5095.67 1591.03 -1567.33 4.00 6001635.44 564553.99 End Dir :5997 6000.00 12.49 307.60 5169.65 5097.65 1591.30 -1567.68 4.00 6001635.71 564553.64 MWD+IFR+MS 6100.00 8.60 302.43 5267.94 5195.94 1601.91 -1582.56 4.00 6001646.18 564538.67 MWD+IFR+MS 6200.00 4.89 289.20 5367.24 5295.24 1607.33 -1592.90 4.00 6001651.51 564528.28 MWD+IFR+MS 6300.00 2.41 234.74 5467.05 5395.05 1607.51 -1598.64 4.00 6001651.64 564522.54 MWD+IFR+MS 6340.40 2.75 199.01 5507.42 5435.42 1606.10 -1599.65 4.00 6001650.22 564521.54 MWD+IFR+MS 6400.00 2.75 199.01 5566.94 5494.94 1603.40 -1600.59 0.00 6001647.51 564520.63 MWD+IFR+MS 6500.00 2.75 199.01 5666.83 5594.83 1598.86 -1602.15 0.00 6001642.96 564519.11 MWD+IFR+MS 6600.00 2.75 199.01 5766.71 5694.71 1594.32 -1603.72 0.00 6001638.41 564517.58 MWD+IFR+MS 6700.00 2.75 199.01 5866.60 5794.60 1589.78 -1605.28 0.00 6001633.85 564516.06 MWD+IFR+MS 6800.00 2.75 199.01 5966.48 5894.48 1585.24 -1606.84 0.00 6001629.30 564514.54 MWD+IFR+MS 6900.00 2.75 199.01 6066.37 5994.37 1580.70 -1608.41 0.00 6001624.75 564513.01 MWD+IFR+MS 7000.00 2.75 199.01 6166.25 6094.25 1576.16 -1609.97 0.00 6001620.19 564511.49 MWD+IFR+MS 7100.00 2.75 199.01 6266.14 6194.14 1571.62 -1611.54 0.00 6001615.64 564509.96 MWD+IFR+MS 7115.88 2.75 199.01 6282.00 6210.00 1570.90 -1611.79 0.00 6001614.92 564509.72 THRZ 7165.94 2.75 199.01 6332.00 6260.00 1568.63 -1612.57 0.00 6001612.64 564508.96 BHRZ 7200.00 2.75 199.01 6366.02 6294.02 1567.08 -1613.10 0.00 6001611.09 564508.44 MWD+IFR+MS 7266.05 2.75 199.01 6432.00 6360.00 1564.08 -1614.13 0.00 6001608.08 564507.43 KLGM 7300.00 2.75 199.01 6465.91 6393.91 1562.54 -1614.67 0.00 6001606.53 564506.92 MWD+IFR+MS 7400.00 2.75 199.01 6565.79 6493.79 1558.00 -1616.23 0.00 6001601.98 564505.39 MWD+IFR+MS 7436.25 2.75 199.01 6602.00 6530.00 1556.35 -1616.80 0.00 6001600.33 564504.84 TKUD 7500.00 2.75 199.01 6665.68 6593.68 1553.46 -1617.79 0.00 6001597.43 564503.87 MWD+IFR+MS 7600.00 2.75 199.01 6765.56 6693.56 1548.92 -1619.36 0.00 6001592.87 564502.34 MWD+IFR+MS 7601.44 2.75 199.01 6767.00 6695.00 1548.86 -1619.38 0.00 6001592.81 564502.32 TKC1 7700.00 2.75 199.01 6865.44 6793.44 1544.38 -1620.92 0.00 6001588.32 564500.82 MWD+IFR+MS 7776.64 2.75 199.01 6942.00 6870.00 1540.90 -1622.12 0.00 6001584.83 564499.65 TKUA 7800.00 2.75 199.01 6965.33 6893.33 1539.84 -1622.49 0.00 6001583.77 564499.30 MWD+IFR+MS 7876.76 2.75 199.01 7042.00 6970.00 1536.36 -1623.69 0.00 6001580.27 564498.13 TMLV 7900.00 2,75 199.01 7065.21 6993.21 1535.30 -1624.05 0.00 6001579.22 564497.77 MWD+IFR+MS 8000.00 2.75 199.01 7165.10 7093.10 1530.76 -1625.62 0.00 6001574.66 564496.25 MWD+IFR+MS 8006.91 2.75 199.01 7172.00 7100.00 1530.45 -1625.72 0.00 6001574.35 564496.14 9 5/8" 8100.00 2.75 199.01 7264.98 7192.98 1526.22 -1627.18 0.00 6001570.11 564494.72 MWD+IFR+MS 8200.00 2.75 199.01 7364.87 7292.87 1521.68 -1628.75 0.00 6001565.56 564493.20 MWD+IFR+MS 8300.00 2.75 199.01 7464.75 7392.75 1517.14 -1630.31 0.00 6001561.00 564491.68 MWD+IFR+MS 8357.31 2.75 199.01 7522.00 7450.00 1514.54 -1631.21 0.00 6001558.39 564490.80 TKNG 8400.00 2.75 199.01 7564.64 7492.64 1512.60 -1631.87 0.00 6001556.45 564490.15 MWD+IFR+MS 8500.00 2.75 199.01 7664.52 7592.52 1508.06 -1633.44 0.00 6001551.90 564488.63 MWD+IFR+MS 8600.00 2.75 199.01 7764.41 7692.41 1503.52 -1635.00 0.00 6001547.34 564487.10 MWD+IFR+MS 8700.00 2.75 199.01 7864.29 7792.29 1498.98 -1636.57 0.00 6001542.79 564485.58 MWD+IFR+MS 8800.00 2.75 199.01 7964.18 7892.18 1494.44 -1638.13 0.00 6001538.24 564484.06 MWD+IFR+MS 8900.00 2.75 199.01 8064.06 7992.06 1489.90 -1639.70 0.00 6001533.69 564482.53 MWD+IFR+MS 9000.00 2.75 199.01 8163.95 8091.95 1485.36 -1641.26 0.00 6001529.13 564481.01 MWD+IFR+MS 9100.00 2.75 199.01 8263.83 8191.83 1480.82 -1642.82 0.00 6001524.58 564479.48 MWD+IFR+MS 9200.00 2.75 199.01 8363.71 8291.71 1476.28 -1644.39 0.00 6001520.03 564477.96 MWD+IFR+MS 9300.00 2.75 199.01 8463.60 8391.60 1471.74 -1645.95 0.00 6001515.47 564476.44 MWD+IFR+MS 9396.75 2.75 199.01 8560.24 8488.24 1467.35 -1647.47 0.00 6001511.07 564474.96 Start Dir 8?/10 9400.00 2.75 199.01 8563.48 8491.48 1467.20 -1647.52 0.00 6001510.92 564474.91 MWD+IFR+MS 9500.00 2.75 199.01 8663.37 8591.37 1462.66 -1649.08 0.00 6001506.37 564473.39 MWD+IFR+MS 9558.70 2.75 199.01 8722.00 8650.00 1460.00 -1650.00 0.00 6001503.69 564472.49 MPS-90 T2 wp 8 9600.00 2.79 252.12 8763.26 8691.26 1458.75 -1651.28 6.00 6001502.44 564471.22 MWD+IFR+MS 9628.79 3.90 275.31 8792.00 8720.00 1458.63 -1652.92 6.00 6001502.30 564469.58 TSHU .. - , ! '~ Sperry-Sun BP Planning Report Company: BP Amoco llate: 8/16/2005 Time: 16:20:33 Page: 5 Field: Mil ne Point Co-ordinatc(NE) Rcfcrcncr. Well: Plan MP S-90, True North Site: M Pt S Pad Vertic al (TVD) Re ference: 72' pre plan RKBE 72.0 Well: Plan MPS-90 Scc6o n (VS) Refer ence: Well (O.OON,O. OOE,311.40Azi) Wcllpath: Plan MPS-90 Survey Calculation Method: Minimum Curv ature Db: Oracle Sure c~ MD Incl Azim TVD Sys TVD N/S E/W DLS MapV MapE ToollComme~ ~ t ft deg deg ft ft ft ft deg/100ft ft ft 9700.00 7.69 296.05 8862.84 8790.84 1460.95 -1659.62 6.00 6001504.56 564462.87 MWD+IFR+MS 9780.41 12.36 303.35 8942.00 8870.00 1468.04 -1671.65 6.00 6001511.54 564450.78 TEIL 9800.00 13.51 304.37 8961.10 8889.10 1470.49 -1675.29 6.00 6001513.96 564447.12 MWD+IFR+MS 9821.56 14.78 305.30 8982.00 8910.00 1473.50 -1679.61 6.00 6001516.93 564442.77 TSAD 9900.00 19.44 307.70 9056.95 8984.95 1487.27 -1698.11 6.00 6001530.53 564424.15 MWD+IFR+MS 10000.00 25.40 309.52 9149.36 9077.36 1511.11 -1727.85 6.00 6001554.11 564394.21 MWD+IFR+MS 10100.00 31.37 310.68 9237.29 9165.29 1541.75 -1764.16 6.00 6001584.42 564357.62 MWD+IFR+MS 10177.45 36.00 311.33 9301.72 9229.72 1569.94 -1796.56 6.00 6001612.32 564324.98 End Dir :1017 10200.00 37.35 311.50 9319.81 9247.81 1578.85 -1806.66 6.00 6001621.14 564314.80 MWD+IFR+MS 10300.00 43.34 312.12 9395.99 9323.99 1622.01 -1854.88 6.00 6001663.86 564266.20 MWD+IFR+MS 10400.00 49.33 312.62 9465.00 9393.00 1670.74 -1908.29 6.00 6001712.12 564212.37 MWD+IFR+MS 10500.00 55.32 313.03 9526.09 9454.09 1724.53 -1966.31 6.00 6001765.39 564153.89 MWD+IFR+MS 10501.81 55.43 313.04 9527.12 9455.12 1725.55 -1967.40 6.00 6001766.39 564152.79 MWD+IFR+MS 10580.91 55.43 313.04 9572.00 9500.00 1770.00 -2015.00 0.00 6001810.42 564104.80 MPS-90 T3 wp 8 10600.00 55.43 313.04 9582.83 9510.83 1780.73 -2026.49 0.00 6001821.05 564093.21 MWD+IFR+MS 10700.00 55.43 313.04 9639.58 9567.58 1836.93 -2086.67 0.00 6001876.71 564032.54 MWD+IFR+MS 10780.00 55.43 313.04 9684.97 9612.97 1881.89 -2134.82 0.00 6001921.23 563984.01 7 5/8" ~ 10780.91 55.43 313.04 9685.49 ~ 9613.49 1882.40 -2135.36 0.00 6001921.74 563983.46 MWD+IFR+MS I • name Plan MP8A0 WEL +WS +Fl-W Nanhmg 83.37 -209.10 6000058.50 L DETAILS E amg Lsuode Wngiwde Sbt 566135.20 70'2478.I79N 149°3741 JOOw n/A ANTI-COLLISION SETTRVGS Interpolation Method:MD Interval 25.00 Depfh Range Fmm: 34.00 To: 10780.91 Maximum Range: 1274.69 Reference: Plan: MPS-90 N'p09 COMPMY DETAILS BP Amoco Calcolanon Med,ad: Mummm CmnWm Famr Symn: ISCWSA Scan Method: Tnv C~Imder Narth Enm Surfce: EBipecal+Canng Wetting Mehod: Roks Ba+ed SLRVEY %OOGRAM Degh Fm D4gh To Stnry?ha Tool 74.00 1300.00 Phmxd: MPS90 xyD7 V65 CB-OYR0.SS 1200.00 1078091 Phmied: MPSAO xy09 V65 MWDHFR+MS -OS WELLPATFI DETAILS 160 ~~ From Colour To MD clan MPS-9o 150 `.> ~e ~ 34 500 s«~e walR wen ~ 4 500 1 OOO Ref. Dazm i' 7T prt plan RKBE 72.OOR 33 loo0 lsoo Y.Sectim ~„~ ~;~, 5 ~ 1500 2000 Awe +ws +Fr-w F vD 2000 2SOO 31140' 0.00 000 1400 125 '~ 2500 3000 3000 3500 3500 ~8 4000 . 1~ 4000 4500 ~ $ ~ so LEGEND 100 ~ / sooo s o ~ 5500 6000 - ,~ 6000 7000 ~0 0 7000 8000 75 8 `' 8000 9000 = 9000 11000 - y 11000 12000 ~ 2000 13000 ~ ° ~ ,{ 0 0 a 1 o ~ 1 i sooo 4 , 5 ~ r ~ ~' ~ _ - 1 _ ~ i _. . s . -x:;.9 - - f - 0 270 - ~ ~v"~ ! ~. ' , ~ ' - 90 ~ 4 , , . ~, - x'11 4,,~„+ ~ _: ~ ~~ - '~ ~_ ' ~ - - 25 ' = ~ 1 ~, ~~ 20 00 21 50 X160 _""`i'.~.~ '°~ ,~ Tr. vo.ling ;ylinde Aziml :h (Tl ~- 4;~.I) [n -g] vs C ntre t Cer, -e Se laration t`Oft/in] Sec MD Irc Ari TVD +N/S •F/-W Dleg TFec< VSec TvgeO I Na0 0.00 0.00 3d.00 0.00 0.00 0.00 0.00 0.00 2 3a0.0o 000 0.00 300.00 0.00 0.00 0.00 0.00 0.00 3 500.00 3.00 IB0.00 499.91 -517 0.00 1.30 180.00 -3.46 1 650.00 6.00 IBO.W 649.43 -17.00 0.00 2.00 0.00 -1114 5 950.00 0.00 0.00 948.88 -32.70 0.00 2.00 180.OD -21.62 6 2001.12 0.00 000 2000.00 -32.70 0.00 0.00 000 -21.62 7 3178.61 47.10 31649 304928 299.00 -314.84 d.00 0.00 473.90 8 4s99.73 67.10 316.49 4016.68 IOS407 -1031.51 0.00 0.00 1470.81 9 467713 44.00 716.50 4070.94 1094.18 -1069.58 4.00 179.93 1525.90 10 4887.22 44.00 JI6.50 4222.00 1200.00 -1170.00 0.00 0.00 1671.20 MPS-90 TI II 495722 41.00 716.50 4272.35 1235.27 -1203.17 0.00 0.00 1719.63 13 521123 37.89 31d.92 M69.65 1749.57 -1714.fi3 4.00 -175.00 1878.60 I7 516112 3389 31d.92 4fi77.19 1447.99 -1413.1d 0.00 0.00 2017.73 14 63W.40 275 199.01 5507.42 160610 -1599.65 d.00 -175.70 226305 IS 9558.70 3.75 199.01 8722.00 1460,00 -1650.OD 0.00 000 220310 MPS90 T3 I6 10501%I 55.47 717.04 9527.12 1725.55 -1967.40 6.00 IIS.71 2616.89 17 18 10580.91 5547 10780.91 SS.d3 313.00 317.00 9572.00 9685.49 17700D 188240 -2013.00 -2135.3fi 0.00 0.00 000 000 2M1R200 MPS-90 TJ 280fi.b1 0 1,000 2,000 3,000 4,000 .-. = 5,000 a ~ 6,000 D ~ 7,000 W 8,000 9,000 10,000 11,000 12,000 13,000 MPS-90 Drill 16" Surtac e Hole TIME vs DEPTH -SAFE Ti mes -Actual Times Set 13-3/8" Casin at 4678' Drill 12-1/4" Intermediate Hole Set 9-5/8" Casing at 8007' Drill 8-1/2" Hole Set 7" Liner at 10780' MD Run GR/CBUCCL & Perforate Run 5-1/2" ESP Completion 0 5 10 15 20 25 • • TIME (days) by ,C: I August 30`t`, 2005 Tom Maunder Alaska Oil & Gas Conservation Commission 333 W. 7`}' Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Permit to Drill, Form: MPU S-Pad / MPS-90 Ivishak Water Supply Well 10-401 Mr. Maunder: BP Exploration (Alaska) Inc. ("BP") hereby to requests a Permit to drill the captioned water supply ~ well: MPS-90. ~ MPS-90 ~is designed to penetrate .the Ivishak 'sands and TD in the Kavik. It is planned to extract clean, hot water from the Ivishak, and use the hot water to improve the performance of MPU's Schrader Bluff, viscous oil project. MPS-90 will be drilled in accordance with 20 ACC 25. The 16" surface hole will be drilled using Doyon 14's diverter system. The 13-3/8" surface casing will be set above the Schrader Bluff in or above the NA shale. The 13-3/8" casing will be cemented to surface in one stage using accepted field practices. The BOP equipment will be installed and tested to 5000 psi. Next, the 12-1/4" intermediate hole will be drilled through the Schrader Bluff and the Kuparuk if possible. Lost circulation may occur in the Schrader Bluff especially after increasing the mud weight to drill the HRZ, Kalubik and Kuparuk. If the Schrader Bluff fails, it is planed to set the 9-5/8" casing near the T/HRZ. The 9-5/8" casing shoe will be cemented with 1000' of annular volume plus excess. A stage S~~ tool will be run below the hydrocarbon bearing sands in the Schrader Bluff and the annulus will be ~' `~-- cemented to surface. The second stage is designed to cover the oil sands with cement as required --' ~.~'`~'`~ and to displace the 9-5/8" x 13-3/8" annulus with cement. Finally, an 8-1/2" hole will be drilled C,``~ through the Ivishak sands and TD in the Kavik. A 7" liner will be set and cemented at TD. Estimated reservoir pressure in the Ivishak is 9.6 ppg EMW. This water supply well will therefore be capable of unassisted flow to surface. However, it will be necessary to complete the well with an electric submersible pump (ESP) to provide high delivery rates (20,000 BWPD). AOGCC regulation AAC 25.200(d) `requires all wells capable of unassisted flow to be completed with downhole tubing and packer that will isolate the tubing/casing annulus from produced fluid, unless otherwise specifically approved by the commission'. As part of this permit, BP requests a variance from AAC 25.200(d), to allow for apacker-less, ESP completion. Asub-surface safety valve (SSSV) would also not be run in the completion: Rule 1 of Conservation Order No. 390 allows for ~.Sc,~.~ ~\~s G.c~ ~P~ ~~,.~~. ~~ ~ r~ Svc c~cc~ ~ 1~ ~ ~~ ~ S~ e a~ c~`> ~o~~ cep\~Y -~o~ iy~,~,c~.~b~h .. • • Milne Point wells equipped with an ESP and which do not require installation of SSSVs, may be completed without a packer assembly. This applies for the Kuparuk oil pool, Schrader Bluff oil pool and Sag River Undefined oil pool in the Milne Point Unit. The Ivishak interval is not addressed in , CO 390. BP request the variance from AAC 25.200(d) for operational reasons consistent with the findings of CO 390. If you have any questions or require any additional information, please contact the undersigned at 564-4395, or Dan Kara at 564-5667. Sincerely, Skip yner Drilling Engineer 89-611252 ~ 32 STEi~'VMAN n SONDRA D '~.P gP EXPLORATIOB ~~K ANC 'Mastercard Check" DATES " PO BOX 196612 ANCHORAGE, AK 99519-661:2 $ ~ ~~ PAY TO THE ''~ J~'~ - DOLLARS ORDER OF ~ ~~- k Alaska First NationaAK gg501 Anchorage, ~ ~ I {~(~ _ MEMO p0060~99 L4..~6 2 27.~~ L564n^ O L3 2 ~:L252 •w .. \ n • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER _~'_ WELL NAME `~~~~~ ~ ~ PTD# ~-~' ~ _" f~ CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well , Permit No, API No. (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (PIS records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce/infect is contingent upon issuance of a conservation order approving a spacing exception. (Company Name1 assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals. through target zones. Rev: 04/01/05 C\j ody\transm ittal_checklist ELL PF~R CHECKLIST Field & Pool Well Name: MILNE PT UNIT IV S-90 Program SER Well bore seg ^ PTD#:2051350 Company BP EXPLORATION (ALASKA) INC Initial ClasslType SER I PEND GeoArea 890 Unit 11328 OnlOff Shore On Annular Disposal ^ Administration 1 Permit fee attached - - - - - - - - - - - - - Yes - - - - - - - - - - 2 Lease number appropriate- - - - - - - - - - - - - - - - Yes Surface location in AD1.038011~, top prod interval & TD in-ADL-380109- - - - - - - . - - - - - - - _ _ _ _ _ - - - 3 Uniquewell_nameandnumber- --- --------- -- ---------- -- --- Yes-- ----------------------------- -------------------------------------- -- - 4 Well located in a-definedpool_-----------------------___--.-_-.--. No--_ _--__Ivisha_kwater source well,_undefinedpool---__.__..----____-..__._-..__--__..__.._- 5 Well located properdistancefromdrillingunitboundary________________________ Yes__ ____-WslllieswithimMPUboumdaryamdPA._____----________---_---_--__-__..-__- 6 Well located proper distance from otherwells- - Yes Nearest Ivishak-penetrations a[e-3-miles NNE_(Kavearak Pt, 32-25) and 3 miles SE-(NWE2-01). - _ - - - _ - _ _ _ _ 7 Sufficientacreageayail_ablein_drillingunit-_ ............................. Yes-- -----AsaboYe.-_-_--__.__--__.-______-__-._____-__-__------_ 8 If deviated, is_wellbore Platincluded - - - - - - - - - - - - - - Yes - - - - - - - - 9 Operatoronlyaffectedparty-------------------------------------- Yes-- ------------, ---------------------------------------------------------- 10 Operatoihasappropriate-bondinforce ------------ ------------- -- Yes-- -----------•-------------------------- ----------------- ------------ -- 11 Permit_canbeissuedwithoutconservationorder---------------------------- Yes- ------------------------------------------------------------------- Appr Date 12 Pe[miteanbeissuedwithoutadministrative_approval_________________________ Yes__ _________________-.___._.________.__.__..__.._ ------------------------- FD 9/7/2005 13 14 Can permit be approved before 15-day wait Well located within area and strata authorized bylnjectionO[der#(put1O#in_comments)_(For_ Yes NA_-_ --___-__-_________--__________________________________________________ 15 All wells withinll4_mileareaofreyiewidentified(Forservicewellonly)--------------- NA--_ ---_---_----______.__................._....._._....................._.__- 16 Pre-produced injector: duration-of pre production less than 3 months-(For service well Only) - . NA_ _ ---------------------------------------------------------- 17 ACNIP-EindingofConsistency_hasbeenissued_for_thisproject________________-- NA--- --------------_____-._-._-.___-______--__-_______.___--_-____________-- Engineering 18 Conduckor. sting-Provided - Yes - - - - - - - - - - - - - 19 Surface casing-protectsall_knowmUSDWs_______________________-_--_ NA--- --_--All aquifers exempted, 40 CFR-147.102jb)(3).-_-_______-______-___-_-_--______-__-- 20 CMT-voladequ_ate_toci[cul_ate_onconductor_8~surf_csg_--------------- ------ Yes-- --_----------___--_.-_--___-_____-___--___-_________--_----__________-_-. 21 CMT-vol adequate-to tie-in long string to surf csg_ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _N_o_ _ _ - _ _ - -All hydrocarbon zones will be-coYered, Schrader by stagejob plus downsqueeze.- - - .. - _ - _ _ _ - _ - _ _ _ _ _ - 22 CMT_willcover_allknow_n_productiyehorizon_s___________________________ Yes-- --_--Production_linerwillbe_cemented._____________-______________________________--._ 23 Casing designs adequateforC,TB&-permafrost-_________________________ Yes__ ..__..--___________________-_.___ _---._-. ---------------------- 24 Adequate tankage-or reserve pit Yes - - - - - - -Rig is-equipped with steel-pits. -No_ rese_rve_pitplanned, All waste to approved disposal wells.- 25 If_a_re-drilll,has_a_1003forabandonmentbeenapproved---------------------- NA___ __-_____________________-_--_____-.__..__.___-_-.--_-.--..__-.----__- 26 Adequate wellbore separatjon-proposed- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ _ _ _ _ _ Proximity analysis perf_o[med, Traveling cylinder path calculated, Gyros likely in surface. hole, _ . _ . _ . _ .. - - - 27 Ifdiverterrequired,doesitmeetregulations_______________________________ Yes-_ -----.----____--_______________________________________--__--__--_--. Appr Date 28 Drilling fluid-program schematic & equip list adequate- - - - - - - - - - - - - - - - - - - - - - - - - Yes _ _ . _ _ _ .Maximum expected fom7atipn pressure 9,6_EMW in Ivishak._ MW planned 10.Q -11.0 ppg._ _ _ _ _ _ _ _ _ _ _ _ _ _ - TEM 9/2112005 29 BOPEs,dotheymeetregulation-------------------------___---___ Yes__ _____-_ _...__-. --------------------------------------------------- Qyt/~ . " 30 BOPS-press rating appropriate; test to_(pu_t psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - MASP with 0.1 gradient 3550-psi. Likely g[adient,445_giving MASP 560 psi._ _ - - - - _ - _ - - - _ _ _ _ - _ - _ _ - - + I 31 Choke-manifoldcomplieswlAPI-RP-53(M_ay84)____________________________ Yes__ ..__..-BP plans-5000 psi BOP test.----_---___--_-_-_-__--____---_..-__---_---_-- 32 Work will occur without operation shutdown_______________________________ Yes__ ___-_Completionisplanned_with drilling rig.-----------------___--._-.-_...-____--__-._.- 33 Is presence-of H2Sgas-probable _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ H2S is notleported on_S pad, Ivishak should contain water, Rigis equipped with-sensors-and alarms. _ _ - . _ _ . 34 Mechanical condition of wells within AOR verified (FOrservice well only) - - - - - - - - - - - - - - Yes - - - - - - -MPS-9Q is much deeper_than_well& in area. There ar_e no penetrations below SB on S pad_or KUP on H_p_ad._ - . Geology 35 Permit can be issued wlo hydrogen_sulfide measures _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ - - No H2S encountered-in previous_Mil_ne Point_Ivish_ak wells. _ - - _ _ - _ _ _ _ _ - _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - - 36 Data_presented on_ potential overpressure zones - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Normal_gradientexpeaed to top Sag River, except Schrader Bluff may be underp[essured, Sag River thru - - - - - Appr Date 37 Seismic analysis-of shallpwgas-zones- - - - - - - - - - - -- - - - - - - - - - - - - - - - - - - - - - NA_ _ _ _ _ _ _ _ Kavik expected to be_9.6 ppg, will be drilled with_ 10,Q--11,0-ppg mud.. _ _ - .. _ - - _ ... _ _ _ - _ _ - - _ - . _ _ - SFD 9/7/2005 38 Seabed conditionsurvey_(ifoff_-shore)______------------------------- NA--- ------.----_ ------------------------------------------------------------- 39 -Contact namephoneforweeklyprogress_reports[exploratoryonly]_________________ N_A--- -----.------.----------------_.__-._-.-__--____-.--_--_.--_--_--_-__.-- Geologic Engineering Public Da Date Date: Ivishak water su I well tanned to drill into Kavik. Com lete I suite lus mudl and sam les will be re uired across the pPY P P o9 P o9 p 4 Commissioner: Commissioner: Commissioner 8.112" section as the nearest wells that have drilled through the Ivishak Formation lie from 3 and 4-112 miles to the WSW, SE, ~ ~, ~ zz ~ ` or E, and NNE. N • Well History File APPENDIX Information of detailed nature that is not particularly germane io the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically . organize this category of information. • X05' -~3s_ ~ 13 `~'~ Sperry-Sun Drilling Services LIS Scan Utility $Revision: 3 $ LisLib $Revision: 4 $ Fri Jul 07 15:30:20 2006 Reel Header Service name .............LISTPE Date .....................06/07/07 Origin ...................STS Reel Name ................UNKNOWN Continuation Number......01 Previous Reel Name.......UNKNOWN Comments .................5TS LIS Writing Library. Scientific Technical Services Tape Header Service name .............LISTPE Date .....................06/07/07 Origin ...................STS Tape Name ................UNKNOWN Continuation Number......01 Previous Tape Name.......UNKNOWN Comments .................ST5 LIS Writing Library. Scientific Technical Services Physical EOF Comment Record TAPE HEADER Milne Point MWD/MAD LOGS WELL NAME: API NUMBER: OPERATOR: LOGGING COMPANY: TAPE CREATION DATE: JOB DATA JOB NUMBER: LOGGING ENGINEER: OPERATOR WITNESS: JOB NUMBER: LOGGING ENGINEER OPERATOR WITNESS SURFACE LOCATION SECTION: TOWNSHIP: RANGE: FNL: FSL: MWD RUN 1 W-0004018179 J. BOBBITT J. HABERTHUR MWD RUN 4 W-0004018179 R. FRENCH E. VAUGHN MPS-90 500292327600 BP Exploration Sperry Drilling Services 07-JUL-06 MWD RUN 2 W-0004018179 J. BOBBITT J. HABERTHUR MWD RUN 3 W-0004018179 R. FRENCH E. VAUGHN MWD RUN 5 W-0004018179 R. FRENCH E. VAUGHN 7 12N 11E 3390 • • FEL: 4656 FWL: ELEVATION (FT FROM MSL 0) KELLY BUSHING: DERRICK FLOOR: 72.00 GROUND LEVEL: 38.00 WELL CASING RECORD OPEN HOLE CASING DRILLERS BIT SIZE (IN) SIZE (IN) DEPTH (FT) 1ST STRING 16.000 20.000 114.0 2ND STRING 12.250 13.375 4372.0 3RD STRING 8.500 9.625 7941.0 PRODUCTION STRING REMARKS: 1. ALL DEPTHS ARE BIT DEPTHS UNLESS OTHERWISE NOTED. THESE DEPTHS ARE MEASURED DEPTH (MD). 2. ALL VERTICAL DEPTHS ARE TRUE VERTICAL DEPTH (TVD). 3. MWD RUN 1 COMPRISED DIRECTIONAL AND DUAL GAMMA RAY (DGR) UTILIZING GEIGER- MUELLER TUBE DETECTORS. 4. MWD RUN 2 COMPRISED DIRECTIONAL, DGR, AND ELECTROMAGNETIC WAVE RESISTIVITY PHASE-4 (EWR4). MAD DATA ACQUIRED OVER THE INTERVAL 4672'MD - 4381'MD WHILE POOH AFTER RUN 2 WERE MERGED WITH RUN 2 MWD DATA. 5. MWD RUNS 3-5 COMPRISED DIRECTIONAL, DGR, EWR4, STABILIZED LITHO-DENSITY (SLD), COMPENSATED THERMAL NEUTRON (CTN), ACOUSTIC CALIPER (ACAL), PRESSURE WHILE DRILLING (PWD), AND BIMODAL ACOUSTIC TOOL (BAT) . 6. LOG AND MERGED DIGITAL DATA (LDWG) ONLY WERE SHIFTED TO A SCHLUMBERGER WIRELINE GAMMA RAY RUN IN THE MPS-90 WELLBORE ON 27 NOVEMBER 2005. THESE DIGITAL DATA WERE PROVIDED BY D. DORTCH (SAIC/BP) ON 16 JUNE 2006. LOG HEADER DATA RETAIN ORIGINAL DRILLERS' DEPTH REFERENCES. 7. MWD RUNS 1-5 REPRESENT WELL MPS-90 WITH API,#: 50-029-23276-00. THIS WELL REACHED A TOTAL DEPTH (TD) OF 10600'MD/9733'TVD. SROP = SMOOTHED RATE OF PENETRATION WHILE DRILLING. SGRC = SMOOTHED GAMMA RAY COMBINED. SEXP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (EXTRA-SHALLOW SPACING). SESP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (SHALLOW SPACING). SEMP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (MEDIUM SPACING). • • SEDP = SMOOTHED PHASE SHIFT-DERIVED RESISTIVITY (DEEP SPACING). SFXE = SMOOTHED FORMATION EXPOSURE TIME - DEEP RESISTIVITY. TNPS = SMOOTHED THERMAL NEUTRON POROSITY (ACAL-DERIVED HOLE SIZE) . CTFA = SMOOTHED AVERAGE OF FAR DETECTOR'S COUNT RATE. CTNA = SMOOTHED AVERAGE OF NEAR DETECTOR'S COUNT RATE. SBD2 = SMOOTHED BULK DENSITY-COMPENSATED (LOW-COUNT BIN). SCO2 = SMOOTHED STANDOFF CORRECTION (LOW-COUNT BIN). SNP2 = SMOOTHED NEAR-DETECTOR-ONLY PHOTOELECTRIC ABSORPTION FACTOR (LOW-COUNT BIN) . SLIDE = NON-ROTATED INTERVALS REFLECTING BIT DEPTHS. SLDSLIDE = NON-ROTATED INTERVALS REFLECTING SENSOR-TO-BIT DISTANCE. PARAMETERS UTILIZED FOR POROSITY LOG PROCESSING: HOLE SIZE: ACAL-DERIVED (8.5" BIT) MUD WEIGHT: 10.5-10.9 PPG MUD SALINITY: 400 PPM CHLORIDES FORMATION WATER SALINITY: 26,000 PPM CHLORIDES FLUID DENSITY: 1.0 G/CC MATRIX DENSITY: 2.65 G/CC LITHOLOGY: SANDSTONE File Header Service name .............STSLIB.001 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.000 Comment Record FILE HEADER FILE NUMBER: 1 EDITED MERGED MWD Depth shifted and clipped curves; all bit runs merged. DEPTH INCREMENT: .5000 FILE SUMMARY PBU TOOL CODE START DEPTH STOP DEPTH GR 75.0 10561.5 ROP 116.0 10597.5 RPD 4356.5 10554.0 RPS 4356.5 10554.0 RPM 4356.5 10554.0 RPX 4356.5 10554.0 FET 4356.5 10554.0 FONT 7930.0 10503.5 NCNT 7930.0 10503.5 RHOB 7930.0 10516.0 DRHO 7930.0 10516.0 NPHI 7930.0 10503.5 PEF 7930.0 10516.0 ~ • BASELINE CURVE FOR SHIFTS: CURVE SHIFT DATA (MEASURED DEPTH) --------- EQUIVALENT UNSHIFTED DEPTH --------- BASELINE DEPTH GR 75.0 73.5 7775.0 7773.5 7782.0 7780.0 7799.5 7796.5 7813.5 7813.0 7824.0 7822.5 7836.5 7835.0 7838.5 7837.0 7941.5 7941.5 7944.0 7944.0 7971.5 7971.0 8008.0 8006.5 8076.0 8076.0 8179.0 8180.0 8231.5 8231.0 8379.5 8378.5 8388.5 8388.0 8405.5 8405.0 8409.0 8409.0 8414.0 8414.0 8418.0 8417.5 8429.0 8429.0 8433.0 8433.0 8437.0 8436.5 8442.0 8442.5 8448.0 8448.0 8456.5 8457.0 8462.0 8462.5 8472.0 8472.5 8491.0 8492.0 8499.0 8499.5 8540.5 8541.5 8548.0 8548.5 8597.5 8598.5 8618.0 8619.0 8623.5 8622.5 8634.0 8633.0 8661.5 8660.0 8676.5 8675.0 8701.0 8699.0 8704.0 8702.0 8816.5 8812.5 8820.5 8818.0 8839.0 8836.5 8851.0 8849.5 8854.5 8852.0 8872.0 8870.0 8900.0 8898.5 8907.5 8905.0 8911.5 8908.0 8917.5 8916.0 8952.0 8950.5 8958.5 8957.0 8970.0 8969.0 8976.0 8974.5 9000.0 8999.5 9031.5 9030.0 e • 9040.5 9067.5 9080.0 9083.0 9087.0 9113.0 9117.5 9119.5 9126.5 9129.5 9132.5 9145.5 9149.0 9154.0 9156.5 9164.5 9192.0 9197.5 9208.0 9216.0 9237.0 9244.5 9247.0 9261.0 9263.0 9268.5 9271.0 9283.0 9285.5 9308.5 9310.5 9338.5 9356.0 9402.0 9411.5 9439.0 9451.5 9456.5 9471.0 9593.5 9595.0 9597.0 9611.0 9612.5 9615.0 9616.5 9619.0 9620.0 9622.0 9623.0 9635.5 9649.5 9661.5 9667.0 9668.5 9672.0 9685.0 9701.5 9707.5 9709.5 9720.5 9040.0 9067.0 9079.5 9081.5 9086.0 9112.0 9116.5 9118.5 9125.0 9128.5 9131.0 9144.5 9148.0 9153.0 9156.0 9163.0 9190.5 9195.5 9207.5 9215.0 9233.5 9244.0 9246.0 9259.5 9262.5 9267.0 9270.5 9282.5 9284.0 9308.0 9309.5 9338.5 9355.0 9401.0 9410.5 9438.0 9450.5 9456.0 9470.5 9593.0 9596.0 9598.0 9611.5 9614.0 9616.0 9618.0 9620.0 9621.5 9623.0 9624.5 9637.5 9649.5 9662.0 9667.5 9669.0 9672.5 9686.0 9700.0 9707.0 9709.0 9720.0 • • 9726.0 9730.5 9736.5 9737.5 9740.0 9756.5 9761.5 9763.5 9766.0 9769.0 9771.0 9774.5 9778.0 9782.0 9791.0 9797.5 9802.0 9805.0 9810.0 9812.5 9815.5 9822.0 9825.5 9827.5 9839.5 9845.0 9846.5 9850.5 9856.5 9869.5 9872.0 9874.5 9876.5 9882.0 9883.5 9888.5 9898.5 9904.0 9905.5 9907.0 9909.5 9912.0 9917.5 9923.5 9930.0 9937.0 9941.0 9955.0 9957.5 9959.0 9961.5 9966.5 9978.0 9979.5 9989.5 9997.5 10001.5 10007.5 10014.0 10022.0 10025.0 9726.5 9731.0 9736.5 9737.5 9741.0 9757.0 9761.5 9763.5 9766.5 9769.0 9771.0 9774.0 9778.0 9782.0 9791.0 9798.0 9802.5 9805.5 9810.5 9813.0 9816.0 9822.5 9824.5 9826.0 9840.0 9845.0 9846.5 9850.5 9857.0 9869.5 9872.0 9874.5 9877.0 9882.0 9883.5 9889.0 9899.0 9904.5 9905.5 9907.0 9909.5 9912.0 9918.0 9923.5 9930.0 9937.0 9941.0 9955.5 9958.0 9959.5 9961.5 9966.5 9978.0 9979.5 9989.5 9997.5 10001.5 10008.0 10013.5 10022.5 10025.0 10034.5 10038.5 10049.0 10055.5 10059.0 10060.0 10061.5 10064.0 10066.5 10068.0 10073.0 10087.0 10092.0 10100.0 10104.5 10112.5 10118.5 10130.0 10144.5 10175.0 10182.5 10190.5 10198.0 10203.5 10209.5 10211.5 10224.5 10227.0 10230.0 10232.5 10237.0 10255.5 10266.0 10274.0 10295.5 10324.5 10327.5 10329.0 10330.5 10335.0 10340.0 10342.5 10344.5 10347.5 10348.5 10351.0 10355.0 10360.5 10367.5 10373.0 10378.0 10384.5 10387.5 10389.0 10391.0 10395.0 10405.5 10407.0 10408.0 10412.0 10417.0 • 10035.5 10038.5 10049.5 10056.0 10058.5 10060.5 10062.0 10064.5 10067.0 10068.5 10073.5 10087.0 10092.5 10100.0 10104.5 10112.5 10118.5 10130.0 10145.0 10175.5 10183.0 10190.5 10198.5 10203.5 10209.5 10212.0 10224.5 10227.0 10230.0 10232.5 10236.5 10256.0 10265.5 10274.5 10295.5 10324.5 10327.5 10329.0 10330.5 10336.0 10339.5 10341.5 10344.5 10347.0 10348.5 10351.0 10354.5 10360.0 10367.0 10373.0 10377.0 10384.5 10387.5 10389.5 10391.0 10395.0 10406.5 10408.0 10409.0 10413.5 10417.5 • • • 10419.0 10419.5 10420.0 10420.5 10425.5 10427.0 10429.0 10431.5 10597.5 10600.0 MERGED DATA SOURCE PBU TOOL CODE BIT RUN NO MERGE TOP MERGE BASE MWD 1 73.5 4672.0 MWD 2 4672.0 7952.0 MWD 3 7952.0 9742.0 MWD 4 9742.0 9867.0 MWD 5 9867.0 10600.0 REMARKS: MERGED MAIN PASS. Data Format Specification Record Data Record Type ............. .....0 Data Specification Block Type .....0 Logging Direction ............ .....Down Optical log depth units...... .....Feet Data Reference Point ......... .....Undefined Frame Spacing ................ .....60 .lIN Max frames per record ........ .....Undefined Absent value ................. .....-999 Depth Units .................. ..... Datum Specification Block sub -type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 FONT MWD CNTS 4 1 68 4 2 NCNT MWD CNTS 4 1 68 8 3 RHOB MWD G/CM 4 1 68 12 4 DRHO MWD G/CM 4 1 68 16 5 RPD MWD OHMM 4 1 68 20 6 RPM MWD OHMM 4 1 68 24 7 RPS MWD OHMM 4 1 68 28 8 RPX MWD OHMM 4 1 68 32 9 FET MWD HOUR 4 1 68 36 10 GR MWD API 4 1 68 40 11 PEF MWD BARN 4 1 68 44 12 ROP MWD FT/H 4 1 68 48 13 NPHI MWD PU-S 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 75 10597.5 5336.25 21046 75 10597.5 FCNT MWD CNTS 626.61 6287.3 1711.1 5148 7930 10503.5 NCNT MWD CNTS 136396 227580 173633 5148 7930 10503.5 RHOB MWD G/CM 1.048 3.171 2.51356 5173 7930 10516 • • DRHO MWD G/CM -1.736 0.377 0.0561989 5173 7930 10516 RPD MWD OHMM 0.6 2000 17.4617 12396 4356.5 10554 RPM MWD OHMM 0.56 2000 6.38333 12396 4356.5 10554 RPS MWD OHMM 0.59 1377.39 5.3882 12396 4356.5 10554 RPX MWD OHMM 0.6 1689.9 5.54658 12396 4356.5 10554 FET MWD HOUR 0.13 110.81 8.0935 12396 4356.5 10554 GR MWD API 17.99 429.39 88.251 20974 75 10561.5 PEF MWD BARN 2.22 13.38 4.89337 5173 7930 10516 ROP MWD FT/H 0.02 551.35 107.497 20964 116 10597.5 NPHI MWD PU-S 6.25 76.55 28.145 5148 7930 10503.5 First Reading For Entire File..........75 Last Reading For Entire File...........10597.5 File Trailer Service name .............STSLIB.001 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.002 Physical EOF File Header Service name .............STSLIB.002 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.001 Comment Record FILE HEADER FILE NUMBER: 2 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 1 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH GR 73.5 4627.5 ROP 114.5 4672.0 ~ • LOG HEADER DATA DATE LOGGED: 07-NOV-05 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 66.37 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT) 4672.0 TOP LOG INTERVAL (FT) 114.0 BOTTOM LOG INTERVAL (FT) 4672.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: .0 MAXIMUM ANGLE: 49.0 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 175785 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) 16.000 DRILLER'S CASING DEPTH (FT) 114.0 BOREHOLE CONDITIONS MUD TYPE: NativejSpud Mud MUD DENSITY (LB/G) 9.30 MUD VISCOSITY (S) 130.0 MUD PH: 7.5 MUD CHLORIDES (PPM): 700 FLUID LOSS (C3): 8.5 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT) .000 .0 MUD AT MAX CIRCULATING TERMPERATURE: .000 79.0 MUD FILTRATE AT MT: .000 .0 MUD CAKE AT MT: .000 .0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type ..................0 Data Specification Block Type.....0 Logging Direction .................Down Optical log depth units...........Feet Data Reference Point ..............Undefined Frame Spacing .....................60 .1IN Max frames per record .............Undefined Absent value ......................-999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channe l • ~ DEPT FT 4 1 68 0 1 GR MWDO10 API 4 1 68 4 2 ROP MWDO10 FT/H 4 1 68 8 3 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 73.5 4672 2372.75 9198 73.5 4672 GR MWDO10 API 17.99 110.18 61.1978 9109 73.5 4627.5 ROP MWDO10 FT/H 1.57 419.83 126.994 9116 114.5 4672 First Reading For Entire Fil e..........73.5 Last Reading For Entire File ...........4672 File Trailer Service name ............. STSLIB.002 Service Sub Level Name... Version Number........... 1.0.0 Date of Generation....... 06/07/07 Maximum Physical Record.. 65535 File Type ................ LO Next File Name........... STSLIB.003 Physical EOF File Header Service name .............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type.......... ....LO Previous File Name.......STSLIB.002 Comment Record FILE HEADER FILE NUMBER: 3 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 2 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH FET 4355.0 7904.5 RPX 4355.0 7904.5 RPS 4355.0 7904.5 RPD 4355.0 7904.5 RPM 4355.0 7904.5 GR 4628.0 7912.5 ROP 4672.5 7952.0 • LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: MAXIMUM ANGLE: TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE DGR DUAL GAMMA RAY EWR4 ELECTROMAG. RESIS. 4 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN): DRILLER'S CASING DEPTH (FT): BOREHOLE CONDITIONS MUD TYPE: MUD DENSITY (LB/G): MUD VISCOSITY. (S): MUD PH: MUD CHLORIDES (PPM): FLUID LOSS (C3) RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): MUD AT MAX CIRCULATING TERMPERATURE: MUD FILTRATE AT MT: MUD CAKE AT MT: NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type ..................0 Data Specification Block Type.....0 Logging Direction .................Down Optical log depth units...........Feet Data Reference Point ..............Undefined Frame Spacing .....................60 .lIN Max frames per record .............Undefined Absent value ......................-999 Depth Units ....................... Datum Specification Block sub-type...0 • 15-NOV-05 Insite 66.37 Memory 7952.0 4672.0 7952.0 1.5 45.1 TOOL NUMBER 120558 67981 12.250 4372.0 Other 9.60 57.0 8.5 400 5.0 3.500 68.0 38.660 152.8 4.100 68.0 3.400 69.0 • • Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 RPD MWD020 OHMM 4 1 68 4 2 RPM MWD020 OHMM 4 1 68 8 3 RPS MWD020 OHMM 4 1 68 12 4 RPX MWD020 OHMM 4 1 68 16 5 FET MWD020 HOUR 4 1 68 20 6 GR MWD020 API 4 1 68 24 7 ROP MWD020 FT/H 4 1 68 28 S First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 4355 7952 6153.5 7195 4355 7952 RPD MWD020 OHMM 0.6 2000 6.04457 7100 4355 7904.5 RPM MWD020 OHMM 0.56 2000 6.28576 7100 4355 7904.5 RPS MWD020 OHMM 0.59 53.13 4.76231 7100 4355 7904.5 RPX MWD020 OHMM 0.6 1603.68 4.85981 7100 4355 7904.5 FET MWD020 HOUR 0.13 110.81 10.8307 7100 4355 7904.5 GR MWD020 API 32.67 408.3 116.773 6570 4628 7912.5 ROP MWD020 FT/H 0.02 405.51 104.115 6560 4672.5 7952 First Reading For Entire File..........4355 Last Reading For Entire File...........7952 File Trailer Service name .............STSLIB.003 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.004 Physical EOF File Header Service name .............STSLIB.004 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.003 • • Comment Record FILE HEADER FILE NUMBER: 4 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 3 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH RPX 7905.0 9689.5 FET 7905.0 9689.5 RPS 7905.0 9689.5 RPM 7905.0 9689.5 RPD 7905.0 9689.5 GR 7913.0 9697.5 PEF 7930.0 9663.0 FONT 7930.0 9650.0 DRHO 7930.0 9663.0 NPHI 7930.0 9650.0 RHOB 7930.0 9663.0 NCNT 7930.0 9650.0 ROP 7952.5 9742.0 LOG HEADER DATA DATE LOGGED: 21-NOV-05 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 66.37 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT): 9742.0 TOP LOG INTERVAL (FT) 7952.0 BOTTOM LOG INTERVAL (FT) 9742.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 1.6 MAXIMUM ANGLE: 11.3 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 175785 EWR4 ELECTROMAG. RESIS. 4 134758 SLD STABILIZED LITHO DEN 10718055 CTN COMP THERMAL NEUTRON 10718055 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) 8.500 DRILLER'S CASING DEPTH (FT) 7941.0 BOREHOLE CONDITIONS MUD TYPE: Other MUD DENSITY (LB/G) 10.50 MUD VISCOSITY (S): 55.0 MUD PH: 9.0 MUD CHLORIDES (PPM): 400 FLUID LOSS (C3) 3.4 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT) 1.900 80.0 MUD AT MAX CIRCULATING TERMPERATURE: 1.110 141.9 • • MUD FILTRATE AT MT: 1.700 MUD CAKE AT MT: 2.200 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: 80.0 80.0 Data Format Specification Record Data Record Type ....... ...... ..... 0 Data Specification Bloc k Type ..... 0 Logging Direction ...... ...... ..... Down Optical log depth units ...... ..... Feet Data Reference Point ... ...... ..... Undefined Frame Spacing .......... ...... ..... 60 .lIN Max frames per record .. ...... ..... Undefined Absent value ........... ...... ..... -999 Depth Units ............ ...... ..... Datum Specification Block sub -type ...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 FCNT MWD030 CNTS 4 1 68 4 2 NCNT MWD030 CNTS 4 1 68 8 3 RHOB MWD030 G/CM 4 1 68 12 4 DRHO MWD030 G/CM 4 1 68 16 5 RPD MWD030 OHMM 4 1 68 20 6 RPM MWD030 OHMM 4 1 68 24 7 RPS MWD030 OHMM 4 1 68 28 8 RPX MWD030 OHMM 4 1 68 32 9 FET MWD030 HOUR 4 1 68 36 10 GR MWD030 API 4 1 68 40 11 PEF MWD030 BARN 4 1 68 44 12 ROP MWD030 FT/H 4 1 68 48 13 NPHI MWD030 PU-S 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 7905 9742 8823.5 3675 7905 9742 FCNT MWD030 CNTS 626.61 3733.04 1411.18 3441 7930 9650 NCNT MWD030 CNTS 136396 225000 172654 3441 7930 9650 RHOB MWD030 G/CM 1.048 3.171 2.51465 3467 7930 9663 DRHO MWD030 G/CM -1.736 0.306 0.0692905 3467 7930 9663 RPD MWD030 OHMM 0.88 2000 44.7788 3570 7905 9689.5 RPM MWD030 OHMM 0.85 2000 4.5046 3570 7905 • • 9689.5 RPS MWD030 OHMM 0.9 1377.39 3.48928 3570 7905 9689.5 RPX MWD030 OHMM 0.95 1689.9 3.59991 3570 7905 9689.5 FET MWD030 HOUR 0.44 91.56 4.22224 3570 7905 9689.5 GR MWD030 API 44.53 399.66 112.554 3570 7913 9697.5 PEF MWD030 BARN 2.58 13.38 4.94767 3467 7930 9663 ROP MWD030 FT/H 3.2 551.35 85.9337 3580 7952.5 9742 NPHI MWD030 PU-S 11.5 76.55 31.5293 3441 7930 9650 First Reading For Entire File..........7905 Last Reading For Entire File...........9742 File Trailer Service name .............STSLIB.004 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.005 Physical EOF File Header Service name .............STSLIB.005 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.004 Comment Record FILE HEADER FILE NUMBER: 5 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 4 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH STOP DEPTH FCNT 9650.5 9775.0 NPHI 9650.5 9775.0 NCNT 9650.5 9775.0 PEF 9663.5 9788.0 DRHO 9663.5 9788.0 RHOB 9663.5 9788.0 RPS 9690.0 9815.0 RPM 9690.0 9815.0 • • RPX 9690.0 9815.0 RPD 9690.0 9815.0 FET 9690.0 9815.0 GR 9698.0 9823.5 ROP 9742.5 9867.0 LOG HEADER DATA DATE LOGGED: 22-NOV-05 SOFTWARE SURFACE SOFTWARE VERSION: Insite DOWNHOLE SOFTWARE VERSION: 66.37 DATA TYPE (MEMORY OR REAL-TIME): Memory TD DRILLER (FT) 9867.0 TOP LOG INTERVAL (FT) 9742.0 BOTTOM LOG INTERVAL (FT) 9867.0 BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG MINIMUM ANGLE: 11.3 MAXIMUM ANGLE: 12.8 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 132482 EWR4 ELECTROMAG. RESIS. 4 157645 SLD STABILIZED LITHO DEN 78609 CTN COMP THERMAL NEUTRON 1844674407370955 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) 8.500 DRILLER'S CASING DEPTH (FT) 7941.0 BOREHOLE CONDITIONS MUD TYPE: Other MUD DENSITY (LB/G): 10.80 MUD VISCOSITY (S) 54.0 MUD PH: 9.0 MUD CHLORIDES (PPM): 400 FLUID LOSS (C3) 3.0 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT) 2.000 72.0 MUD AT MAX CIRCULATING TERMPERATURE: .890 171.0 MUD FILTRATE AT MT: 1.700 64.0 MUD CAKE AT MT: 1.800 70.0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type ..................0 Data Specification Block Type.....0 Logging Direction .................Down • • Optical log depth units...........Feet Data Reference Point ..............Undefin ed Frame Spacing .. ...................60 .lIN Max frames per record .............Undefined Absent value ... ...................-999 Depth Units .... ................... Datum Specifica tion Block sub -type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 FCNT MWD040 CNTS 4 1 68 4 2 NCNT MWD040 CNTS 4 1 68 8 3 RHOB MWD040 G/CM 4 1 68 12 4 DRHO MWD040 G/CM 4 1 68 16 5 RPD MWD040 OHMM 4 1 68 20 6 RPM MWD040 OHMM 4 1 68 24 7 RPS MWD040 OHMM 4 1 68 28 8' RPX MWD040 OHMM 4 1 68 32 9 FET MWD040 HOUR 4 1 68 36 10 GR MWD040 API 4 1 68 40 11 PEF MWD040 BARN 4 1 68 44 12 ROP MWD040 FT/H 4 1 68 48 13 NPHI MWD040 PU-S 4 1 68 52 14 First. Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9650.5 9867 9758.75 434 9650.5 9867 FCNT MWD040 CNTS 1099.1 6287.3 2402.04 250 9650.5 9775 NCNT MWD040 CNTS 139675 227580 171473 250 9650.5 9775 RHOB MWD040 G/CM 2.452 2.913 2.58706 250 9663.5 9788 DRHO MWD040 G/CM -0.021. .0.377 0.123048 250 9663.5 9788 RPD MWD040 OHMM 2.49 190.89 32.4388 251 9690 9815 RPM MWD040 OHMM 2.5 301.99 44.2568 251 9690 9815 RPS MWD040 OHMM 2.65 449.5 51.3469 251 9690 9815 RPX MWD040 OHMM 2.79 608.15 54.0842 251 9690 9815 FET MWD040 HOUR 1.82 31.2 14.7518 251 9690 9815 GR MWD040 API 47.52 429.39 140.163 252 9698 9823.5 PEF MWD040 BARN 3.49 9.94 7.13008 250 9663.5 9788 ROP MWD040 FT/H 0.3 121.49 38.1167 250 9742.5 9867 NPHI MWD040 PU-S 6.25 36.37 22.3012 250 9650.5 9775 First Reading For Entire File..........9650.5 Last Reading For Entire File...........9867 File Trailer Service name .............STSLIB.005 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.006 Physical EOF File Header Service name .............STSLIB.006 Service Sub Level Name... Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Previous File Name.......STSLIB.005 Comment Record FILE HEADER FILE NUMBER: 6 RAW MWD Curves and log header data for each bit run in separate files. BIT RUN NUMBER: 5 DEPTH INCREMENT: .5000 FILE SUMMARY VENDOR TOOL CODE START DEPTH FCNT 9775.5 NCNT 9775.5 NPHI 9775.5 DRHO 9788.5 PEF 9788.5 RHOB 9788.5 RPM 9815.5 RPX 9815.5 RPS 9815.5 RPD 9815.5 FET 9815.5 GR 9824.0 ROP 9867.5 LOG HEADER DATA DATE LOGGED: SOFTWARE SURFACE SOFTWARE VERSION: DOWNHOLE SOFTWARE VERSION: DATA TYPE (MEMORY OR REAL-TIME): TD DRILLER (FT): TOP LOG INTERVAL (FT): BOTTOM LOG INTERVAL (FT): BIT ROTATING SPEED (RPM): HOLE INCLINATION (DEG STOP DEPTH 10506.0 10506.0 10506.0 10518.5 10518.5 10518.5 10556.5 10556.5 10556.5 10556.5 10556.5 10564.0 10600.0 24-NOV'05 Insite 66.37 Memory 10600.0 9867.0 10600.0 • • MINIMUM ANGLE: 13.9 MAXIMUM ANGLE: 16.9 TOOL STRING (TOP TO BOTTOM) VENDOR TOOL CODE TOOL TYPE TOOL NUMBER DGR DUAL GAMMA RAY 134745 EWR4 ELECTROMAG. RESIS. 4 145654 CTN COMP THERMAL NEUTRON 1844674407370955 SLD STABILIZED LITHO DEN 10718055 BOREHOLE AND CASING DATA OPEN HOLE BIT SIZE (IN) 8.500 DRILLER'S CASING DEPTH (FT) 7941.0 BOREHOLE CONDITIONS MUD TYPE: Other MUD DENSITY (LB/G) 10.90 MUD VISCOSITY (S) 54.0 MUD PH: 9.0 MUD CHLORIDES (PPM): 400 FLUID LOSS (C3) 3.0 RESISTIVITY (OHMM) AT TEMPERATURE (DEGF) MUD AT MEASURED TEMPERATURE (MT): 1.900 70.0 MUD AT MAX CIRCULATING TERMPERATURE: .740 191.3 MUD FILTRATE AT MT: 2.400 72.0 MUD CAKE AT MT: 1.900 72.0 NEUTRON TOOL MATRIX: MATRIX DENSITY: HOLE CORRECTION (IN): TOOL STANDOFF (IN): EWR FREQUENCY (HZ): REMARKS: Data Format Specification Record Data Record Type ..................0 Data Specification Block Type.....0 Logging Direction .................Down Optical log depth units...........Feet Data Reference Point ..............Undefined Frame Spacing .....................60 .lIN Max frames per record .............Undefined Absent value ......................-999 Depth Units ....................... Datum Specification Block sub-type...0 Name Service Order Units Size Nsam Rep Code Offset Channel DEPT FT 4 1 68 0 1 FONT MWD050 CNTS 4 1 68 4 2 NCNT MWD050 CNTS 4 1 68 8 3 RHOB MWD050 G/CM 4 1 68 12 4 DRHO MWD050 G/CM 4 1 68 16 5 RPD MWD050 OHMM 4 1 68 20 6 RPM MWD050 OHMM 4 1 68 24 7 RPS MWD050 OHMM 4 1 68 28 8 RPX MWD050 OHMM 4 1 68 32 9 • FET MWD050 HOUR 4 1 68 36 10 GR MWD050 API 4 1 68 40 11 PEF MWD050 BARN 4 1 68 44 12 ROP MWD050 FT/H 4 1 68 48 13 NPHI MWD050 PU-S 4 1 68 52 14 First Last Name Service Unit Min Max Mean Nsam Reading Reading DEPT FT 9775.5 10600 10187.8 1650 9775.5 10600 FONT MWD050 CNTS 1206.88 6077.16 2309.5 1462 9775.5 10506 NCNT MWD050 CNTS 142192 224939 176481 1462 9775.5 10506 RHOB MWD050 G/CM 2.268 2.938 2.49903 1461 9788.5 10518.5 DRHO MWD050 G/CM -0.065 0.115 0.0130541 1461 9788.5 10518.5 RPD MWD050 OHMM 1.15 25.86 5.13318 1483 9815.5 10556.5 RPM MWD050 OHMM 0.99 29.58 4.971 1483 9815.5 10556.5 RPS MWD050 OHMM 1.05 32.55 5.13151 1483 9815.5 10556.5 RPX MWD050 OHMM 1.08 36.51 5.36375 1483 9815.5 10556.5 FET MWD050 HOUR 0.5 33.88 3.18753 1483 9815.5 10556.5 GR MWD050 API 19.16 299.09 60.511 1481 9824 10564 PEF MWD050 BARN 2.22 7.66 4.37244 1461 9788.5 10518.5 ROP MWD050 FT/H 6.88 146.95 65.5415 1466 9867.5 10600 NPHI MWD050 PU-S 7.17 32.98 21.0981 1462 9775.5 10506 First Reading For Entire File.....:....9775.5 Last Reading For Entire File...........10600 File Trailer Service name .............STSLIB.006 Service Sub Level Name.., Version Number...........1.0.0 Date of Generation.......06/07/07 Maximum Physical Record..65535 File Type ................LO Next File Name...........STSLIB.007 Physical EOF Tape Trailer Service name .............LISTPE • Date .....................06/07/07 Origin.... ..............STS Tape Name ................UNKNOWN Continuation Number......01 Next Tape Name...........UNKNOWN Comments .................STS LIS Technical Services Reel Trailer Service name .............LISTPE Date .....................06/07/07 Origin ...................ST5 Reel Name ................UNKNOWN Continuation Number......01 Next Reel Name...........UNKNOWN Comments .................STS LIS Technical Services Physical EOF Physical EOF • Writing Library Writing Library Scientific Scientific End Of LIS File
