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Home My WebLink About2019-05-09_319-239STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 MAY 0 9 2019 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑J Repair Well ❑ Operations shutdown El Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ 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: ConocoPhillips Exploratory ❑ Development Stratigraphic ❑ Service ❑ 219-006 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20799-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CRU CD5-24 Will planned perforations require a spacing exception? Yes ❑ No ❑ 9. Property Designation (Lease Number): 10. Field/Pool(s): ASRC-NPR4, ASRC-NPR2, ASRC-NPR5, ASRC-AA092344 Colville River Unit, Alpine Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 27,128' 7,716' 27,070' 7,715' 7,500 Casing Length Size MD TVD Burst Collapse Structural Conductor 78' 20" 115' 115, Surface 2197' 10 3/4" 2,334' 2,174' Intermediate 13,848' 7 5/8" 13,882' 7,640' Production Liner 7,999' 41/2" 21,699' 7,858' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 4 1/2" i£ 3 1/2" L80 est 13,700' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker Premier Packer, Halliburton TNT Packer no SSSV est 13,052' & 13,622' MD no SSSV 12. Attachments: Proposal Summary ❑ Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑J Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 5/27/2019 OIL WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Adam Klem, 907-263-4529 Email adam.kiem@ConocgPh*ilFias.com Printed Name Adamem Title Completions Engineer Signature Phone 907-263-4529 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: n I _ �� l!/, Location Clearance Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ ❑ Other: Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No ❑ Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and Form 10403 Revised 11/2015 Approved applicatiorov firGTtq ;kL date of approval. Attachments in Duplicate CD5 - 24 Alpine A/C Dual Lateral Producer Proposed Schematic 20" 94# H-40 Welded Conductor to 115' MD 10-3/4" 45.5# L-80 HYD 563 x BTC Surface Casing at 2,253' MD 4-'/2' x 1" GLM 4-1/2" 12.6# L-80 TSBIue 4-'/" x 1" GLM 7 5/8" 29.7# L-80 Hyd 563 x BTC Intermediate Casing at 13,898' MD 4-%" x 1" GLM Upper Completion: 1) 4 V-12.6# TSBIue tubing 2) Shallow nipple profile 3.813" ID 3) 4-%" x 1" Camco KBMG GLM (xx°) w/DCK2 pinned for 2500 psi casing to tbg shear 4) Premier Packer 5) X Nipple profile, 2.813" 6) TNT Packer 7) X Nipple profile, 2.813" Lower Completion: 8) Plop and drop liner in C sand - no junction -4.5" 12.6# L-80 w/ perf pups 9) ZXP liner top packer & Flexlock Liner Hanger XO 5" Hydril 521 Box X 4-1/" H563 pin -4.5" Hydril563 12.6# L-80 w/ Frac Ports C sand Lateral 6 3/4" Hole TD 13,332'- 27,266' MD 4'/z" 12.6# L-80 TXP Linerw/ pert pups 0 0 0 0 0 0 0 0 Premier Packer at 13,000 MD HP Sliding sleeve for Selectivity 13,041' MD 3-1/2" 9.3# TN110SS TNT Production Packer at 13,665' MD ZXP liner top packer (whipstock base) at 13,748' MD 4-'/2" 12.6# L-80 Hyd563 Liner w/ frac ports to-26,650' 0 0 0 0 0 0 00P ------------------------------------------------------------------------------- A sand Lateral 6 3/4" Hole TD 13,898' - 35,630' MD Section 1 - Affidavit 10 AAC 25.283 (a)(1) Exhibit 1 is an affidavit stating that the owners, landowners, surface owners and operators within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283(a)(1). TO THE ALASKA OIL AND GAS CONSERVATION COMMISSION Before the Commissioners of the ) Alaska Oil and Gas Conservation ) Commission in the Matter of the ) AFFIDAVIT OF Jason E. Lyons Request of ConocoPhillips Alaska, Inc. for ) Hydraulic fracturing for the CD5-24 Well ) under the Provisions ) of 20 AAC 25.280 ) STATE OF ALASKA ) THIRD JUDICIAL DISTRICT ) herein. Jason E. Lyons, being first duly sworn, upon oath, deposes and states as follows: 1. My name is Jason E. Lyons. I am over 19 years old and have personal knowledge of the matters set forth 2. 1 am Staff Landman for the well operator, ConocoPhillips Alaska, Inc. ("CPAI") 3. Pursuant to 20 AAC 25.283 (1) CPAI prepared the attached Notice of Operations ("Notice"). 4. On May 8, 2019, CPAI sent a copy of the Notice by certified mail to the last known address of all other owners, landowners, surface owners, and operators of record within a one-half mile radius of the current proposed well trajectory. Subscribed and sworn to this 8th day of May, 2019. 6to .Lyons STATE OF ALASKA ) THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 8th day of May, 2019, by Jason E. Lyons. otary Public, State �Alask�� My Commission Expires: STATE OF ALASKD NOTARY PUBLICREBECCA SWENSEMy Canmission Expires Ir,QCe�Pii I ii1pS Alaska May 8, 2019 To: Operator and Owners (shown on Exhibit 2) Jason Lyons Staff Landman Land & Business Development ConocoPhillips Company 700 G Street Anchorage, AK 99501 Office: 907-265-6002 Fax:907-263-4966 jason.lyons@cop.com VIA CERTIFIED MAIL Re: Notice of Operations pursuant to 20 AAC 25.283 (1) for CD5-24 Well AA-92344 (ASRC), ASRC-NPR2, and ASRC-NPR4 Colville River Unit, Alaska CPAI Contract No. 203488 Dear Operator and Owners: ConocoPhillips Alaska, Inc. ("CPAI") as Operator and on behalf of the Colville River Unit ("CRU") working interest owners, hereby notifies you that it intends to submit an Application for Sundry Approvals for stimulation by hydraulic fracturing pursuant to the provisions of 20 AAC 25.280 ("Application") for the CD5-24 Well (the "Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about May 9, 2019. This Notice is being provided pursuant to subsection of 20 AAC 25.283. The Well is currently planned to be drilled as a directional horizontal well on leases, AA-92344 (ASRC), ASRC-NPR2, and ASRC-NPR4 as depicted on Exhibit 1 and has locations as follows: Location FNL I FEL Township Range Section Meridian Surface 426' 2881' T11 N R4E 18 Umiat Top Open Interval 4023' 1782' T11 N R4E 20 Umiat Bottomhole 2930' 4624' T1ON R3E 3 Umiat Exhibit 1 shows the location of the Well and the lands that are within a one-half mile radius of the current proposed trajectory of the Well, including the reservoir section ("Notification Area"). Exhibit 2 is a list of the names and addresses of all owners, landowners and operators of record of all properties within the Notification Area. Upon your request, CPAI will provide a complete copy of the Application. If you require any additional information, please contact the undersigned. Sincerely, son Lyons Staff Landman Attachments: Exhibits 1 & 2 Exhibit 1 N ASRC-NPR3 o� ASRC-NPR2 ADL387207 o r qa �- CD�21 �1r 4A 'AA092347 {i ASRC-NPR4 ppso ADL387208 11 ADL380075 NPN 19 j `'o O bap 9 ADL380077 ASRC-AA092344 ........ . I j ADL387209 s � 1 � n w _— w O' •�O�i ,� O DL388902 \\\ cp ps AA081817 v I 9 ASRC-NPR2 ADL38890 >c ASRG-NPR4 d F AA092675 — ADL38 Alps 98 PA ADL390337 Frac Points Well Trajectory Open Interval j Wells within Trajectory Radius ASRC- C®n®coPhillips 4_31 Half Mile Frac Port Radius Alaska Half Mile Well Trajectory Radius :_Colville River Unit N _�Nrd ....................... CD5-24 National Petroleum Reserve -Alaska Lease Plat CPAI Lease 0 0.2 0.4 0.6 0.8 1 Miles 4/29/2019 Exhibit 2 List of the names and addresses of all owners, landowners and operators of all properties within the Notification Area. Operator & Owner: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO 1226 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attn: Misty Alexa, NS Development Manager Owner (Non -Operator): None Landowners: Arctic Slope Regional Corporation 3900 C Street, Suite 801 Anchorage, Alaska 99503-5963 Attn: Teresa Imm, Executive VP, Regional and Resource Development Surface Owner: Kuukpik Corporation P.O. Box 89187 Nuiqsut, AK 99789-0187 Attn: Joe Nukapigak, President Section 2 — Plat 20 AAC 25.283 (a)(2) Plat 1: Wells within .5 miles pp'srpa � o O' O�' p`Fi ij. O ASRC-NPR3 ' !� �O�.v o oU $ Np ASRC-NPR2 ADL387207 N CO5,21 p AA092347 ,ASRC-NPR4 po ADL387208 pp� ' ADL380075 0 r' b� 1817 1� Pp ADL380077 ASRC-AA082344 2i t y\ ADL387209 i ...... .. ............... ..... 383902 �p pp`r AA081817 1a i 9 ASRC-NPR2 ADL388905, xT ASRC-NPR4 w - F ADL38 AA092675 Alpine PA _.. --- -- i ADL390337 --------------- Frac Points Well Trajectory " " Open Interval j Wells within Trajectory Radius ASIRC-1 'b Half Mile Frac Port Radius i ConocoPhillips Alaska Half Mile Well Trajectory Radius : Coivilie River _Un_it_ _ N National Petroleum Reserve -Kaska C.�.5�24 Lease Plat CPAI Lease 0 0.2 0.4 0.6 0.8 1 Miles 4/29/2019 :Ge.. sA,..�.t.:e:;r' t a:Fr: f7-T—N:! -, Table 1: Wells within o5 miles Well Name API Status well Type CD5-01 501032073600 ACTIVE INJ CD5-02 501032073700 PA SVC CD5-02A 501032073701 ACTIVE INJ CD5-03 501032071800 ACTIVE PROD CD5-04 501032071100 ACTIVE PROD CD5-05 501032071200 ACTIVE PROD CD5-06 501032074400 ACTIVE INJ CD5-061-1 501032074460 ACTIVE INJ CD5-07 501032073400 ACTIVE INJ CD5-08 501032074100 ACTIVE INJ CD5-09 501032072300 ACTIVE PROD CD5-10 501032072400 ACTIVE PROD CD5-11 501032072600 ACTIVE PROD CD5-12 501032074200 ACTIVE INJ CD5-17 501032075400 ACTIVE INJ CD5-171-1 501032075460 ACTIVE INJ CD5-18 501032075000 ACTIVE PROD CD5-181-1 501032075060 ACTIVE PROD CD5-19 501032076000 ACTIVE INJ CD5-191-1 501032076060 ACTIVE INJ CD5-20 501032075200 ACTIVE PROD CD5-201-1 501032075260 ACTIVE PROD CD5-21 501032073800 SUSP PROD CD5-22 501032075900 ACTIVE PROD CD5-23 501032076100 ACTIVE INJ CD5-25 501032076500 ACTIVE PROD CD5-251-1 501032076560 ACTIVE PROD CD5-313 501032071400 ACTIVE PROD CD5-313PB1 501032071470 PA EXPEND CD5-314 501032070700 PA PROD CD5-314X 501032075500 ACTIVE PROD CD5-315 501032071600 ACTIVE INJ CD5-315PB1 501032071670 PA EXPEND CD5-316 501032075600 ACTIVE INJ CD5-316PB1 501032075670 PA EXPEND CD5-99 501032074800 PA PROD CD5-99A 501032074801 ACTIVE PROD CD5-99AL1 501032074861 INACTV PROD SECTION 3 — FRESHWATER AQUIFERS 20 AAC 25.283(a)(3) There are no freshwater aquifers or underground sources of drinking water within a one-half mile radius of the current or proposed wellbore trajectory. See Conclusion number 3 of the Area Injection Order AIO 018.000- Colville River Field, Alpine Oil Pool: Enhanced Recovery Project, which states "No underground sources of drinking water ("USDWs") exist beneath the permafrost in the Colville River Unit area." 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 of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. SECTION 5 — DETAILED CEMENTING AND CASING INFORMATION 20 AAC 25.283(a)(5) All casing is cemented in accordance with 20 AAC 25.52(b) and tested in accordance with 20 AAC 25.030 (g) when completed. See Wellbore schematic for casing details. SECTION 6 — ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283(a)(6) Casing & Cement Assessments: 10 &'/" casing cement pump report on 2/19/2019 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 11 ppg LiteCrete lead and 15.8ppg class G cement, displaced with 10ppg mud. Full returns were seen throughout the job. The plug bumped at 500 psi and the floats were checked and they held. The 7 & 5/8" casing cement report on 3/5/2019 shows that the job was pumped as designed, indicating competent cementing operations. The first stage cement job was pumped with 13ppg class G cement lead and 15.8ppg Class G tail. Full returns were seen throughout the job. The plug bumped at 1100 psi, and the floats were checked and they held. The second stage cement job was pumped with 11.2ppg cement. Full returns were seen throughout the job. The plug bumped at 1900 psi, and the stage tool was checked and it was closed. Summary All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, ConocoPhillips has determined that this well can be successfully fractured within its design limits. SECTION 7 — PRESSURE TEST INFORMATION AND PLANS TO PRESSURE -TEST CASINGS AND TUBINGS INSTALLED IN THE WELL 20 AAC 25.283(a)(7) On 2/22/2019 the 10-3/4" casing was pressure tested to 3,500 psi for 30 mins. On 3/8/2019 the 7-5/8" casing was pressure tested to 3,500 psi for 30 mins. The 3.5" and 4.5" tubing will be pressure tested to 5,200 psi prior to frac'ing. The 7-5/8" casing will be pressure tested to 3,850 psi prior to frac'ing. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 6,000 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7 5/8" Annulus pressure test 3,850 4.5" & 3 1 /2" Tubing pressure Test 5,175 Nitrogen PRV 7,600 Highest pump trip 7,400 SECTION 8 — PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Weight Grade API Burst API Collapse 10 & %11 45.5 L-80 2,090 psi 3,580 psi 7 & 5/8" 29.7 L-80 6,890 psi 4,790 psi 4.5" 12.6 L-80 8,430 psi 7,500 psi 3.5" 9.3 TN-110 13,970 psi 12,620 psi Table 2: Wellbore pressure ratings Stimulation Surface Rig -Up W 9 Rand ? Tatilr Twe Tank pa�� t X,k ChN Qz� �_ v E • Minimum pressure rating on all surface treating lines 10,000 psi • Main treating line PRV is set to 95% of max treating pressure • IA parallel PRV set to 3500 psi • Frac pump trip pressure setting are staggered and set below main treating line PRV zr. Y"� '�EY7�b`dpftlnC xmca �u , ir;. scraps.. e T ....... a rw. Fcu� m rt-Mi+.w w• a c2b .ti..1b F_ -dLAU ,<i µ SECTION 9 — DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283(a)(9) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that: The Alpine A interval is approximately 30' TVD thick at the heel of the lateral and generally maintaining the same thickness to the toe. The Alpine A sandstone is very fine grained and quartz rich, with a coarsening upward log profile. Top Alpine A is estimated to be at 14,337' MD/-7,599' TVDSS. The estimated fracture gradient for the Alpine A sandstone is 12.5 ppg. The overlying confining zone consists of greater than 400' TVD of Miluveach, Kalubik and HRZ mudstones. The estimated fracture gradient for the Miluveach is 15 ppg and for the Kalubik and the HRZ is 16 ppg. Top HRZ was encountered at 12,188'MD/-7,016 TVDSS. The underlying confining zone consists of approximately 1800' TVD of Kingak shales. The estimated fracture gradient for the Kingak interval ranges from 15-18 ppg. Fracture gradient increases down section. The top of the Kingak interval ranges from --7,630' TVDSS at the heel to --7,760' TVDSS at the toe of the well (no MD as the Kingak interval was not penetrated in the CD5-24 wellbore). SECTION 10 — LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(a)(10) The plat shows the location and orientation of each well that transects the confining zone. ConocoPhillips has formed the opinion, based on following assessments for each well and seismic, well, and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. Casing & Cement assessments for all wells that transect the confining zone: CD5-313: The 7-5/8" casing cement pump report on 7/25/2015. Full returns were not seen throughout the job. The cement job was pumped with 15.8 ppg Class G cement, displaced with 11.1 ppg LSND. The plug bumped at 1,140 psi and the floats held. CD5-313PI31: On 7/15/2015 CD5-313PB1 was plugged and abandoned as per state regulations. CD5-19 and CD5-19L1: The 7-5/8" casing cement pump report on 11/27/2017. Full returns seen throughout the job. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.3 ppg WBM. The plug bumped at 1,0000 psi and the floats held. CD5-25 and CD5-25L1: The 7-5/8" casing cement pump report on 7/25/2015. Full returns were not seen throughout the job. The cement job was pumped with 12.2ppg lead cement and 15.8 ppg Class G tail cement, displaced with 10.6 ppg WBM. The plug bumped at 1,000 psi and the floats held. > D � 0 � � Q � 0 m 75 E Ln Q � u � U- � - - \ \\} � \\/ \/} _ § - k� - �| }$ - \{ c4 o ;;` |2 Nx § \ f 2 E $ � _ ({ § ca } } o \ EE - - \ \ § } § § ( - - - - ;i } § } ( ) § {\\ }\ £2 k § ( § 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) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that three faults or fracture systems transect the Alpine A formation or enter the confining zone within one half mile radius of the wellbore trajectory for CD5-24. The first fault was interpreted from seismic data prior to drilling and confirmed with log data while drilling (fault throw of 22'). The second fault was intersected in the wellbore at 23,370' MD (fault throw of 5') but was no mappable on seismic. The third fault was mapped with seismic data but was not intersected with the CD5-24 wellbore, and therefore could not be confirmed. Any faults that are within the half mile radius of the wellbore do not extend up through the confining interval and fracture gradients within the top seal intervals would not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. CPAI has formed the opinion, based on seismic, well and other subsurface information currently available that the apparent faults will not interfere with containment. Based on our knowledge of the principle stress direction in the Alpine A formation, along with the well path, all of the fractures will be longitudinal, running parallel to the wellbore. Because of this the fractures will only intersect faults that intersect the wellbore. We do not expect any of our hydraulic fractures to intersect faults seen in this wellbore. If there are indications that a fracture has intersected a fault during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. Vertical Well Depth Depth Loss Name MD (ft) TVDSS (ft) Displacement (bbls/hr) (ft) CD5-24 17,708 -7,634 22' None CD5-24 1 23,370' -7,706 5' None Plat 2: CD5-24 Fault Analysis ASRC-NPR3 ASRC-NPR2 ADL387207 CD l w AIL 7888 �+ � ASRC-NPR4 AA092347 ADL380075 " i j ADL387208 i 181T AIVP '�Alvp ��ks ASRC-NPR2 ADL380077 ASRC-AA092344 k ADL387209 S ;w ......... . ' DL388902 y AA081817 -, ADL388905 ASRC-NPR4 ADL•38 AA092675 "" t i ire PA ADL390337 Frac Points _ -_,__--- Well Trajectory Open Interval Wells within Frac Zone Radius j Half Mile Frac Port Radius ASRC- Q Half Mile Well Trajectory Radius i ConOC®Pi11lllIpS Alaska Faults within Frac Point Radius : Colville River Unit - _ _ N - r - - CD5-24 National Petroleum Reserve -Alaska Fault Analysis CPAI Lease 0 0.2 0.4 0.6 0.8 1 Miles 4/29/2019 arcu_. _r ..,. a: uCRU NEWRld MTT,Y A» dS 2 ,. r..�. r. SECTION 12 — PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) CD5-24 was completed in 2019 as a horizontal producer in the Alpine A and C formation. The well was completed with 4.5" tubing, with 3.5" tubing isolating the C lateral. In the A sand is a 4.5" liner with ball actuated sliding sleeves. After the 1 st stage we will shift a sleeve to close off that section of the lateral. We will then pump the 2nd stage and drop a ball (progressively getting larger) after each remaining stage, these balls will provide isolation from the previous stage and allow us to move from the toe of the well towards the heel. Proposed Procedure: Halliburton Pumping Services: (Alpine A Frac) 1. Conduct Safety Meeting and Identify Hazards. Inspect Wellhead and Pad Condition to identify any pre existing conditions. 2. Ensure all Pre-frac Well work has been completed and confirm the tubing and annulus are filled with a freeze protect fluid to 2,000' TVD. 3. Ensure the 10-403 Sundry has been reviewed and approved by the AOGCC. 4. MIRU 25 clean insulated Frac tanks, with a berm surrounding the tanks that can hold a single tank volume plus 10%. Load tanks with 1001 F seawater (approx. 11,200 are required for the treatment with breakdown, maximum pad, and 450 bbls usable volume per tank). 5. MIRU HES Frac Equipment. 6. PT Surface lines to 9,500 psi using a Pressure test fluid. 7. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 6. Bring up pumps and increase annulus pressure from 2,500 psi to 3,500 psi as the tubing pressures up. 9. Pump the 100 bbl breakdown stage (25# Hybor G) according to the attached excel HES pump schedule. Bring pumps up to maximum rate of 35 BPM as quick as possible, pressure permitting. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. 10. Perform a hard shut down, Obtain ISIP and fluid efficiency estimates. 11. Pump the Frac job by following attached HES schedule @ 35bpm with a maximum expected treating pressure of 6,000 psi. 12. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 13. Well is ready for Post Frac well prep for flowback (Slickline and possibly CTU). 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Harrison Be AptNunrb0r: 6010320779 NORTH SLOPE Operato Name; EBUS i0.all6"or wNamben C04695 Longitude: .150.99 Lattuduu 70.29 long&.1"ce0-, NAO27 Imtiaa€ederad: n Gil P oo ch-HYa�vD)� True VetlkelIIepik (TV: 4 300 'ro6a1'WaterV.1cosr 492,584 Hydraulic Fracturing Fluid composition: Clsttll t( Maximum Abstract Maximum Ingredient lgredfent trade<Nar" supow, Purpose IlgtediiIts Sere/ce Concentration In Additive Congeatralontn In 0r¢d Comments Company FHSt Name LastNarnas Ends" Phone Number fcm- J,% by ma r* HF Fluid (%by lips i mass. Sea Water Operator Base Flub Water 7732-18-5 9E.008 36768 1038470 Dens=8.540 MICROBIOCIDE IC Hellibudon Braude U.1ad Bebw bated Bebw 0 NA CAT-3 ACTIVATOR Halliburton Activator Listed! Balk.b w Listed Bew 0 NA CL-22. UC Halliburlon Croaalinker Listed Below Listed Below 0 NA C CROSSLINKER Halliburbn Croselinker Listed Below Listed Below 0 NA LOSURF-300D Hallburfon Non-mnlo Surfactant L ated Below Listed Below 0 NA MO-67 H.Tburton H Control Addxve Listed Bebw Listed Below 0 NA OPTIFLO-111 RELAYED RELEASE Hellburton Breaker Laced Below Listed Below 0 NA BREAKER -SP BREAKER Halliburton Breaker Listed Below Listed Set.. 0 NA G 36 GELLING Halhbudon Gelling Agent Listed Bebw Listed Below A AGEN AGENT 0 NA LVT-200 Pan,- Freeze PnoW Listed Bebw Listed Below 0 NA Wanli Wanii 20140 Proppant Addd- Listed Below Us. Below 0 NA I om1"" Ingredients Listed Above Listed Above I2.4Th (benzene 964M 1.008 0. 0o07a8 37 2-Bromo-2ndro-1, ned'lol 52-51-7 1J0. aJe 001499 74 Denise Tuck, Halllburion, 3000 Dan- T..@ Acrylate polymer Proprietary i.008 0. 001.u08 50 N. Sam Houston Pkwy E, Houston, Halliburton Denise Tuck Hallturbnw 287 A77-a226 TX 77032.281- an 871-6226 Ammonium ulfate T727-54O 100.008 0. 009908 492 Oenise.Tuck® Borate salts Propietary a0. ale O. JS9%64 2g88 Halhburtan Denise Tuck Halliburton.co 2814171-6= Camndum 1302-74 65. 008 9. 153938 456001 Crystalline silica, cruartz 1480&60-7 30.008 -003('-78 153 Denise.Tuck@ Curet-ylicrewn Proprietary 30.008 0.002978 148 Hallibunon Denise Tuck Halliburton.m 281371.6226 oenise.Tuck® EDTA/Copparchalate Proprietary 30.- 0.0)9ae8 3907 Haiburtan Denise Tuck Halllburton.cu 281d71.6226 Ethanol 64-17-8 60.008F4-2 8 M19 Guar um 9000-304 100.•?D88 Hea matic troleum na Na 64742-9 30.00948 1110 H drotreated Distillate, G ht 6474247A 1Jo.004e 13660 Mullde lW2-93-0 45.0088 315000 Na hthalene 91-203 .3. 0088 155 Oenise.Tuck@ Oxylxted phenolic resin Proprietary 30.0088 1480 Hallibunon Denise Tuck Halllburbn.co ZrZr141226 Poly(oxy-1,2ethanedryl)alpha-(4- nonylpheny)-ga-hydroxy-, 12706737-0 -.0088 185 branched Potassium formate 590-294 60.00& O.O5976% 2968 Potassium h droxid, 13101 3 5.008 O. Jo2318 115 Potassium metaborate 13709-94-9 60.0J8 J. J27148 1378 Sodlumw meth icellubse 900432-0 LOOS 0. 2008 0L 50 Sod um chlodtle 7647-145 4. 008 3.390838 lsa360 Sod mllate 283632-0 ♦.iO3 0.•1J100* 50 Sotliumh droxitle 1310-73-2 - o. 024018 it92 Sodium rsulfate 7775-27-1 lo0mJJ8 14M SotliYm sUltate 7757412-0 -ce J. JJOJ39 2 Water 7732-1&5 £Ov^.008 0.399928 19853 Total Water Volume sources may includefresh water, produced water, and/or recycled water _ "Information is based on the maximum potential for concentration and thus the total may he over 100% Nate: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. All component Information listed was obtained from the supplier's Material Safety Data Sheets (MSDS). As such, me Operator is not responsible for inaccurate and/or incomplete information. Any questions regarding the content of the MSDS should be directed to the supplier who provided itThe Occupational Safety and Health Administration's (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "propnetay','trade secret", and "confidential business information" and the criteria For how this information is re rted on an MSDS is suh'ect to 29 CFR 1910.1200 and A endix D. � c 00 00 00 00 00 00 M 00 M 00 M 00 M 00 +� LL' N N N N N PV N N lV N Q � O O O O O O O O O O t v'— 0 0 0 0 O O ri r-I .� V f0 LL �F - a) a- 0 0 coo 0 0 0 0 0 0 0 0 �o 0 LO 0 t-D 0 (D Q rla L ) Ln LO Ln Lli Lf) Ct C} 0 O O I� m N rN-I � M NO N LO LI) � LD � r-I Ln ri LO l.D ko H R:T 00 r- lD e-I 00 Ln N lD lD 00 I-� N d lD al N R:t !? N N O Ql 0 r0 r^-I ri e I r�i r�I F� a, 0 0 0 0 0 0 0 0 0 0 N 0 0 0 0 0 O 0 O 0 O V) -0 o C] 0 n d n o d Ol o Ql Ql o a1 O au Nr-I N M I'* Ln lD I� 0p M O W O 4- N 5 3 CO L% L C m y m 3 of 3 4- U ca hC0 (0 vi L O C v O m O a) CLO ir+ L C U L- ai 6cu � p Q. O L a) cu 4— Ln C -0 m C .Q L � C CO C aj L, do M O 3 a.' 0 LM cu to " C Qu to 00 0 O E N (U .(U � v a O O 0. L Q 3 W 0 N E Ln co O C O 4- Ln +� 3 3 p V � -0 O - o v 2 U C O aJ aL) E w w w to z i V) O t O aJ 0 L O L CO O Q C i 3 L H aJ C m E SECTION 13 — POST -FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.233(a)(13) Flowback will be initiated through PTS until the fluids clean up at which time it will be turned over to production. (Initial flowback fluids to be taken to CD1-01 disposal well until they are clean enough for production.)