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Home My WebLink About2019-08-23_319-389r STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1. Type of Request.- Abandon ❑ Plug Perforations ❑ Fracture stimulate P] Repair Well F-1 Operations shutdown Suspend ❑ Perforate ❑ Other Stimulate F] Pull Tubing F] Change Approved Program[-] 2. Operator Name: Plug for Redrill El Perforate New Pool F-1 Re-enter Susp Well F] Alter Casing El Other: ❑ 4. Current Well Class: 5. Permit to Drill Number: ConocoPhillips Exploratory E] Development 0 216-161 3. Address: Stratigraphic ❑ Service ❑ & API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20752-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? I CRU CD5-20 Will planned perforations require a spacing exception? Yes ❑ No 9. Property Designation (Lease Number).- 10. Field/Pool(s): ASRC NPR4, ASRC NPR2, ASRC-AA092344 I 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): 24,119' 7,649' 24,099' 7,648' 7,500 Casing Length Size MD TVD Burst Collapse Structural Conductor 79' 20" 115' 115' Surface 2,354' 10-3/4" 2,357' 2,183' Intermediate 15,215' 7-5/811 12,290' 7,445' Production Liner 12,8651 4-1/211 24,099' 7,648' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade.- Tubing MD (ft): See Attached Schematic See Attached Schematic 31/211 L80 14,119' Planned Depth Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Halliburton TNT Production Pacts "I 1,295"MD and 12,059'MD planned depth 12. Attachments: Proposal Summary El Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program L] BOP Sketch ❑ Exploratory 0 Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for 9/8/2019 15. Well Status after proposed work: Commencing Operations: OIL 7 WINJ F-] WDSPL F-1 Suspended ❑ 16. Verbal Approval: Date: GAS F1 WAG [I GSTOR [I SPLUG F1 Commission Representative.- GINJ F-1 Op Shutdown F-1 Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name.* Adam Klem Contact Name: Adam Klem Authorized Title: Com ' p!etion Engineer Contact Email: adam. klem(d)-conocophil lips. com M' Contact Phone: 907-263-4529 Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number- 3 Plug Integrity ❑ BOP Test F] Mechanical Integrity Test ❑ Location Clearance F] Other: Post Initial Injection MIT Req'd? Yes F1 No ❑ Spacing Exception Required? Yes ❑ No F-] Subsequent Form Required. - APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 4/2017 Approved application OaD'-'-Gln Le date of approval. Submit Form and Ml NfA Attachments in Duplicate CD5 - 20 Alpine A/C Dual Lateral Producer Proposed Schematic 2W'94# HAO Welded Conductor to 115'MD 10-3/4" 45.5# LAO HYD 563 x BTC. Surface Casing at 2,456' MD 3-1.74 9.3# L-80 eue8rd Upper Com. pletion: 1) 3-Y," '9.3 / t eue8rd 2) Shallow nipple profile 2-812" ID 3) 3-Yz"x 1" Cam co KB -MG GLM (xx.*) w/DCK2 pinned for 2500 psi casing to thig shear 4) TNT Packer 5) X Nipple -profile, 2.813" 6) TNT Packer 7) XN Nipple profile, 2.813". 7518"F 29.7# L-80 Hyd 563 x BTC C sand, Lateral Intermediate Casing at 1 Z661'MD 6 IWO Hole TD 11,979�- 23,554'MD — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — VX2 12.6# L-8 0 TX L iner w. perf pups 0 TNT Production Packer. at 11,271 MD — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — - CMU Siding sleeve fbr' 4 -'Y"'4 -'Y"' 12.6# L-80 T Liner wl frac ports — — Selecbvft� 11,291 ol lol Hj 11 ---------------------------- ---- TNT Production Packer 347' 93#TN110SS at Asand Lateral 12,035- MD69f ZXP finer top packer (w hipstock 6 3144 HUe TD base) at 12,119" MD 6,H 1Z3D3'-24,119'IAB 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 C. Parker Request of ConocoPhillips Alaska, Inc. for Hydraulic fracturing for the CD5-20 Well under the Provisions of 20 AAC 25.280 STATE OF ALASKA THIRD JUDICIAL DISTRICT Jason C. Parker, being first duly sworn, upon oath, deposes and states as follows: I . My name is Jason C. Parker. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. 1 am a Senior 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 August 22, 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 22nd day of August, 2019. Parke STATE OF ALASKA THIRD JUDICIAL DISTRICT This instrument was acknowledged before me this 22nd day of August, 2019, by Jason C. Parker. Notary Public, State of Alaska My Commission Expires: A I A STATE OF ALASKA MECCA SVVENSEN ift-fon m*Au 20 )PPI-' ze- ConocoPh 1*11 *1 pts, Alaska August 22, 2019 VIA CERTIFIED MAIL To: Operator and Owners (shown on Exhibit 2) Jason C. Parker Senior Landman Land & Business Development ConocoPhililips Company 700 G Street Anchorage, AK 99501 Office: 907-265-6297 Fax: 907-263-4966 jason.c.parker@cop.com Re.- Notice of Operations pursuant to 20 AAC 25.283 (1) for CDB -20 Well AA -92344 (ASRC), ASRC-NPR2, ASRC-NPR3, 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's) for the CD8 -20 Well (the 'Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about August 22, 2019. This Notice is being provided pursuant to subsection of 20 AAC 25.283. The Well has been drilled as a directional horizontal well on leases, AA -92344 (ASRC), ASRC- NPR2, ASRC-NPR3, and ASRC-NPR4 as depicted on Exhibit 1 and has locations as follows: Location FNL FEL Township Range Section Meridian Surface 403' 2804' T11N R4E 18 Umiat To Open Interval 2008' 3267' T11 R4E 7 Umiat Bottomhole 1342' 3331' T11 R4E 20 Umiat Exhibit I 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, Jason C. P rk r Senior Landman Attachments: Exhibits 1 & 2 Exhibit 1 T 21Pq �AS�v"NPR 13 1� l±j tAp ti o-.. y ConocoPhill s . I ,.i R4 .. Alaska V CD5-20 ASRC-NPR4 Lease Plat Data. 6/2112019 ASRC-0.N.P• w.3 V MSI s� ASRG-NPR2 08'78887'" AA092347 4 8 8 k' tl a 8 k � n I fit ADL387208 � `� 1q SRC -NP 2 R �CI"'yS A,df 081817 + Frac Points Half Mile Frac Point Buffer � AA092344 , Half Mile Well Track Buffer Wells within Track Buffer'° Well Track Open Interval l Gravel Footprint N ASRC-NPR4 t..Aa .,. Alpine PA 0 0.2 0.4 0.6 0.8 1 Miles CPAI Lease Exhibit 2 List of the names and addresses of all owners, landowners and operators of all properties within the Notification Area. Overator & 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-Ooerator): 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 Table 1: Wells within .5 miles � Well Name Well Type I Status CD5-01 INJ ACTIVE CD5-02 SVC PA CD5-02A INJ ACTIVE CD5-03 PROD ACTIVE CD5-04 PROD ACTIVE CD5-05 PROD ACTIVE CD5-06 INJ ACTIVE CD5-061-1 INJ ACTIVE CD5-07 INJ ACTIVE CD5-08 INJ ACTIVE CD5-09 PROD ACTIVE CD5-10 PROD ACTIVE CD5-11 PROD ACTIVE CD5-12 INJ ACTIVE CD5-17 INJ ACTIVE CD5-171-1 INJ ACTIVE CD5-18 PROD ACTIVE CD5-181-1 PROD ACTIVE CD5-19 INJ ACTIVE CD5-191-1 INJ ACTIVE CD5-201-1 PROD ACTIVE CD5-21 PROD SUSP CD5-22 PROD ACTIVE CD5-23 INJ ACTIVE CD5-24 PROD PROP CD5-241-1 PROD PROP CD5-24L1P61 EXPEND PA CD5-25 INJ ACTIVE CD5-251-1 INJ ACTIVE CD5-313 PROD ACTIVE CD5-313P61 EXPEND PA CD5-314 PROD PA CD5-314X PROD ACTIVE CD5-315 INJ ACTIVE CD5-315PB1 EXPEND PA CD5-316 INJ ACTIVE CD5-316P61 EXPEND PA CD5-99 PROD PA CD5-99A PROD ACTIVE CD5-99AL1 PROD INACTV 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) Casinq & Cement Assessments: 10 & %)) casing cement pump report on 1/24/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg 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 2/5/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg class G cement. Full returns were not seen throughout the job. The plug bumped at 510 psi, and the floats were checked and they held. 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 1/26/2017 the 10-3/4" casing was pressure tested to 3,500 psi for 30 mins. The 3.5" tubing will be pressure tested to 4,400 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) 7,500 Annulus pressure during frac 31500 Annulus PRV setpoint during frac 31600 7 5/8" Annulus pressure test 37850 3 1/2" Tubing pressure Test 4,400 Nitrogen PRV 8788 Highest pump trip 81588 SECTION 8 —PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283(a)(8) Size Wei ht Grade API Burst API Collapse 10 & 3/" 45.5 L-80 21090 psi 3,580 psi 7 & 5/8" 29.7 L-80 6,890 psi 4)790 3.5" 9.3 L-80 10,160 psi __psi 10,540 psi Table 2: Wellbore pressure ratings Stimulation Surface Rig -Up op- T N • 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 3,600 psi • Frac pump trip pressure setting are staggered and set below main treating line PRV • Tree saver used on all fracs rated for 15,000 psi. Pff Tank Pump Truk Stimulation Tree Saver OPEN POSITION (PRIOR TO tMUNDREI, INSERTION) FRAC IRON CONNECT*k WFUHEAD VALM CLOSED TLat , OPERATED VALVE WELL V) i OUAD PM ASSEMI PLACE IN TA CLOSED POSITION ;k r-) INSEIMD) • The universal tool is rated for 15,000 psi and has 84" of stroke. • Tool ID 2.25" down 4 1/2 tubing and 1.75" down 3 V2 tubing. • Max rate with 2.25" mandrel is 60 bpm and with 1.75" mandrel 36 bpm VENT VALVE OPEN Alpine Wellhead System 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 12,907' MD/7,423 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 10,781' MD/6,996' 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 don section. The top of the Kingak interval ranges from 7,453' TVDSS at the heel to7,607' TVDSS at the toe of the well (no MD as the Kingak interval was not penetrated in the CD5-20 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 confinina zone: CD5-01: The 7-5/8" casing cement pump report on 3/15/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.8 LSND. Full returns were seen throughout the job. The plug bumped at 1,685 psi and the floats held. CD5-02: On 5/1/2016 the CD5-02 lateral was plugged back as per state regulations. CD5-02A: The 7-5/8" casing cement pump report on 5/16/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.3 ppg LSND. Full returns were seen throughout the job. The plug did not bump. Pressure was held on cement and the floats held. CD5-03: The 7 & 5/8" casing cement report on 11/1/2015 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement, displaced with 11.1 ppg LSND. No returns were seen. The plug bumped at 320 psi, and the floats were checked and they held. CD5-04: 7-5/8" casing cement pump report on 6/10/2015 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, and displaced with 11.1 ppg LSND. Full returns were seen throughout the job. The plug bumped @ 900 psi and the floats were checked and they held. CD5-05: The 7-5/8" casing cement pump report on 8/27/2015 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Qannik Slurry cement, displaced with 11.1 ppg LSND. Full returns were seen throughout the job. The plug bumped @ 1700 psi and the floats did not hold. Pressure was held on the cement. CD5-06: The 7-5/8" casing cement pump report on 7/21/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.5 ppg mud. Full returns were seen throughout the fob. The plug bumped at 1,100 psi and the floats held. CD5-07: The 7-5/8" casing cement pump report on 2/17/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.8 ppg LSND. Full returns were seen throughout the job. The plug did not bump. Pressure was held on cement and the floats held. CD5-08: The 7-5/8" casing cement pump report on 6/8/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.3 ppg LSND. Full returns were seen throughout the fob. The plug bumped at 1,200 psi and the floats held. CD5-09: The 7-5/8" casing cement report on 12/5/2015 shows that the job was pumped as designed, inidicating competent cementing operations. The cement jobw as pumped with 15.8 ppg class G cement, displaced with 11.1 ppg LSND. Full returns were seen throughout the fob. The plug did not bump, pressure was held on the casing. The floats were checked and they held. CD5-10: The 7 & 5/8" casing cement report on 1/25/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement, displaced with 11.1 ppg LSND. Full returns were seen throughout the job. The plug bumped at 750 psi, and the floats were checked and they held. CD5-11: The 7 & 5/8" casing cement report on 1/4/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement, displaced with 10.9 ppg mud. No returns were seen. The plug did not bump, and the floats were checked and they held. CD5-12: The 7-5/8" casing cement pump report on 6/26/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.8 ppg LSND. Full returns were not seen throughout the job. The plug bumped at 470 psi and the floats held. 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. CD5-314: CD5-314 was plugged and abandoned per state regulations on 5/10/2015. CD5-315: The 7-5/8" casing cement pump report on 10/3/2015 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg class G cement and displaced with 11.1 ppg LSND. Full returns were seen throughout the job. The plug did not bump and the floats held, and pressure was held on the cement. CD5-315PB1: CD5-313PB1 was plugged and abandoned per state regulations on 9/24/2015. CD5-313PB1: CD5-313PB1 was plugged and abandoned per state regulations on 7/14/2015. CD5-18: The 7-5/8" casing cement pump report on 12/16/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg Class G cement, displaced with 11 ppg LSND. Full returns were seen throughout the job. The plug bumped at 750 psi and the floats held. CD5-21: The 9-5/8" casing cement pump report on 3/28/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8 ppg cement and displaced with 10 ppg mud. Partial returns were seen. The plug bumped at 1,032 psi and the floats held. The Nuiqsut 1 was then plugged and abandoned per state regulations on 4/11/2016. CD5-99A: The 7 & 5/8" casing cement report on 10/13/2016 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped at 670 psi, and the floats were checked and they held. CD5-99: CD5-99 was plugged and abandoned per state regulations on 9/30/2016. CD5-17: The 7 & 5/8" casing cement report on 5/11/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and dart opened stage collar. Second stage was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and closed the stage collar at 2000psi. CD5-19: The 7 & 5/8" casing cement report on 11/27/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped at 1000psi, and the floats were checked and they held. CD5-22: The 7 & 5/8" casing cement report on 10/26/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and dart opened stage collar. Second stage was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and closed the stage collar at 2300psi. CD5-23: The 7 & 5/8" casing cement report on 1/7/2018 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped at 1100psi, and the floats were checked and they held. CD5-24: The 7 & 5/8" casing cement report on 3/5/2019 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and dart opened stage collar. Second stage was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped and closed the stage collar at 1990psi. CD5-316: The 7" casing cement report on 9/7/2017 shows that the job was pumped as designed, indicating competent cementing operations. The cement job was pumped with 15.8ppg class G cement. Full returns were seen throughout the job. The plug bumped at 1000psi, and the floats were checked and they held. CD5-20 Fracture Stimulation Area of Review WELL NAME STATUS Casing Size Top of A -sand Top of A -Sand Oil Pool Top of Cement Top of Cement of Cement CD5-06 ACTIVE Cement Operations 10,180' 7,458' 7,690' 6,701' Oil Pool (MD) (TVDSS) (MD) (TVDSS) Bent Determined ey Reservoir Status open hole liner for production Zonal Zl Isolation Calculated TOC 13,395' & Packer Summary Stage 1: 424 sx 15.8 ppgG, Mechanical Integrity gri 11/4/15, 7-5/8" casing CD5-03 ACTIVE 7-5/8" 14,262' 7,322' 13,395' 7,062' calculated CD5-09 ACTIVE 7-5/8" 13,252' 7,346' 12,392' 6,810' calculated CDS-11 @ 13,723 Stage 2: 449 sx 15.8 ppgG pressure tested to 3,500 for 30 7,439' 7,950' 6,675' calculated CD5-315 PB1 PA 7-5/8" 13,688' 7,659' 9,089' 5,454' psi mins CDS-04 ACTIVE 7-5/8" 11,817' 7,402' 10,896' 7,176' calculated CDS-21 PA 10-3/4" N/A CDS-05 ACTIVE 7-5/8" 11,115' 7,404' 10,177' 7,138' calculated CD5-06 ACTIVE 7-5/8" 10,180' 7,458' 7,690' 6,701' Sonic Log CDS-07 ACTIVE 7-5/8" 10,544' 7,393' 9,745' 7,218' N/A CD5-08 ACTIVE 7-5/8" 10,832' 7,409' 8,347' 6,394' Sonic Log CD5-09 ACTIVE 7-5/8" 13,252' 7,346' 12,392' 6,810' calculated CDS-11 ACTIVE 7-5/8" 9,764' 7,439' 7,950' 6,675' calculated CDS-10 ACTIVE 7-5/8" 9,754' 7,427' 8,650' 7,276' calculated CDS-12 ACTIVE 7-5/8" 9,059' 7,498' 7,350' 6,829' Sonic Log CD5-313 ACTIVE 7-5/8" N/A N/A 12,890' 71242' calculated CD5-313 PB1 PA N/A 15,798' 7,626' 2,253' 2,145' calculated CD5-314 PA 10-3/4" N/A N/A 37' 37' calculated CD5-315 ACTIVE 7-5/8" N/A N/A 12,650' 7,172' sonic log CD5-315 PB1 PA 7-5/8" 13,688' 7,659' 9,089' 5,454' calculated CDS-18 ACTIVE 7-5/8" 15,072' 7,539' 11,350' 6,420' Sonic Log & SCMT CDS-21 PA 10-3/4" N/A N/A Top Plug @ 2,096' 1,972' calculated CD5-99 ACTIVE 7-5/8" 17,232' 7,524' 13,078' 6,767' Sonic Log CDS-17 ACTIVE 7-5/8" 15,802' 7,601' 12,200' 6,634' Sonic Log CD5-19 ACTIVE 7-5/8" 13,775' 7,627' 11,050' 6,907' Sonic Log open hole liner for production Calculated TOC 10,896'& Packer 7 & 5/8" casing @ 11,364' 44/13/15, 2 sx ClCIG' 442 sx ClCI G pressure tested to 3,500 psi open hole liner for production Calculated TOC 10,177'& Packer 93 bbls 15.8ppg Class G 8/28/15, 7 & 5/8" casing tested 3,500 @ 10,997' pressure to psi for 30 mins. Open hole for injection TOC @ 7,690'& Packer @ 8,670' 101.3 bbls 15.8 ppg Class G 9/05/16 passing MITIA to Cement 2500 psi intermediate hole currently being drilled TOC @ XXXX &Packer @ 10,472' 82.5 bbls 15.8 class G cement 7/20/16, passing MITIA to 2200 psi Open hole for injection TOC @ 8,347'& Packer @ 114.1 bbls 15.8 ppg class G 7/24/16, passing MITIA 10,127' cement to 2600 psi open hole liner for production Calculated TOC 12,392'& Packer 397 15.8 12/10/2105, 7-5/8" @ 12,545' sx ppg class G casing pressure tested to 3,500 psi for 30 mins. open hole liner for production Calculated TOC 7,950'& Packer 836 sx 15.8 ppg Class G 1/6/15, 7-5/8" casing tested to 3,500 @ 9,043' pressure psi for 30 mins. open hole liner for production Calculated TOC 8,650'& Packer 520 sx 15.8 ppg Class G 1/27/16, 7-5/8" casing tested to 3,500 @ 8,841' pressure psi for 30 mins. Open hole for injection TOC @ 7,350' @ Packer @ 8,274' 95.5 bbls 15.8 ppg Class G 9/28/16, passing MITIA Cement to 2120 psi open hole liner for production Calculated TOC 12,890" & Packer 290 sx of 15.8 ppg class G 7/28/15, 7-5/8" casing @ 13,254 cement pressure tested to 3,500 psi for 30 mins PA PA, Cement Plugs 342 sx 17 ppg class G cement N/A PA PA, Cement Plugs 122 sx 15.6 ppg AS1 cement N/A slotted liner for injection TOC @ 12,650 & Packer @ 267 sx 15.8 ppg class G 10/14/15, 7 & 5/8" 12,474' cement casing pressure tested to 2,000 psi PA PA, Cement Plugs 609 sx 17 ppg class G cement N/A open hole liner for production TOC @ 11,350'& Packer @ 1036 sx 15.8 ppg class G 1/18/17, Passing MITIA 14,511' cement to 2400 psi PA PA, Cement Plugs 74 bbls 17 ppg Qannik slurry cement N/A open hole liner for production TOC @ 13,078'& Packer @ 734 sx 15.8 ppg class G 11/29/16, Passing MITIA 13,516' cement to 3500 psi Open hole for injection p TOC @ 12, 200' &Packer @ Stage 1: 888sx 15.8 ppg class 5/14/17, passing MITIA 13,742' G cement, Stage 2: 237sx 3800 15.8 ppg class G cement to psi Open hole for injection TOC @ 11,050'& Packer @ 1028 sx 15.8 ppg class G 11/29/17, passing MITIA 12,109' 1 cement to 3500 psi CD5-20 Fracture Stimulation Area of Review Stage 1: 586sx 15.8 ppg class CDS-22 ACTIVE 7-5/8" 10,680' 7,471' 8,878' 6,932' Sonic Log open hole liner for production TOC @ 8,878'& Packer @ 9,562' G cement, Stage 2: 363sx 10/28/17, passing MITIA 15.8 ppg class G cement to 3500 psi CDS-23 ACTIVE 7-5/8" 9,190' 7,503' 6,585' 6,181' Sonic Log Open hole for injection TOC @ 6,585'& Packer @ 8,129' 242 sx 15.8 ppg class G 1/9/2018, passing MITIA cement to 3500 psi Stage 1: Lead: 313sx 13 ppg CD5-24 &CD5- 24L1 ACTIVE 7-5/8" 14,338' 7,669 7,900' 5,149' Sonic Log open hole liner for production TOC @ 7, 900 & Packer @ class G cement, Tail: 634sx 15.8 ppg class G cement, 3/8/2019, passing MITIA 12,969' Stage 2: 224sx 11.2 ppg class to 3500 psi G cement CD5-25 & CD5- 61 sx of 12.2ppg class G 1/25/18, 7 5/8" casing 2511-1 ACTIVE 7-5/8" 9,055 7,515 6,655' 6,511 log open hole liner for injection TOC: 6,655'& Packer @ 7,280' cement & 301 sx of 15.8 class pressure tested to 3,300 G cement psi for 30 mins CDS-316 ACTIVE 7" 18,612' 7,331' 18,120' 7,327' sonic log slotted liner for injection TOC @ 18,120 &Packer @ 290 sx 15.8 ppg class G 9/12/17, 7" casing 19,186' cement pressure tested to 3,500 psi SECTION 11 — LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFINING ZONES 20 AAC 25.283(a)(1 1) CPAI has formed the opinion, based on seismic, well, and other subsurface information currently available that 3 faults or fracture systems transect the Alpine A formation or enter the confining zone within one half mile radius of the wellbore trajectory for CD5-20. The three faults systems were interpreted from seismic data prior to drilling and 2 were confirmed with log data while drilling. The first fault was a single fault plane with 9' of throw, the second mapped fault was a series of 3 smaller faults within a 105'MD section and a total throw of 14.5' and the third fault was not present in the CD5-20 wellbore. 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. The frac sleeves were placed 500' minimum away from the faults to mitigate the risk of a fracture intersection. If there are indications that a fracture has intersected a fault during fracturing operations, ConocoPhillips will go to flush and terminate the stage immediately. Well Depth Depth Vertical Loss Name MD (ft) TVDSS (ft) Displacement p (bbls/hr) (ft) CD5-20 141415' 71432' 9' None CD5-20 171275' 71469' 1.5' None CD5-20 17,357' 71470 7' None CD5-20 17,380' 7,471' 6 60-80 Plat 2: CD5-20 Fault Analysis SECTION 12 — PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(1 2) CD5-20 will be re -completed in 2019 as a multilateral horizontal producer in the Alpine A and C formations, with the frac planned for the A sand lateral. The well will be completed with 3.5" tubing and a 4.5" liner with ball actuated sliding sleeves. During the original frac, a leak was discovered causing issues with pumping the designed frac. The leak will be repaired and the frac will continue as originally planned. 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 100° F seawater (approx. 15,000 bbls are required for the treatment with breakdown, maximum pad, and 450 bbls usable volume per tank). 5. MIRU Stinger Tree Saver Equipment and HES Frac Equipment. 6. PT Surface lines to 9,000 psi using a Pressure test fluid. 7. Test IA Pop off system to ensure lines are clear and all components are functioning properly. 8. Pump the 310 bbl breakdown stage (25# Hybor G) according to the attached excel HES pump schedule. Bring pumps up to maximum rate of 20 BPM as quick as possible, pressure permitting. Slowly increase annulus pressure from 2,500 psi to 3,500 psi as the tubing pressures up. Ensure sufficient volume is pumped to load the well with Frac fluid, prior to shut down. 9. Perform a hard shut down, Obtain ISIP and fluid efficiency estimates. 10. Pump the Frac job by following attached HES schedule @ 25bpm with a maximum expected treating pressure of 7,500 psi. • 14 stages, ^0 1,169,688 lbs of 20/40 Wanli proppant • Note due to time constraints the hydraulic fracturing treatment will get split into 2 days of pumping. 11. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 12. Well is ready for Post Frac well prep for flowback (Slickline and possibly CTU). CUSTOMER ConocoPhillips Alaska, Inc. API 50-103-20752 FD (lb/gal) 8.54 -- 70.31369 LEASE CDS-20HALUOURTQIV SALES ORDER BHST (°F) 165 � '".�, ti,.- FORMATION A Sand DATE - Max Pressure (psi) -151.2224 Liquid Additives QryAdditives Treatment Stage Fluid Stage Proppant Prop Slurry Clean Clean Slurry Prop Stage Interval Lo -Surf 300D MO -67 CL -22 UC CL -31 LVF -200 WG -36 BE -6 OptiFlo-111 SP Interval Number Description Description Description Conc Rate Volume Volume Volume Total Time Time surfactant Buffer Crosslinker Crosslinker Freeze Protect rel Suicide Breaker Breaker 1-1 (ppg) (bpm) (gal) bbl bbt (lbs) (hh:mm:ss) (hh:mm:ss) (gpt) (gpt) (gpt) (gpt) (got) (opo (ppt) (opt) (opt) Freeze Protect Freeze Protect 5 2,100 50 5fl 0:10:00 1:34:54 �. 1-2 1-3 25# Hybor G 25# Hybor G Load Well Spacer & Dro Ball 1.688" 5 1,000 24 24 0:04:46 1:24:54 1.00 1.25 0.90 0.45 1000.00 25.00 0.15 2.00 0.25 Ln 1-4 25# Hybor G Flush 25 630 15 1a 0:00:36 1:20:08 1.00 1.25 0.90 0.45 25.00 0.15 2.00 0.25 m 1-5 25# Hybor G Mini-Frac 25 11,258 268 268 0:10:43 1:19:32 1.00 1.25 0.90 0.45 25.00 0.15 2.00 0.25 _ 0 1-6 25# Hybor G Flush 25 13,000 310 31,0 0:12:23 1:08:49 1.00 1.25 0.90 0.45 25.00 0.15 2.00 0.25 R 0 m tfn -* 1-7 Shut -In Shut 25 11,258 268 258 0:10:43 0:56:26 1.00 1.25 0.90 0.45 25.00 0.15 2.00 0.25 c Q -In 0:45:43 o 1-8 1-9 25# Hybor G 25# Hybor G Pad Proppant Laden Fluid Wanli 20/40 1.00 25 12,600 300 300 0:12:00 0:45:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 a 1-10 25# Hybor G Proppant Laden Fluid Wanli 20/40 2.00 25 9,300 221 231 9,300 0:09:16 0:33:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 1-11 25# Hybor G Proppant Laden Fluid Wanli 20/40 3.00 25 25 8,900 21.2 230 17,800 0:09:15 0:24:27 1.00 1.25 0.90 0.45 25.00 0.15 2.00 1-12 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 8,600 20.5 231 25,800 0:09:19 0:15:12 1.00 1.25 0.90 0.45 25.00 0.15 2.00 1-13 25# H bor G & DropBall 1.75" 4,700 1.12 131 18,800 0:05:18 0:05:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 4 2-1 25# Hybor G 'Spacer Fad 25 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 +- N � 2-2 25# Hybor G Pra ant Laden Fluid Wanli 20/40 1.00 25 25" 12,600 30f) 300 0:12:00 0:45:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 2-3 25# H bor G Proppant Laden Fluid Wanli 20/40 2.00 25 9,300 8,900 221 212 231 230 9,300 17,800 0:09:16 0:09:15 0.33.43 0:24:27 1.00 1. . 25 0.90 0.45 25.0? 0.15 2.Od Q- rt' 2-4 25# H bor G Proppant Laden, -.Fluid Wanli 2L1j40 3.00 25 8,600ft 1.00 1.25 0.90 0.45 2 5. 0.15 2404 2-5 25# Hybor G Pro pant Laden Fluad Wank 2{1/40 4.00 25 245 231 25,800 0:09:19 0:15:12 1.0tT 1.25 0.90 0.45 25.04 0.15 2.00 2-6 2$# Hybor S acer &Dro 621#i 1.$13" 4,700 112 131 18,800 0:05:18 0:05:54 1.00 1.25 0.90 (3.45 25.00 0.15 2.00 3-1 25# Hybor G Pad 25 630 1S 15 0:00:36 0:00:36 1.00 1,25 0.9p 0.45 25.10 ff.15 2.00 CV) 3-2 25# Hybor G Proppant Laden Fluid Wanli 20/40 1.00 25 25 12,600 9,300 300 300 0:12:00 0:45:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 3-3 25# Hybor G Proppant Laden Fluid Wanli 20/40 2.00 25 221, 231 9,300 0:09:16 0:33:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 a) wQN 3-4 25# Hybor G Proppant Laden Fluid Wanli 20/40 3.00 25 8,900 212 2301 17,800 0:09:15 0:24:27 1.00 1.25 0.90 0.45 25.00 0.15 2.00 co 3-5 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 8,600 205 231 25,800 0:09:19 0:15:12 1.00 1.25 0.90 0.45 25.00 0.15 2.00 `) 3-6 25# Hybor G Spacer & Drop Ball 1.875" 4,700 112 1.31 18,800 0:05:18 0:05:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 4-1 25# H bor G Pad 25 630 15 1S 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 «` cr T- 4-2 25# Hybor G Proppant Laden Fluid Wanli 20140 1.00 25 25 12 600 9,300 3170 221 300 231 0:12:00 0:45:43 1.00 1..25 0.90 0.45 25.00 0.15 2.00 i✓ sn 4-3 25# Hybor G Pro nt Laden Fluid Wanii 20/40 2.00 25 8,900 212 230 9,300 0:09:16 0:33:43 1..00 1.25 01.90 0.45 25.00 0.15 2.Of3 a 4-4 25# Hybor G Proppant Laden Fluid �lanli 20/40 3.00 25 8,600 17,800 0:09:15 0:24:27 1.00" 1.25 43.90 0.45 25.( 0.1 5 2.00 4-5 25## Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 205 232 25,800 0:09:19 0:15:12 1.00 1..25 0.90 0.45 25.00 0.1.5 2.00 4-6 25## Hybor G Spacer & Dro Ball 1.938°' 4,700 1.12 1.31. 181800 0:05:18 0:05:54 1,000 1,.25 4.90 0.45 25.00 0.15 2.40 5-1 25# Hybor G Pad 25 630 1,5 15 0:00:36 0:00:36 1..00 1.25 03.90 0.,45 25.00 17.15 2.130 In aoo 5-2 25# Hybor G Proppant Laden Fluid Wanli 20/40 1.00 25 25 12,600 9,300 300 221 app 0:12:00 0:45:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 m c N 4 5-3 25# Hybor G Proppant Laden Fluid Wanli 20/40 2.00 25 8,900 212 231 230 9,300 17,800 0:09:16 0:33:43 1.00 1.25 0.90 0.45 25.00 0.15 2.00 °� o cQo 5-4 25# Hybor G Proppant Laden Fluid Wanli 20/40 3.00 25 8,600 205 0:09:15 0:24:27 1.00 1.25 0.90 0.45 25.00 0.15 2.00 N 5-5 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 231 25,800 0:09:19 0:15:12 1.00 1.25 0.90 0.45 25.00 0.15 2.00 5-6 25# Hybor G Spacer &Drop Ball 2.000" 4,700 112 1:31 18,800 0:05:18 0:05:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 6-1 25## H or G Pad 25 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 6-2 25# H bor G Pro apt Laden Fluid Wanh 20/40 1.00 25 25 12,600 300 300 0:12:00 0:39:16 1.00 1.25 0.90 0:45 25.{34 0.15 2.00 ccs to 6-3 25# Hybor G Proppant Laden fluid Wanh 20/40 2.00 25 3,024 3,024 72 72 75 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 c+c- 6-4 25# Hybor G Proppant Laden Fluid Wan1120/40 3.00 25 3,1.92 76 78 86 6,048 9,576 0:03:09 0:24:16 1.00 1.25 0.90 0.45 2 .00 5 0.1 _ 5 2.00 T 6-5 25# Hybor G Pro - ant Laden Fluid Wanli 20/40 4.00 25 0:03:27 0:21:07 1.00 1.25 4.90 0.45 25.00 0.1,5 2.00 6-6 25# Hybor G Pr ant l Aden Fluid Wanli 20/40 5.00 6,006 1.43 158 24,024 0:06:46 0:17:40 1.00 1.25 U.90 0:45 25.00 0.15 2.00 6-7 25# Hybor G Proppant Laden Fluid Wanli 20/40 6.00 25 25 4,452 lt?6 129 22,2Es€7 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.0(3 0.15 2.00 6-8 25# N bor G Spacer & Dro Balt 2.063." 4,200 200 126 25,2110 0:05:06 0:05:42 1.00 1.25 0,90 0.45 25.0€3 0.15 2.40 7-1 25# Hybor G Pad 25 630 15 15 0:00:36 0:00:36 1..00 1.25 0.90 0.45 25.00 0.15 2.00 7-2 25# Hybor G Y Proppant Laden Fluid Wanli 20/40 1.00 25 25 12,600 300 300 0:12:00 0:39:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 r ti'D 04 N 7-3 25# Hybor G Pro ant Laden Fluid Wanli 20/40 2.00 25 3,024 3,024 72 72 75 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 C14 7-4 25# Hybor G Proppant Laden Fluid Wanli 20/40 3.00 25 3,192 78 6,048 0:03:09 0:24:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 N *- 7-5 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 6,006 76 143 86 168 9,576 0:03:27 0:21:07 1.00 1.25 0.90 0.45 25.00 0.15 2.00 00 N 7-6 25# Hybor G Proppant Laden Fluid Wanli 20/40 5.00 25 4,452 106 129 24,024 0:06:46 0:17:40 1.00 1.25 0.90 0.45 25.00 0.15 2.00 @) 7-7 25# Hybor G Proppant Laden Fluid Wanli 20/40 6.00 25 4,200 100 22,260 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 7-8 25# Hybor G Spacer &Dro Ball 2.125" 126 25,200 0:05:06 0:05:42 1.00 1.25 0.90 0.45 25.00 0.15 2.00 8-1 251# ##, bor G Pad 25 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 8-2 25# Hybor G- Proppant Laden Fluid Wank 2%10 1.00 25" 25 12,E 300 300 0:12:00 0:48:07 1.00 1.25 0.903 0.45 25.00 0.15 2.00. _ ,- 8-3 25#_Hybor G Proppant Laden Fluid Wanli 203 40 2.00 25 3,024 72 75 3,024 0:03:01 0:36:07 1.001 1.25 0.90 0.45 25.00 0.15 2. ; 00 as c'v bt 8-4 25# Hybor e Pro arfit Laden Fluid Warrli 243/40 3.00 25 3,024 3,192 72 76 78 6,048 0:03:09 0:33:06 1.00 L25 0.90 0.45 25.00 0.15 2.00 vii m : 8-5 25# Hybor Proppant Laden Fluid Wanh 20/40 4.001 25 6,006 86 9,576 0:03:27 0:29:58 1.001 1.25 0:90 0.45 25.00 0.15 2.00 .,. r 8-6 25# Hybor G Pro ant Laden Flu04 Wanli.2{1/40 5.00 143 168 24;024 0:06:46 0:26:30 1.{30 125 0.90 0.45 25.00 0,15 2.00 8-7 25# Hybor 6 Prop ani #den Fluid Wank 20/40 6.0(3, 25 4,452 106 1.29 22,260 0:05:12 0:19:45 1.00 1.25 0.94 0:45 2500 0.1.5 2.00 0.25 8-8 25# H bot G flash 25 4,2x0. 100 126 25,2£30 0:05:06 0:14:32 1.00 1.25 0:90 0.45 2500 0.15 2.00 0.25 8-9 Freeze Protgct freeze Protect 25 9,916 236 236 0:09:27 0:09:27 1..003 1.25 0.90 0.45 25.00 0.15 2.00 0.50 9-1 Freeze Protect Freeze Protect 2,100 513 5fl 1000.00 9-2 25# Hybor G S pacer & Drop Ball 2.188" 2,10050 SO 0:39:16 1000.00 9-3 25# Hybor G Pad 630 7,5 15 0:39:16 1.00 1.25 0.90 0.45 25.00 1 0.15 2.00 25 1 12,600 300 300 0:12:00 0:39:16 1.00 1.25 0.90 0.45 25.00 1 0.15 2.00 ConocoPhillips Alaska, Inc. - CD5-011 Planned Design 232 289 208 104 2730 5788 35 463 7 Stage CUSTOMER LEASE FORMATION Fluid ConocoPhillips Alaska, Inc. CD5-20 A Sand Stage Proppant API SALES ORDER DATE Prop Conc 50-103-20752 - Slurry Max Pressure Clean FD (Ib/gal) BHST (°F) (psi) Clean 8.54 165 Slurry MALLIBURTGN Prop - � .� �- ° ° Stage 70.31369 151.2224 Interval Li uid Additives 4 Lo -Surf 300D MO -67 CL -22 UC CL -31 LVT-200 WG -36 DfyAdditives BE -6 OptiFlo-111 SP Treatment Interval Number Description Description Description (ppg) Rate (bpm) Volume Volume Volume Total Time Time surfactant Buffer Crosslinker Crosslinker Freeze Protect feel $iaCid� Breaker breaker rn 9-4 25# Hybor G Proppant Laden Fluid Wanli 20/40 1.00 (gal) bbl) bbtj (lbs (hh:mm:ss) (hh:mm:ss ) (gpt) t (gp) t (9p) t (gp) (gpt) (Opt) (ppt) (pp#) (Apt) " N 9-5 25# Hybor G Proppant Laden Fluid Wanli 20/40 2.00 25 25 3,024 7Z 75 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 Max Additive Rate °= Q W 9-6 25# Hybor G Pro ppant Laden Fluid Wanli 20/40 3.00 25 3,024 72 78 6,048 0:03:09 0:24:16 1.00 1.25 0.90 0.45 Zones 9-14 25.00 0.15 2.00 4200 T N 9-7 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 3,192 76 86 9,576 0:03:27 0:21:07 1.00 1.25 0.90 0.45 25.00 0.15 2.00 9-8 25# Hybor G Proppant Laden Fluid Wanli 20/40 5.00 25 6,006 143 168 24,024 0:06:46 0:17:40 1.00 1.25 0.90 0.45 25.00 0.15 2.00 a 9-9 25# Hybor G Proppant Laden Fluid Wanli 20/40 6.00 1 25 4,452 106 129 22,260 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.00 0,15 2.00 9-10 25# Hybor G Spacer &Dro Ball 2.250" 4,200 100 126 25,200 0:05:06 0:05:42 1.00 1.25 0.90 0.45 25.00 0.15 2.0025 10-1 25.# H bor G #�� _ 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 .00 - 10-2 25# H bor G Pro ant Laden Fluid Wanli 20/4() 1,00 25 25 12 600 300 300 0:12:00 0:39:16 100 1.25 0.90 0.45 25.00 {1.15 2.00 cs 10-3 25# Hybor G Proppant Laden Fluid Wank 20/40 2.00 25 3,024 72 75 3,024 0:03:01 0:27:16 1.#30 1.25 0.90 0.45 25.00 0.15 2.00 10-4 25# Hybor G Proppant Laden Fluid Wanli 2£1/4{3 3.00 25 3,024 72 78 6,04$ 0:03:09 0:24:16 1.00 1 25 0.90 0.45 25.00 0.15 2.04 4X 10-5 25# Hybor G Pro ant Laden Fluid Wanli 20/40 4.00 25 3,192 76 86 91576 0:03:27 0:21:07 1,00 1.25 0.90 0.4.5 25.04 0.15 2.00 10-6 25# H bpr G Pro ant Laden Fluid Wank 20/40 5.00 25 6,0(36 143 16£3 24,024. 0:06:46 0:17:40 ,1.00 1.25 0.90 4.45 25,00 0.15 2.00 10-7 25# Hybor G Pro ant Laden Fluid Wan#i 20/40 6.00 25 4,452 106 129 22,260 0:05:12 0:10:54 1,fl0 1. . 25 0.90 0.45 25.00 0.15 2.00 10-8 2$# Hybor G Spacer & DropBali 2.254" 25 4,200 100 126 25,200 0:05:06 0:05:42 1.00 1.25 0.90 0.45 25.00 O.1S 2.00 11-1 25# Hybor G Pad 630 15 1S 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0:15 2.00 Ln r 11-2 25# H bor G Proppant Laden Fluid Wanli 20/40 1.00 25 25 12,600 300 300 0:12:00 0:39:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 T 11-3 25# Hybor G Proppant Laden Fluid Wanli 20/40 2.00 25 3,024 72 75 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 in o 11-4 25# Hybor G Proppant Laden Fluid Wanli 20/40 3.00 25 3,024 3,192 721 75 78 6,048 0:03:09 0:24:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 � a N 11-5 25# Hybor G Proppant Laden Fluid Wanli 20/40 4.00 25 86 9,576 0:03:27 0:21:07 1.00 1.25 0.90 0.45 25,00 0.15 2.00 c 11-6 25# Hybor G Proppant Laden Fluid Wanli 20/40 5.00 25 6,006 143 168 24,024 0:06:46 0:17:40 1.00 1.25 0.90 0.45 25.00 0.15 2.00 '- a 11-7 25# Hybor G Proppant Laden Fluid Wanli 20/40 6.00 25 4,452 106 129 22,260 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 @)11-8 25# Hybor G Spacer &Drop Ball 2.250" 4,200 1.00 7.26 25,200 0:05:06 0:05:42 1.00 1.25 0.90 0.45 25.00 0.15 2.0025 12-1 25# Hybor G Pad 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 12-2 25# #f bor G Pro ant Laden Fluid Wanti 20/40 1.00 25 25 1.2,600 300 300 0:12:00 0:39:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 cv �. 12-3 25# Hybor G Pro - ant Carlen Fluid Wanh 20/40 2.00 25 3,024 3,024 72 72 75 7$ 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0,15 2.00 12-4 25# flyor G Proppant Laden Fluid Wanh 20/40 3.00 25 6,048 0:03:09 0:24:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 12-5 25# Hybor G Pro ant Laden Fluid Wanti'20/40 4.00 25 3,192 76 86 9,576 0:03:27 0:21:07 1.00 1. 25 0.90 0.45 25.00 13.15 2.fl0 T 12-6 25## H bor G Pro ant Laden fluid Wank 20/40 5.00 25 6,006 143 168 24,024 0:06:46 0:17:40 1.00 1.25 0.90 0.45 25.00 0,15 2.00 04 12-7 25# Hybor G Proppant Laden Fluid Wank 20/40 6.00 25 4,452 106 129 22 260• 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 12-8 25# FI bor G Spacer &Dro 8a#{ 2.250" 4,204 100 125 25,21)0 0:05:06 0:05:42 1.00 1.25. €3.90 0.45 25.00 0,15 2.00 � 13-1 25# Hybor G Pad 25 634 15 15 0:00:36 0:00:36 1. 00 1.25 0.90 0.45 25.00. 0,15 2.00 Ln 13-2 25# Hybor G Pro ant Laden Fluid Wanli 20/40 1.00 25 25 12,600 300 3011 0:12:00 0:39:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 13-3 25# Hybor G Proppant Laden Fluid Wank 20/40 2.00 25 3,024 72 75 3,024 0:03:01 0:27:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 c 13-4 25# Hybor G Pro ant Ld aen Fluid Wanli 20/40 3.00 25 3,024 72 78 6,048 0:03:09 0:24:16 1.00 1.25 0.90 0.45 25.00 0.15 2.00 U) a , 13-5 25# H bor G Proppant Laden Fluid Wanli 20/40 4.00 25 3,192 76 86 9,576 0:03:27 0:21:07 1.00 1.25 0.90 0.45 25.00 0.15 2.00 13-6 25# Hybor G Proppant Laden Fluid Wanli 20/40 5.00 25 6,006 143 168 24,024 0:06:46 0:17:40 1.00 1.25 0.90 0.45 25.00 0.15 2.00 N 13-7 25# Hybor G Proppant Laden Fluid Wanli 20/40 6.00 25 4,452 106 129 22,260 0:05:12 0:10:54 1.00 1.25 0.90 0.45 25.00 0.15 2.00 13-8 25# Hybor G Spacer & Dro Ball 2.250" 4,200 100 126 25,200 0:05:06 0:05:42 1.00 1.25 0.90 0.45 25.00 0.15 2.00 ##` 14-1 25# H bor G Pad 25 630 15 15 0:00:36 0:00:36 1.00 1.25 0.90 0.45 25.00 0.15 2.00 14-2 25# Hybor G Pro -,pant Laden Fluid Wanli 20/40 1.£10 25 25 12,600. 300 300 0:12:00 0:47:37 1.00 1.25 fl.90 0:45 25.06 0.15 2.00 14-3 25# Hybor G Pra ant Laden Fluid Wan#i 20/44 2.#14? 2S 3,024 72 75 3,024 0:03:01 0:35:37 1.00 1.25 0.90 0.45 - 25.00 0.15 2.00 14-4 25# H bor G Pro pant Laden Fluid Wan#i 20/4(} 3.4Q 25 3,024 3,1.92 72 76 78 6,048 0:03:09 0:32:37 1.00 1.25 0.90 0.45 25.00 0.15 2.00 to 14-5 25# Hybor G Pro ant Laden Fluid Wanli 20/40 4.00 25 6,006 143 86 9,576 0:03:27 0:29:28 1.04 1.25 0.90 0.45 25.00 #7.15 2.00 4 14-6 25## Hybor G Proppant Laden Fluid Wank 20/40 S.Op 25 4,452 768 24,024 0:06:46 0:26:01 1.00 1.25 0.90 0.45 25,00 0.15 2.00 14-7 25# Hybor G Proant Laden Fluid 20/4(1 6.0 25 4,200 1% 129 22,2617 0:05:12 0:19:15 1.40 7.25 0.90 0.45 25.00 0.15 2.00 0.25 14-8 25# Linear Flash 100 126 25,200 0:05:06 0:14:03 1.00 L25 4.90 0.45 25.00 0.15 2.00 0.25 14-9 Freeze Protect Freeze Protect 25 8,765 2€19 209 0:08:21 0:08:57 1..001.25 0.90 0.45 25.041 0.15 25 630 619, 930 15 14,760 15 15,963 1,169, 688 1 0:00:36 10:48:25 0:00:36 1000.00 2.00 0.50 232 289 208 104 2730 5788 35 463 7 Proppant Type Design Total (lbs) LVT-200 WG -36 BE -6 Opti Flo -III SP (gpm) (gPm) (gPm) (gPm) (9pm) Ppm Wanli 20/40 1,169,688 PPM 1.1 1.3 0.9 Lo -Surf 300D MO -67 CL -22 UC CL -31 LVT-200 WG -36 BE -6 Opti Flo -III SP 0.1 210.0 5.3 0.0 0.4 (gal) (gal) (gal) (gal) (gal) lbslbs lbs lbs Initial Design Material Volume 613.0 766.2 551.7 275.8 6,930.0 15,325.0 91.9 1,226.0 23.0 Max Additive Rate Min Additive Rate Zones 9-14 234 263 5 578 381 477. 343 172 4200 9537 57 763 16 _ 54Q,792 Lo -Surf 300D MO -67 CL -22 UC Zones 1-8 385,666 9,183 628,896 ConocoPhillips Alaska, Inc. -CD5-011 Planned Design 2 CL -31 LVT-200 WG -36 BE -6 Opti Flo -III SP (gpm) (gPm) (gPm) (gPm) (9pm) Ppm PPM PPM PPM 1.1 1.3 0.9 0.5 1,050.0 26.3 0.2 2.1 0.5 0.2 0.3 0.2 0.1 210.0 5.3 0.0 0.4 0.1 Hydraulic Fracturing Fluid Product Component Information Disclosure Fracture Date State: County: API Number: Operator Name: Well Name and Number: Longitude: Latitude: Long/Lat Projection: Indian/Federal: Production Type: 2017-02-13 Alaska Harrison Ba 5010320752 NORTH SLOPE - EBUS CD5-20 -151.22 70.31 Trade Name none Purpose True Vertical Depth (TVD): Total Water Volume (gal)*: 0 619,930 Hydraulic Fracturing Fluid Composition: Acrylate polymer I Proprietary Hmmonium persultate Borate salts 7727-54-0 Proprietary Corundum 1302-74-5 Chemical 14808-60-7 Maximum Proprietary Ethanol Trade Name Supplier Purpose Ingredients Abstract Service Maximum Ingredient Concentration in Additive Ingredient Concentration in ingredient Mass 91-20-3 Oxylated phenolic resin Proprietary Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega- hydroxy-, branched 127087-87-0 Number (CAS (% by mass)** HF Fluid (% by lbs Comments Co many First Name Last Name Email Phone Sea Water BE -65094320 Operator Base Fluid Water #) 7732-18-5 mass)** Density = 8.560 96.00% 7 7.62 0 63.n com MICROBIOCIDE Halliburton Biocide Listed Below Listed Below CL -22 UC Halliburton Crosslinker Listed Below Listed Below 0 NA CL -31 CROSSLINKER Halliburton Crosslinker Listed Below Listed Below Denise.Tuck @Halliburton. 281-871-6226 0 NA LOSURF-300D Halliburton Non-ionic Surfactant Listed Below Listed Below 30.00% 0 NA MO -67 Halliburton pH Control Additive Listed Below Listed Below 30.00% 0.00560% 0 NA O PTI F LO -111 Tuck Denise.Tuck @Halliburton. 281-871-6226 60.00% 0.04214��, 2766 0 NA DELAYED com 100.00% 0.233500 15325 RELEASE Halliburton Breaker Listed Below Listed Below BREAKER 100.000 0.72963% 47887 0 NA SP BREAKER Halliburton Breaker Listed Below Listed Below 5.00% WG -36 GELLING AGENT Halliburton Gelling Agent Listed Below Listed Below 0 NA LVT-200 penreco Additive Listed Below Listed Below 281-871-6226 0 NA Xinmi Wanli com 5.00% 0.00351% 0 NA 20/40 Wanli Industry Developmen Additive Listed Below Listed Below 0.05919° 3885 It Co. Ltd 0 NA Ingredients Listed Above 1,2,4 Trimethylbenzene 95-63-6 1.00% 0.00070° 147 2-Bromo-2-nitro-1,3-propanediol 52-51-7 100.00-'.1 0.00229% 150 Acrylate polymer I Proprietary Hmmonium persultate Borate salts 7727-54-0 Proprietary Corundum 1302-74-5 Crystalline silica, quartz 14808-60-7 Cured acrylic resin Proprietary Ethanol 64-17-5 Guar gum 9000-30-0 Heavy aromatic petroleum naphtha 64742-94-5 Hydrotreated Distillate, Light..C9-16 64742-47-8 Mullite 1302-93-8 Naphthalene 91-20-3 Oxylated phenolic resin Proprietary Poly(oxy-1,2-ethanediyl), alpha-(4- nonylphenyl)-omega- hydroxy-, branched 127087-87-0 Potassium formate 590-29-4 Denise Tuck, Halliburton, 3000 1.00% 0.00099% 65 N. Sam Houston Halliburton Denise Denise.Tuck Pkwy E., Houston, Tuck @Halliburton. 281-871-6226 TX 77032,281- com 871-6226 100.00% 0.01868% 1226 60.00% 0.05919% 3885 Halliburton Denise Tuck Denise.Tuck @Halliburton. 281-871-6226 55.000 9.80220° 643329 com 30.00% 0.00570° 375 30.00% 0.00560% 368 Halliburton Denise Tuck Denise.Tuck @Halliburton. 281-871-6226 60.00% 0.04214��, 2766 com 100.00% 0.233500 15325 30.00° 0.02107% 1383 100.000 0.72963% 47887 45.00% 8.019980 526360 5.00% 0.003510 231 30.00:, 0.02810- 1844 Halliburton Denise Tuck Denise.Tuck @Halliburton. 281-871-6226 com 5.00% 0.00351% 231 60.00° 0.05919° 3885 Potassium hydroxide 1310-58-3 5.00% 0.00229% 151 Potassium metaborate 13709-94-9 60 . 0 0 0.0 2 7 4 3= 1801 Sodium carboxymethyl cellulose 9004-32-4 1.00% 0.00099% 65 Sodium chloride 7647-14-5 4 .00= 3.23642'' 212411 Sodium glycollate 2836-32-0 1.00% 0.00099% 65 Sodium hydroxide 1310-73-2 30.00% 0.03718`-, 2441 Sodium persuffate 7775-27-1- 0.00035% 23 Sodium sulfate 7757-82-6 0.10% 0.00000 % 1 Water 7732-18-5 100.00%1 0.18097% 11879 * Total Water Volume sources may include fresh water, produced water, and/or recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. V3. All component information listed was obtained from the supplier's Material Safety Data Sheets (MSDS). As such, the Operator is not responsible for inaccurate and/or incomplete information. Any y questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administration's (OSHA) regulations govern the criteria for the disclosure of this information. Please note that Federal Law protects "proprietary", "trade secret", and "confidential business information" and the criteria for how this information is reported on an MSDS is subject to 29 CFR 1910.1200(i) and Appendix D. CD5 20 Alpine A Multi -stage Frac Model Frac Design Stage 1 . ... ... ... ... Stade Fluid Description Sta a Description on Design clean VolumeNunber(Ppg)Description Prop conc Proppant (gel) 2,100 1-1 Freeze Protect 1-2 Load Well 15000 1-3 25# Hybor G Mini -Frac 11,258 1-4 25# Linear Flush 13, 000 1-5 Shut -In Shut -In 1-6 25# Hybor G Pad 12,600 1-7 25# Hybor G Proppant Laden Fluid 1.00 Wanli 20/40 91300 1-8 25# Hybor G Proppant Laden Fluid 2.00 Wanli 20/40 81900 1-9 25# Hybor G Proppant Laden Fluid 3.00 Wanli 20/40 87600 1-10 25# Hybor G Proppant Laden Fluid 4.00 Wanli 20/40 0 40 4, 700 1-13 25# Hybor G Spacer and Drop Ball 630 Frac Design Stage 2-5 Stage Number Fluid Description Stage Description 2-1 25# Hybor G Pad 2-2 25# Hybor G Proppant Laden Fluid 2-3 25# Hybor G Proppant Laden Fluid 2-4 25# Hybor G Proppant Laden Fluid 2-5 25# Hybor G Proppant Laden Fluid 2-8 25# Linear Spacer and Drop Ball Prop Conc Proppant Design Clean Volume (ppg) Description (gal) 12,600 1.00 Wanli 20/40 9,300 2.00 Wanli 20/40 8,900 3.00 Wanli 20/40 8,600 4.00 Wanli 20/40 4,700 630 Frac Design Stages 6-14 Stage Number Fluid Description Stage Description Prop Conc (ppg) 1.00 2.00 3.00 4.00 5.00 6.00 Proppant Description Wanli 20/40 Wanli 20/40 Wanli 20/40 Wanli 20/40 Wanli 20/40 Wanli 20/40 Design Clean Volume (gal) 12,600 3,024 31024 3,192 67006 4,452 4,200 630 6-1 6-2 6-3 6-4 6-5 6-6 6-7 6-8 25# Hybor G 25# Hybor G 25# Hybor G 25# Hybor G 25# Hybor G 25# Hybor G 25# Hybor G -25# Linear Pad Proppant Laden Fluid Proppant Laden Fluid Proppant Laden Fluid Proppant Laden Fluid Proppant Laden Fluid Proppant Laden Fluid Spacer and Drop Ball Totals (8 stages) 25# Hybor G 604,234 gal 25# Linear 6,930 gal 20/40 Wanli 1,169,688 lbs Model Results Stages lob Size Top TVD Btrn TVD Propped Fracture Avg (Ib) (ft) (ft) Half- Height (ft) Fracture length (ft) Width (in) 1-5 72,000 7530 7605 520 75 0.32 6-14 90,000 7525 7615 500 9:0 0.34 • Disclaimer Notice: — This model was generated using commercially available modeling software and is based on engineering estimates of reservoir properties. ConocoPhillips is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. SECTION 13 — POST-FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(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.)