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Home My WebLink About2019-10-03_319-453STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ,?n AAr. 9- 9Rn 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate [Z Repair Well ❑ Operations shutdown ❑ 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 0 Stratigraphic E] Service ❑ 219-034 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20800-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CRU-CD5-92 Will planned perforations require a spacing exception? Yes ❑ No ❑ 9. Property Designation (Lease Number): 10. Field/Pool(s): ASRC-NPR4, ASRC-NPR2, ASRC-NPR3, ASRC-NPR1 Colville River Unit, Alpine Oil Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 28,503' 7,325' 28,503' 7,325' 6500 none none Casing Length Size MD TVD Burst Collapse Structural Conductor 76' 20" 115' 115' Surface 2,149' 10-3/4" 2,246' 2,188' 5210 2470 Intermediate 12,254' 7-5/8" 12,293' 7,469 6890 4790 Production Liner 12,853' 4-1/2" 25,000' 7,325-1 7,7801 6,350 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): none n/a 3.5" L80 12,147 est Packers and SSSV Type: Baker Premier, No SSSV Packers and SSSV MD (ft) and TVD (ft): 12,100'MD est, 7452' TVD est 12. Attachments: Proposal Summary ❑ Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑� Service ❑ 14. Estimated Date for 10/13/2019 15. Well Status after proposed work: Commencing Operations: OIL E] 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. Authorized Name: Adam Klem Contact Name: Adam Klem Authorized Title: Completion Engineer Contact Email: adam.klem conoco hilli s.COm Contact Phone: 907-263-4529 to/3 / d C11 Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: q -LIG 3 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ 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 10-403 Revised 4!2017 Approved appli GRIGINAL. the date Of approval. Attachments in Duplicate CD5 — 92 Alpine A Producer Schematic 20" 94# H-40 Welded Conductor 10-3/4" 45.5# L-80 TXP/BTC Surface Casing ".1 1 2.813" X Nipple 7-518" Stage Cementer Cameo KBMG GLM 3'/�"x1" 3 '/Z" 9,3# EUE L-80 Production Tubing Cameo KBMG GLM 3%"x1" 7 5/8" 29.7/39# L-80 BTCM Intermediate Casing Cameo KSMG GL 3 '/z„ x 1 " SLB Downhole G Production Packer 2.813" XN Nipple ZXP Liner Top Packer and Hanger Upper Completion: Length 1) 4-'/" 12.6#/ft HYD563 Tubing (1 jts) XO to 3-'/z" EUE tubing 2) Shallow 2.813" X nipple profile 3) 3-'/" x 1" Camco KBMG GLM (xx°) w/ DV 7' 4) 3-'/2' x 1" Camco KBMG GLM (xx°) w/ DV 7' 4) 3-'/" x 1" Camco KBMG GLM (xx°) w/DCK2 7' pinned for 2500 psi casing to tbg shear 5) BHP Gauge, Encapsulated I -Wire 1.5' w/cannon clamps on every joint 6) 3-'/z" x 7-5/8" Baker Premier Packer 7) XN nipple 2.812" ID 1.5' 8) WLEG Lower Completion: 9) Flexlock Liner Hanger 37' XO 5" Hydril 521 Box X 4-'/" Hyd563 pin 10) 4'/", 12.6#/ft, L-80 H563 Liner w/ 12 ball actuated frac ports to 21,700' MD 1-0 ------------------------------------------ 4-'/2" 12.6# L-80 H563 Production Liner 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 CD5-92 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: 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 October 1, 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 15' day of October, 2019. (2t. -- Jaso r STATE OF ALASKA } THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 18' day of October, 2019, by Jason C. Parker. Notary Public, State of Alaska My Commission Expires: neaw�Ar STATE AMA NOTARY PUBLIC REBECCA SWENSEN Coinminion Ex rea Au . 2l 2420. ConocoPhiiiips Alaska October 1, 2019 To: Operator and Owners (shown on Exhibit 2) Jason C. Parker Senior Landman Land & Business Development ConocoPhillips Company 700 G Street Anchorage, AK 99501 Office: 907-265-6297 Fax: 907-263-4966 jason.c.parker@cop.com VIA. CERTIFIED MAIL Re: Notice of Operations pursuant to 20 AAC 25.283 (1) for CD5-92 Well AA -92344 (ASRC), ASRC-NPR1, 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") for the CD5�92 Well (the "Well"). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about October 1, 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, ASRC- NPR1, ASRC-NPR2, ASRC-NPR3, and ASRC-NPR4 as depicted on Exhibit 1 and has locations as follows: Location FNt_ FEL Township Range Section Meridian Surface 246' 2287' T11N R4E 18 Umiat Top Open Interval 4756' 3043' T1.1N ME 1 Umiat Bottomhole 497' 487' T12N R4E 27 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, JasonP rr cer Senior Landman Attachments: Exhibits 1 & 2 Exhibit 1 1 i 1 22 1 i i ASRC-NPR1CN N' NPR8 f F I 1 j i I 1 11NK.3E Pe- a TIIN2,3 (� i :3 ASI w ASRC-NPR3 „ 1 E is {! If, vl I l 1 16 ! AA087888 AA092347 1 � ----------------- i 1 ` ConocoPhillips ��0• �`} Alaska CDS-92 g, Lease analysis 0 0.2 0.4 0.6 0.8 1 Date:913012019 Miles SRC-AA0923 • Frac Points Half Mile Frac Port Buffer Q Half Mile Well Track Buffer Wells within Track Buffer Well Track Open Interval L� Alpine PA Unit Boundary CPAI Lease ASRC-NPR2 T 12NR4E T11 NR4F VR4 $ l CUS06 CD S!' -' ASRC-NOR4 NkIr 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 O Street, Suite ATO 1226 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attn: Misty Alexa, NS Development Manager Owner (Non-Ogerator9: 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 Ower: Kuukpik Corporation P.O. Box 89187 Nuiqsut, AK 99789-0187 Attn: Joe Nukapigak, President Section 2 — Plat 20 AAC 25.233 (a)(2) Plat 1: Wells within .5 miles r ADL388463 • Frac Points i I Half Mile Frac Port Buffer r Half Mile Well Track Buffer 23 2)4 Wells within Track Buffer Well Track r. !Ailpine PA — — _ — �� Open Interval Alpine PA I - Unit Boundary i ASRC-NPR1 LU M, ' CPA] Lease SRC-NPRB i N _N 3s^, i 31 I � i i r I i ASRC-NPR2 i, 171 'NR3E T12NR4� w . r 8� I. ,N!R4P I L �s lQ R ASRC-N,PR3 ASRC-NPR4 0 ;2 i f S 1 j t AA087888 AA092347 CD5 .rJ° ASRC NPR4 �I ConocoPhillips i�� $eco c Alaska i �5 w W m �. CDS-92 N Lease Analysis7 0 0.2 0.4 0.6 0.8 1 Date: 9/30/2019 Miles SRC-AA0923" Table 1: Wells within .5 miles API Well Name Well Type Status 501032073600 CD5-01 INJ ACTIVE 501032073700 CD5-02 SVC PA 501032073701 CD5-02A INJ ACTIVE 501032071800 CD5-03 PROD ACTIVE 501032071100 CD5-04 PROD ACTIVE 501032071200 CD5-05 PROD ACTIVE 501032074400 CD5-06 INJ ACTIVE 501032074460 CD5-061-1 INJ ACTIVE 501032073400 CD5-07 INJ ACTIVE 501032074100 CD5-08 INJ ACTIVE 501032072300 CD5-09 PROD ACTIVE 501032072400 CD5-10 PROD ACTIVE 501032072600 CD5-11 PROD ACTIVE 501032074200 CD5-12 INJ ACTIVE 501032075400 CD5-17 INJ ACTIVE 501032075460 CD5-171-1 INJ ACTIVE 501032075000 CD5-18 PROD ACTIVE 501032075060 CD5-181-1 PROD ACTIVE 501032076000 CD5-19 INJ ACTIVE 501032076060 CD5-19L1 INJ ACTIVE 501032075260 CD5-201-1 PROD ACTIVE 501032073800 CD5-21 PROD SUSP 501032075900 CD5-22 PROD ACTIVE 501032076100 CD5-23 INJ ACTIVE 501032079900 CD5-24 PROD ACTIVE 501032079960 CD5-241-1 PROD ACTIVE 501032079970 CD5-24L1PB1 EXPEND PA 501032076500 CD5-25 INJ ACTIVE 501032076560 CD5-251-1 INJ ACTIVE 501032071400 CD5-313 PROD ACTIVE 501032071470 CD5-313PB1 EXPEND PA 501032070700 CD5-314 PROD PA 501032075500 CD5-314X PROD ACTIVE 501032071600 CD5-315 INJ ACTIVE 501032071670 CD5-315PB1 EXPEND PA 501032075600 CD5-316 INJ ACTIVE 501032075670 CD5-316PB1 EXPEND PA 501032080300 CD5-98 PROD ACTIVE 501032080360 CD5-981-1 PROD ACTIVE 501032074800 CD5-99 PROD PA 501032074801 CD5-99A PROD ACTIVE 501032074861 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) Casing & Cement Assessments: 10 & %" casing cement pump report on 9/8/2019 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 mud. Full returns were seen throughout the job. The plug bumped at 1000 psi and the floats were checked and they held. The 7 & 5/8" casing cement report on 9/21/2019 shows that the job was pumped as designed, indicating competent cementing operations. The first stage cement job was pumped with 15.8ppg Class G tail. Full returns were seen throughout the job. The plug bumped at 950 psi, and the floats were checked and they held. The second stage cement job was pumped with 15.8ppg Class G tail. Full returns were seen throughout the job. The stage tool was confirmed 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 9/10/2019 the 10-3/4" casing was pressure tested to 3,500 psi for 30 mins. On 9/24/2019 the 7-5/8" casing was pressure tested to 3,500 psi for 30 mins. The 3.5" tubing will be pressure tested to 4,750 psi prior to frac'ing. The 7-5/8" casing will be pressure tested to 4,180 psi prior to frac'ing. AOGCC Rewired Pressures [ell in psi] Maximum Predicted Treating Pressure (MPTP) 6,500 Annulus pressure during frac 3,800 Annulus PRV setpoint during frac 3,900 7 5/8" Annulus pressure test 4,180 3 1/2" Tubing pressure Test 4,750 Nitrogen PRV 8,550 Highest pump trip 8,050 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 L-80 10,160 psi 10,535 psi Table 2: Wellbore pressure ratings Bleed! Tete Tale Tank Stimulation Surface Rig -Up :n 2_ aP F- m V SU L KarUJ, durnd U Pop -Off Tank UN z > M N 4' v C 0. H • 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 3Q00 psi • Frac pump trip pressure setting are staggered and set below main treating line PRV Pop -Ort Terk PUMPTfUCk Alpine 10K Frac Tree ---------- I P. lip -011 �3 lie U., I R N11 I w - 4 1+45 WK rRAC MME --------- ------ ----------- aid uf. N i v IK 4 No 10 ---------- I P. lip -011 �3 lie U., I R N11 I w - 4 1+45 WK rRAC MME --------- ------ ----------- aid uf. N i v IK 4 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 thinned to approximately 20-25ft 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 12256' MD/ -7394' TVDSS in the CD5-92. The estimated fracture gradient for the Alpine A sandstone is 12.5 ppg. The overlying confining zone consists of greater than 300' 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 11291'MD/ -7064' 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 shale interval ranges from — -7,424' TVDSS at the heel to — -7269' TVDSS at the toe of the well (no MD as the Kingak interval was not penetrated in the CD5-92 wellbore). SECTION 10 -- LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283(x)(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. Casino & Cement assessments for all wells that transect the confining zone: CDS-98: The 7 & 5/8" casing cement report on 6/23/2019 shows that the job was pumped as designed, indicating competent cementing operations. The first stage cement job was pumped with 15.8ppg Class G tail. The plug bumped at 1600 psi, and the floats were checked and they held. Partial losses were observed during cement operations, however the cement was logged and TOC was determined to be at 12,850' MD. CD5-23: The 7-5/8" casing cement pump report on 1/7/2018. Full returns were seen throughout the job. The cement job was pumped with 15.8 ppg Class G cement, displaced with 10.8 ppg WBM. The plug bumped at 1,100 psi and the floats held. I�J Ln in u m0 N wo C o m � m �a E o E m oo m o m m d N N c o - d o m a c a c o E CO E w £ E N a N u E x e N � a 0 .q m ti ro Y in m m � O _ - N a Q1 � a 0 � l0 � N N O F j K C O W w C L C d n O O ya 'O O O d G_ t � 0 On C m d E d v E _ O � F O d u o m a� 12 a E N o p CL 0 p N N e h O N Q a D a c O vii n n" a 0 c o H � H O d N C� V n N ri F W Q Z J N N Obi 3 V U 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 ten faults or fracture systems transect the Alpine A formation or enter the confining zone within one half mile radius of the wellbore trajectory for CD5-92. The only fault the CD5-92 wellpath intersected occurred at 13880' MD and had a throw of 3'. This fault was not interpreted in seismic. There were several small natural fracture systems encountered in the CD5-92 wellpath which have no interpretable offset: 16182' MD, 18087' MD, 18121' MD, 18993' MD, 19030' MD, 19102' MD, 24520' MD, 24700' MD. Small losses of drilling fluids were noted associated with the two fracture systems at 24520' MD and 24700' MD; these losses healed after —4 hours and are well beyond the final frac stage. There was one observed fault in the CD5-23 within the one half mile radius at 12,725' MD, with a throw of 6'. 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. Faults and Fractures observed in CD5-92 and CD5-23 Wellbores (Fractures identified by 0' vertical displacement): Well Name Depth NID (ft) Depth TVDSS (ft) Vertical Displacement(ft) Loss (bbls/hr) CD5-92 13880 -7392 3' 0 CD5-92 16182 -7372 0' 0 CD5-92 18087 -7360 0' 0 CD5-92 18121 -7360 0' 0 CD5-92 18993 -7338 0' 0 CD5-92 19030 -7336 0' 0 CD5-92 19102 -7333 0' 0 CD5-92 24520 -7278 0' 22* CD5-92 24700 -7277 0' 22* CD5-23 12725 -7423 6' 0 *Losses healed after —4hrs Plat 2: CD5-92 Fault Analysis 1 i ADL388463 • Frac Points i Half Mile Frac Port Buffer Half Mile Well Track Buffer 1 23 21 Fault in Frac Port Buffer ! ! Wells within Frac Port Buffer 1 j �--------------------------------- !Alpine PA Well Track 1 Open Interval Alpine PA ASRC-NPR1 M. Unit Boundary ! 2`GsQ 6 N CPA] Lease SRC-NPR8 I �� CN i I I • I i 1 1 I 1 34 _ - 36 i I ASRC-NPR2 1 I 1 +- -----yam T1 U-NR3E �:•... T i 2NR•TE i� T11 dP3- .._ . - - .. TIIN 4E LY 3 ASRC-NPR3 ASRC-NPR4 i j ' C" ! AA087888 AA092347 1 i { �.---.-.-----.---.1 CD_5 i I ! W'. 1$ 17 ASRC-NPR4 ;= ConocoPhillips I ~ p Alaska i CD5-92 Fault Analysis N 0 0.2 0.4 0.6 0.8 1 ASRC-AA092344 Date: 913012019 Miles . .:,�:.. i'„ -.:,.! ........._�.;. t'rw"t!^.�. frv'.vx ..-..:. F.. ;�J .h frl':•: If m.�_,-'i.?. R7�sa. S: r.8:-. �a .v :.. .`";�;.� SECTION 12 — PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) CD5-92 was completed in 2019 as a horizontal producer in the Alpine A formation. The well was completed with 3.5" tubing. In the A sand is a 4.5" liner with ball actuated sliding sleeves and pre perforated joints. We will establish injection and drop a ball which will shift a sleeve to close off the perforated joint section of the lateral. We will then pump the 1st 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. 12,694 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. 8. Bring up pumps and increase annulus pressure from 2,500 psi to 3,800 psi as the tubing pressures up. 9. Pump the Frac job by following attached HES schedule @ 25bpm with a maximum expected treating pressure of 6,500 psi. 10. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 11. Well is ready for Post Frac well prep for flowback (Slickline and possibly CTU). s� s $8$$8$8838$8$$$8888888$8$$$$ 8$$ 88888388$888$08$888$$ .i o' o do o d dd 6dd d0 odd d� d d� d d°7 d.'". 8 � ax` a :0a o.odo o 0 o d dd 66. 666 C;) 6 6 o 66 d cd 6 ate `R 10 o 1. 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'L 6iAYL-916t1� �. -u szeu • Lzetl DueSY Pw4V PueStl PweS•b j PueSV PuePY pueS-V _ lieNaiel Ele+�ful Llenlalul 91eAWRI SleNalul iPAfLIV1 __ Lle Nalul d LL�y $888$888$$$888888$8$88$$888888$8,8 8888$$$888888 m dddddddd 66666666 d 6 6 c2i6 6 6 6 66 dd. d d 6 6 .6'ziddd 6d6 u o _ 8 5 8 o aac;6d'd o 0000 ci d 0000 066d666eQoo�n6 o d o d o E c ddod , f m o d0 O 666 Eo d d o d d d e g c ti r^ 8$$$88$�� 8888 8$88888$$8$8$$$888$88$8888888888 c ti mg 3 F E oS SSr oo a o 'i onm i id ;4 ,o Sr E 8 neo° $^on"Fom$ti^oreoom8^ m$s om8^or<gE°8 � ........ 0 .............. 9 9 9 9 P 4 P 4 0 0 0 0 0 0 o a o .n. o d o s o o 8 `8, a o o R 0 0 9^ 0 0 o Q 0 0 9 R 0 0 9 4 o a 1 o 0 � 8�� oggs a�� s sas$o � ci S e 8 H g e o 8 N 8 n n a n g ry g n n n e o g n S n n B o 8 n 8 n M1 0 8 n 8 n n ,1p. ti o 8 ti m Y � a �n�n gnd�n25d"8rtsn �n�n'dan �n� ��4n-« _ ��mmm=arm z e 49) 4119Q �Q 4' '4 1_ 8v '3,$$ '. $ $ 8$$ � 3,F3�SSS 59��e g3�YeS �S�S�9 9JgI8S9 S�SSSS �nNoory _____= (333'333 333333 3333133 333333 333333. 333333 LL LL ¢'' LLWWULLu n s0:�u ss:S ccccco. �LLILL LL�LL ececec t =^m��9 a� 3999.93993�d999999=%993993j'a999399_ ^$d 1. A 4eG«a• eee �ass�dd a� eee qk eq e' eeeee2LL i'in 6;jli nnnnrinn �, R".. nu" E hz Am ma6 .6mmabd a aml dddd6dbd.. mfim E 2 A.-L� O P4CV 3° •Y LOBSL-86C9L� _ I -Y t•9mote, SCZ9L-ZCZ9to A° � •L LtSCt'OLi9.L8 j. -Y 09CZt-C9CZt� pueStl - YRNeOW PueStl 61enaaV l!!) ' RLwruaeW� Lt -s -V —q PW—" Y.:Ic�w.}uq — u cp 11 d Hydraulic Fracturing Fluid Product Component Information Disclosure rvachtt Chia 10/112019 Stale- Alaska Candy, Narrisan Be APINonoer. 6oto32.e00 NORTH SLOPE opevadnrName; Eaub INe0Nanderld Nondli er. C0692 Longf- • -%Uz 1-411hade; 70.31 Larrga.at Ptalec0on• NAD21 aE3iinffedeN. ProducWn7 X04 Tmavesa tWpO ll-M), 7427 TdalWrervokerse 633,164 Hydraulic Fracturing Fluid Composhio Chemical Ma4mum Abstract 8tOMMUm Ingredient Ingredient TWAVUma9-Suppfler purpose Ingredlents Service Coneentratlnnm Adddlve Concentratfonln IngMdMRt Alas Comments Company First Nem. Last Name Email Phone Number(CAS I% by mase{'" HF Flufd(%.by lbs 111) moa: •• Sea Water Operator Base Fluid Water 7732-18-6 .6.009 16.553224 4371078 Dense= 8.590 BE4 Hallburlan Bloekle Lillie] Below Daled Below MICROBIOCIDE 0 NA CL-22 UC Haabudon Crosslinkw I-sled Below Loted Below 0 NA CL-31 CROSBLINNER HalBlxlon Cmas6nker Luted Below 1Jsted Below 0 NA LOSURF-3000 Hallbutor Nan-ionic Surfactant Listed Below Llsted Below 0 NA M047 Haeiilds on pH Control Adolf. Listed Below Listed Below 0 NA 0 TIFLO-III DELAYED Halliburton Breaker Listed Below Listed Below RELEASE 0 NA BREAKER SP BREAKER Hallibunon Breaker Listed Below Listed Below 0 NA WG36 GELLING Holllbunon Gelling Agent Usted Below Listed Below AGENT 0 NA LVT-200 I Penne. Freeze Protect Usled Below Listed Below 0 NA Wanli Wanll21Y40 Prop panl Addeive Listed Below Listed Below 0 NA relents Listed Above Listed Above 1,2,47nmsth Ibero-c 9543E 1.009 0.00069% 40 2-Bmmw2-nN0-1,3• o ediol 5251-7 100.0.1. 0.,11130! 79 Denise Tuck, Halliburton, 3000 Aaylale polymer Proprietary 1.009 0.000959 % N. Sam Houston Denise.Tuok� Hallloudon Denise Tuck HallbunOn.w 281-871,M6, Pkwy E., Houdon, 77032,281- in 87142W Ammonlum persullate 7727-540 1u0.oul 0.01039% IO50 Denise. Some IS Proprietary 50.008 0.,156996 3255 Halliburlan DeniEe Tuck Hallibun.n.o.an.ca 281471-8226 Corundum 1302-745 65,001 L2.636058 721500 C stallkle silica, uarU 1480840.7 30.004 0.005619 321 Denise.Tuck® C-acryteresfn Proplamry n.r s 1.005529 315 Hallburlon Denbo Tuek Hellbundore, 2BI-871-6226 Ethanol 64174 60.109 0.141529 2371 Guar m 9000304 100.00% 0.430059 13136 Hea aromatic tmleum naphtha 64742-945 30.008 0.020769 1185 H drohress d Dlellllate, lig64742474 Wo.0Gt O. %0144. 17212 Mullile 1302.934 45.009 a.,'e038 4905W Ne hdlalane 91-203 -- uu• 1.003469 198 Denise.TuckQ oxylated phenolic resin Proprietary 30.009 0.1216991582 Hallbuntn Denise Tuck Halllbunon.co 2813714126 I on Pdy(oxy-1,226wr di alpha-(4 nerylphenyl)-ge4rydmxy-, 127057474 5.11n: 0.103464 19B brmmhed Polasslum 1-1. 590.29-4 604009 0.0569.9 3255 PoieE6lumh @odds 1310.58-3 S.OUM 0.-05, 126 Polasslum meorborate 13709.949 6".003 0.026468 1511 Saloum carborgirnati cenulas 9004324 I. oot 0.000459 55 Sadi-lilwide 7647-145 J.u09 3.191249 182217 Sod'um cella!, 2836-324 3.0.11 1.00u9'A 55 Sodlumh dradde 1310.73-2 0.009 0.0171]9 set Soll-pionoulfids 777527-1 100.00V 0.00021E 12 6adium Sulfate 7757424 0.108 0.100014 IT Wstr 7732-165 100.0ot 0.11_199 6407 Total Water Volume sources may include fresh water, produced water, ancvor recycled water •' Information Is based on the maximum potential for concentration and thus the total may be over 100% _ Note, For Feld 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, the Operator is not responsible for Inaccurate and/or incomplete informatlom Any questions regarding the content of the MSDS should be directed to the supplier who provided it. The Occupational Safety and Health Administrations (OSHA) regulations govern the criteria for the dsdosure of this informalion. Please note that Federal Law protects "proprietary",'trade setter, and "ccnadentiel business inforipation and the criteda for how this Information is reported on an MSDS is subiect to 29 CFR 1910.12000) and Appendix D_ N O U i � - 00 00 00 00 00 00 00 00 N N N N N N N N N N N +, O O O O O O O O O O O W � O O O O O O O O O O O t dJ- -U dU d- L LL 0/ 0 O 0 0 O OH 0 MO /0 MO r 4) O d O 00 tet' r-, m M O N 0 r� Ln H m M Q0 r- r- r- O O O m m M m M rn m m d- CL V ® O r- d' N m (.0 m V -r 00 Ln N O m r, r -i qt w N to m m ro mr.-q M t�0 w O m Ln r-- O N .L r� r—I O rn 00 r- (Z Ln Ln d' O N N F O O O O O O O O O O O —0 0 0 0 0 0 0 0 0 0 0 -a O O O O O O O O O O O _- o o 0' 0 o 0T 0T, 0' 0' o/ff� 0� / / / m c -i N M Ln QO r� 00 m 1-1 w- � V) O + v 4- a, v 4- v) U aj v co tw ca c N L CO c a� v c � O a1 U � � S v a 0 Q O L- 0 0 (U N m Ln 0 c O E N N Y a) O O 4i, Ln Ln L c c v a W - o O o E � � v O o 0 Q E v N V) E - m EQC O ._ � � O c a }, M c O.+, a o E °1 C — U v ai c v v a, � Qj i C CL O a1 O L O E > U L CO OO 1 N N dl D U r1 4 ' Ln p vLn cu 41 a E _ r� Z3 +� N U U m O p Ll N C (O O O a) C: U O Q O L O k c L ro N C O m E L N 14- ± 47 p a' Ln N L C O _ � U -O p O O E _ � O p- nD Ln O +-1 � O O- U L E L fl- at Lo vi C V1 C � Q O _ N C: p O CB O 4- C) 0 E U p aJ aJ QJ N QJ Q aJ 0 � Qi 0- o O E vnaJ u U aaJ ^ L CO v LLSF,, 00 N o 00 N 4- = O O LL 0 M Y� a� :^4iN CL r 3.. 0 MO 00 O 00 C v o o C Ln c:) r - N -0 O O O O ® 0) CY) CSA N M � r1 4 ' Ln p vLn cu 41 a E _ r� Z3 +� N U U m O p Ll N C (O O O a) C: U O Q O L O k c L ro N C O m E L N 14- ± 47 p a' Ln N L C O _ � U -O p O O E _ � O p- nD Ln O +-1 � O O- U L E L fl- at Lo vi C V1 C � Q O _ N C: p O CB O 4- C) 0 E U p aJ aJ QJ N QJ Q aJ 0 � Qi 0- o O E vnaJ u U aaJ ^ L CO SECTION 13 — POST-FRACTURE WELLBORE CLEANUP AND FLM® 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 C®1-01 disposal well until they are clean enough for production.)