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Home My WebLink About2019-07-29_319-353STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n AAc 25 2Rn ,�8 Y.Mr 6imr % Gi llam JUL 2 5 2019 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑.r Repair Well ❑ ps a idns 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 5tratigraphic ❑ Service ❑ 219-058 3. Address: 6. API Number: P. O. Box 100360, Anchorage, Alaska 99510 50-103-20802-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? KRU 3G-28 Will planned perforations require a spacing exception? Yes ❑ No 0 9. Property Designation (Lease Number): 10. Field/Pool(s): ADL025546, ADL025547, ADL025549 I KU aruk River Field, KU aruk River Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psl): Plugs (MD): Junk (MD): 19,557 5,881 19,557 5,881 7,550 Casing Length Size MD TVD Burst Collapse Structural Conductor 89, 20" 128' 128' Surface 3,356' 10 3/4" 3,394' 3,020' Intermediate 11,596, 7 518" 11,633' 5864' Production Liner 8,091' 41/2" 19.550' 15,881' Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3 1/2" L80 est 11,500' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): Baker Premier Packer, No SSSV est 10,729' MD, 5,684' TVD 12. Attachments: Proposal Summary ❑ Wellbore schematic 0 13. Weil Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 8/5/2019 OIL 0 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 Scott Pessetto, 907-263-4523 Email SCott.t. essettO ConocoPhiiii S.com Printed Name Scott Pessetto Title Completions Engineer NJ L-1 2a1-1 Signature Phone 907-263-4523 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: r jJ 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: Form 10-403 Revised 1112015 Approved applica a I i tNot Submit Form and m the date of approval. Attachments in Duplicate 3G-28 Wellbore Schematic Grassroots Horizontal A -Sand Producer 6-3/4" Production h 7-5/8" x 5-32" Lock Liner Hanger @ 11,459' MD / 5,895' ND ConocoPhillips Updated: 7/25/19 by S. Pessetto Packer sleeves installed Production Liner: 4-1/2" 12.6# L- 80 Hydril 563 @ 19,550' MD / 5,881' ND 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 Paul K. Wharton Request of ConocoPhIllips Alaska, Inc. for ) Hydraulic fracturing for the 3G-28 Well ) under the Provisions of 20AAC 25,280 STATE OF ALASKA THIRD JUDICIAL DISTRICT i §§ Paul K. Wharton, being first duly sworn, upon oath, deposes and states as follows: 1. My name is Paul K. Wharton, and I have personal knowledge of the matters set forth herein. 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 or about July 24, 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 24th day of July, 2019. /''1 STATE OF ALASKA Paul K. Wharton ) THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 24th day of July, 2019, by Paul K. Wharton. -7A - Notary Public, State of Alaska My Commission Expires: e---- -- SPATS OF ALASKA NOTARY PUBLIC RIEBECCA SWJrNSEN M COMMk fon Ex TWA . U, iD20 ConocoPsphilli Alaska Paul K. Wharton Staff Landman P.O. Box 100360 — Suite ATO 1482 Anchorage, Alaska 99510-0360 Phone (907) 263-4076 Paul. K.Wharton@oonocophillips.com To: Operator and Owners (shown on Exhibit 2) Re: Notice pursuant to 20 AAC 25.283 (1) 3G-28 Well Kuparuk River Unit, Alaska ADL 25646, ADL 25547; ADL 25548; ADL 25549; ADL 392374; and ADL 380107 Dear Sirs: ConocoPhillips Alaska, Inc. ("CPA]") as Operator and on behalf of the Kuparuk River Unit ("KRU") 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 3G-28 Well (the "Well'). The Application will be filed with the Alaska Oil and Gas Conservation Commission ("AOGCC") on or about July 24, 2019. This Notice is being provided pursuant to 20 AAC 25.283. The Well has been drilled as a directional well as shown on the attached plat (Exhibit 1). 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 to you. If you require any additional information, please contact the undersigned. Very truly yours, Paul Wharton Staff Landman cc: Scott Pessetto Rebecca Swensen 3G-28 Hydraulic Fracturing Notice Letter July 24, 2019 Page 2 Exhibit 1 3G-28 Hydraulic Fracturing Notice Letter July 24, 2019 Page 3 Exhibit 2 Mineral Owners: Operator: ConocoPhillips Alaska, Inc. 700 G Street, Suite ATO 1220 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attention: Misty Alexa, Manager NS Development Non -Operators: ConocoPhillips Alaska II, Inc. 700 G Street, Suite ATO 1220 (Zip 99501) P.O. Box 100360 Anchorage, AK 99510-0360 Attention: Misty Alexa, Manager NS Development Chevron U.S.A. Inc. 1400 Smith Street Room 40116 Houston, TX 77002 310 K Street, Suite 406 Attention: Dave White ExxonMobii Alaska Production Inc. 3700 Centerpoint, Suite 600 P. O. Box 196601(Zip for PO Box 99519) Anchorage, AK 99503 (Street zip) Attention: Ms. Lisa Cross Surface Owners: State of Alaska Department of Natural Resources Division of Oil and Gas 550 West 7t" Avenue, Suite 1100 Anchorage, AK 99501-3560 Attention: Director Section 2 - Plat 20 AAC 25.283 (a)(2) Plat 1: Wells within 0.5 miles Table 1: Wells within .5 miles Wells within 1/2 mile huffier of well track In Frac Well Point API WELL NAME Status Type Radius 5UIU3ZU146UU 3G-UZ ACTIVE PROD 501032024500 3G-03 ACTIVE PROD 501032014300 3G-04 PA PROD 501032014301 3G-04A ACTIVE PROD 501032014360 3G-04AL1 ACTIVE PROD 501032013200 3G-05 ACTIVE PROD 501032013000 3G-06 ACTIVE PROD 501032012700 3G-07 PA PROD 501032012701 3G-07A ACTIVE PROD 501032012800 3G-08 ACTIVE PROD 501032012900 3G-09 ACTIVE PROD 501032013400 3G-10 ACTIVE INJ 501032013300 3G-11 ACTIVE INJ 501032013100 3G-12 ACTIVE INJ 501032013700 3G-13 ACTIVE INJ 501032013800 3G-14 PA PROD 501032013801 3G-14A ACTIVE PROD 501032013900 3G-15 ACTIVE INJ 501032013500 3G-16 ACTIVE INJ 501032014000 3G-17 ACTIVE PROD 501032014200 3G-18 ACTIVE PROD 501032013600 3G-19 PA PROD 501032013601 3G-19A PA PROD 501032014100 3G-20 ACTIVE INJ 501032014800 3G-21 PA PROD 501032014801 3G-21A ACTIVE PROD 501032014860 3G-21AL1 ACTIVE PROD 501032014861 3G-21AL1-01 ACTIVE PROD 501032014700 3G-22 PA PROD 501032014701 3G-22A ACTIVE PROD 501032014760 3G-22AL1 ACTIVE PROD 501032014761 3G-22AL2 ACTIVE PROD 501032014762 3G-22AL2-01 ACTIVE PROD 501032014770 3G-22AL2PB1 PA EXPEND 501032014400 3G-23 ACTIVE INJ 501032014500 3G-24 ACTIVE INJ 501032024400 3G-25 SUSP PROD 501032024600 3G-25X ACTIVE PROD 501032030300 3G-26 ACTIVE PROD 501032080100 3G-27 ACTIVE PROD yes yes yes yes yes yes yes 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. None as per Aquifer Exemption Title 40 CFR 147.102(b)(3), "That portions of the aquifers on the North Slope described by a'/ mile area beyond and lying directly below the Kuparuk River Unit oil and gas producing field" 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 & s/4" casing cement pump report on 6/14/2019 shows that the original job pumped as designed but did not get cement returns to surface. The cement job was pumped with 11 ppg DeepCrete lead and 12.Oppg tail cement, displaced with 9.6ppg mud. The plug bumped at 500 psi and held 1000psi for five minutes. The floats were checked and they held. Due to no cement returns to surface a top job of 28.5 barrels of 11 ppg Deeperete was pumped after tagging top of cement at 220'MD. The combination of holding floats, 1000psi held, and a top job indicate competent cementing operations. The 7 & 518" casing cement report on 6/29/2019 shows that the job was pumped as designed, indicating competent cementing operations. The first stage cement job was pumped with 15.8ppg class G cement. Circulation was temporarily lost (packed off annulus) during displacement of cement with 11 ppg I_SND but was re-established prior to cement leaving the shoe. The plug bumped at 804 psi, and the floats were checked and they held. Casing was pressured up to 1500psi and held for five minutes. Cement log results were interpreted showing cement top at 7,251' MD (4,477' TVD). The cement top is 898' TVD above the top of the Moraine interval. 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 6/16/2019 the 10-3/4" casing was pressure tested to 3,500 psi for 30 mins. On 7/23/2019 the 7-518" casing was pressure tested to 3,850 psi for 15 mins. The 3.5 tubing will be pressure tested to 4,700 psi prior to frac'ing. The 7-518" casing will be pressure tested to 3,850 psi prior to frac'ing. AOGCC Required Pressures [all in psi] Maximum Predicted Treating Pressure (MPTP) 7,550 Annulus pressure during frac 3,500 Annulus PRV setpoint during frac 3,600 7 518" Annulus pressure test 3,850 3 112" Tubing pressure Test 4,700 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 & Y4" 45.5 L-80 2,090 psi 3,580 psi 7 & 518" 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 10,530 psi Table 2: Wellbore pressure ratings 9re•G (Tatra iBdeFarfi t•a T..t PW%—, Frer Rimp Fi�LF�'Jrx Stimulation Surface Rig -Up 4 1 12 6:Tz U I • 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 3600 psi • Frac pump trip pressure setting are staggered and set below main treating line PRV rz 4; Ott f 0* R ,np TO* 1-;a:PWV R=Funp ftae Punp Kuparuk 10K Frac Tree 4" ll;x''alto r Tree. Cap - ?9.5' r lox VMI re + $" "s ox s aR f wv - .R'2:3.. onocop +h111ips ME Sits 2,S- IN,' Irac TreL4 Waiat d entire #tea is -6 n %r V I.ONaRWO 7--Irw -0Bfi 6s Tree Gap-295016s VCAMERON 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 Kuparuk interval is approximately 80' TVD thick at the heel of the lateral, thinning to -70' TVD at the toe. The Kuparuk interval thickness is derived from the partial penetration in the 3G-28 lateral and the partial penetration in the 3G-27 lateral in addition to offset well thicknesses in 3G and 3S drill sites. The Kuparuk Interval is composed of medium and fine-grained sandstones, siltstones and shale interbeds. The estimated fracture gradient for the Kuparuk interval is 13.1 ppg. Top Kuparuk was penetrated at 11,615' MD/-5,771' TVDSS. The overlying confining zone consists of approximately 300' TVD of Lower Kalubik, Upper Kalubik and HRZ mudstones. The fracture gradient for each of these zones is estimated to be 16 ppg. Top HRZ was encountered at 10,325' MD / -5,462 TVDSS. The underlying confinement zone consists of greater than 500' TVD of mudstones comprising the Miluveach Shale. The estimated fracture gradient for the Miluveach Shale is 15.5 ppg with fracture gradient increasing with depth. The Top Miluveach was not encountered in either the 3G-28 lateral or the recently drilled 3G-27 lateral. Based on offset thicknesses, the top Miluveach is projected to be at 5850' TVDSS. 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: 3G-22 and 3G-22A: The 7" casing cement report on 10/30/1990 reported full returns throughout job. The cement job was pumped with 39 barrels of 15.8ppg Class G cement and displaced with 370 barrels of 10.4 ppg brine. Plug was bumped to 3500psi, floats held. 3G-27: The 7-5/8"" casing cement report on 5/7/2019 reported full returns throughout job. The cement job was pumped with 231 barrels of 15.8ppg Class G cement and displaced with 430 barrels of 11.2 ppg LSND mud. Plug was bumped to 1,070psi and floats held. � o � ! $� ! 2 § k } k ! � 2 � ® § /° e a / § a a k_ % k% §�; ) ! �§ ! § \2 kv " / $ j \ ]� \$ j § ; �k 9 � ` 7 � 2 9 £ ; B " 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 four faults or fracture systems transect the Kuparuk formation or enter the confining zone within one half mile radius of the wellbore trajectory for 3G-28. The first fault was interpreted from seismic data prior to drilling and confirmed with log data while drilling at—11,430' in the tower Kalubik (fault throw of 24'). The second fault was interpreted from seismic data prior to drilling and confirmed with log data while drilling at 14,630' MD (fault throw of 8'). The third fault was mapped with seismic data and intersected with the 3G-27 offset horizontal wellbore and confirmed with log data while drilling at 17,215' MD (fault throw of 20'). There is an additional fault with a down to the east throw of 10' that is located 760' from the TD of the 3G-28 lateral. 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. Maximum principle stress orientation in the area for the Kuparuk interval is N30W to N15W and hydraulic fractures are expected to propagate at an oblique angle 30 - 40 degrees to the drilled 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. Well Depth Depth VerticalLoss Name MD (ft) TVDSS (ft) Displacement (bbis/hr) (ft) 3G-28 11,430 5744 20 None 3G-28 14,612 5802 12 None 3G-28 17,212 5819 20 None 3G-28 19,300 5863 5 None 760' west of 3G-28 N/A N/A 10, N/A TD Plat 2: 3G-28 Fault Analysis SECTION 12 - PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283(a)(12) 3G-28 was completed in 2019 as a horizontal producer in the Kuparuk A and C formation. The well was completed with a 3.5" tubing upper completion and 4.5" liner with ball actuated sliding sleeves lower completion. The first stage will be pumped through a Baker Alpha Sleeve. After the 1 st stage we will drop a ball to shift open the 21 stage sleeve and isolate the first stage. 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: (Kuparuk A/C 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 bbis 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 3,500 psi as the tubing pressures up. 9. Pump the 310 bbi breakdown stage (35# Hybor G) according to the attached excel HES pump schedule. Bring pumps up to maximum rate of 30 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 @ 30bpm with a maximum expected treating pressure of 7,550 psi. 12. RDMO HES Equipment. Freeze Protect the tubing and wellhead if not able to complete following the flush. 13. 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A /C/ k o R 0 0 k k k k m u 0 \ CD/ R t % 40 U)(_ �: @ ip ,0 " o V 2 E 7 @. 7 m q w § § rq : E R 2 � � . SECTION 13 — POST -FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283(a)(13) Flowback will be initiated through a de -sander unit until the fluids clean up at which time it will be turned over to production.