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Home My WebLink About224-1601. Type of Request: Abandon Plug Perforations Fracture Stimulate 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: Capstring, N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,775' N/A Casing Collapse Structural Conductor Surface Intermediate 5,410psi Production Liner 10,540psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng jerry.lau@hilcorp.com 907-564-5280 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Jerry Lau, Operations Engineer AOGCC USE ONLY 10,160psi Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 C061589 224-160 50-231-20032-01-00 Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 3,630' 1,157' Size 117' 7"3,822' 1,157' MD 3-1/2" See Attached Schematic 7,240psi 117' 3,662' 117' 1,157' January 29, 2026 9,773'6,164' Tieback 3-1/2" 9,561' Perforation Depth MD (ft): 3,823' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Happy Valley B (HVB) 13ACO 821 Same ~3089 psi 9,575' Length LTP; N/A 3,621' MD/3,464' TVD; N/A, N/A 9,563' 9,575' 9,363' Deep Creek Unit Happy Valley, Beluga-Tyonek Gas 20" 9-5/8" See Attached Schematic m n P s 66 t N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 326-054 By Grace Chistianson at 9:16 am, Jan 26, 2026 Obtain separate approval from AOGCC before setting any plugs in the well. BJM 26Jan26 10-404 A.Dewhurst 26JAN26 DSR-1/27/26JLC 1/27/2026 01/28/26 Well Prognosis Well Name: HVB-13A API Number: 50-231-20032-01-00 Current Status: Online Gas Producer Permit to Drill Number: 224-160 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Jerry Lau (907) 564-5280 (O) (907) 360-6233 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 3997 psi @ 9084 TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 3089 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: .77 psi/ft using 14.85 ppg EMW FIT at the 7 intermediate casing shoe Shallowest Allowable Perf TVD: MPSP/(0.77-0.1) = 3089 psi / 0.67 = 4610 TVD Top of Applicable Gas Pool: 2236 MD/2106 TVD (HV Beluga-Tyonek) Well Status: Online Gas Producer Brief Well Summary HVB-13A was drilled/sidetracked in February 2025 and originally completed in the T-10 through T-100 Tyonek sands. Production has been steady over the last year but additional Tyonek pay has been identified. The objective of this sundry is to add T-1 through T-17 perforations to increase rate. Notes Regarding Wellbore Condition Inclination o Max inclination = 34.9° at 1200 MD o Max DLS: 6.67° @ 388 MD Min ID o 2.91 4'' Locating Bullet Seal Assembly at 3619 MD Recent Tags o 4/18/25 EL perforated multiple intervals from T-10 through T-100 w/ 2-3/8 guns No issues or tags while perforating Pre-Sundry Steps: 1. MIRU SL 2. PT lubricator to 250 psi low / 3,500 psi high 3. D&T to TD to find updated tag a. Note fluid level if seen 4. RDMO Procedure: 1. MIRU E-line and pressure control equipment 2. PT lubricator to 250 psi low /3,500 psi high 3. RIH and perforate T1 T17 sands from bottom up: Zone Top MD Btm MD Top TVD Btm TVD Footage T1 5,947' 5,967' 5,751' 5,771' 20' T3 6,072' 6,078' 5,876' 5,882' 6' T5 6,109' 6,115' 5,913' 5,918' 6' Well Prognosis T6 6,244' 6,258' 6,047' 6,061' 14' T7 6,338' 6,344' 6,140' 6,146' 6' T7 6,387' 6,397' 6,189' 6,199' 10' T17 6,822' 6,853' 6,621' 6,652' 31' T17 6,855' 6,896' 6,621' 6,695' 41' a. Proposed perfs are also shown on the proposed schematic in red font b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation c. Use Gamma/CCL to correlate d. Record Tubing pressures before and after each perforating run at 5 min, 10 min, and 15 min intervals post perf shot (if using switched guns, wait 10 min between shots) e. Pending well production, all perf intervals may not be completed f. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Patch will most likely be used to avoid shutting off current production g. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 4. RDMO a. If necessary, run cap string to aid with water production if encountered post perforating. Attachments: 1. Current Schematic 2. Proposed Schematic 3. Standard Well Procedure N2 Operations _____________________________________________________________________________________ Updated by CJD 5-16-25 Schematic Deep Creek Unit B Pad Well: HVB-13A PTD: 224-160 API: 50-231-20032-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn Top Btm 20"Conductor 109 / X-56 / Weld Surface 117' 9-5/8'Surface 40 /L-80/ BTC Surface 1,157 Open Hole Whipstock set @ 1,200 MD 7Intermediate 26 / L-80 / BTC Surface 3,823 3-1/2Prod liner 9.2 / L-80 / Hyd 563 3,6219,773 3-1/2Tieback 9.2 / L-80 / EUE 8RD Surf 3,630 JEWELRY DETAIL No Depth Item 1/2 3,621Liner Top Packer / Seal Assy. 3 9,575CIBP 2.75 OPEN HOLE / CEMENT DETAIL 8-1/2Spacer-60 bbl 10.5 ppg / lead- 101 bbl 12 ppg lead/Tail- 61 bbl 15.3 ppg 6-1/8Spacer-30 bbl 10.5 ppg / lead- 186 bbl 12 ppg lead/Tail- 36 bbl 15.3 ppg PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Date Status T10 6,523'6,533'6,3246,33410'4/18/25 Open T10 6,609'6,623'6,4106,42414'4/18/25 Open T10A 6,649'6,655'6,4496,4556'4/18/25 Open T32 7,417'7,427'7,2147,22410'4/18/25 Open T40 7,785'7,816'7,5797,61031'4/18/25 Open T48 8,140'8,160'7,9327,95220'4/18/25 Open T65 8,656'8,662'8,4458,4516'4/18/25 Open T80 8,924'8,938'8,7138,727144/3/25 Open T90 9,115' 9,129'8,904 8,91814' 4/3/25 Open T91 9,152' 9,166'8,941 8,95514' 4/3/25 Open T98 9,225' 9,231'9,014 9,0206' 4/3/25 Open T99 9,242 9,252 9,031 9,041 104/3/25 Open T100 9,295' 9,305'9,084 9,09310' 4/3/25 Open T120 9,617' 9,637'9,405 9,42520' 4/2/25 Isolated _____________________________________________________________________________________ Updated by SRW 1-14-26 Proposed Schematic Deep Creek Unit B Pad Well: HVB-13A PTD: 224-160 API: 50-231-20032-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn Top Btm 20"Conductor 109 / X-56 / Weld Surface 117' 9-5/8'Surface 40 /L-80/ BTC Surface 1,157 Open Hole Whipstock set @ 1,200 MD 7Intermediate 26 / L-80 / BTC Surface 3,823 3-1/2Prod liner 9.2 / L-80 / Hyd 563 3,6219,773 3-1/2Tieback 9.2 / L-80 / EUE 8RD Surf 3,630 JEWELRY DETAIL No Depth ID Item 1/2 3,6212.91Liner Top Packer / Seal Assy. 3 9,575N/A CIBP 2.75 OPEN HOLE / CEMENT DETAIL 8-1/2Spacer-60 bbl 10.5 ppg / lead- 101 bbl 12 ppg lead/Tail- 61 bbl 15.3 ppg 6-1/8Spacer-30 bbl 10.5 ppg / lead- 186 bbl 12 ppg lead/Tail- 36 bbl 15.3 ppg PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Date Status T1 5,947'5,967'5,751'5,771'20'TBD Proposed T3 6,072'6,078'5,876'5,882'6'TBD Proposed T5 6,109'6,115'5,913'5,918'6'TBD Proposed T6 6,244'6,258'6,047'6,061'14'TBD Proposed T7 6,338'6,344'6,140'6,146'6'TBD Proposed T7 6,387'6,397'6,189'6,199'10'TBD Proposed T10 6,523'6,533'6,3246,33410'4/18/25 Open T10 6,609'6,623'6,4106,42414'4/18/25 Open T10A 6,649' 6,655'6,449 6,4556' 4/18/25 Open T17 6,822' 6,853' 6,621' 6,652' 31' TBD Proposed T17 6,855' 6,896' 6,621' 6,695' 41' TBD Proposed T32 7,417' 7,427'7,214 7,22410' 4/18/25 Open T40 7,785' 7,816'7,579 7,61031' 4/18/25 Open T48 8,140' 8,160'7,932 7,95220' 4/18/25 Open T65 8,656' 8,662'8,445 8,4516' 4/18/25 Open T80 8,924' 8,938'8,713 8,727 144/3/25 Open T90 9,115' 9,129'8,904 8,91814' 4/3/25 Open T91 9,152' 9,166'8,941 8,95514' 4/3/25 Open T98 9,225' 9,231'9,014 9,0206' 4/3/25 Open T99 9,242 9,252 9,031 9,041 104/3/25 Open T100 9,295' 9,305'9,084 9,09310' 4/3/25 Open T120 9,617' 9,637'9,405 9,42520' 4/2/25 Isolated STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 2 3 1 - 2 0 0 3 2 - 0 1 - 0 0 We l l N a m e / N o . H A P P Y V A L L E Y B - 1 3 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 4/ 2 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 6 0 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 97 7 5 TV D 95 6 3 Cu r r e n t S t a t u s 1- G A S 11 / 1 7 / 2 0 2 5 UI C No We l l L o g I n f o r m a t i o n : Di g i t a l Me d / F r m t Re c e i v e d St a r t S t o p OH / CH Co m m e n t s Lo g Me d i a Ru n No El e c t r Da t a s e t Nu m b e r Na m e In t e r v a l Li s t o f L o g s O b t a i n e d : CB L 3 - 1 6 - 2 5 , P e r f a n d G P T l o g s , L W D ( D G R , P W D , A D R , A L D , C T N , D D S R , P C G ) No No Ye s Mu d L o g S a m p l e s D i r e c t i o n a l S u r v e y RE Q U I R E D I N F O R M A T I O N (f r o m M a s t e r W e l l D a t a / L o g s ) DA T A I N F O R M A T I O N Lo g / Da t a Ty p e Lo g Sc a l e DF 3/ 1 4 / 2 0 2 5 12 1 3 9 7 7 4 E l e c t r o n i c D a t a S e t , F i l e n a m e : H V B - 1 3 A L W D Fi n a l . l a s 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l M D . c g m 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l T V D . c g m 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A - D e f i n i t i v e S u r v e y Re p o r t . p d f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A - F i n a l S u r v e y s . x l s x 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A D S R _ P l a n V i e w . p d f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A D S R _ V s e c V i e w . p d f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A _ D S R - G I S . t x t 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A _ D S R . t x t 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l M D . e m f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l T V D . e m f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l M D . p d f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l T V D . p d f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l M D . t i f 40 2 1 4 ED Di g i t a l D a t a DF 3/ 1 4 / 2 0 2 5 E l e c t r o n i c F i l e : H V B - 1 3 A L W D F i n a l T V D . t i f 40 2 1 4 ED Di g i t a l D a t a DF 4/ 2 8 / 2 0 2 5 96 1 5 3 5 4 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : H V B 1 3 A S C B L MA I N 3 - 1 6 - 2 0 2 5 . l a s 40 3 3 8 ED Di g i t a l D a t a DF 4/ 2 8 / 2 0 2 5 E l e c t r o n i c F i l e : H V B 1 3 A S C B L F I N A L 3 - 1 6 - 20 2 5 . p d f 40 3 3 8 ED Di g i t a l D a t a DF 4/ 2 8 / 2 0 2 5 E l e c t r o n i c F i l e : H V B 1 3 A S C B L M A I N 3 - 1 6 - 20 2 5 . d l i s 40 3 3 8 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 1 o f 2 HV B - 1 3 A L W D Fi n al. l as DA T A S U B M I T T A L C O M P L I A N C E R E P O R T AP I N o . 5 0 - 2 3 1 - 2 0 0 3 2 - 0 1 - 0 0 We l l N a m e / N o . H A P P Y V A L L E Y B - 1 3 A Co m p l e t i o n S t a t u s 1- G A S Co m p l e t i o n D a t e 4/ 2 / 2 0 2 5 Pe r m i t t o D r i l l 22 4 1 6 0 0 Op e r a t o r H i l c o r p A l a s k a , L L C MD 97 7 5 TV D 95 6 3 Cu r r e n t S t a t u s 1- G A S 11 / 1 7 / 2 0 2 5 UI C No We l l C o r e s / S a m p l e s I n f o r m a t i o n : Re c e i v e d St a r t S t o p C o m m e n t s To t a l Bo x e s Sa m p l e Se t Nu m b e r Na m e In t e r v a l IN F O R M A T I O N R E C E I V E D Co m p l e t i o n R e p o r t Pr o d u c t i o n T e s t I n f o r m a t i o n Ge o l o g i c M a r k e r s / T o p s Y Y / N A Y Co m m e n t s : Co m p l i a n c e R e v i e w e d B y : Da t e : Mu d L o g s , I m a g e F i l e s , D i g i t a l D a t a Co m p o s i t e L o g s , I m a g e , D a t a F i l e s Cu t t i n g s S a m p l e s Y / N A Y Y / N A Di r e c t i o n a l / I n c l i n a t i o n D a t a Me c h a n i c a l I n t e g r i t y T e s t I n f o r m a t i o n Da i l y O p e r a t i o n s S u m m a r y Y Y / N A Y Co r e C h i p s Co r e P h o t o g r a p h s La b o r a t o r y A n a l y s e s Y / N A Y / N A Y / N A CO M P L I A N C E H I S T O R Y Da t e C o m m e n t s De s c r i p t i o n Co m p l e t i o n D a t e : 4/ 2 / 2 0 2 5 Re l e a s e D a t e : 2 / 4 / 2 0 2 5 DF 5/ 2 9 / 2 0 2 5 96 1 5 3 5 4 6 E l e c t r o n i c D a t a S e t , F i l e n a m e : H V B 1 3 A S C B L MA I N 3 - 1 6 - 2 0 2 5 . l a s 40 4 9 0 ED Di g i t a l D a t a DF 5/ 2 9 / 2 0 2 5 E l e c t r o n i c F i l e : H V B 1 3 A S C B L F I N A L 3 - 1 6 - 20 2 5 . p d f 40 4 9 0 ED Di g i t a l D a t a DF 5/ 2 9 / 2 0 2 5 E l e c t r o n i c F i l e : H V B 1 3 A S C B L M A I N 3 - 1 6 - 20 2 5 . d l i s 40 4 9 0 ED Di g i t a l D a t a Mo n d a y , N o v e m b e r 1 7 , 2 0 2 5 AO G C C Pa g e 2 o f 2 11 / 2 5 / 2 0 2 5 M. G u h l Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -08'00' 1a. Well Status:Oil SPLUG Other Abandoned Suspended 1b. Well Class: 20AAC 25.105 20AAC 25.110 Development Exploratory GINJ WINJ WDSPL No. of Completions: _1 Service Stratigraphic Test 2. Operator Name:6. Date Comp., Susp., or 14. Permit to Drill Number / Sundry: Aband.: 3. Address:7. Date Spudded: 15. API Number: 4a. Location of Well (Governmental Section):8. Date TD Reached: 16. Well Name and Number: Surface: Top of Productive Interval:9. Ref Elevations: KB: 17. Field / Pool(s): Deep Creek Unit GL: 593' BF:N/A Total Depth:10. Plug Back Depth MD/TVD: 18. Property Designation: 4b. Location of Well (State Base Plane Coordinates, NAD 27):11. Total Depth MD/TVD: 19. DNR Approval Number: Surface:x- y- Zone- 4 TPI:x- y- Zone- 4 12. SSSV Depth MD/TVD:20. Thickness of Permafrost MD/TVD: Total Depth:x- y- Zone- 4 5. Directional or Inclination Survey: Yes (attached) No 13. Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic information per 20 AAC 25.050 N/A (ft MSL) 22.Logs Obtained: 23. BOTTOM 7" L-80 3,663' 3-1/2"L-80 9,562' 3-1/2"L-80 3,473' 24. Open to production or injection?Yes No 25. 26. Was hydraulic fracturing used during completion? Yes No DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. Date First Production:Method of Operation (Flowing, gas lift, etc.): Hours Tested: Production for Gas-MCF: Test Period Casing Press: Calculated Gas-MCF: Oil Gravity - API (corr): Press.24-Hour Rate Sr Pet Eng N/A N/A Oil-Bbl:Water-Bbl: 0 068240 4/26/2025 24 Flow Tubing 0 1,348 N/A1,3480 TUBING RECORD ACID, FRACTURE, CEMENT SQUEEZE, ETC. Sr Res EngSr Pet Geo Choke Size: 3,823' Tieback PACKER SET (MD/TVD) 8-1/2" Water-Bbl: PRODUCTION TEST 4/5/2025 Date of Test:Oil-Bbl: Flowing *** Please see attached schematic for perforation detail *** Gas-Oil Ratio: Per 20 AAC 25.283 (i)(2) attach electronic information CASING, LINER AND CEMENTING RECORD 2561' FNL, 1547' FEL, Sec 21, T2S, R13W, SM, AK List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data within 90 days of completion, AMOUNT PULLED 222661 222484 TOP SETTING DEPTH MD suspension, or abandonment; or within 90 days of acquisition of the log, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page only if necessary. CBL 3-16-25, Perf and GPT logs, LWD (DGR, PWD, ADR, ALD, CTN, DDSR, PCG) N/A 1,200' MD / 1,140' TVD N/A SETTING DEPTH TVD BOTTOMCASINGWT. PER FT.GRADE CEMENTING RECORD 2191186 2191359 TOP HOLE SIZE 3800 Centerpoint Drive, Suite 1400, Anchorage, AK 99503 223690 2190972 50-231-20032-01-00February 14, 2025 N/A HVB-13AFebruary 24, 20252920' FNL, 337' FEL, Sec 21, T2S, R13W, SM, AK 611' Beluga/Tyonek Gas Pool C061589 9,775' MD / 9,563' TVD 9,575' MD / 9,364' TVD 2550' FSL, 1366' FEL, Sec 21, T2S, R13W, SM, AK STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG Hilcorp Alaska, LLC WAG Gas 4/2/2025 224-160 / 325-131 Surface N/A SIZE DEPTH SET (MD)If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date perf'd or liner run): Surface 3,630' 3,621'6-1/8" L - 243 sx / T - 99 sx 3,464'L - 441 sx / T - 180 sx Surface 9.2#Surface 26# Tieback Assy. 9,773'9.2# G s d 1 0 p dB P L s (att Form 10-407 Revised 10/2022 Due within 30 days of Completion, Suspension, or Abandonment By James Brooks at 2:01 pm, May 16, 2025 Complete 4/2/2025 JSB RBDMS JSB 052025 GDSR-6/3/25BJM 11/11/25 Conventional Core(s): Yes No Sidewall Cores: 30. MD TVD N/A N/A Top of Productive Interval T 10 6523' 6324' 2063' 1937' 2170' 2041' 2597' 2460' 3165' 3017' 4093' 3927' 5834' 5639' 6096' 5899' 6501' 6302' 7761' 7555' 9103' 8891' 9268' 9057' 9379' 9168' 9734' 9522' 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Cody Dinger Digital Signature with Date:Contact Email:cdinger@hilcorp.com Contact Phone: 907-777-8389 General: Item 1a: Item 1b: Item 4b: Item 9: Item 15: Item 19: Item 20: Item 22: Item 23: Item 24: Item 27: Item 28: Item 30: Item 31: Formation Name at TD: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data within 90 days of completion, suspension, or abandonment; or 90 days after log acquisition, whichever occurs first. T 130 T 40 Bel 30 Sterling E Bel 45 T 10 Bel 1 Bel 10 Bel 135 T 5 T 90 T 100 T 110 Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a current well schematic diagram with each 10-407. Submit 10-407 and attachments in PDF format to aogcc.permitting@alaska.gov. All laboratory analytical reports from a well must be submitted to the AOGCC, no matter when the analyses are conducted per 20 AAC 25.071. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, as-built, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. TPI (Top of Producing Interval). Authorized Name and Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. INSTRUCTIONS Wellbore Schematic, Drilling and Completion Reports, Csg and Cmt Reports, Definitive Directional Survey Authorized Title: Drilling Manager If Yes, list formations and intervals cored (MD/TVD, From/To), and briefly summarize lithology and presence of oil, gas or water (submit separate pages if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071 no matter when acquired. Yes No Well tested? Yes No 28. CORE DATA If Yes, list intervals and formations tested, briefly summarizing test results for each. Attach separate pages if needed and submit detailed test info including reports and Excel or ASCII tables per 20 AAC 25.071. NAME Permafrost - Top Permafrost - Base 29. GEOLOGIC MARKERS and POOL BOUNDARIES: (list all encountered)FORMATION TESTS N Form 10-407 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2025.05.16 13:44:25 - 08'00' Sean McLaughlin (4311) _____________________________________________________________________________________ Updated by CJD 5-16-25 Schematic Deep Creek Unit – B Pad Well: HVB-13A PTD: 224-160 API: 50-231-20032-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn Top Btm 20"Conductor 109 / X-56 / Weld Surface 117' 9-5/8'Surface 40 /L-80/ BTC Surface 1,157’ Open Hole Whipstock set @ 1,200’ MD 7”Intermediate 26 / L-80 / BTC Surface 3,823’ 3-1/2”Prod liner 9.2 / L-80 / Hyd 563 3,621’9,773’ 3-1/2”Tieback 9.2 / L-80 / EUE 8RD Surf 3,630’ JEWELRY DETAIL No Depth Item 1/2 3,621’Liner Top Packer / Seal Assy. 3 9,575’CIBP 2.75” OPEN HOLE / CEMENT DETAIL 8-1/2”Spacer-60 bbl 10.5 ppg / lead- 101 bbl 12 ppg lead/Tail- 61 bbl 15.3 ppg 6-1/8”Spacer-30 bbl 10.5 ppg / lead- 186 bbl 12 ppg lead/Tail- 36 bbl 15.3 ppg PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Date Status T10 6,523'6,533'6,324’6,334’10'4/18/25 Open T10 6,609'6,623'6,410’6,424’14'4/18/25 Open T10A 6,649'6,655'6,449’6,455’6'4/18/25 Open T32 7,417'7,427'7,214’7,224’10'4/18/25 Open T40 7,785'7,816'7,579’7,610’31'4/18/25 Open T48 8,140'8,160'7,932’7,952’20'4/18/25 Open T65 8,656'8,662'8,445’8,451’6'4/18/25 Open T80 8,924'8,938'8,713’8,727’14’4/3/25 Open T90 9,115'9,129'8,904’8,918’14'4/3/25 Open T91 9,152'9,166'8,941’8,955’14'4/3/25 Open T98 9,225'9,231'9,014’9,020’6'4/3/25 Open T99 9,242’9,252’9,031’9,041’10’4/3/25 Open T100 9,295'9,305'9,084’9,093’10'4/3/25 Open T120 9,617'9,637'9,405’9,425’20'4/2/25 Isolated Page 1/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Jobs Actual Start Date:2/9/2025 End Date:3/2/2025 Report Number 1 Report Start Date 2/9/2025 Report End Date 2/10/2025 Operation CCI on location at 06:00 and warming up equipment, held PJSM, staged crane, removed windwalls from pits, scoped down doghose, removed choke house and iron roughneck from floor, L/D V door windwall, removed boiler skid and aux fuel tank, lowered pit roof tops, removed back yard modules and pit modules and staged loaded trailers for move Monday morning. Start PU and loading exposed rig mats for transport to HVB pad. Cont PU rig mats, replaced 2" cement hardline on beaver slide with freshly tested hardware, traveled to HVB pad and set felt/liner, installed tree on Kalotsa 9 with wellhead Rep. PU and stage used liner on Kalotsa pad for production to use. Inspect loads for tansport. Wait on CCI rig movers. Perfrom Housekeeping. Cont to wait on CCI rig movers. Report Number 2 Report Start Date 2/10/2025 Report End Date 2/11/2025 Operation Cont cleanup of frozen felt around sub, CCI on location at 08:00 warming up equipment, held PJSM, started transport of permitted loads at 09:00 to HVB pad, spotted cranes, lowered windwalls on derrick board, and picked derrick off carrier, picked drill line spool. (15 mile move-3 hr turnaround for trucks/trailers) Picked carrier off sub, sub off pony walls. Loaded rig mats, pony walls and rig HPU. Transported cranes, sub, carrier, derrick and pony walls to HVB pad, set pony walls and sub, centered up over well, set carrier and drill line spool, set and pinned derrick. Set doghose skid and raised doghouse, set gen skid, flew iron roughneck to rig floor and pinned. Raise mast and pin. Spot gen module. Spot mud pit mods 1 and 2 and raise pit roofs. Crane set choke house. Set jig then spot mud pump 1 and 2 mods, top drive hpu, and boiler house. Hook up eletrical, water, air, steam and mud lines. Stage up boilers. Clear liner, felt and trash from Kalotsa #10. Cont to hook up electrical, air, water and steam lines. M/U mud lines from pits to mud pump. Hook up equalizer lines between pit modules. Begin hooking up Pason lines. Spool on drill line. Report Number 3 Report Start Date 2/11/2025 Report End Date 2/12/2025 Operation RD mech and electric shop, change shack/safety shack, office trailers, cont setting pit 3, poorboy and catwalk, set centrifuge and hung windwalls, hung BOP stack in cellar, welder made some minor repairs, transport trailers to HVB pad. Pinned lower torque tube to upper section, scoped up derrick, transported office trailers to location, and set same, RU comm's, install Handy Berm around rig, took on rig water, brought boilers up to temp/pressure, start steam throughout the rig, installed choke hose to manifold, staged Top Drive on rig floor, installed hooch over centrifuge, cont RU in pits, start hanging tarps. Hung Top Drive on blocks. Install service loop, kelly hose, saver sub, and bails to Top Drive and function test - Good. Set Gen 3 into place and berm in. Begin working through rig acceptance checklist. Continue working through rig acceptance checklist. Rig up generator #3 power. Rig up manual tongs and bring pipe handling equipment to rig floor. Spot mud lab with CCI loader and rig up electrical. Continue hanging tarps/felt around rig. Remove shipping beams from cellar and rig up kill line to mezzanine hookup. Calibrate and function test rig smart and Crown-O-Matic. Function test agitators, mix pumps, and gun lines in pits. Report Number 4 Report Start Date 2/12/2025 Report End Date 2/13/2025 Operation Cont working through rig acceptance checklist, building mud docks and offload mud product, RU comm's to service shacks, troubleshoot Pason PVT sensors, checked 7" for pressure, removed dry hole cap, set test plug, set BOP stack, Wellhead Rep functioned 7" packoff LDS, ran water around pits and plumbing, installed gas sensors and alarms, dressed shakers, RU geronimo line. Witness of initial BOP test waived by AOGCC Rep Jim Regg at 10:40 am on 2-12-25. Troubleshotmud pump engine (battery), replaced 2" hydraulic hose from topdrive HPU skid to sub, installed drip pan, flow riser and flow line, rig electrician tested all audio/visual gas alarms, C/O upper rams to 7", opened lower ram door and verified test joint XO's will be below lower rams, drilled port hole in 3 1/2" test joint (test plug not ported), cont offload mud product trailers, transport 6% KCL mud to pits from Paxton pad, received YJ and WIS tools, received and shipped Sperry tools. Flooded stack for shell test. Accepted rig at 18:00 hrs on 2-12-25. Continue flooding, hook up testing equipment, and purge air from system. Work air out of valves. Witness waived by AOGCC Jim Regg. All tests performed to 250/3000psi lo/hi for 5 min each. Test 4.5" test joint in LPR and dart valve. Rig down 4.5" test joint and P/U M/U 7" Test joint with pump in sub and TIW. Test 7" test joint in UPR with TIW, Mezz kill, UPR IBOP, and CMV#11-14. Witness waived by AOGCC Jim Regg. All tests performed to 250/3000psi lo/hi for 5 min each. Test LWR IBOP and CMV #1-10/15. Test inside/HCR kill, inside/HCR choke, and blinds. Test 3.5" test joint in Annular and LPR. Perform step down test on super choke and manual super choke to 1600psi. One fail/pass (Test #8-Manual Kill). Perform Koomey drawdown test Initial- 3050psi, After-1700psi 200psi recharge- 23sec Full recovery- 90sec 4 Backup NO2 bottles at 2487psi average. Report Number 5 Report Start Date 2/13/2025 Report End Date 2/14/2025 Operation RD test equipment. Primed mud pumps then pressured up mud line from pumps to Top Drive and tested at 2000 psi, set popoff's at 4000 psi, blew down Top Drive, started centrifuging mud weight from 9.2 to 9.0 ppg, obtained RKB's, racked and tallied DP, PU first stand and centered up torque tube/Top Drive over hole. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169Permit to Drill (PTD) #:224-160 Wellbore API/UWI:50-231-20032-01-00 Page 2/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation PU singled in hole to 1257', POOH racked back 20 stands, PU singled in hole 1283', POOH racked back 20 stands. Floor motor battery ruptured, shut down and cleaned up/replaced battery. No personnel were near battery when it ruptured. PU singledin hole 16 jnts HWDP and 10 more jnts DP to 1037', POOH racked back last of pipe. 55 stands DP total and 8 stands HWDP total. During trip RU 2" HP hose from OA to flow line for circulating out the IA after casing cut. CCI RD HandyBerm for one of two empty mud storage tanks on Paxton pad. M/U Mechanical cutter and RIH T/ 1279'. P/U 42K, S/O 37K. Calculated displacement observed. Put 10 wraps to the right into string and slack off slowly engaging cutter at ~1279'. Slack off from 42K to 12K with TQ swings between 3.5-7.5KFt-lbs TQ. Let cutter work for 21 minutes total per YJ rep until TQ leveled off to a smooth 6.5K. P/U and disengaged cutter. Shut annular and break circulation at 721psi taking returns up the OA. Shut down and line up on spacer. Pump 21bbl hi-vis spacer followed by 9.0ppg 6%Kcl until clean returns observed at shakers. Open annular and displace the remaining 7" volume, FCP - 400psi at 112gpm. Total over boarded - 104bbls. Monitored well for 10 min - Static. POOH Racking back F/ 1260' - T/ Surf. Calculated displacement observed. L/D Cutter assy per YJ reps. Blade inspection confirmed good cut. C/O Hyd hose fitting on Iron Roughneck. M/U YJ spear and function test - Good. RIH to No-Go and set 5K down with Top Drive. With Annulus open BOLDS. Pull hanger to rig floor observing break over at 73K and free travel at 52K. Remove packoff. Hanger and packoff in good condition. Rig up Parker TRS power tongs. L/D 7" Casing F/ 1258' - T/ 620'. P/U 50K, S/O 47K. Calculated holefill observed. Report Number 6 Report Start Date 2/14/2025 Report End Date 2/15/2025 Operation Cont POOH L/D 7" casing. L/D hanger, 20' pup, 30 full jnts, one 8.75' cutoff section. RD casing tongs/elevators, cleaned up floor, PU single off catwalk and broke down YJ spear assembly, staged tools for cleanout BHA. PU WIS dual string mills, float sub and 8 1/2" tri-cone bit, RIH on 4 1/2" HWDP to 496'. Cont RIH on 4 1/2" DP from 496' to 1262' (9 5/8" shoe at 1157', 7" casing stub at 1279'), pulled back up into surface casing and parked at 1150'. MU topdrive and circulated surface to surface at 250 gpm-163 psi, shut down and flow checked 5 min = static. Blew down topdrive. POOH on elevators from 1150' to surface and L/D WIS string mills and bit. CCI drifted new 7" casing. PU Sperry TM and DM collars, MU float sub on bottom, RIH one stand, MU topdrive, warmed up tools then shallow pulse tested at 418gpm. Blew down topdrive, pulled OOH and L/D Sperry assembly in one piece. PU and MU WIS open hole whipstock assembly, followed with one jnt 6 5/8" HWDP, MCBPV, Sperry tools and 8 stands HWDP to 596'. RFO = 305.16° Cont TIH at 1-2 min per stand to 1220'. P/U 48K, S/O 42K. Calculated displacement observed. Top off drill string with fill up hose. Obtain parameters, P/U 48K, S/O 42K. RIH to set depth at 1230'. Come on with pumps staging up from 112gpm (75psi) to 405gpm (780psi). Orient Whipstock per directional plan to 159 ROHS. Cycle pumps 6 times to close bypass valve attempting multiple times to close bypass with 112gpm - No success. Walk pumps up to 250gpm observing valve close. Shut down pumps immediately and observe pressure increase to 4200. P/U to 90K confirming set. S/O to 50K then pick back up to 110K observing mill assy shear from whipstock at 62K over. TOW- 1200' BOW- 1214' Turn on rotary and ease down to TOW at 1200' observing TQ increase and psi decrease, confirming shear on plugs. Mill window F/ 1200' - T/ 1214' and rat hole T/ 1221'. 350/395gpm = 1395/1188psi, 60RPM = 7-9KFt-lbs TQ with 10K WOB. Ream through multiple times with pump/rotary. Dry drift with no pump/rotary observing no drag in/out of window. Monitor well for 10 min - Static. POOH F/ 1200' - T/ Surf. Calculated holefill observed. L/D TM/DM together and mill assy per WIS rep. Starter mill was 1/8" undergage and string mill was 1/16" undergage. Clean/clear rig floor. M/U and install wear ring. ID = 9", Length = 34". RILDS (x2). P/U 1.5° bend motor and M/U to Tricone. M/U TM, DM, and flex collar (x2) RIH T/ 110'. Perform RFO (280°). RIH F/ 110' - T/ 1170'. Fill pipe and shallow pulse test MWD tools - Good. P/U 50K, S/O 45K. Calculated displacement observed. Orient to 162° ROHS. Shut down pumps and trip through window observing no drag at the top, start taking wt at BOW (15-20K). P/U to ensure free with no drag pulling out of the window. Come back down observing a 20K bobble entering window. Still stacking 15-20K trying to exit the BOW at 1214'. P/U to check/verify depth and parameters with no drag exiting window. Attempt to trip back through the window stacking 20K with no entry. Orient tool to each quadrant and attempt entry multiple times in each zone with no success. Report Number 7 Report Start Date 2/15/2025 Report End Date 2/16/2025 Operation Cont orienting and S/O setting down at top of ramp. Discussed with Drilling Manager. Attempted to trench and trough down to top of and alongside or whipstock ramp with no luck from 1179' to 1198', 450 gpm-1074 psi, oriented at 160°. Still could not get past 1200'. Drillstring bouncing pretty violent at that depth. Decision made to POOH for whipstock milling assembly. Called out WIS Rep. Pulled back up into surface casing and CBU at 400gpm, 10 rpm. 5 min flow check was static. POOH with rathole assembly racking back HWDP and jars, LD NM flex DC's, MWD, drained and flushed motor. Bit in good shape, graded 1-1 in gauge. Cleaned up floor, staged WIS bi-mill assembly for PU, recorded OD/ID of tools. PU full gauge bi-mill assembly (8 1/2" mills), XO, RIH on HWDP and DP to 1190', MU topdrive, filled pipe, 40K up and down weight. Eased down and dry tagged at 1198'. PU 5'. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 3/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Start rotating 12 rpm-3300 ft/lbs off bott torque, 112 gpm-80 psi, eased down and tagged up at 1198', torque spiked to 4442 ft/lbs, wt dropped off then torque dropped to 3300. PU to 1196', increased to 250 gpm-259 psi, 42 rpm-3921 ft/lbs, eased down and tagged again at 1198', torque very erratic, seeing 0-3 wob. Cont inch down to 1204' and things cleaned up. PU to 1197', inc to 80 rpm-4732 ft/lbs torque, worked down to 1215' clean (BOW 1214'). Started seeing marble size coal nuggets at shakers, backream up to 1196' clean, reamed down to 1215', cont milling ahead at 256 gpm-302 psi, 85 rpm-5250 to 6250 ft/lbs on bott torque and milling formation with 5K wob. Milled to 1221', backreamed to 1195', stopped rot, S/O to 1219' and set down, PU to 1196', wash/ream down to 1221', cont milling to 1226.5', drifted hole and ramp with no rot up to 1198', S/O to 1226' clean. Pulled to 1115' inside surface casing. CBU one time then flow check, well static. POOH with milling assembly. Starter mill 1/8" under gauge and torn up, follow mill 1/16" under gauge. L/D milling assembly. PU and re-run cleanout assembly: 8 1/2" Varel tri-cone, 1.5° bend motor, DM and TM collars, 2 x NM flex DC's. RFP = 282.13°. RIH one stand HWDP, MU topdrive and shallow pulse tested good. Cont RIH HWDP and jars to 6699'. Cont RIH on 4 1/2" DP to 1170', MU topdrive and filled pipe. Orient to 160° and trip past window T/ 1220'with 2K smooth drag traveling through with no issue. Wash down F/ 1220' - T/ 1226' and drill 8.5" intermediate section T/ 1419' (1329'TVD) obtaining clean survey on bottom. CBU and monitor well - Static. 450gpm = 1185psi, 30RPM = 4/3KFt-lbs on/off TQ with 8K WOB. MW 9.0ppg in/out. Max Gas = 19u. P/U 48K, S/O 42K, ROT 46K. POOH on elevators F/ 1419' - T/ Surf. No drag pulling up thorugh window. Calculated holefill observed. L/D flex collars, TM, DM, and break bit from motor per Sperry reps (1-1-WT-A-I-NO-BHA). Clean and clear rig floor. M/U 8-1/2" PDC Bit to Motor. M/U DM, DGR, PWD, ADR, ALD, CTN, and TM. Perform RFO (148.26°). Plug in and download to MWD then shallow pulse test tools - Good. Hold PJSM and install nuclear sources. RIH F/ 121' - T/ 1190'. Fill pipe and orient tool string to 160° ROHS. Trip through window with clean 2K drag and continue in hole washing F/ 1370' - T/ 1419'. P/U 52K, S/O 49K. Calculated displacement observed. Report Number 8 Report Start Date 2/16/2025 Report End Date 2/17/2025 Operation Resumed drilling 8 1/2" hole from 1419'to 1811'. Rot wob 3-5K, 445 gpm-1092 psi, 40 rpm-5100 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 10-12K, 443 gpm-1267 psi, 190 psi diff, 198 ft/hr ROP. MW 9.0/vis 53, ECD 9.5 ppg, BGG 11 units, max gas 36 units. Recieved 7" hanger and packoff, Halliburton staged two bulk trucks cement on A pad. Cont drilling 8 1/2" hole from 1811' to 2187'. Rot wob 5K, 445 gpm-1133 psi, 50 rpm-6100 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 5K, 444 gpm-1172 psi, 116 psi diff, 120 ft/hr ROP. MW 9+/vis 54, ECD 9.5+, BGG 10 units, max gas 62 units. Drill 8.5" INT section F/ 2187' - T/ 2624' (2489' TVD) Total: 437' (AROP: 80fph) 450gpm = 1285/1159psi on/off, 50RPM = 6/5KFt-lbs TQ with 8K WOB. ECD = 9.64ppg with a 9.1ppg MW in/out. Max gas = 70u. P/U 76K, S/O 62K, ROT 69K. Backreaming stands prior to connection. ROT/RECIP while CBU. 450gpm = 1153psi, 50RPM = 5-6KFt-lbs TQ. Obtain SPR's. Monitor well for 10 min - Static. POOH on elevators F/ 2624' - T/ 1730' observing consistent 5-10K clean drag. F/ 1730' - T/ 15 55' re-wipe multiple spots after pulling 35-40K over all pulling clean on second pass through. Pull tight with 55K over at 1555', BROOH F/ 1555' - T/ 1360' circulating multiple BUS observing heavy clay and some coal at shakers, re-wipe backreamed section with no pumps/rotary observing 5K clean drag on second pass through. Stop at 1430' and B/D Top Drive for rig service. P/U 83K, S/O 66K. Calculated holefill observed. Grease and inspect Crown, Blocks, Iron Roughneck, Drawworks, Brake Linkage, and Drive Line. Check fluid levels in Floor Motor, Drawworks, Chaincase, and Top Drive. Inspect Saver Sub. Clean suction screens on both MP's. Trip in hole F/ 1430' - T/ 2564' with no issue or tight spots. Wash down F/ 2564' - T/ 2624'. P/U 80K, S/O 55K. Calculated holefill observed. Pump Hi-Vis sweep and resume drilling 8-1/2" INT section F/ 2624' - T/ 2783' (2644' TVD) Total: 159' (AROP: 80fph) 450gpm = 1250/1075psi on/off, 50RPM = 6/5KFt-lbs TQ with 5-13K WOB. ECD = 9.74ppg with a 9.15ppg MW in/out. Max gas = 85u. P/U 76K, S/O 62K, ROT 69K. Backreaming stands prior to connection. Obtained SPR's. Distance from plan is 10.73’, 9.18’ Low & 5.55’ Left. Report Number 9 Report Start Date 2/17/2025 Report End Date 2/18/2025 Operation Cont drilling from 2783' to 3190'. Rot wob 7K, 445 gpm-1312 psi, 50 rpm-6600 ft/lbs on bott torque, 120 ft/hr ROP. Sliding wob 10K, 446 gpm-1289 psi, 112 psi diff, 69 ft/hr ROP. MW 9.1+/vis 53, ECD 9.8 ppg, BGG 22 units, max gas 209 units. Pumped 20 bbl hi-vis nutplug sweep around at 456 gpm-1265 psi, 50 rpm-6300 ft/lbs off bott torque. Sweep back 150 strokes early and 100% inc in clay/silt cuttings. Cont drilling from 3190' to 3574'. Rot wob 8K, 454 gpm-1533 psi, 50 rpm-8100 ft/lbs on bott torque, 118 ft/hr ROP. Sliding wob 6K, 455 gpm-1400 psi, 200 psi diff, 95 ft/hr ROP. MW 9.2+/vis 54, ECD 9.9 ppg, BGG 34 units, max gas 229 units. Drill 8-1/2" INT section F/ 3574' - T/ 3831' (3670' TVD) Total: 257' (AROP: 74fph) 455gpm = 1548/1351psi on/off, 50RPM = 9/7KFt-lbs on/off TQ with 9K WOB. ECD = 9.83ppg with a 9.3ppg MW in/out. Max gas = 229u. P/U 107K, S/O 73K, ROT 86K. Backreaming stands prior to connection. Final distance from plan is 1.60’, .47’ High & 1.53’ Left. Obtain final survey and SPR's on BTM. Pump Hi-Vis sweep around that came back 35bbls early with 100% increase. 455gpm = 1329psi, 50RPM = 7-8KFt-lbs TQ. Flow check - Static. POOH on elevators F/ 3831' - T/ 3240'. Started seeing overpull at 3530' - T/ 3240' pulling 25-45K over in multiple spots on eac h stand. Worked through each spot numerous times until able to pass through clean with no drag up/down. P/U 112K, S/O 75K. Calculated holefill observed. Pull 50K over at 3240' and attempt to work through without success. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 4/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation BROOH F/ 3240' - T/ 2624' encountering erratic TQ and stalls up to 15K in various spots each stand, minimal pump psi increase (75) and minimal overpull while backreaming (5-10K). Having to work through spots every stand until clean TQ was obtained. 455gpm = 1310psi, 50RPM = 7-10KFt-lbs TQ, ECD = 10.37, Max Gas = 45u. P/U 90K, S/O 72K, ROT 78K. Attempt to POOH on elevators in last short trip zone without success. Decision made to continue BROOH to shoe. BROOH F/ 2624' - T/ 2258' continuing to encounter erratic TQ and stalls up to 15K in various spots each stand, minimal pump psi increase (30-50) and minimal overpull while backreaming (5-10K). Having to work through spots every stand until clean TQ was obtained. 400gpm = 455psi, 50RPM 7-13KFt-lbs TQ, ECD = 10.89, Max Gas = 38u. P/U 80K, S/O 51K, ROT 58K. At 2258' able to POOH on elevators T/ 1922' only seeing 15-20K drag when pulled tight again at 1860' (40K over). Slack off to 30K without break over. P/U to neutral (58K) and M/U top drive. Idle pumps at 112gpm 600psi with initial 20bbl loss until returns achieved. Attempt to rotate and move pipe up/down without success. Add 3 drums of NXS lube and stage pumps up from 122gpm to 455gpm. Initial psi 1360 settling out to 1190psi with flow starting at 26% increasing to 31% no losses. Increase TQ stall to 21K and attempt rotary with no success. Attempt to free pipe by picking up 20K over and slacking off quick ly with no movement. Attempt 5x's slacking off to 20K and picking up to 110K (30 over) and jarring up with no movement. Park at neutral WT and work TQ in and out of string allowing hole time to clean up. Shakers coming back with heavy clays/silts and occasional marble sized coal chunks. Report Number 10 Report Start Date 2/18/2025 Report End Date 2/19/2025 Operation Circulate 2 bottoms ups and pump sweep around BROOH f/ 3019' t/ 1350' 400 gpm 1300 psi 50 rpm 8 k tq off bottom encountered erratic torque spikes at various depths, no increase in pump pressure. Service rig and top drive, circulate 5 bottoms ups while servicing. RIH f/ 1350' t/ 3782' tag fill, seen 4-8k drag through higher inclination zone. Wash and ream last stand to bottom, pump high vis sweep around, hole unloaded at bottoms up and sweep back 2.8 bbls late with 100% increase in cuttings. POOH f/ 3831' t/ 682' no issues observed pulled through ramp and window without issues. Rack back HWDP and Jars, unload sources, download MWD, continue L/D Remaining BHA Bit graded 1-1 in gauge. Cleaned & cleared rig floor. Pulled wear ring. R/U TRS. Test ran hanger. P/U & M/U 7" shoe track, tested floats (ok). Cont. running 7" 26# P-110 DWC/C intermediate casing F/95'-T/1147'. M/U XO & TDS. Broke circ. Staged up pump. P/U-40K S/O-38K GPM-208 SPP-80 psi MW-9.25 ppg Flow-18.6%. Obtained rotary/TQ parameters. 10 RPM = 3.2K 20 RPM = 3.4K 30 RPM = 3.6K. Resumed running 7" intermediate casing as per run tally F/1147'-T/3797' with no issues. M/U tag jt. & XO, washed down F/3797'-T/3831' (bottom). Had 12' of fill on bottom. Circ. & cond. mud while R/U cementers. L/D tag joint. M/U hanger, LJ, and XO. Cont. circulating and working pipe while holding PJSM. Report Number 11 Report Start Date 2/19/2025 Report End Date 2/20/2025 Operation HES pumped 5 bbls water ahead to fill lines, shut in head and PT lines t/ 1200 low 4800 high, pumped 60 bbls 10.5 ppg spacer dropped bottom plug, pumped 101 bbls lead 12 ppg cement at 4.5 bpm followed with 61 bble 15.3 ppg tail cement, dropped top plug, displaced w/ 143 bbls of mud bumping plug, slowed rate t 2.5 bpm last 20 bbls FCP 980 psi presured up to 1700 held for 5 min bled off .75 bbls floats held, CIP 8:52 am, R/D and blow down lines release cementers. total of 7 bbls lost through out job 60 bbls spacer returned and 22 bbls contaminated cement 11.1 ppg R?D cement equipment, pull landing jt, flush lines and stack w/ black water, set pack off as per vault rep, clear floor. Open ram doors and change upper rams f/ 7'' to 2 7/8'' x 5'' VBR's close doors and tighten, set test plug and R/U test equipment, test upper rams w/ 3.5'' and 4.5'' test jts t/ 250/ 3000 psi psi f/ 5 min, pull test plug and R/D set wear ring. M/U mule shoe RIH P/U 4/.5'' DP 100 jts t/ 3150'. Racked back 50 stds in the derrick. L/D mule shoe. Cleaned & cleared rig floor. R/U test equip. Flooded mud lines, stacks, and CM w/ FW. Purged out air. Crew change, held PTSM. Tested 7" intermediate casing T/3000 psi on a chart for 30 min. (ok). Pumped in 1.4 bbls & Bled back 1.4 bbls. R/D & B/D testeding equip. Closed manuls on stack for drilling out FE. P/U 6-1/8" directional BHA #8 as per Sperry. M/U 6-1/8" 5 bladed PDC bit to 1.5° bend mud motor. Messured for off set = 83.62°. P/U & M/U MWD tools, plugged in and uploaded data. Performed shallow pulse test (ok). Held PJSM and loaded sources. M/U jar std. RIH w/ remainder of BHA #8. Currently P/U & singling in with 4.5” DP on top of BHA #8. Report Number 12 Report Start Date 2/20/2025 Report End Date 2/21/2025 Operation RIh P/U DP Singles f/ 679' t/ 2932', continue RIH f/ derrick f/ 2932' t/ 3728' tag up on plugs Drill Cement and FE f/ 3728' t/ 3831' Drill 20' of new hole t/ 3851' 225 gpm 1300 psi 50 rpm 7k tq Circulate bottoms up R/U and Perform FIT t/ 14.85 ppg EMW 1067 psi, R/D test equipment. Drill Ahead 6 1/8'' Hole section f/ 3851' t/ 4185' 260 gpm 1857 psi 50 rpm 8k tq on bottom, MW 9.25 10.92 ppg ECD, 109k PUW 64k SOW 81 ROT Max Gas 174 units Cont. directional drilling 6-1/8" production hole F/4185'-T/4624'. P/U-120K S/O-70K ROT-87K GPM-255 SPP-1885 psi RPM-50 TQ-8.3K WOB-6K Diff-261 psi Flow-20% MW-9.25 ppg ECD-10.98 ppg Max gas- 435 units. Obtained new SPR's and pumped 20 bbl Hi-Vis sweep at 4372', back on time with a 100% increase in cuttings. Crew change, held PTSM. Resumed directional drilling 6-1/8" production hole F/4624'-T/4875'. P/U-122K S/O-75K ROT-89K GPM-231 SPP-1967 psi RPM-55 TQ-9.5K WOB-7K Diff-215 psi Flow-20% MW-9.3 ppg ECD-11.26 ppg Max gas- 315 units. Distance to well plan: 1.45' .72' Low 1.21' Left CBU, shot on bottom survey, obtained new set of SPR's, and flow checked well (static). Pulled wiper trip on elevators w/ no issues F/4875'-T/3807'. P/U- 137K S/O-78K Serviced rig while montioring hole on TT. Inspected & greased crown, blocks, TDS, wash pipe, DWKS, IR, brake linkage, and drive shaft. Inspected saver-sub (ok). Static loss rate. RIH on elevators w/ no issues F/3807'-T/4812'. Washed last std. to bottom. Pumping 20 bbl sweep on bottom at report time Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 5/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Report Number 13 Report Start Date 2/21/2025 Report End Date 2/22/2025 Operation Continue Drilling Ahead 6 1/8'' Hole Section f/ 4875' t/ 5318' 260 gpm 2060 psi 50 rpm 9.6k tq on bottom, max gas 372 units, 6k WOB 9.3 ppg MW ECD 11.2 ppg 134k PUW 75k SOW 95k ROT sweep back on time 100% increase in cuttings Continue Drilling Ahead 6 1/8'' hole section f/ 5318' t/ 5819' 260 gpm 2035 psi 50 rpm 11k tq on bottom, 6k WOB, MW 9.3 ppg ECD 11.2 ppg, 155k PUW 78K SOW 104k ROT Cont. directional drilling 6-1/8" production hole F/5819'-T/5882'. P/U-155K S/O-78K ROT-104K GPM-260 SPP-2214 psi RPM-50 TQ-10.4K WOB-7K Diff-330 psi Flow-20% MW-9.35 ppg ECD-10.99 ppg Max gas- 390 units CBU, shot on bottom survey, obtained fresh set of SPR's, and flow checked well (static). Pulled wiper trip on elevators F/5882'-T/4809' with no issues. P/U-170K S/O-88K. Had calculated hole fill for the trip. Monitored hole on the TT while servicing the rig. Inspected & greased crown, blocks, TDS, wash pipe, IR, DWKS, brake linkage, and drive line. Inspected saver-sub (ok). Static loss rate- 0 bph. TIH on elevators F/4873'-T/5820', washed last std down. Had calculated pipe displacement for the trip. P/U-142K S/O-78K. Pumped 20 bbl Hi-Vis sweep w/ walnut & condet. Sweep came back 6 bbls late, w/ 100% increase in cuttings. GPM-260 SPP-2038 psi RPM-70 TQ-12K Flow-20%. Resumed directional drilling 6-1/8" production hole F/5882' to current depth of 6480'. Pumped sweep at 6383', back 11 bbls late, w/ a 100% increase. P/U-170K S/O-83K ROT-110K GPM-260 SPP-2120 psi RPM-50 TQ-11.6K WOB-8K Diff-290 psi Flow-20% MW-9.25 ppg ECD-11.15 ppg Max gas- 492 units. Distance to well plan: 3.40' .39' Low 3.38' Right Report Number 14 Report Start Date 2/22/2025 Report End Date 2/23/2025 Operation Continue Drilling 6 1/8'' hole secion f/ 6480' t/ 6949' 260 gpm 2200 psi 50 rpm 13k tq on bottom 7k WOB MW 9.3 ppg ECD 11.1 ppg, 180k PUW 86k SOW 115k ROT Max Gas 1218 units, @ 6883' Lost partial returns flow dropped f/ 20-10% inital loss rate was 176 bph while pumping, flowing back on connections but slowing. Continue Drilling 6 1/8'' Hole section f/ 6949' t/ 7199' 240 gpm 1933 psi 50 rpm 13k tq on bottom, 195k PUW 93k SOW 130k ROT, Still partial returns flow up t/ 17%, Loss rate dropped to 37 bph Distance to well plan: 5.46' .08' High 5.46' Right Circulate and condition hole, Flow rate still 17% loss rate 34 bph spot LCM pill and Flow check well for 10 min initial flow 10% final .7% POOH w/ pumps at idle 46 spm 630 psi f/ 7199' t/ 5818'. Flow checked well (slight seepage). POOH on elevators F/5818'-T/3806'. P/U-165K S/O-90K. Monitored well on TT while rebuilding mud system. Serviced rig. Slip & cut 71' of drill line = 15 wraps. Changed out rig smart sensor on TDS bails. Changed oil/filter on DWKS motor. Static loss rate = .36 bph Crew change, held PTSM. Finished rebuilding mud system. Static loss rate = .8 bph. Built 460 bbls. 951 bbls of mud available. TIH on elevators F/3806'-T/5316' w/ no issues. P/U-106K S/O-69K Filled pipe. CBU x 1.5 due to high gas. Max gas - 2940 units. Hole unloaded with super fines at BU. Flow checked well (slight seepage). B/D TDS. P/U-127K S/O-78K ROT-102K GPM-205 SPP-1230 psi RPM-40 TQ-9.4K Flow-17% MW-9.25 ppg ECD-10.62 ppg. Cont. RIH on elevators F/5316'-T/6566'. P/U-142K S/O-86K Filled pipe, broke circ. B/D TDS. Resumed TIH on elevators F/6566'. Lost 485 bbl over last 24 hrs. Report Number 15 Report Start Date 2/23/2025 Report End Date 2/24/2025 Operation RIh f/ 6566' t/ 6949' taking weight unable to work through. Waash and ream in the hole f/ 6949' t/ 7199' tag fill 7152' Drill Ahead 6 1/8'' hole section f/ 7199' t/ 7515' 220 gpm 1900 psi 50 rpm 8k WOB, 290 units of gas, MW 9.3 ppg ECD 10.79 ppg, 9 - 18 bph loss rate, 193k 98k sow 127k ROT Drill Ahead 6 1/8'' Hole Section f/ 7515' t/ 7876' 220 gpm 1951' 50 rpm 14k tq on bottom, 448 units of max gas, 8k WOB 198k PUW 100k SOW 130k ROT Rack back 2 stands change wash pipe, monitoring well on trip tank. RIH, resumed drilling ahead. Cont. directional drilling 6-1/8" production hole F/7876'-T/8201'. P/U-190K S/O-110K ROT-139K GPM-240 SPP-2107 psi RPM-50 TQ-11.9K WOB-4K Diff-298 psi Flow-19% MW-9.25 ppg ECD-10.88 ppg Max gas- 601 units. Added .7% by volume of NXS lube to active system to help reduce TQ. Crew change, held PTSM and weekly safety meeting w/ rig crew. . Resumed directional drilling 6-1/8" production hole F/8201' to current depth of 8411'. P/U-190K S/O-112K ROT-140K GPM-240 SPP-2150 psi RPM-50 TQ-12.5K WOB-8K Diff-350 psi Flow-18% MW-9.25 ppg ECD-10.99 ppg Max gas- 641 units. Pumped 20 bbl Hi-Vis sweep @ 8201', sweep came back 25 bbls late, w/ a 75% increase in cuttings. Distance to well plan: 2.81' 2.76' Low .49' Left Report Number 16 Report Start Date 2/24/2025 Report End Date 2/25/2025 Operation Continue Drilling 6 1/8'' Hole section f/ 8411' t/ 8800' 240 gpm 2170 psi 50 rpm 14.5k Tq on bottom, 9k WOB Max Gas Observed 629 units MW 9.3 ppg ECD 10.98 ppg, 207k PUW 116k SOW 148k ROT Continue Drilling 6 1/8'' Hole Section f/ 8800' t/ 9202' 2240 gpm 2240 psi 50 rpm 15.5k tq on bottom, MW 9.35 ppg ECD 10.59 ppg Max Gas Observed 645 units 233k PUW 118k SOW 157k ROT Cont. directional drilling 6-1/8" production hole F/9202'-T/9571'. Pumped 20 bbl Hi-Vis sweep at 9205', sweep came back 49 bbls late w/ a 100% increase in cuttings. P/U weight came down by 22K after sweep came back. Started dusting up MW for trip margin to 9.5 ppg. P/U-220K S/O-121K ROT-158K GPM-240 SPP-2395 psi RPM-50 TQ-14.9K WOB-7K Diff-396 psi Flow-18% MW-9.35 ppg ECD-11.01 ppg Max gas- 688 units. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 6/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Crew change, held PTSM. Resumed directional drilling 6-1/8" production hole F/9571' to new TD at 9775' called by geologist. P/U -240K S/O-124K ROT-160K GPM-245 SPP-2300 psi RPM-50 TQ-17.7K WOB-8K Diff-375 psi Flow-18% MW-9.5 ppg ECD-11.00 ppg Max gas- 498 units. Distance to well plan: 138.22' 50.68' High 128.60' Right Pumped 20 bbl Hi-Vis sweep around w/ walnut & condet. Current Dynamic loss rate- 15 bph. Report Number 17 Report Start Date 2/25/2025 Report End Date 2/26/2025 Operation Circulate out HI Vis Sweep back 700 stks late 50% increase in cuttings, Flow check well, breathing back initial rate 7 bpm slowing to 5 in 15 min. POOH w/ pumps 46 spm 770 psi f/ 9775' t/ 7165' 15-25k over pulls coming out of slips till 9485' Service rig and top drive, grease blocks and crown, inspect draw works and brake linkage, inspect drive shaft, change saver sub on top drive. RIh f/ 7165' t/ 9775' without issuse, pumped hi vis sweep and washed last stand to bottom. Pump Hi Vis sweep around, sweep back 850 stks late 100% increase, hole unloaded on bottoms up 1441 units of gas on bottoms up. Flow check well f/ 10 min well breathing back 14 bph rate, decision made to weight up t/ 9.7 ppg Circulate and weight up at 200 gpm 50 rpm. Flow check well 30 minutes- initially flowing 5bbl/min slowing to 2bbl/hr after 15 min then static at 30 min mark. L/D E-kelly. POOH f/9766' t/6005'. P/U-235k, S/O-148k. Had to pump and rotate to break over second stand, pulled 70k over did not break over. Was able to pull on elevaotrs the rest of the trip. Observed 15-40k overpull coming out of slips until 6130'. Hole fill- Calc: 23bbl, Act: 24.78bbl (1.78 bbl loss). POOH on elevators f/6005' t/3806' without issue. P/U-158k, S/O-96k. Hole fill- Calc: 40.94 bbl Act: 46.31bbl (5.37 bbl loss). Service and inspect crown, derrick, torque tube, top drive, saver sub, service loop, iron roughneck, drawworks, brake linkage, gear box, chain, driveline, and floor motor. Monitor well on trip tank, static loss rte- 1.4bbl/hr. Cont. to POOH f/3806' t/679'. P/U-90k, S/O-71k. Rack back 8 stands of HWDP and L/D jar stand. PJSM and remove sources. Report Number 18 Report Start Date 2/26/2025 Report End Date 2/27/2025 Operation Download MWD, Continue L/D BHA, Bit graded 1-1 in gauge, clear floor Pull wear ring, set test plug R/U to test BOP's fill stack and lines with water putge air, Shell test stack to 3000 psi no leaks Test BOP's t/ 250/3000 psi f/ 5 min each test, test w/ 3.5 and 4.5 test jts, test upper lower and blind rams, test annular, HCR and Man choke and kill line valves CMV 1-15, auto and man IBOP TIW and Dart valves, inside kill line valves, and electric and man choke valves, test gas alarms and PVT sensors flow paddle, state inspector Jim Regg Waived witness, perform accumulator Drawdown test. R/D and blow down test equipment. R/U to run 3.5'' Liner as per detail, hold PJSM with hands before running, RIH P/U shoe track, filling pipe on the fl y topping off every jt, checked float equipment (good) continue RIH P/U 3.5'' Liner as per detail t/ 5507' Cont to RIH w/3.5" liner as per tally t/6133'. M/U Liner hanger as per YJ rep. P/U and screw into 4.75" drill collar. CBU at 170GPM=525PSI. Max gas at BU 117 units. P/U and single in hole w/ 4.75" drill collars f/6205' t/7164' (32 total). Cont to RIH out of the derrick w/ 8 stands of HWDP f/ 7164' t/ 7650'. Report Number 19 Report Start Date 2/27/2025 Report End Date 2/28/2025 Operation Continue RIH w/ 3.5'' Liner f/ 7650' t/9775' Wash last two stands to bottom. minor tight spots 8914' Stage rate t/ 3.6 bpm 1150 psi, continue working pipe while cementers spot in and rig up R/U cement head and lines, M/U wash up lines. PJSM, pump 5 bbls water ahead, shut in and PT lines t/ 250 low 4000 high, open up and pump 30 bbls 10.5 ppg spacer followed by 186 bbls 12 ppg lead cement, pump 36 bbls 15.3 ppg tail cement, shut in wash over top to cutings box, drop plug and displace cement w/ 90.5 bbls of mud bumped plugs, held 500 psi over FCP at 2350 bled off and checked floats good bled back .5 bbls, pressure up and set liner hanger as per YJ rep, 70 bbl losses through out job 7 bbls contaminated spacer returns to surface, CIP 14:52, Set liner hanger as per YJ rep, Release from hanger and P/U R/D cement head and circulate bottoms up 8 bpm no cemnt returns to surface POOH f/ 3608' t/ Surface L/D Drill collars (32 jnts), L/D running tool and inspect. P/U Cement head, break off pup joint and XO's. Clean and clear rig floor. M/U polish mill assembly. RIH f/ surface t/1324'. Cont. to RIH with polish mill assembly f/1324' to tag TOL at 3632'. Polish TBR as per Yellow Jacket rep. Displace well bore from 9.7ppg 6% KCL PHPA mud system over to CI water. Perform 30min negative pressure test-static. POOH L/D 4.5" DP f/3632' t/1730'. Doping connections and installing thread protectors. Report Number 20 Report Start Date 2/28/2025 Report End Date 3/1/2025 Operation Continue POOH L/D DP cleaning and redoping threads, L/D HWDP and Polish Mills Service rig and top drive, grease blocks and crown, inspect draw works and brake linkage gear box and chain. RIH w/ 37 stands of DP f/ the derrick. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 7/7 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Well Operations Summary Operation Pump string volume POOH L/D DP, cleaning and redoping threads R/U and perform liner lap test t/ 2500 psi f/ 10 min pumped 1.8 bbls bled back 1.8 bbls RIH w/ 34 stands f/ derrick t/ 2128' Pump string volume POOH L/D DP f/ 2128' t/ surface RIH w/ 24 stands out of derrick f/surface t/1541'. Pump string volume to flush pipe. POOH L/D DP f/1541' t/surface. Pull wear ring. Clean and clear rig floor. R/U Parker TRS equipment. M/U floor valve and XO. P/U and M/U bullet seal assembly . Run 3.5" tie back and per tall f/ surface t/ 273'. Cont to RIH w/ 3.5" tie back f/273' t/3593'. P/U two extra jnts and tagged no-go at 3632'. L/D two tag joints. M/U 14.53' of pup joints and hanger. Drained stack, pulled bushing. S/O and landed hanger at 18.58', with no-go 0.88' off of liner top. P/U-48k, S/O-41k. RILS and test seals to 5000psi/5min. R/D Parker TRS casing equipment. Report Number 21 Report Start Date 3/1/2025 Report End Date 3/2/2025 Operation R/U and test tubing and IA t/ 2500 psi f/ 30 min good tests R/D testing equipment, set TWC Flush mud lines and BOP stack, gas buster and top drive w/ bara clean pill. Check end play on top drive, continue cleaning pits remove 5'' liners f/ pumps, clean under rotary table and inspect. Open doors and inspect rams and ram cavities, button up doors and N/D BOP Stack and choke and kill lines, pull riser and flow box, install trolly beam, hook up bridge cranes and transfer stack to bridge cranes. N/U dry hole tree and test void and tree to 5000 psi f/ 10 min good test, suck out tubing and freeze protect well with diesel, secure wellhead. R/D Top drive. Spot crane in, remove gas buster, remove BOP from sub base, pull clam shell and windwalls from mud tanks. Dis-assemble fluid ends on MP's, inspect clean and re-install. Install shipping beams in sub base. Pressure wash derrick. Prep derrick to scope down. Perform derrick inspection. R/D iron roughneck, topdrive HPU, mud pump lines and high pressure lines. Unspool drill line. Hang drill line and service loop in derrick. Dress out derrick to lower. Unplug electrical on Pits 1, 2, and 3. Blow down steam and water. R/D steam, water, air, hydraulic and pason lines. Lower serrick. Unplug all electrical connected to generators. Rig released at 06:00. Field: Deep Creek Unit Sundry #: State: ALASKA Rig/Service: HEC 169 Page 1/1 Well Name: DCU HVB-013A Report Printed: 5/15/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-231-20032-01-00 Field Name:Deep Creek Unit State/Province:ALASKA Permit to Drill (PTD) #:224-160 Sundry #: Rig Name/No: Jobs Actual Start Date:3/16/2025 End Date: Report Number 1 Report Start Date 3/16/2025 Report End Date 3/17/2025 Last 24hr Summary YJ E-Line CBL. PJSM and PTW. MIRU. Tbg/IA/OA: 0/0/0 psi. RIH w/ 1-11/16 SCBL. Tag PBTD @ 9593' MD. Log from TD to 3550'. Good data. Send for processing. RD. Job Complete Report Number 2 Report Start Date 3/31/2025 Report End Date 4/1/2025 Last 24hr Summary Complete PJSM / PTW. Spot Fox CTU10, crane, tool trailer. C/O flowcross valves 1-4 on BOPE stack. Crane pick 1.75" reel (43k) from lowboy to unit. Spot coil pump, return tank, N2 pump, and re-spot crane. N/U BOPE stack and R/U 2" 1502 hardline. Stab pipe through injector head. Completed BOPE test 250 psi low / 3500 psi high as per sundry. AOGCC Jim Regg waived witness 3/31/25 (09:17 am). SDFN. Report Number 3 Report Start Date 4/1/2025 Report End Date 4/2/2025 Last 24hr Summary Complete PJSM / PTW. M/U BHA = 2" BDN. Shell test 250 psi / 3500 psi. MIT-Tubing to 3500 psi for 30 minutes, passed first attempt (Lost 10 psi total). RIH w/BHA and tagged PBTD @ 9688'ctm. Circulate well to FW and blow well dry w/N2. Total fluid returns = 89.2 bbls. Calculated CV + CTBS = 89.3 bbls. Pooh w/BHA. Trap 2400 psi on tubing. SDFN. Report Number 4 Report Start Date 4/2/2025 Report End Date 4/3/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. P-test 250/3,500 psi. SITP 2,400 psi. Run GPT - sat down at 9,651'. No fluid seen. Perforate T-120 Sand from 9,617' - 9,637' with well shut-in. Run GPT and incrementally bleed well pressure to 1,350 psi; fluid level came up to 9,574'. Set CIBP at 9,575'. SD FN. Report Number 5 Report Start Date 4/3/2025 Report End Date 4/4/2025 Last 24hr Summary PTW/PJSM. SITP 1,200 psi. Perforate T-100 Sand (9,295' - 9,305'), T-99 Sand (9,242' - 9,252'), T-98 Sand (9,225' - 9,231'), T-91 Sand (9,152' - 9,166'), T-90 Sand (9,115' - 9,129'), T-80 Sand (8,924' - 8,938') with well shut-in. SDFN and turn well over to Production to flow test. SITP 1,640 psi. Report Number 6 Report Start Date 4/17/2025 Report End Date 4/18/2025 Last 24hr Summary PTW/PJSM. FTP 800 psi. MIRU YJ E-line. PT lubricator to 250 psi low / 3500 psi high - good test. RIH w/ 10'x10'x6' 2 3/8" 5 SPF 60 deg guns on switch and re-perforate T100 (9,295’ – 9,305’), T99 (9,242’ – 9,252’), and T98 (9,225’ – 9,231’). RIH w/ 14'x14' 2 3/8" 5 SPF 60 deg guns on switch and re-perforate T91 (9,152’ – 9,166’) and T90 (9,115’ – 9,129’). RIH w/ 14' x 2 3/8" 5 SPF 60 deg guns and re-perforate T80 (8,924’ – 8,938’). Secure well, SDFN. Report Number 7 Report Start Date 4/18/2025 Report End Date 4/19/2025 Last 24hr Summary PTW/PJSM. FTP 760 psi. RU YJ E-line. RIH w/ 6'x20' 2" 6 SPF 60 deg guns on switch and perforate T65 (8,656’ – 8,662’) and T48 (8,140’ – 8,160’). RIH w/ 31' x 2" 6 SPF 60 deg guns and perforate T40 (7,785’ – 7,816’). RIH w/ 10' x 2" 6 SPF 60 deg guns and perforate T32 (7,417’ – 7,427’). RIH w/ 6'x14'x10' 2" 6 SPF 60 deg guns on switch and perforate T10A (6,649’ – 6,655’), T10 Lower (6,609’ – 6,623’), and T10 Upper (6,523’ – 6,533’). Secure well, hand over to production, RDMO YJ E-line. !"# !$%& &%&% "'( )( $# ( * ( ( +( +,( ! ! #("## $ %& '(()* &+, -( ! ,( ($ %& '(()* &+, . ( - ! . )( / )( "' 0( ) )( +/0)*1 , 2 +/0)2 3232, 4(5 " 6- 66 + +" - #( #( 1-( .-( 213$+ 2.3$ " / #( ! ('(( ('(( / +( +0/'/7 //! &+('&7 8+!'((+#1(('(( ('8( 8+98+: +'870 2 8 9!(:!/'!(88- +, 456 7# - 4*6 ) - 456 ! #.)- ;;"/(/5 /</(</(/8 !'/8 0/'00 85 87&'75+ 8&7& "( ( #.( - ! '( . 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('57 &+5'+& !="-B CB 6)!, 5 5(' ('&8 ! 8'(+ ! +0!'5( 7!'+& 0&+'8/! !&/'5( / +( +(8'7+ /// + +'58 ('! 0(8'!& !="-B CB 6)!, 5 /(!'&! ('/7 ! 5'!8 5 (!8'7& 08'75 000'0/! 5/5'7& / +( + 5'/( /// + '55 ('&/ 0 8'&0 !="-B CB 6)!, 5 /&&' / +'78 ! /'!5 5 (+0'!+ &7'!5 078'&&! 57&'!+ / +( +/ '70 /// +(!'&0 ('7+ 0/8'88 !="-B CB 6)!, 5 !/0'!& ' 7 ! 0'7 5 80'&( &('5/ 0+!'8/! 85&'&( / +( +/+'+7 /// 7+&'(( /'0 0!8'57 !="-B CB 6)!, 5 !70'(0 '(0 ! 7'!8 5 / &' + 8 '78 7( '/ ! &(8' + / +( +!7'0/ /// 777'8( ('/8 058'5& !="-B CB 6)!, 5 58/'5( ('+( ! 0'(7 5 /7('!/ 5/'&5 7(+'8+! &&+'!/ / +( +57' / /// 77('!5 ('58 08&'/7 !="-B CB 6)!, 5 8 !'/! ('07 ! 0' 0 5 !5('(0 !5'/8 7 0'!0! 0/+'(0 / +( +8&'&7 /// 70/'08 ('/( 0&&'/7 !="-B CB 6)!, 5 800' 7 ('55 ! &'85 5 5(/'+/ /8'&& 7/8'5/! 0+ '+/ / +( +&8'58 /// 7&5'7+ ('8& 00&'& !="-B CB 6)!, 5 &5('(/ '!( ! &'5& 5 5&5'&! 0'(& 7!!'87! 78!'&! / +( +05'/! /// 78&'+! '!0 070'(! !="-B CB 6)!, 5 0(/'( '/& ! 0'0( 5 8/8'5! 7' + 75 '75! + 5'5! / +( +7!'!( /// 757'77 ('5( 0+0'&5 !="-B CB 6)!, 5 0&5'07 ' 0 ! 0'+! 5 870'(( ('7& 78('(5! +0&'(( / +( ++/'8! /// 75('7+ (' & 7(7'/5 !="-B CB 6)!, 5 7/7' 8 ('&( ! &'/+ 5 &5+'/! +'&! 787' 75 (!7'/! / + (( '57 /// 7!/'+8 '(/ 7 7'0( !="-B CB 6)!, 5 7+ '&0 ('(0 ! 0'+5 5 0 '0/ 0'+7 7&8'+!5 (('0/ / + ( ('(( /// 7/8'!+ ('+& 7/7'&0 !="-B CB 6)!, 5 +8&'/5 +'7 ! 0'7+ 5 008'!/ /&'/8 70!'5(5 &5'!/ / + ( 7'55 /// 7 7' ('5( 7!7'!5 !="-B CB 6)!, 8 ( +'/! ('8! ! 5'+/ 5 7!0'!/ !5'/+ 77 '(75 //&'!/ / + (/&'&& /// 7 ('&/ '5 757' ! !="-B CB 6)!, 8 (7/'( +'+0 ! 8'7& 5 7++' ( 5/'/5 777'+/5 /77' ( / + (!5'0+ /// 7(/'+& ('+! 787'(& !="-B CB 6)!, 8 58'(! +'87 ! &'57 5 +& '/( 5+'+& 7+&'!55 !8('/( / + (5/'&0 /// 0+8'0! ('&5 7&0'8( !="-B CB 6)!, 8 /(7'/! ('&0 ! 8'0& 8 (/!'5/ 80'+0 +(5'(55 5 /'5/ / + (8('78 /// 077'/ '05 700'! !="-B CB 6)!, 8 /0 '& ('80 ! &'+( 8 (78'0 &&'5/ + /' (5 505'0 / + (8+'57 /// 07('!5 ('!0 770'&( !="-B CB 6)!, 8 !!!'+! ('/( ! &'(+ 8 50'( 05'8& + +'755 8!&'( / + (&0'7( /// 00/'0+ ('&5 7+0'57 !="-B CB 6)!, 8 !+0'( +'&+ ! 0' 8 /(+' 5 7/'57 +/0'!/5 8+7' 5 / + (08'77 /// 0&8'5+ ('7& +(0'(& !="-B CB 6)!, 8 5&('8( ('+! ! 0'(+ 8 /0 '& +('7( +!8'(&5 &&('& / + (75'!7 /// 080'+5 '+8 + 0'(( !="-B CB 6)!, 8 8/!'0! ('/5 ! &'!+ 8 !!!'0& ++'/& +5!'(/5 0//'0& / + (+!'(/ /// 08(' 7 ' +/0' + !="-B CB 6)!, 8 87&'(! ' & ! 0'7/ 8 !+5'+7 (0'05 +8('775 07!'+7 / + ( '&7 /// 05/'8 '85 +!0'!( !="-B CB 6)!, 8 &5+'/8 ('70 ! 0'/5 8 580'(! &'&8 +8+'(55 75&'(! / + ('00 /// 0!5'8& ('5+ +50'7/ !="-B CB 6)!, 8 0 '0! ('/5 ! 0'58 8 8 7'58 /8'(0 +&&'0+5 +(0'58 / + +'!& /// 0/0'(( '( +80'7 !="-B CB 6)!, "'( )( $# ( * ( ( +( +,( ! ! #("## $ %& '(()* &+, -( ! ,( ($ %& '(()* &+, . ( - ! . 4 6 9 456 : 456 213$+ 4 6 2.3$ 4 6 * 4 6 * 4 6 .- 46 1- 46 46 453%;6 *.) 8 005'7/ 7'+8 ! !'&7 8 87('&& !/'8+ +05' 55 +&+'&& / + /0'(8 /// 0 +'7! /'/0 +&0' / !="-B CB 6)!, 8 7!5'0( 0'85 ! 5'77 8 &!+'+/ !7'87 +7('/+8 (/7'+/ / + !!' 7 /// 0 !'7 /'!0 +05'7! !="-B CB 6)!, 8 7++'(! &'+& ! 5'!& 8 0(!'0! 55'/7 +7&'(08 (+/'0! / + !+'( /// 0(7' 0 ('+ +7/' ( !="-B CB 6)!, 8 +& '0+ &'( ! 5'80 8 0&&'(+ 5+'/5 ++ ' !8 88'(+ / + 55'(+ /// 0(!'// '8 +77'58 !="-B CB 6)!, & (/5'/! 8'/( ! 5'0 8 7/7'/! 8!'8! ++8'508 / 0'/! / + 57'50 /// &+7'+7 '!( ++!'+( !="-B CB 6)!, & (70'&0 &'&( ! 8'&& 8 7+ '!5 87' & ((('(&8 /7('!5 / + 8!'/( /// &+5'8( /'/ +++'0 !="-B CB 6)!, & 5+'!7 &'(& ! !'!! 8 +8/'&0 &/'+! ((5'+ 8 !5 '&0 / + 87'(7 /// &7+'0& ('+0 ((8'7( !="-B CB 6)!, & / !'(8 8'+0 ! &'(0 & ( 8'++ &0'&/ ((+'&88 5(5'++ / + &/'77 /// &78' ! ('50 ( '0& !="-B CB 6)!, & /05'&8 8'&5 ! 5'(/ & (00'/0 0/'(! ( 5'(88 5&&'/0 / + &0'!+ /// &7('7! ('&! ( 0'! !="-B CB 6)!, & !!0'57 &'8& ! /'0+ & !+'08 0&'&/ ( 7'+(8 8/7'08 / + 0/'(7 /// &0&'(7 '57 (/!'!8 !="-B CB 6)!, & 5(('7( &'58 ! 5'5! & /(/'&& 7 '8& (/5'(+8 8+ '&& / + 00' 8 /// &0 '(( ('!5 (/+'7/ !="-B CB 6)!, & 5&!'7( &'(+ ! 8'/& & /&8'/7 7&'5 (/7'+08 &85'/7 / + 7/' /// &&&'/! ('8+ (!8'+0 !="-B CB 6)!, & 8/8'8! 8'8+ ! !'+0 & !/&'&+ +('7! (!!'558 0 8'&+ / + 7&'&/ /// && '70 ('75 (5 '8+ !="-B CB 6)!, & 877'/! &'05 ! /'/0 & !7+'(! +8'5/ (!7'!&8 007'(! / + + '!! /// &80'(8 '7& (50'&+ !="-B CB 6)!, & &50'50 &'7 ! 8'( & 550'78 /(('/5 (5!'5/8 7!&'78 / + +&'/0 /// &8/' ('8& (85'(( !="-B CB 6)!, & 0 !'(7 8'+5 ! 0'7& & 8 !'(& /(8'8 (57'588 +(/'(& / + /( '&8 /// &50'/( '5 (&('5 !="-B CB 6)!, & 00&' + 8'&/ !/ '(& & 808'78 / ('!5 (8/'878 +&5'78 / + /(&'80 /// &5!' 7 ('0/ (&8'75 !="-B CB 6)!, & 7!+'(5 &'// !/ '(+ & &!7'!& / 8'!7 (8&'&8& (/0'!& / + / '0( /// &!+'// ('+8 (0 '/7 !="-B CB 6)!, & +(/'/ &'5( !/ '(/ & 0( ' 8 //('07 (& '(/& (+(' 8 / + / 0'/( /// &!5'+7 ('/+ (00' ( !="-B CB 6)!, & +&8'!5 &'( ! 7'8+ & 0&!'+ //8'++ (&8'5/& 8/'+ / + ///'8 /// &!('0( ('05 (7/'+ !="-B CB 6)!, 0 (/0' & 8'!& ! &'/+ & 7/8'5! /!('8 (&+'88& / 5'5! / + //0' / /// &/&'&0 ' (77'/5 !="-B CB 6)!, 0 (+('8/ 8'& ! 5'+5 & 777'8( /!5'75 (0!'0+& /00'8( / + /! '85 /// &//'85 ('55 (+!'& !="-B CB 6)!, 0 8 '&7 5'77 ! /'+( & +5+'5( /!7'0/ (00'7 & !!7'5( / + /!8'8 /// & 7'&( '/! (+7'&5 !="-B CB 6)!, 0 / &'!/ 5'88 ! /'&7 0 ( !'7/ /5/'!! (7 '0 & 5(/'7/ / + /!+'/ /// & 5'0+ ('8 (!'50 !="-B CB 6)!, 0 /0+'!/ !'0& !(0' 8 0 (0&'&8 /58'/0 (78' +& 5&8'&8 / + /5/'/! /// & '!0 '5( (0'&+ !="-B CB 6)!, 0 !5/'!8 8' & !(7' 7 0 !+'5+ /57'/0 (7+'(0& 8/7'5+ / + /58'!/ /// &(0'80 /'// /'! !="-B CB 6)!, 0 5(8'8( 5'0/ ! ('8( 0 /(/'5 /8 '0 (+!'/7& 8+ '5 / + /57'7& /// &(!'55 ('00 0'!7 !="-B CB 6)!, 0 5&&'!+ &' 8 ! 5'(7 0 /&!'(/ /88'& (+0'8/& &8/'(/ / + /8/'78 /// 8++'/7 /'5 //'&! !="-B CB 6)!, 0 8/+'(5 0'!7 ! !'+& 0 !/8'/! /&('05 (/'7!& 0 5'/! / + /87' ( /// 8+5'(+ '+& /+'/& !="-B CB 6)!, 0 8+!'&! &'+7 ! '++ 0 !7+'!/ /&&'/5 (7'05& 007'!/ / + /&!'0! /// 877'!/ ('0! !&'8+ !="-B CB 6)!, 0 &88'+& &'&0 ! ('0+ 0 58 '/ /0 ' 5 5'/+& 75('/ / + /&7'0& /// 87/'70 ('88 5!'!+ !="-B CB 6)!, 0 0 7'8& &'// ! ('77 0 8 !'5 /08'0! +'& & +(/'5 / + /0!'50 /// 800'&& ('0/ 5+'70 !="-B CB 6)!, 0 00+'&8 &' 7 ! ('&/ 0 805' 5 /7('(5 /5'& & +&!' 5 / + /00'7+ /// 80/'0& ('(7 88'+& !="-B CB 6)!, 0 75/'8( &'/8 !(0'(8 0 &!&'&/ /75'! /+'+(0 (/8'&/ / + /7/'/7 /// 8&0'8& ('&/ &/'!/ !="-B CB 6)!, 0 +(!'+( 8'70 !(!'! 0 &+0'&7 /77'(5 !8'/(0 (7&'&7 / + /7&' ! /// 8&/'!& ('7+ &7'8 !="-B CB 6)!, 0 +&7'/7 &'(7 !(+'&8 0 0& '0 /+/'(! 5('800 8('0 / + /+('/5 /// 880'(7 '(7 05'7& !="-B CB 6)!, 7 (/+'(7 &'75 ! &'(5 0 7//' ! /+&'&+ 58'8&0 / ' ! / + /+8'( /// 88/' + '0/ 7 '(8 !="-B CB 6)!, 7 (+!'05 &' & ! 5'+( 0 77&'!0 !( '+ 8('&+0 /08'!0 / + !(('!8 /// 850' 7 '(0 70'88 !="-B CB 6)!, 7 8&'(! 8'0 ! 7'8( 0 +57'!! !(&'8+ 88' /0 !!0'!! / + !(8' ! /// 85/'70 ('+5 +!'/( !="-B CB 6)!, 7 / &'+& 8'( !/('7 7 ((7'++ ! ('+/ 87'7(0 !+0'++ / + !(+'85 /// 8!+'/7 '/( +7'(& !="-B CB 6)!, "'( )( $# ( * ( ( +( +,( ! ! #("## $ %& '(()* &+, -( ! ,( ($ %& '(()* &+, . ( - ! . 4 6 9 456 : 456 213$+ 4 6 2.3$ 4 6 * 4 6 * 4 6 .- 46 1- 46 46 453%;6 *.) 7 /0+'&+ 8'75 ! +'/5 7 (0 '55 ! 8'5& &/'&/0 5&('55 / + ! 5' 0 /// 8!8'80 '!5 /(!'(+ !="-B CB 6)!, 7 !5 '&0 0' 0 ! /'75 7 !!'(/ !/('57 &0'8 0 8//'(/ / + ! +'!( /// 8!('0+ /'55 /(+'! !="-B CB 6)!, 7 5(0' 7 0'/5 ! !'0& 7 +7'( !/&' 0!'5+0 870'( / + !/8'(0 /// 8/5'+5 ('/ / &'05 !="-B CB 6)!, 7 50('57 &'&5 ! /'!( 7 /&('78 !! '!5 0+'(70 &5+'78 / + !!('5/ /// 8 +'50 ('++ //!'&0 !="-B CB 6)!, 7 8!5'(5 &'5/ ! '(! 7 !/5'(( !!&' 5 75'570 0 !'(( / + !!8'!5 /// 8 5' + ('5 /!('!( !="-B CB 6)!, 7 8+&'+5 8'&& !(7'/8 7 !7&'88 !5('!0 7+'800 008'88 / + !!+'&+ /// 8(+' + '/+ /!&'58 !="-B CB 6)!, 7 &87'!& 8'(/ !(&'07 7 550'0( !5!'78 +5' (0 7!&'0( / + !5!'/0 /// 8(5'05 '(0 /5 '75 !="-B CB 6)!, 7 0//' 5'&8 /++'/! 7 8 '// !5&'0+ +7'8+0 +(('// / + !5&'! /// 8(('!/ ' 8 /50'(/ !="-B CB 6)!, 7 078'5& !'+ /+8'&& 7 805'5( !57'+7 /(/'070 +&!'5( / + !57'8+ /// 5+&' + '/5 /8 '&7 !="-B CB 6)!, 7 757' & !'&+ /+0'0/ 7 &!&'+& !8('75 /(&'5+7 (/8'+& / + !8('85 /// 5+/'8/ ('5 /88'0+ !="-B CB 6)!, 7 + ('85 !'/8 /+5'!/ 7 &++'// !8/'8( /(+'777 (77'// / + !8/'/7 /// 57+' 0 ('07 /8+'8/ !="-B CB 6)!, 7 +0/'+( /'&! /+&'&( 7 0& '8( !8!'70 / /'007 8('8( / + !8!'0 /// 57&'! '( /&/'&+ !="-B CB 6)!, + (!&' 5 '+0 /+!'8& 7 7/5'&+ !85'+8 / 8'(&7 / !'&+ / + !85'78 /// 575'(5 '(& /&8'/ !="-B CB 6)!, + (+7'+& ' ! /+/'! 7 770'5+ !88'&/ / &'&/7 /0&'5+ / + !88'88 /// 57/'5+ '!5 /&&'+( !="-B CB 6)!, + &(' ( ' 8 /+!'07 7 +57'& !8&' ( / 0'057 !!0'& / + !8&'(8 /// 57 '!+ ('(& /&7' / !="-B CB 6)!, + / 7'+& ('+& !(5'/8 + ((0'5& !8&'& / 7'&+7 !+&'5& / + !8&'8+ /// 57('58 ('5& /&+' 7 !="-B CB 6)!, + /7('58 ('7 !/ ' ! + (&7'+8 !80'/5 / +'!+7 580'+8 / + !80'/! /// 50+'00 ('5+ /0('(5 !="-B CB 6)!, + !5&'/! ('00 ! &'8! + !5'0/ !80'+/ / +'++7 8/!'0/ / + !80'+! /// 50+' + (' /0('7 !="-B CB 6)!, + 5(8'+7 ('!/ !57'7+ + +5'50 !87'!7 //('/+7 87!'50 / + !87'!+ /// 507'7+ ('77 /0 '/8 !="-B CB 6)!, + 50 '// ('8 75'&+ + /8+'0 !87'8+ //('(57 &57'0 / + !87'8+ /// 50+' 8 ('+& /0 '(0 !="-B CB 6)!, + 8! '75 ('&! +!'!5 + !/('!/ !87'8+ / +'557 0(+'!/ / + !87'87 /// 50+'08 ('/5 /0('8( !="-B CB 6)!, + 8+!'&/ '(5 0&' 8 + !7/' ( !87'0 / 7'8&7 00 ' ( / + !87'&7 /// 57('&! ('00 /&+'0( !="-B CB 6)!, + &8&'88 '/! 08'0! + 558'( !8+'( / 0'!87 7!5'( / + !87'+8 /// 57 '78 ('!( /&7'&5 !="-B CB 6)!, + 0/+'8 '/5 0!'(8 + 8 0'+& !8+'5! / 8'7!7 +(&'+& / + !8+'!5 /// 57!'!0 ('(7 /&0'!5 !="-B CB 6)!, + 008'(( '/5 0!'(8 + 8&!'55 !8+'0/ / 5'7+7 +8/'55 / + !8+'& /// 575'!/ ('(( /&&'8! 3F*.*. @G@ @ Page 1/1 Well Name: DCU HVB-013A Report Printed: 5/15/2025 WellViewAdmin@hilcorp.com Casing Intermediate1 Wellbore Wellbore Name: HV B-13A Total Depth of Wellbore (ftKB): 9,775.00 Original KB/RT Elevation (ft): 611.00 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Intermediate1 Run Date: 2/18/2025 Set Depth (ftKB): 3,822.89 Casing Weight on Slips (1000lbf): 64,000.0 Pick Up Weight (1000lbf): 154,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 8.00 Ft/Min (ft/min): 7.96 Run Job: 251-00024 HVB-13A Drilling, Drilling - Drilling, 2/9/2025 06:00 Set Depth (ftKB): 3,822.89 Set Depth (TVD) (ftKB): 3,662.7 Centralizer Detail: Attribute Subtype: Value: Pipe Reciprocated?: No Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) Casing Hanger 10 1/8 6.28 0.75 22.10 21.35 Casing Joints 7 6.28 26.00 P-110 3.23 25.33 22.10 81 Casing Joints 7 6.28 26.00 P-110 3,702.77 3,728.10 25.33 Float Collar 7.825 6.13 Newland 1.35 3,729.45 3,728.10 2 Casing Joints 7 6.28 26.00 P-110 91.86 3,821.31 3,729.45 Shoe 7.825 6.13 Newland 1.58 3,822.89 3,821.31 Page 1/1 Well Name: DCU HVB-013A Report Printed: 5/15/2025 WellViewAdmin@hilcorp.com Cement Intermediate Casing Cement Type Casing Description Intermediate Casing Cement Cemented String Intermediate1, 3,822.89ftKB Wellbore HV B-13A, HAPPY VALLEY B-13A Job 251-00024 HVB-13A Drilling, Drilling - Drilling, 2/9/2025 06:00 Cementing Start Date 2/19/2025 Cementing End Date 2/19/2025 Top Depth (ftKB) 22.0 Cement Stages Stage Number: 1 Description Intermediate Casing Cement Top Depth (ftKB) 22.0 Bottom Depth (ftKB) 3,831.0 Top Measurement Method Returns to Surface Pump Start Date 2/19/2025 Cement in Place At 2/19/2025 Final Circulating Pressure (psi) 980.0 Plug Bump Pressure (psi) 1,700.0 Full Return? No Returns During Job (%) Volume to Surface (bbl) 22.0 Volume Lost (bbl) 7.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? No Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer)10.50 60.0 4 Halliburton Lead Slurry 243 2.39 12.00 101.0 5 Halliburton Tail Slurry 99 1.24 15.30 61.0 4 Halliburton Displacement 9.20 143.0 5 Halliburton Post Job Calculations Subtype Value Page 1/1 Well Name: DCU HVB-013A Report Printed: 5/15/2025 WellViewAdmin@hilcorp.com Casing Production1 Wellbore Wellbore Name: HV B-13A Total Depth of Wellbore (ftKB): 9,775.00 Original KB/RT Elevation (ft): 611.00 RKB to GL (ft): 18.00 KB-Casing Flange Distance (ft): KB-Tubing Hanger Distance (ft): PBTDs Depth (ftKB): Casing Casing Description: Production1 Run Date: 2/26/2025 Set Depth (ftKB): 9,773.00 Casing Weight on Slips (1000lbf): 105,000.0 Pick Up Weight (1000lbf): 160,000.0 Block Weight (1000lbf): 15,000.0 Make-Up Contractor: Parker Casing Number Hrs to Run (hr): 16.50 Ft/Min (ft/min): 9.87 Run Job: 251-00024 HVB-13A Drilling, Drilling - Drilling, 2/9/2025 06:00 Set Depth (ftKB): 9,773.00 Set Depth (TVD) (ftKB): 9,562.4 Centralizer Detail: 100 cent every other jt Attribute Subtype: Value: Pipe Reciprocated?: Yes Pipe Rotated?: No Float Failed?: No Test Subtype: Pressure (psi): Casing (Or Liner) Details Jts Item Des OD Nominal (in)Nominal ID (in) Wt (lb/ft) Grade Top Thread Make Section Length (ft)Btm (ftKB) Top (ftKB) Liner Hanger 6 7/8 23.57 3,645.13 3,621.56 Cross Over 5.62 1.70 3,646.83 3,645.13 20 Liner 3 1/2 2.99 9.20 L-80 631.86 4,278.69 3,646.83 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.75 4,288.44 4,278.69 16 Liner 3 1/2 2.99 9.20 L-80 497.85 4,786.29 4,288.44 Marker Jt 3 1/2 2.99 9.20 L-80 9.75 4,796.04 4,786.29 16 Liner 3 1/2 2.99 9.20 L-80 498.42 5,294.46 4,796.04 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.74 5,304.20 5,294.46 15 Liner 3 1/2 2.99 9.20 L-80 466.61 5,770.81 5,304.20 Marker Jt 3 1/2 2.99 9.20 L-80 9.75 5,780.56 5,770.81 16 Liner 3 1/2 2.99 9.20 L-80 496.78 6,277.34 5,780.56 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.75 6,287.09 6,277.34 16 Liner 3 1/2 2.99 9.20 L-80 496.93 6,784.02 6,287.09 Marker Jt 3 1/2 2.99 9.20 L-80 9.75 6,793.77 6,784.02 16 Liner 3 1/2 2.99 9.20 L-80 495.48 7,289.25 6,793.77 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.75 7,299.00 7,289.25 16 Liner 3 1/2 2.99 9.20 L-80 500.34 7,799.34 7,299.00 Marker Jt 3 1/2 2.99 9.20 L-80 9.76 7,809.10 7,799.34 15 Liner 3 1/2 2.99 9.20 L-80 461.65 8,270.75 7,809.10 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.68 8,280.43 8,270.75 16 Liner 3 1/2 2.99 9.20 L-80 488.29 8,768.72 8,280.43 Marker Jt 3 1/2 2.99 9.20 L-80 9.75 8,778.47 8,768.72 16 Liner 3 1/2 2.99 9.20 L-80 484.76 9,263.23 8,778.47 RA Marker Jt 3 1/2 2.99 9.20 L-80 9.75 9,272.98 9,263.23 14 Liner 3 1/2 2.99 9.20 L-80 434.22 9,707.20 9,272.98 Float Collar 3 1/2 1.68 9,708.88 9,707.20 2 Liner 3 1/2 2.99 9.20 L-80 62.21 9,771.09 9,708.88 Float Shoe 3 1/2 1.91 9,773.00 9,771.09 Page 1/1 Well Name: DCU HVB-013A Report Printed: 5/15/2025 WellViewAdmin@hilcorp.com Cement Liner Cement Type Casing Description Liner Cement Cemented String Production1, 9,773.00ftKB Wellbore HV B-13A, HAPPY VALLEY B-13A Job 251-00024 HVB-13A Drilling, Drilling - Drilling, 2/9/2025 06:00 Cementing Start Date 2/27/2025 Cementing End Date 2/27/2025 Top Depth (ftKB) 4,572.0 Cement Stages Stage Number: 1 Description Liner Cement Top Depth (ftKB) 4,572.0 Bottom Depth (ftKB) 9,775.0 Top Measurement Method CBL Pump Start Date 2/27/2025 Cement in Place At 2/27/2025 Final Circulating Pressure (psi) 1,900.0 Plug Bump Pressure (psi) 2,350.0 Full Return? No Returns During Job (%) Volume to Surface (bbl) 0.0 Volume Lost (bbl) 70.0 Bump Plug? Yes Float Failed? No Pipe Reciprocated? Yes Pipe Rotated? No Slurry Type Class Amount (sacks) Yield (ft³/sack) Dens (lb/gal) Actual Volume Pumped (bbl) Calculated Volume Pumped (bbl)Q Avg (bbl/min) Pump Used Preflush (Spacer) Spacer 10.50 30.0 4 Halliburton Lead Slurry Lead 441 2.39 12.00 187.5 4 Halliburton Tail Slurry Tail 180 1.24 15.30 36.0 4 Halliburton Displacement 90.8 4 Halliburton Post Job Calculations Subtype Value MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-13A HAPPY VALLEY B-13A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 B-13A 50-231-20032-01-00 224-160-0 N SPT 3473 2241600 2500 0 2642 2588 2580 0 0 0 0 OTHER P Brian Bixby 3/1/2025 MIT-T Post Completion HAK 169 Rig 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:HAPPY VALLEY B-13A Inspection Date: Tubing OA Packer Depth 0 0 0 0IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB250403191038 BBL Pumped:0.8 BBL Returned:0.8 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 9 9 9 *DVSURGXFHU James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:31:18 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, April 23, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Brian Bixby P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC B-13A HAPPY VALLEY B-13A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 04/23/2025 B-13A 50-231-20032-01-00 224-160-0 N SPT 3473 2241600 2500 0 240 240 240 0 0 0 0 OTHER P Brian Bixby 3/1/2025 MIT-IA Post Completion HAK 169 Rig 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:HAPPY VALLEY B-13A Inspection Date: Tubing OA Packer Depth 0 2625 2580 2580IA 45 Min 60 Min Rel Insp Num: Insp Num:mitBDB250403191457 BBL Pumped:1 BBL Returned:1 Wednesday, April 23, 2025 Page 1 of 1 9 9 9 9 9 9 9 999 99 9 9 9 9 9 *DVSURGXFHU MIT-IA James B. Regg Digitally signed by James B. Regg Date: 2025.04.23 12:29:04 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/22/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#2025022 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 14B 50133205390200 222057 4/10/2025 AK E-LINE CBL BRU 241-23 50283201910000 223061 4/7/2025 AK E-LINE Perf BRU 241-26 50283201970000 224068 4/12/2025 AK E-LINE CIBP BRU 244-27 50283201850000 222038 4/8/2025 AK E-LINE Perf MPU B-21 50029215350000 186023 4/7/2025 AK E-LINE LDL MPU C-24A 50029230200100 209134 4/6/2025 AK E-LINE CBL MPU J-25 50029232070000 204073 4/5/2025 AK E-LINE JetCut NCIU A-21 50883201990000 224086 4/4/2025 AK E-LINE Perf NCIU A-18 50883201890000 223033 4/5/2025 AK E-LINE Perf PBU Z-235 50029237600000 223055 4/1/2025 READ InjectiojnProfile HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL HVB 18 50231201210000 225001 4/4/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40328 T40329 T40330 T40331 T40332 T40333 T40334 T40335 T40336 T40337 T40338 T40339 HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.28 08:42:09 -08'00' 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, March 26, 2025 5:35 PM To:Scott Warner Cc:Donna Ambruz Subject:RE: HVB-13A AOGCC 10-403 325-131 PTD 224-160 Approved 03-13-25 Scott, Hilcorp has approval to perforate these additional intervals as requested in your email below, and to proceed with the rest of the sundry based on the results of the cement log, with TOC estimate of 4609’ MD referenced to the CBL log. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Scott Warner <Scott.Warner@hilcorp.com> Sent: Wednesday, March 26, 2025 3:03 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: FW: HVB-13A AOGCC 10-403 325-131 PTD 224-160 Approved 03-13-25 Bryan, Hilcorp is requesting a minor change to the proposed perf table in the approved sundry. Top T1 interval we would like to perforate is 5947’-5967’, in the sundry we have 5948’ as the top. Requesting to add 1 additional foot to that interval. Bottom of the T120 interval we would also like to extend by 1’, making the new bottom interval 9652’ making the whole interval 9617-9652’. I also mention in the table that additional sand may be added but wanted to request clear permission to perforate the T100 which is between the top and bottom proposed perfs. - T100 interval we are requesting is 9295’-9305’. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 The CBL is also attached. Thanks, ScoƩ Warner Kenai – OperaƟons Engineer Office: (907) 564-4506 Cell: (907) 830-8863 To help protect your priv acy, Microsoft Office prevented automatic download of this picture from the Internet. From: Donna Ambruz <dambruz@hilcorp.com> Sent: Friday, March 14, 2025 7:30 AM To: Scott Warner <Scott.Warner@hilcorp.com> Cc: Noel Nocas <Noel.Nocas@hilcorp.com> Subject: HVB-13A AOGCC 10-403 325-131 PTD 224-160 Approved 03-13-25 3 FYI – Please distribute as necessary. Thank you. Donna Ambruz Operations/Regulatory Tech KEN Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 907.777.8305 - Direct dambruz@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. David Douglas Hilcorp Alaska, LLC Sr. GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/14/2025 To: Alaska Oil & Gas Conservation Commission Natural Resources Technician 333 W. 7th Ave. Ste#100 Anchorage, AK 99501 DATA TRANSMITTAL WELL: Happy Valley B-13A (HV B-13A) PTD: 224-160 API: 50-231-20032-01-00 FINAL LWD FORMATION EVALUATION LOGS (02/14/2025 to 02/25/2025) DGR, ADR, PCG-K, ALD, CTN (2” & 5” MD/TVD Color Logs) Final Definitive Directional Survey Folder Contents: Please include current contact information if different from above. 224-160 T40214 Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.03.14 15:54:54 -08'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate 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: Initial Completion, N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 9,775'N/A Casing Collapse Structural Conductor Surface Intermediate 5,410psi Production Liner 10,540psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng LTP; N/A 3,621' MD/3,464' TVD; N/A, N/A 9,563'9,707'9,495' Deep Creek Unit Happy Valley, Beluga-Tyonek Gas 20" 9-5/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Happy Valley B (HVB) 13ACO 821 Same ~3206 psi N/A Length March 19, 2025 9,773'6,164' Tieback 3-1/2" 9,561' Perforation Depth MD (ft): 3,822' 3-1/2" See Attached Schematic 7,240psi 117' 3,661' 117' 1,157' Size 117' 7"3,822' 1,157' MD Hilcorp Alaska, LLC Proposed Pools: 9.2# / L-80 TVD Burst 3,629' 1,157' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 C061589 224-160 50-231-20032-01-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Scott Warner, Operations Engineer AOGCC USE ONLY 10,160psi Tubing Grade: scott.warner@hilcorp.com 907-564-4506 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 325-131 By Gavin Gluyas at 12:35 pm, Mar 07, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.07 12:18:15 - 09'00' Noel Nocas (4361) Submit CBL and obtain AOGCC approval before perforating. Perforations above 5948' md are not authorized under this sundry application. A.Dewhurst 12MAR25BJM 3/12/25 X CT BOP test to 3500 psi DSR-3/10/25 10-404 *&: 03/13/25 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.13 14:04:56 -08'00' RBDMS JSB 031825 Well Prognosis Well Name: HVB-13A API Number: 50-231-20032-01-00 Current Status: New Drill Well Permit to Drill Number: 224-160 Regulatory Contact: Donna Ambruz (907) 777-8305 First Call Engineer: Scott Warner (907) 564-4506 (O) (907) 830-8863 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 4150 psi @ 9433’ TVD (Based on 0.44 psi/ft gradient) Max. Potential Surface Pressure: 3206 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: .77 psi/ft using 14.85 ppg EMW FIT at the 7” intermediate casing shoe Shallowest Allowable Perf TVD: MPSP/(0.77-0.1) = 3206 psi / 0.67 = 4785’ TVD Top of Applicable Gas Pool: 2236’ MD/2106’ TVD (HV Beluga-Tyonek) Well Status: New Drill Initial Completion Brief Well Summary HVB-13A is a new sidetrack well targeting the Tyonek and Beluga sands. This objective of this sundry is to clean out the liner with coil tubing/nitrogen and perforate the Bel 43 through T-120. Wellbore Conditions: - Max Inclination – 34.9° at 1,200’ MD - Max DLS °/100’ – 6.6° at 388’ MD - Liner is full of ~9.1 ppg 6% KCl mud - Tubing and IA are displaced to 8.4 ppg CIW - T & IA have been pressure tested to 2500 psi Pre-Sundry Work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool in 3-1/2” liner a. Send results to AOGCC to review prior to perforating 4. RDMO E-line 5. Pressure test tubing to 3500 psi – chart for 30 min Procedure: 1. MIRU Coil Tubing and pressure control equipment 2. PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24hr notice for BOP test 3. RIH & clean out wellbore to ~9700’ MD (~8’ above landing collar), displace liner to 8.4 ppg water 4. Reverse out wellbore with nitrogen, trap ~2400 psi on wellbore a. ~85 bbls total wellbore volume 5. RDMO Coil Tubing 6. MIRU E-line and pressure control equipment 7. PT lubricator to 250 psi low / 3,500 psi high 8. Ops bleed N2 from well as directed by OE/RE for desired perforating pressure by zone (typically targeting 20% underbalance) 9. RIH and perforate per RE/Geo and test sands within the interval below, from the bottom up: Well Prognosis Below are proposed targeted sands in order of testing (bottom/up), but additional sand may be added depending on results of these perfs, between the proposed top and bottom perfs Sand Top MD Btm MD Top TVD Btm TVD Interval BEL_43 ±3,975' ±4,006' ±3,811' ±3,842' ±31' BEL_46 ±4,130' ±4,140' ±3,963' ±3,973' ±10' BEL_46 ±4,154' ±4,160' ±3,987' ±3,993' ±6' BEL_50 ±4,317' ±4,331' ±4,147' ±4,161' ±14' Perforations above 4785’ TVD will not be added until a plug is set and/or lower perforations are depleted. Perforations will not be added without further AOGCC approval. T1 ±5,948' ±5,954' ±5,752' ±5,758' ±6' T1 ±5,961' ±5,967' ±5,765' ±5,771' ±6' T3 ±6,072' ±6,078' ±5,876' ±5,882' ±6' T5 ±6,109' ±6,115' ±5,913' ±5,918' ±6' T6 ±6,244' ±6,258' ±6,047' ±6,061' ±14' T7 ±6,338' ±6,344' ±6,140' ±6,146' ±6' T7 ±6,387' ±6,397' ±6,189' ±6,199' ±10' T10 ±6,523' ±6,533' ±6,324' ±6,334' ±10' T10 ±6,609' ±6,623' ±6,410' ±6,424' ±14' T10A ±6,649' ±6,655' ±6,449' ±6,455' ±6' T17 ±6,822' ±6,853' ±6,621' ±6,652' ±31' T17 ±6,861' ±6,896' ±6,660' ±6,695' ±35' T32 ±7,417' ±7,427' ±7,214' ±7,224' ±10' T40 ±7,785' ±7,816' ±7,579' ±7,610' ±31' T48 ±8,140' ±8,160' ±7,932' ±7,952' ±20' T65 ±8,656' ±8,662' ±8,445' ±8,451' ±6' T70A ±8,820' ±8,840' ±8,609' ±8,629' ±20' T80 ±8,927' ±8,937' ±8,709' ±8,726' ±10' T90 ±9,115' ±9,129' ±8,716' ±8,918' ±14' T91 ±9,152' ±9,166' ±8,904' ±8,955' ±14' T99 ±9,225' ±9,231' ±8,941' ±9,020' ±6' T99 ±9,242' ±9,252' ±9,031' ±9,040' ±10' T120 ±9,617' ±9,637' ±9,405' ±9,425' ±20' T120 ±9,645' ±9,651' ±9,433' ±9,439' ±6' a. If any zone produces sand and/or water or needs isolated, RIH and set plug above the perforations OR patch across the perforations i. Pending well production, all perf intervals may not be completed ii.Note: Note: A CIBP may be used instead of WRP if it is determined that no cement is needed for operational purposes. Perforations above 4785’ TVD will not be added until a plug is set and/or lower perforations are depleted. Perforations will not be added without further AOGCC approval Perfs above 5948' md are not authorized as part of this sundry. -bjm Well Prognosis iii. If necessary, use nitrogen to pressure up well during perforating or to depress water prior to setting a plug above perforations 10. RDMO 11. Turn well over to production & flow test well 12. Test SVS as necessary once well has reached stable flow rates a. Notify state 24 hrs prior to testing within 5 days of stable production Coil Procedure (Contingency) 1. MIRU Coil Tubing, PT BOPE to 250 psi low / 3,500 psi high a. Provide AOGCC 24 hr notice for BOP test 2. PU wash nozzle and/or motor and mill, RIH and cleanout well to below perfs or proposed plug depth 3. PU CT jet nozzle and RIH, unload fluid from wellbore with nitrogen Attachments: 1. Current Schematic 2. Proposed Schematic 3. Coil Tubing BOP Schematic 4. Standard Well Procedure – N2 Operations _____________________________________________________________________________________ Updated by DMA 03-07-25 CURRENT SCHEMATIC Deep Creek Unit – B Pad Well: HVB-13A PTD: 224-160 API: 50-231-20032-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn Top Btm 20"Conductor 109 / X-56 / Weld Surface 117' 9-5/8'Surface 40 /L-80/ BTC Surface 1,157’ Open Hole Whipstock set @ 1,200’ MD 7”Intermediate 26 / L-80 / BTC Surface 3,822’ 3-1/2”Prod liner 9.2 / L-80 / Hyd 563 3,609’9,773’ 3-1/2”Tieback 9.2 / L-80 / EUE 8RD Surf 3,621’ JEWELRY DETAIL No Depth Item 1/2 3,621’Liner Top Packer / Seal Assy. OPEN HOLE / CEMENT DETAIL 8-1/2”Spacer-60 bbl 10.5 ppg / lead- 101 bbl 12 ppg lead/Tail- 61 bbl 15.3 ppg 6-1/8”Spacer-30 bbl 10.5 ppg / lead- 186 bbl 12 ppg lead/Tail- 36 bbl 15.3 ppg _____________________________________________________________________________________ Updated by DMA 03-07-25 PROPOSED Deep Creek Unit – B Pad Well: HVB-13A PTD: 224-160 API: 50-231-20032-01-00 CASING DETAIL Size Type Wt/ Grade/ Conn Top Btm 20"Conductor 109 / X-56 / Weld Surface 117' 9-5/8'Surface 40 /L-80/ BTC Surface 1,157’ Open Hole Whipstock set @ 1,200’ MD 7”Intermediate 26 / L-80 / BTC Surface 3,822’ 3-1/2”Prod liner 9.2 / L-80 / Hyd 563 3,609’9,773’ 3-1/2”Tieback 9.2 / L-80 / EUE 8RD Surf 3,621’ JEWELRY DETAIL No Depth Item 1/2 3,621’Liner Top Packer / Seal Assy. OPEN HOLE / CEMENT DETAIL 8-1/2”Spacer-60 bbl 10.5 ppg / lead- 101 bbl 12 ppg lead/Tail- 61 bbl 15.3 ppg 6-1/8”Spacer-30 bbl 10.5 ppg / lead- 186 bbl 12 ppg lead/Tail- 36 bbl 15.3 ppg PERFORATION DETAIL Zone Top MD Btm MD Top TVD Btm TVD Amt Date Status BEL_43 ±3,975'±4,006'±3,811'±3,842'±31'Proposed TBD BEL_46 ±4,130'±4,140'±3,963'±3,973'±10'Proposed TBD BEL_46 ±4,154'±4,160'±3,987'±3,993'±6'Proposed TBD BEL_50 ±4,317'±4,331'±4,147'±4,161'±14'Proposed TBD T1 ±5,948'±5,954'±5,752'±5,758'±6'Proposed TBD T1 ±5,961'±5,967'±5,765'±5,771'±6'Proposed TBD T3 ±6,072'±6,078'±5,876'±5,882'±6'Proposed TBD T5 ±6,109'±6,115'±5,913'±5,918'±6'Proposed TBD T6 ±6,244'±6,258'±6,047'±6,061'±14'Proposed TBD T7 ±6,338'±6,344'±6,140'±6,146'±6'Proposed TBD T7 ±6,387'±6,397'±6,189'±6,199'±10'Proposed TBD T10 ±6,523'±6,533'±6,324'±6,334'±10'Proposed TBD T10 ±6,609'±6,623'±6,410'±6,424'±14'Proposed TBD T10A ±6,649'±6,655'±6,449'±6,455'±6'Proposed TBD T17 ±6,822'±6,853'±6,621'±6,652'±31'Proposed TBD T17 ±6,861'±6,896'±6,660'±6,695'±35'Proposed TBD T32 ±7,417'±7,427'±7,214'±7,224'±10'Proposed TBD T40 ±7,785'±7,816'±7,579'±7,610'±31'Proposed TBD T48 ±8,140'±8,160'±7,932'±7,952'±20'Proposed TBD T65 ±8,656'±8,662'±8,445'±8,451'±6'Proposed TBD T70A ±8,820'±8,840'±8,609'±8,629'±20'Proposed TBD T80 ±8,927'±8,937'±8,709'±8,726'±10'Proposed TBD T90 ±9,115'±9,129'±8,716'±8,918'±14'Proposed TBD T91 ±9,152'±9,166'±8,904'±8,955'±14'Proposed TBD T99 ±9,225'±9,231'±8,941'±9,020'±6'Proposed TBD T99 ±9,242'±9,252'±9,031'±9,040'±10'Proposed TBD T120 ±9,617'±9,637'±9,405'±9,425'±20'Proposed TBD T120 ±9,645'±9,651'±9,433'±9,439'±6'Proposed TBD STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Deep Creek Unit, Beluga/Tyonek Gas Pool, HVB-13A Hilcorp Alaska, LLC Permit to Drill Number: 224-160 Surface Location: 2920' FNL, 337' FEL, Sec 21, T2S, R13W, SM, AK Bottomhole Location: 2510' FNL, 1590' FEL, Sec 21, T2S, R13W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Jessie L. Chmielowski Commissioner DATED this 4th day of February 2025. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.04 08:11:22 -09'00' 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name:5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address:6. Proposed Depth: 12. Field/Pool(s): MD: 9,536' TVD: 9,324' 4a. Location of Well (Governmental Section):7. Property Designation: Surface: Top of Productive Horizon:8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27):10. KB Elevation above MSL (ft): 611 15. Distance to Nearest Well Open Surface: x-223690 y-2190972 Zone-4 593 to Same Pool: 2080' to HVB-16A 16. Deviated wells:Kickoff depth: 1,200 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 34 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD 8-1/2" 7" 26# L-80 BTC 3,805' Surface Surface 3,805' 3,648' 6-1/8" 3-1/2" 9.2# L-80 Hyd 563 2,076' 3,605' 3,451' 9,536' 9,324' Tieback 3-1/2" 9.2# L-80 EUE 8RD 5,593' Surface Surface 3,605' 3,451' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): N/A TVD 117' 1,105' 2,831' 6,917' Hydraulic Fracture planned?Yes No 20. Attachments:Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number:Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 2/15/2025 2674' to nearest unit boundary Sean Mclaughlin sean.mclaughlin@hilcorp.com 907-223-6784 7,747' 2534 Cement Volume MD Driven 117' 1,157'9-5/8"606 sx Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 1,157' 3,645' 330 sx Will be plugged PreDrill Conductor/Structural 16"117' Authorized Title: Authorized Signature: 3-1/2" Authorized Name: Production Liner 3,645' 4,247' Intermediate 7,747'6,913' LengthCasing ±1,200' Size Plugs (measured): (including stage data) L - 565 ft3 / T - 101 ft3 L - 1039 ft3 / T - 106 ft3 1,200'1,200' Effect. Depth MD (ft):Effect. Depth TVD (ft): 18. Casing Program:Top - Setting Depth - BottomSpecifications 1562 GL / BF Elevation above MSL (ft): Total Depth MD (ft):Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 Tieback Assy. 2500 2030' FSL, 850' FEL, Sec 21, T2S, R13W, SM, AK 2510' FNL, 1590' FEL, Sec 21, T2S, R13W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2920' FNL, 337' FEL, Sec 21, T2S, R13W, SM, AK C061589 HVB-13A Deep Creek Unit Beluga/Tyonek Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Will be plugged PreDrill 417 sx7" s N ype of W L l R L 1b S Class: os N s No s N o D s s sD 84 o well is p G S S 20 S S S s Nos No S G y E S s No s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) By Grace Christianson at 9:50 am, Dec 20, 2024 Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2024.12.20 09:31:03 - 09'00' Sean McLaughlin (4311) BJM 2/3/25 A.Dewhurst 23JAN25 BOP test to 3000 psi, annular test to 2500 psi 2500 DSR-12/20/24 1562 SFD , Happy If LOT is <14.0 ppg EMW, the following mud weight restrictions apply: If mud weight is increased above 9.5 ppg in the 6-1/8" hole section, swab kick mitigation measures must be employed for the remainder of the hole section. Mitigation measures must include at a minimum pumping any time the drill string is pulled up hole, including short trips. 224-160 50-231-20032-01-00 Valley Submit FIT/LOT results and obtain approval before drilling production hole section. *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.02.04 08:11:38 -09'00' 02/04/25 02/04/25 RBDMS JSB 020425 HVB-13A PTD Program Happy Valley December 13, 2024 HVB-13A Drilling Procedure Contents 1.0 Well Summary................................................................................................................................2 2.0 Management of Change Information...........................................................................................3 3.0 Tubular Program:..........................................................................................................................4 4.0 Drill Pipe Information:..................................................................................................................4 5.0 Internal Reporting Requirements................................................................................................5 6.0 Current Schematic.........................................................................................................................6 7.0 Planned Wellbore Schematic........................................................................................................7 8.0 Drilling / Completion Summary...................................................................................................8 9.0 Mandatory Regulatory Compliance / Notifications....................................................................9 10.0 R/U and Preparatory Work........................................................................................................11 11.0 BOP N/U and Test........................................................................................................................12 12.0 Cut and pull 7” casing, Set Open Hole Whipstock...................................................................12 13.0 Drill 8-1/2” Hole Section..............................................................................................................13 14.0 Run 7” Intermediate Casing.......................................................................................................14 15.0 Cement 7” Intermediate Casing.................................................................................................16 16.0 Drill 6-1/8” Hole Section..............................................................................................................19 17.0 Run 3-1/2” Production Liner......................................................................................................21 18.0 Cement 3-1/2” Production Liner................................................................................................25 19.0 3-1/2” Liner Tieback Polish Run................................................................................................28 20.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................28 21.0 BOP Schematic.............................................................................................................................30 22.0 Wellhead Schematic.....................................................................................................................31 23.0 Anticipated Drilling Hazards......................................................................................................32 24.0 Hilcorp Rig 169 Layout...............................................................................................................33 25.0 Choke Manifold Schematic.........................................................................................................34 26.0 HVB-13 9-5/8” LOT data............................................................................................................35 27.0 Casing Design Information.........................................................................................................36 28.0 8-1/2” Hole Section MASP..........................................................................................................37 29.0 6-1/8” Hole Section MASP..........................................................................................................38 30.0 Spider Plot (660’).........................................................................................................................39 31.0 Surface Plat (As-Built NAD27 & NAD83).................................................................................40 Page 2 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 1.0 Well Summary Well HVB-13A Rig 169 Pad & Old Well Designation Happy Valley B pad Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s)Sterling, Beluga, Tyonek Planned Well TD, MD / TVD 9536 MD / 9324’ TVD PBTD, MD / TVD 9436’ MD AFE Number AFE Days AFE Amount Maximum Anticipated Pressure (Surface)1562 psi Maximum Anticipated Pressure (Downhole/Reservoir)2500 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 611.0 Ground Elevation 593.0 BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 2.0 Management of Change Information Page 4 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 3.0 Tubular Program: Hole Section OD (in)ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) 8-1/2”7 6.276 6.151 7.656 26 L-80 TXP 7240 5410 604 6-1/8”3-1/2”2.992”2.867”4.250”9.2 L-80 HYD-563 10160 10540 207 *Ensure at least 100’ of overlap between casing and liner 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”3.826 2.6875”5.25”16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 5 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellview. x Report covers operations from 6am to 6am x Ensure time entry adds up to 24 hours total. x Capture any out-of-scope work as NPT. 5.2 Afternoon Updates x Submit a short operations update each day to kenaiciodrilling@hilcorp.com 5.3 Morning Update x Submit a short operations update each morning by 7am in NDE – Drilling Comments 5.4 EHS Incident Reporting x Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don’t wait until an emergency to have to call around and figure it out!!!! a. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: x Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 x Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally x Send final “As-Run” Casing tally to Sean.McLaughlin@hilcorp.com,andcdinger@hilcorp.com 5.6 Casing and Cmt report x Send casing and cement report for each string of casing to Sean.McLaughlin@hilcorp.com,and cdinger@hilcorp.com Page 6 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 6.0 Current Schematic Page 7 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 7.0 Planned Wellbore Schematic Page 8 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 8.0 Drilling / Completion Summary HVB-13A is an S-shaped sidetrack development well to be drilled from Happy Valley Pad B. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Beluga and Tyonek sands The base plan is a S wellbore with a kickoff point just below the surface casing shoe at ~1170’ MD. An Intermediate casing string will be run and cemented across the upper Beluga. Maximum hole angle will be ~34 deg. and TD of the well will be 9536’ TMD/ 9324’ TVD. Vertical separation will be 1323 ft. Drilling operations are expected to commence approximately February 2025. The Hilcorp Rig # 169 will be used to drill the wellbore then run casing and cement. All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. Planned Pre Rig operations: - Prep for sidetrack – CIBP set at 2396’, Test casing to 2500 psi. General sequence of operations: 1. Rig 169 will MIRU over HVB-13A 2. NU BOPE and test to 3000 psi. (MASP 1562psi) 3. Cut and pull 7” Intermediate casing from below the surface casing 4. Set 8.5” Openhole Whipstock ~1200’ 5. MU 8-1/2” bit with 6-3/4” tools (Triple Combo) 6. Drill 8-1/2” Intermediate hole to 3805’ MD 7. Run 7” Intermediate casing. TOC planned to Surface 8. Swap casing rams to VBRs, Perform casing test to 3000 psi 9. MU 6-1/8” bit with 4-3/4” tools (Triple Combo) 10. Drill out casing shoe and perform FIT to 14 ppg EMW. 11. Drill 6-1/8” production hole to 9536’ MD 12. RIH w/ 3-1/2” liner. Set liner and cement. Circ wellbore clean. 13. Perform Clean out run to polish bore, LDDP 14. Perform liner lap test to 2500 psi. 15. Run 3-1/2” tie back completion. 16. Land hanger and test.MIT-T to 2500 psi, MIT-IA to 2500 psi 17. ND BOPE, NU tree and test void Reservoir Evaluation Plan: Intermediate Hole: Triple Combo Production Hole: Triple Combo Page 9 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 9.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at (2) week intervals during the drilling of HVB-13A. Ensure to provide AOGCC 24 hrs notice prior to testing BOPs. x The initial test of BOP equipment will be 250/3000 psi & subsequent tests of the BOP equipment will be to 250/3000 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).Confirm that these test pressures match those specified on the APD. x If the BOP is used to shut in on the well in a well control situation test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid program and drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved drilling permits are posted on the rig floor and in Co Man office. x Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. VARIENCE REQUEST: Test 7” 26# L-80 to 3000 psi. 50% of burst is 3620 psi. The casing is being run because it is currently in stock in Kenai. The MASP for the well is 1562 psi. VARIENCE REQUEST: Test 7” 26# L-80 to 3000 psi. 50% of burst is 3620 psi. The casing isQpp being run because it is currently in stock in Kenai. The MASP for the well is 1562 psi. Variance request approved. -bjm Page 10 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 8-1/2” and 6-1/8” x 11” x 5M Annular BOP x 11” x 5M Double Ram o Blind ram in btm cavity x Mud cross x 11” x 5M Single Ram (remove while drilling production hole) x 3-1/8” 5M Choke Line x 2-1/16” x 5M Kill line x 3-1/8” x 2-1/16” 5M Choke manifold x Standpipe, floor valves, etc Initial Test: 250/3000 (Annular 2500 psi) Subsequent Tests: 250/3000 (Annular 2500 psi) x Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). x Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 24 hours notice prior to testing BOPs. x Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 11 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 10.0 R/U and Preparatory Work 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig # 169, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. 8-1/2” hole section mud program summary: Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 1157’- 3805’8.8– 9.5 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for 8.8 – 9.5 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 6. Install 5-1/2” liners in mud pumps. x HHF-1000 mud pumps are rated at 3036 psi (85%) / 370 gpm (100%) at 120 strokes Page 12 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx with 5-1/2” liners. 11.0 BOP N/U and Test 1. N/D Tree and adapter (BPV installed as part of pre-rig work), Install blanking plug 2. N/U 11” x 5M BOP as follows: x BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram x Double ram should be dressed with 7” fixed bore rams in top cavity,blind ram in btm cavity. x Single ram should be dressed with 2-7/8” x 5” variable bore rams x N/U bell nipple, install flowline. x Install (2) manual valves & a check valve on kill side of mud cross. x Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 3. Run BOPE test plug. 4. Test BOPE. x Test BOP to 250/3000 psi for 5/10 min. x 7” test joint required for FBR x Test VBR’s with 4-1/2” and 3-1/2 test joint x Test annular to 250/2500 psi for 5/10 min with a 3-1/2” test joint x Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 5. Mix 9.0 ppg 6% KCL PHPA mud system. 6. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. 12.0 Cut and pull 7” casing, Set Open Hole Whipstock 1. Rig up eline and cut 7” 26# BTC casing at 1267’ 2. Pick up WIS 8.5” Openhole Whipstock. Set at 1200’. x 8.5” hole started in the parent well at 1170’ Pull 7" casing. Page 13 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 3. PU 6-3/4” directional only BHA with 8.5” Mill tooth bit. 4. Drill 200’ of rat hole. Trip to pick up triple combo LWD. ¾14.9 ppg LOT previously approved on 9-5/8” casing shoe (12/11/07). Supporting data in the program attachments. ¾**Assuming the kick zone is at TD, a FIT of 14.0 ppg EMW gives a Kick Tolerance volume of 20 bbls with 9.2 ppg mud weight. 13.0 Drill 8-1/2” Hole Section 1. Pull test plug. Set wear bushing in wellhead. Ensure ID of wear bushing > 8.5”. 2. P/U 6-3/4” Sperry Sun motor drilling assy w/ triple combo tools (DEN, POR, RES) and 8-1/2” bit 3. Ensure BHA components have been inspected previously. 4. Drift & caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics models to ensure optimum TFA. Plan to pump at ~400 gpm. 7. Production section will be drilled with a motor. Must keep up with 3 deg/100 DLS in the build section of the wellbore. 8. TIH to TOC. Shallow test MWD on trip in. 9. Circulate well with 8.8 ppg mud to warm up mud until good 8.8 ppg in and out. 10. Drill 8-1/2” hole to 3805’ MD using motor assembly. x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. x Keep swab and surge pressures low when tripping. x Ensure solids control equipment functioning properly and utilized to keep LGS to a minimum without excessive dilution. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. x Minimize backreaming when working tight hole The chart provided shows leakoff at 14.2 ppg EMW, even though it was documented as 14.9 ppg at the time of the test in 12/11/2007. This still provides adequate kick tolerance. -bjm Page 14 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 11. At TD pump a sweep and a marker to be used as a fluid caliper to determine annulus volume for cement calculations. CBU. 12. Clean out wellbore as necessary 13. TOH with drilling assembly, handle BHA as appropriate. 14. Confirm 7” FBR previously installed in BOP stack and tested with 7” test joint. 14.0 Run 7” Intermediate Casing 1. R/U and pull wear bushing. 2. R/U Parker 7” casing running equipment. x Ensure 7” TXP x CDS40 XO on rig floor and M/U to FOSV. x Use BOL 2000 thread compound. Dope pin end only w/ paint brush. x Ensure all casing has been drifted to 6.125” on the location prior to running. x Note that 26# drift is 6.151” x Be sure to count the total # of joints on the location before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking 80’ shoe track assembly consisting of: 7” Float Shoe 1 joint – 7” BTC, 1 Centralizer 10’ from bottom w/ stop ring 7” Float Collar 1 joint – 7” BTC, 1 Free floating centralizer 7” Landing collar 5. Continue running 7” intermediate casing x Centralization: x 1 centralizer every joint to the shoe x Utilize a collar clamp until weight is sufficient to keep slips set properly. Page 15 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Page 16 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 8. P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Conventional circulation is not permissible once casing hanger is landed. 10. P/U and R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Cement to surface is not expected. However, in the event cement is circulated out ensure hose is in place to take returns to the cellar. 15.0 Cement 7” Intermediate Casing 1. Hold a pre-job safety meeting over the upcoming cement operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cementing unit at acceptable rates. x Determine which pumps will be utilized for displacement, and how fluid will be fed to displacement pump. x Ensure adequate amount of water for mix fluid is heated and available in the water tanks. x Confirm positions and expectations of personnel involved with the cementing operation. i. Extra hands in the pits to strap during the cement job to identify any losses x Review test reports and ensure pump times are acceptable. x Conduct visual inspection of all hard lines and connections used to route slurry to rig floor. 2. Document efficiency of all possible displacement pumps prior to cement job. Page 17 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 3. Flush through cement pump and treating iron from pump to rig floor to the shakers. This will help ensure any debris left in the cement pump or treating iron will not be pumped downhole. 4. R/U cement line (if not already done so). 5. Fill surface cement lines with water and pressure test. 6. Pump remaining 60 bbls 10.5 ppg tuned spacer. 7. Mix and pump cement per below calculations, confirm actual cement volumes with cementer after TD is reached. 8. Cement volume based on annular volume + 40% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Cement Volume: Class G 12.5 ppg lead - 2.1 cuft/sk 15.3 ppg tail - 1.23 cuft/sk Verified cement calcs - bjm Page 18 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 9. Attempt to reciprocate casing during cement pumping if hole conditions allow. Watch reciprocation PU and SO weights, if the hole gets “sticky”, cease pipe reciprocation, land hanger, and continue with the cement job. 10. After pumping cement, drop wiper plug and displace cement with mud out of mud pits. a. Ensure volumes pumped and volumes returned are documented and constant communication between mud pits, and cementers during the entire job. 11. Ensure rig pump is used to displace cement. 12. Land hanger. 13. Displacement volume is in Table above. 14. Monitor returns closely while displacing cement. Adjust pump rate if losses are seen at any point during the job. 15. If plug is not bumped at calculated strokes, double check volumes and calculations. Over displace by no more than 1 shoe track volume, ±4 bbls before consulting with Drilling Engineer. 16. Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held, this is to ensure the stage tool is not prematurely opened. 17. Not expected, but be prepared for cement returns to surface. Cement returns to be taken to cellar. Ensure to flush out any rig components, hard lines and BOP stack that may have come in contact with the cement. 18. R/D cement equipment. Flush out wellhead with FW. 19. Back out and L/D landing joint. Flush out wellhead with FW. 20. M/U pack-off running tool and pack-off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 21. Lay down landing joint and pack-off running tool. Page 19 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to sean.mclaughlin@hilcorp.com and cody.dinger@hilcorp.com This will be included with the EOW documentation that goes to the AOGCC. 16.0 Drill 6-1/8” Hole Section 1. Set test plug. Swap 7” FBR to 2-7/8” x 5” VBR, test with 4-1/2” and 3-1/2” test joints to 3000 psi.,.Test all breaks. Pull test plug, run and set wear bushing. 2. Ensure BHA components have been inspected previously. 3. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. TIH, conduct shallow hole test of MWD and confirm all LWD functioning properly. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 7. Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 8. 6-1/8” hole section mud program summary: Starting mud weight for the production interval is 9.0 ppg or the intermediate interval mud weight at TD, whichever is heavier. Page 20 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Weighting material to be used for the hole section will be barite, salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller’s console, Co Man office, and Toolpusher office. System Type:9.0 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Viscosity Plastic Viscosity Yield Point pH HPHT 3805’- 9536’9.0 – 10.0 40-53 15-25 15-25 8.5-9.5 11.0 System Formulation:6% KCL EZ Mud DP Product Concentration Water KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 5/25/50 BAROID 41 ALDACIDE G BARACOR 700 BARASCAV D 0.905 bbl 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 1.25 ppb (as required 18 YP) 0.75 ppb (initially 0.25 ppb) 1-2 ppb 1 ppb 15 - 20 ppb (5 ppb of each) as required for a 9.0 – 10.0 ppg 0.1 ppb 1 ppb 0.5 ppb (maintain per dilution rate) 9. TIH w/ 4-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 10. R/U and test casing to 3000 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC requirement is 50% of burst. 7” L-80 burst is 7240 psi / 2 = 3620 psi. VARIENCE REQUEST: Test 7” 26# L-80 to 3000 psi. 50% of burst is 3620 psi. The casing is being run because it is currently in stock in Kenai. The MASP for the well is 1562 psi. 11. Drill out shoe track and 20’ of new formation. 12. CBU and condition mud for FIT. 13. Conduct FIT to 14 ppg (13# FIT, 7.2 ppg BHP, 9.2 ppg MW = 19 bbl KTV) VARIENCE REQUEST Variance request granted. -bjm Kick Tolerance should be calculated based on the highest density mud that may be used, which is 10 ppg. There is insufficient KT assuming 10 ppg mud weight and 13 ppg LOT. See condition of approval. -bjm Page 21 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 14. Drill 6-1/8” hole section to 9536’ MD / 9324’ TVD x Pump sweeps and maintain mud rheology to ensure effective hole cleaning. x Pump at ~200-270 gpm. Ensure shaker screens are set up to handle this flowrate. x Keep swab and surge pressures low when tripping. x Make wiper trips every 1000’ unless hole conditions dictate otherwise. Halfway through to interval make a wiper trip to the shoe. x Ensure shale shakers are functioning properly. Check for holes in screens on connections. x Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. x Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 15. At TD; pump sweeps, CBU, and pull a wiper trip back to the 7” shoe. 16. TOH with the drilling assy, standing back enough drill pipe for the upcoming liner run 17. POOH LDDP and BHA. 18. Ensure 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint 17.0 Run 3-1/2” Production Liner 1. R/U Parker 3-1/2” casing running equipment. x Ensure 3-1/2” Liner x CDS 40 crossover on rig floor and M/U to FOSV. x R/U fill up line to fill casing while running. x Ensure all casing has been drifted prior to running. x Be sure to count the total # of joints before running. x Keep hole covered while R/U casing tools. x Record OD’s, ID’s, lengths, S/N’s of all components w/ vendor & model info. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: x (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). x (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). x (1) Joint with Baker landing collar bucked on pin end & threadlocked. x Solid body centralizers will be pre-installed on shoe joint an FC joint. x Leave centralizers free floating so that they can slide up and down the joint. x Ensure proper operation of float shoe and float collar. x Utilize a collar clamp until weight is sufficient to keep slips set properly Page 22 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 4. Continue running 3-1/2” production liner x Fill casing while running using fill up line on rig floor. x Use “API Modified” thread compound. Dope pin end only w/ paint brush. x Install solid body centralizers on every joint to the 7” window. Leave the centralizers free floating. 5. Continue running 3-1/2” production liner Page 23 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Page 24 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 6. Run in hole w/ 3-1/2” liner to the 7” shoe. 7. Fill the casing with fill up line and break circulation every 1,000 feet to the shoe or as the hole dictates. 8. Obtain slack off weight, PU weight, rotating weight and torque of the casing. 9. Circulate 2X bottoms up at shoe, ease casing thru shoe. 10. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 11. Set casing slowly in and out of slips. 12. PU 3-1/2” X 7” YJOC liner hanger/LTP assembly. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 13. Continue running in hole at slow speeds to avoid surging well. Target 20 ft/min and adjust slower as hole conditions dictate. 14. Swedge up and wash last stand to bottom. P/U 5’ off bottom. Note slack-off and pick-up weights. 15. Stage pump rates up slowly to circulating rate. Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low end rheology of the drilling fluid by adding water and thinners. 16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 25 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 18.0 Cement 3-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume is available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. x Pump 20 bbls of freshwater through all of cementing equipment, taking returns to cuttings bin, prior to pumping any fluid downhole x How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. x Which pump will be utilized for displacement, and how fluid will be fed to displacement pump. x Positions and expectations of personnel involved with the cmt operation. x Document efficiency of all possible displacement pumps prior to cement job. 2. Attempt to rotate and reciprocate the liner during cmt operations until hole gets sticky 3. Pump 5 bbls spacer. 4. Test surface cmt lines to 4500 psi. 5. Pump remaining spacer. 6. Mix and pump lead and tail cement per below recipe. Ensure cement is pumped at designed weight. Job is designed to pump 40% OH excess. Page 26 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx Estimated Total Cement Volume: Class G 12.5 ppg lead - 2.1 cuft/sk 15.3 ppg tail - 1.23 cuft/sk 7. Drop drillpipe dart and displace with drilling mud. If hole conditions allow – continue rotating and reciprocating liner throughout displacement. This will ensure a high quality cement job with 100% coverage around the pipe. 8. Displace cement at max rate of 4 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. Page 27 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 9. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 10. Bump the plug and pressure up to up as required by Hanger provider to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. 11. Slack off total liner weight plus 30k to confirm hanger is set. 12. Do not overdisplace by more than 2x shoe track volume. Shoe track volume is 0.7 bbls. 13. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 14. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 15. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 16. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 17. Pressure up drill pipe to 500 psi and pick up to remove the packoff bushing from the nipple. Bump up pressure as req’d to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 18. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 19. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cmt from DP. 20. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Ensure to report the following on wellview: x Pre flush type, volume (bbls) & weight (ppg) x Cement slurry type, lead or tail, volume & weight x Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration x Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Page 28 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx x Note if casing is reciprocated or rotated during the job x Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold x Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure x Note if pre flush or cement returns at surface & volume x Note time cement in place x Note calculated top of cement x Add any comments which would describe the success or problems during the cement job Send final “As-Run” casing tally & casing and cement report to cdinger@hilcorp.com and sesan.mclaughlin@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 19.0 3-1/2” Liner Tieback Polish Run 1. No liner cleanout planned. Service coil will cleanout, displace mud, and blow down well with N2 prior to perforating. 2. Test liner lap to 2500 psi after cement has reached 500 psi compressive strength. 10 min operational assurance test. 3. PU liner tieback polish mill assy per YJOC rep and RIH on drillpipe. 4. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 5. POOH, and LDDP and polish mill. 20.0 3-1/2” Tieback Run, ND/NU, RDMO 1. Run 3-1/2” tubing completion assembly to above the liner top x Tubing will be 3-1/2” L-80 9.2# EUE 8rd 2. Swap the well over to CI Water 3. Space out and land seal bore in tie back sleeve. RILDs. 4. Test IA to 2500 psi and tubing to 2500 psi. Charted 30 min. 5. Install BPV in wellhead. 6. ND BOPE, NU tree, test void Page 29 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 7. Rig Down Page 30 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 21.0 BOP Schematic Single Gate to be removed for production hole due to wellhead height. Page 31 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 22.0 Wellhead Schematic Page 32 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 23.0 Anticipated Drilling Hazards 8-1/2 and 6-1/8” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. x Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. x Use asphalt-type additives to further stabilize coal seams. x Increase fluid density as required to control running coals. x Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal pressures are present in this hole section. Page 33 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 24.0 Hilcorp Rig 169 Layout Page 34 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 25.0 Choke Manifold Schematic Page 35 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 26.0 HVB-13 9-5/8” LOT data Drilling Summary Page 36 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 27.0 Casing Design Information Page 37 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 28.0 8-1/2” Hole Section MASP -bjm1459 psi per Sean McLaughlin email 1/28/25 7.7 ppg 0.40 psi/ft Page 38 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 29.0 6-1/8” Hole Section MASP Page 39 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 30.0 Spider Plot (660’) Page 40 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx 31.0 Surface Plat (As-Built NAD27 & NAD83) Page 41 Version 0.0 December 13, 2024 HVB-13A Drilling Procedure PTD# xxx-xxx !!" # " $ %% %% 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750True Vertical Depth (1500 usft/in)-1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 9750 Vertical Section at 288.10° (1500 usft/in) 5 00 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 400 0 4500 5000 5500 6000 6500 7000 7500 7747 HV #13 9 5/8" 7" x 8 1/2" 3 1/2" x 6 1/8" 5 00 1 0 0 0 1 5 0 0 2 0 0 0 2 5 0 0 3 0 0 0 3 5 0 0 4 0 0 0 4 5 0 0 5 0 0 0 5 5 0 0 60 00 6 5 00 7 0 0 0 7 5 0 0 80 00 8 5 00 9 0 0 0 9 50 09536 HVB-13A wp03a KOP: 3º/100' : 1157' MD, 1105.08'TVD : 160.78° RT TF End Dir : 2336.76' MD, 2206.55' TVD Start Dir 1.5º/100' : 5508.76' MD, 5320.28'TVD End Dir : 5842.25' MD, 5650' TVD Total Depth : 9536' MD, 9323.53' TVD Sterling A Beluga 1 Beluga 51 Beluga 93 T-1A T-6 T-17 T-91 T-120 Hilcorp Alaska, LLC Calculation Method:Minimum Curvature Error System:ISCWSA Scan Method: Closest Approach 3D Error Surface: Ellipsoid Separation Warning Method: Error Ratio WELL DETAILS: Happy Valley B-13 Ground Level: 593.00 +N/-S +E/-W Northing Easting Latitude Longitude 0.00 0.00 2190972.28 223690.68 59° 59' 19.5871 N 151° 30' 32.3055 W SURVEY PROGRAM Date: 2024-10-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 147.00 1157.00 HV #13 MWD (HVB-13) 3_MWD 1157.00 3805.00 HVB-13A wp03a (HVB-13A) 3_MWD+AX+Sag 3805.00 9536.00 HVB-13A wp03a (HVB-13A) 3_MWD+AX+Sag FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 1707.00 1096.00 1824.83 Sterling A 2062.00 1451.00 2189.61 Beluga 1 4197.00 3586.00 4364.46 Beluga 51 4957.00 4346.00 5138.68 Beluga 93 5711.00 5100.00 5903.58 T-1A 5987.00 5376.00 6181.10 T-6 6627.00 6016.00 6824.63 T-17 8912.00 8301.00 9122.20 T-91 9316.00 8705.00 9528.43 T-120 REFERENCE INFORMATION Co-ordinate (N/E) Reference:Well Happy Valley B-13, True North Vertical (TVD) Reference:RKB Permit @ 611.00usft (HEC 169) Measured Depth Reference:RKB Permit @ 611.00usft (HEC 169) Calculation Method: Minimum Curvature Project:Deep Creek Unit Site:Happy Valley B Pad Well:Happy Valley B-13 Wellbore:HVB-13A Design:HVB-13A wp03a CASING DETAILS TVD TVDSS MD Size Name 3648.00 3037.00 3805.18 7 7" x 8 1/2" 9323.53 8712.53 9536.00 3-1/2 3 1/2" x 6 1/8" SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target Annotation 1 1157.00 34.32 227.38 1105.08 -174.27 -187.06 0.00 0.00 123.67 KOP: 3º/100' : 1157' MD, 1105.08'TVD : 160.78° RT TF 2 2336.76 11.00 315.00 2206.55 -324.68 -522.12 3.00 160.78 395.44 End Dir : 2336.76' MD, 2206.55' TVD 3 5508.76 11.00 315.00 5320.28 103.29 -950.10 0.00 0.00 935.18 Start Dir 1.5º/100' : 5508.76' MD, 5320.28'TVD 4 5842.25 6.00 315.00 5650.00 138.13 -984.93 1.50 180.00 979.12 End Dir : 5842.25' MD, 5650' TVD 5 9536.00 6.00 315.00 9323.53 411.04 -1257.84 0.00 0.00 1323.30 Total Depth : 9536' MD, 9323.53' TVD -525-450-375-300-225-150-75075150225300375450525South(-)/North(+) (150 usft/in)-1275 -1200 -1125 -1050 -975 -900 -825 -750 -675 -600 -525 -450 -375 -300 -225 -150 -75 0 75 150West(-)/East(+) (150 usft/in)25050075010 00 12501500HV #139 5/8"7" x 8 1/2"3 1/2" x 6 1/8"25050075010 00 12501 5 0 0 1 7 5 0 2000225025002750300032503500375040004250450047505000525055005750600062506500675070007250750077508000825085008750900092509324HVB-13A wp03aKOP: 3º/100' : 1157' MD, 1105.08'TVD : 160.78° RT TFEnd Dir : 2336.76' MD, 2206.55' TVDStart Dir 1.5º/100' : 5508.76' MD, 5320.28'TVDEnd Dir : 5842.25' MD, 5650' TVDTotal Depth : 9536' MD, 9323.53' TVDCASING DETAILSTVDTVDSS MDSize Name3648.00 3037.00 3805.18 7 7" x 8 1/2"9323.53 8712.53 9536.00 3-1/2 3 1/2" x 6 1/8"Project: Deep Creek UnitSite: Happy Valley B PadWell: Happy Valley B-13Wellbore: HVB-13APlan: HVB-13A wp03aWELL DETAILS: Happy Valley B-13Ground Level: 593.00+N/-S +E/-W Northing Easting Latitude Longitude0.00 0.00 2190972.28 223690.6859° 59' 19.5871 N 151° 30' 32.3055 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Happy Valley B-13, True NorthVertical (TVD) Reference:RKB Permit @ 611.00usft (HEC 169)Measured Depth Reference:RKB Permit @ 611.00usft (HEC 169)Calculation Method:Minimum Curvature & " ' % ! 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(/ -@# -?"/.& "-"%.&1456"-"%.& 1-+%& ')*"11 1456!7! 81-+%& 0-%1,& ')*"11 1456!7! 8 (!"%%!"% ' 9 : ;(*& : <&2 : : $ &2 = $#> $* ?& 8 << & : :859:92: ; : 9& 0.001.503.004.50Separation Factor1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000Measured DepthHV #13No-Go Zone - Stop DrillingCollision Avoidance RequiredCollision Risk Procedures Req.NOERRORSWELL DETAILS:Happy Valley B-13 NAD 1927 (NADCON CONUS)Alaska Zone 04Ground Level: 593.00+N/-S +E/-W Northing EastingLatitudeLongitude0.000.002190972.28 223690.68 59° 59' 19.5871 N 151° 30' 32.3055 WREFERENCE INFORMATIONCo-ordinate (N/E) Reference:Well Happy Valley B-13, True NorthVertical (TVD) Reference:RKB Permit @ 611.00usft (HEC 169)Measured Depth Reference:RKB Permit @ 611.00usft (HEC 169)Calculation Method: Minimum CurvatureSURVEY PROGRAMDate: 2024-10-30T00:00:00 Validated: Yes Version: Depth From Depth To Survey/PlanTool147.00 1157.00 HV #13 MWD (HVB-13) 3_MWD1157.00 3805.00 HVB-13A wp03a (HVB-13A) 3_MWD+AX+Sag3805.00 9536.00 HVB-13A wp03a (HVB-13A) 3_MWD+AX+Sag0.0035.0070.00105.00140.00175.00Centre to Centre Separation (60.00 usft/in)1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000 9500 10000Measured DepthHV #15HV #13GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference1157.00 To 9536.00Project: Deep Creek UnitSite: Happy Valley B PadWell: Happy Valley B-13Wellbore: HVB-13APlan: HVB-13A wp03aDeep Creek UnitLadder / S.F. PlotsCASING DETAILSTVD TVDSS MD Size Name3648.00 3037.00 3805.18 7 7" x 8 1/2"9323.53 8712.53 9536.00 3-1/2 3 1/2" x 6 1/8" 1 McLellan, Bryan J (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, February 3, 2025 3:46 PM To:Sean McLaughlin Subject:RE: [EXTERNAL] HVB-13A PTD questions Sean, Thanks for the information. I’m not completely on the same page regarding the swab kick tolerance assumptions in your email below. If you POOH faster than Ʋuids can drain around or through the bit, then you’ll swab in a kick regardless of swab margin. I’ll approve the permit with some conditions that I think are reasonable. It’s only an issue if LOT pressure is <14 ppg EMW. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Sent: Tuesday, January 28, 2025 8:08 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] HVB-13A PTD questions Brian, When looking at this I noticed a glitch in the pressures the 1700 psi was carried twice. The EMW at the shoe is 7.7 ppg. I used 7.8 ppg as the reservoir pressure and a MW of 9.2 ppg. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 The TIO chart is attached. There is no indication of pressure to surface. The surface cement job seemed to go as planned. When mud weight is increased for stability, it does not get applied to the swab kick scenario. That is the same practice BP used. A 9.2 ppg MW is expected to be 1.4 ppg over pore pressure. A higher MW would further increase the swab margin. The data in the well Ʊle suggests a 14.9 ppg LOT was reasonable and 340 psi was achieved. 1 min 60 psi 2 min 150 psi 3 min 300 psi 4 min 350 psi 10 sec SIP 340 psi 1 min SIP 330 psi 2 min SIP 305 psi 3 min SIP 295 psi Chevron’s LOT procedure was diƯerent than ours but is still valid. They may argue it is more valid. A red Ʋag would have been if they reported a 350 psi LOT. sean From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, January 23, 2025 2:16 PM To: Sean McLaughlin <Sean.Mclaughlin@hilcorp.com> Subject: [EXTERNAL] HVB-13A PTD questions Sean, A few questions regarding the PTD application: 1. Can you send a chart of OA pressures over the past year? I’m looking for information to see if there is communication between surface and the 9-5/8 x formation annulus below the planned cut depth. 2. The kick Tolerance calculations don’t align with the range of mud weights in the program. For the planned FIT below the 7” casing shoe, you have the planned range of mud weights from 9 – 10 ppg, but are running the kick tolerance calcs in the PTD, you assume 9.2 ppg. If I base the calculations oƯ the highest mud CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 3 weight allowed in the program, I only get 10 bbls Kick tolerance, so you wouldn’t have su Ưicient kick tolerance if using 10 ppg mud. I can include a max mud weight as a condition of approval to ensure there is adequate kick tolerance assuming 13 ppg LOT, or list a minimum leakoƯ pressure to drill the well with 10 ppg mud. Which do you prefer? 3. I noted that the LOT done on the surface shoe in 2007 incorrectly called leakoƯ at 340 psi (14.88 ppg), but the chart clearly indicates LO at 300 psi (14.2 ppg). There is suƯicient kick tolerance with 14.2 ppg, even with max mud weight of 9.5 ppg, so this is just an FYI regarding the lower LOT value. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 224-160 DEEP CREEK HAPPY VALLEY BELUGA/TYONEK GAS DCU Happy Valley B-13A WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name:HAPPY VALLEY B-13AInitial Class/TypeDEV / PENDGeoArea820Unit50420On/Off ShoreOnProgramDEVField & PoolWell bore segAnnular DisposalPTD#:2241600DEEP CK, HV BELUGA/TYONEK GAS - 160550NA1 Permit fee attachedYes CIRI Lease C0615892 Lease number appropriateYes3 Unique well name and numberYes DEEP CK, HV BELUGA/TYONEK GAS - 160550 - governed by CO 553A, 553A.0014 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryNA6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (ForNA15 All wells within 1/4 mile area of review identified (For service well only)NA16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)NA17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)NA Sidetrack18 Conductor string providedYes Sidetrack19 Surface casing protects all known USDWsNA20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes Note Variance to 20 AAC 25.030(e} granted because test pressure of 3000 psi will be almost double MPSP.23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitYes25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedNA Sidetrack27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 1562 psi, BOP rated to 5000 psi (BOP test to 3000 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes Measures not required. Nearby wells did not encounter H2S gas.35 Permit can be issued w/o hydrogen sulfide measuresYes Anticipating normally pressured (8.47 ppg EMW) to several severely underpressred (1.1 ppg EMW) reservoirs.36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprADDDate1/22/2025ApprBJMDate2/3/2025ApprADDDate1/22/2025AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDate*&:JLC 2/4/2025