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Home My WebLink About2012 Deep Creek Unitn Hilcorp Alaska, LLC April 1, 2013 Cathy Foerster, Chairman Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: DEEP CREEK UNIT, HAPPY VALLEY FIELD, STATE OF ALASKA, 2012 ANNUAL RESERVOIR REVIEW Dear Commissioner Foerster: Post Office Box 244027 Anchorage, AK 99524-4927 3800 Centerpolnt Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8414 Fax: 907/777-8580 dduffy@hilcorp.com In accordance with Conservation Order No. 553, Hilcorp Alaska, LLC ("Hilcorp"), as Operator, hereby submits for your review the following Annual Reservoir Review for the Happy Valley Field. This is the 8th Annual Reservoir Review and corresponds to events during the 2012 calendar year. Note that the Happy Valley Field has been on production since November 2004. Production Update The following section will detail wellwork and results performed in the Happy Valley Field during the 2012 calendar year. 1. Gas development drilling: The following new exploration and development wells were drilled by Hilcorp to optimize production from the Happy Valley PA. a. HVB-14 — Drilled a 2,005' exploratory drill well targeting the Sterling formation. This well was drilled from the Happy Valley B Pad with a bottom hole location above the existing Happy Valley Participating Area. The well initially flowed 2,300Mcfd at 416psi FTP. Gas composition contains —15.5% nitrogen gas, restricting the allowed production rate from the Sterling, due to pipeline quality limitations. The well has remained under the unloading rate, and current water production of -1bwpd is managed by dropping soap sticks to aid in the unloading of produced fluids. b. HVB-15 — Drilled a 3,069' exploratory drill well targeting the Upper Beluga formation. This well was drilled from the Happy Valley B Pad with a bottom hole location above the existing Happy Valley Participating Area. The well initially flowed 2,500Mcfd at 400psi FTP from the Upper Beluga D sand. Additional Upper Beluga perforations were added (Upper BLG E, F, H, I sands) and the well showed water production during a flowing pressure temperature survey. The Upper BLG H, I sands were isolated and the well returned to production at similar rates with an increase in water production to-3bwpd. This well has remained under the unloading rate due to limitations of compression. Current water production of —Ibwpd is managed by dropping soap sticks to aid in the unloading of produced fluids. c. HVB-16 — Drilled a 4,857' development drill well to target the Beluga formation. This well was drilled from the Happy Valley B Pad, but the well did not reach the intended bottom hole location due to rig limitations. The well was not perforated during the 2012 calendar year. 2. Workover of the existing wells: The following work was performed by Hilcorp to optimize production from the Deep Creek Unit during the 8th POD period. a. HVB-12 — This well was perforated in the Tyonek T-6 sand, adding to the existing Lower Tyonek perforated completion. The well was returned to production flowing 1,000 Mcfd at 805psi FTP. Prior to adding perforations the well was producing approximately 400 Mcfd at 266psi FTP. b. HVB-13 —This well was perforated in the Beluga BLG-40, BLG-36, BLG-29 sands, adding to the existing Beluga and Tyonek perforated completion. The well was returned to production flowing 550 Mcfd at 755psi FTP. Prior to adding perforations the well was producing approximately 250 Mcfd at 265psi FTP. The production rate and FTP dropped off significantly and began flowing water within 5 months. The well was shut in and the BLG-29 was patched due to water production identified during a flowing pressure temperature survey. The well has been unable to flow since the patch installation and remained shut in during the balance of 2012. C. HVA -11 — This well was perforated in the Beluga BLG-50 sand, adding to the existing Beluga and Tyonek perforated completion. There was little to no change in SITP or fluid level as compared to pre -perforation conditions. The well has been unable to flow gas and has remained shut in during the balance of 2012. Prior to adding perforations the well was shut in. 3. Exploration / Seismic: During 2012, Hilcorp contracted with CGGVeritas (CGGV) to conduct the field work portion of a 50 square mile 3D seismic program centered on the Deep Creek Unit. See attached Map (Appendix Q. This work will continue into the 2013 Calendar year. As of December 31, 2012, the cumulative production from the Happy Valley field was 20,847,209 Mcf of gas and 48,518 Bbl of water. Ten (10) Happy Valley wells produced during 2012. As of late December 2012, well test rates were as follows: a. HV -A01— Lower Tyonek Producer. Current rate = 0.65 MMcf/d & 1 BWPD, at 174 psig FTP. b. HV -A02 — Lower Tyonek Producer. Current rate = 0.15 MMcf/d & 1 BWPD, at 173 psig FTP. c. HV -A08 — Beluga and Upper Tyonek Producer. Current rate = 0.4 MMcf/d & 2 BWPD, at 174 psig FTP. d. HV -A09— Upper Tyonek Producer. Current rate = 0.98 MMcf/d & 1 BWPD, at 180 psig FTP. e. HV -A10— Upper Tyonek Producer. Current rate = 2.35 MMcf/d & 0 BWPD, at 197 psig FTP. f. HV -612 — Upper Tyonek Producer. Current rate = 1.03 MMcf/d & 1 BWPD, at 790 psig FTP. g. HV -613 — Beluga and Upper Tyonek Producer. Current rate = 0 MMcf/d & 0 BWPD, at 915 psig SITP. h. HV-1314—Sterling Producer. Current rate = 2.34 MMcf/d & 1 BWPD, at 434 psig FTP. Page 2 L HV -615 — Upper Beluga Producer. Current rate = 2.53 MMcf/d & 3 BWPD, at 485 psig FTP. Appendix A contains the production plots for each individual Happy Valley well. Reservoir Pressure There are currently three different formations (Sterling, Beluga, & Tyonek) and numerous sand intervals open to production at Happy Valley. Because all of the Happy Valley wells have commingled production (from numerous intervals), it is difficult to obtain individual reservoir pressures and is thus difficult to calculate Gas -in-place volumes from material balance. Secondly, very few pressure data points have been taken over the past few years, due to the fact that most wells produce some water with the commingled gas. Shutting in a well that makes any appreciable amount of water puts the gas production/reserves at risk. The recent exploration drilling of the Upper Beluga and Sterling Reservoirs have given two opportunities to collect downhole static reservoir pressure information in 2012. Both the Sterling A and Upper Beluga D sands were produced for a short period of time and then a bottom hole gauge was placed at mid perforation for a short duration PBU (pressure build up). PTA (pressure transient analysis) was performed and extrapolated for reservoir pressures that indicated a pressure gradient of 0.28psi/ft for each reservoir, indicating naturally under -pressured reservoirs. No other downhole reservoir data was gathered during 2012. Cumulative Production As previously mentioned the cumulative production from the Happy Valley field was 20,847,209 Mcf of gas and 48,518 Bbl of water, through December 31", 2011. The cumulative produced gas volumes, sub- divided by well and formation (through 12/31/2012) are as follows: �A�,%fd'�6u f �r//r At�� SF k t� j si,r; i�� spr r � , r✓ U �a ✓'r Gam, .flf ;rf r ih �t7n(�t�1�1,i 4'a'r�fe�x��f'��ms f rH'l.-ern t'�Ite,.4�`}��,��€C.s.v'�I,{"'S�,,��x��'t..:'fd �, t�Y�fi �F ��Fy3nyd. fsc��(;Y#li G -r - ,1 �. �,,, n-rr 1 q , IH �: .Ft��`��„,tlf� G �Pl si',rr5' 9�' �� 7.,' �rE �rt4'xt'j I gr';r J� 4 � �•4'�sr�j!'f{y"n/ 1 ��,�r��$u��.i!+iu t},4 A�✓ j� ?tl �'l , � , �. RX�17) 33d✓ s `f �f f�f�.✓Yh �•� 1 t x r� f �y `" t � t'/ nP� f�.r„'. I Page 3 Reservoir Summary Sterling — The Sterling formation is currently open in the HVB-14 wellbore and is above the currently defined Happy Valley PA. The cumulative production from the Sterling is 0.295 BCF gas and 0 BW. Additional Sterling potential pay exists in the HVB-12, HVB-13, and HVB-15 wells, and additional offset locations may exist for future development from a potential C Pad. Upper Beluga —The Upper Beluga formation is currently open in the HVB-15 wellbore and is above the currently defined Happy Valley PA. The cumulative production from the Upper Beluga is 0.142 BCF gas and 79 BW. Additional Upper Beluga potential pay exists in the HVB-12, and HVB-13 wells. Additional offset locations may exist for future development from a potential C Pad. Beluga — The Beluga formation is currently open in the HVA -08, HVA -11, and HVB-13 wellbores. The HVA -08 well is also producing from the Upper Tyonek formation, at a gas production split of 25% Beluga and 75% Tyonek (determined from downhole measurements). The HV -1313 wellbore is perforated in the Upper Tyonek and Beluga intervals. The first perforated Beluga interval (BLG-130) had no indications of production, but recent perforated BLG-36 & BLG-40 sands proved productive, with a gas production split of 65% Beluga and 45% Tyonek (determined from downhole measurements) since May 2012. HVA -11 wellbore has remained shut in, not capable of flow, since adding Beluga perforations in Dec 2009. Through December, 2011, the cumulative production from the Beluga is 0.551 BCF gas and 8,952 BW. Potential uphole Beluga pay exists in the HVA -09, HVA -10, HVB-12, and HVB-13 wells and will be added as reservoir management allows. Additional offset locations may exist for future development from the B Pad. Upper Tvonek—The Upper Tyonek formation is currently open in the HVA -08, HVA -09, HVA -10, HVA -11, HVB-12, and HVB-13 wellbores. The cumulative production from the Upper Tyonek is 13.899 BCF gas and 28,969 BW. Additional Upper Tyonek potential pay exists in the HVA -01, HVA -10, HVA -11, and HV - B12 wells and will be added as reservoir management allows. Additional offset locations may exist for future development from the B Pad. Lower Tvonek — The Lower Tyonek formation is currently open in the HVA -01, HVA -02, and HVB-12 wellbores. The cumulative production from the Lower Tyonek is 5.987 BCF gas and 10,398 BW. The Lower Tyonek has been tested in HVA -03, HVA -04, HVA -06, HVA -07, and HVA -11. Economically producible gas in the Lower Tyonek has only been found in wells HVA -01, HVA -02 and HVB-12. Pending Proiects 1. Drilling Program: Hilcorp plans to drill 1-3 unit development/exploration wells during the 10th POD period to maximize gas recovery.' The following drilling operations (not limited thereto) are being considered during the 2013 calendar year: ' All proposed drilling activities are discretionary. Hilcorp reserves the right to implement changes to the timing, sequence and scope of its proposed drilling program as economic or geologic factors warrant. z Hilcorp reserves the right to implement changes to the timing, sequence and scope of its proposed workover as economic or geologic factors warrant. Page 4 a. Complete drilling of the development drill well (B-16) to the intended bottom hole location. This well was drilled from the Happy Valley B Pad, targeting the Beluga (BLG-50) formation. b. Drill a 3,000' exploratory drill well (C-17) targeting the Sterling formation. This well will be drilled from a new C Pad with a bottom hole location outside of the Happy Valley Participating Area within the Deep Creek Unit. Location of the proposed C pad is dependent on results of the pending 3D seismic survey. c. Drill a 6,000' exploratory drill well targeting the Sterling and Beluga formations. This well will be drilled from a new Pad with a bottom hole location outside of the Happy Valley Participating Area within the Deep Creek Unit. Location of the proposed pad is dependent on results of the pending 3D seismic survey. If successful, Hilcorp's exploratory drilling program will require expansion of the Deep Creek Unit's sole Production Area, the Happy Valley PA, as well as establishment of a new Production Area(s) for shallow gas. Until such time as Hilcorp gains sufficient information to reasonably know or estimate the land capable of producing or contributing to exploratory formations, all proposed drilling prospects will be drilled, tested and produced on a tract basis. 1. Workover Program: Hilcorp plans to continue operating the Happy Valley wells during the 2013 calendar year to optimize production from the Deep Creek Unit? Possible well workovers may include, but are not limited to: a. HVA -03 acid treatment of open Tyonel< perforations. b. HVB-13 acid treatment of open Beluga perforations. c. HVA -11 perforate in a shallower Tyonek horizon; the T-6, and run capstring. d. Additional acid treatments to wells with perforations that show indications of skin damage. e. Adding additional perforations to existing completions and/or recompleting wells into shallower horizons. f. Installing capillary tubing or velocity strings in existing wellbores, to help unload liquid production. Exploration / Seismic: Data processing and analysis will be conducted after the completion of the winter 2012-2013 50 square mile 3D seismic program centered on the Deep Creek Unit. Testing and Monitoring During the report period the Happy Valley wells were tested regularly (several times monthly) and allocated production numbers were reported to the state monthly. In addition to the well testing, the wellbores were routinely (daily) monitored for any casing or tubing pressure anomalies. Surface Safety Valve Testing The SSV's were tested on April 13th, October 25th, and October 315E 2012. These tests were witnessed by Lou Grimaldi and Bob Nobles, from the AOGCC, with the October 3151 test not witnessed. As of the end Page 5 of the performance period, the HV SSV's are operating with approved tests on all SSV's. The SSV test results for 2012 are attached in Appendix B. Sincerely, Chris Kanyer tachments Cc: Field Well Files, Hilcorp Page 6 APPENDIX A Happy Valley Field Well Production Plots Page 7 T.bine P..... 0.101) 'u. E EEE a E ^ 0 uo`'LL u t Pal (wm.) nn ,GYM do Tublpp Pmavum (pvl(a)) i ®113 Iwav11 and aao ao Iwaa) nro,wmao TutdnU Pmf vum (P.it9l) Pa tviwt am„umeo 6` Tubing Pmuum (Ptl(a)) (ww) wro •eo do Pz (Pjw),Wmdo T'g9f �aee Tubl., Pmevnry Ipolr)I (PPt9), •e0 d0 Pz (w )wdswmdO i (PPt9), •e0 d0 Pz (w )wdswmdO T.bl.O PM.... fp.l(a)) MEN fpNw) oo,u -eq do Pa (p/9V)g4 WMdo gME M Ef3 C u o r Tubing P.m. (P+I(a)) 81 s a s a e y (WM) W M leo do Pa (P/9N)p IWMdo g I I S — ` I i c g I I g I g 6 I s — I I ffi g SS F s s I I i I I $� � s (WM) W M leo do Pa (P/9N)p IWMdo Tubing Pneeun (Pelf.)) as liLI (p/ayy) peel <efl tl0 Pa (PIT.) WW IMMEO Pa Tubing Pmevum (PdUA u u cm -6 (WM).WH •r'J tlo (PIW) oOM �%BM tlO c a `e rR 2 g r 8 E E x ry R 8 E s x a u u cm -6 (WM).WH •r'J tlo (PIW) oOM �%BM tlO Ubl.0 Pronuro(Plt(a)) Lac $ s Q$ c i c R A$ s s R a s s s R o Pal � IPNwI aero veo ao (Pjw )l. wMdo a I E s" Z ry a E R E 0 � IPNwI aero veo ao (Pjw )l. wMdo APPENDIX B Happy Valley Field 2012 Safety Valve System Test Reports Page 18 Alaska Oil and Gas Conservation Commission Safety\'aloe System Test Report Operator. Chewer, SubmittedBy. Sandyilk\SBan Date: 41132012 Operator Rep: RickXusgrae FieldUritPad HappyVallevA-Pad AOGCC Rep: Lou Grimaldi Separatorpsi: LPS 246 BPS well Penult Separ Set LIP Test Test Number Number PSI PSI T Code Cade AI 2030720 246 200 200 P I P Test Code Date Passed Retest Oi1,avAC,GLY{ Or Date Slmtln m CYCIE,9 4/132012 GAS Inner Outer PSI PSI Tubing PSI 255 YesINa Yes/No No No A2 2031130 246 200 199 P I P 4/132012 GAS 24S No No A3 2032220 246 3/12004 SI No No AJ 2032230 246 342004 SI No No A6 A7 2040440 2041060 246 246 6/12004 SI 542004 SI No No No No AS 2041140 246 200 199 P P 4/132012 GAS 256 No No A9 20417001 246 200 200 P P 411320120AS 2601 No I No AIO 2041660 246 20D 200 P P 4/(32012 GAS 275 No No All 2042070 246 1/222010 SI No No D#Re: 5 Componetts: 10 Pages 0 Fmlure Rate: 0.00%0 "mar Remarks: Alaska Oil and Cas Conservation Commission Safety Valve System Test Report Operates Chearen SubmittedBy. Smdybk,',Efi Date: 4/132012 Operator Rep: Rick\bagro%v FieldUritPad HappyVallevil-Pad AOGCC Rep: Lou Grimaldi Separawrpsi: LPS 253 HPS _`t1''e7t,Da[a� Well Permit Number Number B12 2071230 Spar Set L/P Test Test Test Date Passed Rdest Oi�.p•AC,GLCJ, Inter PSI PSI Trip Code Code Code Or Date Slmtln GAS.rV,% PSI 253 200 194 P P 4/132012 GAS Outer Tubing YM/No Yes/No PSI PSI 257 No No B13 2071510 253 200 198 P P 4/132012 GAS 267 No No I1411s: 2 Components: 4 Failure 0 FaSive Rate: 0.00%0 MM" Remarks: Well B 12 failed i st sismdmn c5ried SSV ore dme, passed 2nd slaIIdova Page 19 Alaska Oil and Cas Conservation Commission Safety Valve System Test Report Operator. Hdcap SubmittedBy. SmAyNkMI] s Date 5112012 Operator Rep: Rick Musgrove FieldUritPad HappyValleyB-Pad AOGCC Rep: Bob\ode Separatorpsi: LPS 304 HPS Well Permit Number Separ Set UPTest PSI PSI T Code Test Test Date Passed Retest Code Code Or Date Shut to w,arxc,cn4, inner (14S[CV< ,g PSI Outer Tubing YesrNo PSI PSI Vt./.\'oNumber HV 1114 2120540 304 200 200 P P 110 GAS P 458 No No No No A3 2032220 202 342004 SI No No A4 2032230 202 3112004 SI No No Ab A7 2040440 2041060 202 202 642004 $1 S42004 SI No No No No AS 2041140 202 110 Ito P P 10252012 GAS 230 N0 No A9 2041700 202 110 Ito P P 10.252012 GAS 209 No I No A10 2041560 202 110 110 P P 1025/2012GAS 230 No No All 2042070 202 i 12220!0 SI N0 No ID'ells: 1 Canton ts: 2 Failure 0 FaaureRue. 0.00%p Samar Remarks: Alaska Oil and Gas Conservation Commission Safety Valve System TestReport Operator Hdcap SubmilledBy, SandyMeJ811an Date: 10252012 Operator Rep: Rick hhasgrove FieldUritPad Happy ValleyA-Pad AOGCC Rep: Bob Node Sepmatorpsi: LPS 202 HPS .'s)YPILDafa ,�,; Well Permit ISepar Number Number At 2030720 r„ Set LIP Test Test PSI PSI Trip Code Code 202 110 111 P P Test Date Passed Recest QI,ayAG,CLV, Code Or Date Shutin GaS,Ca'CIE,s 10,252012 GAS Inner Outer Tubing PSI PSI PSI 206 Yes/No No YesIa No A2 2031130 202 110 110 P P 10252012 GAS 204 No No A3 2032220 202 342004 SI No No A4 2032230 202 3112004 SI No No Ab A7 2040440 2041060 202 202 642004 $1 S42004 SI No No No No AS 2041140 202 110 Ito P P 10252012 GAS 230 N0 No A9 2041700 202 110 Ito P P 10.252012 GAS 209 No I No A10 2041560 202 110 110 P P 1025/2012GAS 230 No No All 2042070 202 i 12220!0 SI N0 No Hills: 5 Congwneas: 10 Fadnre 0 Fadure Rate: 0.00%O MM" Remarks: Page 20 Alaska Oil and Gas Conservation Commission Safety Valve System Test Report Operator. HdmP SubmittedBy. Sandy\k\Shan Date: 10252012 Operator Rep: Rick Musarose FieldUriVPad HappyVaileyB-Pad AOGCC Rep: Lou Grimaldi Separarorpsi: LPS 237 HPS 780 ,,,,':Nellv4fa, '. ,�'llofs,� Well Permit Separ�-Set Number Number PSI PSI B12 2071230 730 450 We7f S'SY,,, SSrSY:'`,RffesllS,6b6re,We7LTlPe ..r,,. Plessures,.. UP Test lest Test Date Passed Retest W,mAG,cLG, Inner Outer Tr' Code Code Code Or Date Shutln Gas,Cf'C4E,g PSI PSI 450 P P 10252012 GAS Car,2UC Tubing � YesNo PSI 755 No ,att>Fr, r ij',,., _,� �Ies1Nb No B13 2071510 237 130 10,82012 S[ I No 10,1312012 SI B14 No No B14 2120540 237 300 300 P P 10252012 GAS 395 11\10 No P435 Dells: 3 Components: 4Fadure 0 Fadnre Rate: 0.00%onow Remarks: Alaska Oil and Gas Conservation Commission Safety Valve System TestRepors Operator. HBrnp Submittedily. Saudy\kMllan Date: 10/31/2012 OperatorRep:Dean Gardner FieldUrit'Pad HappyValleyB-Pad AOGCC Rep: Nene Separatorpsi: LPS 337 HPS 850 Well Penult Separ Number Number PSI B12 2071230 tam Set LIP Test Test PSI Trip Code Code Test Date Passed Retest On,PAc,cLyt, Code Or Date Slmiln aksffctEs 10252012GAS Inner Outer Tubing iYevNo PSI PSI PSI I No YesNo No B13 2071510 10,82012 S[ I No No B14 2120540 10252012 GAS No No B15 2121320 337 300 300 P P GAS 11\10 No P435 TOM: 1 Campomenfs: 2 Fagure 0 FhaureRste: 0.00%0 Now Remarks: Nosmimess from AOGCC. Iritail stoat w HVB X15. Page 21 APPENDIX C Deep Creek Unit 50 square mile 3D seismic program Page 22 Deep Creek Unit 3D Seismic Survey Map