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AIO 015
Ima~Pro'ect ~rcler File Covea e 9 J g XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Z-~ ~ ~ Order File Identifier Organizing (done) ~wo-sided II I I II (~ II I I ~ I ^ Rescan Needed II I II I II ~I I ~) ~ I RE CAN DIGITAL DATA OVERSIZED (Scannable) Color Items: ^ Diskettes, No. Maps: Greyscale Items: ^ Other,. No/Type: ~Ot`her Items Scannable by ~ ~~~ a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ^ Logs of various kinds: NOTES: ^ Other:: BY: Maria Date: ~, /s/ Project Proofing III IIIIiI II I II I I BY: Maria Date: ~ /s/ i P S ti 3 ' ` cann ng repara on x 0 = + =TOTAL PAGES T BY: Maria Date: ~'~ ~ l ©q (Count does not include cover sheet) lsl ~z.~..-- , / , IIIIIIIIIIIIIIIIIII Production Scanning Stage 7 Page Count from Scanned File: ^~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ES NO BY: Maria Date: 1 ~, ~~~ /s/ '~ !~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. (~ i ll'I ~< <II11 I I ~I~ ReScanned III IIIIII III I II III BY: Maria Date: /s/ Comments about this file: Quality Checked III (VIII III IIiI III 10/6/2005 Orders File Cover Page.doc • • INDEX AREA INJECTION ORDER NO. 15 West McArthur River 1. May 30, 1996 2. January 2, 1996 3. January 11, 1996 4. Janaury 22, 1996 5. February 9, 1996 6. May 3, 1996 7. May 7, 1996 8. May 17, 1996 9. May 30, 1996 10. September 27, 2004 11. ------------------ Steward Petroleum's Report of 4th Plan of Development Steward Petroleum's Pressure Maintenance and Enhanced Plan Ltr from JKG LA, Inc to JKG LA, Inc Ltr from Steward to JKG LA, Inc In-house memo to Commissioners Stewards Application for Enhanced Recovery Operations Ltr from DNR to AOGCC Notice of Hearing and Affidavit Ownership information Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells Internal note to file AREA INJECTION ORDER 15 i t STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska. 99501-3192 Re: The request of STEWART PETROLEUM ) Area Injection Order No. 15 COMPANY to conduct underground fluid ) injection operations for the purpose of ) West McArthur River Unit enhancing oil recovery from the West ) West McArthur River Oil Pool McArthur River Oil Pool. ) July 24, 1996 IT APPEARING THAT: STEWART PETROLEUM COMPANY ("SPC"), by correspondence dated May 3, 1996, made application to the Commission for authorization to conduct Class II injection into the West McArthur River Oil Pool (WMROP). The application was compliant with the requirements of 20 AAC 25.402 2. On January 2, 1996, SPC submitted to the Commission an engineering analysis related to enhanced oil recovery operations in the West McArthur River Unit. The report entitled "West McArthur River Unit Pressure Maintenance and Enhanced Recovery Plan" is intended to support SPC's application for Class II injection. 3. Notice of an opportunity for public hearing was published in the Anchorage Daily News on May 17, 1996. 4. No protest was filed. FINDINGS: Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project or similar area. 2. SPC is operator of the area proposed for enhanced oil recovery operations in the subject application and is the sole operator of all wells within one-quarter mile of the proposed injection operation. 3. The area proposed for enhanced oil recovery operations includes the WMROP Pool Rules Area. 4. Three development wells are currently producing from the WMROP, the West McArthur River Unit lA, 2A and 3. Additional production wells are not planned at this time. 5. SPC intends to redrill the abandoned Pan-Am West Foreland Unit No. 2 well to a location adjacent to the oil-water contact on the southern margin of the West McArthur River Structure, and convert the well to a Hemlock Fm. injector. The well will be renamed the West McArthur River Unit I-1 (WMRU I-1) well. 6. The WMRU I-1 well as proposed will be located external to the boundaries of the WMROP, as currently defined. 7. Production from the WMROP began with the completion of the West McArthur River No. 1 well in December, 1991. Cumulative volumes of produced fluids from the pool include, approximately 2.5 million barrels of oil, 1.6 million barrels of water, and 610 million cubic feet of associated natural gas. 8. Initial and current reservoir pressure in the WMROP, normalized to a 9400' subsea datum, are approximately 4300 psi (11/91) and 3550 psi (1/96), respectively. Area Injection Order No. 15~ July 24, 1996 Page 2 9. Compositional analysis of crude from the WMROP indicates 28.8 degree API gravity, agas-oil ratio between 140 and 350 scf/stb and a bubble point of 1048 psig. 10. The pressure decline history of the WMROP indicates that fluid expansion is the most probable source of reservoir energy, however a significant component of aquifer support may be present 11. Conservation Order No. 332 defines the WMROP in the West McArthur River Field. The WMROP is within the upper portion of the Hemlock Formation, and is defined as strata common to the 13,174 to 13,660 measured depth foot interval in the West McArthur River Unit No. 1 well. 12. The Hemlock Formation is an Oligocene aged sequence of braided stream deposits consisting of interbedded conglomerates and sandstones, sepazated by thin interbeds of impermeable claystones and siltstones. The Hemlock Formation ranges from four to five hundred feet thick through the project azea. 13. Within the West McArthur River Unit, the Hemlock Formation is comformably overlain by the Oligocene through Lower Miocene aged Tyonek Formation. The Tyonek Formation is a very thick (thousands of feet) sequence of fluvial deposits consisting of a subordinate proportion of sandstone with minor conglomerate interbedded with impermeable claystones, siltstones and coals. 14. All data required by 20 AAC 25.071 or its precursor regulation has been submitted for all wells drilled in the project area. 15. The proposed casing and testing program for the WMRU I-1 well was included in the subject application for authorization to conduct Class II injection operations. 16. Initially, WMROP produced water will be used as the primary source of injectant. If the WMRU I-1 well has injection capacity in excess of produced water volumes, produced water from Unocal's Trading Bay Facility may supplement injection 17. A step rate test must be conducted in the WMRU I-1 to quantify optimal operational parameters including injection capacity and operating pressures. 18. WMROP produced water volumes cannot replace total reservoir voidage, and will only mitigate pressure decline. 19. Produced water from the WMROP will be chemically compatible with WMROP formation fluids. 20. Produced water from Unocal's Trading Bay Facility may require chemical treatment in order to control scale precipitation, however its chemical composition is lazgely comparable to WMROP produced water. 21. SPC estimates the fracture gradient of Hemlock Formation reservoir lithologies of the WMROP to be .75 psi/ft. 22. Depending on the magnitude of tubing friction pressure loss and a .75 psi/ft gradient, the maximum surface pressure for the WMRU I-1 well will range from 3000 to approximately 4000 psi. 23. Average surface pressure for the WMRU I-1 well is dependent on chazacteristics of the Hemlock Formation, the degree of formation damage and other factors related to the well's completion which cannot be estimated at this time. 24. Information from other Cook Inlet basin injection projects show that shales within the Hemlock Formation and the overlying Tyonek Formation have higher fracture gradients than Hemlock Formation reservoir lithologies. 25. The 200 foot thick interval of the Tyonek Formation which directly overlies the Hemlock Formation in the West McArthur River Unit is approximately 30% shale. 26. Injection pressures proposed for the Hemlock Formation will not be sufficient to propagate fractures through the Tyonek Formation shales which directly overlies the WMROP. 27. The subject application for authorization to conduct Class II injection operations contained a standazd laboratory water analysis of WMROP formation water. Area Injection Order No. 15~ July 24, 1996 Page 3 28. Openhole wireline log analysis and EPA-approved laboratory analysis of formation water samples from the West McArthur River Unit D-1 well indicate underground sources of drinking water are present to a depth of 4000 feet subsea in the WMRU I-1 vicinity. 29. Specific approvals to convert the Pan Am West Foreland Unit No. 2 to the WMRU I-1 well will be obtained pursuant to 20 AAC 25.005 or 20 AAC 25.507. 30. The mechanical integrity of the WMRU I-1 well must be demonstrated as specified in 20 AAC 25.412 prior to initiation of injection operations. 31. The operator is required by 20 AAC 25.402 (d) & (e) to monitor tubing-casing annulus pressures of the WMRU I-1 well periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 32. All existing wells drilled within the proposed project area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 or an equivalent precursor regulation. 33. Waterflooding the currently developed portion of the West McArthur River Structure is expected to result in an oil recovery of approximately 50% of the original oil in place or an incrementa14.4 million barrels beyond primary depletion. CONCLUSIONS: An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.402 and 20 AAC 25.460. 2. An Area Injection Order covering the project area will not cause waste nor jeopardize correlative rights. 3. Freshwater is present within the project area based on analyses of water samples and open hole wireline log salinity calculations to a subsea depth of approximately 4000'. 4. Due to the presence of underground sources of drinking water, the less stringent requirements for a underground injection project stipulated in 20 AAC 25.450 are not applicable in the West McArthur River Unit. 5. The location of the WMRU I-injection well within the project area has not been finalized, and specific approvals to drill the well will be required. Shales within the conformably overlying Tyonek Formation will confine injectint to the WMROP. The proposed injection operations will be conducted in permeable strata which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. Enhanced recovery fluids will consist of produced water from the WMROP, possibly augmented by produced water from the adjacent McArthur River Unit. 9. Chemical treatment of proposed injectint can significantly mitigate scale precipitation. 10. Well mechanical integrity must be demonstrated in accordance with 20 AAC 25.412 prior to initiation of injection operations. 11. A schedule must be developed which ensures that mechanical integrity of each injection well is tested at least every four years after an initial test. 12. Tubing-casing annulus pressures and injection rates must be monitored at least weekly for disclosure of possible abnormalities in operational conditions. Area Injection Order No. 15r July 24, 1996 Page 4 13. The cumulative effects of drilling and operating proposed injection wells in the project area are consistent with proven engineering practice and are acceptable to the Commission. NOW, THEREFORE, IT I5 ORDERED THAT Area Injection Order No. 15 is issued with the following rules to govern Class II injection operations in the following affected area: SEWARD MERIDIAN T8N R14W Section 10 All Section 15: N 1/2 Rule 1 Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to those found in the 13,174 to 13,660 measured depth foot interval in the West McArthur River Unit No. 1 well. Rule 2 Fluid Injection Wells The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005 or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 3 Monitoring the Tubing Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4 Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless accompanied by a greater than 10% increase in injection rate indicating possible tubing and casing leaks. Rule 5 Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission which ensures that the tubing- casing annulus for each injection well is pressure tested prior to initiating injection, and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength of the casing will be used. The test pressure must show a decline of less than 10% in a thirty minute period following thermal stabilization. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 6 Well Integrity Failure Whenever operating pressure observations or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and obtain Commission approval to continue injection. Area Injection Order No. 15 July 24, 1996 Page 5 Rule 7 Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 9 Administrative Action Upon request, the Commission may administratively amend any rule stated above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into a USDW freshwater aquifer. Rule 10 West McArthur River Oil Pool Annual Reservoir Report An annual West McArthur River Oil Pool surveillance report will be required by April 1 of each year subsequent to commencement of enhanced oil recovery operations. The report shall include but is not limited to the following: a. Progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters. b. Voidage balance by month of produced fluids and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and where appropriate, analysis of production logging surveys, tracer surveys and observation well surveys. e. Results of any special monitoring. f. Future development plans. g. Review of Annual Plan of Operations and Development. D I ~ horage, A ~y~~ ~ v~_~ ,~ . ~- ~ ~ ~. ~7'tnlil Co AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected bytt may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Tuckerman Babcock, Commissioner x.11 ~t ~~' -~-TU /~~ 4 ~ ~ ~ ~ _ .. _. ~ ~ - ~. ~` ~~~ ~ /~ 1 ~ ~~ ~ ~-- ~ ~ ~~ ~., ~ _ ~~ ~-- ~ `~_~ t, .. ~' -- ~ j~' ~. .~ ~~~ ~~ ass ~c ~ ~ -- ~ C~ -~~~ v~~ ~~ ~ ~,.~ ~`~ R ` ~` `~ f _ ~.. °~- , _ '~ . ''~ ~~, ~-~,y ....~ ` ,~ ~ X10 ~, 1 11 " ~ ~ 1 ~ ~ ~ ~ a ~ - I~ ~ ~i i ~i$, ;~ ~ ,~ "-'~ I j ~`~'~e ~ ._°°°_~ ,, ,~ ~~ ~ , ~;~ ~'i FRANK H. MURKOWSKI, GOVERNOR 1 ~T ~11~ O~ ~ ~ 333 W. 7"' AVENUE, SUITE 100 COi~S~RQAiiOis COM~IISSIOR ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 ' FAX (907) 27&7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing mechanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Inte rg_it~Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. • • Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Inte 'ty" Confinement" Area Injection Orders AIO 1 -Duck Island Unit 6 7 9 AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak 6 ~ 9 Fields AIO 3 -Prudhoe Bay Unit; Western Operating Area 6 ~ 9 AIO 4C -Prudhoe Bay Unit; Eastern O erating Area 6 ~ 9 AIO 5 -Trading Bay Unit; McArthur River Field 6 6 9 AIO 6 -Granite Point Field; Northern Portion 6 ~ 9 AIO 7 -Middle Ground Shoal; Northern Portion 6 ~ 9 AIO 8 -Middle Ground Shoal; Southern Portion 6 ~ 9 AIO 9 -Middle Ground Shoal; Central Portion 6 7 9 AIO l OB -Milne Point Unit; Schrader Bluff, Sag River, 4 5 g Ku aruk River Pools AIO 11 -Granite Point Field; Southern Portion 5 6 8 AIO 12 -Trading Bay Field; Southern Portion 5 6 8 AIO 13A -Swanson River Unit 6 ~ 9 AIO 14A -Prudhoe Bay Unit; Niakuk Oil Pool 4 5 8 AIO 15 -West McArthur 5 6 9 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" River Unit AIO 16 - Kuparuk River Unit; Tarn Oil Pool 6 7 10 AIO 17 - Badami Unit 5 6 g AIO 18A -Colville River Unit; Alpine Oil Pool 6 7 11 AIO 19 -Duck Island Unit; Eider Oil Pool 5 6 9 AIO 20 -Prudhoe Bay Unit; Midnight Sun Oil Pool. 5 6 9 AIO 21 - Kuparuk River Unit; Meltwater Oil Pool 4 No rule 6 AIO 22C -Prudhoe Bay Unit; Aurora Oil Pool 5 No rule 8 AIO 23 - Northstar Unit 5 6 g AIO 24 -Prudhoe Bay Unit; Borealis Oil Pool 5 No rule 9 AIO 25 -Prudhoe Bay Unit; Polaris Oil Pool 6 g 13 AIO 26 -Prudhoe Bay Unit; Orion Oil Pool 6 No rule 13 Dis osal In"ection Orders DIO 1 -Kenai Unit; KU WD-1 No rule No rule No rule DIO 2 -Kenai Unit; KU 14- 4 No rule No rule No rule DIO 3 -Beluga River Gas Field; BR WD-1 No rule No rule No rule DIO 4 -Beaver Creek Unit; BC-2 No rule No rule No rule DIO 5 -Barrow Gas Field; South. Barrow #5 No rule No rule No rule DIO 6 -Lewis River Gas Field; WD-1 No rule No rule 3 DIO 7 -West McArthur River Unit; WMRU D-1 2 3 5 DIO 8 -Beaver Creek Unit; BC-3 2 3 5 DIO 9 -Kenai Unit; KU 11- 17 2 3 4 DIO 10 -Granite Point Field; GP 44-11 2 3 5 • Affected Rules Injection Order "Demonstration of "Well Integrity "Administrative Mechanical Failure and Action" Integrity" Confinement" DIO 11 -Kenai Unit; KU 24-7 2 3 4 DIO 12 - Badami Unit; WD- 1, WD-2 2 3 5 DIO 13 -North Trading Bay Unit; S-4 2 3 6 DIO 14 -Houston Gas Field; Well #3 2 3 5 DIO 15 -North Trading Bay Unit; S-5 2 3 Rule not numbered DIO 16 -West McArthur River Unit; WMRU 4D 2 3 5 DIO 17 -North Cook Inlet Unit; NCIU A-12 2 3 6 DIO 19 -Granite Point Field; W. Granite Point State 3 4 6 17587 #3 DIO 20 -Pioneer Unit; Well 1702-15DA WDW 3 4 6 DIO 21 - Flaxman Island; Alaska State A-2 3 4 7 DIO 22 -Redoubt Unit; RU D1 3 No rule 6 DIO 23 -Ivan River Unit; IRU 14-31 No rule No rule 6 DIO 24 - Nicolai Creek Unit; NCU #5 Order expired DIO 25 -Sterling Unit; SU 43-9 3 4 7 DIO 26 - Kustatan Field; KF 1 3 4 7 Storage Injection Orders SIO 1 -Prudhoe Bay Unit, Point McIntyre Field #6 No rule No rule No rule SIO 2A- Swanson River Unit; KGSF # 1 2 No rule 6 SIO 3 -Swanson River Unit; KGSF #2 2 No rule 7 Enhanced Recove Injection Orders EIO 1 -Prudhoe Bay Unit; Prudhoe Bay Field, Schrader No rule No rule 8 Bluff Formation Well V-105 • Injection Order EIO 2 -Redoubt Unit; RU-6 "Demonstration of Mechanical • Affected Rules "Well Integrity Failure and Confinement" 8 "Administrative Action" 9 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRIVI STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING AOVE~ TISING ORDER NO., CERTIFIED A 0_02 51401.6 ORDER AFFIDAVIT OF PUBLICATION PART 2 OF THIS FORM WITH ATTACHED COPY OF A ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS >• AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7`" Avenue, Suite 100 ° Anchorage, AK 99501 PHONE Pc "I 907-793-1221 DATES ADVERTISEMENT REQUIRED: o Journal of Commerce October 3, 2004 301 Arctic Slope Ave #350 Anchorage, AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED [N ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for consecutive days, the last publication appearing on the day of .2004, and that fhe rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2004, Notary public for state of My commission expires Public Notices Subject: Public Notices • From: Jody Colombie <jody_colombie@admn.state:ak.us> Date: Wed, 29 Sep 2004 13:01:04 -0800 To: undisclosed-recipients:,. BCC: Cynthia B Mciver<bren mriver@drninstate.ak.us>S Angela Webb <angie_~vebb@dmin.state.ak.us> Robert E Miritz <robert_mintzi~Iacv.state.ak.us=>, Christine Hansen <c.hansen(~c~iogec.state.ok.us>, Terrie Hubble.<hubbletl~~bp.com>, Sondra Stewman <StewvmaSD~a BP.com>, Scott & Canimy Taylor ~staylorl~%~alaska.net>, stanekj <stanekj@unocal.com>, eeolaw <ecolaw@trustees.org>, roseragsdale =roseragsdaleECt~,gci.net>, trmjrl <trmjrl@aol.com>, jbriddle <jbriddle@marathondiLcom=-, rockhill <rockhill(«~aoga-org>, shaneg <shaneg@vergreengas.com>, jdarlington ydarington~uforestoil.com>, nelson <knelson~a~petroleumnews.cum>, eboddy <cboddy@usibelli.com>, Mark Dalton <rr~ark:daltonra?hdrinc.com>, Shannoh Donnelly <Shannon.donnelly@conocophillips.com>, "IitIarkP. Worcester" <mark.p.woreester@eonoeophillips,~om>, "a;:rry C. Dethlefs" <ferry.c.dzthlefs~i-conocophillps.com>, Bob <bob@inletkeeper-orgy>, wd~ <wdvr~i;dnr.state.a~.us>, tjr <tjr a dnrstate.ak.us>, bbritch <bbritch@alaska.net>, rzijnelson <mjnelson(apurvingertc.com>, Charles O`Donnell <charles.o'donnell~veco.com> "Randy I.. Skillern" <Ski1leRLrLBP.com>, "Deborah J. Jones" <JonesD6@BP<com>, "Paul G. Hyatt" ~hyattpg(dBP.corn=-, "Stt~-en R. Rossberg" <RossbeRS@BP.eorn>, Lois dais@inletkeeper.org>, Dan Bross <kuacne«~s@;kuac.org>, Gordon Paspisil <PdspisG@BP.com>, "Francis S. Sommer" <SommerFS@,BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>. "Nick W. Glover" <GloverNW(a.;BP.com>, „Daryl J. Kleppin" <Kl~,pprDE(a?BP.com%, "Janet D. Platt" <PIattJD@BP.cam.->, "Rosanne _yI. Jacobsen" <JacobsRM@BP.com==, ddonl:et <ddonkel@cfl.rr.com~, Collins Mount <colins mount@revenue.state.ak.us>, mckay <rnckay(~c;~.gci.net==-, Barbara F Fullmer <Barbara.f.fullmer@conocophllips.com>, boeastwf <l~oca.5t~vf~u?bp.com=.Charles Barer <barker@us~s.~n~r%. d~~u'gschultze <doug~schultze@xtoenergy.com%, I-1anl: Alford <hankalford(a exxonmobil.coin-, 1~Iark Kovac <}~esno I (c%gci.net>, gspfoff <gspfoff@aurorapower-com =, .Gregg 'slady <greggnady@:shell.com>, Fred Steece <fred.steece@state:sdus=', rcrattv <'rcrotty@ch2mcom>, jejones <jejones@aurorapo~~er.c;oma-, dapa <da~a@alaska.net = , j rode--ick <jroderick@gci.net>, eyaricy <eyancyfci~seal-tite.net%, " la~n~s M Ruud" <james_m.ruud~~conocophillips.com>,Brit Lively <mapalaska~ ak.net>, fah <jah@dnr.state.al:.us=, kurt E Olson <kurt alson(a?iegis.state.alc.us ~, buonoje <buonoje~ubp.com>, Mark Hanley <-mark: hanley@;anadarko.com>, Loren Leman Toren__leman~~i;gov.state.ak.us%, Julie Houle <julie_houle(a dnr.state.ak.us>,1ohn ~ k.atz <jE~rkatz~z sso.org=-, Suzan J Full <suzan hill@dec.state.ak.us%, tablerk <tablerk(c-i unocaLcom>, Brady -,brady~u;aoga_org=, Brian Havel©ck <beh@dnr.state.ak.us>. bpopp <bp+~pp@borough.kenai.ak-use, Jim White <jimwhite~;satx.rr.com>, "John S. Haworth"<~c-hn_s.haworth(cL~.exxonmobit.com>, marty <martv(a?.rkindustrial.com-, ahammons <-~l~ammons~%aol.~om==, rmclean <rtncle~u~(~~pobox.alaska.net ~, min1??00 <'mkm7?UO~aol.com>, Brian Gillespie <ifl3rr~g~auaa.alaska.edu=>, David L Boelens <dboelens(c~aurorapower.com>, Todd Durkee <TDURKEE,@ILMG.com>, Gary- Schultz <gary_schultL(~i~~dnr.state.ak.us?, Wa~me Rancier <RANCIER@.petro-canada.ca>, Bill stiller ~:Bil1_Miller~;xtoalaska.com>. Brandon Gagnon <bgagnon@brenalaw.com>, Paul ~~'inslow <pmwinslow~c~'forestoil.com>, Garry Catron <catrorigr(tr~,bp.com>, Sharmaine Copeland ~copelasv@bp.com>. Suzanne Allexan <sallexan~~~helmenergv.com>, Kristin Dirks ~kristili_dirks ci~dnr.state.ak.us>, haynell Zeinan <kj~eman~a;:marathonoil.com>, John Tower <John.Tower~;eia.doe.gov>, Bill Fowler <BillFowler@anadarko.COM> Vaughn Swartz <vaughn.swartz~'rbccm.corri>, Scott Crans~~ick 1 of 2 9/29/2004 1:10 PM Public Notices • • <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com> Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Hapgy Valley #10. Jody Colombe Content-Type: appicatian/msward i Mechanical Integrity proposai.doc Content Encoding: base64 Content-Type: agplication/msword Mecha~-icai Integrityof Weis Not~ce.doc i Content-encoding: base64 ~I Content-Type: application;%rnsword H appyV alley IA_H earingNotice.doc Content-Encoding: base64 2 of 2 9/29/2004 1:10 PM Public Notice • Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 12:55:26 -08.00 Talegal@alaslcajournal. cam Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: application/msword Mechanical Integrity of Wells Notice.doc iGontent-Encoding: base64 .. ................... _ __ Content-Type: application/msword 'Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1:10 PM i Citgo Petroleum Corporation Mary Jones David McCaleb PO Box 3758 XTO Energy, Inc. IHS Energy Group Tulsa, OK 74136 Cartography GEPS 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Kelly Valadez Robert Gravely George Vaught, Jr. Tesoro Refining and Marketing Co. 7681 South Kit Carson Drive PO Box 13557 Supply & Distribution Littleton, CO 80122 Denver, CO 80201-3557 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Richard Neahring John Levorsen Hodgden Oil Company NRG Associates 200 North 3rd Street, #1202 408 18th Street President Boise, ID 83702 Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Kay Munger Samuel Van Vactor Michael Parks Munger Oil Information Service, Inc Economic Insight Inc. Marple's Business Newsletter PO Box 45738 3004 SW First Ave. 117 West Mercer St, Ste 200 Los Angeles, CA 90045-0738 Portland, OR 97201 Seattle, WA 98119-3960 Mark Wedman Schlumberger David Cusato Halliburton Drilling and Measurements 200 West 34th PMB 411 6900 Arctic Blvd. 2525 Gambell Street #400 Anchorage, AK 99503 Anchorage, AK 99502 Anchorage, AK 99503 Baker Oil Tools Ciri Jill Schneider 4730 Business Park Blvd., #44 Land Department US Geological Survey Anchorage, AK 99503 PO Box 93330 4200 University Dr. Anchorage, AK 99503 Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 Williams Thomas North Slope Borough Arctic Slope Regional Corporation PO Box 69 Land Department Barrow, AK 99723 PO Box 129 Barrow, AK 99723 [Fwd: Re: Consistent Wording for Injection~rs -Well Integrity ... • Subject: [Fwd: Re: Consistent Wording for Trajection Orders -Well Integrity (Revised)j- Frorn; John Norman <john_norman@admin.state.ak.us> Date: Fri; 01 Oct 2004 11:09:26 -0800 To: Jc~dyJ Colombie <fody colombie@dmin.state.ak.us> more ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz(cr~,law.state.ak.us> To:jim regg(a~admin.state.ak.us CC:dan seamount a,admin.state.ak.us, john norman(c~admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commission." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim regg~:admin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob -Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim re~a(i~admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection~rs -Well Integrity ... i - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman(~admin.state.us> ' Commissioner Alaska Oil & Gas Conservation Commission 2 of 2 10/2/2004 4:07 PM .[Fwd: Re: Consistent Wording for Injection ~s -Well Integrity ... Subject: [Fwd: Re: Consistent Wording for Injection Orders.- .Well Integrity (Revised)] From: John Norman <johii_norrnan@admn.state.ak.us> Date: Fri, O1 Oct 2004 11:08:55 -0800 To: Jady J Calombe <jody_colombie~a admin.state.ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx ------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders -Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz~,law.state.ak.us> To:dan seamountna,admin.state.ak.us, jim reggnaadmin.state.ak.us, .john norman(cr~,admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg(ci~admin.state.ak.us> 8/17/2004 4:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 1 of 2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ~rs -Well Integrity ... • - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg 'i,' John K. Norman <John Norman(a~admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission _. Injection Order language - questions.doc ;Content-Type: application/msword Content-Encoding: base64 'Content-Type: application/msword ';Injection Orders language edits.doc Content-Encoding• base64 2 of 2 10/2/2004 4:07 PM ~ • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Form 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. • • Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubin /Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once ever r four years thereafter (except at least once every two years in the case of a slurry injection well}, and before returning a well to service follo~vin~ a# a workover affecting mechanical integrity, ~ru ut'°~•°•* ~ ~~ ~ _~~,~~~ ~•*~_ ~4. •*~ v -P ivu.~i ' ~ b' ... ~ Unless an alternate means is approved by the Commission mechanical inte~Trity must be demonstrated. b~~ a tubing pressure test using a T#e ?vfl-surface pressure ofn~~~ 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that mgt-shows stabilizing pressure that does~~-may not change more than 10°~~ercent during a 30 minute period. -4n-y ... _ . The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise krovided in this rule Tthe tubing, casing and packer of an injection well must •a°~^~•~*••~t° maintain integrity during operation. Whenever any pressure communication, leakage or lack o_f_njection zone isolation is indicated by injection rate. oueratin6 pressure observation. test sun~ev, loa or other evidence, tThe operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval, .J, "';~'-~' ~ t N~~ ut~~ ~ ''~ ~ "*;, ~, '~ •' The operator shall shut in the well if so directed by the Commission. The operator shall shut in the well without awaitinza response from the Commission if continued operation ~-vould be unsafe or would threaten contamination of freshwater `=o'~!~-'-'-mss=n= ' tl ~'1 t !., l~ ~ '' ~ Until~corrective action is successfully con~plcted, Aa monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. [Fwd: Re: [Fwd: AOGCC Proposed WI Lane for Injectors]] • Subiect: [Fwd; Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Aubert <winton_aubert@admin.state.ak.us> Date: Thu, 28 Oct 2004 09:48:53 -0800 Ta: Jady J Colarr~bie <jody calornbie@,admin.state.ak_us> This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim reggQadmin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubertQadmin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: '~ FYI. -------- Original Message -------- Subject: AOGCC Proposed WI Language for Injectors Date: Tue, 19 Oct 2004 13:49:33 -0800 From: Engel, Harry R <EngelHR@BP.com> To: winton aubert@admin.state.ak.us Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F; Dube, Anna T; NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 of 3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lan for Injectors]] return'.ng a well to service following a workover.affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall_* immediately*_** notify the Commission" This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or lack of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte A; Digert, Scott A; Denis, John R (ANC); Miller, Mike E; McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [_mailto:jody colombieC~admin.state.ak.us ] Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal.ZIP» «Mechanical Integrity of Wells Notice.doc » 2 of 3 10/28/2004 11:09 AM w1wel MUM iii,' ~~ ~~ ,~;~ ~~,~~ ~~v of~oi~ Arau BAs i~lli`I ;pal E::. • U`_>1_~SUI~GS 4TrF'A~,~ M~~T l~l/ 1~~~ ~z-z~l:: i i : ~~~~ ~~:I_ ~ c~srrix~lx~c FAX td0. 9075623852 }~~Tt.il"~t~L. 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At'~U~(>r~0 U ~ ~ ~?~{-it1t~(? i'.~t)~ ST~'Wtti~T . ltiC11ECL'A I.. ~.OOE~OUCtrJ ~ ,' ~ ; ~G'f;(? ?t)E~~~ RHE'tit JTt~'. 1CU ~_~r3C)t)t?C)t~7 ra.i`.>()(3~)C) ?737 ~i'i-IUfiMAi\, JAi`cCS L. ~ LTA ~,t~t1~rQt){70 0_'~~:>;'.~f1C1~7 34 b~c4 ~SLdCKER. J(3f'4!`! R 8a~!?A~t~Ot7 7,. ~ 7 i~a()~(7 i~77~~} ,'tf;TUS, WIE«I~IAfi~ U_ 0.3"7i9~(1G~ (),,:9;''.y~41h() F, U4i 14 [°'P,fx~ "r1AY 3 0 1996 Alaska Oi! & Gas Cons. Commission An~ptsQe CA`: -.;u -~~ TnU u;; ~ ;8 D I'J OF OIL AND GAS FAX N0. 9075n23852 ,~~ ~ ,11.E ktti~r . -'•: '~U~~ '~)~ S ~: t).. ~ .a yes 'f':i:~'J{: ~~}:OV ~'"' -i~T Ql~ tr t'?F1TP1i.. Cilt. ~ GRsll~zl~x~la ~2AT14~iRL. f.'ri,J~lEhSHII=' fiESt7tJRC~ 7:MF-al"tii~tlT3a~t ~t Cr i~: (::~ i^'i 1"'~.~. ~~ Y 1=' is Li l E.. a4 i~I? C~ ~~ S L.C:(~S >``EC1 i .%i" 7.C:~ r.rCf[''s j~f9E'~~. ~ 1 E:.UlfkftiT r'1=Ti'~Oi_!~t~l"R 1.11~`i~"'~rjY ~~07;~1t. AC1=:imS rw.C~1=S O~iSl~l~lti~ ? . § ~~; .. ~J(?rv 0 . BOG . , `J5i 4 r'r11,'= UC=1= Sl"JQ~.~ C;l= ON5!°lC?f^;i~: ©f=~'~'i-Ii~f;L. C3 ~1 \ C.:11 ~?~ NR~ii" ;:~ •f r r, ;~ ~ l-~'i 't' l.. ~ Y . ft =~~ ill='T i-I Jd , ;33:3`~.5~ 1='CI{_~1h lE~f:~Rl~ l:l`dVIrCTMr'i'dT~~, I.~~L. :~~?_~Ji)5 f~t)~f=JETS. L'~iTi-!~Y~# ~3.~t3~fE~ ~'>G~JF'CTr~ (:l'J:L ~ tsRa C13RPGC2f?S'T ;~?El~ ~' s.S'~>=;)='l~TR P1;OD4lCTTDi~ -- >ai_ASKY~ 3;si =~:.'. ~{I_€:~s;t;~i~; , .1t~!~fr~f R" T~UrTEI. a:i~~l'~ IJr?C~tl`' 1~1'tEi'~GY l...L.C.. 3~4£3r~M ~T'I•ti11Y , X7C?3~3+J~ ~ WC)r's<T.i~~v >Zf1Yr~i_ i ~t i+~TEF;CS i fi,. Q0~}E~C~t?t) p _ n4~:kt)~~ i . ~7F~t?(:lOt~30 3. (•It)(7n(~~f3 ~ . ~ ~0(7GfJt~ ~,, ()ta~3n~JS7n ~, ~~C)4C?Q~ [~..EyF~3~~°;°~4~ c~.~~~Y~3~a 4~). ~i>()c~UCJ t? . Ei''S~~~f> tt~7 ,. ~5 5i}(~~~(yy1~ tip.-3~ CY (~ti/O 1"1 F" P" T d 1 i i~ i'S i ~ 7y ~.. r q, .~ j ~ ~ t y, Alaska Oll ~ Gas ~an~. Gammissicn Ancnorage ,MAY-30-96 THU 09;38 DIV OF OIL AND GAS FAX l1~~~! T'xt~i= ~ ia:>aw C; T, E_. ~ Grt•S''i~~i>!Zi`!C i`J~ii'~E:;•iSl-iii=' (1Ct4';:I:"-^~i:~T TYr'f:: CTL. A~lI~ ~"RP.S' LEra~i:: NC.''TIf•-ICf=~T7:C~i`± l~f~l"iF~ S'TiG!l:~;T F'L1'I<(?1n.I=C}~ r'Qlr:~~r~~i~f" N0. 90i~623952 ~ . `i 7~ .,'?~~ P. Qo/ i ~ .t.r^~T_.._._.._.... ...._. r~.2Y1 ,I'.,IY I ~•~___.___._..........-.~-•i'Tl.~~~l..~J..~..-._._.__._~..... ........-.~._.._~..~....•.,.....-.-. _-.._..,. ~.. .-.~.-..-. .. ... .... .... .. _ i:;;01~ ,Sj-;Qlyi ~: t?n! ~l-lQi=;f' l71"1 r } f t•) A ~~ ~ ~ ~~ h S `.I A ~ L~ `.~ f)~~.11':~:):: b.1Gi•~':{ 1:NtY i'~~iY~lt~ ~ ~±` C,.~ NA~fI~ s;~"'`='F,~.~'1T .i~iTi~.?~..c..",i i 3~~4 Wf~~i F_~' , Fi1.C1-fAlilJ e: lc C>UC~ ~ . ~t1t~; 1 7t3~JG vG ;::. C~>; ( ~ l ~ ^ M~i~i i F~~R Tai{NP 7'i~irl`^Ti'iL~!T~: U_(ii~t)t700t~ i _(7{}~)t}~rE)f? ''s i~~4~c5 ~ul._E : CHARLv F t} A t~<:»(>~)~)4') i . ~)(=)~!}C)(1?.} i•c~~~£3G ~TrLa~:cx>=>i . c~r.L?_..~.V~i~ G C-? . nOGOC~C~C' `:. (?C?~;?~Jt~C~ 3 ~ 98 S i ~'URt;'t' i~C?"1:;>"3Gn1nL ri'4 t~f~~i'"'{ti~Y , ?i , i >4 :?~t7~ ~f.-, . i ~ r ,~k~() 4'7t}3y7 ST~WFi~~I' , GJ7:Ll..SfaM F<~ r1. ~5C~0!?f;~?C1 C ~ ~?~'~~ a~)f~ •i '~t)~? f~'ar~fi T ~1St7Ai , .it~I-iii ~ ~) . r)r~n(?0~(~) ;~ , =>()t)t?()~~~ 15'O;a•4 i~iCAk:MR F:~t~:I:LY T%i.1S''i . i`iiG.f..~::= i ~ _ t?t}(}CaC~t1C~ ~ Cx. t?~~JO~{)t} .ir) o '~ ? M ~~iF.7.N. i=h.~ti~i{ I_ C t t ) }.t~} ( JJ 5 3{ i { •) ~~C~} )~ t- `: )~:s(y ~~ ~ yy(~ 7Ci l'Y~ f N, 1 SIwILW ~'~ ~.TI.L ~ TAU , ~l`iC n 1 / y ( ~ / ' ( ~ ( ~ •' 'J c ~\i~V{aI LTV ( / ~ / ~ ~./ ~ I=.~\.~~ •O •~J'/ [;~'~~~ h~~l='l"f~, bJ~.LL.:fAiri ~ t3.r3(}~~(~~(:) (1.i:5~)()!)~ i :~(7~ ~ i~CAfll~!ALD : uClHi~ L. ;} ,. n~}t1a~C)i} f} _'Jta~°.3~~'il t9~~i~ i~GDt'1hlf1LI3, lv1T! L.Ii~i< 4~i At~t3~?(?{}'?(•} c;„()Ga:35:~~() ~Mt~~:s l..A)~ F'1'-~t3F'~'i;TI1=S . S:Pr~; . , f,). ta~~ ~ti~l~~ ~ n i ~37~r~~r~t7 ~yn~'s~3 >_IiriCSTfl~lE t}~!_ s~ iris C~,fF'Faf~~~, ti .,~;~;>c;~}~~c3 ; _{~i~c~)c•3t~c)t3 57!)`~.~". >rf~f..~!=~i~lDC7F~ l~l::dATf~tiST~ lCC~.T!-1 C~,^~?C}~>i1~c~~` C~xF>~M:~~:}OC} # 990 AE..E'UT CflFtl=`t~r'AT Tt~i~ . TMf-_ ; ~ n ()t?(7t}i)z~c3 c:) ; i ~'~{)'~a() ~ ts'G<i~5 /CRfw'~'Y ~F_'~IL7l,,as~ln.r T~'UST . ..10}-!j~ ~ . GC~~`JUU>j Cr , ~?">C3~JG~C}t;~ i .~`~~-.;_' I:~l.1f~l~DW a . bJ(~LTE~i a)fl?'~ (). (}~7t)~?i)nr} ~ ,, ();34 '? t?i) ~5~~04~ l-'E~i;;Cl~lS. ~~!-l~i~) , Fi~lr~iri;T ~ ~r_r? t)aono~t}c)r~ t?A~7~~i~:~(}(} i'7•~`c~ ~C')1..r~F:i.S (-Uh!?- I-.nl-'~ . ~~.~}~)'.~~c:)flca ~~.~2~~•)nl:.)()(:) 19~a~• i1?CI'1i~C;D~ui`~, I•'tii~, Jf'-1ClC !'! ~4 f-;i:. t:`.f)`1iJC~G,nn t,~.~!~~r~t=)Uf) .~^~J^t.~ Ct~Ti.. 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O~~GGC3t-}f? ~~ ,. ~~~~~~~ ia'1~~~' r~~iTUS, bJll..l-.I~i~f ~. t:_~-'iU~~ut~ U.4?a~t~'b~ 3 MAY 3 0 1996 Als~ke OII & Qes Coos. Commission Anct~orape ,MAY-30-96 THU 09; 39 DIV OF OII. AND GrS F~ S ISO. yu ~66C3tStiC ht~h! 3~ATl., = ~~i/~0l96 ~':~t;TnGt~T t}f- N ~li>iE l~'T,~f=: i0:v8 L3T1* ~ CASlM:i:~?TNC C4Ji~!rri~f-IT.t' ]:~1"OF~i`i(~T~~'C)~ r1DL.. s~U~iE{rf~? : ~c.rf::Fi~ri~"t' TYr--'~ i~C2T~I~'1:~:~TTC?i~ i~Ai`~1•~= 4,f FSUL_ ~:~~ S-1 i~:~lAr1~~ T~TF~f.- ~~~rRr'~ 75 ., ~~(t 4 t3 i"i.'.:'I'iit7l..;m~J~ GCJ~i'~i'~~~ arrtR~. ~~saic~r~i;: r.~ ., ~ 0 l A~ Qi~ESi-lC3iil~ Cil= E= S!^;i/~!z~:. c~w~~~:~ t:Z~ 1~t~~if 3~ 7caa ~f~'1'Tl..~l' , K~i`!?~4:.'TI-l ~, a5 7b~? C:!-iF'.~. aT:[;?~~ON: Gr1~St~T 3~s~5~"~ ~=•t~l..f~rti ~i~~~~ f ~VI::S'~i~ti~:1~'i'~ , i_ . i... , 3~;~Q5 ~;CIT:~EFi?'L , C(-iTF~E'iY~i ;3~8~~ ~'sct~~'iwTA ~~~. <~~ ,a~~ cni,:~°c~~r-t~r~. ~~ X47 1*,~C:t;i='("'1'A F'I;OX~l.1C1'~C~~ - n1_jtSK,'-t 33! 4~ ~L.Ot:t`C!~' . .~til-#i~# r, ~ ' i?t.~ s i ~l:~ , 33~ 1 ~ E~C;AF' F's~>*i^:C;'f i.. ~ f.- , C:. , ~ sc~~~s i~t~ni_s~a , 1~~~ ~ 3;~~30:~ i~'Ci1hY . S:tL~i`~fit f-1 1, lam. C ~§ , 1 7? ~ ~~C~ i~r r,:}~ ~ ~~~r ~i> 5 ~i3 ~~t~o ~ . UUC~O~~!? 4.=:i~~s•1~7~!~~ ~~ . O~i:;~+~t~C~ ~ . UC)U~UGf} a ., {?4?(7 c7~5c)~7 L•~,'~~?~rlw'~' ,.. ~ ;}(If)s?t5(1~3 ~? . ~U(7nOt?G ..i . ~:UCJt7(?~~ l:~t)~~~35t)i) 0 ~ L-}.r~??~~t7 ~'r~~cat~c3 a 5'~'i()t~)t:)~) (? ~ ~' i ~7'wbt? i . "~5~7t7~3t~?) . , Gi4 .~ ~~~~~~~~ MAY ~ ^ '~4~ Alaska Oll & Gas Cons, Commission Anchorage ~8 Notice of Public Hearing M STATE OF ALASKA Alaska Oii and Gas Conservation Commission Re: The application of Stewart Petroleum Company for an Area Injection Order for the West McArthur River Unit in Cook Inlet. Notice is hereby given that in correspondence dated May 3, 1996, Stewart Petroleum Company, has petitioned the Alaska Oil and Gas Conservation Commission, in conformance with 20 AAC 25.420, to obtain approval to conduct underground fluid injection operations for the purpose of enhancing oil recovery from the West McArthur River Oil Pool. The proposed area of injection is located in the western portion of Trading Bay in Cook Inlet, and conforms to the West McArthur River Pool Area as defined in Conservation Order No. 332. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM June 17, 1996 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address at 9:00 am on June 24, 1996 in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office, (907) 279-1433 after June 17, 1996. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 279-1433 no later than ,lar~J~4.996.~--~~-~ David W. Commiss Published May 17, 1996 AO-02614045 ~~17840 STOF 0330 AO-02614045 AF F ID VIT O F PLI B L IC TIO N $67.20 STATE OF ALAS[CA, ) Afotice of P 9 " sr;ar~ as' atasKa illasko (?il end Cos THIRD JUDICIAL DISTRICT. ) Conservation commission Eva M. Kaufmann Re: The applicofion of SteWpri -Petroleum CortW>eny far pn ar ................................................... ea lmacrion order far tits being first duly sworn on oath ~ty~ t•fs9cArt{gUr hivet Unit in' k: mist. deposes and says that he/she is •rvo„ce ;5 fferehlY g; yen thM in an advertising representative of cor>respondel5c¢ tlotid MAY 3, t99d,_ sr~wa.a Patroteum the Anchors a Dail News, a g y company, nos pet;tionpd try Alaska Oil and Ges Gofilervq- daily newspaper. That said Tian cammisslon; ih eonfar. newspaper has been approved manse with 20 AAC 25x20; to obtain t~ppravai to cond°cf> by the Third Judicial Court, undergtaund fluid inter}ipn, operotioris for the purpose Of Anchorage, Alaska, and it now (,erihanciny on recovery fromine west MC,9rrl,ur River oii cool. and has been published in the the proWOSeo area C~ iniettion is located in the western porti En lish Ian ua a continual) as a g ~ g y on of rrpdinp 9av tn:cook:lnlet, and conforms' t0 the Wesi daily newspaper in Anchorage, McArthur River Pao1 Area as defined in Conservation Orck : Alaska, and it is now and during ( Na p~ al I said time was printed in an - son who may be barmen ii tfie regaesrea oi'Eer is )sages office maintained at the aforesaid may filea:writtenprotest prior to 4:00 PM June 17; 199d with lace of ublication of sold P P . the Alaska pit and fps Conner- vptipn commission newspaper. That the annexed is , 3001 Porcupine or;ve, anchorppe, piaska 99501, and requesT o a copy of an advertisement as it h~rinp on +he- matfer:. Ir 'rhe >Isrotest is timely tiled dnd was published in regular ISSUes . 'raises p substantial Ghd mpterf. (and not in supplemental form) of al issue_crucvcti to The Commis- 51an-s°d2ferrn;narlon,Q hedrin said newspaper on g ep fhe matter will be held at he oaove aadress of 90o pn, ar, June 24, 1996 in canfQrmance May 17, 1996 wife 20 AAC 23.540. If a hearing tea to bo held,:interested,parties "maY canfiryti fhi4 bv, Galling the CQ mmission's office, (907)' I:R79-1433 After. Jt+nd i7, i996; 'lf. and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. signed -~~-~ Subscribed /and sworn to beF re me this ~/.. day of ' ~~... t ~. Notary Pubhc in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES __ . ................19 ~~~~aP s((W qRr~~% ;~ ~ --- - pU~d.®G : ~~ ~~'~/,~~JJ~Sdori Ex~ ~ 1~~~1 lion wne consider tAe -issugtKe,. of the order without a hearing; If YOU. pr@ a'PerSari wifh a dispbilify who mby need ~ ape. s~ia+ ~ modification in order ~ to:. zomment or to iaitend ttu pubii~ hearing, piepse confptt Didna Fteck af,279q~33 rip feber thon Juee 19, 1996.: Bli9avid W. Johnston Commissioner fsub,;_:May iT, 799d ,_, ~ 7 9075623852 P, 02/14 ~~TONY KNOWLES, GOVEANUR ~ ~~ ~ ~~ ~ t iI r~ ~~ it i ~ 1~~1 ! ~i~ :~,. rJ~ 3601 C STREET. SURE 1380 ANCHORAGE. ALASKA 99503.5948 n~i,/1ca~,v n~ ~;, ;a,~t~ GAS PHONE: (907)7622549 May 7, 1996 Alaska Oii and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-~ 192 Attn: David W. Johnston Chairman Dear Mr. Johnston: Reference is made to your letter of Mazch 25.1996 requesting information about the West McArthur River Unit (WMRU). Zn response to your questions, I offer the following: 1) The DNR approved the WMRU on July 27, 1990. A copy of the Decision and Findings of the Commissioner of the DNR regarding the approval of the WMRU, dated July 27,1990, was provided tv the Alaska Oil and Gas Consen•ation Commission (ADGCC). The WMItU ' is a two lease unit chat includes ADLs 359111 and 359112. At the time the WMRU was approved by the DNR, the Stewart Petroleum Company was the sole working interest owner in the WMRU. The Stewart Petroleum Company owned 100% working interest in the two leases included in the WMR'L'. 2) Pursuant to 1 I AAC 82.605, working or royalty interest in a lease may be transferred with the approval of the Commissioner.. Assignments of interest in state oil and gas leases aze submitted to the Aivision of Oil and Gas for approval and tl~e Division maintains files of all state oil and gas leases currently in effect. Since the formation of the WMRU, Stewart Petroleum has assigned worlciag ?merest and overriding royalty interest in.the two leases to numerous parties and the assignees nave chanced over time. As of May 7, 1996, Attachment 1 lists the current working and royalty interest in ADLs 359111 and 359112. It should be noted that there may be other investment-type agreements or investor interests associated with these two leases. However, the DNR does not approve them nor track them in the uidividual lease 51es. ~ 3) Plans of development for the WMRU are submitted and reviewed by the Division anuually_ The Fifth Plan of Development (POll) fox the WMRU was approved on November 6, 1995 for the period December 31, 1995 through December 30, 1996. A copy of the Fifth POD is attached for your information. R~C~IV~D MAY °, ~~~,:1956 ' . . Alaska tNl & GA~~nission .t; 'l l i(1 . a : ~ ``- :~~~' u~~:9 rfl,. t;0. 9075623852 David V1r. Johnston May 7, 1965 Page 2 4) The '~i iRU Agreement sets forth the rights and obligations between the royalty Owner, the State of Alaska, and the unit operator and working intcrest owners in the icases of the unit. The WMRU Oi erating Ar,,r•eement, a.~rzendments to the unit operating agreement, and any other separate agreements between Stewart PetralCUrn and the working interest owncrs, overriding royalty interest owners, or other investors in the unit set forth the rights and obligations between these various parties and the Unit Operator of the VVMRU, Stewart Petroleum. At ±~;~ time Stcyv nrt Petroleum made application for the formation of the ~1RU, Stewart was required to submit, for informational purposes only, a unit operating agreement exet;uted by tl:e working interest owners in the unit. The unit operating agreement or any other agreements between the working interest owners in the unit or any other individual investors in the unit dv not require the commissioner's approval for adoption or amendment. The D~iR approved an initial participating area, the Area 1 Participating Area (A1PA), for the WMRU on September 19, 1994. As part of the approval of the A1PA, the Commissioner approved an allocation schedule setting out the percentage of pmduetion and Costs to be allocated to each lease or portion of lease within the paiucipating area. if there is a different allocation formula among the parties holding an interest in the unit, the parties to the different allocation formula not approved by the Commissioner are required iv subFZUt a copy of that allocation formula to the Commissioner and a statement explaining the reasons for the difference. No such allocation schedule has been submitted io the Commissioner to date. Except for the unit agreement, contracts or agreements between Stewart Petroleum and the working interest owners or overriding royalty interest owners or individual investors in the unit are not approved by the DNR. We understand that Stewart Petroleum has numerous investors whu „lay or may not have various forms of ownership interest in the WMRU leases. These parties may or may not have any correlative rights in the WMRU leases. Stewart Petroleum, the Unit ~pcrator, likely plays a different role then Stewart Petroleum, the working interest owner. The rights and obligations of Stewart Petroleum, both as Unit Operator and working interest owner, anti these investors should be set forth in the contracts and/or agreements between those parties. Sincerely, ,~ Kenn A. Boyd DirECtar Attachments S e e ~ ~~~ ~~~e.~ ~oe .~l-4.e.~.na.~4,s i1~1 i! '1i J/ 3r.~. wMRU.A000r.~rkc J~ ~ ~ ~ 1 y 1 ~1AY 3 0 1yn, Alaska Oll & Gas Cons. Commission Anchorage ~~ • • Stewart Petroleum company Denali Towers North, Suits 1300 2550 Denali Street, Anchorage, Alaska 99503 (907) 277-4004 • FAX (907) 274-0424 May 3, 1996 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Re: Application for Enhanced Recovery Operations West McArthur River Unit Gentlemen: QcXs~ )~ ~'' ~k Q ~~ JA '_Yk~ t Q~~~r ~^ a~P ~~~ Enclosed is the Application for Enhanced Recovery Operations for the West McArthur River Unit as required by 20 AAC 25.402(c). If there are any questions, please contact me at 277-4004. /~/ ' /l+r~ Tim Billingsle Petroleum Engineer Stewart Petroleum Company cc: William R. Stewart, President -Stewart Petroleum Company Paul D. White, Operations Manager- Stewart Petroleum Company i 1~ ~~ ~+ ~ ~. ~~~~+-~~ ~,,:~a ~,,~. „~~~E~m~+~~at~ ~1tNnN,ay~ • West McArthur River Unit Enhanced Recovery Application Stewart Petroleum Company May 3, 1396 RECEIVED MAY 4 6 1996 ~~9NkA ~t~ i4 ~+~4 j r~~~:9 tiiliit:ITi4~~~f111 Ac+Ch~r~(~8 • • 20 AAC 23.402{C~ Enhanced Recovery Application 1) Location Ptat Attached are two plats showing the location of the proposed West McArthur River Unit No. I-1 injection well. This well will be a sidetrack of an abandoned weN, the West Foreland Unit No. 2 which was drilled and abandoned by Amoco in 1966. The WFU #2 was a directional well and Stewart Petroleum is proposing a sidetrack of this well bore and directionally drill further out to a location in the Hemlock which will support production in the 3 producing wells of the West McArthur River Unit. This is the only injector proposed at this time. An Application for Permit to Drill has been submitted for the WMRU #1-i . it is anticipated that the redrill will take place in the summer of 1996. This enhanced recovery application is being submitted in order to obtain approval for injection to begin shortly after drilling is completed on the proposed injection well. There are no other wails within 114 mile of the proposed injection interval. 2} Offset Surface Owners and Operators There are no other operators or surface owners besides Stewart Petroleum within 1/4 mile radius of the proposed injection well bottomhoie location. • • West McArthur River Unit Unit Boundary Plat Proposed WMRU No. I-1 T8N, R14W, Seward Meridian W. McArthur River Unit ADL 17602 Stewart Pet. Co. Unocal ADL 359111 ' 2 5 __ .............._.,._. WMRU-3 • 12 13 ~~dV Q K 100 1" = 1 mile AWE IW i t~ West McArthur River Unit Ido. I-1 Proposed Location Section 9 Section 10 • WMRU #3 / ~ WMRU #1 ~• ~ . WMRU #2A ,' ~ ~' ~ Section 16 ~ ~ Section 15 ' ' o ~ o ' ~ - ~ ~ ~- .- ~ ~ ~ ~ WMRU #t-1 ' ' ~ ' ' . ' , - 1780' Proposed Target ~,~ ., ~ WFU #2 _ ~ West Foreland #1 Section 21 Section 22 1 " = 2000' 3) Affidavit Showing Notification of Other Operators and Surface Owners Even though there are no other nearby owners ar operators besides Stewart Petroleum at the proposed injection well's bottom hole (ovation, the surface owner and subsurface owner of the surface location of the proposed injection wet! have been provided a copy of this application for injection. At the surface location of the proposed injection wail, the surface owner is Salamatof Native Association, Inc. and the subsurface owner is Cook Inlet Region, Inc. I, Tim A. Billingsley, as agent for Stewart Petroleum Company declare and affirm that I have knowledge of the matters set forth in this application and that on S/ 9~ ,the following surface and subsurface owners were provided a copy of this enhanced recovery application by certified United States Mail from Anchorage, Alaska: Cook Inlet Region, Inc. P. O. Box 93330 Anchorage, Ak 99509-330 Salamatof Native Association, Inc. P. ®. Box 2682 Kenai, Ak 99691 Attn: Mr. Jerry Booth f~ Tim A. BilGngsl Petroleum Engineer Stewart Petroleum Company Attn: Mr. James Segura RECEIVED ~il:l~~i1~ (~tt Lwi r:~. . `1iY1?y ? i • 4) ®escription of Operation for Which Approval is Requested The West McArthur River Unit presently consists of 3 producing wails completed in the Hemlock formation. The proposed injection well will inject produced wafer from these 3 producers back into the Hemlock to maintain reservoir pressure and to sweep oil to the producers. Due to the small number of wells, it would be uneconomical to develop a more thorough injection pattern at this time. The produced water rate from the 3 current producers at WMRU is 2000 BWPD and increasing. Once an injection rate is established in the WMRU #!-1, the injection rate may be enhanced with water from Unocal's Trading Bay facility. However, it would be prudent to demonstrate that the injection rate below fracture gradient in WMRU #I-1 is significantly higher than 2000 BPD before incurring the expenses of laying a 3 mile flowline to UnocaPs Trading Bay facility. Currently, the produced water at WMRU is disposed in the WMRU D-1 injection well located on the same drilling pad as the 3 producers.. This is a shallow vertical well with an approved disposal zone in the Tyonek formation at 4300' TVD. This injector wiA remain operational as a back-up for produced water disposal should the WMRU #i-1 have mechanical problems. it should be pointed out that there is currently no back-up for produced water disposal at WMRU. An important economic benefit of this proposed enhanced recovery project in addition to secondary recovery is that it provides an alternate injection well which will reduce the risk of shutting in oil production due to a lack of water injection capability. Such a shutdown of approximately 2 weeks occurred in December 1995 when Well D-1 became plugged with solids and a coiled tubing unit had to be mobilized to clean out the well. Therefore, this application is requesting approval to inject ail of the produced water from the WMRU into the proposed WMRU #1a1, If sufficient injection capacity below the fracture gradient is demonstrated, a supplemental water source could be the Unocal Trading Bay Facility which would require a flowiine of approximately 3 miles. 5) Pools to be Affected The West McArthur River Field Hemlock formation (Field & Pool Code #930148} is the pool which will be affected by this proposed enhanced recovery project. The nearest producing weft is WMRU #2A which is completed in the Hemlock at 9413'-9599' TVD. The proposed WMRU #(-1 will be lower structurally than #2A and the anticipated injection interval will be 9500'-9650' TVD. 6) Injection Formations The name, description, depth and thickness of the formation into which fluids are to be injected and appropriate geological data on the injection zone including lithoiogic descriptions and geologic names have been previously submitted to AOGCC in "West McArthur River Unit Pressure Maintenance and Enhanced Recovery Plan, 1/2/96" by Art Saltmarsh. Excerpts from this plan are as folbws: The reservoir of primary interest at WMRF is the Hemlock Formation. The Hemlock Formation unconformably overlies the West Foreland, and consists of a thick sequence of interbedded conglomerates, and sandstones, separated by thin interbeds of impermeable claystones and siitst©nes. The Hemlock Formation is very uniform in thickness, although there is considerable variation between the individual benches. As an example, benches 2 and 3 usually show the biggest variation in thickness (in WMRU #1A, bench 8 appears thicker than in WMRU #3). This stratigraphic variation is typical of a braided stream depositional environment. HEMLQCK LITHOFACIES There are approximately six (6) lithofacies present in the Hemlock at WMRF. This is very consistent with the facies found at MRF. Porosity within the Hemlock is intergranular, and the rocks are well cemented and competent. The lithofacies, from coarsest to finest are as follows; RESERVOIR FACIES 1) Pebble/cobble conglomerate - These conglomerates range from clast- supported to very sandy and matrix-supported. Cobbles and pebbles in the conglomerates are well rounded, and moderately sorted, indicating considerable transport distance from the source. Porosities are relatively uniform, ranging from 7-11 °lo. (Cores from MRF show a degree of very fine material in the matrix, mixed with the sand. This has a tendency to reduce the porosity and permeability at the MRF. There does not appear to be the same amount of f+nes in the WMRF, as the porosity range is higher for the conglomerates than at MRF. The lack of fine grained material should not affect the fluid flow within the Hemlock). 2) Pebble/gravel sandstone -This lithofacies is mare unifarm in grain size, and is entirely matrix supported. Porosities range from 1 Q-16 °l~. 3) Medium to coarse grained sandstane - Facies is moderately well sorted, and matrix supported. Porosities range from 12-18 %. RECEIVED MAY 0 6 1996 Alaska Oil & Gas Cons. Commission Anchorage 4) Fine grained sandstone -Facies is well sorted. Porosities range from 12-14 %. {note: When the fades permeabiiities are higher). NON-RESERVOIR FACIES grains are well sorted, the porosities and 5) Very fine grained siltstones -Facies rocks are dense and generally non- permeable. Porosities are very low ranging from 1-4 °lo. 6) Highly carbonaceous cfaystones - Facies is non-permeable and rocks generally have no porosity. Cuttings and log response in these zones resemble coals. Along with the siltstone fades, these fades generally act as seals for the overlying and underlying reservoir rocks. HEMLOC?~ RESERVf31R CHARACTERIZATIC}N The Hemlock reservoir at WMRF is heterogeneous, based primarily on the analysis of wireline logs, FMS, and determination of depositional environments. The Hemlock is variable both horizontally and vertically. The source of sediments for Hemlock deposition was from the NW, and the general trend of the fades is NW-SE. This pattern creates a preferential flow from SE-NW within the reservoir. This same pattern was found at the MRF but had little to no effect on production or injection performance over the field as a whole. Porosities in the sandstone fades of the Hemlock are between 12-18°l0, with same small sands displaying higher averages. This includes the fine sandstone, medium to coarse sandstone, pebble/coarse sandstone fades. Permeabiiities in these same fades range from 100-300 md. The conglomerate fades are slightly less porous, with porosities ranging from 7-11 °to and permeabiiities ranging from 10-50 md. This contrast in porosities and permeabiiities between the reservoir faeies can affect fluid flow between the fades. An important distinction to make is that there are no non-permeable zones, that would create baffles to fluid flow, between these genetic units. Although fluid flow will be affected by this contrast, there will be no restriction to flow. At MRF, the porosity and permeability contrasts were a Tittle higher. It was found that during enhanced recovery operations, the best reservoir faeies {sandstone and pebble-sandstone faeies} actually flushed quicker than the conglomerate faeies, although the conglomerate units stiff contributed oil. The total oil in place at MRF was volurnetricaAy calculated at 1.1 billion bbls. Primary recovery was expected to be approximately. 20%. Water injection was • initiated early in the life of the field and recovery to date is in excess of 500 MMbbls which equates to a recovery efficiency of 45% of original oil in place. Ultimate secondary recovery is expected to be 50°I° of OQIP. (See last section for estimated recovery at WMRF) ~) Logs of the Injection Wel! The WMRU #I-1 has not yet been drilled so no logs are available at this time. Logs are on file for the completion intervals of the 3 producers at WMRU and the abandoned WFU #2. Interpreted logs from WMRU #2A and #3 are attached which show the completion intervals in Benches 1-3 of the Hemlock. tt is anticipated that WMRU #1-1 will be perforated similarly in Benches 1-3. Logs will be submitted from the WMRU #t-1 when they become available. In addition to the formation evaluation logs, a cement bond log of the 5-1l2" completion liner will be submitted. 8) Casing Program Attached are the proposed casing and cementing programs for WMRU #I-1. After the packer and tubing have been run in the well, the casing x tubing annulus will be pressure tested to 0.25 psilTVD ft or approximately 2350 psi. Sufficient notice will be given the AOGCC so a witness may be present for this pressure test. Injection will not begin until the casing is pressure tested as described above. UVMRU #I-1 20" 79.6# @ 655' MD 13-3/8" 54.5# @ 2001' MD Cmted w/1710 sx Top of 7-5/8" liner @ 7283' MD Top of Sidetrack Window @ 7483' MD RCC~~~~r~ Cement Plug: 8600'-8900' 9-518" 40 & 43.5# @ 9083' MD Cmtd w/2130 sx HDC Ret @ 10,555' MD w/50 s; DST Perfs. 10,600-10,670' BP @ 11,200' MD w/50 sx DST Perfs. 11,340'-11,385' 7" @ 11948' M D 11019' TVD Proposed Sidetrack MAY ~ '= '~"~ ~~~ dt QAR ~i~if~,~ (.i{Ihd111*YIO~ anehc~rr~ 7-5/8" liner @ 11059` MD 9271' TVD Cmtd w/115 cuft cmt 5-1/2v liner @ 11972` MD 9830` TVD Cmtd w/125 cuft cmt West 14~IcArthur River Unit #I-1 Redrill Casing Specificati®ns ____ _ _ ___ _ ___ _~ u__`~_ _ ~_ ^_ __~__ ___ Jaint ' Strength _K fbs _ Body Strength _K Ibs _ ___ __Burst _psi _ Collapse psi __ _ _ ID___ ____ _ _ Drift ID __ _ __ M_in Tarq ft-Ibs (Jpt Torq ft-Ibs _ _ Max Torq _ft-Ibs Casinq in place __ ____ Intermediate~13_3/8" 54_5#, K-80, BT&C __ ~ 909 __ _ 853 ___ 2730 _ 1130 _ _ __ 12.615 12.459 Intermediate 9-5/8" 43.5#, L-$0 BT&C 1074 100_5 -- -- 63_30 ---- 3810 ___8.755 8.599 9-5/8" 40#, L-80, BT&C 979 916 5750 3090 8.835 $.679 Proposed Liners Liner 7-5/8" 29.04#, L-80 STL 444' 555 6890 4790 i 6.875 6.750 -- 4600 5300 6000 Liner ~ 5-1/2" 17#, L-80, FL4S 248 397 7740 6280 4.892 4.767 3000 3300 3600 • • CSGSPECLXLS • West McArthur River Unit #1-1 Redrilt Cementing Program 7-5/8" Drilling Liner 8-1/2" hole cLD 11,059' MD, top of liner at 7283' MD Cement volume for liner based on 1000' of fill-up above shoe: 1000' x 0.077 cuft/ft (8-1/2" x 7-518") x 1,50 excess = 115 cuff Cement = 15.8 ppg Class G 5-1/2" Dril4ing Liner 6-3/4" hole @ 11,972' MD, top of liner at 10,859' MD Cement volume for liner based on caliper hole volume plus 25°10, liner lap, and shoe joints. Estimated volume is: 913' (11,972' - 11,059') x 0.0835 cuft/ft (6-314" x 5-1/2") x 1.25 = 95 tuft 200' liner lap @ 0.0928 cuft/ft x 200' = 20 tuft 80' shoe jts x 0.1305 cuft/ft (5-1/2" liner capacity) = 10 cult 95 + 20 +10 = 125 cult Class G cement @ 15.8 ppg REC~IVE~ MAY ~? 6 1996 ptask~ Uil & Gas Cons. Com~+ssion p~orage • 9) Type of Fluid to be Injected Produced water from WMRU Weiis Nos, 1A, 2A and 3 will be injected into WMRU #t-1. Since this water's source is the same Hemlock formation as the injection destination, compatibility is not an issue. !t is unknown at this time what will be the maximum rate which can be injected daily into WMRU #!-1. !f there is considerable more injection capacity than there is produced water available, then water from Unocal's Trading Bay Facility may be piped down to WMRU to enhance the injection rate. Laboratory water analyses are attached for the produced water from WMRU #Z and #3 wells and the produced water at Unocal's Trading Bay Production Facility. There may be a compatibility problem with Unocal's water because of the higher sulfide and bicarbonate concentrations. These problems can be resolved with chemical treatment if it can be demonstrated that the injection capacity is significantly high to warrant adding Unocal's water to the injection program. 10) Injection Pressure The fracture gradient at WMRU is estimated to be 0.75 psi/ft based vn extrapolated data from the MR field. Therefore, the maximum allowable surface injection to avoid fracturing the Hemlock formation will be 3000 psi (0.75 x 9500' TVD - .433 psilft hydrostatic gradient x 9500' TVD}. Another variable which may enter into the above equation is tubing friction pressure losses. If the injection rate is high, then significant tubing pressure lasses will add to the aNowable surface injection pressure without exceeding the fracture pressure, Far example, the tubing friction pressure bss for injecting 5000 BWPD in Z-7/8" tubing is approximately 780 psi. The allowable surface injection pressure in this scenario would be 3780 psi. 11} Protection of Freshwater Strata The proposed casing and cementing plan for the WMRU #I-1 wit( ensure that no injection water will be able to migrate from 9500' TVD to fresh water strata near the surface. 12) Water Analysis A water analysis of the produced water from WMRU is attached. Also attached is the water analysis of the Unocal Trading Bay Production Facility produced water which may be utilized as supplemental injection water depending on the injection capacity of WMRU #1-1. • 13) Freshwater Exemption A freshwater exemption is not applicable because the Hemlock injection zone in question at 9500' TVD is not a freshwater interval. 14) Expected Incremental Increase in Ultimate Hydrocarbon Recovery Ultimate primary recovery estimates were calculated by Huddleston & Company, Inc. for the Stewart Petroleum leases with the three current producing wells and no additional drilling or enhanced recovery projects. This primary recovery estimate of 4.4 MMBO was classified as "Proved Developed Producing" by Huddleston. The ultimate incremental secondary recovery classified as "Proved Undevelopedn by Huddleston was estimated at 4.4 MMBO. This estimate was based on one injection well in a southern, peripheral location and corresponds to the 50% secondary recovery factor which will be achieved by the nearby McArthur River Field (MRF}. The correlation with the larger MRF secondary recovery fac#or is justified because the lack of a complete peripheral pattern with resulting poorer areal sweep efficiency at WMRF will be compensated by the more homogeneous reservoir at WMRF which will result in a better vertical conformance than at MRF. ~v~0 ~~~~ P~ ~ ~ ~o~g6 m~`on M S£a~s ~m A~aSKa~~1 ~G~~~hora9e T4d.~q `^~ I~n.dwGf i p^ Foci/. Unocal Wemco utlet, 4/1/9b, 10:30am MG/L MEO/L PPM MOLES/1000 GM CALCIUM 2658.40 132.65 2611.89 0.067 MAGNESIUM 178.00 14.64 174.89 0.007 IRON 0.50 0.02 0.49 0.000 SODIUM 6714.00 291.92 6596.53 0.294 CHLORIDE 14924.00 420.86 14662.88 0.424 SULFATE 552.00 11.49 542.34 0.006 BICARBONATE 532.30 8.72 522.99 0.009 STRONTIUM 64.00 1.46 62.88 0.001 TOTAL DIS. 25,623.20 25,174.88 SOLIDS SPECIFIC GRAVITY = 1.0178 PH = 7.1 IONIC STRENGTH = 0.5251 f. KCAL...=tVC =NC7~=G~5 POSITIVE VALUES INDICATE SCALING TENDENCIES TEMP CALCIUM CALCIUM BARIUM STRONTIUM RESISTIVIT (°F) CARBONATE SULFATE SULFATE SULFATE (OHM-METERS) 40 0.26 -17.44 0.00 0.00 0.413 60 0.40 -17.44 0.00 0.00 0.325 80 0.60 -17.44 0.00 0.00 0.249 100 0.85 -17.51 0.00 0.00 0.203 120 1.16 -17.80 0.00 0.00 0.168 140 1.51 -18.09 0.00 0..00 0.145 160 1.83 -18.37 0.00 0.00 0.126 180 2.26 -14.92 0.00 0.00 0.113 200 2.66 -13.89 0.00 0.00 0.101 220 3.07 -12.86 0.00 0.00 0.093 250 0.083 300 0.069 350 0.061 400 0 .055 W~1TE~~ ANAL..Y'~ 2 S M~~~f~,,~ ~'rve.. Stewart Petroleum, West °~5~~~, 4/1/96, Heater Treater No. 3, 1:OOpm CALCIUM MAGNESIUM IRON SODIUM CHLORIDE SULFATE BICARBONATE STRONTIUM TOTAL DIS. SOLIDS SPECIFIC GRAVITY = PH = IONIC STRENGTH = MG/L MEQ/L PPM MOLES/1000 GM 5337.60 266.35 5231.62 0.134 3 .40 0 .28 3 .33 O .000 1.40 0.05 1.37 4.000 5510.00 239.57 5400.59 0.242 17644.00 497.56 17293.66 0.502 340.00 7.08 333.25 0.004 238.30 3.91 233.57 0.004 74.00 1.69 72.53 0.001 29,148.70 28,569.92 1.0203 6.4 0.6518 r t ±" '-"~ RECF MAY 4 - ~ri~ Alaska Oil & Gaa r~,,,~,,; :~~:~~~~~ ~~~~ Anch~+~~;;~ POSITIVE VALUES INDICATE SCALING TENDE NCIES TEMP CALCIUM CALCIUM BARIUM STRONTIUM RESISTIVIT (°F) CARBONATE SULFATE SULFATE SULFATE (OHM-METERS) 40 -0.66 -11.29 0.00 0.00 0.365 60 -0.56 -11.29 0.00 0.00 0.287 80 -0.35 -11.29 0.00 0.00 0.222 100 -0.11 -11.30 0.00 0.00 0.179 120 0.23 -11.35 0.00 0.00 0.149 140 0.60 -11.40 0.00 0.00 0.129 160 0.93 -11.45 0.00 0.00 0.112 180 1.39 -9.61 0.00 0.00 0.100 200 1.78 -9.00 0.00 0.00 0.090 220 2.20 -8.39 0.00 0.00 0.083 250 0.074 300 0.062 350 0.054 400 0.049 • WA`I'"EFL ANAL.-`t'~- Y / ~G~l/'f'ljrr K~VC/' Stewart Petroleum, West 4/1/96, Heater Treater No. 2, 1:OOpm MG/L CALCIUM MAGNESIUM IRON SODIUM CHLORIDE SULFATE BICARBONATE STRONTIUM 5276 .80 56 .90 1.10 5351 .00 17432 .00 311 .00 293 .40 69 .00 TOTAL DIS. SOLIDS SPECIFIC GRAVITY = PH = IONIC STRENGTH = 28,791.20 PPM 5173.28 55.78 1 .08 5246.03 17090.03 304.90 287.64 67 .65 28,226.39 RECEIVED 1 .020o MAY Q ~ ~g96 7.3 0.6463 Alaska 0i1 ~ AnchorageComm+ssian SCAL Z N~ Z NC] X CE's MOLES/1000 GM 0.133 0 .002 0.000 0 .235 0.496 0.003 0.005 0 .001 POSITIVE VALUES INDICATE SCALING TENDENCIES TEMP CALCIUM CALCIUM BARIUM STRONTIUM RESISTIVIT (°F) CARBONATE SULFATE SULFATE SULFATE (OHM-METERS) 40 0.33 -11.94 0.00 0.00 0.370 60 0.44 -11.94 0.00 0.00 0.291 80 0.64 -11.94 0.00 0.00 0.225 100 0.89 -11.95 0.00 0.00 0.182 120 1,22 ~ -12.00 0.00 0.00 0.151 140 1.59 -12.06 0.00 0.00 0.130 160 1.92 -12.11 0.00 0.00 0.113 180 2.38 -10.25 0.00 0.00 0.102 200 2,77 -9.64 0.00 0.00 0.091 220 3.19 -9.02 0.00 0.00 0.084 250 0.075 300 0.063 350 0.055 400 0.050 MEO/L 263 .31 4 .68 0.04 232.66 491 .58 , 6 .48 4 .81 1 .57 4JfiiTE~~ ~N~L_Y~.=~ MG/~r~u. R/2/ Stewart Petroleum, West 4/1/96, Disposal Pump Discharge, 1:34pm MG/L MEQ/L PPM MOLES/1000 GM CALCIUM 5300.80 264.51 5197.48 0.133 MAGNESIUM 20.90 1.72 20.49 0.001 IRON 0.90 0.03 0.88 0.000 SODIUM 5303.00 230.57 5199.64 0.233 CHLORIDE 17304.00 487.97 16966.72 0.492 SULFATE 303.00 6.31 297.09 0.003 BICARBONATE 295.30 4.84 289.54 0.005 STRONTIUM 75.00 1.71 73.54 0.001 TOTAL DIS. 28,602.90 28,045.39. SOLIDS SPECIFIC GRAVITY = 1.0199 PH = 7.5 IONIC STRENGTH = 0.6416 SGAL..StVC :~NG"~=~E:~ POSITIVE VALUES INDICATE SCALING TENDENCIES TEMP CALCIUM CALCIUM BARIUM STRONTIUM RESISTIVIT (°F) CARBONATE SULFATE SULFATE SULFATE (OHM-METERS) 40 0.54 -11.92 0.00 0.00 0.373 60 0.65 -11.92 0.00 0.00 0.293 80 0.86 -11.92 .0.00 0.00 0.226 100 1.10 -11.94 0.00 0.00 0.1.83 120 1.43 -12.00 0.00 0.00 0.152 140 1.80 -12.05 0.00 0.00 0.131 160 2.13 -12.11 0.00 0.00 0.114 180 2.59 -10.25 0.00 0.00 0.102 200 2.98 -9.64 0.00 0.00 0.092 220 3.40 -9.02 0.00 0.00 0.085 250 0.075 300 0.063 350 0.055 400 0.050 ~5 1V~e~no~ar~~.un~. To: The Commission Thru: David Norton Fm: Jack Hartz Subj: West Mc.~rthur River Unit -- Inquiry from w`IO • ~~a~~ ~~ ~~iasi~a Oil and Ga::%~'on_ervauon _;.......~so Febr~zarv °, 1996 %i +(C~ /f~ The attached letter from Petroleum, Inc. requests information regarding rules, regulations and methods for instituting a waterflood in a pool where wells have different ownership shares. Also enclosed are correspondence between WIO's and Stewan Petroleum regarding plans being formulated for secondary recovery from the pool. There appears to be some confusion amongst WIO's in the W?~iRU about the status of unitization. I spoke with Mike Kotowski at DOG who stated the WMRU has a valid Unit Agreement, Operating Agreement and that a Panicipating Area has been approved for the productive area. Mr. Stewart has sold interests in each well in the form of working interest and overrides which may complicate administration of the Unit, however, the unit and operating agreements may have provisions for multi-variable ownership interests or provisions for resolving unit issues. Division of Oil and Gas will be soliciting new working interest owners to sign the Unit and Operating Agreements if thev have not already done so. V I have no recommendation regarding these questions and await your direction as to any funher attention to be directed to these issues. Perhaps the letter should be forwarded to Rob Mintz for his review and response. cc: Mike Kotowski, DNR -Division of Oil and Gas 01-26-,cg6 '_3:35 29:.820: F=~RCLE~M NC. P.02/10 EPIC CENT:R 901 NORTH MAIN, BUITE 1300 WICttITA, K.tN$A8 97202•e8t3 , 31e/291.8200 January 26, 1996 Jack Hartz Alaska 0i1 And Gas Conservwtiou Com.~issic;, Ya: Facsimile Re; West McArthur River Unit Dear Mr. Hartz: We are a working irnerest owner in the West McArthur River Unit in the Cook Inlet. There are two letters attached. Please note that they are being sent per request of Mr. Blair Wonzel and not at our own initiative. We have some questions regarding waterflooding in Alaska: I) Do the rules and regulations provide for unitization when there is .different ownership of the wells in, a pool? 2) What percentage of voluntary signup is required for "forced unitization"? 3) Before there can be injection in a pool with wells with different ownership doesn't there have to be unitization? ? `NiL br in c~rtac'Mt1~2 you this afternoon even t.~:ough I will be out or"the or~ce. YIy phone is 316-291=8284 and our fax is 316-291-8201. _ Thark3, 1 Craig S er Production Engineer Petroleum, Inc. ~~ ° ~~ JAN ~`' ~4`~ ~~~~n~~~icn ~tl & ~2s ions ~~srn ~E t,,..a '1S,f'tC~!`r' ~ 4 ~_--_~-~9~0 1~: 7 c9i8w71 FETP.CLEIiM INC. ~! ~ . ~• , ~• . Stewart Petroleum Company ~° Denali Towers North, Suite 1300. 2550 Denali Street, Anchorage, Alaska 99603 (90'7) 277-4004 • FAX (907) 274-0424 •. S~ 't.. t - ~.. '. ~'' ~'~` Eby r ~ e~,~ .' ~~ ~~ ~~ ~•~r - - l r^ ' .y.~1 ~~~ ' January 22, 1996. F.2o/10 .~~,~i~ G ~ ~~~ J Re: West McArthur River Field Cook Inlet Basin, Alaska ~!ir..~onn i{; varvey, President JKG i.A, Inc. . 30" 1alort` Main Street, Suite 1300 . Wichita, Kansas 67242 Mr. Robert C. Heaton, vice Pres... Petro(sum; Inc. ,. ~ ~ f - --~, 301 North Maln Street, Su(te 1300 ~`. ~~-~ ~= - ~"-' Wichita, Kansas 67202 v~fi1 2 ~ ~~o~ Mr. David L. Murfin, President ~ ~ ~. . Murfin inc. ~ ~ + ~ Cs1 ~ Cas C;;,~s. C~M;~+s~o~ . ~ ~:as~ca 250 North Water, Suite 300. Wichita, Kansas 8?202 Gentlemen: We.are in receipt of your joint letter~dated January 11, '1996 concerning our.pressure maintenance program in~ the West McArthur River Field. We do not have a "potential" need #or repressuring in this field. We have a very real need as do all Caok Inlet Basin Fiaids. Every successful field in the basin estai7iiQhed pressure maintenance early in field Ilfe (2-3 years). ~ Further, we have been' under ongoing pressure :from Alaska Oii and Gas Conservation Commission (AOGCC) for _ almost two years with respect to initiation of a pressure maintenance program. The State :requires prudent reservoir management and maximum recovery of reserves. Duplication of our enure file (n this matter fs not practical but the enciosed~tetter (Enclosure 1) from AOGCC dated 7/11/95 is typical. It Is .for that reason as well as genuine concern for.the reservoir that we propose to "move at such a fast pace". Our deliberations concerning pressure maintenance were ~nat undertaken tightly nor were they reached without good ~ professional advice. The ~ enclosed Pressure Maintenance and Enhanced Recovery Plan (Enclosure 21 was prepared and submitted to AOGCC on January Z, 1996. This plan was prepared by~ Mr. Art Saltmarsh; Certified Professional Geoiggist, wha was heavily involved in development of the waterflood program at the adJacent McArthur River Field. The plan has been extremely successful at that field and ultimate recoveries are new anticipated to~total in the order r.i~/_~ January Z2, '1998 ~ ~ ~l~tj L ~ j;a~ Raga .Z ~. ~ - flW~~{.3 cl ~ ~~ cons. c~:~~,,;~~iL:, ~.,~,L...7n~ of 5~i6 u~t3lP. iVir. Saltmarsh was assisted In preparation''of' our plan by Nir. Aaul White, Operations Manager for Stewart Petroleum Company, who has more than 30 years experience In both drilling and production, including waterftood operations,- and. Mr. Tim 9illingsiey, Petroleum i:ngirteer for Stewart Petroleum Company. Mr, 3iilingslay has almost 20 years of Petroleum Engineering experience .including wptsr#lood ~,aork ~t Prudhoe Say. ) think a reading of this plan will indicate to you that it has hoe.^, w®ll.thought out. ~~ . 'd'd.iti3 respect to your specific questions we respond as follows: (;) dour contention that our water injection plan will water out', first Weil Rio. ZA and then Wei11Vo. 7 A is correct over extended. time. Ali wells in the. basin. eventually ~r~at9r out. However; it is important to realize that the reason for the plan is to create a waterftood front that will push the oil toward the crest of the structure and toward the producing wails. Tha whole idea behind the waterflood design is to~ increase ultimate oil recovery from all three wells. Pressure Is declining at West McArthur River and :will need to be .maintained at approximately 3000 psi 'to provide optimum production and recavery, In the absence of such pressure maintenance, our primary recavery with be in the order of ZO-25 %. Waterftood can double our recovery from the field and from alt three wells: At the adjacent McArthur River Field (MRF) fully stabilized production rates were ' . reailzed.for a period of 8-9 years onca~ pressure° maintenanca~ became. effective, followed by average decline of about 12-~'14°!0. As the water injection rates were increased over time, there was a corresponding Increase in oii~production. MRF is now aimast 30 years old. The- waterftood process there has, In fact, resulted in approxlma#eiy double the oil recovery. Although smaller in 'size, ws should have . similar performance from our program. Our response time to injection should be relatively short end will be indicated by a ~flattening or Haar term reversal of decline. . if your argument concerns "early water breakthrough" as opposed to "watering out", experience at MRF shows that with proper injection Weil placement, as we neileve we have, breakthrough, will. not occur. In summary, a waterftood wfil~ increase ultimate recavery wail beyond the primary recovery possible from a solution gas drive reservoir . such as ours. Without pressure maintenance (In addition to major problems with - AOGCC} our~fleld will be fully depleted in 3-b years after recovering less than half of the potentially recov®rable~reserves. That alternative is~simply unacceptable. (Z) AA three wails will benefit by increased oil recoveries. See(1) above. Ali wells wilt eventually benefit from one injection well to the south, #ZA will benefit the mast at flrst, followed by #1A and finally #3 will experience favorable oil production response due to the one injection welt. The small number of producing wails In the field at this time does not justify drilling. more Infection welts sa that ail producers will benefit !n a similar time frame from the injection protect. With only 3 producing wells, It is not possible to drill and complete infection wails with a regular in-field pattern or in~ rt perigherat pattern around the outer edge of~the field. ~'_-c6-1998 13:38 2918c01 •, . • January 22, 1996 . Page 3 PETROLEUM INC. Y-='V. va. 'eyy'S ~ ~m JAN ~~ 1~9~ Y1P ii. +i G.'. j~ (3) Ail three wens will benefit by increased ail recoveries. See(1) above, {4} Ali three wells will benefit by increased oil r®coveries. See(1) above. F.08/_0 (5) Of ail the adjectives available to me, i would not select "non-commercial" in describing Welt #1A. It went on stream 12/31/96 and produces more than 2700 BOPD. It is the highest well an the structure at this point which is ro- an opti,;,um location fior an 1nJection wait. (S) With respect to "greater ultimate recavery of oit/gas", please see 1 nclosure 2 and the enclosed reserves report prepared by Huddleston & Co., Inc., Houston, Texas {Enclosure 3). As yvu can gee, Huddleston gives us minimal Prov®d Reserves until the pressure maintenance program Is accomplished and resu~tsse~n. Most of the reserves are presently in the "Probable" category p'®nding reclass(flcation to."Proved" following pressure maintenance. By the way (arid, before you ask) the liuddleston stutly was fully paid by Stewart Petroleum and is not reflected anywhere in your LOE. With respect to protection of correlative rights, the Area !Participating Area approved of#ective 10/1/94 by the Alaska Department of Natural Resources (DNR) was formed for that purpose. The Area I Participating Area covers ail of Section 10, T8N, R14W. Ali three producing wails are located within Section 10..A. copy of the.Appiicatlon and Approval of the Participating'Area i9 enclosed (Enclosure 4). Please Hots on page 3 under item V4. that DNR found the correlative rights of ail parties to be protected. Further, at item V5., DNR found that formation of the PA :equitably divides costs and produced hydrocarbons and secs forth a development plan which includes pressure maintenance activities. (7) Your interpretation of the "Field Production Facilities" provision {Paragraph IX) of the Participation Agreement is accurate. 1t was included In order to insure drderiy development of the field. Vita! facilities such as inj®ction wails must be accommodated and the provision, as drafted and signed, is equitable. With respect to participation in decisions, we weicarne input but :final decisions rest with tl7e oQerator in this instance. ~- (8) . We have received input from some but not all Non-Operators as to the pressure maintenance program. All input so fiat has been positive with the exception of yours: The prevailing fesiln~ from~Non-Operators is that the program wilt enhance production and should be undertaken, They are correct and the program will be undertaken. It is our pasition~ that the "Field Production Facil(ties" provision {Paragraph tX) of the Participation Agreement clearly .prevails over Article ~ VII D.3. of the Operating Agreement (and any other provision of the Operating Agreement) under the specific language of Paragraph Xi of the Participation Agreement. (9) We already have a unit under State of Ataeka Regulations, entitled "West McArthur River Unit", containing 6330 acres. We also have an approved "Area 1 . Participating Area° discussed under (6) above. The Ar®a ] Participating Area.contains fiQ~0 acres-and covers ail tfirea producing wells. We .have neither plans nor 01-26-1996 13:38 2918201 • .January 22, 1998 Page 4 PETROLEUM INC. ~ P. 09/10 ~:~~, ~ ; £. C;. E1i1:....,. c::1., government obligation to further pool, unitize, or segregate acreage at this time. In the event we establish commercial production of hydrocarbons in the future in a portion of the West McArthur River Unit not covered by the Area 1 Participating Area, we will Corm an "Area !) Participating Area"~ ender StatB of Alaska regulations and any additions! Participating Areas as may bs necessary. '~ (10) Your questions as to unitization are not applicable. See (8} and (9) above, (11) We ~ have .already complied with both AOGCC and DNR ret~uirements in all matters mentioned. (12) We can only take your word as to what "normally" occurs outside the State of Alaska.. Th.e applicable Participation Agreement, Operating Agreement, Unit Agreement. Partlcipating'Area >xpprovai, and State of Alaska statues and regulations do nqt ~ remotely : contemplate tormatiori of en "engineering ~ committee" or --an : . "operators committee" as suggested:. We have no plans, therefore, for formation of. any such committee of .committees. ~~ in summary, we plan ~to move ahead with our plane for. the badly needed pressure maintenance program. ~ In the likely event you fail to respond to the cash call antiClpated~for March, 1996, an operator's Iles will'be invoked under terms of the Operating Agreement. Your group Is undoubtedly used to operating and owning large interests in oil and. gas operations.. You are not .the operator in this instance and you collectively hold interests in the wells averaging less than 4°~6. Your participations to date have been on a turnkey basis. I am aware Petroleum, Inc. operates far more properties and is. a much larger company than~is Stewart Petroleum Company, However, l am also. aware that Petroleum inc. has yet to operate a well in Alaska... i seem to recoil. that .Mr. , Garvey participated In partnership with Beard Oil Company as aNon-Operator in a dry hole. offshare• Kalgin island. That,. 1 believe, is the total Alaska experience of your group, l would like to~point out that Stewart Petroleum Company and its prJncipaJs, orti the other hand. have operated 11 wells in AJask.a, 6 of which produced hydrocarbons. tn.cl.uding employees and consultants, .we have combined Alaska experience In excess of 2b0 man years and invaiving nearly 100 Alaska wails. Mr. darvey, it would have been much easier for us~both 1f you had simply lifted the telephone and called me with your questions and concerns rather than calling and inciting various non-operators, sending copies of your letter to others, and generally trying to be an operator In an area in' which you are not qualified to operate. 1 can only a9sume that you have a bad case of sour grapes for the 4allowing reasons: 1. You and Beard Oif Company held an option arrangement on the acreage which now comprises the West McArthur River Unlt (8330 acres) tram 1111/85 until 12/1/88. i ,know because t arranged it with the Fairbanks ownership group for you. During that three year option period .you were unable to raise money and cause~a well to be drilled on the prospect. 1 took assignment of the ~acreage~ in 1989 and have 01-26-1996 13:39 2918201 FE-FCLcUM ^vC. r.1~r7/1@ ~• r ` I caused ail activity since then to actually happen. 2. in March, 1993 when (against my batt8t judgement; ' a?'.c:°1Qd Petrolsc:*n, Inc. to participate in W®il No. 2, Stewart Petroleum granted.Petroieum inc, an option ,o participate retroactively In Well No. 1. Petroleum, inc. falled to participate and, according, was not entltted to participation in the redrlli project, Well No. 1A. Wall No. 1A, of course, fa an excellent well producing ~• 2700 BOPD and is the best producing well In Cook Inlettoday. I am at 'a loss with respect to disposition of Petrol®um,, lnc's letter dated August 3, 1995. ~ 1. vaguely retail going .~ovQr a letter with Mr ©arvey In my offices In ~ariy August just prior to leaving for a business trip, st which time 1 answered most of the questions posed. We now have the current copy provided. Rest assured we will answer the l®tter in writing. in the near future. i3asicatty, the fetter reflects an unfamiliarity with remote Alaska operations and the high coats involved..: While 1 don _t~..:_. ~ ..... remember why the 8/3/96 letter was not answered, ! do remember that we have managed to Increase pro.ductlvn from X3000 80PD to.y5.000 BOPD sines. date. of th.e ..., ..... left®r. Presumably,. that.wlp Justify our use of the intervening time. Investment to' date at Weat McArthur River Field totals ±;.52,000,000. Combined investment by JKG/Petroleum, Inc./Murfln is known to you. You were insulated from an extreme .cost overrun 'on Well No. 2 by turnkey. and your share of Permanent Production Faciiitles has been financed for you and charged monthly to I.OE. You have recovered about half. of your investment, excluding tax benefit and your future !oaks good. However, In the event you are unhappy not only with Stewart Petroleum Company and its operations, but also with flr~ancial results, we suggest that°you sell at this, point prior to our implementation of the pressure maintenance program this Spring. Stewart Petroleum Company, on behalf of itself and certain investors who will remain anonymous; hereby offers each of you a refund of your entire investment less revenues to date. This offer will remain open unfit the close. of business, Alaska time, on February 23; '!996. Closing would be 30 days from your acceptance of our.offer, {n the meantime we are proceeding with the pressure malntenanc~ program as scheduled. . . Sincerely, _ ._ - _ ~..., . ~ ~ ~ W. R. Stewart President ~.lWsi::~ C:I ~ Ct~ Cans. Gc;r^?s~i:n WRS:rs ,. ~.~~~~ . cc: AA partleipanta P.S. to Mr. Garvey: Please give by best to Messrs ,~Ulonrbacher and Platt, ex- participants who falled to stay with the program. to my ,next life i hope that t, too, can be a critic rather than a doer. ~ Critics have better hours. ~3 V~-G... ~.... _.. .~.~. vv G."..~JGU~ ~ .I R~Lt~..r~l"I llVl.... • January 1 i, 1995 RE: WEST MC.4~THU~R RI'J~R FOLD Cook Jn1,et Basin, Alaska i1~j. Bill S*w~vart Stewar Petrole~„m Company Denali Towers North, Suie 13vu 2550 Denali Street Anchorage, Alaska 99503 Dear IYir. Stewart P.03/10 Wa acknowledge receipt or' your undated letter setting` forth your recommendation ~to~ commence a pressure maintenance program in the West 1VIcArthur River Field, hook Inlet Basin. As you ~ow,,7KG L.A., Inc. (subsidiary of Feuoleum, Inc.), Petroleum; Inc., and Murfiu, Inc. own an interest in all three wells in this field. Whi?e we recognize the Fetential need for repressuring, we have a number of questions and concerns relative to the manner in which you propose to accomplish this. ~ We are aiso concerned as to.why you.propose to move at such a fast pace, Our questions and cnneerns. . are as follows: ~ ~ . (1) It appears that the wate~lood. program you propose will systematically water oat each well as the oii fronris shoved to. the Northeast. The program would cause well 2A, to water out first followed by lA. The n3 well would then be the only long lived producung well. Is this correct? . (2) If the ~3 well is the only producing well left, how does your proposed wate~flood program benefit all participants as you.indicated in your letter? (3) If the'2A Well waters ot%t first,~how does an owner with an interest in only this well beneft? .. (4} Why would t.+!e owner it the early watered out wells eve.*t~ consider year program ~iv'iJ1I:p tl't2.iI"rieli will Suvn wa%'.r C.ut i%vith tuZ Oil recovered essentially by the owners under the ~3 well? (5). It the lA well is deemed to~ be non-commercial after sidetracked, could this well be an injector point? (6) Have you conducted a study that indicates .your proposed program will (1) insure a . greater ultimate recovery of oiUgas; and (Z) protect the correlative nghts of all parties owning an interest in the various proration units? ~ ~ ~ . JAN ~ ~1~9>; ..- . FJasica Oll & Gas Cons. C :r~~iss:o;~ • Ancfictsns -'~- ~.C;L .iM iNC. P.04/10 • •~ .. lVlr. Bill st2wart January 11, 199b ~agp 't`wo (7) As set out in your letter, the "Field Production Facilities" provision of the Participation Agreements provides that tre casts for a water injection well or wells shall be allocated evenly to u~:e we.l(s) producin cr capable of preduc:ng and shall be borne by the participants in such well or wells on the basis of ownership therein. Said provision also provides that the ron-co::sent previsic ns (sabse a;:e^t wells) of the Operating Agreement are nat. applicable to water sjecWor. wells. Lo ycu believe uus pro yisicu ~/rV Vludes owners from participating In decisions relative ~o the what, when, whore and how c a pressure maintenance program? (8)- Do ycu plan to obtai.~i ",~:puf' er acceptance ~ om the Non-Qperators as to the progran yoli prop05e? ' ~Ve believe that t<'ie Nan-Operators have the right, per Article VII D.3. of the Operating • Agreement, to anticipate in deciding what type of pressure maintenance program is necessary, as we~ as when the pro~*am should be initiated. Said Article VII D.3. provides that the Operator shall not undertake any single project estimated to require an expenditure in . . excess of $50,000 without the c~r.,sgnt or- all n 'es. (9)' Do you plan to unitize the acreage currently set up ~ for the 3 wells aad • prepare a unitization agreement? (1Q) . If you do not unitize this acreage, how. do you plan to handle the following: (a) day -te-day operations of the injection program, ~ - (b) billing of costs incur, ed after the initial program costs, (c) allocation of revenue. - (I1) If you do not unitize, how do you plan to comply with the Alaska Oil ~ and Gas Conservation Commission's requirements for repressuring, unitization, allocation of un:.t ,production, etc.7 ' {12) Norma 'y, an. engiree^.r:; cernmittee (established from the worldng interest owners) determines the parameters of a waterflood protect taldrg into account the' c-srrent production, feet of pay, c~.:.*n~alative production, remailzing reserves, etc. Tract paricipation percentages . would be determined based on the coLective dersion of this committee. • As Operators Committee (also established from the working interest owners} would - prepare the applicable agreement, obtain acceptance of same by all owners and then submit same to the Commission for their approval. Do you plan to establish either an engineering committee or an operators. committee? ..: ~.~~ a {' J~AN~ 2 ~ 1~g6 . -.,, .... ~as~a Cii ~ Gas tans. Cu'~r~~issian ~ ' ~diataga - . wi-co-lBSo 13~ .c ~F:vc<J: FETr^cCLEii'I iNC. P.05/i0 • Mr. Bit Stewa., Ja.nuarv i i; 1996 Page ~ rsee As you caa see, we have a number of problems with your repressure recommendation. We need your response to :he ~~ove q~iestions and/ar concerns before we can respond to your . A.c c. ~~~e are aware u~t ycu haven't responded to Pe~oleum, Ire's letter dated August 3, 1995 ;~herzin u'~ey nad as.{ed for answers on many questions concerning operating costs and other ~operatlonai matters. Petroleum, inc. is mast interested in receiving your response. Your very early response to this Ie ~°r as well as Pe:roleum~, Inc.'s Iet~r of August 3, 1995 is requested. Please direct your reply, to. the attention of each of the owners who are co- authors to this letter, J"~G LA, INC. PETROLEUlY1, INC.. .MURF~TI', INC. ~ :, ~ ' John K Garvey ~ Robert C. Heaton ~ David L. Murfan President '. Vice President ~ President AlSska iii & G,s Cans. {;,:~~ ~ saran M~r.+~lii ~~~J rar ~ _ .- - "A% �wz • • Stewart Petroleum Company West McArthur River Unit Pressure Maintenance and Enhanced Recovery Plan Submitted January 2, 9996 Stewart Petroleum Company West McArthur River Unit Pressure Maintenance and Enhanced recovery Plan Submitted January 2, 1996 by ~~~SALTMARSH CONSULTING SERVICE 10007 Lee Street Eagle River, Alaska 99577 ~, S i!,1 .:,~P~E' ~~ A~qs ~1 • ' • ,~- 1 1 i h ' '~ ~ i *: 49~H ~ ~ 1 I .......................~ ~jj~' ~, ac. sa~~nn~sH :~~ i • .~ ~ •. No. 393 ~.•~~~i ~ ~O~ ' G~~ F ~•`•`•...••' Introduction The following Plan Of Development was prepared for the AOGCC as requested, for pressure maintenance and enhanced development of reserves at West McArthur River Field, Cook Inlet, Alaska, as per AAC 25.402 of the Alaska Administrative Code. The following will be discussed; - Location -Structure - Stratigraphy - Depositional Environment - Hemlock Lithofacies - Hemlock Reservoir Characterization - Reservoir Pressure - Material Balance - WMRU Development Plan -Appendices This is not an application for Enhanced Recovery Operations. When this Plan Of Development has been approved, the required permits will be submitted in accordance with the Alaska Administrative Code. LOCATION West McArthur River Field is located on the western side of the Upper Cook Inlet, adjacent to the McArthur River Field. It lies approximately 4000 ft. offshore. Due to the proximity and similarity to the McArthur River Field, all analogies in this report will be made to McArthur River Field (Enclosure #1). STRUC?'URE The structures on the west side of Cook Inlet were formed by tectonic events as a series of en-echelon structures related to the Bruin Bay and Castle Mountain-Lake Clark fa~.ilt systems. These faults are major strike-slip or wrench faults and have influenced the structural and stratigraphic development of the Cook inlet Basin. Wrench faults controlled sedimentation as early as Late Jurassic time. The greatest structural development was probably during Plio••Pleistocene time, although structures may have been present in Early Oligocene time, as indicated by possible thinning to the crest of several units within the West Foreland and Hemlock at MRF. Due to the limited well coverage at WMRF, it is unclear as to whether there was some structure pr~~sent prior to West Foreland and Hemlock deposition. The West McArthur River Field stE~ucture is a NW-SE trending anticline separated from the MRF's Northwest Feature by a major NW-SE trending fault (Dolly Varden fault). The fault displays approximately 100-150 ft. of down to the south throw and segregates the Northwest Feature (at MRF) from the WMRF structure. Due to the pressure differences across this fault, there is little doubt that it acts as a seal to the WMRF. There is a second NW-SE, down to the south trencing fault to the south of the WMRF which separates it from the West Forelands #1 gas discovery well. Again, this is a sealing fault based on pressure data, and test data from the West Forelands #1 well. The MRF and WMRF structures are believed to be Tertiary in age (probably post-Kenai Group), although there is evidence to suggest that the structures are re-activation of older structures, as mentioned earlier. (Enclosure #2 is across-sectional representation of WMRF) Both the MRF and the WMRF structures are slightly asymmetrical, with the western limbs dipping at approximately 30-40 degrees, and the eastern limbs dipping at approximately 20-30 degrees. The structural axes of both fields trends approximately NE. Faulting at MRF and WMRF generally displays two types of throw, that greater than 100 ft., and throw less than 100 ft. The faults with greater than 100 ft. throw are considered to be :pealing faults, while those with throw less than 100 ft are not sealing. The larger faults are readily visable and documented by seismic and can be seen on logs when correlated between wells. The faults with less than 100 ft. of throw can not be seen on seismic and are difficult to see even when they cut a well path. Pressure ~ i data and production /injection data from wells at MRF support these assumptions as to whether the faults seal or not. STRATIGRAPFIY Tertiary rocks of the Cook Inlet were originally referred to as the "Kenai Group". Eventually the usage of the name Kenai pertained only to coal-bearing beds, and such rocks were referred to as the "Kenai Formation". In 1962, Parkinson divided 'the Kenai Formation into three major lithologic units, the Lower, the Middle and the Upper Kenai. Despite the fact that later drilling revealed five lithologic units rather than three, Parkinson's nomenclature can still be found in literature, particularly in articles concerning the Swanson River ail field (Feckler and Calderwood , 1972). Feckler and Calderwood (1972) F~roposed that the five rocks units. be recognized as formations and that the name "Kenai" be elevated to group status as originally used. These proposals are generally accepted and the name "Lower Kenai" has been replaced by the two units, West Foreland Formation and Hemlock Conglomerate; the "Middle Kenai", actually comprised of two units, is now called the Tyonek Formation and Beluga Formations, and the "Upper Kenai", referred to as the Sterling Formation. The primary reservoir rocks at the MRF are the Kenai Group, including the West Foreland, Hemlock, and Tyonek (Grayling Gas Sands). • The reservoir of primary interest at WMRF is the Hemlock Formation, although there may be some potential in the West Foreland (from log analysis of the WMRF #1A). The Hemlock Formation unconformably overlies the West Foreland, and consists of a thick sequence of interbedded conglomerates, and sandstones, separated by thin interbed ~ of impermeable claystones and siltstones. Occasionally, thin coal beds are found between the "benches" of the Hemlock, although no coal interbeds have been seen in benches 1-3 at WMRF. The Hemlock Formation is very uniform in thickness, although there is considerable variation between the individual benches. As an example, benches 2 and 3 usually show the biggest variation in thickness (in WMRU #1A, bench 3 appears thicker than in WMRU #3). This stratigraphic variation is typical of a braided stream depositional environment. DEPOSITIONAL E~iVIRONMENT Extensive core analysis from cora~s taken at the MRF, indicates that the Hemlock was deposited in a fluvial ~:nvironment, dominated by a large braided stream complex. An excellent analogy of the depositional environment of the Hemlock Fm. is the present day Matanuska River, and its braided stream complex. The Matanuska River displays Bars and islands composed of conglomerates, while the channels between these "islands" are composed of fine to coarse grained sandstones. There is a high degree of variability both laterally and vertically in a system of this nature, and this is seen clearly in well lag correlations at MRF and WMRF. Distribution of lithofacies is irregular within the benches. Based on log correlations at MRF and WMRF, horizontal and vertical continuity of individual lithofacies is generally difficult to determine, but in this type of system, porous rocks are in contact with porous rocks, both vertically and horizontally. Studies done by Schlumberger, Marathon and Unocal, using all available FMS and Dipmeter data from the west side of Cook Inlet have shown that the depositional trend of thE~ braided stream complex was generally NW-SE. The source for the sediments of the Hemlock Fm. is also from the NW. HEMLOCK LITHOFACIES There are approximately six (6) lithofacies present in the Hemlock at WMRF. This is very consistent with the Facies found at MRF. Porosity within the Hemlock is intergranutar, anc~ the rocks are well cemented end competent. The lithofacies, from coarsNSt to finest are as follows; RESERVOIR FACIES Pebble/cobble conglomerate -These conglomerates range from clast-supported to very sandy and matrix-supported. Cobbles and pebbles in the conglomerates are well rounded, and moderately sorted, indicating considerable transport distance from tt'-e source. Porosities are realitively uniform, ranging from 7-11 %. (Cores frr,~m MRF show a degree of very fine material in the matrix, mixed with the sand. This has a tendency to reduce the porosity and permeability at the MRF. There does not appear to be the.. same amount of fines in the WMRF, as the porosity range is higher for the conglomerates than at MRF. The lack of fine grained material should not affect the fluid flow within the Hemlock). Pebble/gravel sandstone -This lithofacies is more uniform in grain size, and is entirely matrix supported. Porosities range from 10-16 %. Medium to coarse grained sandstone -Facies is moderately well sorted, and matrix supported. Porosities range from 12-18 %. Fine grained sandstone -Facies is well sorted. Porosities range from 12-14 %. (note: When the facies grains are well sorted, the porosities and permeabilities are higher). NON-RESERVOIR FACIES Vern fine grained siltstones -Fades rocks are dense and generally non-permeable. Porosities are very low ranging from 1-4 %. Highly carbonaceous claystones -Facies is non-permeable and rocks generally have no porosity. Cuttir•igs and log response in these zones resemble coals. Along with the siltstone facies, these facies generally act as seals for the overlying and underlying reservoir rocks. (Enclosures 4, 5, and 6 are FMS lithologic representations of WMRU #'s 1, 2A and 3.) HEMLOCK RESERVOIR CHARACTERIZATION The Hemlock reservoir at MRF and WMRF are hetergeneous reservoirs, based primarily on the analysis of cores, wireline logs, FMS, and determination of depositional environments. Reservoir heterogeneity is among the major reasons why enhan~;ed oil recovery is so difficult to • • determine (in the case of WMRF, there is no core to help in this analysis). The presence and likely distribution of several heterogeneity types is predictable on the basis of their close relationship with depositional environments, diagenetic patterns, and tectonic style. The Hemlock is variable both horizontally and vertically. Any boundaries of permeable bodies within an unfaulted reservoir usually coincide with changes in reservoir facies, i.e., with boundaries of genetic units. The source of sediments for Hemlock deposition was from the NW, and the general trend of the facies is NVV-SE. This pattern creates a preferential flow from SE-NW within the reservoir. This same pattern. was found at the MRF but had little to no effect on production or injection performance over the field as a whole. Porosities in the sandstone facies of the Hemlock are between 12- 18%, with some small sands displaying higher averages. This includes the fine sandstone, medium to coarse sandstone, pebble/coarse sandstone facies. Permeabilities in these same facies range from 100-300 md. The conglomerate facies are slightly less pcarous, with porosities ranging from 7-11 % and permeabilities ranging from 10-50 md. This contrast in porosities and permeabilities between the reservoir facies can affect fluid flow between the facies. An important distinction to make is that there are no non-permeable zones, that would create baffles to fluid flow, between these genetic units. Although fluid flow will be affected by this contrast, there will be no restriction to flow. At MRF, the porosity and permea4~ility contrasts were a little higher. It was found that during enhanced reco~iery operations, i.e., waterflood, that the best reservoir facies (sandstone and pebble-sandstone facies) • actually flushed quicker than the congl~,merate facies, although the conglomerate units still contributed oil. Berruin, et al (Berruin and Morse, 1979) have analyzed layered heterogeneous systems and concluded that the waterflood pertormance of a randomly stratified system (MRF and ?NMRF) can be represented by the pertormance of a uniform system having an absolute permeability equal to the geometric mean of the individual permeabilities of the heterogeneous system. The total oil in place at MRF was volumetrically calculated at over 1.1 billion bbls in place. Initial recovery efficiency was expected to be approximately 20 %. Recovery to date is in excess of 500 mmbbls. This equates to a recovery efficiency of approximately 42 % of oil in place with enhanced recovery waterflood. At present, the recovery efficiencies at WMRU can be expected to be the same as those efficiencies at MRF. RESERVOIR PRESSURE Reservoir pressure has declined since the initial production of oil at WMRF .The presure decline has flattened out as can be seen from the graph (Figure # 1 ). The latest pressure was obtained from the WMRF #1A on December 30, 1995. This pressure w:~s taken over the perfed interval in Benches 1, 2, and 3, and is a co-mingled pressure. The pressure was considerable higher than the pressure taken before the abandonment of the WMRF #1 well bore. A probable exp'anation for this is that during early December, the disposal well was shut i~ ~ for remediation work, and production in the WMRF was also shut gown. This shut down gave the reservoir a chance to recover, and reac~~ a uniform pressure. At present, .--, WMRU Reservoir Pressure vs Cumulative Field Production, Res. BBLs 4400 4300 4200 4100 4000 3900 3800 .~ a a 3700 m .3600 3500 3400 3300 3200 3100 3000 - Orig. BHP #1, 11/91 Orig BHP #2A 9/93 . , Orig. #1 A, 1/96 Ori #3 BHP 7/95 • #1 BHP 3/9 g. , , 4 • #2A BHP, 3/94 • #1 BHP, 10/95 0 500000 1000000 1500000 2000000 2500000 3000000 3500000 Cum Res. BBLs Produced, #1, #2A and #3 the pressure obtained from the WMRU #~1A well will be considered as a static reservoir pressure. MATERIAL BALANCE Material balance is based on the premise that reservoir space voided by production is immediately filled by the expansion of remaining fluids and rock. In general, material balance includes balancing either masses or volumes of fluids at different condition:.. Material balance calculations are generally based on observed production data, measured reservoir pressure, and the PVT properties of reservoir fluids. Except in a few special cases, there is no need for volumetric information concerning the reservoir, such as thickness, porosity, saturation, etc. Applying material balance to reservoirs that have a produ~:tion history leads to an estimate of original oil or gas in place entirely indeF~endent of volumetric calculations. Material balance calculations serve as a check on the volumetric methods. Several conditions or assumptions must be met in order to have valid and reliable material balance calculations; 1 -Reservoir hydrocarbon fluids are in phase equilibrium at all times, and equilibrium is achieved instantanec:~usly after any pressure change. 2 -The reservoir can be represented by a single average pressure at any time (Pressure gradients in the reservoir cannot be handled). 3 -Fluid saturations are uniform throughout the reservoir at any time (Saturation gradients cannot be handled). 4 - Coventional PVT relationships for black-oil and normal gas are applicable and are sufficient to describe; fluid phase behavior in • compositional reservoirs. Volatile-oil and retrograde gas condensate calculations are very complex and require more sophiticated data and computers. Most material balance calculations require only three types of data for completeness: 1-cumulative fluid production at several times (cumulative oil, gas and water); 2- average reservoir pressures at the same times, averaged accurately over the entire reservoir; 3- Fluid PVT data at each reservoir pressure as well as formation compressibility. In the case of WMRF, there is no data available on the rock compressibility for the Hemlock reservoirs. There is data available on rock compressibilities from cores at MRF. An attempt will be made to obtain this data .from Unocal and material balance calculations can be completed at a later date. Additionally, pressures have been obtained as co-mingled pressures across all three producing benches at V`JMRF. Individual bench pressures have not been taken. Using an "averaged" reservoir pressure will lend a certain amount of error to the material kralance calculations. WMRU DEVELOPMEfVT PLAN Although pressure decline of the Hemlock reservoir has started to flatten out (Figure # 1), there is no pressure data available from the water leg of the Hemlock to suggest that the WMRF has an active water drive in place. It is safer to suggest that the reservoir is driven by solution gas drive only. Based on reservoir perFonnance at MRF, a combination pressure maintenance -enhanced reco~-ery waterflood should be initiated at WMRF in order to recover the maximum amount of oil as is possible. • The optimum well placement for K~ waterFlood program would be a peripheral pattern of injection wells to create a sweep front toward the producing wells. This method was utilized at MRF, and has resulted in approximately 42 % recovery efficiency of OIP. Due to the size of the WMRU and the economics of drilling, a one well injection plan, with the well placed at the SE corner of the WMRF will be utilized. Injection of water into the producing interval will result in a pressure enhancement and create a sweep of water and oil toward the crest of the structure and the producing wells. The current plan is to utilize an existing abandoned well bore for water injection. The PanAm WFU-2 has been studied and it is feasible to re- enterthis well bore with minimum difficulty. The surface location of the WFU-2 is just south of the WMRF wells :surface location. (An AFE for this operation is included in the Appendix). 'The WFU-2 well was drilled to a down dip location just below the oil/wader contact at WMRF (-9600), at the southern end of the WMRF structure (Ec~closure #1). Cement plugs placed in the abandoned wellbore will be drille~~ out, and a window will be cut in the existing casing. A new well bore will drilled to the north, to a location on the southeastern nose of the WMRF structure, and approximately 50- 100 ft. updip from the current bottom hole location and above the established O/V11 contact (-9600 ft.) of the WMRF. New casing will be run and cemented, and perfs will be shot in Hemlock benches 1, 2, and 3. Produced water from the existing WMRF wells will be re-injected into the Hemlock to facilitate pressure maintenance and enhanced recovery. Reservoir pressure in the Hemlock should be maintained at approximately 3000-3500 psi. To achieve this pressure, the following formula (generally accepted in the industry and at the MRF) as: BOPD (produced) X FVF (FVF has been calculated at 1.102, Appendix) As an example, if there are 5000 bbls. /day total fluid produced from the reservoir (total fluid =oil + water), then the amount of water that needs to be injected into the producing intervals is: 5000 X 1.102 = 5,510 bwpd ^~ ~ °~ ~, wG~.- . z ~- This assumes that water injection will begin before the reservoir reaches the bubble point pressure, - 931 psi. This volume of injection would maintain pressure in the reservoir at the approximate reservoir pressure at tl~e start of injection, based on 5000 bbls of total fluid production from the r~:servoir. Injection pressures should be maintained at approximately 3000-3x00 psi at the well head. Rock strength data from MRF (by Marathon and Unocal) indicates that there is a fracture gradient in the H~:mlock of approximately .75 or about 7000-7200 psi. in the Hemlock Frri., and these injection pressures are below any possible fracture threshhold for the Hemlock reservoir. These calculations are approximr:~tions only. As the WMRF # 1a is completed and brought on production, 'the actual produced fluids figures will change. Also, after completion of tree injection well, an additional six months or more of production will have occurred, resulting in lower reservoir pressures. The ideal reservoir pressure to maintain at the WMRF is between 3-3500 psi, based on the exlaerience at MRF. At present, produced water from yVMRF is approximately 2000 bwpd. This water is being disposed of in a disposal well located at the onshore drill site. The volume of water that will be required for injection will be considerably higher than 2000 bbls to maintain the desired reservoir pressure. Additional water will be needed to make up the difference between current amount of produced water and the amount needed for pressure maintenance. Several possibilities are currently under consideration for a useable water source. By re-injecting produced water, a minimum amount of treatment will be required before injection. • • APPENDIX l LABORATORY PROCEDURES Stewart Petroleum Company Compositional Analysis Study No. 1 Well West McArthur River Field Cook Inlet, Alaska RFL 930234 Duplicate samples of separator gas and separator liquid were received is our laboratory on Deaernber 27, 1993. The ambient tempeiadrre bubblepoiraa of the separator liquid samples aad the opening pressures of the separator gas cylinders were measured as quality checks. An additional pair ~ separator gas samples were received on January 26, 1994. A listing a~f samples received in the laboratory is summarized on page three. The compositions of the separator gas samples were determined using u Programmed extended gas chromatography. The compositions, together with the calculated properties of the separator gas, are presented on pages four and eight. The oamposition of the separator liquid was. measured to a triacontanes plus fraction using the low temperature distillation/chromatographic technique. This r+esnlted in the composition listed on Page five. Using the reported gastiquid ratio (page six) in ooryunction with the compositions of the separator products, the wellstream composition was calculated. This composition is presented on page xven. The pnoeding data was forwarded to a representative of Fairweather E 8t P Services, Inc. Due to the non- equihbrium nature a~ the separator products and the uncertainty of the recombination rates, it was decided to ~ ~ TABLE OF CONTENTS Laboratory Procedures Pg .................... i General Welllnjormation .................... !,2 Preliminary Quality Checks .................... 3 Separator Gas Composition .................... 4 Separator Liquid Composition .................... S Recombination L)ata .................... Reser--oir Fluid Composition (Calculated) .................... Separator Gas Composition .................... 6 7 8 Stewart Petroleum Company West McArthur River #1 RFL 930234 General Well Information Company ......................................................... Well Name ....................................................... API Well Number .............................................. File Number ..................................................... Date Sample Collected ..................................... Sample Type .................................................... Geographical Location ...................................... Field ................................................................. Stewart Petroleum Company West McArthur River #1 so-133-2oa19 RFL 930234 15-Dec 83 Separator Cook inlet, Alaska West McArthur River Well Description Formation ......................................................... Hemlock Pool (or Zone) .................................................. Bench 2 Date Completed ............................................... 20-0ec-91 Elevation .......................................................... 163 RKB ri Producing Interval ............................................ 13254-13360 n Total Depth ...................................................... 13742 tt Tubing Size ...................................................... 3.5 in Tubing Depth .................................................... ' n Casing Size ...................................................... 75/8 liner in Casing Depth ................................................... 13742 ft Pressure Survey Data Data from Original Discovery Well Date ................................................................ 20-Dec-81 Reservoir Pressure .......................................... 4290 psig Data at Sample Collection Date ................................................................. 15-Dec-93 Reservoir Pressure ........................................... 4217 psig Reservoir Temperature ..................................... 175 'F Pressure Tool ................................................... Amerada Gauge Flowing Bottom-Hole Pressure ......................... 3000 psig Flowing Tubing Pressure .................................. 50 (annulus) psig • Qata not ronvarded to Core Laboratories. ~t CORE LABORATORIES ~ ~ Stewart Petroleum Company West McArthur River aft RFL 830234 Production Data Data from Original discovery Weil Location ........................................................... pr. r a. a.ow«r.+in Date ................................................................. (wls r ew e.eovwy ww~ Oil Gravity ~ STP ............................................ pw r u~. e.oo~-.er.wN1 'API Separator Pressure ........................................... ~uwrn»a.mov«r..q psig Separator Temperature ..................................... cws r gyn. Aroorwyw.q °F Production Rates Gas ......................................................... prs r m. wa1 Msct/D Liquid ...................................................... pN. ra. -~1 STbbUD Gas/Liquid Ratio ...................................... fuw.rena.eovywwl scf/bbl Separator Conditions Primary Separator Pressure ............................. 50 psig Primary Separator Temperature ....................... 105 'F Secondary Separator Pressure ......................... 24 psig Secondary Separator Temperature ................... 150 'F Primary Separator Gas Production Rate........... 180 Mscf/D Gas Factors - Field Values: Pressure Base ..................................... 14.65 psis Temperature Base ............................... 60 °F Compressibility Factor (Fpv) ................ 1.007 Gas Gravity Factor (Fg) ....................... 1.051 Laboratory Values: .. Pressure Base ......................................... 14.65 psia Temperature Base ................................... 60 'F Compressibility Factor (Fpv) .................... 1.007 Gas Gravity Factor (Fg) ........................... 0.9995 Primary Separator Liquid Rate .......................... bbUD at 'F Stock Tank Liquid Rate ..................................... 500"' bbUD at 60 °F Separator Gas /Separator Liquid Ratio............ ' scf/bbl Separator Gas /Stock Tank Liquid Ratio.......... 360 scf/bbl Stock Tank Liquid /Separator Gas Ratio.......... 2.78 bbUMscf Separator Liquid /Stock Tank Liquid Ratio....... bbUbbl at 'F "Does not include 1500 bbUD of "power oil' • D~a nct forv-rarded to Core laboratories. p~ y CORE iABORATORIES • • Stewart Petroleum Company West McArthur River #1 RFl 930234 SUMMARY OF SAMPLES RECEIVED • and Preliminary Checks of Sample Quality Separator Oas Sam es CyCnder Numtxr K18264' K29728 CU19' CLM317 CyYnder Size, Nters 37.85 37.85 0.30 0.30 Pressuna, psip 24 24 22 22 Tertiperature,'F 150 150 120 120 Opsninp Cond~ions Pressure, psip 24 23 na ~ Temperature, •F 70 70 rra na Uquid Content, x 0 0 ra ns Air Content, mo196 0.223 0.319 5.04 14.56 .~ ~_.,. Sirrlpfulp Date 1 ~DeC•9© 7 ~uec-xs ~ r.+arrxr. ~ ~„m.-a, Se rotor U uld Sam lee Cyflnder Number 2132' 612 Cylinder Stze, x 500 500 Press~ue, pei0 50 50 Tsrnperature, 'F bbl i t Ch c B 105 105 e k u epo n Pressure. pep 58 68 Temperahue, •F 63 63 Water Content, ce 0 0 Sample Vohune, x 460 ~ 487 Sarnplinp Date 15-Deo-93 15-Dea93 • These samples selected for further analysis. 1000 100 ,f Y s ~ to 3 W 1 Q.1 .350 -300 -250 -200 -150 -100 410 0 50 100 1.50 400 ~r~ ~ $O IMC~: ~.lA Ef1pMINIMI0 aM a00~L S°I:: •:: L. s.::«:. ..:.. «.j..~«j..j. ..~.T..:..:.. «H•?..i..f. ..«.«. .« • ~• t ..... .. .. . ..«.«._...«. »i::a~"..i:a.. «i••1'WT• .-f..{..j«(.. ..1-•r••I..M .. 3.. ' i i j~ • . ~. « •. .. »i::~:a»i:: ..:..s.-}..;.. «j..T«l..T.. ..t.y..}..j.. ..M.Y•l..f•• ..{.. ~«3« i_3 I ~ i i , ..t..T.. .« «.«..i : :•:::i...a'~"«::. «j...j...}..' «f«T.1.. « ..i..:« ...r.q..t.. : C. ~:Z=1:: .:i..J..a..~.. 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' flt:~ e y~... .• •• i i ..... .. .,..rw ~ -,F'« .:w~ ..,.. r. ..r.r..,.. y_ w: -r ":i-'v-•i. w• ° w ::rr:i : : .:r»r +- :.r:-r'te'':'-rr-•• :~::'r-:»i:: ..~r::~.:y ~ ::r-i-w« . . r .r .. ..«.~«:..1. ..S.i...f« ..M....«f.. .:..S.i..:.. ..1..1.1..1.. f j j N M ..i..i•.i--:.. .~.w. j ~ 1..1«1..1. ~r H«W{•r .y..f..1..1.. r . :.~i.. 1..1- ~ ..1«>«S.i.. .~.-irM-~.. .. . .. . •- « «f.1..S-•1« ..S--r..,.N.. ..M.r.y..N- ..j.-F--S.. . rW..... .. « - . . .r..t..q.. _.. . «:..r..». .q ,I,~Y,~YM ~' SNW~ = ~wS ~\~w p ~'~ ~ MIA 130'f i»i...:«s,.. j - i-•w•i..i.. .w--i--a..i.. . .:.-i--i.y.. .. i--i«i-..i.. . tAMIhW IMN) j ; € E i i E i E i i j E [ i F p~ 3 CORE LABORATORIES • Stewart Petroleum Company West McArthur River lift RFL 930434 COMPOSITION OF SEPARATOR GAS (by Programmed-Terr~peratura, CspisrY Chranstography) Component Md 96 Phut Products (G Liquid Densky M1M Hydrogen Sulfide 0.00 Carbon Dio~dde 0.03 0.8172 44.010 Nitrogen 16.09 0.8086 28.013 Methane 53.88 0.2997 16.043 Ethane 7.29 1.939 0.3558 30.070 Propane 9.88 2653 0.5065 44.097 iso-Butans 249 0.810 0.5623 58.123 n-Butane 4.13 1.296 0.5834 58.123 iso•Pentane 1.35 0.491 0.6241 72.150 n•Pentane 1.38 0.497 0.6305 72150 Hexanes 1.26 0.486 0.6850 84.0 Heptanes 1.43 0.598- 0.7220 96.0 Octanes 0.66 0298 0.7450 107 Nonanes 0.25 0.125 0.7640 121 Decanes 0.08 0.043 0.7780 134 Totals 100.00 9236 Properties of Plus Fractions ~~ Component Md 96 Density API MW ~ Heptanes plus 242 0.7356 60.7 1026 ~ Note: Component properties assigned from ~terature. ° ref: Gaa Producers b Suppliers Asaocfetifon (GPSA) Erpineering Data Book Page 4 SAMPLING CONDITIONS 24 psig 150 °F Gss CyYndsrs K18264 Average Sample Properties CrNical Pressure, pe9a ................................ 614.2 Critical Terrrperat<ue, °R ............................. 434.4 Average Molectdar Weigh .......................... 28.99 Cakxihted Gas Gravity (air =1.000) ......... 1.001 at 14.61; psis and 60 °F Value, Btu/sd dry gas• Gross ....................................................... 1436 CORE LABORATORIES ~. Stewart Petroleum Company West McArthur River f1<1 RFL 830234 COMPOSITION OF SEPARATOR LIQUID (by Law Temperature ~P~Y CBraPhY) Component I Mol % I Wt % I Y I hAVlf Hydrogen Su18de o.00 0.0o SAMPLING CONDITIONS Carbon Diaidde 0.00 0.00 Nitrogen 0.00 0.00 50 psig IlAetharrc 0.85 0.06 0.29®7 16.043 105 •F Ethane 0.62 0.08 0.3558 30.070 Propane 231 0.44 0.5065 44.097 iso-Butane 1.06 0.27 0.5623 58.123 Liquid CyMnders n-Butane 2.50 0.63 0.5834 58.123 2132 iso-Perdane 1.72 0.53 0.6241 72150 n-Pentane 2.57 0.80 0.6305 72150 Hexanes 8.45 233 0.6850 84.0 Average Sample Properties Heptanes 8.58 272 0.7220 86.0 Octanes 10.22 4.71 0.7450 107 Average Mobcular Weight .......................... 232.35 Nonanes 8.42 3.34 0.7640 121 Cala~ated Y ~ 0 prig and 60'F ....... 0.8900 Octanes 5.58 3.21 0.7780 134 v /~ ~7 S e~`L Undecanes 4.35 275 0.7890 147 . Dodecanes 3.82 2~ 0.8000 181 Tridecanes 4.02 3.03 0.8! 10 175 Tetradearws 3.46 283 0.8220 190 Per~decanes 3.27 2.90 0.8320 206 Hemdecanes 261 249 .0.8390 222 Heptadecanes 245 250 0.8470 237 Properties of Plus Fradbns Ocladecanes 2.55 275 0.8520 251 Nonadecarrss 211 239 0.8570 263 ~~ ~ Eicoeanes 1.89 224 0.8620 275 Phrs Fncdiort Mol% Wt96 DensRy API f1AW Heneicaearws 1.66 2.07 0.8870 291 Docosarres 1.57 2.06 0.8720 305 Tricosanes 1.42 1.94 0.8770 318 Hepfanss phis 81.92 94.88 0.9121 23.5 2~ Tetracosanss 1.32 1:88 0.8810 331 Undecanes phis 53.14 80.90 0.8469 17.8 354 Pentacosarws 1.29 1.92 0.8850 345 Perrtadecarws plus 37.49 69.64 0.9745 13.6 432 Hexacosanes 1.15 1.78 0.8890 359 Eicosanes phrs 24.50 56.61 1.0102 8.4 ~ 537 Heptacosanes 1.02 1.64 0.8930 374 Pentacosanes phis 18.85 46.42 1.0468 3.5 648 Octacosanes 1.00 1.B7 0.8960 388 Triscontarres phis 11.23 37.75 1.090;3 -1.8 781 Nonacosanes 0.96 1.66 0.8990 402 Triacar~nes phis 11.23 37.75 1.0903 781 Totals I 100.00 ( 100.00 p~ 5 CORE LABORATORIES ~ ~ Stewart Petroleum Company West McArthur River #1 RFL 930234 WELLSTREAM RECOMBINATION CALCULATION (based «~ Bea producBon data) Conditions for Recombination Calculations Prinwy Stage at 50 psip and 105'F Secondary Stage at 24 psi0 and 150'F Stock Tank at 0 psip and 60'F Gas Gravity (air=1.000) ..................................».......... Gss Gravity Factor, FD .......................................»...... Gas Deviation Factor, Z .............................................. Super CampressibUity Fedor, Fpv .............................. Pressure Base, psia .................................................. 0.906 Prinwy Stabs Gss Fk+~r Rage, MecUD ...........».......... 180.00 1.0610 Stodt Tank Liqua Fkrrv Rah, bbUD ........................... 500.0 Flea Gas / OY Ratio, sct/STbbF .................................. 3®0.00 0.986 1.0070 14.65 ReeomWnatlon Ratss and Ratios - Gas GravRy (air=1.000) ...............»............................. 1.001 Gas GravUy Fedor, Fp ............................................... 0.9®95 Gas DwiaBon Fedor, Z ...........................»............... 0.986 SupercanpressibWty Factor, Fpv ............................... 1.0070 Presaure Base, psia .................................................. 14.85 Ligtdd Volume Fsdor, S'bbi/STbbl ~ 60 •F .............. 1.0227 Bitumen, Sediment b Water (BSbW) Fedor ............. 1.000 Primary Stage Gas Fkwv Rah, Mscf/D ....................... 171.18 Primary Stake Liquid FkNV Rats, trbtN ....................... 511.33 Prirrtsry Stage Gas / OY Ratio, scUS'bbl .................... 334.78 Sbdt Tank Lkµid Fkrrv Rate, tab W ......................»... 500.0 Corroded Gas /Oil Ratio. scUSTbbI .......................... 342.37 WeiYstrsam RecomWrrstlon RsLto aro[/mol 0.66783 • Flom: Sfand'wp. M.B.. Yolunwfrie and Pfaw ttatiavior of Oil Fiaa Firdrocarbon Systems', SPE (Dapas),1877, stir EdMion, Appsndbc p. " Oats not suppRsd b Caro Laboratories Pape 6 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 COMPOSITION OF RECOMBINED WELLSTREAM (from Caiculsted ~ of separator products) I Ma % I ~- I I Mw HydroDen Sulride o.00 o.ao RECOMBINATION CONDITIONS carbon o+wade o.01 0.00 0.8172 44.010 Nitrogen 6.44 1.20 0.8086 28.013 ~ psl9 Methane 2211 235 0.2997 16.043 105 •F Ethane 3.29 0.66 0.3558 30.070 Propane 5.26 1.54 0.5065 44.097 iso-Butane 1.63 0.63 0.5623 58.123 Recombination Parameters t}Butane 3.15 1.21 0.5834 58.123 iso-Pentane 1.57 0.75 0.6241 72150 Primary Stage Gas / ON Ratio, scf/S'bbl r~Pentane 2.09 1.00 0.6305 72150 st recombination corxiitions ....................... 334.78 Hexanes 4.37 243 0.6850 84.0 Wellsfr~m Recornbir~ation Ratio Heptanes 4.52 288 0.7220 96.0 moles has / nale squid .............................. 0.66793 Octanes B.39 4.53 0.7450 107 Nonar~es 3.95 3.17 0.7640 121 Decanes 3.37 299 0.7780 134 Average Wepstream Properties Undecar~es 2.61 254 0.7890 147 Dodecanes 229 244 0.8000 161 AveraDe Molea~r WegM .......................... 150.9 Tridecanes 241 280 0.8110 175 Cakxriated Denstiy at 0 psis and 60'F ....... 0.8288 Tetradecanes 207 261 0.8220 190 PeMadecanes 1.96 268 0.8320 206 Hexadepnes 1.56 230 0.8390 222 Heptadeanes 1.47 231 0.8470 237 Propertles of Plus Fractions Octadecarws 1.53 255 0.8520 251 Nonadecarres 1.27 221 0.8570 Z63 Uq~ U9~ Eicosanes 1.13 206 0.8620 275 Plus Fradlon Mo196 Wt96 Y API MW Heneicosanes 0.99 1.91 0.8670 291 ( x Docosanes 0.94 1.90 0.8720 305 Tricosanes 0.85 1.79 0.8770 318 Heptanas phrs 50.08 88.24 0.9105 23.8 266 Tetrac~sanes 0.79 1.73 0.8810 331 Undecanes plus 31.85 74.67 0.94 17.8 .354 Pentacosanes 0.77 1.76 0.8850 345 PerMadegnes pkis 22.47 64.28 0.9745 13.6 432 Hexa~anes 0.69 1.64 0.8890 3.59 Eicosanes plus 14.68 52.23 1.0102 8.4 _537 Heptacosanes 0.61 1.51 0.8930 374 Par4aCasarws phis 9.98 42.84 1.0468 3.5 648 Oc~osanes 0.60 1.54 0.8960 388 Triacontanes plus 6.73 34.84 1.0900 -1.8 781 Nonaccaanes 0.58 1.55 0.8990 402 Triacontanss plus 6.73 34.84 1.0903 781 100.00 ~ 100.00 p~ 7 CORE LABORATORIES Stewart Petroleum Com~ny West McArthur River #1 ~. aont Composition of Separator Gas (From Chromatopraphtc Technique Component Md 96 GPM MW l>•ns Hydrogen Sulfide 0.00 carbon oiadde o.03 44.010 .8172 Nitrogen 14.85 28.013 .8086 Methane 56.56 16.043 .2997 Ethane 7.78 2088 30.070 .3558 Propane 9.70 2668 44.097 .5065 iso-Butane 242 .787 58.123 .5623 n-Butane 4.18 1.311 58.123 .5834 iso-Per~ane 1.30 .473 72150 .6241 n-Perdane 1.35 .486 72150 .8305 Hennes 0.90 .347 84.000 .6850 Heptanes 0.66 .276 96.000 .7220 Octanes 0.21 .095 107.00 .7450 Nonanes 0.05 .025 121.00 .7640 oecanes o.01 .oos 134.00 .neo Undecanes plus Nil Totals Properties of Plus Fractions I Mol % I Mw I I~ I API Heptanes plus 0.93 100.2 0.730 621 Decanes plus 0.01 134.0 0.779 50.0 • From: Starling, M.B., •Valtxnetric and Phsse Behavior of Oil Field Hydrocarbon Syatems•, SPE (Dagas},1977, 8th Ed~ion, Appendbr il. Sampling Conditions 21.5 psig 120 °F Sample Characteristics This is Core lrab sample number 205 Crlfkal Pressure (psis) ............................. 621.7 Cr~ical Ternperattrre (•R) .......................... .424.8 Average Mobcufar Weight ........................ 27.30 cala~ated t3as Gravy fair =1.000 ......... 0.943 Gss Gravity Fedor. Fp .........„ ..................................... 1.0300 Super CurtrpressibiUly Fedor, Fpv at sanrpGng ............................. 1.0031 Gas Z-Factor at sampling ' .......................... 0.994 at u.sa psis and i0'F Heatirq Value. Btu/sct dry gas Gross ..................................................... 1362 Air Conterh, mol % Air Oxygen ................................................ 1.10 Ak Nitrogen ............................................... 3.93 Total Air Content ....................................... 5.04 p~ g CORE LABORATORIES APPEND/X 11 • LABORATORY PROCEDURES Stewart Petroleum Company West McArthur River Unit No. ZA West McArthur River Field Cook Inlet, Alaska RFL 930231 Duplicate samples of separator gas and separator liquid were received in our laboratory on November 29, 1993. The ambient temperature bubblepoints of the separator liquid samples were measured as sample quality checks. These data and a list of samples received can be found on page four. The composition of the separator gas was determined using temperature programmed extended gas chromatography. The composition, together with the calculated properties of the separator gas, is presented on page five. The composition of the separator liquid was measured to an eicosanes plus fraction using the flash/chromatographic technique. This resulted in the composition listed on page six. Using the reported gas/liquid ratio in conjunction with the compositions of the separator products, the reservoir fluid composition was calculated. This composition is presented on page seven. The separator gas and separator liquid were physically recombined to the reported gas/liquid ratio and the resulting fluid was used to complete the remaining testing program. A portion of the recombined reservoir fluid was charged to ahigh-pressure, visual cell and thermally expanded to the reported reservoir temperature of 174 °F. After establishing thtrmal equilibrium, the fluid sample was subjected to a constant wmposition expansion. Complete data derived from the pressure-volume relations measurements, including relative volumes, Y-functions, calculated single phase densities, and average single-phase compressibilities, may be found on pages eight and nine. At the completion of the constant composition expansion, the sample of reservoir fluid was re-pressurized and equilibrated in single-phase. A differential vaporization procedure was then conducted for the purpose of measuring two-phase properties as a function of pressure depletion. A complete listing of the results is presented on page ten. The viscosity of the reservoir fluid was subsequently measured over a range of pressures at the reported reservoir temperature in a rolling-ball viscometer. Both single-phase and two-phase viscosities of the reservoir fluid are presented on page eleven. A small portion of the reservoir fluid was charged to a single-stage test separator to determine the effect of surface separation on gas/oil ratio, stock tank oil gravity and formation volume factor. Results of the separator test are presented on page twelve. During the separator test, the primary stage gas was collected and analyzed to a heptanes plus fraction using temperature-programmed gas chromatography. The composition of the separator gas along with the total gas properties are presented on page thirteen. The differential vaporization data were subsequently adjusted using the results of the separator test. The adjusted differential vaporization data are presented on page fourteen. This report includes graphical presentations and analytical expressions. The statistical summaries represent an objective estimate of non-systematic error using a preset level of ~dence. The confidence intervals are calculated using the Student "t" density distribution tables. An appendix is included which contains nomenclature and equations that extend and define the analytical expressions and data relationships presented in the report. 3 0 ~. 6 9 • • TABLE OF CONTENTS Laboratory Procedures Summary ojPYT Data General Welllnjormation Preliminary Quality Checks Wellstream Recombination Pressure-Volume Relations Dij, j'erential Vaporization Vscosity ojReservoir Fluid Separator Flash Analysis Di,,a'erential Vaporization adjusted to Separator Conditions Equations a»d Nomenclature .................... 1 .................... 1 .................... 2.3 .................... 4 .................... S.7 .................... 8, 9 .................... /0 .................... II .................... 12,13 .................... 14 ....................Appendix 3 0 ~,'7 0 ~ ~ LIST OF FIGURES . .t!g Pressure-Volume Relations Relativei~olume .................... A-1 Y-Function .................... A-2 D~wential Vaporization Relative Oil i~olume Solution Gas/Oil Ratio Oil Density Incremental Gas Gravity Deviation Factor, Z .................... B-1 .................... B-2 .................... B-3 .................... B-4 .................... B-S Viscosity Analysis Two Phase Fluid Viscosities .................... C-1 Single-Phase Oil Vscosity .................... C-Z D~wential Vaporization Adjusted to Separator Conditions Solution Gas/Oil Ratio Formation Volume Factor .................... D-1 .................... D-Z 3 0~~1 Stewart Petroleum Company West McArthur River Unit No. ZA RFL 930231 SUMMARY OF PVT DATA Reported Reservoir Conditions Average Reservoir Pressure .................. 4187 psig Average Reservoir Temperature ............ 174 °F Pressure-Volume Relations Saturation Pressure ............................... 931 psig Avg Single-Phase Compressibility ......... 6.25 E~ vN/psi (5000 ib 931 prig ) Thermal Exp @ 5000 psig ..................... 1.04264 vat 174 •F /vat 6'9 •F Differential Vaporization Data at 931 psig and i /a 'r Solution GaslOil Ratio ........................... 140 scf /bbl of residual a1 at 60 •F Relative Oil Volume ............................... 1.125 bbl /bbl of residual o~ at 60 °F Density of Reservoir Fluid ..................... 0.8219 grtVcc Reservoir Fiuid Viscosity 2.47 cp at 931 psig and 174 °F Secarator Test Results Separator Conditions Formation Volume Factor Total Solution Gas/Oil Ratio Tank Oil Gravity (°API at 60 °F ) si °F A B 15 80 1.102 117 28.8 (A) Bartels of saturated oil per barrel of stock tank oil at 60 'F. (B) Total standard cubic feet of gas per barrel of stock tank oii at 60'F. 3 Q~.'72 page 1 CORE LABORATORIES ~ ~ Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 General Well Information Company ........................................................ Well Name ..................................................... API Well Number ............................................ File Number .................................................... Date Sample Collected ............................•...... Sample Type .................................................. Geographical Location .................................... Field ............................................................... Stewart Petroleum Company West McArthur River Unit No. ZA 50-133-20447-01 RFL 930231 13-0ct-93 Separator Cook Inlet Alaska West McArthur River Well Description Formation ......................................................... Hemlock Pool or Zone Bench 1 Date Completed ............................................... 26-0Ct-93 Elevation .......................................................... 163 (RKB) ft Producing Interval ............................................ 12480-12550 ft Total Depth ...................................................... 13475 ft Tubing Size ...................................................... 3.5 in Tubing Depth .................................................... 12445 ft Casing Size ...................................................... 7.625 in Casing Depth ................................................... 13390 ft Pressure Survey Data Data from Original Discovery Well Date ................................................................ Reservoir Pressure .......................................... ' psig Data at Sample Collection Date ................................................................. 13-0ct-93 Reservoir Pressure ........................................... 4187 psig Reservoir Temperature ..................................... 174 °F Pressure Tool ................................................... Electronic Gauge Flowing Bottom-Hole Pressure ......................... 3598 psig Flowing Tubing Pressure .................................. 80 psig • Data not fonirarded to Core Laboratories. Page 2 3 0 ~'7 3 CORE LABORATORfES • Stewart Petroleum Company West McArthur River Unit No. ZA RFL 930231 Production Data Data from Original Discovery Well Location ........................................................... Date ................................................................. Oil Gravity @ STP ............................................ ' °API Separator Pressure ........................................... psig Separator Temperature ..................................... ' °F Production Rates Gas ......................................................... Mscf/D Liquid ...................................................... ' STbbl/D Gas/Liquid Ratio ...................................... ' scf/bbl Separator Conditions Primary Separator Pressure ............................. 15 psig Primary Separator Temperature ....................... 80 °F Secondary Separator Pressure ......................... na Psig Secondary Separator Temperature ................... na °F Primary Separator Gas Production Rate........... 27.5 Mscf/D Gas Factors - Field Values: Pressure Base ..................................... 14.73 psia Temperature Base ............................... 60 °F Compressibility Factor (Fpv) ................ 1.004 Gas Gravity Factor (Fg) ....................... 1.096 Laboratory Values: •• Pressure Base ......................................... 14.65 psia Temperature Base ................................... 60 °F Compressibility Factor (Fpv) .................... 0.9449 Gas Gravity Factor (Fg) ........................... 1.0065 Adjusted Primary Separator Gas Prod Rate...... 27.4 Mscf/D Primary Separator Liquid Rate .......................... 200 bbl/D Stock Tank Liquid Rate ..................................... ' bbl/D Separator Gas /Separator Liquid Ratio............ 137.1 scf/bbt Separator Gas /Stock Tank Liquid Ratio.......... ' scf/bbl Stock Tank Liquid /Separator Gas Ratio.......... ' bbl/Mscf Separator Liquid /Stock Tank Liquid Ratio....... ' bbl/bbl • Data not forwarded to Core Laboratories. Pape 3 at 60 °F at °F at °F 3 p~74 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 PRELIMINARY QUALITY CHECKS PERFORMED ON SAMPLES RECENED IN LABORATORY Separator Gas Sam lin Conditions Laborato O enin Conditions Cylinder Number Air psig 'F psig °F Content mol 96 106' 15 80 25 72 0.11 109 15 80 25 72 23.18 Separator Liquid Sam lin Conditions Laborato Bubble oint Cylinder Number Water psig °F psig °F Recovered cc A90A01543 15 80 0 70 0 A90A01542• 15 80 29 70 0 • These samples selected for further analysis. Page 4 3 075 CORE LABORATORIES • Stewart Petroleum Compa• West McArthur River Unit No. 2A RFL 930231 SEPARATOR GAS COMPOSITION IN WELLSTREAM RECOMBINATION Component Mo196 GPM MW Hydrogen Sulride 0.00 ~ 34.080 Carbon Dioxide 0.01 44.010 Nitrogen 1244 28.013 Methane 46.50 t s.043 Ethane 8.77 2333 30.070 Propane 13.73 3.762 44.097 i-Butane 3.39 1.103 58.123 n-Butane 6.63 2.079 58.123 i-Pentane 2.19 0.797 72.150 n-Pentane 2.30 0.828 72.150 Hexanes 1.81 0.699 84.000 Heptanes 1.58 0.648 96.000 Octanes 0.58 0.262 107.000 Nonanes 0.07 0.035 121.000 Decanes Trace 134.000 TbieEs :•k:::•»;:.:::~>;;:::,.•: ::::.s•:<n 100.00 12548 :~>'`>~:::.,.....,~.;:.;.;.:.:,.:,,. Page 5 Gas Cylinder Number .106:201 Sampling Conditions Separator Pressure, psig .................. 15 Separator Temperature, 'F ............... 80 Field Data Pressure Base, prig ...................... 14.73 Temperature Base. 'F ...................... 60 Fg factor ......................... 0.9552 Fpv factor ......................... 1.0040 Field m~sured gas flow rate in Mscf/D at 14.73 psis and 60'F ..................... 27.500 Laboratory Data Pressure Base, prig ...................... 14.65 Temperature Base, •F ...................... 60 Fg factor ........................................ 0.9449 Fpv factor ........................................ 1.0065 Lab corrected gas flow rate in Mscf/D at 14.65 psia and 60'F ..................... 27.420 Total Gas Properties Calculated separator gas gravity (air=1.000) ........................................ 1.120 Gross heating value in Btu/scf at 14.65 psis and 60'F ..................... 1676 Ca~ulated Z (deviation) factor at sampUng conditions ...................... 0.987 3 01'7 6 CORE LABORATORIES • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 SEPARATOR LIQUID COMPOSITION IN WELLSTREAM RECOMBINATION Plus Fractions Component Mol % Weight % Density Molecular st 60'F Wei ht Hydrogen Sulfide 0.00 Carbon Dio~dde 0.00 Nitrogen 0.00 Methane 0.28 0.03 Ethane 0.26 0.05 Propane 1.20 0.31 'rButane 0.60 0.20 n-Butane 1.69 0.57 i-Pentane 1.51 0.63 n-Pentane 2.46 1.03 Hexanes 6.40 3.12 Heptanes 8.18 4.56 0.9155 260. Octanes 10.99 6.82 Nonanes 6.10 4.28 Decanes 5.54 4.31 Undecanes 4.45 3.80 0.9539 344. Dodecanes 3.95 3.69 Tridecanes 4.17 4.23 Tetradecanes 3.56 3.92 Pentadecanes 3.35 4.00 0.9841 417. Hexadecanes 2.69 3.47 Heptadecanes 2.52 3.47 Octadecanes 2.61 3.80 Nonadecanes 2.19 3.34 Eicosanes plus 25.30 40.37 1.0245 515. 100.00 100.00 Page 6 Liquid Cylinder Number A90A01542:703 Sampling Conditions Separator Pressure, psig .................. 15 Separator Temperature, 'F ............... 80 Separator Flow Rate (at sampling condoions) 200 bbUD Total Liquid Properties (at sampling condsions) Sample Density. gm/cc ..................... 0.8904 Sample Molecular Weight ................. 233. 3 0 x'7'7 CORE LABORATORIES • • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 RESERVOIR FLUID COMPOSITION FROM RECeMt3tNED WELLSTREAM Component Mol % Weight % Density rNcc at 60 •F Molecular Wei ht Hydrogen Sulfide 0.00 Carbon Dioxide 0.00 0.00 Nitrogen 2.64 0.39 Methane 10.07 0.85 Ethane 2.06 0•~ Propane 3.85 0.89 'rButane 1.19 0.36 n-Butane 2.74 0.83 i-Pentane 1.65 0.63 n-Pentane 2.43 0.92 Hexanes 5.43 239 Heptanes 6.78 3.42 0.9149 259. Octanes 8.78 4.93 Nonanes 4.82 3.06 Decanes 4.37 3.07 Undecanes 3.51 2.71 0.9539 344. Dodecanes 3.11 2.63 Tridecanes 3.29 3.02 Tetradecanes 2.81 2.80 Pentadecanes 2.64 2.85 0.9841 417. Hexadecanes 2.12 2.47 Heptadecanes 1.99 2.47 Octadecanes 2.06 2.71 Nonadecanes 1.73 2.38 Eicosanes plus 19.93 53.89 1.0245 515. 100.00 Pape 7 Sampling Conditions Separator Pressure. psip .................. 15 Separator Temperature. •F ............... 80 Field measured Separator Gas /Separator Liquid rata at sampAnp conditions 137.5 scUbbl Lab corrected Separator Gas /Separator liquid ratio at sampgnp conditions 137.1 scfJbbl Sample Molecular Weight 190.s 3 078 CORE LABORATORIES • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 VOLUMETRIC DATA (at 174 °F) Saturation Pressure (Psat) 931 psig Density at Psat 0.8219 gm/cc Thermal Exp ~ 5000 psig 1.04264 Vat 174 °F /Vat 69 °F AVERAGE SINGLE-PHASE COMPRESSIBILITIES Single-Phase Pressure Range Compressibility ps;g vN/psi 5000 to 4000 5.83 E -6 4000 to 3000 6.04 E -6 3000 to 2000 6.32 E -6 2000 to 931 7.16 E -6 3 079 Page 8 CORE WBORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 PRESSURE-VOLUME RELATIONS (at 174 °F) Pressure Relative Y-Function (B) Density psig ~ Volume (A) gMx 5000 0.9746 0.8433 4500 0.9774 0.8409 4000 0.9803 0.8384 3500 0.9832 0.8359 3000 0.9862 0.8334 2500 0.9892 0.8308 2000 0.9924 0.8282 1500 0.9957 0.8254 1400 0.9964 0.8248 1300 0.9971 0.8243 1200 0.9978 0.8237 1100 0.9986 0.8230 1000 0.9994. 0.8224 b~931 1.0000 0.8219 923 1.0015 918 1.0024 909 1.0042 899 1.0062 864 1.0138 782 1.0356 5.255 690 1.0694 4.931 620 1.1046 4.684 532 1.1669 4.373 451 1.2522 4.087 382 1.3601 3.844 325 1.4898 3.642 285 1.6157 3.501 188 2.1606 3.159 144 2.6515 3.004 98 3.6025 2.841 (A) Relative Vdume: VNsat or volume at indicated pressure per volume at saturation pressure. (B) Where: Y-Function = (Psat - P) (Pats) ' (VNsat - 1) 3 0 ~. 8 0 Page 9 CORE LABORATORIES • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 RELATIVE VOLUME ( at 174 ' F ) 1.0000 0.9950 0.9900 ~ 0.9850 { 0.9800 0.9750 0.9700 ~ 0 1000 2000 3000 4000 5000 Pressure. psig Relative Volume Expression: y= a + b (Xd)~i + c (Xd)^J + d log(Xd)~k LEGEN D where: a= 4 29155e- 01 i= 0 150 o L.oboratory Data . b= 6.59582e- 01 . j= 0.467 _________ Confidence Limits analytical Expression c= -8.87367e- 02 k= 0.995 d= -1.48783e- 01 Saturation Presauro: 931 psig vote: Xd (dimansionlese 'X') ~ Pi / Psat. psig Current Reservoir Pressure: 4187 psig Confidence level: 99 x pressure-Volume Relations Confidence interval: +/- 0.00006 'r squared': .999836 Figure A-1 CORE LABORATORIES 3 0181 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 6.0 5.5 5.0 4.5 O c 4.0 li } 3.5 3.0 2.5 2.0 0 100 200 300 400 500 600 700 800 900 1000 Pressure. P~9 Y-Function Expression: ys a + b (Xd)~i LEGEND ~'he~' a~ 2.49551e+ 00 t= 1.000 o L.oborotory Data _________ Confidence Limits b= 3.28584e+ 00 Analytical Expression Saturation Prossure: 931 psiy Note: Xd (dimaneionlep 'X') ~ Pt / Peot. pttq Current Reserwir Pressuro: 4187 psiy Confidence level: ~ ~ pmssure-Volume Relations Confidence intervoi: +/- 0.08954 ' Fg u re A-2 r squorod': .991046 CORE LABORATORIES Y-FUNCTION ( at 174 ' F ) ~ ~ i 1 ! ~ ~ ~ i r' I t .,r" ~ i i . ~ ; , ,. ,,.. ~' ~ ,,, ~ i i I ~ ; ; ' ' ,: ~' .- ;' { .' . ,,. r t'~ ~ ! ~ I i .r~~ ~ •' ~ f i •'~' ~ ~/ f ,,~ . f~. S t ~ • ' ~~ r i .• .%~~ .•' ~, f - ,.% I i . .' ',, f f ~ 3 082 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 DIFFERENTIAL VAPORIZATION (at 174 °F) Gas Solution ~ Relative Relative Oil Deviation Formation Incremental Pressure GaslOil Oil Total Density Factor Volume Gas psig Ratio Volume Volume gMcc Z Factor Gravity Rsd A Bod B Btd C Air=1.Ot>0 b~-931 140 800 130 700 122 600 113 500 104 400 94 300 82 200 67 100 48 0 0 @60°F 1.125 1.125 0.8219 1.121 1.160 0.8230 0.972 0.02130 0.848 1.118 1.197 0.8239 0.974 0.02434 0.820 1.115 1.251 0.8248 0.976 0.02837 0.803 1.112 1.331 0.8258 0.979 0.03397 0.799 1.108 1.460 0.8269 0.981 0.04228 0.812 1.104 1.687 0.8282 0.984 0.05589 0.848 1.099 2.166 0.8297 0.988 0.08221 0.918 1.090 3.624 0.8320 0.992 0.15458 1.055 1.053 0.8434 1.845 1.000 Gravity of Residual Oil = 27.7 °API at 60 °F Density of Residual Oil = 0.8878 gm/cc at 60 °F (A) Cubic Feet of gas ai 14.66 psis and 60'F per Barrel of residual oil at 60'F. (B) Barrel of oil at indicated pressure and temperature per Barrel of residual oil at 60'F. (C) Barrels of al plus liberated gas at ind'~cated pressure and temperature per Barrel of residual oil at 60'F. (D) Cut~ic Feet of gas at indicated pressure and temperature per Cubic Feet at 14.65 psis and 60 'F. p~ 10 CORE LABORATORIES 3 483 * ~ Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 SOLUTION GAS/OIL RATIO ( scf/bbl at 174 ' F ) 150.0 128.0 100.0 $ 75.0 e 0 N 50.0 25.0 ~.~ f I I ~` { f 200 400 800 800 1000 Preseuro. pelQ Solution Gas/08 Ratio Edon: y= a + b (~)--i + c (Xi)~j + d (xi)~k L-EGEND ~: a= 5,46753e- 03 i= 0.500 o --- Laboratory Data Confidence Vrnits ~----- b= 4.89378s+ 00 j= 1 •~ AnayEical Exprossion c= -9.55848e- 04 k= 2.000 d= 2.06175e- 05 Saturation Proseuro: 931 Psi Nets: ~ (inanmentd 'X'~ ~ Pr'wwn. P~9 Confdence level: 99 X DiffererltiOl VaporiZOtiOn Confidence interval: +/- 0.4 sct/bbl Figure B-2 'r squared': .999919 CORE U180RA'InRIES 3 0.84 • • Stewart Petroleum Company West McArthur River Unit No. ZA RFL 930231 0.8500 ~~ :~L7i 0.8400 a 0.8350 a 0.8300 o.sz5o 0 8200 OIL DENSITY ( grn/cc at 174 ' F ) 0.845 ~ i ~ 0.840 t t ~< I 0.835 i 0.830 ~ R $ f 0.825 ~ 0.820 t 0 1000 2000 3000 4000 5000 Prwixe• P~9 4 1 ~ ~ l 1 • 0 100 200 300 400 500 600 700 800 900 1000 Pressure. paig Oil Density Expression (below bubbispoint): y= a + b (xd~i + c (xd)-•j LEGEND where: a= 8.43481 e- 01 i= 0.250 o _-- Laboratory Data Confidence Limits ~--~~- b= -1.99521e- 02 J= 1•~ Analytical Expression c= -1.56483x- 03 Saturation Prossure: 931 prig iVote: Xd (dknrrotoNe.. x) - PI /Prat. pei9 Confidence level: 99 R Differential Vaporization Confidence interv~ol: +/- 0.0001 gm/cc 'r squared': .999779 Fgure B-3 C ~~~ n + l . ~ t ~ i ~ ! i ~~ Sin91~-Photo ~ (~ ~ ~ 1 E 3 085 Stewart Petroleum Company West McArthur River Unit No. 2A RFl 930231 ~ ~~ F~ 200 1.75 ~.~ a ,.2s ~.oo o.7s t ~ ~ i I i I i ` i 1 ~ E , f; 1 ~ ( ! ` fi t { ~ I it i ~ , ~ ~ i ( ~ ~; :. - i ~ ~ ~ I ; ~ i i j ,, ,. `` ~ i ,~ ., . •. :, ; ~ ~ ~ ' ,. -,, -.. ~ -. ' go o zo o 30 0 40o soo eo o 70o aoi o Pressure. P~9 ~' ~~ won' y= a + b (xd)~i + c (Xd)~j LEGEND '"'~OfO' a= 1.84481 e+ 00 i= 0.289 o Laboratory Qata Co~dence Limits --------- b= -1.55509e+ 00 j= 1.405 Analytical Expression c= 6.08678e- 01 Saburotian Prssswe: 931 pei~ Nate: Xd (dtmr~etonleee 'X') ~ PI ~ Peat Pr9 Confidence lev~sl: 99 7C ' Differential Vaporization Confidence interwl: +/- 0.0288 'r squarod': .994216 Figure B-4 CORE U80RATORES 3 o~ss Stewort Petroleum Company West McArthur River Unit No. 2A RFL 930231 DL1/IATION FACTOR, Z ( at 174 ' F ~ 0 N o o 0. 0. i i ~ ~~~ ice`. i . ( ~ t 1 ~~`, f ~ ! ( ' .99 ,,~ .r•, f f ~' ' `` • ~ ~,, ``~ 9a ~ ------ I '•- k ~~`• f , ~., ~ ~ ~. ~ - •._ - ~ ~ ~ i - _ ~ 97 i 96 i ~ - ~ i ~ 95 O 100 200 30 0 400 500 Q00 70 0 t30 Prsseurs. peig Ds~vtion Factor Exproseion: y= a + b (Xd~i LEGEND Mff°~'°' o= 9.99999e- 01 i= 0.616 o Loborotory Dato _________ t;onfidence Limits b= -3.12295x- 02 Malyticot Expression SaburotJon Pressur+a 931 psiq Nobx Xd (dm~nsionMss 'X') ~ PI / Psot. Oro ~°"~~° te"'~~ ~ ~ Differential Vaporization Contidenoe trttervol: +/- 0.0017 Fgure B-5 'r squarod': .997739 3 0 ~. 8'7 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 RESERVOIR FLUID VISCOSITY (at 174 'F) Oil Gas OiUGas Pressure Viscosity Viscosity Viscosity ~ cp cp ratio 5000 3.67 4000 3.38 3000 3.08 2000 2.79 1500 2.64 b>,931 2.47 800 2.49 700 2.52 600 2.58 500 2.66 400 2.78 300 2.95 200 3.18 100 3.51 0 4.21 0.0132 188 0.0131 193 0.0129 199 0.0128 209 0.0125 222 0.0122 241 0.0118 269 0.0111 315 • Gas viscosity data calculated from correlation of Les A.L., Gonzalez M.H.. and Eakin B.E., 'The Yaeo:igr of Natural Gases', Journal or Petroleum Teehrrotogy, August. 19136, pp. 997-1100. p~ 1t CORE LABORATORIES 3 0188 • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 830231 RESERVOIR FLUID VISCOSITY ( cp at 174 ' F ) 4.50 4.25 4.00 3.78 3.50 S 3.25 a 3.00 278 2so 225 200 0 ,00 200 300 400 500 soo 700 eoo goo 1000 ~. P~9 ~ ~ iOf 1' ~ a + b (Xd)~i + c (Xd)~j LEGEND fie"Q' a= 4.Z1206e+ 00 i= 0.700 o Laborotory Doto Confidence Limits ~ ~~ b= -4.00l325e+ 00 J= 1.250 ~~--- - Analytical Expn3ssion ~ 22ag45e+ 00 Solurntlon Pr+easurx 831 peig tom.: xd (a~,~«,.r«~... x) - a / r~.~r, ar9 Confidence level: g9 X Rdling-Bel! v8coslty Confidence intenrol: ' ' +/- 0.0142 cp Fgure C-1 r squarod : .99ii7t3 ~ i ~ ~ ~ 0.0140 Caiouiabd Dot vi,oodgr. cP i 0130 0 -- i . { 0 0 20 j t ~ . 1 } OA110 0 200 400 600 800 Pnswre. pd9 i i i ~ ~.. ~ .~ I ~ ~ I + I ~ _ [, 1 ~ ~ f i _ i ( - f t ~ ~ ~ i E -- --- - ----- ~ -- ~ ~ ~ i ~ ~ x ooi:F I.Aeow-~roitlEs 3 089 • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 4.OC 3.7~ 3.50 3.25 3.00 275 225 200 0 ,~ ,~ z~ 2500 3000 3500 4000 ,~ Sooo Pressure, P~q Single-Phase b- °~ y= a + b (dx~i LEGEND ~°' a= 247325e+ 00 ~_ 1•~ o Laboratory Doto _________ Confidence Limits b~ 2.94429s- 04 Malytical Expression Soturofion Prwsesr: 931 peiq Note mC (delEo 'X7 ~ (Pat - PI (. P~ Confidence IsMei: ~ x Rolling-Ball Yscosity Confidence intervd: +/- 0.0085 ep , , Fgure C-2 ; .~,~ r ooi~ ueort~-> SINGLE-PHASE FLUID VISCOSITY ( cp at 174 • F ) i ~ ' ~ i E } i + ' ~ _'i _~ ~ 1 {{ i ~ 1 t i 1 ~ s t 1 . I I i ~ ( i i i ~ I ~ ~ i i f ~ ' ~ ~ _ ` i I ~ ! i i ~ i i 1 I ! ~ ~ ~ ~ I ; t -~ I I I - 3 090 • Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 SEPARATOR FLASH ANALYSIS Flash Gas/Oil Gas/Oil Stock Tank Formation Separator Specific Oil Phase Conditions Ratio Ratio Oil Gravity Volume Volume Gravity of Density ( sct/bbl) (scuSTbd) at 60 •F Factor Factor Flashed Gas (gm/cc ) 'F (A) B) 'API Botb C D Air=1.t)00 931 174 15 80 107 110 0 80 7 7 Rsfb = 117 1.025 28.8 1.102 1.009 • Cdlected and analyzed in the lat~oratory by gas dxorr~atography (A) Cubic Feet of gas at 14.65 psis and 60'F per Barrsl of o~ at ir~eated pressure and temperature. (B) Cubic Feet of gas at 14.65 psis and 60'F per Barrel of Stock Tank OA at 60'F. (C) Barrels of saturated oil at 931 prig and 174'F per Barrel ~ Stock Tank Oil at 60'F. (D) Barred o(oil at indicated pressure and temperature per Barrel of Stock Tank Oil at 60 'F. 0.8219 0.931 • 0.8619 1.198 0.8740 page 12 CORE LABORATORIES 3 0191 Stewart Petroleum Company West McArthur River Unit No. 2A RFL fi~0231 Composition of Primary Stage Test Separator Gas (by gas chron~toyraphy ) Component Mel 96 GPM MW Oens rrVcc Hydrogen Sulfide 0.00 Carbon Diwdde 0.00 Nitrogen 15.33 28.013 .8086 Methane 55.90 16.043 .2997 Ethane 9.17 2.439 30.070 .3558 Propane 10.30 2.823 44.097 .5065 L5o-Butane 1.98 .644 58.123 .5623 n-Butane 3.40 1.066 58.123 .5834 iso-Pentane 0.87 .317 72150 .6241 n-Pentane 0.87 .313 72150 .6305 Hexanes 1.24 .479 84.000 .6850 Heptanes plus 0.94 .413 103.00 .7370 Totals ........... 100.00 8.494 • From: Standing, M.B., 'Vdumetric and Phase Behavior of Oil Field Hydrocarbon Systems', SPE (Dallas), 1977, 8th Eddion, Appendix II. Page 13 Sampling Conditions 15 psig 80 °F Sample Characteristics This is Core Lab sample number 104 Critical Pressure (psis) ............................. 623.2 Critical Temperature ('R) .......................... 421.6 Average Molecular Weigh ........................ 27.0 Calculated Gas Gravely (air =1.000) ......... 0.931 Gas Gravity Factor, Fg ...:............................................ 1.0366 Super CompressiWldy Factor, Fpv at sampling wnditions ............................. 1.0031 Gas Z-Factor at sampling conditions ' .......................... 0.994 at 14.66 psis and 60'F Nesting Value, Btu/scf dry gas Gross ..................................................... 1337 CORE LABORATORIES 3 0 ~. 9 2 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 DIFFERENTIAL VAPORIZATION ADJUSTED TO SEPARATOR CONDITIONS* Gas Solution Formation Formation Oil OiUGas Pressure Gas/Oil Volume Volume Dens'~ty Viscosity prig Ratio Factor Factor gmlce Ratio Rs A Bo B C 5000 117 1.074 0.8433 4500 117 1.077 0.8409 4000 117 1.080 0.8384 3500 117 1.084 0.8359 3000 117 1.087 0.8334 2500 117 1.090 0.8308 2000 117 1.094 0.8282 1500 117 1.097 0.8254 1400 117 1.098 0.8248 1300 117 1.099 0.8243 1200 117 1.100 0.8237 1100 117 1.101 0.8230 1000 117 1.101 0.8224 ba 931 117 1.102 0.8219 800 107 1.098 0.02130 0.8230 188.0 700 99 1.096 0.02434 0.8239 193.0 600 91 1.092 0.02837 0.8248 199.0 500 81 1.089 0.03397 0.8258 209.0 400 71 1.086 0.04228 0.8269 222.0 300 60 1.081 0.05589 0.8282 241.0 200 46 1.076 0.08221 0.8297 269.0 100 27 1.068 0.15458 0.8320 315.0 'Separator Conditions First Stage Stock Tank 15 psig at 80 °F 0 psig at 80 °F (A) Cubic Feet of gas at 14.65 ps'ra and 60'F per Barret of Stock Tank Oil at 60'F. (B) Barrel of oil at indicated pressure and temperature per Barrel of Stock Tank Oil at 60'F. (C) Cubic Feet of gas at indicated pressure snd temperature per Cubic Feet at 14.65 psis and 60'F. 3 093 p~ 14 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFi. 930231 sof_u~noN c~as/af_ f~~no ~ scf~STbb~ ~ ,~ ,~ ,~ 25 0 ~~ ~ i f i 1 r ~ ii 1 I~ ! !` i 1 1 ~ s f Pei Pab 0 LEGEND DV Adjusted to Separator -- Diftere~d vaportrotion Fgure D-1 -O- 13 psty at d0 'F 3 Q~.94 1.13 1.12 1.11 1.10 1.09 e ~, 1.08 1.07 1.06 1.OS 0 Stewart Petroleum Company West McArthur River Unit No. 2A tit. 93o2a1 FORMATION VOLUME FACTOR 1000 2000 3000 4000 3000 Prossu% P~9 LEGEND OV Adjusted to Separator - Differonlid Vapo~rotion Fg'ure D-2 '~' 15 psiq at 80 ' F 3 p ~. 9 5 • EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A Sinale-Phase Relations: Average Compressibility - co _ _ 1 dv ~ rv; -rv;_~ ~P_~ _ P~ forPb <P; 5 Pw (al.l) v dP rvp Two-Phase Relations: Constant Mass Expansion Relative Volume - rvF _ v' _ 1 + ~~ _ P )~P' for 0 5 P < Pb (a1.2) vb Yf olume - Differential Relative Total V r( ~" s ~WY / `Rs 1 ~ +~o, fir, _ for 0 < P < Pb (a1.3) C t Differential Gas Formation Volume Factor - ~~' C~Tr~ Z, for0<P <Pb (a1.4) P T~ a Formation Volume Factor (adjusted for surface separation) - ~o~ = Qo, ~~'~ ~ for 0 < P 5 Pb (al .5) a Solution Gas/Oil Ratio (adjusted for surface separation) - _ lRS` _ Rs~ ~~ ~' ~ RS . R' for 0 < P 5 Pb (a1.6) t o` BloctOil Syiunas Page A-1 ~ Q ~ ~ e ~ ~. EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A DEFINITION OF TERMS Definition of Variables - ~ Formation Volume Factor c Isothermal Coefficient of Compressibility C~ Conversion Constant for gas to liquid volume (e.g., 5.61459 cf/bbl) L Limits of Confidence, t P Pressure rv Relative Volume (from constant mass expansion) R, Gas in Solution T Temperature v Volume Yf Y-function (from constant mass expansion) Z Gas Deviation Factor Definition of Subscripts - a in absolute units a at bubble point pressure d from differential vaporization analysis f .from flash separation test (separator test) s ~ P~ t any discreet point 0 oil phase reservoir in solution r total ,. at working conditions. a~ at base conditions a~raisy:r.~ Page A-2 ` 3 0197 ! ~ APPEIVD/X 111 • Stewart Pe leum ~ompan Denali wars North, Suite 1300 2550 Denali $~reast, Anchorage, Alaska 99503 (907) 27'~-4004 • FAX (907) 274-0424 {t y~~ ~~ ~ ~~ ~~ ~~ . Pan American West Foreland Unit No. 2A Sidetrack and Convert to Water Injector AFE Cost Estimate Attached is the AFE cost estimate to re-enter, sidetrack and drill the WFU #2A as an injection well on the southern edge of the West McArthur River Unit. Total cost to drill, complete and equip is estimated at $2.972MM. The estimated rig days to redrill is 22 days with an additional 6.5 days ttl complete the welt. The cost to equip WFU No.2A of $750M will include a pipeline, pump and filtration equipment to inject produced water from the unit. Tim Billingsle Petroleum Engineer • WFU #2A Injector AFE Estimate WFU #2A In' or Comments Inta . Drl Costs AFE Estimate Drill 2000' MD Professionai Fees O I Bonds, Permits, Insurance 175,000 ' Surve in 20,000 Construction Location and Cellar 225,000 Access Roads 200,000 Airstri Other Surface Dam es 0 1 Drilli Ex se Ri Standb Ri & Crew 220,000 22 da s Extra Labor 0 Cam 8 Cateri 40,000 Extra E ui t 10,000 Fuel 25,000 Bits 38,000 Mill, bits Mob & Demob 50,000 Corin Core Anal sis S cial Services 20,000 DST open hole Mud and Additives 75,000 Ri Su rf E mt & Services 0 Surf Eqmt Rentals 25,000 Subsurface Tool Rentals 75,000 Mudto in Services 0 Electric L s 70,000 Cement 8 Services 0 Casin Crew & E mt 0 Geol ical Ex se 01 En ineerin and Su ision 75,000 Trans nation 8 Frei ht 50,000 P&A costs Clean-up Misc. 10,000' Overhead 80,000', Total Intan . Dri Costs 51,483,000 i i Tan ible Drl Costs ~ ! Surface Casi 0! Intermediate Casi Oi Float E mt 8 Centralizers 0 Casin head and Valves 20,000'i Misc ~ Total Ta . Drl Costs 520,000 ' ! i Total Drilli Costs 51,503,000 WFU #2A Injector AFE Estimate Inta ible Com costs Ri Expense Ri Standb Ri 8 Crew 81,000 6.5 DAYS Extra Labor 20,000 Camp 8 Cateri 20,000 Extra E ui t Casin Crew i3< E mt 10,000 Cement and Services 20,000 Fuel 15,000 Bits 5,000 Lo i cased hole 50,000 Perforati 75,000 Formation Tests Test E ui t Rentals Stimulation Com letion Fluid 8 Service 50,000 S ueeze Cemenf Subsurface Tool Rental Surface E t Rentals 10,000 S iaF Services 10,000 Trans rtation and Frei ht 100,000 Ri Su E mt & Services 20,000 Weldi En ineeri 8~ S ision 25,000 Misc. 10,000 Overhead 25,000 Total Intan .Com .Costs ;546,000 Tan ible Com Costs Casin Liner 10,000 Tubi 80,000 Artificial Lift E mt Packers, etc. 40,000 Liner H r, Float E mt 13,000 Tubi head Whd. Assy, Christmas Tree 20,OOOi Valves, fitti s, etc 10,0001 Misc. Total Tan .Com .Costs ;473,000 f Total Com letion Costs ;749,000 Total Drill &Com lete ;2,222,000 I WFU #2A Injector AFE Estimate Inta ib{e E i Costs Trans. 8~ Frei 10,000 Weldi Construction Crew 50,000 P{PELINE Dirt Work 75,000 Environmental Restoration E ineerin and Su ision 20,000 Misc. 10,000 Ovefiead 5,000 Total Inta . E ui Cost 6170,000 T ible E Cats Line Pi 30,000 PfPEL{NE Pum in E 't 250,000 Filtration E ui t ~ 225,000 Tanks Bld sand Facilities 75,000 Oil Transfer & Shi E t S ial Prod E mt Misc. Total T . E i i Costs 6580,000 Tota{ E ui i Costs 6750,000 Cost Summa Drillin Costs 61,503,000 Com letion Costs 6719,000 E ui i Costs 6750,000 Total Cost 62,972,000 APPENDIX I V West McArthur River Unit Monthly Production Data Well No. 1, #1A aft er 12/95 ! Well No. ZA Welt No. 3 MONTH Oil Gas I Water I Oit Gas Water ~ Oil Gas Water STBO I SCFG I STB STBO MSCFG STB STBO SCFG STB 12/91 1997 1 330 1 0' ! I I I 1/92 0 ' O i 0; 2/92 0 ~ 0 ; 0 3/92 0 0 0 4/92 0 0 01 I 5192 0 0 0 6/92 1656 265 327 ' 7/92 0 0 0 8/92 0 0 0. 9/92 0 0 O i 10/92 0 0 01 ~ ' 11/92 0 0 0 12/92 0 0 0 ~ 1/93 0 0 0 ! 2/93 0 0 0 1 3/93 1361 354 162 1 4/93 0 0 0 5/93 0 0 0 6/93 0 0 0 7/93 0 0 0 8/93 26609 6927 11929 9/93 27684 7198 29991 ; 10/93 12196 3171 15575- 838 111 4 11/93 8534 2219 104301 0 0 0 12/93 23296 6057 33030 0 0 0 1/94 31374 8157 46964 14140 1909 632 2/94 25746 6694 45125 49674 6706 332 3/94 22079 5741 46300, 64601 9561 0 4/94 20607 6082 46747 68436 9618 0 5/94 19875 6192 44733 77697 10051 379 6/94 17104 6357 496651 71901 9358 1630 7/94 1810 543 8590' 73645 17250 2415 8/94' 7884 1812 38887 '; 719081 17639 2992 9/94 8624 2056 376951 I 62673 15264 3657 10/94 7528 1771 35461 68730 16882 8020 11/94 5833 1352 25688, 61646 15039 10581 12/94 9335 2185' 4121 1 i 57811 14379 11055 1/95 9206 2188 41396 j 62419 15298 13712 2/95 8049 1900 36360' I 47492 11762 12827 3/95 88631 2153! 42526: ' 51045 12717 15552', 4/95 8414; 1972! 38785 47047; 11559 157401 5/95 82521 19331 37156; 49851 11990 200731 6195 7898 18861 34757! 462441 11363 21501 ~ 7/95 8598; 2007' 36474' 45382; 11302. 26175] ' 571111 15748 30727 8/95 6935 17501 33718; i 393961 9952 23622 I 63867 16131 27375 9/95 5873 1628 329101 381611 10617 23799 ~ 56653 15744 21275 10195 33581 8101 15963' 375241 91211 25983 ! 58714! 14261 23217 11!95 01 Oi 0~ 353571 8351 254561 53742:. 13073 25259 12/95 ~ 11011 3231 0 27767.. 68781 21327 I 28774] 6756 21721 TOTAL 356,578! 93,690! 918,555 :1,243,598' 267 7991 266 137' i 290 087; 74 957' 127 853 West McArthur River Unit Reservoir Voidage Summary Date Surface Produced Volume ! In' ion Reservoir Void Volume Oii Gas Water Vofume Oil Gas i Water Total ' (STBO) ~ (MSCFG STBW) ~ ~ (STBW (RBO ! (RBG I (RBW) , 12/91 ! 1997 1 330 1 0 I 0 ; 2155 ; 8 0 '. 2162 6/92 ~ 1656 , 265 327 ' 0 j 1787 1 0' 327 ' 2114 3/93 1361 354 162 ; 0 ~ 1469 ! 101 ; 162 1731 4/93 0 0 0 ! 0 0 1 O i 0 0 5/93 0 0 O i 0 O i O I 0 0 6/93 0 0 0 ! 0 0 0 0 0 7/93 0 0 O i 0 0 ~ 0 ' 0 0 8/93 26609 6927 11929 ; 0 28711 1970 ! 11929 42610 9/93 27684 7198 29991 1 0 29871 2043 1 29991 61905 10/93 13034 3282 15579 ; 0 14064 900 15579 30543 11/93 8534 2219 10430 0 9208 630 10430 20268 12/93 23296 6057 33030 0 25136 1719 33030 59886 1/94 45514 10066 47596 0 49110 2347 47596 99052 .2/94 75420 13400 45457 0 81378 2010 45457 128845 3/94 86680 15302 46300 0 93528 2393 46300 142220 4/94 89043 15700 46747 0 96077 2487 -46747 145311 5/94 97572 16243 45112 0 105280 2072 45112 152464 6/94 89005 15715 51295 0 96036 2574 51295 149905 7/94 75455 17793 11005 0 81416 5743 11005 98164 8/94 79792 19451 41879 0 86096 6419 41879 134393 9/94 71297 17320 41352 0 76929 5658 41352 123940 10/94 76258 18653 43481 0 82282 6182 43481 131945 11/94 67479 16391 362691 0 72810 5402 36269 114481 12/94 67146 16564 52266. 0 72451 5490 52266 130207 1/95 71625 17486 55108 0 77283] 57371 55108 138128 2/95 55541 13662 49187, 0 599291 4506] 49187 113621 3/95 59908 14870 580781 0 64641 4955' 58078 127674 4195 55461 13531 545251 0 59842 4409 54525 118777 5/95 58103 13923 572291 0 62693 4444 57229 124367 6195 54142 13249 56258 0 58419. 43401 56258 119017 7/95 111071 29057 93376 0 119846. 9266' 93376 222488 8/95 ; 1101981 27833 84715' 0 118904 83431 84715! 211961 9/95 j 100687!: 279891 77984' 0 j j 108641;` 9555, 779841 196181 10!95 ~ 99596 241921 65163, 0 107464 i 6869 65163 ; 179496 11 /95 ~ 88099 ] 21424 50715 0 I I 950591 6021 ~ 507151 151795 12/95 57642;. 13957' 430481 0 i 62196; 4068! 43048, 109311 TOTAL ! 1,889,263; 436,446! 1,312,545! 0 2,038,515 124,593. 1,312,545; 3,475,652 1/3/96 r a ~c ~, MAY-~0-96 THU 09 ~ 39 ll 'v ur u ~ Hive Grp r« ~,u, .,u ~ n0%s~- r', u~~ ~ a • S~,e~c~vart Pew oleum ~ompan Denali TocvQrs North, Suite 2300 2550 Denali $II'eLt, Anchorage, Alaska 99503 1907) 2"r"r;4004 • FAX (997) 274-0424 ~,~ °~ ~ ~~ ~~ ~~ Report on Fourth Plan of Development ~rtd Submittal of Fifth Plan of Development West McArthur River Unit Gook Inlet Basin, Alaska Stewart Petroleum Company by Tim Billingsley Petroleum Engineer for Stewart Petroleum Company -~ 9 ~~~~1`~~ September 20, 1995 MAY 3 0 1996 Alaska Oil ~ Gas Cans. Commission Ancnorage ~1AY-30-06 THU 09;0 UiV Or OiL Ai~lD GAS An ivy `yU!Go~~85~ F. 09/14 .~ ~ • Introduction and t3ackoround This =fifth Plan of Development fcr the `~~!est '~.°;,Ar?h:,,r River U^i4 coveriry the perod December 31,1995 through December 34, 1996 is submitted tv the Department Of Natural Resources as per 11 AAC 83.343 and Article 8 of the `~fVest McArthur River Unit Agreement. The West McArthur River Unit was formed in 1990 by Stewart Petroleum Comany (SPC) and approved vn Juiy 27, 1990 by CNR. The Unit includes th>? fctio.ving leases: ADL 35911 ; ADL 359112 A map of the unit area was included with the First Plan of Development. The West McArthur River structure underlies bath of these leases and is a structurally clvszd anticline which is mapped on subsurface data and s2ismicalty confrrmed. The horizons of interest are the Hemlock Conglomerate, the West Forelands Formation, the Lower Tyonek Formation, and the Grayling Gas Sands. The structural interpretation is based on subsurface data from wells {including West McArthur River Unit No. 1, Na. 2 and No. ZA, and No. 3) as welt as seismic information. The following Plans of Explaratian and Development have previously been submitted and approved by DNR: Plan of exploration Exibi# "G" to the Unst Agreement approved on July 27, 1990 and expiring December 30, 1991. First Plan of Development Submitted to DNR on Dec. 11, 1991, for the two-year period from Dec. 31, 1991 through Dec. 3Q, 1993. This plan was approved subject to the commencent of drilling of the WMRU No. 2 prior to Dec. 1, 1992. Second Flan of Development Originally submitted to DNR on Dec. 1, 1992 and revised on Jan. 9, 1993 to reflect a delay in the spud date for WMRU No. 2 well. Third Plan of Development Submitted to DNR on Oct. 20, 1993 for the period from Dec. 31, 1993 tv Dec. 30, 1994. Amended on May 26, 1993 to reflect a delay in the spud date for WMRU Na. 3 welt. This plan was approved on Dec ~ 7, 1993 and the amended plan was approved June 14, 1994 subject to the WMRU No.3 well being spudded by Dec. 30, 1994. I~CC~~ V L~ MAY 3 0 1996 Ak~ska Ott & Gas Cons. Cotnmisswn Anchorage i ~ Fourth Plan of Development Su#amittLd to DNR or: September 13, 1994 for the period Pram December 31, 199a to December 30, 1995. This plan was approved o^ Dem.-=r;; ~r 22, 1994 rarrtingent on beginning drilling of tl~e WMRU #3 by March 31, 1995. This deadline was met with the WMRU #3 being spudded on 3/Z9/95. An addition to the Fourth Plan. of Development was requested on July 19, 199b which was the proposal to rednfl the WMRU #1 to a new bottomhole location. Approval vas granted from DNR on August 4, 199. .j RECEIVEf~ u4AY 3 C 1996 Alaska 0!! ~ ~a~ Cdna• COmmtssa~n Anchorage ~[A`r'-30-96 I nil u~ ~ ~ii iJ: d Cr G: ~. H~iu GAa FAX N0, 9075623852 P. 11/14 rvurth Plan v# ~evei©nment fieview The Fourth Plan of Development was dated September 13, 199a and approved ©ecen,her 22 1?9~. Ths Plan de3crib4d four (A) tasks which were scheduled during the the term of the r=ourth Plan of Development, Dec. 31, 1994 to Dec. 30, 1995. The following paragraphs describe the work accampfished during this period_ Task 1 Finish drilling WMRU No. 3 and complete as a producer. This wel{ was completed and flagon production July 5, 1995. Initial production was 282? BOPD and 1232 6WPD. Average production far the first two months of production was X950 OFD and 98513WP©. Task 2 Produceion facility modifications for WMRU No. 3: A third heater treater was installed to process production from WMRU No. 3. Tur#sine power units were also installed to provide electric power for the production faeiliteS includ'mg electric-driven hydraulic pumps to jet lift the wells. A 10,000 bbl 01 tank was installed to provide more onsite storage capacity during pipeline slowdowns. Task 3 Initiate Pressure Maintenance of Reservoir: This task has not been performed yet. 8attomhole pressure Information from WMRU No. 3 indicates the reservoir pressure has not declined from surveys in Wells No. 1 and No. ZA frfteen marr#hs earlier. More needed pressure information will be obtained during the redrill on Well No. 1. An enhanced recovery plan will be generated after the redrfll operation is completed. If it Is determined that reservoir pressure support is needed, the location of the first injection well wilt probably be a relatively short redrill utilizing the abandoned West Forelands Unit No. 2 weQbate located about 1000' south of the existing surface faciiites at WMRU. Task 4 Obtain permits and construct facilites for sea water iniection: This task has also not bean done yet for the same rea.Sons as Task #3 above. In addition, the WMRU wells cun'ently produce enough formation wate3r so that if and when waterflood injection begins, produced water will probably be the injectanf instead of sea water. This would require filtration and treatment of the preduc°d water but would avoid cosily permits and construction of a sea water intake source. !f mare injection water is required than what is produced by the Unit, fresh water wells or surface water might be utilized as supplemental water sources. :s !n addition to the above major tasks, a recinlt on WMRU IVo. 1 well will be completed during the fourth quarter of 1995. The current bottom hole lacaiian wiU be abandoned and the well will be redrilled to a more favorable location which will reduce water production and increase oil production. Important reservoir pressure information will be obtained during the redrill operations at both the original and new bottomhole locations. RE~El~/ED ~1AY 3 0 1996 Alaska 011 & Qas Cons. Commission Anchorage i IAY-3u-:~G i riu U9 : 4G D I V OF OIL AND GAS FAX N0. 9075623852 F, ~i 4 • Fifth Ptarr of Develogmertt The timelines for accomplishing the following tasks are shown on the accompanying project schedule: Task 1 Initiate Pressure Maintenance of Reservoir; °ricr Task 3} The depletion of the reSeNOir pressure at WMRU will be addrQssed in the near future. Reservoir pressure information from Weil No, 1 before it is redrilled and from Weil Ivo. 1A after the redrill wilt be vital in determining how significant the reservoir pressure decline has been at 1NMRU. It is anticipated that an injection well wilt be drilled on the southern edge of the structure to help mitigate the pressure decline. The most economical injection well scenario is the to-entry and sidetracfcing of an abandoned well, the West Forelands Unit No_ 2. The bottom hole location of this well is in Section 1 S, about 1 mite sou#hwest of WMRU No. 2A. it is anticipated this work will be done in the third quarter of 1996. A second injection well to the northeast of afi the producers may also be necessary in the future. This northern injector will be much more expensive due to the longer distance from the onshore surface location. Results from the first injection well to the south would be analyzed before drilling a more expensive well to the northeast. Also, a bottomhofe location to the northeast will be outside the current unit boundaries. Therefore, further drilling to the northeast is not feasible until results fmm the first injection well are obtained and unit expansion to the northeast can be negotiated with offset ownership. Task 2 Construct facilities for vrvduced water injection: (Prior Task 4} (n conjunction with task 1, wafer for injection will need to be obtained- There may enough produced water from WMP,U wells No. 1A, 2A and 3 to provide sufficient reservoir pressure support. '€ t``,°r~ ;s a need for make-up water, fresh water could be utilized from a shallow water well or surface water pending appropriate permits. Facilities will be needed consisting of frltration and possibly oxygen scavenging and other chemical treatments. Also, a road and water pipeline will need to be constructed from the current WMRU surfers facilities to the WFU #2 drilling pad_ ~~~~~~~~ Alaska alt & Gas Cons. Ctxnmiss~n Atttittora9e Wes# McArlhtlr River Uni# Pifth Plan of Development Project Schedule 1995 19 96 Task Oct Nov Dec Jan Feb Mar A t Ma Jun Jul Au Se Oct Nov Dec. Redrill WMFtU #1A 1. Inj. Well Redrill (VJFU tr'2A) 2. Produced V'/ater Treatment Facilities w ~: ; ~'~ c' .~ ~_~ i i.." ~ F_.~ „h t ~ ,.,..r m `' ~~ ~ g~ ^ 1 ~ y 6= ~_ C Y' ' C1AY-30-96 THU 09 ; 40 D I V OF OIL RAID GRa" -FAX idQ, 9015620852 P, 4i i 4 ' = ^v~ JO IVJU ~..... ..RIVER UNIT ~` • i d 3 PAN AM WFlJ' 1 S ~ C T0.1t,pli' ao~ - 3591 ti WMRU-3 ~/- 1VO,g72 9 MD lYD. W~~~2 ,n+a zy,4sa' ~6 PAN AM WFii-2 i' ` Tp. 11,964' i ~ ' Q wr+av.~a i~ ~ SPG WMRU-t ~~C~'"1~•T1 TVQ 9,~St' 3 ~~~~~ ~~ MaY 3 0 ~s Alaska Gii 3, Gas Cons. 'ammisl AE
