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Home My WebLink AboutCO 332Conservation Order Cover Pa{ge XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. .~..~~ Conservation Order Category Identifier Organizing ldo.el RESCAN .~.---~---'- ~~Golor items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plottedscanner) [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' ~ ~~ogs of various kinds ~~-,~ [] Other ' BY: ,'~ARIA Scanning Preparation TOTAL PAGES Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ~ COUNT MATCHES NUMBER IN SCANNING PREPARATION: ~ YES NO Ry: Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES NO (SCANNING IS C POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501 Re: The application of Stewart Petroleum ) Company to present testimony for ) classifying and prescribing pool rules ) for operation and development of the ) West McArthur River Unit. ) Conservation Order No. 332 West McArthur River Field West McArthur River Oil Pool April 11, 1994 IT APPEARING THAT: . By letter dated December 27, 1993, Stewart Petroleum Company (SPC), through its agent Fairweather E & P Services, Inc., requested a public hearing to present testimony for classifying and prescribing pool rules for development and operation of the West McArthur River oil pool in the West McArthur River field. 2. Notice of public hearing to be held on February 4, 1994 was published in the Anchorage Daily News on January 4, 1994. o A hearing concerning the matter of the applicant's request was held in conformance with 20 AAC 25.540 at the office of the Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 am February 4, 1994. ° The hearing record was held open an additional two weeks to allow the Commission time to review the transcripts and consider additional questions. FINDINGS' 1. The area proposed for pool development by SPC includes two State of Alaska oil and gas leases, ADL 359111 and ADL 359112. . The West McArthur River Unit (WMRU) No. 1 well, completed in December 1991 encountered commercial hydrocarbons in the Hemlock formation in the SE %, Section 10, Township 8 North, Range 14 West, Seward Meridian. 3. The WMRU No. 2A well, completed in October 1993, encountered commercial hydrocarbons in the Hemlock formation in the SW~A, Section 10, T8N, R14W, SM. 4. The WMRU No. 2 well, with a proposed bottom hole location in NE~A, Section 15, T8N, R14W, SM., was plugged and abandoned at a depth of 6429 feet in June 1993. Conservation Order #332[ West McArthur River Field Page 2 April 11, 1994 , Production testing of the WMRU No. 1 commenced in August 1993 and will continue until September 30, 1994 under Commission authorization granted March 25, 1994. o Production testing of the WMRU No. 2A commenced in January 1994 and will continue until September 30, 1994 under Commission authorization granted March 25, 1994. 7. Neither producing well encountered a gas-oil contact. 8. SPC estimates the oil-water contact to be 9600' subsea. 9. The WMRU is classified by the Alaska Department of Natural Resources as an exploratory unit. 10. Currently, produced oil is trucked to Marathon Oil Company's Trading Bay Production Facility for final processing and sale. 11. SPC has interpreted the WMRU accumulation to be an asymmetrical northeasterly trending anticline with steeply dipping flanks, bounded on the north by a fault. SPC suggests a smaller productive structure may exist to the south that is fault separated from the primary structure. 12. Seismic data used by SPC to aide in structural interpretation is 1960s vintage, and has not been migrated. 13. In addition to the above wells, SPC used well information from Pan-American's West Foreland No. 1 and Pan-American's West Forelands Unit No. 1 & 2 wells. West Foreland No. 1 was drilled in 1961, and is currently shut-in as a gas well. The two West Foreland Unit wells were drilled in 1964 and 1966, respectively; both are plugged and abandoned. 14. The WMRU No. 1 development oil well appears to contain a complete and representative section of the Hemlock formation between the measured depths of 13,174 and 13,660 feet. 15. Reservoir porosity calculated by SPC from well logs ranges from 6% to 23% and averages approximately 14%. 16. Permeabilities calculated by SPC from drill stem tests conducted in the WMRU No. 1 and No. 2A wells range from 1 to 183 millidarcies in the Hemlock formation. The average permeability of all test intervals was 99 millidarcies. Conservation Order #332{ West McArthur River Field Page 3 April 11, 1994 17. Based on SPC's analysis of fluid samples from the WMRU No. 1 & No. 2A wells, reservoir oil is 28.8°API gravity, with a gas oil-ratio between 140 and 350 scf/stb and a bubble point of 1048 psig. 18. Average initial reservoir pressure in the WMRU No. 1 well is estimated to be 4295 psig at 9384 feet TVD SS. 19. SPC's development plans for the reservoir are uncertain at this time. SPC plans at least one additional well to the NE%, Section 10, T8N, R14W, SM. 20. SPC plans to construct permanent processing facilities and a pipeline to the Marathon Oil Company's Trading Bay Production Facility to facilitate long term sales of hydrocarbons from the WMRU. CONCLUSIONS: . An Order classifying and prescribing rules for development of the oil and gas accumulation shown to underlie the WMRU within the Hemlock formation is appropriate at this time. , Only a portion of the WMRU has been shown by SPC to be productive. Evidence from WMRU No. 1 and No. 2A wells conclusively show the Hemlock formation to be oil-bearing under portions of SPC's northern lease, ADL 359111. Evidence from Pan American's West Forelands Unit No. 2 well suggests that oil-bearing Hemlock formation does not extend into ADL 359112. 3. Additional drilling will be required to fully delineate the accumulation and to support a claim that oil-bearing Hemlock formation extends into ADL 399112. 4. Evaluation of potential reservoir management issues cannot be undertaken until the accumulation is further delineated. , Future development plans, including enhanced oil recovery efforts, are uncertain at this time. Near-term development is contingent upon the results of a well to be drilled in the northern portion of Section 10, TSN, R14W, SM. Regardless of the outcome of this well, long-term sales of hydrocarbons from the WMRU may occur if conservation principles are applied and followed while producing the field. . Imposing statewide conservation regulations, 20 AAC 25, without modification is appropriate at this time to prevent waste, protect correlative rights and enhance ultimate recovery. 7. Statewide conservation regulations will allow SPC sufficient latitude to conduct development activities currently ongoing in the WMRU. Conservation Order #332~ West McArthur River Field Page 4 April 11, 1994 8. The order may require modification as additional data becomes available from ongoing and future development activities planned by SPC. NOW, THEREFORE, IT IS ORDERED TItAT the rules hereinafter set forth, in addition to state-wide requirements under 20 AAC 25, apply to the following described area: SEWARD MERIDIAN Township 8 North Range 14 West Section 10 Rule 1. Field and Pool Name The field is the West McArthur River field. Hydrocarbons contained within the Hemlock formation constitute a single oil and associated gas reservoir called the West McArthur River oil pool. Rule 2. Pool Definition The West McArthur River oil pool is defined as the accumulation of oil and gas that is common to and correlates with the accumulation found in the WMRU No. 1 well between the measured depths of 13174 feet and 13660 feet. Rule 3. Regular Production Regular production will be deemed commenced following completion of testing operations in WMRU No. 1 and No. 2A or on September 30, 1994, whichever is sooner. Rule 4. Reservoir Management Plan The operator shall submit to the Commission an annual reservoir management plan by June 1 of each year. The plan must describe all development activities currently ongoing and anticipated to be undertaken during the coming year. Modifications to the annual reservoir management plan must be submitted to the Commission. Information derived from testing and producing of existing wells and information from future drilling will be presented to the Commission as part of the annual reservoir plan. The plan must include: a. Voidage balances by month of produced fluids (i.e., oil, water, gas) and injected fluids (i.e., gas, water, Iow molecular weight hydrocarbons). b. Progress of any enhanced recovery project(s) approved by the Commission. c. Analysis of reservoir pressure surveys within the field. Conservation Order #332' West McArthur River Field Page 5 April 11, 1994 d. Results and analysis of production logging surveys, tracer surveys and observation well surveys. Rule 4. Reservoir Pressure Monitoring a. Prior to regular production, a pressure survey shall be take on each well to determine reservoir pressure b. A minimum of one bottom-hole pressure survey per producing governmental section shall be mn annually. The survey in part 'a' of this section may be used to satisfy the minimum requirements. c. The datum for all surveys is 9400 feet TVD SS. d. Pressure surveys will be either a pressure build up, pressure fall oft', RFT, static bottom-hole after the well has been shut-in for an extended period, or other Commission approved survey. Rule 5. Enhanced Oil Recovery Plan An enhanced oil recovery plan must be submitted to the Commission within one year after commencement of regular production from the field. Rule 6 Administrative Action Upon request by the operator or upon its own motion, the Commission may administratively amend this order if the revision does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. DONE at Anchorage, Alaska a David W.~~-on, C~~man~ i~ussell A. Douglass, Corr~issioner Thckerman Babcock, Commissioner Conservation Order #332 { West McArthur River Field Page 6 April 11, 1994 AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for reheating. 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). ALASKA OIL AND GAS CONSERVATION COMMISSION May 26, 1994 W. ALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Re~ ADMINISTRATIVE APPROVAL NO. 332.1 Time extension for submittal of the West McArthur River Field Reservoir Management Plan Jesse Mohrbacher, Agent Stewart Petroleum Company c/o Fairweather E & P Services, Inc. 715 L Street Anchorage, AK 99501-3192 Dear Mr. Mohrbacher: We have received your correspondence dated May 25, 1994 requesting an extension of 30 days for filing the West McArthur River Field Reservoir Management iPlan required by Rule 4 of Conservation Order No. 332. The extension would allow incorporation of recently acquired reservoir data into the plan. The commission has determined that the time extension will not promote waste nor jeopardize correlative rights. Additionally, this will be the initial submittal of the aforementioned plan which warrants consideration of all available data. Therefore, the commission extends the deadline for filing the West McArthur River Field Reservoir Management Plan until July 1, 1994. Sincerely, Russell A. Douglass Commissioner BY ORDER OF THE COMMISSION Stewart Petroleum Company Denali Towers No~th, Suite 1300 2550 Denali Street, Anchorage, Alaska 99503 (907) 277-4004 · FAX (907) 274-0424 January 11, 1996 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Ak 99501 Attn: Mr. David W. Johnston, Commission Chairman Re: Enhanced Recovery Plan West McArthur River Unit COMM COMM COMM RES ENG S.E.G NRO eEOL AS'Sf STAT TECH STAT TECH , , _ JAN '1 6 ! '96 A~aska Oil & Gas Cons. Q~mn Anchorace Dear Sirs: A meeting was conducted at the AOGCC office on 1/5/96 regarding future plans for enhanced recovery at the West McArthur River Unit operated by Stewart Petroleum Company. In attendance were AOGCC staff members Robert Crandall, Jack Hartz and Blair Wondzell along with Art Saitmarsh-Consulting Geologist for Stewart Petroleum and Tim Billingsley-Petroleum Engineer for Stewart Petroleum. The "West McArthur River Unit Pressure Maintenance and Enhanced Recovery Plan, 1/2/96" was submitted and discussed. This correspondence with attached project timing graph should be added to the submitted plan as an introduction and to help clarify some questions which were discussed at the 1/5/96 meeting. This correspondence along with the submitted report dated 1/2/96 satisfies AOGCC Order No. 332 Pool Rule No. 5 for the West McArthur River Unit which requires: "An enhanced oil recovery plan must be submitted within one year after commencement of regular production from the field." Regular production from the field began on 9/30/94 and an extension for filing the "Enhanced Recovery Plan" was granted until 1/2/96. (This allowed for preliminary results from the WMRU #lA redrill to be included in the plan). It is also understood that this plan as submitted is different and less detailed than an "Application for Enhanced Recovery" as outlined in 20 AAC 25.402. Some of the details required for that application that need to be evaluated include: 1) cost comparisons and compatibility tests for alternative injection water sources such as fresh water wells or produced water from other fields in the area, 2) more accurate incremental secondary reserve estimates utilizing structure maps and other reservoir information that may be modified from the recently obtained results on the WMRU #lA redrill, 3) examination of the WFU #2 surface site for environmental liabilities which would preclude use of that area as an injection site for the WMRU, 4) re-entry into the plugged WFU #2 well including casing integrity evaluation prior to redrilling the well and using it as an injector. Pending favorable results from these evaluations, the Application for Enhanced Recovery would proceed. Stewart Petroleum Company would like to mention at this time that negative results from any of the above items or additional economic setbacks could jeopardize the implementation of enhanced recovery. However, this letter and corresponding report submitted to you describes the intentions at this time of Stewart Petroleum to begin water injection at WMRU in late 1996. Thank you for your consideration and Stewart Petroleum would especially like to acknowledge the cooperation and helpful insights offered by Bob Crandall, Jack Hartz and Blair Wondzell. We will keep you informed of developments on this matter. If you have any questions regarding this information, please call me at 277-4004. Sincerely, Tim Billingsl~y Petroleum Engineer, Stewart Petroleum Company cc: William R. Stewart, President-Stewart Petroleum Company Paul White, Operations Manager- Stewart Petroleum Company Art Saltmarsh, Consulting Geologist for Stewart Petroleum Company West McArthur River Unit Enhanced Recovery Project Timing. I 1/96 2/96 3/96 4/96 5/96 6)~ ~/96 8/96 9/96 10/9__6_' 1~/9612/96 Secondary Reserve Estimate Evaluate additional injection water source I ~iiii~iiiiiiii iii~iiiiii::~iiiii;; .... -{ ................. Surface facilty design E?!ronmental Site Evaluation-WFU #2 ::::::::::::::::::::: Re-enter WFU #2- evaluate casing _ .:...~......~.:~:.~:~.~~ ................... Redrill WFU #2 ~::::::::::::::::::: ::::::::::::::::::::: .................. Construction of Surf. Facilities Application for Enhanced Recovery __(.he_a_dng will require 30 days) Begin Injection --- -- - .................. -:~:-:.~..,.-,-;-;--~.~.~-:~,-: ~:~-;-:,--,:.~I.-.-~ 1/9/96 Stewart Petroleum Company West McArthur River Unit Pressure Maintenance and Enhanced Recovery Plan Submitted Jenuary 2, 199~ JAN 0 5 1~ Introduction The following Plan Of Development was prepared for the AOGCC as requested, for pressure maintenance arid 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 Re.~ervoir Characterization - Reservoir Pressure - Material Bala~nce - WMRU Development Plan - Appendices This is not an application for Enh.anced 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). STRUCTURE 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 fault 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 present prior to West Foreland and Hemlock deposition. The West McArthur River Field structure 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 trending 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 a cross-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 sealing 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 JAN 0 5 data and production / injection data from wells at MRF support these assumptions as to whether the faults seal or not. STRATIGRAPHY 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 oil field ( Feckler and Calderwood, 1972). Feckler and Calderwood (1972) proposed 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 #lA). 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 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 #lA, bench 3 appears thicker than in WMRU #3). This stratigraphic variation is typical of a braided stream depositional environment. DEPOSITIONAL ENVIRONMENT Extensive core analysis from cores taken at the MRF, indicates that the Hemlock was deposited in a fluvial environment, 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 log 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 consistant 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 Pebble/cobble conqlomerate - 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 realitively uniform, ranging from 7-11%. (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 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/qravel 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 .qrained 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 Very fine grained siltstones - Facies rocks are dense and generally non-permeable. Porosities are very Iow ranging from 1-4 %. Highly carbonaceous claystones - Facies is non-permeable and rocks generally have no porosity. Cuttings 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 enhanced 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 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 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 porous, 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 permeability contrasts were a little higher. It was found that during enhanced recovery operations, i.e., waterflood, that the best reservoir facies (sandstone and pebble-sandstone facies) actually flushed quicker than the conglomerate 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 performance of a randomly stratified system (MRF and WMRF) can be represented by the performance 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 #lA on December 30, 1995. This pressure was 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 explanation for this is that during early December, the disposal well was shut in for remediation work, and production in the WMRF was also shut down. This shut down gave the reservoir a chance to recover, and reach a uniform pressure. At present, WMRU Reservoir Pressure vs Cumulative Field Production, Res. BBLs 4400 4300 420O 4100 3900 3800 370O 3600 350O 3400 33OO 3200 3100 I Orig. BHP #2A, 9~93 ~,#1 BHP, 3t94i I#2A BHP, 3/94 1 -- ! 300O t J Orig. #3 BHP, 7195i Orig. #lA, 1t961 J I#1 BHP, 10/95 i___ 0 500000 1000000 1500000 2000000 2500000 3000000 3500000 Cum Res. BBLs Produced, #1, #2A and #3 the pressure obtained from the WMRU #lA 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 conditions. 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 production history leads to an estimate of original oil or gas in place entirely independent 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 instantaneously 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 WMRF. Individual bench pressures have not been taken. Using an "averaged" reservoir pressure will lend a certain amount of error to the material balance calculations. WMRF DEVELOPMENT 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 performance at MRF, a combination pressure maintenance - enhanced recovery waterflood should be initiated at WMRF in order to recover the maximum amount of oil as is possible. The optimum well placement for a waterfiood 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- enter this 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/water contact at WMRF (-9600), at the southern end of the WMRF structure (Enclosure #1). Cement plugs placed in the abandoned wellbore will be drilled 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/W 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 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 the start of injection, based on 5000 bbls of total fluid production from the reservoir. Injection pressures should be maintained at approximately 3000-3500 psi at the well head. Rock strength data from MRF (by Marathon and Unocal) indicates that there is a fracture gradient in the Hemlock of approximately .75 or about 7000-7200 psi. in the Hemlock Fm., and these injection pressures are below any possible fracture threshhold for the Hemlock reservoir. These calculations are approximations only. As the WMRF # la is completed and brought on production, the actual produced fluids figures will change. Also, after completion of the 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 experience at MRF. At present, produced water from WMRF 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. APF'ENDIX ! LABORATORY PROCEDURES Stewart Petroleum Company Compositional Anslysis Study No. 1 Well West McArthur River Field Cook Inlet, Alaska RFL 930234 Duplicate ~mples of separator gas and separator liquid were received in our laboratory on December 27, 1993. The ambient temperature bubblepoints of the separator liquid samples and the opening pressures of the separator gas cylinders were measured as quality checks. An additional pair of separator gas samples were received on January 26, 1994. A listing of samples received in the laboratory is sununarized on page three. The compositions of the separator gas samples were determined using temperature programmed extended gas chromatography. Thc compositions, together with thc calculated properties of thc SCl~rator gas, arc presented on pages four and eight. Thc composition of thc scpmator liquid was measured to a triacontanes plus fraction using thc low temperature distillation/chromatographic technique. This resulted in thc composition listed on page five. Using the reported gas/liquid ratio (page six) in conjunction with the compositions of the separator products, thc wellstream composition was calculated. This composition is presented on page seven. The preceding data was forwarded to a representative of Fairweather E & P Services, Inc. Due to the non- equilibrium nature of the separator products and the uncertainty of the recombination rates, it was decided to suspend further analysis. TABLE OF CONTENTS Laboratory Procedures i General Well Information .................... 1,2 Preliminary Quality Checks .................... 3 Separator Gas Composition .................... 4 Separator Liquid Composition .................... $ Recombination Data .................... 6 Reservoir Fluid Composition (Calculated) .................... 7 Separator Gas Composition .................... 8 General Well Information Stewart Petroleum Company West McArthur River #1 RFL 930234 Company ......................................................... Stewart Petroleum Company Well Name ....................................................... West McArthur River #1 APl Well Number .............................................. 60-133-20419 File Number ..................................................... RFL 930234 Date Sample Collected ..................................... 15-Dec-93 Sample Type .................................................... Separator Geographical Location ...................................... Cook Inlet, Alaska Field ................................................................. West McArthur River Well Description FOrmation ......................................................... Pool (or Zone) .................................................. Date Completed ............................................... Elevation .......................................................... Producing Interval ............................................ Total Depth ...................................................... Tubing Size ...................................................... Tubing Depth .................................................... Casing Size ...................................................... Casing Depth ................................................... Pressure Survey Data Hemlock Bench 2 20-Dec-91 163 RKB 13254-13360 13742 3.5 7 5/8 liner 13742 Data from Original Discovery Well Date ................................................................ Reservoir Pressure .......................................... 20-Dec-91 4290 psig Data at Sample Collection Date ................................................................. Reservoir Pressure ........................................... Reservoir Temperature ..................................... Pressure Tool ................................................... Flowing Bottom-Hole Pressure ......................... Flowing Tubing Pressure .................................. 15-Dec-93 4217 175 Amerada Gauge 3000 50 (annulus) psig °F psig psig * Data no~ forwarded to Core Laboratories. Page 1 CORE LABORATORIES Production Data Stewart Petroleum Company West McArthur River #1 RFL 930234 Data from Original discovery Well Location ........................................................... Date ................................................................. Oil Gravity ~ STP ............................................ Separator Pressure ........................................... Separator Temperature ..................................... Production Rates Gas ........ ... ..... ... ......... ............................. Liquid ...................................................... Gas/Liquid Ratio ...................................... Separator Conditions Primary Separator Pressure ............................. Primary Separator Temperature ....................... Secondary Separator Pressure ......................... Secondary Separator Temperature ................... Primary Separator Gas Production Rate ........... {th~ ~ ~he d~c~vMy 50 t05 24 150 180 psig °F Mscf/D STbbFD scf/bbl psig °F psig °F Mscf/D Gas Factors- Field Values: Pressure Base ..................................... Temperature Base ............................... Compressibility Factor (Fpv) ................ Gas Gravity Factor (Fg) ....................... Laboratory Values: .. Pressure Base ......................................... Temperature Base ................................... Compressibility Factor (Fpv) .................... Gas Gravity Factor (Fg) ........................... 14.65 60 1.007 1.051 14.65 6O 1.007 0.9995 psia °F psia °F Primary Separator Liquid Rate .......................... Stock Tank Liquid Rate ..................................... Separator Gas I Separator Liquid Ratio ............ Separator Gas / Stock Tank Liquid Ratio .......... Stock Tank Liquid / Separator Gas Ratio .......... Separator Liquid / Stock Tank Liquid Ratio ....... 500** 2.?8 bbl/D at °F bbFD at 60 °F scf/bbl , scf/bbl bbl/Mscf bbl/bbl at °F ** Does not include 1500 bbl/D of "power oil" * Data not forwarded to Core laboratories. Page 2 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 SUMMARY OF SAMPLES RECEIVED and Preliminary Checks of Sample Quality ICylinder Number Cylinder Size, Iitere Sampling Conditions Pressure, prig Temperature, 'F Oper~ng Cond~ Pressure, peig Temperature, 'F Air Content, mol% Sampling Date Separator Gas Samples 37.85 37.85 0.30 CLH317 24 24 22 22 150 150 120 120 24 23 na na 70 70 na na 0 0 na na 0.223 0.319 5.04 14.56 15-Dec-93 15-Dec-93 13-Jan-94 13-Jan-94 ICylinder Number Separator Liquid Samples Cylinder Size, cc Sampling Conditions Pressure, prig Temperature, *F Bubblepolnt Check Pressure, peig Temperature, 'F Sample Volume, cc Sampling Date 5O 5O 105 105 56 68 63 63 0 0 460 487 15-Dec-93 15.Dec-93 * These samples lalected for further analysis. 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T"I"¥T' ' ~'' ............ ~ ,, .~: , :-r,, '-~--r-,*--~ .... f--;--f--h-. ~,,, ............ , ...... , ii~ iii! "'."'+"!".~ ..... ~'"{'"!".~ ..... !"+"~"t'"~"'{"'~r"f"!'"~".*'"t"q""l"~"'*"~'"'~"* .... q"'~'"t''°~''' ' ~'~."~"' K~Si--~-.-,~. "+'+'~'-:- · -.~..~..4-..i .... ,+-.i..+..i.. --.---~--~--'+-- .-i--~ .........T-'t--r--~ ..... ¢--t--r-r--'i,,; -!--i--f- ~ F. qulllbdum I~' :: .: :: :: "'f'T'T"F' ,--..--i--~-- "'i',"]"i"'['" ~u~.~.,.t~ m,~ ...'~"~ L.L.L.L: ~ ~ ~ ' , , ..r-,--_--, ..... +-+-.r..,' ..... ?.t_--,--r-r ............. -r..i.:-- : . · · '--r-'..--':--:' .... .~..i..,..~ .... I ..... , ........ I..i..i..i ..... +--r-!---i .... ~-" (dished line) 011 I ' i i - - i i -350 -300 -250 -200 -150 -100 -50 0 50 100 150 200 Bollin~ I~n~, °F ~wroe: GPSA Engineering Deta Page 3 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 COMPOSITION OF SEPARATOR GAS (by Programmed-Temparature, Capillary Chromatography) Plant Liquid Com~ Mol % Products Density MW (GPM1 (gm/cc) Hydrogen Sulfkle 0.00 Carbon Dioxide 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 9.68 2.653 0.5065 44.097 iso-Butane 2.49 0.810 0.5623 58.123 n-Butane 4.13 1.295 0.5834 58.123 iso-Pentane 1.35 0.491 0.6241 72.150 n-Pentane 1.38 0.497 0.6305 72.150 Hexanes 1.26 0.486 0.6850 84.0 Heptanes 1.43 0.598 0.7220 96.0 Octanes 0.66 0.298 0.7450 107 Nonanes 0.25 0.125 0.7640 121 Decanes 0.08 0.043 0.7780 134 Tota,, ........... I oo.ool I Properties .of Plus Fractions Liquid Uquid Component Mol % Density APl MW Heptanes plus 2.42 0.7356 60.7 102.8 SAMPLING CONDITIONS 24 psig 150 °F Gas Cylinders K18264 Average Sample Properties Critical Pressure, pala ................................ 614.2 Critical Temperature, °R ............................. 434.4 Average Molecular Weight .......................... 28.99 Calculated Gas Gravity ( air = 1.000 ) ......... 1.001 at 14.66 psla and 60 fi= Heating Value, Btu/scf dry gas* 1436 Note: Component properties assigned from literature. * ref: Gas Producers & Suppliers Assoc, ia~ (GPSA) Engineering Data Book Page 4 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 COMPOSITION OF SEPARATOR LIQUID (by Low Temperature Distillation/Extended Capillary Chromatography) Hydrogen Sulficle Carbon Dioxide Nitrogen Methane Ethane Propane iso-Butane n-Butane iso-Pentane n-Pentane Hexanes Hel:~anes Nonanes Undecanes Tridecanes Tetmdecanes Pentaclaca~ Idexaclecanes Heptadecanes Nonadecanes Elcosanes Heneicosanes Tricosanes Tetmcosanes Pentacosanes Hexacosanes Hel:,~cosanes Nonacosanes Trlaconlanes plus Totals Liquid I I I (gnVcc) I 0.00 0.00 0.00 0.00 0.00 0.00 0.85 0.08 0.2997 16.043 0.62 0.08 0.3558 30.070 2.31 0.44 0.5065 44.097 1.06 0.27 0.5623 58.123 2.50 0.63 0.5834 58.123 1.72 0.53 0.6241 72.150 2.57 0.80 0.6305 72.150 6.45 2.33 0.6850 84.0 6.58 2.72 0.7220 96.0 10.22 4.71 0.7450 107 6.42 3.34 0.7640 121 5.58 3.21 0.7780 134 4.35 2.75 0.7890 147 3.82 2.65 0.8000 161 4.02 3.03 0.8110 175 3.46 2.83 0.8220 190 3.27 2.90 0.8320 206 2.61 2.49 0.8390 222 2.45 2.50 0.8470 237 2.55 2.75 0.6520 251 2.11 2.39 0.8570 263 1.89 2.24 0.8620 275 1.65 2.07 0.8670 291 1.57 2.06 0.8720 305 1.42 1.94 0.8770 318 1.32 1.88 0.8810 331 1.29 1.62 0.8850 345 1.15 1.78 0.8890 359 1.02 1.64 0.8930 374 1.00 1.67 0.8960 388 o.g6 1.66 0.8990 402 11.23 37.75 1.0903 781 11oo.ool loo.oo j SAMPLING CONDITIONS 50 psig 105 °F Liquid Cylinders 2132 Average Sample Properties Average Molecular Weight .......................... Calculated Density at 0 psig and 60 'F ....... 232.35 0.8900 Plus Fraction 'Unclecanes plus Penflideeanes plus Eicosanes plus Penlacosanes plus Tdacontanes plus Properties of Plus Fractions I IDe. yIAPl I Mw I I I I 81.92 94.88 0.9121 23.5 269 53.14 80.90 0.9469 17.8 354 37.49 69.64 0.9745 t3.6 432 24.50 56.61 1.0102 8.4 · 537 16.65 46.42 1.0468 3.5 648 11.23 37.75 1.0903 -1.8 781 Page 5 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 WELLSTREAM RECOMBINATION CALCULATION (based o~ rind productk~ data) Conditions for Recombination Calculations Primary Stage at 50 psig and 105 'F ~ Stage at 24 psig and 150'F Stock Tank at 0 psig and 60 'F Field Gas Rate Correctlen Fagtor~- Gas Gravity (air=l.000) .............................................. 0.905 Gas Gravity Factor, Fg ............................................... 1.0510 Gas Deviation Factor, Z .............................................. 0.986 Super Compressibility Factor, Fpv .............................. 1.0070 Pressure Base, psia .................................................. 14.65 Laboratory Gas Rate Correction Factors. Gas Gravity (air=1.000) .............................................. 1.001 Gas Gravity Factor, Fg ............................................... 0.9995 Gas Devlatio~ Factor', Z ............................................ 0.986 Supercompressibility Factor, Fpv ............................... 1.0070 Pressure Base, psia .................................................. 14.65 Field Measured Rates and R;~t]~ - Primary Stage Gas Flow Rate, Mscf/D ....................... Stock Tank Uquid Flow Rate, bbi/D ........................... Field Gas / Oil Ratio, scf/STbbi .................................. Recombination Rates and Ratios - Primary Stage Gas Flow Rate, Idscf/D ....................... Primary Stage Uquld Flow Rate, bbi/D ....................... Primary Stage Gas / Oil Ratio, scf/S~bbl .................... Stock Tank Uquld Flow Rate, bbi/D ........................... Corrected Gas / Oil Ratio, scf/STbbl .......................... 180.00 500.0 360.00 171.18 51 t .33 334.78 500.0 342.37 Laboratory Ueuld Rate Correction Fac(9~ - Liquid Volume Factor, $'bbi/STbbl ~ 60 °F .............. 1.0227 Bitumen, Sediment & Water (BS&W) Factor ............. 1 .(XX) Wellstream Racomblnation Ratio mol~mol ......................... 0.66793 * From: Standing, M.B., 'Volumetric and Phase Behavior of Oil F'mkl I-lydrocarlxm Systems', SPE (Dallas),1977, 8th Edition, Appendix fl. Page 6 CORE LABORATORIES Stewart Petroleum Company West McArthur River #1 RFL 930234 Hydrogen Sulr~ie Carbon Dioxide Nitrogen Methane Ethane Propane iso-Butane n-Butane isckPentane n-Pentane Hexanes Heptanes Nonanes Undecanes Dodecanes Tridecanes 'l'etradecanes Pentadecanes Hexadecanes Heptadecanes Octadecanes Nonadecanes Elcosanes Heneicosanes Trlcosanes Tetracosanes Pentacosanes Hexacosanes Heptacesanes Nonacosanes Trtacontanes plus Totals ........ COMPOSITION OF RECOMBINED WELLSTREAM (from calculated recombination of separat~ products) IJquid I I I 0.00 0.00 0.01 0.00 0.8172 44.010 6.44 1.20 0.8086 28.013 22.11 2.35 0.2997 16.043 3.29 0.66 0.3558 30.070 5.26 1.54 0.5065 44.097 1.63 0.63 0.5623 58.123 3.15 1.21 0.5834 58.1 23 1.57 0.75 0.6241 72.150 2.09 1.00 0.6305 72.150 4.37 2.43 0.6850 84.0 4.52 2.88 0.7220 96.0 6.39 4.53 0.7450 107 3.96 3.17 0.7640 121 3.37 2.99 0.7780 134 2.61 2.54 0.7890 147 2.29 2.44 0.8eX)0 161 2.41 2.80 0.8110 175 2.07 2.61 0.8220 190 1.96 2.68 0.832O 206 1.56 2.30 0.8390 222 1.47 2.31 0.8470 237 1.53 2.55 0.8520 251 1.27 2.21 0.8570 263 1.13 2.06 0.8620 275 0.99 1.91 0.8670 291 0.94 1.90 0.8720 305 0.85 1.79 0.8770 318 0.79 1.73 0.8810 331 0.77 1.76 0.8850 345 0.69 1.64 0.8890 359 0.61 1.51 0.8930 374 0.60 1.54 0.8960 388 0.58 1.55 0.8990 402 6.73 34.84 1.0903 781 RECOMBINATION CONDITIONS 50 psig 105 °F Recombination Parameters Pdrnary Stage Gas I Oil Ratio, scf/S'bbl at recombination conditions .......................334.78 Wellstream Recombination Ratio moles gas I mole liquid .............................. 0.66793 Average Wellstream Properties Average Molecular Weight .......................... Calculated Density at 0 psig and 60 °F ....... 150.9 0.8288 Plus Fraction Heptanas plus Undecanss plus Per~adec~nes plus E.__~___qes plus Pe~ac~,anes plus Trlacontanes plus Properties of Plus Fractions Mo~% I Wt% I Dens~yI APl I MW I I (gnvcc) ! (~v~ I 50.08 88.24 0.9105 23.8 266 31.85 74.67 0.9469 17.8 354 22.47 64.28 0.9745 13.6 432 14.68 52.23 1.01 02 8.4 537 9.98 42.84 1.0468 3.5 '648 6.73 34.84 1.0903 -1.8 781 Page 7 CORE LABORATORIES Stewart Petroleum Company west McArthur River #1 RFL ~$0234 Composition of Separator Gas ( From Chromatographic Technique ) Component Mol % GPM MW Dens (gnvcc) Hydrogen Sult'gle 0.00 Carbon Dioxide 0.03 44.010 .8172 Nitrogen 14.85 28.013 .8086 Methane 58.56 16.043 .2997 Ethane 7.78 2.069 30.070 .3558 Propane 9.70 2.658 44.097 .5065 leo-Butane 2.42 .787 58.123 .5623 n-Butane 4.18 1.311 58.123 .5834 iso-Pontane 1.30 .473 72.150 .6241 Hexanes 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 Decanes 0.01 .005 134.00 .7780 Undecanes plus Nil Tot, is ........... I lOO.001 8.0~2 I I Properties of Plus Fractions Component Mol % MW Dens APl (gm/cc) Gravity Heptanes plus 0.93 100.2 0.730 62.1 Deoanes plus 0.01 134.0 0.779 50.0 Sampling Conditions 21.5 psig 120 °F Sample Characteristics This is Core Lab sample number 205 Critical Pressure (psia) ............................. 621.7 Critical Temperature (°R) ..........................424.8 Average Molecular Weight ........................ 27.30 Calculated Gas Gravity (air = 1.000) ......... 0.943 Gas Gravity Factor, Fg ................................................ 1.0300 Super Compressibility Factor, Fpv at sampling conditions ............................. 1.CX:)31 Gas Z-Factor at sampling conditions *. ......................... 0.994 at 14.65 psia and 60 '1= Heating Value, Btu/scf dry gas Gross ..................................................... 1362 /Ur Content, mol % Air Oxygen ................................................ 1.10 Air Nitrogen ............................................... :3.93 Total Air Content ....................................... 5.04 * From: Standing, M.B., "Volumebic ~ Phase Behavior of Oil Field Hydrocarbon Systems', SPE (Dallas),1977, 8th Edition, Appendix II. Page 8 CORE LABORATORIES APPENDIX II LABORATORY PROCEDURES Stewart Petroleum Company West McArthur River Unit No. 2A West McAr~hur 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 reeombined 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 a high-pressure, visual cell and thermally expanded to the reported reservoir temperature of 174 °F. After establishing thermal equilibrium, the fluid sample was subjected to a constant composition 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 w/th 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 confidence. 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 0169 TABLE OF CONTENTS Laboratory Procedures i Summary of PVT Data General t4Zell Information Preliminary Quality Checks Wellstream Recombination Pressure-Volume Relations Differential Vaporization Viscosity of Reservoir Fluid Separator Flash Analysis Differential Vaporization adjusted to Separator Conditions 2,3 5,7 11 12,13 14 Equations and Nomenclature .................... Appendix 3 0170 LIST OF FIGURES Pressure- Volume Relations RelativeVolume .................... A-I Y-Function .................... A-2 Differential Vaporization Relative Oil Volume .................... B-1 Solution Gas~Oil Ratio .................... B-2 Oil Density .................... B-3 Incremental Gas Gravity .................... B-4 Deviation Factor, Z .................... B-5 Viscosit), Analysis Two-Phase Fluid Viscosities .................... C-1 Single-Phase Oil Viscosity .................... C-2 Differential Vaporization Adjusted to Separator Conditions Solution Gas~Oil Ratio Formation Volume Factor D-1 D-2 0171 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 SUMMARY OF PVT DATA Reported Reservoir Conditions Average Reservoir Pressure .................. Average Reservoir Temperature ............ 4187 psig 174 °F Pressure-Volume Relations Saturation Pressure ............................... Avg Single-Phase Compressibility ......... Thermal Exp (~ 5000 psig ..................... 931 6.25 1.04264 psig E-6 v/v/psi ( 5000 to 931 psig ) V at 174 °F / V at 69 °F Differential Vaporization Data ( at 931 psi~ and 174 °F ) Solution Gas/Oil Ratio ........................... Relative Oil Volume ............................... Density of Reservoir Fluid ..................... 140 1.125 0.8219 scf / bbl of residual oil at 60 °F bbl / bbl of residual oil at 60 °F gm/cc Reservoir Fluid Viscosity 2.47 cp at 931 psig and 174 °F Se: )arator Test Results Separator Conditions Formation Total Solution Tank Oil Gravity Volume Factor Gas/Oil Ratio ( °APl at 60 °F ) , psi~ °F, (A) (S) 15 80 1.102 117 28.8 (A) Barrels of saturated oil per barrel of stock tank oil at 60 'F. (B) Total standard cubic feet of gas per barrel of stock tank oil at 60 °F. 3 0172 Page 1 CORE LABORATORIES General Well Information Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 Company ......................................................... Stewart Petroleum Company Well Name ........................................................ West McArthur River Unit No. 2A APl Well Number .............................................. 50-133-20447-01 File Number ..................................................... RFL 930231 Date Sample Collected ..................................... 13-Oct-93 Sample Type .................................................... Separator Geographical Location ...................................... Cook Inlet, Alaska Field ................................................................. West McArthur River Well Description Formation ......................................................... Pool (or Zone) .................................................. ' Date Completed ............................................... Elevation .......................................................... Producing Interval ............................................ Total Depth ...................................................... Tubing Size ...................................................... Tubing Depth .................................................... Casing Size ...................................................... Casing Depth ................................................... Pressure Survey Data Hemlock Bench 1 26-Oct-93 163 (RKB) 12480-t2550 13475 3.5 12445 7.625 13390 Data from Original Discovery Well Date ................................................................ Reservoir Pressure .......................................... psig Data at Sample Collection Reservoir Pressure ........................................... Reservoir Temperature ..................................... Pressure Tool ................................................... Flowing Bottom-Hole Pressure ......................... Flowing Tubing Pressure .................................. 13-Oct-93 4187 174 Electronic Gauge 3598 80 psig °F psig psig * Data not forwarded to Core Laboratories. Page 2 3 0173 CORE LABORATORIES Production Data Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 Data from Original Discovery Well Location ........................................................... Date ................................................................. Oil Gravity @ STP ............................................ Separator Pressure ........................................... Separator Temperature ..................................... Production Rates Liquid ...................................................... Gas/Liquid Ratio ...................................... Separator Conditions Primary Separator Pressure ............................. Primary Separator Temperature ....................... Secondary Separator Pressure ......................... Secondary Separator Temperature ................... Primary Separator Gas Production Rate ........... 15 80 na na 27.5 °APl psig °F Mscf/D STbbI/D scf/bbl psig °F psig °F Mscf/D Gas Factors - Field Values: Pressure Base ..................................... Temperature Base ............................... Compressibility Factor (Fpv) ................ Gas Gravity Factor (Fg) ....................... Laboratory Values: .. Pressure Base ......................................... Temperature Base ................................... Compressibility Factor (Fpv) .................... Gas Gravity Factor (Fg) ........................... 14.73 60 1.004 1.096 14.65 60 0.9449 1.0065 psia °F psia °F Adjusted Primary separator Gas Prod Rate ...... Primary Separator Liquid Rate .......................... Stock Tank Liquid Rate ..................................... Separator Gas / Separator Liquid Ratio ............ Separator Gas I Stock Tank Liquid Ratio .......... Stock Tank Liquid / Separator Gas Ratio .......... Separator Liquid / Stock Tank Liquid Ratio ....... 27.4 2OO 137.1 Mscf/D bbl/D bbl/D scf/bbl scf/bbl bbl/Mscf bbl/bbl at at at 60 °F °F °F * Data not forwarded to Core Laboratories. Page 3 3 01' 4 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 PRELIMINARY QUALITY CHECKS PERFORMED ON SAMPLES RECEIVED IN LABORATORY Separator Gas Sampling Conditions Laboratory 0penin~l C.,ondition,s Cylinder Number Air psig °F psig °F Content 106' 15 80 25 72 0.11 109 15 80 25 72 23.18 Separator Liquid Sampling Conditions Laboratory Bubblepoint 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 0175 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 SEPARATOR GAS COMPOSITION IN WELLSTREAM RECOMBINATION Component Mol % GPM MW Hydrogen Sulfide 0.00 34.080 Carbon Dioxide 0.01 44.010 Nitrogen 12.44 28.013 Methane 46.50 16.043 Ethane 8.77 2.333 30.070 Propane 13.73 3.762 44.097 i-Butane 3.39 1.1 03 58.123 n-Butane 6.63 2.079 58.1 23 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 1 34.000 Gas Cylinder Number 106:201 Sampling Conditions Separator Pressure, psig .................. Separator Temperature, 'F ............... Field Data Pressure Base, psig ...................... Temperature Base, °F ...................... Fg factor ......................... Fpv factor ......................... Field measured gas flow rate in Mscf/D at 14.73 psia and 60 °F ..................... Laboratory Data Pressure Base, psig ...................... Temperature Base, °F ...................... Fg factor ........................................ Fpv factor ........................................ Lab corrected gas flow rate in Mscf/D at 14.65 psia and 60 °F ..................... Total Gas Properties Calculated separator gas gravity (air=1.000) ........................................ Gross heating value in Btu/scf at 14.65 psia and 60 °F ..................... Calculated Z (deviation) factor at sampling conditions ...................... 15 80 14.73 60 0.9552 1.0040 27.500 14.65 60 0.9449 1.0065 27.420 1.120 1676 0.987 Page 5 3 0176 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 . ~im/cc at 60 °F Wei~lht Hydrogen Sulfide 0.00 Carbon Dioxide 0.00 Nitrogen 0.00 Methane 0.28 0.03 Ethane 0.26 0.05 Propane 1.20 0.31 i-Butane 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 0.95,39 344. 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. Totals ............... I oo I ,oo.oo I ...... : ..... Liquid Cylinder Number A90A01542:703 Sampling Conditions Separator Pressure, psig .................. Separator Temperature, °F ............... Separator Flow Rate (at sampling conditions) 200 bbl/D Total Liquid Properties (at sampling conditions) Sample Density, gm/cc ..................... Sample Molecular Weight ................. 15 0.89O4 233. Page 6 3, 0177 CORE LABORATORIES Stewart Petroleum Company west McArthur River Unit No. 2A RFL 930231 RESERVOIR FLUID COMPOSITION FROM RECOMBINED WELLSTREAM Plus Fractions Component Mol % Weight % Density I Molecular ~lm/cc at 60 'FI Weight Hydrogen Sulfide 0.00 Carbon Dioxide 0.00 0.00 Nitrogen 2.64 0.39 Methane 10.07 0.85 Ethane 2.06 0.33 Propane 3.85 0.89 i-Butane 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 2.39 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. Totals ............... I oo.oo I oo.oo I , Sampling Conditions Separator Pressure, psig .................. Separator Temperature, °F ............... 15 8O Field measured Separator Gas / Separator Liquid ratio at sampling conditions 1.37.5 scf/bbl Lab corrected Separator Gas / Separator Liquid ratio at sampling conditions 137.1 scf/bbl Sample Molecular Weight 190.6 3 0178 Page 7 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 VOLUMETRIC DATA (at 174 °F) Saturation Pr'essure (Psat) Density at Psat Thermal Exp @ 5000 psig 931 psig , 0.8219 gm/cc 1.04264 Vat174°F/Vat69°F AVERAGE SINGLE-PHASE COMPRESSlBILITIES Pressure Range psig Single-Phase Compressibility v/v/psi 5OOO 4000 3000 2000 to to to to 4000 3000 2000 931 5.83 E -6 6.04 E-6 6.32 E-6 7.16 E -6 3 0179 Page 8 CORE LABORATORIES Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 PRESSURE-VOLUME RELATIONS (at 174 °F) Pressure psig Relative Volume (A) Y-Function (B) Density gm/cc 50O0 0.9746 4500 0.9774 4000 0.9803 3500 0.9832 3000 0.9862 25OO 0.9892 2000 0.9924 1500 0.9957 1400 0.9964 1300 0.9971 1200 0.9978 1100 0.9986 1000 0.9994 b)~931 1.0000 923 1.0015 918 1.0024 909 1.0042 899 1.0062 864 1.0138 782 1.0356 690 1.0694 620 1.1046 532 1.1669 451 1.2522 382 1.3601 325 1.4898 285 1.6157 188 2.1606 144 2.6515 98 3.6025 5.255 4.931 4.684 4.373 4.087 3.844 3.642 3.501 3.159 3.004 2.841 0.8433 0.8409 0.8384 0.8359 0.8334 0.8308 0.8282 0.8254 0.8248 0.8243 0.8237 0.8230 0.8224 0.8219 (A) Relative Volume: V/Vsat or volume at indicated pressure per volume at saturation pressure. (B) Where: Y-Function = (Psat - P) (Pabs) * (V/Vsat- 1) Page 9 3 0180 CORE LABORATORIES 1.0000 0.9950 0.9900 0.9850 0.9800 0.9750 0.9700 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 RELATIVE VOLUME ( at 174- 'g) 0 1000 2000 34)00 4000 5000 Pressure, pslg Relative Volume Expreeelon: y= o + b (Xd)^i + c (Xd)-~j + d Iog(Xd)Ak where: o= 4.29155e- 01 b= 6.59582e- 01 c= -8.87367e- 02 d= -1.48763e- 01 j= 0.467 k= 0.995 Note: Xd (dimensionless 'X') -, Pi/Psat, paig Confidence level: 99 % Confidence interval: +/- 0.00006 'r squared': .999836 LEGEND o Laboratory Data Confidence Limits Analytical Expression S~turofion Pressure: 931 palg Current Reservoir Pressure: 4187 psig Pressure-Volume Relations Figure A-- 1 CORE LABORATORIES 3 0181 6.01 5.5 5.0 4.5 4.0 3.0 2.5 S~ewar~ Pe[roleum Company West McArthur River Unit No. 2A RFL 930231 Y-FUNCTION ( et 174 'F ) 2.0 0 300 400 100 200 I 600 700 800 9O0 1000 Pressure, pslg Y-Funu-fion Exprmmion: ¥= o + b (Xd)~i where: a-- 2.~.9551e+ O0 b= 5.28564e+ O0 i= 1.OO0 Note: Xd (dimenslonleas °X') - Pi / Psat, psig Confidence level: 99 % Confidence interval: +/- 0.08954 'r squared': .991046 LEGEND o Laboratory Data Confidence Limits Analytical Expression S~turcCdon Pressure: 931 I~|g Current Reservoir Pressure: 4187 psig Pressure-Volume Relations Figure A--2 CORE LABORATORIES 3 0t 82 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 DIFFERENTIAL VAPORIZATION (at 174 °F) Pressure psig Solution Gas/Oil Ratio Rsd (A) b~931 140 800 130 7OO 122 600 113 5O0 104 400 94 300 82 200 67 100 48 0 0 @ 60 °F Relative Relative Oil Oil Total Density Volume Volume gm/cc Sod (B) Btd (C) 1 125 1 121 1 118 1 115 I 112 1 108 1 104 1.099 1.090 1.053 = 1.000 Deviation Factor Z Gas Formation Volume Factor 1.125 0.8219 1.160 0.8230 0.972 0.02130 1.197 0.8239 0.974 0.02434 1.251 0.8248 0.976 0.02837 1.331 0.8258 0.979 0.03397 1.460 0.8269 0.981 0.04228 1.687 0.8282 0.984 0.05589 2.166 0.8297 0.988 0.08221 3.624 0.8320 0.992 0.15458 0.8434 Incremental Gas Gravity {Air=l 0.848 0.820 0.803 0.799 0.812 0.848 0.918 1.055 1.845 Gravity of Residual Oil = 27.7 °APl at 60 °F Density of Residual Oil = 0.8878 gm/cc at 60 °F (A) Cubic Feet of gas at 14.65 psia 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 oil plus liberated gas at indicated pressure and temperature per Barrel of residual oil at 60 °F. (D) Cubic Feet of gas at indicated pressure and temperature per Cubic Feet at 14.65 psia and 60 °F. Page 10 3 CORE LABORATORIES 0183 Stewart Petroleum Company West McAdhur River Unit No. 2A RFL 930231 SOLUTION GAS/_OIL RATIO (. scf/bbl at 174-'F ) 125.0 100.0 75.0 25.0 0.0 0 200 400 600 800 1000 Pressure, psig Solution Gas/Off Ratio Expmsslon: ¥= a + b (X1),,-i + c (Xi)-,j + d where: a= 5.46753e- 03 b= 4-.89378e+ 00 c= -9.55848e- 04 d= 2.08175e- 05 j= 1 .,500 k= 2.000 Note: Xi Onoremental 'X') - preemum, peig Confidence level: Confidence interval: 'r squared': 99 ~ 0.4 ecf/bbl .999919 LEGEND Laboratory Dora Confidence Umits Analyficol Expression Saturation Pre~eure: 9;~1 peig Differential Vaporization Rgure B-2 CORE LABORATORIES 3 01.84 0,8500 0~450 0~400 0.8,TE~ 0~500 0~250 Stewart Petroleum Company West McAr~hur River Unit No. 2.A RFL 950231 0,8200 0 100 2O0 500 OIL DENSITY ( gm/cc at 174 'F) ' 0,845 , r I ~lngll--Ph<ll~ / 0.~0 ,, o ~um. p~g ,~ .......... 400 500 600 Pressure, psig 700 800 900 1000 011 Denslt7 Expression (below bubblepoinO: ~ a + b (:Xd).,,.l + c (Xd).-.j where: a= 8.4G401e- O1 I= 0.250 b= -1.99521e- 02 j= 1,866 c= -1.5648,.~- 03 Note: Xd (a'Imenatonleee 'X') - Pi/Pad:, prig Confidence level: Confidence Interval: 'r ~luared': 9g :~ +/- 0.0001 gm/cc .ggg77g LEGEND Laboratory Data Confidence Umits AnaljAioal Expression Saturation Pressure: 931 peig Differential VaporizaUon Figure B-3 CORE LABORATOPJES 3 0 85 1.2.5 1.00 0.7~ 0 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 950251 GAS GRAVrTY ( at 17¢ 'F) )0 200 :500 400 500 600 700 800 Pressure, p~ig ecru Omvi~ F_xpree~on: y,= e + b (Xd)-,i + c whore: a= 1.84461e+ O0 i= 0.289 b= -1.55509e+ O0 j= 1.405 c- 6.08678e- 01 LEGEND Laboratory Data Confidence Umits Analyfioal Expression Sal:urc~on Pressure: g51 pelg Note: Xd (cllmenaionlee~ 'X') '- PI / Pact, paig Confidence level: 99 ?; Confidence Interval: +/- 0.0288 'r squared': .994216 Differential Vaporization Figure B--4 CORE LABORATORIES 3 0186 N 1.00 0.99 0.98 0.97 0.96 0.95 Stewart Petroleum Company West McAr~hur River Unit No. 2A RFL 950251 DEVIATION FACTOR, Z ( at 174 'F ) 0 100 200 4OO 500 Pmaaure, I~ig 600 700 800 Factor ExpresMon: ¥,= a .i- b (Xcl)--! a= 9.99999e-- 01 b= -3.12295e- 02 [= 0.616 Note: Xd (dimermtonlmm 'X3 - PI / I~ I~ig Confldance level: 99 X Confldem~ Interval: +/- 0.0017 'r squared': .997739 LEGEND Laboratory Data Confldencm Umlta Analyt!cal Expre~ion Sc~cu~n Pnm~um: 931 peig Differeotial Vaporization Rgum B-5 CORE LABORATORES 3 0187 Pressure psig Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 RESERVOIR FLUID VISCOSITY (at 174 °F) Oil Viscosity cp 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 Gas Viscosi~ Oil/Gas Viscosity ratio 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 Lee A.L., Gonzalez M.H., and Eakin B.E., 'The Viscosity of Natural Gases', Journal of Petroleum Technology, August, 1966, pp. 997-1000. Page 11 CORE LABORATORIES 3 0188 ,3.7.5 3,50 2.75 2~0 Stewart Petroleum Company West McArthur River Unit No, 2A RFL 950231 2,25 0 lO0 I 2OO RESERVOIR FLUID VISCOSITY (cp at 174'F) 0.0140 I0.0130 0.0120 o.01 lO 2O0 40O 600 8OO I~, pldg 4OO 5OO 600 Pressure, pelg 7OO i 1000 011 MocMoRy Exp~n: y= ~ + b (Xd)-,I + c (Xd),,J am 4.21206e+ O0 i== 0.700 b= -4.00825e+ O0 J= 1.250 c= 2.26945e+ O0 Nob: Xd (cnrrmrmi~m 'X') - F~ / Pot, Confidence level: gg ~ Confidence lntervoh +/- 0.01~2 cp 'r ~quamd': .999713 LEGEND Lubomtory Data Confidence Umlta Anal~ical Expression Saturation Pre~ure: 931 pelg Rolling-Ball Viscosity Figure C-1 3 0189 4.00 3.75 -- 3.50 3.2.5 3.00 2.75 2~50 2.OO 0 Stewart Petroleum Company West Mc. Arthur River Unit No. 2A RFL 93~)231 SINGLE-PHASE FLUID VISCOSITY ( cp et 174 'F) 500 1000 1500 2000 2500 ,TO00 Pre.urn, p~lg Slngl~-Phas~ V~seoalt~ E.~on: ~= ~ + b (~).-~ where: ~= 2.47325e+ O0 b= 2.94429e- 04 Not~ dx (de~ ~') - I F~ot - ri I, p.ig Confidence level: Confldenoe Interval: 'r squared': 99 ~; +/- o.ooes .p .9999~ LEGEND Laboratory Data Confidence Umlta ,analytic, al Expression Saturation Prassurs: 931 pslg Rolling-Ball Viscosity Rgum C-2 3 0190 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 ( scf/bbl ) ( scf/STbbl ) at 60 °F Factor Factor Flashed Gas ( gm/cc ) psis] I °F (A) (B) ( °APl/ Bofb (C1 (D) ( Air=1.000 / 931 174 0.8219 15 80 107 110 1.025 0.931 * 0.8619 0 80 7 7 28.8 1.102 1.009 1.198 0.8740 Rsfb = 117 * Collected and analyzed in the laboratory by gas chromatography. (A) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel of oil at indicated pressure and temperature. (B) Cubic Feet of gasat 14.65 psia and 60 'F per Barrel of Stock Tank Oil at 60 °F. (C) Barrels of saturated oil at 931 psig and 174 'F per Barrel of Stock Tank Oil at 60 'F. (D) Barrels of oil at indicated pressure and temperature per Barrel of Stock Tank Oil at 60 °F. Page 12 CORE LABORATORIES 3 O191 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 Composition of Primary Stage Test Separator Gas ( by gas chromatography ) Component Mol % GPM MW Dens (gm/cc) Hydrogen Sulfide 0.00 Carbon Dioxide 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 iso-Butane 1.98 .644 58.123 .5623 n-Butane 3.40 1.066 58.123 .5834 iso-Pentane 0.87 .317 72.150 .6241 n-Pentane 0.87 .313 72.1 50 .6305 Hexanes 1.24 .479 84.000 .6850 Heptanes plus 0.94 .413 103.00 .7370 Totals ........... I loo.oo I I I Sampling Conditions 15 psig 80 °F Sample Characteristics This is Core Lab sample number 104 Critical Pressure (psia) ............................. 623.2 Critical Temperature (°R) .......................... 421.6 Average Molecular Weight ........................ 27.0 Calculated Gas Gravity (air = 1.000) ......... 0.931 Gas Gravity Factor, Fg ................................................ 1.0366 Super Compressibility Factor, Fpv at sampling conditions ............................. 1.0031 Gas Z-Factor at sampling conditions *. ......................... 0.994 at 14.66 psia and 60 °F Heating Value, Btu/scl dry gas Gross ..................................................... 1337 * From: Standing, M.B., "Volumetric and Phase Behavior of Oil Field Hydrocarbon Systems", SPE (Dallas), 1977, 8th Edition, Appendix I1. Page 13 CORE LABORATORIES 3 0192 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 930231 DIFFERENTIAL VAPORIZATION ADJUSTED TO SEPARATOR CONDITIONS* Pressure b)) psig Solution Gas/Oil Ratio Rs (A) Gas Formation Volume Factor Formation Volume Factor Bo 1.074 1.077 1.080 1.084 1.087 1.090 1.094 1.097 1.098 1.099 1.100 1.1Ol 1.101 1.102 1.098 1.096 1.092 1.089 1.086 1.081 1.076 1.068 Oil Density gm/cc 5000 117 0.8433 4500 117 0.8409 4000 117 0.8384 3500 117 0.8359 3000 117 0.8334 2500 117 0.8308 2000 117 0.8282 1500 117 0.8254 1400 117 0.8248 1300 117 0.8243 1200 117 0.8237 1100 117 0.8230 1000 117 0.8224 931 117 0.8219 800 107 0.02130 0.8230 700 99 0.02434 0.8239 600 91 0.02837 0.8248 500 81 0.03397 0.8258 400 71 0.04228 0.8269 300 60 0.05589 0.8282 200 46 0.08221 0.8297 100 27 0.15458 0.8320 Oil/Gas Viscosity Ratio 188.0 193.0 199.0 209.0 222.0 241.0 269.0 315.0 *Separator Conditions First Stage Stock Tank 15 psig at 80 °F 0 psig at 80 °F (A) Cubic Feet of gas at 14.65 psia and 60 °F per Barrel 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 and temperature per Cubic Fee{ at 14.65 psia and 60 °F. Page 14 3 0193 CORE LABORATORIES 150 125 100 0 0 Stewart Petroleum Company West Mc. Arthur River Unit No. ZA ~ 930~1 SOLUTION GAS/OIL RATIO ( .cf/S'rbbl ) Saturation Preasure 931 psig 2OO Pressure, psig 1000 LEGEND Differential Vaporization 15 pelg at 80 'F DV Adjusted to Separator Rgure D-1 3 0194 Stewart Petroleum Company West McArthur River Unit No. 2A RFL 9,.10231 FORMATION VOLUME FACTOR 1.13 1.12 1.11 1.10 1.09 1.08 1.07 1.06 Saturation Praaaure 931 palg IOO0 2OOO Pre.ute, psig LEGEND ----- Differential Va~rtzetion -[3- 15 p~lg ~t 80 'F DV Adjusted to Sepemtor Figure D-2 3 0195 EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A Sin.qle-Phase Relations: Average Compressibility - ror~b <~ Two-Phase Relations: Constant Mass Expansion Relative Volume - ~, (~- ~,)1~, rvi =--=l+ for 0 < P/<P~ Differential Relative Total Volume - /3,,= G +fo, forO<~<g Differential Gas Formation Volume Factor - fgi =('PbaseTr)kpiTbasea Zi for 0 < P~ < Pb Formation Volume Factor (adjusted for surface separation) - Solution Gas/Oil Ratio (adjusted for surface separation) - o,) or0< (al.l) (al .2) (al .3) (al .4) (al .5) (al.6) Page A-1 Black Oil 3 0196 EXTENSIONS TO ANALYTICAL EQUATIONS Appendix A DEFINITION OF TERMS Definition of Variables - ? C~ L P T Z Formation Volume Factor Isothermal Coefficient of Compressibility Conversion Constant for gas to liquid volume (e.g., 5.61459 cf/bbl) Limits of Confidence, ± Pressure Relative Volume (from constant mass expansion) Gas in Solution Temperature Volume Y-function (from constant mass expansion) Gas Deviation FaCtor Definition of Subscripts - in absolute units at bubble point pressure from differential vaporization analysis from flash separation test (separator test) gas phase any discreet point oil phase reservoir in solution total at working conditions at base conditions Page A-2 Black Oil Systems 3 0197 APF'ENDIX III Stewart Petroleum Company Denali Towers North, Suite 1300 2550 Denali Street, Anchorage, Alaska 99503 (907) 277-4004 · FAX (907) 274-0424 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 to complete the well. 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 ~ Comments i WFU #2A Injector ._~ ., Intan,q. Drl,q Costs i AFE Estimate '~ Drill 2000' MD P__r..0_fe_ _s s_~i o _n_a_l__F _e~_s. .............................................................. .0_~ Bonds, Permits, Insurance j 175,~__~_~ I 2o,oooL Construction 1 Access Roads L 200,000 AirstripI .................................................. J_ Other _ R_ i_g_~S t_ a_n_d_d b_Y_ __R_~_g_,&_C_rew_ .......................................................................... 2_2_.9,000.2_2_~_a_~s__ Extra Labor _C__a_. ~m_p__&__C__at.e_r_i_.ng... _4_0._,._0._0-0_ Extra Eq.~ui_p_rn_e_n_t~ ...................................................................................... 1_0_.,_00_0_ Fuel 25 000 Bits 38 000 Mill, bits _M_o_b_.~....9~m~b~ ..5.._0_:0_.9~ _Goring S P_e_ ci___a_l__S_e r v i___c_c_e_s. ............................................................................................ ..2_o_-0_0~; 9S__T_ op_ e_~. h__o!e- ~ud and Additives .......................................................... Z _5. . ;_0_0. .0_ :.B J.g. _s_u_PP. o__E _E_q_m_t.. A §_~ ~ i_ c_ .e_s_ ................................................................... ~ Surf Eqmt Rentals 25,000 Subsurface Tool Rentals : : M____ud Iogg i n_n~_ Services 0 ElectricL?g__s_ ...................................................................... _7_0_;__0_0_0_ Cement & Services 0 G__~eo I__o_g_i_c~ I Expense 0 En ineerin and Supervision 75,000 ...1-r~nsp_o_rtAt]_on & F rei_g_h_L ................................................ .5__0, 00__9 P&A costs _Mis_c_. ................................................................................................................ !0_,-0.0-0_ 0 v__er~e_~9. ............................................................................. A0:_qg_0 ....................... Tan,qible Drl,q Costs Surface Casin_g_ ................................................................................... _0_. ~ n__t..e_r_m~_d La t, e_ -G_._a_sj...n._.g, ............................................................................... _o Float Eqmt & Centralizers 0 p a__..s_i~ .g_h _e_a._d._ _a_n_ _d~ _a Lv_ _e..s_ .................................................. _2_ _9:_°._9 _o_ Misc _ _T_o.t..aJ )-_.a_n. _g:_D_..r!_g.__C_..o_s,._t_s_ ................................................................. WFU #2A Injector AFE Estimate r R._ i_c~ Expense .............. ] ......................................... q Rig_. Standby [ Ri~ & Crew ~ 81,000i6.5 DAYS o,ooot Extra Equipment ~_as~in_.g_ Crew & Eqmt 10,000L Cement and Services ........................................ _2_o,_g_o~,L Bits 5,000 ~2a aj_ng_(F_a s_ ~_ _h_o_Le_)_ ................ ~_........................................... .5__0;._0. 0_0: Perforating___ ............................... i ................................................................ ~_5:~._~_.. Formation Tests _'l-_est___.E_gu i pment Rentals Stimulation C~9_rn_pletion Fluid & Service ................................................................... Subsurface Tool Rental . $_U_..rf~?_~P_..m_ t_R....e_.n_t~ i_s_ ................................................................. _S._pecial Services ....................................................... _.T..r_a_0..S._B_o_~at i_o_n_...a_ .~_~__F_re_i~9 ~_t_ _ .R__i_g_ _S_u_gp__9_fi_E__g_.m__t_&__S_e_ rv__!i_c_e s_ ............................................ ._w~_Ldin__~ .E__p~ ~ n~_e?_g_ ~_.. _S_u._ .p..e__r:,j~ o~ .................................................. ..2....5_,_90_0_ .~j_s:: ............................................................................................................................ .!.0_,_~g. ............................................................................................................. Overhead 25,000 ........................................................................................ Tota~ ~ntang:.....C__o__m~_..C__os__t! .... : ..................................... $__~,_~.~ ...................................................................................... / g a s_j njLL..jn~ r,_ ........................................................................... j ~ ,.._o_g_0_ ......................................................................................... P a__c k_? r__s_,...e~t_c_. ................................................................................. _4. _0~, g 0___0.. Liner ~gr, Float Eq__.m...! .................................................................. TLs_, .0_0_o T___u_bin___ghead_ ........................... ?_h_d:_.6S_~::._. _C_h__ .r.L~Lm_a_. ~__.T..r.~_~ .................................................. _2_0,__0_0_0 .................................................................................... Valves, :JttJn_~z..e_.~: ..................................................................... _'J_~ _0_0..~ Misc. Tota~ Ta n.~.__Cg_m_p_.._C__o?_~. .................................................... _~_~_ ?~_,.~. ~0__. Total ComRl_.e._t_i?__C._9_.s_t_s- ............................................... $__7__J,g,__l~_~_ ........................................................................... WFU #2A Injector AFE Estimate Intan,qible E ui in,q Costs .................... :_9!_.!PP! ....................... Tran_~_._. &~ F___r_e. ig__ht' ~l_0_,~O~__0_j ___W~!_dj.n_g_ ............................................. Construction Crew ........................................... .5_0,__o.9_o_.!p_LP. _E..L_.!_N_.E_ Dirt Work 75,000 Environmental Restoration En ineering and Supervision .............. _2_0,___~_0_. Misc. ........................................................ Overhead T__otal In_~ta__n_g_. E_quipping Cost Tan.qible Equi pin!:l. Costs Li__n_e Pipe 30,000 PIPELINE _P_u__m_.ping Equipment ............................................... Filtration Equipment 225,000 ..................................................................... Tanks ................................................... .~. ................................ BId.___~s and Facilities 75,000 _s_._p_e_~j_~LP..r_o__d_.~_q__m_t_ ........................................................................................................................................ Misc. ........................................... Total Tan Equi pin Costs $580,000 ............................................................. ............................................................................. r- ........................................................... ~ .......................... Total Equipping Costs $?50,000 ...................................................... ................................................ ....C.:o~. L S_u_m_m_a. _fy ......................................................................................................................... ...D._r~ n_a_c_._o~L~_ ................................................................ _$.._~_,..~_ .o_s..,_o_o_o_ .................................................................................................. _C_ .o.._mpLe._tj.9. n_.~.9_s_t.S. _ ................................................................................... _$ ?_ !._9.,_o_o.o_ .................................... ~.~ _u~ p_. ~..n._9_ _9..9.. ~_t. ?_ ................................................... , $~.~0_,._o_.o_ .o_ Total Cost $2,972,000 APPENDIX IV West McArthur River Unit Monthly Production Data i Well No. 1, (#lA after 12/95) i l~ Well No. 2A --~-i I Well No. 3 MONTH Od Gas Water t = O~i i Gas . Water i ' Oil Gas i Water ....... i S(~B_O__)_.~_(M_SC__F_G_)_L_(S_TBW) i___~ (S_T__B~)__L(M_SC_F_~_ (STBV~ t ! (S_mB_O_) i_~_SCFG)! ~TB__W)_ ..... ~ ----! - ~ ~ ~ ! -'-- h .... F-'~ ..... 12/91 I 1997 33--01 ~! i { ............... { ....... 1/92 ~ o} o! o~ I ! -- 1 3/92 L 0 0.[ 0 _~_ l 4/92 t 0 .... -'~'- .'~.--- 6 j-~----1 .................... ' ' 5/92 T ~- ..... '--'8 ........... 0 I ....... '-- - 6/92 1656 265~ 327 ~7/92 0 0 0 .8/92 0 0 0 ....................... 9/92 0 0, 0 10/92 0 0 0 11/92 0 0 0 12/92 0 0 0 1/93 0 0 0 .................................................................................................................................................... 2/93 0 0 0 ...................................................................................................................... 3/93 1361 354 162 .............................. 4/93 0 0 0 ....................................... ~. .......................................................................................................................................................................................................................... 5/93 0 0 0 ........................................................................................................................................ 6/93 0 0 0 7/93 0 0 0 ............................. ---1 ................................................................................................. 8/93 26609 6927 11929 ................................................ 9/93 27684i 7198 29991 10/93 12196' 3~ 7'-~' 15575 '-" 838 .... 111 4 ........................................................................................................ 11/93 8534 2219 10430 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 49665 71901 9358 1630 ':7~'8~~ ....................... :'i~i',i~ ................ ~;~'~ .............. ~-~-88"! ............... ~'~-,i,'~ ....... :":i~§8' ............. -5-,;f.:f~ ............................................................................................................................................................................................ 8/94 7884 1812 38887 71908 17639 2992 ....................................................................................................................................................... 9/94 862~ ............. 2_.0_5_e_ ....... _.3_7_6_9...~. ................... _'6.2_6_7._3. ......... _1_5,~§.4._ ....... _3.6_5_.7_ .................................................. 10/94 7528 1771 35461 68730 16882 8020 11/94 5833 1352 25688 61646 15039 10581 12/94 9335 2185 4121r 1 57811 14379 11055 .................................................................................................................................. 1/95 9206 2188 41396 62419 15298 13712 ......................................................................................................................... ~_/~._.5_ ................ ~p._4_9 ...... _';1_.~9_0 ......... _3.._6_3._6_0_. ............ _.4Z.4_9_2_ ...... _1__1._'7__6..2_ ........ ~..2_8_2Z 3/95 8863 2153 42526 51045 12717 15552 ....................................................................................................... 4/95 8414 1972 38785 47047 11559 15740 .................................................... 5/95 8252 1933 37156 49851 11990 20073 6/95 7898 1886 34757 46244 11363 21501 ..................................................................................................................................................................................... 7/95 8598 2007 36474 45362 11302 26175 57111 15748 30727 ......................................................................... ~ .................................................................................................................... 8/95 6935 1750 33718 39396 9952 23622 63867 16131 27375 9/95 5873 1628 32910 38161 10617 23799 56653 15744 21275 10/95 3358 810 15963 37524 9121 25983 58714 14261 23217 11/95 0 0 0 35357 8351 25456 53742 13073 25259 12/95 1101 323 0 27767 6878; 21327 28774 6756 21721 TOTAL 356,578 93,690 918,555 1,243,598 26~,797 2,66,137 290,087 ~41957 127,853 West McArthur River Unit Reservoir Voidage Summary Date i Surface Produced Volume .! I Injection i I Reservoir Voidaae Volume i ....... O--i~- .... i Gas I Water i ~---V-ol-~'-n-~--i i .... ....... "0,-~ .... -~---"Gas-"-!'-~at-~, z (STBO) (MSCFG) (STBW) (STBW) I (RB_O_) (RBG)_~ (RBW) i 1997] 3301 0 i 5 i [ ..... --~1~-I ...... 8 .... 0i- 12/91 6~92 16561 265] 327' 6 T [ ~-~871- 0 ~27-~' ~-~4 3/93 ] 13611 354 ~._6._2~_~ :. 0_ -i 1469_ 101. 162 1731 4/93 0 0f 0 _!~ O_ .~_~1 ____0_ 0 O~ 0 o o, o o - o o 6/93............... -6- 0............. -(~-----__~_[~ .... -~- ...................... -0- 0 0 7/93 0 0 0 0 0 oi o: 0 8/93 26609 6927 11929 0 28711 1970 11929: 42610 ........... 9/93 27684 7198 29991 0 29871 2043 29991 61905 10/93 13034 3282 15579 0 14064 900 15579 30543 ................................................................................................. 11/93 8534 2219 10430 0 9208 630' 10430 20268 ........................ 12193 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 20113 45457 128845 ................................................................................................. ."T- .... 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 36269 0 72810 5402 36269 114481 12/94 67146 16564 52266 0 72451 5490 52266 130207 ~/95 ........ -¢"i'~-~-~~ ..... ~-'~;~'~- .............. -;~-i"8-~- ..................... 6 ................................ ~ ............ S-~-~'~' .......... ;~-i-~ ............................................................................................................................ 2/95 55541 13662 49187 0 59929 4506 49187 113621 ............................................. 3/95 59908 14870 58078 0 64641 4955 58078 127674 4/95 55461 13531 54525 0 59842 4409 54525 118777 5/95 58103 13923 57229 0 62693 4444 57229 124367 6/95 54142 13249 56258 0 58419 4340 56258 119017 .................................................................................... 7/95 111071 29057 93376 0 119846 9266! 93376 222488 ................................................................................................... ..... ._8_/9_5_ ........... _t !_0...1_e...8_ .......... _2._7_8__3__3_ ..... ~.4_7j _5_ ................... ._0_ ................................ t ?_~_9-,0_4. ................... _8_3.,4__3_ .............. _~?..7_.L5_ 9/95 100687 27989 77984 0 108641 9555 77984 196181 ............................................................................................................................................................................................................................................... 10/95 99596 24192 65163 0 107464 6869 65163 179496 .............. 11/9 5 88099 21424 50715 0 95059 6021 50715 151795 12/95 57642 13957 43048 0 62196 4068 43048 109311 , TOTAL 1,86~,-~6-~ 43~,446 1,312,545 ............ -0 .............. '~3~-~-~' 124,5~3 1,312,545-~-~'~,~,' 1/3/96 E & P SERVICES,, INC, May 25, 1994 /q¢t 332, ~ David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Request for 30 Day Extension for Submittal of the West McArthur River Field Reservoir Management Plan Dear Chairman Johnston: Stewart Petroleum Company (Stewart), hereby requests a 30 day extension to the June 1, 1994 deadline for submittal of the West McArthur River Field Reservoir Management Plan. The extension is requested in order to incorporate recently acquired reservoir data into the Plan and to allow sufficient time for careful preparation of the initial document. It is anticipated that the Reservoir Management Plan will be a working document that will evolve with the development of the West McArthur River Field. If you have any questions about this request or any other matter, please contact the undersigned at any time. Sincerely, Jesse Mohrbacher, Vice President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company cc: W.R. Stewart, Stewart Petroleum Company RECEIVED MAY 2 5 1994 Alaska Oil & Gas Cons. Commission Anchorage 715 L Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258-5557 E & P SERVICES, INC.. OMM _ --.... 'RES EN -~ ENG May 1 8, 1 994 G~ASSTt. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission ~'-t 3001 Porcupine Drive .,,~'~ · Anchorage, Alaska 99501-3192 ,,~,~__ Re: Minor Correction and Comment t~ Conservation Order N0._332/.¢) Pool Rules for the West McArthur River Field ~---'" "-------~ Dear Chairman Johnston: Stewart Petroleum Company (Stewart) would like to inform the Commission of a minor discrepancy in the findings of Conservation Order No. 332. In Finding No. 12, the seismic data is referenced as being 1960's vintage and unmigrated. In actuality, the data was acquired in 1980 and is unmigrated. This error was stated by Stewart personnel during testimony at the Pool Rules hearing on February 4, 1 994. Stewart would also like to comment on Conclusion No. 2 of the Conservation Order. Although the West McArthur River Unit has not been shown to be productive for oil on its' southern lease (ADL 399112), this acreage is capable of commercial gas production as evinced by the Pan American West Foreland No. 1 gas well. Stewart recognizes that these gas reserves are not considered in Conservation Order 332, however, these reserves and the associated lease are an important part of the future development scenario for the West McArthur River Unit. We hope that this information is useful to the Commission during the development of the West McArthur River Field. If you have any questions or comments, please contact the undersigned at any time. Sincerely, Jesse Mohrbacher, Vice President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company RECEIVED MAY 20 1994 Naska Oil & Gas Cons. Commission Anchorage cc: W.R. Stewart, Stewart Petroleum Company 715 L Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258-5557 E & P SERVICES, INC. May 18, 1994 David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-31 92 Re: Minor Correction and Comment to Conservation Order No. 332, Pool Rules for the West McArthur River Field Dear Chairman Johnston: Stewart Petroleum Company (Stewart)'would like to inform the Commission of a minor discrepancy in the findings of Conservation Order No. 332. In Finding No. 12, the seismic data is referenced as being 1960's vintage and unmigrated. In actuality, the data was acquired in 1980 and is unmigrated. This error was stated by Stewart personnel during testimony at the Pool Rules hearing on February 4, 1 994. Stewart would also like to comment on Conclusion No. 2 of the Conservation Order. Although the West McArthur River Unit has not been shown to be productive for oil on its' southern lease (ADL 399112), this acreage is capable of commercial gas production as evinced by the Pan American West Foreland No. 1 gas well. Stewart recognizes that these gas reserves are not considered in Conservation Order 332, however, these reserves and the associated lease are an important part of the future development scenario for the West McArthur River Unit. We hope that this information is useful to the Commission during the development of the West McArthur River Field. If you have any questions or comments, please contact the undersigned at any time. Sincerely, Jesse Mohrbacher, Vice President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company RECEIVED MAY 2 0 1994 Alaska Oil & Gas Cons. CommissioD Anchorage cc: W.R. Stewart, Stewart Petroleum Company 715 L Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258-5557 ?, 02 I':'A r..:, E: ~ ~l.t> L. NLIH~ER: AGFCFEMENT TYF'E ' NOJ'ZFZ[;~TZGN NOTIFICATION NAMe. 'I,' 0 T A L.. A CR E ACRES' £ll~ ~,'I,,tC)RE OF"FSHORE: 4, i 75 ,, 0<-)¢ L': D E (:) N,S' l"l D R IE O F' F',.¥ t"t 0 F'~ i?:: ", 'D . ':') (') ~) 4, f'7.5 ,, I.;) ~,,j N i:!: F;.: I,.,,f g I:( i( :1: N r:,;, Ir4, 0 Y A I. 'f' ¥ "" ]: D v ,,. ...... ,, ,~,~,,...,t",~,::. :1: N ..... '"' ....... " ..... '1354 WAGNI,.:.k ,' RT[:~HA!:~D., f!: ~) ~ (-) (') O (') e () O 2, eoOer.'~o(,),, .,,..6,,,:,t I I::.NI::.A TEI(NA ]:NVk;,,S f Niii:F!T,S, ,...-, .:> 4 ..(:., ~.> C;C~t..E., OHAFtL, Y Iii: ('), (') ~,') (') (') ~) ~) (") i .,, 0 0 (') (-) 0 (,) (') 6488~ STI:~OEL;i(ER., 1,4 ]: L, t.., :t: ~,.h ~ (:;, i ¥"I '2~:J,!;"¥' E; .'J (:t F'~ T F'E'-'''';~'''''~ '- ,') (,) (') 0 (.) 0 (.) ,~'~ , ,,,,,,,,.,..,U~ CC. IidPAi'4Y, '5(.).~,' ' ' - 1"?0:';',., 9'7 ,S"f I:;.WA!:~'T., .... ~:t:L, LI At"iI",,: ., i ~ ,,'") I.".' 19(:)f:t~ MEDEi*iA I""AH]',t.,.Y TRU,.?T M]:L.i,.IE 092(-)9 ,,'~HO6R.T.'N, F'I::/,,~NK L. (').., 28947 ,.~LN,SOk O:I:L. &(.,.~,.~," ' .LNC,. , ~7083 RENI"R[}, ~.].'LLZ~ D t 9087 hL, D. ONAI,.,,T;,, ,,,.[),,,H',I C; O. o<)oo(fee O, 0625~:,e,e I ~OB~,.t t"tCDL']NAL. I), U,J;l:l,,L;t:Ai'/ H e,eOOeOe(.) 0, (:)625000 .,:. c;,,~. .,;. ]E~LJ~,~E:,S',,~', I..L.!:tYI) .~ o,eeo~oo 0,,0,5250,0(> I'7089 L,:I:i4E:$'FONE OIL & .[;.A~ CONF'AN'I;, 1 9 (') B[$C:AI,.,I) E:t'.,~I,,J 00 I) I:~t E v. T R U.,~' T ,'",, . ,. , 1,1,... I.'I'H 0 t 9(')9(.) ALEU'I ......'F' THE (.) I.,OR 131:? A '¥' :[ C) N , , , .,, " 'N .... J -', t 9086 GAkVr:.Y l;~l!i'.V.rl£:t..~,~]..}[:: l'[.~lJ,S"l' JOI, IN f ? 4 f '? ": "" BI,II'~I'~L)~,S', (H/W), JANE: V ~94~8 l::'"", ..... , ..... ," I ':?4 I.,~; F'OL, AR:I:,.¥ FUN.'D, t.,~ F',,, (,)., t 9'4 i ":' ....... '5 ,=. &',.~.N6YC]Nr;. Ctll:l., F~I:t;F'];N:i:NG i~984 F::t:CHAF~D,S'ON, H/H, JACK H I998:.',),,I:.:U,,,,,.,,E.$~.,'," '"" .... JA,S'ON N. O. "';')0(')(')(')0(') O, (')':'~f 254,)0 1 9"?'3t BURC;E,.~,.?, C'vRE[i. ORY S'., i 991i1':.~IZ,~L!t'.~GI:,S'5', Jl.',':lr.'F.' I., · ,-~,,,~ - , ,, ,...,..6;,,~ I'HURN,,~N, JANE.$ L. 2(.) J 7"~' [~"' ............., "' , 2(,)I"?;~ }'.~OY]<(:), ~:.!,~i,.,AR F'¢~LJL (-) 2(-)~'7"? ,S"i'ID:WA~T Fnl"t:l:L.Y I'RU,S'T, O,OOO(.)OOO O, 1 2506,.ee ,l) '1 I~, ,,.(')369 STf£WAR'F I'I:~LJ,ST, TI. ii: RE:I.:~ECCA L 0. O[-)O(.)¢O(.) 0 ,, t "::,~. ., (.) (-) O (-) .... '" 'fl.,ll: AUDRA LAD 0 (.)000'~(~(.) O, jo,:-' 2(.) I '76 ,.~'I'I',;.NHlkT 'l h: LJ ,$' "F ,, . , 7,~,')3 ,~'T'i:.WAR 1 RE;I:t~:,C,C,A I,,. ~Pl't- 8-94 FRI 10:24 · RUN DATE:'I2/"I RUi',! 'I't hFS: i $; 6'2 ST AK/DIV OIL AND GAS FAX NO, 9075823852 ~ I P, 03 F.~.'S. REE MSN T I'YPIE ~, NOTIFIF~ATION iWO'l' Z FIC~T.T. ON AND gA~' ~"I'EWr~RT I-F. TROLEUN. COMPANY OWNER '.2.,.)3 ~ ~ '1 ~2~ 2825 19~ 7 ~94f2 i 99 ~ 5 ~ 99~2 ~ 998 ~ 2263 2~I 7~ 20t 7~ 29I 7? ..... '>07',~7-. NAN/;,' .WA[.;NE:R, I:.I .I: OI-tA RD £AI..E: 4~), & N i;, ~.i '!' E: K N A ,1: N V I::,.~' 'T' i'i E: N '~'5' , C 0 I,,. ]:::, & t"IA 1'< I.. Y ~ T "" ..... ~ ........ ~ ...... ~ ' ' rVJE&KI..I~, Will,," 'r~..~¢l G ,S' T 1: W A J'~ T F' I:: T' R O L. E:tJ t ~ O ~ ]: N 3 O N, J Ot,,1N C, ALDI:.NWOOD NE:V, l'l,~u,~"r~ ALE:UT [;OI'~'t'"Ui.~I~T:[ON, THE:, GARVEY RE:VOG~BLE: 'I'RLJ$'[, JOHN MEi)I=t'iA FAN 2: LY TRUS 7, N '.1: L.L I E ~'i'-IOG R t N, F 1;~ hNK L ~'EN,~OR OIL & ~AS', RI:NI;:'F~O, ~II..I.I~fl HC;DON~I..]), JOHN N~;DONAI. D, W:~JL.I..:[AN H ~'~LJr~&j:.,S S, LLOYD A BL.IRI:~OW,~, (H/W), JANt: V AND F' E R,S' 0 N,~', ( H / W ),i~ 0 B S R';' & D ~:: A ,%'~AN~;YON~; O;J:L R I: f,'.' J: N :r, NG R]:C:I..IARD.~'ON, H/W, CLINTON, EL.,I ZAB~'FH BURC, E~;,S', ~ND& BREEZE IkRE..~L &~BL.E BOYI(O, E:~C~AR PAUl.. ,STE:~ART 11;~U5'1', THE RE:BECC~ L b'7'E~l'~'l' TRUST, TJ-I~ ~U])R~ L~D ,S'I'I~.~ITF, I'll=BEC,t,& L. RI.,IEE, J]:N KLJ ~. ,~, __~. 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING FEBRUARY 4, 1994, 9:00 O'CLOCK A.M. TRANSCRIPT OF PROCEEDINGS HELD AT THE ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA RECEIVED FEB 1 4' 1994 Alaska Oil & Gas Cons. Commission Anchorage R & R COURT REPORT ER.S 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 pROCEEDINGS CHAIRMAN JOHNSTON: I'd like to call this hearing to order. I note the time is approximately three after nine o'clock. The date is February 4, 1994. We are located in the Commission's offices, located at 3001 Porcupine Drive, Anchorage, Alaska. My name is David Johnston, I'm chairman of the Commission; to my right is Commissioner Russ Douglass; and to our far right is Laurel Evenson, of R & R Court Reporters, who will be making a transcript of these proceedings. The seat to my left is currently vacant right now, but we hope to be joined by Commissioner Babcock shortly. He had some difficulty coming into town this morning because of the icy conditions out in the valley. So with that said, I'd like to ask Commissioner Douglass to read the public notice that was provided. COMMISSIONER DOUGLASS: Notice of Public Hearing,, State of Alaska, Alaska Oil and Gas Conservation Commission. Regarding the application of Stewart Petroleum Company for a public hearing to present testimony for classification of a new oil pool and prescribing pool rules for its development in the West McArthur RiVer Unit in Cook Inlet. Notice is hereby given that Stewart Petroleum Company has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony for classification and prescribing of pool rules for development of R & R COURT REPORTERS 810 N STREET 1007' 'JEST THI'RD AVENUE 277-0572/Fax 274-8982 z72-7~15 ANCHORAGE, ALASKA 09501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 a new oil pool in the West McArthur River Unit. The proposed development area is located in the western portion of Trading Bay in Cook Inlet. An oral public hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 a.m., on Friday, February 4, 1994, in conformance with 20 AAC 25.540. Ail interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special accommodation, auxiliary aid or service, or alternative communication format in order to comment on the proposed action, please contact Diana Fleck at 279-1433 by 4:30 p.m., January 25, to make any necessary arrangements. Signed Russell A. Douglass, Commissioner, Alaska Oil and Gas Conservation Commission. Published January 4, 1994. CHAIRMAN JOHNSTON: Thank you. These proceedings will be held under Commission regulations, specifically 20 AAC 25.540. Those established are procedures for conducting hearings on these matters. It does allow for sworn testimony or unsworn statements. Greater weight will be given to sworn testimony. If you wish to be considered an expert witness in these matters, we would ask that you state your qualifications. The Commission will then rule as to whether we would consider you an expert witness in the matters before us today. R & R COURT REPORTERS 1310 N STREET 277-0572/Fax 274-898~ 1007 IdEST THIRD AVE#UE 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The order of testimony, we'll have the applicant going first and then we will follow that with any other individuals that would wish to make a sworn statement or to provide an unsworn statement. At the conclusion of testimony, we will allow an opportunity for questions to be asked. If you do have a question, however, we would ask that you would write those down on a piece of paper and forward it to the front here, and if we feel that the question is germane, then we will ask that of the individual testifying. A written transcript of these proceedings will be made and will be part of the public record in these proceedings. If you wish to Obtain a copy of the transcript, we would ask that you contact R & R Court Reporters directly and make those arrangements for yourself. At this time I'd like to ask the applicant to identify themselves. Please, step forward. MR. MOHRBACHER: My name is Jesse Mohrbacher. I'm vice president of Fairweather E & P Services, and I'm representing Stewart Petroleum as agent. CHAIRMAN JOHNSTON: Mr. Mohrbacher, are you the only individual that will be testifying on behalf of Stewart Petroleum? MR. MOHRBACHER: No; there are three other individuals that will be testifying. R & R COURT REPORTERS 810 N STREET 1007' gEST THIRD AVENUE 2T/'-O572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON= Okay. Do you and these other individuals wish to offer sworn testimony? MR. MOHRBACHER: Yeah, I believe so. CHAIRMAN JOHNSTON: Okay. I would ask then that the. three of you please step forward and identify yourselves for the record, and I would ask Commissioner Douglass to swear you in. MR. MOHRBACHER: Okay. There will actually be four. CHAIRMAN JOHNSTON: That will be fine. Would you please stand and identify yourself. MR. MOHRBACHER: Again, I'm Jesse Mohrbacher, .representing Stewart Petroleum Company as agent. MR. MANGUS: I'm Marvin Mangus, an expert witness, representing Stewart Petroleum. CHAIRMAN JOHNSTON: Thank you. MR. BORNEMANN: I'm Ted Bornemann, from Schlumberger, and I have done some work for Stewart Petroleum on behalf of my company. CHAIRMAN JOHNSTON: Thank you. MR. MILLS: I'm Jim Mills, of Halliburton Energy Services. CHAIRMAN JOHNSTON: Thank you. COMMISSIONER DOUGLASS: Would you all please raise your right hand? R & R COURT REPORTERS 810 N STREET 1007 kJEST THIRD AVE#UE 2F'/'- 0572/Fax 274-8982 272-7515 ANCHORAGE, ALASEA ~501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 (Oath administered) IN UNISON: I do. COMMISSIONER DOUGLASS: Thank you. CHAIRMAN JOHNSTON: Thank you. The individuals are properly sworn, and you will remain sworn for the duration of these proceedings, and that will be for the remainder of the day, and if we feel it necessary -- find the need to recess and continue this hearing on a remaining day or another day, you will be continued to be sworn in. Mr. Mohrbacher, if you would like to present your introductions and begin the proceedings. MR. MOHRBACHER: Yes, you bet. As has already been made mention, other individuals besides myself will be testifying on behalf of Stewart Petroleum Company. Mr. Mangus will present the current structural picture of.the West McArthur River field and provide the Cook Inlet basin geology relative to the West McArthur River field. Mr. Bornemann will be describing the reservoir zones and the log analysis related to those zones. Mr. Mills will be presenting drill stem test parameters and data collected from the drill stem tests on the two existing wells as McArthur River field -- West McArthur River field, and the fluid properties associated with the reservoir fluids. I would like to give a brief overview of the project, the West McArthur River project to date, and the project was R & R COURT REPORTERS 810 N STREET 1007 UEST THIRD AVENUE 2T'/'- 057~/Fax 774-8982 27~-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 7 initially started with the drilling of the West McArthurRiver Number 1 ..... CHAIRMAN JOHNSTON: If I might interrupt you there before you proceed any further. I presume you wish to be considered an expert witness in this or are you just providing an overview? MR. MOHRBACHER: I'm providing an overview at this point. CHAIRMAN JOHNSTON: No expert witness considerations then? MR. MOHRBACHER: It may be necessary at a later time, but I don't anticipate it or only if the Commission asks a question which may require that. CHAIRMAN JOHNSTON: That would be fine. Please proceed. I'm sorry for the interruption. MR. MOHRBACHER: Okay. 'The West McArthur River project was started with the spudding of the West McArthur River Unit Number 1 exploratory well on June 23, 1991. That well penetrated the Hemlock conglomerate on November 13, 1991, and discovered oil in the Hemlock conglomerate, West McArthur River field structure. Subsequent to that discovery of oil the well was tested and commerciality was confirmed. A disposal well was. drilled in January of '93 for disposal of waste drilling fluids and cuttings from the discovery well and cuttings and waste drilling muds to be generated from R & R COURT REPORTERS 810 # STREET 1007 k/EST THIRD AVENUE 2'77-O572/Fax 274-8982 272-7'515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 8 additional drilling activities. A confirmation well, the West McArthur River Unit Nu~nber 2 well, was spotted in April of '93, and directed to a bottom hole location southeast of the discovery well. The Stewart Petroleum elected to run an intermediate formation microscanner run to determine the axis of the structure. It was determined at that time that the well had already crossed the axis of the structure. The well was plugged back and redrilled to a new bottom hole location to the north. That will has subsequently been renamed as West McArthur River Unit Number 2-A. The West McArthur River Unit Number 2-A was TD'd on August 24, 1993, and completed on October 26, 1994 -- excuse me, 1993. Two additional benches in the Hemlock conglomerate were found to be productive in the Number 2-A well whereas one bench was productive in the Number 1 well. Both wells are currently in the production testing phase, and Stewart Petroleum is in the process of procuring tangibles for a March/April pipeline construction project. That's the current status of the West McArthur River project. At this time I'd like to turn it over to Marvin Mangus to present the structural picture and geological of the prospect. CHAIRMAN JOHNSTON: Before you return to your seat, Mr. Mohrbacher, just a couple of questions for you. The document that you submitted to us, do you consider this your R & R COURT REPORTERS 8'10 N STREET 277-0572/Fax 274-8982 1007 k'EST THIRD AVENUE 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 plan of operation and development for this pool? MR. MOHRBACHER: Yes, we do. CHAIRMAN JOHNSTON: And do you feel that the plan of operation and development prevents waste, protects correlative rights and insures maximum recovery? MR. MOHRBACHER: Yes, we do. CHAIRMAN JOHNSTON: Thank you very much. COMMISSIONER DOUGLASS: Are you going to enter it into the record? CHAIRMAN JOHNSTON: Yes, why don't we enter that into the record and mark it as Exhibit 1, and that will be the application and cover letter. The next'witness, I guess, is Mr. Mangus. MR. MANGUS: Okay. This is Exhibit Number 1, 2, and this would be 3 ..... CHAIRMAN JOHNSTON: Okay, ..... MR. MANGUS: I would suggest the nomenclature, this is the stratigraphy of the Cook Inlet, and this is the ..... CHAIRMAN JOHNSTON: Well, let's mark those Exhibits Numbers 2, 3 and 4. MR. MANGUS: 2, 3 and 4? CHAIRMAN JOHNSTON: Right. MR. MANGUS: Oh, okay. CHAIRMAN JOHNSTON: Okay, and if I could have R & R COURT REPORTERS 810 N STREET 1007' bEST THIRD AVENUE 277-0572/Fax 274.-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 10 MR. MANGUS: You can have the chart. CHAIRMAN JOHNSTON: I'd just note for the record that Exhibit Number 2 is Stratigraphic Nomenclature, Cook Inlet Basin, Alaska; Exhibit Number 3 is Formation Thickness Drill, the Stewart Petroleum West McArthur River Number 1 Well; and Exhibit Number 4 is the Structural Map for the Accumulation. Mr. Mangus, do you wish to be considered an expert witness in this matter? MR. MANGUS: Yes. CHAIRMAN JOHNSTON: If you would please state your qualifications. MR. MANGUS: Qualifications. I have a bachelor of science degree in earth science, master's degree in geology, doctoral work in geology. I've been associated with Alaskan geology for the last 47 years, all over the state of Alaska, working geology essentially in -- all over the state of Alaska, primarily as a surface man in geology, and also subsurface work in the Cook Inlet and the North Slope of Alaska and Arctic Canada. Okay, ..... CHAIRMAN JOHNSTON: How long have you been specifically working this area here for the West McArthur River Unit? MR. MANGUS: Three years. R & R COURT REPORTERS 810 N STREET 1007 J~'EST TH[RD AVENUE 277-0572/Fax 27&-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 him? CHAIRMAN JOHNSTON: Three years. 11 You'll accept COMMISSIONER DOUGLASS: Yes. CHAIRMAN JOHNSTON: Mr. Mangus, we're very impressed by your qualifications and consider you an expert witness in these matters. Before you proceed, are you picking him up okay, Laurel? COURT REPORTER: Yes, thank you. CHAIRMAN JOHNSTON: Okay. MR. MANGUS: I'll get the mike over here. Can you see this all right? CHAIRMAN JOHNSTON: Yes, we can, but I think it would be helpful if we could just turn around, show it to the audience so ..... MR. MANGUS: That's okay. Maybe I could hang it up. CHAIRMAN JOHNSTON'. up, that would probably be the best. In fact if we could hang it Are you going to be referring to it frequently? It might be best to hang it up over on that wall. (Off record comments) MR. MANGUS: What I did here was just take the nomenclature reviews of the Cook Inlet Basin that was written by Calderwood and Fackler, in 1970, and I won't go into too much of the geology because I think everyone in here knows R & R COURT REPORTERS 810 N STREET 1007' k'EST TH[RD AVENUE 277-O572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 12 pretty much the geologic history of the Cook Inlet. And the other exhibit here is where we drilled the first West McArthur -- Stewart Petroleum West McArthur River Number 1. As you well know, the Cook Inlet tertiary sediments are of the Tertiary Age were deposited in essentially an intermontane basin between the Chugach Mountains and the Alaska Range. The source area varied from time to time with orogenies taking place in between the deposition. And they range in age from -- here in the Cook Inlet as the younger tertiary beds from Eocene on up, the rest on our unconformitably on the Cretaceous Jurassic and older tertiary Paleocene Age which outcrops uP around in the Palmer area and the Chickaloon and the Sedaka (ph) Formations. The well is approximately -- as Jesse said, we went atop the Hemlock conglomerate at about 9,200 and some feet. The Number 2 area shows where -- diagram, rather, shows that the Sterling Formation in the well, in the area, is absent where we drilled the well. We spotted the well in the Beluga Formation. We did not have a complete thickness of the Beluga Formation. We felt that some was eroded away. We have essentially had 3,326 feet. At the.top of the Tyonek was picked at that massive coal bed which the industry and the Geological Society uses as a top, went through the Tyonek .which is a series of coal beds, conglomerate sandstone, shells and pyroclastics. We bottomed out on that or topped the Hemlock at 9,416 at the -- in the well bore. The Hemlock was essentially 385 feet or 400 R & R COURT REPORTERS 810 N STREET 1007 UEST THIRD AVENUE 277-0572/Fax 27/,-8982 272-7515 ANCHORAGE, ALASKA g~501 10 11 12 13 14 15 16 17 18 19 2.0 21 22 23 24 25 13 feet thick. We went into the West Forelands only 51 feet, and we definitely had a lithologic break, and we felt very sure that it was West Forelands formation, so we suspended a well because of no oil and gas shows. The Hemlock from top to bottom had good shows in it. Now where I derived it at this map, it's -- I'll skip all the other geology, but I mapped it on the top of the Hemlock Formation and you saw the existing wells plus two Stewart Petroleum wells; Stewart Petroleum West McArthur River Number i and West McArthur River Number 2-A. The top of the formation, it's an asymmetrical -- I feel it's an asymmetrical structure. The western flanks being a little steeper than the southern flanks or -- I'm sorry, I'm up the Brooks Range here, eastern limb is a little less steep than the other ones.. The average dip in here we"ye considered 28 to 30 degrees on the data we have available. The axis for the anticline was established by a seismic high here at this shot line FW-1 -- or WF-1, and I took an equal distance point between the Stewart Number i and the Stewart Number 2-A, because they ended up each being on the flank of the anticline, and the Number i being on the east flank of the anticline, and the Number 2-A well being on the west flank of the anticline. But you see the structure strikes essentially northwest position. They took -- as I say, it took -- established the axis through here, through the high on the R & R COURT REPORTERS 810 N STREET 1007' k'EST TH[RD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA ~501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 14 seismic line. Now this is apt to change because this seismic is very old and was not migrated. There's not much we can do with it, so the axis may shift a little bit here, but we feel it's put in here, but it could change. But that has no relevance to -- change to me as far as the production is concerned. We establish here that the oil-water contact is at 9,600 feet. Keith Calderwood felt it was 9,650 because of these drill stem tests in the previous Pan-American wells and the shallow West Foreland Unit Number 1 well, and -- anyhow, essentially the structure is about the same as when Calderwood first proposed it. The structure's been known since the 1950s, has been called at one time the West Forelands Unit structure, but we now consider it -- call it the West McArthur River structure, and that's the way it was established by the state. I guess I better get over here. The green is the oil-water contact. This Pan-American well has some gas in it, and in the Tyonek we thought it was a structure trap. There's something here that goes on the -- did not have enough evidence to pin this down, and hopefully there's a fault there so there's -- could be some possible oil in this area. The gases seem to be high in nitrogen and nitrogen is associated with petroleum, and also nitrogen is -- and it's similar to the other analysis of the gases in the rest of the Cook Inlet. R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277-O57~/Fax 274-898~ 272-7515' ANCHORAGE, ALASI(A 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 15 We propose another well, which will be to the north here. We don't know exactly where yet, but we need this, and with that third well, we feel we can pin this structure down a little better than we have it now. But essentially we feel this is it. We. independently mapped it from what Keith Calderwood did and Mr. Bornemann and I came up with essentially the same structure. So we feel pretty confident with the control we have and everything that this is the configuration of the West McArthur anticline. It's essentially from here to here, essentially about five miles long and about -- (clears throat) excuse me, a mile and a half across. I used a 30 degree dip on the north side and it could be a little tighter than that. At the time we seen maybe that there could be some other tensional faulting, transfers falling across, but essentially all your thrusts, as you well know, are usually in the -- essentially, roughly a north/south lineation. These -- of course there's different faults. These are usually high angle reverse faults tied in, and these, of course, are tensional relieving. And I don't know that I have much more to say about the structure. To me it's quite obvious the way it runs, and with that I'll just close it because I won't go into the -- as I say, the original geology because I think we're all familiar with that. And we had no good oil and gas shows in the rest of the R & R COURT REPORTERS 810 # STREET 1007' UEST THIRD AVE#UE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 16 formations penetrated by the drill. It was strictly dealt with in the Hemlock Formation and hopefully with this well -- the third well should be structurally higher, maybe we'll have some production in the West Foreland. And so that's about all I have to say right now. CHAIRMAN JOHNSTON: Questions? COMMISSIONER DOUGLASS: You mentioned your seismic data. Did you just use that seismic data in determining that apex, that structural ..... MR. MANGUS: No. COMMISSIONER DOUGLASS: ..... or is there additional? MR. MANGUS: That seismic data has been used for years, and Calderwood uses itoh their original proposal and we've looked at it through the years and they had another chap look at it, and so it's -- I use it because that was the high on the line. So just to get this oriented in essentially the right position I just picked it from that old seismic line. CHAIRMAN JOHNSTON: What is the date on that seismic data; do you know? MR. MANGUS: Well, it's in the '60s, but Jesse, do you know? '62 or 3, in there. MR. MOHRBACHER: '60s, I think. MR. MILLS: I believe there was some -- there was some other data in '$1. R & R COURT REPORTERS 810 N STREET 1007 MEST THIRD AVENUE 277-05?2/Fax 774-898:~ 27~-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 the data was. MR. MANGUS: MR. MILLS: MR. MANGUS: 17 Do we have that? I can't pin a date down. Yeah. No, I don't ..... CHAIRMAN JOHNSTON: I was just wondering ..... MR. MANGUS: ..... know either. CHAIRMAN JOHNSTON: ..... what the vintage of HR. MANGUS: We can certainly get a hold of it, but that seismic data is expensive. CHAIRMAN JOHNSTON: And difficult to obtain. MR. MANGUS: The independents can't go out and buy things like the majors. CHAIRMAN JOHNSTON: We understand. What -- hold on one moment -- sometimes with the air base nearby it makes it difficult to conduct business. Would you specifically list for us the data that you used to draw the structure? In other words, what was your well data that you used, specifically the data from which wells? MR. MANGUS: I used -- all the wells are plotted here. Let me put my cheaters on here. We used the Pan-American West Foreland Unit Number 1, Pan-American West Foreland Number Unit Number 2, Pan-AmWest Forelands Number 1, Stewart Petroleum West McArthur River Number 1, and the Stewart Petroleum West McArthur River Number 2-A. CHAIRMAN JOHNSTON: Did you use ..... R & R COURT REPORTERS 810 g STREET 1007 WEST THIRD AVENUE 277-O57~/Fax 274-8987. 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 18 MR. MANGUS: I used the top of the Hemlock as a base, subsea, naturally. And the KB on the well was 165 feet, and from there I went and -- and also for the oil-water contact I used these drill stem tests. This one and this one, Pan-Am had oil shows in it. The Number i was a poor test in that they used the old wire line test because it was drilled in the early · 60s there, and of course most of the industry always felt they didn't test that properly. But we used this as the oil-water contact, and we also used this essentially for the oil-water contact. Right now we do not have enough control yet, we're up in the air, and.Mr. Bornemann will talk more about the oil-water contact in the two stored wells. CHAIRMAN JOHNSTON: Could you trace on the map up there for me where you have the oil-water contact drawn? I can't see it from my seat here. MR. MANGUS: Yeah, we have it drawn on the 9,600-foot contour here. We come around and this Pan-Am well, the West Forelands Number 2, it was drilled at 9,628"TVD, and so we came right along here, then back up and we used the 9,600 foot contour, and we used this control here to show West Foreland Unit Number 4. It produced oil -- I think it was 41 barrels a day in the Tyonek, and we feel that it was a fault trap in there that had migrated probably maybe out of the Hemlock, up into the -- that's anyone's guess at that time. R & R COURT REPORTERS 810 N STREET 1007 k'EST TH%RD AVENUE 277-O572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA ~01 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 19 CHAIRMAN JOHNSTON: What is your evidence for a productive rock in the southern part there, south of that fault? Is there any well data in there? MR. MANGUS: There is one, it's a gas well, it's Pan-Am's, it's a gas field. And, again, we felt it was a fault trap, it was wet in the Hemlock, but we thought we had a fairly good show. But we feel that maybe this is a continuation of the plunge because it's a fault trap. CHAIRMAN JOHNSTON: But you do not have any direct evidence that would suggest that the fault trap is oil bearing? MR. MANGUS: No. CHAIRMAN JOHNSTON: Okay. MR. MANGUS: This is more of an optimistic ..... CHAIRMAN JOHNSTON: Right. MR. MANGUS: ..... thing down the road. But this will basically be drilled. CHAIRMAN JOHNSTON: You do have plans to put a well in there? MR. MANGUS: Well, they're negotiating on that. CHAIRMAN JOHNSTON: If things work out? MR. MANGUS: Yes, if things work out. COMMISSIONER DOUGLASS: Did you use any data from the Number 2 well? I know it didn't get down to the R & R COURT REPORTERS 810 N STREET 1007 td~ST THIRD AVENUE 277-057~/Fax 274 - 898,?. 272-7'315 ANCHORAGE, ALASI(A 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Hemlock. but MR. MANGUS: original. 2O 2 -A? COMMISSIONER DOUGLASS: NO, Number 2, the MR. MANGUS: Yes, I used evidence from the Number 2, because that's why we turned and went the other way, because we were about 300 feet low to the Number i well and the Number 2 well. So then we turned it, and we essentially turned and we went up the nose of the anticline and the south plunge paralleled the bedding there, and when we ended.up I was on the well we completed. We ended up -- we had a slim hole string in there and we just couldn't control, but -- so we couldn't cut -- penetrate across the bedding; we had to run parallel there with it. And we were fortunate we could even do that from the condition that hole was in. But every well is plotted on there,, we used geological data from it. CHAIRMAN JOHNSTON: Have you generated any cross sections of the accumulation? MR. MANGUS: No. CHAIRMAN JOHNSTON: Would it be possible to have that done as part of the information that we could put in the file., just to have a couple of cross sections going east/west, north/south? Would that be possible? MR. MILLS: Yes, it would. It would have to be R & R COURT REPORTERS 810 N STREET 277*-0572/Fax 274-8982 1007 ~IEST TH]RD AVENUE 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 21 at a later time though. CHAIRMAN JOHNSTON: Yeah, that would be fine, but it would be nice to get a cross section or two in the public record on this, if you could generate something for us, we would appreciate that. Thank you. Okay, in summarizing again, your evidence for the oil-water contact comes from which wells? HR. MANGUS: Well, the Pan-AmWest Foreland Number 1, Pan-AmWest Foreland Number -- using the Number 2 well and two existing wells, and the Shell Number 4 well. CHAIRMAN JOHNSTON: Okay. Excellent. HR. MANGUS: And that's about it. CHAIRMAN JOHNSTON: Any other questions? COMMISSIONER DOUGLASS: No more questions. CHAIRMAN JOHNSTON: At this time, Mr. Mangus, we have no further questions for you, but we would reserve the right to call you back ..... HR. MANGUS: Fine. something else. CHAIRMAN JOHNSTON: ..... later.if we think of Thank you. Next witness then. HR. BORNEMANN: I'm Ted Bornemann, and I'm here to testify as an expert witness for Stewart Petroleum. CHAIRMAN JOHNSTON: Mr. Bornemann, if you would care to state your qualifications. HR. BORNEMANN: Yeah, I have a Ph.D. in R & R COURT REPORTERS 810 N STREET 1007' gEST THIRD AVENUE 277-057~/Fax 274-8982 27~-7515 A#CflORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 22 geology, and I have been working for the last 12 years for Schlumberger Well Services, doing geological well log interpretations, particularly dip meter and image interpretation, and I have been working in Alaska for a total of over eight years. CHAIRMAN JOHNSTON: And you have specifically worked on these wells? MR. BORNEMANN: Yeah, I have specifically worked on all the wells, including the old wells since, I believe, this summer of '92. CHAIRMAN JOHNSTON: Thank you. COMMISSIONER DOUGLASS: No objection. CHAIRMAN JOHNSTON: The Commission will accept you as an expert witness in these matters. If you'd please proceed. MR. BORNEMANN: What I was asked to present and what. I'm doing here is the reservoir -- the proposed reservoir zonation for the McArthur River Unit, and the -- I have brought. two logs. for the record of West McArthur River Number 1 and the West McArthur River Number 2, 2-A. These logs may be somewhat of a novelty but they are based on the interpretation of electrical information images that Stewart Petroleum has acquired in both wells. These -- and I'included a few exhibits of the actual images, some poor copies, actually, but I can actually show you the conglomeratic nature of -- see actually R & R COURT REPORTERS 810 N STREET 1007 k'EST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20¸ 21 22 23 24 25 23 pebbles -- you see pebbly sandstones and, in this case, you can see a sandy siltstone separating two conglomerate units. Now I have divided the Hemlock. Also the West Foreland is also conglomeratic but it's of a slightly different nature. So I have -- there's no doubt for me where the top of the Hemlock is, and then I divided the Hemlock into a total of six benches, starting from the top of the Hemlock. So the top of the Hemlock is -- and I placed the top of the.Hemlock at the uppermost conglomerates -- the massive conglomerates -- more massive conglomerates section which is in line with the traditional Hemlock pick used in the Cook Inlet, okay. Plus right above here we get more into the Tyonek deposition, basically more flat plane, a lot of coal swamps and occasionally pebbly sands as well in the Tyonek. Overall, therefore, the deposition of sequence of the Hemlock is dominated by conglomerates and pebbly sandstones. The various conglomerate benches are topped by a silty sandstone'or sandy siltstone which are most likely impermeable or they could be permeable, but I don't think there are good reservoir rock, okay, they're most likely producing. And each sequence represents a depositional sequence in the sedimentalogical sense that I would think we have a major event depositing conglomerates, et cetera, and then we have a -- call it a quiet time, a less energy time and we get the sandstones, et cetera. And we have six of these sequences. R & R COURT REPORTERS 810 Id STREET 1007 k'EST TH%RD AVENUE 277-0572/Fax 27&-8982 2'/'2- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 24 This is roughly in line with the -- on the McArthur River Field proper and the bench, yes, I would think so. So I have not attempted any formulation across the ..... This one exhibit here, where I shut it down to show the correlation between the two wells, this is West McArthur River Unit 1, but we have all six benches, including the top of the West Foreland penetrated. Now in McArthur River Unit Number 2 which essentially turns into a horizontal well at the bottom part of the location, we do not penetrate the West Forelands, but we actually terminate in Bench 4. So we never even reach Bench 5 and Bench 6. And it correlates quite well. CHAIRMAN JOHNSTON: So within the productive intervals in the 2-A well are benches what specifically? MR. BORNEMANN: Okay, the wells Bench l, I would say Bench 2, Bench 3, and possibly Bench 4. CHAIRMAN JOHNSTON: Possibly Bench 4. What benches are being tested currently? MR. BORNEMANN: It is my understanding that the benches under testing is two, three and perhaps one, but Jesse Mohrbacher knows more about this. And the principal bench in Number 1 well is Bench Number 2. CHAIRMAN JOHNSTON: Very good. Okay. Maybe we could kind of straighten up these exhibits and get them entered into the record. MR. BORNEMANN: Yeah. Okay, I sort of have my R & R COURT REPORTERS 810 N STREET 1007 I~'EST TH[RD AVENUE 277-0572/Fax 274-8982 272-7515 ANCItORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 25 own -- if this is not contrary, I numbered this Exhibit 5, which is the ..... CHAIRMAN JOHNSTON: Okay. MR. BORNEMANN: ..... log for the McArthur River Well Number 1. CHAIRMAN JOHNSTON: Okay, and just for the benefit of the audience, again, this is the log being submitted. MR. BORNEMANN: This is the equivalent log for McArthur River Unit Number 2-A. CHAIRMAN JOHNSTON: And ~that will be Exhibit Number 6, the 2-A well. MR. BORNEMANN: Uh-huh (affirmative). Now we have -- these exhibits shows a correlation of the two logs basically between the two wells showing the various benches. CHAIRMAN JOHNSTON: Okay, and I note that we have Exhibits Number 7, 8, ..... MR. BORNEMANN: about it. It's at the bottom. The last one I haven't talked I need that. CHAIRMAN JOHNSTON: So we have then Exhibits Number 7, 8, 9 and 10, and basically showing -- that's 9 and 10 and 7 and 8. MR. BORNEMANN: I also took a look at the reservoir properties in terms of porosity and water saturation of the West McArthur River Unit. And this here is just a short R & R COURT REPORTERS 810 N STREET 1007' I/EST THIRD AVENUE 277-057~/Fax :~74-898Z :~72-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 example, we ran what we call a program that's called Elemental Analysis which computes porosity as well as mineral volumes simultaneously and hydrocarbon volume. CHAIRMAN JOHNSTON: And that's done in the Number 2-A well? MR. BORNEMANN: This example I brought here is actually from Bench 4 in the Number 2-A well, so one of -- I mean the best bench is Bench 2, for example. This is a not so good bench, if you wish, but it still has considerable oil content in it, okay. CHAIRMAN JOHNSTON: What specifically does that exhibit then tell us? MR. BORNEMANN: Well, it tells you -- the main thing is this track here shows the mineral percentage in terms of clays, quartz, and in this case moved oil and water porosities or oil field porosities/water field porosities. This track here is the porosity analysis that shows the total effective porosity. The green is the contained oil in the porosity, this section here. The lighter section is the water in the porosity. CHAIRMAN JOHNSTON: Do you feel those values would also be representative of the benches above? MR. BORNEMANN: No. There are better in the benches above. CHAIRMAN JOHNSTON: They are -- pardon? R & R COURT REPORTERS 810 N STREET 1007 I~EST TH[RD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 13 14 15 16 17 18 19 20 21 22 23 24 25 27 MR. BORNEMANN: They are better in the benches above. The porosities are far higher in Bench 2, and I was coming to that. The -- and this is again the water saturation in the Bench 4. I took a plot in the Cook Inlet in the Hemlock Formation. It .is not advisable to use water as a calculated water saturations from logs and predict any water production because one has to always consider water saturation as well as the effective porosity. And Floyd Bettis, from my company, years ago worked on the McArthur River Unit field with a lot of core data, and he established a water cut plot, and I plotted some points on these curves, meaning we have a line here -- the graph is divided into water -- calculated water saturation from logs going from the bottom -- 100% water saturation to 10% here. The abscissa is the porosity going from one. percent porosity to 50% porosity which is -- it's represented as a log lock plot. The straight line represents if the points plot on this line would predict the water cut of zero, no water whatsoever. I plotted some numbers. This first bent line is a water cut of 10%, so any points plotting between this line and this line, we would predict from log readings, would have a water cut between zero and 10%. The Bench 2 in the Number 2 well usually falls just in about the one or 2% range. So we predict very little if any water cut in the better benches on the Number 2~ well -- in the Number 1 well which is structurally R & R COURT REPORTERS 810 N STREET 1007' k/EST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 deeper -- I would say it's around 10%. predict from the log analysis. 28 That is what we would These exhibits would be Exhibits 11 and 12. These might well include 13 and 14. Just for the record, for the Commission, these are the papers that were published that describe the underlying methodology and also the application in the McArthur River Unit Field detailing this technique on predicting water cut. CHAIRMAN JOHNSTON: For the record Exhibit Number 3 is predicting water ..... COMMISSIONER DOUGLASS: 13. CHAIRMAN JOHNSTON: Excuse me, 13 is predicting Water Cuts By Use of Well Logs, by Floyd E. Bettis of Schlumberger; and Exhibit Number 14, Using Log Derived Values of Water SaturatiOn and Porosity, by R.L. Morris and W.P. Biggs, of Schlumberger. Any additional testimony? MR. BORNEMANN: Yeah, the -- I think for the record the porosity ranges in -- is roughly -- if I take the two works together 6% to about 23% is an average in the well Number 2 of 15%, and then the Number 1 well of 12% porosity. That's about volume porosity. And so otherwise any other questions? CHAIRMAN JOHNSTON: I guess what we need to establish right now, I think it would be helpful, is -- and you R & R COURT REPORTERS 810 N STREET 277-0572/Fax 274-8982 1007 ~JEST THXRD AVENUE 272-7'515 ANCHORAGE, ALASKA 99~01 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 29 may not be the person to answer this, but the type log that is going to be offered to identify the oil accumulation, what is that type log; are we talking the Number 1, the Number 2-A or what is your call on that? Basically we're looking for a well that would have a complete section of the productive interval that we're talking about. MR. BORNEMANN: That would really be decided by Stewart Petroleum. The Number i well is the only one which has a complete Hemlock section, however, the Number 2 well, I feel, represents better the hydrocarbon accumulation in the field. So ..... CHAIRMAN JOHNSTON: Perhaps I should direct the question then to Mr. Mohrbacher. Do you have any feeling on which log you want to use as your type log or have you thought about that? MR. MOHRBACHER: Well, we have discussed that, and with regards to what Mr.. Bornemann has mentioned, if you're -- it depends on what you're getting at. As far as the individual zones in the reservoir, Well Number i penetrates them all. However, zones not productive in well Number i have been shown to be productive in well Number 2. Possibly a type log would be a hybrid of the two. CHAIRMAN JOHNSTON: So from a geologic description you would offer West McArthur River Number 1 perhaps? And then for use to describe porosities, R & R COURT REPORTERS 810 N STREET 1007 MEST THZRD AVENUE 277-O572/Fax 27~-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 3O permeabilities in oil, water cuts and such, you'd offer number 2-A? I mean is that kind of what you're thinking of? MR. MANGUS: Your last question, I think maybe we can -- it's possible to make a composite of the two wells, we could probably do something like that. MR. BORNEMANN: Yeah, I'think in terms of the geological zonation Number I would be appropriate, and in terms of characterizing all the benches in terms of porosities and water saturations, et cetera, a combination of the two wells. COMMISSIONER DOUGLASS: Well, if we're dividing a correlatable section, it.sounds to me like the Number i well would be the ..... MR. BORNEMANN: If the main emphasis is on more the geologic and the zoning of the reservoir, then I think Number 1 is the well to use, yes. COMMISSIONER DOUGLASS: That would provide a vertical interval essentially that Would be correlatable across the structure? MR. BORNEMANN: Right, because the Number 2 well has the additional difficulty that is horizontal. We cannot even make a TVD log. I mean because all the data projects into one point. So ..... CHAIRMAN JOHNSTON: Well, let's recognize Number 1 then as the type log to describe the correlatable section that we're dealing with here. And then certainly we'll R & R COURT REPORTERS 810 N STREET 1007 MEST THZRD AVENUE 277-0572/Fax 274-8982 27'2-7515 ANCHORAGE, ALASEA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 31 recognize the 2-A for the benefits that it can give us in those matters. Any further comments then? MR. BORNEMANN: Only to comment on the map that Marvin made. He mentioned 30 degrees on the western flank. This is all confirmed by the dip meter data that was acquired, et cetera, so on the old wells, like West Foreland Unit Number 1, et cetera is -- all these old wells have dip meters in them and it's quite usable, so ..... CHAIRMAN JOHNSTON: Any questions? COMMISSIONER DOUGLASS: Not at this time, no. CHAIRMAN JOHNSTON: Thank you, Mr. Bornemann. We have no further questions for you at this time, but, again, we'd reserve the right to call you back if we need to. CHAIRMAN JOHNSTON: You've just handed us an exhibit. We'll mark this as exhibit, what -- Number 15, and it's titled West McArthur River Well Test Summary. And if you'd briefly describe what this tells us? MR. MILLS: These are some of the results from well testing on West McArthur River Number i and West McArthur River Number 2-A. Also on the bottom of that is the results of the PBT analysis that was taken on Bench i in West McArthur River Number 2-A. The results that I've summarized here have been presented to the Commission in the Well Test Reports, and basically the results are pretty much the same that the R & R COU R T R E P OR T E R -~ 810 N STREET 277-0572/Fax 274-8982 1007 k'EST T#ZRD AVE#UE 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 32 Commission already has. Basically in these tests the test objectives were short-term in nature, were pretty much after permeability scan to establish a stabilized flow rate to get some kind of a representative fluid sample. In most cases it was whether or not the zone produced oil or water, and to gather an initial reservoir pressure. COMMISSIONER DOUGLASS: Excuse me. We haven't had him introduced or ..... CHAIRMAN JOHNSTON: I was just going to do that. Yeah, we kind of jumped ahead. If you'd.identify yourself for the record and state your qualifications if you wish to be considered an expert. MR. MILLS: My name is Jim Mills, I'm with Halliburton Energy Services. I'll testify as an expert witness on the well testing part of this. I'll present the results of a fluid analysis, but I don't consider myself an expert. I have a bachelor of science degree in petroleum engineering, and I've been involved in well testing with Halliburton for the last ten years, the last five years here in Alaska. CHAIRMAN JOHNSTON: And you've specifically worked on these wells? MR. MILLS: I was involved in -- directly involved with the operations of this well. I reviewed all the analyses, although I didn't perform them myself. CHAIRMAN JOHNSTON: That's fine. R & R COURT REPORTERS 810 N STREET 1007 t/EST THIRD AVENUE 277-O572/Fax 274-8982 27'~-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 33 COMMISSIONER DOUGLASS: Okay. CHAIRMAN JOHNSTON: The Commission will consider you an expert witness in these matters. MR. MILLS: West McArthur River Number 1, we began testing this well on November 2 of '91. The net interval perforated was 110 feet, and the well flowed at a stabilized rate of 500 barrels per day for about a 26-hour period. In the summary table we show a number of fluid parameters. All of these in the above summary are derived from fluid correlations that we use in our analysis software, and are directly measured properties. In this well we found a permeability in the range of 183 millidarcies, although gravity was measured at 22 degrees, formation temperature 174 degrees, and initial reservoir pressure of 4,295. During the light-time portions of this test the pressure data was influenced by tidal effects, and we saw no evidence of any types of boundaries or impediments to flow. But like I said, the pressure data was influenced by those tidal effects. So I would not say it was definitive. CHAIRMAN JOHNSTON: What is your datum here on the -- in terms of your pressure? MR. MILLS: That's RKB. CHAIRMAN JOHNSTON: And depth? MR. MILLS: Yes. At mid par (ph) of depth of -- I'm going to have to give that to you in measured depth. R & R COURT REPORTERS 810 N STREET 1007 ~/EST THIRD AVENUE 277-0572/F~x 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 34 CHAIRMAN JOHNSTON: Okay. MR. MILLS: It would be 13,304, I believe is mid par of measured depth. CHAIRMAN JOHNSTON: And we are specifically looking at the Number 1 well? MR. MILLS: Yes, that's correct. Bench Number 2 in the Number I well was the only zone that was tested. CHAIRMAN JOHNSTON: Right. MR. MILLS: Testing on West McArthur River Number 2-A, we began that in September of '93. Bench Number 4 being the lower most zone, that's the first zone that was tested. We perforated a net interval of 12 feet. We estimated slug flow rate of 40 barrels per day. The well did not produce to service, and we calculated a permeability in the range of one millidarcy. Initial reservoir pressure 4,304 psi. Bench Number 3 was then tested. We perforated a net interval of 150 feet. The well produced at a stabilized rate of 125 barrels per day for a 24-hour period. Permeabilities in the range of 120 millidarcies and initial reservoir pressures of 4,279 psi. Bench Number 2, the net interval perforated was 190 feet, stabilized rate of 266 barrels per day for a little over 28 hours. Permeabilities in the 96 millidarcy range, and the static reservoir pressure was calculated, would be 4,051 psi. R & R COURT REPORTERS 810 N STREET 277-0572/Fax 274-8982 1007' WEST THIP. D AVENUE 2~-~15 ANCHORAGE, ALASICA ~01 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 35 Bench Number 4, the net perforated'interval was 70 feet, and it flowed at a stabilized rate of 185 barrels per day for a 24-hour period. Permeabilities in the range of 94 millidarcies, with a static reservoir pressure of 4,185. In all Benches, 1, 2, and 3, pretty much all of the build-up data was influenced in the late time by tidal effects. I feel like in none of these tests do we see any kind of impediments to flow. CHAIRMAN JOHNSTON: In terms of describing the reservoir characteristics again would you say that the data on -- from West McArthur River Number 1 would be representative? In other words, would we be safe in saying that the original reservoir pressure is 4,295, the original GOR is 160, and the bubble point is 1,0487 MR. MILLS: I feel confident in the pressure and the GOR. Those are measured properties. The bubble point was derived from fluid correlations. CHAIRMAN JOHNSTON: But you feel that the Number 1. could be used to describe the reservoir characteristics, not the Number 2 -- 2-A? MR. MILLS: In pressure, I feel very confident of that. CHAIRMAN JOHNSTON: It looks like they're all in the ballpark anyway. MR. MILLS: Right, yeah. GOR typically in a R & R COURT REPORTERS 810 N STREET 1007 WEST THIRO AVENUE 277-0572/Fax 274-8982 27~-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 36 well test situation there's -- it's subject to some errors. CHAIRMAN JOHNSTON: Right. What we're trying to do is establish for the record in the Conservation Order what the reference point is going to be. MR. MILLS-. Certainly. CHAIRMAN JOHNSTON: Any additional comments? MR. MILLS: Again, I've summarized the PVT data. This sample was a surface sample that was taken during the testing of Bench Number I in West McArthur River 2-A. The fluid was sent down the core labs and they've prepared the analysis on that., and basically I've just summarized the parameters that they presented. COMMISSIONER DOUGLASS: Are there any plans to do any additional testing to arrive or to check that PVT data or are they confident that that's representative of the in-place values? MR. MILLS: Certainly in Well Number 1, I believe that there are some plans to acquire additional PVT data. MR. MOHRBACHER: I can speak with respect to that, if necessary, if you'd like. COMMISSIONER DOUGLASS: I was just establishing these baselines and establishing whether or not they might change in the future. MR. MOHRBACHER: I would definitely say that R & R COURT REPORTERS 810 N STREET 1007 MEST THIRD AVENUE 277- 05 72/F ax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 37 they may, especially when the results are fully analyzed from the existing ongoing production tests. COMMISSIONER DOUGLASS: So these would be considered preliminary at this point? MR. MOHRBACHER: (Nods affirmatively) It is important to note, if I might add, that the wells are being tested under hydraulic pumping, artificial lift, and the wells tend to behave differently than under unassisted float conditions. CHAIRMAN JOHNSTON: I think at this time we · have no further questions. Thank you. Any other witnesses? Then I guess that does it. You show productive interval extending onto -- a lease to the northeast there which is labeled Unocal, and yet in your application you indicated that you did not feel any integration of interest was necessary since this was basically all Stewart Petroleum leases. Could you give us your thoughts on the integration of interests or the necessity for integration of interests? Perhaps it would be helpful, Jesse, if you would step up to the microphone here so we can make sure that you're picked up. MR. MOHRBACHER: If Stewart Petroleum -- the next well planned to be drilled will spill (ph) rest within the West McArthur River Unit and be in accordance with the required R & R COURT REPORTERS 810 N STREET 1007 tdEST THIRD AVENUE 27'/- O572/Fax 274-898~ 27Z-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 38 minimum of 500-foot setback from a lease line. Subsequent to that well it may be possible to explore the acreage on the Unocal lease -- beneath the Unocal lease. Prior to doing that Stewart would enter into an agreement with Unocal for a farm-out on their portion of the prospect. Nothing has been done with that other than preliminary discussions at this point in time. CHAIRMAN JOHNSTON: Then what specific area are you asking us to establish pool rules for? Do you wish us to define the pool as extending up into the Unocal .leases or -- and also this would also apply to the -- what is it, the Phillips lease to the south there, I guess. MR. MOHRBACHER: Our application requested pool rules for the West McArthur River Unit. CHAIRMAN JOHNSTON: And specifically what is the West River McArthur Unit? MR. MOHRBACHER: The West McArthur River Unit is the area on the map bounded in yellow; two leases -- if I may point to them -- this area right here is the northern lease, and this area is the southern lease, and those leases make up the West McArthur River Unit. With respect to pool rules for the.accumulation, obviously we believe the accumulation rests on acreage outside the West McArthur Unit. With respect to the Unocal interests and the Phillips interests, I'm not prepared to make a complete comment R & R COURT REPORTERS 810 N STREET 1007 gEST THIRD AVE#UE 277-O572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA ~)501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 on that at this point in time. clarified by Stewart Petroleum. 39 That would need to be further CHAIRMAN JOHNSTON: So in terms of maximizing recovery from the accumulation, what is your proposed game plan? MR. MOHRBACHER: The plan is completely delineate the field, for starters. I mean we have to drill additional oil production wells to do that. CHAIRMAN JOHNSTON: And do you have any idea how many additional wells you'll be drilling? MR. MOHRBACHER: Up to six additional wells on Stewart acreage, and depending on what the status of the southern block is and the Unocal acreage, possibly more. CHAIRMAN JOHNSTON: And over what time frame do you anticipate drilling these wells? MR. MOHRBACHER: Probably over the next three to four years. CHAIRMAN JOHNSTON: In terms of pressure support what is your game plan? MR. MOHRBACHER: With delineation of the field a pressure maintenance program will be identified and proposed. It appears that the field in the northern block could be supported with the existing -- possibly with the existing Pan-Am well to the south of the southern nose, which is -- could be re-entered and recompleted as a water injection well. R & R COURT REPORTERS 810 N STREET 1007 I~'EST THZRD AVENUE 277'-0572/Fax :~74-898Z :~72- 7'315 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 40 That is one possibility. Additional wells would need to be placed on each side of the structure. We're not prepared at this time to say where those wells would need to go or exactly how many are going to be required. We think we need to delineate the field better in order to make that decision. CHAIRMAN JOHNSTON: Do you see the need to require an integration of interests in terms of pressure support/waterflood activities and such? MR. MOHRBACHER: That may be required, but possibly not at this time since we have not completed delineating the field. CHAIRMAN JOHNSTON: So basically what you're saying is that you'll need a period of primary recovery before an intelligent waterflood plan can be developed or enhanced recovery plan? MR. MOHRBACHER: That is correct. CHAIRMAN JOHNSTON: What is the drive mechanism that we have here? MR. MOHRBACHER: It's water drive. CHAIRMAN JOHNSTON: Pardon me? MR. MOHRBACHER: Water drive. CHAIRMAN JOHNSTON: Water drive. And it doesn't seem like it's a real active water drive since you're on artificial lift? MR. MOHRBACHER: We are currently hydraulically R & R COURT REPORTERS 810 N STREET 1007 MEST TH[RD AVENUE 2??-0572~Fax 274-8982 272-7515 ANCHORAGE, ALASKA ~01 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 41 pumping wells, yes. CHAIRMAN JOHNSTON: Do you see any of these wells capable of unassisted flow? MR. MOHRBACHER: Well, ..... CHAIRMAN JOHNSTON: Or will they all be? MR. MOHRBACHER: Well, they were capable of unassisted flow during the initial DST tests. CHAIRMAN JOHNSTON: They were, okay. MR. MOHRBACHER: And they still are today, however, we're producing them on hydraulic lift because that would be the production mechanism we intend to use. COMMISSIONER DOUGLASS: Your six wells that you tentatively plan, is that -- or if I understand you, those six wells would essentially be focused on that northern anticline that was described by Mr. Mangus; is that correct? I mean that's your main target of development? MR. MOHRBACHER: No. If on the northern anticline on Stewart acreage we're currently anticipating approximately four wells. The third well definitely, and the fourth well will be assigned after the third well. Southern acreage may require additional wells. COMMISSIONER DOUGLASS: I'm not sure I picked up on all that. You said four wells, you're going to drill -- or going to explore that southern ..... MR. MOHRBACHER: We may drill a total of four R & R COURT REPORTERS 810 N STREET 1007 k'EST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 42 wells in this area. We're going to drill a well to the north, we may drill a well to the south. Additional one or two wells may be required on the Unocal acreage, an additional one or two wells may be required down here. (Commissioner Babcock now present) COMMISSIONER DOUGLAS: But at this point the wells in that southern section would really be termed exploratory since there's no indication right now that there's an oil accumulation present? MR. MOHRBACHER: Any well drilled to the southern section would be in an effort to do two things; test the Hemlock and Tyonek and West Forelands for oil, but also to develop the West Foreland gas field. COMMISSIONER DOUGLAS: I guess that's what I missed in your original -- or in your Exhibit 1. It was for an oil development, and that was -- I wasn't aware of any gas development, and now you're coming forth with a gas development. So I'm somewhat ..... MR. MOHRBACHER: Well, it's a separate issue, 'cause there is a gas field there, and it is not being produced and it's not going to be produced in the near future. It's my understanding that a separate hearing of this type may be required for production of that gas. COMMISSIONER DOUGLAS: Okay, for that pool development. R & R COURT REPORTERS 810 N STREET 1007' IdEST THIRD AVENUE 277-0572/Fax 274-8982 ;72-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 43 MR. MOHRBACHER: That pool development. COMMISSIONER DOUGLAS: Yes. CHAIRMAN JOHNSTON: If it is a separate pool. MR. MOHRBACHER: Yes. COMMISSIONER DOUGLAS: I mean if that's what you're saying is the gas zone there is an entirely separate pool that is not in pressure communication with the West McArthur River Unit pool. MR. MOHRBACHER: be at this time. questions? Correct. It's not believed to CHAIRMAN JOHNSTON: Right. Any further COMMISSIONER DOUGLAS: Have you made any estimates on oil in place or recovery factors at this point? MR. MOHRBACHER: We've used a primary recovery factor of 0.25, and an effective waterflood recovery factor of 0.15. That's comparable to what's seen in the Trading Bay Unit and McArthur River Field. .COMMISSIONER DOUGLAS: Those would be additive? MR. MOHRBACHER: Yes. CHAIRMAN JOHNSTON: But do you have any estimate of original oil in place? MR. MOHRBACHER: Original oil in place is currently estimated at somewhere in the order of 100 million barrels, looking at all acreage, and using the southern block R & R COURT REPORTERS 810 N STREET 1007 I,IEST THIRD AVENUE 277-05?2~Fax 274-8982 272-~15 ANCHORAGE, ALASKA ~501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 44 included in there. This thing is we only have two wells in place, and obviously it's been something of a moving target at this point in time. As additional wells are drilled and the field delineated, those reserves estimates will be updated. CHAIRMAN JOHNSTON: And of this estimated 100 million original oil in place what percentage of that would you estimate to occur in that southern fault block? MR. MOHRBACHER: I don't have an exact planimeter measurement of that southern fault block, but just looking at it, it appears to be on the order of.30%. CHAIRMAN JOHNSTON: 30%. And earlier we heard that that southern fault block, there's no direct evidence that 'there is oil there, that it is a optimistic view on the part of Stewart Petroleum. MR. MOHRBACHER: Yes, you could say that's an optimistic view. CHAIRMAN JOHNSTON: I think at this time I'd like to note for the record that Commissioner Babcock has joined us, and I'd like to take a 10 or 15-minute recess here so we can bring Commissioner Babcock up to date as to what has transpired this morning. With that, let's reconvene at approximately say 10:30. (Off record - 10:16 a.m.) (On record - 10:44 a.m.) CHAIRMAN JOHNSTON: I'd like to reconvene this R & R COURT REPORTERS 810 N STREET 1007 IdEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 45 hearing. I believe we were talking with Mr. Mohrbacher. If we could have you step forward again and sit down at the table here, we have only a few more questions for you. One of the things that we need to do is to also clearly define the interval that we're talking about here. So if you could -- you or any one of your support could give us basically the interval that you wish us to define as the pool, and also if you would give us a name for that pool. MR. MOHRBACHER: Mr. Bornemann at this time. MR. BORNEMANN: I'm going to turn that over to If you take your Exhibit Number -- what is it now, 5, I believe, the Log of the West McArthur River Unit Number 17 CHAIRMAN JOHNSTON: We have a 5 and a 6. Let's see, is it ..... (Simultaneous speech) MR. BORNEMANN: So the pool would go from Hemlock Bench Number 1, which is at measured depth 13,174 feet. CHAIRMAN JOHNSTON: Right, okay. MR. BORNEMANN: And it would go, as defined right now, to the bottom of the Hemlock, the base of Bench Number 6, which is at 13,660 feet measured depth, and measured depth is from KB, which is 163 feet. CHAIRMAN JOHNSTON: That was 163; is that what I heard? R & R COURT REPORTERS 810 N STREET 1007 ~EST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASI(A 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. BORNEMANN: said 166, so it's 163 feet. CHAIRMAN JOHNSTON: what is recorded. 46 Yeah, it is -- I think Marvin Okay, very good. That's MR. BORNEMANN: If a future were high on structure penetrates the West Foreland again and finds oil, that would be included in the pool, but at present, there's no evidence for that. CHAIRMAN JOHNSTON: And are we calling this the West McArthur River pool? MR. BORNEMANN: I would say so, but this is up to Stewart Petroleum, yes. CHAIRMAN JOHNSTON: The West McArthur River oil pool. That's fine. CHAIRMAN JOHNSTON: What is your evidence for productive zone on the Unocal acreage? MR. BORNEMANN: I have no evidence for that. CHAIRMAN JOHNSTON: So, again, this would be the current interpretation? MR. BORNEMANN: It's the interpretation of the structure map using the oil-water contact as established by oil shores within the test on the old wells and extending the structure as it is shown on the map, basically. CHAIRMAN JOHNSTON: There is no well data from that part of it? R & R COURT REPORT'ER~ 810 N STREET 1007 WEST THt'RD AVENUE 277- 0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 47 MR. BORNEMANN: There is no well data that I have looked at or I'm not aware of, that is exactly a well situated in that nose of the -- in the northeastern nose of the anticline that goes into the Unocal structure, yes. CHAIRMAN JOHNSTON: What is the plunge on the anticline, in what direction? MR. BORNEMANN: I think, from what I remember when I did that it was about 5 degrees either way, plunging north -- plunging the northwestern part plunging to the northeast 12 degrees as well as about 5 degrees plunging to the southwest. So roughly -- I'm talking about plunge this way and this way, roughly 5 degrees. Dips in the Hemlock on the eastern -- on the western flank based on West Foreland Unit Number 1 are 30 degrees in the Hemlock, roughly 20 degrees on the eastern flank. So it's slightly asymmetric CHAIRMAN JOHNSTON: And so the structure is, in your opinion, controlled entirely by a dip of the structure; is there any fault control or anything other than saY the fault block to the south that the principal structure itself is all structural -- or structural depth? MR. BORNEMANN: Yeah, it's all structure. The principal structure is the anticline, yes. I have some sketches that could indicate another fault, but this is not really proving stuff like this here. COMMISSIONER DOUGLAS: On the oil-water contact R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277- 0572/Fax 274 - 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 48 do you -- has oil-water contact been determined in Number 1 or Number 2-A? MR. BORNEMANN: I regard this as a philosophical question. What is the oil-water contact? Where you have no more oil and only water or what? COMMISSIONER DOUGLAS: No more movable oil. MR. BORNEMANN: Well, you can move oil down to the all the oil where we encountered it in those wells. If all the oil can be produced economically down there, I'm not so sure in terms of water contact or not. COMMISSIONER DOUGLAS: So if I hear you right, there's not a point in -- or a point determined in the Number 1 or the Number 2-A where essentially if you perforated the Hemlock you would get 100% water production? MR. BORNEMANN: Not as far as I know. CHAIRMAN JOHNSTON: .Any more questions? COMMISSIONER DOUGLAS: No. MR. BABCOCK: I have one question, a request rather, that the cross sections that the Chairman asked you to provide that to use that to reconcile the well data with the structural interpretation, I don't think we specifically asked for that, but that's what we'd like to see. And I have an additional question for Mr. Mohrbacher. CHAIRMAN JOHNSTON: I think at this time we have no further questions of you. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 49 Mr. Mohrbacher. MR. BORNEMANN: MR. BORNEMANN: Thank you. Thank you very much. MR. BABCOCK: Excuse me for not being here earlier to hear the bulk of your testimony, but based on the information that you submitted earlier one of the observations I have is that the plan of operation and development seems to be designed to be rather flexible, which is natural, but I wondered if you'd have any objection to meeting with the Commission on an annual or semi-annual basis, even quarterly basis, if you thought that would be productive to keep us informed of the changes to the plan of operation, development. We don't always require approval of revisions of plans of operation and development, but under 05.030 we do have that authority, and I'm certainly considering that in this case. And I just wondered what your -- since you have more familiarity than I do what the likely changes -- the scheduled likely changes, what would you recommend that I consider? MR. MOHRBACHER: We have no objection to meeting with the Commission to update the Commission on the status of the development project. Key elements of the development project such as drilling success of wells and delineating the field are going to occur at somewhat and possibly irregular times, possibly on the order of once every six months at a minimum, and a status update or something like R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 50 that we don't think is unreasonable, or as necessary for when key development issues come forth. MR. BABCOCK: All right, thanks. That's all, Mr. Chairman. CHAIRMAN JOHNSTON: Just springing off those thoughts a little bit, Jesse, it appears to the Commission that you are not asking for any exceptions to the statewide rules, and as such then our order that we would write for the West McArthur River pool will be fairly simplistic in relative terms to other orders that the Commission has issued. But I also note that the order would again be based upon evidence that is somewhat preliminary at this step. You don't know everything that you would like to know about the pool, so it appears to me that we are going to have to issue revisions to that order as data comes before us and as changes to the order warrant. 'For example, the most obvious would be what are your plans for waterflood. That may require some future revisions to the Conservation Order. So I think we need to be prepared to sit down with you and work closely for the next few years here and develop this thing in a manner that will benefit not only Stewart Petroleum but obviously the state of Alaska. So the order I think that you'll see again will be pretty straight-forward. It will be basically defining this pool in terms of the vertical extent, it will recognize that you are planning to develop a particular area, and that a lot of R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 51 additional work needs to be done here, and it will basically set up the need for period updates and reissuances of that order as data comes forward and as you develop it. And that's not a bad way of going. You know, I think it's maybe a little bit difficult, especially for an independent to come up with the full sweep of data that perhaps is a little bit easier for a major to acquire because of the financial wherewithal involved, and certainly this is something that is commonly done in the Lower 48. You go into a period of primary recovery, and you acquire data, and that data will tell you a particular course of action that you need to follow in terms of pool development, and so I think the Commission just needs to recognize the limitations and be prepared to issue revisions to that order and work with the operator in terms of preventing waste, insuring maximum recovery, and protecting the correlative rights of people that may become involved in this particular accumulation. MR. BABCOCK: One of the things -- the Commission has a few rules, and we expect those to be obeyed, and otherwise I'm very encouraged by Stewart's exploration and proposal, and I'd like to do everything that I can to promote and encourage further activity and development, and I'm glad to see you moving forward with it. CHAIRMAN JOHNSTON: Well, independents are a backbone of the oil and gas business in the Lower 48, and I R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 52 think the value to -- that they provide to the country is often underestimated, so in terms of having an independent up here operating in the state of Alaska, I think that's good news indeed, and I hope you're able to make this a going proposition for you. I think that can only benefit Alaska, and what the Commission -- our role here is, again, to oversee production so that all those that have an interest in this concern are protected. But we're not here to put roadblocks up in front of you; what we're here to do is to resolve conflict if we can and to aid you in the development of this prospect. MR. BABCOCK: Mr. Chairman, I'd just like to take back -- I shouldn't use the word "promote," I really meant a word that you used which is "aid," in support, so that's what I meant, to beg off on having the flu. CHAIRMAN JOHNSTON: I didn't even catch that one. that's that. MR. BABCOCK: I beg off on having the flu and CHAIRMAN JOHNSTON: Jesse, what have you learned to date from the testing of the two wells? MR. MOHRBACHER: Well, we have got both wells currently under production tests. The second well, the Number 2-A well was placed on production tests a little over a week ago. That well is producing about 1% water out of three benches, the top three benches of the Hemlock. Very much -- R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 53 very close to what Ted Bornemann referred to in his prediction of watercut. The second well has also been on production. It has had some additional watercut to it, but watercut that's not necessarily due to the formation Bench 2, it's watercut coming from below in a wetter sand. We've learned that the western part of the river structure is a commercially viable venture, and we're preparing to build a pipeline to officially transport oil to market. CHAIRMAN JOHNSTON: Have you begun construction of the pipeline then? ~MR. MOHRBACHER: We have tangibles en route to Alaska and -- but we have not actually started construction at this date. CHAIRMAN JOHNSTON: Have all the permits been obtained? MR. MOHRBACHER: There is one final permit still in review process. That is the Oil Spill Contingency Plan which is -- has been submitted for final review and no objections have been heard back after this last go-round of submittals from the ADEC. So that project is essentially fully permitted, with the ADEC's concurrence that our existing version of the spill plan is complete enough. CHAIRMAN JOHNSTON: In your application you've made some statements about your involvement in getting an MPDS permit from the Department of Environmental Protection. While R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572~Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 54 this is not necessarily pool related, I found it to be an interesting topic. Could you give us a brief explanation of the difficulty that you've encountered with obtaining an MPDS permit? MR. MOHRBACHER: Originally the plan for the project, for the most expedient development was to lay one pipeline, multi-phase to the Trading Bay production facility and have Marathon Oil Company process West McArthur River crude oil and natural gas and remove the water and discharge the water to Cook Inlet as the Trading Bay production facility does with the rest of the Trading Bay unit, produce water. The EPA subsequently ruled that Marathon Oil Company could not discharge Stewart Petroleum West McArthur River water because we had an onshore wellhead, although we have an offshore reservoir. That determination, which is somewhat difficult to understand that a small increment of additional produced water is going to make any additional environmental impact is not believed to be true or warranted. But because of that determination Stewart Petroleum Company was forced to install processing facilities at their West McArthur River Unit surface location and handle all processing of crude oil and natural gas at the wellhead. CHAIRMAN JOHNSTON: So are you saying EPA would not issue you an MPDS permit for an onshore location or ..... MR. MOHRBACHER: We were not asking for an MPDS R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/Fax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 55 permit. We were simply asking for approval for Marathon to use their existing MPDS permit to discharge another water source. CHAIRMAN JOHNSTON: Did you try to obtain an MPDS permit for yourself so you could -- so that discharge could be authorized? MR. MOHRBACHER: We did not because the most expedient thing -- trying to obtain an MPDS permit in Cook Inlet is not a short-term venture. The permit in Cook Inlet is currently under review, and it's been under review for a very significant amount of time, and most operators in Cook Inlet are operating under a grandfather clause of which Stewart would not be privy to. CHAIRMAN JOHNSTON: You would not be covered. MR. MOHRBACHER: Stewart had the foresight to drill a disposal well which is subsequently able to accept all produced water from the unit. CHAIRMAN JOHNSTON: But because you're not able to discharge your produce water into the Cook Inlet your forced now to construct your own processing facilities; is that correct? MR. MOHRBACHER: Correct. It has resulted in increased production costs because we have to remove water -- produce water from the crude oil down to 0.5% or less, whereas we would have been able to pay a fee to Marathon Oil Company to do that for us. So we are using more capital to do the same R & R COURT REPORTERS 810 N STREET 1007 NEST THIRD AVENUE 277- 0572/F ax 274 - 8982 272 - 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 56 amount of work, and we also have to lay additional -- and additional pipeline to handle our produced gas. CHAIRMAN JOHNSTON: So were you also forced to expand your surface facilities to accommodate the production facility? MR. MOHRBACHER: Yes. We've had to increase the size of our surface facilities by approximately 30% to accommodate additional production facilities. CHAIRMAN JOHNSTON: So because of the difficulty over an MPDS permit it is costing you additional capital and also additional surface disturbance? MR. MOHRBACHER: That's correct. CHAIRMAN JOHNSTON: Do you know what the difficulty is in getting the MPDS permits? MR. MOHRBACHER: I'm not prepared to comment on that. CHAIRMAN JOHNSTON: As I said, it was somewhat off the subject, but I found it to be an interesting comment. Again, there's something about seeing an agency forcing an operator to take a course of action that, 1, increases his costs and then also increases surface disturbance which is an environmental impact for the sake of a document that should be issued in a much more timely manner. So it's just one of those little things that I don't necessarily think is something that we should emulate. I think it doesn't say much for the EPA. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 2~7- 0572/Fax 274- 8982 272 - 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 57 MR. BABCOCK: One potentially serious ramification of EPA's position that I see is whether or not the denial of the use of that Trading Bay facility, to the extent that you had anticipated, whether that will cause you to not produce even as much as a single barrel of oil with the increased costs onshore or the lack of access to Trading Bay cause you not to produce any gas or oil that you otherwise would have produced. MR. MOHRBACHER: That may be possible although I cannot say definitively one way or the other. It will increase capital costs and long-term operating costs which may reduce the overall economic viability of the field. MR. BABCOCK: Well, I anticipate that the Commission -- I don't mean to jump the gun, but I anticipate the Commission will hold the record open for some time after this hearing, and if Stewart Petroleum Company has any information that they could share with the commission as to whether or not the denial of access to Trading Bay for the purposes you initially anticipated, will cause you to produce less gas or oil than you otherwise would, I would like to have an answer to that question. CHAIRMAN JOHNSTON: questions? Well stated. Any more COMMISSIONER DOUGLAS: No, no more questions. MR. BABCOCK: That's it. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 58 CHAIRMAN JOHNSTON: Well, Mr. Mohrbacher, I think at this juncture the Commission has no further questions. Again, I'd just like to say that we're pleased to have Stewart Petroleum operating. We did have some difficulty over the Number 2-A well. I think we have straightened that out, and I think we have achieved an understanding with Stewart Petroleum as to the standard of operations that we expect in the future, and I have no doubts that Stewart Petroleum, with your services, will continue to improve upon the record that they have now achieved with us. We're pleased to have you up here in the state and the best of luck. We hope you make this a going venture for the state of Alaska and yourselves. So with that I would like to hold the hearing record open for an additional two weeks to allow time to get the transcript prepared, for us to review it, and if we have any additional questions we'll be in touch. So we will close the record two weeks from now at close of business at 4:30, February the ..... COMMISSIONER DOUGLAS: He wanted to summarize. CHAIRMAN JOHNSTON: Oh, that's right. I'm sorry. any comment. some ..... COMMISSIONER DOUGLAS: And we need to invite CHAIRMAN JOHNSTON: You did want to make MR. MOHRBACHER: I wanted to clarify a couple R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274-8982 272-7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 59 of points at the end of my testimony. Commissioner Douglass asked how many wells we anticipated drilling on various parts of the acreage, and what I meant to say, if I did not -- what I meant to say is that with existing Stewart. Petroleum acreage mapped on the wall there, we anticipate up to six wells drilled on Stewart Petroleum acreage. If Unocal acreage is at a later date determined to be warranted for drilling and a integration of those interests are accomplished, an additional, possible two wells may be warranted on that productive acreage. · CHAIRMAN JOHNSTON: Are you talking to Unocal at this juncture about the possibility of investigating that acreage? MR. MOHRBACHER: Yes, we are. We have had discussions with Unocal, primarily on an informal basis at this time, and they have requested to -- that we acquire additional reservoir data and demonstrate the commerciality of the prospect and then when it comes time that their acreage may be -- warrant drilling, those interests could be integrated. CHAIRMAN JOHNSTON: Any other points then? MR. MOHRBACHER: Yes. Commissioner Douglass, I believe you asked also about original oil in place or possibly Mr. Chairman? I may have gotten ahead of myself and with regards to original oil in place we likely have a few hundred -- several hundred million barrels of oil in place. Applying a R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/Fax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 60 recovery factor of 0.4, and recovering all oil from the mapped acreage, recoverable reserves may be on the order of a hundred million barrels. So that is a significant difference from what we discussed previously. CHAIRMAN JOHNSTON: change. Yes, that is a significant COMMISSIONER DOUGLAS: You actually stated reserves when I'd asked for oil in place. MR. MOHRBACHER: Correct. As additional wells are completed those figures may be revised. MR. BABCOCK: Was any portion of that estimate on the Unocal acreage? The Chairman asked about the southern segment which you estimated about 30%. Is there any percentage on your acreage that you're estimating including in that number? MR. MOHRBACHER: In that number Unocal acreage comprises approximately 30%. MR. BABCOCK: So 40% is your northern segment on your property? 30% southern segment, 30% Unocal, 40% your northern segment of your property? MR. MOHRBACHER: That would be a reasonable estimate without actually calculating it. MR. BABCOCK: Thank you. Can you pick that up? I'm trying to use your numbers. I forgot to put my microphone on. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 61 COURT REPORTER: Yes, I did. CHAIRMAN JOHNSTON: Yeah, you were mentioning the fact that you thought that that number might be reserved or revised in the future with additional drilling. I guess I have to note that I would think that that number probably will be revised as you get additional information. What we have here is very sketchy information. You have a couple of wells that have oil flowing out of them, and you have some seismic data on a very wide grid with a vintage of 1960, and the quality of that and the difficulty of acquiring seismic at .that time was probably not the best. So I think the Commission has to recognize that this information is -- will be developed over time, and that why you say 100 million barrels recoverable, that's a very nice target, and I hope to heck that it is. But on the other hand I think we have to recognize that it is an optimistic viewpoint on the part of Stewart Petroleum. MR. MOHRBACHER: That's right, it is. CHAIRMAN JOHNSTON: At this time before we do close for the day, I'd like to ask if anybody in the audience has any statements that they would like to make or any other comments? I see none. Then, again, we'll hold the hearing record open for two weeks and we'll close it at two weeks Friday from today. I don't know what date that is, but we can all figure it out. The 18th, okay, at 4:30 p.m. then the hearing record will be closed on this. R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274 - 8982 272 - 7515 ANCHORAGE, AEASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 With no further comments, thank you for coming and we appreciate your attendance. Thank you. (Off record - 11:13 a.m.) (END OF PROCEEDING) R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274- 8982 272- 7515 62 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 63 CERTIFICATE UNITED STATES OF AMERICA) ) ss STATE OF ALASKA ) I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing of the Alaska Oil and Gas Conservation Commission was taken before Laurel Kehler-Evenson on the 4th day of February 1994, commencing at the hour of 9:00 o'clock a.m., at the offices of the Alaska Oil & Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska, pursuant to Notice; THAT this Transcript, as heretofore annexed, is a true and correct transcription of the testimony given at said Public Hearing, taken by Laurel Kehler-Evenson and thereafter transcribed by Laurel Kehler-Evenson; THAT the original of the Transcript has been lodged with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska; THAT I am not a relative, employee or attorney of any of the parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this llth day of February 1994. Notary Public in and for Alaska My commission expires: 10/10/94 RECEIVED FEB 1 4 1994 Alaska Oil & Gas Cons. Commission Anchorage R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/F ax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 ALASKA OIL AND GAS CONSERVATION COMMISSION STEWART PETROLEUM COMPANYO POOL WEST MCARTHUR RIVER FIELD~ COO~~I~SIN RULES, PUBLIC HEARING-FEBRUARY 4, 1994 SIGN IN PLEASE NAME & COMPANY (PLEASE PRINT) Do You Plan to Testify? Yes No ! · _ ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 January 12, 1994 Mr. Jesse Mohrbacher, Vice President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company 715 L Street Anchorage, AK 99501 Mr. Mohrbacher: We are in receipt of your December 27, 1993 petition requesting pool rules for the West McArthur River Unit (WMRU). A notice of public hearing to be held at our offices on Friday, February 4, 1994 has been published. The purpose of this letter is to offer some specific guidance for testimony that Stewart Petroleum should be prepared to provide at the hearing. The Commission has several areas of concern in these matters; 1) protection of freshwater aquifers, 2) protection of correlative rights, 3) prevention of waste and 4) maximum ultimate recovery. We expect a petitioner for pool rules to be able to provide sufficient information specific to the proposed area of development to allow the Commission to write rules that address these concerns and provide a basis for interpretation of future pool . performance data. Any modification of statewide regulations requested by an operator for the operation of a pool must be justified in the context of the above listed concerns. Your application makes no specific reference to exceptions to statewide regulations that you consider necessary for your development plan. We therefore conclude you are seeking primarily to formally classify the WMRU Hemlock Oil Pool pursuant to 20 AAC 25.520. Please be prepared to designate a type log interval for pool definition. Mr. Jesse Mohrbacher Stewart Petroleum Co. January 12, 1994 Key descriptive parameters of the reservoir and fluids derived from your development activities to date within the WMRU should also be addressed in your testimony. Following are examples of the kinds of information expected: reference datum in feet subsea for reporting pressure data original reservoir pressure oil saturation pressure (avg) oil gravity -API reservoir temperature porosity (range/avg) permeability (range/avg) solution gas oil ratio formation volume factor @ original pressure formation volume factor @ saturation pressure initial water saturatuon oil viscosity ~ original pressure (cp) oil viscosity @ saturation pressure (cp) estimated volume of oil and gas in place The Commission notes that your interpretation indicates the Pan Am WFU-2 well encountered oil bearing Hemlock Conglomerate. The Commission requests Stewart Petroleum Company address this interpretation at the February 4 hearing. We understand you are currently gathering data on the WMRU Hemlock formation; however, we view this pool rules hearing as an important opportunity to review available engineering and geologic data from the subject pool. If you have questions please contact Bob Crandall or myself at 279-1433. Sincerely Russell Douglass Commissioner STOF0330 Ai' r OF PUBLlCA(i .ON STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT. ) Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she ls an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and It now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed In an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on 1/4, 1994 ~ 6! Public Hearing STATE OF: ALASKA Alaska 011 and Gas Conservation Commission Re: The application of Stewart PetroLeum Company for a pub. Itc hearing to present testimo-I ny for classification of a new oll IX>Ol and prescribing pool rules for its development in the West McArthur River Unit in Cook Inlet. ' Notice is' hereby given that Stewart Petroleum Company has petitioned the Alaska Oil and Gas Conservation Com- mission under 20 AAC 25.520 to hold a public hearing to pres- ant testimony for classification and prescribing of pool rules for development of a new oil pool in the West McArthur River Unit. The proposed velopment area is located in l the western portion of Trading ~ Bay in Cook Inlet. An oral public hearing will be . held at the Alaska Oil and Gas Conservation Commis.~ion, 3001 'Porcupine Drive, Anchorage, Alaska 99501, at 9:00 a.m. on Friday, February 4, 1994, in conformance with 20 AAC 25.540. All interested persons and parties are invited to pres- ent testimony. If you are a with a disability who may need a special ac. commodatlon, auxiliary aid or service, or alternative commu. (nlcatlon format in order to comment on the proposed ac- lion, please contact Diana, Fleck at 279.1433 by 4:30 p.m; January 25 to make any neces- sary arrangements. /s/Russell A. Douglass, Commissioner Alaska OII and Gas '. ,. I Conservation Commission AO,08.5762 ' Pub,,sh:. January ~, 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. Subscribed and sworn to before me this ...~..... day of .~...:..n~... ....... Notmy Public In and for the Sate of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES · ~-, Commls~lon Explre~: ............ :?.?.r.!~,.~.?.?Z .......... ~ 9 ...... Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Rez The application of Stewart Petroleum Company for a public hearing to present testimony for classificatiOn of a new oil pool and prescribing pool rules for its development in the West McArthur River Unit in Cook Inlet. Notice is hereby given that Stewart Petroleum Company has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony for classification and prescribing of pool rules for development of a new oil pool in the West McArthur River Unit. The proposed development area is located in the western portion of Trading Bay in Cook Inlet. An oral public hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 a.m. on Friday, February 4, 1994, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special accommodation, auxiliary aid or service, or alternative communication format in order to comment on the proposed action, please contact Diana Fleck at 279-1433 by 4:30 p.m. January 25 to make any necessary arrangements. Russell A. Douglass, Commissioner Alaska Oil and Gas Conservation Commission Published January 4, 1994 E & P SERVICES, INC, December 27, 1993 RECEIVED Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Attn: Mr. David W. Johnston, Chairman DEC 2 8 199~ Alaska 0il & Gas Cons. Commission Anchorage Re: Stewart Petroleum Company, Request for Hearing to Establish Pool Rules for the West McArthur River Field, Cook Inlet Basin, Alaska Dear Chairman Johnston: Pursuant to the provisions of 20 AAC 25.517 and 25.520, Stewart Petroleum Company hereby submits the enclosed Plan of Development and Operation for the West McArthur River Field. By this submittal, Stewart Petroleum Company is requesting that the Commission hold a hearing to present data and establish Pool Rules for the West McArthur River Field. Stewart Petroleum Company is currently conducting a long term production test on the West McArthur River Unit (WMRU) No. 1 well. The WMRU No. 2A well is expected to begin testing by the end of this month. Data from these tests will be summarized and presented to the Commission at the time of the Pool Rules Hearing. The Plan of Development and Operation will be revised as necessary based on the data acquired during testing and future production operations. The enclosed Plan of Development and Operation specifies three primary objectives for the development of the West McArthur River Field. These are as follows: · Prevention of waste. Protection of correlative rights for each property owner in the pool. ° Maximum ultimate recovery of oil and gas that is prudent. The Plan also specifies how these objectives will be accomplished during development of the field. Integration of interests for the West McArthur River Unit is required by 20 AAC 25.517 (c). Integration of interests in the West McArthur River Unit is very straight forward as the Unit is a single party Unit with Stewart as the operator for both leases in the Unit. 715 L Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258-5557 Chairman David W. Johnston December 27, 1993 Page 2 If you have any questions regarding this submittal or require any additional information please contact the undersigned or Robert Gardner at 258-3446. Sincerely, Jesse Mohrbacher, Vice President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company cc: W.R. Stewart, Stewart Petroleum Company R.C. Gardner, Fairweather E&P Services Inc. Enclosures RECEIVED DEC 2 8 199~, Alaska Oil & Gas Cons. Commismm, Anchorage November 11, 1993 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attention: Mr. Jack Hartz RECEIVED NOV 12 1993 Alaska Oil & Gas Cons. Commission Anchorage Re: Justification and Supporting Documentation for Long Term Production Tests for the Stewart Petroleum Company West McArthur River Unit No. 1 and No. 2A Wells. Dear Mr. Hartz: Thank you for taking the time to' meet with me the other day regarding the application of Stewart Petroleum Company (Stewart) for a 120-day extension to the long term production test for the West McArthur River Unit (WMRU) No. 1 well. During that meeting, the Commission requested additional information detailing the test objectives, data acquisition plans, analysis of results, and how this information will be utilized in the future development plans for the WMR 0ilfield. In response to the Commission's request, the attached long term production testing program has been defined. The attached program identifies the purpose of the testing program, the test objectives, data collection, production logging plans, data analysis, disposition of gas, and the use of test results. Results of the production test will be submitted to the Commission to support the WMR Plan of Development. Stewart proposes to conduct a 120 day flow test of the WMRU No. 1 well to acquire reservoir and surface production data in order to prepare a sound Plan of Development and Operation for the WMR field. The test is proposed to commence immediately upon issuance of the Commission's approval for a 120 day testing extension. Stewart proposes that a similar 120 day production test be commenced on the WMRU No. 2A well when adequate processing capability and tankage are operational at the WMRU facility in early December 1993. Both tests will be metered separately Stewart.intends to submit a Plan of Development and Operation to the Commission a minimum of 90 days prior to the expiration of the proposed test. This will allow sufficient time for a pool rules hearing and establishment of pool rules prior to moving into 715 L Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258,5557 Mr. David W. Johnston November 10, 1993 Page 2 permanent production status when pipeline facilities are operational. Currently, the pipeline is estimated to be complete and operational by February 1994. Ail permits are in place with the exception the ADEC Contingency Plan amendment for pipeline operations. The C- Plan approval is expected on or about November 20, 1993. Once the permits are in place, construction will commence immediately. Although winter construction will be more costly, it is necessary due to the logistical requirements resulting from the use of the facility road to construct the line and the desire to bring the field to permanent production as soon as possible. If you have any questions regarding the attached information, please contact the undersigned or Bob Gardner at 258-3446. Thank you for your attention to this matter. Sincerely, Jesse ~ohrbacher, viCe President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company Attachments cc: W.R. Stewart, President, Stewart Petroleum Company Bob Gardner, Fairweather E&P Services, Inc. RECEIVED NOV 1 2 1993 Alaska Oil & Gas Cons. Commission Anchorage Stewart P /'oleum ( ompany Dena.Ii .T.~ra Nor~, Sui~ 1300 2550 Denali~ti~t, Anchorage, ~aska 99503 (907) 277~4004 · FAX.(907) 274-0424 November 10, 1993 Re: West McArthur River Unit Area and all wells drliled within this Unit Area or in the vicinity of the Unit Area. Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 9950143192 Attn; Mr. David W. Johnston Commissioner Gentlemen: The purpose of this letter is to confirm that Fairweather E & P Services, Inc. has been designated the agent of Stewart Petroleum Company and is authorized to represent Stewart Petroleum Company in all matters before the Commission with respect to the captioned area. This authorization includes, but is not limited to, execution and filing of any and all required reports and appearances before the Commission as necessary. All prior authorizations are hereby revoked. This authorization shall remain in full force and effect until revoked or modified in writing by Stewart Petroleum Company. Thank you for your cooperation in this matter. WR$:rs Sincerely, W. R. Stewart President RECEIVED NOV I 2 1995 Alaska Oil & Gas Cons. Commission Anchorage STEWART PETROLEUM COMPA/~Y WEST McARTHUR RIVER UNIT No. 1 and 2A WELLS LONG TERM PRODUCTION TESTING PROGRAM 1.0 Introduction and Statement of Purpose Stewart Petroleum Company (Stewart) proposes to conduct an additional 120 days of long term production testing for the West McArthur River Unit (WMRU) No. 1 well. An equal 120 day test period is proposed for the WMRU No. 2A well commencing when adequate processing capability and tankage are operational at the WMRU facility in early December 1993. Production from both wells will be metered separately for proper data collection. These additional production tests are necessary to better define the reservoir characteristics of the WMR field. This reservoir information will also be necessary for preparation of a sound Plan of Development and Operation which will be required prior to placing the field on permanent production. Adequate reservoir information will also help determine the optimum design of the field production facilities. The data gathered to date has been somewhat inconsistent due to mechanical equipment problems, startup difficulties in oil processing, and other startup problems such as handling the 50% water cut in the well. These problems have been abated and the well will now be able to be produced at a stable rate for a sustained period of time. A minimum of three different stabilized production rates (2000, 2500, and 3000 bpd)' will be used in the production test to gather adequate reservoir data. 2.0 Test Objectives 2.1 Reservoir and Subsurface Data The following reservoir information will be identified by the production test: Static bottomhole pressure (bhp) (prior to startup) Flowing bhp Individual well productivity index (PI) Reservoir fluid composition Pressure maintenance requirements Additional reservoir information determined from the production test is discussed in section 4.0 below. 2.2 SurfaCe Facilities Optimum economic design of surface production and processing equipment will require additional production data from both RECEIVED NOV 1 2 199 Alaska Oil & Gas Cons. Commission Anchorage the No. 1 and 2A wells. The results of the test will determine the optimum size and capacity of the following equipment: Tankage for crude oil storage Heater treater vessels Free water knockout vessels Jet pump power units Gas Compressor Water disposal' equipment 3.0 Production Logging 3.1 Static Bottomhole Pressure Prior to placing the WMRU No. 1 well back on production, the static bhp will be remeasured with a mechanical pressure gauge. This parameter will be necessary in order to perform the volumetric analysis on the reservoir. Current static bhp data is available for well No. 2A from the recent DST test on the well. 3.2 Spinner and Temperature Surveys After the No. l.well has been on production for approximately two weeks and heated up to 120°F surface temperature, a temperature and spinner survey will be run in order to define the source of water intrusion into the No. 1 well. It is necessary to heat the well up prior to running these surveys in order to minimize the potential for deposited paraffin interfering with the downward movement of the tool string. 3.3 Pressure, Volume, Temperature (PVT) Data A PVT sample will be collected from the No. 1 well during the production logging operations. This sample will be necessary to define the composition of the.reservoir fluids. Currently, no PVT data is available for the No. 1 well. PVT samples have been collected for the No. 2A well during the recent DST and are at the laboratory undergoing analysis. 4.0 Data Analysis Data acquired from the production test will be analyzed to determine the following information: Maximum production rates for oil, water, and gas Flowing bhp Productivity Index (PI) Inflow Performance Relationship (IPR) Pressure maintenance (water injection) requirements and how to maximize oil recovery RECEIVED NOV 12 199<l Alaska Oil & Gas Cons. Commission Anchorage Bubble point pressure and gas saturation Reservoir status, saturated or unsaturated Total field reserves Size and capacity of surface production equipment Optimum power fluid rate and pressure Haliburton Reservoir Services will perform the reservoir analysis and prepare a detailed report to present the results. Trico Industries, Inc. will also prepare a report detailing the optimum design and operating conditions for the jet pump equipment. These results will help ensure that sound development decisions are made and that maximum future recovery of oil and gas is achieved. 5.0 Disposition of Gas Gas produced during the production test will be utilized on-site for several lease operations. These uses include the following: Equipment Jet Pump Power Unit Gas Use (MCF/Day) 53 Crude Oil Processing Equipment 60 Boilers 240 Cuttings Grinding Power and Steam Supply 150 Refuse Incinerator 25 Total 528 Excess gas will be flared. An average of 230 MSCF/day of gas was being flared during the last 30 days of production testing. The volume of flared gas will increase if additional production is realized by the surface power upgrade.~ b~_Kt_t.h.e__~total volume flared is not anticipated to be more tha~0~0~'""MSCF/~_~_y~per well. These flare volumes are well below the allo- ~a%b-l~g"~iYs in Stewart'sADEC Air Quality Control Permit to Operate. ~ ~ , ~ /~ ~^,~.~ , . , - , . ~/{~..~::~.~ &,~..~,~ !.-~ ~:,.:~'..? ~ /~ ~ ~-..~,.-., The gas-ozl ratmo (GOR) for productmon mn september 1993 was reported at 196 SC~/bbl. The average G0R during the July 1992 DST for the No. 1 well was 160 scf/bbl. With these GOR values, production from the well will still be in compliance with 20 ]LAC 25.2A0 (b). 6.0 Use of Test Results 6.1 Plan of Development and Operation The results from the proposed well tests will be used to frame RECEIVED NOV 1 2 199} Alaska Oil & Gas Cons. Commission Anchorage and support the Plan of Development and Operation that is to be submitted to the Commission. The Plan of Development will identify the following: Reservoir characteristics Ail available test data Plan for additional wells Pressure maintenance program (water injection) How to maximize recovery and minimize waste Protection of freshwater The above elements of the Plan of Development will be based on all available test data at the date of filing. Additional subsequent test results will likely be submitted to the Commission at the time of the pool rules hearing. 6.2 Pool Rules Hearing At the time of a pool rules hearing, additional test data not contained in the Plan of Development and Operation will be available to the Commission. This additional test data will assist the commission in assessment of the Plan of Development and Operation and determining any amendments to the Plan that may be necessary. The additional data will also be beneficial to the Commission in the establishment of pool rules for the WMR field. 6.3 Integration of Interests Integration of interests in the WMRU leases is very straight forward as the WMRU is a single party unit with Stewart as the operator for both leases in the Unit. 7.0 Summary Additional production testing is required for the WMRU No. 1 and No. 2A wells in order to properly plan for future development of the field. All aspects of future field development will benefit from additional production data because better engineering of the field infrastructure will be the end result. This in turn will prevent waste and maximize ultimate recovery and profits from the field. The additional data will also be required to prepare a sufficient and comprehensive Plan of Development and Operation for submittal to the Commission. This document will be required prior to establishment of pool rules and placement of the field on permanent production. Since it is Stewart's intention to go into permanent production as soon as the pipeline facilities are ready, it is in the best interest of both Stewart and the Commission to have adequate data available for establishment of pool rules. RECEIVED NOV 1 2 1995 Alaska Oil & Gas Cons. Commission Anchorage E & P SERVICES, INC. November 8, 1993 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Attention: Mr. Russell A. Douglass, Commissioner Re: Application for 120-Day Extension to the Long Term Production Test for the Stewart Petroleum Company West McArthur River Unit No. 1 Well. Dear Mr. Douglass: Stewart Petroleum Company (Stewart) hereby makes application for a 120-day extension to the production test period for the West McArthur River Unit.(WMRU) No. 1 well. The previously approved 60- day extension has expired and additional production data is necessary for sound reservoir engineering, design of future artificial lift equipment, and other production facility design. The WMRU No. 1 well is currently shut-in awaiting installation of an additional surface power unit to increase the horsepower and working pressure of the artificial lift system. Installation of the additional power unit should be complete on or about November 22, 1993. Production data for the first 60 day test is attached. To date, the data has been somewhat inconsistent due to mechanical problems with the surface power package. A significant rise in water production began in mid to late August and has stabilized at about 50 to 55% during the last three weeks of the 60-day production test. The water intrusion is believed to be coming from approximately 40 ft below the perforated interval via an apparent channel between the formation and cement. RECE The flowing bottomhole pressure (bhp) during the latter half of the production test was approximately 2800 psi. By increasing the surface working pressure and horsepower of the jet pump unit we intend to draw the well down to approximately 1000 psi bhp. This approach will attempt to lower the water cut through increased gross production, which in turn, will hopefully result in additional oil bearing zones flowing into the wellbore. If the water cut remains at an elevated and unacceptable level'after the increase in horsepower, a remedial program will be designed after g production logs including temperature and spinner surveys. NOV - 8 199 , ka Oil & Gas Cons. Conlnli$~lO"nL Street Anchorage, Alaska 99501 (907) 258-3446 FAX (907) 258-5557 Mr. David W. Johnston November 8, 1993 Page 2 Gas generated from the production test will be utilized for the following purposes: - Firing of the jet pump surface power packages; - Firing of the crude oil processing equipment; - Firing of boilers for steam supply; - Firing of an on-site refuse incinerator; and Power and steam generation for a cuttings grinding operation (reserve pit thawing is anticipated). Excess gas will be flared. Approximately 175 to 200 MSCF/day of gas was being flared during the production test. The volume of flared gas will increase if additional production is realized by the surface power upgrade, but the total volume flared is not anticipated to be more than 400 MSCF/dayo Stewart is currently finalizing plans to construct the 2.8 mile WMRU pipeline from the WMRU ~surface location to the Trading Bay Production Facility. All permits are in place for line construction with the exception of the ADEC Contingency Plan approval for pipeline operations. It is anticipated that the C- Plan approval will be issued on or about November 20, 1993. Once these permits are in hand, construction operations will commence. A 4-inch, schedule 80 gas line will be constructed parallel to the crude oil line to transport all excess gas to the sales point at the Trading Bay Production Facility. The pipeline facilities are anticipated to be fully operational in February 1994. It is very important to Stewart that the 120-day testing extension be granted. This will assure that sufficient data is available to make sound development decisions in the early life of the WMR 0ilfield. The additional data will assist Stewart in the planning and design of future artificial lift equipment, crude oil processing facilities, water injection requirements, and reserves estimates. R[¢EIVED NOV - 8 199 Alaska Oil & Gas Cons. Commission Anchorage Mr. David W. Johnston November 8, 1993 Page 3 If you have any questions regarding this application, please contact the undersigned or Jesse Mohrbacher at 258-3446. Thank you for your attention to this matter. Sincerely, Robert C. Gardner, President Fairweather E&P Services, Inc. and Agent, Stewart Petroleum Company cc: W.R. Stewart, President, Stewart Petroleum Company RECE ¥ED NOV - ~ Alaska Oit & I~as Cons. Comm%ss~o~ Anchorag~ 20OO STEWART PETROLEUM COMPANY WMRU NO. 1 AUGUST PRODUCTION TEST DATA 1500 ~ 1000 500. 345678 9 101112131415 1617181920212223242526272829 AUGUST OIL + WATER ,_ GAS(MSCF) -n- GROSS NOTE: Gas figure is for flared gas only. RECEIVED NOV - B 199~ Alaska Oil & Gas Cons. OOl. itfffissiOf~ Anchorage 23OO STEWART PETROLEUM COMPANY WMRU NO. 1 SEPTEMBER PRODUCTION TEST DATA 2000 1500 1000 500 m~m---m'--'m----m~._ ~ ~--m~-_ .,~.. - WATER GAS ,,I I ,, I ,,I , I ,,I ,, I I,,, I ,,,I,, I ,,I I , I I I I , I I I I I I 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 SEPTEMBER m OIL _,_ WATER . GAS (MSCF) -.m- GROSS NOTE: Gas figure is for flared gas only. RECEIVED NO¥ - 8 199 Alaska Oil & Gas Cons. commiSSiOt' Anchorage 3000 STEWART PETROLEUM COMPANY WMRU NO. 1 OCTOBER PRODUCTION TEST DATA 2500 2000 1500 1000 5OO I I I I 1 2 3 4 OIL , WATER 5 6 7 8 9 10 OCTOBER _, GAS(MSCF)._.,-, GROSS NOTE: Gas figure is for flared and used gas. RECEIVED NOV - ~ 199~ Alaska Oil & Gas Cons. Comm'tss~O~ Anchorage i i i STRATIGRAPHIC NOMENCLATURE COOK INLET BASIN, ALASKA ~ ~ 0 FORMAT I ON DESCRIPTION ! ~ Alluvium and glacial deposits -- Q~ Sterling Formation Massive sandstone and C~ conglomerate beds with ~ ~ 0 -11,000 occasional thin lignite bed. C~ ..~ Beluga Formation Claystone, siltstone, and thin ~. 0%6000, sandstone beds, thin sub- bltumlnous coal beds. o Sandstone, claystone, and C~ I Tyonek Formation siltstone interbeds and c~ I masslve subbitumlnous · ~z-,B 4000'- 7700' " ~< coal beds. ~-~ I~ Hemlock Conglomerate S~zndstone and conglomerate 300'- 900' ................................ Tuffaceous siltstone a'nd ~ West Foreland Formation claystone. Scattered sand- . ~._ 300'-1000' stone and conglomerate beds. RESTS UNCONFORMABLY ON OLDER TERTIARY, CRETACEOUS AND JURASSICROC1 I BY: CALDERWOOD 8~ FACKLER FORMATION THICKNESSES DRILLED STEWART PETROLEUM W.M.R. NO. I WELL FORMATION TVD STERLING FM BELUGA FM 3326 Ft. .,~~-~-~,~*~--~-- 3326' TYONEK FM 5948 Ft. , . 9416' --- HEMLOCK CGL 384 R. ~-~~-~-~~- - 9800' ~ WEST FORELAND FM 51 FT. I I I I I MRU-1 CONFIDENTIAL , L WRU-2A 1240O 1 Bench-I 12588 i~t O0 12800 t ~2OD 127~ iS,900 Bench-2 12800 1:94013 Bench-3 1 13080 I]-5 Bench-6 131 613' · . 13700 West Forelond 132~3 133~3 13403 ~,~Fli]ENTI/~L MRU-1 .'[ 37t. a ,0 i37~4., 0 WEST FOREI~AND CO NGLOMERATIC S ANDST()NE MRU-1 1364~0 .1364~ .,. 0 BENCH-6 HEMLOCKC.ON(;I,OMER~/I. ~'''' .'~ "" "E' MRU-1 CONGLOMER~i,E I ~I BENCH.5 ~i B.ENCH-6 CONFIDENTIAL MRU-~A ELAN- ER~ECI1'VE POROSITY O JO 132~ 2..o ~o ?re::iczing ~:ater Cut by Use of ~'ell Logs By Floyd E. Bettis Schlumberger Offshore Services, Anchorage, Alaska Ouring the preduclng lifo'of ar~ o'i!fie!d. ~'ater saturation and porosity cul: off limits are u<_ual'13, established for the various duci"' ~"" :~ '" '[he :.~se o ~ ' ~.:.r,'a,..,. ~,.er satur&tion i~mit ,,g .... an::.' s'i ng! e ..... vai;,d only i~; i:?,cse cases where t.h=. range of porosity a~"e verb' si~,all. Examp':es ,^'ill be fiiverl 0¢ a prc, ducing ir)terval with a relative large poro.~i:'.y.r'~.:nge: ~',-,ere one water saturation limit is invalid. Two methods of prec"ict';:,r~ wa,.~_.r. ,':ut will then De demonstrated ' " ' ' , ' ' b ' upon e tablishing the usin9 ::)g ,.,ara. [;o'th me~h,.)os ,.~r'e asr-:o s ,,¢c.~ble water vo~.~,r,:, ¢ · S~rr' ': r for the for~,ation ~r~ i. The f'irst method is a cross pint of porosity Vs water satur- ation on a i.::.g.-iog scale. Ail ';¢+:erva'is ~:;hich are at or near irceCuc- iale water s,.'~.~.urat, ion will plot on or' near a line determined by ¢ · .,~,~rr = C for l. he for,~a~.ion, if the gravity of the oil is known, other 'lin:s can be established for '~a,..r cuts of 10 percent, 20 per cent, eton 2. The second method is based on the calculation of three per- meabilities fror., log~,~:~ta,. , intrinsic permeability, permeability to oil and permeability to water. The permeability feet to oil and water is determined ir~ each zone of i '= ' n,._rest and by applying ~:nowledge of the relative mobility of the oil and water,'the..water cut can be predicated. This method is best handled by a computer pr. ocessed interpretation pro- gram. . INTRODUCTION The McArthur River Field1 is located in the Cook Inlet southwest of Anchorage, Alaska. The field has four producing intervals, of which the Hemlock Fox,nation is the most important'. The Hemlock is over 300 feet thick and consists of sandstones and conglomeratic sandstones, with a porosity range from 3 P.U. to 20' P..U~ The interval is further divided into six zones or benches., which are correlatable over most of the field. A waterflood system was'.i,n place shortly after produc- tion started, The field has been 'under.active waterflood for over 10 years, with 564 million barrels of .water being injected during the -2- period2. Total oil production from the Hemlock in the I~,cArthur River Field ~as 380 million barrels at the end of 1979. The normal completion technique during development was to perforate all the benches which ~'ere above the field oil/water contact. Since the average porosity was higher in benches 2(H2) and 3(H3) than in the lower benches, bench 4(H4), bench 5(H5) and bench 6(H6), benches H2 and H3 had higher flow rates and earlier water break through than the lov:er benches. In addition, the production of fluids causes changes in the permeability of the formation, resulting in declining rates. The reperforating of the intervals can sometimes restore the flow rates. Usually, decreasing rates, combined with increased water cut requires a redrill and recompletion of the pro- ducing intervals. The IqcArthur River Field water saturation limit aboYe which an interval would not be perforated, was set at a value of 62 percent. As experience with redrilled wells increased, the water saturation limit was lowered to 55 percent. The flood ~'ater salinities and the formation water salinities are very close to the same value, so water saturation values calculated in flooded intervals should be accurate. In February of 1979, a review of the results of the I,~cArthur River Field redrilling program showed a need for a'better method of determining which benches to perforate for production. The field is on gas lift, so a minimum water cut is very desirable. DETEP~'<I,NING IRREDUCIBLE WATER VOLUME The first step in developing a water cut prediction method was to determine the irreducible water volume present in the Hemlock formation. A number' of wells had been cored and SWirr and po. rosity determined. Two methods were used, one using air to flush the core and the other using mercury3. The value of SWirr · ~ : C using air varied for .035 to .046.. When mercury was used the value of SWirr · f : C dropped below .018. A number of wells were then selected at or near the top of the'structure and plots of SW vs j~ from computer process'ed interpretation were made. Figure I is the plot on one of these wells. This well was completed during development with zero water cut. The plot shows an irreducible water volume C = SWirr · fi of .027. This value of C was confirmed on additional wells and has been used on all additional plots in the Hemlock Formation in the McArthur River Field. It was expected at this point to see a change in the irreducible water volume when the interval changed from sand- stones to conglomeratic sandstones, but this did not occur. One possible explanation is the sandstone grains filling the pore space between the large pebbles are the same size as the sandstone grains in the sandstone intervals. Once the value of C was determined, then the water cut prediction in each bench can be made using the empirical equations presented by Park Jones in 19454. 3 KRW : (SW - SWirr ~ s~FFF' 2 KRO : (0.9- SW_ ) 0 9 SWi Fr KRW Relative permeability to water KRO : Relative per~neability to oil The water oil ratio is defined by equation WOR = ~ Y'W MO 5 KO MW ' Where 8 : Reservoir volume factor for oil KW = Effective formation perm. eability to water K O = Effective formation perm,,eability to oil M W : Water viscosity at reservoir conditions M O : Oil viscosity at reservoir conditions The relative permeability ratio (Kw/KO = KRw/KRo) is available using log data and the value of C from the SW vs ~ cross plots. R.L. Morris and W.P. Biggs6 proposed a value of A where A = 8 MQ/M.w for five cases of varying oil gravities from 45o %o 14o. Fioure ~ Ts a series of charts with value 'of A for 45o, 35o, 27o and 19o ~ils assuming a water viscosity equal to .4 CP. The chart with A: 5 for an oil gravity of 35o matches closely the conditions in the McArthur River Field. Using this chart, water cut lines can now be plotted on the SW vs ~ cross plot as shown in Figure 3. As expected, the points all fall between 0 and 10% water cut. In the porosity range 'expected inlthe Hemlock a straight line from the intersection of the irreducible water volume to the water saturations for various water cuts related to SWirr = 30 percent is a close approxima- tion of the values obtained from Chart A : 5 and will be used in the rest of the discuss ion. See FigUre 4. FIELD EXAMPLES Figure 5 is 'the SW vs ¢ cross plot on the first well in which the water cut prediction method was compared to the Field Water Saturation cut off of 55 percent. A large number of the points plotted in the six benches, plotted between the zero and 10 percent water cut lines. The exceptions are the points which are circled and labeled H2. These points are in bench 2, and are of special interest, since they fall above the ~'ater saturation limit of 55 percent set by the field operating unit. In contrast, the SW vs ~ cross plots indicate a water cut of at least 40 percent. Figure 6 is the output of .an experimental com- puter processed interpretation program, a 3 perm Saraband, in which three permeabilities are calculated. They are the intrinsic permea- bility, the relative permeability to oil and the relative permeability to water. In intervals where SW is near SWirr the computed relative permeability to ~'ater will be near z~ro and will increase as the SW increases v;b. en compared to SWirr. The computed permeability to oil will be at a maximum when SW is close to SWirr and will decrease as Sk~ becomes greater than S~irr. The Hemlock was completed starting in H4 and actual water cut determined after each bench was perforated. H4, as predicted from the SW vs ~ cress plots and the 3 perm Saraband, had zero water cu.t. After bench 3 was perforated the ~'ater cut was 10 percent. The 3 perm Sarabond shows an increase in the relative permeability to' water at the base of the interval perforated. Bench 2 was then added to the perforations~' Water cut now jumped to 90 percent. This 'demonstrates the advantage of using the 3 perm Saraband or SW vs ~ cross plots to. pick the intervals to perforate as compared to using the Field ~:ater Saturation limit of 55 percent. Figure 7' is the Sk' vs ~ cross plot on bench 1 of the first well which was co.~,pleted using the SWirr · ~ : C : .027 method. The plot shows H1 should make near zero water cut. Figure 8 is the plot of bench 2 which indicates a water cut in the 30 percent range. Figure 9 is the plot of the top of bench 5 which is separated from the rest of the bench 5 interval by a shale break. Figure 10 is the 3 perm output on this well, showin~ the perforated interval and confirms the zero water cut expected in bench 1. Figures 11, 12, 13, 14 and 15 are the SW vs ~ cross plots on an infill well drilled in an area where it was expected to have most benches near zero water cut. The cross plots indicate the only H1 would yield low water cut. H1 was not perforated because total log data indicated poor reservoir characteris, tics due to high silt content. H4 was selected for a completion attempt. The cross plots predict a water cut between 20 percent and 30 percent. The well was completed with a water cut of 25 percent. The final example shown in figures 16, 17, 18 and 19 are on a recent redrill which was necessary because the well had a water cut of 90% coming ~from H2. The redrill was moved down dip on the nose of the structure to penetrate the most promising interval. Figure 16 shows Sw vs ~ cross plot in H2. It indicates a very high water cut as expected. Figure 17 is the plot of H3. It is divided into an upper and lower section with isolation due to a shale break. The upper zone shows a very high water cut and appears to be poorly isolated from H2. The lower zone indicates a water cut between 20 to 30 percent. Figure 18 is the plot of H4. This plot shows an interval of 146 feet ~'ith a predicated ~'ater cut of less than 10 percent. Figure 19 is the plot ,of H5. This interval is divided into two zones, an upper and a lower. The lower interval has a much lower water cut predicated when compared to the upper. Figure 20 is the plot of H6. The plot indicates H6 should make a high water cut. H4 was selected for completion. After perforating the-well flowed 2580 barrels of oil per day with less than 1 percent w'ater cut. This is an outstanding redrill completion in a field which is entering a declining stage of its producing history and has produced about 80 percent of its expected recovery. · CONCLUSION Two methods of predicting water cut from well logs have been presented. By determining SWirr · ~ : C and cross plotting porosity vs water saturation on a log-log scale, water cut lines can be de- termined. A computer processed interpretation output, which determines the relative pe~-maability to oil and the relative permeability to ~'ater by.using SWirr · ~ : C can also predict water cut. These methods have proven superior to the traditional method of setting a single value of water saturation. limit for the McArthur River Field. 1. Oil and Gas Fields of the Cook Inlet Basin of Alaska. Alaska Geologi. cal Society. 1975. 2. Statistical Report 1979. State of Alaska Oil and Gas Conservation Co,,mi ssion. 3. Core Data supplied by I.',cArthur River Field operators. 4. Jones, P.J. "Production Engineering and Reservoir I,~echanics (Oil, Condensate, and Natural Gas)". Published by Oil and Gas Jour. (1945) pp. 45-46. 5. Person, S.J. "Elements of Oil Reservoir Engineering". NcGraw-Hill Book Company, Inc. (1950). pp. 291. 6. R. L. Iqorris and W. P Biggs "Using Log-Derived Values of Water Saturation and Porosity". ~C ,o %'A1ER CUI' CHAR'i' A = 2 Y~'AIER CU! CHART A : 5 !o i ! t 7D aO 6o 'wA1ER CUT CHART A = 10 ]?o WATER CUT CHART A = 20 IO 7 ! ! I ! 20 :il) 40 .~0 60 -- s ,.,.j~) I I 70 ao I0 ~0 30 J ! ,~0 s i. /~6 .5 CI.~A ~Cl E I,,.S TIC.S IOO % 0 H~ J, oc ~,T~o. 0 (&' S~v) i ~ ~ I~C ~' I % OF IUtC v~. H,~.,~ i w.,., "~:, ~'"'":' SILT ~ 0 I~ 0 ' + i , ' -'Z:-': -. i I o · e~' · -/*k~ o o (~ · s~,l .2~ % o i '_L:' iI I:I. 11 :~i°' ,."7': I. UpPd& !1 /'/5 USING WATER LOG-DERIVED SATURATION AND B~ R. L,. Mo~is and ~V. P. Biffs Schlmaber~ WeLt Services, Houstoa, Tern VALUES OF POROSITY ABSTRACT Modem logging methods provide good values of [~orosity and water saturation M most reservoir /ormatiou~. These p~ete~ ~ es~eat~l M the c~mii~ o[ in.place byd~cw~s. Howe~er. /~ati~. A~i~i~ai rese~o~ and fluid ~poties m~t be c~sidsre~ To determine whethe~ a zone shoeid prodm:e clean hydrocarbons, or with a wat~ cal, the com- ~ted wat~ sat~ati~ ~ compwed 'wiM Me ~dKibie wat~ sdtwati~ o/ the intuit. The. i~ter uaZM c~ ~e~entiy be det~Med ~m d plot o[ ~sitiez uer3~ water 3at~4~ t~Jgboat the f~i~ of interest. Thi~ meth~ of defYiNg i~e~cible water sat~ti~ b~ been ~o~ ~d ~ed f~ m~ ye~. Today, with Me inc~ed acc~acy and efficiency of modem logging ~elbo~. For intervals indicated to be above the tranzilion zone, the com~uted values of porosity and Tbe~ aigmented ~ ~/edge of f~~ ~zsire, ~d fluid uiscosities and uol~e fact,s. these dam ~ a ~~ble e3timale of ini~l rate o/~ucti~ from the un,rated intervals. Additioa~ emp/eical methods ~re szed lot the estimations o[ r~lati~e pemeabilities to oil ami water/or iatm'odLs in tba transiticm zone. They prouide re&so, ably ~cc~rate estMatimL1 of :be water /,,cUcm o! These methods are asr/al in carbonates od s~d formations: both clean ~nd sbaly. They es. Me--ct ~edicti~ of ~oducti~, and tbe~ ~i~ a check ~ the efficiency of the com~Jeti~. INTRODUCTION What will ~e zone produce? WL1/ Lc produce cle~n oil, o~ ~ water, or o~y wJcez? [s Lc s~t~en~y p~~le? For ~velopmenc of o~ p=o~c~on ~ese ques~ons ~e ~. More ~d more ~ ~e ~t~ co ~e lo~ ~ysc. He c~ provide ~e answers ~rou~ ~ co.claire sm~ of lol-de~v~ v~ues ~ water ~aSon ~d porosi~. Much has been wrtnen on using logs to determJne porosity and water ~a~on. ~ese p~amecers ~e impo~c ~ rese~oir compu~ons; when co~ined ~ rese~o~ ~- mensions,- ~ey e~le compu~on ~ ~e vol~e of ~-place hy~~bons. HI~ poro~ and Iow water sa~a~on are ~~le ~ pro~ve propel zones. ~ s~l~en~y ~ and low, resp~vely, ~e zone m~y ~ co~id~y r~ommen~for comple~oa. ~ consider~ sep~a~ely, ~e v~ues ~ poro~ ~d w~er s~r~on ~ no~ r~y eider ~e ~e or rate ~ fl~d pro~c~on f~m ~ zone ~ ~ceresc. ~e p~~ p~blem of ~e lot ~ys~ ~en is d~i~n~ c~~ v~ues for ~ese p~e~ers. Wi~h experience in a field or forma~on ~he analyst may know ~he values requ~ed for effecSve proc~cfion. For example, he may know ~hat a cerr~tn sand, wt~h an averase porosity of 25~, ~ produce off wir~ only he,Liable quan~fies of water as Ions as ~he water sam- ra~on is less ~han $5~o. Or, expe~ence wi~h a ~ven Ltmeswne forma~on may show porosiSes ~reater ~han 6% will produce oil. and ~at as lon~ as ~he water sa~ra~on is less ~an ~0% ~he water frac~on will be toler~le. Such empiricisms are useful. They are s~e ff forma~on character~s~cs are un~orm enough for ex~rapola~on from well to well, or field to field, But how ~re cr~cal values demrmmed where d~e char~cter~s~cs are not ficlendy un, om, or for wfldca~ weils where emp~-~cal dar~ are not available? ii i SP INDUCTION-ELECTRICAL 0 ohms 100 I I II II 10 BULK DENSITY -~+ 2.5 grams/cc 3.0 I · iiii i Rm{ = 1.1 ~ 110° F. R~ = 0.13 ~h~ Fig. I - Logs recorded in a Wyoming uzell. q Cross-plot comparisons cf water saturation and porosity usually solve ~he problem. Correspondin$ values cf wscer saturation and porosity are computed from the logs i: more- or-less relular intervals ch~uihouc :he zone cf interest. Plotted on I linear lzid, these values ~ic panerns ~ indicaxe whether me intervals are aJ~ve or within ~he off-water ~rans/~on zones. Then. for intervals indicated w be above me zone cf ~ransi~lon. the com- puted values cf porosity and water saturation can be used in an emplxical method to escimam permeabtltty. These techniques are not new. Early papers on capillary pressure studies suggested a coherent relationship between irreducible water saturation (S~)and porosity (~)values when plotxed on a linear char~¢t'~) Analyses cf cores rakes in wells drilled wi~h off-base muds indicated ~hat plots cf waxer sanu:ation (Sw ) and porosity could be used to dlfferen,~-te between ~he intervals above and ~hose within ~ransicion zones.¢4) %Empirical relac/onships between permeability, irreducible water san~rat, on, and porosity were presented almost twenty years t~o ks); these, and atmflax relac~onsh.tps <6), hive since been used with good success. However, is old and as potenctally effective is these various porosity vs water sanitation methods are, ~hey have not been used extensively in weal evaluations based on lo~ analysis. Perhaps the Ilmited application cf the methods resuAted from lack cf accuracy with los-derived values, The. logs cf even an Ltcfle as ten years ago fatAed to provide the resolu- tion or accuracy needed to reliably ee~blish coherea~ Sv vs d pamerns. But today's lo~a do. Basic measurements cf formation resistivity, deast~, acoustic velocity, and neur. ron lo$ characmris~ica are improved. Wl~h combina~oas cf da~a fr~m several lo~s we can mow recognize li~ological changes and can thus compum more accuram values cf bo~h porosity and water samra~on. It is ~mne to rake another look at Sw vs $ comparisons and a~ ~heir applicac~ons in 1o$ analysis. The purpose of this paper is to show how log-derived values of porosity and wa:er saturation may be used to predtc~ type and rate of fluAd production from oil-beeries for- mations. Some cf the methods are reiterated from previous publAcacions~ o~ers are new. The quan~ml:tve aspecte of the methods axe valuable. Even more valuable m the lo$ analysr~ however, is the ability of the methods m rescue an interpretation--to reco~d~ the effects of unusual forma~on conditions before the well is erroneously either completed or abandoned. TABLE1 ' ' WYOMING WEI. L ' O-J BASIN WELL, " i i · i i i i i i P.int 1 57 13 49½ 24 2 53 15 55 23 3 44 18 62~ 23 4 42 19 6~ ~ 6 42 19 61 21 7 ~ ~ 61 21 8 ~ 23 ~ ~ 9 ~1 21 ~ ~ 10 ~2 ~ 67 ~ 11 ~2 ~ 7~ 21 12 69 22 13 71 21~ Avmage 43 19 63 22 CROSS PLOT OF WATER V$ POROSITY SATURATION Cursory eximtnscLona o/ lo,a, o~ ev~ ~ loi-~ved v~u~ porosi~, ~ be mi~e~~ For ~ple, Fils. I ~d 2 ~e m~ons of logs from w~s. ~e ~c~on-~~ S~ ~d Fox.on ~n~ Log s~o~ r~or~ ~ a Wyo~ w~ ~ ~i~ 2 ~e ~ons ~ ~ ~c~on-~~ S~ey So~c-G~ ~y Los r~or~ ~ ~ D~ver-J~~ B~ W~ ~e ~ ~ ~er~ ~ ~ese ~ w~ (4,~2-~512* ~ P~ 1, ~d ~02~58 ~ Pi~. 2) ~e on ~e I-~ lols. Bo~ ~ ~e de~~d ~ ~y ~y. A su~i~ ~Uon of ~e lo~s f~s ~o ~~e ~ one ~d wo~d be ~ ~ p~~z ~ ~e o~er. Fig. 2 - Logs /rom a t~ell in the Oent~er.]alesb,~rg Basin. Even when the values cf water smmxacion and porosity from the cwo weals axe corm- paxed there ts no clear indica~on Gat one well wouAd be better than tho ocher. In ea~.h well. lo~ values were ~ad' at cwo-foot intervals cbxough the zones of Interest. From these dan cbs con-espon~ values cf porosity and water saturation were computed. The results of r~e computations axe shown in Table 1. It is eviderm chac both sands contain hydrocaxbens. The sand cf Fig. 2 has, on the average, ~gher values cf both water samxacLon and porostm/. But. cbe values of water samxacion axe nor so ~t~ thac c~e zone can be categorically com. denmed~ many wells produce clean oil from zones with even lxtgher water samA-a~lons. Experlenca with a given sand p~vides lmowled~ of cxictcaA value~ of water samma~on. Without experience, however, additional invesclgacLoa is needed before the sand in Fig. 2 cas be cordials, ally recommended or condemned. Recognizing Zones at Irreducible Water Saturation Wl~e a cursow exAmAnacion of water saturation and porosity values is inconclusive, a c.-~es-plo~ comparison of point-by-point values ~ the zone usually solves the problem. Fig. 3 in a plot of Sw vs qb values for the Wyoming well (Fig. l}. The points, numbered in order of descent throu~ the sand. fall in a coherent pattern, closely conformin$ w a single hyperbolic curve. In Fig. 4, similar plots cf data from the O-J Basra well are scactered~ the plotted points fail w describe a coherent paxzarm. The d~fference in the cwo plots ts ~e basis for extending log a.ualy~. The sand in Fig. 1. vlch the coherent Sv va qb. plot. is at irreducible vace~ saturation (S~) and will produce oil wl~out predu~g water. The sand in Pig. 2 ia in r~e ~an~lclon zone (between S~ and 100~ S,,) and should produce water, wtch or mchout off. 20 15 I0 / lC: 100 md / / / / / 10 md I md C = 0.078 i,, I I [ 0 20 lO 60 80 100 Fig. 3 - Cross plot o~ Sw vs qb values co~. puled/rom lo. gs in Fig. I. 2O IOO logs in Fig. Z. The pre~Loualy r~erenced pipers discuss ~elir~onships betwee~ c~pQ~U ~ess~es, irre~le wamr sa~a~ons, ~ro~es, ~d ~rm~~es. ~ere ~s ~ener~ a~me~ · a~ for a ~ ~ ~e ~d/or ~ ~e, a co~ela~on e~s~sbe~n ~re~le wa~er ~~~ ~d porom~. F~~ore, ~s co~a~on Is ~ sa~ac~o~y press~ ~ a ~le ~on ~ h~r~c fo~: ~3.4) where. G - a constant for a particular r~x:lc type and/or gr~i,,_ size. The points plotted in Fig,. :3 fall on, or very close co, a hyperbolic line described by S, = 0.078/~b, (Or, the produce $, . ~ is nearly constant ac 0.078 thr~u~hou~ the zone). This coheren~ pattern is thac of a homogeneous formation ac Lrreducible water saturation, and thus indicates oil production from the zone should be wacer-freeo Estimating Permeability Once Lc is established thac a zone is at irreducible water saturation (i.e., above the transition zone), the los-derived values of Sw and ~b may be used to dezermLue a reason-. able ea~mr.e cf the formation permeability. An e~cal equation used in this est~natlon ia al follows: ~6) where k A ~raphLcal expression of Eq. 2 is ~Lven in Pig. 5, Is~pe~~~ c~es ~e plo~d v~sus S~ ~d ~. ~e~ c~ ~e plowed us~g c - 2~ for m~ ~ ~a~ offs, ~d c - 79 for ~ gas. S I m 11 a r p I o c s of is~permeability curves can be made on the ~, v. ~ plo~ used co reco~ize zones ac irreduc, lJ31e wa~er san~ation. Curves for 1, 10, and 100 md are superimposed on Fig. $. The positions o~ the plotted points with respect to these curves indicate a wide variation of per- meability through the zone, varying from I co 90 md. However, points for levels numbered $ through I]. fall between 10 and 100 md. and indicate ~he zone is suf- ficiently permeable for effective production. Thls sand is presently producin$ 70 BOPD, 1530 Mcr/D, and no water. 21 IN GAS I IN OIL k .-- Permeebilil~ ' ned 0 20 40 60 I0 10O $1rr Fig. 5 - £mpiricai reiatioasbip between permeability, porosity, and water sataration /or Oil and gas ti~s above tr~sition zone (Eq..2). Transition Zone Plots Tranatrion zorn are recognized by their faUu~e to form coheren~ h~erbo~c pa~ on S. vs ~ ~ ~o~. F~e~ore, ~ ~~on zones, ~e v~ ~ wa~er ~~on ~end co ~~ ~ ~~ ~ ~ ~e ~.~ese~~s~emo~a~~cin ~o~ ~~on zones, but ~e ~e~le ev~ ~ ~ lon~ ~~on ~ne~. The plot of Fig. 4 is typical of a formation deep in a long rranatrton zone. It indicates that production from the zone will include water. A ~ stem test of this zone produced 17% oil and 83% water. When ~he zone of tntere~ is ~n but near ~he to9 of · long ~ran~Lclca zone, i~ my re~ ~ a rea~~y coheren~ p~ on ~e S. v8~ c~8aplo~~lein~e~d~ F i~. 6. ~ese los sec~ons w~e r~ord~ ~ a d~ W~cox ~d ~ L~~. ~ ~e older zones (as ~~ed by ~e ~m ray), wa~er ~~on ~d po~s~ y~ues w~e compu~ ~d cross plo~e~ ~e res~ c~sa plo~ ~ Fi~ 7, d~~es a f~y c~~t patc~ ~d su~e~s ~ ~ov~r~sl~on off zoo. ~e ~m~ co~o~ r~~y w~ co a c~ ~ Sw ~ - 0.~0~. However, core cap~lary pressure mea~Lremenm (a~r-brine) were available. The va ~ ~ f~m core m~men~ ~ ~ plo~ ~ Fi~ 7. ~ ~s ploc w~ · e l~t ~ ~e lo~-de~v~ v~ ~d ~ a ~e ~ S t~" 0.~. ~us, ~e z~e ~~s co ~ ac ~e c~ ~ a f~lylon~~~~n~~p~~f~m~~ne (1083~87 fO w~ water-free, buc ~e hce~ p~c~ r~ ~owe a 5% ~r ~ While an Sw vs ~ cross plot from the top of a long rranst~ton zone describes a her~c pa~e~, ~e zone may pro.ce some wat~. However, b~use ~e wat~ u~y low, ~a · e ~re~on me.od; a coher~pa~m ~~es o~ p~c~om zo~ is no~ a~ ~e~e wa~ p~~~ es~~s ~ ~ ~s~~c. ~NOUCTION-ELECTRICAL SUIWLry SP 1o · ,. .', Fig. 6- Logs recorded in a deep ~[ilcox sand in Louisiana. · 0 ef Sire end ~ · Log.deelvad Sw and ~ I 20- c~ o · II-' 16t- O~ 14- ' 67 2 12- 5w~ : 0.10~ IC- I I I I I 20 40 60 I0 100 Fig. 7 - Plot o/Sw us d~ /rom logs in Fig. 6 describes reasonably coherent pattern. Compariso~ mitb co~e data indi~:ates /ormation to be in the top o/a long transiti~ zone. .J Importance of Correct Sw and Data The efficiency of the S. vs ~ method for extendin$ log analysis is largely dependent on cae accuzlcy of CAe S v and ~) values. The more accu:ately these values are determ~ed, the more etfecuve is the dt~Uon between formations above and cAose in ~anslcLon zones. Further, permeab~LW estima~ona are parcl~arly sensitive to errors in CAe values of porosit7 and water sanLration. The cross ploc data in Pis. 8 were r~ken from loss recorded tn CAe Smackover for- mation of an l~ant Texas well. Formation resistivity values were obr~lned from an Induc~Lon- Electric Los; forma~Lon water reststiviW was obtained from a water car~o~. T~is formicLon ~s composed primarily of varying fractions of lhnesmne, dolomite, and anhydrite, To obtain the best possible value of porositT, data from density and neutron logs were compared: fLrst, co define CAe licAology varia~ions from inte~wal co interval; and, second, to cAere, by compute the porosity, c?~ A cementation exponent m - 2 was used in the derivation of for- motion factor for CAe $. computations° With the exception of data points from CAe bottom ten feet of ~e formation, CAe points form a coherent pattern. This pa~ern conforms closely with a hyperbolic cu~e of S.~ - 0.008. Thus, cae points in cae pattern are deemed to represen~ levels ac S~rr . Data points (open circles) from the bottom ten feec of formation a~e sca~ered, and show a definite trend of lncresaing S w with increased depth. The lower ten fee~ are obviously in the transi- tion zone~ 2O 18¸ · FOC.NouIroa K z IQQmd 10 md / / ° I md / / · · C mo. OOl i I I I I I 10 ~0 30 &O $0 60 Sw Fig. 8-Cross plo~ o! Sw as ~ /rom logs i~ Smac~mt, er Li~e. East Texas. P~ities ~ete~ined /rom and ~ea~ Log dam. lC z I00 md Smeekover Limo 10 md 0 o · /I md ~ S..ic / o Peeosi~ from Sonic vma 23,000 Yf :~ 5,1QQ · C -" O.OOl 0 lO 20 30 ~0 $0 60 Sw Fig. 9- Cross plot o/ data /rom same ~n. :orval as in Fig. 8. but u~ith porosities determined /rom Sonic Lof. Bec.iuse cae coherent: paL'zerfl ~dJ.c~tee r. Ae log-d.e~ved values ~ $,, equzJ.$tr.r , permejJ3LLLz:~en m~ty be escLmzted ua~$ Eq. 2. F'rom c~e sul)ezl.mposed c~'yes i wl, de range ~ pezm~~es a.~ e~denr,. ~or., of a nmnber of levels ~ciLc3ce pezmetJo~es i'z~cer d~i.u J. O0 md, The ~w va ~ cross plot in ~ ~ Hm~ ~o~ev~, ~~ ~u ob~ ~m ~~c~o~U~o~y~e~c Log i: la hOC poss~le ~o a~t foz v~ona ~ ~olo~. ~e~ore. ~~es w~e comput~ ~~~ ~e en~e s~on co 23,~ ft/s~. ~e ~ov~~on ~ta genez~y co~o~ ~o · p~ ~ Sw ~ = 0.~8. However. ~e ~ot Is more ~e~ O~y one ~ ~es ~a 1~ md v~ue; pe~~U es~es f~m ~s plo~ wo~d ~ ve~ pess~s~c. In d~e compulsion of $. and ~ rJ3eze are od~er sotLrces for error. For example, S. values are affec:ed by errors in ~he value used for forma~ion water resisciv~t7 An improper value of R. usually will not ~reatly alter ~he ploc coherence~ ~he plot may differentiate between levels at S tr~ and those in ~he ~ranatl~on zone. However, permeablltt7 escLmaten ~ be erroneous because d3e computed value of S. is wrong. Heterogeneous Formations Hetero~eneoue formations, ~hoe® with varytn~ rock Upes,. complicam incerPre~on of S. ve ~ cross plo~s. For forn~ons above transi~on. ~he S. ~ value is determined by ~he rock type, or by average ~ size in sandsmaee. If a forma~ includes zones of differen~ rock types or ~ratn sizes, and all are above ~he ~ranstc~on zone, coherent pa~arns for each type will appear on Ge S. vs ~ cross plo~. For example, d3e plot.ed da~ on Fi~. l0 ~re scamered and ~~ ~ac:e~s~c d plo~ f~m a ~~on zone. ~e ~~ v~uH ~ro ob~ f~m ~~n ~ de~ ~d n~n ~. ~ese comp~~ ~ ~~ ~e B~olo~ ~ ~e fox,on as v~g ~~ ~ ~zone, ~y s~mne, ~d ~1o~ ~escone?) In Iris. 11, ~hese same points are idem~fled accordiag m ll~holo~y. Two major pa~erne now emerge. Bach is reasonably coherenr~ The doloml~ic ]Jmestone intervals describe a I0 · · · · · · · · I I , I I I t I0 13 20 2J 30 35 40 0 ~3 Dolomiflc Limesl®eo 0 I O! I , I I I I I, I Sw Fig. lO-Scat:fred cross plot o~ log- derived ~ata ia a beterogeseo#s /ormation. Pig. Il- Coherent ~attems emerge ~hen :be cross plot ~oiats o~ Pig. ~0 are identi[ied by ]ithology. pattern to ~he le/t of a sandatone patterr, The "~y s~tone" ~te~s f~ be~n. Two s~tone ~ts f~ ~ ~e dolo~c ~estone pa~:e~; ~ese ~m~, however, c~e from ~e ve~ t~ ~ ~e fo~a~on cap. ~ree points f~ si~i~y ~o ~e ~t ~ ~e~ reap~ve ma~ l~es (dolo~c- ~mes(one a[S. - 23~ ~ ~ - 18~ ~ - 13~). ~ese ~m~ ~e f~m me lowe~ost p~ ~ ~e fox,on ~d prob~ly represent en~ ~to ~e top ~ ~e tr~i~on 'm' Variations A cementacLon exponent (m) o/ 2.0 is commonly used in Io$ interpretation of carbonate forma~ions. Or, 1 1 where F ts ~he forma~ion resis~ivit7 facwr used in computation of Sw HoweYer, in 9ome carbonate rocks~ ~uch as ooLLcas~Lc llme~wne, d2e true "rn" ponent may be as high as 2,8. From lo8 dam alone it ts lmpoaaiMe to define variations in "m': There/ore, as indicated by Eqs $ and 4, incorrect values c/S, aze computed when ~be cemenmllon exponent is erroneously assumed to be 2.0. rf ~he ~z'ue cemenrA~ion exponent Is hi~her chon 2.0, the resulcin$ values of water saturation will be wo low; a 100% water- saturated formacton may even appear to be hydrocarbon productive. This problem of ht~h "m" valuea has Ions been croublesome in classic Archie me,ods of lo$ interpretation. 3Q ii i i i i i "m" = 2.8 2.,~ 2.2 2.0 lib · , I I, & I ,~ 0 20 ,~0 60 80 100 Swa Fig. 12- Incorrect assumptions of cemen- tation exponent "rn" lead to revers e.s lope plots in 100% water saturated carbonates. 0 0 · I0 2 · II · 8® 6 · ! · 20 ~O 60 80 100 Sw Fig. I$ -- Scatter plot from water, productive carbonate formation in North Texas. The ~ vs ~ cross ploc offers a po=~',~t solt~Lon for r~s problem. Fig. 12 ~ows ~e compu~ ~:s on ~e ~ss ploc of M~ "m" v~ues. For ~ c~e ~e ~e wa~er "m". ~e er~r in ~p~ ~er n~a~on is ~r~e for m~ v~ues ~ "m". For e~pl~ ~ 1~ water sa~c~ fo~a~o~ m~ m. L8 ~d ~. 10~ I~ co ~ app~c wat~ ~aOon ~ ~ However, ~e "~ope" ~ ~e Sv ~ c~e is rever~ ~ ~s ~c co~o~ ~o ~e h~er~c r~on~p es~~ for zones et S~. ~~ore, ae cross plot ~n~s ~ a zone. The cross plot ht Fl$. 13 resulted fr~m interpretacton ce lo~s ~ ~ · ~o~ T~s c~~ fo~on. A den~-neu~on complan ~~ed ~e fo~on w~ ~y ~lo~c ~escone. ~a~r ~~o~ ~mpuc~ for & n~r ~ ~e ~e~s be~n ~ ~d ~%. However, ~e cross ploc po~s, num~er~ ~ o~er ~ desc~c ~u~ ~e for~o~ ~e sca~ere~ ~ey f~ m de~e a coheren~ pa~e~ and ~us pro~le water pro~cao~ A ~ s~em cesc ~ ~e fo~s~on r~ver~ o~y w~cer. The low water saO, LTations tn Fi~p 13 may hive resulted from use ce an incozTect cemenr, a~ton arq)orient.. We ttsed m = 2 in the computations ce Sw . It is enti,rely possible that "m" is actually ~er. Ir the formation Is assumed 100% water saturated, appro= prt~te value, s ce "m" for e~ch level can be computed. These valuse range from 2.2 co 2.8. We have no confLrmacton chat "m" varies, or chat it is actually hiSj2er than 2.0. However, ~ts example illustrates ~he tTpe Of cross plot that results when '°m" varies (upward from an assumed value of 2.0) in a 100~ water nmrated carbonam. It further illustrates how the cross plot can rescue an ~nterprecation in such formations. Sholy Sends The Sw va ~ cross plot la a~o useful in the study ce sl~ly sande. However, sppll- c~cton ce the method Is slightly different from tha~ for clean formations. Shaly sands are heterogeneous due to vn.rymg mounts of thy or shale. In addition, 'there sly bo hecerogenetty due co Goss changes in sand grLin size. As a result ~he Sv ye ~ crosS plot ~end~ co be less coheren~ rJ~n in clean The I-ES log of a Miocene sand in $outh Louisiana la shown in Fig. 14. Between 12,570 and 12,628 ft the sand is subdivided into three ca£e~orles: h18~2 resistivity zones, "A"; .medium resistivity zone~, "B"; and one Iow reactivity zone, "G". Dam token at 2of eot intervals f~'om the induction, sonic, and density logs were used to compute water saturations, assuming a dispersed clay model for the md. ~?) These values were computed uatng the following equa~ionss R~ ' +-~ --'2- 1-Q SP Resistivity 10 -I.~+ 0 ohms Fig. I~- indactios*£lectricai $#r~ey o/ a sbaiy.,t~iocene s~md. Louisiana, where: wa~er sav. Lra~on assurnmK :he shLly sand ~o conform ~o the persed clay model form~tion factor derived from sonic data (not corrected for shale effects) apparent clay fract/on c/ the pore volume as computed from sonic and denaity data apparent porosity from ~he sonic data (assumed to be total po- rostty, lncludin$ fluids and clay) apparent porosity fr~m denatty data (assumed to be effective porosity) DEPTHI I~E$. OEI~. SON Q 1~0 1.~ 1~9 ~1 .3~ 1~2 ~ '18.7 ~.7 .~ ~.0 5~0 1~4 5.~ ' 18.1 ~. 1 .~ 1~6 10.00 18.1 ~. 1 .~ 13.5 35.4 1 ~ 6.~ 21.2 21.5 - 0 ~.3 ~.3 1~0 6.80 21.2 21.5 -0 ~.6 ~.6 1~2 6.~ 18.1 17.9 -0 34.7 ~.7 1~4 2.~ 15.1 ~ 1 .3~ ~.0 63.0 1~ Z~ 2~0 ~.0 .1~ ~.5 ~.0 1~8 ~ 18.1 17.9 -0 ~.2 ~.2 1~ 3.~ 1~9 17.9 .2~ 51.0 6Z0 1~2 Z~ 9.0 15.8 .~ 89.0 93.0 1~4 1.~ ~.0 28.7 .~ ~.0 1~6 1.~ ~.0 ~.7 .~4 ~.0 ~.0 1~ 1.~ ~.0 ~.7 .~ 4ZO 59.0 1~12 8.~ 2~6 ~1 .~1 21.0 ~.0 1~14 14.~ 2~6 ~ 1 .~1 16-0 ~.0 1~16 10.00 ~.2 ~1 -0 17.4 17.4 12618 7.~ ~.2 ~.2 .O~ 18.0 26.0 1~ 4.~ 26.6 ~.4 .095 ~.0 1~22 ~00 24.2 ~.4 .1~ ~.5 ~.0 1~24 1.00 21.8 ~.7 .241 54.0 65.0 1~ .~ 21.8 ~.6 .1~ 715 1~ .55 2Z4 2~4 ~ .083 85.0 86.0 The mac_h~ne-compuced results are siren in Table The cross plot of SwQ ~nd ~ in Fi~, 15 shows consider~ble sca=er. However, lden~t~on ~ ~ ~n~ ~ rems~ ~e~w ~.e., A, B, or C) h~ps d~e ~o sep~ p~ne~. ~e "B" zone pom~ f~ ~o ~e ~t ~ ~o~ f~m "A" zones. ~e ~m~a f~m · e "C" zone ~ow ~ r~l~y ~cr~~ wa~r ~a~on m~ ~, ~~g pene~on ~ ~ ~o~ ~~on zone. Studies of shaly oil san(ts have indicated ~hat more coherent patterns are obr~tned by including shaliness in the saturation data. This is done by un, rig $= in the cross plot. S= la defined as (he percent o~ total pore space occupied by both water and dispersed clay. Or, The machine-computed values of Sz are also Styes in Table 2. Fl~. 16 Is a cros~ plot of Sz va ~D · With the shaltness factor, Q, thus included, the patterns for the "A" and "B' zones are more clea~ly defined and separated. These patterns are tTpical for $trr conditions in a heterogeneous sand. They illustrate the effec~ of ~-ttn atze cha~ge in the formation. The finer ~rain sands con~orm to a hl~her $w~ value, and plot to the right o~ the ltr~r-~ratn-sand zones. The "C" zone is a~ain indicated to be a transition zone, with water saturations increutn~ with depth. ]4 O 20 40 0 lO IQ0 Fig. 15 - Cross ldot of log.derived data from sand in Fig. 14. 21 24 ~0 (j~O II Id" 1C - teuliluae t,, I I I , I, 0 20 4o d~O Io I00 SZ Fig. i6- Better resolution is obtained in shaly sand though cross [,lot of Sz vs q~D (£xamlrle /rom Id.) PLOT OF BULK VOLUME WATER V$ DEPTH The fore.inS discussions have shown that the product Sw6 tends co be cons~ for homo~eous, hyd~c~bo~be~ fo~a~ons ~ove ~e cr~s~on zone. ~er~ore, ~ plo~ ~ Sw ~ vs dep~ shoed ~~e: ~. ~en rela~v~y cons~ ~a~ ~e fox,on ~s homogeneous ~d a~ lrre~le wa~er ~2~on. 2. ~en ch~S In lev~, bu~ ea~ lev~ re~n~ rela~v~y cons~, ~ ~e fo~a~on Is a~ lrr~~le wa~er ~a~on bu~ Is he,cross--us. 3. ~en ~:ea~y increasm~ m~ ~cr~s dep~, or va~ns as porosi~ v~es, ~ ~e forma~on is in ~e ~r~si~on or wamr zone. This product $, ~ is, of course, an expression of ~he bulk volume water frac~ton (BVW). A plot of S. ~ vs depth is pzr~lc~ly suited to study of shaly sands. In chis sppll- cation the value of water samracton is computed on the basis of a dispersed clay model. This value of S,o is then mulctplted by ~D, and the produc~, represen~in$ bulb volume water (BVW), is ~lor~ed versus depth. Then, tn addil:ton to the plot of BVW, values of and ~s ara also plotted. The value of ~'s is assumed equal to the combined clay and fluid n anG BVW Is con~t~ereume cia o The difference becwee considered the bulk volume bulk volume hydrocarbons. INOUCTION . ILI~'IICAL o IO ~O 3o Fig. 17- Plot us depth o~ b#lk uolume water. C~D, and ds simpli[ies eual-etioa o~ sbal7 saad tion. SP Resistivity % of Sulk Volume 20 · Fig. 18 --Log and bulb volume plot [rom a Cali/ornia well. FI~, l? is a bulk volume plot, as described a~ove, for the example o~ "A" zone~ ~e ~ ~ol~e ~t~ v~ue~ ~e r~v~y cosset a~ 0.0~, ~d ~e clay fr~c~on~ ~e low. ~e m~ r~~ "B" zonea ~e ~ac~e~z~ hy a b~k vol~e wa~er frac~on ~ 0~7~, ~d ~ ~er ~y cont~ ~e b~ volume plot ~us ~sc~ea ~e het~ ~~ ~e ~. ~e ~ ~e r~v~y co~ v~ue~ ~ b~ vol~e w~er zones ~e ~ ~e~e wa~ sa~on. ~e "~' zo~s, m~ ~e ~~ f~er s~e ~d M~er clay con~ ~d have lower ~e~ffi~. W~e fo~a~on ~es~a be~n 12,~ ~d 12,~ ft were ~ ~d ~us ~~ co co~ ~s m~e~re~on. zone "C" ~e s~y lnc~m~ b~ vol~e w~er la ~a~e~s~c~ ~e zone, The I-F.~ lo$ and bulb volume plot in Iris. 18 were obtained from a well in Cal~forma. The computation of the bulb volume plot was performed in the same manner as described a~ove. In the top of the sand, down co 4,690 fo, the averase bulk volume water ts 0.05. From 4,690 ft to 4,752 ft, the bul~ volume water is approx~nately 0.09. The re. lacively constant value in each Interval indtcacea each is at Lrreducible water saturation. The cwo levels of BVW sugsest sand heterogeneity, with the' shallower level (~ac with'the lower value of BVW) beans more permeable. Below 4,752 fo, the BVW increases with depth and thus shows entry into the cransic~on zone. Some hydrocarbon saturation ia indic, aced throughout the lower pa_,'c of the sand. However, cheae are residual hydroca~bona~ the BVW plot cenda co parallel the plot of ~ . These bulk volume plots are pa_-~lc~ly suited co shaly sand studies. They provide a concinuotm and dia~noscic evaluation of the formation. Va.--lacions in ~ratn size and c~y con, eno, and thus in permeability, are indicated. For example, the plo~ in l~i$. 18 indic, aces a probable permeability barriar ac 4,690 ft. This barrier mi~h~ be hnpo~t when con- atdertng rese~oLr drainage. PERMEABILITIE$ FROM LOG DATA To predict race of production formation permeability. We have already indic, aced chac gq. 2 can be used in such estimates wh_~n_ ~_~_ form-,~n is ac lrredu~e water saturation. Good results a~e often obcah~ in carbonates aa we~l aa in sand~conea. Following a~ Lw~ e~amples chac illustrate permeability esclmacion~ from log Gas Sand Permeability The I-F.~ in Iris. ~9 was recorded in a deep Miocene Sas sand in Lou~siana. The bulk volume ploc computed from log data show~ bulk vo~ttme wa£er co be less ~ ~ a.,ld faJ~y ....... - ~a a depth of 14,104 fL. The~:efore, water sact~ra~on values are accepted as Lrre- This well was cored. In add/tion to permem~ty measurements o/ the cor~s, ~r-b~ ~~ presage me~a~ements were ma~. On fou~n core pluss, ~k~ at ~t~a be~een I%0~ ~d 14,096 f~ · e ~Y~e S~.~ Y~e wis 0.035~. w~s 0.0~ Core pe~~~es ~e com- p~ed m~ lo~-d~v~ pe~e~es Fl~ ~. ~e log-de~ved v~es were ~m- puted accordin~ to ~, ruth c - :~$0o (This constm~ h~s been determmed from empirical studies of deep Miocene gas sands in this are~.) Although the~e are vat. clone between the core and 1o$ values of permeibflltT, there is good 8'z~ss alreement down to 14,104 fi, the. top of the trinsit/on zone. Between 14,042 and 14,104 fi, the averase core permea- bLLtty is 320 md; averase 1o$ perme~btllt~ is 280 md. Fig. 19 -/..of and hula ~,o/,,,me plo~ fi'om a Carbonate Permeabilities Ys Production Rates A recent paper discussed the extensive use of lo$ data in plannln$ well complet/ons in Chaveroo field, New Mexico. (8) Product/on there is from the San Andres format/on, primarily a c~rbonate format/on which is characterized by low poroatt/es and varia~/ons in litholo~y. The paper demonstrates that better complet/ons are made in wells where son/c, densiv/, and neutron data are used to define lltholosy and, thus, to improve the accuracy of porosity determinat/on. Laterolo~ and Mtcrolaterolo~ values are used with the porosity data to compute water saturat/ons and lndica~ions of movabl.e oil. The numerous compu- tat/OhS of lo$ data are performed by electronic computer. The Sw vs q~ cross plo~s in Pig. 21 were ~en from machine-computed da~a on fo~ Chaveroo we~s. ~e po~ v~ues were de~e~ed (on a foo~-by-f~ basis ~rou~ ~e prolog ~e~) from ~e somc-densi~-n~n compu~ons. ~e wa~er saracens for ~e plo~ed po~s ~e average v~ues~ ~ey were obeyed by avera~g ~ ~e wa~er samra~ons for a sm~e po~ v~ue ~ ~e ~~ w~. ~e n~er ~ S, v~ues used ~ ~e average, ~d ~us ~e nu~er ~ fo~on f~ e~i~g a ~ven porosi~, ~e ~~ed opposite ea~ plo~ (~ove 6~ po~). Pe~e~aes for ea~ cross plo~ po~ were computed using c - 2~ ~ Eq. ~C~esfor0.1 m~ 1.0m~ ~dl0.0md~e sho~ on ~e cross plo~s. ~ ~o~ on ea~ c~ss plo~ is a h~erboBc c~e ~ S, ~ - 0.01. ~s app~s ~o be a ~od v~ue for ~r~uc~le b~k vol~e wa~ ~ ~ fo~a~on. Comp~son ~ ~e four c~ss plo~s su~es~s ~z W~ "A" ~s ~e leasz percale for- ma~ons, ~d is mos~ E~ly ~o produce wa~er. W~s "C" ~d "~' app~ m have more zones of ht~er perme~ffi~. Torsi millldarcy-fee~ were computed for each well. Only zones wl~ porosic~es grea:er ~han 6~ and indications of movable oil, were included in rh~s compuzacLon. For each plo~ed point ~he log-derived permeability was mulcLplied by the number of formation feec having ~ha~ porosity (the number of wazer saturation values used in compu .~$n$ ~e plotted average). The resul~£ng compu~aulon of ~o~al millidarcy-feec for each well Is compared with lrd~lal produc~Lon in T~ble $. The general relacLonships between log-derived capacity and actual well produc~on ~re ~od. Bven ~hou~h non-linear they su~ges~ d2a~ empirical studies based on ~hese log~Lng ~echniques may well provide close eacLma~lon~ of initial produc~on. TABLE3 WELL A B C O i Md ft 0.71 4.57 23.06 23.37 BO/D 105 279 523 609 GOR 60 293 265 592 BW/D 7O 0 5 6 We have indicated the $, vs 6 interpretations are effective in both carbonates and sandstones. However, -in one ~vPe of reservoir the methods a~e ineffective; ~hey do apply where produc~Lon depends almost exclusively on ~he presence of fractures. The log- derived values of $.~ and c~ are based on bulk volume measurements. Because fractures represent, only a ~mall percent of the bulk volume, the me,hods have no resolu~on for fracture analysis. Furthermore, de~errntna~Lon of permeabil~ from rela~Lonshi~ with porosity, d~Ls relaulons~tp is withouc meamn$ in fractured formations. 14, 14 10 ,~d Well A 10 md Well ! 12! // Tot.i md ft= 0.71 12- / Tot. I md ft ~..~7 / ~o / /.d ~. / / / / ,: 0/.1 md 20 aOSW 60 80 100 0 20 40 60 8Q 1OO , -- / Total .d .ft = 23.06 I// Total -dft = 23.37 12' 1/ y / 0 I , I,, I, 0 20 40 ~0 8Q 100 O 20 40 60 80 100 Sw Sw WATER.CUT PREDICTION The fore.ins discussions have dealt primarily with lden~tn$ zones at irreduc~le water saturation, and then computin$ the permeablllties of these zones. When combined with pressure, fluid viscosity, and reservoir volume factor, the data enable reasonable estimates of production rate. Water production is no problem in these above=transition formations. However, it is often necessary, or advantaseous, co perforate intervals in the ~ransi- tlon zone. Then, the production will probably include water. In some intervals the water cut may be tolerable; In others lc may be prohibitive. Here, a~ain, lo!~ data enable a reason- able estimate of water cut--and thus further ex~end the value of lo$ analysis. The water-oil ratio (WOR) o! surface product/on is defined by the followin$ equation:~9) ko, /~. (8) where reservoir volume factor for the oil effective (formation) permeability tO water k effective permeability to off water viscosity ac reservoir conditions ~o ' otl viscosity ac reservoir conditions The water cu~ of the production, expressed in percent o~ total production, is then computed as follows.- WOR Water C~c - (9) I + WOR Application of Eqs 8 and 9 requires evaluation of both the relative permeability ratio and the fluid characteristics. Park Jones, in 19415 ~t0) , presented empirical equations for determtr~tion of relative permeabilitles when $. and SLrr were known. These equations, which have since been used with ~ood results, are aa follows: (10) where relative permeability co water --~,4v~. nermeability to Oil W ATFJ ~IT C~ART A -- ~ WATER CUT C]qAItT A = 5 10 30 40 SO 60 SO 10 60 Sw(%) 7O I0 WATER CUT C].IART A = 10 WATER CUT C]'IART A: 20 Sfrr(~l lO Sw(%) 60 70 80 10 :10 30 ~O SO 60 70 80 Thus, with $, de~errnined from log compucactons and with $irr de~ermh~edfr~m $, vs ~ cross plots, the rela~ve permeability ratio (k,/ko = k~, /k~o ) can be evaluated. Los data do ncc define the fluid characterisctcs. Therefore, solution of Bq. 8 requires either prior knowledge or an esctmate of reservoir volume factor and oil-water vtscosicy ratio. Best results are obtained where these fluid characcerisctcs are known from nearby production, or are measured from fluid samples. The latter can be obtained with wireLtne formation tests° However, satisfactory results ~re often obtained using escZma~ed values of: A = ~9 /% (12} where A = a factor representing the composite fluid characterisctcs. The value of "A" can vary from about 2 for light otls to 100 or more for very heavy otis. To tilustra~e varia~tons of "A" we present five typical cases below. In each case the water viscosity has been considered equal co 0.4 cp. TYPE OIL, Ap! GRAVITY ~ ~ A Very L~gtmt 45° 0.~ 1.6 2 t.l~t 35° . 1.4 1.4 $ Medium 27': 3.3 1.2 10 Heavy 19':' 8.0 1.05 20 Very Heavy l,t" ' 20.0 1.00 50 From compartson with the above c~ses, appropriate values of "A" can be selected when the o~1 type can be predicted with reasonable accuracy. To facilitate computation of water cut, graphical soluctons based on Eqs. 8 -- 12 have been prepared. The charts, for "A" values of 2, 5, 10, and 20, are presented in Fig. 22. The esctmated water cut is defined, on the appropriate "A" chart, by the intercept of and S, for a ~tven level tn the cranstcton zone. The Io~ tn Fi$. 23 were recorded tn a D-J Basin well. Water saturactons and po- rosictes were computed at two-foot intervals in the sand from 6,0~4 co 0,072 fo. The ~ntervals are numbered sequenctally, scarcin~ with I at the top of tho sand. [u the Sw va ~5 cross plot (Fi$. 24) points i and 2 fall close co a hyperbolic line represenctn$ Sw ~ - 0.09. Ale though only lhnited data are available in chis four-foot interval, we have assumed points 1 and 2 are from above the ~ransicion zone. Below d~ts four-foot interval, however, the data plot ~o the right of the apparent St~ line (S, ~ - 0.09), and the points are sca~ered. The cross plot therefore indicates entry into a cransi~ton zone between (5,056 ,ft (point 2) and 5,058 ft (point 3). The ~op of the sand, inclu~ng the intervals represented by points 1, 2, and 3, was perforated for produccton. What, if any, should the production water cu~ ~e ? ~a,- r. he ~urpose of water-cut compucacton, the data fo~ points l, 2, and 3 were con- ...... ~ ~,~,-macion thickness. The compucacLons of per-- L~ I I I I I SP R~sistivity GR ~t 0 10 2O _~.~ 0 50 0 200 120 90 60 · .... ~ "' ~ ~ · 10-' Fig. 2~ - Logs/rom LEVEL ~ S. SI"' c-k 2~o k~= k~. k,. k o ii ii / 1 20'~ 47<~ 47% tS.! md l.O 0 0 18.1 2 18.4 49 49 10.0 1.0 0 0 10.0 $ {.6.~ 71 55 4.4 0.3 0.045 ' 0;2 1.3 i · L' Totals 0.2 29.4 2~ 22- II- (~Saalc 16- 12- IC 0 SIEG#tI¥ Skaly Send 0.09 20 40 60 IQ IOQ Sw Fig. 24- Cross plot /ran togs M F(g. 2~ indicates entry into transition The oH l~raYit~ in this formallon is known to be 43° APl. Therefore, A --2. Combinin$ l~qs. 8 and 12, we find WOR -- A kw,'(2) 0.2, . 0.0136 ko 29.4 and, from Gq. 9, WOR 0.0156 - . 1.35% Water Cut - 1 + WOR 1.0136 The ird~ial produc~ion from rJ~ts perforated interval was 277 BOP'E) wi~h a 2% water cut. The los-derived prediction is very close to actual production daca. After one monr~ ~he water cut increased to 20%° The loS dar~, al~ou~h not specifically deftninl~ ~e increase, infer ~hat an increase should be expected. The da.r~ for point 4, only ~wo fee~ below point 3, indicate a 99+ ~o water cut for rJ~at level. This rapid increase implies ..... ~- ,.w. likelihood of an early increase in wacer pro- SUMMARY This paper has presented methods by which the utility of los analysis can be ex~ended. In addition to uae in calculation o~ reserves, the 1o$ data enable reasonable esr. tmams of formation permeability, and production rate and water cur.. The methods and major con- sidsrations are summarized below: 1. Correlactve comparisons of log-derived values of S, and c~ distingu~sh between ~ormations in and those above the transition zone. 2. The methods are moat effective tn formations of varying porosity and of sufficient thickness to define a recognizable pattern. For a homogeneous formation above the transition zone, Ltnear cross p/ocs of S, vs ~ describe a coherent patte.--n. This pattern generally takes the form of an equilateral hyperbola, where S, ~ is a constant value. For a heterogeneous formation above the trtnsition zone, multiple patterns a.re ofte~ obtained. Resolution of the tndividu~l pattens requLres knowledge of 11cho- lo87 variations. Transition zone plots usually are scattered, and show increasin~ values of S, with increased depth. 6. In shaly sands, experience indicates better resolution ~nen Sz is cross plotted v8 e~fective porosity. Another presentation of r~ese techniques is the bulk volume plot, versus depth, of water, hydrocarbons, and clay. The resultin$ log ide.,u~les Ltthology changes and tncttcates zones at irreducible water saturation. 8. In zones above tzansition, permeability may be estimated from log data. 9. In transition zone.s, the logs enable predictions of production water cut. 10. Effective predictions of production require sood values of S,, and ,~. Multiple logs are often required for accurate porosity determination in unknown or variable llthologies. CONCLUSIONS Although these techniques of Sw vs ~6 comparisons are not new, they are more ef- fective than in past applications baaed on log-derived data. Modern logs measure formation characteristics more accurately than lo~n of yesteryear. The greater vtrtety of logs now available .permits Lithology identification and, thus, more precise porosity determination. With local experience uain~ these methods, the log analyst can predict qtttce accurately the production from a prospective produ~g zone. With enough experience to establish Strr ~ in a ~iven formation, he can accu,--ately predict production, even when the formation in a well is too chin to provide enoush data points to establish a pattern. He can,. in fact, use chis prediction to verify the mechanical efficiency of the completion program. These methods can greatly extend the ul:LLlty of log analysis. Therefore, don't stop your log analysis with the computation of water saturation and porosity. Plot these values to predic: production. Predict with greater accuracy, reLiaJ~illty, and confidence. REFERENCES 1. Archie, G. El.: "Classification o£ Rese~oir Rocks and Petmphysical Considerations", A.A.P.G. Bull. (Feb., 1952), Vol. 36, No. 2, pp 27~298. 2. R~kwo~, S. H., L~r, G. H., ~d L~o~, B. J.: "Rese~oir Volume~c ~ar~etem De{in~ by Capilla~ Pressure S~dies", Pe~. Trans. AIME (1957), Vol. 210, pp. 232-259. 3. Weaver, A. G. T.: "An Approach m Cat,hate Rese~oir ~v~luntion B~ on Me~ Inj~on Data, Western C~ada", Oil in C~nada (M~. 31, 1958). 4. Buckles, R. S.: "Cotze/a~int ~d lveral~t Co,ate Wate~ Satura~on Data", /our. Canadian Pe~. rec~. (]~Mar., 1~5) pp 42-52. 5. Wylie, M. R. J., ~d Rose, W. D.: "Some ~fic~ Considerations Relat~ to ~e Qu~fitafive Kv~uati~ of ~e Physical Character~fi~ of Rese~oir Rocks f~m KI~t~c~ Lot Dia", Pet. rech. (April, 1950)pp. 6. Schl~ber~er Well Su~eyinl Co~.: "Eot ~te~retsfi~ Chis~', ~ouston, Tern, 7. AI~r,.R.P., Raymer, L. L., Hoyle, W. R., ~d Tl~er, M. P.: "Fo~fi~ Densi~ Lot AppEc~ fions in Liquid-FilI~ Holes",/oar. Pet. Tech. (Mar., 1~3) pp 321-332. 8. Burke, J. A., C~s, M. R., ~d Coz, J. T.: "Com~t~ P~essinl of Los Data Enables Be~er P~uction in Chave~ Field", pa~ p~nt~ at 41st A~ual F~I M~fin~ SPE of Dall~, Tez~ (Oct. 2-5, 1~6). ' 9. Piton, S..J.: "Elements of Oil Rese~oir ~n~finZ", M~mw~ilI Book Comply, ~c. (1950) pp. 291. .. Jones, P. J.: "P~ucfion ~n~n~finz ~d R~e~oir M~a~cs (Oil, Coati,sate, ~d Namr~ G~)" publi~ by Oil ~d G~ ]o~. (194~ ~. 4~. I0. :SUPPLEMENTARY BIBLIOGRAPHY 1. Alit, R. P.: "Lo~nl Trends i~ Carbonate Rocks", T~e ~iae~ ~, (Oct., 1957) pp. 97-1~. ~ Wi~, R. H.: "Lo~ ~te~ts~on ~ Hete~~ C~ate Rese~oim", Pe~. Tr~. AI~E (195~ Vol. 210, pp. 268-274. 3. Du~n, J. D.: "Some Pet~physic~ Asp~ of ~e Mi~issippi~ "Chat', Gli~ Field, ~o~ Co~, K~s~s", The Log A,~st (Nov., l~J~., 1~ Vol. VH, No. 4, pp. 3~3g. 4. Piton, S. J., Boa~an, ~. M., ~d NerVe, R. ~.: "P~cgon of Relagve Pemeabili~ Chamcte~ is~ics of Inte~g~ular Rese~oir Rocks ~mm El~c~ Resis~vity Me~umments", fo,r. Pet. Stewart Petroleum Company W. McArthur River Well Test Summary Bench FVF Viscosity Perm. Oil Gravity Temp Pressure GOR Bubble Pt. # (Rvol/Svol) (cp) (md) (°API) (°F) (psig) (scf/stb) (psig) W. McArthur River #1 2 1.102 5.161 18322 174 4295 160 1048.4 W. McArthur River ~f2A '- .. 1 1.101 4.894 94 30 174 4185 155 712 2 1.108 3.074 96 ~ 30 175 4051 153 680 · 3 1.101 4.882 121 27 174 4279 100 ~ 713 4 ** ** 1.1 ** 173 4304 ** ---- ** PVT DATA Bench FVF @ Pi FVF @ Pbp Visc.@ Pi Visc. @ Pbp[ Oil Gravity GOR Bubble Pt # (Rvol/Svol) (Rvol/Svol) (cp) (cp) (°API) (scf/stb) (psig) W. McArthur River 1 1.079 1.102 3.4 2.47 28.8 140 931 RECEIVED Gas Cons. Commission Bottom Perforation BENCH 2 ~ 12,820 MD o ~°oo SPC WMRU- 2A T.D. 13,475' SPC WMRU- 1 T.D. 13,742' Top Perforation 2 13,254 MD ~'°Oo~° SCALE' 1": 500' SECTION EXHIBIT ~ C. Stewart':P.. troleum'- Company 3111 C Street ..~,S'tiite 400 · Anchorage, Alaska 99503 (907) 563-2830. FAX (907) 562-3804 :., .... ~'~ ~"~ .~ :'_ ~'~" ~ ~'~, ~x APPLICATION FOR APPROVAL OF WEST McARTHUR RIVER AGREEMENT UNIT ",,:~:~ ]9 1990 DIVISION OF OIL & GAS ANOHORAGE, ALASKA SUBMITTED TO STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES APRIL 19, 1990 DMEMForm No. 18-83 (UNIT AGREEMENT) DNR Form No. 10-1128 (Revised April 1990) UNIT AGREEMENT WEST McARTHUR RIVER UNIT STATE OF ALASKA TABLE OF CONTENTS ARTICLE · 2. 3. 4. 5. 6. 7. 8. · 11. 12. 13. 14. 15. 16. 17. 18. TITLE DEFINITIONS ................................ EXHIBITS ................................... CREATION AND EFFECT OF UNIT ................ DESIGNATION OF UNIT OPERATOR ............... RESIGNATION OR REMOVAL OF UNIT OPERATOR .... SUCCESSOR UNIT OPERATOR .................... UNIT OPERATING AGREEMENT ................... PLANS OF EXPLORATION, DEVELOPMENT, AND OPERATIONS ........... ~ ................... PARTICIPATING AREAS ........................ ALLOCATION OF UNITIZED SUBSTANCES AND EXPENSE; PAYMENT OF RENTALS, ROYALTIES AND NET PROFIT SHARE ..................... EXPANSION AND CONTRACTION .................. EFFECTIVE DATE, TERM, AND TERMINATION ...... EFFECT OF CONTRACTION AND TERMINATION ...... COUNTERPARTS ............................... LAWS AND REGULATIONS ....................... APPEARANCES AND NOTICES .................... J©INDERS ................................... DEFAULT .................................... PAGE 9 10 12 16 16 18 18 18 19 19 20 EXHIBIT A B C D E F TITLE ATTACHMENTS PAGE OWNERSHIP INFORMATION .................. MAP OF UNIT AREA AND TRACTS ............ PARTICIPATING AREA ..................... MAP OF PARTICIPATING AREA .............. ALLOCATION OF PARTICIPATING AREA EXPENSE ALLOCATION OF UNIT EXPENSES ............ RECEIVED APR 2 · aska Oil & Gas Cons. Commission Anchorage UNIT AGREEMENT WEST McARTHUR RIVER UNIT STATE OF ALASKA RECITALS The Working Interest Owners who are parties to this Agreement are owners of interests in oil and gas leases subject to this Agreement. The Commissioner of the Department of Natural Resources, State of Alaska, is authorized by Alaska Statute 38.05.180 (p) and (q) and regulations adopted under that statute to consent to and approve oil' and gas unit agreements affecting oil and gas leases in which the State of Alaska has an interest; and The parties to this Agreement have complied with the Alaska Statutes and regulations prescribing the procedures governing the submission of applications and criteria for approval of oil and gas unit agreements; and The Commissioner of the Department, of Natural Resources has found that this Agreement is necessary or advisable to protect the public interest. AGREEMENT The parties commit to this Agreement their respective interests in the below-defined Unit Area, and agree severally among themselves as follows: ARTICLE 1 Definitions 1.1 Alaska Oil and Gas Conservation Commission means the independent quasi-judicial agency of the State of Alaska having jurisdiction and authority over all persons and property, public and private, necessary to carry out the purpose and intent of the Alaska Oil and Gas Conservation Act, AS 31.05. 1.2 Commissioner means the commissioner of the state Department of Natural Resources or his designee. 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11 Effective Date means the time and date this Agreement becomes effective as provided in Article 14.1. Force Majeure means wars, riots, acts of God, unusually severe weather, or any other cause beyond the Unit Operator's reasonable ability to foresee or control (including delays caused by operational failure of existing transportation facilities or delays caused by judicial decisions or lack of them). Oil and Gas RiGhts means the rights to explore, develop, and produce Unitized Substances from lands within the Unit Area. Outside Substances means oil, gas, other hydrocarbons or nonhydrocarbon substances purchased or otherwise obtained from outside the Unit Area by the Unit Operator and, with the approval of the Commissioner, injected into a Reservoir in the Unit Area. Participating Area means all or parts of Unit Tracts described and designated as a Participating Area under this Agreement for the purposes of allocating one or more Unitized Substances produced from a Reservoir. Participating Area Expense means all cost, expense or indebtedness incurred by the Unit Operator under this Agreement or the Unit Operatin~ Agreement for or on account of production from or operations in a Participating Area and allocated solely to the Unit Tracts in that Participating Area. Paying Quantities means quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking considered as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. Reservoir means that part of the Unit Area containing an accumulation of Unitized Substances which has been discovered by drilling and evaluated by testing a well or wells, and which is geologically separate from and not in hydrocarbon communication with any other accumulation. Royalty Interes$, with regard to Article 12, means a right to or interest in any portion of, or the proceeds or value of, the Unitized Substances, other than a Working Interest. ( 2 1.12 State means the State of Alaska acting in this Agreement by and through the Commissioner of the Department of Natural Resources, or the Commissioner's authorized representative. 1.13 1.14 1.15 1.16 1.17 1.18 1.19 1.20 1.21 1.22 Sustained Unit Production means continuing production of Unitized Substances from a reservoir in the Unit Area into a pipeline or other means of transportation to market, but does not include testing, evaluation, or pilot production. Unit Area means the lands described in Exhibits A and B to this Agreement, submerged or not. Unit Equipment means all personal property, lease and well equipment, plants, platforms and other facilities and equipment used, taken over, or otherwise acquired for use in Unit Operations. Unit Expense means all costs, expenses, or indebtedness incurred by the Unit Operator under this Agreement or the Unit Operating Agreement for or on account of Unit Operations, except for Participating Area Expense. Unitized Substances means all oil, gas (except helium), gaseous substances contained therein, condensate, distillate, and all associated constituent liquid or liquefiable substances (other than water) within or produced from the Unit Area. Unit Operating Agreement means the agreement(s) entered into by the Unit Operator and the Working Interest Owners, under Article 7 of this Agreement. Unit OperatiOns means all operations conducted under this Agreement in accordance with a plan or plans approved under Article 8 of this Agreement. Unit Operator means the party designated by the Working Interest Owners and approved by the Commissioner under this Agreement to conduct Unit Operations within the Unit Area. Unit Tract means each separate parcel which is described in Exhibit A and given a Unit Tract number. Unit Tract Participation means the percentage allocation credited to a Unit Tract in a Participating Area for the purpose of allocating Unitized Substances under this Agreement. 1.23 Working Interest means a leasehold interest. 1.24 Workinq Interest Owner means a party who owns a Working Interest. 2.1 2.2 2.3 2.4 2.5 2.6 2.7 ARTICLE 2 Exhibits Exhibits. The following-described Exhibits are to be attached to and made a part of this Agreement. At the time of approval of this Agreement, only Exhibits A and B are required. Exhibits shall be supplied by the Unit Operator pursuant to the provisions of this Article. Exhibit A is a schedule that identifies and describes each Unit Tract, shows the Working Interest ownership of Oil and Gas Rights in each Unit Tract, and shows the royalty and net profit share rates applicable to each Unit Tract. Exhibit B is a map that shows the boundary lines of the Unit Area and of each of the Unit Tracts. Exhibit C is a schedule that identifies and describes a Participating Area established under this Agreement, including geologic descriptions and schedules showing Unit Tract numbers, legal descriptions, lease numbers, and Unit Tract Participation. Separate Exhibits shall be prepared for each separate Participating Area established in the Unit Area. A revised Exhibit C shall be submitted to the Commissioner within thirty days of approval of any division of interest or allocation formula affecting or revising Unit Tract Participation. Exhibit D is a map showing the boundary lines of a Participating Area and the Unit Tracts in that Participating Area established under this Agreement. Separate Exhibits shall be prepared for each separate Participating Area established within the Unit Area. Exhibit E is a schedule that describes the allocation of Participating Area Expense to each Unit Tract in the Participating Area(s) established under this Agreement. Separate Exhibits shall be prepared for each separate Participating Area established in the Unit Area. A revised Exhibit E shall be submitted to the Commissioner within thirty days of approval of any division of interest or allocation formula affecting or revising Participating Area Expense allocated to the Tracts in a Participating Area. Exhibit F is a schedule that describes the allocation of Unit .Expense to each Unit Tract in the Unit Area. A revised Exhibit F shall be submitted to the Commissioner within thirty days of approval of any division of interest or allocation 2.8 formula affecting or revising Unit Expense allocated to the Tracts in the Unit Area. Exhibits shall be revised by the Unit Operator whenever changes are made in the Unit Area, Participating Areas, ownership of one or more leases, or the allocations of Unitized Substances, Unit Expenses, or Participating Area Expenses to the individual Unit Tracts. Copies of the revised Exhibits shall be submitted for the approval of the Commissioner, and shall be filed for public record in the filing office of the Department of Natural Resources, Anchorage, Alaska. 3.1 3.2 3.3 3.4 ARTICLE 3 Creation and Effect of Unit Ail Oil and Gas Rights in and to the lands described in Exhibit A and shown in Exhibit B are made subject to this Agreement in order that Unit Operations may be conducted as if the Unit Area were a single lease. Unit Operations conducted under a plan or plans approved in accordance with Article 8 of this Agreement shall, subject to the provisions of section 3.3, cause each lease in the Unit Area to continue in effect, as if Unit Operations were conducted on each lease. Except as otherwiSe provided by applicable regulations, where only a portion of a State of Alaska lease is committed to this Agreement, the commitment constitutes a severance of the lease as to the unitized and nonunitized portions of the lease. The portion of the lease not committed to this Agreement will be treated as a separate and distinct lease having the same effective date and term as the original lease and may be maintained thereafter only in accordance with the terms and conditions of the original lease, statutes, and regulations. Any portion of the State lease not committed to this Agreement will not be affected by the unitization or pooling of any other portion of the lease, by operations in the Unit Area, or by suspension approved or ordered for the Unit under appropriate statutes and regulations. Production from any part of a Participating Area shall be considered as production from each Unit Tract in the Participating Area and shall cause the portion of each lease that is either wholly or partially contained within the Participating Area to continue in effect just as if a well were producing from each Unit Tract in the Participating Area. 3.5 3.6 3.7 3.8 3.9 The provisions of the various leases, agreements, or other instruments pertaining to the respective leases or production from those leases, are amended only to the extent necessary to make them conform to the written provisions of this Agreement, but otherwise shall remain in full force and effect. Nothing in this Agreement shall be construed to result in the transfer of title to Oil and Gas Rights by any party to any other party or to the Unit Operator. Except to the extent modified in this Agreement, the Unit Operator shall have the same rights to use of the surface and the subsurface as are granted in the respective leases. The Unit Operator will, to the extent feasible and prudent, minimize and consolidate surface facilities in order to minimize surface impacts. Ail data and information determined by the Commissioner or the Alaska Oil and Gas Conservation Commission to be necessary for the administration of this Agreement or for the performance of statutory responsibilities shall be provided by the Unit Operator, or Working Interest Owners, or both, to the requesting authority upon written request. Ail Working Interest Owners of a State of Alaska oil and gas lease must commit to this Agreement in order for that lease to be committed to this Agreement, 4.1 4.2 ARTICLE 4 Designation of Unit Operator STEWART PETROLEUM COMPANY is hereby designated as the Unit Operator and agrees to accept the rights and obligations of the Unit Operator to conduct Unit Operations and to explore for, develop, and produce Unitized Substances as provided in this Agreement. Except as otherwise provided in this Agreement and subject to the terms and conditions of plans approved in accordance with Article 8 of this Agreement, the exclusive rights and obligations of the Working Interest Owners to explore for, develop, and produce Unitized Substances in the Unit Area are delegated to and shall be exercised by the Unit Operator. This delegation neither relieves a lessee of the obligation to comply with all lease terms nor transfers title to any lease. The Unit Operator shall notify the other Working Interest Owners and the Commissioner of all actions taken by the Unit Operator under this Agreement. 6 5.2 5.3 5.4 ARTICLE 5 Resignation or Removal of Unit Operator The Unit Operator may apply for resignation. Such resignation shall not become effective until sixty (60) days after written notice of an intention to resign has been delivered by the Unit Operator to the Working Interest Owners and the Commissioner, and until all artificial islands, installations and other devices, including wells, used for conducting operations in the Unit Area are placed in a condition satisfactory to the Commissioner for suspension or abandonment of operations. However, if a successor Unit Operator is designated and approved as provided in Article 6, the resignation shall be effective upon the approval of the successor Unit Operator by the Commissioner. The Unit Operator may be removed as provided in the Unit Operating Agreement. This removal shall not be effective until the Working Interest Owners notify the Commissioner and the Unit Operator, and until the Commissioner approves the designation of a successor Unit Operator. The resignation or removal of the Unit Operator shall not release the Unit Operator from liability for any failure to meet its obligations which accrued before the effective date of its resignation or removal. The resignation or removal of the Unit Operator shall not in itself terminate the Unit Operator's rights, title, or interest as the owner of a Working Interest or other interest in the Unit Area. Any termination of the Unit Operator's rights, title, or interest would occur independently under the terms of the leases and governing law. When the resignation or removal of the Unit Operator becomes effective, the Unit Operator shall relinquish to the successor Unit Operator possession of all Unit Equipment, artificial islands, wells, installations, devices, records, and any other assets used for conducting Unit Operations, whether or not located in the Unit Area. 6.1 ARTICLE 6 Successor Unit Operator Whenever the Unit Operator tenders its resignation as Unit Operator or is removed as provided in Article 5, a successor Unit Operator may be designated as provided in the Unit Operating Agreement. The successor Unit Operator must accept, in writing, the rights and obligations of a Unit Operator. The successor Unit Operator shall file three (3) executed copies of the designation of successor with the Commissioner. 6.2 However, the designation of successor shall not become effective until approved by the Commissioner. If no successor Unit Operator is designated as herein provided within sixty (60) days following notice to the Commissioner of the resignation or removal of a Unit Operator, the Commissioner, at the Commissioner's election, may designate any one of the Working Interest Owners as successor Unit Operator or declare this Agreement terminated. 7.1 7.2 7.3 7.4 ARTICLE 7 Unit Operating Aqreement The Working Interest Owners and the Unit Operator shall enter into a Unit Operating Agreement which shall describe how all expenses incurred in conducting or maintaining operations pursuant to this Agreement shall be apportioned. The Unit Operating Agreement shall also describe how the benefits which may accrue from operations conducted in the Unit Area shall be apportioned among the Working Interest Owners. Any allocation of expenses or liabilities, or allocation of the production of Unitized Substances or other unit benefits set forth in the Unit Operating Agreement will not be binding on the State for the purposes of determination or settlement of State royalties or net profit share. Allocations of expenses or Unitized Substances for the purpose of determination or settlement of State royalties or net profit share must be based on Exhibits C, E, and F of this Agreement, and must be approved by the Commissioner in writing before taking effect. The Working Interest Owners and the Unit Operator may establish, by means of the Unit Operating Agreement and amendments thereto, other rights and obligations between the Unit Operator and the Working Interest Owners as they deem necessary or appropriate. However, no Unit Operating Agreement shall be deemed to modify the terms and conditions of this Agreement, or to relieve the Working Interest Owners or the Unit Operator of any obligation set forth in this Agreement. In case of any conflict between the terms of this Agreement and the Unit Operating Agreement, this Agreement shall prevail. Where conflicts exist solely between Working Interest Owners, the Unit Operating Agreement shall control. Any Working Interest Owner shall be entitled to drill wells on the unitized portion of its lease when the Unit Operator has declined to drill such wells, so long as such activities are conducted under an approved permit to drill and a plan approved under Article 8 of this Agreement. If any such well drilled by a Working Interest Owner is determined to be 7.5 capable of producing Unitized Substances in Paying Quantities, that land upon which it is situated shall be included in a Participating Area. Such Participating Area shall be established or enlarged as provided in this Agreement, and the well shall thereafter be operated by the Unit Operator in accordance with the terms of this Agreement and the Unit Operating Agreement. Copies of the Unit Operating Agreement cited in Article 7.1 shall be attached to this Agreement when this Agreement is filed with the Commissioner for approval. The copy of the Unit Operating Agreement filed with the Commissioner shall be for informational purposes only. The Unit Operating Agreement shall not be deemed to be approved by the State's approval of the Unit Agreement. Copies of all other Unit Operating Agreements and any amendments to Unit Operating Agreements also shall be filed with the Commissioner at least thirty (30) days prior to their effective dates. 8.1 8.2 8.3 ARTICLE 8 Plans of Exploration, Development, and Operations A unit plan of exploration or a unit plan of development shall be submitted for approval by the Commissioner at the time this Agreement is filed. The plan must meet the requirements of State of Alaska Regulations 11 AAC 83.341 or 11 AAC 83.343. Requirements contained in a unit plan approved by the Commissioner are incorporated into this Agreement by reference as of the date of approval of such plan. No exploration, development, or production activities may be commenced or conducted on the Unit Area except in accordance with an approved plan. Plans of operations, applications for permits to drill, and other applications pertaining to proposed activities located on or under State of Alaska leases must be approved by the State agency normally receiving such applications prior to commencement of operations as provided under 11 AAC 83.341 - 11 AAC 83.346 and 20 AAC 25. When no Unitized Substances are being produced in Paying Quantities from the Unit Area and when all or part of the unit Area is subject to one or more leases beyond the primary term and where there are one or more wells capable of producing hydrocarbons in Paying Quantities, a continuous drilling or well reworking program shall be maintained, with lapses of no more than ninety (90) days per lapse between such operations (unless a longer period is approved by the Commissioner), unless a suspension of production, or other operations has been ordered or approved by the Commissioner, or operations are being conducted in accordance with an approved plan of 8.4 8.5 8.6 exploration or development. Plans may call for a cessation of drilling operations for a reasonable period of time between the discovery and delineation of a Reservoir and the initiation of actual production when such a pause in drilling activities is warranted to permit the design, fabrication, and erection of platforms, artificial islands, installations, and other devices needed for development and production operations; provided, however, that the Unit Operator requests and obtains the approval of the Commissioner for suspension of operations or production pursuant to applicable State statutes and regulations. The Commissioner, after giving written notice to the Unit Operator, may require the Unit Operator to modify the rate of exploration, development, or production from the Unit Area. For the purposes of this Agreement, if a well has been drilled, or drilling has commenced on a well on a lease which is committed to the Unit Agreement, that well will be considered to be a unit well upon the approval of this Agreement. Any injection of Outside Substances into a Reservoir in the Unit Area must be approved by the Commissioner as part of a unit plan of development or operation. Any injection of Outside Substances into a Reservoir in the Unit Area or a Reservoir otherwise subject tQ the jurisdiction of the Alaska Oil and Gas Conservation Commission must also be approved by the Alaska Oil and Gas Conservation Commission. ARTICLE 9 Participatinq Areas At least ninety days prior to Sustained Unit Production from a Reservoir in the Unit Area, the Unit Operator, on behalf of the Working Interest Owners, shall submit to the Commissioner an application for approval of the proposed initial Participating Area. For each subsequent Participating Area, the application shall also be submitted at least ninety days prior to sustained production from the subject Reservoir. 9.2 The application for approval of a Participating Area shall include, in the format of Exhibits C and D, a proposed division of interest allocating Unit Tract Participation. Upon approval by the Commissioner, the area of productivity as described in Exhibits C and D constitutes a Participating Area. 10 9.3 The application for approval of a Participating Area shall include, in the format of Exhibits E and F, a proposed formula for allocating Participating Area Expense and Unit Expense. 9.4 A Participating Area shall include only the land known to be underlain by Unitized Substances and known or reasonably estimated through use of geological, geophysical, and engineering data to be capable of producing or contributing to production of Unitized Substances in Paying Quantities. 9.5 A separate Participating Area shall be established for each separate Reservoir in the Unit Area. Any two or more Reservoirs or Participating Areas may be combined into one Participating Area with the consent of the Commissioner. 9.6 The Unit Operator, at its own election or at the direction of the Commissioner, shall submit an application for expansion or contraction of a Participating Area whenever expansion or contraction is warranted on the basis of further drilling or otherwise. A Participating Area shall be expanded to include acreage reasonably proven through use of geological, geophysical, and engineering data to be capable of producing or contributing to production of Unitized Substances in Paying Quantities, or contracted to exclude acreage reasonably proven through use of geological, geophysical, and engineering data to be incapable of producing or contributing to production of Unitized Substances in Paying Quantities, subject to the approval of the Commissioner. New Exhibits C, D, E, and F shall be filed with the Commissioner as part of the application for expansion or contraction. 9.7 In the event that the Working Interest Owners are unable to agree on the fair, reasonable, and equitable allocation of production or costs, such allocation will be prescribed by the Commissioner and the Alaska Oil and Gas Conservation Commission. 9.8 The effective date of the initial Participating Area will be no later than the date of the first Sustained Unit Production. For each subsequent Participating Area, the effective date shall be established by the Commissioner. A revision of a Participating Area becomes effective as of the first day of the month in which the knowledge or information on which the revision is predicated is obtained, unless a more appropriate effective date is approved or prescribed by the Commissioner. 9.9 No land in a Participating Area shall be excluded from the Participating Area due to the depletion of Unitized Substances. 9.10 If any gas saved, removed, or sold from one Participating Area is used for repressuring or recycling purposes in another 11 Participating Area, the gas first withdrawn from such last- mentioned Participating Area that is saved, removed, or sold during the life of this Agreement shall be considered to be the gas so transferred. 10.1 10.2 10.3 10.4 ARTICLE l0 Allocation of Unitized Substances and Expense; Payment of Rentals, Royalties and Net Profit Share The formula which allocates the Unit Expense and Participating Area Expense among the Unit Tracts encompassing any State lease within the Unit Area shall not take effect until approved by the Commissioner in writing. Any proposed revision of an approved formula which allocates the Unit Expense and Participating Area Expense among the Unit Tracts encompassing any State lease within the Unit Area shall not take effect until approved by the Commissioner in writing. When requested by the Commissioner, the Unit Operator shall promptly file with the Commissioner all data that relates to the proposed or revised allocation formula. Ail Unitized Substances saved, removed, or sold from the Unit Area shall be allocated to the Participating Area established for the Reservoir from which the Unitized Substances were produced, as set forth in Exhibit C. Unitized Substances allocated to a Participating Area shall be allocated to each Unit Tract within the Participating Area in accordance with each Unit Tract's Unit Tract Participation and among Working Interest Owners of a Unit Tract in accordance with each Working Interest Owner's ownership in the Oil and Gas Rights in the Unit Tract. The amount of Unitized Substances allocated to each Tract, regardless of whether the amount is more or less than the actual production of Unitized Substances from the Unit Tract, shall be deemed for all purposes to have been produced from that Unit Tract. For all Participating Areas, the Working Interest Owners may allocate Unitized Substances, Participating Area Expense, and Unit Expense among themselves in amounts other than those set out in Exhibits C, E, and F, provided that any allocation which is different than the allocations required by Exhibits C, E, and F shall be promptly submitted to the Commissioner for the State's information with a statement explaining the reason for the different allocation. Prior to the injection of Outside Substances into any Reservoir within the Unit Area, the Working Interest Owners and the Commissioner shall agree upon the rate at which such Outside Substances will be considered to be recovered. As long as royalty has already been paid once, no royalty shall be due or payable for produced substances which are determined to be 12 recovered Outside Substances. However, as to Outside Substances, only dry gas and not products extracted therefrom may be saved, removed or sold royalty-free. If more than one type of Outside Substance is injected at any time, the Working Interest Owners and the Commissioner may agree upon differing recovery rates for each type of Outside Substance. Any withdrawal of royalty-free Unitized Substances shall terminate upon the withdrawal of an amount equal to the Outside Substances originally injected. 10.5 No royalty, overriding royalty, production, or other profit- based payments shall be payable to the State of Alaska on account of the proportion of Unitized Substances used in the Unit Area for development and production or unavoidably lost. Gas that is flared for any reason other than safety purposes as directed by the Alaska Oil and Gas Conservation Commission shall not be deemed to be unavoidably lost. 10.6 If a State oil and gas lease committed to this Agreement requires the payment of minimum royalty, that lease is amended to delete that minimum royalty obligation. Rental, at the rate specified in Alaska Statute 38.05.180(n), shall be paid in lieu of minimum royalty. 10.7 Each month, the Unit Operator shall furnish to the Commissioner a schedule which shall specify, for the previous month, the total amount of U~itized Substances produced, the amount of Unitized Substances used for development and production or unavoidably lost, the amount of Unitized Substances allocated to each Tract as royalty delivered in kind to the Commissioner, and the amount of Unitized Substances allocated to each Tract as royalty production to be settled in value. 10.8 Each Working Interest Owner under a State lease shall make settlement for its share of royalty on Unitized Substances taken in value by the State as provided under the terms of each respective lease. 10.9 Regardless of whether so provided under the terms of the respective lease, royalty paid in value shall be free and clear of all lease expense, Unit Expense, and Participating Area Expense (and any portion of those expenses that is incurred away from the Unit Area), including, but not limited to, expenses for separating, cleaning, dehydration, gathering, salt water removal, and preparing the Unitized Substances for transportation off the Unit Area. 10.10 Ail payments to the State of Alaska shall be made payable in the manner directed by the Commissioner to any depository designated by him or her. 13 10.11 In the event of the failure of any Working Interest Owner to make proper settlement of any royalty due, the Commissioner shall have all rights and remedies available to him or her under law, the lease, and this Agreement, including any rights of cancellation and termination of the lease. 10.12 As close as practicable to six months before the commencement of Sustained Unit Production from a Participating Area, the Unit Operator shall give the Commissioner notice of the anticipated date for commencement of production. Within ninety days of receipt of that notice, the Commissioner shall give written notice to the Unit Operator of the State's election to take in kind all, none, a specified percentage, or a specified quantity of its royalty on any Unitized Substances produced from the Participating Area. Upon ninety days advance written notice to the Unit Operator, the Commissioner may increase or decrease the amount of royalty the State takes in kind. 10.12.1 10.12.2 In the written notices given under this Article, the Commissioner may elect to specify the Tracts from which royalty taken in kind by the State is to be allocated. If the Commissioner does not specify any Tracts in the notice, the royalty taken in kind shall be allocated to all Tracts in accordance with the Tract Participation. The royalty taken in kind by the State shall be delivered to the Commissioner, or to any individual, firm, or corporation designated by the Commissioner, at the Unit Area boundary and in a pipeline or other facility capable of carrying the State's royalty share with the Unitized Substances of the Working Interest Owners, or at any other place mutually agreed upon by the Commissioner and the Unit Operator. 10.12.3 The State's royalty Unitized Substances delivered in kind shall be delivered in good and merchantable conditions and be of pipeline quality. Royalty delivered in kind shall be free and clear of all lease expenses, Unit Expense, and Participating Area Expense (including any portion of those expenses which is incurred away from the Unit Area), including but not limited to expenses for separating, cleaning, dehydration, gathering, salt water disposal, and preparing the Unitized Substances for transportation off the Unit Area. 10.12.4 Each Working Interest Owner shall furnish storage for the State's royalty share of Unitized Substances produced from the Unit Area to the same extent that 14 the Working Interest Owner provides storage for its own share of Unitized Substances or to the extent provided in the base, whichever is greater. 10.13 If a State royalty purchaser fails for any reason to take delivery of Unitized Substances, or in an emergency, the Commissioner may elect without penalty to underlift for up to six (6) months all or a portion of the State's royalty on Unitized Substances produced from the Unit Area or from any Tract within the Unit Area. The State's right to underlift is limited to the portion of royalty Unitized Substances that the royalty purchaser failed to take delivery of, or the portion necessary to meet the emergency condition. Underlifted Unitized Substances may be recovered by the State at a daily rate not to exceed twenty-five percent of its Royalty Interest share of daily production at the time of the underlift recovery. Recovery of underlifted Unitized Substances will be completed within two (2) years of the date such underlift commences. The State and any Working Interest Owner shall be free to enter into an agreement covering underlifting of Unitized Substances by the State, and in that event said agreement shall control the rights and obligations of the parties rather than the provisions of this Section. 10.14 The Unit Operator and the Working Interest Owners shall keep and have in their possession books and records showing the development, production, and~ disposition of all Unitized Substances produced from the Unit Area. The Unit Operator and the Working Interest Owners shall permit the Commissioner to examine those books and records at all reasonable times. The books and records shall be made available to the Commissioner in Anchorage or Juneau, Alaska, upon request. These books and records of development, production, and disposition shall employ methods and techniques that shall ensure the most accurate figures reasonably available without requiring separate tankage or meters for each well. The Unit Operator and Working Interest Owners shall use generally accepted and accounting practices consistently applied. 10.15 Notwithstanding the provisions of the State lease forms, all rights and obligations relating to net profit share shall be determined in accordance with 11 AAC 83.201 - 11 AAC 83.295, as amended. Notwithstanding any statute, regulation, or other law to the contrary, the period of limitation for lawsuits by the State of Alaska concerning net profit share reports or payments shall be no earlier than three (3) years following the audit periods specified in 11 AAC 83.245, as amended. The Working Interest Owners holding interests in net profit share leases agree to maintain the records relevant to determination of net profit share unless destruction of the documents is approved by the Commissioner; however this obligation shall 15 terminate six years after the termination of the applicable State lease(s). 11.1 11.2 11.3 11.4 ARTICLE %% Expansion and Contraction After notice to the Working Interest Owners, and with the approval of the Commissioner, the Unit Operator, at its own election or at the direction of the Commissioner shall, when warranted, expand the Unit Area to include any additional lands determined to overlie any Reservoir, any part of which is within the Unit Area, or to include any additional lands regarded as reasonably necessary for the purposes of this Agreement. Any expansion shall not be effective unless approved by the Commissioner. Any lease, no part of which is included in a Participating Area on the tenth anniversary of the effective date of the initial Participating Area established under this Agreement, shall be excluded from the Unit Area and from this Agreement. If any portion of a lease is included in a Participating Area, the portion of the lease outside the Participating Area will neither be severed nor will it continue to be subject to the terms and conditions of the Unit Agreement. The portion of the lease outside the Participating Area will continue in full force and effect so long as ~production is allocated to the unitized portion of the lease and the lessee satisfies the remaining terms and conditions of the lease. Not sooner than ten (10) years from the Effective Date of this Unit Agreement, the Commissioner will, in the Commissioner's discretion, contract the Unit Area to include only that land covered by an approved unit plan of exploration or development or underlain by one or more oil and gas reservoirs or one or more potential hydrocarbon accumulations, and those lands which facilitate production, including the immediate adjacent lands necessary for secondary or tertiary recovery, pressure maintenance, reinjection, or cycling operations. Before any directed contraction or expansion of the Unit Area under this Article, the Commissioner will give the unit Operator and the Working Interest Owners of the affected leases reasonable notice and an opportunity to be heard. 12.1 ARTICLE %2 Effective Date, Term, and Termination This Agreement shall become binding upon each party as of the date each party signs the instrument by which it becomes a party, and shall become effective upon approval by the 16 Commissioner. At least one counterpart of this Agreement shall be filed for record by the Unit Operator in the filing office of the Department of Natural Resources, Anchorage, Alaska and one counterpart shall be filed for record with the office of the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska. 12.2 This Agreement terminates five (5) years from the Effective Date unless: (a) A unit well in the Unit Area has been certified as capable of producing Unitized Substances in Paying Quantities, in which case the Unit Agreement will remain in effect for so long as Unitized Substances are produced in Paying Quantities from the Unit Area', or for so long as Unitized Substances can be produced in paying Quantities and Unit Operations are being conducted in accordance with an approved unit plan of exploration or development, or, should production cease, for so long thereafter as diligent operations are in progress to restore production and then so long thereafter as Unitized Substances are produced in Paying Quantities, or 12.3 (b) The Unit term is extended with the approval of the Commissioner in accordance with State statutes and regulations. No extension shall exceed five (5) years. If the Commissioner orders or approves a suspension of Unit Operations or suspension of production on all or part of the Unit Area, this Agreement shall be continued in force and effect during the period of the authorized suspension, and thereafter so long as operations are being conducted in accordance with the provisions of Article 8. 12.4 Nothing in this Article holds in abeyance the obligations to pay rentals, royalties, or other production or profit-based payments to the State of Alaska from operations or production in any part of the Unit Area. For the purposes of this Article, any seasonal restriction on operations or production or other conditions specifically required or imposed as a term of sale of the original lease, or as a condition imposed under this Agreement, will not be considered a suspension of operations or production ordered pursuant to law or prevention due to Force Majeure. However, seasonal restrictions on operations or production imposed subsequent to approval of this Agreement may provide a basis for a suspension of operations or production if the Commissioner, in his or her sole unfettered discretion, so finds. 12.5 This Agreement may be terminated, with the approval of the Commissioner, at any time by an affirmative vote of the 17 Working Interest Owners as specified in the Unit Operating Agreement. 13.1 13.2 13.3 13.4 ARTICLE 13 Effect of Contraction and Termination Any lease or a portion of a lease eliminated from the Unit Area pursuant to this Agreement may be maintained only in accordance with the terms and conditions contained in the applicable State statutes and regulations and the lease. Upon termination of this Agreement, a lease which was subject hereto may be continued in force and effect in accordance with the terms and conditions contained in the applicable State statutes and regulations and the lease. Each State lease covering State lands within the Unit Area shall remain in force for ninety days after the date on which this Agreement terminates, unless applicable state statutes or regulations provide for a longer period of time. The Unit Operator and the Working Interest Owners shall have the right for a period of one year after the date of termination of this Agreement to salvage and remove Unit Equipment. The Unit Operator and Working Interest Owners shall rehabilitate the leased land eliminated from this Agreement to the satisfaction of the Commissioner within one year after the date of termination of this Agreement. The Commissioner may extend the period for salvage and removal of Unit Equipment and rehabilitation of the leased land. 14.1 ARTICLE 14 Counterparts An owner of Oil and Gas Rights may become a party to this Agreement by signing the original of this instrument, or a counterpart or other instrument agreeing to become a party. The signing of these instruments shall have the same effect as if all parties had signed a single original of this Agreement. 15.1 15.2 ARTICLE 15 Laws and Regulations Except as provided in section 10.15, this Agreement shall not have the effect of altering the applicability of any State statute, regulation, or other law. State leases are subject to all valid applicable local laws and regulations insofar as such laws and regulations: 18 15.3 (a) do not conflict with Federal or State statutes, regulations, or other law; (b) do not conflict with the provisions of this Agreement; and (c) do not conflict with the terms of any lease subject to this Agreement. In case of conflict between this Agreement and the Unit Operating Agreement, this Agreement controls the respective rights and obligations of the Unit Operator, the Working Interest Owners, and the State of Alaska. However, where conflicts exist solely between Working Interest Owners, the Unit Operating Agreement shall prevail. ARTICLE 16 Appearances and Notices 16.1 16.2 The Unit Operator, after notice to the other affected parties, shall have the right to appeal any decisions under or affecting this Agreement. The expense of these appearances shall be paid and apportioned as provided in the Unit Operating Agreement. However, any affected Working Interest Owner shall have the right, at, its own expense, to be heard at any such proceeding. Any order or notice relating to this Agreement which is given to the Unit Operator of record shall be deemed given to all Working Interest Owners in the Unit Area. All notices required by this Agreement to be given to the Unit Operator Shall be deemed properly given if they are in Writing and delivered personally, or sent by prepaid registered mail, certified mail, telex, or facsimile machine to the address set forth below. All notices aCtually received will also be deemed properly given. Name: Stewart Petroleum Company Address: 3111 C Street, Suite 400 Anchorage, AK 99503 Facsimile #: 907/562-3804 Telex #: N/A 17.1 ARTICLE 17 Joinders The Commissioner may order or, upon request, approve a subsequent joinder to the Unit Agreement pursuant to the expansion provisions of Article 11. A request for a 19 subsequent joinder shall be accompanied by a signed counterpart to this Agreement and shall be submitted by the Unit Operator at the time it submits a notice of proposed expansion pursuant to Article 11. A subsequent joinder shall be subject to the requirements which may be contained in the Unit Operating Agreement; provided, however, that the Commissioner may require modification of any provision in a Unit Operating Agreement which the Commissioner finds would prevent or frustrate a subsequent joinder. 18.1 18.2 18.3 18.4 18.5 ARTICLE 18 Default Failure to comply with any of the terms of this Agreement, including any plan approved under Article 8 of this Agreement, is a default under this Agreement. The Commissioner will give notice to the Unit Operator of the default. The notice will state the nature of the default, and, for defaults capable of being cured, include a demand to cure the default by a specified date determined by the Commissioner. If there is no well certified as capable of producing Unitized Substances in Paying Quantities at the time a default occurs and the default is not cure~ by the date indicated in the demand, the Commissioner will, at the Commissioner's discretion, and after giving the Unit Operator reasonable notice and an opportunity to be heard, terminate this Agreement by sending notice of the termination to the Unit Operator. Termination is effective when the notice is sent. If there is a well capable of producing Unitized Substances in Paying Quantities at the time a default occurs and the default is not cured by the date indicated in the demand, the Commissioner will, at the Commissioner's discretion, seek to terminate this Agreement by judicial Proceedings. The remedies provided in this article are in addition to any other administrative or judicial remedy which may be prescribed or provided for in the leases subject to this Agreement, this Agreement, or Federal or State law. 20 IN WITNESS OF THE FOREGOING, the parties have executed this Unit Agreement on the dates opposite their respective signatures. ATTEST: Rebecca L. Stewart, Secretary Date' April 19, 1990 By:STEWAR~ COMPANY W. R. Stewart Title- President Address' 3111 C Street, Suite 400 Anchorage, Alaska 99503 Qualification File No.: 2049 STATE OF ALASKA THIRD JUDICIAL COURT THIS IS TO CERTIFY that on the 19th day of April, 1990, before me the undersigned, a Notary Public in and for the State of Alaska, personally appeared W. R. STEWART, to me known and known to me to be the PRESIDENT of STEWART PETROLEUM COMPANY and he acknowledged to me that he had in his official capacity executed the foregoing instrument as the free act and deed of the said corporation for' the uses and purposes therein stated, and that he was duly authorized to do so on behalf of said corporation. WITNESS MY HAND and official seal on the day and year first above- written. Stateunt. txt Notar~ Public ~h and for Alaska My Commission Expires: A~Comml~o, 5~: .SeplemDer ?, ]992 21 EXHIBIT "A" SCHEDULE SHOWING PERCENTAGE[ & KIND OF OWNERSHIP WEST McARTHUR RIVER UNIT STATE OF ALASKA PAGE 1 o! 1 STATE LANDS TRACT ,,, DESCRIPTION T8N, R14W, S.M. Sec. 3, Protracted, Ail; Sec. 4, Protracted, Ail; Sec. 5, Unsurveyed, Ail tide & submerged lands; Sec. 8, Unsurveyed, Ail tide & submerged lands; Sec. 9, Unsurveyed, All tide & sut~erged lands; Sec. 10, Protracted, All; Sec. 15, Protracted, All; Sec. 16, Unsurveyed, All tide & submerged lands. T8N, R14W, S.M. Sec. 21, Unsurveyed, Ail tide & submerged lands; Sec. 22, Unsurveyed, Ail tide & submerged lands; Sec. 23, Protracted, All; Sec. 27, Unsurveyed, All tide & suk~nerged lands; Sec. 34, Unsurveyed, All tide & submerged lands. ACRES 4175 SERIAL · NUMBER & EXPIRATION DATE ADL-359111 11-30-90 2155 ADL-359112 11-30-90 * BASIC ROYALTY & OWNERSHIP PERCENTAGE LESSEE OF RECORD OWNERSHIP & OVERRIDING ROYALTY PERCENTAGE State of Alaska 12.5% Stewart Petroleum Company Richard E. Wagner V. Paul Gavora William G. Stroeker Charles E. Cole 2% of 8/8 ths. 1% of 8/8 ths. 1% of 8/8 ths. 1% of 8/8 ths. State of Alaska 12.5% Stewart Petroleum Company Richard E. Wagner V. Paul Gavora William G. Stroeker Charles E. Cole 2% of 8/8 tbs. 1% of 8/8 ths. 1% of 8/8 ths. 1% of 8/8 ths. *Net Profit Share Rates not applicable to Unit Tracts. WORKING INTEREST & OWNERSHIP/PERCENTAGE 100.00% 100.00% TOTAL UNIT ACRES 6330 R15W~- -'-I -t- I I T9N + l- + -F I I + T + + I I I -F -I- + T8N-,~ I I ±% + I I -1- + Ii mm + t + I I I I R~4W -f' -t- -I- -fR13W+ "i + + ~-° +T~+.' I o I + -l- o+ I I -~-~-~- I I + T PETROLEUM ,+ TR. 1 + -p + WEST McARTHUR UNIT BOUNDARY TOTAL UNIT AREA: ~330 ACRES AD L-359111 STEWART PETROLEUM CO. 12 -F I + 1. I -I- +T8N I + I i T + I ,iiii, i,ilii~ iiilii. I I + ~ -PT7N I EXHIBIT "B" WEST Mc. ARTHUR RIVER UNIT STEWART PETROLEUM COMPANY 3111 C STREET, SUITE 400 ANCHORAGE, AK 99503 FORELAND Rl14w I R13W .. ?redic~ing ~,;ater Cut by Use of '~'ell Logs By Floyd E. gettis Schlumberger Offshore Services, Anchorage, Alaska P, uring *he preducing life''":' . '.. ' .. o, a;', o'~ i f; eld ... ~'ater saturation an.'.'. ' ', established for the variet.~s F~orosity cut off lib.,its are u,_'.uall.~ duc:i",~ ~.~t:,r,'als '[h~ :.~se of art'.,-' si~gle '.~'ater saturation limit valid only i~ ;:hr:se cases where the range of porosity are very smal). Examp'~es will be fiiver~ ()F a producing interval vzii:h a ~'e!ative large perosit'.y, range: ,';~ere one ~,'ater sa~u~'a't~on limit is invalid. Two methcds of F.',redictir~.9 .~at~..'.r cut will then De demonstrated ",.,-'-t.a.o 'E;oth met~.c:.ds are based upon e~:tabl ishing.. 'the ~-L~ed-. '"')gl: '~ .~ . S~!irr'. ': C, for the formation ljcib]e wa e)'" vo.:.J,.qe~ . i. The First method is a c. rcss plot of porosity Vs water satur- ation l)n a ').':'~g.-lor.j scale. .All -; "+~ . ~,.~.rva'ts v,'~ich are at or near irceduc- ible water saturat'~on w~ll plot on er near a line determined by ~ · SWirr': C for Lhe fo~,~,ai:ioa, if the gravity of the oil is known, other lines sar~ be esLabiished for '~ater cuts of t0 percent, 20 per- cent, etc. 2. The second method is based on the cal'culat~on of three per- meabilities from log data, intrinsic permeability, permeability to oil and permeability t.o water... The permeability feet to oil and water is determined i~ each zone of interest and by applying knowledge of the relative mobility of the oil and water,'the.~water cut can be predicated. This method is best handled by a computer prlocessed interpretation pro- gram. INTRODUCTION The McArthur River Field1 is located in the Cook Inlet southwest of Anchorage, Alaska. The field has four producing intervals, of which the Hemlock Fo),mation is the most important'. The Hemlock is over 300 feet thick and consists of sandstones and .conglomeratic sandstones, with a porosity range from 3 P.U. to 20'P..UJ The interval is further divided into six zones or benches, which.are correlatable over most of the field. A waterflood system was'.i,n place shortly after prodg;c~ tion started. The field has been 'under.active waterflood for over ]0 years, with 564 million barrels 'of .water being injected during the ,. , ,' -2- period2. Total oil production from the Hemlock in the McArthur River Field was 380 million barrels at the end of 1979. The normal completion technique during development was to perforate all the benches which were above the field oil/water contact. Since the average porosity was higher in benches 2(H2) and 3(H3) than in the lower benches, bench 4(H4), bench 5(H5) and bench 6(H6), benches H2 and H3 had higher flow rates and earlier water break through than the lower benches. In addition, the production of fluids causes changes in the permeability of the formation, resulting in declining rates. The reperforating of the intervals can sometimes restore the flow rates. Usually, decreasing rates, combined with increased water cut requires a redrill and recompletion of the pro- ducing intervals. The McArthur River Field water saturation limit above which an interval would not be perforated, was set at a value of 62 percent. As experience with redrilled wells increased, the water saturation limit was lowered to 55 percent. The flood water salinities and the formation water salinities are very close to the same value, so water saturation values calculated in flooded intervals should be accurate. In February of 1979, a review of the results of the McArthur River Field redrilling program showed a need for a'better method of determining which benches to perforate for production. The field is on gas lift, so a minimum water cut is very desirable. DETER~'<INING IRREDUCIBLE WATER VOLUME The first step in developing a water cut prediction method was to determine the irreducible water volume present in the Hemlock formation. A number' of wells had been cored and SWirr and po.rosity determined. Two methods were used, one using air to flush the core and the other using mercury3. The value of SWirr - ~ = C using air varied for .035 to .046... When mercury was used the value of SWirr · ~ = C dropped below .018. A number of wells were then selected at or near the top of the'structure and plots of SW vs ~ from computer process'ed interpretation were made. Figure I is the plot on one of these wells. This well was completed during development with zero water cut. The plot shows an irreducible water volume C = SWirr · ~ of .027. This value of C was confirmed on additional wells and has been used on all additional plots in the Hemlock Formation in the McArthur River Field. It was expected at this point to see a change in the irreducible water volume when the interval changed from sand- stones to conglomeratic sandstones, but this did not occur. One possible explanation is the sandstone grains filling the pore space between the large pebbles are the same size as the sandstone grains in the sandstone intervals. Once the value of C was determined, then the water cut prediction in each bench can be made using the empirical equations presented by Park Jones in 19454. 3 KRW = {SW - S~,'irrl ' i s -FF, KRO : (0.9 - SW 0 9 SWirr' KRW : Relative permeability to water KRO = Relative permeability to oil The ~.,'ater oil ratio is defined by equation ~'!OR : B Y~ MO 5 ~;here B = Reservoir volume factor for oil KW = Effective formation permeability to water K O : Effective formation permeability to oil M W : g'ater viscosity at reservoir conditions M O : Oil viscosity at reservoir conditions The relative permeability ratio (Kw/)x) KRW/KRo) is available using log data and the value of C from the SW vs ~ cross plots. R.L. Morris and W.P. Biggs6 proposed a value of A where A : ~3 M /MW for five cases of varying oil gravities from 45o %o 14o. Figure ~ is a series of charts with' value 'of A for 45o, 35o, 2'/o and 19o oils assuming a water viscosity equal to .4 CP. The chart with A : 5 for an oil gravity of 35o matches closely the conditions in the McArthur River Field. Using this chart, water cut lines can now be plotted on the SW vs ~ cross plot as shown in Figure 3. As expected, the points all fall between 0 and 10% water cut. In the porosity range expected in the Hemlock a straight line from the intersection of the irreducible water volume to the water saturations for various water cuts related to Sg'irr = 30 percent is a close app.roxima- tion of the values obtained from Chart A : 5 and will be used in the rest of the discuss ion. See Figure 4. FIELD EXAMPLES Figure 5 is the SW vs 0 cross plot on the first well in which the water cut prediction method was compared to the Field 14ater Saturation cut off of 55 percent. A large number of the points plotted in the six benches, plotted between the zero and 10 percent water cut lines. The exceptions are the points which are circled and labeled H2. These points are in bench 2, and are of special interest, since they fall above the water saturation limit of 55 percent set by the field operating unit. In contrast, the SW vs ~ cross plots indicate a water cut of at least 40 percent. Figure 6 is the output of .an experimental com- puter processed interpretation program, a 3 perm Saraband, in which three per~.eabilities are calculated. They are the intrinsic permea- bility, the relative permeability to oil and the relative permeability to water. In intervals where SW is near SWirr the computed relative permeability to ~'ater ~'ill be near z~ro and will increase as the SW incraases ~.;Y, en compared to SWirr. The computed permeability to oil will be at a maximum ~'hen SW is close to SWirr and will decrease as SW becomes greater than S~irr. The Hemlock was completed starting in H4 and actual water cut determined after each bench was perforated. H4, as predicted from the SW vs ~ cress plots and the 3 perm Saraband, had zero water cu.t. After bench 3 was perforated the water cut was 10 percent. The 3 perm Sarabond shows an increase in the relative permeability to' water at the base of the interval perforated. Bench 2 was then added to the perforations~ k'ater cut now jumped to 90 percent. This demonstrates the advantage of using the 3 perm Saraband or SW vs ~ cross plots to. pick the intervals to perforate as compared to using the Field ~;ater Saturation limit of 55 percent. Figure 7 is the Sk' vs ~ cross plot on bench 1 of the first well which ~'as co.~.pleted using the SWirr - ~ : C = .027 method. The plot shows H1 should make near zero ~ater c6t. Figure 8 is the plot of bench 2 which indicates a water cut in the 30 percent range. Figure 9 is the plot of the top of bench 5 which is separated from the rest of the bench 5 interval by a shale break. Figure 10 is the 3 perm output on this well, showin~ the perforated interval and confirms the zero water cut expected in bench 1. Figures 11, 12, 13, 14 and 15 are the SW vs ~ cross plots on an infill well drilled in an area where it was expected to have most benches near zero water cut. The cross plots indicate the only H1 would yield low water cut. H1 was not perforated because total log data indicated poor reservoir characteristics due to high silt content. H4 was selected for a completion attempt. The cross plots predict a water cut between 20 percent and 30 percent. The well was completed with a water cut of 25 percent. The final example shown in figures 16, 17, 18 and 19 are on a recent redrill which was necessary because the well had a water cut of 90% coming Free,rom ~. The redrill was m~ved dewn dip on the nose of the structure to penetrate the most promising interval. Figure 16 shows Sw vs ~ cross plot in H2. It indicates a very high water cut as expected. Figure 17 is the plot of H3. It is divided into an upper and lower section with isolation due to a shale break. The upper zone shows a very high water cut and appears to be poorly isolated from H2. 1. Oil and Gas Fields of the Cook Inlet Basin of Alaska. Alaska Geologi. cal Society. 197 5. 2. Statistical Report 1979. State of Alaska Oil and Gas Conservation Coz, mission. 3. Core Data supplied by l.°,cArthur River Field operators. 4. Jones, P.J. "Production Engineering and Reservoir lqechanics (Oil, Condensate, and Natural Gas)". Published by Oil and Gas Jour. (1945) pp. 45-46. 5. Person, S.J. "Ele.~ents of Oil Reservoir Engineering". I,~cGraw-Hill Book Company, Inc. (1950). pp. 291. 6. R. L. Iqorris and W. P Biggs "Using Log-Derived Values of Water Saturation and Porosity". EXHIBIT "C" Participating Area No participating area is created by this Unit Agreement at the time of Application for Approval. If hydrocarbons in paying quantities are discovered, the Unit Operator will submit the proposed Participating Area(s) to the Commissioner in accordance with 11 AAC 83.351. EXHIBIT "D" Map of Participating Area No participating area is created by this Unit Agreement at the time of Application for Approval. In the event hydrocarbons in paying quantities are discovered within the proposed West McArthur River Unit, the Unit Operator will submit the proposed Participating Area(s) to the Commissioner in accordance with 11 AAC 83.351. (See Exhibit "C") EXHIBIT "E" Allocation of Participating Area Expense No participating area is created by this Unit Agreement at the time of Application for Approval. In the event hydrocarbons in paying quantities are discovered within the proposed West McArthur River Unit, the Unit Operator will submit the proposed Participating Area(s) to the Commissioner in accordance with 11 AAC 83.351. (See Exhibit "C") EXHIBIT "F" Allocation of Unit Expense (See Model Form Unit Operating Agreement with Accounting Procedure attached as Exhibit "C" thereto. This form of Operating Agreement is subject to amendment upon future ratification and joinder of the West McArthur River Unit Agreement by working interest owners other than Unit Operator.) A.A.P.L. EO.R~ 610-1982 MODEL FORM OV~gING AGREEMENT :.... ,....:...., .,.,....,....... : ...t.~,,,. ~ ~,, ~ ~ '..,..,, .',...,,:.,~ .:.....~: .,.,,:~. UNIT OPERATING AGREEMENT DATED: March 1, 1990 OPERATOR: Stewart Petroleum Company West McArthur River Unit Cook Inlet Basin Third Judicial District, State of Alaska COPYRIGHT 1982 -- ALL RIGHTS RESERVED AMERICAN ASSOCIATION OF PETROLEUM LANDMEN, 2408 CONTINENTAL LIFE BUILDING, FORT WORTH, TEXAS, 76102, APPROVED FORM. A.A.P.L. NO. 610 1982 REVISED A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 TABLE OF CONTENTS Artide Title Page I. DEFINITIONS ...................................................................................... II. EXHIBITS .......................................................................................... 1 III. INTERESTS OF PARTIES ........................................................................... 2 A. OIL AND GAS INTERESTS ......................................................................... 2 B. INTERESTS OF PARTIES IN COSTS AND PRODUCTION .............................................. 2 C. EXCESS ROYALTIES, OVERRIDING ROYALTIES AND OTHER PAYMENTS .............................. 2 D. SUBSEQUENTLY CREATED INTERESTS ............................................................. 2 IV. TITLES ............................................................................................ 2 A. TITLE EXAMINATION ............................................................................ 2-3 B. LOSS OF TITLE ................................................................................... 3 ....... ,~ ...... ; ................... : .................................................................... 3. Other Losses .................................................................................... 3 V. OPERATOR ........................................................................................ 4 A. DESIGNATION AND RESPONSIBILITIES OF OPERATOR ............................................... 4 B. RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR ......................... 4 1. Resignation or Removal of Operator ................................................................. 4 2. Selection of Successor Operator ..................................................................... 4 C. EMPLOYEES ..................................................................................... 4 D. DRILLING CONTRACTS ........................................................................... 4 VI. DRILLING AND DEVELOPMENT ..................... : .............................................. 4 A. INITIAL WELL ................................................................................... 4-5 B. SUBSEQUENT OPERATIONS ....................................................................... 5 1. Proposed Operations .............................................................................. 5 2. Operations by Less than All Parties .................................................................. 5-6-7 3. Stand-By Time .................................................................................. 7 4. Sidetracking .................................................................................... 7 C. TAKING PRODUCTION IN KIND ................................................................... 7 D. ACCESS TO CONTRACT AREA AND INFORMATION ................................................. g E. ABANDONMENT OF WELLS ....................................................................... 8 1. Abandonment of Dry Holes ........................................................................ 8 2. Abandonment of Wells that have Produced ............................................................ 8-9 3. Abandonment of Non-Consent Operations ............................................................ 9 VII. EXPENDITURES AND LIABILITY OF PARTIES ...................................................... 9 A. LIABILITY OF PARTIES ........................................................................... 9 B. LIENS AND PAYMENT DEFAULTS ................................................................. 9 C. PAYMENTS AND ACCOUNTING .................................................................. 9 D. LIMITATION OF EXPENDITURES .................................................................. 9-10 1. Drill or Deepen .................................................................................. 9-10 2. Rework or Plug Back ............................................................................. 10 3. Other Operations ................................................................................ 10 E. RENTALS~ SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES ................................... 10 F. TAXES .......................................................................................... 10 G. INSURANCE ..................................................................................... 11 VIII. IX. X. XI. XII. XIII. XIV. XV. XVI. Deleted Deleted ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST ....................................... 11 A. SURRENDER OF LEASES ........................................................................... 11 B. RENEWAL OR EXTENSION OF LEASES .............................................................. 11 C. ACREAGE OR CASH CONTRIBUTIONS ............................................................. 11-12 D. MAINTENANCE OF UNIFORM INTEREST ........................................................... 12 E. WAIVER OF RIGHTS TO PARTITION ............................................................... 12 F. PREFERENTIAL RIGHT TO PURCHASE ............................................................. 12 INTERNAL REVENUE CODE ELECTION ............................................................. 12 CLAIMS AND LAWSUITS ........................................................................... 13 FORCE MAJEURE ................................................................................ i. 13 NOTICES .......................................................................................... 13 TERM OF AGREEMENT ............................................................................ 13 COMPLIANCE WITH LAWS AND REGULATIONS ..................................................... 14 A. LAWS, REGULATIONS AND ORDERS ............................................................... 14 B. GOVERNING LAW ............................................................................... 14 C. REGULATORY AGENCIES ......................................................................... 14 OTHER PROVISIONS ....................................................................... ,,, .... ., 14 MISCELLANEOUS .................................................................................. 15 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 5 6 7 8 9 10 11 12 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 ~0 ~2 54 ~5 37 38 39 4O 41 42 45 46 47 48 ~9 50 51 52 55 54 55 56 57 58 59 6O 61 62 6~ 65 67 68 69 70 OPERATING AGREEMENT THIS AGREEMENT, entered into by and between Stewart Petroleum Comparly 3111 "C" Street, Suite 400, Anchorage, Alaska 99503 , hereinafter designated and referred to as "Operator", and the signatory party or parties other than Operator, ~metimes hereinafter referred to individually herein as "Non-Operator", and colleetively as "Non-Operators". WITNESSETH: WHEREAS, the parties to this agreement are owners of oil and gas leases and/or oil and gas interests in the land identified in Exhibit "A", and the parties hereto have reached an agreement to explore and develop these leases and/or oil and gas interests for the production of oil and gas to the extent and as hereinafter provided, NOW, THEREFORE, it is agreed as follows: ARTICLE I. DEFINITIONS As used in this agreement, the following words and terms shall have the meanings here ascribed to them: A. The term "oil and gas" shall mean oil, gas, casinghead gas, gas condensate, and all other liquid or gaseous hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is specifically stated. B. The terms "oil and gas lease", "lease" and "leasehold" shall mean the oil and gas leases covering tracts of land lying within the Contract Area which are owned by the parties to this agreement. C. The term "oil and gas interests" shall mean unleased fee and mineral interests in tracts of land lying within the Contract Area which are owned by parties to this agreement. D. The term "Contract Area" shall mean all of the lands, oil and gas leasehold interests and oil and gas interests intended to lat. developed and operated for oil and gas purposes under this agreement. Such lands, oil and gas leasehold interests and oil and ,gas interests are described in Exhibit "A". E. The term "drilling unit" shall mean the area fixed for the drilling of one well by order or rule of any state or federal body having authority. If a drilling unit is not fixed by any such rule or order, a drilling unit shall be the drilling unit as establish- ed by the pattern of drilling in the Contract Area or as fixed by express agreement of the Drilling Parties. F. The term "drillsite" shall mean the oil and gas lease or interest on which a proposed well is to be located. G. The terms "Drilling Party" and "Consenting Party" shall mean a party who agrees to join in and pay its share of the cost of any operation conducted under the provisions of this agreement. H. The terms "Non-Drilling Party" and "Non-Consenting Party" shall mean a party who elects not to participate in a proposed operation. Unless the context otherwise clearly indicates, words u~d in the singular include the plural, the plural includes the singular, and the neuter gender includes the masculine and the feminine. ARTICLE II. EXHIBITS The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof: [] A. Exhibit "A", shall include the following information: (1) Identification of lands subject to this agreement, (3) Percentages or fractional interes~ of parties to ~is agreement, (5) Addresses of parties for notice purposes. B. Exhibit "B", Form of Lease. C. Exhibit "C", Accounting Procedure. D. Exhibit "D", Insurance. E. Exhibit "E", G~ Balancing Agreement. F. Exhibit "F", Non-Discrimination and Certification of Non-Segregat~ Facilities. G. Exhibit "G", Tax Parmership. If any provision of any exhibit, except Exhibits "E" and "G", is inconsistent with any provision contained in .~e body of ~is agreement, ~e provisions in the body of ~is agreement shall prevail. : -1- A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 2l 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 ARTICLE III. INTERESTS OF PARTIES A. Oil and Gas Interests: If any party owns an oil and gas interest in the Contract Area, that interest shall be treated for all purposes of this agreement and during the term hereof as ii it were covered by the form of oil and gas lease attached hereto as Exhibit "B", and the owner thereof shall be deemed to own both the royalty interest reserved in such lease and the interest of the lessee thereunder. B. Interests of Parties in Costs and Production: Unless changed by other provisions, all cost~ and liabilities incurred in operations under this agreement shall be borne and paid, and all equipment and materials acquired in operations on the Contract Area shall be owned, by the parties as their interests are set forth in Exhibit "A". In the same manner, the parties shall also own all production of oil and gas from the Contract Area subject to the payment of royalties a~ :5el; for~ Jr1 3/1/90 Part±cipat'ion hcA'eement which shall be borne as hereinafter set forth. Regardless of which party has contributed the lease(s) and/or oil and gas interest(s) hereto on which royalty is due .md payable, each party entitled to receive a share of production of oil and gas from the Contract Area shall bear and shall pay or deliver, or cause to be paid or delivered, to the extent of its interest in such production, the royalty amount stipulated hereinabove and shall hold the other parties free from any liability therefor. No party shall ever be responsible, however, on a price basis higher than the price received by such party, to any other party's lessor or royalty owner, and if any such other party's lessor or royalty owner should demand and receive settlement on a higher price basis, the party contributing the affected lease shall bear the additional royalty burden attributable to such higher price. Nothing contained in this Article III.B. shall be deemed an assignment or cross-assignment of interests covered hereby. C. Excess Royalties, Overriding Royalties and Other Payments: Unless changed by other provisions, if the interest of any party in any lease covered hereby is subject to any r(~yalty, overriding royalty, production payment or other burden on production in excess of the amount stipulated in Article llI.B., such party burdened shall assume and alone bear all such excess obligations and shall indemnify and hold the other parties hereto harmless from any and all claims and demands for payment asserted by owners of such excess burden. D. Subsequently Created Interests: If any party should hereafter create an overriding royalty, production payment or other burden payable out of production attributable to its working interest hereunder, or if such a burden existed prior to this agreement and is not set forth in Exhibit "A", or was not disclosed in writing to all other parties prior to the execution of this agreement by all parties, or is not a jointly acknowledeed ancl accepted obligation of all parties (any such interest being hereinafter referred to as "subsequently created interest" irrespective of thc timing of its creation and the party out of whose working interest the subsequently created interest is derived being hereinafter referred to as "burdened party"), and: 1. If the burdened party is required under this agreement to assign or relinquish to any other party, or parties, all c~I' a l~Ortion of its working interest and/or the productkm attributable thereto, said other party, or parties, shall receive said assi.enmvnl and/re' production free and clear of said subsequently created interest and the burdened party shall indemnify and save said other party. or parties, harmless from,any and all claims and demands for payment asserted by owners of the stfl>sequently created interest; and, 2. If the burdened party fails to pay, when due, its share of expenses chargeable hereunder, all provisions of Article VII.B. shall be enforceable against the subsequently created interest in the same manner as they are enforceable against the workin.e imcrest of the burdened party. ARTICLE IV. TITLES A. Title Examination: Title examination shall be made on the drillsite of any proposed well prior to commencement of drilling operations or, if the Drilling Parties so request, title examination shall be made on the leases and/or oil and gas interests included, or planned to be includ- ed, in the drilling unit around such well. The opinion will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable leases. At the time a well is proposed, each party contributing leases and/or oil and gas interests to the drillsite, or to be included in such drilling unit, shall furnish to Operator all abstracts (including federal lease status reports), title opinions, title papers and curative material in its possession free of charge. All such information not in the possession of or made available to Operator by the parties, but necessary for the examination of the title, shall be obtained by Operator. Operator shall cause title to be examined by attorneys on its staff or by outside attorneys. Copies of all title opinions shall be furnished to each party hereto. The cost incurred by. Operator in this title program shall be borne as follows: [] Option No. 1: Costs incurred by Operator in procuring abstracts and title examination (including preliminary, supplemental. shut-in gas royalty opinions and division order title opinions) shall be a part of the administrative overhead as provided in Exhibit and shall not be a direct charge, whether performed by Operator's staff attorneys or by outskle attorneys. -2- 1 2 3 4 5 6 7 8 9 10 Ii 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 5o 51 52 53 54 55 56 57 58 59 60 61 62 63 65 66 67 68 69 70 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE IV continued [] Option No. 2: Costs incurred by Operator in procuring abstracts and fees paid outside attorneys for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) shall be borne by the Drilling Parties in the proportion that the interest of each Drilling Party bears to the total interest of all Drilling Parties as such interests appear in Ex- hibit "A". Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of thc. above functions. Each party shall be responsible for securing curative matter and pooling amendments or agreements required in connection with leases or oil and gas interests contributed by such party. Operator shall be responsible for the preparation and recording of tx×}ling designations or declarations as well as the conduct of hearings before governmental agencies for the securing of spacing or pooling orders. This shall not prevent any party from appearing on its own behalf at any such hearing. No well shall be drilled on the Contract Area until after (1) the title to the drillsite or drilling unit has been examined :,s above provided, and (2) the title has been approved by the examining attorney or title has been accepted by all of the parties who are to par- ticipate in the drilling of the well. B. Loss of Title: reduction of interest from that shown on Exhibit "A", the party contributing the affected lease or interest shall have ninety (90/s from final determination of title failure to acquire a new lease or other instrument curing the entirety of the title failure, which/quisi- tion will not be subject to Article VIII.B. and failing to do so, this agreement, nevertheless, shall continue in force as to all re~ining oil and gas leases and interests: and, (a) The party whose oil and gas lease or interest is affected by the title failure shall bear alone the entire loss a.~ it shall not be entitled to recover from Operator or the other parties any development or operating costs which it may have theretof~e pa'~ or incurred, but there sh:dl be no additional liability on its part to the other parties hereto by reason of such title failure/ (b) There shall be no retroactive adjustment of expenses incurred or revenues received from the operatio~of the interest which has been lost, but the interests of the parties shall be revised on an acreage basis, as of the time it is determin~~ has oc- curred, so that the interest of the party whose lease or interest is affected by the title failure will thcS'ed in thc C(mtract Area by the amount of the interest lost; (c) If the proportionate interest of the other parties hereto in any producing well thereffffor~h Contract Area is increased by reason of the title failure, the party whose title has failed shall receive the pro~~s'uch in- terest (less costs and burdens attributable thereto) until it has been reimbursed for unrecov~~ion with such well; (d) Should any person not a party to this agreement, who is determined to.the ~ t ti cl~ which h, as failed, pay in any manner any part of the cost of operation, development, or equip, fire, arty or parties who bore the costs which are so refunded; (e) Any liability to account to a third party for prior production ~o'~~dlurc~shall be borne by the party or parties whose title failed in the same propor'tio~~~:m,d.. (f) No charge shall be made to the joint account for legal ~i the inn.~x'.st claimed by any party hereto, it being the intention of the parti~~n~es in connection therewith. 2. Loss by Non-Payment or Erroneous Paym~shut-i.n payment, minimum royalty or royalty payment, ~n terminates. there shall be no monetary liability against th~' the required payment secures a new lease covering the s~p5r paym~e,nt, which acquisition will not be subject to A~~ct'~ as of the date of termination of the lease invol~~~ n intel'est in the Contract Area on account of ~~1 to make the required payment shall not ha~~d)le to the lost interest, calculated t shall be reimbursed for d or wells previously a (a) Proceeds . up to the am (b) Pr oil and g c term d po (c) Any monies, up to the amount of unrecovered costs, that may be paid by any party who is, or becomes, the owner of the interest 3, Other Losses: All losses incurred, '.:t!:er th'_'."_ th_"':'z ret fer:h in .a._"t?s'!-2:: !\.'.!3.!. :m,J !V..r3.2. '_')',.,"t', shall lit, }oint losses and shall be borne by all parties in proportion to their interests. There shall be no readjustment of interests in the remaining portion of the Contract Area. -3- A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE V. OPERATOR A. Designation and ResponsibLlities of Operator: Stewart Petroleum Company shall be the Operator of the Contract Area, and shall conduct and direct and have full control of all operations on the Contract Area as ~-rmitted and required by. and within the Emits of this agreement. It shall conduct all such operations in a good and workmanlike manner, but it shall have no liability as Operator to the other parties for losses sustained or Liabilities incurred, except such as may result from gross negligence or will/ul misconduct. 12 13 14 15 16 17 19 20 21 __ 23 24 25 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 65 66 67 68 69 70 B. Resignation or Removal of Operator and Selection of Successor: 1. Resignation or Removal of Operator: Operator may resign at any time by giving written notice thereof to Non4Dperators. Lf Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators. except the selection of a successor. Operator may be removed if it fails or re/uses to carry, out its duties hereunder, or becomes insolvent, bankrupt or is placed in receivership, by the a.ffirmafive vote ti two (2) or more Non-Operators owning a majority interest based on ownership as shown on Exhibit "A" remaining after excluding the voting interest of Operator. Such resignation or removal shall not become effective until 7:00 o'clock A.M. on the first day of the calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator or action by the NonK)perators to remove Operator, unless a successor Operator has been selected and assumes the duties of Operator at an earlier date. Operator. after effective date of resignation or removal, shall be bound by the terms hereof as a Non4Dperator. A change of a cor- porate name or structure of Operator or transfer of Operator's interest to any single subsidiary, parent or successor corporation shall not be the basis for removal of Operator. 2. Selection of Successor Operator: Upon the resignation or removal of Operator. a successor Operator shall be selected by the parties. The successor Operator shall be selected from the parties owning an interest in the Contract Area at the time such successor Operator ks ~lected. The successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership a.s shown on Exhibit "A": provided, however, if an Operator which has been removed fails to vote or votes onh' to succeed itself, the successor.Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership a,s shown on Exhibit "A" remaining after excluding the voting interest of the Operator that was removed. C. Employees: The number of employees used by Operator in conducting operations hereunder, their selection, and the hours of labor and the compensation for services performed shall be determined by Operator. and all such employees shall be the employees of Operator. D. Drilling Contracts: All wells drilled on the Contract Area shall be drilled on a competitive contract basis at the usual rates prevailing in the area. If it so desires. Operator may employ its own tools and equipment in the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges shall be agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by Operator under the same terms and conditions as are customary and usual in the area in contracts of in- dependent contractors who are doing work of a similar nature. A. Initial Well: On or before the 30th day of oil and gas at the following location: ARTICLE VI. DRILLING AND DEVELOPMENT November , 19 90 Surf: SW/4 16-8N-14W, SM Btm: SE/4 iO-SN-14W, SM Operator shall commence the drilling of a well for and shall thereafter continue the drilling of the well with due diligence to 14,500' TMI) (10,600' TVD) or to a depth sufficient to fully penetrate the Hemlock Formation, whichever is lesser. unless granite or other practically impenetrable substance or condition in the hole. which renders further drilling impractical, is en- countered at a lesser depth, or unless all parties agree to complete or abandon the well at a lesser depth. Operator shall make reasonable tests of all formations encountered during drilling which give indication of containing oil and gas in quantities sufficient to test. unless this agreement shall be limited in its application to a specific formation or formations, in which event Operator shall be required to test only the formation or formations to which this aereement may apply. -4- 1 2 3 4 6 7 8 9 10 i1 12 13 14 15 16 17 18 19 2o 21 22 23 2/4 25 26 27 28 29 3o 31 32 34 36 37 38 39 `4o 41 42 .46 49 56 58 6o 61 62 63 66 67 68 69 7o A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VI continued If, in Operator's judgment, the well will not produce oil or gas in paying quantities, and it wishes to plug and abandon the well as a dry hole, the provisions of Article VI.E.1. shall thereafter apply. B. Subsequent Operations: 1. Proposed Operations: Should any party hereto desire to drill any well on the Contract Area other than the well provided for in Article VI.A, or to rework, deepen or plug back a dr)' hole drilled at the joint expense of all parties or a well jointly owned by all the parties and not then produdng in paying quantities, the party desiring to drill, rework, deepen or plug back such a well shall give the other parties written notice of the proposed operation, specifying the work to be performed, the location, proposed depth, objective forma- tion and the estimated cost of the operation. The parties receiving such a notice shall have thirty (30) days after receipt of the notice within which to notify the party wishing to do the work whether they elect to participate in the cost of the proposed operation. If a drill- ing rig is on location, notice of a proposal to rework, plug back or drill deeper may be given by telephone and the response period shall be limited to twell~/-[011r (~.41, hours, exclusive of Saturday, Sunday and legal holidays. Failure of a party receiving such notice to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation. Any notice or response given by telephone shall be promptly confirmed in writing. If all parties elect to participate in such a proposed operation, Operator shall, within ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the ~ellty-f011r (24)hour period when a drilling rig is on loca- tion, as the case may be), actually commence the proposed operation and complete it with due diligence at the risk and expense of all par- ties hereto; provided, however, said commencement date may be extended upon written notice of same by Operator to the other parties, for a period of up to thirty (30) additional days if, in the sole opinion of Operator, such additional time is reasonably necessary to obtain permits from governmental authorities, surface rights (including rights-of-way) or appropriate drilling equipment, or to complete title ex- amination or curative matter required for title approval or acceptance. Notwithstanding the force majeure provisions of Article XI, it the actual operation has not been commenced within the time provided (including any extension thereof as specifically permitted herein) and if any party hereto still desires to conduct said operation, written notice proposing same must be resubmitted to the other parties in accor- dance with the provisions hereof as if no prior proposal had been made. 2. Operations by Less than All Parties: I~ any party receiving such notice as provided in Article VI.B.1. or VII.D.1. (Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation shall, within ninety (90) days after the expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the t~e~ty-b~r 1~4) hour period when a drilling rig is on location, as the case may be) actually commence the proposed operation and complete it with due diligence. Operator shall perform all work for the account of the Consenting Parties; provided, however, if no drilling rig or other equipment is on location, and if Operator is a Non-Consenting Party, the Consenting Parties shall either: (a) request Operator to perform the work required by such proposed opera- tion for the account of the Consenting Parties, or (b) designate one (1) of the Consenting Parties as Operator to perform such work. Con- senting Parties, when conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and con- ditions of this agreement. ff less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the applicable notice period, shall advise the Consenting Parties of the total interest of the parties approving such operation and its recommendation as to whether the Consenting Parties should proceed with the operation as proposed. Each Consenting Party, within ~n~-[0ut (~1. hours (exclusive of Saturday, Sunday and legal holidays) after receipt of such notice, shall advise the proposing party of its desire to (a) limit par- ticipation to such party's interest as shown on Exhibit "A" or (b) carry its proportionate part of Non-Consenting Parties' interests, and failure to advise the proposing party shall be deemed an election under (a). In the event a drilling rig is on location, the time permitted for such a response shall not exceed a total of ~W011~y~f0~lt (~1 hours (inclusive of Saturday, Sunday and legal holidays). The proposing party, at its election, may withdraw such propo~aLif .there is insufficient participation and shall promptly notify all parties of such decision. The entire cost and risk of conducting such operations shall be borne by the Consenting Parties in the proportions they have elected to bear same under the terms of the preceding paragraph. Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and encumbrances of every kind created by or arising from the operations of the Consenting Parties. If such an operation results in a dry hole, the Consenting Parties shall plug and abandon the well and restore the surface location at their sole cost, risk and expense. If any well drilled, reworked, deepened or plugged back under the provisions of this Article results in a pro- ducer of oil and/or gas in paying quantities, the Consenting Parties shall complete and equip the well to produce at their sole cost and risk, .. , , ,, , , . , -5- 1 2 3 4 5 6 7 8 9 I0 1! 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 65 66 67 68 69 7O A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICL,E VI eonlinued and the well shall then be turned over to Operator and shall be operated by it at the expense and for the account of the Consenting Par- ties. Upon commencement of operations for the drilling, reworking, deepening or plugging back of an3' such well by Consenting Parties in accordance with the provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting Parties. and the Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non-Consenting Party's interest in the well and share of production therefrom until the proceeds of the sale of such share, calculated at the well, or market value thereof if such share is not sold, (after deducting production taxes, exdse taxes, royalty, overriding royalty and other in- terests not excepted by Article III.D. payable out of or measured by the production from such well accruing with respect to such interest until it reverts) shall equal the total of the following: (a) 100% of each such Non-Consenting Party's share of the cost of any newly acquired surface equipment beyond the wellhead connections (including, but not limited to, stock tanks, separators, treaters, pumping equipment and piping), plus 100% of each such Non-Consenting Party's share of the cost of operation of the well commencing with first production and continuing until each such Non- Consenting Party's relinquished interest shall revert to it under other provisions of this Article, it being agreed that each Non- Consenting Party's share of such costs and equipment will be that interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning of the operations; and (b) /400 % of that portion of the costs and expenses of drilling, reworking, deepening, plugging back, testing and completing, after deducting any cash contributions received under Article VIII.C., and /,00 % of that portion of the cost of newly acquired equip- ment in the well (to and including the wellhead connections), which would have been chargeable to such Non-Consenting Party if it had participated therein. An election not to participate in the drilling or the deepening of a well shall be deemed an election not to participate in any re- working or plugging back operation proposed in such a well, or portion thereof, to which the initial Non-Consent election applied that is conducted at any time prior to full recovery.by the Consenting Parties of the Non-Consenting Party's recoupment account. Any such reworking or plugging back operation conducted during the recoupment period shall be deemed part of the cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties one hundred percent (100%) of that portion of the costs of the reworking or plugging back operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a reworking or plugging back operation is proposed during such recoupment period, the provisions of this Article VI.B. shall be ap- plicable as between said Consenting Parties in said well. During the period of time Consenting Parties are entitled to receive Non-Consenting Party's share of production, or the proceeds therefrom, Consenting Parties shall be responsible for the payment of all production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to Non-Consenting Party's share of production not excepted by Ar- ticle III.D. In the case of any reworking, plugging back or deeper drilling operation, the Consenting Parties shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all such equipment shall remain unchanged: and upon abandonment of a well after such reworking, plugging back or deeper drilling, the Consenting Parties shall account for all such equip- merit to the owners thereof, with each party receiving its proportionate part in kind or in value, less cost of salvage. Within sixty (60) days after the completion of any operation under this Article, the party conducting the operations for the Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to the well, and an itemized statement of the cost of drilling, deepening, plugging back, testing, completing, and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement of such costs of operation, may submit a detailed statement of monthly bill- ings. Each month thereafter, during the time the Consenting Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities in- curred in the operation of the well, together with a statement of the quantity of oil and gas prodoced from it and the amount of proceeds realized from the sale of the well's working interest production during the preceding month. In determining the quantity of oil and gas produced during any month, Consenting Parties shall use industry accepted methods such as, but not limited to, metering or periodic well tests. Any amount realized from the sale or other disposition of equipment newly acquired in connection with any such .operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such Non-Consenting Party shall revert to it above provided; and if there is a credit balance, it shall be paid to such Non-Consenting Party. . -6- 1 2 4 5 6 7 8 9 10 11 12 13 15 16 17 18 19 2O 21 22 2~ 2~ 25 26 27 28 29 3O 31 32 35 ~6 ~7 ~8 39 4O 41 42 45 46 47 48 49 5O 51 52 53 54 55 56 57 58 59 6O 61 62 6~ 65 66 67 68 69 7O A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VI continued If and when the Consenting Parties recover from a Non-Consenting Party's relinquished interest the amounts provided ior the relinquished interests of such Non-Consenting Party shall automatically revert to it, and, from and after such reversion, such Non- Consenting Party shall own the same interest in such well, the material and equipment in or pertaining thereto, and the production therefrom as such Non-Consenting Party would have been entitled to had it participated in the drilling, reworking, deepening or plug,e, ing back of said well. Thereafter, such Non-Consenting Party shall be charged with and shall pay its proportionate part of the further costs of the operation of said well in accordance with the terms of this agreement and the Accounting Procedure attached hereto. Notwithstanding the provisions of this Article VI.B.2., it is agreed that without the mutual consent of all parties, no wells shall be completed in or produced from a source of supply from which a well located elsewhere on the Contract Area is producing, unless such well conforms to the then-existing well spacing pattern for such source of supply. The provisions of this Article shall have no application whatsoever to the drilling of the initial well described in Article VI.A. except (a) as to Article VII.D.I. (Option No. 2), if selected, or (b) as to the reworking, deepening and plugging back of such initial well after it has been drilled to the depth specified in Article VI,A. if it shall thereafter prove to be a dry hole or, if initially completed for pro- duction, ceases to produce in paying quantities. 3. Stand-By Time: When a well which has been drilled or deepened has reached its authorized depth and all tests have been completed, and the results thereof furnished to the parties, stand-by costs incurred pending response to a party's notice pr,posing a reworking, deepening, plugging back or completing operation in such a well shall be charged and borne as part of the drilling or deepen- ing operation just completed. Stand-by costs subsequent to all parties responding, or expiration of the response time permitted, whichever first occurs, and prior to agreement as to the participating interests of all Consenting Parties pursuant to the terms of the second gram. matical paragraph of Article VI.B.2, shall be charged to and borne as part of the proposed operation, but if the proposal is subsequently withdrawn because of insufficient participation, such stand-by costs shall be allocated between the Consenting Parties in the proportion each Consenting Party's interest as shown on Exhibit "A" bears to the total interest as shown on Exhibit "A" of all Consenting Par- ties. 4. Sidetracking: Except as hereinafter provided, those provisions of this agreement applicable to a "deepening" operation shall also be applicable to any proposal to directionally control and intentionally deviate a well from vertical so as to change the bottom hole location (herein called "sidetracking"), unless done to straighten the hole or to drill around junk in the hole or because of other mechanical difficulties. Any party having the right to participate in a proposed sidetracking operation that does not own an interest in the affected well bore at the time of the notice shall, upon electing to participate, tender to the well bore owners its proportionate share (equal to its interest in the sidetracking operation) of the value of that portion of the existing well bore to be utilized as follows: (a) If the proposal is for sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs incurred in the initial drilling of the well down to the depth at which the sidetracking operation is initiated. (b) If the proposal is for sidetracking a well which has previously produced, reimbursement shall be on the basis of thc well's salvable materials and equipment down to the depth at which the sidetracking operation is initiated, determined in accordance with the provisions of Exhibit "C", less the estimated cost of salvaging and the estimated cost of plugging and abandoning. In the event that notice for a sidetracking operation is given while the drilling rig to be utilized is on location, the response period shall be limited to forty-eight (48) hours, exclusive of Saturday, Sunday and legal holidays; provided, however, any party may request and receive up to eight (8) additional days after expirat!on of the forty-eight (48) hours within which to respond by paying for all stand-by time incurred during such extended response period. If more than one party elects to take such additional time to respond to the notice, stand- by costs shall be allocated between the parties taking additional time to respond on a day-to-day basis in the proportion each electing par- ty's interest as shown on Exhibit "A" bears to the total interest as shown on Exhibit "A" of all the electing parties. In all other in- stances the response period to a proposal for sidetracking shall be limited to thirty (30) days. C. TAKING PRODUCTION IN KIND: Each party shall take in kind or separately dispose of its proportionate share of all oil and gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating oil and gas for marketing purposes and production unavoidably lost. Any extra expenditure incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 3O 31 32 33 34 35 36 37 38 39 40 41 42 43 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VI continued require4 to pa.',' tor only its proportionate share ot such part of Operator's surface tacilitit.'s which it u:v.:.,,. Each part.',' shall execute such dMsion orders and contracts as may he necessary I,r the ~fie ot its intcrest in prt~duction the Contract Area, and. except as providt4 in Article \"ll.B.. shall be entitle4 to receive paymem directly from the purchaser thcrcof its share of all production. In the event any party shall fail to make the arrangements necessary to take in kind or separately dispo~' of its prolmrtionate share of the oil and gas produced from the Contract Area, Operator shall have the right, subject to the revcx:ation at will by the party ownmg it. but not the obligation, to purchase such oil and gas or sell it to others at any time and ~rom time to time. for the account oi thc non- taking party at the best price obtainable in the area for such production. Any such purchase or sale by Operator shall be subject alwavs to the right of the owner of the production to exercise at any time its right to take in kind, or separately dispose of. its share of all oil and gas not previously delivered to a purchaser. Any purchase or sale by Operator of any other party's share of oil and gas shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (I) year. Notwithstanding the foregoing, Operator shall not make a sale, including one ins interstate com- merce, of any other party's share of gas production without first giving such other party thirty (30) days notice of such intended sale. D. Access to Contract Area and Information: Each party shall have access to the Contract Area at all reasonable times, at its sole cost and risk to inspect (~r observe opt.rati~ and shall have access at reasonable times to iniormatkm pcrtainin.~ to the development or operation thereoL including Operator's and records relating thereto. Operator. upon request, shall furnish each of the other parties with copies of all forms or rt'ports fih'd with governmental agencies, daily drilling reports, well logs, tank tahles, daily gauge and run tickets and reports of stock on hand at thc each month, anti shall make availahle samples of any cores or cuttings taken froln any wcll drillt.d on die Contract Area. Thc cost gathering and furnishing intormation to Non.()pcralor. olht.r than that spetliticd abovc, shall bc t'JliJrRt'd to Iht' Non ()[~t.r,ll,,l' quests the information. E. Abandonment of Wells: 1. Abandonment of Dry Holes: Except for any well drilled or deepened pursuant to Article VI.B.2., any well wi'rich Ms been drilled or deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or deepening such well. Any party who objects to plugging and abandoning such well shall have the right to t~ke over the well and conduct further operations in search of oil and/or gas subject to the provisions of Article VI.B. 2. Abandonment of Wells that have Produced: Except for any well in which a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all parties. If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of all the parties hereto. If, within thirty (30) days after receipt of notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the interval(s) of the formation(s) then open to production shall tender to each of the other parties its proportionate share of the value of the well's salvable material and equipment, determined in accordance with the provisions of Exhibit "C", tess the estimated cost of salvaging and the estimated cost of plugging and abandoning. Each abandoning party shall assign the non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the well and related equipment, together with its interest in the leasehold estate as to, but only as to, the in- terval or intervals of the formation or formations then open to production. If the interest of the abandoning party is or includes an oil and gas interest, such party shall execute and deliver to the non-abandoning party or parties an oil and gas lease, limited to the interval or in- tervals of the formation or formations then open to production, for a term of one (1) year and so long thereafter as oil and/or gas is pro- duced from the interval or intervals of the formation or formations covered thereby, such lease to be on the form attached as Exhibit 62 63 64 65 66 67 68 69 70 -8 alternate- 3 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 6O 61 62 63 64 65 66 67 68 69 70 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VI continued "B' '. The assignments or leases so limited shall encompass the "drilling unit" upon which the well is located. The payments by, and the assignments or leases to, the assignees shall be in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of partidpation in the Contract Area of all assignees. There shall be no readjustment of interests in the remaining portion of the Contract Area. Thereafter, abandoning parties shall have no further responsibility, liability, or interest in the operation of or production from the well in the interval or intervals then open other than the royaltie~ retained in any lease made under the terms of this Article. Upon re- quest, Operator shall continue to operate the assigned well for the account of the non-abandoning parties at the rates and charges con- templated by this agreement, plus any additional cost and charges which may arise as the result of the separate ownership of the as,signed well. Upon proposed abandonment of the producing interval(s) assigned or leased, the assignor or lessor shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in further operations therein subject to the pro- visions hereof. 3. Abandonment of Non-Consent Operations: The provisions of Article VI.EA. or VI.E.2. above shall be applicable as between Consenting Parties in the event of the proposed abaFdonment of any well excepted from said Articles; provided, however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further operations therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well in accordance with the provisions of this Article VI.E. ARTICLE VII. EXPENDITURES AND LIABILITY OF PARTIES A. Liability of Parties: The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area. Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership or association, or to render the parties liable as partners. B. Liens and Payment Defaults: Each Non-Operator grants to Operator a lien upon its oil and gas rights in the Contract Area, and a security interest in its share of oil and/or gas when extracted and its interest in all equipment, to secure payment of its share of expense, together with interest thereon at the rate provided in Exhibit "C". To the extent that Operator has a security interest under the Uniform Commercial Code of the state, Operator shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the oh- raining of judgment by Operator for the secured indebtedness shall not be deemed an election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof. In addition, upon default by any Non-Operator in the payment of its share of expense, Operator shall have the right, without prejudice to other rights or remedies, to collect f,'om the purchaser the proceeds from the sale of such Non-Operator s share of oil and/or gas until the amount owed by such Non-Operator, plus interest, has been paid. Fach purchaser sh&ll be entitled to rely upon Operator's written statement concerning the amount of any default. Oper:.tor grants a like lien and ,security interest to the Non-Operators to secure payment of Operator's proportionate share of expense. If any party fails or is unable to pay its share of expense within sixty (60) &,ys after rendition of a statement therefor by Operator, the non-defaulting .parties, including Operator, shall, upon request hy Operator, pay the unpaid amount in the proportion that the interest of each such part2) hears to the interest of all such parties. Each party so paying its share of the unpaid amount sh~,ll, to obtain reimbursement thereof, be subrogated to the security rights described in the foregoing paragraph. C. Payments and Accounting: Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the devel(~pment and operatipn of the Contract Area pursuant to this agreement and shall charge each of the parties hereto with their respective propor- tionate shares upon the expense basis provided in Exhibit "C". Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits made and received. Operator, at its election, shall have the right from time to time to demand and receive from the other parties payment in advance of their respective shares of the estimated amount of the expense to be incurred in operations hereunder durinll the next succeeding month, which right may be exercised only by submission to each such party of an itemized statement of such estimated expense, together with an invoice for its share thereof. Each such statement and invoice for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month. Each party shall pay to Operator its proportionate share of such estimate within fifteen (15) days after such estimate and invoice is received. If any party fails to pay its share of said estimate within said time, th~ amount due shall bear interest as provided in Exhibit "C" until paid. Proper adjustment shall be made monthly between advances anti actual ex- pense to the end that each party shall bear and pay its proportionate share of actual expenses incurred, and no more. , D. Limitation of Expenditures: 1. Drill or Deepen: Without the consent ot all parties, no well shall be drilled or deepened, except any well drilled or deepened pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the drilling or deepening shall include: 1 2 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 24 25 26 27 28 29 30 32 34 35 36 37 39 40 41 42 44 45 46 47 48 49 50 51 52 54 55 56 57 58 59 60 61 62 63 65 66 67 68 69 70 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VII continued [] Option No. I: All necesaary expenditure~ for the drilling or deepening, testing, completing and equipping of the well, including necessary tankage and/or surface fadlifies. [] Option No. 2: All necessary expenditures for the drilling or deepening and testing of the well. When such well has reached its authorized depth, and all tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators who have the right to participate in the completion costs. The parties receiving such notice shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect to participate in the setting of casing and the completion at- tempt. Such election, when made, shall include consent to all necessary expenditures for the completing and equipping of such well. in- cluding necessary tankage and/or surface facilities. Failure of any party receiving such notice to reply within the period above fixed shall constitute an election by that party not to partidpate in the cost of the completion attempt. If one or more, but less than all of the parties, elect to set pipe and to attempt a completion, the provisions of Article VI.B.2. hereof (the phrase "reworking, deepening or plugging back" as contained in Article VI.B.2. shall be deemed to include "completing") shall apply to the operations thereafter conducted by less than all parties. 2. Rework or Plug Back: Without the consent of all parties, no well shall be reworked or plugged back except a well reworked or plugged back pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the reworking or plugging back of a well shall include all necessary expenditures in conducting such operations and completing and equipping of said well, including necessary tankage and/or surface facilities. 3. Other Operations: Without the consent of all parties, Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of F±ft:¥ Thousand Dollars ($ 50 ~ 000.00 ) except in connection with a well, the drilling, reworking, deepening, completing, recompleting, or plugging back of which has been previously authorized by or pursuant to this agreement; provided, however, that, in case of explosion, fire, flood or other sudden emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion are required to deal with the emergency to safeguard life and property but Operator, as promptly as possible, shall report the emergency to the other parties. If Operator prepares an authority for expenditure (AFE) for its own use, Operator shall furnish any Non-Operator so requesting an information copy thereof for any single project costing in excess of F. :Lf ty Thousand Dollars ($ 50 ~ 000. O0 ) but less than the amount first set forth above in this paragraph. E. Rentals, Shut-in Well Payments and Minimum Royalties: Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid hy the party or parties who subjected such lease to this agreement at its or their expense. In the event two or more parties own and have con- tributed interests in the same lease to this agreement, such parties may designate one of such parties to make said payments for and on behalf of all such parties. Any party may request, and shall be entitled to receive, proper evidence of all such payments. In the event of failure to make proper payment of any rental, shut-in well payment or minimum royalty through mistake or oversight where such pay- merit is required to continue the lease in force, any loss which results from such non-payment shall be borne in accordance with the pro- visions of Article IV.B.2. Operator shall notify Non-Operator of the anticipated completion of a shut-in gas well, or the shutting in or return m production of a producing gas well, at least five (5) days (excluding Saturday, Sunday and legal holidays), or at the earliest opportunity permitted by circumstances, prior to taking such action, but assumes no liability for failure to do so. In the event of failure hy Operator to so notify Non-Operator, the loss of any lease contributed hereto by Non-Operator for failure to make timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article IV.B.3. F. Taxes: Beginning with the first calendar year after the effective date hereof, Operator shall render for ad valorem taxation all property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed thereon before they become delinquent. Prior to the rendition date, each Non-Operator shall fvrnish Operator information as to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on leases and oil and gas interests contributed by such Non- Operator. If the assessed valuation of any leasehold estate is reduced by reason of its being subject to outstanding excess royalties, over- riding royalties or production payments, the reduction in ad valorem taxes resulting therefrom shall inure to the benefit of the owner or owners of such leasehold estate, and Operator shall adjust the charge to such owner or owners so as to reflect the henefit of such reduc- tion. If the ad valorem taxes are based in whole or in part upon separate valuations of each party's working interest, then notwithstanding anything to the contrary herein, charges to the joint account shall be made and paid by tile p:,rties hereto in accordance with thc' tax value generated by each party's working interest. Operator shall bill the other parties for their proportionate shares of all tax payments in the manner provided in Exhibit "C". If Operator considers any tax assessment improper, Operator may, at its discretion, protest within the time and manner prescribed by law, and prosecute the protest to a final determination, unless all parties agree to ahandon the protest prior to final deter- ruination. During the pendency of administrative or judicial proceedings, Operator may elect to pay. under protest, all such taxes ,'md any interest and penalty. When any such protested assessment shall have been finally determined, Operator shall pay the tax for the:' joint count, together with any interest and penalty accrued, and the total cost shall then be assessed against the parties, and be paid by'them, as provided in Exhibit "C". ., Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect to the production or handling of such party's share of oil and/or gas produced under the terms of this agreement. ,., -10- 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 02 63 65 66 67 68 69 70 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICL,lg VII continued G. Insurance: At all times while operations are conducted hereunder, Operator shall comply with the workmen's compensation law of the state where the operations are being conducted; provided, however, that Operator may be a self-insurer for liability under said com- pensation laws in which event the only charge that shall be made to the joint account shall be as provided in Exhibit "C". Operator shall also carry or provide insurance for the benefit of the joint account of the parties as outlined in Exhibit "D", attached to and made a part hereof. Operator shall require all contractors engaged in work on or for the Contract Area to comply with the workmen's compensation law of the state where the operations are being conducted and to maintain such other insurance as Operator may require. In the event automobile public liability insurance is spedfied in said Exhibit "D", or subsequently receives the approval of the parties, no direct charge shall be made by Operator for premiums paid for such insurance for Operator's automotive equipment. ARTICLE VIII. ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST A. Surrender of Leases: The leases covered by this agreement, insofar as they embrace acreage in the Contract Area, shall not be surrendered in whole or in part unless all parties consent thereto. However, should any party desire to surrender its interest in any lease or in any portion thereof, and the other p~,rties do not agree or consent thereto, the party desiring to surrender shall assign, without express or implied warranty of title, all of its interest in such lease, or portion thereof, and any well. material and equipment which may be located thereon and any rights in production thereafter secured, to the parties not consenting to such surrender. If the interest of the assigning party is or includes an oil and gas in- terest, the assigning party shall execute and deliver to the party or parties not consenting to such surrender an oil and gas lease covering such oil and gas interest for a term of one (1) year and so long thereafter as oil and/or gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit "B". Upon such assignment or lease, the assigning party shall be relieved from all obligations thereafter accruing, but not theretofore accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party shall have no further interest in the assigned or leased premises and its equipment and pro- duction other than the royalties retained in any lease made under the terms of this Article. The party assignee or lessee shall pay to the party assignor or lessor the reasonable salvage value of the latter's interest in any wells and equipment attributable to the assigned or leas- ed acreage. The value of all material shall be determined in accordance with the provisions of Exhibit "C", less the estimated cost of salvaging and the estimated cost of plugging and abandoning. If the assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the interest of each bears to the total interest of all such parties. Any assignment, lease or surrender made under this provision shall not reduce or change the assignor's, lessor's or surrendering party's interest as it was immediately before the assignment, lease or surrender in the balance of the Contract Area; and the acreage assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this agreement. B. Renewal or Extension of Leases: If any party secures a renewal of any oil and gas lease subject to this agreement, all other parties shall be notified promptly, and shall have the right for a period of thirty (30) days following receipt of such notice in which to elect to participate in the ownership of the renewal lease, insofar as such lease affects lands within the Contract Area, by paying to the party who acquired it their several proper pro- portionate shares of the acquisition cost allocated to that part of such lease within the Contract Area, which shall be in proportion to the interests held at that time by the parties in the Contract Area. If some, but less than all, of the parties elect to participate in the purchase of a renewal lease, it shall be owned by the parties who elect to participate therein, in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the purchase of such renewal lease. Any renewal lease in which less than all parties elect to participate shall not be subject to this agreement. Each party who participates in the purchase of a renewal lease shall be given an assignment of its proportionate interest therein by the acquiring party. The provisions of this Article shall apply to renewal leases whether they are for the entire interest covered by the expiring lease or cover only a portion of its area or an interest therein. Any renewal lease taken before the expiration of its predecessor lease, or taken or contracted for within six (6) months after the expiration of the existing lease shall be subject to this provision; but any lease taken or con- tracted for more than six (6) months after the expiration of an existing lease shall not be deemed a renewal lease and shall not be ~ubject to the provisions of this agreement. The provisions in this Article shall also be applicable to extensions of oil and gas leases. , C. Acreage or Cash Contributions: '7. ,' . While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a Well'or any other operation on the Contract A?ea, such contribution shall be paid to the party who conducted the drilling or other operation and shall be applied by it against the cost of such drilling or other operation. If the contribution be in the form of acreage, the party to wh6m the con- tribution is made shall promptly tender an assignment of the acreage, without warranty of title, to the Drilling Parties in t}h~ pr0P0rtigns ( i 2 6 7 8 11 12 14 17 18 2O 21 22 2~ 24 2~ 26 27 28 29 3O 32 .37 38 ~0 42 43 ~6 ~7 ~8 49 ~0 ~2 ~7 ~8 ~9 6O 62 6~ 66 67 68 6~ 7O A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 ARTICLE VIII continued said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to the extent possible, be governed by provision identical to this agreement. Each party shall promptly notify all other parties of any acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area. The above provisions shall also be applicable to fional rights to earn acreage outside the Contract Area which are in support of a well drilled inside the Contract Area. if any party contracts for any consideration relating to disposition of such party's share of substances produced hereunder, such consideration shall not be deemed a contribution as contemplated in this Article VILI.C. D. Maintenance of Uniform Interest: For the purpose of maintaining uniformity of ownership in the oil and gas leasehold interests covered by this agreement, no party shall sell, encumber, transfer or make other disposition of its interest in the leases embraced within the Contract Area and in wells, equipment and production unless such disposition covers either: 1. the entire interest of the party in all leases and equipment and production; or 2. an equal undivided interest in all leases and equipment and production in the Contract Area. Every such sale, encumbrance, transfer or other disposition made by any party shall be made expressly subject to this agreement and shall be made without prejudice to the right of the other parties. If, at any time the interest of any party is divided among and owned by four or more co-owners, Operator, at its discretion, may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures, receive billings for and approve and pay such party's share of the joint expenses, and to deal generally with, and with power to bind, the co-owners of such party's interest within the scope of the operations embraced in this agreement; however, all such co-owners shall have the right to enter into and execute all contracts or agreements for the disposition of their respective shares of the oil and gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale proceeds thereof. E. Waiver of Rights to Partition: If permitted by the laws of the state or states in which the property covered hereby is located, each party hereto owning an undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its undivided interest therein. F. Preferential Right to Purchase: Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract Area, it shall promptly give written notice to the other parties, with full information concerning its proposed sale, which shall include the name and address of the prospective purchaser (who must be ready, willing and able to purchase), the purchase price, and all other terms of the offer. The other parties shall then have an optional prior right, for a period of ten (10) days after receipt of the notice, to purchase on the same terms and conditions the interest which the other party proposes to sell; and, if this optional right is exercised, the purchas- ing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all purchasing par- ties. However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage its interests, or to dispose of its interests by merger, reorganization, consolidation, or sale of all or substantially all of its assets to a subsidiary or parent com- pany or to a subsidiary of a parent company, or to any company in which any one party owns a majority of the stock. ARTICLE IX. INTERNAL REVENUE CODE ELECTION This agreement is not intended to create, and shall not be construed to create, a relationship of partnership or an association for profit between or among the parties hereto. Notwithstanding any provision herein that the rights and liabilities hereunder are several and not joint or collective, or that this agreement and operations hereunder shall not constitute a partnership, if, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, each party hereby affected elects to be exc}uded from the application of all of the provisions of Subchapter "K", Chapter i, Subtitle "A", of the Internal Revenue Code of 1954, as per- mitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Operator is authorized and directed to ex- ecute on behalf of each party hereby affected such evidence of this election as may be required by the Secretary of the Treasury of the United States or the Federal Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by. Federal Regulations 1.761. Should there be any requirement that each party hereby affected give further evidence of this election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal Revenue Service or as may be n~cessary to evidence this election. No such party shall give any notices or take any other action inconsistent with the election made hereby. If any present or future income tax laws of the state or states in which the.Contract Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter "K", Chapter 1, Subtitle "A", of the Internal Revenue Code of 1954, under which an election similar to that provided by Section 761 of the Code is per- mitted, each party hereby affected shall make such election as may be permitted or required by such laws. In making the foreg6ing elec- tion, each such party states that the income derived by such party from operations hereunder can be adequately determined without the computation of parmership taxable income. -12- A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1982 1 2 3 4 5 6 7 8 9 10 11 I2 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 4O 41 42 43 44 45 46 47 48 49 5o 51 52 53 54 56 57 58 59 60 61 62 63 65 66 67 68 69 7o ARTICLE X. CLAIMS AND LAWSUITS Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure does not exceed Twent¥-f ive Thousand DoLlars ($ 25 ~ 000.00 ) and if the payment is in complete settlement of such claim or suit. if the amount required for settlement ex- ceeds the above amount, the parties hereto shah assume and take over the further handling of the claim or suit, unless such authority is delegated to Operator. Ail costs and expenses of handling, settling, or otherwise discharging such claim or suit shah be at the joint ex- pense of the parties participating in the operation from which the claim or suit arises, if a claim is made against any party or if any party is sued on account of any matter arising from operations hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall immediately notify aLl other parties, and the claim or suit shall be treated as any other claim or suit involving operations hereunder. ARTICLE XI. FORCE MAJEURE If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other than the obligation to make money payments, that party shall give to all other parties prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspended during, but no longer than, the continuance of the force majeure. The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned. The term "force majeure", as here employed, shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming suspension. ARTICLE XII. NOTICES All notices authorized or required between the parties and required by any of the provisions of this agreement, unless otherwise specifically provided, shall be given in writing by mail or telegram, postage or charges prepaid, or by telex or telecopier and addressed to the parties to whom the notice is given at the addresses listed on Exhibit "A". The originating notice given under any provision hereof shall be deemed given only when received by the party to whom such notice is directed, and the time for such party to give any notice in response thereto shall run from the date the originating notice is received. The second or any responsive notice shall be deemed given when deposited in the mail or with the telegraph company, with postage or charges prepaid, or sent by telex or telecopier. Each party shall have the right to change its address at any time, and from time to time, by giving written notice thereof to all other parties. ARTICLE XlII. TERM OF AGREEMENT This agreement shall remain in full force and effect as to the oil and gas leases and/or oil and gas interests subject hereto for the period of time selected below; provided, however, no party hereto shall ever be construed as having any right, title or interest in or to any lease or oil and gas interest contributed by any other party beyond the term of this agreement. [~1 Option No. 1: So long ;ts any of the oil and gas leases subject to this aRre{'ment re'main or art' c¢)ntirltwd in forct' :ts to any parl of the Contract Area, whether by production, extension, renewal or otherwise. [] Option No. 2: In the event the well described in Article VI.A, or any subsequent well drilled under any provision of this agreement, results in production of oil and/or gas in paying quantities, this agreement shall continue in force so long as any such well or wells produce, or are capable of production, and for an additional period of ~ days from cessation of all production; provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, reworking, deepen- ing, plugging back, testing or attempting to complete a well or wells hereunder, this agreement shall continue in force until such opera- tions have been completed and if production results therefrom, this agreement shall continue in force as provided herein. In the event the well described in Article VI.A, or any subsequent well drilled hereunder, results in a dry hole, and no other well is producing. 6r capable of producing oil and/or gas from the Contract Area, this agreement shall terminate unless drilling, deepening, plugging back or rework- ing operations are commenced within __ days from the date of abandonment of said well. : :: It is agreed, however, that the termination of this agreement shall not relieve any party hereto from any liability Which has accrued or attached prior to the date of such termination. ;.. -13- A.A.P.L. FORM 610 - MODEL FORM OPE. RATING AGREEMENT - 1982 1 2 3 4 5 6 7 8 9 i0 I1 12 13 14 15 16 17 18 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 65 67 68 69 70 ARTICLE XIV. COMPLIANCE WITH LAWS AND REGULATIONS A. Laws, Regulations and Orders: This agreement shall be subject to the conservation laws of the state in which the Contract Area is located, to the valid rules, regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state, and local laws, or- dinances, rules, regulations, and orders. B. Governing Law: This agreement and all matters pertaining hereto, including, but not limited to, matters of performance, non-performance, breach, remedies, procedures, rights, duties and interpretation or construction, shall be governed and determined by the law of the state in which the Contract Area is located. !f '~z Cz.':.tract .~.r~ k !~ two or more :tats, the !2-, of the .'.t2te cf e~-~ll go,,ern C. Regulatory Agencies: Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any rights, privileges, or obligations which Non-Operators may have under [ederal or state laws or under rules, regulations or orders promulgated under such laws in reference to oil, gas and mineral operations, including the location, operation, or production of wells, on tracts offset- ting or adjacent to the Contract Area. With respect to operations hereunder, Non-Operators agree to release Operator [rom any and all losses, damages, injuries, claims and causes of action arising out o[, incident to or resulting directly or indirectly from Operator's interpretation or application of rules, rulings, regulations or orders of the Department of Energy or predecessor or successor agencies to the extent such interpretation or ap- plication was made in good faith. Each Non-Operator further agrees to reimburse Operator for any amounts applicable to such Non- Operator's share of production that Operator may be required to refund, rebate or pay as a result of such an incorrect interpretation or application, together with interest and penalties thereon owing by Operator as a result of such incorrect interpretation or applicatiun. Non-Operators authorize Operator to prepare and submit such documents as may be required to be submitted to the purchaser of any crude oil sold hereunder or to any other person or entity pursuant to the requirements of the "Crude Oil Windfall Profit Tax Act of 1980", as same may be amended from time to time ("Act"), and any valid regulations or rules which may be issued by the Treasury Department from time to time pursvant to said Act. Each party hereto agrees to ft, rnish any and all certifications or other information which is required to be furnished by said Act in a timely manner and in sufficient detail to permit compliance with said Act. ARTICLE XV. OTHER PROVISIONS - 14- A.A.P.L. FORM 610 - MODEL FORM OPERATENG AGREEMENT - 1982 I ARTICLE XVI. 2 MISCELLANEOUS 3 4 This agreement shall be Nnding upon and shall inure to the benefit of the parties hereto and to their respective heirs, devisees, 5 legal representatives, successor~ and asxigns. Thiz instrument may be executed in any number of counterparm, each of which ~ be considered an original for all purposes. lIN wrl'NE25S WHEREOF, thi~ agreement shall be effective as of 1st dayof March 19 90 . 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 35 36 37 38 39 40 41 42 43 45 47 48 49 50 51 52 53 54 55 56 57 58 59 61 62 63 65 67 68 69 70 OPERATOR STEWART PETROLEWM COM. PANY By: W. R. Stewart, President NON-OPERATORS -15- EXHIBIT "A" Attached to and made a part of the West McArthur River Unit Operating Agreement dated March 1, 1990. Contract Area: T8N, R14W, Seward Meridian 4,175.00 acres Sec. 3, Protracted, All, 640.00 acres; Sec. 4, Protracted, All, 640.00 acres; Sec. 5, Unsurveyed, All tide and submerged lands, 465.00 acres; Sec. 8, Unsurveyed, All tide and submerged lands, 130.00 acres; Sec. 9, Unsurveyed, All tide and submerged lands, 630.00 acres; Sec. 10, Protracted, All, 640.00 acres; Sec. 15, Protracted, All, 640.00 acres; Sec. 16, Unsurveyed, All tide and submerged lands, 390.00 acres. TSN, R14W, Seward Me~ridian 2,155.00 acres Sec. 21, Unsurveyed, Ail tide and submerged lands, 125.00 acres; Sec. 22, Unsurveyed, All tide and submerged lands, 635.00 acres; Sec. 23, Protracted, All, 640.00 acres; Sec. 27, Unsurveyed, All tide and submerged lands, 495.00 acres; Sec. 34, Unsurveyed, All tide and submerged lands, 260.00 acres. Total 6,330.00 acres Working Interest Owners: Stewart Petroleum Company 100.00% Addresses of Parties for Notices and Billings: Operator: Stewart Petroleum Company 3111 C Street, suite 400 Anchorage, Alaska 99503 Non-Operators: EXHIBIT "B" THERE IS NO EXHIBIT "B" TO THIS UNIT OPERATING AGREEMENT. 601, BOX 8OO TULSA OK 74101 COPAS - 1984 - ONSHORE Recommended by the Council of Petroleum Accountonts Societies EXHIBIT "C" Attached to and made a part of the West Operating Agreement dated March 1, 1990. McArthur River Unit ACCOUNTING PROCEDURE JOINT OPERATIONS I. GENERAL PROVISIONS Definitions "Joint Property" shall mean the real and personal property subject to the agreement to which this Accounting Procedure is attached. "Joint Operations" shall mean all operations necessary or proper for the development, operation, protection and mainte- nance of the Joint Property. "Joint Account" shall mean the account showing the charges paid and credits received in the conduct of the Joint Opera- tions and which are to be shared by the Parties. "Operator" shall mean the party designated to conduct the Joint Operations. "Non-Operators" shall mean the Parties to this agreement other than the Operator. "Parties" shall mean Operator and Non-Operators. "First Level Supervisors" shall mean those employees whose primary function in Joint Operations is the direct supervision of other employees and/or contract labor directly employed on the Joint Property in a field operating capacity. "Technical Employees" shall mean those employees having special and specific engineering, geological or other profes- sional skills, and whose primary function in Joint Operations is the handling of specific operating conditions and problems for the benefit of the Joint Property. "Personal Expenses" shall mean travel and other reasonable reimbursable expenses of Operator's employees. "Material" shall mean personal property, equipment or supplies acquired or held for use on the Joint Property. "Controllable Material" shall mean Material which at the time is so classified in the Material Classification Manual as most recently recommended by the Council of Petroleum Accountants Societies. 2. Statement and Billings Operator shall bill Non-Operators on or before the last day of each month for their proportionate share of the Joint Ac- count for the preceding month. Such bills will be accompanied by statements which identify the authority for expenditure, lease or facility, and all charges and credits summarized by appropriate classifications of investment and expense except that items of Controllable Material and unusual charges and credits shall be separately identified and fully described in detail. 3. Advances and Payments by Non-Operators h. Unless otherwise provided for in the agreement, the Operator may require the Non-Operators to advance their share of estimated cash outlay for the succeeding month's operation within fifteen (15) days after receipt of the bill- ing or by the first day of the month for which the advance is required, whichever is later. Operator shall adjust each monthly billing to reflect advances received from the Non-Operators. Each Non-Operator shall pay its proportion of all bills within fifteen (15) days after receipt. If payment is not made within such time, the unpaid balance shall bear interest monthly at the prime rate in effect at Securi~;y Pacific Bank: WA on the first day of the month in which delinquency occurs plus 1% or the maximum contract rate permitted by the applicable usury laws in the state in which the Joint Property is located, whichever is the lesser, plus attorney's fees, court costs, and other costs in connection with the collection of unpaid amounts. Adjustments Payment of any such bills shall not prejudice the right of any Non-Operator to protest or question the correctness thereof; provided, however, all bills and statements rendered to Non-Operators by Operator during any calendar year shall con- clusively be presumed to be true and correct after twenty-four (24) months following the end of any such calendar year, unless within the said twenty-four (24) month period a Non-Operator takes written exception thereto and makes claim on OperaU)r for adjustment. No adjustment favorable to Operator shall be made unless it is made within thc same t)rescribc(t period. The provisions of this paragraph shall not prevent adjustments resulting from a physical inventory of Controllable Material as provided for in Section V. COPYRIGHT© 1985 by the Council of Petroleum Accountants Societies. -1- Audits A. A Non-Operator. upon notice in writing to Operator and all other Non-Operators, shall have the right to audit Opera- tor's accounts and records relating to the Joint Account for any calendar year within the twenty-four (24) month period following the end of such calendar year; provided, however, the making of an audit shall not extend the time for the taking of written exception to and the adjustments of accounts as provided for in Paragraph 4 of this Section I. Where there are two or more Non-Operators, the Non-Operators shall make every reasonable effort to conduct a joint audit in a manner which will result in a minimum of inconvenience to the Operator. Operator shall bear no por- tion of the Non-Operators' audit cost incurred under this paragraph unless agreed to by the Operator. The audits shall not be conducted more than once each year without prior approval of Operator. except upon the resignation or removal of the Operator, and shall be made at the expense of those Non-Operators approving such audit. B. The Operator shall reply in writing to an audit report within 180 days after receipt of such report. 6. Approval By Non-Operators Where an approval or other agreement of the Parties or Non-Operators is expressly required under other sections of this Accounting Procedure and if the agreement to which this Accounting Procedure is attached contains no contrary provisions in regard thereto, Operator shall notify all Non-Operators of the Operator's proposal, and the agreement or approval of a majority in interest of the Non-Operators shall be controlling on all Non-Operators. II. DIRECT CHARGES Operator shall charge the Joint Account with the following items: 1. Ecological and Environmental Costs incurred for the benefit of the Joint Property as a result of governmental or regulatory requirements to satisfy environ- mental considerations applicable to the Joint Operations. Such costs may include surveys of an ecological or archaeological nature and pollution control procedures as required by applicable laws and regulations. 2. Rentals and Royalties Lease rentals and royalties paid by Operator for the Joint Operations. Labor A. (1) (2) (3) (4) D. Salaries and wages of Operator's field employees directly employed on the Joint Property in the conduct of ,Joint Operations. Salaries of First Level Supervisors in the field. Salaries and wages of Technical Employees directly employed on the Joint Property if such charges are excluded from the overhead rates. Salaries and wages of Technical Employees either temporarily or permanently assigned to and directly employed in the operation of the Joint Property if such charges are excluded from the overhead rates. Operator's cost of holiday, vacation, sickness and disability benefits and other customary allowances paid to employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this Section II. Such costs under this Paragraph 3B may be charged on a "when and as paid basis" or by "percentage assessment" on the amount of salaries and wages chargeable to the Joint Account under Paragraph 3A of this Section II. If percentage assessment is used, the rate shall be based on the Operator's cost experience. Expenditures or contributions made pursuant to assessments imposed by governmental authority which are applicable to Operator's costs chargeable to the Joint Account under Paragraphs 3A and 3B of this Section II. Personal Expenses of those employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this Section II. 4. Employee Benefits Operator's current costs of established plans for employees' group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus, and other benefit plans of a like nature, applicable to Operator's labor cost chargeable to the Joint Account under Paragraphs 3A and 3B of this Section II shall be Operator's actual cost not to exceed the percent most recent- ly recommended by the Council of Petroleum Accountants Societies. Material Material purchased or furnished by Operator for use on the Joint Property as provided under Section IV. Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use and is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided. Transportation Transportation of employees and Material necessary for the Joint Operations but subject to the following limitations: A. If Material is moved to the .Joint Property from the Operator's warehouse or other properties, no charge shall be made to the ,Joint Account for a distance greater than the distance from the nearest reliable supply store where like material is normally available or railway receiving point nearest the Joint Property unless agreed to by the Parties. -2- If surplus Material is moved to Operator's warehouse or other storage point, no charge shall be made to the Joint Ac- count for a distance greater than the distance to the nearest reliable supply store where like material is normally available, or railway receiving point nearest the Joint Property unless agreed to by the Parties. No charge shall be made to the Joint Account for moving Material to other properties belonging to Operator, unless agreed to by the Parties. In the application of subparagraphs A and B above, the option to equalize or charge actual trucking cost is available when the actual charge is $400 or less excluding accessorial charges. The $400 will be adjusted to the amount most recently recommended by the Council of Petroleum Accountants Societies. Services The cost of contract services, equipment and utilities provided by outside sources, except services excluded by Paragraph 10 of Section II and Paragraph i, ii, and iii, of Section III. The cost of professional consultant services and contract ser- vices of technical personnel directly engaged on the Joint Property if such charges are excluded from the overhead rates. The cost of professional consultant services or contract services of technical personnel not directly engaged on the Joint Property shall not be charged to the Joint Account unless previously agreed to by the Parties. 8. Equipment and Facilities Furnished By Operator A. Operator shall charge the Joint Account for use of Operator owned equipment and facilities at rates commensurate with costs of ownership and operation. Such rates shall include costs of maintenance, repairs, other operating expense, insurance, taxes, depreciation, and interest on gross investment less accumulated depreciation not to exceed eight percent ( 8 %) per annum. Such rates shall not exceed average commercial rates currently pre- vailing in the immediate area of the Joint Property. In lieu of charges in paragraph 8A above, Operator may elect to use average commercial rates prevailing in the immedi- ate area of the Joint Property less 20%. For automotive equipment, Operator may elect to use rates published by the Petroleum Motor Transport Association. ~ 9. Damages and Losses to Joint Property 10. 11. 12. All costs or expenses necessary for the repair or replacement of Joint Property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other cause, except those resulting from Operator's gross negligence or willful misconduct. Operator shall furnish Non-Operator written notice of damages or losses incurred as soon as practicable after a report thereof has been received by Operator. Legal Expense Expense of handling, investigating and settling litigation or claims, discharging of liens, payment of judgements and amounts paid for settlement of claims incurred in or resulting from operations under the agreement or necessary to protect or recover the Joint Property. ~ .... + +~+ ~^ ~ .... ~^ ...... ¢ .... ~ 0pcr"-tcr'~ ~ ~+-~ ^~ ~^~ cr ~::p~r..~ ~ ~.+~a~ ~++ Taxes All taxes of every kind and nature assessed or levied upon or in connection with the Joint Property, the operation thereof, or the production therefrom, and which taxes have been paid by the Operator for the benefit of the Parties. If the ad valo- rem taxes are based in whole or in part upon separate valuations of each party's working interest, then notwithstanding anything to the contrary herein, charges to the Joint Account shall be made and paid by the Parties hereto in accordance with the tax value generated by each party's working interest. Insurance Net premiums paid for insurance required to be carried for the Joint Operations for the protection of the Parties. In the event Joint Operations are conducted in a state in which Operator may act as self-insurer for Worker's Compensation and/ or Employers Liability under the respective state's laws, Operator may, at its election, include the risk under its self- insurance program and in that event, Operator shall include a charge at Operator's cost not to exceed manual rates. 13. Abandonment and Reclamation Costs incurred for abandonment of the Joint Property, including costs required by governmental or other regulatory authority. 14. Communications Cost of acquiring, leasing, installing, operating, repairing and maintaining communication systems, including radio and microwave facilities directly serving the Joint Property. In the event communication facilities/systems serving the Joint Property are Operator owned, charges to the Joint Account shall be made as provided in Paragraph 8 of this Section II. 15. Other Expenditures Any other expenditure not covered or dealt with in the forego'lng provisions of this Section II, or in Section III and which is of direct benefit to the Joint Property and is incurred by the Operator in the necessary and proper conduct of the Joint Operations. III. OVERHEAD Overhead - Drilling and Producing Operations i. As compensation for administrative, supervision, office services and warehousing costs, Operator shall charge drilling and producing operations on either: ( ) Fixed Rate Basis, Paragraph lA, or (:~) Percentage Basis, Paragraph lB Unless otherwise agreed to by the Parties, such charge shall be in lieu of costs and expenses of all offices and salaries or wages plus applicable burdens and expenses of all personnel, except those directly chargeable under Paragraph 3A, Section II. The cost and expense of services from outside sources in connection with matters of taxation, traffic, accounting or matters before or involving governmental agencies shall be considered as included in the overhead rates provided for in the above selected Paragraph of this Section III unless such cost and expense are agreed to by the Parties as a direct charge to the Joint Account. ii. The salaries, wages and Personal Expenses of Technical Employees and/or the cost of professional consultan~ services and contract services of technical personnel directly employed on the Joint Property: ( ) shall be covered by the overhead rates, or (×) shall not be covered by the overhead rates. iii. The salaries, wages and Personal Expenses of Technical Employees and/or costs of professional consultant services and contract services of technical personnel either temporarily or permanently assigned to and directly employed in the operation of the Joint Property: ( ) shall be covered by the overhead rates, or (×) shall not be covered by the overhead rates. A. Overhead - Fixed Rate Basis ~ (1) Operator shall charge the Joint Account at the following rates per well per month: Drilling Well Rate $ N/A (Prorated for less than a full month) Producing Well Rate $ N/A . (2) Application of Overhead - Fixed Rate Basis shall be as follows: (a) Drilling Well Rate (1) Charges for drilling wells shall begin on the date the well is spudded and terminate on the date the drill- ing rig, completion rig, or other units used in completion of the well is released, whichever is later, except that no charge shall be made during suspension of drilling or completion operations for fifteen (15) or more consecutive calendar days. (2) Charges for wells undergoing any type of workover or recompletion for a period of five (5) consecutive work days or more shall be made at the drilling well rate. Such charges shall be applied for the period from date workover operations, with rig or other units used in workover, commence through date of rig or other unit release, except that no charge shall be made during suspension of operations for fifteen (15) or more consecutive calendar days. (b) Producing Well Rates (1) An active well either produced or injected into for any portion of the month shall be considered as a one- well charge for the entire month. (2) Each active completion in a multi-completed well in which production is not commingled down hole shall be considered as a one-well charge providing each completion is considered a separate well by the govern- ing regulatory authority. (3) An inactive gas well shut in because of overproduction or failure of purchaser to take the production shall be considered as a one-well charge providing the gas well is directly connected to a permanent sales outlet. (4) A one-well charge shall be made for the month in which plugging and abandonment operations are com- pleted on any well. This one-well charge shall be made whether or not the well has produced except when drilling well rate applies. (5) All other inactive wells (including but not limited to inactive wells covered by unit allowable, lease allow- able, transferred allowable, etc.) shall not qualify for an overhead charge. The well rates shall be adjusted as of the first day of April each year following the effective date of the agreement to which this Accounting Procedure is attached. The adjustment shall be computed by multiplying the rate cur- rently in use by the percentage increase or decrease in the average weekly earnings of Crude Petroleum and Gas Production Workers for the last calendar year compared to the calendar year preceding as shown by the index of average weekly earnings of Crude Petroleum and Gas Production Workers as published by the United States Department of Labor, Bureau of Labor Statistics, or the equivalent Canadian;index as published by Statistics Canada, as applicable. The adjusted rates shall be the rates currently in use, plus or minus the computed ad- justment. B. Overhead - Percentage Basis (1) Operator shall charge the Joint Account at the following rates: -4- (a) Development Two Percent ( 2 %) of the cost of development of the Join~ Property exclusive of costs provided under Paragraph 10 of Section II and all salvage credits. (b) Operating Six Percent ( 6 %) of the cost of operating the Joint Property exclusive of cosk~ provided under Paragraphs 2 and 10 of Section II. all salvage credits, the value of injected substances purchased for secondary recover>.' and all taxes and assessments which are levied, assessed and paid upon the mineral interes~ in and to the Joint Property. (2) Application of Overhead - Percentage Basis shall be as follows: For the purpose of determining charges on a percentage basis under Paragraph lB of this Section III, development shall include all costs in connection with drilling, redrilling, deepening, or any remedial operations on any or ali wells involving the use of drilling rig and crew capable of drilling to the producing interval on the Joint Prop- ertl,: also. preliminary expenditures necessary in preparation for drilling and expenditures incurred in abandoning when the well is not completed as a producer, and ori~:inal cost of construction or installation of fixed assets, the expansion of fixed assets and any other project clearly discernible as a fixed asset, except Major Construct/on as defined in Paragraph 2 of this Section III. Ail other costs shall be considered as operating. Overhead - Major Construction To compensate Operator for overhead costs incurred in the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernible as a fixed asset required for the development and operation of the Joint Property. Operator shall either negotiate a rate prior to the beginning of construction, or shall charge the Joint Account for overhead based on the following rates for any Major Construction project: A. 2 % of first $100,000 or total cost if less, plus ~ B. 2 % of costs in excess of $100,000 but less than $1,000,000, plus C. 2 % of costs in excess of $1,000,000. Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single project shall not be treated separately and the cost of drilling and workover wells and artificial lift equipment shall be excluded. 3. Catastrophe Overhead To compensate Operator for overhead costs incurred in the event of expenditures resulting from a single occurrence due to oil spill, blowout, explosion, fire, storm, hurricane, or other catastrophes as agreed to by the Parties, which are necessary to restore the Joint Property to the equivalent condition that existed prior to the event causing the expenditures, Operator shall either negotiate a rate prior to charging the Joint Account or shall charge the Joint Account for overhead based on the following rates: A. 2 % of total costs through $100,000; plus B. 2 % of total costs in excess of $100.000 but less than $1,000,000; plus C. 2 % of total costs in excess of $1,000,000. Expenditures subject to the overheads above will not be reduced by insurance recoveries, and no other overhead provi- sions of this Section III shall apply. Amendment of Rates The overhead rates provided for in this Section III may be amended from time to time only by mutual agreement between the Parties hereto if, in practice, the rates are found to be insufficient or excessive. IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS Operator is responsible for Joint Account Material and shall make proper and timely charges and credits for all Material moveI ments affecting the Joint Property. Operator shall provide all Material for use on the Joint Property: however, at Operator's option, such Material may be supplied by the Non-Operator. Operator shall make timely disposition of idle and/or surplus Material. such disposal being made either through sale to Operator or Non-Operator, division in kind, or sale to outsiders. Operator may pureha~se, but shall be under no obligation to purchase, interest of Non-Operators in surplus condition A or B Material. The disposal of surplus Controllable Material not purchased by the Operator shall be agreed to by the Parties. 1. Purchases Material purchased shall be charged at the price paid by Operator after deduction of all discounts received. In case of Material found to be defective or returned to vendor for any other reasons, credit shall be passed to the Joint Account when adjustmen[ has been received by the Operator. 2. Transfers and Dispositions' Material furnished to the Joint Property and Material transferred from the Joint Property or disposed of by the Operator. unless otherwise agreed to by the Parties, shall be priced on the following basis exclusive of cash discounts: -5- A, New Material (Condition A) (1) Tubular Goods Other than Line Pipe (a) (b) Tubular goods, sized 2~ inches OD and larger, except line pipe, shall be priced at Eastern mill published carload base prices effective as of date of movement plus transportation cost using the 80.000 pound carload weight basis to the railway receiving point nearest the Joint Property for which published rail rates for tubular goods exist. If the 80,000 pound rail rate is not offered, the 70,000 pound or 90,000 pound rail rate may be used. Freight charges for tubing ~vill be calculated from Lorain, Ohio and casing from Youngstown. Ohio. (c) (d) For grades which are special to one mill only, prices shall be computed at the mill base of that mill plus trans- portation cost from that mill to the railway receiving point nearest the Joint Property as provided above in Paragraph 2.A.(1Xa). For transportation cost from points other than Eastern mills, the 30,000 pound Oil Field Haulers Association interstate truck rate shall be used. Special end finish tubular goods shall be priced at the lowest published out-of-stock price, f.o.b. Houston, Texas, plus transportation cost, using Oil Field Haulers Association interstate 30,000 pound truck rate, to the railway receiving point nearest the Joint Property. Macaroni tubing (size less than 2~ inch OD) shall be priced at the lowest published out-of-stock prices f.o.b. the supplier plus transportation costs, using the Oil Field Haulers Association interstate truck rate per weight of tubing transferred, to the railway receiving point nearest the Joint Property. (2) Line Pipe (a) (b) Line pipe movements (except size 24 inch OD and larger with walls h inch and over) 30,000 pounds or more shall be priced under provisions of tubular goods pricing in Paragraph A.(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio. ~ Line pipe movements (except size 24 inch OD and larger with walls h inch and over) less than 30,000 pounds shall be priced at Eastern mill published carload base prices effective as of date of shipment, plus 20 percent, plus transportation costs based on freight rates as set forth under provisions of tubular goods pricing in Para- graph A.(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio. (c) Line pipe 24 inch OD and over and h inch wall and larger shall be priced f.o.b, the point of manufacture at current new published prices plus transportation cost to the railway receiving point nearest the Joint Property. (d) Line pipe, including fabricated line pipe, drive pipe and conduit not listed on published price lists shall be priced at quoted prices plus freight to the railway receiving point nearest the Joint Property or at prices agreed to by the Parties. (3) Other Material shall be priced at the current new price, in effect at date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property. (4) Unused new Material, except tubular goods, moved from the Joint Property shall be priced at the current new price, in effect on date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property. Unused new tubulars will be priced as provided above in Paragraph 2 A (1) and (2). B. Good Used Material (Condition B) C. Material in sound and serviceable condition and suitable for reuse without reconditioning: (1) Material moved to the Joint Property At seventy-five percent (75%) of current new price, as determined by Paragraph A. (2) Material used on and moved from the Joint Property (a) At seventy-five percent (75%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as new Material or (b) At sixty-five percent (65%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as used Material. (3) Material not used on and moved from the Joint Property At seventy-five percent (75%) of current new price as determined by Paragraph A. The cost of reconditioning, if any, shall be absorbed by the transferring property. Other Used Material (1) Condition C Material which is not in sound and serviceable condition and not suitable for its original function until after recon- ditioning shall be priced at fifty percent (50%) of current new price as determined by Paragraph A. The cost of reconditioning shall be charged to the receiving property, provided Condition C value plus Cost of reconditioning does not exceed Condition B value. -6- (2) Condition D Material, excluding junk, no longer suitable for its original purpose, but usable for some other purpose shall be priced on a basis commensurate with its use. Operator may dispose of Condition D Material under procedures normally used by Operator without prior approval of Non-Operators. (a) Casing, tubing, or drill pipe used as line pipe shall be priced as Grade A and B seamless line pipe of com- parable size and weight. Used casing, tubing or drill pipe utilized as line pipe shall be priced at used line pipe prices. (b) Casing, tubing or drill pipe used as higher pressure service lines than standard line pipe, e.g. power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non upset basis. (3) Condition E Junk shall be priced at prevailing prices. Operator may dispose of Condition E Material under procedures nor- mally utilized by Operator without prior approval of Non-Operators. D. Obsolete Material Material which is serviceable and usable for its original function but condition and/or value of such Material is not equivalent to that which would justify a price as provided above may be specially priced as agreed to by the Parties. Such price should result in the Joint Account being charged with the value of the service rendered by such Material. E, Pricing Conditions (1) Loading or unloading costa may be charged to the Joint Account at the rate of twenty-five cents (25¢) per hundred weight on all tubular goods movements, in lieu of actual loading or unloading costs sustained at the stocking point. The above rate shall be adjusted as of the first pay of April each year following January 1, 1985 by the same percentage increase or decrease used to adjust overhead rates in Section III, Paragraph 1.A(3). Each year, the rate calculated shall be rounded to the nearest cent and shall be the rate in effect until the first day of April next year. Such rate shall be published each year by the Council of Petroleum Accountants Societies. (2) Material involving erection costs shall be charged at applicable percentage of the current knocked-down price of new Material. 3. Premium Prices Whenever Material is not readily obtainable at published or listed prices because of national emergencies, strikes or other unusual causes over which the Operator has no control, the Operator may charge the Joint Account for the required Material at the Operator's actual cost incurred in providing such Material, in making it suitable for use, and in moving it to the Joint Property; provided notice in writing is furnished to Non-Operators of t'he proposed charge prior to billing Non-Operators for such Material. Each Non-Operator shall have the right, by so electing and notifying Operator within ten days after receiving notice from Operator, to furnish in kind all or part of his share of such Material suitable for use and acceptable to Operator. Warranty of Material Furnished By Operator Operator does not warrant the Material furnished. In case of defective Material, credit shall not be passed to the Joint Account until adjustment has been received by Operator from the manufacturers or their agents. V. INVENTORIES The Operator shall maintain detailed records of Controllable Material. 1. Periodic Inventories, Notice and Representation At reasonable intervals, inventories shall be taken by Operator of the Joint Account Controllable Material. Written notice of intention to take inventory shall be given by Operator at least thirty (30) days before any inventory is to begin so that Non-Operators may be represented when any inventory is taken. Failure of Non-Operators to be represented at an inven- tory shall bind Non-Operators to accept the inventory taken by Operator. 2. Reconciliation and Adjustment of Inventories Adjustments to the Joint Account resulting from the reconciliation of a physical inventory shall be made within six months following the taking of the inventory. Inventory adjustments shall be made by Operator to the Joint Account for overages and shortages, but, Operator shall be held accountable only for shortages due to lack of reasonable diligence. 3. Special Inventories Special inventories may be taken whenever there is any sale, change of interest, or change of Operator in the Joint Property. It shall be the duty of the party selling to notify all other Parties as quickly as possible after the transfer of interest takes place. In such cases, both the seller and the purchaser shall be governed by such inventory. In cases involving a change of Operator, all Parties shall be governed by such inventory. 4. Expense of Conducting Inventories A. The expense of conducting periodic inventories shall not be charged to the Joint Account unless agreed to by the Parties. B. The expense of conducting special inventories shall be charged to the Parties requesting such inventories, except in- ventories required due to change of Operator shall be charged to the Joint Account. -7- EXHIBIT "D" Operator, at all times while conducting operations under this agreement, shall carry or provide for the benefit of the joint account the types and not less than the amount of insurance as are shown below: (a) Workers' Compensation Insurance providing statutory coverage under the Workers' Compensation Laws of the State of Alaska with employer's liability protection in the amount of $500,000 per occurrence and a Broad Form All States Endorsement. (b) Commercial General Liability Insurance with bodily injury and property damage liability limits in the amount of $2,000,000 combined single limit each occurrence and a general aggregate of $5,000,000 affording insurance for premises-operations, owners and contractors protective, independent contractors, products/completed operations, blanket contractual liability, broad form property damage, personal injury liability, explosion, collapse and underground, incidental errors and omissions coverage. (c) Excess Liability Insurance in the amount of $10,000,000. (d) Airport Premises Liability Insurance in the amount of $20,000,000. (e) Marine Carqo Insurance in the amount of $150,000 per load. (f) Operators' Extra Expense Indemnity Insurance (blowout, redrill, seepage, and pollution liability) in the amount of $50,000,000. If Operator elects to carry such insurance under its present policies, Operator shall make a reasonable charge therefore. If separate policies are secured, the actual premiums paid shall be included as a part of unit expenses. EXHIBIT "E" THERE IS NOT EXHIBIT "E" TO THIS UNIT OPERATING AGREEMENT. EXHIBIT "F" Unless exempted by Federal law, regulation or order, the following terms and conditions shall apply during the performance of this contract: I. EOUAL OPPORTUNITY CLAUSE During the performance of this contract, the OPERATOR agrees as follows: A. The OPERATOR will not discriminate against any employee or applicant for employment because of race, color, religion, sex, or national origin. The OPERATOR will take affirmative action to ensure that applicants are employed and that employees are treated during employment, without regard to their race, color, religion, sex or national origin. Such action shall include, but not be limited to the following: Employment, upgrading, demotion, or transfer, recruitment or recruitment advertising, layoff or termination; rates of pay or other forms of compensation; and selection for training, including apprenticeship. The OPERATOR agrees to post in conspicuous places, available to employees and applicants for employment, notices to be provided by the contracting officer setting forSh the provisions of this nondiscrimination clause. B. The OPERATOR will, in all solicitations or advertisements for employees placed by or on behalf of the OPERATOR, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex or national origin. C. The OPERATOR will send to each labor union or representative of workers with which he has a collective bargaining agreement or other contract or understanding, a notice to be provided by the agency contracting officer, advising the labor union or worker's representative of the OPERATOR'S commitments under Section 202 of Executive Order 11246 of September 24, 1965, and shall post copies of the notice in conspicuous places available to employees and applicants for employment. D. The OPERATOR will comply with all provisions of Executive Order 11246 of September 24, 1965, and of the rules, regulations, and relevant orders of the Secretary of labor. E. The OPERATOR will furnish all information and reports required by Executive Order 11246 of September 24, 1965, and by the rules, regulations, and orders of the Secretary of Labor, or pursuant thereto, and will permit access to his books, records, and accounts by the contracting agency and the Secretary of Labor for purposes of investigation to ascertain compliance with such rules, regulations, and orders. EXHIBIT "F" 2 F. In the event of the OPERATOR'S noncompliance with the nondiscrimination clauses of the Agreement or with any of such rules, regulations, or orders, this Agreement may be canceled, terminated, or suspended in whole or in part and the OPERATOR may be declared ineligible for further Government contracts in accordance with procedures authorized in Executive Order 11246 of September 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in Executive Order 11246 of September 24, 1965 or by rule, regulation, or order of the Secretary of Labor, or as otherwise provided by law. EXHIBIT "G" PLAN OF EXPLORATION Proposed West McArthur River Unit Cook Inlet Basin Alaska PLAN OF EXPLORATION PROPOSED WEST McARTHUR RIVER UNIT BACKGROUND Location Cook Inlet Basin, Alaska Kenai Peninsula Borough Approximately 24 miles NW of Kenai and 66 miles SW of Anchorage Geologic Setting The West McArthur River Prospect lies in the west-central part of Cook Inlet Basin in an area of large anticlinal folds where major oil fields are being developed. These structures produce both oil and gas from nonmarine Tertiary sediments. The analog field is the giant McArthur River Field (575 MMBO) immediately east of the prospect. Trapping Mechanism Structurally closed anticline mapped on subsurface data and seismically confirmed. ~ Objectives Oil (primary): Hemlock Conglomerate Oil (secondary): West Foreland and Tyonek Formations Non Associated Gas: Grayling Gas Sands (Middle and Upper Tyonek) Initial Test Well The Unit Operator plans to drill an Initial Test Well in order to test the oil potential of the Tyonek, Hemlock, and West Foreland Formations. The well would be drilled directionally from an onshore location in NW/4 16-T8N-R14W, SM to an offshore bottom hole location in SE/4 10-T8N-R14W, SM. Depth would be ±14,500' TMD (±10,600' TVD). Arrangements with the surface owner for use and occupancy of the surface have been secured. A plan of operations for the proposed "West McArthur River Unit No. 1" follows. In the event hydrocarbons in paying quantities are discovered, the Unit Operator will submit a Plan of Development to the Commissioner in accordance with 11 AAC 83.343. West McArthur River unit No. 1 Plan of Operations 1.0 INTRODUCTION The West McArthur River Unit No. 1 is designed to test the hydrocarbon potential of the West McArthur River Prospect located between the West Foreland shoreline and the McArthur River field. The primary objective is the Hemlock Conglomerate. Secondary objectives are the Tyonek and West Foreland formations. The subject well will be a directional well drilled from an onshore surface location in NW/4 16-SN- 14W to an offshore bottom hole location in SE/4 10-8N-14W. Stewart Petroleum Company will operate the well with the assistance of ENSR Consulting and Engineering on behalf of itself and other working interest owners. Interests of the other working interest owners will remain unrecorded until drilling operations are completed. Well design is complete, subject to final survey, and drilling rig negotiations, acquisition of third party services and supplies, and applications for operating permits are in progress. A spud date of 08/01/90 is planned. 2.0 SITE LOCATION AND FACILITIES The wellsite is approximately 66 miles southwest of Anchorage and 24 miles northwest of Kenai, Alaska. The surface location is situated on the southeast end of an abandoned airstrip which was used to support the Pan American Petroleum Company West Foreland Unit No. 2 well drilled in 1966. The surface estate is owned by Salamotof Native Association and the subsurface under the drillsite is owned by Cook Inlet Region, Inc. (CIRI). Arrangements have been made with both of these organizations for surface use and subsurface easement, since the well course will pass through CIRI'S subsurface estate for a short distance before going offshore and into the prospect acreage. The drillsite is located on the northeast coast of the West Foreland peninsula and on top of the coastal bluff at an elevation of approximately 120 ft. The area is well drained and covered by dense growth of alders, spruce, and other vegetation. The drillsite is accessible from the Marathon Trading Bay Production Facility located approximately 2.5 miles to the north by a road that is used by local residents, hunters, and fishermen. This road will require some minimal upgrading which will be accomplished during the construction phase of the program. The arrangements with CIRI and Salamatof Native I 1 i i TgN LNG ~¥ PRODUCTION J F,ACI LI T1F. ES ~' STEWART PETROLEUM CO. J BOTTOM HOLE LOCATIO~ I W E 5 1 j FORELAND A-035017 I · INSET '. I .A~OCO L~I,?ION OP PA~ILITIE'c 112-3337-84. F~E 3 INS~~E: 4" = I Mile PETROLEUM CO. ~tewart Petrolcu~ Co~pa=y 3111 C Street,'~uite 400 A=chorage Alaska 99503 PROJECT 85-101 WEST McARTHUR RIVER PROSPECT SURFACE FACILITIES MAP THIS PLAT IS A LEASE DOCUMENT PIZEP/~.ED FOR $TE'gVART PETROLEUM CID. BY ALASI..A J~A.P .SE ii'VICI 1NC. APPROVED AUGUS~ 1989 I ~t~:~'.~oo~ ~ EXHIBIT '1 Association include designation of a pipeline corridor along this access road. 3.0 PROJECT SCHEDULE The proposed Project Schedule follows in time-flow form. It is anticipated that all permitting activities will be completed no later than 03/31/90. Mobilization of equipment will require barging across Cook Inlet from the Kenai/Nikiski area. Mobilization of construction equipment is scheduled to commence 06/01/90 by which time Cook Inlet should be free of winter ice. Loaded barges will be beached at high tide at a barge landing site adjacent to the Marathon facility. Equipment will be off-loaded and transported to the site by truck utilizing the existing access road. Mobilization of the drilling rig and third party equipment is scheduled to commence during the first half of July which allows prior completion of construction activities and accommodates rig availability. A spud date of 08/01/90 is planned and a 75-day drilling program is anticipated. A preliminary Drilling Curve follows the Project Schedule. Subsequent activities depend on the outcome but preliminary planning indicates the well can be completed and equipped for production by mid-November, 1990 and the production facilities and pipeline installed to allow commencement of production by 06/01/91. A second well could spud on or about 08/01/91 at' the election of the working interest owners. 4.0 DRILLING PROGNOSIS 4.1 General The well will be drilled to a total depth of approximately 14,500 ft. Total vertical depth at TD will be approximately 10,600 ft. which should be sufficient to fully test the Hemlock Conglomerate and penetrate the West Foreland formation, the deepest potential oil-bearing horizon to be evaluated in this well. Maximum hole angle will be on the order of 48 degrees and horizontal displacement will approach 10,000 ft. Preliminary Vertical Section and Horizontal View follow. 4.2 Hole Sizes and Casing Program Hole Size Depth (MD) (Driven) 100 ft 26" 2,100 ft 17-1/2" 6,000 ft 12-1/4" 11,500 ft 8 - 1/2" TD Casinq . Description Conductor 30" O.D., 0.625 wall Surface 20", 133 lb, K-55 BTC Intermediate I 13-3/8", 72 lb, N-80 or L-80 BTC Intermediate II 9-5/8", 47 lb and 53.5 lb, N-80, BTC Liner 7", 291b and 32 lb, C-95, BTC rI i.,I-I --'ira m z · 3000 4000 5000 90OO 30" CONDUCTOR KOP 500' LOGS. EOB TO 2065' LOGS, 133/=- "' TO APPROXIMATELY 6000' i 1.000 15,300 LOGS, 95/a' to 11,500' DROP: 12,407' LOGS' 7" LINER OR P & A (TESTING) ;C ~0 30 zO 5C 50 70 £0 90 ;DO PRELIMINARY DRiLLiNG CURVE STEWART PETROLEUM COMPANY WEST McARTHUR R!VER EXPLORATORY WELL NO.1 DIRECTIONAL HOLE ENSR Consulting =_nd Engineering Marker MD TVD A) KO? 5OO 5OO B) EOB 2065 1896 C) Drop 12407 8953 D) TD 14326 10620 DEPARTURE 0 606 8166 9043 PRELIMINARY VERTICAL SECTION STEWART PETROLEUM COMPANY WEST McARTHUR RIVER TEST WELL SECTION A-T N 57.00 E TVD SCALE: I inch= 2000 feet DEP SCALE: I inch = 2000 feet DRAWN: 08/09/89 T 2000 9000 10000 11000 ENSR Consulting' and Engineering Marker '~D ..... TWD" A) KO? 500 500 B) EOB 2065 1896 C) Drop 12407 8953 D) TD 14326 10620 _~~1300G DE-F ~RT~D R~ 0 606 8166 9043 PREL[MtNARY HORIZON"AL VIEW STEWART PETROLEUM COMPANY CLOSURE' 90A3 feet N 57.0 E SCALe_: I inch = 20G0 feet DRAWN: 08/09/89 '~00C 9000 8000 5000 5000 40C0 *~00 2000 ,,f 2000 4000 5000 5000 7000 5000. 9000 10000 4.3 Wellhead and BOP Equipment The following wellhead components and associated BOP equipment will be utilized: Casinq Size 30" Conductor 20" Surface 13-3/8" Intermediate I 9-5/8" Intermediate II Wellhead Section BOPE Description 30" Weld-on flange 29-1/2", 500 psi wp diverter 20" SOW casing head 20", 2,000 psi wp BOP, RSR 13-5/8" x 20" 13-5/8", 5,000 psi tubing head wp BOP, RSRRA 9-5/8" x 13-5/8" 13-5/8", 5,000 psi tubing head wp BOP, RSRRA 4.4 Drilling Fluid Program A drilling fluid system containing polymers and co-polymers of cellulose, acrylamide-AMPS and glycol with specialty additives including surfactants will be used. This is a water-based system designed to drill a relatively high angle hole over a course deviation approaching 10,000 ft. and minimize formation damage. At the conclusion of the drilling operation, the drilling fluids and cuttings will be dewatered. The recovered fluids will be disposed of by annular injection. The remaining dewatered solids will either be buried on-site in a lined and sealed pit or transported to an approved disposal site in conformity with State of Alaska Solid Waste Regulations. 4.5 Formation Evaluation A mud logging unit will be employed for cuttings and drilling fluid analysis from spud to TD. Open hole wireline logs will be run at each casing point. The following logging program is preliminary and may be modified to accommodate specific downhole objectives: 20" casing point Run 1: DIL/SP/SFL/LSS/GR 13 -3/8" casing point Run 1: DIL/SP/SFL/LSS/GR 9-5/8" casing point Run 1: DIL/SP/BHC/GR Run 2: CNL/LDT/GR/EPT Run 3: CST (Side-wall cores) optional Total Depth Run 1: DIL/SP/BHC/NGT Run 2: HDT (Dipmeter) Run 3: CNL/LDT/GR Run 4: CST (Side-wall cores) optional Run 5: RFT (Optional) Tools will be available for conventional coring in intervals of interest. The amount of coring, if any, is dependent upon drilling progress, the nature of formations penetrated, and is at the discretion of the operator and the other working interest owners. 4.6 Logistics and Support Equipment and materials required for the drilling operation will be transported to the site by barge and truck during the mobilization phase of the project. After spud additional materials and tools, as required, will be delivered to the site in the same manner or by aircraft using the airstrip at the Marathon Trading Bay Facility. Drilling crews and service company personnel will be housed at the Marathon permanent camp at Trading Bay. Arrangements are being finalized with Marathon Oil Company for this support. Rig tour changes will be made via carryall truck. Crew rotation will be via fixed-wing aircraft or helicopter from Kenai. The Stewart Petroleum Company drilling supervisor and geologist will be housed in temporary quarters at the drillsite due to the necessity of being on-site at all times. Telephone and data fax communication will be available at the drillsite and a radio link will be maintained with the Marathon Facility Camp. Daily~reports will be transmitted to the Stewart Petroleum Company offices in Anchorage, for transmittal by data fax to the other working interest owners. 5.0 SAFETY & CONTINGENCIES No drilling operations will commence or be continued when any of the following conditions exist: 1. Drilling will not begin until the Stewart Petroleum Drilling Supervisor is satisfied that the rig is properly rigged up to begin operations and all required materials and third party equipment are on location. 2. At any time when there is an insufficient supply of drilling fluid materials on location required for pressure control. 3. At any time when sufficient emergency containment and cleanup equipment is not on location or is inoperative. 4. At any time when the manpower required to safely conduct the drilling operation is not available. 5. At any time when critical equipment needed to assure a normally safe operation is inoperative. Ail wellsite operations will be under the direct supervision of the wellsite drilling engineer. A wellsite geologist will also be on-site to supervise mud logging, sample collection, and core recovery. Additional operations personnel will be at the wellsite as specific activities dictate. Operator and contractor personnel involved directly in drilling operations will be trained in well control procedures. All supervisory drilling personnel will be M/~S certified as operator's representatives. An inventory of on-site spill containment and cleanup equipment will be maintained on-site and drilling crews will be trained in the use and location of this equipment.