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Home My WebLink AboutCO 104Conservation Order Cover Page 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 Color items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plo~j~'/'sca n ner) ~..~Maps: ~~ [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other BY: ~~ MARIA mF Scanning Preparation BY: RIA Production Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: ~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: _.f~__ YES NO BY: Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES NO (SCANNING IS COMP~T THIS 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 1. 2. 3. 4. March 21, 1971 April 24, 1971 May 28,1971 April 7,1972 ) ') I Conservation Order 104 Subpoena Notice of Hearing and affidavit of publication T ranscri pt Union's request for amendment of Order Conservation Order 104 STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 Re: THE MOTION OF THE ALASKA OIL ) AND GAS CONSERVATION COMMITTEE to ) hold'a hearing to consider issuance ) of an order or orders, effective ) July 1, 1972, restricting the ) flaring or venting of casinghead ) gas from the referenced oil pools ) to the amount required for safety. ) Conservation Order No. 104 McArthur River Field Middle Kenai "G" Oil Pool Hemlock Oil Pool West Foreland Oil Pool June 30, 1971 IT APPEARING THAT: 1. The Oil and Gas Conservation Committee published a notice of public hearing in the Anchorage Daily News on April 24, 1971, pursuant to Title 11, Alaska Administrative Code, Section 2009. 2. A public hearing was held on May 28, 1971 in the City Council Chambers of the Z. J. Loussac Library, 5th Avenue and F Street, Anchorage, Alaska, at which time operators, subpoenaed witnesses, and affected and interested parties were heard. The hearing record was held open through June 4, 1971 and additional information was received. "3 , · Conservation Order No. 100, permitting the flaring of casinghead gas in excess of the maximum amount that can be beneficially utilized, expires June 30, 1971. FINDINGS: 1. There is a growing shortage of natural gas in the contiguous 48 states and Hawaii, and natural gas is being sold at increasingly higher prices in both intrastate and interstate markets. 2. There are increasing needs for natural gas in the village of Tyonek and Greater Anchorage Area and Kenai Peninsula BoroughS, on both interruptible and uninterruptible bases. Specific needs are those of the Native Village of Tyonek, Inc., Chugach Electric Association, Inc., the City of Anchorage Municipal Light and Power Department, and Alaska Public Service Corporation. 3. Alaskan gas is being exported to Japan, and there are potential markets for Alaskan gas in the contiguous 48 states and Hawaii. 4. The Jones Act has impeded utilization of Alaskan gas elsewhere in the United States., 5. Substantially all fuel requirements on the oil-producing platforms of the McArthur River Field are now met by casinghead gas. Conservation Order No. 104 Page 2 June 30, 1971 6. The casinghead gas and the entrained liquids now being flared could be beneficially utilized. There are uses for interruptible casinghead gas, and alternative fuels exist in the event the supply of gas is interrupted. 7. The Oil and Gas Conservation Committee has been concerned with the flaring of casinghead gas from the referenced field since 1967 and has held several public hearings to determine the progress of eliminating gas flaring in excess of the amount beneficially used. 8. During 1970, 14,332,204,000 cubic feet, or 78% of the gas produced from McArthur River Field was flared. 9. There was conflicting testimony as to the minimum amount of gas necessary for a safety flare. 10. Restricting the flaring or venting of casinghead gas produced from each of the three platforms in the referenced field to a volume necessary for an adequate safety flare will conserve gas. 11. Expert opinions differ as to the effect on ultimate recovery of a restriction in the rate of production or injection under a fluid injection project, but it is not proven that any such restriction will reduce ultimate recovery from the referenced pools and thereby cause waste. A fluid injection project is in operation in the McArthur River..Field. CONCLUS IONS: 1. One year is a reasonable period of time in which to complete arrangements for use of excess casinghead gas currently being flared. 2. Except in cases of emergency, the flaring or venting of gas after 7:00 A.M., ADST, July 1, 1972 in excess of the amount required for safety will constitute waste as waste is defined in AS 31.05.170(11). 3. A hearing is required to determine the amount of gas necessary for adequate safety flares. NOW, THEREFORE, IT IS ORDERED THAT: 1. Casinghead gas in excess of the maximum amount that can be beneficially utilized may be flared until 7:00 A.M., ADST, July 1, 1972. 2. Effective at 7:00 A.M., ADST, July 1, 1972, the flaring or venting of casinghead gas from the McArthur River Field is prohibited, except for the amount necessary for adequate safety flares and except in emergencies. Conservation Order No. 104 Page 3 June 30, 1971 3. The commencement, nature and termination of all emergencies requiring flaring of casinghead gas in excess of the amount required for safety flares shall be reported to the Committee within 96 hours after occurrence. DONE at Anchorage, Alaska, and dated June 30, 1971 · · Th~omas R. Marshall,- Jr., Executiv~ SeCretary Alaska Oil and Gas Conservation Committee Concurrence: omer . urrell, Chairman Alaska Oil and Gas Conservation Committee Alaska Oil and Gas Conservation Committee /' STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 Re: THE APPLICATION OF UNION OIL ) COMPANY OF CALIFORNIA for an order ) amending Rule No. 2 of Conservation ) Order No. 104 by deleting the date ) "July I, 1972" and substituting the ) date "November I, 1972'v. ) ) ) Conservation Order No. 104-A McArthur River Field Middle Kenai "G" Oil Pool Hemlock Oil Pool West Foreland Oil Pool June 8, 1972 IT APPEARING THAT: I. The Oil and Gas Conservation Committee published a notice of public hearing in the Anchorage Daily News on April 14, 1972, pursuant to Title II, Alaska Administrative Code, Section 2009. 2. A public hearing was held May II, 1972 in the City Council Chambers of the Z. J. Loussac Library, 5th Avenue and F Street, Anchorage, Alaska, at which time operators and affected parties were heard. FINDINGS: I. Immediately following issuance of Conservation Order No. 104, operators and affected parties commenced studies to determine a beneficial use or uses of the excess cas inghead gas being flared. 2. Following. determination of beneficial uses of the excess casinghead gas being flared, engineering and design studies were undertaken and equip- ment and construction contracts were entered into. 3. All of the foregoing was accomplished with due diligence, but was delayed owing to necessary engineering and design time, seasonal weather conditions, and construction and delivery time of specially-designed equipment. CONCLUSIONS: I. Operators of the referenced pools and affected parties have made a bona fide effort to comply with Conservation Order No. 104, but compliance will be delayed by conditions beyond their control. 2. Compliance with Conservation Order No. 104 can be expected by October 15, 1972. 3. The dates in Rule Nos. I and 2 of Conservation Order No. 104 should be changed to the earliest practicable date which is reasonable, but not beyond such date. Conservation Order No. 104-A Page 2 June 8, 1972 NOW, THEREFORE, IT IS ORDERED THAT: I. Rule No. I of Conservation Order No. 104 is amended to read as follows: "Casinghead gas in excess of the maximum amount that can be beneficially utilized may be flared until 7:00 A. M., ADST, October 15, 1972.~ 2. Rule No. 2 of Conservation Order No. 104 is amended to read as follows: '~Effective at 7:00 A. M., ADST, October 15, 1972, the flaring or venting of casinghead gas from the McArthur River Field is prohibited, except for the amount necessary for adequate safety flares and except in emergencies." 3. The Oil and Gas Conservation Committee, by administrative order or orders, may extend the date provided for in Rule Nos. I and 2 of this order. No such order or orders may extend the date beyond 7:00 A. M., ADST, November I, 1972, except pursuant to Title II, Alaska Administrative Code, Section 2012. [)ONE at Anchorage, Alaska, and dated June 8, 1972. . ~-~r~'~'~'i'~ ]"r-,-, ~-x;-c-u-q~i've ~ecretary Alaska [)il and Gas Conservation Committee Concurrence: --B-~]'~:rel I, Cha, rman Alaska Oil and Gas Conservation Committee '~"-----'"'-0. K. Gi Ibr-eth, Jr., Me~lC~r Alaska Oil and Gas Conservation Committee (~ZASKA OIL AND GAS CONSERVATION bufit,."tlTTEE October lO, 1972 Fie: Administrative Decision No. IO4-A.I i',lc Arthur River Field Middle Kenai ~'G" Oil Pool Hemlock Oil Pool West Foreland Oi I Pool Mr. Wade S. McAlister Union Oil Company of California 909 W. 9th Avenue Anchorage, Alaska 99501 Dear Mr. McAlister: Pursuant to Order No. 3 of Conservation Order No. IQ4-A, the Oil and Gas Conservation Committee hereby further amends Rule No. I and Rule No. 2 of Conservation Order No. 104 to read as fol lows: Rule No. I "Casinghead gas in excess of the maximum amount that can be beneficially uti iized may be flared no later than 7:00 A. ~., AST, November I, 1972.~ Rule No. 2 ~Effective no later than 7:00 A. H., AST, November I, 1972, the flaring or venting of casing head gas from the Mc Arthur' River Field is prohibited, except for' the amount necessary for adequate safety flares and except in emergencies. '~ Unforseen manufacturing and shipping difficulties affecting fifteen valves and valve gear operating mechanisms have resulted in an unavoid- able delay in the line becoming operational. Thomas R. ';'~larshalI,F .......... ......... Jr[ E~-~Executlve'--i Secretary Alaska Oil and Gas Conservation Committee ce: Homer L. Alaska Oil and Gas Conservation Commit'tee ~-~ .................. Alaska ()il and Gas Conservation Committee do / o :x B.,, /o 3 Ax / o ~94 ,;~ CO:~SERVATIO~ ORDER /¢1r)4 . (;~,¢,~trict~ flat'nfl of camin,q head 9a~ after, July I, Iht?) i...~c Arthur River Oil Field I · e 3, e 6, ge I0. II. 14. Inventory C. O. 104 Affidavit of publication Hotice of ~ublication Alaska Oil and Gas Conservation Committee Exhibit /I1: I'lcArthur River Oil and Ga~ Production October 1967 through March 1971. Exhibit //2: McArthur River Field' Catculated value of ga~ flared. Exhibit /t3: Alaska Pipeline Company Annual sales history and forecast. Marathon Oil Company Exhibit /?1' Economics of west side to Anchorage pipeline. Total excess gas. Exhibit /?2: City of Anchorage propomal and available casinghead gain. Exhibit//3' Econc~nic~ of west side to Anchorage pipeline. City of Anchorage I~unicipal Power and Li.g, ht Department requirement. Exhibit /.f4: Gas quality specifications Exhibit ~./5: Economics of west side to east side pipeline, excess ga~ Exhibit ¢!A: Exploded diagram of platform Union Oil Company of California Exhibit //1: Letter from W. A. McBean, W. A. McBean and Assoc. Ltd. to Francis Barker, Marketing Division, Union Oil Company of California, dated.,April 26, 1971, Re: West Foreland Ga~ Plant- Alaska; our letter February 19, 1971 Conservation Order ~. I04 Page 2 17. 18. 21. Subpoena~ to : James R. 1tender,hot, dated ~-lav 21, Ig71 Reggie Elkin~, dated !!ay 21, 1071 Robert E. Sharp, dated ~aay 21, 1971 L. J. Schultz, dated !!ay 21, 1971 Lynn P. Bartlett, dated May 21, 1971 Dale Teel, dated May 24, 1971 John Bergquist, dated May 27, 1971 Note: Exhibits fi led in Conservation File No. 105 and made a part of the record of Conservation File 104 include City of Anchorage Exhibit A (invitation to bid for gas service) testimony of the subpoened witrle~sem .. statements from the Alaska Conservation Society and the Sierra Club, and gas sa,~e$ correspondence of Dale Teel, Anchorage Natural Gas Corp. 0 6T (5 - 197'2 DIVISION OF OIL AND GA5 Gentlemen: Union Oil and Gi,'.-" Division' Western Region Union Oil Company of California 909 W. 9th Avenue, Anchorage, Alaska 99501 Telephone: (907) 279-7681 union October6, 1972 State of Alaska Oil & Gas Conservation Committe~ 3001 Porcupine Drive Anchorage, Alaska 99504 lc. Emu'i c. ENG [~_4~:. 4EN~ ~ I DRAFT SEC J CONFER: ._ ~,'~r,,~'~. . , ,,.,~. Re. CONSERVATION ORDERS 103 A and 104 A Application of Extension Reference is made to Conservation Orders affecting the flaring of casinghead gas in Cook Inlet, State of Alaska in requiring such flaring ceased by October 15, 1972. Operators and affected parties have made a bona fide attempt to comply with the above mentioned Conservation Orders. Pipelines have been constructed for the delivery of casinghead gas to onshore facilities and this pipeline and related facilities and equipment are near completion. Several major components for the 10" and 16" gas pipelines and facilities from East Foreland to the Nikiski Area were up to six weeks late arriving in Alaska due to manufacturing and s_hi~ng difficulties. Fifteen valves critical to the final . stallation of the two pipeline systems were approximately three months late- arriving in late September. The late shipment caused several days delay in final pressure testing and clean- ing of these pipelines. The gear operators, shipped separately and needed in order to open and close these valves, arrived in late September and were discovered to be the wrong size. The manufacturer was immediately notified and instructed to expedite delivery on two correct size operators and air freight them to Alaska. In addition, all available sources of these operators have been investigated. At the present time, a date of October 9 or 10 is the earliest possible shipment to Alaska (from St. Louis, Mo.). Efforts are continuing in an attempt to improve de-- livery. Several days of purging the pipelines with natural gas will be required in State of Alaska -2- Oil & Gas Conservation Committee Application of Extension, Gonservation Orders October 6, 1972 order to reduce water content of the gas to market specifications, thus meeting the October 15 "no flare" deadline will not be possible. Due to circumstances beyond the control of the parties constructing said pipelines, certain items of vital, indispensable equipment are not presently available and is contemplated that this lack of availability of required equipment will delay opera- tion of said pipeline beyond the date of October 15, 1972. Additional documenta- tion of this fact is available if required. Application is hereby made for an extension of the implementation of the no flare order previously ordered for October 15, 1972, to be extended to November 1, 1972. I'~- is the intention of the operators and the affec'~-ed parties to comply with the above referred to Conservation Orders as soon as equipment now lacking has been installed and construction completed on said pipeline. In the event 'the line becomes opera- tional before the requested extension date of November 1, 1972, the line will be put into operation at the earliest possible date. Should your committee require any additional information or evidence to process this application for extention, we will make such information available on notice. Your Committee will be notified when said pipelines go into operation. Very truly yours, UNION OIL COMPANY OF CALIFORNIA ) //' .... , ......... . /./ ' ~' ........ ~,,.. :~ Z' ~/ '/< '""'? /'~;~"( ~.~"'/,,,"i""('"' ' MARATHON O IL COMPANY By: /~~~~-,~m~-~-- TESTIMONY TO EXTEND TttE DEADLINE OF THE NO FLARE PROVISION CON- TAINED IN CONSERVATION ORDER N6S. 102, 103, 104, AND 105 TO BE PRESENTED BEFORE THE ALASKA STATE OIL AND GAS CONSERVATION COM- MITTEE ON MAY 11, 1972 TESTIMONY TO BE PRESENTED BY C. L. ROBERTS My name is Claude Roberts and I am the Anchorage Division Petroleum Engineer for Marathon Oil Company. In addition, I am co-chairman of the Mechanical Coordinating Subcommittee of a Marathon-Union joint task force established to design and install a Cook Inlet gas gathering system. It is in this latter capacity that I testify today. My testimony will illustrate the tremendous effort required to study, plan, design, and install the facilities necessary to deliver gas produced on the west side of Cook Inlet to the market area on the east side. My first exhibit illustrates this gas gathering system and its orientation to the casinghead gas production from the McArthur River and Trading Bay Fields. The exhibit further shows the "market area" at Nikiski and the location of the large dry gas reservoirs in the Cook Inlet Basin. The gas gathering system consists of the Liquid Extraction Unit at West Foreland, the large compressor facility, a 16" pipeline to Granite Point, dual 10" submarine lines to East Foreland, and finally a 16" pipeline into the Nikiski area. The status of each of these phases will be discussed thoroughly. Orders were issued for the various oil fields in Cook Inlet by the Alaska Oil and Gas Conservation Committee effective July 1, 1971. The Conservation Committee order, ed: (1) casi~ghead gas in excess of the maximum amount that can be beneficially utilized may be flared until 7 AM, ADST, July 1, 1972; (2) effective at 7 AM, ADST, July 1, 1972, the flaring of any casinghead gas from the McArthur River Field (and all other Cook Inlet fields) is prohibited except for the amount necessary for adequate safety flares and except in emergencies;, and (3) the commencement, nature, and termination of all emergencies requiring flaring of casinghead gas in excess of the amount required for safety flares shall be reported to the Committee within 96 hours after occurrence. We had previously studied various plans to further beneficially utilize the excess casinghead gas in connection with.several hearings extending from 1968 through May, 1971. After issuance of these orders, Marathon, and I'm sure other companies as well, immediately reviewed these plans and initiated studies and investigations necessary to evaluate all available alternatives to comply with the no flare order in the relatively short period of time allowed for compliance. Market potential and financial arrangements, both of which can be handled only on a separate compa~y-by-company.basis, were necessary prerequisites. Conversely, the physical and mechanical aspects dictated a joint effort for consideration of a gas gathering system. Therefore, on July 12, 1971, top-level management of Marathon and Union met in Los Angeles to consider the problem. The result of this meeting was the establishment of a joint Marathon- Union task force to evaluate all problems and alternatives connected with such a project. Plans for formal organization with appro- priate assignments were immediately initiated. Marathon and Union once again reviewed the various alternatives for disposition of the relatively small casinghead gas reserve -4- including: (1) storage of the gas by injecting into known onshore structures adjacent to the Trading Bay Production Facility; (2) return of the casinghead gas to the reservoirs from which it was produced; (3) storage of the gas in the Grayling gas sands of the McArthur River Field; and (4) delivery of the gas to the market area on the east side of Cook~ Inlet, thus displacing gas already supplying these markets. It was again concluded that delivery of the gas to markets on the east side offered the only acceptable disposition of the gas and this was. practical only if the gas gathering system could be utilized for future transportation of a substantial gas reserve. Gentlemen, the only reason we were able to consider building a pipeline system to the east-side was because of this dry gas reserve in the McArthur River Field. Although the review of the various alternatives of disposition were concluded quickly, several months of planning and design were necessary to identify and eValuate the many problems of building a pipeline system across Cook Inlet to the east side. -5- Recognizing the need for current and accurate gas production data, material balances for each of the three Trading Bay Unit' platforms, the Monopod Platform, the Trading Bay Production Facil- ity, and the Liquid Extraction Unit were made. A review of the gas productiOn forecast for Trading Bay Unit and Trading Bay Field was commenced in order to evaluate platform compression require- ments. Ail platform and onshore facility schematic drawings, tracing the path of the crude and gas streams were updated. Plans were made for acquiring analyses of the various Crude and gas streams in order to determine the amount of processing required to make the gas deliverable. On July 21, 1971, we contacted Earl & Wright, Engineering consultants, to discuss methods of determining the best possible pipeline routes across the Inlet. On July 22, F. M. Lindsey & Associates.were asked to furnish a proposal to perform sub-surface reconnaissance work in Cook Inlet. The purpose of this work was to better define the submarine -6- trench which existing bathymetric maps indicated ran north-south immediately east of the McArthur River and Trading Bay Fields platforms. It was not known whether or not the trench was contin- uous. At the same time, plans were being formulated to determine the feasibility of expanding and/or modifying the Liquid Extraction plant. The original plant was designed to process 32 million cuBic,feet per day of cas±nghead gas and 5 million cubic feet per day of crude flash vapors. Preliminary production forecasts indi- cated the gas volume would exceed this amount requiring expansion of these facilities. It was evident that some additional plant proceSsing would be required in order to make the gas deliverable even though additional processing for iiquid recovery was unecon- omical. On July 27 and 28, our process engineers met with Fluor Cor-. poration in Houston to outline various plans for modification of the plant. Fluor was requested to furnish a cost estimate for making a feasibility study for enlarging the plant and for optimizing -7- the amount of compressor horsepower that would be required to deliver plant residue gas to a pipeline system. Also, on July 27, we prepared a tabulation of anticipated compressor horsepower requirements, assuming different pressures for gas disposition on the east side. This information was mailed to various compressor manufacturers and suppliers requesting their proposal for furnish- ing the necessary horsepower on either a purchase or rental basis. On August 2, the Marathon-Union Task Force began detailed studies to solve the many problems involved in designing and con- strUcting a pipeline from West Foreland across Cook Inlet to the Nikiski area. In order to proceed as.rapidly as possible, the overall project was broken into two major segments, the West Side onshore facilities to be under the direction of Marathon Oil Com- pany, and the marine and East Side facilities under the direction of UniOn Oil Company. During the period from July 27 through August 2, 1971, crude and gas samples were obtained from the platforms in the Trading Bay Unit and the Trading Bay Field as well as the Trading Bay Pro- duction Facilities. In that the samples were necessarily shipped -8- by truck to Core Laboratories in Dallas, Texas, for analysis, data from these samples were not available for plant expansion design until early September. Marathon and Union proceeded with the general reconnaissance survey by Lindsey & Associates of the trench area as shown in Exhibit 2 in an effort to find the shortest route to the east side. If a direct route was feasible, it was evident that much time, material, and money could be saved. The results of the survey, showed that in the trench area, immediately east of the McArthur River platforms, water depths were from 240 feet to 400 feet. On August 6, we met with Earl & Wright to explore the feasi- bility of a pipe lay truss (stinger) deSign necessary to operate in water depths of 300 feet and greater in Cook Inlet. Also on this date, we received some preliminary infOrmation from J. Ray McDermott and Brown & Root, Inc., concerning deep water pipelining in Cook Inlet. On August 13, Union conferred with Dames & Moore, Earth Science Consultants, outlining the conditions of the various possible routes -9- of the marine line. We also received additional information from Hood Corporation concerning problems of laying pipelines in Cook Inlet. Gentlemen, at this timew about mid-August, you can see that we had only scratched the surface of obtaining the necessary data to evaluate the various pipeline routes across Cook Inlet. Our preliminary discussions with the various pipeline consultants and contractors were for the purpose of updating ourselves on the "state of the art" of laying pipelines in deep water to ascertain if any of the newer techniques could be applied in Cook Inlet. Although these discussions were encouraging in that perhaps a deep water crossing could be made, more information was urgently needed. This additional information had to be obtained quickly, because if 'the only feasible marine route was to the north opposite Granite Point, a land line approximately 26 miles long had to be installed from West Foreland during the coming winter. A pipeline across the McArthur River flats route can only be installed during freeze-up. Such a line would have to be designed, pipe and materials ordered, -10- and contractor mobilized, all in advance of freeze-up, expected as early as December 1. Only a little over two months remained for all of this activity to take place. Although preliminary studies were being made on the Liquid Extraction Unit and Compressor Station, final compressor design criteria could not be established until the. route and the "market" were established. On August 23, 24, and 26, Union and Marathon personnel met with J. Ray McDermott and Brown & Root respectively to discuss possible construction methods of a "deep water" marine pipeline. As a result of those meetings, it was decided that it was not feasible to lay pipe across COok Inlet with conventional pipeline methods in water deeper than 180 feet. We further felt that we could not risk trying some of the new developments of deep water pipelining in Cook Inlet, but would have to utilize the more conventional methods in order to minimize risks of installation and operation. We had previously made studies of the feasibility of using existing onshore and offshore lines in the upper Cook Inlet. It was decided that these lines could not be utilized and that it -11- would be necessary to construct a west side pipeline from the Trading Bay Production Facility at West Foreland to Granite Point and a dual submarine line from Granite Point to East Foreland. A detailed two-phase survey along the proposed northern marine route, as illustrated on Exhibit 2, was commenced immediately by Dames & Moore. The purpose of the study was to determine geologic and oceanographic conditions along alternate rOutes which might influence the location, design, and installation of the proposed marine pipeline. To accomplish these objectives, geophysical profiles, bottom samples, and current measurements were obtained at several locations between Granite Point and East Foreland. Specifically, the scop~ of work included: (1) a review of pub- lished and other available literature pertaining to the bottom conditions and oceanographic framework of the area. These included several previous studies conducted in Cook Inlet related to con- struction of offshore platforms and pipelines; (2) geophysical profiling along selected traverses using a high-resolution boomer system and sidescan sonar; -12- (3) measurements of current speed and direction at various depths at nine different stations during periods of flood and ebb tide; (4) sampling of surficial bottom soils at selected localities by means of clam-shell bucket; (5) a determination of maximum current velocities which might occur along the proposed route based on oceanographic data collected during the survey; (6) an engineering evaluation of soil conditions and current regime as related to pipeline design and construction. Information from this marine survey indicated a mobile bottom condition in the area between Granite Point and the northern part of Middle Ground Shoals. We refer to this mobile bottom area as the "dune area" because of the · shifting nature of the gravel bed and sand occurring rapidly between tides. In order to provide a sound foundation and therefore a stable pipeline system, we needed to know the bottom conditions and the extent of the dune areas. Ail the above information would be gathered and furnished to Earl & Wright, who had been given the contract to perform an engi- neering study required to design the submarine gas pipeline. -13- Dames & Moore performed the offshore pipeline route survey between September 8 and September 26. Profiles of the bottom and sub-bottom were obtained along four different corridors between Granite Point and the East Foreland area. Additional profiles were obtained in the northern portion in order to further define the duned area. On September 2, 1971, immediately after the decision to lay the pipeline north to Granite Point, Fluor Corporati6n was author- ized to proceed with the proposed Liquid Extraction Unit feasibility study to determine the optimum method of modification and estimated coSt. The Liquid Extraction Unit utilizes a turbo-expander to develop the refrigeration necessary to recover the maximum amount of butanes and heavier hydrocarbon liquids. This refrigeration scheme leaves the residue gas at low pressure, approximately 70 PSIG. Since the residue gas has to be delivered into a pipeline system at relatively high pressure, the'question arose as to whether or not the turbo-expander provided the optimum method of obtaining ~the required refrigeration. It was Fluor's assignment to evaluate -14- alternative methods of obtaining the refrigeration and thus optim- ize the amount of horsepower required for compression. The modi- fied plant would also have to operate at a higher pressure if it was to handle the anticipated increased volume of gas. The pressure level as well as the method of refrigeration greatly affects the amount and type of horsepower required. By September'7, Marathon and Union had complete~ a pipeline optimization study, only 12 days after the decision was made to go north to Granite Point for a Cook Inlet crossing to East Fore- land. The optimization study considered various sizes of onshore and submarine lines to carry various volumes of gas at pressureS of 700 to 1200 PSIG. This study resulted in the decision to install 16-inch onshore lines and dual 10-3/4 inch submarine lines. -15- On September 13, Marathon began preparing the specifications for the West Side line. It was necessary that these specifications include instructions for construction of a safe system, protection · of the environment, and to ensure a satisfactory completion date. On September 24, Marathon placed an order for 27 miles of 16 inch, .344 wall thickness, Grade 5LX-52 ERW line pipe for the west side portion of the gas gathering system. From September 30 through October 20, Dames & Moore and F. M. Lindsey conducted a terrain survey and a soil investigation for the proposed 16-inch west side pipeline. The purposes of this work were to provide data for pipeline routing, d~sign for weighting and anchoring the pipe, and to provide plan and profile drawings for construction. Specifically, the scope of work included: '(1) a review of the published literature pertaining to soil condi- tions of the route corridor; (2) a photo-geologic appraisal of the proposed and alternative pipeline routes; (3) a shallow sub- surface investigation including hand-augered boring and drillings and sampling with helicopter transportable rotary wash drill rig; -16- (4) laboratory testing of soil samples; and (5) analysis of back- fill and buoyance problems, frost penetration, studies of anchor designs, and a general review of construction problems. Following analyses of these data, sPecifications for the construction of the line were mailed to prospective bidders on October 26, 1971. A major consideration was the'anchoring system necessary to over- ,, come the negative buoyancy of a large diameter pipeline carrying natural gas through terrain such as the mud flats of the McArthur River. Three types of anchors were utilized: (1) screw-in auger type were used where the terrain was not too rocky or swampy. These were spaced approximately 80 feet apart; (2) concrete sadle weights weigh- ing 4,000 pounds each and spaced about 25 feet apart were used where the auger anchors could not be used; and (3) concrete bolt-on weights weighing 2,300 pounds each were installed at 13-foot intervals at water crossings. Ail together, about 2,500 of these three types of anchors were used in the 26.2 miles of line. These had to be designed, manufactured, and delivered before freeze-up. The last barge load -17- of concrete weights was off loaded at West Foreland on November 24. The Land and Legal Subcommittee was preparing the many appli- cations necessary to obtain a right-of-way. On October 5, 1971, application was filed with the U. S. Department of Interior, Bureau of Indian Affairs, to construct a pipeline across the Moquawkie Indian Reservation. On October 7, application was made to the Department of Army, Alaska District Corps of Engineers, for a permit to construct a pipeline across several rivers along the route from West Foreland to Granite Point. On November 1, application for a right-of-way construction permit was delivered to the State of Alaska, Division of Lands. Data from the Dames &Moore terrain study ahd the Lindsey survey were a necessary Part of these appli- cations, thus precluding the filing of these applications any earlier. Our process engineers received Fluor's feasibility study for the Liquid Extraction Unit modifications on October 4. Critical to our design was the final disposition' of the gas on the east side of the Inlet. Two markets with sufficient capacity to handle the total expected volumes existed. The Collier Chemical · complex could utilize the gas at approximately 650 PSIG, but the gas would have to be further processed. Swanson River Field pres- · sure maintenance project could take the gas without further proces- sing, but the pressure would need to be maintained at 1050 ~PSIG. In July, 1971, Union initiated feasibility studies for an east side plant to process the gas for removal of the propane and heavier hydrocarbon components to prOvide suitable gas feed stoc}~ to the Collier Chemical Plant. Five engineering and construction companies were consulted and proposals for processing, storage, and other facilities required to produce and make disposition of liquefied hydrocarbons were developed. Simultaneously, surveys and studies were undertaken to develop markets for the products that would be produced. Engineering consultants and Union Oil Company had to determine not only a suitable processing design, but availability of equip- ment, materials, construction manpower, suitable sites for facili- ties, and numerous other factors critical to design and timing. In -19- addition to locating product consumers, marketing research also required development of many other factors such as production forecasts, type and quantity of products, ~ype and size of storage tanks, transportation and loading facilities, etc. By November 23, 1971, it was determined that a plant on the east side was not feasible and plans for the plant were abandoned. This left Swanson River Field as the only market capable of taking all the gas expected from the Trading Bay Production Facility Com- pressor Station. In the meantime, Marathon was proceeding with preparation of compressor inquiries to obtain quotations for equipment to meet pressure conditions of botk possible gas markets'. On October 27, specifications were mailed to three manufacturers of compressor equipment. I would like to digress just for a moment to better explain the need for the considerable front-end engineering required to design the large compressor facility. Normal compressor design parameters include gas rate predictions, temperatures, suction~ and discharge pressures. This ~.nstallation was further complicated by rapidly declining gas rates,.variable · gas compositions, and variable operating conditions. It will be necessary for this compressor facility to perform under a wide range of operating conditions, including the LEX running and not running, one submarine line inoperative, one machine down for maintenance, · etc. These are the types of variables that must be analyzed prior to finalizing a design, purchase, and installation of a 7200 horse- power compressor station. It was these factors that lead us, last year at the May hearing, to advise that a minimum of 18 months would be required to complete such a project. To have been prepared to go to bid on a compressor station of this size and complexity within a period of four months was indeed an accomplishment. By November 1, the west side pipe and materials were on order, bids were out to pipeline contractors and compressor manufacturers. To be safe, only four weeks were left to mobilize on the west side of the Inlet and to receive and unload the 27 miles of 16-inch · pipe. On November 3, all 16-inch pipe and coating materials left · · Seattle by barge. On November 9, bids were received from three contractors for the construction of the 16-inch west side pipeline. On November 12, the construction contract was awarded to Locher Company. On November 13, the barge carrying the 16-inch pipe arrived at West Foreland and was beached for unloading operations. On November 22, we completed the offloading and storing of the Pipe at a storage site adjacent to the Trading Bay Production Facility. On November 30, a plant engineering subcommit~tee representing the plant owners reviewed the Liquid Extraction Unit modifications and compre'ssor requirements. A recommendation to purchase three Cooper- Bessemer 2400 horsepower compressor units was made and purchase orders were issued on December 2, 1971. On December 1, the State of Alaska, Division of Lands, granted a permit for the construction of right-of-way across'state lands from West Foreland to Granite Point. On Dec~nber 6, a crew from -22- F. M. Lindsey & Associates began the construction survey for the pipeline route. On December 13, the U. S. Department of Interior, Bureau of Indian Affairs, granted an easement for the construction of the pipeline right-of-way across the Moquawkie Indian Reserva- tion. On that date, Locher completed the barging of their equip- ment to West Foreland and began the construction of their Pipeline camp. Most of the construction material had been transported to the staging area before the ice conditions in Cook Inlet shut down barge traffic. However, 650 sets of screw-in anchors and all the pipeline valves and fittings had to be transported to the job Site by air. On December 22, the Department of the Army, Corps of Engi- neers, issued a permit for crossing the four major rivers between West Foreland and Granite Point. We were mobilized and all the permits necessary for beginning construction of the West Side pipe- line had been received. Locher Company commenced right-of-way clearing operations on December 18, but unfavorable Weather conditions caused consi- derable problems resulting in some delay of the construction -23- schedule. However, through a diligent effort, the contractor com- pleted the construction effort on March 22 following a successful hydrostatic test of the pipeline. Ail that remained was the envi- ronmental restoration of the right-of-way. Fertilizing and reseed- ing operations along various areas of the right-of-way were completed on April 4. While Marathon was occupied in mobilizing materials and the contractor on the west side, Union Oil Company was busy analyzing the mass of data acquired in the detailed marine survey. Earl & Wright were commissioned on September 5 to develop design criteria for gas pipelines crossing.Cook Inlet from Granite Point to East Foreland. The Dames & Moore study furnished informa- tion of the water current velocities and directions and the bottom soil conditions along the pipeline route. Earl & Wright used this information to study the design requirements for twin i0-inch and twin 12-inch lines, taking into account static stability, dynamic stability, pipe metallurgy, corrosion protection, stabilization methods, installation problems and procedures, and relative costs. As indicated on Exhibit 2, the route would proceed in a direc- · tion perpendicular to the shore line for a distance of 8,800 feet from Granite Point to a location northeast of the northernmost Amoco platform in the Granite Point Field. It then proceeds for a dis- tance of approximately 30,000 feet to a point northeast of Middle Ground Shoals and thence for a distance of 71,700 feet to a point on the East Foreland, in the vicinitY of Nikishka #2. On both sides of the Middle Ground Shoals area, the. water depths are about 150 feet at mean low, low water, while at the Shoal crossing, the water depth is only aboUt 70 feet. Bottom conditions along the route vary from gravel, cobbles, and boulders in the vicinity of Granite Point to large stretches of sand and gravel between Middle Ground Shoals and the East Foreland. Conventional pipe laying methods for deep water and strong currents such as experienced in the Cook Inlet call for a lay truss supported both at the lay barge and on the bottom, as illustrated on Exhibit'3. The pipe lay truss acts as a cradle for the pipelines as they are being laid. Without support from both the surface and the bottom, the lay truss would simply be swept away in the strong · currents of Cook Inlet. The lay truss must be of sufficient length to provide for a safe pipe laying configuration consisting of overbend and sag-bend which stresses the pipe to no more than 80 percent of minimum yield. The total length of the lay truss designed for this pipe laying operation is about 340 feet long and weighs approximately 300 tons. An underwater pipeline is much different from ~ pipeline on land, since it must have sufficient weight for static stability, must avoid resonance caused by long unsupported spans, and must have sufficient strength t° avoid buckling or overstressing during the pipe laying operation. A pipeline across Cook Inlet is differ- ent from the usual underwater line because of the bottom soil con-. ditions and current velocities which are very high and persist at bottom depth. When bottom irregularities 'or scouring result in excessive span lengths and flutter of the unsupported lines, or when high current velocities result in horizontal movement of the lines, it is necessary. i -26- { to provide additional support and anchoring. A line on the bottom of Cook Inlet is subjected to both a lift force and a drag force which vary with the. square of the current velocity. The lift force is counteracted by the weight of the line, its contents, and any weight coating provided, while the drag force is resisted by friction between the..pipe and the bottom soils. Protection against corrosion is another important design para- meter and cathodic protection in Cook Inlet presents some unusual problems. Corrosiveness is about eight times as high in 'Cook Inlet as it is for normal sea water. The swift currents, high dis- solved oxygen, and abrasion by suspended solids, acceler'ate corro- sion rates. Two basic cathodic Protection systems were analyzed. One - impressed current, and two - sacrificial anodes (zinc bracelets). Armed with the mass of data supplied by Dames & Moore and the study by Earl & Wright, Union and Marathon personnel 'held engi- neering conferences with Brown & Root, Inc., and J. Ray McDermott, -27- Inc., in Houston and New Orleans during the week of November 30 ~ December 5, 1971. These meetings resulted in the finalization of the marine pipeline system. The line consists of dual 10-3/4 inch OD, .594 wall thickness, grade 5LX52 seamless line pipe. Concrete weight coating will be applied, using one, two, and three 1/2-inch thicknesses of 190 pound per cubic foot concrete. The pipe lay truss was designed to withstand two times the force exerted on it by the weight of the pipelines when filled with sea water, and the force exerted by the sea water floWing perpendicular to the lay truss at a velocity of 7.1 knots. It was further stipulated that the truss would not be permanently deformed by bending in a storm current of 8.4 knots. The truss was designed and is being built so that the pipe would not be stressed to more than 80 percent of the minimum yield .from the' time it leaves the lay barge until it is landed on the sea floor. On December 2, Union Oil Company issued a purchase order for 246,000 feet of 10-3/4 inch seamless line pipe. The Pipe will be coated with a cold-tar corrosion coat and with a sufficient thick- · ness of the 190 pound per cubic foot steel reinforced concrete weight coating necessary to provide bottom stability. Zinc anode · bracelets will be installed every 340 feet for corrosion protection. On December 23, a preliminary draft of the general project~ construction specifications was mailed to McDermott and Brown & Root. The final drafts were mailed on January 17, 1972, and the bid due date was established as January 31. Concurrently to the preparation of the specifications for installing the submarine lines, bid specifications were prepared for the continuous posi- tioning service necessary to guide the lay barge on its proper course, the radiographic inspection of the welds, helicopter service, . dock and stevedore service. Ail business arrangements had been completed for the installation of the ~orrosion wrap, cathodic protection bracelets, and weight coating of the 10-3/4" pipe prior to its transportation to Cook Inlet. Negotiations were commenced with the various tug and barge companies concerning the transporta- tion of the pipe to Cook Inlet. -29- Referring back to Exhibit 1, you will note that the proposed routing of the East Side pipeline from the beach approach to the Swanson River Field line tie-in will follow a general southerly direction to the Swanson River line junction and beyond to the Collier plant. To comply with the Natural Gas Pipeline Safety Act requirements, this pipeline will be designed for Class III construction utilizing 16" OD, .344 wall thickness, Grade 5LX52, ERW, steel pipe. Approxi- mately 28,500 feet of pipe will be required between the shore approach and the Collier plant tie-in. It is planned to ship this 16" pipe from Vancouver, Washington, along with the 10-3/4" pipe for the dual submarine line. UniOn Oil and Marathon decided to install a liquid hydrocarbon recovery system to collect any liquid hydrocarbons that may accu- mulate in the line. It is possible that at the operating condi- tions of the pipeline system, a retrograde condensation problem may exist. Also, in the event of an LEX plant upset, it is possible that liquid hydrocarbons can enter the pipeline system. For these -30- reasons, it was felt mandatory that an extensive liquid recovery system be designed. While the engineers were designing the submarine line and the East Side facility, our la%~ers and land men were preparing the necessary applications to secure all the required permits for the construction of these facilities. Applications for permits to construct the marine line were mailed out early in January and negotiations for the right-of-way acquisition at East Foreland commenced shortly thereafter. Please refer to Exhibit 4, illustrating the engineering and construction schedule for the dual submarine portion of the project. The vertical axis is the percent of project days from July 1, 1971, to completion. The horizontal axis shows the actual time frame in months. Note that 40 percent of project time was required to obtain the final design criteria. On January 31, bid proposals' fOr installing the dual submarine lines were received from Brown & Root and J. Ray McDermott. Because of the substantial cost involved with this portion of the project, an extensive evaluation of each of the contractor's bids was re- · quired. By mid-February, J. Ray McDermott Co. was selected as the contractor to install the submarine pipeline and mobilization of the pipelaying spread commenced immediately. The logistics required to mobilize a complete pipelaying spread with the necessary auxiliary support systems and personnel are tremendous. The lay barge had to go into drydock for extensive refitting and revamping in order to perform work in Cook Inlet. Heavier anchors and wires, had to be installed. A large gimbel- type hitch, required to hold the pipelaying truss, had to be fabricated and conneCted to the lay barge. Tugs, pipe barges, crew living quarters, had to be negotiated for and mobilized. This equipment is only found on the Gulf COast and along the West Coast. It is no small task to solve the logistics of mobilizing such an operation. You will note that it was mid-December before the.final design of the marine pipeline system was completed; now, 90 days later, men, equipment, and materials began their journey to Cook Inlet. McDermott's lay barge departed Harvey, Louisiana, on April 8. It will require approximately 60 days for its trip to Cook Inlet with its scheduled arrival sometime during the first week of June. · It will require about seven days to unload the barge at Kenai and to connect the lay truss'which is being fabricated in Anchorage (fabrication of the truss commenced on April 15). We expect to have the lay barge on the right-of-way at Granite Point by June 14. · About 50 days will be required to lay pipe across Cook Inlet, and we plan to hydrostatically test the system by mid-August, 1972. A schedule for the construction of the East Side pipeline and liquid handling facility has been prepared, and is illustrated as Exhibit 5. Final engineering design was completed and specifi- cations for construction went out to bid on March 28. Hood Con- struction Company of Whittier, California, was awarded the bid on April 24. The installation of the line should commence shortly after the pipe's arrival at Nikiski between May 15 and June 1. It should take approximately 45.days to complete construction of the pipelines. -33- Bids on the equipment for the liquid handling facilities were received on May 1; equipment was ordered May 4; and delivery is estimated around August 1. Completion date for the east side liquid handling facility is scheduled for October 1, with start- up estimated by October 15. Exhibit 6 shows the schedule for the compressor station and modifications to the Liquid Extraction plant at West Foreland. As mentioned earlier, the three large compressors were placed on order in early December, 1971. This provided for the necessary shop space while all the design parameters were being finalized. Marathon personnel met with CB/Southern on January 26 to finalize these parameters. I will describe some of the equipment to indicate the order of magnitude of facilities comprising the 7200 horsepower compressor plant. There will be three 2400 horsepower units. Each unit will consist of an engine skid, two piping skids, one gas cooler skid, one lube oil module skid, and one utility cooler skid. The total station will therefore be comprised of 18 large skids. The esti- mated weight of this equipment is over 1,200,000 pounds and will require 21'rail cars for transportation from Hous%on to Anchorage. This entire compressor station will be housed in a building 46 feet wide by 150 feet long with an eave height of 27 feet. · The design functions of the expanded compressor station are to compress approximately 48 million cubic feet of gas per day received from the McArthur River and Trading Bay Fields platforms from 150 PSIG to about 425 PSIG. Approximately 6-1/2 million cubic feet per day of crude flash vapors will be compressed from 10 PSIG to 525 PSIG. This portion of the compressor station is referred to as the boosting service'and delivers gas to the'Liquid Extraction Unit. The remainder of the horsepower will b°e used for transporta- tion and will compress approximately 45 million cubic feet per day of LEX residue gas frOm 150 PSIG up to 1200 PSIG, which is the pressure necessary to enter the pipeline facility. Fluor Corporation was selected as contractor for the installa- tion of the compressor units, designed, and fabricated by CB/Southern. As prime contractor, Fluor will also make the modifications to the Liquid Extraction Unit. On February 23 and 24~ Fluor came to -35- Anchorage to discuss the final process and mechanical flow of the plant modifications and the compressor installation. A construc- tion agreement was executed on March 22. Fluor's construction superintendent moved to Anchorage on April 10 and commenced mobili- zation of the subcontractors necessary to excavate and prepare. foundations for the large compressor skids and to do the installa- tion work. These contractors are mobilized and are waiting for the ice to leave the Inlet so that they can barge their equipment to the construction site. One of the large compressor units should'arrive in Anchorage the first of June. The second and third units will arrive in Anchorage around June 21. These units will be barged from Anchorage to the Trading Bay Production Facility, unloaded, skidded into position, and set on their foundations. The final engine should be in place by July 15. Once the units are in place, a critical phase of the construc- tion effort has passed. However, considerable work remains to be done prior to completion estimated by October'l, 1972. In order -36- to allow for contingencies and provide sufficient time to de-bug the system, we anticipate final start-up about November 1. This is two months ahead of the time frame which we testified to in a previous hearing. I would like to assure you that every effort has been made and will continue to be made to place this pipeline system, com- pressor station, and plant facilities into operation at the very earliest date. Hopefully, I have been able to illustrate the magnitude of the project and to emphasize the tremendous amount of front-end designing and engineering reguired for such a massive · project. Since the most costly portion of this project still remains to be completed, a final cost is not known at this time; however, when this project has been completed, the cost as presently estimated will be in excess of 25 million dollars. Finally, I hope I have shown the good faith which Union Oil Company and Marathon Oil Company put forth to comply with the Committee's orders pro- hibiting the flaring of casinghead gas. Although my presentation -37- has been quite lengthy, I have covered only the major points of · ~the project; and I would now solicit any questions that you may have. Thank you. CLR/jmk o 3 6 SCALE I~ ~ILE$ WEST FORELAND FIELD NORTH TRADING BAY FIELD oo .o P. TRADING BAY FIELD /./ '-.{/% Mc: ARTHUR RIVER FIELD o; i/,_ N. COOK INLET FIELD RIG TENDERS, STD., LNG & COLLIER DOCKS KENAI IOE BAY ¥ / / / / ALASKP, C, GuLF OF ALASKA pacific LEGEND ~ OIL FIELD ~--1 GAS FIELD ~ EXISTING PIPELINES ~ MARATHON OPERATED ~ OUTSIDE OPERATED EXHIBIT I GAS GATHERING AND TRANSMISSION FACILITY TRADING BAY PRODUCTION FACILITY FORELRND ~.,~_ 'SPARK~,. TEXACO J'A' SALMON' UNION AMOCO "B" GRANITE PT PROOUCTION FACILITY AMOCO I AMOCO MOBIL ~ "NO. I' SHELL SHELL AMOCO · D# E,4ST FORELAND ~IIKISHKA NO. 2 COLLIER CARBON' E, CHEMICAL CO. SOUL DER POIIV T EXHIBIT 2 MARATHON- UNION GAS GATHERING SYSTEM SCALE' 1"' 4000' EXISTING PIPELINES COMPLETED GAS GATHERING SYSTEM PIPELINES UNDER CONSTRUCTION LEX PLANT- COMPRESSOR STATION SAND & GRAVEL DUNES < 10' ,, ,, . > 10' SUBMARINE TRENCH 5'-I EXHIBIT 3 COOK INLET PIPE LAYING OPERATION DUAL PIPELINES BOTTOM OF TRENCH STINGER 340' FIELD JOINT WRAP STATION WELD STATION LAY BARGE INSPECTION STATION WELDING STATIONS MUDLINE EL. - 180'-0 EXHIBIT 4 SUBMARINE ENGINEERING & PIPELINE PROJECT CONSTRUCTION SCHEDULE 0 0 100 90 80 60 50 40 30 20 10 0 ' I JULY AUG SEPT OCT NOV DEC 1971 JAN FEB MAR APRIL o. DATE OF NO FLARE ORDER I. PRELIMINARY ENGINEERING DESIGN 2. SELECTION OF ROUTE :5. FINAL ENGINEERING DESIGN 4. SELECT CONTRACTOR AND START MOBILIZING LAY SPREAD 5. DELIVER PIPE TO CEMENT COATING FIRM 6. START LAYING SUBMARINE PIPE LINES 7. TIE-IN EAST SIDE LINES AND TEST LINES MAY JUNE JULY AUG 1972 SEPT OCT NOV DEC 100 90 80 60 50 140 130 120 10 0 EXHIBIT 4 EXHIBIT 5 EAST SIDE PIPELINE & ENGINEERING & LIQUID HANDLING CONSTRUCTION SCHEDULE FACILITY 100 100 90, , ,,! , ' -,-,~ :~5 ,,,'"' ; ' 'i~ ~c~ ~;,,,,'""- ' ' 80 .................... 1 ............ 4 ~iO:-".~~ ........................................... I .......... j~11~_~,'~'"' I. PRELIMINARY ENGINEERING DESIGN 40 '~ ~. FINAL ENGINEERING DESIGN 40 30 ~l~ ~. ~o~,~,z~ co~,~c,o~ ~~___~ 6. DELIVER PIPE 10- -~~ s. CONNECT INTO EASTSlDE ~^C, UT,~S * ,~ST UN~S 10 oO::~~-~'2_ ..... - ............................ ~ ................................................................. l--I ..... I--'-~ ........ -~ .... I ......... I ..... ,o JULY AUG SEPT OCT NOV DEC JAN FEB MAR APRIL MAY JUNE JULY AUG SEPT OCT NOV DEC 1971 1972 ~0 50 0 Z EXHIBIT 5 EXHIBIT 6 WEST SIDE LEX & COMPRESSOR ENGINEERING & CONSTRUCTION EXPANSION SCHEDULE LU , .............................. -~ -2 ~. FINAL COMPRESSOR DESIGN ~_~-- 4. FINAL LEX DESIGN e FLUOR NEGOTIATION ................................... ~ ................................................................................................................................................................... 5. DELIVER ENGINE ONE TO ALASKA -~~ 6. DELIVER ENGINES TWO ~ THREE TO ALASKA _ ~~~ ........................................................... _ Z SET ENGINES ON FOUNDATIONS ' 8. PROJECT COMPLETION ~~~~ ................................................................................................................................................................................... 9. START UP JULY AUG SEPT OCT NOV DEC JAN FEB MAR APRIL MAY JUNE JULY AUG SEPT OCT NOV DEC 90 90 80 80 70 7O 60 60 50 50 40 40 30 30 20 20 10 10 0 ,0 1971 1972 EXHIBIT 6 ~,,' '~ /' 'AI.3~KA CONSERVATION SOCIETY \' i KENAi PENI'I~ISULA CHAPTER ~:': .-~ ~' 7'/ SOLDOTkA . . Division of Oil and Gas 3001 Porcupine Drive Anchorage, Alaska DIVISION OF OIL AND O.',,.q CO, RE' Request for delay on termination of Cook Ihlet offshore flaring This organization would oppose a delay in termination of offshore flaring for the following reasons' 1. 'Continued flaring provides obvious air pollution which can be seen from Kenai almost any day as a low-lying cloud of black (the evening of 4/25/72, it looked yellow-greenish) smoke over the Inlet. 2. The flaring of the offshore casinghead gas is a waste of a resource. 5. The additional wasting of the resource should not be permitted to continue .... lest it make the installation of another LNG plant or other such type of gas reprocessing for trans-shipment less economically feasible. Does not the fact that the proposed plant under consideratiom by Pacific Electric Service Co. contradict the earlier statements regarding lack of feasibility for the usage of the gas from the offshore platforms? 4. Even if it may be essential to extend the deadline, this organization recommends that it be done on a month~to-month basis with the review required for continuing extensions of an additional ....month. ~r..~....sJA ~d~~ER~~~. : in Alaska P.S. The Pipe coating is not be g accomplished for the project. Is the lack of the 60-80 jobs involved in the required pipe coating considered by this Division in its.'del~berations over the delay in gas flaring termination deadline? .~... .J To AMOCO EXHIBIT "A" C,C). /o~J-A SCHEMATIC GAS FLOW DIAGRAM COOK INLET GAS GATHERING SYSTEM UNION OIL COMPANY OF CALIFORNIA MAY I0, 1972 PREPARED B.Y...H.O.B,~.S..-..B.~NN.E.~.'~A,~-ALASKA CORP. OF STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT, ) ss. being first duly sworn on oath .~he deposes and says that ................ is the .... ~..e.D.a...1.....C.~.e..~.k. ..... of the Anchorage News, a daily news- paper. That said newspaper has been approved as a legal news- ,paper by the Third Judicial Court, Anchorage, Alaska, and it is now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all of said time was printed in an office maintained at the aforesaid place of publication of said news- paper. That the annexed is a true copy of a Leg.a.1 ' Notice 1930 as it was published in regular issues (and not in supplemental form) of said newspaper for. a period of ..... .o. ~.e.. ...... insertions, commencing on the ..14 .... day of .... AP.~.~.~, ........... ,19 ?.2, and ending on the ...... .3:.½.~ ........ day of )f ~.].,r±l ........ : ......... , 19...72., otb dates inclusive, and that such newspaper was regularly distributed to its subscribers dur- ing all of said period. That the full amount of the fee charged for the foregoing publication is the sum of $ '12.50 which amount has been paid in full at the rate of 25¢ per line; Mini- mum charge $7.50. ,,. ,,~/ i.. ,x. ..,~'.~ x-: ....,-,'... ~.:,, .__~. .._~ .~. . . . & ~ . . .~-:~.~ Subscribed a~l sworn to before me this .3.~'.i. day of..~prL1 ....... 197.,, .... ............. ,: :' ..... .'., ,: ,,..,: NOTICE OF PUBLIC HEARING STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES Alaska Oil and Gas Con$1rvatJoR Commitlee Consen/etion File Nos, 102, 103, 104 105 RI: The application of Union Oil Company of California, Atlantic- Richfield Com- pany, Shell Oil Company, and Amoco t Production Company for orders amend- ing Rule No. 2 of Conservation Order Nos. 102, 103, 104 and 105 by delet- ing the date "July 1, 1972" end ~ub- stituting in its place the date "Novae- '' bar 1, 1972." Notice is hereby given that the refer- enced companies have requested the Oil end Gas Conservation Committee to issue orders which extend the period of time from July I, 1972 to November 1, 1972, cluring which casinghead oas in addition to the amount necessary for safety can be flared from the oil pools identified in the refer- enced conservation orders covering the fol- lowing fields: Granite Point, Trading Bay, McArthur River, end Middle Ground Shoal.' The hearing will bi held et 9:00 a.m., ~May 11, 1972, in the City Council Cham- ~bers of the Z.J. Loussac Library, 5th Ave- i nue and F Street, Anchorage, Alaska, at which time operators of the identified oil pools and affected and interested perti#,. will be heard. i Thomas R. Marshall, Jr. Executive Secretary Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 . Publish: April 14, 1972 ] Leael Notice No. 1930 NOTICE OF PUBLIC HEARING STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES Alaska Oil and Gas Conservation Committee Conservation File Nos. 102, 103, 104 and 105 Re: The application of Union Oil Company of California, Atlantic Richfield Company, Shell Oil Company, and Amoco Production Company for orders amending Rule No. 2 of Conservation Order Nos. 102, 103, 104 and 105 by deleting the date "July I, 1972" and substituting in its place the date "November I, 1972". Notice is hereby given that the referenced companies have requested the Oil and Gas Conservation Committee to issue orders which extend the period of time from July 1, 1972 to November I, 1972, during which casinghead gas in addition to the amount necessary for safety can be flared from the oil pools identified in the referenced conservation orders covering the following fields: Granite Point, Trading Bay, McArthur River, and ~iddle Ground Shoal. The hearing will be held at 9:00 a.m., May 11, 1972, in the City Council Chambers of. the Z. J. Loussac Library, 5th Avenue and r Street, Anchorage, Alaska, at which time operators of the identified oil ~ools and affected and interested parties will be heard. Thomas R. Marshall, Jr. Executive Secretary Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 Publish: April 14, 1972 Union Oil and Gas Di,' ';sion: Western Region Union Oil Company ot California 909 W. 9th Avenue, Anchorage, Alaska 99501 Telephone: (907) 279-7681 union Robert T. Anderson District Land Manager April 7, 1972 State of Alaska Oil & Gas Conservation Committee 3 001 Porcupine Drive Anchorage, Alaska 99504 Re- CONSERVATION ORDER ~ 104 STATE OF ALASKA Application of Extension Gentlemen: Union Oil Company of California, as Operator of the ~%rading Ba..y Uni,t, requests Conservation Order ~104, Order 2, be amended ~y deleting t~'e date "July 1, 1972" and substituting in its place the date "November 1, 1972." Immediately upon issuance of said Conservation Order, Union and Marathon Oil Company jointly proceeded to design and construct a 52 mile pipeline system 'to deliver excess casinghead gas from the Trading Bay Production Facility West Foreland to the North Kenai Industrial Complex. Barring un- foreseen, adverse circumstances causing delay, the requested amendment will provide sufficient time to complete construction and insure the system is operational thereby allowing compliance with 'the flare curtailment pro- vision of said Order. In 'the event it is deemed necessary that a Public Hearing be held in 'this matter, we respectfully request such hearing be held on May 10, 1972. The 30 day notice period if required for such hearing is hereby waived. All affected working interest owners in the Trading Bay Unit have been advised of this request. Very truly yours, RTA/nr Robert T. Anderson /,/ , CONSERVATION FILE NO. 104 McArthur River Field Middle Kenai ~G~' Oil Pool Hemlock Oil Pool West Foreland Oil Pool PROCEEDINGS MR. BURRELL: Good morning, ladies and gentlemen. I'm Homer Burrell. This is a hearing on Conservation File No. 104, entitled McArthur River Field, Middle Kenai "G" Oil Pool, Hemlock Oil Pool, West Foreland Oil Pool. The Alaska Oil and Gas Conservation Committee will hold a hearing pursuant to Title 11, Alaska Administrative Code, Section 2009, to consider issuance of an order or orders, effective July 1, 1972, restricting the flaring or venting of casinghead gas from the referenced oil pools to the amount required for safety. The hearing will be held at 9:00 A. M. May 28, 1971 and so long thereafter as the hearing may be continued, in City Council Chambers of the Z. J. Loussac Library, 5th Avenue and F Street, Anchorage, Alaska, at which time operators of the referenced pools and affected and interested parties will be heard. Evidence will be sought as to, but not limited to, the following: 1. Can excess casinghead gas be marketed, injected into any reservoir or pool, or otherwise beneficially utilized by July 1, 19727 2. Will the flaring or venting of casinghead gas after June 30, 1972 in excess of the amount required for safety constitute waste, as "waste" is defined in AS 31.05.170(11)? 3. Will more waste be caused than prevented by an order restricting production of oil to a rate whereby all produced casinghead gas is beneficially utilized or is required for a safety flare? Signed by Thomas R. Marshall, Jr., Executive Secretary. Published April 24 in the Anchorage Daily News. To my left is Mr. Tom Marshall; to his left is Mr. Gilbreth, both members of the Committee; moving around the table, Lonnie Smith, John Levorsen, Gar Pessel, 3ohn Miller, and Harry Kugler. To my right, Bob Hartig, John Norman -2- of the Attorney General's Office. Without objection, the record shall include the hearing of Conservation File No. 105, on May 25, relating to the shortage of gas in the lower 48 states, including remarks of the Honorable Secretary Hollis Dole, and articles from various newspapers. Without objection, they will be entered into the record of this hearing. If there is anyone who missed them, we can read them again. Okay. At yesterday's hearing on Conservation File No. 104 -- I beg your pardon, 103--the operators requested they be allowed to defer giving their testimony as to marketing efforts, marketing .opportunities~ until today, and that today's testimony on that area, in that area, would cover both hearings and that was acceptable to us. We have a Mr. John Bergquist under subpoena who appeared here today and I would ask Mr. Bergqutst, since he is under subpoena, if he wants to testify now or if he would like to wait until later, after the other testimony. MR. BERGQUIST: If it is alright with you, I would Just as soon wait until later. MR. BURRELL: Alright~ sir, that will be alright. We simply wanted to let people go about their business when we pull them in on subpoena. We also have testimony in the record of the hearing on May 25, Conservation File No. 105, and some additional testimony on May 26, Conservation File No. 102, from six other people who were subpoenaed and if there be no objection, we would like to have their remarks and cross-examination entered into the record. Is there any objection? We can always get these people back here; they are subject to recall. Anybody change their mind, let us know. I believe we will have Mr. Miller explain some Committee exhibits at this time. --3-- MR. MILLER: These are the same types of exhibits we presented the previous days, only for McArthur River Oil Field, cumulative oil production by pools and field totals. Total cumulative oil production is 102,618,000 bbls., and field total of produced gas is 42,992,906 MCF. This includes 10,320,000 MCF of dry gas with all the casinghead gas. Of this grand total, 17.2% was utilized and of that amount it also included some 2.5 million MCF of dry gas. 82.8% of the total gas was flared. Here again this includes some produced dry gas, 7.8 million MCF of dry gas. The value of the accumulated oil production, this again is based on money paid to the State for royalty oil, is 274,832,000 dollars. We have tried to make some sort of comparison or measurement of the flared gas and since the value is under question we have compared it on the energy, heat energy, or BTU basis of oil with the gas analysis and the value of the BTU's for both McArthur River gas and oil. The heating value of the gas and BTU's per cubic feet are a little over a thousand and required 5,886 cubic feet of gas on a heat basis to equal a barrel of McArthur River oil. Apparently in March 1971, 30,900 MCF of gas a day were flared with a heating value of 31.58 billion BTU's per day. Equating this to oil, this would be equivalent to 5,250 barrels of oil, the oil having a value of $14,201 per day. Future estimated gas to be flared, above that utilized, is 39~360 MMCF and this again is based on the operator's curve. Equating this to McArthur River oil, this is equivalent to 6,687 million barrels of oil, that oil having a value of a little over 18 million dollars. Here again, I see we have got it on the board sideways if everybody can turn their head around or else I can turn it around, the same curve we had before, illustrating the gas sales history and predicted growth in the Cook Inlet area. This figure out here at 1990 is 65 billion cubic feet of gas per day. -4- ~R. BURRELL: Let the record reflect that the exhibits introduced by Mr. Miller will enter the record as Committee Exhibits 1, 2 and 3, in the order in which he introduced them. Is there anybody who would care to testify on the matter now at hearing? MR. BEVAN: Mr. Chairman, I'm John Bevan with Marathon Oil Company. In response to the Committee's call on Conservation File No. 104, we will present three witnesses. First, Mr. C. J. Diver of Marathon, and Chairman of the Trading Bay Unit Engineering and Planning Group, will testify as to the engineering aspects. Second, Mr. B. G. Howard, Marathon's Anchorage Division Operation Manager, will give testimony concerning certain marketing aspects and, third, Mr. W. L. Bradferd, Regional Gas Manager, Western Region, Union Oil Company of California, will also give testimony concerning certain marketing matters. As stated in the hearing yesterday, in Conservation File No. 103, in which the pertinent marketing testimony given today will be applicable to and incorporated by reference in Con~p. rv~ ~ " point of view of installing the necessary compression, dehydration and pipeline facilities, it is quite unlikely that this could be accomplished. The lead- time necessary in ordering the equipment which would be required to dispose of this gas as well as the very limited construction seasons available to us in Alaska precludes our being able to dispose of this gas by the date proposed by the Committee. However, it is possible from a physical sense only that these facilities might be installed by January 1, 1973. There are certainly other considerations which we feel override the purely physical ability to install equipment and have it operating by a certain date. I will discuss with you some of the aspects to which I refer. In the Trading Bay Unit, if we try to inject this gas, the most practical and logical point of injection would be from the Grayling Platform. This is a result of it being located at the hightest structural position of any of the three platforms in the unit. Our investigations indicate that the necessary rates of injection would require pressure from the range of three to four thousand pounds at the wellhead. To achieve this pressure would require reciprocating com- pression equipment on board the platform. For your reference, an expanded view of the Grayling Platform and the various mechanical equipment packages currently installed on board this platform is shown on the slide. As you can see, we have a very crowded condition which exists on all deck levels on the platform. The installation of a large reciprocating compressor, on a platform, involves consideration of the deck loading effects as well as vibration problems which would result. Because of the weight of this type equipment, it is not possible to install it on a cantilever deck. To solve the weight and vibration problem the unit would have to be located somewhere on the main load-bearing decks. As you can see, all of this deck area is currently being utilized. The only -6- possible way this type equipment could be installed would be to remove water injection equipment, which is vital to the pressure maintenance project. We could not, for safety reasons, remove any other items. Therefore, it is not feasible nor desirable to attempt this type installation. We have considered the possibility of compressing this gas onshore and taking it through a high- pressure pipeline to the Grayling Platform. To attempt this poses a very complicated and hazardous situation. There are no unused pipeline connections in any leg by which this line could be tied into the platform. It would be necessary to bring the high-pressure line up the outside of a leg. This line would be carrying gas at three to four thousand psi. You can imagine the additional hazards this would add to the platform. Ice movements could cause -- could part the line allowing the uncontrolled escape of high-pressure gas around the platform. Another hazard would exist on board the platform; should a leak occur, and there are no guarantees it would not, the amount of gas released before the line could bleed-down would be substantial. We currently compress gas for lift purposes to approximately 1300 psi. These lift systems are considered by our safety experts to be the most hazardous portion of our operation. When we compare these pressures, with those necessary to inject the gas, the exposure to potential trouble increases as the ratio of the pressure. We can only tell you that this would be the very last method that we would as a practical matter even consider as a means of disposing of this gas. In summary, injecting this gas into any zone in the McArthur River Field would create an additional safety hazard of the greatest magnitude on the Grayling Platform. Another possible location for a disposal project would be injection of this gas into water-bearing strata onshore. A first consideration for such -7- a project would be the location of a geologic structure which could serve as a storage container. The unit does not currently own an onshore lease underlaying by a closed geologic structure into which we might even consider injecting this gas. If we did, however, we can visualize several things which might occur. We would certainly increase the pressure in any aquifer in which we injected this gas. The aquifer could be expected to expand, that is, provided it had sufficient areal extent to expand, and we might create a gas bubble in the crestal portion of the structure. At the same time, we would also create high-pressure water sources, possibly affecting offsetting acreage to our hypothetical lease. This could cause a liability situation with the offsetting ~wners, which we would not care to be responsible for. In addition, we would have potentially contaminating source of high-pressure water and gas which, through a geological discontinuity, might find its way in the fresh water-bearing sands. Further, if we attempted to,produce this gas we would expect to recover a very small fraction of the total injected. This is a result of the expansion of the aquifer back through the gas saturated section, and the trapping of large volumes of this gas at relatively high pressures. This type of disposal should not be considered in the same light as storage project in other parts of the United States. In those situations gas is cycled in and out of the reservoirs many, many times and once a residual gas saturation has been established the next cycle through the reservoir can be expected to recover nearly all the gas which has been injected. In our case, there would only be one cycle of injection and production. As stated in many previous hearings on this subject, the primary beneficiary use of this gas is to move the oil through the reservoir to the well bore and assist in its production to the surface. ReinJection -8- of this gas will not, in our opinion, be a further beneficial use of the gas, but for the reasons stated, create additional hazard with little possibility of recovering the gas. The third question in the call for this hearing inquires as to whether more waste would be caused than prevented by an order restricting production of oil to a rate whereby all produced casinghead gas was used for fuel or required for a safety flare. An examination of the Trading Bay Unit, reveals some very alarming results if such an order were issued. The immediate effects would be a curtailment of production to about 50% of that currently being produced. At these producing rates, the amount of water injection would not -- would need to be curtailed from present level. There would be fewer turbines required to drive injection pumps and, therefore, less gas required and, therefore, less crude oil production from the platforms. This situation would feed on itself to where we estimate that the production from the unit would drop from its current rate of 125,000 barrels a day to approxi- mately 35,000 barrels, a total reduction of 70% of the current unit production and nearly half of Alaska's current daily production. Nearly all, if not all, injection equipment would be shut down and surplus to the operation. The pressure maintenance project would no longer be necessary, and we would rely primarily on aquifer expansion to maintain our reservoir pressure. At this level of production we estimate the producing life of the field would be extended a minimum of ten years. We do not, at this time, have the necessary experience to state definitely what this extension in the life of the field would do to our operation. However, it is not unreasonable to make some projections to the effect, based on experience in all other operating areas in the world. The maintenance and/or replacement of equipment is a continual, -9- never-ending problem in this and most other businesses. In our particular business, decisions about the remedies to solve these problems are governed by the amount of oil remaining to be recovered, the rate at which it will be recovered, and the cost associated with maintaining or replacing equipment. It takes very little imagination to see that extending the expected operating life of the equipment an additional ten years can only serve to increase the amount of necessary expenditure required to operate this equipment. We therefore have a situation at which we would be experiencing more frequent requirements for maintenance and lesser production rates from which to pay for the necessary maintenance. It is entirely possible that the cost associated with this type operation could become so burdensome as to require premature abandonment of the entire platform, resulting in lowered ultimate recovery. In addition, we need to consider the potential effect on the platforms them- selves apart from the equipment and wells located on board. These platforms are located in one of the most corrosive and erosive environments in the world. We have installed elaborate protection systems to attempt to at least retard the rate of sea water corrosion on the exposed jacket sections and conductors. Nevertheless, we are still experiencing corrosion. Adding 10 years to the life of these structures is an alarming consideration. It must be remembered that the rate of corrosion, due to the environment in which these platforms exist, is independent of the oil rate off the production platform. We believe that, in view of the risks involved in the entire Cook Inlet operation, adding an additional 10 years to the life of these projects cannot be justified. If we were to assume, and it is only an assumption, that we might recover the same amount of oil at a curtailed production rate as compared to our current method of operation -- as I have previously stated -- -10- the production life of this field would be extended approximately 10 years. We calculate that during this 10 year period 20-25% of the anticipated future recovery would be produced. For the reasons mentioned previously, it can be seen that we would be placing in added Jeopardy 20-25% of the remaining oil to be produced from this field. It is obviously impossible to qualify the risks involved in doing this; however, it is not unreasonable to say that it would be a major risk that we would be running. Another aspect which we might discuss is the effect of such a curtailment on the State of Alaska revenue. If we assumed a curtailed production schedule and if we assumed that the ultimate recovery were very nearly the same, and we did not have to prematurely abandon the platform, the present worth difference to the State of Alaska, on income generated under this curtailed production schedule as compared to that to be generated on the present method of operation, would cost the State 33 million dollars in present worth income discounted at 8%. I have explained to you the reasons why we do not believe it is reasonable to inject this gas in pools or reservoirs in the Trading Bay Unit. Likewise, I have discussed with you the risks involved in attempting to dispose of this gas at an onshore location. Also, we have considered the effect of a curtailed production schedule both in terms of a potential loss and of ultimate recovery, as well as a very real effect on current income to the State. Thank you for your attention. MR. BURRELL: Thank you, Mr. Diver. Mr. Diver, I didn't hear any discussion of the possibility of injecting the gas into the West Foreland gas pool -- a gas field -- which I believe is something like 10 miles from the onshore production facility. Has that been considered? MR. DIVER: The unit doesn't own that lease. -11- MR. BURRELL: No, that's true. Maybe nobody can get together except for 6.2 cents in six weeks, too. The people who bought the gas didn't own it either. In other words, they got together in a heck of a hurry when they wanted to, and I would suggest that -- uh -- maybe some arrangements could be worked out here. I believe we have the ssme participants -- some same people -- who own this gas field in question. My question is, has there been any discussion or any consideration of injecting that gas into the West Foreland gas pool? MR. DIVER: I couldn't answer, I'm not aware of any discussions that have taken place. MR. BURRELL: Are you aware of any consideration? MR. DIVER: It certainly would be a consideration. I'm not aware that there have been any studies specifically made to do this very thing. MR. BURRELL: As I understood it, your testimony with respect to the platform indicated that one year was a practically impossible period of time, that is by July 1, 1972, within which equipment could be installed on platforms and in an additional period of six months it might be reasonably possible timewise; but then you also go on to state, as I understood it, that there was still no place you could puc it on the platform -- you'd have to pull the compressors being used for water injection off the main deck to increase the pressure. MR. DIVER: That' s right. MR. BURRELL: What would you do if there was a market for the gas right now, say five cents an MCF, or say $5.00 an MCF? What would you do if there was a market for that gas to somebody who was standing there yelling for it, what would you do to get it to them? MR. DIVER: To physically get it to them? -12- MR. BURP. ELL: Right. MR. DIVER: Well, it's available, most of this gas is available at the onshore production site at the Trading Bay Production facility. MR. BURRELL: Then why are we having to have compressors in the platform? ~{R. DIVER: The consideration that I made was that we would inject this gas for a consideration for -- MR. BURRELL: Look, the only need for the compressors that we are talking about on the platform is for injection. Is that right? MR. DIVER: That' s right. MR. BURRELL: Good, right. So the gas is going to shore right now? MR. DIVER: A great amount of it is going ashore. MR. BURRELL: A vast majority of it? MR. DIVER: Right, quite a lot of it, yes. MR. BURRELL: Essentially all except what is being used on the platform for fuel and safety flare purposes? MR. DIVER: and -- yeah. MR. BURRELL: Essentially all. MR. DIVER: Essentially all. MR. Bt5%RELL: I think that is all the questions I have right now. Mr. Gi lb re th ? MR. GILBRETH: Mr. Diver, I believe in response to a question from Mr. Burrell, you made the statement that the same people do not own the West Foreland gas. Is the McArthur River Unit a grass roots unit? That is, one from the surface down where all rights are unitized? MR. DIVER: Yes. MR. GILBRETH: It is? Then do not people -- -13- MR. DIVER: Pardon me. I should qualify that. There is different owner- ship in various productive reservoirs. In other words, there are different working areas, participating areas, depending on which production horizon we are talking about and the areal extent to which that reservoir or the areal extent of that reservoir. So -- MR. GILBRETH: Each participating area -- each pool is included in a separate participating area, is it not? MR. DIVER: Yes. MR. GILBRETH: And does not the unit agreement have a provision that provides that participating areas can be combined if the operators are agreeable, if they so desire? MR. DIVER: I'll have to defer -- I can't -- I don't know. ~fl~. GILBRETH: Is there someone in your company who can? MR. HOWARD: That's true, Easy, they can be combined for the purpose of -- MR. GILBRETH: In other words, it would Just be a matter of the operators themselves within the unit to negotiate with each other on an ownership of the gas and transporting at shore, would it not? MR. DIVER: Well, I don't know if you are talking about a combination of participating areas, that's certainly an ownership -- at least onshore those are two different things. The onshore area that you are talking about is not owned by the unit although it may be owned by some participants in the unit. MR. GILBRETH: Well, is there any ownership, let me ask this, is there any ownership in the McArthur River Oil Field as we know it? The West Forelands -14- gas pool production, within the McArthur River Field, the platforms, or the onshore facilities, are they owned by any parties who are not a member of the McArthur River Unit? Trading Bay Unit, pardon me. In other words, there are not any outsiders, it's all an in-house ownership with different people owning different interests and different things. Is this right? MR. DIVER: That's correct. MR. BURRELL: Mr. Gilbreth, I'm not sure that we haven't gotten apples and oranges mixed up here. I don't think there is a West Foreland gas pool within McArthur River Field. MR. DIVER: That's right. MR. BURRELL: If there is, I don't know about it. MR. GILBRETH: I'm sorry, it should have been Middle Kenai. MR. BURRELL: Oh, the West Foreland gas pool I referred to was the one onshore. MR. DIVER: There is a West Foreland oil pool. MR. GILBRETH: I'm sorry, I might have misled you. I meant the Middle Kenai Oil Pool. Sorry. Mr. Diver, have you been present for the hearings on the Middle Ground Shoal and the Granite Point and Trading Bay Field that have been held for the past three days? MR. DIVER: Not all of them, no. MR. GILBRETH: Did you hear the testimony of Mr. Logan and Mr. Giles on the first day of the hearings, regarding restriction of production injection? MR. DIVER: Yes. MR. GILBRETH: Could you tell us whether or not you agree with the testimony or the conclusions reached by those gentlemen that there would be damage resulting from curtailment in production or curtailment of injection? -15- MR. DIVER: Well -- uh -- I have not read all the articles that Mr. Giles, I believe it was, quoted or referred you to. Uh -- I can visualize very easily where curtailment of production could cause, or a curtailment of injection could cause, a loss in ultimate recovery. This is not at all beyond reason, and I can also see that curtailment of production, as we have testified on at least one other occasion, could cause a loss in ultimate recovery. MR. GILBRETH: I believe on the other occasion you are referring to there was testimony sh~wing that a well closed in for some period of time did not regain its prior productivity. Is that not true? MR. DIVER: Yes, that is what happened. MR. GILBRETH: Since that time, have you developed any additional infor- mation that tends to support this on other wells? MR. DIVER: Well, the previous testimony referred to one particular well, G-16. This is off the Grayling Platform, and we have since analyzed the performance of several other wells in the unit that had to be shut-in for operational reasons. And we think, in our opinion as engineers, there has been a drop in the productivity in this, but as we stated before, it's not firm testimony, not firm evidence, that we could come to you with because we unfortunately did not have a productivity index measurement before and after the shut-in. But the actual oil rate from the well did drop, and dropped drastically in several cases. Whether this could be considered firm enough evidence is beyond me, but we have seen curtailment of oil rate on a well after shut-in. MR. GILBRETH: I see. Could you tell us, also, have there been any wells where you received, experienced, higher production rates after shut-in? MR. DIVER: Not to my knowledge. -16- MR. GILBRETH: Not to your knowledge. Alright, you mentioned, I believe, with regard to reinJection -- possible reinJection of the surplus gas -- that it would be necessary to lay a high-pressure line outside the leg of the -- was it the Grayling Platform? MR. DIVER: Yes. That is coming from shore. MR. GILBRETH: Coming from shore back? And that this was very undesirable from a safety point of view? Can you tell us, would the existing gas line that you use now stand the higher pressures that you mentioned, I believe you said three to four thousand pounds injection pressure? MR. DIVER: I would rather defer this to a production engineer from Union Oil Company who I'm sure could answer that question. If I have to answer that question, I would say I don't believe it would because I don't believe that any connections were put on these platforms with four thousand pound working pressure connections. This does not -- I don't know about the pipeline, I'll have to say I don't know. MR. GILBRETH: Let me tell you t'he reason for my asking the question, and then you may have someone who could answer it. I simply wondered if you are putting the low pressure gas to shore now, relatively iow pressure, through one line, and I'm wondering if that could go to shore through a third line that could be installed over the leg and not create such a hazard to have the high-pressure gas come back through the existing line. MR. DIVER: This certainly -- if it were possible, and I don't say that it is possible -- would eliminate one of the hazards I mentioned. It would not eliminate the hazard on the platform of this high-pressure gas, whether it comes through in a leg or on the outside of a leg. The outside of a leg has one hazard-- the line may be swept away by the ice. The other -17- is having three thousand pounds of gas on board the platform. That is not our idea of a safe operation. MR. GILBRETH: Yes, sir. I don't want to get technical, but I believe you said that gas serves its main purpose by helping the oil through the the reservoir. Isn't, in fact, the oil existing in McArthur River oil one phase in the reservoir and there is no free gas in it? MR. DIVER: That's right, there is no free gas, but there is energy involved due to the composition of the oil with the gas in solution such that as the pressure is reduced, of course, this whole mass tends to expand. MR. GILBRETH: It is one phase then until it reaches some point where the pressure is below the saturation pressure. MR. DIVER: Yes. MR. GILBRETH: Then the gas is evolved and you get considerable increase in energy response at that point? MR. DIVER: Yes, sir. This point of release of gas is in the well bore in the case of McArthur River. MR. GILBRETH: I see. MR. DIVER: There is no free gas solution -- free gas saturation, pardon me, in the Hemlock Reservoir or any other. MR. GILBRETH: Earlier testimony has indicated that gas injection into the oil reservoir probably would not be feasible and certainly not advisable until it had been proved that water injection was not possible or efficient. Can you tell ma, in the McArthur River Field, has the injection program progressed to the point that you can now rule out gas injection as a recovery medium for recovering oil? MR. DIVER: Yes, I stated this in my testimony in Juneau and I would -18- be glad to restate it. We would not consider gas injection in the Hemlock Rese rvoi r. MR. GILBRETH: It's definitely written out for the McArthur River Field. MR. DIVER: It's definitely ruled out. MR. GILBRETH: Can you tell me, has it been written out or can it be written off for possible future recovery of the West Foreland oil zone? MR. DIVER: This is under study right now. We are, as an engineering planning group, charged with coming up with development plans, but I can tell you that our results right now would rule out gas injection. MR. GILBRETH: And would this likewise be true for the oil zone in the "G" Zone? MR. DIVER: Yes. MR. GILBRETH: What kind of a lag time do you find from the time you inject fluids until you can see any response? In other words, if you were to shut off injection, how long would it take you to feel response in your producing wells, or vice versa, if you increased it -- how long would it take to feel response? MR. DIVER: It is a very difficult question to answer in this particular reservoir because of the configuration we are in: As you are aware, it is a peripheral-type flood and reservoir studies that we have run that fairly accurately simulate the reservoir indicate a response time of about two to three months. MR. GILBRETH: I see. Is it not true that you now believe that there is some partial water drive in the reservoir? MR. DIVER: Yes. You are asking about the Hemlock? -19- MR. GILBRETH: I'm sorry, yes, about the Hemlock. I~hat kind of a water cut do you have from the Hemlock, where your main pressure maintenance program is in operation, and about what percentage of the wells are cutting water? MR. DIVER: The Dolly Varden Platform, which produces from the Hemlock approximately 42,000 barrels a day, has a water cut of about 2%. The Grayling Platform which produces about 36,000 barrels of Hemlock oil a day, has about an 8% water cut, the King Salmon Platform, which produces roughly 27,000 barrels a day from the Hemlock, has about an 8% water cut. I had to weight these~ I don't have the overall unit number released. MR. GILBRETH: Are most of the wells cutting water? MR. DIVER: No, no, there are several wells cutting water around the first line of wells in from the periphery of the reservoir. MR. GILBRETH: I see. But several of the interior wells then are not cutting? MR. DIVER: Several, yes, yes. MR. GILBRETH: You mentioned that from purely a physical point of view you could not reinject produced gas before January 1, 1973. Can you tell us what kind of a delivery, date you could normally expect on compression equipment if you were to order it~ say, now? MR. DIVER: I'm told that this would run somewhere in the vicinity of nine months for the type of equipment that we would have to be talking about. MR. GILBRETH: And then could you give us some idea of what would happen from the point of delivery, in terms of time, until you could start injecting? Is this nine months delivery down South, or delivery to Alaska? MR. DIVER: Yes. I would defer that question, with your permission, -20- to one of our other engineers. MR. GILBRETH: Alright, sir. You mentioned that reinjection of gas under high pressure on a platform would be the very last condition that you would consider for disposing of the gas. If that is the very last, can you tell us what any others would be? MR. DIVER: My whole feeling on this is I think we would prefer to sell it. That would be number one, I guess. MR. GILBRETH: I think everybody in the room is unanimous on that. MR. DIVER: Our only other consideration that we dream of would be to dispose of this gas onshore, but we Just don't envision a safe operation by trying to take this gas back out to our platform and it's physically impossible due to the space limitations to put the equipment on board the platform. MR. GILBRETH: Let me pose to you a hypothetical question. If it were not unsafe from the surface consideration -- in other words, if it were not unsafe on the platform, would it be safe from a reservoir standpoint? Can you see a safety hazard being created by injecting of the gas into sub-surface strata? Either your dry gas zone or an oil zone. MR. DIVER: There would, in my opinion, be no real hazard created in this field by injecting it into the gas zones that we have. I don't believe that we would recover all that we put in that reservoir. We would not recover all the gas we inject, but from a safety point of view, underground, I wouldn't think in terms of putting it into one of these oil reservoirs. MR. GILBRETH: I see. Could you tell me why you do not feel you would recover all of it if it were to go into an existing gas zone? MR. DIVER: Well, if we injected all of the produced gas that is under discussion here, there would be more injected than we would withdraw. There- fore~ we would be under this same consideration as we were with an onshore -21- aquifer. I strongly believe that there would be some trapped gas as we expanded the gas reservoir into what is currently aquifer and as the aquifer comes back I believe we would trap some of this gas. MR. GILBRETH: You do have some voidage now, but you are telling me that it wouldn't take long to fill up that voidage where you have produced gas. MR. DIVER: It would replace that. It would take some time. I don't mean to imply that it would happen immediately, to fill up this voidage that we have already created, but there would be an over-injection as it were. MR. GILBRETH: To get rid of all the gas for all the future that you can use there would be an over-injection? MR. DIVER: Yes. MR. GILBRETH: Alright, thank you, sir. It is true, isn't it, that you are stripping out a large part of the butanes and heaviers from the gas? MR. DIVER: Yes, at the L.E.X. plant onshore. MR. GILBRETH: I believe that is all I have for right now, sir. MR. BURRELL: I have a couple of questions for you, Mr. Diver. I believe the McArthur River Field went on production in 19677 MR. DIVER: I believe, yeah, in November of 1967. MR. BURP. ELL: I believe the wells that discovered the field, on the basis of which some three platforms and pipelines at 60 odd million dollars worth were built, were drilled about 1965-66. Anyhow, they were drilled before the-- MR. DIVER: They were certainly drilled before the purchase of equipmemt. ~R. BURRELL: Around that time. Were tests conducted in those wells, was there a GOR established as a result of those tests? From the wells -22- drilled from floating equipment prior to the ordering of the platforms? MR. DIVER: Yes, I have to doubt some of the original GOR numbers, but not orders of magnitude. They are very small differences that I might have, in PVT results, but they are not much. MR. BURRELL: Right. So, it would be fair to say that before the plat- forms were ordered there was some knowledge of the amount of gas that would be present with the oil and some kind of an estimate of the size of oil field or you wouldn't have ordered the three platforms. MR. DIVER: Well, I agree with your rough estimate. It was a rough estimate. MR. BURRELL: Right, very rough. It appears as though in the design of the platforms, which have been on production for 3 1/2 years, there was no consideration or no plan to provide for installation of any compression equipment to do anything with that gas. I Just wonder why that was. MR. DIVER: If we move ourselves back in time to the original floater well and the original design of the platforms that went in out there (as you are aware, two of the platforms are 48-well platforms) we did not anticipate the producing rate that we currently enjoy, by wells we did not anticipate the rate. We also, at that time, had a large amount of separation equipment on board the platforms which as a result of the much higher producing rates was never utilized. We had to put much larger equipment on board these plat- forms than we originally anticipated, and space was designed and laid out on the platforms, with certain oil rates in mind, by wells. These did not materialize. It was for higher than that and more space has been required. Also, a lot of injection equipment has been put up, water injection equipment, which we felt was the best way to re-pressure or pressure maintain these -23- reservoirs. MR. BURP. ELL: Then what you are saying, as I understand it, is the combination of unanticipated high rates causing a need for larger separation equipment, and the injection project, neither of which you contemplated originally, is the reason why you ran out of space. MR. DIVER: That isn't unreasonable. MR. BURP. ELL: Is that reasonably close to accuracy? MR. DIVER: Yes, the injection equipment occupies a great amount of space on these platforms and is very successful. It's causing a very successful project. }9{. BURRELL: It sounds as though this field has been much more successful than originally anticipated. I hear remarks about the injection rates, I mean about the producing rates being so much higher than anticipated. MR. DIVER: Well, I don't think we were disappointed to find out -- MR. BURRELL: Well, we are glad it is very profitable. MR. DIVER: I didn't say profitable, sir. I said-- (LAUGHTER) MR. BURP. ELL: Well, the rates are much higher. MR. DIVER: So are the expenditure rates. MR. BURRELL: Are much higher than anticipated? MR. DIVER: Sure. MR. BURRELL: Well, we won't ask for a balance sheet. Tell me about the platforms that were installed about 1967. What was the, at that time, what was the estimated life of the field? What was in mind when the platforms were designed, 25 years productive life or so? MR. DIVER: Approximately 25-30, in that range. -24- MR. BURRELL: And hc~¢ about a safety factor on the life of the platforms? Was it not 100% probably? MR. DIVER: I was not involved in the design of the platforms in any way, and I couldn't say. I don't know. MR. BURP, ELL: But there were, undoubtedly, safety factors. MR. DIVER: With normal engineering practices in design there would be a safety factor built in. This safety factor would be based on anticipated corrosion rates, erosion rates and whether the design, corrosion and erosion rates are the same am what we currently experience, I don't know. MR. BURRELL: Is there anybody who can tell us? MR. DIVER: I don't know. MR. BURRELL: You mean there is nobody who knows? UNIDENTIFIED VOICE: Yes, there is. MR. BURRELL: Maybe we can get somebody who can help us. MR. DIVER: Maybe we can. MR. BURRELL: You indicated, as I understood, that restricting produc- tion to the amount required for a safety flare and beneficial use would perhaps extend the producing life 10 years. MR. DIVER: Yes, sir. MR. BURRELL: And I was just interested in whether or not that was within the safety margin allowed for the construction of a platform. MR. DIVER: My intent was to poin~ out that there is a certain amount of exposure every day~ and to add 10 more years of exposure only adds to the risk. MR. BURRELL: Yes, but 10 years might only use up 10 or 20% of a 100% safety factor. Also, if that be the safety factor we haven't been able to -25- ascertain. MR. DIVER: It might be that way. It might not be. MR. BURRELL: Mr. Marshall has some questions. MR. MARSHALL: Mr. Diver, I would like to ask you a few questions relative to the Middle Kenai Gas Pool that has already been established within the unit. It would appear that there is in excess of 167 feet of net formation which appears as though it would be productive of gas within that pool. Are there any of these gas sands which are presently depleted? MR. DIVER: Not to my knowledge, no. MR. MARSHALL: Have you any thumbnail estimate of reserves from your Middle Kenai Gas Pool, in your unit? MR. DIVER: They are substantial, I would say that. MR. MARSHALL: Would you say they would exceed half a trillion cubic feet? MR. DIVER: Not in my opinion. The difficulty we are into on these, and this is why I have to disagree with that number, is we have seen very little of these gas sands away from the platforms due to the configuration of the wells when we cut these gas sands drilling the oil wells, drilling the Hemlock and G and West Foreland Wells. We encounter the gas sands in relatively close to the platform and we really don't know what occurs in these gas sands as you come over the structure. We have not drilled them over there. It is conjecture, I believe, ~o say that the same identical sand conditions exist on one side of the field, as so far we have seen them relatively close to the top of the structure. MR. MARSHALL: Have you cut these gas sands with the drill bit in more than one platform? -26- MR. DIVER: Yes, we have gas wells on all three platforms, so we have certainly cut them--we've got completions. MR. ~ARSHALL: And ordinarily in your unit, are your correlations rather valid? Is there evidence of continuity of formations of your producing intervals, as a general statement, in your unit? MR. DIVER: Generally continuity, but not quality. The quality does change with structural location in other reservoirs and, as I say, we don't know about these in s~me places. MR. MARSHALL: Could you list any particular detrimental constituents in your gas analysis from the Middle Kenai Gas Pool? MR. DIVER: No, this is essentially a typically Alaskan dry gas. MR. MARSHALL: Very high in methane. Do you see any mechanical problem or perhaps we have already answered this with your statement that you do have a well producing or capable of producing dry gas from each of your unit platforms. Do you see any mechanical problem with using this gas to solve the interruptibility problem as far as the production of the dry gas goes, excluding pipeline breaks, or other pipeline -- MR. DIVER: Yes. These -- we will not withdraw above certain rates out of these wells for fear of sand flow conditions which we have experienced in some of our Kenai fields at the onshore Kenai Gas Field. And to attempt to back up the interruptible nature at the rates that we would be required to produce these things would not be a sound thing. We also have to use some of this fuel, or s~me of this dry gas, for fuel for our operations and there would not be enough gas. The sum total of this is there would not be enough gas. MR. MARSHALL: Uh -- that's assuming your present density of gas wells? -27- MR. DIVER: That's right. MR. MARSHALL: It's not considering, if need be, more gas wells could be drilled? MR. DIVER: Well, certainly, there's a lot of gas sands to drill wells into, but we would not anticipate a major drilling program to develop the gas reserves from these platforms. MR. MARSHALL: Could you give me an estimate of the combined deliverability of dry gas from all of your Middle Kenai gas wells, a thumb- nail estimate would suffice. MR. DIVER: Approximately 25 million cubic feet per day. That is the total. That does not take anything out for fuel that is required. MR. MARSHALL: Do you see any reason why depleted Middle Kenai gas sands could not be used for storage of gas? MR. DIVER: No, provided it was injected into these reservoirs from somebody else's platform, one we're not trying to produce oil off of. As I answered Mr. Gilbreth, reservoir-wise, I don't believe that you would hurt one of these reservoirs by injecting gas into it. MR. MARSHALL: Mechanically, the equipment problem, the space problem, is the limiting factor as you see it now. MR. DIVER: And the hazard problem. The safety aspects of trying to inject gas into these reservoirs. MR. MARSHALL: Because of high pressures on the platform or because of the formation problem? MR. DIVER: No, the high pressures on the platforms. MR. MARSHALL: Could you discuss the reliability of your pipeline transmission to your west side site? -28- MR. DIVER: They have been very. reliable. We have had only very minor connection leaks at one platform at the leg at the connection point onto the leg. There have been occasions, I believe, and I can only say I seem to recall one time where a pipeline pig was stuck in the line on one of the platforms which when the weather warmed up was loosened, but there have been no breaks, if that's what you meant. MR. MARSHALL: Thank you. That concludes my questioning. Mr. Gilbreth? MR. GILBRETH: While they were asking questions I thought of some more along the same lines that Mr. Marshall asked about the interruptibility. Apparently you haven't had any pipeline breaks. Can you give us some idea about the interruptibility due to shutdown? I believe one of the prior hearings indicated that sometimes it was rather substantial. MR. DIVER: Yes. Well, in January, of course, we were very nearly -- the entire field was very nearly shut down due to the ice conditions at the terminal. MR. GILBRETH: Did this last nearly the whole month? MR. DIVER: About 20 days. MR. GILBRETH: I believe you made the statement that there would not be enough dry gas to compensate or bridge this interruptibility gap. MR. DIVER: Well, if we were forced, the implication is that if we were obligated -- MR. GILBRETH: Yes, sir. MR. DIVER: -- in a contract to deliver certain volumes, why that compared to, for instance, our current solution gas production? This is the implication that would be made. MR. GILBRETH: As I understand your statement, then, you're saying -29- that if during some period of time like the January shutdown it became necessary for you to turn on your three or four gas wells, or whatever you have, three gas wells, you could not safely, from a reservoir stand- point, deliver enough gas to maintain the level that you have from the casinghead gas now? ~R. DIVER: During these periods of time, of course, and in this particular instance, it occurred in some bitter cold weather and quite a lot of fuel is required merely to maintain platform integrity, to keep things operating out there and not freezing up. Therefore, we have to take off part of this dry gas, and -- MR. GILBRETH: Yes, sir, I understand. MR. GILBRETH: And then there is not enough left as -- MR. DIVER: Yes, that is right. MR. GILBRETH: -- to bridge the gap. MR. DIVER: In my opinion, I don't believe there would be. MR. GILBRETH: Alright, sir, you made the statement back earlier that if production were restricted the present worth value of future income to the State of Alaska would be decreased by some 33 million dollars, considering an 8% present worth factor. MR. DIVER: Yes, sir. MR. GILBRETH: Could you tell me, considering that it was predicated on the assumption that production would be restricted to conserve the gas, did you give any value to the present worth of gas at some future time? MR. DIVER: No. MR. GILBRETH: In figuring this 33 million dollar decrease? MR. DIVER: No, I did not. I can't imagine that with the volumes of gas -30- that we are talking about here that it would alter that number very much. But the magnitude of that number is so large compared to the value we had to place on the gas at the extreme time in order to balance out. MR. GILBRETH: Just for information, Mr. Diver, what have you previously testified would be the volume of gas that you will flare in the future? Do you recall? MR. DIVER: I believe that I said we would have something on the order of 27 billion cubic feet of excess casinghead gas. MR. GILBRETH: I have a figure, Mr. Diver, from the exhibit that the committee put on that was gathered from prior testimony. It might be off a little bit, depending upon differences in times. It is talking about 39 billion cubic feet of gas. You don't think there is any chance 39 billion cubic feet of gas in the future might be worth 33 million dollars? MR. DIVER: This is only the State's, of course. MR. GILBRETH: Yes, sir. MR. DIVER: No, I don't. MR. GILBRETH: Okay. We'd have only 1/8 left. MR. DIVER: That's right. Yes, sir. MR. GILBRETH: That's all I have, sir. MR. BURRELL: Mr. Diver, you testified that the three gas wells, one on each platform, couldn't make up enough dry gas to solve an interruptibility problem if your casinghead gas is contracted for. MR. DIVER: At current delivery schedule, yes, sir. MR. BURRELL: If the current amount of casinghead gas was under sale contract, without an interruptibility clause, if that were true, you say that the three gas wells couldn't make it. -31- MR. DIVER: In my opinion, I don't think it would. MR. BURP. ELL: That's right. I would like to ask you a question. Is there any lm~ against drilling more gas wells? MR. DIVER: Nope. ~[R. BURRELL: Additional gas wells could be drilled, then, which would alleviate this shortage. MR. DIVER: Yes. I think that along the same lines that Mr. Marshall was asking awhile ago and as I indicated, we would anticipate that if we required more firm deliverability and actually set out to develop these gas reserves it would require another platform. We would do it on another platform. MR. BURRELL: We don't have any testimony -- you said that you would defer to somebody else, as I recall, on the estimate of the gas reserves. MR. DIVER: No. MR. BURP. ELL: Nobody else is going to testify on that? MR. DIVER: On the gas reserves? MR. BURRELL: On the gas reserves. MR. DIVER: No, Mr. Marshall said that, are they more than half a trillion, and I said not in my opinion, they were not more than half a trillion. MR. BURRELL: I see. We've got a gas pool that evidently is pretty good size, at least in the south direction, it covers three platforms, and unless we get some type of a reserve estimate from the witnesses we will feel free to make our own. There is no problem on slots, is there, for drilling additional gas wells? -32- MR. DIVER: Yes. MR. BURRELL: There is? Do you have any wells drilling from any of the platforms right now? MR. DIVER: No. MR. BURRELL: How many slots do you have available on each platform? MR. DIVER: On the Dolly Varden Platform there are eight remaining unused slots. On the Grayling Platform there are eight remaining available slots that are in usable condition. On the King Salmon I will have to consult with one of the Atlantic Richfield people. Well, the thing that we are looking at is the fact that the only logical place to develop these sands would be in a manner similar to the Phillips development of the North Cook Inlet Field on top of the structure in these types of high permeability gas sands. It makes very little sense to drill down structure in this type of reservoir~ This would mean then that we are really only talking about~ for gas development, the slots on the Grayling platform. The other platforms are too far off the crest to reach the sands considered. MR. BURRELL: Have you considered dedicating the slots on the Grayling to gas wells and reaching out from the other two platforms for any additional injection or oil wells? MR. DIVER: No, because we -- the crestal high in the structure is nearest the Grayling platform. We anticipate in the future, and I can't say this year or next year, but there will be slot usage -- we will need more wells in the Trading Bay Unit in the McArthur River Field to recover the Hemlock oil. We have already had to redrill t~,o wells that were lost for unknown reasons, but we had to abandon them. We don't know how much more of this -33- to anticipate, but we would not want to use up all the slots and, particularly, we would not want to use up all the slots on the Grayling platform which is, as I say, probably the last production point in the long-range look, and you have to be pretty long range with these size platforms. We don't want to utilize all the slots for gas wells or even any more for gas wells off the Grayling platform. MR. BURRELL: But you indicated that additional development wells are planned in the next year or two -- MR. DIVER: No, I said we can't tell you that we are going to be drilling in the next year or two, but we can easily foresee as engineers, looking at a long-range viewpoint of this thing, that in the future we will require more Hemlock wells and possibly more G and West Foreland oil wells° MR. BURRELL: Sounds to me that by deferring the drilling of them for that long that you are deferring production for possibly as long as ten years. MR. DIVER: I wouldn't anticipate that we would increase the rate particu- larly by drilling these wells, but we are talking about ultimate recovery in the future as we see where we need to locate these wells. MR. BURRELL: But you are talking about maintaining the rate by drilling. MR. DIVER: That's right. We may substitute a well making 100% oil for a well making 50%. This is the type of thing that we would be looking at in the future. MR. BURRELL: I don't think I have any further questions, Mr. Diver. Have you got the answer there? MR. DIVER: There are eight. MR. BURRELL: Eight available slots in each of the three platforms? MR. DIVER: Yes. They are not available. They are -- -34- MR. BURRELL: Eight that are not in use. MR. DIVER: That's right. Could be drilled, though. Let's put it that way. MR. BURRELL: Any additional questions, Mr. Smith? MR. SMITH: Yes, Mr. Diver, back on your earlier testimony on production rates, I would like to clear up a point or two. I think you said the current rate is in the range of 125 thousand barrels per day. Is that right? MR. DIVER: 120 to 125 thousand. MR. SMITH: And then you indicated that if we prohibit flaring of gas that the curtailment in oil production rate would drop down to the range of 35 thousand barrels per day. How did you arrive at this calculation? MR. DIVER: Well, we add up the fuel requirements that we have in the unit and this includes all of the equipment that is currently operating, and arrive at an oil rate based on a gas/oil ratio of the lowest gas/oil ratio wells which happen, in this case, to be the Hemlock. MR. SMITH: What gas/oil ratio, approximately, are we talking about? MR. DIVER: Roughly 300. We can add all the fuel req. uirements up and arrive at an oil rate. When we arrive at that oil rate, we find out that the rate is so low that we don't need. all the injection that we currently have. We, therefore~ would only logically cut back this injection. As we do that we would cut back the fuel requirements which, again, gives you another fuel requirement and a lowered oil rate. And as you lower this oil rate you need less injection again, so this is what I intended to say when I said it would feed on itself to the point of where we would in all probability shut in practically all of the injection, if not all of it. MR. SMITH: Perhaps that's where my figure differed from yours, then. -35- I was using your previously presented forecast, Curve R, produced and utilized gas. bfR. DIVER: No, that would no longer be valid because a great amount of the fuel, or a large portion of it, is chewed up in these injections. MR. SMITH: Well, this 35 thousand barrels per day projection -- at what point in time was that projection, in mid-'72; first of '73? MR. DIVER: No, this was in '71. MR. SMITH: Thank you. MR. MARSHALL: Mr. Diver, in your previous testimony here a few minutes ago you mentioned that your estimated deliverability from your existing gas wells was in the neighborhood of 25 million cubic feet per day. Now, am I correct that your current flare rate is about 30 million a day? MR. DIVER: Yes, that's not unreasonable. MR. MARSHALL: This would be from several months back, but I -- it's fair then to think that the present volume gas flared is somewhere in the neighborhood of 30 million feet per day. MR. DIVER: Something in that range. MR. MARSHALL: I see. This record I'm looking at is from the McArthur River Oil Field, and would probably be from all platforms combined. MR. DIVER: Is that from the onshore production site? MR. GILBRETH: If I might clarify something, the volume of gas reported flared from the McArthur River Field to us in December, which was the last we have with us today, is about 1,027,000 MCF casinghead gas and 201,000 MCF gas well gas which gives a total of roughly 1.22 million MCF for the month -- it would be about 40 million a day. That's on the McArthur River Field. MR. BURRELL: Mr. Diver, I must interrupt, too, to clarify something. When Mr. Marshall gave the figure of approximately 30 million a day, your response to him was that wasn't unreasonable. I presume that you were talking about the figure and not the flaring, because that is what this hearing is all about. I didn't want that to go by in the record. MR. MARSHALL: Well, actually this figure I'm-- I was trying to grope for was from our Exhibit No. 2, Current Gas Flared, MCF Per Day, March 1971. We have it listed as 30,900 MCF per day. What strikes me is that assuming that is for the gas flared on all platforms, a combined total, that is, of the platforms of the McArthur Oil Field, then you're probably within about 80% of matching the deliverability from your dry gas wells with the total amount of casinghead gas now flared. Does this seem reasonable with your arithmetic? MR. DIVER: Well, provided that there were no other demands on those gas wells for fuel during times when the oil production was drastically curtailed. Unfortunately, there are demands for fuel, requirements for space heating, for boiler use, many of these types of things and our injection project goes on, which uses a lot of fuel. So there are a lot of fuel require- ments in that 25 million. The 25 million is not totally available, Mr. Marshall, is what I am trying to say. There -- there is a portion of this that has to be cut out -- it is not available for delivery. We need to utilize it. MR. MARSHALL: I see your point. In other words, the 30 million flared per day is in excess of your use for so called beneficial use as fuel, etc. MR. DIVER: Yes. MR. MARSHALL: Fine, you have clarified that point. MR. GILBRETH: This is Gilbretho Mr~ Diver~ can you tell me whats in your opinion, is the amount of gas necessary to be flared each day for a -37- safety flare? MR. DIVER: We estimate approximately one million cubic feet a day is required, and this is based primarily on the fact that the safety flare is there primarily to safely vent excess gas in case of a compressor failure and we have to unload large volumes of gas through a vent line. If we tried to unload these large volumes of gas, and it comes at pretty high rates, we need a large enough, if you will, pilot flame so that we don't blow the pilot out. We estimate about one million a day, and as Mr. Duthweiler said yesterday, Union Oil's policy is that they are saying 50 cubic feet per barrel. MR. GILBRETH: I have heard the testimony now three or four times, 50 cubic feet per barrel, but I wonder if this is not a figure that the operators have derived from flashing from the low pressure separator or something of that nature. If we take it to the extreme and say you were producing 10 barrels a day, then this would say that it would be necessary to have 500 cubic feet to keep the flare burning-- I don't believe you'd keep one burning for that. MR. DIVER: We wouldn't like to, as I say, we may arrive at our number in a different manner. We also, I believe, I know we do on the Dolly Varden, handle our crude oil in a separator, in a slightly different fashion, in a major departure from most of the other platforms in that we don't flash to an atmospheric condition. MR. GILBRETH: On your platform, do you see a need for having more than one safety flare going at a time? }{R. DIVER: I could rationalize that it would be highly desirable. We do not on the Dolly Varden, obviously. We only have one flare going. As to whether it is necessary or not, I believe this is a matter of individual -38- preference. MR. GILBRETH: 3ust as a matter of curiosity, do the other platforms all have two flares? Or do you know? MR. DIVER: I don't know. I'd have to fly over to see them. MR. BURRELL: Does anybody else have any questions of Mr. Diver? MR. KUGLER: We have defined the Middle Kenai Gas Pool in the McArthur River Field. Are there any other sas reservoirs that have not been defined? Dry gas? MR. DIVER: Not to my knowledge, no. MR. KUGLER: Nothing above the Middle Kenai Gas Pool? MR. DIVER: Not to my knowledge -- there are none. MR. I(UGLER: You talked about another platform. Is this being considered, another platform for development? MR. DIVER: There is no consideration that I am aware of for the imminent design and construction of such a platform. All we are saying is, due to the limited slot availability and our foreseeable requirements, potential require- ments to develop the oil field from the Grayling platform, that this would be a requirement if we decided to do so. We envision this as a requirement. When I say we -- this is Marathon. MR. KUGLER: Do you have an). idea what reserve of gas it would take to pay for a platform-- to develop the gas? MR. DIVER: This, of course, is a very complicated economic question to answer, and if you have enough of the sas then it obviously would not take very much. I mean very much in the way of reserves. However, there are a number of considerations, economic-wise, that are involved here. MR. ICOGLER: I understand the whole thins. Would 1/2 a trillion cubic -39- feet be enough to build a platform, to develop? MR. DIVER: We obviously hope so. This is provided that there is sufficient incentive in price to do this. You only got to start it when you put the platform in, of course. There are many other considerations. MR. KUGLER: Well, if you knew you had 1/2 a trillion feet, would you build a platform? MR. DIVER: When we had a market lined up with a current price and -- MR. KUGLER: Thank you, that's all. MR. BURP, ELL: Does anybody else have any questions? Mr. Marshall? MR. MARSHALL: Mr. Diver, I'm looking at a very recent gas supply contract, and I noticed the clause which covers lower pressures, whereas through mechanical failure or some other unseen failure the seller cannot meet the contract pressure and quantity stipulations. The contract states that the seller then can deliver lesser quantities at lesser pressures, if he so desires, and if the buyer desires to buy them. What I'm trying to fit together is that even if your dry gas supply would be substantially less than the contract would call for, in this position casinghead gas, that the alternate gas supply would serve to keep the contract valid and although it wouldn't cause an interruption in supply, it would cause just a lessening of supply. Could you see any fallacy in that statement? MR. DIVER: I don't know what contract you refer to, and as far as a fallacy in your statement, as I said, there would be capacity -- well capacity -- that would be excess to our needs from the gas wells. As to whether a contract could be written and agreed to by all the parties, with very loose open terms and apparently the contract you have does have a lot of loopholes in it for the producer -- uh , I don't know. It seems to me -40- that this is conjecture as to whether we couldn't negotiate such -- MR. MARSHALL: Maybe to generalize a little more -- contracts are written where lesser pressures and quantities of gas can be supplied and the contract still kept alive. MR. DIVER: Almost all casinghead contracts, that I'm aware of, have stipulations in them that the production and marketing of the gas is secondary to the oil production, and it is subservient to the oil production -- words to the effect almost verbatim, subservient to the oil production -- and implying that this is a highly interruptible source -- that this gas production is essentially at the control of the oil production. I agree with you. MR. }~RSHALL: Thank you. ~fl~. BURRELL: Mr. Diver, does a liquified methane plant require continuous delivery? What are the problems for a LNG plant if it goes down for 20 days in January? MR. DIVER: I couldn't answer that. MR. BURRELL: We'll ask somebody else then. Oh, as a housekeeping item for the record that exhibit which was of the platform put up on the slide -- is that being entered as an exhibit? MR. DIVER: Yes. We would lika to call it I-A, or whatever you prefer, Mr. Chairman, because we have a technical problem in that Mr. Howard has the exhibits 1-5 which were so numbered. Excuse me, Mr. Howard said we don't necessarily need to introduce that at this point. MR. BURRELL: I think we would like to introduce them at this point~ Marathon Exhibit A. Union has supplied us with some small prints. We would rather have them printed in the record. They are much easier. The print is a copy of the slide? -41- UNIDENTIFIED VOICE: Yes. MR. BURRELL: We will accept that. MR. DIVER: Union will appreciate that, I'm sure. MR. BURRELL: I'm sure. Are there any other questions of Mr. Diver? MR. MARSHALL: Do you have this exhibit with you at this time? MR. DIVER: Yes. MR. BURRELL: Does anybody in the audience have any questions of Mr. Diver? If there be no further questions of Mr. Diver, unless he objects, we will take a 15 minute break. BREAK MR. BURRELL: We will reconvene the hearing at this time, and we are going to try and wrap this up -- at least for the people who have to catch a two o'clock airplane -- se we may continue right on through noon. Mr. Bevan, your next witness? MR. BEVAN: Well, sir, we now call Mr. Howard to discuss the marketing aspect of this problem, and inasmuch as he won't be giving testimony I don't believe there is any need to state his qualifications. MR o BURRELL: I see no reason to do that either. ~. MARSHALL: Please raise your right hand. In the matter now at hearing, do you swear to tell the truth~ the whole truth, and nothing but the truth, so help you, God? MR o HOWARD: I do. ~. MARSHALL: Thank you. MR. HOWARD: I am B. G. Howard, Divisions Operations Manager for Marathon's Alaska Operations. I am aware of the negotiations which have taken place and/or are currently underway involving Marathon's sale of gas -42- in Alaska. I will attempt to answer your questions regarding the marketing possibilities of casinghead gas both as of now and in the future from the Trading Bay Production facility located at the West Foreland in Cook Inlet, Alaska. This is the facility that receives gas from both the Trading Bay Fields and the McArthur River Field, often referred to as the Trading Bay Unit. In referring to your first question in the Notice of Public Hearing, April 24, 1971, can excess casinghead gas be marketed by July 1, 19727 Marathon Oil Company has never received an offer to purchase its share of this excess casinghead gas available at West Foreland. I'll show you a couple of economic appraisals which will illustrate the reason for the apparent lack of interest from gas purchasers in this area for this particular gas. There are only two marketing outlets for this gas in this area, and these are the Anchorage marketing area and the Nikiski area the east side of the Inlet. I should like to discuss with you the appraisals we have made for transporting this West side gas to these locations. First, let's consider the movement of this gas to the Anchorage area. Our economic-type analysis of transporting all of the west side casinghead gas to the Anchorage area indicates the construc- tion of some 94 miles of pipeline will be required, including a crossing of the Susitna River and the Knik Arm, the installation of a great amount of horse- power and the necessary dehydration equipment. We estimate the total investment required will be 21.8 million dollars. Allowing 6% interest on this investment and the necessary operating and maintenance expenses over the eight year period in which the casinghead gas will be available will result in a total cost of 29.9 million dollars. This Exhibit 1 is a schedule of the investment and operating cost estimates to transport this total west side gas to the Anchorage area. I would like to point out that the 6% interest on investment is cost -43- only of securing the necessary funds and these figures do not include any return on investment. It may be noted, then, that the available gas from the time delivery might commence in late '72 has been estimated at 45.8 billion cubic feet. The estimated cost, then, for transporting -- well, excuse me -- for transportation cost alone is 65.3 cents per MCF laid down in Anchorage. I want to emphasize this is transportation cost alone and does not include any value for the gas. It should be apparent that transportation costs -- that these transportation costs of 65 cents would preclude this gas from competing with a non-interruptible high quolity gas which is already available to the consumer in the Anchorage area. We could consider these calculations and estimates an exercise in futility, anyway, inasmuch as the domestic require- ments for Anchorage are currently supplied by a franchised public utility, on a long term contract. On May 10 of this year, we've heard references made several times in this hearing, the City of Anchorage issued an invitation to bid for gas service to supply the Municipal Power and Light Department for electric power generation. The bid specs call 263.8 billion cubic feet of gas to be delivered over a 20 year period, with initial deliveries commencing in late 1972 at approximately 12 million cubic feet per day. On May -- excuse me -- a recent news release appeared in one of the Anchorage papers covering this invitation to bid, indicating that the excess gas available in Cook Inlet might be used to supply this market. Let's examine this for just a moment. We've prepared Exhibit No. 2 which shows on a vertical scale a volume of gas in MCF per day and on the horizontal scale appears time in years. We have plotted the estimated average daily gas requirements of the City of Anchorage from the information contained in the contract documents issued with the bid proposal. We have also plotted on this graph the total estimated casinghead -44- gas that will be available from the west side of the Inlet. You will note that beginming in 1973 the city's requirements are expected to average only 12 million cubic feet per day, increasing to approximately 25 million cubic feet per day by 1980. The excess casinghead gas that will be available in 1971 is approximately 62 million cubic feet per day, declining to near zero by 1980. These curves intersect in late 1975, which indicates that the volume of excess gas available at that time will be insufficient to meet the city's requirements. Also, it can be seen that in the early stages of such an arrangement a considerable volume of gas will be in excess of the city's requirement. In fact, we estimate that the city could only utilize approxi- mately 23 billion cubic feet or 30% of the remaining gas available on the west side at this time. This would represent only 8.8% of their total future requirements of almost 264 billion. Considering the transportation costs now, to move this volume of 23.3 billion cubic feet to Anchorage for a city's power generation requirements, we would like to refer you to this Exhibit No. 3. Note an investment of approximately 15.3 million is required for pipeline and compression facilities~ and adding interest on the investment and operating expenses runs the total cost over a five year period now, to an estimated 20.6 million dollars. Comparing this total to the 23 billion cubic feet of gas available, results in the transportation cost of 89¢ per MCF. Again I should like to emphasize that there is no value allowed for the gas; this is trans- portation cost alone. There are four other aspects to the city bid specifi- cations for supplying this fuel for power generation which we should consider. The quality specifications included in the bid renders the casinghead gas available on the west side of the Inlet completely unusable for this purpose. A chemical analysis of the residue gas from the LEX plant~ which makes up -45- a majority of the gas available on the west side, indicates that no degree of processing or purification could make this gas meet the quality specs contained in the specifications called for by the city. For example, the excess gas contains 7.11 volume percent of nitrogen while the city specs call for less than one percent. The excess gas contains about 73% methane while the city calls for greater than 99%. The excess gas contains 8.2 - 8.4% ethane, while the city specs require less .15 percent. Further, the city bid requirements dictate that the supply will guarantee a continuous, uninterruptible supply of gas to the city. We have Just experienced a winter during which, on several occasions, production was essentially shut-in as a result of ice conditions in the Inlet, which should be a very stark reminder to all of us of the interruptible nature of this type of production. The excess casinghead gas is of interruptible nature, for this and other reasons, therefore cannot be considered a guaranteed continuous supply. There are four distinct reasons, then, any one of which would eliminate this gas from consideration as a supply for the city's power generation market. To review (1) the west side excess casinghead gas will not meet the quantity require- ments; (2) it is not possible to treat this casinghead gas to meet the city's strict quality specification; (3) the city's requirement of a non- interruptible supply of gas cannot be satisfied with this casinghead gas production; and (4) the most important -- the transportation costs render this gas completely non-competitive with other fuels today. Granted, the city can relax the quality, quantity and delivery specifi- cations, and they have indicated that they are going to consider this in June, and I'm aware of that. However, from the foregoing discussion I think it should be apparent that there is no market for the casinghead gas in the -46- Anchorage area, unless the consumer is forced to accept a considerable increase in his utility rate. As previously stated, the only other area where this gas could be further utilized is in the Nikiski area. This map we prepared on economic schedules to illustrate the cost of transporting the excess gas from the west side to the Nikiski area. This schedule is shown as Exhibit No. 5. In order that all of the casinghead gas available on the west side be transported across the Inlet and to avoid attempting crossing with a deep trench running from down the Inlet in the vicinity of' McArthur River Field we have included in this appraisal a building of a line from the Trading Bay Production facilities to Granite Point and then across the Inlet to the Nikiski area. Total investment for pipelines and compressors has been estimated at 21.5 million dollars. Again allowing 6% interest on investment and considering appropriate operating expenses would bring the total to almost 30 million dollars. By the time this project could be completed we estimate that there would be some 45.8 billion cubic feet of gas remaining to be transported through the system. The unit cost, then, to deliver this gas to the east side would approximate 64 cents per MCF. If this gas were to be considered as a feed stock to an LNG operation it would be appropriate to apply a shrinking factor for the nitrogen and CO~ contained in gas, thereby reducing the effective volume of the gas. Making these corrections would result in a transportation cost of about 70 cents per MCF laid down at the gate of an east side LNG plant. Again, the transportation cost is so much higher than the price of gas available in that area on the east side that it rules out consideration of this gas as competitive fuel or feed stock in the Nikiski area. We have discussed the two potential delivery points for this gas and the transportation costs associated with delivery. I was about -47- to say we've discussed the delelivery of this gas to the two potential points where it might be utilized. I believe that it is evident that the transporta- tion cost alone would rule out the utilization of this gas to either the Anchorage or the Niktski area. Due to its kind of remote location, the limited volume, very poor quality and interruptible nature of production, the owners of the Trading Bay production facility recognized real early that the market for this gas would likely be impossible. However, in an effort to recover and save as much as possible of the liquids contained in the excess gas, they elected to construct the LEX plant at the Trading Bay production facility. The owners of this plant, Marathon Oil Company, Union Oil Company of California, Atlantic Richfield Company, Phillips Petroleum Company, Amoco Production Company, Skelly Oil Company, and Standard Oil Company of California, likewise recognize that the economics of such a plan were about as marginal. Nevertheless, the construction was undertaken and the facility was placed on stream in early 1970, and now recovers butanes and heavier liquids from the casinghead gas produced from the McArthur River and the Trading Bay Fields. It is anticipated that this facility will recover some 4.1 million barrels of butanes and gasoline after processing some 58 ~billion cubic feet of gas. These liquid~ would otherwise ha'ye been lost. As you are aware, these products are reinjected into the crude stream at the Trading Bay production facility. These statistics that I Just mentioned sound real impressive; however, I would like to point out that the economics of this plan indicate that each barrel of production recovered will cost the plant owners about $2.91. Comparing this cost to the current sales price of crude oil, I believe it is obvious there is very little profit in this operation. I believe you are also aware that we are not now recovering the -48- propane from the LEX process, as this product cannot be reinjected into the crude stream because of its high vapor pressure. To recover and market this product would require separate handling and transportation. Marathon has .. evaluated several proposals from interested propane purchasers to market this propane which could be extracted from the Trading Bay casinghead gas available at West Foreland. A rather rapid decline in the projected propane production and the difficult transportation problems associated with the icing conditions in the winter months have negated a suitable market and arrangement to date. You will recall that at the last public hearing on this subject a Calgary-based firm forwarded to this committee a wire indicating their interest in purchasing propane from this facility and I believe this wire was read into the record at that hearing. As has been the case more often that not, as soon as this firm, was made aware of all the facts they withdrew the offer. We are currently negotiating a market for approximately 10,000 gallons of propane per day at the moment and we are optimistic that suitable arrangements can be consum- mated by mid-summer 1971 to market this product. As soon as a preliminary agreement has been reached for the prospective purchaser, we will submit the necessary plant modifications for approval of the plant owners. Regarding the three questions included in the notice for call of this pucliC hearing, we believe our testimony has covered all the possible means of disposing of the excess casinghead gas, and Mr. Diver has also testified regarding the curtailment of production so as to eliminate any excess gas. We feel that the gas cannot be marketed, it is unreasonable and unsafe to oil recovery. We believe that the sum total of this testimony also goes to speak to your question No. 2, which inquired as to whether the flaring or vemting of casinghead gas in excess of the amount required for safety -49- would constitute waste. For the reasons contained in this testimony, we believe that continued use of gas under present conditions does not consti- tute waste, as waste is defined in Alaska Statute 31.05.70(11). In closing, I would like to reiterate that this gas is being beneficially utilized to the greatest extent possible at this time. Nevertheless, we stand ready to discuss any proposal that might allow us to reuse this gas more beneficially. That concludes my direct testimony, Mr. Chairman. MR. BURRELL: Thank you, Mr. Howard. As I recall your statement, you had about a 90¢ transportation cost to Anchorage based on 45 billion cubic feet of casinghead gas. MR. HOWARD: Are you referring to the exhibit covering the City of Anchorage power and light requirements? ~{R. BURRELL: I think that is the one. UNIDENTIFIED VOICE: Exhibit No. 3. MR. HOWARD: That was the right one, at 90¢. That is correct. MR. BURRELL: And I think the other one was 70¢ for transportation costs. But in any event, that's not really relevant. In each case we're talking about 45 billion cubic feet of casinghead gas, is that right? MR. HOWARD: This Exhibit No. 3, which relates to the amount of gas that could be utilized by the city's generation requirement, is 23 billion. MR, BURRELL: Oh, I guess it was the other exhibit that showed the 45 billion. MR. HOWARD: The first exhibit covering all the west side gas was compared for 45.8 billion cubic feet which is all the gas which would be available approximately in 1973. MR. BURRELL: Well, my point is this. We've got dry gas in the McArthur -50- River Field. We've got casinghead gas in other fields that could be picked up with this pipeline. Assume an equivalent quantity, however, of dry gas could be made available at the same time, wouldn't that in effect roughly reduce the transportation cost by one-half? MR. HOWARD: All of the west side gas was included in this amount. MR. BURRELL: Dry gas, also? MR. HOWARD: All of the west side casinghead gas. There was no dry gas included in this. MR. BURRELL: That's what I was complaining about. If you assume an equivalent quanti~y of dry gas was available, wouldn't that effectively halve the transportation costs because you took your capital cost and operating cost and divided it by the quantity of casinghead gas? Now if you take that bottom figure which is the quantity of casinghead gas and double it by adding an equivalent amount of dry gas, it would reduce that to -- your transportation cost -- to about one-half, wouldn't it? ~. HOWARD: I think that if you assume the right number you can get any number you want to reach in this. MR. BURP. ELL: Let's double the MCF by taking your casinghead and adding to it an equivalent amount of dry gas. Now doesn't that halve your transportation cost? MR. HOWARD: I don't think I could quarrel with your arithmetic. MR. BURRELL: Okay. And likewise, if there is a lot more than an equal amount, like if there is three times as much~ the transportation cost is dropping rapidly. My point is this, Mr. Howard. We have been told that the casinghead gas is non-competitive because of the existence of a much cheaper dry gas. The dry gas is therefore keeping the casinghead gas from being -51- marketed. N~¢ why can't the dry gas help the casinghead gas be marketed? Otherwise, it looks like we'd be in terrible shape if somebody finds another gas field. We better quit leasing gas prospects, maybe. MR. HOWARD: Mr. Chairman, are you relating this to the City of Anchorage proposal? MR. BURRELL: Any proposal. MR. HOWARD: I don't think that your point has much meaning unless you tie it down to a specific market. MR. BURRELL: Well, I'm not talking about necessarily the ones that are currently being offered. I am talking about the liquefaction proposal, any prospective proposal. MR. HOWARD: Certainly, Mr. Chairman, if you deliver more gas through these same facilities, the unit cost of transportation will go down. I'm having a little difficulty following how we do get to this point, so that we deliver more gas through t'he system. MR. BURRELL: Well, my thought was Just to put dry gas into the system, too, and you can extend the life for amortization purposes~ as well as reduce the throughput charge~ the transportation charge. MR. HOWARD: I'm trying to understand what you're saying. I~m not sure I'm up with you yet. Are you talkin~ of taking this casinghead gas to the east side, or are you talking about bringing it to Anchorage? MR. BURRELL: Anywhere. Anywhere there is a market for it~ whether it be a LNG plant on the east side or it be an Anchorage market. I am saying that if you add dry gas to the stream, will that not reduce the transportation costs? For two reasons -- you've got additional gas moving through, available~ and you've got a longer amortization period. -52- ~R. HOWARD: I don't think I can answer your question directly. I think I would have to answer like this, Mr. Chairman. If you're talking about bringing this casinghead gas into the City of Anchorage, for this power generation requirement which has been discussed at length at these hearings, then you would have to, and could, mechanically develop some gas well gas, a sufficient quantity to satisfy this total commitment of 264 billion. It would not be, as you suggested a moment ago~ half and half. I believe you said an equal amount. MR. BURRELL: That was just an example, for arithmetic. MR. HOWARD: Well, that's the reason I'm telling you I can't talk in generalities about the economics of marketing gas, Mr. Chairman. MR. BURRELL: Well, I just want you to agree with my arithmetic. MR. HOWARD: Well, I think you could get any member of your staff to agree with your arithmetic. You don't need me up here for that. If you were to bring this volume of west side casinghead gas into Anchorage you would have to supplement it with something over 200 billion cubic feet of dry gas reserves, and you would still be utilizing all the west side casing- head gas that will be available, so let's conserve all this gas. Now, that is not what you're suggesting. MR. BURRELL: That's exactly what I am talking about° MR. HOWARD: Okay. To furnish this 200 odd billion in gas it would be necessary to supplement this casinghead gas, and would dictate that we develop a dry gas reserve in Cook Inlet. These development costs, including a platform, pipeline to shore, gas treating and handling facilities, and a pipeline to Anchorage, would run on the order of 30 million dollars. I believe that if we refer back to the exhibit that has the curves on it we can see that in -53- November 1973 the city's initial deliveries are only 12 million cubic feet a day. I believe you can appreciate the economic considerations of spending 30 million dollars for a 12 million dollar market initially which only grows to 25 million by 1980. You cannot develop that gas field and lay that gas down in Anchorage at a competitive price. You're looking again in the range of 70 or 80 cents to lay this gas down in Anchorage. It will not compete with the gas that is already available in Anchorage. MR. BURRELL: Are you saying that the dry gas couldn't be developed for market from the McArthur River Field, and be competitive in the Anchorage m arke t ? MR. HOWARD: Not for 263 billion, not for this kind of market. Mr. Chairman, you must appreciate how low your rate of return is early the first eight or ten years in the life of that project when you're comparing that to a 30 million dollar investment. I'm saying -- I want to get on record that it can be done, if the consumer in Anchorage is willing to pay considerably more for his utility bills than he is now paying. MR. BURRELL: I just wanted to find out whether or not you thought it could compete, and the answer is no, it can't compete. MR. HOWARD: No, sir. It cannot. MR. BURRELL: That's what I was after. Did you Just dedicate additional reserves in Kenai Gas Field to Anchorage Natural Gas Company, perhaps so they could bid on this contract? MR. HOWARD: So they could bid on which contract? MR. BURRELL: City contract. MR. HOWARD: We are currently in very serious negotiations with APL on our additional reserves, committing additional reserves. -54- ~. BURRELL: To the Alaska Pipeline? MR. HOWARD: To the Alaska Pipeline. ~R. BURRELL: Which is the line that runs through the city gate, Anchorage. b~t. HOWARD: They have changed their name. I'm not quoting the correct name, it's Alaska Public Services. MR. BURRELL: That's all the questions I have now, sir. Mr. Gilbreth? MR. GILBRETH: Mr. Howard, you just mentioned that it would be virtually impossible to move the gas to the City of Anchorage without the consumer having to pay an increased price. I believe your figures there showed either 65.3 cents or 89 cents an MCF depending upon whether you're looking at the overall reserve or Just what is useful. Can you tell us what the current cost of gas is for the same purposes that this would be used for? Do you have any idea what it was? MR. HOWARD: I'm not sure I understand your question. You're telling us the current price of which gas, sir? .MR. GILBRETH: The gas which this would replace. Apparently, you said that this gas could not be competitive and it's obviously being used now for something less than 89 cents an MCF. How much less than 89, do you know? MR. HOWARD: I believe that Mr. Teel testified day before yesterday that he was paying about 20 cents an MCF for this gas at Kenai. I understand that is very close. MR. GILBRETH: But what is it where this, where your figures go to, back where the market is? I think this is back to the same deal. I mentioned that I'm paying $1.30 at my house for it; the city is paying something more than 20 cents. Do you know what they are paying? -55- not? MR. HOWARD: I think that is probably a matter of public record. bR. GILBRETH: Ail I was trying to determine -- MR. HOWARD: I think you will find that it is around 50 cents, is it MR. GILBRETH: I don't know. You said this couldn't be competitive with 89 cents. How do you know that it can't if you con't know what it is selling for? MR. HOWARD: It's pretty close to 50 cents, I believe. MR. GILBRETH: Okay. That's what I wanted to find out. Let me refer to your curve here Just a moment. Somewhere along the lines that Mr. Burrell was talking about. As I understand it, your curve, the shaded area is the amount of casinghead gas that can be utilized to supply the City of Anchorage requirements included in their bid proposal. MR. HOWARD: That is correct. MR. GILBRETH: If you were to develop a dry gas supply on the same side of the Inlet that the line is laid, would it not be available to supply the flat area under the line? MR. HOWARD: Yes, it would be close to the same volume as Mr. Burrell and I were discussing in a hypothetical case a minute ago. Certainly it would be available. That would 'be the reason for development. MR. GILBRETH: Okay, and I believe that someone, Mr. Diver indicated earlier, that you do have dry gas reserves in the McArthur River Field. MR. HOWARD: That ' s true. MR. GILBRETH: As I understood your testimony, then, it would cost 30 million dollars to develop those dry gas reserves to put in the same line that is carrying this gas? I understood you to include pipeline costs -56- in there, also. MR. HOWARD: It wouldn't necessarily be the same line. It might be a little different design including a different volume of gas. 30 million dollars, the figure that I mentioned, would cover platforms, wells, submarine line to shore, gas feeding and handling facilities both on the platform and on the shore, and the pipeline to Anchorage. ~{R. GILBRETH: And the pipeline to Anchorage. In other words, those figures plus the other figures would be two pipelines to Anchorage, is it not? MR. HOWARD: No, sir. MR. GILBRETH: You had a pipeline here of 16 million dollars. You said an additional 30 million -- it would cost 29.9 million under this proposal -- and then I understood it would cost another 30 million to get to Anchorage? MR. HOWARD: No, sir. MR. GILBRETH: Oh, I'm sorry. MR. HOWARD: I said it would cost a total of 30 million dollars to build the platform~ develop the oil in the gas field, and bUild the necessa~z gas handling facilities, and a pipeline to Anchorage. MR. GILBRETH: Oh, I see. MR. HOWARD: You wouldn't have me install two pipelines. MR. GILBRETH: Well~ I didn't think so. That's why I was trying to get the, what the duplication was because I understood your testimony -- MR. HOWARD: There is no duplication. MR. GILBRETH: Then if you had the dry gas developed under that condition can you give me any idea how much additional cost it would be to put the wet -57- gas into the system, to clean it up, to get it in? MR. HOWARD: It wouldn't be a great deal. You would have to have some compression and treating facilities. You can see that five million dollars worth of compressors in there, it might be a little more for a compressor -- ~R. GILBRETH: Well, then, you might be looking to put dry gas and wet gas both, or casinghead gas, at a figure of maybe on the order of 40 million dollars? MR. HOWARD: That might be a better estimate. MR. GILBRETH: But if you had that, as I understand it, if you do have the gas reserves, you could utilize the shaded area for the casinghead and have dry gas available to supply the needs out here? MR. HOWARD: That's exactly the hypothetical case that we have outlined a minute ago. MR. GILBRETH: And then the dry gas reserves would have to go to, any amount of dry gas would help reduce the cost per MCF of the overall throughput. MR. HOWARD: I~m not sure it would, Mr. Gilbreth~ if you compare your 10 million dollars, your estimate -- not mine -- against that 23 billion cubic feet -- uh -- what kine of number is that, anyway? MR. GILBRETH: Mr. Howard, I'm talking about the overall city's require- men ts. MR. HOWARD: Well, I gave you the figure of 70-80¢ to bring the dry gas reserves into Anchorage. I gave the figure of 30 million dollars to develop this project. Now to get the casin~head gas~ as you are suggesting, we'll have to add another 10 by your estimate and what do you get for that 107 You get 23 billion, right? MR. GILBRETH: That sounds pretty good. MR. HOWARD: So, let's just compare that 10 million dollars to 23 -58- billion cubic feet, and it's in the neighborhood of 55-60 cents. You're the arithmetic expert. So you're not reducin~ the cost of laying down the total package in Anchorage. Is that your question? ~{R. GILBRETH: Well, yes. You'd be in a position, though, as I understood your testimony, that you could only supply this right here with casinghead. You would be in a position, would you not, at that time to supply the entire arno un t ? ~{R. HOWARD: That's true -- that's true. ~fR. GILBRETH: That's all. MRo HOWARD: Do we under -- I think I understood what you said -- we under- stand each other. MR. GILBRETH: My question is, if you were to develop the dry gas and. utilize the casinghead gas now being flared by building another platform putting in the necessary lines there and getting the produced gas to shore, then would you not be in a position -- would you be able to then supply the requirements or the needs that the City of Anchorage had outlined in their bid.? MR. HOWARD: Yes, sir, that's true. You would be able to satisfy their total requirements through the line and also salvage that 23 billion cubic feet of gas. Then I believe you asked what price it would reduce the price to, reasonably, and the answer to that is, I believe you would find, if you run these estimates out, that you would still be in excess of 70 cents. Mll. GILBRETH: I see. We'll run those out, but I wanted to determine this would be done for something on the order of 40 million-- rough rounded figures, plus 'or minus, with the volume that they need. MR. HOWARD: (indiscernable) MR. BURRELL: The Chair would like to recognize the Honorable Senator -59- C. R. Lewis, Alaska State Senator, who has come to see us. Nice having you, Senator. SENATOR LEWIS: Thank you. MR. BURRELL: Please ask questions any time that you'd like to. MR. GILBRETH: ~r. ~Ioward, are you in a position to tell us if you are negotiating with anyone to sell the casinzhead gas being flared, or any part of it? Or tail gas from the plant, I should say. MR. HOWARD: I don't believe that I can say that we are seriously negotiating with anyone to sell this gas at this time. MR. GILBRETH: You have had contacts, I believe you said, in the past. Have all of these turned out to be sour contacts or do some of them look like they have any promise down the road? MR. HOWARD: We have had discussions with a couple of people that we didn't feel. had much potential in the beginning, and later I think it was confirmed that there was not much potential in this market. We've had some discussion with other firms that are more in a position to handle this gas or which, you know, made a lot more sense to us. We've not had any discussion that would encourage us to a great extent that we will ever be able to market this gas. MR. GILBRETH: The interruptibility problem has been brought up in all of the hearings, including this one here. Can you tell me, at the onshore facility where the liquids are extracted from the gas at West Foreland~ has your interruptibi!ity been serious enough that you would, be unable to deliver the small volume that the City of Anchorage has wanted -- has your production ever dropped below that level? MR. HOWARD: Yes, sir, it has. -60- ~. GILBRETH: During the ice stage here in January? Are there other times -- is this something unusual or does this happen very frequently? I.{R. HOWARD: We have experienced some shut-downs of short duration for reasons other than icin~ conditions at Drift River which would have interrupted the 12 million deliverability situation. They have been of real short duration. ~R. GILBRETH: I see. In general, then, the plant itself more or less operates continually, except during these unusual circumstances? MR. HOWARD: Yes. Generally, if you are referring to mechanical problems on the platform. Normally you do not have mechanical problems on more than one platform at a given time, so it tends to balance out the effect. MR. GILBRETH: I see. A question was asked a little earlier, and I wonder-- are you the one who might answer? Asking about the rating of lines in the platform, the gas lines. Are you in the position to answer that or should we ask someone else? MR. HOWARD: I really don't have personal knowledge of the ASA rating on those pipelines penetration connections. I would be guessing, I think. }.~l. GILBRETH: Alright, sir. Is there someone who might be able to testify? That's all I have for right now. MR. BURRELL: Mr. Marshall? MR. MARSHALL: Mr. Howard, this morning we heard that an estimate of total deliverability of dry gas for Middle Kenai sands presently developed within your unit is 25 million cubic feet per day. We also heard that at the end of the contract period, the City of Anchorage proposed, gas contract, that this volume is over 25 million cubic feet of gas per day. Are there presently drilling rigs on the platform within your unit which are capable -61- of drilling Middle Kenai gas wells? biR. HOWARD: First, could I correct one statement which you made in the question -- in reference to the average contract quantity of the city's requirements at the end of their period. I believe it is in the range of 65-67 million per day rather than 25. MR. MARSHALL: Pardon me, I'm in error there. MR. HOWARD: That 25 million number I mentioned was the 1980 number which happened to be about when the casinghead gas supply will be exhausted on the west side. Mit. MARSHALL: Fine. MR. HOWARD: By 1993 the maximum peak daily gas requirement -- I'm talking about peak daily requirements as opposed to the average daily takeover a year -- the supplier of this type of gas will be required to maintain a deliverability in that last year of 109 million cubic feet per day. MR. MARSHALL: In response to my last question -- are there drilling rigs on the platforms now which are capable of drilling Middle I<enai gas wells? MR. HOWARD: Yes, sir, there are drillinM rigs each of the three plat- forms which could be used to drill wells. MR. MARSHALL: Thank you. MR. BURRELL: Mr. Gilbreth? MR. GILBRETH: Mr. Howard, I was Just doing some rough figuring while Mr. Marshall was asking questions. The total amount of gas that is required under the Anchorage contract, do you think it could be delivered from the dry gas reserves that you have under the McArthur River platform? ~{R. HOWARD: There -- yes, sir -- there are sufficient reserves according to our latest estimates by our reservoir engineering section, and there are -62- sufficient reserves in that pool to meet the city's power ~,eneration require- ments, which are 264 billion cubic feet, roughly. MR. GILBRETH: Do you think it could develop enough deliverability to meet the requirements? ~. HOWARD: Yes, sir. It could be done. It would require, as I suggested earlier, another platform installation. ~R. GILBRETH: Yes, sir. It's very difficult to see the figures from your exhibit from here, but the second little box under the curve there is something 281.8 billion, is it? MR. HOWARD: 263.8 billion. That's the total package that the city is requesting in their bid invitation over a 20 year period. MR. GILBRETH: If you Just take that volume of gas there and I realize a lot of other factors are involved, but if you take that volume of gas -- that 40 or so million dollars we were talking about to develop a casinghead and dry gas supply -- it would lower the cost per MCF for transportation down considerably, something on the order of 15 to 20 cents. MR. HOWARD: I believe you are pulling that old arithmetic trick on me again. How high does our economics -- I think you will appreciate it's not as simple -- if you would invest 30 million dollars and you have got to have a regular term for your money, and you can't live with this little cash flow in the first 10 or 12 years of the life of a project that will necessitate the 30 million dollar investment. If you just use the very minimum rate of return on your money you still look at the 70-80 cent number I threw out at you earlier. I would be happy to get with you later to show you how we developed these n~nbers. I do not have them with me and I do not have an exhibit up in front. -63- MR. GILBRETH: Is it not true that most oil companies now look at the overall picture on a project and look at the average rate of return throughout the life so that they can go into projects such as this? Most businesses don't return much money the first two or three years, anyhow, and looking at it over the long pull and then discount back to present conditions. ~gR. HOWARD: I can't speak for all the oil companies, Mr. Gilbreth -- we don't like to go into projects of this magnitude unless we see a reasonable rate of return on our money, and we have gone into such projects where we enjoy very little cash flow in early years, but if you do you still have to build it in the price market so you can get a decent rate of return on the whole project. That's more or less my company's philosophy. MR. GILBRETH: You work both on the rate of return and cash flow? MR. HOWARD: Yes, sir. I think that's fair. MR. GILBRETH: Alright, sir. That's all I have. MR. BURRELL: Mr. Howard~ avoiding arithmetic, I have a couple of questions for you° One is -- you mentioned something about reserve estimates for the dry gas under the McArthur River Field. We have had some difficulty getting that. It is the first time I have heard this testimony that there is a reserve estimate -- can you tell me about what it is? MR. HOWARD: I think I could -- if I would be allowed to qualify to some extent -- I could say that Mr. Marshall's number of 1/2 a trillion is in the neighborhood of some of our recent estimates. Would that suffice? MR. BURRELL: That will suffice~ We recognize the fact that you didn't qualify as an expert witness because you were going to give marketing testimony. MR. BURRELL: Are you currently negotiating the sale of gas for liquefac- tion and if so, is it just casinghead gas or a combination of casinghead and -64- dry gas that is under consideration? MR. HOWARD: We have some very. serious negotiations with some potential LNG purchasers, west coast purchasers, underway at the moment. As to the second portion of your question, certainly if a project involves the develop- ment and production of the Grayling gas reserves we would certainly pick up this casinghead gas on the west side. MR. BURRELL: In other words, the answer to my question is both casing- head and dry gas are under consideration for contract purposes. MR. HOWARD: It certainly entered into the discussions, yes, sir. MR. BURRELL: Mr. Marshall? MR. MARSHALL: Mr o Howard, do I understand that the representation on Exhibits 1 and 2, on the board now, concern the economics of the gas produced Just from the Trading Bay Unit as it is presently defined? MR. HOWARD: No, sir= those analyses contain all of the casinghead gas that is available on the west side of the Inlet, which includes casinghead gas from Trading Bay Unit, Trading Bay Field; and that gas that is available in the Granite Point Field which includes Granite Point and North Trading Bay. MR. MARSHALL: Well, perhaps I'm giving you the fuel to sweeten up your arithmetic to the contrary, but how would you get the gas from Granite Point shore facility to your Trading Bay shore facility? Would you use the existing pipelines or would this necessitate more construction? MR. HOWARD: Those analyses include new pipeline from t'he Trading Bay production facility at West Foreland up to Granite Point, about 29 miles. MR. MARSHALL: I see. MR. HOWARD: From West Foreland up to Granite Point, and another 65 miles from Granite Point into the gate at Anchorage. That comes up to -65- 94 miles, which might sound a little long if you put a scale on a map, but the lines necessarily move several miles away from the beach sometimes to facilitate river crossing such as the Susitna River. MR. ~t~RSHALL: Thank you. MR. BURRELL: Does anybody else have any questions of Mr. Howard? Does anybody in the audience have any questions of ~Ir. Howard? Thank you, Mr. Howard. MR. HOWARD: Thank you for your attention. ~R. BURRELL: I will repeat again that some people want to catch an airplane and we can adjust the schedule here so that those people who want to catch the plane can make it. ~{. HOWARD: I wondered if I might be allowed to put one more comment in the record? MR. BURRELL: Yes, sir, but before you do that I think I had better accept Marathon's Exhibits 1-6 into the record -- 1-5. MR. HOWARD: We would like to refer to the State's Exhibit No. 2, wherein the BTU content of casinghead gas is compared to the TRU content of crude oil to reach a theoretical value of the gas. Information from this type of exhibit has appeared in the local Newspaper, and I believe this infor- mation has been a little misleading and probably misinterpreted° This surely is not in the best interest of the industry or the public. I believe that everyone here will agree that the dry gas reserves located in the Kenai Gas Field is very desirable gas from purchasers' standpoint, for several reasons. There are substantial gas reserves located in that field. The gas is of very high quality, it's available at high pressure, and it's -- -66- and this reserve is connected both to the Nikiski and Anchorage area, by pipe- line. Currently, the average price, as we stated a few minutes ago, of Kenai Gas into the Alaska Pipeline at the field is approximately 20 cents per MCF, if you will, 20 cents per million BTU's. This represents less than 1/2 of the 46 cent theoretical value reflected on the Commission's Exhibit No. 2. I would just like to further point out that the price represents -- excuse me, the 20 cent price represents the current value for the Kenai gas because it is being sold at that price and does not, in any way, infer that the casinghead gas on the west side might have a similar value. In fact, we have to take into consideration that this casinghead gas does not have any present value, except for those purposes for which it is now being used. Thank you, Mr. Chairman. MR. BURRELL: Thank you, Mr. Howard. I regret any misunderstanding. It was clearly intended, we thought, just to equate on the BTU content alone and not to imply that was the market value. MR. HOWARD: I bring it up only because, as I mentioned, I think that there must 'be a lot of people reading the newspaper around town that might be getting misled by what's been stated. MR. BURRELL: That has happened before. Mr. Gilbreth has a question. MR. GILBRETH: Mr. Howard, I just have one question along that same line. On your platforms do you have any standby diesel oil fuel or anything like that? Do you utilize it? }~R. HOWARD: We have a -- we certainly have diesel fuel on board the platforms. We have one 1100 horsepower AC generating unit powered by Solar turbines which is a dual fuel unit that can burn either gas or the diesel fuel. That's about the only significant equipment we have other than the drilling rigs that would burn diesel. -67- MR. GILBRETH: You do buy diesel for those units, do you not? MR. HOI~ARD: Yes, sir. .MR. GILBRETH: Can you tell me, is your cost for diesel -- it is more expensive than the selling price of crude oil, there on the platform or at the meter? MR. HOWARD: I'm sure it is, I couldn't quote you the price. MR. GILBRETH: Oh, let me ask this, if you were looking at it Just strictly on BTU or heat basis on your platform, and what you have to pay for diesel, would you see anything wrong with a BTU comparison as to what the gas was worth to replace diesel? ~.~{. HOWARD: Mr. Gilbreth, I don't believe you could make that comparison, I don't believe you can-- different engines, of course, have different efficiencies. I don't believe you could relate the cost of fuel -- fuel in that engine -- of diesel, strictly to BTU content. MR. GILBRETH: I know you can't, but BTU is your primary basis for selling fuel, is it not? MR. HOWARD: I think it applies in most liquid fuels. I think we all appreciate it does not and never has applied to gas. !~e have tried -- we have successfully pointed that out to the FPC people for a number of years. ~.{R. GILBRETH: Our intent, in preparing this, was simply to show that the gas being flar~ed does have a BTU content, it can be used for heat or for fuel, and that fuel is being purchased for this use and the contention, of course, is that the gas has no value because it's being blown out the stack. Certainly it's not being marketed and, in that light, it has no value, l~e are merely trying to show what replacing fuel is worth on a BTU basis. That's all. MR. HOWARD: But it's unfortunate that it has been misinterpreted -- -68- much different than you had intended, for these purposes. ~{. GILBRETH: For that we apologize. MR. HOWARD: We accept your apology and we also appreciate your attitude. MR. BURRELL: Mr. Howard, I believe ~r. }.~arshall has an additional question. MR. MARSHALL: Mr. Howard, back to the exhibits on the board on my right. As I understand, the basis -- the supply basis for those exhibits is all the casinghead gas available on the west side of the Inlet. MR. HOWARD: Yes, sir, that is true. MR. MARSHALL: When we were discussing the alternate supply of gas, namely the gas supply from the Middle Kenai Gas Sands in the Trading Bay Unit, which were represented to be about 25 million cubic feet per day, we are not including the potential supply of dry gas that could be derived from the Trading Bay Field into that figure -- is that correct? MR. HOWARD: No, sir, that's correct. There are no dry gas reserves nor costs included in these analyses. These relate only to the casinghead gas and it is the total casinghead gas that is available on the west side. MR. MARSHALL: Yes, fine. And, additionally, the 25 million cubic feet per day figure of dry gas derived from the Trading Bay Unit does not include the Trading Bay Field, which lies up to the north. MR. HOWARD: The 25 million deliverability ability that we mentioned earlier related to three gas wells, one of which is located on each of the three Trading Bay Unit Platforms, and it does not have any reference to the Trading Bay Field. MR ~ MARSHALL: Thank you. UMIDENTIFIED VOICE: Mr. Burrell, how about if I make a statement -- MR. BURRELL: Would you come up here so we can get your name in, get you -69- on the recorder? BUD ISAACS: This is Bud Isaacs again. I testified yesterday in behalf of the Trading Bay Field. There are no dry gas reserves in the Trading Bay Field, as we stated yesterday, to our knowledge. It's all associated gas. MR. MARSHALL: I see. Thank you. MR. BURRELL: Thank you, Mr. Isaacs. Are there any additional questions of Mr. Howard? Does anybody in the audience have any questions of Mr. Howard? Thank you, Mr. Howard. MR. BEVAN: Mr. Chairman, I would like to present Mr. Bradford, who will also discuss marketing problems, and therefore will need no qualifications. MR. BURRELL: He will not have to be qualified as an expert witness to discuss marketing. MR. BRADFORD: Mr. Chairman-- MR..MARSHALL: Stand and raise your right hand. In the matter now at hearing do you swear to tell the truth, the whole truth and nothing but the truth, so help you, God? MR. BRADFORD: I do. Mr. Chairman, I am W. L. Bradford, Regional Gas Manager, Western Region, Union Oil Company of California. My decision to testify today, although it had not been planned, was keyed by Mr. MarshallVs very legitimate question: "Have the operators, in good faith, actually sought to market this gas?" I appeared before the Commission in about February 1968 and reviewed with you at that time what efforts we had made, the markets we had sought and where we thought we were going. I think the timing is very good that we go through another such session. At that time, in 1968, we told of studies to lay a line from the west side to the east side, around the north, very similar to the Marathon exhibit. One of the values, of course, -70- of taking the gas to the east side besides the more potential possibilities of sale, is the value of an extraction plant being preferably located on the east side. Our attention was directed there first. This takes us back to that point in time. I think we essentially wound up the testimony with the comment, based om the 25 million dollar cost as related to the then expected 100 billion per day of excess gas, no concrete way of getting that gas to a market place was apparent. We used other alternatives. We worked with other companies, particularly the operating companies in the Cook Inlet, and we did not develop any further technology or information which changed the figures and facts that we had at the time we talked to you. At this point, it was necessary to direct our attention back to our problems on the west side. A gasoline plant did look possible, although much more desirable on the east side. We proceeded to do the engineering to locate this plant on the west side. By the late summer of '68 we had the plant out for bid and were proceeding along that line. And as you know, the plant was built and is presently operating. While we were doing the engineering on the west side plant, we tried once again to locate a route to get this gas to the east side. Brown and Root of Houston looked at a course around the trench to the south; I believe we are all now familiar with this famous trench that we have been lying down the middle of Cook Inlet. But, again, the cost was over 15 million dollars and was not a suitable alternative. So, again, we completed the plant with no outlet for the remaining residue gas. We then looked to marketing propane, from West Foreland. We talked initially to the Japanese. -71- This finally fell through because they could not use anything less than a 30 thousand ton ship, which is approximately three months production for the plant, and required excessive storage. We also had a very serious engineering problem which we -- would have been necessary to come back to had we been able to get close to a market. The LPG would have to be pipelined to the Drift River Terminal. The storage would have to be refrigerated storage. We really did not have a technical answer, to how we would load refrigerated storage from onshore to a wharf that was several miles offshore. In December of '68, again while the plant was in progress in looking at ways to market propane, we contacted Florida Ocean Services. There was a development that was working successfully in the offshore Texas - Louisiana area, that of spooling the line instead of using a lay barge. We invited Florida Services - Ocean Services to look into our problem and come up and see if they could, economically, get first~ a small line across the Inlet for propane. This would circumvent the necessity of refrigerated loading problems and also the very difficult problems of the wharf at Drift River. There was also the possibility in doing this of tying this in with the other supply on the east side. Again, the cost was excessive for the job to be done. Partly due, I would say primarily due, to the fixed cost of moving in and out the large reels required for this type of a lay which would have to be built for the Job specifically. As it turned out, it was actually not less expensive than a conventional lay barge. We looked not only at the small line for the propane. We also investigated laying two larger lines, with the possibility that we could carry the residue gas over with propane without extraction on the west side. Again, the -72- cost exceeds those that we already had. Another problem that we didn't look into seriously until we got to the point where it became imminent, was that they continually said we could get the oil across, but there was no guarantee that it will stay in. As to the flare gas on the west side, we have looked at various plants. Although I notice in the orders, I mean the statutes, that carbon black plants aren't recommended, we did look into it to see if it would be feasible. They were not. Collier Carbon and Chemical made that investigation for us. We talked to the Borden Chemical people. We understood they were planning a plant on the west coast essentially for the production of methanol. We thought that with less expensive gas in Alaska, they could locate the plant up here with less expensive fuel, haul the methanol back to the west coast, and come out ahead. We directed to their attention both to the east side so that that spot would have C02 available for them in the manufacturing process. More particularly, we brought them over to the west side, had them fly around the west side with the hope that they could, with the least expensive gas which would be available from the west side, locate their plant over there. The west side decision was almost immediate. They had no way that they could put a plant that could operate on the west side. As the economics finally came out, they did not, even with the secondary advantages of wharfs, available CO2, they could not come out ahead, locating a plant in Alaska. As you see, on the propane itself we are going to be caught in the middle. There is too little for export, there ss too much for the existing Alaskan market. With propane, there still continues to be two possibilities. Sell to the local market, whatever they want, if they come and get it. Various -73- contacts along this line have been Uni-gas and Petrolane. Marathon is now discussing very seriously with Rock Island the marketing of this propane. The other alternative is to find ways, either in combination with other products or direct barging, of taking the propane out. Such sales are Hawaii, the West Coast, United States. We also recognized, as you pointed out earlier in the testimony, gas purchasing..~o~ transmission companies have begun to scratch pretty hard for gas in the south 48. Of course, coming to Alaska is much equivalent for their purposes as going to Equador, Indonesia, where-have you -- it's a long ways. But, we invited a large mid-continent ~ransmission company to come up and look into our problem. We had done a lot of work and come up with no answers, the thought being maybe with their broader expertise, and longer experience in, specifically, the pipelining business, they could find a way to get this gas economically across the Inlet. Unfortuuately, their answer didn't come out to be any better than ours. They were not interested. We had hoped that part of the incentive was that if they got in on the come, that they would certainly be in the best place for future development. It was not enough incentive. We have continued to be active in the potential supply of LNG. We have initiated discussions with Pacific Lighting, for example, and others in the industry. We did discuss with Pacific Lighting the flare gas. Pacific Lighting undertook a project to make their estimate of a line across the Inlet. Again, their independent study was much the same as ours. We feel at this time, that under the existing market conditions, we do not now see or in -74- the foreseeable future see, an outlet for the flared gas on the west side of the Inlet. I have one other little statement to make which Bill Howard covered very adequately on, let's see, Exhibit No. 2. The only thought that I had on that, outside of the problem that we all see, was it may correctly instead of being called calculated value of gas flared or dollar value of future gas to be flared, you might say the value of oil upon BTU equivalent, of gas flared. Something right in the title that is pulled out of the text and relates to exactly what it means. That does conclude my testimony, Mr. Chairman. MR. BURRELL: Thank you, Mr. Bradford. Mr. Bradford, are you still negotiating with a view towards liquifying the gas? M~. BRADFORD: Yes, we are. MR. BURRELL: And would these negotiations include casin~head gas that is being flared? MR. BRADFORD: We always include casinghead gas in our discussions. MR. BURREL~: Could you, just because I'm not too bright on this, even though this isn't arithmetic, could you tell me why nobody can build a plant on the west side? I know some~of~the reasons, I think, but I would like to hear it from you, your reasons why nobody has been willing to build a plant on the west side for any purpose, primarily for liquifaction, or anything else. MR. BRADFORD: I haven't been in the liquefaction budiness for a long while now, although I will make an attempt and it will be a problem because this will be my opinion. A liquefaction plant, particularly with any -75- liquefaction plant because you're talking export when you're talking liquefaction plant, would have to have tremendous reserves behind it and reserves not in billions or hundreds of billions of feet. I am sure that you would need 2 trillion feet, would be my guess as a minimum, and as you know, on the west side we're not even close to this. The only thing we can hope is that this gas, all the gas that a liquefaction plant needs, that this can he brought into it. Augmented. MR. BURRELL: So for that reason it would have to be on the east side because there is additional gas available on the east side. MR. BRADFORD: This is where large gas reserves are. MR. BURRELL: Of course, if somebody finds a new dry gas field on the west side or somethin~ like that, that would solve the problem, if it's big enough. MR. BRADFORD: If it's bis enough, it will be sold. MR, BURRELL: Mr. Marshall? MR. MARSHALL: Mr. Bradford, I was interested in your review of your efforts to find a market for petroleum liquids. I notice in a May 21 issue of the Oil Daily a small article which describes the Columbia gas systems proposed reforming plant to be built at Greensprings, Ohio, and this particular plant would produce 250 million cubic feet of pipeline quality gas from petroleum liquids. This is a very large volume of gas. I wonder if such a plant could be reduced in size and still be efficient or in other words, have you looked into any of the possible economics of reforming the petroleum -76- liquids to pipeline quality gas, specifically, as they may affect the reserves for the City of Anchorage contract. ~flt. BRADFORD: I have not looked into this possibility with reference to Alaska. I think that this general knowledge without a specific study would almost exclude it. There is one problem, the minimum break-even in those plants is usually 20,000 barrels per day and even at that, costs that they are trying to achieve are 80¢ an MCF. You can see with these figures we would not have the supply to install a break-even plant. Even if they did, they would exceed the present gas prices of the City of Anchorage. MR. BURRELL: Mr. Gilbreth, do you have any questions? MR. GILBRETH: Mr. Bradford, you mentioned that the shortage of reserves was one of the things that had precluded people from establishing a plant on the west side. Have you heard anything or do your studies or experience indicate an unfavorable situation from the standpoint of docking, loading, and things of this nature? MR. BRADFORD: Yes, that is part of it. MR. GILBRETH: Is it almost mandatory that any facility be at Drift River or below in the Inlet? MR. BRADFORD: When we looked at exporting programs~ first on the large scale, Drift River would have had the dock, but we looked all along the coast and there wouldn't have been a suitable dock. It became logical why they picked Drift River in the first place° Then when we were looking at the smaller sales where we could barge, we looked at bringing barges directly into the plant area, right at the Forelands, beaching them at high tide and -77- filling them. And this is more than likely the way they will take the small amount of propane out, but even there, it probably precluded bringing the barge in for at least three months of the year, due to ice and winter conditions. bRt. GILBRETH: Could you tell me, is the volume so small that it's not feasible to barge butane and propane to the south 48, in any way? MR. BRADFORD: Butanes are being carried to the south, and the oil now. The propane barging of this volume, it would probably be the transportation costs. MR. GILBRETH: Would it even be feasible if there were enough volume? MR. BRADFORD: If there was enough volume, I believe you'd go the ship route. MRo GILBRETH: It might be feasible, then. MR. BRADFORD: With adequate volume, yes. At this time I might, this touches on it, read a couple of paragraphs of this letter into the testimony, the May 4th hearings, the McBean & Associates, Calgary -- MR. BURRELL: You mean March 4? MR. B.RADFORD: March 4. I'm sorry. I had a telegram written into the record saying that they were ready, willing and able to pick propane and butanes up from the West Foreland facility, and this was, suffice it to say, quite a surprise to us. But since they didn't take the time to come to Anchorage~ we did go to Calgary to talk to McBean & Associates, and as very often happens at these things, I think what was our answer at the time, usually when these fellows find out the facts, we don't hear from them again. That's always the way it is the first time. And I submit this as an exhibit, if you desire. -78- Two sentences in here, I believe -- two paragraphs -- are the gist of it: '~We wish to withdraw our preliminary offer made to you in our letter of February 19, 1971, with respect to the purchase of propane for the West Foreland gas line for Alaska." I'm skipping the middle sentence. It Just says why they made the mistake. Final paragraph: ~We do not feel this plant yield is sufficient to warrant any substantial investment for marketing. If, however, in the future, through any new discoveries in that area, you find that gas plant production does increase to the figures we were looking for originally, we would most certainly appreciate a chance to make you an offer for the purchase of propane.~ Signed: McBean & Associates, W. A. McBean, Petroleum Engineer. MR. BURRELL: I would accept this letter into the record as Union Exhibit 1-A. Thank you. MR. GILBRETH: That was short offer, wasn't it? MR. B.RADFORD: It's always worthwhile, to chase these down, and this is what I want to impress you with, we always do. Because even though we don't feel the one that they are talking about -- conversation can sometimes be fruitful. I think we've evidenced lots of unique marketing, even on the Kenai side -- the hot houses, the little gas utility to generate power from the Sterling, etco I think we have been very aggressi've in our marketing practices and technique, and we don~t even leave the little ones behind. MR. BURRELL: Does anyone have any questions of Mr. Bradford? Does anybody in the audience have any questions of Mr. Bradford? I believe you are excused then, sir. I thank you very much. MR. BEVAN: That concludes our testimony, Mr. Chairman. MR. BURRELL: Thank you, Mr. Bevan. Mr. Bergquist, would you like to testify at this time, sir? -79- MR. MARSHALL: Please raise your right hand. In the matter now at hearing do you swear to tell the truth, the whole truth, and nothing but the truth, so help you God? MR. BERGQUIST: I do. MR. MARSHALL: Be seated. MR. BURRELL: Mr. Bergquist, would you state your position, who you work for, and what your title is? MR. BERGQUIST: My name is John F. Bergquist. I am Senior Energy Reserves Engineer for Pacific Lighting and Service Company. My business address is 720 West 8th Street, Los Angeles, California. MR. BURRELL: Thank you, sir. I know you Just came to Alaska to attend our hearings, but did you come here to look into any possibilities of liquefying any gas in Alaska by any chance? MR. BERGQUIST: Our company ha~ been involved in studying the possibilities of liquefying the gas in Alaska for shipment to southern California for a period of time, over two years. MR. BURRELL: Yes, the article in the Oil Daily,_ which I read into the record the first day of these hearings,was a statement by your company negotiating for Alaska gas for liquefaction and shipment to California. Would you say the Jones Act is somewhat of a financial problem in respect to this transaction? MR. BERGQUIST: I would certainly agree with that statement. It is not a precluding factor, we don't think. We hope to be able to obtain some form of relief from the penalties imposed by the Jones Act. MR. BURP. ELL: Are you -- uh -- attempting, in the course of negotiations, to get dedication of some gas reserves in Alaska? MR. BERGQUIST: Yes, that was the status of the negotiations at this -80- time, to attempt to obtain dedication of gas reserves. ~. BURP, ELL: If you were successful in consummating your negotiations today, would -- how long do you think it would be before you could have a plant on-stream? MR. BERGQUIST: That's a very difficult question. We would have to put our formal applications together for regulatory approval in both California and before the Federal Power Commission. Probably have to make some, at least preliminary arrangements for financing the project. Have to go through the regulatory hearing period, and there is, of course, the possibility of appeal by any interested party which could delay a final decision. Assuming it's approved then, you would have a construction period which might be anywhere from one to two years. So we are probably looking at three to four years, overall. MR. BURRELL: Well, the testimony to date indicates that most of this flare gas will be gone in three to four years. I presume that would play only a small part, if any, in your feed stock requirements. MR. BERGQUIST: I would have to agree with your statement. That might be only a very small part. MR. BURRELL: What can you think of that can be done to speed up this plant going on stream? How can you get it on stream tomorrow? MR. BERGQUIST: There is no way you can get it on tomorrow. You would have to go through the construction period even if you were able to get all the approvals and forms done in that short period of time. MR. BURRELL: There would be an absolute minimum of one year construction period and more likely one to two years. MR. BERGQUIST: I couldn't see it being less than two years. -81- MR. BURP. ELL: I thought I understood you to say before a construction period of one to two years. ~{. BERGQUIST: Well-- uh -- this is a question I'm not really certain of the answer and -- uh -- perhaps one year would be adequate. It could well be more if we -- some sort of problems come up. MR. BURRELL: Sure. Could you ship LNG over Drift River? If you had a plant over at Drift River, with that long pier out there? MR. BERGQUIST: Physically, it might be possible. However, I don't think that our company would intend to do that. MR. BURP, ELL: No, I know you intend to have a plant on the east side, if you build one at all. Physically, refrigeration difficulties could be solved if you shipped it out over a long pier like that. MR. BERC~QUIST: Well, there are costs associated with transporting LNG through pipelines and the cost goes up rapidly the longer the pipeline. However, the big problem that occurs to me immediately with Drift River side or the west side of the Cook Inlet is the problem with ice and putting an LNG tanker in there. I don't believe our company would do that at all unless the amount of gas available on that side was such that -- MR. BURRELL: I'm assuming that. I'm assuming that the gas were available there and that you were willing to build a plant on the west side. You could, physically, an LNG tanker could get into Drift River. It's no more sensitive than the other tankers, particularly, is it? Delicate, perhaps, is another way of putting it. MR. BERGQUIST: The tanker itself might not be. There could be problems with your storing LNG if your ship was delayed for any period of time from its normal schedule. -82- MR. BURRELL: Which has happened to Drift River. There have been ice problems that have kept tankers from landing. MR. BERGQUIST: That's one reason an ice-free port would be better. MR. BURP. ELL: Right. How about Valdez? MR. BERGQUIST: How much gas is available there? MR. BURRELL: I haven't noticed any. Does anybody here have any questions for Mr. Bergquist? MR. GILBRETH: Mr. Bergquist, in your present looking for gas, do you -- I assume you have some minimum quantity which you need to be able to create a market for gas. MR. BERGQUIST: Let me say -- when we first began considering the Cook Inlet as a source of gas for an LNG project, we desired to put together a project which would transport the equivalent of 500 million cubic feet per day to California. We have not been successful in obtaining the volume of gas reserves that would be necessary to support such a project for 20 years. At this time we are investigating the possibility of smaller projects. I don't have a minimum reserve figure to really pin down as to what quantity is required. I would expect that it certainly would be in excess of a trillion cubic feet. MR. GILBRETH: Can you tell me if the casinghead gas -- if the liquids were extracted here, or knocked out Just the normal liquids, without going through a regular butane/propane extractions -- would they meet your quality standards or would the gas have to go through a complete extraction process to meet your -- whatever your requirements might be? MR. BERGQUIST: The answer of that question would really depend upon the quality of the gas that we are buying for the LNG plan and, of course, we are interested in the methane. -83- MR. GILBRETH: Well, I know you have been through at least some of the hearings during the last two or three days, and the operators have testified about the composition of the gas and so forth. Are you interested Just primarily in the .methane and ethane? Are you interested in the butanes and propanes also? MR. BERGQUIST: We are interested primarily in the methane and ethane. MR. GILBRETH: For liquefaction? MR. BERGQUIST: Basically. MR. GILBRETH: If I understand you right, it would probably be necessary if casinghead gas even could be used for the purposes for which you are investigating, it would be necessary that it be -- well -- extracted or gone through a plant or treated before it would meet your requirements. MR. BERGQUIST: Mr. Gilbreth, it might depend on what sort of contracts are eventually negotiated with the producer. I believe physically that the heavier than ethane ends would be removed from the stream before it goes through the liquefaction process. MR. GILBRETH: I see. MR. BERGQUIST: Who eventually does it, I don't know at this time. MR. GILBRETH: But it could be done so it could be liquefied? MR. BERGQUIST: It would have to be done. MR. GILBRETH: Well, I mean the casinghead gas could be utilized for this purpose? MR. BERGQUIST: I see no reason it couldn't. MR. GILBRETH: That is what I was wondering. MR. BURRELL: Mr. Marshall? -84- ~IR. MARSHALL: Mr. Bergquist, did I understand you to say that you can utilize ethane in your liquefaction plants that you are contemplating? ~{. BERGQUIST: That's a technical question and I'm really not exactly certain of the answer. I understand there is some ethane that enters the liquefaction plants, in some cases depending on process or something, but the degree to which this occurs -- I couldn't give you a specific answer. ~%. ~ARSHALL: Did I get this clearly? You have not been able to find sufficient reserves to meet your approximately one trillion cubic foot require- ment? b~R. BERGQUIST: Well -- MR. MARSHALL: Is this another way of indicating that you feel that there is not a trillion cubic feet of uncommitted gas reserves? With what qualifica- tions would you inquire? MR. BERGQUIST: First, I would say that my statement was that our requirements -- our minimum requirement is probably in excess of a trillion cubic feet. Secondly, we certainly have not, as of this date, to my knowledge been able to conclude a contract for any portion of that volume in Cook Inlet. My own personal feeling is there probably is on the order something in excess of that in various phases, exactly where and how much in each place -- I don't know. MR. MARSHALL: I feel that I have sorta gotten to -- your face is becoming familiar here in Anchorage, ~{r. Bergquist -- over a period of years we have seen you here. This we are very happy about, and I noticed that you or members of your company are rather frequently seen in our town. Is the purchase of gas your principal business? MR. BERGQUIST: Yes. -85- MR. MARSHALL: That is in Anchorage, or Juneau? MR. BERGQUIST: Shall I say that the obtaining of a gas supply from Alaskan fields is our principal reason for being in Anchorage or Juneau. MR. MARSHALL: You-- I will put it this way-- are you introducing any factor in your gas sales plan for the purchase of yet undiscovered fields in Alaska? Does this fit into your program? MR. BERGQUIST: Well, as I said earlier, we started out with the desire to put together a project that would deliver the equipment, the 500 million cubic feet per day, and this is really still in the back of our mind. We would like to eventually get to size of transporting at least that volume from southern Alaska to southern California, if the gas is available. So, obviously, that would require the development of quite a bit of gas not Presently discovered. MR. MARSHALL: I see. And so that you have certain flexibility in your programming and planning for any liquefaction of Alaska gas, you are looking at a long range program where it would be a continuing program? In other words, the fact that it may not be available today does not preclude your plans if it were available next year or the following year? MR. BERGQUIST: No. We are still hopeful of putting together the project. MR. MARSHALL: Thank you very much. MR. BURRELL: Mr. Bergquist, would you tell me since this gas doesn't store very well -- liquefied gas is kind of expensive storage -- obviously, this isn't for peak load, this is for regular use? MR. BERGQUIST: This would be a base load project. MR. BURRELL: I think there is storage in the Los Angeles area. -86- MR. BERGQUIST: Yes, we have -- uh -- we have several underground storage reservoirs available to us at this time. MR. BURRELL: You wouldn't want to bring one up, would you? }{R. BERGQUIST: I don't think it would be possible. MR. BURRELL: Does anybody else have any questions? MR. GILBRETH: Just as a matter of curiosity, could you give me any idea what price Alaskan gas -- what range the price is going to have to fall into to be able to compete with the gas of the south 48, considering the Jones Act and liquefaction necessary and so forth? MR. BERGQUIST: I really don't think that I can since this would depend upon the size of the project we succeed in putting together. This has a -- certainly an effect on the price delivered in southern California, and how that equates with the other competitive prices. MR. BURRELL: Mr. Bergquist, can I follow up on that a little bit. I understand there is a contract to lay it down on the east coast from Algeria, LNG, although there have been some political difficulties over there, for 55¢. Does that sound like a reasonable or rational number for the west coast? MR. BERGQUIST: Well, I hope it would sound like one. I'm not sure that that's the right one. MR. BURP. ELL: Nor am I. But it could be? MR. BERGQUIST: It could be. It could be that area, right. MR. BURP, ELL: I have nothin§ further. Does anybody in the audience have any questions? Mr. Griffin? MR. GRIFFIN: Mr. Griffin, Union Oil Company. I wanted to, since this seems to be a day of mathematics, be sure I understood what you said, 3ohn. If you're looking for 500 million feet per day and extends over a 20 year -87- period, is my mathematics correct when I total about four trillion feet? MR. BERGQUIST: We would like to have that volume, yes. MR. GRIFFIN: Thank you. MR. BURRELL: I'll follow up Mr. Griffin's question. You did state that that was what you had originally hoped for and now you're willing to settle for considerably less? MR. BERGQUIST: We may have to settle for something less than that to begin with, but we hope to get more as time goes by. MR. BURRELL: We all do. Thank you very much, sir. Does anybody else in the audience have any questions? (NO RESPONSE) Thank you very much for coming. MR. BERGQUIST: Your welcome, sir. MR. BURRELL: Is there anybody else who wishes to testify or make a statement, or ask a question? (NO RESPONSE) We'll just adjourn, then. Thank you very much. -88- McARTHUR RIVER OIL FIELD Cook Inlet, Alaska OIL AND GAS PRODUCTION, OCTOBER 1967 THRU MARCH 1971 Pool Oil Estimated Value Based on Cumulative Production Payments for Royalty Oil ._ (Thousand Bbls.) (Thousand Dollars) (~as Produced Utilized FIared (MCF)., (MCF) .,. (%) (.M?F) ,(%) Hemlock 95,191 29,004,914 Middle Kenai 4,834 13,334,757' West Foreland 2,593 653,235 TOTAL 102,618 $274,832 42,992,906* 7,3-75,209* 17.2 35,617,697' 82.8 F"~ ACCEPTED ~ Il ~. ii ~UNSERVA,-ION TEE ~ Includes 10,320,666 ~CF Produced D~ Gas, 7,792,598 ~CF Flared D~ Gas, and 2,527,866 ~C~ Ht~l~zed D~ ~as. CALCULATED VALUE OF GAS FLARE Basis: Heat Content }{eat Value of Gas - BTU/CF 1,022 Heat Value of Oil - BTU/Bbl. 6,015,125 Volume (CF) Gas Equal to One Bbl. Crude (Heat Basis) 5,886 Current Gas Flared- MCF/D (March 1971) Heat Value of Gas Flared- Billion BTU/D Oil BTU Equivalent to Gas Flared - Bbl./D Average Price of Oil - S/Bbl. (March 1971)* Dollar Value of Gas Flared - $/D (March 1971) 30,900 31.580 5,250 $2.705 $14,201 Future Future Estimated Total Gas to be Flared - MMCF ** Oil BTU Equivalent to Future Gas to be Flared - Bbl. Dollar Value of Future Gas to be Flared 39,360 6,687,054 $18,088,481 * Field Crude Oil Posting at Pipeline Connection as of 3/31/71. ** Gas Volumes from Operators' Exhibits submitted for Conservation File No. 100 on March 4, 1971. i~C.~ ~o x ~o To ~ ,NCH ~6 l~Z~ .:.i ' ' .. -.. ALASKA PI PELI'_NE 'COMPANY ;_ ANNUAL GAS SALES HISTORY 1~ FORECAST ::~ z z EXHIBIT 1 MARATHON OIL COMPANY ECOHOMICS OF WEST SIDE TO ANCHORAGE PIPELINE TOTAL EXCESS GAS Total West Side Gas 1973- 1980 45,800,000 MCF Investment' Pipeline Compressors Sub Total Interest @ 6% on max. life of 8 years: Operating Cost: (Dehydration compression line maintenance 1 ' . Total Per Unit Cost: 1973 - 1980 Volume $29,900,000 45,800,000 MCF $16,100,000 5,700,000 ,8oo,ooo $ 6,000,000 2,100,000 $29,900,000 = $0.653/MCF laid down to Anchorage C,O. FILE c.o. CITY OF ANCHORAGE PROPOSAL AVAILABLE CASINGHEAD GAS WEST SIDE COOK INLET MAY1971 MARATHON OIL CO. EXHIBIT 2 6o 5O ESTIM, 20 265.8 6AS 1971 2 $ 4 5 6 7 8 9 1980 i 2, 3 4 5 6 7 8 9 1990 · EXHIBIT 3 MARATHON OIL COMPANY ECONOMICS OF WEST SIDE TO ANCHORAGE PIPELINE CITY OF' A~ICHORAGE MUNICIPAL POWER AND LIGHT DEPT. REQUIREMENT Total West Side Gas 1973 - 1980 23,300,000 MCF Investment: Pipeline Compressors Sub Total Interest @ 6% on max. life of 8 years: Operating Cost: (Dehydration, compression, line maintenance) Total Per Unit Cost: $20,660,000' 23,300,000 MCF $13,625,000 1,680,000 $15,305,000 $ 4,400,000 955,O00 $20,660,000 = $0.89/MCF laid down to Anchorage Date · ALASKA OILand G~.S CONSERVATION COMMITTEE ~~EXHIBIT - C,O. FiLE "Z:f0 ~ /0 EXHIBIT 4 MARATHON OIL COMPA~tY GAS QUALITY SPECIFICATIOiiS Chemical Components Oxygen Nitrogen Carbon Dioxi de Hydrogen Sulfide & Sulphur Methane Ethane Propane Max Heating Value BTU/Cu Ft Sp Gravity LEX R~sidue Vol % -0- 7.11 0.10 0.00 73.57 8.42 10.80 1169.4 .7214 City of Anchorage Vol % Less than 1.00 Less than 0.05 0 Greater than 99.0 Less than 0.15 Less than 0.05 lOlO 0.555 to 0.580 EXHIB IT 5 MARATHOi; OIL COMPANY ECONOMICS OF WEST SIDE TO EAST S I DE P I P EL I NE EXCESS GAS Total West Side Gas 1973 - 1980 45,800,000 MC F Investment: Pipeline Compressors Sub Total $16,450,000 5,120,000 2T2T757 ; ooo Interest @ 6% on max. life of 8 years: $ 5,930,000 Operating Cost: (Dehydration, compression, line maintenance). 2,100,000 Total $29,600,000 Per Unit Cost: $29,600,000 45,800,000 MCF = $0.646/MCF laid down to East Side Correcting for nitrogen and carbon dioxide @ 7.21% $0.646 = $0.696/MCF laid down to East Side .9279 Ij CONSERVATION COMt,,~iT'TF'E J! ]] ... C.O. FILE ~ ~0 ~/' ~ GAS LIFT COh~P~ESSOR PACKAGE $ UN~TS EACK OVER TANKS WATER INJECTION PACKAGE H£LIPAD DF~ILLING DECK LIVING QUARTERS SOLOR GA:~ L~I~T COMPR£SSOR PA(~KAGE · 4 UNITS GENERATOR $E'7S~ ~ .... 4 UNITS ~ DC GEN. SETS ~LU ~EAO DEAERATOR TOWERS DECK ,~, c,,~,, - ................... NO ,2 G~O$~ CO~ACTO~ D~IIV~NG WAT~FI~ SUB-~CK W~TE ~ T~ ~ c~ ~ .- ...... .... CRANE ..... ~.OI~AR TURBINES DRIVING WATER INJ[:CTION ...... kMI~ L L 14E-J~) ROOM ,13 BOOM ",, FLARE BOOM HEAD ~ Iii HEMLOCK S E PANATOR VAPOR RECOVERY Am C~E SS~ , , / ,~'MOTO~ C~TR~ CENTER ACCEPTED ,.-.. ALAS!<A O~L c,.'~d GAS ~ ",",.~,, ,. -4 . c.o. __ OPERAIIONS b. L. T£LEPHONE 40~ ,' 3006. 505 - 6TH STREET S.W. CALGARY I. ALBERTA April 26, 1971 Mr. Francis Barker, lk~arketfl~_ g Division, Union Oil Company of California, ZOO East Golf Road, Palatine, Illinois 60067. Dear Francis: Our File #71-15 %. ~ ,~,~ -- JJ CONSE~VA'~~r~-rC~ Westforeland Gas Plant - Alas'.[[~ C. 0. FILE ~ /~ Our Letter February 19, 1971 We wish to withdraw our preliminary offer made to you in our letter of February 19, 1971, with respect to the purchase of propane from the Westforeland Gas Plant in Alaska. At the time, we had erroneously been lead to believe that the current propane yield from the Plant was in the order of 4, 000 bbls/day and that this would diminish to approximately 1, 800 bbls/day 5 years hence. The figures that we were working with at the time were obtained from Marathon, and we were lead to believe that they represented 41% of the total. On further checking and subsequent to your visit to Calgary, we now find ~hat their figures represent the total production. " · . We do not feel that this plant yield is sufficient to warrant any substantial investment for marketing. If, however, in the future through any new discoveries in the area, you find that gas plant pro- duction does increase to the figures that we were.looking at originally, we would most certainly appreCiate a chance to make you an offer for the purchase of propane. . Yours truly, WAM: em c.c. Mr. J. Moore W. A. McBEAN & ASSOCIATES LTD. W. A. McBoan, P. Eng. R E C E 1 V E 1) A,Pt't 5 1971 ........ ~..~, ~.~ .... No. 103 ~,~mlo~. Oil ~'~ ~-~ ~-o~i~,i~ Oil PO01 I~ASKA OZL 7~-D GAS '-~ .... * ...... STATE OF ALASTJ~ Re: Ti-~Z ~,_~T~-.,, T,:~.:,~.,:~c,~,,-~. OiL ) ) hold. . a hearing to ) of an order affecting the ,~a of gas ) ) produced ~s ~,e ~esult of crude oil ) producing opera,ions i~ a.~rtain ) Cook %nIe~ oil fleIds ) Cons. e ~-vation ""¢" ~,~.±~ No. 105 Middle Gzonnd Shoal Field MGS "A"~ "C", "C"~ "D", "E", "F", ~nd "G" Oil Pools Cons~¢ation File i';o~ 102 ~d~a Xenai Oil Pool Consar~"a~ion Pile. No. 103 Trading Bay Field M~ddle Kenai "B", "C", "D" and ~:E" Oil Pools z~.=,~u~ Oil Pool "S" ~,~ Oil Pool ;,~:.,lo~, ~ Oil Pool Consez-¢aCio~ File No. 104 ~ l~d~e Xens~ "G" Oil Pool Hanlo~; Oil Poo% Wa~2 Foral~d Oil Pool TO: L. J =n~-~ YOU ~ COi~,.',~%'.'DED to appear in ~l-,.a City Libramy, 5~h Avenue" ' "F" .... ~'~" ;mg~oraga, ~=as,4~, on May 25, 26, 27, and 28, 1971. ~ 9:00 o'clock A. M., ~c so mane thereafter as the referenced ~ ........ ~- behalf of ~/~a Sta~e of Alaska in hearings may bo continued, ~o ,.,...,...~-y ~a ,, Fj~ASKA OIL ~ GAS CO~;RV~ION CO~DffTTEE Ch~an , ..... an~ by tendering 2o him ~a faa for '--'-- ' aa~;. ~ay at~¢nd~a%c~' and ~he ::~zcaga ~a.~.cr~beu by r~.a Rules governing the ad:ntr, is~ra:ion of al! Cour:m. 103 1971, .... SYATZ OF ;~ASi{A -o~,.,=: TP~ HOTIO?'T OF TIrE --Am%,~'e"* OiL ) =~i':D CAS CONSERV~JflON CO~.~IT~ to hold a ........... ~ c-~n~.,~r issu~ca ) produced a~ die zacul~ of cz~de oil ) ) producfuz operations in cert~n ) ) Cook inlet oil fields ~.~e No. 105 ~Xidd~a Ground Shoal ~" ' HCS '%"~ "g"~ "C"~ ;'D'~ "E"~ ~:F'~ ~d ~'O~' Oil Pao!s Csm.sarvatior~ File i.}o. 102 Granite Point Field Middle 'Kenal Oil Pool Conze~ation File No. 103 Trading B~M Field Hiddla Kanai "B", '~", "D", amd '~" Oil Pools H~lock Oil Pool 0~ Pool Hemlock I~E ~ ~ 0~. Pool ~'"~"~' No 104 ~ ~.~.~2nu~ ~'tv~- Yield ' ~df~e Kanai "G~' 0il Pool .H~!ogk Oil Pool Wes~ Forel~d Oil Pool SUB?OENA TO: D;J~E TEEL YOU I-2:3, "^' ~""~"-' '*" · · ~,u~.~.~-,~.,., =o appear in the City Council Chambers of the Z J Loussa~ Libra~7.~ Sth Ave~u~ ~a = Street, Anchorage, Alaska, om ~izy 25, 26~ 27~ and 1971, at 9~00 o'clock A. M,, ~d so long thereafter am ~he referenced hearings may be con~inued, ~o testify on ~eaamz of the ALA$16% O~ ~2D GAS CONSE~,,/ATiON CC2.-.2,fITTEE ..... ,.~:,,~:~.,~ ~o him the fee for each ray's at=endg%ce ~md the ,.;.=,.~<.,a ,~:~c.=~uu by ~ha Rules governing ~ha a~r,~nistratien of a~ Courts. , u, - : i 241 _ :".'ica l~e.2 s .... , Conservation File ~o, 103 O~ ~ 0tl Pool ~ "O' Oil ~oot Oil ~I ~orel~ Oil ~ooi ~~. to ~tify ~ ~f ~ the OIL ~le~ pt"im~~t by ~ ~s. lov~~ ~ ~i~etretion of ell Co. ts. ) ATJO GAS ~.~"~o~w~.',-~ produced n7 u,~.~ .c~,~ o~ crude oil producing opcratio~-~ in carta~: ) ) Cook Inle~ oil ~zc~.~ Conserca~ion ~,~!. No 105 Middle. Groined Shoal Field ifGS "A~' ':'~" ","" "~" "E" ~ ~ cma Oil Pools Con~ar¢ation File No. 103 "G" i~iZ Oil ,,~~,. ,,- Oil Pooi ~z~a~ze Kamai ~, Oil Pool ~anlock Oil ?os! Wesg ~orelmxd Oil Pool 5~PO~A .... ~ Alaska o~ .-~,~y 25 26, 27 anu nay Lacv,,~.~.~ .... ~-', ==~.x~y on b~h~f az the SCa~e of At~ka ~ ti:cna .,, GAS u~,d~,~,~ATION COMI4ITTEE and by ~cn,'-arxn$ to him t/~a fern for aaca day's at-~end~ca ~d the ~.ilcag~ prescribe4 by ~ha Rules ~overnz~ the a&-minisgration of all Courts. .... .. T o z al 0_ _ ~/. _~.~... . __ OIL A~-~ ¢;~ ~%,,~,~,RVAI~OJ CO).D~TTEE STATE OF AfJkSKA Ro: TF{E };u~IO,.i Oi? T~ ALASKA OiL ) ) ) hold a of ~ o's'doT pr~ucud ~ ~e rcsul= of c~de oil ) ) p~duc!~g ) Cook Inie= oil fields ) Consolation ?Jla No, 105 Middle G%~ound Shoal Fiuld ~:F" .... ~ "G" Oil G~anite Poin= Field ~ddia Kcn~ Oil Pool ConseTvntion File No. 103 Trading Bay Vieid ~,a ,~ Oil Pools ~~' Oil Pool ,~ Oil Pool Hemlock ~.. Oil Pool Conservation File No. 104 ~.~;u~,&e Kcna~ .- Oil Pool Hemlo~ Oil Pool Wesg Porelm~d Oil Pool Librax-y, 521: Avenue~.~ "F:' o °~.ca~'~ Anchorage, Al~ka, on ~y 25, 26, 27, and 28. 1971, ~x'a 9:00 o'clock A. 1.~., ~,d so long -cneraa×~er as ~m referenced conuinuc~ ~o tes'~ify on ~ ' ~= hearings uay be '~ * ', ~enm~ of i~%a S~atc of Alaska in ~:hasa hca~"ings, :-, OiL A'~D~.~ GAS C~.~v~IO~ CO}%[ITTEE Chai~:~n NOTICE OF PUBLIC HEARING STATE OF ALASKA DEPARTMENT OF NATURAL RESOURCES Alaska Oil and Gas Conservation Committee Conservation File No. 104 Re: McArthur River Field Middle Kenai "G" Oil Pool Hemlock Oil Pool West Foreland Oil Pool The Alaska Oil and Gas Conservation Committee will hold a hearing pursuant to Title 11, Alaska Administrative Code, Section 2009, to consider issuance of an order or orders, effective July 1, 1972, restricting the flaring or venting of casinghead gas from the referenced oil pools to the amount required for safety. The hearing will be held at 9:00 A. M. May 28, 1971 and so long thereafter as the hearing may be continued, in City Council chambers of the Z. J. Loussac Library, 5th Avenue and F Street, Anchorage, Alaska, at which time operators of the referenced pools and affected and interested parties will be heard. Evidence will be sought as to, but not limited to, the following: 1. Can excess casinghead gas be marketed, injected into any reservoir or pool, or otherwise beneficially utilized by July 1, 19727 2. Will the flaring or venting of casinghead gas after June 30, 1972 in excess of the amount required for safety constitute waste, as "waste" is defined in AS 31.05.170(11)? 3. Will more waste be caused than prevented by an order restricting production of oil to a rate whereby all produced casinghead gas is beneficially utilized or is required for a safety flare? Thomas R. Marshall, Jr. Executive Secretary Alaska Oil and Gas Conservation Committee 3001 Porcupine Drive Anchorage, Alaska 99504 Publish April 24, 1971 AFFIDAVIT OF PUBLICXTION STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT, ) ss. being first duly sworn on oath deposes and says that ................ is the .... .L_.e.-.~?..]:...C...]_..e.~.k.. .... of the Anchorage News, a daily news- paper. That said newspaper has been approved as a legal news- paper by the Third Judicial Court, Anchorage, Alaska, and it is now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all of said time was printed in an office maintained at the aforesaid place of publication of said news- paper. That the annexed is a true I.e~_~]. ?:!ot,-ice' 80~+0 copy of a ........... :.- ...................... as it was published in regular issues (and not in supplemental form) of said newspaper for. a period of ..... .Cz~e ...... insertions, commencing on the ....2.~ ..... day of ....~_?~-J:---]-- ........... ,19.7..]-.., and ending on the .... .2..~. .......... day of of ...~.~.r..~..l_ ................ , 19._.~..1_., both dates inclusive, and that such newspaper was regularly distributed to its subscribers dur- ing all of sa,id period. That the full amount of the fee charged for the foregoing publication is the sum of $ '16.,°5 which amount has been paid in full at the rate of 25¢ per line; Mini- mum charge $7.50. Subscribed arid sworn to before methis ~ damon. 19...~ ..... the State of Alaska, ~hird Division, A~horage, Alaska ff .: CO~I~ION EXPIRES ...... ....... zz, He~k.: ~: ,~. . - ' -:' -.::::: ~_-.:::.¥::..~... .. . ~ . '-~om, ~e~ene~ ~ ~ ~ I .~.'.a~g::~,~ h~Zd ~ !:~ . ~~:'~ ~ ~ ~whe~l J ter a ~-~ : - ~ · . , T%m~: ~.~ ~r~; Expunge . ~~OB ~mmi~ee ~~e, :~ka-: ~ i I