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Home My WebLink About2004_AnnIntroState of Alaska Alaska Oil and Gas Conservation Commission 2004 Annual Report PREFACE The Alaska Oil and Gas Conservation Commission ("Commission") is an independent, quasi-judicial agency of the State of Alaska, established by the Alaska Oil and Gas Conservation Act (AS 31). Regulations adopted by the Commission can be found in Title 20, Chapter 25 of the Alaska Administrative Code. Our mission is to prevent physical waste of hydrocarbon resources, promote greater ultimate recovery, protect underground supplies of drinking water, and afford all owners of oil and gas rights an equal opportunity to recover their fair share of the resource. We accomplish this in two ways: 1) by regulating subsurface oil and gas drilling, development, production, reservoir depletion and metering operations on all lands in the exercise of the State's police powers, and 2) by compiling and maintaining drilling, completion, and production information for all wells within the State, and making the non -confidential portion of that information readily available to the public. The United States Environmental Protection Agency ("EPA") has delegated to the Commission primary responsibility for the Class II Underground Injection Control ("UIC") program in Alaska, which encompasses operations for enhanced oil recovery ("EOR") and underground disposal of oil field wastes. The Commission consists of three Commissioners, seven technical professional staff members, five field inspectors, and 12 support staff. Our annual budget is funded by the oil and gas companies operating in Alaska through an annual regulatory cost charge assessed pursuant to AS 31.05.093. In 2004, the Commission's budget amounted to slightly more than one cent per barrel of produced oil. To find out more about the Commission and the information we have available for the public, please visit our web site at www.aogcc.alaska.gov. INTRODUCTION The Commission is providing this annual report for the calendar year 2004 as a public service. It is intended to offer key administrative, engineering and geologic information on oil and gas operations throughout the State. This information may be used as a basis for preliminary engineering analyses of producing properties and development activities, and also for the development of analogs for exploratory projects. The contents of this report are abstracted from a wide variety of information from Alaskan petroleum exploration and development operations that the Commission routinely collects. We invite requests for additional information. ACTIVE AND INACTIVE POOLS The Commission maintains jurisdiction over all active and inactive oil and gas pools and disposal wells throughout the State. At the end of 2004, there were 56 oil pools, 60 gas pools, 4 source water pools and 28 disposal projects statewide. Of these, 42 oil pools, 39 gas pools, 3 source water pools and 24 disposal projects were active. In addition to production and disposal operations, there were 32 FOR projects underway in the operating oil pools, utilizing water, immiscible gas, or miscible gas as energizing fluids to improve resource recovery. Three new gas pools began regular production in 2004: OPERATOR GEOLOGIC BASIN FIELD RESERVOIR HC TYPE Aurora Gas, LLC Cook Inlet Albert Kaloa Undefined Gas Forest Oil Corporation Cook Inlet West Foreland Tyonek Undefined Gas Union Oil Company of California Cook Inlet Deep Creek Tyonek Undefined Gas One new source water supply pool began operation in 2004: OPERATOR GEOLOGIC BASIN FIELD RESERVOIR TYPE BP Exploration (Alaska) Inc. Arctic Slope Prudhoe Bay Ugnu Undefined Water Operations began in three new waste disposal pools in 2004: OPERATOR GEOLOGIC BASIN FIELD RESERVOIR TYPE Marathon Oil Company Cook Inlet Sterling Undefined Disposal Pelican Hill Oil and Gas Inc. Cook Inlet Iliamna* Undefined Disposal Union Oil Company of California Cook Inlet Deep Creek Undefined Disposal * Disposal injection into Iliamna #1 was limited to wastes generated during exploratory drilling of that same well. Iliamna #1 was plugged and abandoned in 2004. PRODUCTION During 2004, Alaska's oil and natural gas liquid ("NGL") average production rate dropped below 1 million barrels per day for the first time since 1977. Total oil and NGL production decreased 6.2% from 1,048,740 barrels per day in 2003 (382.8 million barrels total) to 984,150 barrels per day in 2004 (360.2 million barrels total). Oil production decreased 7% from 355.6 million barrels in 2003 to 332.4 million barrels. Part of the production decrease was caused by an unplanned, extended shut down of production from the Prudhoe Bay Unit ("PBU") during August and September. The total estimated impact was a deferral in production of 2.5 million barrels of oil. Another major impact on Alaska's production occurred during maintenance and upgrade of the Alpine Oil Field facilities, in the Colville River Unit ("CRU"), during July and August, which resulted in a 1.5 million barrel production deferral. Without these production interruptions, Alaska's daily average oil and NGL production rate would have been about 995,000 barrels per day, a decrease of 4.8% from 2003. NGL production increased slightly from 27.2 million barrels in 2003 to 27.8 million barrels in 2004, a gain of 2%. Natural gas production increased 2% to 3.7 trillion cubic feet, of which 3.2 trillion cubic feet (87%) were used for FOR purposes. Of the 515.6 billion cubic feet of remaining gas, 238.8 billion cubic feet (46%) were used to fuel oil and gas lease operations, 6.5 billion cubic feet (1 %) were consumed in flaring or as pilot/purge gas (0.2%), and 270.3 billion cubic feet (52%) were sold (a 2% increase in gas sales), mainly in south central Alaska. At year-end, Alaska's active wells (capable of production or those supporting oil or gas operations) totaled 3,988, an increase of 156 wells (4%) from 2003. These include 2,581 oil producers, 225 gas producers, 1,178 service wells (mostly injectors and water supply), and 4 gas storage wells. COOK INLET BASIN — SIGNIFICANT PRODUCTION CHANGES Cook Inlet oil production decreased 18% during 2004 to an average rate of 22,414 barrels per day, which was 2% of Alaska's daily oil production. Cook Inlet gas production increased by 1 %, from 568 million cubic feet per day ("MMCFD") in 2003 to 571 MMCFD in 2004. On the west side of Cook Inlet, Aurora Gas LLC ("Aurora") brought the Kaloa #2 gas well on-line in October, and during December 2004, this well averaged 4.8 MMCFD. Aurora also continued regular production from the Lone Creek #1 well, and for the last quarter of 2004, this well produced at an average rate of 5.1 MMCFD, a drop of 15% from the last quarter of 2003. For Aurora's Nicolai Creek Unit, production during the last quarter of 2004 averaged 2.3 MMCFD, a decrease of 53% from December of 2003. Forest Oil Corporation ("Forest") began producing a Tyonek Undefined gas pool from the West Foreland #2 well in December 2004. During its first month of production, West Foreland #2 averaged 3.4 MMCFD over 15 operating days. Alaska Oil & Gas Activity Exploration and Satellite 350 Developments 4500 t: o❑� 300 4000 3500 Approved 250 Permits 3000 �<J 200 + 2500 Y ❑Cookook Inlet , I — Active Reservoirs 150 2000 Prudhoe Bay and Kuparuk 1500 100 ° CAk - 1000 Active Wells 50 500 0 0 1950 1960 1970 1980 1990 2000 2010 On the Kenai Peninsula, production continued from Marathon Oil Company's ("Marathon") Falls Creek, Grassim Oskolkoff, and Susan Dionne Participating Areas ("PA"), all included within the Ninilchik Unit. During December, the Falls Creek PA produced an average of 12.5 MMCFD of gas, an increase of 7% over December 2003. For the Grassim Oskolkoff PA, December production averaged 6.6 MMCFD, a 50% decrease from one year ago. Production from the Susan Dionne PA was relatively steady over the past year, averaging about 10.3 MMCFD. On November 5th, Union Oil Company of California ("Unocal") began regular production from the Happy Valley gas field within the Deep Creek Unit, located on the southern portion of the Kenai Peninsula. During December, Happy Valley production averaged 4.9 MMCFD. On the West side of the Cook Inlet, Aurora began gas production from the Kaloa #2 well. During the last quarter of 2004, Kaloa #2 averaged 4.9 MMCFD. In July of 2004, Evergreen Resources (Alaska) Corporation ("Evergreen") curtailed pilot production from the Pioneer Unit coal bed methane ("CBM") project near Wasilla, Alaska. During September, Evergreen merged with Dallas -based Pioneer Natural Resources Company ("Pioneer"). At the end of September, Pioneer announced that it was releasing all existing shallow gas leases in the Matanuska-Susitna Borough acquired as part of its merger with Evergreen, and withdrawing exploration license applications made by Evergreen in August 2004. ARCTIC SLOPE — SIGNIFICANT PRODUCTION CHANGES On the Arctic Slope, oil and NGL production decreased 5% to an average of 961,738 barrels per day. PBU oil and NGL production declined by 9%, a loss of 44,715 barrels per day compared to 2003. Contributing to the production impact were: unplanned downtime at PBU Gathering Center #2 in August and September resulting in a two -week extension of a scheduled turnaround (for equipment repairs and upgrades), and numerous intermittent plant shutdowns over a three-week time period at PBU Gathering Center #1. The total estimated impact on Alaska's oil production was 2.5 million barrels. By mid -October, production from PBU was restored to its normal level. Production from the Kuparuk River Field, the second largest on the Arctic Slope, decreased by 7%, or 15,390 barrels per day during 2004. However, production from other Arctic Slope fields partially offset these losses. The Alpine Oil Field continued to improve: during 2004 Alpine averaged 98,895 barrels per day, an increase of slightly more than 1 % over 2003. During 2004, ConocoPhillips Alaska Inc. ("ConocoPhillips") and its partner Anadarko Petroleum Corporation completed Phase 1 of the Alpine Capacity Expansion Project ("ACX"), a project designed to increase water and gas handling capabilities. By December 2004, Alpine oil production had climbed to 115,923 barrels per day. Both companies have approved a second phase of the ACX project, which is scheduled for completion in 2005. Oil production from BP Exploration (Alaska) Inc.'s ("BP") Northstar Island increased 9% from 62,926 barrels per day in 2003 to 68,520 barrels per day in 2004. Combined production from Northstar and Alpine averaged 167,415 barrels per day, or about 17% of Alaska's total daily oil and NGL output. Since 2000, production from Alpine and Northstar has helped stabilize Alaska's daily oil and NGL production rate at about 1 million barrels per day. Shallower accumulations of more viscous oil (also referred to as "heavy oil") are becoming increasingly important to Alaska. Regular production of this shallower, colder, and more viscous oil has been established in the Orion and Polaris Pools within the PBU, the Schrader Bluff Pool within the Milne Point Unit ("MPU") and the Tabasco and West Sak Pools within the Kuparuk River Unit ("KRU"). During 2004, combined production from these five pools averaged 44,508 barrels per day, or 5% of Alaska's total oil output, which is a jump of 28% from 2003. Orion oil production rose from 1,008 BOPD in 2003 to 5,040 BOPD in 2004. The increase at Polaris was more modest: from 2,514 BOPD in 2003 to 2,717 BOPD in 2004. Petroleum News (October 31, 2004) reported that ConocoPhillips was investing $500 million dollars to expand production from the West Sak Oil Pool within the KRU. As a result of ConocoPhillips continued efforts, average daily West Sak production rose approximately 50%, from 7,804 BOPD in 2003 to 11,709 BOPD for 2004. By December 2004, West Sak production jumped to 17,072 BOPD. At Milne Point, Schrader Bluff oil production averaged 21,019 barrels per day, an increase of 10% over 2003. In 2004, the Schrader Bluff Oil Pool provided 41 % of the daily oil production from the MPU. Alaska's Average Daily Oil & NGL Production Rate 2,500,000 2,000,000 1,500,000 1,000,000 500,000 0 4- 1960 Colville River & Northstar Units Other Fields Kuparuk River Unit Prudhoe Bay Unit Cook Inlet 1965 1970 1975 1980 Year 1985 1990 1995 2000 During 2004, BP continued to test the limits of viscous oil drilling and production technology at Milne Point. In 2003, BP obtained the first sustained production from the vast, viscous oil resources trapped within the Ugnu Formation, producing a total of 2,212 barrels of oil. In 2004, oil recovered from the Ugnu increased to 14,534 barrels. UNDERGROUND INJECTION (UIC PROGRAM) The UIC Program gives the Commission and EPA the opportunity to ensure fluids injected into the subsurface are consistent with mandates provided in the Federal government's Safe Drinking Water Act and State of Alaska Statutes. The Commission maintains primacy for Class II injection wells, while EPA oversees the Class I UIC program. At year-end, there were 1,155 Class II UIC wells in Alaska: 1,088 were involved with enhanced oil recovery, 56 were engaged in disposal operations, and four were gas storage wells in the Swanson River Unit on the Kenai Peninsula. In addition, there were seven Class I, non -hazardous disposal injection wells located on the Arctic Slope: three at PBU, two at Northstar, and one each at the Colville River and Badami Units. ENHANCED RECOVERY INJECTION FOR and reservoir pressure management through water and gas injection continues to be a main driver in Alaska's sustained hydrocarbon production. A total of 1,088 water and gas injection wells actively supported oil and gas recovery during 2004, a 4% increase from 2003. Water injection for enhanced recovery operations totaled over 1.11 billion barrels (approximately 3.04 million barrels a day), a 10% increase from 2003. Approximately 3.2 trillion cubic feet (87% of the produced volume) of gas were reinjected in FOR projects throughout the State. During 2004, the Commission issued new or revised Area Injection Orders ("AIO's") that affected FOR injection programs in the Orion, Aurora, and Alpine Oil Pools. DISPOSAL INJECTION AND STORAGE INJECTION Underground injection has become one of the most successful and widely used practices for waste management in Alaska hydrocarbon development. It is driven primarily by operational efficiency and efforts to minimize surface impacts. Favorable subsurface conditions have contributed to the successes achieved to date. Class II wastes are predominantly produced water, cuttings and spent drilling mud. During 2004, 65.1 million barrels of waste (94% of the waste stream) were injected into Class II disposal wells, an 8% decrease from 2003. In addition, 4.3 million barrels (6% of the waste stream) were injected into Class I disposal wells. Historically, just 1.2% of total disposal has occurred in Class I wells; however, some fluids eligible for Class II have now been diverted to Class I at Northstar Island, which placed a second, Class I well in operation during 2004 (Northstar #32). During 2004, the Commission issued two Disposal Injection Orders ("DIO's") affecting underground injection of Class II wastes in the Deep Creek Unit, and at Iliamna No. 1 (Tyonek Formation). The Commission also issued a correction to the DIO 25, which governs Class II injection within the Sterling Unit No. 43-9 Well of the Sterling Unit Gas Field. Underground storage of gas was approved in three wells in the Swanson River Unit. From September through December of 2004, Unocal conducted storage injection operations in two of the three approved gas storage wells, Swanson River KGSF #1 and KGSF #3. A total of 753.2 million cubic feet of gas were injected into these wells over 189 operating days, and 448.3 million cubic feet of gas were produced over 86 operating days. PERMITTING The Commission approved 256 drilling permits during 2004, up 5% from 2003. Of these, 247 were new permits and 9 were revised permits. Exploratory and stratigraphic test wells accounted for 27 permits, while development and service wells totaled 229 permits. In addition, one permit was issued to re-enter and test an existing plugged and abandoned well. EXPLORATION AND STRATIGRAPHIC WELL PERMITS During 2004, 27 permits for exploratory and stratigraphic test wells were approved. Of these, 20 were for new wells, four were revised permits, one was for a re-entry of an existing well, and two approved permits were superseded. The 25 new, revised, and re-entry permits represent a 19% increase from 2003. In the Cook Inlet Basin, 15 permits were approved. Of these, Unocal received eight (four wildcat wells and four delineation wells: according to Commission regulations, exploration wells include those drilled to discover or delineate a pool). Marathon and Aurora received two permits each, Pelican Hill Oil and Gas Inc. ("Pelican Hill") received one, and Evergreen (which merged with Pioneer in September) permitted one stratigraphic test. Aurora also received one permit for re-entry of a previously plugged and abandoned well to test and possibly develop bypassed reserves. On the Arctic Slope, nine exploratory wells were permitted: ConocoPhillips permitted five, all of which were in the National Petroleum Reserve - Alaska ("NPR -A"); Total E&P USA, Inc. ("Total E&P") permitted one NPR -A exploratory well; and Kerr-McGee Corporation ("Kerr-McGee") permitted three wells in the state waters of the Beaufort Sea near Oliktok Point. In addition, the U.S. Bureau of Land Management ("BLM") received a permit to re-enter and deepen an existing well near Fort Yukon as a stratigraphic test. During 2004, the average approval time for a complete exploratory well permit application without special issues involving spacing, bonding, shallow drilling hazards, or shallow aquifers was seven and one-half working days. Exploration and Stratigraphic Test Permits Development, Service and Re -Entry Permits Marathon Aurora 2 Permits 3 Permits BLM Kerr-M( 3 Perrr ConocoPhillip 5 Permits Pioneer (Evergreen) 1 Permit Pelican Hill 1 Permit Total E&P 1 Permit Unocal 8 Permits Total = 25 Permits Arctic Slope = 9 Permits Cook Inlet = 15 Permits Fort Yukon = 1 Permit DEVELOPMENT AND SERVICE WELL PERMITS BP 141 Perry Unocal Marathon 7 Permits 9 Permits XTO )rest 'ermit Aurora 1 Permit ConocoPhillips 68 Permits Total = 229 Permits Arctic Slope = 209 Permits Cook Inlet = 20 Permits Development and service wells accounted for 229 drilling permits, a 4% increase over 2003. BP was the most active operator with 141 permits, followed by ConocoPhillips with 68, Marathon with nine, Unocal with seven, XTO with three, Aurora and Forest with one each. During 2004, the average approval time for a complete development and service well permit application was six working days. The Commission authorizes work on existing wells with sundry approvals. In 2004, the Commission received 496 applications. Of these, 429 were approved, an increase of 14% from 2003. Sixty of the applications were denied, three were cancelled, two were withdrawn and two were not used. The average approval time for a complete sundry application was four working days. DRILLING Statewide, 1,467,814 feet were drilled in 237 exploratory and development wells or well bore segments. This represents a 1 % increase in drilled footage from the 1,453,377 feet drilled in 226 wells during 2003. EXPLORATION WELLS In 2004, drilling operations were conducted on 23 exploratory wells: 14 in the Cook Inlet Basin, seven on the Arctic Slope and two in the Beaufort Sea. This compares with 28 exploratory wells drilled during 2003 (17 in the Cook Inlet Basin and 11 on the Arctic Slope). Total exploratory footage drilled within the State increased 40% to 160,306 feet. Arctic Slope exploratory drilling totaled 73,436 feet in 2004, an increase of over 80% from 2003. Cook Inlet exploratory drilling increased 17% to 86,870 feet during 2004, up from the 74,214 feet drilled in 2003. Exploration and Stratigraphic Wells Drilled Exploration and Stratigraphic Footage Drilled Total E&P Pelican Hill 1 Well 1 Well Auron 1 Well Anadarko 1 Well Kerr-McGee 2 Wells Pioneer (Ever( 5 Wells ConocoPhillips 5 Wells Total = 23 Wells Arctic Slope / Arctic Ocean = 9 Wells Cook Inlet = 14 Wells Total I Pioneer (Evergreen) Kerr-McGee ConocoPhi Aurora Anadarko 1\11—th— Pelican Hill Jnocal Total = 160,306' On the Arctic Slope, Kerr-McGee announced in March that it had tested 960 barrels per day of 38-degree API oil from the Sag River Formation in the Nikaitchuq #1 well drilled on Spy Island in the Beaufort Sea. The company also announced that a second well, Nikaitchuq #2 was a successful delineation test. In September, ConocoPhillips and Anadarko announced that the Carbon #1 well, drilled in the National Petroleum Reserve -Alaska ("NPR -A") flowed gas at a rate of 24 MMCFD and 1,250 barrels of 59-degree API condensate per day from an unstimulated Upper Jurassic reservoir. They also announced that the Spark #4 well, drilled three miles northeast of Carbon #1, penetrated a similar hydrocarbon -bearing reservoir, but the well was not tested. In the Cook Inlet Basin, Unocal continued delineation of the Happy Valley area on the southern Kenai Peninsula, drilling the Happy Valley #3, #4, and #6 wells. Approximately 8 miles to the southwest, Unocal also drilled the Star #1 exploratory well. In November, Unocal announced that this well had tested gas from the Tyonek Formation at a rate of 500,000 cubic feet per day. Eleven miles south of the Happy Valley drill site, Unocal also completed the Red #1 exploration well, but no test results have been announced. Also in November, Pelican Hill announced that Iliamna #1, located onshore near the Trading Bay Production Facility, was a dry hole, and that they would begin operations on N. Beluga #1 later that month. From January through April, Evergreen drilled, then plugged and abandoned five stratigraphic test well bores in the Wasilla — Houston portion of the Matanuska-Susitna Valley. DEVELOPMENT AND SERVICE WELLS During 2004, 1,311,343 feet were drilled in 214 development and service wells: 175,777 feet in 22 wells in the Cook Inlet Basin and 1,135,666 feet in 192 wells on the Arctic Slope. This represents a decrease of 2% in the total footage drilled compared with 2003. Cook Inlet Development and Service Wells - Drilled Forest 1 Sidetracked Well Unocal XTO 2 Sidetracked Wells Marathon 10 New Wells Arctic Slope Development and Service Wells - Drilled L,rAi I ozal = 61 Wells 9 Sidetrac Wells 29 New Wells 24 Multi Wellb 23 Multilateral Wellbores nr Total = 22 Wells Total = 192 Wells BPXA Total = 131 Wells tracked Its In the Cook Inlet Basin, during 2004, development drilling was limited to a total of 19 new wells at West Foreland, Redoubt, Beaver Creek, Kenai Beluga, Cannery Loop, Happy Valley, and Swanson River. Two sidetracked wells were drilled at Middle Ground Shoal. Two service wells were drilled in the Cook Inlet Basin: one new well and one sidetrack well. Both will be used for gas storage within the Swanson River Unit. On the Arctic Slope, BP and ConocoPhillips drilled 192 development and service wells: 65 new wells, 80 sidetracks and 47 multilateral well bore sections. BP was the most active operator, drilling 131 wells. Ninety-three development and service wells and well bores were drilled in the PBU. Of these, only 18 were new wells, with the remaining 75 consisting of 64 sidetracked wells and 11 multilateral well bores used to develop additional reserves from Alaska's maturing Arctic Slope fields. BP continued development at MPU with drilling operations in 32 wells and well bore segments: 15 new wells, 4 sidetracked wells and 13 multilateral well bores. Most of the drilling within the MPU was intended to develop Schrader Bluff reserves. BP drilled three new wells from Northstar Island in the Beaufort Sea: one development well and two service wells. BP also drilled four sidetracks at Duck Island (Endicott) and two sidetracks at Point McIntyre. ConocoPhillips drilled 61 Arctic Slope development and service wells and well bores during 2004: 43 within the KRU (15 new wells, nine sidetracks and 19 multilaterals) and 18 within the CRU (14 new wells and four multilaterals). One-third of ConocoPhillips' 2004 drilling program (20 wells and well bores) tapped reserves in the West Sak sands, including five "tri-lateral" wells (one new well with two multilateral well bore segments) and two "dual -lateral" wells (one new well with one multilateral well bore segment) drilled from the 1 E-Pad. FIELD INSPECTIONS During 2004, the Commission's Petroleum Inspectors witnessed 18 of 73 diverter tests (25%) and 119 of 569 blowout prevention equipment ("BOPE") tests (21 %). Initial BOPE tests were witnessed on 4 of 7 remote exploratory wells (57%), and 15 of 17 (88%) initial BOPE tests were witnessed on rigs that started operations after extended shut down or long rig moves. Inspectors conducted 131 rig inspections and 2,090 wellhead and well house system inspections. Inspectors witnessed 2,131 of 5,093 safety valve system tests (42%) and 239 of 331 mechanical integrity tests (72%). Abandonment operations were witnessed by the Commission on 2 of 5 remote exploratory wells within the NPR -A, while BLM representatives witnessed critical plugs in the other three NPR -A wells. Plugging activities were also witnessed on 7 other wells within the State during 2004. Twenty location clearance inspections were conducted during 2004, including three abandoned exploratory well locations. Commission Inspectors witnessed 19 of 32 scheduled gas meter calibrations statewide. Commission Inspectors also witnessed 131 oil meter provings, 105 of which were on the Arctic Slope. Field inspection statistics are presented in Section 11 of this report (Field Inspection Program). COMMISSION ACCOMPLISHMENTS During 2004, the Commission processed 264 applications for permits to drill, 493 sundry approval applications, 645 sundry reports, and 425 well completion or re -completion reports. The Commission issued 79 new Orders, amended Orders, and Administrative Approvals that affect oil and gas production or development drilling. We also issued one Regulatory Cost -Charge order. The Commission issued three enforcement actions: one for the Prudhoe Bay Unit A-22 well incident (penalty $717,112), one concerning the Prudhoe Bay Unit H-11 well (penalty $102,500), and one for excessive flaring (penalty $1,383.12). We also investigated the interruption of production during August and September at PBU Gathering Centers #1 and #2 by reviewing numerous sources of data, and performing field inspections, site visits and interviews. By year-end, the cumulative number of orders and administrative approvals issued by the Commission reached 1,475: 1,298 Conservation Orders ("CO's") and Administrative Approvals, 88 AIO's, 45 DIO's, 11 Aquifer Exemption Orders, 6 Storage Injection Orders, 2 Enhanced Recovery Injection Orders, and 25 miscellaneous ("Other") Orders. Of these, 819 orders and administrative approvals are active. The following chart displays the level of Commission regulatory activities on an annual basis. Note that CO's concerning flaring abruptly ceased after 1994, due to a 1995 change in gas disposition regulation 20 AAC 25.235. 90 80 70 60 d N N N 50 d v O w 0 40 E z 30 20 10 0 Alaska Oil and Gas Conservation Commission - Order History 1958 1963 1968 1973 1978 1983 1988 1993 1998 2003 As part of the Commission's efforts to protect underground sources of fresh water and to eliminate orphaned wells, our Senior Staff arranged for the plugging and abandonment of five shallow, coal bed methane wells located in the Matanuska-Susitna Valley. The Commission requires all applicants for permits to drill oil and gas wells in Alaska to post a bond, which insures that all wells will be drilled, operated, maintained and abandoned in accordance with the requirements of the Alaska Administrative Code. Alaska has had a very low rate of failed oil and gas operators. However, in this case, the operator became insolvent, ceased operations, and the affected leases expired. The operator's bond was forfeited and used for plugging, abandonment and location clearance costs for all five wells. The Alaska Department of Natural Resources ("DNR") collected a similar bond from the operator to perform surface reclamation. The Commission and DNR coordinated closely with affected surface owners, including the Matanuska-Susitna Borough, to insure the wells were properly plugged and abandoned, and that the well sites were properly reclaimed. One of the primary functions of the Commission is dissemination of non -confidential well and production information to the public. During 2004, 748 people visited the Commission, 271 visited the library or members of our staff to request information, and we responded to 567 additional requests for information. Our web site, available at http:/www.aogcc.alaska.gov, has been newly upgraded and expanded. On October 1st, the Commission implemented two new web applications. The Well and Production Information application allows users to review and download public well and production data. Our WebLink® application allows immediate access to electronic images of each page of our 5,900 non -confidential well history files. Both applications are available at http://www.aogcc.alaska.gov/publicdb.htm. Instructional videos, frequently asked questions videos and supplemental lists are also included to facilitate self -training. From September through December of 2004, there were 12,755 new visitors to the Commission' web site and 10,514 follow-up visits. In the last quarter of 2004, following the release of our web applications, visits to our web site increased 19%, requests for information decreased by 23%, and library visitors decreased by 28%. Finally, to improve value of this report, it has been reformatted and expanded. Production, injection, disposal, and permitting data for several years have been included to reveal trends. Reserve values gleaned from non -confidential publications have been included to aid in assessment of Alaska's remaining oil and gas resources. Hyperlinks have been provided to allow users to access location maps, unit maps, structure maps, selected type logs, and listings of orders and references. Additional hyperlinks are also provided so users can review production, injection and disposal data in report form, for easy reading and printing, or as a tab -delimited text file, for easy downloading. The use of this technology will allow the Commission to update and improve this report continuously, and make it a much more valuable information resource. Suggestions for additional features or improvements are always welcome. FIELD AND POOL SUMMARY SHEETS The summary sheets presented herein provide information about development wells and regular commercial production operations in Alaska's known oil and gas fields. Each summary sheet offers a "snapshot" of development activities in a particular pool for the month of December 2004. Unless otherwise noted, the well and completion counts presented on these sheets include only development and service wells. Please review the "Data Origins and Limitations" statement provided at the beginning of the Field and Pool Summary Sheets section to avoid any potential misunderstanding of the different types of data presented. Additional limitations and comments are included on the individual sheets. John K. Norman Daniel T. Seamount, Jr. Cathy P. Foerster Commission Chair Commissioner Commissioner