Summary With an active drilling program that was generating over 90,000 barrels of drilling waste each year, the THUMS Long Beach Unit in Wilmington Field, California, was spending over 3.5 million dollars per year to dewater and ship these solid wastes to on-shore landfills for disposal. In 1994, THUMS implemented an environmentally safe and economic program of hydraulic fracturing for the long-term, onsite disposal of drilling mud, drill cuttings, and tank bottoms. By reinjecting the drill cuttings downhole, transportation, the major portion of drilling waste disposal costs, was eliminated. This paper reviews the regulatory permitting process and addresses injection interval assessment, well candidate selection, fracture containment, and offset well seismic monitoring. The equipment, injection history, and economics of disposing over one million barrels of slurry over a 3-yr period are detailed.
Introduction The Wilmington Field, discovered in 1936, is the largest field in the Los Angeles Basin and the fourth largest oil field in the United States having produced over 2 billion of the estimated 3.1 billion bbls of oil originally in place. The Long Beach Unit (LBU) with 900 million bbls of oil in place covers 6,479 acres of the eastern portion of the field (Fig. 1—Geologic Setting of Long Beach Unit) underlying the downtown area of the City of Long Beach and the recreational offshore harbor area. Although production began in the western portion of Wilmington Field in the late 1930's, concern for surface-subsidence left the eastern portion of the field, including the LBU, undeveloped until the early 1960's when legislative and legal actions cleared the way for development under highly controlled conditions designed to protect the environment. The LBU is operated by the City of Long Beach (City) through its Department of Oil Properties with the California State Lands Commission (State) approving the plan of operations and budget, the bottomhole location of all new wells and other specific well details. As a result of competitive bidding, THUMS Long Beach Company (THUMS), originally a consortium of five major oil companies, Texaco, Humble (Exxon), Unocal, Mobil, and Shell, became field contractor for the Unit. Since production began at the LBU in 1965, over 1,300 wells, a quarter of those injection wells, have been directionally drilled from four manmade gravel islands and a landfilled pier located in the Port of Long Beach.
By the end of 1991, each of the five original THUMS stockholders had sold their shares to ARCO Long Beach Inc. (ALBI), a subsidiary of Atlantic Richfield Company (ARCO). In 1992, ARCO began the investment of more than $100 million in a new enhanced waterflood project for the Unit. THUMS' active drilling program was generating over 90,000 barrels of drilling waste per year. At that time, drilling wastes were being dewatered and shipped by truck to permitted landfills for disposal at a cost of over $3.5 million annually. By 1993, concerns over increasing cost and the availability of landfills to meet disposal requirements led THUMS to investigate alternative methods of waste disposal. ARCO and others were already employing onsite disposal of drill cuttings and other solid wastes in remote onshore areas such as the North Slope and in offshore operations in the Gulf of Mexico, North Sea, and Mediterranean. The success of these waste disposal efforts led THUMS to initiate their own program of hydraulic fracturing for the long-term disposal of slurrified nonhazardous drilling wastes.
Permit Application After investigating the regulations and a review of other operator's efforts in the area of waste disposal, an assessment was made for the need for information or approval from various regulatory agencies such as the Environmental Protection Agency (EPA), the State of California's Division of Oil, Gas and Geothermal Resources (DOG), and Department of Toxic Substances Control (DTSC), Regional Water Quality Control Board (RWQCB), and the Port of Long Beach. The State of California's Division of Oil, Gas and Geothermal Resources was determined to have primary regulatory responsibility for the disposal of drilling wastes. The first step in applying for an injection permit was to request that these nonhazardous slurrified drilling muds and cuttings be classified as Class II injection fluids. The State had previously determined that Diatomaceous Earth Filter Back wash and Drilling Mud Filtrate were Class II injection fluids. And since the primary components of the drilling mud and cuttings slurry were approved Class II liquids and native formation solids, the same Class II designation was requested for this slurry. Once the slurry was classified as a Class II fluid, a permit was applied for permission to inject those materials into a Class II water disposal well.
The permit was requested in April 1993 and approval received from the State in December of that year. A subsequent change in the requested injection interval required resubmission of the permit request and final approval was granted three months later in August 1994. A number of provisions were incorporated into the permit approval:The injection well must be completed with tubing and a packer set in cemented casing above the injection zone.
An ultrasonic cement inspection log (USI) must be run on the injection well to verify cement competency and bonding prior to injection.
Operating pressure must be accurately monitored and recorded on both the tubing and casing annulus of the injection well.
An accurate downhole gauge and recorder must be installed on the injection well.
The volume and density of the injected fluid must be monitored and recorded by a recording flow meter and recording densimeter.
All injection well gauges or measurement devices must be calibrated every six months.
The injection fluid must be held in impervious containers prior to injection.
Maximum allowable injection pressure gradient must not exceed the fracture gradient of the confining shale.