In the largest divestiture of federal property in the nation's history, Occidental Petroleum purchased the federal government's 78% interest in the immense Elk Hills petroleum reserve in February 1998 for $3.65 billion. Truly unique in California's San Joaquin Basin, Elk Hills is a light oil field with appreciable gas reserves. At the time the government handed Oxy the keys, about 1,000 wells were producing in the range of 55,000 barrels of oil and 400 million cubic feet of gas per day. The 49,000-acre Elk Hills Field has massive infrastructure, boasting the largest gas processing capacity west of New Mexico's San Juan Basin, a 47-megawatt cogeneration plant, and waterflood projects cycling 170,000 barrels of water per day. And, it's smack in the middle of one of the nation's most prolific petroleum basins. Just to the southeast lies Los Angeles and the burgeoning southern California energy market. "Elk Hills is a perfect energy hub," says Don Romine, general manager, Occidental of Elk Hills Inc. "The field is the largest single source of gas in the state of California, and one of the largest sources of light oil." President Taft created the Elk Hills Naval Petroleum Reserve in 1912, withdrawing the field from the public domain. Neighboring Buena Vista Hills was also designated a reserve that same year, and Wyoming's Teapot Dome was set aside in 1915. These proven oil deposits were intended as emergency fuel sources for the U.S. Navy. Elk Hills, an obvious surface anticline with oil seeps, had been deemed productive after a shallow Pliocene dry gas zone had been discovered in 1910 at a depth of 1,610 feet. But the mother lode, a deeper Pliocene reservoir dubbed the shallow oil zone, wasn't found until 1919 when Standard Oil Co. drilled on a school section that it had purchased 10 years earlier. Standard's Hay #1 flowed 200 barrels of light oil per day from a depth of 2,480 feet. The company was encouraged enough to drill additional wells, completing two more producers for 400 barrels and 850 barrels per day, respectively. The enormity of Elk Hills' accumulation was foreshadowed in July 1919 when Standard's Hay #7 blew out. The well flowed at an estimated rate of 50 million cubic feet of gas per day and burned wildly for almost a month before the flames could be extinguished. The Hay #7 produced 43 billion cubic feet of gas during the next seven years. In the early 1920s, the government's interest in the field was leased to Edward Doheny's <$iPan American Petroleum & Transport Co. > An infamous scandal soon erupted, however, over bribes allegedly paid to obtain the leasing rights on Elk Hills and its sister petroleum reserve, Teapot Dome. The U.S. Supreme Court, finding that the oil leases on the two reserves had been corruptly obtained, invalidated both the Elk Hills lease and the Teapot Dome lease in 1927. In 1944, after determining that the Elk Hills accumulation extended underneath adjoining property owned by Chevron (formerly Standard Oil of California), the government agreed to jointly develop the property with Chevron as a 22% partner. But, other than a brief spate of production near the close of World War II, Elk Hills lay fallow for about 30 years. Finally, the field was commercially developed in 1976. Peak production of 181,000 barrels of oil per day was reached in 1981. In September 1992, Elk Hills produced its one billionth barrel of oil. The Department of Energy grappled with several drawbacks in its long administration of Elk Hills. The revenues from the field, which totaled $13 billion, were deposited directly into the U.S. Treasury. Unlike a private firm, the DOE had to rely on appropriations from the government for capital budgets. The federal budget cycle meant that several years would typically pass between requests for funds and receipt of the money. Also, because of the annual fluctuations of government budgets, the DOE found it difficult to carry out long-term plans for the property. Further, the federal government's many policies regarding procurement of materials and equipment were unwieldy, and hampered the cost-effective operation of the field. What Oxy bought was an aging field that had not been managed in typical oil industry fashion. The reserves were indeed immense-in 1998, the company booked additions of 307 million barrels of oil and 708 billion cubic feet of gas from its Elk Hills purchase. But, to achieve its vision of creating a premier energy hub, Oxy faced a tremendous task. Its first priority upon possession of Elk Hills was gas sales. The company immediately began to construct a pipeline and drill wells. Says Romine, "The capacity to move gas off of Elk Hills was only about 100 million cubic feet per day, but the gas production was several times higher. Most of the production was being reinjected, and we wanted to sell substantially more gas." Oxy finished the 300-million-cubic-foot pipeline in six months, and by the end of 1998 it had tripled gas sales at the field. The new line runs west and provides outlets to the southern California markets, including the cogeneration projects at the mammoth heavy oil fields on the western side of the San Joaquin. Oxy is building a second line as well, this one capable of transporting 200 million per day to the east to provide interconnects to markets in northern California. "Oil prices were on their way down when we took over the field, and they continued in that direction," notes Romine. "Our strategy was to move more gas, and that worked out exceptionally well for us because California gas prices stayed very strong." Initially, Oxy brought five drilling rigs into Elk Hills; by the end of 1998 it was running eight rigs and 28 workover rigs. In its first year, the company drilled 140 wells and worked over 250 wells. For 1999, it expects to complete 100 wells and the same number again in 2000. The introduction of newer oilfield technologies has been a cornerstone of Oxy's management of the field. "One of the innovations we've introduced at Elk Hills is short- and intermediate-radius horizontal drilling," says Brian Casey, geoscience manager. The methods, well known in other parts of the Patch, had not been used in California before. Oxy experimented with the technique in its Northwest Stevens area, where a number of reservoirs displayed large gas caps and very narrow oil rims. "With this type of horizontal drilling, we could reenter old wells that were very closely spaced. That drove our costs way down versus vertical wells," he says. Oxy also preplanned its horizontal wells using 3-D visualization techniques, cutting expensive wellsite geosteering costs. "We did our geosteering ahead of the game, had it captured, then drilled the well according to plan. That saved us quite a bit of money on each hole." The company built 3-D earth models constrained with the well data, and then designed the well paths. "We make adjustments to the 3-D model as we drill, and each subsequent well is improved." In another Stevens area known as 26-R, Oxy was grappling with multiple, very steeply dipping reservoirs. Separate reservoir units featured separate gas, oil and water contacts. The company wanted to nail down the contacts exactly. "We reentered an existing well and drilled it obliquely down through the bedding, hitting each individual bedding unit," says Casey. "Then we could see the gas-oil-water contacts within that reservoir unit and the beds that we wanted to drill. We used the intermediate-radius technique to turn 90 degrees and drill laterals along strike." Today, Oxy drills most all of its Stevens wells as horizontals. Fracturing is another enhancement Oxy has added to Elk Hills. "When we took over the field, we were told that fracing was ineffective here for several reasons. Today, we effectively frac virtually every reservoir," says Casey. "Now, when we are working in an area with tight, poorer-quality rock, we can either drill and frac vertical wells or drill horizontal wells. In the western side of the field, we're trying both approaches in the shallow oil zone to determine which works best." Oxy also embarked on the first phase of a two-part, 145-square-mile 3-D seismic shoot over the field. The company started shooting on the less complex and more developed eastern limb of the field last year. At press time, the eastern shoot was complete and the company had begun shooting the western half. 3-D seismic already existed on portions of Elk Hills, but the quality of the data was poor. "Little pieces of data were pretty good, other pieces weren't even usable," says Romine. "We had several hurdles to overcome. The terrain is rough as a cob, and we have a shallow, weathered zone that really complicates the seismic as well." Nevertheless, Oxy ran several field trials with various contractors and succeeded in retrieving some excellent quality data. "We're just getting our first peek at the first phase of the 3-D program," says John Allen, technical services manager. "The seismic will allow us to define the reservoir in a way that hasn't been done before. We have the well control to tie the data down superbly to depths of 6,000 to 7,000 feet. We're especially interested in the stratigraphy of the shallow oil zone and Stevens reservoirs." Cost control has been an equally important emphasis. Oxy has established alliances with <$iNabors Drilling >, <$iHalliburton Energy Services > and <$iBrown & Root > for drilling, pumping and fracturing, and gas plant operations. "Our alliances have helped us to cut costs tremendously," says Romine. "In the first year of operations, we completed our drilling package for $63 per foot for a 3,000-foot well. That's in contrast to the industry average of $99 per foot in California." This year, Oxy has pushed costs down even further, and is drilling shallow oil zone wells for around $55 per foot. "Our operating and lifting costs are the same story," Romine says. "Before we took over, those costs were running $4.50 per barrel. We dropped that cost down to $1.89 per barrel the first year, and now we're down to $1.40 per barrel." Net to Oxy, Elk Hills now produces an average of 40,000 barrels of oil, 9,500 barrels of NGLs, and about 290 million cubic feet per day of natural gas. "We have opportunity at Elk Hills that we can't yet measure," says Allen. "As we understand the field better, we see more and more drilling opportunities. We think we can mitigate decline in the already producing reservoirs, and even pull up production. But the real opportunities are in the reservoirs that haven't been exploited yet." Casey agrees: "It's apparent to us that there are areas on the flanks within the boundaries of the field that look attractive for additional stepout drilling. We also believe that we have potential for deep gas objectives beneath the surface anticlines, similar to the East Lost Hills feature." "The infrastructure is capable of handling substantial growth," says Romine. "And the exploration potential of Elk Hills hasn't even been remotely tapped. We see tremendous opportunities here." And, in a key addition that will solidify Elk Hills as an integral player in the West Coast energy market, an Oxy power company subsidiary has plans to build a 500-megawatt, combined-cycle power plant at the field. This July, Oxy initiated the 12-month approval process for the state permit. "We're going to participate in the deregulated California power market," says Romine. "We will sell whatever form of energy has the greatest value." M Oxy's first priority upon taking possession of Elk Hills was to sell substantially more gas, says Don Romine, general manager, Occidental of Elk Hills. At far left, Oxy is building Elk Hills into a tremendous energy hub, capable of supplying energy in whatever form will fetch the greatest value. A BILLION-BARREL BEHEMOTH Elk Hills, named for the Tule elk that once frequented its dun-colored slopes, is an imposing surface anticline that covers an area five miles wide by 15 miles long. Cumulative production on the field totals 1.119 billion barrels of oil and 1.046 trillion cubic feet of gas. The petroleum accumulation is quite complex. The surface structure is underlain by at least three major anticlines at the Miocene Stevens level. A series of northeast-southwest trending normal faults cut almost vertically through the shallow oil zone, but sole out into the shales above the Stevens. And, a tremendous thrust fault lies below the Stevens. Crude production at Elk Hills comes mainly from the Pliocene shallow oil zone at depths of 3,000 feet and the Miocene Stevens at around 6,000 feet. Oil gravities range from the mid-20s in the shallow oil zone to the mid-30s in the Stevens. About two-thirds of the 3,000 wells sunk at Elk Hills have targeted the shallow oil zone; most of the remainder exploited the Stevens reservoirs. The production levels are the reverse, with a third flowing from the shallow oil zone and two thirds from the Stevens. The Miocene Carneros (Temblor) formation, target of the deep drilling near East Lost Hills, has produced about 110 million barrels of oil at Elk Hills. Elk Hills' substantial gas production comes from several sources as well. About 25 million cubic feet per day is produced from a dry gas zone in the Pliocene found at about 1,600 feet. Some 150 million cubic feet per day is recovered from a gas cap in a Stevens reservoir that is being blown down; the rest of the gas is associated with Stevens oil production. A 3-D seismic survey covering 145 square miles will reveal volumes about Elk Hills' complex structure and stratigraphy, says John Allen, technical services manager. cutline Geoscience manager Brian Casey notes that technologies such as horizontal drilling and 3-D visualization have proven quite effective at Elk Hills. People require numbered signs along the roadways to find their way in the rough terrain of the immense Elk Hills Field.