International Petroleum Encyclopedia

PRODUCTION FROM ENHANCED oil and heavy oil projects around the world increased to 2.3 million b/d at the beginning of 1998 from 2.2 million b/d at the beginning of 1996, according to a semiannual survey by Oil & Gas Journal.

The 1998 figure represented 3.5% of global oil production.

The survey covers enhanced oil recovery (EOR) and in situ thermal heavy oil projects (Tables A-D). It excludes mining and primary heavy recovery oil projects, which are nevertheless discussed in this article.

According to the 1998 survey, U.S. EOR production increased by 5% from the 1996 survey to 760,000 b/d. This rate equals 12% of average U.S. total production in 1997 of 6.4 million b/d (Fig. 1 and Tables 1 and 2).

Fig. 2 shows types and categories of EOR projects covered in the survey.

The estimated 2.3 million b/d worldwide EOR and heavy oil production is based on this survey and other published material. It includes 760,000 b/d in the U.S., 400,000 b/d in Canada, 280,000 b/d in China, 200,000 b/d in the former Soviet Union, and 700,000 b/d in other areas.

The dominant process worldwide is thermal recovery (steam or in situ combustion). It accounts for production of about 1.3 million bo/d. In the U.S., about 60% of the EOR production is by thermal processes. Gas injection (light hydrocarbons, carbon dioxide, and nitrogen) accounts for most of the remainder.

Carbon dioxide

The 1998 survey reflected a sustained increase in miscible CO2 activity in the U.S. Production with this recovery method was up 4.9% from the previous survey at 179,000 b/d at the beginning of 1998.

West Texas

The West Texas and New Mexico Permian basin, which has substantial infrastructure, remained the center of CO2 activity. But new CO2 EOR projects were possibile for areas in California, Kansas, Oklahoma, and the Texas Panhandle.

Shell CO2 Co. Ltd. provided innovative CO2 sales agreements and technology assistance to independents wanting to commence CO2 EOR projects. According to Shell, depressed oil prices during 1998 prevented a number of independents from announcing new projects.

Shell CO2 Co. Ltd. is a limited partnership owned 80% by Shell CO2 Co. and 20% by Kinder Morgan Energy Partners L.P. Shell CO2 Co. was formed in 1997 after Shell Western E&P Inc. and Amoco Producing Inc. combined their Permian basin oil and gas properties (but not the CO2 source fields and pipelines) to form Altura Energy Ltd.

Shell CO2 Co.`s main assets in 1998 were its interest in the 500-mile Cortez pipeline and the McElmo Dome CO2 source field, which holds more than 10 tcf of CO2. Other assets included Shell`s interest in the Department of Energy Canyon CO2 source field in Colorado and the Bravo Dome CO2 source field in New Mexico as well as the Bravo Dome pipeline to Denver City, Tex.

The Cortez and Bravo Dome pipelines are two of the three major pipelines supplying CO2 to the Permian basin. The other line is from Sheep Mountain in Colorado, which delivers about 150 MMcfd of CO2. Bravo Dome in 1998 delivered about 400 MMcfd of CO2 to the region.

Kinder Morgan entered the CO2 picture in 1997 after purchasing the 140-mile Central basin pipeline from Enron Liquids Pipeline Co. The pipeline transports CO2 from Denver City, near the terminal for the Cortez, Bravo Dome, and Sheep Mountain pipelines, south to near McCamey, Tex.

One benefit of combining the assets, according to Tim Bradley, president of Shell CO2 Co. Ltd., was that "...new customers will no longer have to negotiate third-party pipeline arrangements for deliveries south of Denver City." The agreement did not affect existing transportation and sales agreements or third-party shippers, according to Bradley.

Shell said its CO2 producing capacity from McElmo Dome at the beginning of 1999 was 1.1 bcfd. During 1998, Shell increased McElmo Domes producing capacity by drilling two additional wells, debottlenecking the production facilities, and installing liners in producing wells so that wells can be produced up the casing.

Another new name in the CO2 supply picture in 1998 was a partnership consisting of PetroSource Corp. (47%), Mcnic Pipeline & Processing Co. (31%), and ARCO Permian (22%). The partnership in September 1998 completed installation of an 82-mile, 10-in. pipeline for moving vented CO2 from four gas plants in the Val Verde basin to the Canyon Reef Carriers Inc. CO2 pipeline. In September the line was delivering about 70 MMscfd CO2 to Altura`s Cogdale and South Cross Units.

Because PetroSource Corp. received CO2 from the gas plants at near atmospheric pressure, it incurred costs for leasing compression facilities from Canyon Reefs Carriers.

PetroSource`s line replaced a CO2 line purchased from Canyon Reef Carriers by Delhi Gas Pipeline Corp. and converted to natural gas service. Koch Industries Inc., which owns Delhi, and Altura announced plans for the possible conversion of this line back to CO2 service.

Ridgeway Arizona Oil Corp. also entered the CO2 supply picture. Its initial aim was to supply CO2 to California oil producers. But since a venture of PetroSource Corp. (60%) and Mcnic Pipeline & Processing Co. (40%) obtained the exclusive marketing rights to Ridgeway`s CO2, it indicated that the CO2 might be sold in West Texas instead.

Ridgeway made its discovery in 1994 near St. Johns, Ariz., close to the New Mexico border. Its preliminary estimates indicated that CO2 in place might be as much as 21 tcf.

Producing zones were at a relatively shallow 2,200-ft depth and had 400-690 psi bottom hole pressures.

Ridgeway initially planned a 509-mile pipeline to Bakersfield, Calif. Development of the CO2 source field would require drilling as many as 300 wells. Each well was expected to produce only about 2-3 MMcfd, much lower than the McElmo Dome wells.

Canada

In Canada, PanCanadian Petroleum Ltd. was engineering and planning facilities required for a miscible CO2 flood in the Weyburn field. PanCanadian estimated development cost of about $1 billion (Canadian) over 5 years. It expected to recover about 38% of the oil in place, or an additional 130 million bbl. This would increase recovery to 50% of oil in place.

CO2 for the Weyburn project would be delivered through a new 202-mile pipeline to be built by Dakota Gasification Co., Bismarck, N.D. The CO2 is a byproduct of DGC`s lignite coal-to-natural gas conversion process at its Great Plains coal gasification complex at Beulah, N.D.

In September 1998, DGC announced it was reviewing feasibility of the project. This review could delay the project, in which CO2 injection was scheduled for a Dec. 1, 1999, start.

Steam floods

Through thermal EOR, old fields, some discovered a century ago, still produce oil at significant rates.

California`s Kern River field, discovered in 1899 with a 40-ft deep, hand-dug well, produces a 13° gravity oil with a high viscosity of 1,500 cp at 70° F. and 33 cp at 220° F.

About 2 billion bbl remain in place in this 9,880-acre field, estimated to have had 3.5 billion bbl of original oil in place.

Bottom hole heaters had some success handling the high viscosity oil in the 1950s. But better performance came when steam injection started in the 1960s.

In 1998, Kern River produced 136,000 b/d of oil from about 7,400 wells. Operators had to bear the cost of disposing of 900,000 b/d of produced water and injecting the equivalent of 400,000 b/d of steam via about 2,000 injection wells.

Kern River`s main three operators were Texaco Inc. 95,000 b/d, Chevron Corp. 21,000 b/d, and Aera Energy LLC 13,500 b/d.

Texaco in 1997 bought Monterey Resources, a spinoff from Santa Fe Resources Inc. Aera Energy LLC was a combination of Shell Oil Co.`s CalResources LLC (58.6%) and Mobil Exploration & Production U.S. Inc. (41.4%).

The Aera production also included former ARCO Western Energy production. In 1998, Mobil exchanged some of its Gulf of Mexico properties for ARCO Western properties, which were to be operated by Aera.

The cost of operating California steam floods decreased. Chevron trimmed operating costs by reducing steam injection in its California operations to 172,000 b/d in 1996 from 233,000 b/d of cold water equivalent in 1993. Oil production fell only to 63,000 b/d from 68,000 b/d.

This, along with other cost reductions, cut Chevron`s producing costs to $4/bbl from $7.30/bbl in Kern River and to $5/bbl from $8/bbl in Coalinga, another California giant field under steam flood.

But even these lower costs were not sufficient to keep these projects economic if oil prices remained in the $8-9/bbl range.

Cogeneration helped some heavy oil projects remain economic during periods of low oil prices. Tidelands Oil & Production Co., in its Wilmington steam flood, received only $6.50/bbl at the beginning of March 1998. But because its steam prices were indexed to oil price, costs also decreased and kept the project economic.

In a new application for steam, Marathon was to test steam injection in the Yates field in West Texas. One problem it faced was water quality because of the very hard produced water. Marathon planned for the 180-acre pilot to start in 1999.

The P.T. Caltex Indonesia-operated Duri field on Sumatra Island remained the world`s largest steam flood. Although production from the field was not expected to increase, oil sales increased after Talisman (Corridor) Ltd. completed a 325-mile pipeline to Duri from gas fields in South Sumatra. The transported gas displaced about 50,000 bo/d being burned for steam generation.

Hydrocarbon miscible

ARCO Alaska Inc. planned to initiate a hydrocarbon miscible project in Tarn field on Alaska`s North Slope. ARCO Alaska considered this accumulation to be a satellite field of the Kuparuk River unit.

ARCO planned to employ an EOR process initially as a key aspect of producing the reservoir.

Hydrocarbon miscible injectant varies in quality depending on location and time. For instance, ARCO Alaska in the Prudhoe Bay hydrocarbon miscible project injected gas comprising 22% CO2, 25% methane, 22% ethane, 26% propane, and 5% butane and heavier hydrocarbons.

But as reservoir pressure decreased, ARCO Alaska expected to reduce methane injection to maintain miscibility of the injectant.

Heavy oil

Heavy oil is mined, recovered in situ with thermal recovery, and-as proposed for a number of heavy oil projects in the Orinoco region of Venezuela-produced with horizontal wells.

Recovery of bitumen and tar sand in Canada and Venezuela was set to increase. The Alberta Department of Energy estimated that production could triple by 2005 to 1.5 million b/d from 500,000 b/d in 1998 (Fig. 3). Table 3 lists announced projects.

In Venezuela, four joint venture agreements had been signed for exploiting the Orinoco tar sands. These agreements represented production of as much as 650,000 b/d of 8-9° API oil by the early 2000s.

Three other projects were being discussedl in 1998.

Canada

The Cold Lake area in 1998 produced about 115,000 b/d (160,000 b/d of blended bitumen). Imperial expects this rise to about 150,000 b/d (210,000 b/d of blended bitumen) in the following few years.

To transport the increased quantities, Imperial (58%), Amoco (21%), and Koch (21%) planned a 150 mile, 36-in. pipeline from the Cold Lake area to the Hardisty, Alta., terminal and a 12-in. pipeline to transport lighter hydrocarbon-liquid diluent from Hardisty to Cold Lake. Initial capacities were to be 330,000 b/d in the larger line and 50,000 b/d in the diluent line.

With additional pumping stations, Imperial said, the bitumen pipeline would have capacity of up to 700,000 b/d of blended bitumen. Pipeline construction for the $250 million project was planned for 1999, with operations to start in 2000.

In another large project, Shell Canada Ltd. and Broken Hill Proprietary Co. Ltd. (BHP) were proceeding with a feasibility study for a $3.6 billion (Canadian) project to mine bitumen from Lease 13, about 42 miles north of Fort McMurry, Alta. They planned to lay a 300-mile pipeline to Scotford and to build a 150,000 b/d hydrogen conversion process upgrader next to Shell`s Scotford refinery, near Edmonton.

The cost estimate included $1.2 billion for the Muskeg River mine, $400 million for the Corridor pipeline, and $1.8 billion for the Scotford upgrader. Start-up was scheduled for 2002.

Construction of a pilot plant on Lease 13 received regulator approval in January 1998.

Syncrude Canada Ltd.`s mining operation was expanding. The company expected production to increase from 74 million bbl/year in 1996 to 82 million bbl/year by 2000. Also, with the new Aurora Mine project, production would increase to 258,000 b/d by 2004 and 312,000 b/d in 2005.

Suncor Energy Inc. was to expand its oil sand mining production with an initiative called Project Millennium. The $2.2 billion (Canadian) project would increase plant capacity to 130,000 b/d by 2001 and then to 210,000 b/d in 2002 from 85,000 b/d in 1998.

Venezuela

Since allowing foreign investment in its marginally economic and undeveloped oil fields, the government of Venezuela had signed a number of major heavy oil projects.

Petroleos de Venezuela SA (Pdvsa) negotiated contracts with Ameriven SA (30% Arco, 30% Pdvsa, 20% Phillips, and 20% Texaco), the Petrozuata project (50.1% Conoco and 49.9% Pdvsa), the Sincor project (47% Total, 30% Pdvsa, and 15% Statoil), and the Cerro Negro project (41 2/3% Mobil, 41 2/3% Pdvsa, and 16 2/3% Veba Oel).

Coastal Corp., Exxon Corp., and BP Exploracion de Venezuela SA in 1998 were looking at operations in the tar sands.

These synthetic crude projects were at various stages of being approved in 1998 and were thought capable of producing about 650,000 b/d within a few years.

Venezuela contains about 289 billion bbl of recoverable heavy oil and other hydrocarbons technically recoverable by EOR.

Petrozuata started producing in September 1997 at the rate of 30,000 b/d. In the second half of 2000, production was expected to reach its 35-year plateau level of 120,000 b/d.

As proposed for the other joint ventures, Petrozuata relied on horizontal wells to recover the heavy 9-10° API oil. It expected to finish its primary drilling program by mid-1999. Over the life of the project, about 530 horizontal wells were planned.

Petrozuata chose horizontal wells without steam stimulation because technology advances allowed longer lateral wells to be drilled and completed at producing rates sufficient to make the project economic.

The Petrozuata project aimed to recover 1.5-2 billion bbl of extra-heavy crude. The $2.4 billion project included an upgrader to convert the diluted extra-heavy crude to a synthetic crude. The upgrader in 1998 was under construction at Jose, Venezuela, scheduled to start up in 2000.

Other countries

For 1997, China National Petroleum Corp. indicated it produced about 190,000 b/d of heavy crude from 9,000 thermal recovery wells. In the survey the information listed from China, as with some other countries, were unchanged from the prior survey because updates were not received.

Han Dakuang, Research Institute of Petroleum Exploration & Development, Beijing, said in his 1997 World Petroleum Congress presentation that by the end of 1995 China had about 120 EOR projects, producing about 280,000 bo/d. He said that by 2000, after completion of the Daqing 50,000 ton/year polyacrylamide plant, polymer EOR could add production of 100,000-140,000 b/od.

Another country not responding was Romania. In 1994, Petrom R.A., the Romanian national oil company, indicated that in situ combustion and steam injection projects were being operated in the Videle, Moreni, and Supalcu de Barcau areas. Also, three reservoirs were being mined in the Sarata Montiaru, Matita, and Slolont areas.

Romania`s Supalcu de Barcau was the largest in situ combustion project in the world in 1998. In 1994, 507 wells produced about 8,800 b/d. Both air and steam were injected into the 33-52 ft thick reservoir encountered at depths of 115-772.

In Asia, Tatarstan had plans for steam injection in seven bitumen areas. It forecast production of 17,000 b/d by 2015.

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Piping at Arco Alaska Inc.`s Kuparuk River unit on Alaska`s North Slope is part of a system that uses miscible hydrocarbon injectant to enhance oil production from the field. Photo courtesy of Fisher-Rosemount Systems.