EOR oil production up slightly

Guntis Moritis
Production Editor

This photo shows piping at ARCO Alaska Inc.'s Kuparuk River unit on Alaska's North Slope. ARCO uses miscible hydrocarbon injectant to enhance oil production from the field. (Photo courtesy of Fisher-Rosemount Systems)

Worldwide oil production from enhanced oil and heavy oil projects, at the beginning of 1998, is about 2.3 million b/d, as shown in the Journal's exclusive biennial enhanced oil recovery (EOR) survey.

This rate is up slightly from the 2.2 million b/d at the beginning of 1996.

The 2.3 million b/d represents about 3.5% of the world's oil production.

The Journal's tabulation of EOR and in situ thermal heavy oil projects starts on p. 60. Mining and primary heavy recovery oil projects are discussed within this article.

The Journal's survey found U.S. EOR production increased by 5.0% from the previous survey, to 760,000 b/d (Tables B, C, and D). This rate equals 12% of U.S. total oil production that in 1997 averaged 6.4 million b/d (Fig. 1 [76,586 bytes] and Table 1 [60,106 bytes] and Table 2 [59,940 bytes])

Fig. 2 [60,636 bytes] clarifies the type and category of EOR projects covered in this survey.

The estimated 2.3 million b/d worldwide EOR and heavy oil production is based on the results from this survey and other published material and is broken down as follows: U.S.-760,000 b/d, Canada-400,000 b/d, China-280,000 b/d, former Soviet Union-200,000 b/d, and others-700,000 b/d.

Worldwide thermal recovery (steam or in situ combustion) is the dominant process and accounts for the 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, CO₂, and nitrogen) accounts for most of the remainder.

Carbon dioxide

Miscible carbon dioxide (CO ₂) activity continues to increase in the U.S. The production with this recovery method is up 4.9% from the previous survey and at the beginning of 1998 was about 179,000 b/d.

West Texas

The West Texas and New Mexico Permian basin with its existing CO ₂ infrastructure remains the center of activity. But new CO ₂ EOR projects remain a possibility for areas in California, Kansas, Oklahoma, and the Texas Panhandle.

Shell CO₂ Co. Ltd. continues to promote CO₂ flooding by providing innovative CO₂ sales agreements and technology assistance to independents that want to commence CO₂ EOR projects. According to Shell, the softness in oil prices during the first part of 1998 has delayed a number of independents that it has been working with from announcing new projects.

Shell CO₂ Co. Ltd. is a new limited partnership, owned 80% by Shell CO₂ Co. and 20% by Kinder Morgan Energy Partners L.P. Shell CO₂ Co. was formed last year 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 are 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 include Shell's interest in the DOE 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 CO₂ supply pipelines. The other line is from Sheep Mountain in Colorado, which delivers about 150 MMcfd of CO₂ to the Permian basin. Bravo Dome delivers about another 400 MMcfd of CO₂ to the region.

Kinder Morgan entered the CO₂ picture last year 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., is that "...new customers will no longer have to negotiate third-party pipeline arrangements for deliveries south of Denver City." The agreement does not affect existing transportation and sales agreements or third-party shippers, according to Bradley.

Shell says its current CO₂ producing capacity from McElmo Dome is about 920 MMscfd and it plans to increase capacity to 1.1 bcfd by the end of 1998. This expansion entails 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 is PetroSource Corp. It is building an 82-mile pipeline to move about 100 MMscfd of vented CO₂ from gas plants in the Val Verde basin to McCamey, Tex. At McCamey, the line ties into another CO₂ infrastructure.

PetroSource's line replaces a CO₂ line that was purchased from Canyon Reef Carriers Inc. by Delhi Gas Pipeline Corp. and converted to natural gas service.

Ridgeway Arizona Oil Corp. is another company entering the CO₂ supply picture. Its aim is to supply CO₂ to California oil producers.

It made its discovery in 1994 near St. Johns, Ariz., close to the New Mexico border. It says preliminary estimates indicate that CO₂ in place may be as much as 21 tcf.

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

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

Canada

In Canada, PanCanadian Petroleum Ltd. is evaluating initiating a miscible CO ₂ flood in the Weyburn field. PanCanadian estimates development cost of about $1 billion (Canadian) over 5-years. It expects 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.

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.

To overcome the high viscosity, bottom hole heaters had some success in the 1950s. But real success came when steam injection started in the 1960s.

Kern River now produces 136,000 b/d of oil from about 7,400 wells. But operators must bear the cost of disposing 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 four operators are: Texaco Inc. 95,000 b/d, Chevron Corp. 21,000 b/d, Aera Energy LLC 11,000 b/d, and ARCO Western Energy 2,500 b/d.

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

Cost for operating California steam floods has decreased. As an example, 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, translates to Chevron's producing costs dropping 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 may not be sufficient to keep these projects economic if oil prices remain as low as during March 1998, when Kern River 13° API gravity oil dropped into the $8/bbl range, about half of the price realized during March 1997. On a positive note, oil prices started to improve towards the end of March after recent announcements of production cutbacks by some of the main oil producing countries.

Cogeneration has helped some heavy oil projects to remain economic during low oil price periods. Tidelands Oil & Production Co. in its Wilmington steam flood, for instance, 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 will test steam injection in the Yates field in West Texas. One problem it faces is water quality because of the very hard produced water. Marathon plans for the 180-acre pilot to start in 1999.

The P.T. Caltex Indonesia-operated Duri field on Sumatra Island remains the world's largest steam flood. Although production from the field will not increase, oil sales will increase after Talisman (Corridor) Ltd. completes a 325-mile pipeline to Duri from gas fields in South Sumatra. The transported gas will displace about 50,000 bo/d currently being burned for steam generation. The project is scheduled to be completed in July 1998.

Hydrocarbon miscible

ARCO Alaska Inc. plans to initiate a hydrocarbon miscible project in its recently discovered Tarn field, on Alaska's North Slope. ARCO Alaska considers this accumulation to be a satellite field of the Kuparuk River unit.

ARCO plans to employ an EOR process initially as a key aspect of successfully 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 injects 22% carbon dioxide, 25% methane, 22% ethane, 26% propane, and 5% butane and heavier hydrocarbons.

But as reservoir pressure decreases, ARCO Alaska expects to reduce methane injection to maintain the 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 in Venezuela, produced with horizontal wells.

Bitumen and tar sand recovery in Canada and Venezuela is set to increase significantly. The Alberta Department of Energy estimates that production could triple by 2005 to about 1.5 million b/d from the current 500,000 b/d (Fig. 3 [48,311 bytes]). Table 3 lists announced projects.

In Venezuela, six joint venture agreements have been signed for exploiting the Orinoco tar sands. These projects might be producing 700,000 b/d of 8-9° API oil the early 2000s.

Canada

The Cold Lake area currently produces about 115,000 b/d (160,000 b/d of blended bitumen). In the next few years, Imperial expects to up this to about 150,000 b/d (210,000 b/d of blended bitumen).

To transport these increased quantities, Imperial (58%), Amoco (21%), and Koch (21%) plan a 150 mile, 36-in. pipeline from the Cold Lake area to the Hardisty, Alta., terminal and a smaller 12-in. pipeline to transport lighter hydrocarbon-liquid diluent from Hardisty to Cold Lake. Initial capacities of the two lines will be 330,000 b/d and 50,000 b/d, respectively.

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

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

Estimated project cost includes $1.2 billion for the Muskeg River mine, $0.4 billion for the Corridor pipeline, and $1.8 billion for the Scotford upgrader. Start-up is scheduled for 2002.

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

Syncrude Canada Ltd.'s mining operation is also expanding. It expects production to increase from 74 million bbl 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.

A Suncor Energy Inc. initiative for expanding its oil sand mining production is called "Project Millennium." The $2.2 billion (Canadian) project aims to increase plant capacity to 130,000 b/d by 2001 and then to 210,000 b/d in 2002 from the current 85,000 b/d.

Venezuela

Since allowing foreign investment in its marginally economic and/or undeveloped oil fields, a number of major heavy oil projects have been announced in Venezuela.

Petroleos de Venezuela SA (Pdvsa) has negotiated or is negotiating contracts with Conoco Inc., Mobil Corp., ARCO Corp., and Total Petroleum, Coastal Corp., and Exxon Corp. and their partners to exploit areas in the Orinoco tar sands.

These six synthetic crude projects are at various stages of being approved and could be producing about 700,000 b/d in a few years.

Venezuela contains about 289 billion bbl of recoverable heavy oil and EOR reserves.

The first project to be initiated, Petrozuata, a joint venture of Conoco Inc. and Pdvsa, will rely on horizontal wells to recover the heavy 9° API oil. Its recent well with 7,222 ft TMD and total displacement of 5,743 ft is the longest horizontal well drilled in Venezuela to date.

By yearend 1998, Petrozuata expects to complete 42 producing wells. It expects to finish its primary drilling program by mid-1999. Over the 35-year life of the project, about 530 horizontal wells are planned.

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

The Petrozuata project aims to recover 1.5-2 billion bbl of extra-heavy crude. The $2.4 billion project includes an upgrader to convert the diluted extra-heavy crude to a synthetic crude. The upgrader is under construction at Jose, Venezuela.

Another project is Total's Sincor project. This project also will rely on horizontal wells to produce about 200,000 b/d of 8-9° API crude, for a period of 35 years. As with other crudes from this area, the crude will be mixed with a diluent for shipment to Jose on the coast.

Total plans to process the crude diluent mix into 30° API, low-sulfur synthetic crude.

Overall project investment is estimated to be $2.7 billion. Production is to start in 2000.

Other countries

In 1995, China National Petroleum Corp. indicated it produced 152,000 b/d of heavy crude from 7,100 thermal recovery wells. The information listed from China as with some other countries remains the same because no updated information was 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 also adds that by 2000, after finishing the Daqing 50,000 tons/year polyacrylamide plant, polymer EOR could add an incremental production of 100,000-140,000 b/od.

Another country not responding is 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 are being mined in the Sarata Montiaru, Matita, and Slolont areas.

Romania's Supalcu de Barcau is the largest in situ combustion project in the world. In 1994, 507 wells produced about 8,800 b/d. Both air and steam are injected into the 33-52 ft thick reservoir that lies at a 115-772 ft depth.

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