OGJ SPECIAL EOR Survey and Analysis New technology, improved economics boost EOR hopes

Guntis Moritis
Production Editor

• Microbial Enhanced Oil Recovery[74840 bytes]

Estimated worldwide production from enhanced oil recovery projects (EOR) and heavy oil projects, at the beginning of 1996, was about 2.2 million b/d, according to the Journal's 13th exclusive biennial EOR survey.

This is about 3.6% of the world's oil production and compares to the previous survey's estimated 1.9 million b/d at the beginning of 1994.

The Journal's tabulation of EOR projects starts on p. 45.

The Journal's survey found U.S. EOR production increased by 2% from the previous survey, to 724,000 b/d (Tables F, G, and H). This rate equals 11% of U.S. total oil production that in 1995 averaged 6.54 million b/d.

The number of U.S. EOR projects has steadily decreased since 1986 and EOR production peaked in the 1992 survey (Fig. 1 [53851 bytes] and Tables 1 [47319 bytes] and 2 [43233 bytes]).

Fig. 2 [38572 bytes] clarifies the type and category of EOR projects covered in this survey.

The estimated 2.2 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.-724,000 b/d, Canada-515,000 b/d, China-166,000 b/d, FSU-200,000 b/d, and others-593,000 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 700,000 b/d EOR production is by thermal processes. Gas injection (light hydrocarbons, CO₂, and nitrogen) accounts for most of the remainder.

In Canada, excluding steam for recovering bitumen, light hydrocarbon injection dominates EOR processes, and production totals about 95,000 bo/d.

Carbon dioxide

Miscible carbon dioxide (CO₂) activity continues to increase in the U.S. Production is up 5.3% from the previous survey and is now over 170,000 b/d.

One catalyst increasing CO₂ activity is an effort to improve CO₂ sales from the sizable reserves existing in Colorado and New Mexico. Both Shell Western E&P and Mobil Exploration & Producing U.S. Inc. have actively promoted CO₂ sales from McElmo Dome, near Cortez, Colo., to other operators who can take advantage of the infrastructure existing in the Permian and Delaware basins of West Texas and New Mexico.

Shell and Mobil contend that improved reservoir simulation capabilities, changed reservoir management focus, and significant cost reductions allow even small projects to be economic. CO₂ floods, previously, were thought feasible primarily in large fields that benefit from economies of scale and often require substantial capital and operating cost outlays.

Shell estimates that CO₂ project costs, on a $/bbl of oil equivalent basis, have dramatically decreased to $10.25 in 1995 from $18.20 in 1985. Costs, 1985 vs. 1995, break down as follows:

• Capital-$1.50 vs. $0.80

• Operating expense- $5.00 vs. $2.60

• CO₂ purchase- $6.50 vs. $3.25

• Royalty, and production tax, property tax and insurance-$5.20 vs. $3.60.

In regard to CO₂ supply, Shell said deliveries from McElmo Dome, near Cortez, Colo., increased from about 600 MMscfd in 1995 to the current producing capacity of about 700 MMscfd. It attributes most of this increased demand to existing EOR projects.

One company injecting more CO₂ is Mobil, which says the additional CO₂ will accelerate, above previous plans, oil recovery from its CO₂ floods such as Salt Creek, Postle, and Slaughter.

Because of increased CO₂ injection, CO₂ supply is currently tight in the area. McElmo Dome and the two other major supply points, Bravo Dome in New Mexico and Sheep Mountain in Colorado, are said to be at capacity.

But with more investment, additional CO₂ could be provided. Shell estimates daily capacity of the 502-mile Cortez CO₂ pipeline from McElmo Dome to Denver City, Tex., is about 1 bcf, although reaching this volume will require additional investment in pump stations and drilling more CO₂ producing wells.

Even to maintain the present producing capacity of 700 MMscfd at McElmo Dome, Shell has had to workover wells, such as changing from 41/2-in. to 5-in. tubing, and has plans to drill additional CO₂ producing wells.

Shell and Mobil have been promoting "win/win" innovative financial packages to attract new CO₂ projects. Shell says the contract with Fina Oil & Chemical Co. at West Brahaney Unit (Table A) represents the first time an operator has traded CO₂ supply for a working interest in a field.

From the West Brahaney Unit, Fina expects to recover, with CO₂ injection, an additional 3 million bbl of oil and extend the life of the unit 10 years.

Amoco Producing Co. also has been involved with other operators in innovative contracts for CO₂ supply and engineering in West Texas. These contracts were for the El Mar field, now operated by Meridian Oil, and for the Orla Petco-operated East Ford that began CO₂ injection in 1995.

Shell says it is also close to signing a contract with another operator in the Delaware basin and is working on two other proposals.

Outside of West Texas and New Mexico, CO₂ flooding prospects have increased after completion of Transpetco Transportation Co.'s 120-mile, 12.75-in. CO₂ pipeline from Bravo Dome to Guymon, Okla. Mobil will purchase part of the CO₂ for its Postle flood, but Transpetco expects various other fields in the Oklahoma and Texas panhandles to buy the remainder of the pipeline's capacity (Table A).

Heavy oil

Increased primary bitumen and tar sands recovery in Canada and Venezuela is on the drawing boards. Mining projects by Syncrude Canada Inc. and Suncor Inc. have expansions and new project plans. A new mining project by Solv-ex Corp. has also been proposed. Imperial Oil Ltd. at Cold Lake and Amoco Canada Petroleum Co. Ltd. at Wolf Lake and Primrose have sizable expansion plans.

Canada

In the next few years, Imperial expects to be producing about 130,000 b/d at Cold Lake and Amoco 55,000 b/d at Wolf Lake and Primrose, up from the current 95,000 b/d and 10,000 b/d, respectively.

Syncrude's average daily production was 202,000 b/d. Good prices, averaging $18.40/bbl for syncrude sweet blend and continued cost reduction, from $10.57/bbl in 1994 to $9.34/bbl in 1995, are helping expansion plans. Syncrude has plans to increase production by about 15,000 b/d by 2000 and Suncor, by 2001, plans to be producing 105,000 b/d, up from 76,000 b/d in 1995. These two mining projects are not tabulated in the survey.

Some estimates expect Alberta's heavy oil sands production to eventually exceed 1.2 million b/d. Recoverable bitumen reserves in Alberta are estimated at 300 billion bbl.

Venezuela

In Venezuela Maraven SA, Lagoven SA, and Corpoven SA have negotiated or are negotiating contracts with Conoco Inc., Mobil Corp., Arco Corp., and Total Petroleum to exploit areas in the Orinoco tar sands.

These four synthetic crude projects are at various stages of being approved and could be producing about 600,000 b/d by 2000. Venezuela contains about 289 billion bbl of recoverable heavy oil and EOR reserves.

China

In 1995, China National Petroleum Corp. indicated it produced 152,000 b/d of heavy crude from 7,100 thermal recovery wells. This is the first OGJ EOR survey that includes China's projects. The four heavy oil production bases are Liaohe, Xinjiang, Shengli, and Henan. The heavy oil production represents 5% of China's 1995 production.

CNPC estimates proven geological heavy oil reserves of about 8.4 billion bbl in 70 discovered heavy oil fields.

Romania

In 1994, Petrom R.A., the Romanian national oil company, indicated that several in situ combustion and steam injection projects, started in 1964, 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.

The 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.

Tatarstan

Another country that did not respond to our survey, Tatarstan, has plans for steam injection in seven bitumen areas. The first project is planned to start in 1996, and it has forecast production of 17,000 b/d by 2015.

Prices

Prices for heavy oil are more attractive than in the past. At the beginning of 1994, Kern River 13^o API heavy oil price was just above $7, but during 1995 the price ranged from $13 to $15/bbl. In addition, heavy oil production costs have also decreased significantly. In Cold Lake, the 1986 costs were more than Canadian $7/bbl. These dropped to about $4.50/bbl in 1994. Likewise, costs for Texaco in Kern River dropped from $6.27/bbl in 1990 to $4.86 in 1994.

SAGD

Steam-assisted gravity drainage (SAGD) continues to be of interest to Canadian operators. One such innovative project, originally operated by the Alberta Oil Sands Technology & Research Authority (Aostra), extracts bitumen with dual horizontal wells drilled from a tunnel. In 1995, a new operator, Gibson Petroleum Co. Ltd., became operator of this underground test facility (UTF).

Phase A of the UTF started in 1987 with three pairs of 197-ft laterals. In Phase B, which started producing in December 1992, production from the longer laterals have averaged 2,000 b/d. To date, over 2 million bbl of 8^o API have been produced from the UTF site.

Phase B has recovered about 40% of the bitumen in place, and Gibson expects ultimate recovery will be about 60% of bitumen in place. Steam/oil ratios have been about 2.5.

In their next phase, Gibson will verify if SAGD wells drilled from the surface are more economical than wells from a tunnel. Gibson has drilled two pairs of wells, 295 ft apart. To place the upper lateral (Fig. 3 [58917 bytes]) a magnetic guidance tool, developed by Sperry Sun and Vector Magnetics kept the upper lateral about 16 ft above the lower one.

Gibson expects each pair of laterals to produce about 1,000 b/d.

Other processes

Although chemical and polymer flooding has waned for a number of years, China is starting new projects. Also, Microbial enhanced oil recovery (MEOR) seems to be attaining commercial success.

Microbial

Even though only two survey respondents described microbial EOR, one in the U.S. and one in China, there are indications that more MEOR projects are active. One such country is Romania with about nine experimental projects active in 1994.

Biodynamics Corp. (formerly Alpha Environmental Midcontinent Inc.), Oklahoma City, indicates having used MEOR processes in more than 2,000 wells over the past 9 years. It currently is involved in about 400 active projects. Biodynamics' targets have been single wells in primary phase of recovery, and waterfloods. It says customers have been able to qualify for U.S. enhanced oil recovery tax incentives.

Fig. 3 [58917 bytes] illustrates a typical MEOR process. Biodynamics estimates that incremental recovery with the process costs $2/bbl.

In another MEOR process, Alan Sheehy of the University of Canberra, Australia, says a new microbial process, Biological Oil Stimulation (BOS), is being used by a number of operators in the North Sea. As with the Biodynamics information, Sheehy did not provide a listing of the operators who are using the process.

Sheehy describes BOS as the use of microbes and nutrient substrates that occur naturally in virtually all petroleum reservoirs. Growth of indigenous and resident microbes is stimulated by the addition of minor amounts of the missing organic nutrients.

Polymer flooding

Although use of polymers for augmenting waterfloods in the U.S. has declined over the years, a number of international projects are under way.

Polymer flooding is being pursued by CNPC in the Daqing, Dagang, Shengli, Liaohe, and Jilin oil fields. CNPC expects that with polymers recovery of original oil in place will increase by 8-10%.

By 2000 the Daqing Petroleum Administration Bureau has indicated that 150,000-200,000 b/d may be produced with polymer flooding. Full-scale polymer operations are expected in 1997.

Tiorco Inc., Englewood, Colo., has installed an alkaline-surfactant-polymer waterflood chemical process and water injection facility for a pilot waterflood pattern in Xinjiang Petroleum Administration Bureau's (XPAB) operated Karamay reservoir, in the Junggar basin of northwest China.

Tiorco describes the field as shallow (depth about 2,200 ft), having viscous, light-to-heavy oil with very little natural energy to produce under primary recovery from the 96-ft thick producing zone. The field currently has 7,000 producing wells. About 35% of the original oil-in-place has been recovered.

AEA Technology, of the U.K., has completed a study for CNPC of polymer flooding in the Henan Petroleum Exploration Bureau's (HPEB) Shuanghe oil field. AEA's simulation indicated that polymer-augmented waterflooding would increase recovery by 4-9% of the oil-in-place. AEA's economics indicate that with western oil prices and polymer costs, the project would have a return on investment of 14-18%.

Tiorco has also commissioned two polymer systems at ONGC's polymer-augmented waterflood project in Ahmedabad, India.

Also not shown in the survey listing are six experimental and one commercial chemical flood in Romania.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.