CO2 FOR EOR IS PLENTIFUL BUT TIED TO OIL PRICE

Chuck Norman
CRS Services Inc.
Lakewood, Colo.

Development of the U.S. CO2, resources from the Rocky Mountain area are tied to West Texas and New Mexico Permian basin enhanced oil recovery projects and the price relationship of crude Oil to CO2.

Several general areas within the U.S. are known to contain in situ commercial grade CO2 deposits, including central Mississippi and a number of Rocky Mountain locations. However, the Rocky Mountain reserves constitute the vast majority of the known resource base. Table I provides statistics for CO2 deposits that supply the Permian basin oil fields, and the map (Fig. 1) shows the main CO2 pipelines.

The advantages of natural subsurface CO2 reserves are relative purity and a large resource base.

CO2 IN COLORADO

In Colorado, carbon dioxide was discovered by Continental Oil Co. (Conoco) in 1925 upon completion of the Sherman A-1 well in the North McCallum field in Jackson County.1 Other small reservoirs, too small to develop, were found in several Colorado counties, including Las Animas, Prowers, and Rio Blanco.

Two major CO2 reservoirs under development are: Sheep Mountain and McElmo Dome.

Sheep Mountain, western Huerfano County, was discovered in 1972 by Atlantic Richfield Co. (ARCO) while exploring for natural gas. ARCO and Exxon Corp. have jointly developed the Sheep Mountain Unit. In early 1983, the ARCO-operated unit began moving CO2 by pipeline to the Seminole San Andres unit in the West Texas Permian basin.

The largest Colorado CO2 deposit is the McElmo Dome Unit in Dolores and Montezuma counties. Full scale CO2 production started in late 1983, after unitization of several large tracts and upon completion of the 500 mile Cortez pipeline to Permian basin oil fields.

Shell Western Exploration & Production Inc. operates the McElmo Dome CO2 production and gathering facilities. Other interest owners include Mobil Oil Corp. and Chevron Corp., as well as several other companies. Shell and Mobil also have significant ownership interests in the Cortez pipeline and several of the Permian basin oil fields receiving McElmo Dome CO2.

In another use of McElmo Dome CO2, affiliates of Beard Oil Co. operate a dry ice production facility .

The federal government's Crude Oil Windfall Profit Tax Act of 1980 provided part of the incentive for developing CO2 deposits. Under that Act, the windfall profit on conventional crude revenue was taxed at the rate of 70%. However, for certain enhanced recovery projects, including CO2 flooding, the WPT rate was reduced to 30%.

There is no question that for crude oil produced from the Permian basin oil fields in the early 1980s, this WPT rate differential favored CO2 flood development. However, this incentive has not been available since the collapse of oil prices in early 1986.

CO2 EOR

Injection of CO2 into oil reservoirs is one of several enhanced oil recovery techniques available. Miscible flooding is the most common form Of CO2 EOR projects.

A miscible flood initiates a chemical interaction between the crude and CO2. In a miscible phase the CO2 is dissolved in the crude, greatly reducing oil viscosity and increasing oil bulk and relative permeability. The result is increased reservoir pressure and easier movement of the swelled oil through the formation to the well. Light, low-viscosity oil is preferred.

Some other crude oil reservoir parameters believed to increase the probability of a successful CO2 injection program are: 3

Low vertical permeability in a horizontal reservoir o Homogeneous formation
No natural water drive
No major gas cap
No major fractures.

Many CO2 floods are incorporated into oil fields already under waterflood. Often, to optimize CO2 sweep of the oil reservoir, CO2 and water are injected in alternating cycles. Engineering studies have shown that although it has been quantitatively proven that CO2 can enhance crude oil recovery there is a fairly wide range of results. Based on using 2.413 Mcf/bbl, projected incremental recoveries have ranged from around 5 to 22% of original-oil-in-place (OOIP).4 This explains the wide (and unpredictable) range of economic outcomes for CO2 floods.

The volume of CO2 purchased per incremental barrel is typically 4-5 Mcf, although 20-25% of the CO2 is often recycled after the initial phase of injection.

Fig. 2 shows the facilities that must be installed or modified to implement a CO2 flood. Because CO2 and water form carbonic acid, an extremely corrosive agent, certain infrastructure, such as wellhead equipment and certain processing facilities must be of stainless steel. For all practical purposes the entire infrastructure of an oil field is impacted.

Transportation of CO2 is another primary concern. Although CO2 can be moved by truck, pipelines are more economical for large volumes. But in highly developed areas, pipeline right-of-way acquisition may be extremely difficult or impossible.

Even in areas where rights-of-way are available, the value of the CO2 deposit must justify initial pipeline construction costs. Because of high line pressure, CO2 pipelines require a heavier-walled pipe than natural gas pipelines. The pipeline economics of CO2 injection are very sensitive to the distance from the CO2 source to the injection point and pipeline capacity.

Capital costs for an intermediate capacity pipeline of 300 MMcfd are about $400,000/mile. However, there are some economies of scale for variable costs (Fig. 3).

Both Sheep Mountain and McElmo Dome pipelines transport CO2 in a dense vapor state in the range of 1,200-2,780 psia. Because CO2 expands as it moves from the high Colorado elevations to the Southwest, each pipeline has a pressure-reduction facility in New Mexico. For both CO2 sources, generally, no pressurization is necessary for injecting CO2 into the crude oil reservoirs.

A CO2 injection project must justify much higher lease operating costs because of increased power requirements, gas processing for CO2 removal, and other incremental costs. In the Permian basin, typical lifting costs (excluding CO2 flooding) are in the vicinity of $4-5/bbl. The added operating costs of a CO2 flood, including 4-5 Mcf/bbl, corrosion inhibitors, recycling, and fluid handling, can add another $5/bbl.

Incremental capital costs attributable to CO2 are $25/bbl. Total lifting costs, then, are likely to fall in the range of $11-14/bbl, not including administrative overhead royalties or production taxes.5

Because most of these costs are incurred several years prior to production of any incremental crude oil, this estimated incremental cost per barrel also excludes the time value of money.

Shell believes that CO2 will increase ultimate crude oil recovery in the Wasson field (Permian basin) by 350 million bbl to a final total of 1.3 billion bbl. It is estimated that CO2 injection will extend the life of the field by at least 25 years and that 60% of the original oil in place will ultimately be recovered.6

Primary recoveries average about 30% in the Permian basin. Over 80 billion bbl of oil have been discovered in the Permian basin, but production has been declining since 1974 in spite of extensive secondary (waterflood) projects. Therefore, as much as 70% of this resource base, or 56 billion bbl, is unrecoverable under conventional production techniques.

Using current technology, this additional oil (if economic to produce) could require 12 tcf of CO2, a volume well within known available supply sources (Table 1). The Permian basin, although a mature crude oil province by any measure, has many of the geological characteristics favoring CO2 flooding and relatively close proximity natural CO2 reserves. One recent example is Mobil Exploration & Producing U.S. Inc.'s start-up of CO2 injection in the Salt Creek field in Kent County Tex.8

OTHER USES FOR CO2

In the halcyon days of the early 1980s, CO2 enthusiasts forecast an explosion in CO2 demand. One use often mentioned was for coal slurry pipelines. Because such pipelines require massive amounts of water, a resource in chronic short supply in the West, CO2 seemed an ideal substitute. At one point, Arthur D. Little Inc. and W.R. Grace & Co. jointly licensed a liquid CO2 coal slurry transportation system.

The partnership proposed one scenario under which the CO2, after transporting the coal to its destination, would be recovered and used as an enhanced recovery agent for crude oil. Like many of the ambitious plans for CO2 use, this one is still on the shelf.

A recent potential Of CO2 is to enhanced recovery of coalbed methane gas. Amoco has been testing nitrogen injection into coal seams near Durango, Colo. Recently, Amoco also has started a pilot project to test CO2, which theoretically would be more effective than nitrogen in displacing methane adsorbed to the subsurface coal.9 If successful, a potentially huge CO2 market would open up in the nearby San Juan basin. One source for this potential market is the significant volumes of CO2 currently being vented into the atmosphere as a by-product of coalbed methane production.

Another possible use of CO2 is for manufacturing methanol and MTBE.10 Methanol is a gasoline additive that reduces nitrous oxide emissions, while MTBE (methyl tertiary butyl ether) is an oxygen-containing molecule that reduces carbon monoxide emissions. Starting in 1995, federal clean air laws will require an increased oxygen content for gasoline, which may bode well for CO2 demand.11

Although this is being discussed as a potential use for the southwestern Wyoming CO2 reserves, the author is not aware of and similar applications for CO2 in the foreseeable future. Methanol producers also have alterative technologies available that do not require CO2, therefore CO2 will have to be available at a price that is competitive.

A final possibility, for CO2 demand exists in many of the now mature Mexican oil fields. A recent detailed engineering study supports the use of CO2 in several large Mexican fields now under waterflood. 12 However, it is by no means certain that U.S. CO2 sources could overcome the economic and political obstacles.

MARKET STRUCTURE

To analyze the market structure of the CO2 industry, one should consider the individual segments of production, transmission, and end use (i.e., oil field injection).

For McElmo Dome, at least two of the same participants, Shell and Mobil, are involved in all three segments. The CO2 production and transmission segments are a small fraternity, in large part due to the enormous capital requirements accompanying CO2 development and use.

The entire Rocky Mountain CO2 resource base serving the Permian basin is principally owned by Shell and Mobil (McElmo Dome), Exxon and ARCO (Sheep Mountain), and Amoco and Amerada Hess (Bravo Dome). This implies an oligopolistic market structure. Oligopoly describes a situation of a few interdependent producers. Accordingly, the pricing decisions by one firm are likely to impact the pricing decisions of the other producers. Unlike pure competition, it is very difficult to predict market price distortions (if any) under an oligopoly.

However, the CO2 production industry is characterized by high barriers to entry and only a few firms. Some economists would argue that these conditions would lead to the same price-quantity outcome as a monopoly.13

A monopoly based price is generally higher than a free market price. However, the concern of at least some royalty/land owners and county governments is that the price of Rocky Mountain CO2 is artificially low.14 Two 1986 econometric studies that may be of interest are References 15 and 16 .

Fig. 4 is a synopsis of one of these studies. The other study arrives at similar permissible CO2 prices using only slightly different assumptions. By permissible price we mean the price that could be paid for CO2 without rendering the EOR project uneconomic.

Using typical Permian basin CO2 efficiencies of 5 Mcf of CO2/incremental bbl, Fig. 3 indicates much higher permissible CO2 values than have been reported for ad valorem assessment (Table 2) at the applicable oil prices. Some extrapolation is required because the average price of Permian basin crude oil for the period 1985-1991 is in the vicinity of $16.50/bbl. However, assuming a linear relationship to $16.00/bbl, the permissible price is still in the range of $1.50/Mcf at a CO2 efficiency of 5 Mcf of CO2/incremental bbl.

These econometric models are extremely sensitive to CO2 efficiency, required rate of return, assumed crude oil prices, and incremental operating costs. Moreover, these studies were prepared when the economics of CO2 injection were still evolving and only a short period of historical operating data was available.

For example, both models appear to use incremental cost assumptions that are lower than those represented to the author by Exxon outlined previously. This may explain why actual CO2 prices have been lower than those projected by the two models.

An analysis of sales contracts, actual CO2 production and transmission costs, and incremental lease operating costs associated with CO2 flooding would perhaps help clarify the price question. Unfortunately, this information is highly confidential and not available to the author.

An artificially low CO2 price would theoretically shift more economic gain to the target reservoir. Classical economic theory predicts that if excess profits are available, more firms will enter the market in search of such excess profits. Entry will continue until average total costs (including return on investment) is equal to price.

However, crude oil producers have been relatively cautious to embrace CO2. While the potential economic benefits of CO2 are significant, it is not a panacea. The reason is twofold. First, CO2 technology is still evolving. Secondly, experience has shown that the economics of CO2 flooding are unpredictable.

There are several other factors that must be considered in the context of the McElmo Dome market structure and prices:

Significant federal income tax credits are available (generally after 1990) for the implementation of qualified EOR projects. For a qualified CO2 flood, the federal tax credits usually increase as the price of CO2 increases. 17 As a crude oil producer (and CO2 purchaser) in the Permian basin, Shell's economic interests may be best served by high CO2 prices. The resulting federal EOR tax benefit may more than offset the increased CO2 royalty and ad valorem tax liabilities resulting from higher CO2 prices.
A CO2 producer's interest in the target reservoir is an important consideration. For example, Shell's ownership interest in McElmo Dome is more than its ownership interest in the Denver Unit. Because Shell is a net seller Of CO2, it would appear that they would favor a higher price.
A sealed bid process has been used to award CO2 sales contracts.
Manipulation of CO2 prices could be accomplished only at the risk of violating federal anti-trust laws.
Currently, Permian basin CO2 supply exceeds demand by about 300 MMcfd. This condition would put tremendous strain on any organized effort to control prices.

Because of these reasons, it is not possible to categorically determine if the CO2 prices are purely market driven. The publicly available financial information is too scant to document an unequivocal conclusion. However, the current facts suggest that CO2 producers would encourage higher, rather than lower CO2 prices.

PRICE CONSIDERATIONS

The price of CO2, at least in the Permian basin, is a function of crude oil prices (which drives EOR project demand), CO2 supply, and transportation. However, crude oil prices have by far the greatest short-term influence on CO2 prices.

Economists often describe a commodity's price in terms of elasticities. One useful elasticity is that of price elasticity of demand. Changes in the price of a commodity often lead to changes in the quantity demanded.

The price elasticity of demand attempts to measure this response. If a price increase is met by a more than proportionate decrease in the quantity, demanded, the demand is said to be elastic. For example, the demand for a nonessential good such as candy is obviously elastic, price has a large impact on quantity. On the other hand, demand for some goods (such as medical services) is inelastic. The quantity demanded is not affected very much by price.

While it is not possible to precisely quantify CO2 price elasticities, a few general observations may be helpful. The author conjectures that Permian basin CO2 prices may be inelastic up to prices in the range of $1.25/Mcf. One factor in favor of CO2 price inelasticity is the lack of substitutes once the infrastructure for a CO2 flood is in place. However, an economic factor of even greater significance to CO2 is cross-price elasticity.

In the case of CO2, this is a measure of the reaction to CO2 demand given a change in the price of crude oil. Most observers would agree that CO2 prices are probably very cross-price elastic with crude oil. For example, a 10% decrease in the price of crude oil would probably lead to a greater than 10% decrease in the quantity of CO2 demanded, other things being equal.

The point is that an awareness of price elasticities is necessary to understand the variables that are significant to CO2 prices.

What is the outlook for crude oil prices? The dismal record of oil price prognosticators demonstrates the futility of crude oil price predictions. However, a few key statistics may be useful.

In 1990, 14% of the U.S.'s lower 48 state onshore oil production (660,000 b/d) came from enhanced oil recovery reservoirs.18 Of this, a significant portion was produced in the Permian basin from CO2 floods. Crude oil produced using EOR recovery techniques is much more sensitive to price than conventionally produced crude.

Under the assumption of 2.2%/annum economic growth, the federal Energy Information Administration predicts that EOR production in 2000 will range from 500,000 to 780,000 b/d, depending on crude oil price projection.

By 2010, the range of EOR production is even wider: 290,000-850,000 b/d.18 CO2 prices will probably vary accordingly.

There is also an effective CO2 price floor that is a function of costs. Estimated variable (i.e., incremental) costs of producing and gathering McElmo Dome CO2 are in the range of $0.15-0.20/Mcf. The variable pipeline transportation costs is in the range of $0.25-0.35/Mcf. Total variable production and transportation costs, then, are estimated to be in the range of $0.40-0.55/Mcf. This represents the minimum price to provide an incentive for continued production.

Finally, at least three other factors may significantly impact future CO2 prices.

First, recycled CO2 may become a significant supply source. At some point, the incremental oil revenue will be less than incremental costs in fields currently under CO2 flood. At that juncture, the residual CO2 may be available for sale to another buyer, probably at a salvage value price.

Second, in the southern part of the Val Verde basin of West Texas, several gas fields produce a methane/CO2 mixture containing 520% CO2. This CO2 by-product bears little (or perhaps none) of the incremental lifting costs. Accordingly, it is currently available at a price of as low as $0.10/Mcf.5

Third, history has proven that technology, often has an unexpected, but dramatic effect on commodity economics. This may prove to be especially true in view of the relative youth of the enhanced oil recovery (EOR) industry in general and CO2 flooding in particular.

For example, if new advances in EOR halved the amount of CO2 required to recover an incremental barrel of oil, CO2 demand (and price) would decrease significantly. On the other hand, if new technology allows CO2 flooding to be economically applied to smaller reservoirs or expands the range of potential EOR candidates, CO2 demand (and price) will increase.

Of course, the most likely outcome is that some technological advancements will increase CO2 demand while others will have the opposite effect.

GENERAL OBSERVATIONS

Some general observations concerning CO2 prices are:

Rocky Mountain CO2 prices are much more sensitive to crude oil prices and future oil price expectations than any other single variable.
Assuming McElmo Dome CO2 production is an independent profit center, there is an effective long-term price floor of about $0.50/Mcf and a ceiling of $1.25/Mcf, FOB Permian basin, at current oil prices.
Demand from sources other than Permian basin EOR projects and/or much higher oil prices will be required to raise CO2 prices significantly in the next 5 years.
Permian basin CO2 prices may be depressed by the availability of recycled and by-product CO2 and the potential continuation of excess supply.
The impact of technology will be significant, but the impact on future CO2 prices is not presently determinable.

REFERENCES

Rocky Mountain Association of Geologists, Guide Book to the Geology of North and Middle Parks Basin, Colorado, Rocky Mountain Association of Geologists, 1957.
Beard Oil Co., Annual Report, 1991.
Klins, M,A,, Carbon Dioxide Flooding-Basic Mechanisms and Project Design, international Human Resources Development Corp., 1984.
Brock, W.R., and Bryan, L.A., "Summary Results of CO2 EOR Field Tests, 19,-2-1987," Society of Petroleum Engineers, 1989.
Interview, with Larry Bryan, Exxon USA (CO2 Marketing), Midland, Tex., ]an. 8, 1993.
"Shell Mulls Role for Dialysis in CO2 Application," The Oil Daily, Dec. 18, 1991, p. 3.
Smith, L.R., and Currens, D.R., Overview of CO2 Flood and Supply Source Activity for EOR in the Permian Basin, Matthew Bender & Co., 1984.
"Mobil starts up Salt Creek CO2 project," OGJ, Nov. 8, 1993.
"San Juan Basin Prospects Look Good For 1993," Western Oil World, October 1992.
"Wyoming Touted as Methanol Refinery Site," Denver Post, Dec. 17, 1992.
Annual Energy Outlook 1992, U.S. Department of Energy, Energy Information Administration, January 1992.
Arriola, T.A., Arteaga, C.M., and Chimal, R.J., "Recuperacion De Petroleo De Medios Porosos Por Inyeccion De CO2," Rev. Inst. Mex. Petrol., July-Sept 1990.
Griffin, J.M., and Steele, H.B., Energy Economics and Policy, Harcourt Brace Jovanovich, 1986.
OGCC Cause No. 389, Colorado Oil & Gas Conservation Commission.
Stern, K.M., "Review of Current and Potential Future CO2 Sources," Energy Progress, September 1986.
Wolsky, A.M., and Jankowski, D.J., "The Value of CO2: Framework and Results," SPE, September 1986.
Grindinger, D.J., "The Section 29 Credit and the EOR Credit: Two Major Tax Incentives Affecting the Development of Natural Resources," Rocky Mountain Mineral Law Institute, 37th Annual Proceedings, July 18-20, 1991.
Annual Energy Outlook, DOE/EIA, 1992.