CHAPTER 7 CO2-EOR 101: AN OVERVIEW OF CO2 ENHANCED OIL RECOVERY
| Jurisdiction | United States |
(May 2015)
CO2-EOR 101: AN OVERVIEW OF CO2 ENHANCED OIL RECOVERY
Program Director
Bureau of Economic Geology
Jackson School of Geosciences
University of Texas at Austin
Austin, Texas
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IAN J. DUNCAN leads the Earth Systems and Environment group at the Bureau of Economic Geology at The University of Texas at Austin (BEG). For the last 4 years Ian has been working on policy, as well as legal and technical aspects of carbon management in the context of CO2 Enhanced Oil Recovery and sequestration in brine reservoirs. Ian was the geologic sequestration lead for the FutureGen Texas Team and in this role was responsible for putting together the Environmental Information Volume (EIV) that formed the basis for ES for the two Texas FutureGen sites. Ian has given numerous talks at national conferences on gasification technologies and CO2 sequestration, as well as sequestration as a part of EOR. Ian currently has research interests in science-based regulatory frameworks for CO2 sequestration, geomechanical and fluid-flow modeling of faults and seals in engineered brine reservoirs, and risk assessment for CO2. Ian is the Co-PI of a $38-million DOE-funded project to study 1 million tons/year CO2 injection into the water leg of an EOR project at Cranfield field, Mississippi.
INTRODUCTION
A declining rate of discovery of new oil fields over the last few decades has resulted in an increased number of enhanced oil recovery projects. In the US, CO2 based enhanced oil recovery (CO2-EOR) has increasingly become the technology of choice for new projects on old onshore fields in the US.
CO2-EOR is sometimes referred to as tertiary oil production. In this sense primary production phase occurs when a new oil reservoir is discovered and the initial production is driven by the energy provide by the pressure of the oil and in some cases, natural gas. For oil close to saturation in natural gas, as the reservoir pressure decreases this gas exsolves (referred to by industry as the bubble point) with a sudden increase in viscosity of the oil and drop in production of the well. Where the oil is strongly under-saturated with gas, the reservoir pressure can decrease substantially before injection of fluids for pressure maintenance is required to prevent this effect. As the reservoir pressure gets lower and the flow rate of wells decrease, "artificial lift" may be employed to get oil to the surface and prolong production. At some point decreasing production and the cost of lifting the oil make primary production uneconomic. At this point as little as 10%, or as much as 70 or 80%, of the original oil in place (OOIP) may remain in the reservoir. In the majority of oil fields 50 to 70% of the original oil remains. Such fields may be a suitable target for secondary production strategies, the most common of which is water flooding.
In secondary production new wells are drilled to injection water, typically in the center of a cluster of four or more production wells. In many types of reservoirs secondary production can produce more oil than the primary phase. Other in exceptional reservoirs, even after water flooding, over half of the OOIP remains in the reservoir. The remaining oil is largely trapped in pore spaces by capillary and viscous forces, and is said to be at "residual saturation". This creates a significant opportunity for tertiary production strategies, one of the most common being based on injecting CO2 as a solvent for crude oil. In CO2-EOR, CO2 typically more than 95% pure is injected into the reservoir. The key reasons that CO2 is so successful in oil recovery are that it lowers the viscosity, increases the volume the oil (by decreasing the oil density) and lowers its surface tension. At the scale of pores, the increase in volume of the oil and lower surface tension begins to break down the equilibrium of capillary forces that had effectively trapped oil bubble within pores; and the oil can potentially be displaced by injected fluids flowing through the reservoir. As more CO2, or a slug of water is injected, oil previously immobile, can flow towards a production well. If the reservoir pressures are sufficient for miscibility of the oil and CO2; then the CO2 dissolves completely into the oil. So called miscible CO2 flooding is generally regarded by engineers as the most effective.
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The first patent related directly to CO2-EOR was awarded in 1952 to engineers at the Atlantis Refining Company; and the first pilot was conducted in the Mead Strawn Field in west Texas in 1964. The first commercial full scale CO2 flood was implemented in the Permian Basin in 1974.
Implementation of CO2-EOR
Injection of CO2 into the reservoir and production is done by wells drilled in a pattern designed to maximize oil production. The most common configuration is four production wells located in a square with an injection well located in the center (known as a "five-spot" pattern). Such a pattern is commonly repeated over the area of the reservoir. In the Permian Basin CO2 floods have been optimized in an injection strategy know as WAG (water alternating gas) to utilize the pore scale enhancement of pore scale mobility provided by CO2 and the flow unit scale efficiency of water-flooding. WAG floods have an additional advantage of helping to effectively block the CO2 from channeling in high permeability pathways. In some reservoirs, where extremely high permeability pathways (referred to as "thief zones" by some) create almost instantaneous breakthrough of CO2 from injection to production wells, the operators has injected gels to block these zones.
When oil is produced from the CO2-EOR process the CO2 exsolves (forming a separate gas phase) when the oil is depressurized at the surface during production. This CO2, together with gas that has been produced is run through a capture plant that returns the CO2 to a pure phase. This process is known as recycling, as the gas is then reused.
The capital investment needed for a CO2-EOR project includes the costs of:
(1) Construction of whatever capture and compression infrastructure is needed to source the CO2 (or well development for natural CO2 reservoirs);
(2) Pipeline construction for both CO2 delivery and transporting oil for sale (in some cases only a spur pipeline to the nearest transmission pipeline may be required);
(3) Constructing a plant for separating and purifying CO2 for recycling into the reservoir;
(4) Infill drilling of wells to create patterns (in many cases existing wells are reworked as production or injection wells but typically significant numbers of new wells are required; and
(5) Running CO2 distribution pipelines to each injection well as well as gathering lines from the production wells to the recycling plant.
Incremental operating costs for EOR projects also have three main components. They consist of (1) cost of separating/purifying and compressing CO2 for recycling; (2) the cost of acquiring CO2 from pipeline or capture, compression and transportation costs for anthropogenic CO2; (3) cost of electricity to lift fluids for production well or in some cases to increase pressure of CO2 for injection; and (4) other normal costs for operating an oil field.
CO2 Sources and Capture from Anthropogenic Sources
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CO2 utilized for the initial EOR projects in the Permian Basin were obtained from natural gas processing plants that removed the gas as an impurity that was unacceptable in the sale of the natural gas itself. The industry quickly became aware of naturally occurring CO2 reservoirs in Colorado, New Mexico and Mississippi. Four CO2 fields were developed in the early 1980's: McElmo Dome (Colorado); Sheep Mountain (Colorado); Bravo Dome (New Mexico); and Jackson Dome (Mississippi). Pipelines were constructed connecting these natural CO2 reservoirs with oil field in the Permian Basin (Texas and New Mexico), Mississippi and Louisiana. In the Permian Basin over 22 million metric tons of CO2 per year is distributed to oil reservoirs by a 3980 km pipeline complex. Increasing numbers of projects in the early 80's and particularly over the last decade have finally taxed the production capacity of these sources. Substantial increases in CO2-EOR in the future will require a significant increase in the capture of CO2 from anthropogenic sources such as natural gas processing plants, coal fired power plants, chemical plants, and cement kilns.
CO2 emissions from large, stationary, anthropogenic sources can be conveniently divided into three categories: high purity, more than 90% pure; intermediate purity, 90 to 15% pure; and low purity, lower than 15% CO2. High purity CO2 is sequestration or EOR ready (though it may require removal of unwanted contaminants, particularly water). High purity CO2 stream typically come from chemical processes such as the manufacture of methanol from syngas produced from the gasification of coal. The main potential for intermediate purity CO2 comes from the development of Integrated Gasification and Combined Cycle (IGCC) coal based power plants that produce syngases with around 40% CO2. However the vast bulk of CO2 over the next 50 or more years will come from the low purity sources such as coal and natural gas fired power plants. Typical pulverized coal fired power plants produce a flue gas with ~ 12% CO2 and 88% N2. Such...
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