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Once secondary recovery techniques such as waterflooding no longer produce oil economically, tertiary recovery techniques, also known as enhanced oil recovery, may be utilized to produce additional oil. While the primary and secondary oil recovery phases depend upon pressure, tertiary recovery methods work by actually altering the original properties of the oil. One of the most common tertiary recovery methods is Carbon Dioxide enhanced oil recovery, or CO2 EOR. Beyond primary and secondary recovery phases, an additional 5 to 20% of the oil in the reservoir can be recovered by CO2 EOR. The CO2 is commonly sourced from large underground deposits and can also be captured from sources such as electric power plant emissions.
Once captured, it is generally brought to the oilfield by pipeline and injected into the reservoir or held in storage tanks. The CO2 is compressed to a high pressure and injected into the oil reservoir to begin the EOR process. Produced water, or oilfield brine, is injected alternately with the compressed gas in what is known as the “water alternating gas”, or WAG, method. Once the pressurized CO2 and water are injected into the reservoir, the oil reacts very differently with the CO2 than it does with the water. Water injection drives oil out of the formation through pressure by direct force.
CO2 injection, on the other hand, is miscible, or able to mix, with the oil. Miscibility means that CO2 can dissolve into and swell the residual oil within a miscible zone. Once the CO2 has been absorbed, inside the miscible zone, the oil’s viscosity is reduced and it is now able to flow more easily through the formation. Because of its lower viscosity, CO2 may begin to form channels through the oil. This channeling effect allows large amounts of CO2 to force through to the production well, bypassing much of the oil. The WAG method uses the pressure of the water injection to reduce channeling. This creates a stable force that drives oil to the production well. Once the oil, CO2, and water mixture reaches the surface through the production well, the CO2 and water are separated from the oil. The oil is sent to storage tanks where it is stored or transported by pipeline to a refinery.
This flow diagram demonstrates how the CO2 flood cycle works. The reservoir, surface facilities and wells make up a closed loop system where virtually all the CO2 is retained in the project. After the CO2 EOR process is complete effectively all of the injected CO2 remains underground in the reservoir. But because CO2 is a valuable commodity, there is interest in recapturing as much of the CO2 as possible. Therefore, at completion, recycled water is sometimes injected into the reservoir to produce any recoverable CO2. This CO2 is then transported to another location sometimes within the same field for reuse. Current CO2 EOR technology makes an estimated 35-50 billion barrels of oil economically recoverable in the United States. The recovery potential for CO2 EOR is more than double the country’s proved oil reserves.
Primary Oil Recovery – Secondary Oil Recovery – Tertiary Oil Recovery
Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir’s original oil in place is typically produced during primary recovery. Secondary recovery techniques extend a field’s productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place.
However, with much of the easy-to-produce oil already recovered from U.S. oil fields, producers have attempted several tertiary, or enhanced oil recovery (EOR), techniques that offer prospects for ultimately producing 30 to 60 percent, or more, of the reservoir’s original oil in place.
Department of Energy – Enhanced Oil Recovery
Other Carbon Dioxide-Enhanced Oil Recovery links:
National Energy Technology Laboratory – NETL
United States Geological Society – USGS
Carbon Dioxide-Enhanced Oil Recovery – (CO2-EOR)
Gas injection used as a tertiary method of recovery involves injecting natural gas, nitrogen or carbon dioxide into the reservoir. The gases can either expand and push gases through the reservoir, or mix with or dissolve within the oil, decreasing viscosity and increasing flow. (Rigzone “EOR”) Gas injection accounts for nearly 60 percent of EOR production in the United States. (DOE “EOR/CO2”)
The EOR technique that is attracting the most new market interest is carbon dioxide (CO2)-EOR. First tried in 1972 in Scurry County, Texas, CO2 injection has been used successfully throughout the Permian Basin of West Texas and eastern New Mexico, and is now being pursued to a limited extent in Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska, and Pennsylvania. (DOE “EOR/CO2”)
Until recently, most of the CO2 used for EOR has come from naturally-occurring reservoirs. But new technologies are being developed to produce CO2 from industrial applications such as natural gas processing, fertilizer, ethanol, and hydrogen plants in locations where naturally occurring reservoirs are not available. One demonstration at the Dakota Gasification Company’s plant in Beulah, North Dakota is producing CO2 and delivering it by a new 204-mile pipeline to the Weyburn oil field in Saskatchewan, Canada. Encana, the field’s operator, is injecting the CO2 to extend the field’s productive life, hoping to add another 25 years and as much as 130 million barrels of oil that might otherwise have been abandoned. (DOE “EOR/CO2”)
Why use CO2?
Water and oil don’t mix, but a solvent can mix with oil, form a homogenous mixture, and carry the oil. Natural gas is very miscible with oil but it is relatively expensive. Underground deposits of CO2 are relatively inexpensive, naturally occurring sources of gas. If CO2 produced by human activities can be captured inexpensively, it could become a source as well. (DOE “CO2 Enhanced”)
Under pressure, oil and CO2 have miscibility, (most common when CO2 is compressed and oil is low-density) thus the pressure of a depleted reservoir must be considered when evaluating a well for CO2 injection. Low pressure reservoirs may need to be re-pressurized by injecting water. (DOE “CO2 Enhanced”)
Once the oil and CO2 are miscible, the CO2 can displace the oil from the rock pores. As CO2 dissolves in the oil it swells the oil and reduces its viscosity. Often, CO2 floods involve the injection of volumes of CO2 alternated with volumes of water; water alternating gas or WAG floods. This approach helps to mitigate the tendency for the lower viscosity CO2 to finger its way ahead of the displaced oil. Once the injected CO2 breaks through to the producing well, any gas injected afterwards will follow that path, reducing the overall efficiency of the injected fluids to sweep the oil from the reservoir rock. (DOE “CO2 Enhanced”)
The physical elements of a typical CO2 flood operation can be used to illustrate how the process works. First, a pipeline delivers the CO2 to the field at a pressure and density high enough for the project needs (>1200 pounds per square inch [psi] and 5 pounds per gallon; for comparison water density is 8.3 pounds per gallon), and a meter measures the volume of gas purchased. This CO2 is directed to injection wells strategically placed within the pattern of wells to optimize the areal sweep of the reservoir. The injected CO2 enters the reservoir and moves through the pore spaces of the rock, encountering residual droplets of crude oil, becoming miscible with the oil, and forming a concentrated oil bank that is swept towards the producing wells. (DOE “CO2 Enhanced”)
The produced fluids are separated and the produced gas stream, which may include amounts of CO2 as the injected gas begins to break through at producing well locations, must be further processed. Any produced CO2 is separated from the produced natural gas and recompressed for reinjection along with additional volumes of newly-purchased CO2. In some situations, separated produced water is treated and re-injected, often alternating with CO2 injection, to improve sweep efficiency (the WAG process mentioned earlier). (DOE “CO2 Enhanced”)
Nitrogen: Nitrogen may be used in areas where CO2 is not economically available for use. (DOE NETL “EOR-Gas Flood”). Can be used to recover “light oils” that are capable of absorbing gas under reservoir conditions, are low in methane, and at least 5,000 feet deep to withstand the high injection pressure necessary for the oil to mix with the nitrogen without fracturing the producing formation. When nitrogen is injected into a reservoir, it forms a miscible front by vaporizing lighter oil components. As the front moves away from the injection wells its leading edge goes into solution, or becomes miscible, with the reservoir oil. Continued injection moves the bank of displaced oil toward production wells. Water slugs are injected alternately with the nitrogen to increase the sweep efficiency and oil recovery. Nitrogen can be manufactured on site at relatively low cost by extraction from air by cryogenic separation, and being totally inert it is noncorrosive. (DOE NETL “Miscible Recovery”)
Natural gas: Natural gas is miscible with oil and can be used to clean oil from underground reservoirs, but it is a valuable commodity. It is cheaper to use other gases, especially CO2. (DOE NETL “CO2/EOR”)
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