Most oil is produced in three distinct phases: primary, secondary, and tertiary, or enhanced oil recovery (EOR). The definition of tertiary or EOR is that something is added to the reservoir after secondary recovery in order to increase production. This can be gases, chemicals, microbes, heat, or even the addition of energy, such as the stimulation of the oil through vibration energy. The purpose of EOR is to increase oil production, primarily through an increase in temperature, pressure, or an enhancement of the oil’s ability to flow through the reservoir. The challenge of EOR is that the remaining oil often is located in regions of the reservoir that are difficult to access, and the oil is held in the pores by capillary pressure. The goal of DOE’s EOR program is to develop technologies that enable recovery of this remaining oil. During primary recovery, the natural pressure of the reservoir drives oil into the wellbore, and artificial lift techniques (such as pumps) bring the oil to the surface. Only about 10 percent of a reservoir's original-oil-in-place (OOIP) is typically produced during primary recovery.
A pumpjack in Hall-Gurney oilfield near Russell, KS, with an ethanol plant in the background. By-product CO2 from the ethanol plant is being injected into the Lansing-Kansas City formation of Hall-Gurney field as part of the first-ever CO2 flood in Kansas. This NETL project provides a source of CO2 for enhanced oil recovery that is otherwise unavailable in Kansas while creating an opportunity for sequestering the CO2, a chief greenhouse gas.
Since shortly after World War II, producers have employed secondary recovery techniques to extend the productive life of oilfields, usually increasing the recovery rate to 15-40 percent of OOIP. For the most part, those techniques involve injecting water to displace oil, driving it to the wellbore. In some cases, natural gas—often produced simultaneously with the oil—is reinjected to maintain reservoir pressure, thus driving oil into the wellbore.
This broad range in recovery rates stems from the unique reservoir parameters of each oilfield. The main parameters that determine reservoir productivity are the rock properties, fluid saturations, reservoir temperature, and pressure.
Conventional primary and secondary recovery operations typically leave behind two thirds of OOIP. This is reflected in the recovery to date of the U.S. oil endowment. In all, more than 600 billion barrels of oil has been discovered in the United States. Of that total, about 400 billion barrels is unrecoverable by conventional primary and secondary means; of this figure, about 200 billion barrels lies at <5,000 feet subsurface. That shallow remaining volume is the main target for EOR. Most EOR involves the injection of gases or chemicals or thermal enhancement. The injection processes can occur as flooding or as slugs (i.e., batches of fluids injected in phases) or as a combination of both. The combination processes typically include water as a flooding agent or as a slug for one of the phases in an effort to control costs.
Gas injection , particularly in the form of CO2 flooding is the fastest-growing form of EOR in the United States. CO2 floods now account for about 4 percent of the Nation's oil production. The injected gas typically acts as a sort of solvent to reduce oil's viscosity, rendering it more mobile, while helping to sustain reservoir pressure.
Chemical EOR entails injecting chemicals either to reduce interfacial tension between the in-place crude oil and injected water, allowing the oil to be produced, or injecting other chemicals that can shut off excess water production, thus improving the “sweep” of a reservoir.
Thermal EOR entails introducing heat into the reservoir in a controlled manner to reduce oil viscosity. This method typically targets highly viscous, or heavy, crude oils. Because [color=black]heavy oil[color:7cdf=#005898:7cdf] is such an important component of the U.S. oil resource base, yet has been underutilized, DOE has devoted a special focus area to it—including “cold” recovery methods for heavy oil outside of thermal EOR.
DOE's EOR program also focuses on “novel” methods outside the industry mainstream. The novel category is a catch-all for any new ideas that don't fit into the traditional EOR world. Such alternatives could include [color=black]microbial processes[color:7cdf=#005898:7cdf] or the use of acoustic energy, seismic vibration, or microwave energy to render the oil less viscous and/or more mobile.
Subsurface imaging of EOR projects via computer simulation is an important component of tertiary recovery. Without such tools, an EOR operator cannot successfully optimize injection profiles, well patterns, sweep efficiency, and the like.
Gas injection
Gas flooding technologies primarily use carbon dioxide flooding as a method to produce more oil from the reservoir by channeling gas into previously-bypassed areas. CO2 flooding technologies experiment with a number of foams, gels, and thickening agents to improve sweep efficiency. CO2 floods are extensively used in some regions of the U.S., particularly in West Texas and the southern Rocky Mountains. CO2 flooding currently produces about 190,000 BOPD. In the past decade flooding with nitrogen gas, flue gas, and enriched natural gas have also shown some beneficial results by increasing recovery when used to re-pressure reservoirs. Nitrogen and flue gas may be useful in areas where CO2 is not economically available for use.
This schematic illustrates a nitrogen-CO2 flood. This and other cross-sectional illustrations of EOR methods that are in the public domain are available free from NETL.
Many reservoirs are not being considered for CO2 flooding or other EOR methods because of their extreme heterogeneity often caused by natural fractures. The degree to which the injected CO2 is transferred through these fractures is critical to a CO2 flood's economics. NETL research seeks to understand these transfer mechanisms and thus improve the sweep efficiency of this promising EOR method. The top figure depicts X-ray images of a CO2 front movement through a fractured core, showing the influence of gravity segregation. The bottom image displays a pressure distribution map with a unique gridding technique feature. Both are featured in the fact sheet entitled Investigation of Efficiency Improvement During CO2 Injection in Hydraulically and Naturally Fractured Reservoirs, Project No. DE-FC26-01BC15361.
Chemical method
Chemical methods focus mainly on alkaline-surfactant-polymer (ASP) processes that involve the injection of micellar-polymers into the reservoir. Chemical flooding reduces the interfacial tension between the in-place crude oil and the injected water, allowing the oil to be produced. Micellar fluids are composed largely of surfactants mixed with water. Goals of polymer floods are to shut off excess water in producing wells, and to improve sweep efficiency to produce more oil. Chemical field trials by industry indicate that surfactants can recover up to an additional 28% of reservoir oil; however the economics have not been favorable when the price of oil is factored against the cost of surfactants and polymers. Chemical flooding technologies are subdivided into alkaline-surfactant-polymer processes, polymer flooding, profile modification, and water shut off methods.
Thermal EOR
Heavy oil is recovered by introducing heat into the reservoir through thermally controlled processes. Steam flooding and in situ combustion or air injection are the most frequently-used thermal recovery methods. Steam flooding is used extensively in the heavy oil reservoirs in California. Experiments with cold production and sand injection and horizontal well production of heavy oils have been conducted mainly in Canada and Venezuela, which have extensive heavy oil reservoirs. Steam flooding is conducted by injecting steam into reservoirs that are relatively shallow, permeable, and thick, and contain moderately viscous oil. The dominant mechanism in thermal recovery by steam is the reduction in the viscosity of the oil, allowing flow to the wellbore. Problems with reservoir heterogeneity and steam distribution are being overcome. Steam flooding production in the U. S. averages nearly 500,000 BOPD.
In situ combustion introduces heat in the reservoir by a process of injection air and downhole ignition to burn portions of the oil to displace additional oil. The combustion front is sustained and propagated through continuous injection of air into the reservoir. Premature breakthrough of the combustion front contributes to operational problems. Both steam flooding and in situ combustion have high surface facility costs and require special safety measures.
Low-permeability heavy oil resources offer huge potential for adding to U.S. reserves. Diatomite formations in California alone contain 12-80 billion barrels of original-oil-in-place that could be tapped with a successful thermal recovery—primarily steam injection—scheme. One NETL project lends support to the technical case for thermal recovery from diatomite formations. This illustration, which shows computed tomography-derived images of water being taken up by an oil-saturated diatomite core (with times below it shown in minutes), is featured in the fact sheet entitled Heavy and Thermal Oil Recovery Production Mechanisms, Project No. DE-FC26-00BC15311.
