Water Flood Secondary Oil Recovery

Water Flood Secondary Oil Recovery

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In the primary recovery phase of oil production both gravity and the natural pressure of the reservoir drive oil into the production well. Typically, only about 10% of the original oil in the reservoir can be produced in the primary recovery phase.

During primary recovery, water that exists naturally in the oil reservoir is produced alongside the oil. Upon reaching the surface, the produced oil and water are separated. The oil is held in storage tanks and then transported for sale. The water, or oilfield brine, is held in a storage tank for later use.

Once the pressure in the reservoir has begun to drop, it is necessary to utilize secondary recovery techniques to continue to produce oil from the reservoir at an economical rate.

Secondary recovery techniques will help maintain the pressure in the reservoir and extend a well’s productive life. One of the most common secondary techniques, waterflooding, uses the injection of water into the reservoir to drive more oil towards the production well. To prepare for the waterflood process, additional water is brought to the pad site and held in a storage tank. This water will be injected into the reservoir with the previously recovered oilfield brine.

Certain production wells are selected as injection wells for pumping water into the reservoir or, if necessary, new injection wells may be drilled. The precise configuration of these wells will vary, but one of the most common is the five-spot pattern. A five-spot pattern has four water-injection wells located at the corners of a square with a producing well at the center.

Once the injection wells are established, water is pumped through them and down into the reservoir.

As the water enters the reservoir from the injection wells, it creates pressure and sweeps the oil towards the production well. The waterflood process is repeated throughout the field and can recover an additional 10 to 20% of the original oil in the reservoir.

The water is injected until it reaches the production well in large quantities. Once the ratio of water to oil produced from a well becomes too high, it is no longer economical to continue with the waterflood and the process is complete.

Water Flooding

PRIMARY RECOVERY: First stage of hydrocarbon production, in which natural reservoir energy, such as gasdrive, waterdrive, or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to the surface. The primary recovery stage reaches its limit either when the reservoir pressure is so low that the production rates are not economical, or when the proportions of gas or water in the production stream are too high. During primary recovery, only a small percentage of the initial hydrocarbons in place are produced, typically around 10% for oil reservoirs. (Schlumberger)

SECONDARY RECOVERY: Second stage of hydrocarbon production during which an external fluid such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. The most common secondary recovery techniques are gas injection and waterflooding. Normally, gas is injected into the gas cap and water is injected into the production zone to sweep oil from the reservoir. A pressure-maintenance program can begin during the primary recovery stage, but it is a form or enhanced recovery. The secondary recovery stage reaches its limit when the injected fluid (water or gas) is produced in considerable amounts from the production wells and the production is no longer economical. The successive use of primary recovery and secondary recovery in an oil reservoir produces about 15% to 40% of the original oil in place. (Schlumberger)

Water Injection:

When an oil reservoir is first produced, the pressure that exists in the subsurface provides the energy for moving the oil, gas and water that is in the rock to the surface. After a while, the pressure dissipates and pumps must be used to remove additional volumes of oil. Depending on the characteristics of the rock and the oil, a considerable amount of the original oil in place may be left behind (perhaps 60 percent or more) as residual oil. Waterflooding is a process whereby water is pumped down selected wells to push a portion of the remaining oil out of the rock towards the producing wells. In most cases, CO2 enhanced recovery operations take place in oil reservoirs where this less expensive waterflooding option has already been implemented, although the remaining oil saturation in the post-waterflood reservoir is still significant, perhaps 50 percent of the original oil in place. (DOE “CO2 Enhanced”)

The injected water is often oilfield brine from the separators but can also be water from other sources that has been treated. The injected water must be compatible with the producing formations and not cause reactions that decrease the permeability of the formation being flooded. Suspended solids that can plug the pores are removed from the injection water by filtration. Organic matter and bacteria that produce slimes are neutralized by biocides. Oxygen is removed from the water to prevent corrosion. (Hyne “Nontechnical Petro”)

While production wells can be converted into injection wells, water-injection wells are also drilled specifically for this purpose. Water is then pumped into the reservoir, or gravity can help to push the liquid into the formation. This solution positions water tanks on hills or somewhere above the well, and the water simply is fed into the wellbore. (Rigzone “Water Injection”)

Waterfloods are described by the aerial pattern of the wells and are either spot or line drives. The common five-spot pattern has four water-injecting wells located at the corners of a square with a producing well at the center. The pattern is repeated in the field so that four injection wells surround each producing well and four producing wells surround each injection well. A seven-spot pattern has six injector wells surrounding a producer; whereas an inverted seven-spot pattern has six producer wells surrounding an injector. A line drive has alternating lines of producers and injectors and can be either direct or staggered. An edge waterflood uses injection wells along the margin of the field. The injected water drives oil up and toward the producing wells in the center. (Hyne “Nontechnical Petro”)

Primary production usually only recovers some 30 to 35% of the oil in place. Although the effectiveness of water injection varies according to the formation characteristics, a waterflood can recover anywhere from 5% to 50% of the oil that is remaining in the reservoir, greatly enhancing the productivity and economics of the development. (Rigzone “Water Injection”)

This form of EOR is typically more productive when there are relatively small amounts of primary production, and the process becomes uneconomical when the water cut reaches the 90 to 99% level. Some waterfloods may take up to two years of injection before production is increased; and some reservoirs do not have the right characteristics, and water injection is not a viable option for increasing production from waning wells. (For example, water injection is never used on natural gas wells.) (Rigzone “Water Injection”)

Fluids such as water will always flow along the route of least resistance. A reservoir rock might have a zone of high permeability, such as a well-sorted bed of sandstone or a porous or fractured zone in limestone. As the water sweeps through the reservoir, the injected water flows fastest through the most permeable zone (a thief zone) and reaches the producing well to cause a breakthrough. Once a breakthrough occurs, the rest of the water will tend to flow through that permeable zone bypassing oil in the less permeable portions of the reservoir. The sooner the water breaks through, the less efficient the waterflood. (Hyne “Nontechnical Petro”)

Gas Injection:

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”)

            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?

• it is miscible with crude oil
• less expensive than other similarly miscible fluids

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”)