You must log in to edit PetroWiki. Help with editing
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information
Waterflooding is the use of water injection to increase the production from oil reservoirs. Use of water to increase oil production is known as "secondary recovery" and typically follows "primary production," which uses the reservoir’s natural energy (fluid and rock expansion, solution-gas drive, gravity drainage, and aquifer influx) to produce oil.
Rationale for waterflooding
The principal reason for waterflooding an oil reservoir is to increase the oil-production rate and, ultimately, the oil recovery. This is accomplished by "voidage replacement"—injection of water to increase the reservoir pressure to its initial level and maintain it near that pressure. The water displaces oil from the pore spaces, but the efficiency of such displacement depends on many factors (e.g., oil viscosity and rock characteristics). In oil fields such as Wilmington (California, US) and Ekofisk (North Sea), voidage replacement also has been used to mitigate additional surface subsidence. In these cases, the high porosity of the unconsolidated sandstones of the Wilmington oil field’s reservoirs and of the soft chalk reservoir rock in the Ekofisk oil field had compacted significantly when the reservoir pressure was drawn down during primary production.
Over the past 40 years, SPE has published three significant and in-depth books written by Craig, Willhite, and Rose et al. that address waterflooding technology.
In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice.
Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, US. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on a die).
Much of waterflooding’s technology and common practice developed in the U.S. between 1940 and 1970. By the mid-1940s, the onshore US oil industry was maturing and primary production from many of its reservoirs had declined significantly, whereas most reservoirs elsewhere in the world were in the early stages of primary production. Also, in the U.S., thousands of wells had been drilled that were closely spaced, so that the effects of water injection were more obvious and so were more quickly understandable.
In addition to the need to dispose of saline water that was produced along with the oil, several other factors made waterflooding a logical and economical method for increasing recovery from oil fields. Very early on, it was recognized that in most reservoirs, only a small percentage of the original oil in place (OOIP) was being recovered during the primary-production period because of depletion of the reservoirs’ natural energy. Additional recovery methods were needed to produce the large quantity of oil that remained. Water injection’s early success in lengthening the oil-production period by years made waterflooding the natural step after primary production to recover additional oil from reservoirs whose oil-production rate had declined to very low levels.
Other key factors that drove waterflooding’s development and increasing use were:
- Water is inexpensive
- Water generally is readily available in large quantities from nearby streams, rivers, or oceans, or from wells drilled into shallower or deeper subsurface aquifers
- Water injection effectively made production wells that were near the water-injection wells flow or be pumped at higher rates because of the increased reservoir pressure
Concurrently, the scientific reasons behind waterflooding’s success were identified (i.e., that water has viscosity, density, and wetting properties, compared to oil, that affect how efficiently it will displace various oils from reservoir rock).
By the 1970s, most onshore oil fields in the US, USSR, and China, for which waterflooding was the logical recovery process, were being produced by use of this technology in various well-pattern arrangements. Some US offshore oil fields and oil fields elsewhere in the world were receiving water injection as deemed appropriate by their owners and operators. Since then, many large-scale water-injection projects have been applied to oil reservoirs in locations ranging from far offshore in the North Sea to the Arctic regions to desert areas.
Unit displacement efficiency is how water displaces oil from a porous and permeable reservoir rock on a microscopic scale. This is the level of analysis that is applied when water-/oil-flow measurements are made on small core-plug samples in a laboratory. Calculations for determining how well waterflooding will work on a reservoir scale must include the effects of geology, gravity, and geometry (vertical, areal, and well-spacing/-pattern arrangement). The formula for overall waterflood oil-recovery efficiency ER might be simply stated as the product of three independent terms:
where ED = the unit-displacement efficiency, EI = the vertical-displacement efficiency, and EA = the areal-displacement efficiency. Of course, assuming independence of these three factors is not valid for real oil reservoirs.
Oil properties are important to technical and economic success of a waterflood. The key oil properties are viscosity and density at reservoir conditions. In a porous medium, the mobility of a fluid is defined as its endpoint relative permeability divided by its viscosity; hence, a fluid with a low viscosity (≤ 1 cp) has a high mobility unless its relative permeability is very low. Similarly, a low-API crude oil (≤ 20°API) has a high viscosity and a very low mobility unless it is heated to high temperatures. Because water’s viscosity at reservoir temperatures generally is much lower than or, at best, equal to that of the reservoir oil, the water-/oil-viscosity ratio is generally much greater than 1:1. The water-/oil-mobility ratio is a key parameter in determining the efficiency of the water/oil displacement process, with the recovery efficiency increasing as the water-/oil-mobility ratio decreases.
More information on the displacement of oil by water in waterflooding can be found in:
- Microscopic efficiency of waterflooding
- Macroscopic displacement efficiency of a linear waterflood
- Areal displacement in a waterflood
- Vertical displacement in a waterflood
Reservoir geology considerations
The most important aspect of evaluating a field waterflooding project is understanding the reservoir rocks. This understanding begins with knowing the depositional environment at the pore and reservoir levels and possibly also several levels in between. Second, the diagenetic history of the reservoir rocks must be ascertained. Then, the structure and faulting of the reservoir must be determined to understand the interconnectivities among the various parts of the reservoir, particularly the injector/producer connectivity. Finally, the water/oil/rock characteristics need to be understood because they control wettability, residual oil saturation to waterflooding, and the oil relative permeability at higher water saturations. Because of these needs, there always should be a developmental geologist on the waterflood-evaluation team.
All oil reservoirs are heterogeneous rock formations. The primary geological consideration in waterflooding evaluation is to determine the nature and degree of heterogeneities that exist in a particular oil field. Reservoir heterogeneities can take many forms, including
- Shale, anhydrite, or other impermeable layers that partly or completely separate the porous and permeable reservoir layers.
- Interbedded hydrocarbon-bearing layers that have significantly different rock qualities—sandstones or carbonates.
- Varying continuity, interconnection, and areal extent of porous and permeable layers throughout the reservoir.
- Directional permeability trends that are caused by the depositional environment or by diagenetic changes.
- Fracture trends that developed because of regional tectonic stresses on the rock and the effects of burial and uplift on the particular rock layer.
- Fault trends that affect the connection of one part of an oil reservoir to adjacent areas, either because they are flow barriers or because they are open conduits that allow unlimited flow along the fault plane.
The structure of the reservoir and how it affects waterflood performance is another geological consideration. Structure creates dipping beds that dip at various angles. The interplay between the bed angle, gravity, and the oil/brine density difference at reservoir conditions significantly affects the relative vertical and horizontal flow behaviors. Structural considerations also can include whether the oil column has an underlying aquifer or an overlying gas cap, either of which can significantly affect the likelihood of successfully waterflooding the oil column.
Geologists and geophysicists must assess such geological and structural aspects of a reservoir. Geologists use cores and routine-core-analysis data to develop an understanding of the depositional environment and post-depositional diagenesis and to characterize the reservoir’s internal architecture. Using seismic data, geophysicists can discern the major faults, as well as trends in rock quality, since cores and well logs are essentially pin pricks into the overall reservoir.
The technical team that is evaluating and monitoring waterflood performance should include a geologist and a geophysicist. Including a geostatistician on the technical team, as well, will help to ensure that the geoscientists’ reservoir description is properly translated into engineering calculations, whether those are simpler calculations or are detailed numerical reservoir simulations.
For a waterflood, the reservoir description must be developed on the scale that is required for the quantitative evaluation (i.e., it must be "fit-for-purpose"). A variety of approaches (e.g., object- and pixel-based techniques) can be used. The "flow unit" is a concept that frequently is used by geologists and that would be useful to engineers. "A flow unit is a volume of the total reservoir rock within which geological and petrophysical properties that affect fluid flow are internally consistent and predictably different from properties of other rock volumes (e.g., flow units)." 
The process of evaluating a reservoir’s geology begins when the reservoir is discovered and is placed on primary production. After a waterflood has been initiated, the production- and injection-well data provide additional insight into the internal characteristics of the rock volume that is being flooded. In fact, the waterflood production-well data (the water and oil rates as a function of time) are critical because they are the first data that relate directly to the interwell connectivity within the reservoir and that validate or cause modification of the geoscientists’ concepts of the various levels of reservoir heterogeneities.
During a waterflood, tracers can be injected to track which injector/producer pairs are well connected and which are poorly connected. Other monitoring techniques include the use of specially drilled observation wells and 4D-seismic interpretations to track the directionality and shape of the higher-pressure water-swept reservoir areas that are centered on the injection wells.
Limitations of waterflood technology
Waterflooding can increase the volume of oil recovered from a reservoir; however, it is not always the best technology to use and it can have complicating factors. When evaluating how best to produce a particular oil reservoir, a petroleum engineer should include waterflooding in the options that are analyzed, both technically and economically. Those evaluations should include such potentially complicating factors as:
- Compatibility of the planned injected water with the reservoir’s connate water
- Interaction of the injected water with the reservoir rock (clay sensitivities, rock dissolution, or generally weakening the rock framework)
- Injection-water treatment to remove oxygen, bacteria, and undesirable chemicals
- The challenges involved in separating and handling the produced water that has trace oil content, naturally occurring radioactive materials (NORMs), and various scale-forming minerals
Key points concerning waterflooding are:
- Waterflooding is the most commonly used secondary oil recovery method. This is because water is inexpensive and readily available in large volumes and because water is very effective at substantially increasing oil recovery.
- The level of effectiveness of a waterflood depends on the mobility ratio between the oil and water, and the geology of the oil reservoir. Waterflooding is effective because almost all reservoir rocks are either water-wet or mixed-wet. The depositional and diagenetic characteristics of a reservoir control major aspects of the water/oil displacement process. These characteristics can either enhance waterflood performance or have detrimental effects on the WOR as a function of time. Often, the details of a reservoir’s internal geology are not known until production wells start producing injected water.
- Gravity effects—i.e., the interplay between the gravity/density effects and the geologic layering of a reservoir—are important in waterfloods because at reservoir conditions, oil always is less dense than connate brine or injected water. This interplay can either help or hurt waterflood performance relative to a homogeneous system.
- Waterflooding is a process that typically takes several decades to complete. Hence, continuous, routine field production and pressure data must be taken for monitoring and analyzing waterflood performance. There are opportunities to modify the original waterflood design and operating guidelines on the basis of analysis of the actual field production data. Occasionally, more-expensive, special-data acquisition programs (i.e., 3D- or 4D-seismic data) are run to assist the evaluation process. A variety of engineering tools have been developed to analyze waterflood performance, ranging from simple plots of field production data to full-field numerical-reservoir-simulation models.
- Waterfloods are dynamic processes the performance of which, as production wells respond to the injection of water, can be improved by modification of operations by the technical team. Such modifications include changing the allocation of injection water among the injection wells and the waterflooded intervals, drilling additional wells at infill locations, and/or modifying the pattern style.
- Waterflooding has been used successfully in oil fields of all sizes and all over the world, in offshore and onshore oil fields.
|ED||=||the unit-displacement efficiency|
|EI||=||the vertical-displacement efficiency|
|EA||=||the areal-displacement efficiency|
- ↑ Craig Jr., F.F. 1971. The Reservoir Engineering Aspects of Waterflooding, Vol. 3. Richardson, Texas: Monograph Series, SPE.
- ↑ Willhite, G.P. 1986. Waterflooding, Vol. 3. Richardson, Texas: Textbook Series, SPE.
- ↑ Rose, S.C., Buckwalter, J.F., and Woodhall, R.J. 1989. The Design Engineering Aspects of Waterflooding, Vol. 11. Richardson, Texas: Monograph Series, SPE.
- ↑ Fettke, C.R. 1938. The Bradford oil field, Pennsylvania and New York. Mineral Resources Report M21, Pennsylvania Geological Survey, Harrisburg, Pennsylvania, 298–301.
- ↑ Scheihing, M.H., Thompson, R.D., and Seifert, D. 2002. Multiscale Reservoir Description Models for Performance Prediction in the Kuparuk River Field, North Slope of Alaska. Presented at the SPE Western Regional/AAPG Pacific Section Joint Meeting, Anchorage, 20–22 May. SPE-76753-MS. http://dx.doi.org/10.2118/76753-MS
- ↑ Ebanks, W.J., Jr., Scheihing, M.H., and Atkinson, C.D. 1993. Flow Units for Reservoir Characterization. In Development Geology Manual, D. Morton-Thompson and A.M. Woods, No. 10, 282–285. Tulsa: AAPG Methods in Exploration, American Association of Petroleum Geologists.
Noteworthy papers in OnePetro
Shehata, A. M., Alotaibi, M. B., & Nasr-El-Din, H. A. 2014. Waterflooding in Carbonate Reservoirs: Does the Salinity Matter? Society of Petroleum Engineers. http://dx.doi.org/10.2118/170254-PA
Technical Aspects of Waterflooding. 2013. https://webevents.spe.org/products/technical-aspects-of-waterflooding
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro