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Waterflood design

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The design of a waterflood has many phases. First, simple engineering evaluation techniques are used to determine whether the reservoir meets the minimum technical and economic criteria for a successful waterflood. If so, then more-detailed technical calculations are made. These include the full range of engineering and geoscience studies.

The geologists must develop as complete an understanding as possible of the internal character of the pay intervals and of the continuity of nonpay intervals. This preflood understanding often is limited because the injector/producer wells connectivity has not been determined quantitatively. Interference testing can provide insight into connectivity when its cost is justifiable. Data gathered from smart wells can be particularly helpful in determining connectivity in high-cost environments where there is a limited number of wellbores. Analogs also can prove useful. Otherwise, little definitive data will be available until after there has been significant fluid movement from the injectors toward the producers.

The engineer will make a number of reservoir calculations to determine the well spacing and pattern style that will be used in a particular flood. These choices are based on the available understanding of the reservoir geology, the proposed design of surface facilities (particularly water-injection volumes), and any potential limits on the numbers of injectors and producers. Such factors are interrelated in terms of capital and operating costs and oil-, water-, and gas-producing rates to define the overall economics of the project. In making these preliminary calculations, facility capacities need to be flexible because as the waterflood progresses, there almost certainly will be modifications to the original designs and operating plans.

In this article, a number of waterflood design considerations will be discussed briefly. (Rose et al.[1] is entirely devoted to this topic.) The design aspects discussed below include

  • Injection/producer pattern layouts
  • Injection-water sensitivity studies
  • Injection wells, injectivity, and allocation approaches, including well fracturing
  • Pilot waterflooding
  • Production wells
  • Surface facilities for injection water
  • Surface facilities for produced fluids

Injection/producer pattern layouts

Fig. 1 shows a variety of injector/producer pattern layouts that can be considered. In reality, the existing wellbore locations might limit the pattern layout to a nonsymmetrical arrangement like that shown in Fig. 2. Also, as shown in Fig. 3, the orientation of the rows of producers and injectors must take into account any permeability anisotropy and natural-fracture orientation. At offshore locations, the number of well slots on the drilling platforms limits the number of producers and injectors and their layout.

Injection-water-sensitivity studies

The factors to which injection-water-sensitivity studies relate are water-source and -volume options, source water/connate water compatibility, and source water/reservoir rock interactions. After the preliminary reservoir evaluation indicates that waterflooding is likely to be economically justified and that it will increase significantly the volume of oil recovered, the next consideration is to find an acceptable source from which to obtain enough water for the proposed waterflood project. Fig. 4 schematically shows the variety of natural sources for such water. Onshore locations typically obtain injection water from subsurface aquifer intervals or nearby streams or rivers. Nearshore and offshore waterflood projects typically use seawater.

Source water/connate water compatibility mainly concerns whether mixing the two waters causes any precipitation of insoluble carbonate or sulfate compounds that might impair reservoir permeability. Although permeability impairment typically is not a major consideration, precipitation and scale buildup in pumps and other surface water-handling equipment can cause costly downtime and repairs.

Potential sensitivity of the reservoir pay intervals to the injection water is a major consideration. For sandstone reservoirs that contain various types of clay, the key consideration is whether there exists clay sensitivity to the difference between the connate water salinity and the injection-water salinity, particularly for freshwater injection water sources. Such sensitivity can occur either as clay swelling or as mobilization of clay fines, both of which can reduce reservoir permeability significantly. For high-porosity chalk reservoirs, the injection water/reservoir rock interaction might weaken the rock framework and cause pore collapse and surface subsidence.[2]

Another aspect of injection water sensitivity is the amount and size of suspended particulate being carried by the injection water. This is a concern mainly when using surface water sources for the injection water. An example of where this is a significant consideration is the Kuparuk oil field on the North Slope of Alaska, US, where nearshore ocean water is the waterflood injection water. There, the spring runoff down the rivers from the Brooks Mountains can cause the nearshore ocean water to contain unacceptable amounts of solid particulate for several weeks of the year. Similar problems occur in the Gulf of Mexico in fields near the mouth of the Mississippi River. Also in the Gulf of Mexico, water that is drawn from too near the surface often contains organic matter that can reduce injectivity.

Injection wells, injectivity, and allocation approaches

Several aspects of the design and operation of water injection wells are critical to their success. The first is that these wells must have sufficient injectivity to flow the desired volume of water into the reservoir each day. The expected injectivity can be calculated on the basis of routine core analysis, special core analysis and/or log data, and the existing production wells’ productivity; however, well injectivity often is not known until water actually is injected into the reservoir interval. This is because the near-wellbore "skin" (a rock volume of reduced permeability around the wellbore) is not known until an actual well test is conducted. Injection wells can be fractured to eliminate positive skin in the near-wellbore region; however, fracturing must be done carefully to avoid fracturing out of the reservoir interval and into adjacent porous and permeable intervals into which injection water can be lost.

An aspect of well injectivity that has been studied during the last 20 years is the change in rock stresses that is caused by the cooling effect of the injection water on the near-wellbore region around injectors. This happens particularly in Arctic and offshore waterflood operations, where the injection-water temperatures can be considerably below the reservoir temperature (i.e., more than 100°F difference). Perkins and Gonzalez[3] have studied this phenomenon and found that the cooling effect reduces the earth stresses by several hundred psi. Hence, in the reservoir, a small area around water injectors’ wellbores will fracture more easily, giving that area enhanced permeability (or negative skin).[3] For the Prudhoe Bay field on the North Slope of Alaska, US, the fracture gradient was reduced to as low as 0.50 psi/ft from the original fracture gradient of 0.60 to 0.70 psi/ft.[4]

Another critical aspect of water injection well design and operation is the allocation of water to zones being waterflooded. Having the ability to allocate injection water as desired to the various waterflooded intervals is important for waterflood success because the overall waterflood is controlled primarily at the injection wells, not at the production wells. This is not an issue if there is only one reservoir interval, but in many oil fields, there are multiple reservoir intervals being waterflooded at the same time. If possible, the injection well bottomhole tubing, packer, and perforation configuration should be designed to allow control of the relative volumes of water that are injected into the various intervals being waterflooded. This can be accomplished if each injection well is perforated in only one reservoir interval, but one reservoir interval per injector is unlikely to be cost-effective compared to the alternative of fewer wells with more-complicated arrangements of chokes, tubing strings, and packers, particularly if there are multiple pay intervals stacked on top of each other.

Optimum completion design is site-specific and must be based on mechanical and reservoir characteristics for the project at hand.

Pilot waterflooding

Pilot waterfloods seldom are used today because of the wealth of experience in waterflooding; however, in many situations, they have been conducted to provide more quantitative data on the potential for successful waterflooding on a fieldwide scale.[5] Such pilot waterfloods definitely provide useful data concerning water injectivity, tendencies for early water breakthrough, and additional recovery potential. Determining recovery potential requires a pilot waterflood that is designed to represent what will happen in a full-scale application. Too often, one-pattern pilot waterfloods have been conducted that do not represent the confined injection/production relationship that is needed. Also, if the pilot waterflood is conducted on a well spacing that is considerably smaller than that used for the full-field waterflood (so that injector/producer connectivity data can be obtained sooner), the information it provides might be misleading about the injector/producer connectivity on the larger well spacing of the full-field waterflood. Thus, definitive objectives of a pilot waterflood should be established, and the pilot project should be designed and operated accordingly.

Production wells

In many cases, the water injection wells are drilled as new wells; however, the production wells typically are those that already are producing from the oil field. For waterflooding, producers should be completed in the same intervals in which the injection wells are completed. If the production wells are completed in several reservoir intervals, it is best to have sufficient length between the perforated reservoir intervals to allow workover operations to shut off those intervals that are producing much water and little oil by either cement-squeeze operations or by setting a packer in the production tubing.

Surface facilities for injection water

Maintaining high water quality is important for sustaining injectivity, reducing corrosion related costs, and minimizing equipment plugging. The American Petroleum Institute (API) has published recommendations for analysis of oilfield waters[6] and for biological analysis of injection waters.[7] The industry also has adopted standardized procedures for membrane/filterability tests.[8]

The water injection surface facilities prepare the water chemically for injection and pressure the water to the desired wellhead injection pressure. Depending on the source of the injection water, the water might need treatment to remove oxygen, prevent scale and corrosion, and chelate the iron. It also might need microbiological treatment and to be filtered to remove particulates.[9][10] What injection-water preparation techniques are used will vary from one waterflood project to the next. This page specifically discusses surface and produced waters, but the techniques that are covered here also are applicable to water that is produced from aquifers.

One major consideration in injection water treatment is to prevent the reservoir from being "inoculated" with sulfate-reducing bacteria that can cause a reservoir to develop an in-situ H2S concentration during the waterflood. This particularly is a problem when using ocean water, which contains both the sulfate-reducing bacteria and the sulfate ions that are their food supply. Once the sulfate-reducing bacteria have been introduced into a reservoir, they are essentially impossible to kill; however, they can be controlled with the injection of bactericides such as formaldehyde.[11][12]

Pressuring water to the desired injection pressure is the final step before it is piped to the injection wells. The wellhead injection pressure is calculated by subtracting the weight of the injection-water column from the desired bottomhole pressure, and then adding friction-flow pressure losses down the wellbore.

In a few reservoir situations, "dumpflooding" has been practiced. This is where a water-bearing formation above or below the oil reservoir is perforated, as is the oil-reservoir interval in those same wellbores. Water then is allowed to flow directly from the water-bearing formation into the oil-bearing formation, without ever bringing that water to the surface for any treating or pumping. This is a very simple approach to waterflooding, but generally it has been unsuccessful because the rate of water injection is uncontrolled and limited to the pressure difference between the two formations, which decreases with time as the water-bearing interval is depleted, particularly near the wellbore, and as the oil reservoir interval near the wellbore pressures up.

Surface facilities for produced fluids

The facilities for handling produced fluids for a waterflood must be designed with considerable flexibility. These facilities must handle a wide range of gas-, oil-, and water-production rates over the course of the waterflood, typically a period of several decades.

Initially, the production wells are likely to handle only oil and gas, without water production. When water breakthrough occurs, the water volumes will increase and, over time, water will become the great majority of the produced fluids. Accordingly, a variety of water issues must be considered. First is whether the produced fluids can be separated easily or must be treated with heat and/or chemicals in the surface equipment to achieve the desired level of separation. Second is whether the precipitation of scale in the producing wells or the production surface facilities is causing complications. Regarding scaling tendencies and because of increasing environmental concerns, the handling of naturally occurring radioactive materials (NORMs) has become an issue with respect to produced water discharges.[13]

Over the duration of a waterflood and as produced water volumes increase, there is likely to be the need and desire to reinject the produced water. In this situation, the produced water must be treated so that its oil and particulate content is sufficiently small that, when the water is reinjected, these very small oil droplets will not reduce the injectivity of the water injectors.[14] Oil fields in the North Sea and on Alaska’s North Slope have had to reinject large volumes of produced water.[15][16] Regarding injectivity losses, experimental coreflood data tend to be more pessimistic than is actual injector performance in the field.[12] In all cases, to reinject produced water successfully, that water must be treated to meet specifications determined to minimize those injectivity losses.[16]


  1. 1.0 1.1 1.2 1.3 1.4 Rose, S.C., Buckwalter, J.F., and Woodhall, R.J. 1989. The Design Engineering Aspects of Waterflooding, Vol. 11. Richardson, Texas: Monograph Series, SPE.
  2. Teufel, L.W. and Rhett, D.W. 1992. Failure of Chalk During Waterflooding of the Ekofisk Field. Presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, 4–7 October. SPE-24911-MS.
  3. 3.0 3.1 Perkins, T.K. and Gonzalez, J.A. 1985. The Effect of Thermoelastic Stresses on Injection Well Fracturing. SPE J. 25 (1): 78–88. SPE-11332-PA.
  4. Garon, A.M., Lin, C.Y., and Dunayevsky, V.A. 1988. Simulation of Thermally Induced Waterflood Fracturing in Prudhoe Bay. Presented at the SPE California Regional Meeting, Long Beach, California, USA, 23–25 March. SPE-17417-MS.
  5. Sylte, J.E., Hallenbeck, L.D., and Thomas, L.K. 1988. Ekofisk Formation Pilot Waterflood. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 2–5 October. SPE-18276-MS.
  6. RP 45, Recommended Practice for Analysis of Oilfield Waters, second edition. 1968. Washington, DC: API. (Reissued 1981, third edition, 1 August 1998)
  7. API RP 38, Recommended practice for biological analysis of subsurface injection waters, third edition. 1982. Washington, DC: API.
  8. TM0173-2005, Methods for Determining Quality of Subsurface Injection Water Using Membrane Filters. 2005. Houston: NACE International.
  9. Mitchell, R.W. 1978. The Forties Field Sea-Water Injection System. J Pet Technol 30 (6): 877–884. SPE-6677-PA.
  10. Hamouda, A.A. 1991. Water Injection Quality in Ekofisk—UV Sterilization and Monitoring Techniques. Presented at the SPE International Symposium on Oilfield Chemistry, Anaheim, California, USA, 20–22 February. SPE-21048-MS.
  11. Kriel, B.G., Crews, A.B., Burger, E.D. et al. 1993. The Efficacy of Formaldehyde for the Control of Biogenic Sulfide Production in Porous Media. Presented at the SPE International Symposium on Oilfield Chemistry, New Orleans, 2–5 March. SPE-25196-MS.
  12. 12.0 12.1 Frazer, L.C. and Bolling, J.D. 1991. Hydrogen Sulfide Forecasting Techniques for the Kuparuk River Field. Presented at the International Arctic Technology Conference, Anchorage, 29–31 May. SPE-22105-MS.
  13. Hart, A.D., Graham, B.D., and Gettleson, D.A. 1995. NORM Associated with Produced Water Discharges. Presented at the SPE/EPA Exploration and Production Environmental Conference, Houston, 27–29 March. SPE-29727-MS.
  14. Hjelmas, T.A., Bakke, S., Hilde, T. et al. 1996. Produced Water Reinjection: Experiences From Performance Measurements on Ula in the North Sea. Presented at the SPE Health, Safety and Environment in Oil and Gas Exploration and Production Conference, New Orleans, 9–12 June. SPE-35874-MS.
  15. Hsi, C.D., Dudzik, D.S., Lane, R.H. et al. 1994. Formation Injectivity Damage Due to Produced Water Reinjection. Presented at the SPE Formation Damage Control Symposium, Lafayette, Louisiana, USA, 7–10 February. SPE-27395-MS.
  16. 16.0 16.1 Martins, J.P., Murray, L.R., Clifford, P.J. et al. 1995. Produced-Water Reinjection and Fracturing in Prudhoe Bay. SPE Res Eng 10 (3): 176–182. SPE-28936-PA.

Noteworthy papers in OnePetro

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Online multimedia

Technical Aspects of Waterflooding. 2013.

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See also


Waterflood monitoring