Underground Injection for Disposal

Fact Sheet - Underground Injection for Disposal

   
 
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Injection into underground formations represents the most common approach for onshore management of produced water. Under U.S. Environmental Protection Agency (EPA) rules, produced water injection wells are classified as Class II wells. Class II wells are further subdivided into II-R (enhanced recovery), II-D (disposal), or II-H (hydrocarbon storage). Most produced water is injected to maintain reservoir pressure and hydraulically drive oil toward a producing well. This type of injection for "enhanced recovery" is discussed in a separate fact sheet. This fact sheet describes underground injection of produced water solely for disposal. The figure at right shows a typical injection wellhead.

  Injection well at Texas waste disposal facilityInjection well at Texas waste disposal facility; Source: J. Veil, Argonne National Laboratory.

Significant volumes of produced water are injected in the United States. Virtually all states with oil and gas production operations also have produced water injection wells. According to the Ground Water Protection Council, approximately 170,000 Class II wells are found in 31 states (GWPC undated). In early 2003, Argonne interviewed staff from oil and gas agencies in three large oil- and gas-producing states (California, New Mexico, and Texas) to learn the number of injection wells in each state, and what percentage were used for enhanced oil recovery or for disposal. The numbers of wells and water volumes injected are estimates. Nevertheless, they highlight the importance of injection as a produced water management option.

  • California had nearly 25,000 produced water injection wells. The annual injected volume is approximately 1.8 billion bbl, with about 20% injected for disposal.
  • New Mexico had 903 permitted disposal wells, with 264 of them active. Approximately 190 million bbl of produced water is injected for disposal.
  • Texas had 11,988 permitted disposal wells, with 7,405 of them active. In 2000, approximately 1.2 billion bbl of produced water were injected into nonproducing formations, and 1 billion bbl were injected into producing formations. In sum, operators in these three states inject more than 4 billion bbl of produced water per year for disposal.

Injection Well Siting and Construction 
Operators injecting for disposal will typically seek formations that exhibit the right combination of permeability, porosity, injectivity, and other geologic features enabling the injected water to enter the formation under pressures lower than fracture pressure. The injection formation should be geologically isolated from any underground source of drinking water (USDW) and from hydrocarbon-producing formations (unless the injection is for enhanced recovery). Operators should avoid areas with excessive faulting, fractures that extend vertically, or other improperly cemented well bores.

  Injection well cross sectionCross-section drawing of an injection well; Source: U.S. Environmental Protection Agency.

Class II injection wells are constructed so that injected fluids are conveyed to the authorized injection zone and do not migrate into USDWs. Class II wells are drilled and constructed with steel pipe (called casing) cemented in place to prevent the migration of fluids into USDWs. Surface casing is cemented from below the lowermost USDW up to the surface to prevent fluid movement. Cement is also placed behind the injection casing at critical sections to confine injected fluids to the authorized injection zone. A typical produced water injection well is also equipped with injection tubing, through which the fluids are pumped from the surface down into the receiving geologic formations (GWPC undated). The figure below shows a cross-section drawing of an injection well with casing, cement, and tubing.

Treatment Prior to Injection
It is important to ensure that the produced water injectate is compatible with the receiving formations to prevent premature plugging of the formation or damage to equipment. It may therefore be necessary to treat the water prior to injection to control excessive solids, dissolved oil, corrosion, chemical reactions, or growth of microbes.

Solids are usually treated by gravity settling or filtration. Residual amounts of oil in the produced water not only represent lost profit for producers, but can also contribute to plugging of receiving formations. Various treatment chemicals are available to break emulsions or make dissolved oil more amenable to oil removal treatment.

Corrosion can be exacerbated by various dissolved gases - primarily oxygen, carbon dioxide, and hydrogen sulfide. Oxygen scavengers and other treatment chemicals are available to minimize levels of undesirable dissolved gases.

The water chemistry of a produced water sample does not necessarily match the receiving formation. For example, various substances dissolved in produced water could react with the rock or other fluids in the receiving formation, and trigger undesirable consequences. Before beginning a water flood operation, it is important to analyze the constituents of the produced water with the purpose of avoiding chemical reactions that form precipitates. If necessary, treatment chemicals can minimize undesirable reactions.

Bacteria, algae, and fungi can be present in produced water. They can also be introduced in the course of water handling at the surface. Bacteria, algae, and fungi are generally controlled through filtration or the addition of biocides.

References 
GWPC, undated, "Injection Wells, An Introduction to Their Use, Operation, and Regulation," prepared by the Ground Water Protection Council, Oklahoma City, OK. Available at http://www.gwpc.org/e-library/documents/general/Injection%20Wells-%20An%20Introduction%20to%20Their%20Use,%20Operation%20and%20Regulation.pdf [PDF].

Veil, J.A., M.G. Puder, D. Elcock, and R.J. Redweik, Jr., 2004, "A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane," prepared by Argonne National Laboratory for the U.S. Department of Energy, National Energy Technology Laboratory, January. Available at http://www.evs.anl.gov/pub/dsp_detail.cfm?PubID=1715.

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