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Produced oilfield water

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Extraction of oil and gas from underground reservoirs often is accompanied by water or brine, which is referred to as produced water. As reservoirs mature, especially if secondary or tertiary recovery methods are used, the quantity of water climbs and often exceeds the volume of the hydrocarbons before the reservoir is exhausted. The cost of producing, handling, and disposing of the produced water often defines the economic lifetime of a field and the actual hydrocarbon reserves; therefore, understanding and predicting the aspects, behavior, and problems induced by the produced-water flow is important. This page provides an introduction to produced water, production mechanisms, economics, and characterization.

Importance of produced water

Because the produced water is not usually a revenue stream, the emphasis on water-flow prediction, technology development, and engineering application has not traditionally been a major focus of oil- and gas-production engineering. This is complicated by the multidisciplinary nature of produced water issues, involving

  • Chemistry
  • Hydrodynamics
  • Surface/interfacial science
  • Materials science
  • Corrosion
  • Mechanical, chemical, and petroleum engineering
  • Environmental regulators

Produced water is chemically very complex. The process of producing and processing produced water causes changes in temperature and pressure. The addition of treating chemicals, along with the presence of coproduced gas, oil, and likely solids, changes the produced-water properties and behavior. Understanding how production perturbs the chemical state including the salt composition of the produced water is the key to predicting and controlling many problems. Also, the salt composition is an excellent source of information about the particular reservoir and the reservoir depletion process.

Diagnosing the source of the increased water production from a well is important in deciding whether to pursue water-shutoff options. First, if the field is waterflooded, water must be produced to recover the oil in accordance with relative permeability; only water in excess of this should be a target for remedial treatments. If this is edge water, water shutoff can be difficult, even with polymer-gel technology. Polymer-gel water-shutoff treatments have proved successful in cases in which faults intersect the wellbore, causing a channel for water flow. If excess water production is bottomwater, the well can be plugged back. However, excess water production is often the result of intrusive water from a shallow sand or another aquifer gaining access to the well from a leaky casing or faulty completion. This source of intrusive water can be repaired, depending on the economics.[1]

Waters produced with petroleum are growing in importance from an environmental standpoint. In the past, these waters were considered waste and required disposal. Early on, less attention was paid to the fate of the produced water in the environment, because, after all, it was only water. It later became clear that possible contamination from produced-water disposal practices, especially on the surface, needs to be considered. The bulk of produced water from land-based operations is reinjected. Injection of these waters back into the petroleum reservoir serves three purposes: it produces additional petroleum through secondary recovery (waterflooding), it uses a potential pollutant, and, in some areas, it controls land subsidence.

Secondary and tertiary oil-recovery processes that use water injection result in the production of even more water with the oil. To inject these waters into reservoir rocks, suspended solids and oil must be removed to an appropriate degree to prevent plugging. Most offshore platforms dispose of their produced water directly into the ocean, but have to meet increasingly stringent regulations on the entrained and dissolved oil and other chemicals that are in the produced water. Some offshore operators are considering produced-water reinjection to avoid meeting these expensive ocean-disposal requirements.

Where does the water come from?

In the original reservoir, the pores in the mineral matrix contain the natural fluids at chemical equilibrium. Because reservoir rock is largely of sedimentary origin, water was present at the time of rock genesis and, therefore, is trapped in the pores of the rock. Water may also move or migrate according to the hydraulic pressures induced by geological processes that also form the reservoirs.

In hydrocarbon reservoirs, some of the water is displaced by the hydrocarbon, but some water always remains. If the rock originated in a sea or ocean, then it will be saline. Rocks deposited in lakes, rivers, or estuaries have fresher water. Originally, the water was in chemical equilibrium with the mineral suite of the rock, but, on invasion of the oil and gas, a new equilibrium with those phases was achieved. Thus, there are both equilibria and chemical-reaction dynamics associated with the inorganic (mineral) phases and the oil and gas phases that are important to understand. Water is an excellent solvent; it will react to dissolve many of the phases it contacts.

Primary production

When oil or gas is flowed or lifted from a reservoir, some water inevitably accompanies the other phases. This is a consequence of the relative permeability behavior of the rock. In particular, if the water saturation is above the irreducible water saturation (Swr), then some water will move along with the oil and gas phases present as the fluids flow from the pores of the reservoir rock. This water is in chemical equilibrium with the rock and gas phases under the original temperature and pressure present in the reservoir. Because the pressure and temperature change as a consequence of producing the oil and gas, the chemical equilibrium of the water is perturbed. The perturbation can have severe detrimental effects. The operator must evaluate these effects and define their economic and environmental impacts and if required develop mitigation methods.

The chemical changes occurring during primary production are largely a result of cooling the water and reducing the pressure as it comes up the tubing into the surface production facilities. However, more complex behavior can result if multiple zones or reservoirs are coproduced either within the same wellbore downhole or mixed on the surface. The mixing can lead to scale deposition, corrosion, and other effects. Artificial lift can also alter the stability of the water. In particular, gas lift and jet pumps are particular artificial lift examples in which the chemical composition of the system may change because of the addition of foreign gas or water streams in the wellbore. Another impact of artificial lift is on the pressure profile of the system. Electrical submersible pumps can locally heat the water enough to enter a scaling regime (particularly for calcium carbonate) in the area of the motor, deposit scale on it, and cause the motor to burn out.

During primary production, the water cut may increase as the reservoir is depleted. This is particularly important in reservoirs that have natural waterdrives so that a water aquifer is in both pressure and hydraulic communication with the hydrocarbon reservoir. Thus, as the hydrocarbon is produced, the water from the aquifer is drawn in to fill the void left behind, and the water saturation of the rock is increased. The pressure in the reservoir attempts to stay constant. Depending on the efficiency of the hydraulic connection to the aquifer, the pressure decline over time will be reduced, perhaps to zero in some cases. However, the proportion of water produced will rise until the cost of handling the water exceeds the value of the hydrocarbons produced. Oil and gas reserves of the typical reservoir are limited by this water-handling cost. Clearly, produced-water issues are central, although this may not be immediately apparent because only the hydrocarbons produce revenue.

Economics of produced water

Except in the case of gas production from coal seams, water production rates usually start slowly from the initial development of a property. Facility designers may deliberately forestall construction and installation of water-handling equipment at the beginning of a project to reduce upfront capital costs. The eventual appearance of water production requires the addition of the capital investment and operational expense to handle the growing water rates, which do not generate revenue to offset the cost. The natural tendency for companies is to minimize the immediate expense; as a result, companies often underdesign the equipment or fail to budget properly for operational expenses.

Fig. 1 demonstrates the impact of rising water cut on the total cost of producing a barrel of oil assuming a constant water treatment cost of US $0.10 per barrel of water. Actual water costs can be lower or higher. This sobering fact vividly illustrates the importance of improving the technology of water treatment to lower the unit cost over time as reservoirs mature. Most secondary and tertiary oil reserves are produced at high water cuts.

Typically, the connate or formation water (as the original water in the reservoir is called) is more saline than surface water. Many oil and gas reservoirs are in rocks originally lying at the bottom of oceans and were saturated with the seawater present at the time. Of course, the composition of these ancient seawaters may be significantly different than current seawater. Additionally, as the sediments were buried and the temperature and pressure increased, the chemical composition of the water and rock changed to maintain chemical equilibrium. These reactions took place over geologic time, so the aqueous phases of most oil reservoirs are in true chemical equilibrium with the mineral suite with which it is in contact. The converse is not necessarily true; many examples of meta-stable mineral suites are known in hydrocarbon reservoirs, probably because of mass-transfer limitations. Thus, one use of an examination of the water composition by geochemists is to provide insight into the burial history of the sediments in the reservoir. In particular, the isotope ratios of the elements are indicative of the origins of the waters and, in some cases, of the mechanisms by which the hydrocarbons were produced during geologic time.

Besides the commonly thought of species or components in the water such as salts and dissolved minerals, oilfield waters also contain organic species. Much less attention has been allocated to the organic chemical species in the produced water, yet they also have consequences. In particular, new environmental concerns about water and air pollution have required more focus on the dissolved organic species in the water. Some examples of these species include the volatile organic acids like:

  • formic, acetic, propionic, and butyric acids
  • naphthenic acids
  • dissolved aromatic compounds like benzene, toluene, and xylenes

The latter species are particularly important for offshore overboard water-disposal operations, because they are often included in the measurements of the oil-in-water carryover, which are limited by law in many areas. The carryover of oil and other hydrocarbons in the produced water is one of the most important issues facing the surface engineer.

How do we characterize produced water?

Because produced waters are chemically complex systems, compositional computer models are needed to predict their behavior accurately. This technology has advanced steadily since the mid-1970s. One of the first thermodynamics-based water-chemistry computer models was WATEQ, developed by Truesdale and Jones at USGS, along with its database of 522 dissolved species and 192 mineral phases. This computer code was converted to FORTRAN IV in 1974 and became known as WATEQF. It has become the standard against which all future chemistry models are measured. Several major efforts to improve and extend the range of applications of these chemistry models have resulted in sophisticated programs to model water flow and geochemical reactions in reservoirs, production of water to surface, and water-chemistry changes during processing in surface facilities. These changes can have extremely serious impacts through precipitation of scales and corrosion; therefore, the accuracy of these predictions affects the profitability and, sometimes, the viability of many oil and gas projects.

Along with the computer models is the improvement in analytical chemistry technology needed to characterize the individual water in a particular system and provide the fundamental chemical equilibrium and kinetics data that form the basis for the computer models. The analytical instruments now used include:

  • Inductively coupled plasma spectroscopy (ICP)
  • Ion chromatography (IC)
  • Capillary electrophoresis (CE)
  • Ion selective electrodes
  • Automatic titrators

In certain special analyses, more advanced techniques are used such as mass spectroscopy, high performance liquid chromatography (HPLC), and various "hyphenated techniques" such as inductively coupled plasma-mass spectroscopy (ICP-MS), gas chromatography-mass spectroscopy, and HPLC-mass spectroscopy. In circumstances in which speciation of the inorganic constituents is particularly of interest, ion chromatography can be used along with ICP or ICP-MS detection. Laser light-scattering instruments are usually used for looking at suspended particles and entrained oil droplets and their size distribution.

One of the most significant produced water developments during the last two decades has been in the environmental impact and regulatory area. It is no longer a technical issue regarding the composition and fate of the produced water from oil and gas extraction (and transportation and refining, also). In many cases, government regulations limit or change the options available and may define the degree of characterization through sampling and analysis imposed on the operator. In the US, produced water is still an exempt effluent and need not meet the more stringent requirements of hazardous wastes; however, other federal and state regulations impose many other requirements that must be monitored, met, and documented continuously. These regulations, the priority of concerns, and their degree of enforcement differ worldwide. When operating in different areas, familiarization with these regulations is mandatory, preferably during the conceptual facility- and field-design stages of a new development. Regulations worldwide have become more stringent. When choosing a particular method to handle produced water, that method’s viability for the long term must be considered.


  1. Elworthy, R.T. 1922. A Field Method and Apparatus for the Determination by Means of Electrical Conductivity Measurements the Character of Waters Leaking into Oil and Gas Wells. Summary Report No. 605, US Department of the Interior, Bureau of Mines, Washington, DC.

Noteworthy papers in OnePetro

Use this section to list papers in OnePetro that a reader who wants to learn more should definitely read

Online multimedia

Dalrymple, Dwyann. 2013. Produced Water Management - “Waste to Value”.

Walsh, John M. 2012. Selection and Troubleshooting of Flotation Equipment for Produced Water Treating.

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Produced water properties

Sampling and analysis of produced water

Mixing of produced water

Dissolved constituents in produced water

Suspended solids in produced water


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E. Dwyann Dalrymple