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Dissolved constituents in produced water

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Knowledge of the dissolved constituents is important because these constituents are related to the origin and/or migration of an oil accumulation, as well as to the disintegration or degradation of an accumulation.[1] The concentrations of organic constituents in oilfield brines vary widely. This page discusses the occurrence of dissolved gases, organic constituents, and dissolved solids in produced water.

Dissolved gases

Large quantities of dissolved gases are contained in oilfield brines. Most of these gases are hydrocarbons; however, other gases such as CO2, N2, and H2S often are present. The solubility of the gases in water generally decreases with increased water salinity and temperature and increases with pressure.

Hundreds of drillstem samples of brine from water-bearing subsurface formations in the US Gulf Coast area were analyzed to determine the amounts and kinds of hydrocarbons.[2] The chief constituent of the dissolved gases usually was methane, with measurable amounts of ethane, propane, and butane.

The concentration of the dissolved hydrocarbons generally increased with depth in a given formation and increased basinward with regional and local variations. In close proximity to some oilfields, the waters were enriched in dissolved hydrocarbons. Up to 14 scf dissolved gas/bbl water was observed in some locations.

Organic constituents in oilfield waters

In addition to the simple hydrocarbons, many organic constituents in colloidal, ionic, and molecular form occur in oilfield brines.[2] Because the analytical problems are difficult and very time consuming, many organic constituents present in oilfield brines were not determined. In recent years, some of these organic constituents have been measured quantitatively, because better analytical techniques have been adapted to the difficult produced-water matrix.

In general, the more alkaline the water is, the more likely it will contain higher concentrations of organic constituents. The bulk of the organic matter consists of anions and salts of organic acids; however, other compounds also are present. Explorationists can use such data to look for anomalies in these constituents, while environmental scientists can use it to evaluate spills and effluents. The corrosion engineer needs to know how much of the inhibitor added at the well remains in the produced water so that its corrosion can be controlled. Organic-scale-inhibitor compounds are monitored routinely to verify that their concentration exceeds the minimum effective dose.

Knowledge of the concentrations of benzene, toluene, xylenes, and other components in oilfield brines is used in exploration. The solubilities of some of these compounds in water at ambient conditions and in saline waters at elevated temperatures and pressures have been determined.[3][4]

However, the actual concentrations of these and other organic constituents in subsurface oilfield brines are another matter. It has been shown experimentally that the solubilities of some organic compounds found in crude oil increase with temperature and pressure if pressure is maintained on the system. The increased solubilities become significant above 150°C. The solubilities decrease with increasing water salinity. Waters associated with paraffinic oils are likely to contain fatty acids, while those associated with asphaltic oils more likely contain naphthenic acids.

Quantitative recovery of organic constituents from oilfield brines is difficult. Temperature and pressure changes, bacterial actions, adsorption, and the high inorganic/organic-constituents ratio in most oilfield brines are some reasons why quantitative recovery is difficult. The effect of bacteria on the samples is particularly significant.[5] Unless samples are stabilized with an effective dose of biocide, significant or complete depletion of the organic acids is likely before the sample can be analyzed. Total loss of 300 ppm of acetic acid within 24 hours in an unstabilized produced-water sample was observed, while one containing 200 ppm of biocide suffered no loss of acetic acid.

Dissolved solids

Oilfield waters include all waters or brines found in oil fields. Such waters have certain distinct chemical characteristics.[6][7] Approximately 70% of world petroleum reserves are associated with waters containing more than 100 g/L of dissolved solids.[8] Water containing dissolved solids in excess of 100 g/L can be classified as brine. Waters associated with the other 30% of petroleum reserves contain less than 100 g/L of dissolved solids. Some of these waters are almost fresh; however, the presence of fresher waters usually is attributed to invasion after the petroleum accumulated in the reservoir trap.

Examples of some of the low-salinity waters can be found in the Rocky Mountain areas in Wyoming fields such as[9][10]:

  • Enos Creek
  • South Sunshine
  • Cottonwood Creek

The Douleb oil field in Tunisia is another example. Extremely fresh water was discovered in the Cano Limon, Colombia, oil field with only 300 mg/L total dissolved solids (TDS), mostly sodium bicarbonate and sodium acetate. The chloride content was only approximately 20 mg/L.

The composition of dissolved solids found in oilfield waters depends on several factors. Some of these factors are:

  • Composition of the water in the depositional environment of the sedimentary rock
  • Subsequent changes by rock/water interaction during sediment compaction
  • Changes by rock/water interaction during water migration (if migration occurs)
  • Changes by mixing with other waters, including infiltrating younger waters such as meteoric waters.

The following are definitions of some types of water that may be encountered:

  • Meteoric water. This is water that recently was involved in atmospheric circulation; furthermore, "the age of meteoric groundwater is slight when compared with the age of the enclosing rocks and is not more than a small part of a geologic period." [11]
  • Seawater. The composition of seawater varies somewhat but, in general, will have a composition relative to the following (in mg/L): chloride—19,375, bromide—67, sulfate—2,712, potassium—387, sodium—10,760, magnesium—1,294, calcium—413, and strontium—8.
  • Interstitial water. Interstitial water is the water contained in the small pores or spaces between the minute grains or units of rock. Interstitial waters are syngenetic (formed at the same time as the enclosing rocks ) or epigenetic (originated by subsequent infiltration into rocks).
  • Connate water. The term "connate" implies born, produced, or originated together (connascent); therefore, connate water probably should be considered interstitial water of syngenetic origin. Connate water of this definition is fossil water that has been out with the atmosphere for at least a large part of a geologic period. The implication that connate waters are "born with" the enclosing rocks is an undesirable restriction.[11]
  • Diagenetic water. Diagenetic waters are those changed chemically and physically, before, during, and after sediment consolidation. Some of the reactions that occur in or to diagenetic waters include bacteria change, replacement (dolomitization), infiltration by permeation, and membrane filtration.
  • Formation water. Formation water, as defined here, is water that occurs naturally in the rocks and is present in them immediately before drilling.
  • Juvenile water. Juvenile water is water derived from primary magma.
  • Condensate water. Water associated with gas is carried as vapor to the surface of the well, where it condenses and precipitates because of temperature and pressure changes. This water occurs more often in the winter, in colder climates, and in gas-producing wells. This water is easy to recognize because it contains a relatively small amount of dissolved solids, mostly derived from reactions with chemicals in or on the well casing or tubing or carried as a mist in high-rate-gas-flow wells.

Importance of water analysis

Water analyses may be used to identify the water source. In the oil field, one of the prime uses of these analyses is to determine the source of extraneous water in an oil well so that casing can be set and can prevent such water from flooding the oil or gas horizons. In some wells, a leak may develop in the casing or cement, and water analyses are used to identify the water-bearing horizon so that the leaking area can be replaced. With the current emphasis on water pollution prevention, it is very important to locate the source of a brine so that remedial action can be taken.

Historically, comparisons of water analysis data are tedious and time consuming; therefore, graphical methods were mainly used for positive, rapid identification. A number of systems were developed, all of which have some merit, with the most popular being the Stiff diagram (Fig. 1). The new computer chemistry models mentioned previously have largely displaced the manual graphics, but the visual comparisons are still useful in certain situations.

References

  1. Zarrella, W.M. et. al. 1967. Analysis and Significance of Hydrocarbons in Subsurface Brines. Geochim. Cosmochim. Acta 31: 1155.
  2. 2.0 2.1 Buckley, S.E., Hocott, C.R., and Taggan, M.S. Jr. 1958. Distribution of Dissolved Hydrocarbons in Subsurface Waters. Habitat of Oil, 850-882, ed. L.C. Weeks. Tulsa, Oklahoma: AAPG.
  3. McAuliffe, C.D. 1966. Solubility in Water, Paraffin, Cyclobrffin, Olefin, Acetylene, Cyclo-olefin and Aromatic Hydrocarbons. J. Phys. Chem. 70 (4):1267. http://dx.doi.org/10.1021/j100876a049
  4. Prince, L.C. 1976. Aqueous Solubility of Petroleum as Applied to Its Origin and Primary Migration. AAPG Bull. 60 (2) 213-244.
  5. Postgate, J.R. 1979. The Sulfate Reducing Bacteria, 151. New York City: Cambridge University Press.
  6. Noad, D.F. 1962. Water Analysis Data: Interpretation and Applications. J Can Pet Technol 1 (2): 82-89. http://dx.doi.org/10.2118/62-02-07
  7. Ostroff, A.G. 1979. Introduction to Oilfield Water Technology, 394. Houston, Texas: NACE.
  8. Bright, J. 1983. Oilfield Water Analysis Data Bank. DOE/EC/10116-2. Washington, DC: US DOE.
  9. Coffin, C.R. and DeFord, R.K. 1934. Waters of the Oil and Gas Bearing Formations of the Rocky Mountains. Survey Pov Memorial Volume, AAPG 927-952.
  10. Crawford, J.G. 1949. Waters of Producing Fields in the Rocky Mountain Region. Trans. of AIME 179 (1): 264-286. http://dx.doi.org/10.2118/949264-G
  11. 11.0 11.1 White, D.E. 1957. Magmatic, Connate, and Metamorphic Water. Geol. Soc. Am. Bull. 68 (1957): 1659.

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