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Produced water density

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The formation water density is defined as the mass of the formation water per unit volume of the formation water. The density of formation water is a function of:

  • Pressure
  • Temperature
  • Dissolved constituents

Density is determined most accurately in the laboratory on a representative sample of formation water.[1] . Electronic densiometers can quickly determine the density with accuracy of +/−0.00001 g/cm3 over a wide range of temperatures, although most oilfield data are reported at a 60°F reference temperature.

Measuring formation water density

In the past, density in metric units (g/cm3) was considered equal to specific gravity; therefore, for most engineering calculations, density and specific gravity were interchangeable in most of the older designs.[2] However, process simulation software used in modern facility design uses the true density or specific gravity of the water to avoid significant cumulative errors, especially when working with low-gravity heavy oils or concentrated brines. Thus, water samples taken for providing input to these programs must have accurate densities determined experimentally. Alternatively, some modern multicomponent chemical equilibrium simulators accurately calculate the densities (and other physical properties) from the complete analysis of the waters within the temperature and pressure range of the thermodynamic database. Experimental verification of the computer predictions should be performed in cases in which any error could have significant impact.

When laboratory data or actual water samples are unavailable, the density of formation water at reservoir conditions can be estimated roughly (usually to within +/−10%) from correlations (Figs. 1 through 3). The only field datum necessary is the density at standard conditions, which can be obtained from the salt content by use of Fig. 1. The salt content can be estimated from the formation resistivity, as measured from electric-log measurements. The density of formation water at reservoir conditions can be calculated in four steps.

  • With the temperature and density at atmospheric pressure, obtain the equivalent weight percent NaCl from Fig. 2.
  • Assuming the equivalent weight percent NaCl remains constant, extrapolate the weight percent to reservoir temperature and read the new density.
  • Knowing the density at atmospheric pressure and reservoir temperature, use Fig. 3 to find the increase in specific gravity (density) when compressed to reservoir pressure. For oil reservoirs below the bubblepoint, the "saturated-with-gas" curves should be used; for water considered to have no solution gas, the "no-gas-in-solution" curves should be used. These curves were computed from data given by Ashby and Hawkins.[3]
  • The density of formation water (g/cm3) at reservoir conditions is the sum of the values read from Figs. 2 and 3. They can be added directly because the metric units are referred to the common density base of water (1 g/cm3). The metric units can be changed to customary units (lbm/ft3) by multiplying by 62.37.

Another approach to calculating water density is to first calculate the density of formation water at standard conditions with McCain’s correlation.[4][5]


where density is in lbm/ft3, and S is salinity in weight percent. Then, density at reservoir conditions is calculated by dividing the density in Eq. 1 by the brine FVF at the reservoir temperature and pressure of interest.

The specific gravity of formation water can be estimated, if the TDS is known, with


where Csd = concentration of dissolved solids (also known as TDS), mg/L.

Rogers and Pitzer[6] provide precise but very detailed calculations. They tabulated a large number of values of compressibility, expansivity, and specific volume vs. molality, temperature, and pressure. A semiempirical equation of the same type was found to be effective in describing thermal properties of NaCl (0.1 to 5 molality) and was used to reproduce the volumetric data from 0 to 300°C and 1 to 1,000 bars.


  1. Saline and Brackish Waters, Sea Waters and Brines. 1982. Annual Book of ASTM Standards, American Soc. for Testing and Materials, Part 31—Water, Section VII, Philadelphia.
  2. Collins, A.G. 1975. Geochemistry of Oilfield Waters. New York: Elsevier Scientific Publishing Co.
  3. Ashby, W.H. Jr. and Hawkins, M.F. 1948. The Solubility of Natural Gas in Oil-Field Brines. Paper presented at the 1948 SPE Annual Meeting, Dallas, 4–6 October.
  4. McCain, W.D. Jr.: McCain, W.D. Jr. 1990. The Properties of Petroleum Fluids, second edition. Tulsa, Oklahoma: PennWell Books.
  5. McCain Jr., W.D. 1991. Reservoir-Fluid Property Correlations-State of the Art (includes associated papers 23583 and 23594 ). SPE Res Eng 6 (2): 266-272. SPE-18571-PA.
  6. Rogers, P.S.Z. and Pitzer, K.S. 1982. Volumetric Properties of Aqueous Sodium Chloride Solutions. J. Phys. Chem. Ref. Data 11 (1): 15–81.

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See also

Produced oilfield water

Produced water properties

Oil density

Gas properties

Sampling and analysis of produced water


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