Laboratory Measurements of Gas-Water Interfacial Tension at HP/HT Reservoir Conditions
- Jay Alan Rushing (Anadarko Petroleum Corp.) | Kent Edward Newsham (Apache Corp.) | Kees Cornelius Van Fraassen (U. of Calgary) | Sudarshan A. Mehta | Gordon R. Moore (R.C. Hutchins & Co. Ltd.)
- Document ID
- Society of Petroleum Engineers
- CIPC/SPE Gas Technology Symposium 2008 Joint Conference, 16-19 June, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2008. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 4.3.1 Hydrates, 4.1.5 Processing Equipment, 5.8.9 HP/HT reservoirs, 4.2.3 Materials and Corrosion, 4.6 Natural Gas, 4.1.2 Separation and Treating
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This paper presents preliminary results from a laboratory study designed to measure gas-water interfacial tension (IFT) at high-pressure/high-temperature (HP/HT) reservoir conditions. We used a pendant drop method with computer-aided image processing and analysis to measure gas-water IFT for several dry gas mixtures at pressures from 1,000 psia to 20,000 psia and temperatures of 300oF and 400oF. For our study, we define a dry gas as one that remains in the single hydrocarbon (gas) phase during the entire isothermal pressure depletion path from the reservoir through surface conditions. We also evaluated the effects of two common nonhydrocarbon contaminants (i.e., carbon dioxide and nitrogen) on the gas-water IFT behavior. Gas mixtures contained up to 20 mol% of either CO2 or N2 each. Finally, we evaluated the effects of total dissolved solids content in the connate water. All IFT measurements were made with either distilled water or synthetic brine with total dissolved solids concentrations of 100,000 ppm NaCl.
Study results demonstrate the complex interactions between pressure and temperature as well as gas and water compositions on gas-water IFT. Specifically, we observed the following behavior in the measured IFT:
?? temperature has a significant impact on gas-water IFT. Increasing the temperature from 300oF to 400oF tended to decrease the IFT for all pressures and gas compositions;
?? the effects of CO2 varied depending on pressure, temperature, and concentration. For a given temperature, the presence of CO2 in the gas decreased the IFT at higher pressures; however, the pressure at which this trend was observed varied. Generally, higher concentrations of CO2 resulted in lower IFTs over a much greater pressure range than for the gases with lower CO2 concentrations;
?? the effects of N2 also varied depending on pressure, temperature, and concentration. For lower N2 concentrations, we observed higher IFTs over the entire pressure range than for the gas with no N2. However, the gases with higher N2 concentrations had higher IFTs for the low pressure range only;
?? the presence of total dissolved solids in the water caused the gas-water IFT to be higher than the values measured with distilled water. Higher concentrations of NaCl dissolved in the water caused greater increases in IFT for all pressures, temperatures and gas compositions evaluated in the study.
The majority of natural gas resources targeted for exploration and development activities by the oil and gas industry prior to the 1980s were at depths less than 10,000 ft. Most of these natural gas resources exhibited normal pore pressure and temperature gradients. However, the natural gas industry has continued to extend exploration and development activities to depths much greater than 10,000 ft. In some geologic basins, these depths are approaching 20,000 to 25,000 ft. Many of these deep natural gas resources are also characterized by both abnormally high pore pressure and temperature gradients, i.e. high-pressure and high-temperature (HP/HT) reservoir conditions. And, natural gases at HP/HT conditions frequently contain nonhydrocarbon contaminants (e.g., CO2, N2 and/or water vapor).
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