Measurement and Modeling Gas-Water Interfacial Tension at High Pressure/High Temperature Conditions
Date
2014-01-17
Authors
Journal Title
Journal ISSN
Volume Title
Publisher
Abstract
Many reservoir engineering studies require knowledge of the surface tension of water-gas and water-oil systems. Examples are imbibition studies and calculations of fluid saturations in water-gas and water-oil regions. Capillary pressure is directly proportional to the surface tension between the two phases. Because at reservoir conditions the surface tension of water–gas and water-oil systems is generally about one order of magnitude higher than surface tension of equilibrium oil-gas system, one would expect the capillary pressure to strongly influence the flow process in water-gas and water-oil systems.
The majority of natural gas resources targeted for exploration and development activities by the oil and gas industry prior to the 1980s were at depth 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 depth much greater than 10,000 ft. In some geological 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. Natural gases at HP/HT conditions frequently contain non-hydrocarbon contaminants (e.g., CO2, N2 and/or water vapour)
Similar to more conventional resources at lower pressures and temperatures, effective exploitation of these deep, natural gas resources requires accurate description of key reservoir rock and fluid properties including gas-water interfacial tensions (IFT) to quantify the capillary pressure based vertical distribution of gas-in-place and the potential recoverable gas, i.e., reserves. Unfortunately there are few gas-water IFT data (especially at high pressure/high temperature conditions) published in the petroleum industry. Even the few existing laboratory data are often inconsistent (Hough, et al., [1951], Jennings and Newman [1971]). Most of the published data are measured at pressures less than 15,000 psi and temperatures less than 356ºF. In addition most data were measured with either pure or two-component hydrocarbon systems rather than natural gas mixtures. Also there are few published data showing the
iii
effects of non-hydrocarbon contaminants (CO2 or N2) on gas-water IFT at high pressure and high temperature reservoir conditions.
To address these inadequacies an extensive laboratory program has been arranged in the current study to evaluate a range of dry gas properties at high pressure/high temperature conditions. Pendent drop method has been used with computer-aided image processing and analysis to measure gas-water IFT for several pure gases (CO2, N2, methane) and mixtures of hydrocarbons and non-hydrocarbon gas contaminants (CO2 and N2) up to 20 mole % at pressures from 1,000 psi to 20,000 psi and temperatures from 122ºF to 400ºF. The effects of pressure, temperature, gas composition and two common non-hydrocarbon contaminants (i.e., CO2 and N2) evaluated on the gas-water IFT behaviour. All the IFT measurements were made with distilled water. Rather than relying on correlations or previously published data, water-vapor-saturated gas as well as gas-saturated water densities were measured directly at each pressure and temperature.
Time dependent interfacial tension (dynamic IFT) and constant equilibrium IFTs for gas-water systems at pressures and temperatures representative of gas well conditions and higher were measured to calculate the critical flow rate necessary to keep gas wells unloaded.
In this current dissertation, based on measured data and evaluated trends for different gas mixtures and their contaminants at pressures from 1,000 psi to 20,000 psi and temperatures from 122ºF to 400ºF, correlations as a function of pressure, temperature, and gas composition are proposed based on Parachor method.
The linear gradient theory has been used to predict methane-water interfacial tension at HP/HT conditions. The best empirical correlation has been found by minimizing the difference between the calculated IFT values using the proposed model and the experimental methane-water IFT values by using an objective function. The proposed model is in excellent agreement with the experimental IFT data with an absolute average error of less than 2.5%.
Description
Keywords
Engineering, Engineering--Petroleum
Citation
Shariat, A. (2014). Measurement and Modeling Gas-Water Interfacial Tension at High Pressure/High Temperature Conditions (Doctoral thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca. doi:10.11575/PRISM/26843