Physical and Rheological Behavior of HP/HT Fluids in the Presence of Water
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 94068, "Physical and Rheological Behaviour of High-Pressure/High-Temperature Fluids in Presence of Water," by F. Gozalpour, SPE, A. Danesh, SPE, M. Fonseca, A.C. Todd, SPE, B. Tohidi, SPE, and Z. Al-Syabi, Heriot-Watt U., prepared for the 2005 SPE Europec/EAGE Annual Conference, Madrid, Spain, 13–16 June.
An equation-of-state (EOS) -based phase-behavior model was developed to describe the behavior of high-pressure/high-temperature (HP/HT) fluids in the presence of water. The interaction between water and hydrocarbon was simulated by addition of an asymmetric (nonrandom) term to the attractive term of a conventional (random) mixing rule. Vapor/liquid and liquid/liquid hydrocarbon/water solubility data for a wide range of hydrocarbons were used to determine the binary interaction parameters of the conventional and nonrandom terms. The phase-behavior model was evaluated against two-phase and three-phase equilibrium data of hydrocarbon and water binary and ternary mixtures not used in developing the model.

Introduction
Exploitation of HP/HT reservoirs increasingly is being pursued in the North Sea. The U.K. Dept. of Trade and Industry defines HP/HT fields as those with temperatures greater than 149°C and pressures greater than 68 948 kPa. Franklin field, with a 202°C temperature and 111 695-kPa pressure, is probably the harshest HP/HT field in production or under development in the North Sea. HP/HT reservoir fluids can be gas condensate or oil, depending on reservoir conditions. For example, Franklin is a gas condensate field, but Heron field, with a 177°C temperature and 88 804-kPa pressure, is an oil field.
Reliable information about fluid phase and flow properties within the reservoir, wellbore, and transfer lines is required for process design and management. Physical and rheological data about HP/HT fluids play a vital role in well-capacity estimation and well-number optimization. This information on HP/HT fluids generally is scarce. Volatility of heavy compounds increases with pressure and temperature and can result in gas-condensate fluids that are rich in heavy compounds. Water volatility also increases sharply with temperature; hence, water can be a major constituent of HP/HT fluids and, therefore, should be considered. In reservoir fluids, water is a polar component in comparison to hydrocarbons, which are nonpolar. Phase-behavior models with conventional mixing rules that do not consider water polarity may fail to predict water solubility in hydrocarbon phases. A higher water content of HP/HT fluids compared to conventional reservoir fluids also could affect mixture viscosity. Reliability of phase-behavior and viscosity predictive models that have not been evaluated at HP/HT conditions is questionable for HP/HT fluids.

HP/HT-Fluid Phase Behavior
The mathematical relationship for the proposed phase-behavior model is summarized in Appendix A of the full-length paper. EOSs are developed for pure compounds. Mixing rules are required to calculate the EOS parameters for mixtures. The van der Waals random-mixing rule is used widely in the petroleum industry to calculate the EOS parameters for hydrocarbon mixtures. The mixing rule has one adjustable parameter for each pair of components involved, and it is called the (random) binary interaction parameter (BIP), kij.
To simulate the behavior of a polar component such as water in a hydrocarbon mixture, the random mixing rule was modified by adding an asymmetric (nonrandom) term to its attractive term. The introduced nonrandom term also has one adjustable parameter for every water/hydrocarbon pair that is called the nonrandom binary interaction parameter,
lpi. The conventional kij and lpi BIPs for water/hydrocarbon were determined by matching the solubility data of hydrocarbon/water systems.