Gas-condensate reservoirs are an essential part of Saudi Arabia's hydrocarbon resources. A good understanding of the effect of water on the phase-behavior properties of these hydrocarbons is essential for accurately forecasting the performance of the reservoirs with numerical simulators. In addition, the scaling and corrosion tendencies of the produced brine are strongly influenced by mass transfer with the hydrocarbon phase.
This paper presents unique experimental phase-behavior data for a typical Saudi Arabian gas-condensate three-phase (aqueous/ condensate/gas) system. The objective of this work is to quantify the effect of the aqueous phase on gas-condensate fluid properties.
The results show that appreciable amounts of carbon dioxide and methane are partitioned from the gas-condensate phase into the aqueous phase. Another important observation is the mass transfer of water into the condensate phase. The mass transfer between the condensate and aqueous phases results in a slight decrease in the gas/condensate ratio (GCR). The carbon dioxide in solution makes the brine acidic and can dissolve carbonate minerals from the formation (e.g., calcium carbonate). In addition, the acidic or sour brine will be quite corrosive. The experimental results are compared with equation-of-state (EOS) and other correlations published in the literature.
Natural-gas reservoirs are an essential part of Saudi Arabia's hydrocarbon resources. The phase behavior of such hydrocarbons has been studied extensively, both in-country and worldwide. One of the factors that has not been studied is the effect of water on the phase behavior of gas-condensate systems. This is important because natural-gas reservoirs contain interstitial brine in equilibrium and frequently are underlain by an aquifer. In addition, the mass transfer between the hydrocarbon and aqueous phases strongly influences their scaling and corrosion potentials.
Previous work1,2 on oil/water and gas-condensate/water mixtures has shown considerable solubilities of carbon dioxide, hydrogen sulfide, methane, and ethane in water. Mass transfer occurs when the oil or gas condensate is contacted with water/brine, and these components will partition into that phase (Fig. 1). As a result, the composition of the hydrocarbon phase is altered, and some of its properties [e.g., saturation pressure, gas/oil ratio (GOR), and formation volume factor (FVF)] can be altered as well. Another important aspect is the partitioning of water into the hydrocarbon phase at reservoir conditions. This dissolved water in the hydrocarbon phase may drop out in the lines as the gas condensate is produced and may lead to corrosion and/or scaling problems.
The literature contains limited data on the solubility of hydrocarbon gases in the aqueous phase, and the available data are for single hydrocarbon-water systems (e.g., methane-water). Even more limited are data on the solubility of complex natural-gas mixtures in water and brine. This paper provides experimental data on the effect of contacting one Saudi Arabian natural-gas condensate with water and brine.
The main effects that are observed involve the mass transfer of some of the more water-soluble light components of the gas condensate (carbon dioxide, methane, and, to a lesser extent, ethane) into the aqueous phase. The loss of these lighter components (especially methane) from the condensate phase leads to a change in its gas-related properties (e.g., the GCR, dewpoint pressures, and liquid yields). Some water is also partitioned into the gas-condensate phase.
As a result of this mass transfer, the brine can become more acidic owing to the dissolution of carbon dioxide and hydrogen sulfide. This can then dissolve some of the carbonate minerals in the formation, which could then precipitate in the wellbore or at the surface when the pressure is released.3,4 The acidic brine is corrosive, 4 and large savings can be realized by its effective mitigation.5
The experimental apparatus and procedures are described. The properties of the gas condensate and brine used in this study are then presented. Following that, the experimental results are presented. Finally, some conclusions are drawn. It must be pointed out that in this paper "water" refers to pure water, and "brine" refers to the saline, aqueous phase (reservoir brine).
The apparatus consists of a high-pressure, high-temperature, three-windowed pressure/volume/temperature (PVT) cell (Ruska Model 2730*) with a volume of approximately 400 cm3. The cell is placed inside a temperature-controlled bath. It can be isolated and rocked inside the air bath (Fig. 2).
The volume of the sample inside the cell was measured using a cathetometer and the Ruska pump. The volume depended on the dimensions of the cell, pump position, temperature, pressure, reference points, and calibration factors. The internal volumes of the cell and connecting tubing were calibrated, including temperature- and pressure-correction coefficients. Frequent calibrations of the pressure transducers, temperature readers, and gauges ensured the accuracy of the measurements (temperature ±1°F, pressure ±5 psi, volume ±0.2 cm3). In addition, several data points were duplicated to check for reproducibility. The measurements were repeated if the duplicate results were not in agreement or if they fell out of trend with other data points at different pressures. Finally, the results were checked for thermodynamic consistency by comparing them with EOS calculations.