Study on Prediction Model About Water Content in High-Temperature and High-Pressure Water-Soluble Gas Reservoirs

Because of a large amount of natural gas dissolved in the formation water of high-temperature and high-pressure (HTHP) water-soluble gas reservoirs, the water vapor content in water-soluble gas reservoirs is generally maintained under a supersaturated state; meanwhile, natural gas has a high carbon dioxide fraction, which significantly affects the water vapor content. Application of the conventional method to calculate the water content of HTHP water-soluble gas reservoirs leads to errors. In this work, the water content of HTHP water-soluble gas reservoirs was studied through laboratory experiments and theoretical research, and the main factors affecting water content were studied. Results show that the water content of water-soluble gas reservoirs decreases as pressure increases. The water content decreases faster in the low-pressure stage, while the decease of water content in the high-pressure stage is relatively steady. The water content of gas reservoirs increases with increasing temperature. When the temperature is lower than 100 °C, the change is slow; when the temperature is higher than 100 °C, the change is fast. The water content of gas reservoirs is affected by temperature during the low-pressure stage. The water content in the high-temperature stage is obviously affected by pressure; the water content of the gas reservoir is also affected by the carbon dioxide content of the natural gas component and the salinity of the formation water. Higher carbon dioxide content and lower formation water salinity yield higher water content. Furthermore, error analysis of the conventional water content prediction method and the measurement shows inconsistency in measurement and calculation. The error between the two methods is large, with an average of 54.88%. Based on the experiment, a mathematical model for calculating the water content of HTHP water-soluble gas reservoirs was established considering pressure, temperature, salinity, and natural gas composition. The predicted water vapor content of natural gas is close to the experimental value with a high precision. The average relative error between the measured and model calculated value is about 8.72%.