Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs

Abstract 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%.

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Multiphysics coupling study of near-wellbore and reservoir models in ultra-deep natural gas reservoirs

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01424-7 ◽

2022 ◽

Author(s):

Pengda Cheng ◽

Weijun Shen ◽

Qingyan Xu ◽

Xiaobing Lu ◽

Chao Qian ◽

...

Keyword(s):

Natural Gas ◽

Pore Pressure ◽

Production Rate ◽

Gas Production ◽

Permeability Evolution ◽

Gas Reservoirs ◽

Reservoir Properties ◽

Gas Field ◽

Natural Gas Reservoirs ◽

Stress Dependent

AbstractUnderstanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

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