In the emergence of new technologies to harness renewable energy, industrial-scale storage of heated water in a geothermal system is a promising technique. A porous, permeable medium, bounded by a poorly thermally conductive/convective overburden and underburden, can be used for transient subsurface thermal storage. The reservoir in this concept forms a geothermal battery. As a very simplified scenario, consider a single well injecting and producing hot water diurnally or seasonally. The source of the hot water could be solar-heated water, for example, or possibly even water heated from the excess regional electricity supply. For that situation, this study investigates the influence of spatial permeability heterogeneity on heat recovery, and the distributions of temperature and pressure inside the reservoir. Four heterogeneous models are created from lognormal distributions of permeability by varying the standard deviations while keeping the mean absolute permeability at 100 mD. The injection pressure experienced while pumping into a candidate formation is affected by heterogeneity; higher bottom hole pressure is required to inject water into a more heterogeneous reservoir. The spatial distribution of temperature is less affected by permeability heterogeneity. In the simulations carried out, 91% of the heat is recovered after the 30 ${}^{\mathrm{th}}$ cycle of injection/production operation in all cases proving less impact of heterogeneity on heat recovery for fixed injection and production rates.

Well deliverability impairment due to liquid dropout inside gas-condensate reservoirs below dewpoint pressure is a common production problem. The operating conditions and the thermodynamic properties of the condensate govern the production performance of this type of reservoir. Modeling condensate production using analytical, semi-analytical or empirical formula for quick assessment of reservoir performance is a complicated method due to the complex thermodynamic behavior. The objective of this study is to provide a fundamental understanding of the flow and thermodynamics of gas-condensate fluid to develop tools for the production prediction. The prior developments of flow modeling of gas-condensate are briefly reviewed. The multi-phase flow and the depletion stages during production are discussed. Each component of pseudo-pressure calculations to determine the condensate flow rate is explained. Thermodynamic properties and laboratory experiment relevant to the flow of condensate are also explored. Pressure-volume-temperature (PVT) properties such as two-phase envelope, constant composition expansion (CCE) and constant volume depletion (CVD) are demonstrated for three different gas-condensate fluids namely lean, intermediate and rich.

The growth in productions of liquid hydrocarbons from tight formations (shales) has been phenomenal in recent years. During the production of liquids (oil and condensate), large amounts of associated gas are also produced. The economic viability of a producing well depends on maintaining a reasonable proportion of liquid. The compositions and state of reservoir fluid play an important role in producing liquids from tight formations or shales in the USA such as Eagle Ford in Texas, Niobrara in Wyoming-Colorado, and Bakken in North Dakota. Small deviation in reservoir temperature around the critical point changes the state of the fluid (volatile oil or condensate) and as a result, the production of liquid is affected. Impacts of the state of the fluid (volatile oil or condensate), reservoir permeability and operating conditions on ultimate recoveries and produced gas liquid ratio are studied here. Five different reservoir fluids representing low to high liquid hydrocarbon contents are considered. Around 2% increment in condensate recovery after 10 years of production is observed from 100 nD permeability reservoir filled with the richest fluid (fluid 5) when the well is operated at 3, 000 psia compared to 1, 000 psia. At the same conditions, 9.3% more condensate is recovered for the leanest fluid (fluid 1). Therefore, operating the well at higher flowing bottom hole pressure (BHP) maximized the liquid recoveries of volatile oils and condensates in case of low permeability reservoirs (100 nD). However, in case of higher permeability (1, 000 nD) reservoir, lower operating pressure was preferable to increase the recovery. Conclusively, bottom hole pressure has less impact on the richer fluids and higher permeability reservoir. Operating well at higher BHP (3, 000 psia) also suppresses the production of gas and relatively enhances the production of liquid. Liquid to gas ratio (LGR) declines more rapidly for 100 nD permeability reservoirs compared to 1, 000 nD at BHP of 1, 000 psia. High fracture permeability (1, 000mD and above) appeared to negatively affect liquid recoveries at higher BHP resulting in reduction of recovery by around 2%. An optimum fracture permeability may be necessary based on reservoir permeability, operating pressure and type of fluid.