Productions of volatile oil and gas-condensate from liquid rich shales

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.