Mechanisms in CO2-enhanced coalbed methane recovery process

Coalbed methane (CBM) is a significant unconventional natural gas resource existing in matrix pores and fractures of coal seams and is a cleaner energy resource compared to coal and crude oil. To produce CBM, stimulation operations are required, given that the coal permeability is generally too low. Hydraulic fracturing is the most widely used technology for reservoir stimulation; however, there are a few challenging issues associated with it, e.g., huge water consumption. In the past decade, the use of liquid nitrogen (LN₂) as a fracturing fluid has been intensively studied for stimulating CBM reservoirs, achieving considerable progress in understanding fracturing mechanisms and optimizing fracturing techniques. This paper presents a thorough review of experimental design and observations, modeling procedures and results, field applications, and published patents. Existing studies are divided into five different groups for discussion and comparison, including immersion tests, injection tests, jet drilling tests, numerical modeling, and field applications. Based on the comprehensive evaluation of the outcomes, it is obvious that cryogenic fracturing using LN₂ is a promising eco-friendly fracturing technique that can effectively enhance coal rock permeability to increase the production of CBM.

Understanding gas-enhanced methane recovery in graphene nanoslits via molecular simulations

Carbon dioxide (CO₂) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO₂ in enhancing oil recovery, the high mobility of CO₂ in porous media is one of the major issues faced during CO₂ EOR projects. Foam injection is a proven approach to overcome CO₂ mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO₂ and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).