Treating Liquid Banking Problem to Increase Shale Gas Wells Productivity

Abstract

One of the common causes of gas wells productivity loss is attributed to liquid accumulation near the wellbore over the production life of the wells. For gas condensate reservoirs, when the bottomhole pressure falls below the dew point pressure, liquid hydrocarbon drops out of the gas phase, residing in the near wellbore region and causing condensate block. Fracturing fluid also contributes to liquid blockage as only 5 to 30% of fracturing fluids are recovered from the reservoir. For a tight shale formation where the pore sizes are as small as nanometers, capillary pressure is large enough to cause liquid entrapment in the pore body reducing the relative permeability to the gas phase. A variety of methods such as gas cycling, super critical CO2 injection, solvent injection, and wettability alteration using fluorinated surfactants/polymers have been suggested to treat liquid block or banking (i.e., water and condensate). However, these methods are either not effective or expensive, and do not provide a good return on investment. As capillary pressure depends on surface/interfacial tension (ST/IFT) and the contact angle, a treatment method that combines the effect of ST/IFT reduction and wettability alteration can be applied to lower capillary pressure, thus, to enhance liquid unloading. In addition, reducing the ST between gas and the liquid phase (water/gas condensate) will increase the carrying capacity of the gas phase with respect to the banked liquid phase. This paper presents a practical laboratory testing procedure developed to screen and recommend cost effective production enhancement formulations to treat liquid blocking. Based on laboratory test results obtained from this testing procedure, a non-fluorinated production enhancement formulation was recommended for a field trial. The recommended formulation was tested at two gas wells: one vertical and one horizontal in North Texas. The proposed formulation was used in the fracturing fluids when the wells were re-fractured. Production data from the two wells have shown a sustained increase in gas production and water recovery rate. The lessons learned here can be used as a guideline to increase production life of existing gas wells and to maximize hydrocarbon (gas and associated condensate) recovery rates.

Wettability Alteration of Berea Sandstone for Gas Condensate Applications

“…Bang et al reported the gas relative permeability could experience up to a 95% reduction due to liquid banking near the wellbore, thereby stopping gas production entirely in many cases . However, the condensate bank formed around the wellbore can be treated using gas injection or surface/interfacial tension reduction or can be delayed by hydraulic fracturing and horizontal completion. − Under reservoir conditions, increasing condensate saturation is highly correlated with a reduction in the relative gas permeability in the presence of an immobile liquid . The presence of 19% connate water during condensate formation may decrease the relative permeability of the gas by 60% …”

Review of the productivity evaluation methods for shale gas wells

“…They discovered the existence of gas-water two-phase flow, trilinear, and five-linear flow patterns between different flow regions (Bello and Wattenbarger 2010;Brown et al 2009;Ozkan et al 2010;Brohi et al 2011;Ozkanet et al 2011;Stalgorova and Mattar 2012a, b;Yin et al 2015;Zhang et al 2015;Fan and Ettehadtavakkol 2016;Su et al 2016a, b;Zeng et al 2019;Liu et al2020;Behmanesh et al 2021). The flow coupling laws between multiple media were described mathematically by the mass transfer control equation, which considered the typical flow mechanisms such as Knudsen diffusion, molecular surface diffusion, adsorption-desorption, Klinkenberg effect, high-speed non-Darcy effect, Darcy flow, effective stress sensitivity (Carlson and Mercer1991;Wang et al2015;David Obembe et al 2017;Phan et al 2018;Sun et al2019;Zhong and Leung 2019;Hassan et al 2020;Zeng et al 2021). Thereby establishing an analytical model describing the cross-scale transport of shale gas was developed.…”