Gas-Diffusion Coefficient in Organic Matter Affects Estimation of Shale-Gas Reservoirs
Authors: Carpenter Chris 
Published: September 2022

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201653, “On the Inference of Gas Diffusion Coefficient in Organic Matter of Shale Gas Reservoirs,” by Esmail Eltahan, SPE, Mehran Mehrabi, and Kamy Sepehrnoori, SPE, The University of Texas at Austin, et al. The paper has not been peer reviewed.

US shale reservoirs are tight and inherently heterogeneous, with an abundant presence of kerogenic material. Modeling fluid flow in shale reservoirs is complex because of flow physics such as pressure flow and diffusion. Many field-performance forecasts underestimate production from these reservoirs constantly because most current models ignore important governing physics. This study provides new insights on diffusion in organic matter to correct a main source of underestimation of gas production in shale-gas models. In the complete paper, the authors implement a multiscale diffusion model to estimate gas-diffusion coefficient in organic matter.

Background

Pores in shale-gas resources, which are on the order of a few to tens of nanometers in diameter, are much smaller than pores in conventional resources. At such small pore size, the ratio of surface area to pore volume becomes large, giving importance to transport mechanisms that depend on the surface area. According to other researchers, in addition to the free gas, considerable amounts of gas molecules will exist on the surface of organic material (adsorbed gas) and inside the solid matrix of kerogen (dissolved gas).

Although typically neglected in conventional gas resources, the adsorbed and dissolved gas should receive attention in the case of shale-gas resources because of an abundance of organic material and substantial pore surface area. Gas production from shale is largely facilitated by maximizing the contact a well creates with the formation. In practice, the contact is established by numerous hydraulic fractures along a wellbore that extends for a lengthy horizontal distance in the formation. The induced-fracture networks grant direct access to the free gas in organic and inorganic pores as well as the adsorbed and dissolved gas through organic pores. Gas is depleted in the same manner as it is stored (in laboratory experiments, but in reverse order). Free gas is expanded first, creating local pressure sinks that force adsorbed gas to detach from the pore surface. As the desorption process continues, the number of unoccupied spots on the pore walls increases. Local concentration disruptions occur at those spots, which cause the dissolved gas to diffuse back into the pores.

The contribution of dissolved gas in field cases has been reported in several studies, which provides motivation to study the physics of dissolved-gas diffusion on the pore scale and to develop consistent predictive models on the mesoscale.

In a previous work by the authors, they presented a mathematical model for the evolution of dissolved gas that considers detailed pore geometry. However, the authors write that they have shown that pore geometry has minor influence, in contrast to the involved diffusion-length scales. Thus, the key components of previously obtained insights are used to build a simple model. The proposed model is considerably simpler in implementation, yet descriptive of the key components that govern dissolved-gas evolution. The mathematical model and its associated equations are detailed in the complete paper.