Producers that ply shale gas plays could someday benefit from increased insight into shale reservoirs courtesy of researchers at the University of Oklahoma (OU).

Researchers there are developing a simulator for shale gas reservoirs that is intended to allow for better management of gas production, as well as improved drilling location selection and cost reduction.

Richard Sigal, Faruk Civan and Deepak Devegowda of OU’s Mewbourne College of Earth and Energy are the first to systematically tackle this challenge, the university said. The project is supported with $1.054 million from the Research for Partnership to Secure Energy for America plus an additional $250,000 in matching funds from a consortium of six oil and gas producers.

“Simulators for conventional reservoirs are not suited for shale gas reservoirs,” said Sigal. “An example of this is the deposition of frack water used to force the gas from the reservoir. In a shale gas reservoir, massive hydraulic fracturing opens up the reservoir so the gas can flow. This involves pumping a large amount of water into the reservoir. In conventional reservoirs all this water is produced back, but in shale gas reservoirs only a small percentage of the water is produced.”

Reservoir simulators currently available do not successfully predict volumes of produced water, Sigal said. “Researchers need to model the deposition of this [fracking] water to better understand the reservoir and address concerns the effects this water can have on shallow aquifers. One goal of the simulator project is to determine and provide the capacity to model frac water deposition,” he said.

Researchers at the university are making use of a new $2 million microscope to examine the porosity of shale reservoir rock. Carl H. Sondergeld and his collaborators have found two kinds of pore space in the rocks. Besides inorganic pore space where one would expect to find gas, the research discovered pores the size of nanometers in the organic portion of the rock. “This discovery needs to be incorporated into the simulator design,” Sigal said.

OU researchers recognized that the physics of fluid flow and storage are different in the inorganic and the organic portions of shale gas reservoirs. The reservoirs also contain both natural and induced fracture systems each with different properties.

“There are three basic issues with the physics of these natural non-porous systems,” the researchers said. “First, the standard equations used to describe gas transport are incorrect in the small pores in the organic material where a significant portion of the hydrocarbon gas is stored.” Researchers studying artificial nanomaterials have developed new gas transport equations that need to be adapted to the complicated pore spaces that describe shale reservoirs, they said.

Secondly, in standard simulators, an assumption known as instantaneous capillary equilibrium provides the relationship between the gas and water pressure. Equilibrium cannot be maintained because of differences in the transport rates for water and gas in shale gas reservoirs, so the standard equations must be modified, according to the OU researchers. “Finally, the very large capillary forces caused by the very small pore size require a different treatment of relative permeability, which controls the relative transport of the water and gas,” they said.

“This is a three-year project to develop the new simulator starting with the fundamentals,” Sigal said. “We have already developed a 1-D model. The next step will be to build a simple 3-D testbed system. At first, we will test this model against models run on commercial simulators.

“Next, we will build modules that incorporate the individual modifications needed for conventional simulators to correctly model shale gas reservoirs. These modules will be available for adoption by industry for use in existing company or commercial simulators. Finally, we will use the modified simulators to history-match production from existing reservoirs. Our commercial sponsors will provide data for this.”