University Of Oklahoma Research Team To Test 'Quad Porosity Simulation Model' For Shale Gas Reservoirs Early 2012
A University of Oklahoma interdisciplinary research team will field test a newly developed ‘quad porosity model' for shale gas reservoirs in the next few months. The three-year, $1.5M project was funded by the Research for Partnership to Secure Energy for America and a consortium of nine oil and gas producing companies.
"The challenge for the team at the outset was to understand shale gas reservoirs in order to develop a predictive tool for better forecasting and economics," says Deepak Devegowda, professor and lead investigator in the Mewbourne School of Petroleum and Geological Engineering. "Shale gas reservoirs are complex systems unlike conventional reservoirs."
Just a year into the project, the OU research team has made a number of discoveries, which has led to a greater understanding of gas and liquids transport in shale gas reservoirs and the development of the quad porosity model. A previous OU research effort led to the development of the quad porosity model by using scanning electron microscopy, which indicated that gas shales can be characterized by four porosity systems.
Notably, however, the key pore spaces influencing both storage and transport of fluids are the inorganic and organic pore space. "The texture, fabric and constituents of gas-bearing shale formations containing various pore types in the nanometer sizes are intriguingly complicated," states Faruk Civan, OU professor and co-investigator on the project.
"Developing a realistic simulator is an exciting challenge," he said. "Our work focuses on understanding and testing the theoretical description of mechanisms of gas storage and fluid (gas/liquid) transfer in such an intricate system of inorganic and organic pores and natural and induced fractures. OU is pioneering permeability measurement, which incorporates all flow regimes," remarks Civan. "We can also determine properties of shale rock."
The OU research team had to rethink the physics of fluid flow and storage, which are very different in these nanoporous inorganic and organic pores. Additional complexity arises due to adsorption of gas in the organics in a high-density layer adjacent to the pore walls. While current numerical reservoir simulators are sophisticated in terms of their gridding algorithms and computational efficiency, they are restricted to modeling viscous flow. Adapting these to model transport in nanoporous shale gas reservoirs, where up to four different flow regimes may be observed, is challenging.
The small pore size in shales has been shown to have considerable impact on gas and liquids transport. Pore proximity effects, which are negligible in conventional reservoirs, exert forces that lead to substantial enhancement in the ability of the rock to flow and modify the behavior of the molecules themselves.
Standard equations used to describe gas transport cannot be applied to the small pores in the organic material where a significant portion of the gas is stored. The OU research team has shown permeability enhancement effects of up to two orders of magnitude in very small pores and this, in part, explains how gas is produced from these extremely tight formations.
One of the key developments of the research team over the last year is predicting the phase behavior of gas condensates in nanopores. As development activity, spurred by low gas prices, is focusing on the liquids-rich regions of shale gas plays, a concern of immediate significance is how to model gas condensates in nanopores. In conventional reservoirs, at low pressures, a phenomenon called condensate dropout occurs, which restricts the available pore space for gas to flow, thereby impairing well performance.
The OU research team has been able to show that in very small organic and inorganic nanopores, the influence of pore walls on fluid behavior is such that gas condensates tend to behave as dry or wet gases leading to a considerable decrease in condensate dropout. This development further explains the prolific production of rich gas-condensate fluids from these extremely tight reservoirs while conventional knowledge tends to indicate higher well productivity impairment.
Not only do these nanopores favorably modify phase behavior and the permeability to gas, but the apparent viscosity and interfacial tension also change for the better under the influence of pore walls, causing Civan to remark, "Nanopores are our friends and OU is the first to model this phenomenon."
One of the key advantages of their formulations to account for these diverse and complex phenomena in shale gas reservoirs is that they can easily be incorporated into commercial simulators. Ongoing research work is attempting to answer questions, such as the location and distribution of frac water following stimulation. The OU research team has already developed some flow models to answer these questions.
Future work will also include the effect of these mixed wettability systems where the organic material is predominantly gas wetting while the inorganics are water-wetting, thereby meriting new formulations for multiphase transport and relative permeability. For more information, visit http://shale.ou.edu.
SOURCE: The University of Oklahoma