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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, $1.5 million 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 project
information and publications related to the development of the quad
porosity simulation model for shale gas reservoirs, visit http://shale.ou.edu.
