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Modeling Diffusion Dominated Non-hydrocarbon Distributions in Gas Reservoirs

P.J. Hicks, Jr., S.A. Barboza, and R.J. Pottorf
ExxonMobil Upstream Research Company, P.O. Box 2189, Houston, TX 77252-2189

The presence of non-hydrocarbon gases can have significant adverse effects on hydrocarbon gas reservoirs by increasing the costs of production and treatment and by diluting the hydrocarbon reserves. Predicting the distribution of the non-hydrocarbon gases in a reservoir can be important for efficient facilities design, well placement and reserve estimation. The non-hydrocarbon gas distribution may be controlled by a number of factors including reservoir geometry; charge rates and compositions; mechanism, timing and location of non-hydrocarbon gas generation; and the physics of the gas mixing processes.

To simulate this in-reservoir fluid mixing process we have employed new simulation capability within Permedia MPath along with analytical models and proprietary reservoir simulation tools. Important numerical modeling and fluid property parameters contributing to uncertainty in the mixing time scales include the magnitude of the diffusion and dispersion coefficients; numerical modeling schemes, including discretization schemes and boundary conditions; and the effect of these models and associated parameters on the resulting temporal and spatial concentrations of non-hydrocarbons gases in the reservoirs.

A specific case that we have considered is estimating the time scales of diffusive mixing of CO2within CH4reservoirs. Naturally occurring CO2is an important non-hydrocarbon gas in many hydrocarbon gas reservoirs world-wide including the Big Piney LaBarge Field in southwest Wyoming and the Sleipner West Field in the Norwegian North Sea, a feature that contributes significantly to operational costs. In our model, CO2is produced off-structure and migrates to the flanks of the reservoir mixing by molecular diffusion with an earlier CH4gas charge. Diffusion of the CO2into the hydrocarbon accumulations is impeded by the 3D distribution of porosity within the reservoir and by the presence of relatively impermeable, water-saturated layers between primary reservoir intervals. Time scales of reservoir fluid mixing in this case exceed 106 – 107 years, depending on reservoir geometry and porosity, indicating that reservoir concentration gradients may be preserved for long periods of time. Diffusion is more rapid in higher quality reservoir units leading to more uniform concentrations owing to the shorter diffusion path length. Steeper concentration gradients tend to be preserved in the lower quality reservoir units and low-permeability, intra-reservoir layers.


AAPG Search and Discover Article #90066©2007 AAPG Hedberg Conference, The Hague, The Netherlands