The present study investigates the alteration of the properties, transport, and production of gas-condensates in shale gas reservoirs and develops and demonstrates an effective and practical methodology to apply these modifications in existing numerical simulation software. Simple models that investigate the phenomena can be investigated without the need for any modifications to an existing simulation code, but realistic models will require significant modifications. Our modeling results indicate that when pore sizes are in the sub-10 nm range, typical of many gas shales, the influence of pore walls on the phase behavior and viscosity of typical gas-condensate fluids is dramatic, in both organic and inorganic pores, and creates favorable fluid and transport conditions leading to enhanced production. This is because the fluid mixture in such porous formations tends to exhibit behavior similar to that of a dry gas or a leaner gas-condensate system, thereby reducing the condensate banking effect considerably in the near-wellbore region and consequently, not impairing the productivity of the producing well. The results also underscore possible reasons for the significant production of condensate liquid from these nanoporous media in contrast to what is expected based on the industry's collective experience with conventional reservoirs. Consequently, the analysis and exercises carried out in this article provide valuable insights into the nature of fluid behavior and advances our understanding of the mechanisms of gas-condensate transport in extremely low permeability nanoporous media.
Xiong, Xinya (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Michel Villazon, Guillermo German (University of Oklahoma) | Sigal, Richard F. (University of Oklahoma) | Civan, Faruk (University of Oklahoma)
Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non-Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick's law of diffusion. The coupled model is then compared to conventional transport models over a wide range of reservoir properties and conditions.
As pore-pressure is reduced, adsorbed phase gas desorbs into free gas and apparent permeability increases. The difference in the estimated apparent permeability with and without the consideration of the adsorption volume can be a factor of two or more at initial reservoir conditions. Diffusion on the surface of organic pores can be a substantial transport mechanism in shales depending on the pore connectivity, pore pressure, and pore size distribution in the organic pores. The interpretation of production data will be compromised without considering the effects of adsorption on apparent permeability. This work implies that permeability measurements for shale gas reservoirs must be done with methane at in-situ pore pressures. Because these corrections are pore-pressure not effective pressure dependent, effective pressure is not a valid parameter to use in quantifying the pressure dependence of these transport equations.
Effect of retardation in fluid displacement on transport inside capillary tubes during leak-off and clean-up for hydraulically stimulated reservoirs is investigated by modeling of the relevant phenomena. The effect of wall proximity during the transport in narrow capillaries is formulated. The importance of the critical properties alteration due to confinement is demonstrated by modification of the real gas deviation factor. The relaxation in fluid displacement observed in the fluid transport dynamics is coupled with the bundle of tubes representation of porous media for investigation of the relaxation effects on fluid saturation, capillary pressure, and relative permeability. An analytical formulation of the relaxation time corresponding to water removal during clean-up processes following hydraulic fracture stimulation is presented. The dynamics of advancement of the wetting and non-wetting fluids inside capillary tubes are illustrated by various applications.
Gas-bearing shales are characterized by pore systems that are present in the organic (kerogen) matrix, inorganic matrix, natural fractures, and induced fractures. Each pore system has different physical properties. The organic matrix essentially has gas-wet nanopores with adsorptive properties. The inorganic matrix is an ultra-low permeability matrix that is most likely water-wet but could have more complex wettability. Two alternative but complementary approaches, namely a lumped tank model and a continuum model, for describing gas transport in shale are developed and their capabilities are demonstrated by various applications. Our continuum approach describes gas transport in a manner analogous to the methods employed by commercial simulators. The model is discretized and petrophysical and fluid parameters incorporated into the model that may then be calibrated to obtain a history match. Often, this process leads to non-uniqueness in the match because the number of observations is likely to be smaller than the number of parameters to be resolved. Our lumped tank approach treats the porosity systems within shales as tanks interacting with each other such that relevant physical phenomena, such as adsorption, are described by rate equations. Calibration of this model to production data enables the quantification of grouped parameters and not necessarily the individual storage- and transport-related parameters, thereby reducing the severity of the non-uniqueness of the history matching process. Several case studies conducted exclusively delineate the advantages and disadvantages of both approaches in shale-gas production analysis and simulation. Comparisons between the tank model and the continuum approach for different case studies show good matches within an acceptable measure of tolerance. Reservoir parameters determined from the tank approach are compared with the values used in the continuum approach. The new models are shown to accommodate the inherent complexities of transport processes occurring in shale-gas reservoirs.