Shale Gas-in-Place Calculations Part II - Multicomponent Gas Adsorption Effects
- Robert Chad Hartman (Weatherford Laboratories) | Raymond Joseph Ambrose (Reliance Energy Inc) | I. Yucel Akkutlu (University of Oklahoma MPGE) | C.R. Clarkson (U. of Calagary)
- Document ID
- Society of Petroleum Engineers
- North American Unconventional Gas Conference and Exhibition, 14-16 June, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.3.4 Scale, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.7 Reserves Evaluation, 5.8.3 Coal Seam Gas, 4.1.5 Processing Equipment, 5.2.2 Fluid Modeling, Equations of State, 4.6 Natural Gas, 4.1.2 Separation and Treating, 1.2.3 Rock properties, 5.4.2 Gas Injection Methods, 5.8.2 Shale Gas, 5.2.1 Phase Behavior and PVT Measurements, 5.1 Reservoir Characterisation
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Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorption capacity by not properly accounting for the volume occupied by the adsorbed phase. Scanning electron microscopy has discovered nanopores in organic-rich shale with sizes typically in 3-100 nm range; adsorption data show presence of smaller pores and micropores (< 2 nm) as part of the predicted pore size distributions. At pore diameters of this scale the adsorption potential is high and thus the fractional pore volume occupied by adsorbed gas is often substantial. Hence a portion of the total pore volume would be occupied by the adsorbed gas and not available for the free gas molecules. In SPE 131772 a volumetric method, which accounts for the pore volumes occupied by the adsorbed and free gases, has been proposed based on single-component Langmuir adsorption model. In SPE 141416 we recognized the importance and impact of multi-component gas adsorption potential and adsorbed gas density when calculating gas-in-place estimates. We combined the widely used yet thermodynamically inconsistent Extended Langmuir model with volumetrics and free gas composition to formulate a new gas-in-place equation that accounts for the pore space taken up by a multi-component adsorbed gas phase. This paper extends the discussions on the adsorption layer effect of multi-component natural gases. The approach is based on thermodynamically-consistent ideal adsorbed solution (IAS) model to accurately predict adsorbed gas storage capacity for gas mixtures. We expanded on our previous work, where we calculated single-component adsorbed-phase density using molecular modeling and Monte Carlo simulation methods, and propose a new equation-of-state-based analytical approach to predict the adsorbed-phase density of a mixture. In concert, the model improves accuracy of the gas-in-place equations needed to account for the pore space taken up by a multi-component adsorbed phase. The new method yields total gas-in-place predictions, which suggest that an adjustment is necessary in volume calculations, especially for gas shales with high C2+ composition and high in total organic content. The new method is therefore recommended for shale gas-in-place calculations.
Natural gas production from fine grained, organic rich mudstones/siltstones (i.e., "shales??) has increased steadily over the last decade. Currently it makes up a large portion of the total gas production in North America and is gaining traction globally. Because of commodity pricing, recent focus has shifted away from producing mature dry shales to more profitable production of shale condensate/natural gas liquids. This has occurred in the Barnett, Woodford, Eagle Ford and Marcellus formations specifically.
One of the primary variables when assessing the economic viability of any shale gas reservoir is the volume of hydrocarbons-in-place. It is the foundation for the determination of reserves specifically in low permeability reservoirs where flow is in transient regime for very long periods of time, sometimes months or even years (Ibrahim and Wattenbarger, 2006, Ambrose et al., 2011). Since production involves transient flow for such long periods, it is critical to have a best estimate of the resource -both liquid and gaseous phase hydrocarbons in-place- so that the uncertainties can be alleviated during the reserve estimation.
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