Multi-component sorbed phase considerations for Shale Gas-in-place Calculations
- Raymond Joseph Ambrose (Reliance Energy Inc) | Robert Chad Hartman (Weatherford Laboratories) | I. Yucel Akkutlu (University of Oklahoma MPGE)
- Document ID
- Society of Petroleum Engineers
- SPE Production and Operations Symposium, 27-29 March, Oklahoma City, Oklahoma, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.8.2 Shale Gas, 5.1 Reservoir Characterisation, 5.4.2 Gas Injection Methods, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale
- 8 in the last 30 days
- 2,055 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 8.50|
|SPE Non-Member Price:||USD 25.00|
Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorbed-gas by not properly accounting for the volumes occupied by the sorbed and free gas phases. Scanning electron microscopy (SEM) has discovered nanopores in organic-rich shale with sizes typically in 3-100 nm range, although pores less than 3 nm cannot be captured with current SEM technology. At that scale the adsorption layer thickness is not infinitesimally small. Thus a portion of the total pore volume would be occupied by a finite-size adsorption layer and not available for the free gas molecules. In SPE 131772, we proposed a volumetric method which accounts for the volumes taken up by the free gas and by the adsorption layer. The study was based on a single-component Langmuir adsorption model, however. This paper extends the discussions on the adsorption layer effect for multi-component natural gases with a sorption model also known as extended-Langmuir.
We combine the extended-Langmuir adsorption isotherm with volumetrics and free gas composition to formulate a new gas-in-place equation accounting for the pore space taken up by a multi-component sorbed phase. The 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. Using typical values for the parameters, calculations show a 20% decrease in total gas storage capacity compared to that using the conventional approach. The adjustments need to be done on the free gas volume is 18% more than the value using single-component (methane) case. The role of multi-component adsorption is more important than previously thought. The new methodology is therefore recommended for shale gas-in-place calculations.
Production from organic rich shales has increased steadily over the last decade and now makes up a large portion of the natural gas production in North America. Productive shale resources now include the Barnett, Woodford, Haynesville, Eagle Ford, and Marcellus, to name a few. Interestingly, the recent product price differential between condensate/natural gas liquids and natural gas has shifted the production within these large plays to the more "liquids-rich?? portions. This has occurred in the Barnett, Eagle Ford and Marcellus specifically. The liquids-rich portions of these plays offer improved well economics due to increased condensate and natural gas liquids production which yield higher pricing on an energy equivalent basis.
One of the primary concerns in any reservoir is the hydrocarbon in place. It is the foundation for the determination of reserves specifically in reservoirs with low permeability. In reservoirs with low permeability the wells are in transient flow for very long periods of time, sometimes months or even years (Ibrahim and Wattenbarger, 2006, Ambrose et al., 2011). Since the wells are in transient flow for such long periods, it is critical to have the best estimate of the resource in place.Having the best estimate for the resource in place can help to alleviate issues related to uncertainties in reserves.
|File Size||577 KB||Number of Pages||10|