000			03202nab a2200217 4500
005			20260520000315.0
008			260224s2012 xxu
245	0	0	_aInnovative methods for flow-unit and pore-structure analyses in a tight siltstone and shale gas reservoir
260			_a _b _cfeb. 2012
270			_a08/05/2012 ; 07/05/2012
300			_a19 p. ; 355-374
520			_aTranscripción del resumen del autor: Tight gas reservoirs are notoriously difficult to characterize using laboratory-based methods because of: the existence of heterogeneity at several scales; fine pore structure that may not correlate to depositional controls and environment due to theimpact of diagenesis; stress sensitivity of porosity and permeability; sensitivity of permeability to fluid saturation; and nonDarcy flow effects under laboratory conditions, etc. Porosity, pore size distribution and permeability are correspondingly difficult to measure in the laboratory and upscale to reservoir scale. A promising technique to characterize flow heterogeneity in tight gas reservoirs is to relate permeability to dominant pore throat size; permeability is measured using steady- or nonsteady-state techniques and dominant pore size is typically estimated using the mercury intrusion method. Permeability and porosity is measured on full-diameter core or core plugs which may contain heterogeneities that are at a much finer scale than the sample size, resulting in composite estimates of both properties. We investigate the use of non-routine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow unit identification. Profile permeability is used to characterize fine-scale (< 1 inch) vertical heterogeneity in a tight gas core; over 500 measurements were made. Profile permeability, while useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; further, the scale of measurement is much smaller than logscale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ and point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, a new method (for tight gas) was used to estimate the pore size distribution of several tight gas samples: N2 adsorption. A uni- or bi-modal distribution was observed for the samples, with the larger peak corresponding to the dominant pore throat radius, as inferred from the rp35 calculations. Further, the adsorption-desorption hysteresis loop was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides for rapid analysis and does not suffer from some of the same limitations of Hg-injection, however the method is limited to fine pore structures (< 1,000 nm).
581			_a2
773	0		_tAAPG Bulletin _g96
942			_cARTICULO
100	1		_aClarkson, Christopher R. _952557
100	1		_aJensen, Jerry L. _942846
100	1		_aPedersen, Per Kent _952558
100	1		_aFreeman, Melissa _952559
999			_c187145 _d187145