Geologically-based permeability anisotropy estimates for tidally-influenced reservoirs using quantitative shale data

Abstract

The effect of the vertical to horizontal permeability ratio ( k v / k h ) on many displacement properties is significant, making it an important parameter to estimate for reservoir models. Simple ‘streamline’ models have been developed which relate k v / k h at the reservoir scale to shale geometry, fraction and vertical frequency. A limitation of these models, especially for tidally-influenced reservoirs, is the lack of quantitisative geological inputs. To address this lack of data, detailed shale characteristics were measured, using Lidar point clouds, from four different tidally-influenced reservoir analogues: estuarine point bar (McMurray Formation, Alberta, Canada), tidal sand ridge (Tocito Sandstone, New Mexico), as well as both unconfined and confined tidal bars (Sego Sandstone, Utah). Estuarine point bars have long ( x̄ = 67.8 m) shales that are thick and frequent relative to the other units. Tidal sand ridges have short shales ( x̄ = 8.6 m dip orientation) that are thin and frequent. Confined tidal bars contain shales that are thin, infrequent and anisotropic (x– = 16.3 m dip orientation). Unconfined tidal bars contain nearly equidimensional shales of intermediate length ( x̄ = 18.6 m dip orientation) with moderate thicknesses and vertical frequency. The unique shale character of each unit results in a different distribution of estimated k v / k h values. Estuarine point bars have lower average k v / k h values ( x̄ = 8.2 ×10 −4 ) than any other setting because of the long shales they contain. Tidal sand ridges have short, but frequent shales, which results in moderate k v / k h estimates ( x̄ = .011). Estimates of k v / k h are typically highest in confined tidal bars ( x̄ = .038), which contain anisotropic and infrequent shales. Unconfined tidal bars have moderate lengths and frequency resulting in k v / k h estimates averaging 0.004. The results of this study highlight the link between heterogeneity, reservoir architecture and flow parameters.

Measuring anisotropic permeability using a cubic shale sample in a triaxial cell

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“…Although economic shale gas production has been achieved through horizontal drilling and multistage hydraulic fracturing, shale reservoir permeability is still one of the critical parameters in the evaluation of a shale gas play and the understanding of its gas flow and production behaviour. Laboratory measurement using core samples is an important means of obtaining anisotropic permeability information (Burton and Wood, 2013). However, such measurements of shale permeability often use core samples that were drilled vertically, and hence, measure only the vertical permeability of the reservoir.…”

Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs

“…As a consequence, fluid flow direction depends on both pressure gradient and the principal directions of anisotropy. Several studies have shown the existence of anisotropy in the shale formations (McCarthy 1991;Ayan et al 1994;Kwon et al 2004;Burton 2011). In fact, anisotropy exists in the scale of micrometer or nanometer under microstructural observations using transmission electron microscopy (TEM) (Kwon et al 2004).…”

Of sand and mud: Sedimentological criteria for identifying the turbidity maximum zone in a tidally influenced river

“…Burton & Wood () provided quantified assessments of the thickness and lateral distribution of mud beds in tidally influenced reservoirs. From the standpoint of reservoir heterogeneity, the ‘shale length’ (i.e.…”