Nisael A. Solano

Modeling core-scale permeability anisotropy in highly bioturbated “tight oil” reservoir rocks

A high-resolution simulation model of a heterogeneous low-permeability rock sample is used to investigate the effects of physical and biogenic sedimentary structures on scaling and anisotropy of absolute permeability at the core scale. Several simulation sub-samples with random locations and volumes were also selected for evaluation of the effects of scale and lithological composition on the calculated permeability. Vertical and horizontal permeability values (from whole core simulation) are in good agreement with routine core analysis (RCA) measurements from offsetting cores. Despite relatively good reservoir quality associated with geobodies of biogenic and relic bedding structures, results from the full diameter core simulation demonstrate that their limited volumetric abundance and restricted connectivity prevent these features from controlling fluid flow in these rocks. In fact, permeability seems to be dominated by the tighter encasing matrix, which exhibits average permeability values very close to those reported from RCA. Geometric averaging offers a better representation for the upscaling of horizontal permeability datasets; whereas, both geometric and harmonic averaging work similarly well for the vertical measurements. The methodology used in this work is particularly applicable to the detailed characterization of reservoir rocks with a high degree of heterogeneity caused by biological reworking and diagenesis.

Combined Use of Neutron-Scattering, Fluid-Invasion, and Image-Analysis Techniques to Assess Pore Structure, Accessibility, and Connectivity in Tight Rock

Low-permeability (unconventional) reservoirs exhibit heterogeneities at multiple scales that affect flow. While macro-scale heterogeneities are typically evaluated using welltest or production-analysis techniques, core-scale (and finer) analyses are relied upon to evaluate micro-and nano-scale heterogeneities. Pore structure is a known control on flow at the core scale; for unconventional reservoirs, however, pore-size distributions, pore accessibility, and connectivity are challenging to evaluate. In the present study, a combination of neutron-scattering methods, fluid invasion, and imaging techniques were used to evaluate the degree of pore accessibility and connectivity in a tight oil reservoir within the Cardium Fm. of western Canada. In previous work, cmto sub-cm scale variations in lithology (elementary lithological components, or ELCs) have been shown to affect flow at the core scale significantly and that reservoir quality varies with the ELCs. The fundamental controls on flow within these ELCs (i.e. at the pore scale), however, are poorly understood. The aim of the present study was to gain insight into these controls. Small-angle and ultra-small angle neutron scattering (SANS/USANS) has revealed that while the Cardium samples exhibit a wide range in pore-size distribution, the accessibility of pores varies significantly with pore size. In particular, the large pore fraction seems to be less accessible than the small pore fraction, which is counter-intuitive. Mercury intrusion data partially support this finding. High-resolution scanning electron microscopy (SEM) imaging suggests that pores within mineral grains may indeed be disconnected/isolated. The SANS/USANS interpretations are based on a simple 2-component (poresþ average mineral phase) model, however; detailed mineral mapping reveals that several components may affect significantly the scattering behavior which leads to the conclusion that a multi-phase model may be more appropriate, and that use of the conventional 2-phase model could lead to errors in calculated pore-size distributions and the percentage of disconnected porosity.