Characterization of Unconventional Reservoir Core at Multiple Scales

Abstract

Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties which control production and account for fracturability. Multiscale imaging studies from whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, fracture density, pore types, pore connectivity, mineralogy and organic content to the petrophysical response and production characteristics. In this paper we describe examples of the application of a multiscale imaging and analysis method to characterize challenging unconventional reservoirs which incorporates: Geological rock typing and heterogeneity characterization at the core/plug scale (3D imaging and conventional descriptions);  Mineralogy, primary grain structure and porosity/microporosity characterization at the pore scale via a range of 3D imaging technology (CT, micro-CT);  SEM/SEM-EDS/FIBSEM analysis to reveal the nanoporous structure of important pore types (e.g, secondary porosity, microporous matrix, diagenetic minerals including clays);  SEM and micro-CT analysis of wettability (applicable for oil reservoirs);  Integration of image data to generate 3D model structures that honour the primary grain structure and accurately capture the nanoporous regions.The generation of integrated image-based microstructures provides the basis for the computation of key petrophysical and multiphase flow properties which impact on the storage capacity and production characteristics of the samples. Petrophysical properties are first calculated on various pore types at representative scales; these predictions are then upscaled to estimate the contributions to permeability, formation factor and elastic response of the key constituent phases (e.g., porosity and permeability associated with clays, slot-like pores, cement, and partially dissolved minerals (e.g. feldspars)) at the plug scale. Estimation of drainage relative permeability and capillary pressure from 3D image data and modelling are compared and predictions of flow properties derived. These predictions are compared/calibrated to high quality experimental data on the same or sister core material.

Multi-Scale Rock Characterization and Modeling for Surfactant EOR in the Bakken

“…Scaling relations are based on the seminal work of Mattax and Kyte (1962), where oil recoveries as a fraction of the recoverable oil between two systems are related by using a Љdimensionless-timeЉ approach. The most widely used scaling relation for an oil/water system is defined as follows (Ma et al 1995): (1) where t D is the dimensionless time, k is the permeability, is the porosity, is the IFT, m is the geometric mean of water and oil viscosity, t is the imbibition time, and L a is the characteristic length defined as: (2) where V is the volume of the sample, A i is the area open to imbibition in the ith direction, and d ai is the distance the imbibition front travels from the open face to a no-flow boundary.…”

“…The hierarchical imaging workflow coupled with advanced numerical methods (hereinafter referred to as Digital Rock (DR) technology) allows for 3D mapping of pore geometry, pore connectivity, and mineral and fluid distribution, as well as first-principle-based calculation and upscaling of rock properties. The application of this technology to unconventional reservoirs has been a key focus area for a number of case studies that demonstrate great potential (Walls et al 2012, Alberts et al 2013, Korost et al 2013, Koroteev et al 2014, Fogden et al 2014). Knackstedt et al (2013) showed an image registration method that projects a 2D SEM slice to a 3D microCT image such that an integrated understanding of mineral distribution, porosity, and fluid distribution can be acquired.…”

“…Akbarabadi and Piri (2014) used a nanoCT scanner to study SI processes in organic-rich shale formations and observed limited imbibition rates of brine into oil-wet organic matter. Alberts et al (2013) demonstrated that fluid mapping techniques using DR technology can produce pore-scale wettability maps that greatly improve pore-scale understanding of fluid flow and facilitate predictive modeling of oil recovery in tight rock. Coupling fluid mapping techniques with SI experiments on Bakken core plugs could contribute to the development of effective surfactant systems that target oil-wet mineral surfaces and achieve optimal performance.…”