American Oil and Gas Reporter - February 2015 - 76

SpecialReport: Improved Oil Recovery
Moreover, several studies show that kerogen pores in a continuous organic framework can form an effective pore system to
dominate the flow pathway. All these factors demonstrate the importance of considering a designated porosity system to model
flow behavior in kerogen.
To better characterize subtle pore systems, a state-of-the-art,
microscale model with a shale subdivision scheme has been developed. It partitions porous media in shale into three submedia
(i.e., porosity and permeability systems) with distinctive characteristics-inorganic matter, kerogen, and the natural or hydraulic
fracture network-and then applies appropriate convective or diffusive flow mechanisms to each submedium.
The microscale technique has been used to investigate threephase (oil, gas and water) flow in liquids-rich shale formations.
By dividing shale systems into different submedia, the model accounts for variability in mineralogy, pore size and structure while
considering the multiphase flow behavior. The model provides
the capability to better analyze the complex nature of mass transfer in liquids-rich shales. Relative permeabilities are accounted
for by employing functions specific to shale reservoirs, and the
model can handle the various flow and storage mechanisms that
correspond with shales, such as molecule/wall interactions, slippage of the gas phase, multicomponent desorption, and capillary
absorption.
Complicated Dynamics
Simulation results show that hydrocarbon production from shale
reservoirs exhibits complicated dynamics controlled by a number of factors. Because of shale's very high capillary pressure,
water (if available in the fracture network) imbibes into the water-wet inorganic matter during the late production period. On the
contrary, mass flow in oil-wet kerogen is limited mostly to twophase oil and gas flow. Although kerogen is a rich source of hydrocarbons, relatively high capillary pressure and very low rock
permeability hinder oil production in organic-rich shale. Such problems might be alleviated by employing appropriate production

enhancement techniques compatible with the ultratight nature of
these reservoirs.
Understanding storage and flow mechanisms from liquid-rich
shale reservoirs such as the Eagle Ford, Woodford and Bakken
is crucial in the overall effort to increase ultimate hydrocarbon
production and recovery. High-resolution analytical tools have
identified kerogen, inorganic matter, and natural/hydraulic fracture porosity/permeability systems with distinctive hydraulic, wettability, transport and storage characteristics in shale reservoirs.
Different physics can be assumed in the various porosity types,
where each of these media can respond differently in similar situations. The current model is built on a unique tool for simulating general multiple-porosity systems, in which several
porosity/permeability systems may be tied through arbitrary transfer functions and connectivities.
The kerogen grid blocks in the model represent mainly carbon-rich material, which is the main source of hydrocarbon generation during diagenesis. Kerogen units are dispersed randomly in an inorganic frame within the shale structure using Monte
Carlo algorithm, and their abundance is calculated using a total
organic carbon value, kerogen, and inorganic matter density and
porosity.
As a measure of the quantity of kerogen or organic richness,
TOC is defined as the mass percent of organic matter in the shale
matrix. The model considers no limits in the connectivity of different porosity systems. Kerogen grid blocks can neighbor other kerogen and inorganic grids, or be located directly adjacent to
fracture grids. Figure 1 shows a cross-section of a single shale
matrix block where kerogen blocks (red squares) are dispersed
randomly in a frame of inorganic matter (yellow).
Indispensable Role
The modeling results underscore the necessity of better
characterizing kerogen to generate more realistic models of the
shale matrix. Although different shale samples show significant
variations in microstructure, kerogen-with pore sizes ranging from

FIGURE 1
Kerogen (Red) Distributed in Inorganic Frame (Yellow) in Shale Matrix

76 THE AMERICAN OIL & GAS REPORTER

American Oil and Gas Reporter - February 2015

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