Page 148 - Fundamentals of Gas Shale Reservoirs

128 PETROPHYSICAL EVALUATION OF GAS SHALE RESERVOIRS

pyrite, siderite, dolomite, calcite, K‐feldspar, plagioclase, Solid matrix Pore space
quartz, and organic carbon (Franquet et al., 2012). This log
can give an idea of the geomechanical properties of the shale
formations, regarding the defined relationship between min­ Kerogen (organic matter)
eralogical content and brittleness of the shale layers (refer to
Section 6.2.5). Gas

6.4.1.8 Nuclear Magnetic Resonance Log Nuclear
magnetic resonance (NMR) log provides useful information
for petrophysical study of the hydrocarbon‐bearing intervals.
Free fluid porosity (effective porosity), rock permeability,
and bound fluid volume could be obtained by processing and Non-kerogen (inorganic matrix)
interpreting the NMR log data (Labani et al., 2010). Unlike Water
neutron, density, and acoustic porosity data which are affected
by all components of the reservoir rock, NMR has a signal
that contains no contribution from the rock matrix and only
responds to the hydrogen associated with pore‐filling fluids;
because of that, NMR porosity does not need to be calibrated
with lithology or lithofacies changes (Coates et al., 1999). FIGURE 6.10 Simple petrophysical model showing the volu­
This is particularly beneficial in gas shale reservoirs where metric constituents of gas shale matrix and pore space.
matrix calibration is difficult due to a high degree of hetero­
geneity. NMR properties of different reservoir fluids are The density log is commonly used to calculate the total
quite different from each other. These differences make it porosity of a formation. Equation 6.6 states the bulk density
possible to type hydrocarbons and, as a result, to determine of a clean rock.
the density of pore‐filling fluid (Coates et al., 1999; Sigal (1 ) (6.6)
and Odusina, 2011). The density of formation fluid can be b ma f
used later for TOC and kerogen density estimation (refer to Equation 6.6 can be written in the form of Equation 6.7 if a
Section 6.2.5). TOC component is added to it (Sondergeld et al., 2010):
1 V V (6.7)
6.4.2 Well Log Interpretation of Gas Shale Formations b ma TOC f TOC TOC

The first step for petrophysical evaluation of the gas shale res­ Since the TOC term is generally provided as a weight
ervoirs is to define a petrophysical model that serves as a basis fraction (w TOC ) (e.g., Passey et al., method), the TOC volume
for well log interpretation. Hitherto, different petrophysical fraction (V TOC ) has to be converted to a weight fraction:
models have been introduced for gas shale reservoirs (Passey W TOC
et al., 1990, 2010; Ambrose et al., 2010; Ramirez et al., 2011). V TOC b (6.8)
Like the conventional reservoirs, shales are assumed to consist TOC
of two main components: solid matrix and pore space. The Then Equation 6.8 can be written as follows:
organic matter is assumed to be part of the solid matrix.
Figure 6.10 shows a simple petrophysical model for the gas w w TOC
shale reservoirs. This model is used for the following well ma b b TOC ma TOC
log analysis to determine petrophysical parameters of gas (6.9)
shale reservoirs. ma f
where ϕ is the total density porosity, ρ is the solid matrix
ma
6.4.2.1 Determination of Total Porosity Typical gas density, ρ is the bulk density, w is TOC weight fraction,
b
TOC
shale reservoir porosities are low, often in the range of ρ is organic material or kerogen density, and ρ is the fluid
TOC
3–10%. Porosity calculations using only conventional log density. f
measurements may have significant uncertainties due to the In a simple model, a fixed value can be used for fluid
variable mineralogies, variable amounts of low‐density density. It can be assumed to be 0.5 g/cm for gas shale and
3
organic material, and fluids present in these reservoirs 0.8 g/cm for oil shale. However, considering Figure 6.10,
3
(Franquet et al., 2012). Total porosity can be determined fluid density can be estimated using the following equation
using NMR log data. Comparison of NMR total porosities if water saturation, S , is known:
with core porosities in several shale plays has shown good w
agreement (Jacobi et al., 2009). f g 1 S w w S w (6.10)