Page 149 - Fundamentals of Gas Shale Reservoirs

WELL LOG ANALYSIS OF GAS SHALE RESERVOIRS 129
Due to the high heterogeneity of the shale layers, it is not time. Kerogen transit time for coal is reported to be approx­
possible to determine a specific value for ρ , although a imately 120 (us/ft).
ma
3
default value of 2.65 g/cm can be considered since quartz
and most clays have a density close to 2.65 g/cm . But to get 6.4.2.2 Determination of Water Saturation Considering
3
an accurate matrix density, it has to be measured using a the complexities of shales, the Archie equation may seem
mineralogy logging tool. Using the percentage of different too simple for estimating the water saturation of these kinds
minerals from the mineralogy logging tool, ρ could be of reservoirs. However, the Archie equation has been
ma
computed using the following formula: accepted as an industrial standard for water saturation deter­
mination of the gas shale layers based on porosity and resis­
n
(1 K ) Min K (6.11) tivity logs:
ma i i k
i 1 aR
w
where Min and ρ are the volume percentage and density of S w n m R (6.17)
i
i
mineral i, respectively, and K and ρ are the volume t
k
percentage and density of kerogen, respectively. Determining some parameters of the Archie equation in gas
Considering Figure 6.10, Formula (6.11) could be simpli­ shale is not as easy as in conventional reservoirs:
fied into the following form:
• Salinity of the formation water and thus pore water
(1 K ) K (6.12)
ma nk k resistivity, R
w
where ρ is the nonkerogen density. • Archie parameters of the gas shale layers (a, m, and n).
nk
Van Krevelen in 1961 showed that the density of vitrinite
varies as a function of thermal maturity (Van Krevelen, In general, formation water salinity of the shale formations
1961). Density may change from 1.27 g/cm , for low matu­ cannot be obtained directly since these layers do not produce
3
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rity vitrinite, to 2.25 g/cm for pure graphite. This is due to formation water normally. Existing data indicates that great
loss of volatility in vitrinite. Ward (2010) reported that variability occurs over short vertical distances; therefore,
vitrinite reflectance can be used to estimate kerogen density. compared to conventional reservoirs, it is difficult to deter­
Equation 6.13 can be utilized to convert vitrinite reflectance mine a fixed value for R and, as a result, the validity of the
w,
(R ) to kerogen density: Archie formula for estimating water saturation is questionable
o (Luffel and Guidry, 1992; Sondergeld et al., 2010). Besides
.
.
k 0 342R o 0 972 (6.13) that, the Archie model does not differentiate the electrical
Total shale porosity can also be calculated from the sonic log contribution of different types of water saturating the shale
using a model similar to the one used for density log. Wyllie matrix and uses a single value for water resistivity. Obviously,
et al. (1956) proposed a linear time–average or weighted– this simplification can turn out to be erroneous when different
average relationship between porosity and transit time for electrical contribution exists from clay‐bound water and free
clean and consolidated formations with uniformly distrib­ water. With conventional reservoirs, water resistivity value
uted small pores: can be obtained in both porous and permeable reservoirs that
have a bottom water leg. Glorioso and Rattia (2012) proposed
DT DT (1 ) DT (6.14) that for gas shale reservoirs, water resistivity could be calcu­
ma f
lated over non‐kerogen intervals (intervals with no kerogen
Equation 6.14 can be rewritten if we add a TOC component content). Within these intervals, it can be assumed that water
to it: saturation would be high because there is not any organic
DT DT 1 V DT DT V matter for generating hydrocarbon; therefore, the lean shale
ma TOC f TOCTOC (6.15) intervals could be similar to the water saturated intervals
Since the TOC term is generally provided as weight fraction in the conventional reservoirs. Cementation exponent (m),
(w TOC ), it has to be converted to weight fraction (see Eq. 6.8). saturation exponent (n), and tortuosity factor (a) have been
Then Equation 6.15 can be rearranged as follows: discussed in depth for the conventional reservoirs, but there
are limited reviews for the gas shale. In conventional
w reservoirs, formation water provides paths for electric cur­
DT DT ma TOC b DT ma DT TOC
TOC rents, while in shale formations, due to presence of large
sonic DT DT amount of interconnected clays accompanied by formation
f ma water, there are more paths for them. These extra paths
(6.16) increase the ease of electric current flow in shale (Yu and
where DT is rock transit time (us/ft), DT = matrix transit Aguilera, 2011). This phenomenon would be reflected by a
ma
time, DT = fluid transit time, and DT = kerogen transit reduction in formation factor and, as a result, in cementation
f TOC