Page 115 - Fundamentals of Gas Shale Reservoirs

PERMEABILITY MEASUREMENT 95
space, an ideal shape would be a circle, where the value of 5.5 PErmEabILITy mEaSurEmENT
the shape factor would be 1. The shape factor is given by
Liquid or gas can be used to measure permeability on core
G VL (5.8) plugs in laboratories. Usually, gas preferred as the sample
A s 2 preparation is relatively simpler and the measurement
duration is also much shorter. However, at low average
where A is the surface area of the pore or throat block, V is pressure gas slippage occurs, which causes Darcy Law to
block volume, and L is the block length. This is equivalent to produce high permeability values and requires Klinkenberg
corrections. The corrected permeability is then termed “liquid
A
G (5.9) permeability” or “Klinkenberg permeability.”
P 2 Both steady state and unsteady state methods are used
for permeability measurement as outlined by Luffel (1993).
where A is the cross‐sectional area and P is perimeter.
Permeability measurements are done using resin disks, where a
piece of the rock is embedded in resin (Egermann et al., 2004,
2006; Lenormand and Fonta, 2007; Lenormand et al., 2010).
5.4 aDVaNTaGES aND DISaDVaNTaGES For rocks with permeabilities >1 mD, the initial coating is done
OF EXPErImENTaL PSD mETHODS with a high viscosity resin. This would prevent the resin from
invading the pores. For lower permeabilities, a low viscosity
In some instances, it is difficult to obtain suitable core resin allows the partial invasion over a small distance and a good
plugs for evaluating the petrophysical properties of reser­ sealing. After the sample is embedded in the resin, the sample is
voir rocks. In this situation, MICP and N adsorption tests cut into slices, with thicknesses ranging from 1 to 5 mm and
2
can be carried out. The advantages of the MICP technique their surfaces are polished. Samples with predicted low perme­
are: it directly measures the pore volume through the abilities undergo the measurement using a modified steady‐state
mercury volume injected; it requires small rock cuttings or method with gas flow rate measured at the outlet; this minimizes
fragments; results are obtained relatively quickly with rea­ or eliminates any potential errors due to system leaks.
sonable accuracy; and finally very high capillary pressure The resin disc is placed between two end pieces of the
ranges can be achieved. The measurement does not require core holder. The tightness is ensured by applying a load
a completely symmetrical sample, but it is commonly using a hydraulic press. The entry can be connected to several
limited to 1 cm . vessels of different volumes. The outlet is either open to the
3
MICP and N are destructive techniques but quite often atmosphere or closed with a small volume. Inlet and outlet
2
used as relevant PSD measurements for gas shales (Clarkson pressures are also measured.
et al., 2013). MICP is capable of characterizing the PSD in The gas permeability is derived from pressure and flow
the range of mesopores (5 nm < pore diameter > 50 nm: rate. The average pressure <P> = (P + P )/2 used was in
out
in
intra‐ and interclay) to macropores (pore diameter > 50 nm: the range of 14.5–101.5 psi through 5 pressure periods. The
intergrains and discontinuities) while N relates to pores less average gas permeability <K > at a single point steady‐state
g
2
than 2 nm. The pore diameter classification in this study is measurement was found using the Jones–Owens technique
based on IUPAC classification (Rouquerol et al., 1994). (Jones and Owens, 1980). The measurements were con­
The N method also requires crushing the sample into ducted at a net confining pressure of 1015 psi. The micro­
2
powder to fully wet the surface of the sample, which could scopic flow can be described as “average” gas permeability:
affect the original pore structure of the solid matrix. Another
inconvenience of the MICP and N methods for evaluating K K 1 b (5.10)
2
the properties of shale is the occurrence of a double layer (or g 1 P
Stern layer). This layer is directly related to the surface where K is the average gas permeability, K is the Klinkenberg
clay‐bound water that reduces porosity and pore radius. corrected permeability that is determined from the intercept,
l
g
NMR is a nondestructive technique and it supposes that
the sample is fully or partially water saturated (i.e., in a pre­ and b is the gas slippage factor that is computed from the
slope of the gas permeability versus the reciprocal average
served condition) for proper porosity assessment. In contrast pressure plot. The Klinkenberg plot is used to determine the
to MICP PSD that provides only “connected” pore throats as liquid permeability and also take into account the gas slip­
tube shapes and no pore body sensu‐stricto, NMR PSD page effects. Gas slippage factor is given by:
provides full experimental characterization of pore geom­
etry (Chen and Song, 2002), the size of the pore body behind m
the throats (Burdine et al., 1950; Churcher et al., 1991; Heath b K (5.11)
et al., 2011) and the isolated pores (e.g., if the sample kept its 1
original fluid). where m is the slope.