Research paperShale pore size classification: An NMR fluid typing method
Introduction
The production of shale gas has been highly successful in North America, followed by China, where production reached 7.9 billion m3 in 2016 in the marine shale of the Sichuan basin (Liu et al., 2017). The success in shale gas industry raises great interests in fundamental investigations on shale petrophysical properties, such as pore size distribution (PSD), effective porosity and clay-bound water, which can be used to estimate hydrocarbon storage capacity (Furmann et al., 2016; Testamanti and Rezaee, 2017). For example, clay-bound water, residing in nanometer-scaled pore structure, is the most key petrophysical parameter and commonly used to calibrate log porosity for shale formation evaluation (Coates et al., 1999).
Unlike conventional natural gas reservoirs, gas shale is particularly complex in its mineral composition (Curtis et al., 2012), and it is characterized by low porosity, extremely low permeability, and a complicated pore structure (Curtis, 2002; Sondergeld et al., 2010; Hinai et al., 2014). In past decades, various analysis methods, including image analysis, intrusive fluid detection methods and nonintrusive fluid detection methods, have been used to investigate the pore structure features of shale (Ambrose et al., 2010; Clarkson et al., 2013; Kuila and Prasad, 2013; Hinai et al., 2014; Testamanti and Rezaee, 2017). Among these methods, each method has advantages and limitations (Hinai et al., 2014; Clarkson et al., 2013). Typical image analysis methods include scanning transmission electron microscopy (TEM), atomic force microscopy (AFM) and focused ion beam scanning electron microscopy (FIB-SEM). Based on these methods, Reed et al. (2007) and Bustin et al. (2008) defined the nanopores inside the organic matter of gas shale, and Loucks et al. (2012) classified shale pores as organic pores, intra-pores and inter-pores. Intrusive fluid detection methods, including mercury injection capillary pressure (MICP), low pressure gas (N2 and CO2) adsorption, and nuclear magnetic resonance (NMR) methods, can be used to characterize pore characteristics, such as the PSD, pore throat and pore body sizes, and specific surface area (Fleury, 2007; Ambrose et al., 2010; Yao et al., 2010a, 2010b; Clarkson et al., 2013; Kuila and Prasad, 2013; Hinai et al., 2014; Zolfaghari and Dehghanpour, 2015; Chen et al., 2015). Nonintrusive fluid detection methods, such as X-ray computerized tomography (X-CT), can be used to simulate the 3D distribution of the PSD, fracture morphology, and fluid transport (Desbois et al., 2011; Yao and Liu, 2012; Blunt et al., 2013; Korost et al., 2013; Vega et al., 2014). However, the laboratory methods mentioned above have certain limitations. For example, MICP can only detect certain parts of pores but not all nanopores because the original pore structure may be destroyed by applying an extremely high intrusion pressure (Yao and Liu, 2012; Clarkson et al., 2013). The X-CT scanning technique is also not applicable for the analysis of nanopores, and low-pressure gas adsorption technology is not effective for pores of >300 nm (Clarkson et al., 2013). The limitations of these methods make it difficult to characterize the full-scale PSD of shale using an individual method.
As a nondestructive and relatively new method, the NMR core analysis method has been used for the petrophysical characterization of sandstones, coal and shales (Timur, 1969; Westphal et al., 2005; Yao et al., 2010b; Josh et al., 2012; Chi and Heidari, 2014; Gips et al., 2014; Gannaway, 2014; Saidian et al., 2014; Saidian and Prasad, 2015; Wang et al., 2015; Zhao et al., 2015; Minh et al., 2016; Sondergeld et al., 2016; Zolfaghari et al., 2017; Sun et al., 2018). For example, using NMR, X-ray CT scanning and SEM observation, researchers found that shale pores of 3–100 nm commonly have a typical transverse relaxation time (T2) distribution of 0.01–10 ms (Hinai et al., 2014; Huang and Zhao, 2017), and T2 spectra ranging from 10 to 300 ms represent micro fractures (Tinni et al., 2014). Based on different scenarios of NMR simulation experiments, Gannaway (2014) quantified the effective porosity, organic porosity and inorganic porosity in gas shale. Generally, studies have given various classifications for pore typing.
Shale is complex in its petrological composition and pore structure, and thus, fluid types within shale vary. In the normal definition used by a log analyst, pore fluid types were divided into movable fluid and irreducible fluid, and the latter was further divided into capillary bound fluid and clay bound fluid (Straley et al., 1997; Sondergeld et al., 2010; Rylander et al., 2013; Jiang et al., 2013; Mehamed and El-monier, 2016). In a generally accepted definition of sandstones or carbonate rocks, the clay bound porosity is not part of the effective porosity and is the difference between the total porosity and effective porosity. However, recent SEM studies of shales have indicated that many nanopores (gas unrecoverable) are paragenetic with organic matter but not clay minerals (Reed et al., 2007; Bustin et al., 2008; Sondergeld et al., 2010; Loucks et al., 2012; Jing et al., 2017). Considering that we cannot determine whether the so-called “clay bound fluid” occurs in the clay minerals of shales or not (Prammer et al., 1996), in this study, we defined the difference between the total porosity and effective porosity as the unrecoverable porosity. The fluid type corresponding to the unrecoverable porosity is called unrecoverable fluid. Based on a typical T2 distribution obtained from NMR measurements, we defined a T2 cutoff of T2C1 to distinguish the movable fluid (T2 > T2C1) from the irreducible fluid (T2 < T2C1), and we defined another T2 cutoff of T2C2 to differentiate the capillary bound fluid (T2C1>T2 > T2C2) and unrecoverable (conventionally called “clay bound”) fluid (T2 < T2C2).
The value of T2C1 for a certain rock is commonly determined by a series of NMR centrifugal tests at different water saturation levels. Straley et al. (1997) concluded typical T2C1 values of 33 ms and 100 ms for sandstones and carbonates, respectively. Based on NMR measurements of 12 brine-saturated shale samples, Sun et al. (2012) suggested a T2C1 of 8.29 ms for shale. Apart from the determination of T2C1, the determination of T2C2 is also important for evaluating production performance in the late gas production stage. However, the determination of the value of T2C2 for a certain rock is relatively difficult because of methodological limitations. Recently, there have been some reports of T2C2 for sandstone (e.g., Straley et al. (1997)) but no in-depth research of the T2C2 of shale. Based on NMR core measurements, Straley et al. (1997) provided a definition of T2C2 = 3 ms for sandstones. For a long time, 3 ms was the most acceptable T2C2 for both sandstones and shales (Sondergeld et al., 2010; Rylander et al., 2013). Recently, some researchers have reported different values of T2C2 for different shales, such as T2C2 = 0.2 ms for Swiss Molasse shales (Esteban et al., 2013) and T2C2 = 0.25 ms for Carynginia shales (Testamanti and Rezaee, 2017). In fact, the pore structure is very different for shales deposited in different environments; thus, it is problematic to evaluate the shale PSD using a certain value of T2C2 for different shales. It is urgent to develop a method that can be used to accurately calculate the values of T2C1 and T2C2 for different shales.
In this study, we collected seven shale samples from the Lower Silurian Longmaxi formation in the Sichuan basin and conducted a series of NMR experiments on full brine-saturated, cyclic centrifugal treatment, and cyclic heat treatment samples. These experiments utilized a quantitative method for the determination of T2C1 and T2C2 for different shales. This study also provides a pore type classification method for assessing the full-scale PSD of gas shale.
Section snippets
Principle of NMR spectrometry
The principle of the low-field nuclear magnetic resonance method can be found in many publications (e.g., Yao et al., 2010b; Sondergeld et al., 2016). In a typical low-field nuclear magnetic resonance (LF-NMR) measurement, T2 provides abundant information associated with pore fluids in porous rocks. A typical T2 distribution is related to the bulk fluid relaxation, surface relaxation and diffusion mechanisms of fluids in porous media (Kleinberg and Horsfield, 1990; Kenyon, 1997; Coates et al.,
Experimental set-up
The NMR spectrometer adopted a relatively low magnetic field of 0.55 T (frequency of 23.402 MHz). The NMR T2 measurement parameters were performed with waiting time of 1500 ms, number of scan of 128, and 5000 stacks were performed to obtain each relaxation curve. The laboratory temperature and magnet temperature of NMR spectrometer were 21 °C, and 32 °C, respectively. Specifically, the NMR experiment used an extremely low echo spacing of 0.115 ms, which allowed the NMR spectrometer to detect
Characteristics of shale samples
The shale samples have TOC contents of 0.86–3.84 wt % and bituminous reflectances (Ro) ranging from 1.15% to 1.25% (Table 2). The mineral composition of shales mainly includes quartz and clay minerals, followed by feldspar and calcite and negligible magnetic minerals (Fig. 2). Fig. 3 shows some typical characteristics of the mineral constitution and morphology in the studied shale samples.
The helium gas porosities are 2.45–5.01%, and the air permeabilities range from 41.9 nD to 4700.0 nD (Table
Threshold temperature for determining T2C2
In this study, NMR core measurements combined with centrifugation and heat treatment were employed to quantitatively identify unrecoverable fluid, capillary bound fluid and movable fluid in shale pores. Separating the movable fluid from the capillary bound fluid can be easily achieved using the common movable fluid cutoff (T2C1) method discussed in the previous section. However, determining T2C2 and distinguishing the unrecoverable fluid from the capillary bound fluid is difficult. Prior to
Conclusions
Based on a series of NMR experiments involving seven marine shale samples, this study provided a new method for pore fluid typing and the full-scale PSD classification of shales. The main achievements are as follows.
- (1)
The shale pore fluid types were divided into movable fluid, capillary bound fluid, and unrecoverable fluid based on two cutoffs (T2C1 and T2C2) from the T2 spectra under 100% brine-saturated, centrifugal and heat-treated conditions.
- (2)
The amplitudes of the T2 spectra of the studied
Acknowledgements
We acknowledge financial support from the National Natural Science Foundation of China (Nos. 41472137 and 41711530129), and the Foundation for the Author of National Excellent Doctoral Dissertation of PR China (No. 201253).
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