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Comparative Porosity and Pore Structure Assessment in Shales: Measurement Techniques, Influencing Factors and Implications for Reservoir Characterization

Figure 1. The porosity values obtained from mercury intrusion capillary pressure (MICP), Helium, and nuclear magnetic resonance (NMR) for two different shale formations.

The Pore Size Distribution from Gas Adsorption

Figure 6 displays Caryngina PSD obtained from LP-N2-GA experiments. As can be seen, the PSD peak in Carynginia appears around 20 nm, implying the pore majority locating in fine mesopore sizes that dominantly controls the total pore volume. Monterey shales, by contrast, present a different scenario (Figure 7), showing PSD peak at ~50–100 nm with the pore majority in fine macropore ranges, which is intimately related to the high quartz content.

Figure 6. Carynginia pore size distribution (PSD) derived from low-pressure N2 gas adsorption based on BJH theory.

The Pore Throat Size Distribution from MICP

Carynginia and Monterey pore throat size distributions (PTDs) measured by MICP are plotted in Figure 8 and Figure 9. The peaks of MICP- derived PTD in Carynginia are commonly located in pore sizes ~4–5 nm, which are smaller compared to that interpreted by LP-N2-GA. A wider range of the detectable large pores (i.e., pore sizes larger than 100 nm) is revealed by MICP technique compared to LP-N2-GA. Consistent with the NMR and LP-N2-GA interpretations for Carynginia samples, larger PTD amplitude is shown in the samples of higher clay (e.g., AC1, AC2), while the lowest PTD amplitude is found in samples of the lowest clay samples (i.e., AC8). The Monterey PTD, however, presents a weak interrelationship between the clay content and the amplitude of curve (Figure 9), which agrees with the behaviours of Monterey PSD (e.g., Figure 4, Figure 5 and Figure 7) that is most likely under the large influences of low-clay contents [44].

Figure 7. Monterey pore size distribution (PSD) derived from low-pressure N2 gas adsorption. Modified from Saidian, Kuila [44].

Figure 7. Monterey pore size distribution (PSD) derived from low-pressure N2 gas adsorption. Modified from Saidian, Kuila [44].

Discussion

Carynginia samples are characterized by abundant clay contents, while Monterey shales are clay-poor (Table 1). NMR technique, which is highlighted by non-destructive measurement of total porosity, involves the detection of effective porosity and clay bound water (CBW), which is tightly bound on the surface area of clay minerals and universally quantified by cutting the effective porosity off total porosity [52,53]. Other penetration approaches, e.g., helium, MICP, and low-pressure gas adsorption, nevertheless, are merely approachable to the interconnected pores, missing out the closed-pores or the ineffective porosity occupied by CBW.

Figure 8. MICP pore throat size distribution (PTD) for Permian Carynginia shales.

Figure 8. MICP pore throat size distribution (PTD) for Permian Carynginia shales.

Under extreme circumstances, for shales containing very high clay contents and thus high CBW, the most of pore spaces could be nearly fully-occupied by the volume of CBW [8,54] that would influence the petrophysical properties in shales [27,55,56,57]. As helium porosimetry is able to obtain effective porosity by covering a wider pore size range (i.e., 0.1 nm–100 µm) than MICP (i.e., 3.6 nm–100 µm) (Figure 10) [34], the CBW is calculated by subtracting the helium porosity (i.e., effective effective) from NMR porosity (i.e., total porosity).

Figure 9. MICP pore throat size distribution (PTD) for Monterey shales. Modified from Saidian, Kuila [44].

Figure 9. MICP pore throat size distribution (PTD) for Monterey shales. Modified from Saidian, Kuila [44].

Figure 11 cross-plots the calculated CBW versus the clay content in both Carynginia and Monterey shales. The CBW, which accounts for the porosity discrepancy between NMR and helium measurement, displays higher values in clay-rich Caryngnia shales, but lower values are found in Monterey shales. The correlation presents a good linear relationship (R2 = 0.76), indicating that the correlation equation (Equation (3)) is adaptable for the estimation of CBW in the shale, whose clay type is dominantly contributed by illite:

 indicating that the correlation equation (Equation (3)) is adaptable for the estimation of CBW in the shale, whose clay type is dominantly contributed by illite:

where C B W is the volume of clay bound water (%), V s h   ( % ) is the clay contents (%). Moreover, the equation is most likely to fit into the formation with the brine salinity of 20,000–30,000 ppm that matches with our studied formations.

Figure 10. The multi-scaled methods for pore characterization in shales Modified from other studies [32,34,58,59].

Figure 10. The multi-scaled methods for pore characterization in shales Modified from other studies [32,34,58,59].

Apart from the influencing factors associated with clays, the compatibility of the penetrated working fluid molecules with shale nanopore structure also causes the interpretation inconsistencies. Unlike NMR using H2O as working fluid to access pore body, the working molecule involved in MICP is merely attainable to the limited pore throat size. The mineral-controlled geometrical pore shapes, which are highly intimated with the mineral compositions and assemblages, pose a large impact on the porosity discrepancies between NMR and MICP in Carynginia shales [60].

Figure 11. The cross-plot of clay bound water (CBW) (%) versus clay content (%) for studied shale samples.

To summarize, the possible reasons for the higher NMR porosity over MICP are: (1) the volume of clay bound water; (2) the porosity contributed by pores smaller than 3.6 nm; (3) the different mechanisms involved in NMR pore body detection versus MICP pore throat detection (e.g., MICP assumes the pores are cylindrical in shape with a smooth surface, but the real pores are complicated with rough surfaces bound with water layers) [34]; (4) the pore shape combination that intimately related to shale compositions. When the comparisons are carried out between helium and MICP, theoretically, for shales containing high proportion of micropores, helium porosity is supposed to be higher than MICP due to its wider detection of pore size range [58].

However, the higher MICP porosity values are observed in some of the studied samples in both Carynginia and Monterey (e.g., AC1, AC3, M5-B, M4) (Figure 1). As the samples from both formations show a small proportion of micropores, the possible reasons could be explained by the increased mercury uptake induced by the high-pressure application (i.e., 60,000 psi) in MICP measurement [61]. Similar phenomenons have also been found in coals [62], which possess similar characteristics as shales [63,64].

Conclusions

The discrepancies in porosity or pore size distribution between MICP, NMR, and LP-GA porosimetry are largely controlled by shale compositions, particularly, the clay minerals. The clay-rich shales generate NMR porosity significantly higher than MICP and helium porosity, while the clay-poor shales exhibit a high porosity consistency between NMR, MICP and helium porosimetry.

The higher porosity values unveiled by NMR over MICP/helium technique are fundamentally attributed to CBW, meanwhile, the clay mineral compositions and assemblages, coupled with pore geometry also contribute to the discrepancies. The MICP and helium both detect intercommunicated pores and display consistent porosity for shales deficient in pores smaller than 3.6 nm. The shales of deficient micropores may possibly show higher helium porosity over MICP porosity, which essentially result from the high pressure application involved in MICP technique.

 

Author Contributions

Investigation and writing, Y.Y.; Supervision, reviewing and correcting, R.R.

Funding

This research was funded by China Scholarship Council. Grant number: 201606450018.

Acknowledgments

The authors acknowledge Unconventional Gas Research Group (UGRG), the discipline of Petroleum Engineering and the discipline of Chemical Engineering in Western Australian School of Mines (WASM), Curtin University for the facility assistance. The Department of Mines, Industry Regulation and Safety of the Government of Western Australia is acknowledged for their permission of core sample collections. The editor and anonymous reviewers are also appreciated for their comments to improve this work. Y. Yuan sincerely thanks China Scholarship Council-Curtin International Postgrad Research Scholarship (CSC-CIPRS) for their financial support.

Conflicts of Interest

The authors declare no conflict of interest.

Appendix A

Table A1. The porosity values obtained from MICP, Helium and NMR techniques for the studied samples in Carynginia and Monterey. Some data are collected from other studies [26,27,46].

Table A1. The porosity values obtained from MICP, Helium and NMR techniques for the studied samples in Carynginia and Monterey. Some data are collected from other studies [26,27,46].

 

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Contact:

Yujie Yuan* and Reza Rezaee

Western Australian School of Mines, Minerals, Energy and Chemical Engineering, Curtin University,

Perth WA 6845, Australia; [email protected]

* Correspondence: [email protected]

 

© 2019 by the authors. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (http://creativecommons.org/licenses/by/4.0/).

 

Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo. In an independent way he’s researching about shale gas & tight oil and building this website to spread the scientist knowledge of the shale industry.
http://www.allaboutshale.com

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