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A comparative study on pore size distribution of different Indian shale gas reservoirs for gas production and potential CO2 sequestration Ashutosh Tripathy, Vinoth Srinivasan, and TN Singh Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b04137 • Publication Date (Web): 21 Feb 2018 Downloaded from http://pubs.acs.org on February 22, 2018
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A comparative study on pore size distribution of different Indian shale gas reservoirs for gas production and potential CO2 sequestration Ashutosh Tripathy, Vinoth Srinivasan*, T.N.Singh Department of Earth Sciences, Indian Institute of Technology Bombay, Mumbai, 400 076, India Keywords: shale gas; pore size distribution; MIP; gas adsorption; CO2 sequestration; Indian shale
Abstract
A thorough knowledge on pore size distribution is one of the fundamental requirements for characterization of shale gas reservoirs and for accurate estimation of their gas storage potential. However, being important future source of energy need in India, the pore size distribution of Indian shale gas systems is not scientifically well understood. In the present study, the nano-scale pore size distribution of prospective Indian shale basins, viz. Cambay, Cauvery, Krishna-Godavari (K-G) and Damodar valley were investigated using Mercury Injection Porosimetry (MIP) and low-pressure gas adsorption (LP-N2 and LP-CO2) techniques. The study focused on identifying the priority basins for shale gas production which can be substituted for sequestration of CO2 based on their PSDs. The samples exhibited higher thermal maturity with increasing organic content. The chemical composition of the shale samples was inferred from XRD data, which depicted higher clay content. The prominent clay minerals identified Muscovite, Illite and kaolinite, which are generally flaky in nature. These minerals contributed
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significantly to the pore size complexity of the studied shale samples. The experimental result suggested that the samples exhibited diversified pore size characteristics. The shales are chiefly bimodal, consisting of mesopores (2–50nm) and micropores (50nm), mesopore (50nm to 2nm) and micropores (20nm are accessible by water intrusion. A similar type of work for characterizing nanopores was reported by Sun et al11. From the Niutitang formation shale, they found that organic porosity is independent of organic matter maturity. Yang et al44 investigated the fractal dimension and pore structure of Sichuan basin shale using FE-SEM, gas adsorption and helium pycnometry and correlated the pore structure parameters with organic content, fractal dimensions and pore structure parameters. Sun et al45 applied neutron scattering with polydispersive spheres model to investigate the porosity and PSD and found a good correlation with those of gas adsorption (CO2, N2) and helium pycnometry results. From the above discussed literatures, it is evident that methods such as FE-SEM, TEM, X-ray CT are principally useful to study the pore morphology, macerals and mineralogical discernment including organic matter. On other hand, methods such as neutron scattering, BET - gas adsorption, MIP are largely useful to understand PSD and for quantification of pore symmetry and their connectivity to assess the gas storage potential. However, each method has its own typical features and limitations. FIB-SEM has limited spatial resolution of 5-10 nm which may not depict the complete pore structure and distribution43,44,46. Neutron scattering (SANS/USANS) depends on the section orientation such that section along bedding plane may offer low porosity than the one perpendicular to bedding plane (as observed in Marcellus shale)30. Though MIP is a very efficient tool for pore characterization, the smallest pore size that can be accessed with the help of MIP is 3nm12. Therefore, at very high pressures of
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intrusion (60,000 psi), mercury could induce structural defects like micro-cracks in the sample thus leading to overestimation of porosity. Low-pressure gas adsorption using N2 and CO2 can be used as an efficient tool for micro-pore characterization47. Nitrogen and Carbon dioxide, having significantly lower molecular diameter than a micro-pore are best suited for the purpose25,48. From the above literatures, it can be inferred that PSD based on a single method may lead to inaccurate conclusions. Moreover, a single method may be biased towards certain component of the sample and give erroneous sorption values. Therefore, a combination of two or more methods is sufficiently required to accurately study the complex PSD in shale reservoir rocks. In the present study, MIP technique and gas adsorption (N2 and CO2) are implemented to correlate the PSD of different sedimentary basins. N2 adsorption is used for the study of macro and mesopores while CO2 adsorption is used for characterization of micro-pores. Materials and Method Shale gas resources in India are restricted to marine depositional environment. The representative samples were collected from the four major prospective shale gas basins in India, i.e. Cambay, Cauvery, Krishna-Godavari and Damodar basin (Figure 2). The samples collected were in form of 100 mm diameter cores. The depth and formation data were recorded. The original cores were packed with sealed bags to retain the natural moisture content and stored in core boxes. Later, the required chip and powder samples were derived from these cores. The details of the samples collected are given in Table 1. The table furnishes the basin, sub-basin, location and depth data of the sample cores along with a brief physical description of the cores. As collection of shale sample involves significant difficulty and due to the limitation of gas wells in the regions, the present research was carried for the samples from their current working depth. Therefore, Damodar valley samples were from shallower depth, considering the chief association of basin with coal formations which is under further exploration. Table 1. Details of collected samples
Sample No S1
Basin Cambay
Sub-Basin Jambusar-
Location Uber
Depth (meters) 2515
Physical Description Extremely flaky and brittle,
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Broach S2
Cauvery
Ramnad
Attiyuttu
2720
S3
K-G
Godavari
Rajahmundri
2426
S4
Damodar
North Karanpura
Chandol
511
inherent micro-cracks found Compact and finer particle size observed Relatively hard and compact cores Darker in color and relatively harder in feel
Geological Background Cambay basin: Geographically, Cambay basin is located in the North West Indian state of Gujarat, extending from Surat in the south to Sanchor in the north. The basin covers a total area of 53,500 sq. km. In the north, the basin territory narrows and continues into the Barmer basin of Rajasthan. Cambay basin is an elongated intra-cratonic late cretaceous to tertiary rift basin. The basin is bounded by well-defined step faults as basin margin. The basin is a deeper marine deposit with deltaic and nearshore environments in the northern parts. The thermal maturity of the shale deposits increases from north to south with the oil to gas phase and concentration. The Cambay shale which is the principal source rock contains high TOC content in the basin depocenters, with concentrations greater than 4 weight percent with the base of the shale, having vitrinite reflectance (Ro) values greater than 1.1. The Oil and Natural Gas Corporation of India drilled two vertical holes in the Cambay basin and found signatures of gas content in the Cambay black shale formation49. Cauvery basin: The basin is located in the southeastern coastal region of Tamil Nadu, a southern Indian state. The basin covers a gross onshore area of 23,569 sq. km50. It is mainly composed of rifted grabens where the Mesozoic sediments fill the grabens and form several sub-basins. The organic rich source rock is of early cretaceous age found in Andimadam formation and Sattapadi shale. The organic rich shales are interpreted to be deposited under marine conditions. The TOC of these organic rich formations ranges from 2 to 2.5 percent. Ro values vary from 1.0 to 1.5 percent51. The samples investigated in the present study were collected from Ramnad Sub basin, lying southwards.
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Krishna-Godavari (K-G) basin – Geographically, Krishna-Godavari basin is located in the southeast coast in the Indian state of Andhra Pradesh. It is a peri-cratonic passive margin basin covering an area of 28,000 sq. km46. The basin is structured as an en-echelon horst and graben system, which is covered by sediments from Permian to Recent age. The known hydrocarbon bearing areas are divided into five petroleum systems, the major source rocks being early Permian, cretaceous, paleocene and Eocene. The thermal maturity of the shales ranges from 0.7% to 2% Ro52. Damodar valley – Damodar valley is a prominent basin situated in the eastern part of India covering the Indian states of Jharkhand, West Bengal and Chattisgarh. The sampling was done from North Karanpura, a sub-basin of Damodar Valley basin. The Damodar valley is a permo-carboniferous basin encompassing an area of 5880 sq. km50. The sedimentation is mainly of glacio-fluvial and lacustrine in nature corresponding to early Permian age. The early Permian shale, called as the Barren measures which was deposited during a marine incursion is found to be the only thermally mature shale in the region. The average TOC of the shale being 3.5%, the vitrinite reflectance ranges from 1.0 % to 1.3 % Ro53.
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Figure 2. Map showing geographical distribution of the studied sedimentary basins in India (edited from EIA50)
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Figure 3. A schematic stratigraphic correlation of studied Indian shale basins (Highlighted are the studied formations) (edited from EIA50) Experimental Approach X-Ray Diffraction Analysis (XRD): The XRD analysis was performed to identify and quantify the mineral phases present in the shales, especially the clay fraction. The analysis was performed using an X-Ray PANalytical Diffractometer (Empyrean) with a starting position [°2θ] of 4.0 to the end position [°2θ] of 80.0, with a step size [°] of 0.020. These XRD data were then processed using X’Pert Highscore Plus software. The peaks obtained from the XRD analysis were compared with the JCSD-2013 database for the identification of different mineral phases.
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Mercury Intrusion Porosimetry (MIP): Mercury Intrusion Porosimetry is an old conventional technique practiced to understand the information of materials such as their pore size distribution, total porosity or pore volume and the specific surface area. In this technique, by applying external pressure mercury is injected into the porous media. Mercury can intrude well within the mesopore region of pore diameter >5nm. The quantity of mercury that can intrude and the amount of pressure required is directly proportion to the pore size of the material. The data is then converted into the pore size distribution of the sample using54 equation given as:
= −
(1)
Where, is the pressure of intrusion, σ is the surface tension of mercury, θ is the contact angle and is the pore radius. The powdered samples were oven treated for a considerable period of time (approximately 8 hours) prior to the experiments to remove moisture and inherent gas present inside the pores. Low-pressure gas sorption: Low pressure adsorption is an effective method to measure specific pore volume, shape and pore size distribution with specific surface area at pressure
